PetroVietnam Seeks Partners at Home, Abroad for Oil, Gas Development

PetroVietnam is seeking partners to expand its oil and natural gas production at home and internationally to meet Vietnam's growing economy and energy needs, said company officials at the Offshore Technology Conference Monday in Houston.

Vietnam's rising energy demand, which has grown at a rate of 15 percent per year, has prompted the country to seek to aggressively increase its overseas exploration budget. That demand lagged some in the past two years, but is expected to rise again in 2013, said PetroVietnam officials in a panel discussion.

Total oil production in Vietnam has grown to 320,000 barrels of oil per day (bopd)) of sweet crude. PetroVietnam aims to ramp up its production from 120,000 bopd this year to 180,000 bopd in 2015 to 470,000 bopd in 2025. PetroVietnam currently produces 1 billion cubic feet per day (Bcf/d) of gas; plans call for that production to grow to 1.5 Bcf/d within the next four to five years as the company fully develops its offshore gas resources.          

The company started pursuing offshore exploration and production globally in the early 2000s, and now participates in 20 projects in 15 countries globally, including South America, North Africa, Central and Southeast Asia. The company now has 90 production sharing agreements with partners in Vietnam and overseas. PetroVietnam aims to increase its international production from 26,000 bopd to 60,000 bopd by 2015, with first production expected from projects in Peru, Algeria and Russia in November of this year and in 2014 and 2015.

Domestic exploration efforts have focused on Vietnam's offshore continental shelf, but officials say the nation's has significant untapped ultra-deepwater potential with undiscovered resources of 3.250 million cubic meters (114.8 million cubic feet), said Do Van Hau, president and CEO of PetroVietnam. The company is seeking partners to help it address the challenging challenges of producing natural gas with high carbon dioxide content.

The company has interests available in acreage in Uzbekistan and Myanmar; PetroVietnam is negotiating with a partner for its Myanmar interest.

Hau said the company does not have any plans at this time to drill in Cuba. Reuters reported last year that PetroVietnam was considering drilling offshore Cuba in 2013.

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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Andy Brown Joins BMT as VP of Business Development

BMT Scientific Marine Services (BMT), a subsidiary of BMT Group Ltd, is pleased to announce that Andy Brown has been appointed as vice president of business development.

Andy has worked in the offshore oil and gas sector for over 25 years and has wide ranging experience in business development, marketing, commercial documentation, project management, cost control, corporate finances and personnel management. His technical experience includes the management, design and development of numerous multidisciplinary oceanographic projects including oceanographic data acquisition systems, deepwater oceanographic moorings and buoyed systems on behalf of governments, oil and gas operators, engineering firms and construction companies worldwide. Andy has previously held senior management positions at large consultancies in the offshore sector, with responsibility for operations throughout the Americas and SE Asia.

In his new BMT role based in Houston, Andy will oversee the development and implementation of sales plans for all geographic regions and participate in identification, promotion and implementation of new products and services that will best benefit our clients.

Tom Johnson, President of BMT Scientific Marine Services, said on this new appointment: “I am delighted that Andy has joined BMT Scientific Marine Services.  I expect that Andy’s technical expertise and management experience will allow him to lead our dynamic business development team as we expand our global sales efforts. Our goal, as always, is to serve our client’s needs and to be able to deliver locally in many of the major oil basins worldwide.”

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Andy Brown Joins BMT as VP of Business Development

BMT Scientific Marine Services (BMT), a subsidiary of BMT Group Ltd, is pleased to announce that Andy Brown has been appointed as vice president of business development.

Andy has worked in the offshore oil and gas sector for over 25 years and has wide ranging experience in business development, marketing, commercial documentation, project management, cost control, corporate finances and personnel management. His technical experience includes the management, design and development of numerous multidisciplinary oceanographic projects including oceanographic data acquisition systems, deepwater oceanographic moorings and buoyed systems on behalf of governments, oil and gas operators, engineering firms and construction companies worldwide. Andy has previously held senior management positions at large consultancies in the offshore sector, with responsibility for operations throughout the Americas and SE Asia.

In his new BMT role based in Houston, Andy will oversee the development and implementation of sales plans for all geographic regions and participate in identification, promotion and implementation of new products and services that will best benefit our clients.

Tom Johnson, President of BMT Scientific Marine Services, said on this new appointment: “I am delighted that Andy has joined BMT Scientific Marine Services.  I expect that Andy’s technical expertise and management experience will allow him to lead our dynamic business development team as we expand our global sales efforts. Our goal, as always, is to serve our client’s needs and to be able to deliver locally in many of the major oil basins worldwide.”

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TAQA Gets Approval for Cladhan Development

TAQA Bratani reported late Wednesday that it has received approval from the UK government for its development plan for the Cladhan field in the North Sea.

The initial phase of development of the field – which is located on Blocks 210/29a and 210/30a in the northern North Sea – will consist of two producer wells and one injection well.  Cladhan is expected to produce over 17,000 barrels of oil equivalent per day initially with first oil expected in the first quarter of 2015. Production will be tied back to TAQA's Tern Alpha platform which lies some 11 miles northeast of the Cladhan field.

TAQA Bratani Managing Director Leo Koot commented in a company statement:

"The Cladhan development is the third field that TAQA has developed and the largest project to date. Developing Cladhan as a tie back to Tern supports TAQA's strategy to invest in our infrastructure as we recognise the crucial part it plays in allowing us to maximise recovery from the northern North Sea."

TAQA current has a 40.1-percent stake in the Cladhan field but an agreement to acquire further equity in the field from Sterling Resources could see its interest increase to 52.7 percent.

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TAQA Gets Approval for Cladhan Development

TAQA Bratani reported late Wednesday that it has received approval from the UK government for its development plan for the Cladhan field in the North Sea.

The initial phase of development of the field – which is located on Blocks 210/29a and 210/30a in the northern North Sea – will consist of two producer wells and one injection well.  Cladhan is expected to produce over 17,000 barrels of oil equivalent per day initially with first oil expected in the first quarter of 2015. Production will be tied back to TAQA's Tern Alpha platform which lies some 11 miles northeast of the Cladhan field.

TAQA Bratani Managing Director Leo Koot commented in a company statement:

"The Cladhan development is the third field that TAQA has developed and the largest project to date. Developing Cladhan as a tie back to Tern supports TAQA's strategy to invest in our infrastructure as we recognise the crucial part it plays in allowing us to maximise recovery from the northern North Sea."

TAQA current has a 40.1-percent stake in the Cladhan field but an agreement to acquire further equity in the field from Sterling Resources could see its interest increase to 52.7 percent.

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

TAQA Gets Approval for Cladhan Development

TAQA Bratani reported late Wednesday that it has received approval from the UK government for its development plan for the Cladhan field in the North Sea.

The initial phase of development of the field – which is located on Blocks 210/29a and 210/30a in the northern North Sea – will consist of two producer wells and one injection well.  Cladhan is expected to produce over 17,000 barrels of oil equivalent per day initially with first oil expected in the first quarter of 2015. Production will be tied back to TAQA's Tern Alpha platform which lies some 11 miles northeast of the Cladhan field.

TAQA Bratani Managing Director Leo Koot commented in a company statement:

"The Cladhan development is the third field that TAQA has developed and the largest project to date. Developing Cladhan as a tie back to Tern supports TAQA's strategy to invest in our infrastructure as we recognise the crucial part it plays in allowing us to maximise recovery from the northern North Sea."

TAQA current has a 40.1-percent stake in the Cladhan field but an agreement to acquire further equity in the field from Sterling Resources could see its interest increase to 52.7 percent.

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.

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BP Reviewing Mad Dog Phase 2 Development Plans

BP plc and partners are reviewing their plans for the second phase of the Mad Dog field development in the U.S. Gulf of Mexico as current market conditions and industry inflation have made the current development scheme less attractive.

BP, Chevron Corp. and BHP Billiton Petroleum are reviewing the existing plans and other options in evaluating how to develop the project, BP's largest greenfield development in the U.S. Gulf in a decade and one of the world's largest spars.

However, BP told Rigzone it fully intends to develop the Mad Dog Phase 2 resources and is committed to moving forward with the right plan.

"It is too early to speculate when the details of the final plan will be approved by BP and its co-owners," a BP spokesperson said in an email statement.

The current plans for Mad Dog Phase 2 include a spar floating system with infield flow lines and associated subsea infrastructure to connect the subsea production and injection wells. The project also includes export pipelines connected to the existing Mardi Gras system.

The spar will have production capacity of 130,000 barrels of oil per day, 75 million cubic feet per day of total compression, and water injection capacity of 280,000 barrels per day (bopd) for waterflood of western and southern field segments. Water injection capacity can be expanded to 350,000 bopd to accommodate future injection requirements.

The development concept includes 33 wet wells, 19 production and 14 injection wells.

BP is operator of Mad Dog Phase 2 with 60.5 percent working interest. BHP Petroleum holds 23.9 percent interest and Chevron owns 15.6 percent.

Mad Dog Phase 2 was one of seven projects BP anticipated would be in the post-final investment decision stage in the 2015-2020 timeframe. BP expected to kick off construction of the Mad Dog 2 infrastructure around the end of 2013, according to a BP December 2012 presentation.

Mad Dog Phase 2 is one of 11 BP megaprojects that will each require a gross investment of over $10 billion.  Located in the southern Green Canyon area of the U.S. Gulf in water depths of 4,500 to 6,800 feet (1,372 to 2,073 meters), Mad Dog is estimated to contain reserves ranging from 200 to 450 million barrels of oil equivalent.

The company reported late last year it was on track to deliver 15 projects from 2012-2014. BP started up three of those projects in 2012, including the Galapagos project in the U.S. Gulf, Clochas Mavacola in Angola and Devenick in the North Sea.  

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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BP Reviewing Mad Dog Phase 2 Development Plans

BP plc and partners are reviewing their plans for the second phase of the Mad Dog field development in the U.S. Gulf of Mexico as current market conditions and industry inflation have made the current development scheme less attractive.

BP, Chevron Corp. and BHP Billiton Petroleum are reviewing the existing plans and other options in evaluating how to develop the project, BP's largest greenfield development in the U.S. Gulf in a decade and one of the world's largest spars.

However, BP told Rigzone it fully intends to develop the Mad Dog Phase 2 resources and is committed to moving forward with the right plan.

"It is too early to speculate when the details of the final plan will be approved by BP and its co-owners," a BP spokesperson said in an email statement.

The current plans for Mad Dog Phase 2 include a spar floating system with infield flow lines and associated subsea infrastructure to connect the subsea production and injection wells. The project also includes export pipelines connected to the existing Mardi Gras system.

The spar will have production capacity of 130,000 barrels of oil per day, 75 million cubic feet per day of total compression, and water injection capacity of 280,000 barrels per day (bopd) for waterflood of western and southern field segments. Water injection capacity can be expanded to 350,000 bopd to accommodate future injection requirements.

The development concept includes 33 wet wells, 19 production and 14 injection wells.

BP is operator of Mad Dog Phase 2 with 60.5 percent working interest. BHP Petroleum holds 23.9 percent interest and Chevron owns 15.6 percent.

Mad Dog Phase 2 was one of seven projects BP anticipated would be in the post-final investment decision stage in the 2015-2020 timeframe. BP expected to kick off construction of the Mad Dog 2 infrastructure around the end of 2013, according to a BP December 2012 presentation.

Mad Dog Phase 2 is one of 11 BP megaprojects that will each require a gross investment of over $10 billion.  Located in the southern Green Canyon area of the U.S. Gulf in water depths of 4,500 to 6,800 feet (1,372 to 2,073 meters), Mad Dog is estimated to contain reserves ranging from 200 to 450 million barrels of oil equivalent.

The company reported late last year it was on track to deliver 15 projects from 2012-2014. BP started up three of those projects in 2012, including the Galapagos project in the U.S. Gulf, Clochas Mavacola in Angola and Devenick in the North Sea.  

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@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

Argentina to Create $2 Billion Oil, Gas Development Fund

BUENOS AIRES -

Argentina's government plans to put up to $2 billion into a new petroleum exploration-and-production fund as the South American nation struggles to become self sufficient in oil and natural gas.

The Argentine Hydrocarbon Fund is authorized to lend money, contribute capital and buy securities issued by oil companies in which the government has an equity stake, according to a resolution published Friday in the government-published Official Bulletin.

The government controls energy companies Enarsa and YPF SA.

It wasn't immediately clear how President Cristina Kirchner will capitalize the fund. Barclays said in a report it thinks the money will come from central bank's foreign currency reserves.

The 2013 budget earmarks almost $8 billion of reserves to pay creditors. But economic growth of just 1.9% last year means that Argentina won't have to pay several billion dollars to investors that own securities whose payouts are linked to the economy's performance.

"We expect, therefore, the treasury to tap reserves and issue a low-coupon hard-currency bond [most likely not marketable] to the central bank," Barclays economist Sebastian Vargas wrote.

A spokeswoman for the Economy Ministry didn't immediately reply to a phone call and email seeking comment.

The central bank, a virtual appendage of the Economy Ministry, is struggling to rebuild its reserves even as a bumper soybean harvest brings billions of export dollars into the country.

On Thursday, those reserves, which the government uses to pay its creditors and buy imported fuels like natural gas, slipped to a six-year low of $39.8 billion. Analysts blame the gradual erosion in reserves on the decline in the value of the bank's gold holdings and persistent capital outflows.

A fire last month that crippled YPF's largest refinery which supplies about 30% of Argentina's domestically produced fuel will force the state controlled company to import significantly more diesel and gasoline this year, putting even more pressure on reserves.

Mrs. Kirchner seized a controlling stake in Argentina's No. 1 oil and gas producer, YPF, from Spain's Repsol SA last year and has tasked the company with reversing years of declining production that have turned Argentina into a net energy importer.

Mrs. Kirchner accused Repsol of decapitalizing YPF through an overly generous dividend policy, which left the firm with scant resources to reinvest in its business. Repsol has denied those accusations and is suing her government for about $10.5 billion in compensation for its YPF shares.

YPF invested 16.48 billion pesos ($3.2 billion) in 2012, an increase of nearly 26% on the year.

The company is also seeking foreign investors to help it develop what are believed to be the world's third-largest shale gas deposits, which are mainly located in the Patagonian province of Neuquen.

Last year, YPF held talks with Norway's Statoil ASA, Russia's government-controlled gas company, Gazprom, and Chevron Corp., among others.

In December, YPF signed a preliminary agreement with Chevron to spend $1 billion to drill 100 wells in Neuquen, and in a separate deal it agreed to invest $1.5 billion with a company linked to Argentina's Bulgheroni family.

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

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Argentina to Create $2 Billion Oil, Gas Development Fund

BUENOS AIRES -

Argentina's government plans to put up to $2 billion into a new petroleum exploration-and-production fund as the South American nation struggles to become self sufficient in oil and natural gas.

The Argentine Hydrocarbon Fund is authorized to lend money, contribute capital and buy securities issued by oil companies in which the government has an equity stake, according to a resolution published Friday in the government-published Official Bulletin.

The government controls energy companies Enarsa and YPF SA.

It wasn't immediately clear how President Cristina Kirchner will capitalize the fund. Barclays said in a report it thinks the money will come from central bank's foreign currency reserves.

The 2013 budget earmarks almost $8 billion of reserves to pay creditors. But economic growth of just 1.9% last year means that Argentina won't have to pay several billion dollars to investors that own securities whose payouts are linked to the economy's performance.

"We expect, therefore, the treasury to tap reserves and issue a low-coupon hard-currency bond [most likely not marketable] to the central bank," Barclays economist Sebastian Vargas wrote.

A spokeswoman for the Economy Ministry didn't immediately reply to a phone call and email seeking comment.

The central bank, a virtual appendage of the Economy Ministry, is struggling to rebuild its reserves even as a bumper soybean harvest brings billions of export dollars into the country.

On Thursday, those reserves, which the government uses to pay its creditors and buy imported fuels like natural gas, slipped to a six-year low of $39.8 billion. Analysts blame the gradual erosion in reserves on the decline in the value of the bank's gold holdings and persistent capital outflows.

A fire last month that crippled YPF's largest refinery which supplies about 30% of Argentina's domestically produced fuel will force the state controlled company to import significantly more diesel and gasoline this year, putting even more pressure on reserves.

Mrs. Kirchner seized a controlling stake in Argentina's No. 1 oil and gas producer, YPF, from Spain's Repsol SA last year and has tasked the company with reversing years of declining production that have turned Argentina into a net energy importer.

Mrs. Kirchner accused Repsol of decapitalizing YPF through an overly generous dividend policy, which left the firm with scant resources to reinvest in its business. Repsol has denied those accusations and is suing her government for about $10.5 billion in compensation for its YPF shares.

YPF invested 16.48 billion pesos ($3.2 billion) in 2012, an increase of nearly 26% on the year.

The company is also seeking foreign investors to help it develop what are believed to be the world's third-largest shale gas deposits, which are mainly located in the Patagonian province of Neuquen.

Last year, YPF held talks with Norway's Statoil ASA, Russia's government-controlled gas company, Gazprom, and Chevron Corp., among others.

In December, YPF signed a preliminary agreement with Chevron to spend $1 billion to drill 100 wells in Neuquen, and in a separate deal it agreed to invest $1.5 billion with a company linked to Argentina's Bulgheroni family.

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

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Ivanhoe, SBM Team Up in Alliance for Offshore Heavy Oil Development

Ivanhoe Energy and SBM Offshore announced they have formed a global strategic alliance (Alliance), combining their respective expertise to create Floating, Production, Upgrading, Storage and Offloading vessels (FPUSO).

The two companies have combined their respective technologies and experience to produce a first of its kind design for offshore facilities that will economically produce and upgrade heavy oil from offshore fields with crude oil quality down to 10 degree API gravity, or lower.

"We expect this combination of technologies to become the pre-eminent method for producing and upgrading heavy oil at offshore locations around the world," said Michael Wyllie, SBM's chief technology officer.

Industry experts have estimated that offshore heavy oil resources exceed 500 billion barrels recoverable. Given the global abundance of such oil deposits and depleting conventional oil supplies, this Alliance creates significant potential for the offshore heavy oil sector.

SBM is a publicly traded, world leader in providing offshore Floating, Production, Storage, and Offloading (FPSO) vessels. With a market cap of over $3 billion and over 7,000 employees, SBM currently has around 1 million barrels of throughput per day from a fleet of 16 production systems in operation world-wide.

Ivanhoe Energy's Heavy-to-Light (HTL) process is a partial upgrading technology that drastically reduces the viscosity of stranded heavy oil resources and produces a high quality synthetic crude oil that commands greater value from refineries around the world. In addition to creating operating efficiencies, the technology will greatly improve the economics of heavy oil development. HTL's small footprint and modularization capability makes installation on FPSOs possible.

Moreover, by providing a source of lighter oil on the FPUSO, some of this fluid can be re-circulated back to the subsea wells, providing a robust solution to overcome the flow assurance challenges of subsea heavy oil wells. This important feature can be an enabler for heavy oil field developments, especially those in deep water.

"Ivanhoe Energy and SBM collaborated over the last two years to develop this new concept," said Dr. Michael Silverman, Ivanhoe Energy's chief technology officer. "In 2012, with engineering support from AMEC Engineering, we completed the conceptual design of an offshore FPUSO facility that will upgrade up to 60,000 barrels per day."

The Alliance is exploring a number of potential business models and applications. Given the number of existing and potential FPSOs, this Alliance is another important avenue to commercialize the HTL process in the near term.

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Ivanhoe, SBM Team Up in Alliance for Offshore Heavy Oil Development

Ivanhoe Energy and SBM Offshore announced they have formed a global strategic alliance (Alliance), combining their respective expertise to create Floating, Production, Upgrading, Storage and Offloading vessels (FPUSO).

The two companies have combined their respective technologies and experience to produce a first of its kind design for offshore facilities that will economically produce and upgrade heavy oil from offshore fields with crude oil quality down to 10 degree API gravity, or lower.

"We expect this combination of technologies to become the pre-eminent method for producing and upgrading heavy oil at offshore locations around the world," said Michael Wyllie, SBM's chief technology officer.

Industry experts have estimated that offshore heavy oil resources exceed 500 billion barrels recoverable. Given the global abundance of such oil deposits and depleting conventional oil supplies, this Alliance creates significant potential for the offshore heavy oil sector.

SBM is a publicly traded, world leader in providing offshore Floating, Production, Storage, and Offloading (FPSO) vessels. With a market cap of over $3 billion and over 7,000 employees, SBM currently has around 1 million barrels of throughput per day from a fleet of 16 production systems in operation world-wide.

Ivanhoe Energy's Heavy-to-Light (HTL) process is a partial upgrading technology that drastically reduces the viscosity of stranded heavy oil resources and produces a high quality synthetic crude oil that commands greater value from refineries around the world. In addition to creating operating efficiencies, the technology will greatly improve the economics of heavy oil development. HTL's small footprint and modularization capability makes installation on FPSOs possible.

Moreover, by providing a source of lighter oil on the FPUSO, some of this fluid can be re-circulated back to the subsea wells, providing a robust solution to overcome the flow assurance challenges of subsea heavy oil wells. This important feature can be an enabler for heavy oil field developments, especially those in deep water.

"Ivanhoe Energy and SBM collaborated over the last two years to develop this new concept," said Dr. Michael Silverman, Ivanhoe Energy's chief technology officer. "In 2012, with engineering support from AMEC Engineering, we completed the conceptual design of an offshore FPUSO facility that will upgrade up to 60,000 barrels per day."

The Alliance is exploring a number of potential business models and applications. Given the number of existing and potential FPSOs, this Alliance is another important avenue to commercialize the HTL process in the near term.

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Interoil Mulls Share Placing to Fund Colombia Field Development

South America-focused Interoil Exploration & Production announced Wednesday that it is looking at raising around $35 million via a share placing in order to provide it with funds to restart production drilling at its onshore Colombia asset.

Oslo-based Interoil has onshore operations in Colombia and Peru (along with a stake in the Ebony discovery offshore Ghana, West Africa). In Colombia it produced an average of 1,026 barrels of oil per day (net to the company) during December, while production in Peru amounted to 2764 bopd.

Last month, Interoil noted that despite a decline in production from its Colombian asset, on the Puli C block, it "strongly believes" in its intrinsic value and that it would have to raise equity in order to fund a drilling campaign to grow production and reserves at the asset.

Earlier in February, Interoil announced that it had agreed to sell its Altair and COR-6 exploration licenses in Colombia to Trayectoria Oil & Gas for $2 million. The deal also meant the Interoil would be relieved of the costs of exploration commitments that amounted to $26 million.

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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Serica Moves Closer to Columbus Field Development

Junior producer and explorer Serica Energy reported Wednesday that it has issued tender documents for the development of the North Sea's Columbus field, where it is the operator.

Serica said that its field development plan for Columbus provides for the supply of 51.3 million cubic feet of gas per day at its peak, with 3,600 barrels per day of condensate and natural gas liquids (NGLs). In total, the firm estimates that proven and probable reserves of 78 billion cubic feet of gas and 4.8 million barrels of condensate/NGLs can be recovered from the field.

Serica said that it is taking a "significant step" with the development and that tender documents are now being issued to prequalified contractors for the fabrication, installation and hook-up of subsea facilities and for the provision of associated subsea equipment and systems. Field development is scheduled to begin in the second half of this year, with first production targeted for summer 2015.

The field will be developed in parallel with the construction of a bridge-linked platform (BLP) that will be connected to the nearby producing Lomond field via a 5-mile pipeline.

Serica Chairman Tony Craven Walker commented in a company statement:

"The Columbus field is a valuable asset and core to our North Sea interests. Whilst we await certain consents I am very pleased that Serica, and its partners in the field, are able to announce this important step towards field development today. The project will bring much needed gas to the UK but will also provide Serica with a valuable cash flow which will enable it to build on other projects with significant future growth potential."

Oil sector analysts at London-based Northland Capital Partners commented:

"This is a very encouraging announcement… With the tendering process now underway for the Columbus subsea development, Serica can advance its financing options. The company has an existing underused debt facility of $50 million but may look to secure alternative funding. It is likely to require around GBP 50 million ($78 million), although we would expect an update following the tender process."

Serica holds a 32.2-percent interest in the Columbus field.

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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Shell Reassesses Development Plan for North Sea Fram Field

LONDON - Royal Dutch Shell PLC is reassessing its development plan for the Fram oil and gas field in the North Sea following "unexpected" initial drilling results, the company said late Thursday.

Shell had planned to produce an average of 35,000 barrels of oil equivalent a day from the field, with first production targeted within the next three years.

"Development drilling for the Fram field began last year but early assessments have shown unexpected well results. Development drilling will continue for the next several months and the results will inform a revised strategy for Fram," Shell said in a statement posted on its website.

Shell and its partner in the joint venture Esso Exploration & Production UK Ltd., a unit of Exxon Mobil Corp., is continuing to evaluate the potential of the Fram reservoirs, with a view to producing an alternative development plan for the field, Shell said.

Shell has already cancelled an order with SBM NV for a floating production storage and offloading vessel, or FPSO, that was to be used in the Fram project.

The Fram field is located 220 kilometers east of Aberdeen and 50 kilometers west of the median line between the U.K. and Norway in a water depth of approximately 100 meters.

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

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Shell Reassesses Development Plan for North Sea Fram Field

LONDON - Royal Dutch Shell PLC is reassessing its development plan for the Fram oil and gas field in the North Sea following "unexpected" initial drilling results, the company said late Thursday.

Shell had planned to produce an average of 35,000 barrels of oil equivalent a day from the field, with first production targeted within the next three years.

"Development drilling for the Fram field began last year but early assessments have shown unexpected well results. Development drilling will continue for the next several months and the results will inform a revised strategy for Fram," Shell said in a statement posted on its website.

Shell and its partner in the joint venture Esso Exploration & Production UK Ltd., a unit of Exxon Mobil Corp., is continuing to evaluate the potential of the Fram reservoirs, with a view to producing an alternative development plan for the field, Shell said.

Shell has already cancelled an order with SBM NV for a floating production storage and offloading vessel, or FPSO, that was to be used in the Fram project.

The Fram field is located 220 kilometers east of Aberdeen and 50 kilometers west of the median line between the U.K. and Norway in a water depth of approximately 100 meters.

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

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North Carolina Bill Aims to Send Signal on Future Shale Development

North Carolina hopes recent legislation introduced into its general assembly will send a "very clear signal" to oil and gas companies that the state wants shale gas exploration in the state, a state representative told Rigzone in an interview Monday.

State Sen. E.S. "Buck" Newton, the sponsor of Senate Bill (SB) 76, the Domestic Energy Jobs Act, told Rigzone that, while the ban on horizontal drilling and hydraulic fracturing has been lifted, the state hopes to provide certainty to the energy industry by fixing a specific date in which permits for shale gas drilling can be pulled.

Newton, who represents Johnston, Nash and Wilson counties in eastern North Carolina, introduced the bill last week. SB 76, which would authorize the state's Department of Environment and Natural Resources to issue permits for oil and gas exploration and production, including horizontal drilling and hydraulic fracturing, on or after March 1, 2015.

North Carolina officials hope to send a signal in two ways – one, that the legislature is very serious about pursuing shale exploration, and two, that the state is working "with all deliberate and purposeful speed" to get itself ready to issue permits.

Early indicators show North Carolina to have shale gas reserves that may be on the order of the Fayetteville play in Arkansas, with approximately 1.4 million surface acres with shale deposits of an average thickness of 200 feet. North Carolina has three basins with shale potential. The Deep River Basin, the one that is most talked about, has wet gas reserves.

Last year, the General Assembly passed a bill -- over the veto of then Democratic Gov. Beverly Purdue's veto a bill -- that would authorize and legalize hydraulic fracturing and horizontal drilling. General Assembly ratified the Clean Energy and Economic Security Act, which reorganized the state's Mining Commission as the North Carolina Mining and Energy Commission, and directed the commission and other state regulatory agencies to develop a modern regulatory program for the management of oil and gas activity in the state, including horizontal drilling and hydraulic fracturing.

Historically, horizontal drilling had been effectively illegal in the state because of fears that landowners might use horizontal drilling to drill into a neighboring property and steal another landowners water supply, said Bill Weatherspoon, executive director of the North Carolina Petroleum Council, a division of the American Petroleum Institute, in an interview with Rigzone. The law, which dated to the 1940s, forbade drilling to vary more than 3 degrees off center when a well was drilled.

The bill will rewrite existing North Carolina oil and gas legislation in part to modernize the tax structure.

"We wanted to give companies an incentive to come earlier rather than later," Newton commented.

The legislation includes a severance tax, which will be 1 percent in the first year of production, 2.5 percent in the second year, and then will go to a floating rate that would adjust with natural gas prices, ranging from 2.5 percent to 6 percent. Energy industry officials, in early discussions with state officials, really like the proposed severance tax, which gives them flexibility, Newton said.

SB 76 will also attempt to create a one stop shop for pulling permits so that companies will not have to go to different agencies. One thing North Carolina officials want to make clear is that oil and gas companies will not have to pay local taxes or impact fees, other than regular property taxes, to ensure that local governments can't use impact fees as a means to create barriers.

"Not having any experience in the oil and gas industry, we get to draw on the experiences of other states that have been in the industry for a long time and to cherrypick the best of the best," Newton said, adding that the bill not only covers regulatory changes for onshore drilling, but changes that could govern offshore drilling down the road.

"We're trying our best to introduce standards and practices the industry finds helpful and familiar."

The state has no horror stories of environmental problems related to oil and gas, and has a clean slate which state officials hope to keep clean through the use of technological standards, said Weatherspoon.

"The state is trying to take a very calm, study-type approach," said Weatherspoon of the two-year timeframe to accomplish the revisioning of rules and regulations before 2015.

While the counties Newton represents are not among the 10 to 12 counties that have shale gas resources, Newton's familiarity with what oil and gas exploration and development have done for other U.S. state economies – and the need to create jobs and new sources of revenue within North Carolina – prompted him to introduce the legislation.

The legislation is also part of Newton's effort to help North Carolina Gov. Pat McCrory frame his plans to bringing the oil and gas industry for North Carolina. During his election campaign last fall and his inaugural speech, the newly elected governor expressed his desire to get North Carolina into the energy business.

The new Republican-dominated leadership in the state not only is showing interest in developing the state's onshore shale resource, but its offshore interests as well. McCrory already is working with the governors of South Carolina and Virginia to re-open the Atlantic Outer Continental Shelf for exploratory drilling.

Newton doesn't anticipate the bill not passing, due to the fact that McCrory and North Carolina's General Assembly – with Republicans now controlling both for the first time in more than a century – favor bringing oil and gas development to the state. Newton said he hadn't briefed McCrory on SB 76, but saw no reason to think he wouldn't fully back the legislation.

Other than some coal mining activity, the state has not had a significant oil and gas exploration and production industry. North Carolina has been well-known for its tobacco, textiles and furniture-making industries, but the state's economy has been in transition for the past 50 years, with banking, pharmaceutical and life sciences and transportation now major industries in the state.

To date, 125 oil and gas wells have been drilled in the state, but all were capped and abandoned, said Weatherspoon. However, a discovery in near the central North Carolina town of Sanford in Lee County indicated the state could have shale gas potential.

Some leasing activity offshore North Carolina for exploratory drilling did take place in the 1970s, when Mobile Corp. bid $103 million for one offshore tract 40 miles offshore Cape Hatteras, N.C., Weatherspoon noted. While geologists believe there might be a natural gas play offshore the state, drilling never took place due to political opposition.

The effort to update North Carolina's oil and gas regulations are all about jobs and revenue, said Weatherspoon, noting that the state ranks among the top U.S. states in terms of unemployment.

"Politically, there's strong motivation for state officials to do everything they can to create jobs."

Gov. McCrory has made revitalizing the state's economy his No. 1 priority. With the fifth-highest employment rate in the country, McCrory said he hoped that Republicans and Democrats from all areas of the state can work to help turn North Carolina's economy around. These efforts include better matching the talents and expertise of the state's workforce with opportunities available through educational programs.

In December of last year, North Carolina's unemployment rate rose to 9.2 percent from 9.1 percent in November. The state started 2012 with a 10.2 percent unemployment rate.

While early indicators show the state to have good potential for gas reserves, environmentalists have worked hard to play upon the fear of the unknown, said Newton, who pointed to the lively debate between environmentalists and legislators when the bill was introduced.

Newton expects debate to continue, but also believes that people in the state are hungry for economic growth and jobs, noting that, "The more people learn about it, the more excited they are."

Karen Boman has more than 10 years of experience covering the upstream oil and gas sector. Email Karen at kboman@rigzone.com.

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JX Nippon Receives Approval for Mariner Field Development Plan

The UK's Department of Energy and Climate Change (DECC) has approved JX Nippon Exploration and Production's (JXNEPUK) field development plan for the Mariner oil field in the North Sea, the latter's parent – JX Nippon Oil and Gas Exploration – disclosed in a statement late Monday.

The Mariner heavy oil field, one of the four major assets in the UK, is sited in Block 9/11a in the North Sea, 93 miles (150 kilometers) east of Shetlands in a water depth of 360 feet (110 meters). The total investment in the field, including drilling, will be in excess of $7 billion, JX Nippon revealed.

Discovered in 1981, the Mariner field is estimated to have recoverable reserves of more than 250 million barrels of oil and 55,000 barrels of average daily oil production for the first four years.

Life of the oil field is expected to be around 30 years from 2017.

JX Nippon's development plan for the field involves building of a production, drilling and quarters platform along with a floating storage and offloading system. The company is also expecting to drill a significant number of production wells after startup in 2017.

"The Mariner field is one of our major assets in the UK, and we expect that it will contribute to the achievement of our long term daily production goal of 200,000 barrels of oil equivalent by 2020," JX Nippon noted in its statement.

Statoil is the operator of the field with a 65.11 percent interest. JXNEPUK and Cairn Energy hold the remaining stakes at 28.89 percent and 6 percent respectively.

Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@rigzone.com.

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The Philippines Pushes Ahead with Offshore Development Efforts

As the 12th most populous nation in the world, the Philippines is grappling with an uncontrollable energy thirst – common among emerging economies – amid brisk rural-urban migration.

The Philippines will to be home to some 101.2 million people by 2014, up 5.4 million from 2011, according to the country's Commission on Population. The country has a median age of 22.2, and the United Nations has predicted that the working-age population will start becoming particularly prominent in 2015.

With an expected growth rate of around 2 percent per annum, it comes as no surprise to industry watchers that the Philippines has started focusing on developing its petroleum sector. The Philippine Department of Energy (DOE) said it aims to make the country 60 percent self-sufficient in energy by 2024 in a 2011 public address.

In the same year that the DOE committed to raise the country's energy self-sufficiency, the agency launched its largest ever petroleum block contracting round. The fourth Philippine Energy Contracting Round (PERC 4), which was launched June 30, 2011 saw 15 oil blocks – 12 offshore and three onshore – spanning an area of more than 25.5 million acres (10 million hectares) being offered.

The contract areas cover hydrocarbon prolific areas within the basins of the Northwest Palawan, East Palawan, Sulu Sea, Mindoro-Cuyo, Cagayan, Central Luzon and Cotabato.

The country has 27 active service contracts (SC) for oil, according to the DOE. Production is dominated mostly by state-backed Philippine National Oil Company (PNOC) and several large international operators such as Exxon Mobil Corp., Shell Philippines Exploration B.v., Nido Petroleum Ltd., BHP Billiton Petroleum and Galoc Production Company.

The Philippines produced some 1.64 million barrels of oil in 2012, a remarkable achievement considering that the country produced no oil before 2000, according to the DOE. The Galoc field, sited 37 miles (60 kilometers) northwest of Palawan Island, accounted for 1.5 million barrels. The Nido oil field is the second largest producing field, followed by the Matinloc and North Matinloc oil fields.

"Although [the country's] current production of crude oil is quite modest, the Philippine petroleum industry may have significant potential in the disputed area of the South China Sea Basin, which is adjacent to the Northwest Palawan Basin," according to an August 2012 report published by the International Monetary Fund.

With the Philippines government showing a renewed commitment to expediting exploration activity, several companies have responded by ramping up efforts on the exploration and surveying fronts.

Manila moved to challenge China's claim to most of the South China Sea/West Philippine Sea at a Jan. 23 United Nations tribunal.

"This afternoon, the Philippines has taken the step of bringing China before an arbitral tribunal under the 1982 United Nations Convention on the Law of the Sea (UNCLOS) in order to achieve a peaceful and durable solution over the West Philippine Sea," the Philippines Department of Foreign Affairs (DFA) said in a public statement issued the same day.

Several days later, Forum Energy Philippines disclosed that it secured a two-year extension from the DOE to drill two appraisal wells in an offshore petroleum license, SC72, located in territory claimed by China in the South China Sea.

SC72 is sited west of the Palawan Island in the South China Sea, spanning 3,398 square miles (8,800 square kilometers). Results from a 248-square mile (96-square kilometer) 3D seismic survey of the license indicated a mean volume of 3.4 trillion cubic feet of gas-in-place with significant upside, Forum revealed in its 2011 earnings report.

The company plans to start on its second sub-phase work program on SC72, which involves the drilling of two appraisal wells.

Beyond the SC72 acreage, other oil and gas blocks around the Reed Bank are also manifesting probabilities of rich recoverable reserves, the DOE said in a separate 2011 report.

Meanwhile, Nido Petroleum confirmed in a Dec. 19, 2012 statement that it will be drilling in SC63 and SC58 in the North West Palawan Basin. Nido plans to start drilling SC63 by November this year. Industry watchers are expecting the company to announce its drilling program soon.

The block offers numerous drill-ready prospects with multiple potential plays that include the Apribada and Biniray West prospects with 63 and 236 million barrels of oil respectively. The prospects have a gross mean prospective resource of 1.8 trillion cubic feet of gas.

Nido already has an inventory of drill-ready prospects and leads defined on 3D seismic with a drill commitment by January 2014 for SC58. The SC58 holds great potential, given its position as a deepwater block adjacent to the giant Malampaya gas field operated by Shell, Edison Investment Research noted in a December report.

Of the new blocks being offered during PERC 4, there is significant optimism surrounding the East Palawan blocks, also known as areas 10, 11, 13 and 14. Each area could contain gross mean prospective resources of 116 million barrels and 279 billion cubic feet of gas in place, according to the DOE. These blocks border on Borneo and share similar geological characteristics with existing Malaysian fields.

With such optimistic oil and gas reserve figures being made public, the area has since received considerable attention from China – a country which is as eager as the Philippines muscles in on new offshore petroleum opportunities.

"I believe there is a lot more oil and gas in the Philippines given the country's proximity to other producers in the Asia Pacific such as Indonesia and Australia," PNOC's CEO Antonio Cailao said in a statement made to Reuters last year.

"The Philippines sits in the middle of the Asia Pacific region, surrounded by countries with substantial oil and gas assets, yet the Philippines has very low proven reserves. This either means the country is extremely unlucky or it has not yet begun to scratch the surface in terms of exploring its hydrocarbons potential," Cailao later told the Oxford Business Group.

Quintella has reported on the upstream and downstream oil and petrochemicals markets from 2004. Email Quintella at quintella.koh@rigzone.com.

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UK Approves Statoil's Mariner Field Development Plan

OSLO - The U.K. has approved Statoil ASA's field development plan for the $7 billion Mariner heavy oil field, in the North Sea, the U.K.'s largest offshore development in more than a decade, Helge Lund, chief executive of the Norwegian company said Friday.

"We expect to produce about 250 million barrels of oil," said Mr. Lund. "It's a significant investment for us."

The U.K. is a major partner for Statoil, which is in the planning phase for its next U.K. heavy oil field, Bressay, and expects to make an investment decision on that later this year.

"This is a very big project, but there's more to come," said U.K. Energy Secretary Edward Davey in an announcement at the Oslo Energy Forum at Holmenkollen, overlooking the Norwegian capital. "This is a huge and challenging project."

Statoil expects to invest $7 billion in the Mariner field and use pioneering technology to extract the oil, which is much heavier than traditional North Sea oil. Statoil already has experience with heavy oil fields, Mr. Lund said.

"We have done Grane in Norway, which is a heavy oil field, we have done Peregrino very successfully for the last two years in Brazil, so this is a natural extension for us in building a real strong foothold within heavy [oil]," he said.

The Mariner field was discovered in 1982, but production was delayed due to technical challenges in extracting the viscous and dense oil.

"For the technology to exploit it, we've had to wait 30 years, said Mr. Davey. "We've had to wait for Statoil to innovate in the way that you've done, world-leading innovation from Statoil to enable us to exploit these resources. So it's a real tribute to Statoil," said Mr. Davey as he signed the approval letter.

"We have done these projects before, so we are confident on the technology and the execution part as well," said Mr. Lund. "But it is a complex project and a big project, so it requires the best of our teams to make it a success."

It is estimated that the field will produce for 30 years from 2017. Production will reach an output plateau of around 55,000 barrels a day in the 2017-20 period.

Statoil is the operator for Mariner with a 65.11% stake. The field is co-owned by Cairn Energy PLC subsidiary Alba Resources Ltd. with a 6% stake, and JX Nippon Exploration and Production (U.K.) Ltd. with a 28.89% stake.

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

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