KBR Selected for Chevron Lianzi Project

KBR announced that it was selected by Subsea 7 to perform the topsides design for the Chevron Lianzi development project in a unitized offshore zone between the Republic of Congo and the Republic of Angola.

KBR will provide laser scanning of the entire Benguela Belize Lobito Tomboco topsides, FEED verification, detailed engineering and procurement services. The topsides design will include multiple equipment packages. In addition, KBR will provide the necessary assistance during fabrication, installation, pre-commissioning and commissioning phases of the project. This project will be managed from KBR's Houston operating center and its Luanda, Angola office.

"This award reflects KBR's longstanding commitment to executing projects in Africa and provides KBR with a unique opportunity to build a relationship with Subsea 7 as a new client for years to come," said Roy Oelking, Group President, KBR Hydrocarbons. "I am confident through our experience, capabilities and team that we will deliver a successful project to our client."

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KBR Selected for Chevron Lianzi Project

KBR announced that it was selected by Subsea 7 to perform the topsides design for the Chevron Lianzi development project in a unitized offshore zone between the Republic of Congo and the Republic of Angola.

KBR will provide laser scanning of the entire Benguela Belize Lobito Tomboco topsides, FEED verification, detailed engineering and procurement services. The topsides design will include multiple equipment packages. In addition, KBR will provide the necessary assistance during fabrication, installation, pre-commissioning and commissioning phases of the project. This project will be managed from KBR's Houston operating center and its Luanda, Angola office.

"This award reflects KBR's longstanding commitment to executing projects in Africa and provides KBR with a unique opportunity to build a relationship with Subsea 7 as a new client for years to come," said Roy Oelking, Group President, KBR Hydrocarbons. "I am confident through our experience, capabilities and team that we will deliver a successful project to our client."

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Shell Gets Clearance for Chinese Shale Project

BEIJING - Royal Dutch Shell PLC said Tuesday it has received approval from the Chinese government for the company's first shale-gas production-sharing contract in China, a significant milestone as the country looks to tap potentially massive unconventional gas reserves and achieve ambitious shale-gas production targets.

Li Lusha, a spokeswoman for Shell, said the Chinese government has approved the Anglo-Dutch company's plan to explore, develop and produce shale gas with partner China National Petroleum Corp. in the Fushun-Yongchuan block in the Sichuan Basin.

Word of the government's approval comes more than a year after Shell and state-oil giant CNPC said they reached a deal in March 2012 to develop the shale reserves. The companies haven't disclosed details of the contract, but the approval suggests authorities in Beijing have developed the regulatory framework needed to spur wider international investment in developing its shale reserves.

China is looking to replicate a boom in North American natural-gas production, which has begun reshaping global energy markets. Chinese companies need international competitors such as Shell to lend technology and operational expertise in extracting the gas trapped in shale rock formations.

Shell Chief Executive Peter Voser said in Beijing on Tuesday that the company is gearing up for what he described as a "significant drilling season in 2013 and in 2014."

Mr. Voser said Shell and CNPC are continuing to explore which drilling locations are best-suited for long-term development and production, and said the company is committed to helping Beijing achieve its shale-gas production targets.

China has set a target of producing some 6.5 billion cubic meters a year of shale gas by 2015 and as much as 100 billion cubic meters a year by 2020, up from virtually zero in 2012. That is a target some analysts have been skeptical the country can achieve.

The U.S. Energy Information Administration has said China has an estimated 1,275 trillion cubic feet, or 36 trillion cubic meters, of technically recoverable shale-gas reserves, more than Canada and the U.S. combined. If extracted, unconventional reserves could help alter China's energy profile, which has become increasingly reliant on imported oil and polluting coal to power its economic growth.

Such massive estimates are sending Shell's international rivals into the market as well. Chevron Corp., for example, has drilled at least one exploratory well in China and has plans for more, but company executives have cited a shortage of infrastructure and geological data as among the reasons it expects slower progress compared with North America.

Soaring gas production in North America has helped lower fuel prices for chemical production and other industrial activity. In also has raised the prospect of liquefied-natural-gas exports from Canada and the U.S. during the coming decade. Mr. Voser reiterated earlier estimates that U.S. exports of LNG might hit 50 million to 60 million tons a year, but said he expects much of the U.S. gas to remain at home to be used as a replacement for coal in power generation and to build up domestic industry.

"I think LNG will be exported out of the United States but I see the volume as being limited," he said. 

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

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Shell Gets Clearance for Chinese Shale Project

BEIJING - Royal Dutch Shell PLC said Tuesday it has received approval from the Chinese government for the company's first shale-gas production-sharing contract in China, a significant milestone as the country looks to tap potentially massive unconventional gas reserves and achieve ambitious shale-gas production targets.

Li Lusha, a spokeswoman for Shell, said the Chinese government has approved the Anglo-Dutch company's plan to explore, develop and produce shale gas with partner China National Petroleum Corp. in the Fushun-Yongchuan block in the Sichuan Basin.

Word of the government's approval comes more than a year after Shell and state-oil giant CNPC said they reached a deal in March 2012 to develop the shale reserves. The companies haven't disclosed details of the contract, but the approval suggests authorities in Beijing have developed the regulatory framework needed to spur wider international investment in developing its shale reserves.

China is looking to replicate a boom in North American natural-gas production, which has begun reshaping global energy markets. Chinese companies need international competitors such as Shell to lend technology and operational expertise in extracting the gas trapped in shale rock formations.

Shell Chief Executive Peter Voser said in Beijing on Tuesday that the company is gearing up for what he described as a "significant drilling season in 2013 and in 2014."

Mr. Voser said Shell and CNPC are continuing to explore which drilling locations are best-suited for long-term development and production, and said the company is committed to helping Beijing achieve its shale-gas production targets.

China has set a target of producing some 6.5 billion cubic meters a year of shale gas by 2015 and as much as 100 billion cubic meters a year by 2020, up from virtually zero in 2012. That is a target some analysts have been skeptical the country can achieve.

The U.S. Energy Information Administration has said China has an estimated 1,275 trillion cubic feet, or 36 trillion cubic meters, of technically recoverable shale-gas reserves, more than Canada and the U.S. combined. If extracted, unconventional reserves could help alter China's energy profile, which has become increasingly reliant on imported oil and polluting coal to power its economic growth.

Such massive estimates are sending Shell's international rivals into the market as well. Chevron Corp., for example, has drilled at least one exploratory well in China and has plans for more, but company executives have cited a shortage of infrastructure and geological data as among the reasons it expects slower progress compared with North America.

Soaring gas production in North America has helped lower fuel prices for chemical production and other industrial activity. In also has raised the prospect of liquefied-natural-gas exports from Canada and the U.S. during the coming decade. Mr. Voser reiterated earlier estimates that U.S. exports of LNG might hit 50 million to 60 million tons a year, but said he expects much of the U.S. gas to remain at home to be used as a replacement for coal in power generation and to build up domestic industry.

"I think LNG will be exported out of the United States but I see the volume as being limited," he said. 

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

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Empyrean Energy Ups Stake in California Project

Empyrean Energy Plc announced it has increased its working interest in the Eagle Oil Pool Development Project in the San Joaquin Basin, California to 57.2126 percent.

The increase in working interest has resulted from previous partner FAR Limited deciding to surrender its interest. FAR Limited has stated the reason for surrendering its interest in the Eagle Oil Pool Development Project along with another non-core asset is to focus operations and exploration efforts on its African assets. There is no direct cost associated with the additional working interest other than the nominal costs of assignment and recording. Empyrean will pay a proportionately higher share (57.2126 percent) of future joint venture costs.

An independent expert has estimated that the Eagle Oil Pool Development Project could contain a P50 (probability 50 percent unrisked) reserve of 7.1 million barrels of recoverable oil and 12.3 billion cubic feet of associated gas, with the P10 assessment estimated at 22.7 million barrels of oil and 22.7 billion cubic feet of associated gas. The Project is a structural-stratigraphic trap play targeting the Eocene aged Gatchell sands. The Project covers approximately 5,160 gross acres with a discovered yet undeveloped oil accumulation. The operator of the Project is TSX-V and ASX-listed Strata X Energy, of Denver, Colorado.

Recent exploration efforts by operators nearby to the Project have targeted other formations including the Kreyenhagen Shale and Monterey Shale. These exploration efforts are being monitored by Strata X Energy to determine if targets in addition to the Gatchell sands should be included in future exploration and testing efforts. The Company currently believes, based on existing results and data, that the Gatchell sands remain the priority target for future testing with potential for the Monterey Shale to be included as a secondary objective. Stratigraphic trap plays such as the Eagle Ford Shale play in Texas, within which the Company's Sugarloaf Project is situated, have become highly sought after in the USA due to modern day advancements in drilling and completion technology. These advancements have allowed unconventional hydrocarbon plays to achieve highly valued production from formations that were previously thought to be either too technically difficult or too expensive to develop.

Strata X Energy has indicated that a vertical well test of the Gatchell sands has merit, subject to the results of nearby exploration wells. Further discussions need to take place with Strata X Energy before any future operational plans are finalized.

"This increased working interest at the Eagle Oil Pool Development Project gives Empyrean greater leverage and flexibility in the project. Given the renewed activity in the San Joaquin Basin we are happy to have been able to add significantly to our working interest in the project at essentially no cost," Empyrean CEO Tom Kelly said.

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Total Makes Final Investment Decision on Moho Nord Project

Total reported Friday it has made a final investment decision (FID) for the Moho Nord development in the Moho Bolindo license offshore Republic of Congo.

First oil is expected in 2015 from the $10 billion Moho Nord development, which will consist of the Moho-Bilondo Phase 1bis and Moho Nord project. Oil output from the development is expected to reach 140,000 barrels of oil equivalent per day (boepd) in 2017. The FID follows on the Moho Bilondo Phase 1E project, which came on stream in 2008. Total also announced engineering, procurement and construction awards for the project.

The Moho Nord project will target additional reserves in the southern portion of the Phase 1bis license and new reserves in the northern part of the license. Total estimates the additional reserves at approximately 485 million barrels of oil equivalent.

First oil is expected to be achieved from the Phase 1 bis project in 2015 and first oil from the Moho Nord project in 2016, partner Chevron Corp. reported Friday.

As part of the Phase 1bis development, Total will tie back 11 subsea wells in the Miocene to the existing floating production unit (FPU) on location at the field. The FPU's processing capacity will be increased by 40,000 boepd.

Total will also drill 17 subsea wells targeting Miocene reservoirs for the Moho Nord development. These wells will be tied back to a new FPU. Seventeen more subsea wells targeting Albian reservoirs will be developed from a newbuild tension leg platform. The new production will be processed on the FPU, which will have 100,000 boepd capacity, before being exported via a new 50-mile pipeline to the onshore Djeno terminal.

The company has taken measures to limit the project's environmental impact, including the elimination of flaring under normal operating conditions and reinjecting all produced water. Total will also promote the use of local content in the project by encouraging development of the regional industrial base.

Moho Nord is located approximately 46 miles (75 kilometers) from Pointe-Noire and 15.5 miles (25 kilometers) west of N'Kossa in 1,476 feet to 3,937 feet (450 meters to 1,200 meters) of water.

Total’s subsidiary Total E&P Congo is operator of the Moho Bilondo license with a 53.5-percent interest. Partners include state-owned Societe Nationale des Petroles du Congo with 15 percent and Chevron Overseas Congo with 31.5 percent.

Total E&P Congo operates 10 of the 22 fields developed in the Republic of Congo, accounting for almost 60 percent of the national's oil output. Total's net equity production averaged 113,000 boepd last year.

Most of Total's oil production comes from the deepwater Moho-Bolindo license and the Nkossa oil field. The company also produced 30 million cubic feet per day of natural gas in 2011, which came from associated gas from its oil fields, according to a January 2013 analysis from the U.S. Energy Information Administration.

Congo's oil production rebounded from 2008 to 2010 thanks to new projects coming online, mainly from Congo's first deepwater oil field, Moho-Bilondo.

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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Total Makes Final Investment Decision on Moho Nord Project

Total reported Friday it has made a final investment decision (FID) for the Moho Nord development in the Moho Bolindo license offshore Republic of Congo.

First oil is expected in 2015 from the $10 billion Moho Nord development, which will consist of the Moho-Bilondo Phase 1bis and Moho Nord project. Oil output from the development is expected to reach 140,000 barrels of oil equivalent per day (boepd) in 2017. The FID follows on the Moho Bilondo Phase 1E project, which came on stream in 2008. Total also announced engineering, procurement and construction awards for the project.

The Moho Nord project will target additional reserves in the southern portion of the Phase 1bis license and new reserves in the northern part of the license. Total estimates the additional reserves at approximately 485 million barrels of oil equivalent.

First oil is expected to be achieved from the Phase 1 bis project in 2015 and first oil from the Moho Nord project in 2016, partner Chevron Corp. reported Friday.

As part of the Phase 1bis development, Total will tie back 11 subsea wells in the Miocene to the existing floating production unit (FPU) on location at the field. The FPU's processing capacity will be increased by 40,000 boepd.

Total will also drill 17 subsea wells targeting Miocene reservoirs for the Moho Nord development. These wells will be tied back to a new FPU. Seventeen more subsea wells targeting Albian reservoirs will be developed from a newbuild tension leg platform. The new production will be processed on the FPU, which will have 100,000 boepd capacity, before being exported via a new 50-mile pipeline to the onshore Djeno terminal.

The company has taken measures to limit the project's environmental impact, including the elimination of flaring under normal operating conditions and reinjecting all produced water. Total will also promote the use of local content in the project by encouraging development of the regional industrial base.

Moho Nord is located approximately 46 miles (75 kilometers) from Pointe-Noire and 15.5 miles (25 kilometers) west of N'Kossa in 1,476 feet to 3,937 feet (450 meters to 1,200 meters) of water.

Total’s subsidiary Total E&P Congo is operator of the Moho Bilondo license with a 53.5-percent interest. Partners include state-owned Societe Nationale des Petroles du Congo with 15 percent and Chevron Overseas Congo with 31.5 percent.

Total E&P Congo operates 10 of the 22 fields developed in the Republic of Congo, accounting for almost 60 percent of the national's oil output. Total's net equity production averaged 113,000 boepd last year.

Most of Total's oil production comes from the deepwater Moho-Bolindo license and the Nkossa oil field. The company also produced 30 million cubic feet per day of natural gas in 2011, which came from associated gas from its oil fields, according to a January 2013 analysis from the U.S. Energy Information Administration.

Congo's oil production rebounded from 2008 to 2010 thanks to new projects coming online, mainly from Congo's first deepwater oil field, Moho-Bilondo.

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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View the original article here

Total Makes Final Investment Decision on Moho Nord Project

Total reported Friday it has made a final investment decision (FID) for the Moho Nord development in the Moho Bolindo license offshore Republic of Congo.

First oil is expected in 2015 from the $10 billion Moho Nord development, which will consist of the Moho-Bilondo Phase 1bis and Moho Nord project. Oil output from the development is expected to reach 140,000 barrels of oil equivalent per day (boepd) in 2017. The FID follows on the Moho Bilondo Phase 1E project, which came on stream in 2008. Total also announced engineering, procurement and construction awards for the project.

The Moho Nord project will target additional reserves in the southern portion of the Phase 1bis license and new reserves in the northern part of the license. Total estimates the additional reserves at approximately 485 million barrels of oil equivalent.

First oil is expected to be achieved from the Phase 1 bis project in 2015 and first oil from the Moho Nord project in 2016, partner Chevron Corp. reported Friday.

As part of the Phase 1bis development, Total will tie back 11 subsea wells in the Miocene to the existing floating production unit (FPU) on location at the field. The FPU's processing capacity will be increased by 40,000 boepd.

Total will also drill 17 subsea wells targeting Miocene reservoirs for the Moho Nord development. These wells will be tied back to a new FPU. Seventeen more subsea wells targeting Albian reservoirs will be developed from a newbuild tension leg platform. The new production will be processed on the FPU, which will have 100,000 boepd capacity, before being exported via a new 50-mile pipeline to the onshore Djeno terminal.

The company has taken measures to limit the project's environmental impact, including the elimination of flaring under normal operating conditions and reinjecting all produced water. Total will also promote the use of local content in the project by encouraging development of the regional industrial base.

Moho Nord is located approximately 46 miles (75 kilometers) from Pointe-Noire and 15.5 miles (25 kilometers) west of N'Kossa in 1,476 feet to 3,937 feet (450 meters to 1,200 meters) of water.

Total’s subsidiary Total E&P Congo is operator of the Moho Bilondo license with a 53.5-percent interest. Partners include state-owned Societe Nationale des Petroles du Congo with 15 percent and Chevron Overseas Congo with 31.5 percent.

Total E&P Congo operates 10 of the 22 fields developed in the Republic of Congo, accounting for almost 60 percent of the national's oil output. Total's net equity production averaged 113,000 boepd last year.

Most of Total's oil production comes from the deepwater Moho-Bolindo license and the Nkossa oil field. The company also produced 30 million cubic feet per day of natural gas in 2011, which came from associated gas from its oil fields, according to a January 2013 analysis from the U.S. Energy Information Administration.

Congo's oil production rebounded from 2008 to 2010 thanks to new projects coming online, mainly from Congo's first deepwater oil field, Moho-Bilondo.

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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Statoil Gives Go-Ahead to Smorbukk South Extension Project

Statoil reported Wednesday that, along with its partners, it has decided to go ahead with the Smørbukk South Extension project on the Åsgard development, offshore Norway.

The extension holds estimated recoverable reserves of 16.5 million barrels of oil equivalent and will be developed with a new subsea template that will be connected to existing infrastructure in the area.

Recovered gas will be re-injected into the reservoir in order to maintain pressure as oil is drained out of it. The field will be connected to the Åsgard A FPSO installation.

Astrid Helga Jørgenvåg, Statoil's asset owner for Åsgard, commented in a company statement:

"We've matured a profitable project out of a discovery from 1985. Experience from Åsgard operations, existing infrastructure and a bit of patience have contributed to an investment decision for this project.

"In addition we will consider the use of a new well technology that will increase the recovery from this type of reservoir. Smørbukk South Extension is a strategically important project that emphasizes our ambitions to increase recovery from mature areas."

The extension project will use standard equipment, and Statoil has already made investments to minimize the time from project sanction to production start-up, the firm said.

Statoil will now award several contracts for the development, it added.

Drilling operations are planned to begin in early 2015, with production start-up planned for September 2015. Total investments for the project are estimated to be around $595 million.

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Statoil Gives Go-Ahead to Smorbukk South Extension Project

Statoil reported Wednesday that, along with its partners, it has decided to go ahead with the Smørbukk South Extension project on the Åsgard development, offshore Norway.

The extension holds estimated recoverable reserves of 16.5 million barrels of oil equivalent and will be developed with a new subsea template that will be connected to existing infrastructure in the area.

Recovered gas will be re-injected into the reservoir in order to maintain pressure as oil is drained out of it. The field will be connected to the Åsgard A FPSO installation.

Astrid Helga Jørgenvåg, Statoil's asset owner for Åsgard, commented in a company statement:

"We've matured a profitable project out of a discovery from 1985. Experience from Åsgard operations, existing infrastructure and a bit of patience have contributed to an investment decision for this project.

"In addition we will consider the use of a new well technology that will increase the recovery from this type of reservoir. Smørbukk South Extension is a strategically important project that emphasizes our ambitions to increase recovery from mature areas."

The extension project will use standard equipment, and Statoil has already made investments to minimize the time from project sanction to production start-up, the firm said.

Statoil will now award several contracts for the development, it added.

Drilling operations are planned to begin in early 2015, with production start-up planned for September 2015. Total investments for the project are estimated to be around $595 million.

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Novatek Gets Go-Ahead for Arctic LNG Gas Project

MOSCOW - Russia's largest independent gas producer OAO Novatek said Wednesday it has received environmental approval for a liquefied natural gas project in the Arctic and that construction will begin soon.

Yamal LNG, a joint project with France's Total SA, is expected to produce its first gas at the start of 2017, with output eventually reaching 16.5 million metric tons per year.

Last week, Novatek said it was in advanced talks with a number of potential clients, including China and India on selling LNG supplies from the Arctic project.

Novatek has been banking on Russia's government ending state-controlled OAO Gazprom's monopoly on gas exports and allowing other firms to sell LNG on foreign markets, which are more lucrative than Russia's. Last month, President Vladimir Putin instructed government officials to consider liberalizing exports to boost Russia's share of the global LNG market from 3.6%.

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

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Statoil Gives Go-Ahead to Smorbukk South Extension Project

Statoil reported Wednesday that, along with its partners, it has decided to go ahead with the Smørbukk South Extension project on the Åsgard development, offshore Norway.

The extension holds estimated recoverable reserves of 16.5 million barrels of oil equivalent and will be developed with a new subsea template that will be connected to existing infrastructure in the area.

Recovered gas will be re-injected into the reservoir in order to maintain pressure as oil is drained out of it. The field will be connected to the Åsgard A FPSO installation.

Astrid Helga Jørgenvåg, Statoil's asset owner for Åsgard, commented in a company statement:

"We've matured a profitable project out of a discovery from 1985. Experience from Åsgard operations, existing infrastructure and a bit of patience have contributed to an investment decision for this project.

"In addition we will consider the use of a new well technology that will increase the recovery from this type of reservoir. Smørbukk South Extension is a strategically important project that emphasizes our ambitions to increase recovery from mature areas."

The extension project will use standard equipment, and Statoil has already made investments to minimize the time from project sanction to production start-up, the firm said.

Statoil will now award several contracts for the development, it added.

Drilling operations are planned to begin in early 2015, with production start-up planned for September 2015. Total investments for the project are estimated to be around $595 million.

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Talisman Scraps Yme Project after SBM deal

Dutch oilfield services firm SBM Offshore has settled its dispute over the Yme project, offshore Norway. The firm has agreed to pay to Talisman Energy Norge and its partners an additional $270 million, on top of an earlier payment of $200 million, to cover the decommissioning of the abandoned Yme platform.

Talisman and its partners have seen a number of delays, as well as safety issues, at Yme. This included an evacuation of 140 workers from the platform in July 2012 due to structural concerns.

Once it has received the settlement payment, Talisman said it will complete the work necessary to ensure the safe re-manning of the platform and will then remove the MOPU (mobile offshore production unit), which will subsequently be scrapped.

Paul Warwick, Talisman's executive vice-president for Europe-Atlantic, commented in a statement:

"Delays to first production on the Yme project have been a great disappointment to the Yme joint venture partners. Recent analysis has concluded that a new topsides solution is needed in order to develop the Yme field. The arrangement with SBM Offshore allows the Yme joint venture partners to continue to evaluate options for the field."

Meanwhile, SBM noted that the settlement paves the way for it to carry out a fundraising exercise required to help balance the firm's books.

"Today we have resolved the legacy difficulties of Yme at an agreed cost, bringing an end to a period of significant uncertainty for the company," SBM director Sietze Hepkema said.

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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Talisman Scraps Yme Project after SBM deal

Dutch oilfield services firm SBM Offshore has settled its dispute over the Yme project, offshore Norway. The firm has agreed to pay to Talisman Energy Norge and its partners an additional $270 million, on top of an earlier payment of $200 million, to cover the decommissioning of the abandoned Yme platform.

Talisman and its partners have seen a number of delays, as well as safety issues, at Yme. This included an evacuation of 140 workers from the platform in July 2012 due to structural concerns.

Once it has received the settlement payment, Talisman said it will complete the work necessary to ensure the safe re-manning of the platform and will then remove the MOPU (mobile offshore production unit), which will subsequently be scrapped.

Paul Warwick, Talisman's executive vice-president for Europe-Atlantic, commented in a statement:

"Delays to first production on the Yme project have been a great disappointment to the Yme joint venture partners. Recent analysis has concluded that a new topsides solution is needed in order to develop the Yme field. The arrangement with SBM Offshore allows the Yme joint venture partners to continue to evaluate options for the field."

Meanwhile, SBM noted that the settlement paves the way for it to carry out a fundraising exercise required to help balance the firm's books.

"Today we have resolved the legacy difficulties of Yme at an agreed cost, bringing an end to a period of significant uncertainty for the company," SBM director Sietze Hepkema said.

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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Endeavor to Advise Petrobras on Papa Terra Project

Endeavor Management announced Monday that Petrobras has retained the Houston-based consulting firm to provide third party review and advisory services on the Papa Terra project. Endeavor will work with the Papa-Terra Integrated Project Team to identify potential improvements to the drilling and completion program of all wells to be drilled with the new Tension Leg Wellhead Platform (TLWP) and Tender Assisted Drilling Rig (TAD) for the Papa Terra field. Endeavor Management will also evaluate the schedule status of the TAD semi and TLWP drilling package.

The Papa Terra field is a heavy crude oil field located in the Campos Basin offshore Brazil. Bruce Crager, executive vice president of Endeavor Management, stated, "This is a major project for Petrobras and is their first use of a TLWP and tender assisted drilling unit. We are pleased to have been selected to join Petrobras on the Integrated Project Team along with personnel from Chevron, who are a partner in the Papa Terra field."

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Endeavor to Advise Petrobras on Papa Terra Project

Endeavor Management announced Monday that Petrobras has retained the Houston-based consulting firm to provide third party review and advisory services on the Papa Terra project. Endeavor will work with the Papa-Terra Integrated Project Team to identify potential improvements to the drilling and completion program of all wells to be drilled with the new Tension Leg Wellhead Platform (TLWP) and Tender Assisted Drilling Rig (TAD) for the Papa Terra field. Endeavor Management will also evaluate the schedule status of the TAD semi and TLWP drilling package.

The Papa Terra field is a heavy crude oil field located in the Campos Basin offshore Brazil. Bruce Crager, executive vice president of Endeavor Management, stated, "This is a major project for Petrobras and is their first use of a TLWP and tender assisted drilling unit. We are pleased to have been selected to join Petrobras on the Integrated Project Team along with personnel from Chevron, who are a partner in the Papa Terra field."

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Japex to Buy 10% of Petronas Canada LNG Project

TOKYO - Upstream energy company Japan Petroleum Exploration Co. said Monday it has agreed with Petroliam Nasional Berhad, or Petronas to buy 10% of a Canada liquefied natural gas venture and shale gas project controlled by the Malaysian state-owned energy company.

Its preliminary agreement to join the British Columbia Pacific Northwest LNG scheme and buy into the associated North Montney gas development is the latest in a string of moves by Japanese energy companies seeking to line up relatively cheap gas in North America to ship home to meet rising LNG demand caused by a shift away from nuclear power.

The Japanese upstream company, also known as Japex, will find ways to price the LNG at "reasonable levels," said Man Saito, Japex's Managing Director told reporters.

Mr. Saito said Japex is considering using more than one benchmark to price the gas it exports from Canada, but didn't give details.

Once finalized, Japex would receive 1.2 million metric tons of LNG annually from the project. He didn't disclose the price Japex will pay.

The Pacific Northwest LNG export terminal project in British Columbia was acquired by Petronas last year as part of its $5.2 billion purchase of Canada's Progress Energy Resources Corp.

The 12 million tons-a-year terminal, to be located on the Lelu island in the port city of Prince Rupert, will cost up to C$11 billion ($10.7 billion) to build, Petronas has said.

Petronas aims to make a final investment decision on it by the end of 2014 and start commercial operations by the end of 2018.

It is just one of several energy companies building LNG export terminals in Canada and the U.S. to create outlets for surplus gas caused by shale-drilling technology that has unlocked massive new reserves.

The oversupply has caused North American gas prices to fall to below $2 a million British thermal units earlier last year, compared with as much as $18/MMBtu in Asia, where LNG is priced against oil.

Royal Dutch Shell Plc is spearheading one LNG venture at Kitimat, some 200 kilometers from the Petronas one, working with several Asian partners including Japan's Mitsubishi Corp.

Another LNG project is a 50-50 joint venture by Chevron Corp. and Apache Corp, also at Kitimat.

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

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Japex to Buy 10% of Petronas Canada LNG Project

TOKYO - Upstream energy company Japan Petroleum Exploration Co. said Monday it has agreed with Petroliam Nasional Berhad, or Petronas to buy 10% of a Canada liquefied natural gas venture and shale gas project controlled by the Malaysian state-owned energy company.

Its preliminary agreement to join the British Columbia Pacific Northwest LNG scheme and buy into the associated North Montney gas development is the latest in a string of moves by Japanese energy companies seeking to line up relatively cheap gas in North America to ship home to meet rising LNG demand caused by a shift away from nuclear power.

The Japanese upstream company, also known as Japex, will find ways to price the LNG at "reasonable levels," said Man Saito, Japex's Managing Director told reporters.

Mr. Saito said Japex is considering using more than one benchmark to price the gas it exports from Canada, but didn't give details.

Once finalized, Japex would receive 1.2 million metric tons of LNG annually from the project. He didn't disclose the price Japex will pay.

The Pacific Northwest LNG export terminal project in British Columbia was acquired by Petronas last year as part of its $5.2 billion purchase of Canada's Progress Energy Resources Corp.

The 12 million tons-a-year terminal, to be located on the Lelu island in the port city of Prince Rupert, will cost up to C$11 billion ($10.7 billion) to build, Petronas has said.

Petronas aims to make a final investment decision on it by the end of 2014 and start commercial operations by the end of 2018.

It is just one of several energy companies building LNG export terminals in Canada and the U.S. to create outlets for surplus gas caused by shale-drilling technology that has unlocked massive new reserves.

The oversupply has caused North American gas prices to fall to below $2 a million British thermal units earlier last year, compared with as much as $18/MMBtu in Asia, where LNG is priced against oil.

Royal Dutch Shell Plc is spearheading one LNG venture at Kitimat, some 200 kilometers from the Petronas one, working with several Asian partners including Japan's Mitsubishi Corp.

Another LNG project is a 50-50 joint venture by Chevron Corp. and Apache Corp, also at Kitimat.

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

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2H Offshore Wins Detailed Design Project with LLOG

2H Offshore Inc., an Acteon company, has recently been awarded a Steel Catenary Riser (SCR) detailed design project with LLOG Exploration Company. The SCRs will be the first attached to the Exmar OPTI-11000 semisubmersible.

The scope of work includes the provision of detailed design of the production and export SCRs tied back to the Exmar OPTI-11000 semisubmersible for the Delta House field development. LLOG is currently developing the Marmalard and SOB2 fields in the Mississippi Canyon area of the Gulf of Mexico which will both be tied back to the Delta House Floating Production Facility located in MC Block 254 in approximately 4,500 feet of water.

"2H has supported and provided riser engineering services to Exmar since 2005 in their development of the OPTI-EX semisubmersible which was used to develop LLOG's Who Dat Field," said 2H Offshore Inc. Vice President David Walters. "We look forward to providing our expertise in detailed design on the first SCRs attached to the OPTI-11000 semi-submersible"

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Senex Starts Fracture Stimulation Project Onshore Southern Cooper Basin

Senex Energy, the operator of the onshore PEL 115 permit, disclosed Wednesday that it has started fracture stimulation operations at the Kingston Rule-1 unconventional gas exploration well in the Southern Cooper basin.

The company has also started work over and zone perforation operations at the Hornet-1 well sited in the same permit.
The fracture stimulation program over the wells will be completed over a two-month period, with flow testing to continue into June this year.

Kingston Rule-1 was drilled by Senex late last year and intersected 174 feet (53 meters)of net gas pay, with 30 feet (nine meters) in the Epsilon Formation and 144 feet (44 meters) in the Patchawarra Formation tight gas sands. The well also intersected 492 feet (150 meters) of Murteree and Roseneath Shales. Mud logs confirmed the presence of liquid hydrocarbons throughout the Permian section.

The multi-stage fracture stimulation of Kingston Rule-1 targets tight gas sands within the Patchawarra and Epsilon formations. At present, three of a total six zones have been fracture stimulated with bridge plugs set between each zone. The forward operation will be to fracture stimulate the remaining three zones.

Hornet-1 was drilled by Victoria Petroleum in 2004 and intersected gas shows in the Epsilon Formation and 91 feet (28 meters) of net gas pay in the Patchawarra Formation. Two drill stem tests were conducted on Hornet-1 and resulted in gas flowing to surface. The multi-stage stimulation of Hornet-1 will target additional gas sands within the Patchawarra Formation.

As Hornet-1 was a pre-existing well, a work over rig was brought onto the site, to prepare the well for fracture stimulation and perforate the zones in advance of the fracture stimulation equipment arriving onsite.

"We are very pleased that the stimulation of Kingston Rule-1 has commenced and look forward to evaluating the results, along with those from Hornet-1, over the coming months. There is a lot of interest in the unconventional gas potential which is believed to exist in the Cooper Basin and we are excited to be part of it," Orca Energy's Executive Director, Greg Bandy, said in a statement.

Senex has an 80 percent interest in both of the wells, while Ocra Energy holds the remaining 20 percent stake.

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