Halliburton Awarded Multiple Statoil Contracts For North Sea Drilling
Halliburton (NYSE:HAL) has been awarded several contracts by Statoil (NYSE:STO) to provide services for two high-pressure and high-temperature drills off the shore of Norway's coast in the North Sea.
Halliburton estimates the value of these multiyear deals has the potential to exceed $200 million.
Under the contracts, Halliburton will provide directional drilling, logging-while-drilling, cementing, drilling fluids, and completion equipment and related services at the Gudrun and Brynhild fields.
Drilling is scheduled to begin in the third quarter of 2011.
Wednesday, April 6, 2011
Transocean Execs Donating Portion of Bonuses To Victims (RIG)
Transocean Execs Donating Portion of Bonuses To Victims (RIG)
Transocean's (NYSE:RIG) senior management team said last night they would donate the portion of their bonuses they earned from getting good marks on internal safety metrics to the families of the 11 men killed in last years Deepwater Horizon tragedy.
The donation will be made to the Deepwater Horizon Memorial Fund, established last year in the wake of the disaster, for donations by coworkers and friends to help the families of the 11 men lost in the accident.
The non-deductible sum will exceed $250,000. More than $1.6 million has already been distributed to the families to date.
"Nothing is more important to Transocean than our people, and it was never our intent to diminish the effect the Macondo tragedy has had on those who lost loved ones," said Steven Newman, chief executive, announcing the bonus donations, in a news release on Tuesday. "The executive team made this decision because we believe it is the right thing to do."
The donation will be made to the Deepwater Horizon Memorial Fund, established last year in the wake of the disaster, for donations by coworkers and friends to help the families of the 11 men lost in the accident.
The non-deductible sum will exceed $250,000. More than $1.6 million has already been distributed to the families to date.
"Nothing is more important to Transocean than our people, and it was never our intent to diminish the effect the Macondo tragedy has had on those who lost loved ones," said Steven Newman, chief executive, announcing the bonus donations, in a news release on Tuesday. "The executive team made this decision because we believe it is the right thing to do."
Kuwait eyes LNG project Down Under
Kuwait eyes LNG project Down Under
Apr 7, 2011
Tamsin Carlisl
KUWAIT CITY // The Kuwait Foreign Petroleum Exploration Company (Kufpec) expects D-Day in August for a final investment decision on its participation in a A$20 billion (Dh75.83bn) Australian liquefied natural gas (LNG) project.
Development of the Wheatstone LNG project off the coast of north-west Australia is slated to start next year, Ali al Shammari, the deputy managing director of Kufpec, told a conference in the Kuwaiti capital.
Kufpec, which is the Kuwaiti government's overseas oil and gas investment arm, has joined forces with the US oil and gas producer Apache to explore and develop gas prospects including the Julimar and Brunello fields off the north-west coast of Australia. The Kufpec-Apache partnership's licences are for areas close to the Wheatstone gasfield, operated by the US oil major Chevron, and the Gorgon and Pluto fields, where two other large LNG projects are under development.
Kuwait, which started importing LNG in 2009, is expected to do so until it boosts production from its own gasfields.
Kimimasa Mayama / Bloomberg News
"We selected Australia as an exploration focus due to stable fiscal terms and high geological potential," Mr al Shammari said.
In October 2009, Kufpec and Apache signed an agreement with Chevron to supply gas to Wheatstone LNG in return for equity stakes in the project. Kufpec now holds a 7 per cent interest in the project, after the South Korean utility Kogas also signed up as an equity partner.
"Wheatstone is a potential game-changer for Apache, unlocking 2.1 trillion cubic feet of gas reserves at two of Apache's largest discoveries and generating steady production for 15 years at prices pegged to world oil markets," G Steven Farris, the chairman and chief executive of Apache, said at the 2009 signing ceremony.
On completion, the planned LNG plant at Ashburton North, in the state of Western Australia, will have an annual production capacity of 15 million tonnes of the super-chilled fuel. The first phase of the project, already under development, will export up to 8.9 million tonnes per year of LNG to Asian customers including Kogas, and the Japanese utilities Tokyo Electric Power and Kyushu Electric Power.
The power companies have already signed long-term gas purchase contracts with the Wheatstone partners. Exports are expected to commence in 2014.
Japanese plans to import gas from Wheatstone are unlikely to be affected by the recent earthquake disaster and nuclear crisis in the country. Analysts expect Japan to require substantial additional LNG imports to compensate for potential nuclear plant closures and slower nuclear development.
Natural gas is an important part of Kufpec's development portfolio.
The company is also involved in a Singapore project that exports gas to industrial users in South East Asia and a Chinese project supplying gas for domestic power generation. It has interests in producing gasfields in Pakistan and expects soon to bring a new Indonesian field into production and to sanction the development of a Malaysian field with 1 trillion cubic feet of reserves, a company official said yesterday.
The overseas gas projects are part of a Kuwaiti government plan to increase the emirate's access to global gas supplies and to broaden its oil and gas industry technical expertise.
"We are looking at an area in which we can transfer technology. LNG is an area where we were lacking," Mr al Shammari said.
Kuwait started importing gas in 2009. The LNG imports are expected to continue until the emirate completes complex projects to boost production from deep gasfields in the north of the country.
Apr 7, 2011
Tamsin Carlisl
KUWAIT CITY // The Kuwait Foreign Petroleum Exploration Company (Kufpec) expects D-Day in August for a final investment decision on its participation in a A$20 billion (Dh75.83bn) Australian liquefied natural gas (LNG) project.
Development of the Wheatstone LNG project off the coast of north-west Australia is slated to start next year, Ali al Shammari, the deputy managing director of Kufpec, told a conference in the Kuwaiti capital.
Kufpec, which is the Kuwaiti government's overseas oil and gas investment arm, has joined forces with the US oil and gas producer Apache to explore and develop gas prospects including the Julimar and Brunello fields off the north-west coast of Australia. The Kufpec-Apache partnership's licences are for areas close to the Wheatstone gasfield, operated by the US oil major Chevron, and the Gorgon and Pluto fields, where two other large LNG projects are under development.
Kimimasa Mayama / Bloomberg News
"We selected Australia as an exploration focus due to stable fiscal terms and high geological potential," Mr al Shammari said.
In October 2009, Kufpec and Apache signed an agreement with Chevron to supply gas to Wheatstone LNG in return for equity stakes in the project. Kufpec now holds a 7 per cent interest in the project, after the South Korean utility Kogas also signed up as an equity partner.
"Wheatstone is a potential game-changer for Apache, unlocking 2.1 trillion cubic feet of gas reserves at two of Apache's largest discoveries and generating steady production for 15 years at prices pegged to world oil markets," G Steven Farris, the chairman and chief executive of Apache, said at the 2009 signing ceremony.
On completion, the planned LNG plant at Ashburton North, in the state of Western Australia, will have an annual production capacity of 15 million tonnes of the super-chilled fuel. The first phase of the project, already under development, will export up to 8.9 million tonnes per year of LNG to Asian customers including Kogas, and the Japanese utilities Tokyo Electric Power and Kyushu Electric Power.
The power companies have already signed long-term gas purchase contracts with the Wheatstone partners. Exports are expected to commence in 2014.
Japanese plans to import gas from Wheatstone are unlikely to be affected by the recent earthquake disaster and nuclear crisis in the country. Analysts expect Japan to require substantial additional LNG imports to compensate for potential nuclear plant closures and slower nuclear development.
Natural gas is an important part of Kufpec's development portfolio.
The company is also involved in a Singapore project that exports gas to industrial users in South East Asia and a Chinese project supplying gas for domestic power generation. It has interests in producing gasfields in Pakistan and expects soon to bring a new Indonesian field into production and to sanction the development of a Malaysian field with 1 trillion cubic feet of reserves, a company official said yesterday.
The overseas gas projects are part of a Kuwaiti government plan to increase the emirate's access to global gas supplies and to broaden its oil and gas industry technical expertise.
"We are looking at an area in which we can transfer technology. LNG is an area where we were lacking," Mr al Shammari said.
Kuwait started importing gas in 2009. The LNG imports are expected to continue until the emirate completes complex projects to boost production from deep gasfields in the north of the country.
Bering Begins Assessment on Eagle Ford Shale Acreage
Bering Begins Assessment on Eagle Ford Shale Acreage
Wednesday, April 06, 2011
This prospect has potential gross reserves of 3,000,000 barrels of oil and 120 well locations and will target the Eagle Ford, Austin Chalk, Buda and Edwards zones. Bering will retain a 100% working interest and an 80% net revenue interest with a two year lease term.
The Eagle Ford Shale is a shale rock formation located in multiple counties in South Texas. It underlies the Austin Chalk and the Edwards limestone formation and is just below these formations. It is considered by geologists to be the "source rock," or the original source of hydrocarbons (oil and gas) that are now found in the Austin Chalk above it. Industry leaders have been quoted as saying that it has the "perfect mineralogical makeup for shale play" and one of the world's largest oil & gas companies has already called it the sixth largest domestic oil discovery in the U.S. history.
"This is a crucial step in implementing our drilling program," stated Steven Plumb, Chief Financial Officer of Bering. "We expect to complete this process in the near term so that we can begin drilling our initial wells by this summer."
Wednesday, April 06, 2011
Bering Exploration Inc.
Bering has begun a geological assessment on its 1,200 gross acres targeting the Eagle Ford shale play in Central Texas. This assessment will help define Bering's initial drilling program. The company expects to have a preliminary plan completed by early next week.This prospect has potential gross reserves of 3,000,000 barrels of oil and 120 well locations and will target the Eagle Ford, Austin Chalk, Buda and Edwards zones. Bering will retain a 100% working interest and an 80% net revenue interest with a two year lease term.
The Eagle Ford Shale is a shale rock formation located in multiple counties in South Texas. It underlies the Austin Chalk and the Edwards limestone formation and is just below these formations. It is considered by geologists to be the "source rock," or the original source of hydrocarbons (oil and gas) that are now found in the Austin Chalk above it. Industry leaders have been quoted as saying that it has the "perfect mineralogical makeup for shale play" and one of the world's largest oil & gas companies has already called it the sixth largest domestic oil discovery in the U.S. history.
"This is a crucial step in implementing our drilling program," stated Steven Plumb, Chief Financial Officer of Bering. "We expect to complete this process in the near term so that we can begin drilling our initial wells by this summer."
SeaBird Awarded 2D, 3D Shallow Water Contracts
SeaBird Awarded 2D, 3D Shallow Water Contracts
Wednesday, April 06, 2011
Wednesday, April 06, 2011
SeaBird Exploration plc
SeaBird updated on the following new contracts awarded in the 2D and 3D shallow water.
Hawk Explorer has been awarded a short survey in direct continuation from the current employment in West Africa where the vessel will be employed until end May/ early June 2011.
Northern Explorer is currently carrying out a survey in East Africa with expected completion mid May 2011, and has now been awarded a further contract in South Africa where she will be employed until mid to end July 2011.
Geo Mariner is mobilizing to South East Asia with arrival mid April, and has been awarded a 2D contract for one month survey with client option to extend for a further month together with an option for a further 3D survey. This will keep the vessel busy to mid June, and with the option to end of July.
These contracts have a combined value of approximately US $7-9 million and represent approximately 6 vessel-months utilization including mobilization time and including the option on Geo Mariner.
With these awards and the general improvement in the tender activity SeaBird believes that the 2D activity will increase going forward resulting in a much improved utilization for its 2D fleet compared to 2nd half of 2010. Rate levels are however still low but on profitable EBITDA levels.
Hawk Explorer has been awarded a short survey in direct continuation from the current employment in West Africa where the vessel will be employed until end May/ early June 2011.
Northern Explorer is currently carrying out a survey in East Africa with expected completion mid May 2011, and has now been awarded a further contract in South Africa where she will be employed until mid to end July 2011.
Geo Mariner is mobilizing to South East Asia with arrival mid April, and has been awarded a 2D contract for one month survey with client option to extend for a further month together with an option for a further 3D survey. This will keep the vessel busy to mid June, and with the option to end of July.
These contracts have a combined value of approximately US $7-9 million and represent approximately 6 vessel-months utilization including mobilization time and including the option on Geo Mariner.
With these awards and the general improvement in the tender activity SeaBird believes that the 2D activity will increase going forward resulting in a much improved utilization for its 2D fleet compared to 2nd half of 2010. Rate levels are however still low but on profitable EBITDA levels.
Iran Aims to Produce More Than 35 Tcf of Gas from North Pars Field
Iran Aims to Produce More Than 35 Tcf of Gas from North Pars Field
Wednesday, April 06, 2011
Knight Ridder/Tribune Business News
Wednesday, April 06, 2011
Knight Ridder/Tribune Business News
by A.Yusifzade, Trend News Agency, Baku, Azerbaijan
Iran aims to produce over 35 trillion cubic feet (TCF) of gas from North Pars field for 35 years, FNA reported the Managing-Director of the South Pars Special Energy Zone (SPSEZ) Organization Seyed Pirooz Mousavi as saying.
By completion of the designed projects in the North Pars region, recoverable capacity of gas from North Pars gas field would reach 35 Tcf, Mousavi added.
The giant gas field has a significant share in Iran's prosperity and the Iranian government is resolved to develop the field, Mousavi stressed.
According to Mousavi, North Pars gas field reserves holds an estimated 57.1 trillion cubic feet of gas (some 1.63 trillion cubic meters).
Mousavi said that Kangan and Upper Dalan gas-bearing formations hold 72 percent of the field reserves and another 28 percent belongs to the Dallan gas formation.
According to the Pars Oil and Gas Company, North Pars Gas Field is one of the biggest independent gas fields of Iran. This field which was discovered in 1967, is located approx. 120 kilometers south east of Bushehr in water depths of 2 to 30 meters in the Persian Gulf.
Exploration activities started in this field in 1963 and the first exploration well was completed in 1967.The total volume of the gas in place of this field is about 58.9 TCF and the recoverable volume of sour gas is approximately 47.2 TCF.
By completion of the designed projects in the North Pars region, recoverable capacity of gas from North Pars gas field would reach 35 Tcf, Mousavi added.
The giant gas field has a significant share in Iran's prosperity and the Iranian government is resolved to develop the field, Mousavi stressed.
According to Mousavi, North Pars gas field reserves holds an estimated 57.1 trillion cubic feet of gas (some 1.63 trillion cubic meters).
Mousavi said that Kangan and Upper Dalan gas-bearing formations hold 72 percent of the field reserves and another 28 percent belongs to the Dallan gas formation.
According to the Pars Oil and Gas Company, North Pars Gas Field is one of the biggest independent gas fields of Iran. This field which was discovered in 1967, is located approx. 120 kilometers south east of Bushehr in water depths of 2 to 30 meters in the Persian Gulf.
Exploration activities started in this field in 1963 and the first exploration well was completed in 1967.The total volume of the gas in place of this field is about 58.9 TCF and the recoverable volume of sour gas is approximately 47.2 TCF.
FX Energy to Re-Enter Bakken Well
FX Energy to Re-Enter Bakken Well
Wednesday, April 06, 2011
Wednesday, April 06, 2011
FX Energy Inc.
FX Energy is rigging up to begin the re-entry of an existing wellbore in northern Montana. The purpose of the re-entry is to gather data from the wellbore to assist the Company in evaluating the hydrocarbon and CO2 potential in the Company's northern Montana acreage. The well will be deepened from its current depth in the Cutbank formation of approximately 3,216 feet. Samples will be taken from the Lodgepole, Bakken, Nisku and Duperow formations at depths ranging from 4,400 to 5,500 feet. The well will be drilled by the Company's wholly owned subsidiary, FX Drilling Company headquartered in Oilmont, Montana.
"This is the first step in a thorough program aimed at evaluating the potential of the Bakken trend in our area of the Alberta Basin. We are in discussions with other companies with the hope of expanding our position in the trend," said Andy Pierce VP of Operations for FX Energy.
Following completion of the re-entry project the well will be plugged and abandoned.
"This is the first step in a thorough program aimed at evaluating the potential of the Bakken trend in our area of the Alberta Basin. We are in discussions with other companies with the hope of expanding our position in the trend," said Andy Pierce VP of Operations for FX Energy.
Following completion of the re-entry project the well will be plugged and abandoned.
Far East Reports Net Present Value of Shouyang Block Resources
Far East Reports Net Present Value of Shouyang Block Resources
Wednesday, April 06, 2011
Far East Energy Corp.
Far East announced the results of an independent report by Netherland, Sewell & Associates (NSAI) evaluating, as of December 31, 2010, the contingent gas resources and Net Present Value at 10% Discount ("NPV10") of the net contingent cash flow for the three target coal seams in Far East Energy's 485,000 acre (1960 square kilometers) Shouyang Block, situated in Shanxi Province, China.
The report gives a Best Estimate of NPV10 of $738.3 million, and a High Estimate of $1.46 billion, net to Far East.
"Obviously, this is a very strong report, and one with which we are well pleased," said Michael R. McElwrath, CEO and President of Far East. "These estimates highlight the robust economic potential of the Block. And, it is important to note that we hope and believe that these numbers are just the beginning, as meaningful improvements in well-by-well gas rates and sustainability – which we certainly expect as we further develop, dewater, and optimize production – should have the impact of increasing these estimates, as well as reclassifying some of these resources as reserves."
McElwrath continued, "This report includes only our interest in the Contingent Resources and, of course, does not constitute a reserves report. While, under the terms of our gas sales agreement, we received payment for gas at year-end 2010, we did not flow gas through the system until mid-January, and even then that was frequently interrupted as we worked out the bugs in the gathering system during the testing and commissioning process. That lack of gas flow at year-end and our anticipation of frequent interruptions as testing and commissioning occurred, led us to decide that under the applicable rules we did not have a sufficiently completed gas sales system functioning as of year-end to recognize proven gas reserves in our December 31, 2010 financials. We will recognize proved gas reserves as appropriate in 2011, and will also provide a report indicating the probable and possible gas reserves at that time."
McElwrath continued, "With our current cash balance of $34 million, we will again accelerate the pace of our drilling program, and drilling should be funded until approximately the end of 2011. Additionally, we are also targeting a total of 200 to 250 wells in 2012, and 300 to 400 in 2013. Of course, the costs of these accelerated outyear drilling programs will be partially offset by growing revenues from gas sales, and discussions are underway with several international banks and other institutions for debt financing. Shouyang's potential becomes more apparent with each successive independent analysis that we receive, and we will proceed apace to realize the value of the underlying resource."
Wednesday, April 06, 2011
Far East Energy Corp.
Far East announced the results of an independent report by Netherland, Sewell & Associates (NSAI) evaluating, as of December 31, 2010, the contingent gas resources and Net Present Value at 10% Discount ("NPV10") of the net contingent cash flow for the three target coal seams in Far East Energy's 485,000 acre (1960 square kilometers) Shouyang Block, situated in Shanxi Province, China.
The report gives a Best Estimate of NPV10 of $738.3 million, and a High Estimate of $1.46 billion, net to Far East.
"Obviously, this is a very strong report, and one with which we are well pleased," said Michael R. McElwrath, CEO and President of Far East. "These estimates highlight the robust economic potential of the Block. And, it is important to note that we hope and believe that these numbers are just the beginning, as meaningful improvements in well-by-well gas rates and sustainability – which we certainly expect as we further develop, dewater, and optimize production – should have the impact of increasing these estimates, as well as reclassifying some of these resources as reserves."
McElwrath continued, "This report includes only our interest in the Contingent Resources and, of course, does not constitute a reserves report. While, under the terms of our gas sales agreement, we received payment for gas at year-end 2010, we did not flow gas through the system until mid-January, and even then that was frequently interrupted as we worked out the bugs in the gathering system during the testing and commissioning process. That lack of gas flow at year-end and our anticipation of frequent interruptions as testing and commissioning occurred, led us to decide that under the applicable rules we did not have a sufficiently completed gas sales system functioning as of year-end to recognize proven gas reserves in our December 31, 2010 financials. We will recognize proved gas reserves as appropriate in 2011, and will also provide a report indicating the probable and possible gas reserves at that time."
McElwrath continued, "With our current cash balance of $34 million, we will again accelerate the pace of our drilling program, and drilling should be funded until approximately the end of 2011. Additionally, we are also targeting a total of 200 to 250 wells in 2012, and 300 to 400 in 2013. Of course, the costs of these accelerated outyear drilling programs will be partially offset by growing revenues from gas sales, and discussions are underway with several international banks and other institutions for debt financing. Shouyang's potential becomes more apparent with each successive independent analysis that we receive, and we will proceed apace to realize the value of the underlying resource."
Sefton Expects Improved Flow Rates at Tapia, Charges Ahead in Ks.
Sefton Expects Improved Flow Rates at Tapia, Charges Ahead in Ks.
As was announced on March 1, 2011, TEG USA commenced its pilot steam flood operations at the Hartje #10 well in March and is currently injecting steam at about 35% capacity which will be increased to approximately 75% to 80% capacity (normal operating levels) over the coming weeks. At that point, approximately 700 to 780 bbl of steam will be injected per day into the center of the oilfield.
TEG USA averaged approximately 123 bbl per day during March, which is regarded as the baseline primary oil production level and it is anticipated with the injection of steam into the Hartje #10 well this will rise as it did for the pilot cyclic steam program last year.
Local California oil is currently posting at a 4% premium to NYMEX futures, rather than the more typical 7%-9% deficit. This spread has averaged a positive $4.20, for a posting of just over $107/bbl average for the month of March.
The preparatory work for the steam flood sensitivity geologic modeling will be completed in early April ready for Dr. Farouk Ali to commence his steam flood modeling work, which will last several weeks and is expected to be completed in May 2011.
Testing and activation of the LAGGS pipeline have begun. Three areas for repair have been identified. The repairs will be made in the order of their operational importance.
It is anticipated that later in 2011 the two systems, Vanguard and LAGGS, will be connected together and, as a result, it will be possible to move gas to market at two separate points and to two separate markets. This will give Sefton the possibility of moving gas to the higher return market from month to month.
Jim Ellerton, Acting Chairman and CEO of Sefton Resources said, "The Company is progressing well - we expect improved flow rates at Tapia and the prospect of still further increases once we can implement the recommendations of Dr. Farouk Ali's report. At the same time, we have continued to make progress in Kansas and this will continue further in the coming months so that we can activate the assets as soon as is possible. We are cash generative, profitable and actively increasing our investor profile and believe this will position us well for the future."
Wednesday, April 06, 2011
Sefton Resources Inc.
Sefton updated on trading for its oil production assets in California and gas infrastructure assets in Kansas.
Sefton updated on trading for its oil production assets in California and gas infrastructure assets in Kansas.
California
Sefton's 100% owned subsidiary TEG Oil & Gas USA, Inc ("TEG USA") is the operator of its operations in California at Tapia and Eureka Canyon.As was announced on March 1, 2011, TEG USA commenced its pilot steam flood operations at the Hartje #10 well in March and is currently injecting steam at about 35% capacity which will be increased to approximately 75% to 80% capacity (normal operating levels) over the coming weeks. At that point, approximately 700 to 780 bbl of steam will be injected per day into the center of the oilfield.
TEG USA averaged approximately 123 bbl per day during March, which is regarded as the baseline primary oil production level and it is anticipated with the injection of steam into the Hartje #10 well this will rise as it did for the pilot cyclic steam program last year.
Local California oil is currently posting at a 4% premium to NYMEX futures, rather than the more typical 7%-9% deficit. This spread has averaged a positive $4.20, for a posting of just over $107/bbl average for the month of March.
The preparatory work for the steam flood sensitivity geologic modeling will be completed in early April ready for Dr. Farouk Ali to commence his steam flood modeling work, which will last several weeks and is expected to be completed in May 2011.
Kansas
Sefton's Assets in Kansas are in Leavenworth County, including the Vanguard pipeline and the recently acquired LAGGS pipeline, and Anderson County, being the Waverly facility. Additional assets along the LAGGS pipeline are currently undergoing due diligence and are expected to close by 30 April 2011.Leavenworth County
Repairs to all of the 8" and the bulk of the 6" and 4" segments of the Vanguard Pipeline system have been completed and tested. Strategically, the 8" portion of the system is the most critical segment of the system and this segment will see the first volumes in 2011 with initial revenue from the Company's 100% owned subsidiary, TEG Midcontinent Inc and a third party expected to accelerate during the coming yearTesting and activation of the LAGGS pipeline have begun. Three areas for repair have been identified. The repairs will be made in the order of their operational importance.
It is anticipated that later in 2011 the two systems, Vanguard and LAGGS, will be connected together and, as a result, it will be possible to move gas to market at two separate points and to two separate markets. This will give Sefton the possibility of moving gas to the higher return market from month to month.
Anderson County
The Waverly facility consists of over 10 miles of pipeline, fifteen well bores, two salt water disposal wells and a dehydration facility capable of processing 10 million cubic feet of gas per day. The Waverly facility has an inactive tap with Post Rock (an interstate pipeline company) at the dehydration facility. Reactivation of the tap is expected to take place in early 2012.Jim Ellerton, Acting Chairman and CEO of Sefton Resources said, "The Company is progressing well - we expect improved flow rates at Tapia and the prospect of still further increases once we can implement the recommendations of Dr. Farouk Ali's report. At the same time, we have continued to make progress in Kansas and this will continue further in the coming months so that we can activate the assets as soon as is possible. We are cash generative, profitable and actively increasing our investor profile and believe this will position us well for the future."
Aker to Demerge EPC Sector
Aker to Demerge EPC Sector
Wednesday, April 06, 2011
Wednesday, April 06, 2011
Aker Solutions
Aker Solutions is establishing a specialized EPC company in order to further leverage the experience and expertise built up through field development projects over more than 40 years.
Aker Solutions announced that the new company, previously launched under the working title "Aker Contractors," will take the name Kværner, thereby continuing a proud industrial heritage since 1853. Kværner aims for a separate listing on the Oslo Stock Exchange in July.
The board of directors of Aker Solutions decided to propose to the annual general meeting on May 6, a demerger of Aker Solutions. This move is in line with plans previously communicated by the company.
"Aker Solutions is cultivating its core businesses in separate companies. The new focused entities have a clear ambition to grow in their respective markets: Kværner as a specialized EPC (engineering, procurement and construction) company tailored to meet EPC market trends and client demands in the global market, and Aker Solutions as a fully-fledged provider of engineering, technologies, solutions and services for the upstream oil and gas industry," said Aker Solutions executive chairman Øyvind Eriksen.
Aker ASA, through Aker Holding, will continue as a long-term investor in both companies.
"The Kværner name represents a proud history in the North Sea and international markets. I am proud to see such a powerful name reintroduced for a new EPC company with strong ambitions for growth. I look forward to being a part of writing the next chapter of the Kværner story. I am confident about the company's potential for the future," said Kjell Inge Røkke, main shareholder of Aker ASA.
"The yards at Stord and Verdal have used the Aker name for decades, and we would of course have preferred to continue this tradition. However, more important is the commitment expressed by Aker ASA and its main shareholder, Mr Kjell Inge Røkke, to continue to support and invest in our business. We look forward to build a successful company together with management and owners," says Atle Teigland, group union convenor and member of the board of Aker Solutions.
Aker Solutions announced that the new company, previously launched under the working title "Aker Contractors," will take the name Kværner, thereby continuing a proud industrial heritage since 1853. Kværner aims for a separate listing on the Oslo Stock Exchange in July.
The board of directors of Aker Solutions decided to propose to the annual general meeting on May 6, a demerger of Aker Solutions. This move is in line with plans previously communicated by the company.
"Aker Solutions is cultivating its core businesses in separate companies. The new focused entities have a clear ambition to grow in their respective markets: Kværner as a specialized EPC (engineering, procurement and construction) company tailored to meet EPC market trends and client demands in the global market, and Aker Solutions as a fully-fledged provider of engineering, technologies, solutions and services for the upstream oil and gas industry," said Aker Solutions executive chairman Øyvind Eriksen.
Aker ASA, through Aker Holding, will continue as a long-term investor in both companies.
"The Kværner name represents a proud history in the North Sea and international markets. I am proud to see such a powerful name reintroduced for a new EPC company with strong ambitions for growth. I look forward to being a part of writing the next chapter of the Kværner story. I am confident about the company's potential for the future," said Kjell Inge Røkke, main shareholder of Aker ASA.
"The yards at Stord and Verdal have used the Aker name for decades, and we would of course have preferred to continue this tradition. However, more important is the commitment expressed by Aker ASA and its main shareholder, Mr Kjell Inge Røkke, to continue to support and invest in our business. We look forward to build a successful company together with management and owners," says Atle Teigland, group union convenor and member of the board of Aker Solutions.
Total: UK Open to Mitigating Effect of Oil Tax Rise
Total: UK Open to Mitigating Effect of Oil Tax Rise
Wednesday, April 06, 2011
Dow Jones Newswires
by James Herron
The U.K. government appears willing to consider measures to mitigate the effect of a recent large increase in tax on oil and gas producers, following a meeting with oil industry representatives last week, a senior executive at French oil company Total said Wednesday.
Representatives of the Department of Energy and Climate Change and the Treasury "realized that the concerns of industry are real...not just a selfish reaction," said Patrice de Vivies, Total's vice president of Exploration and Production in northwestern Europe.
Oil companies and many industry analysts have said the increase in the supplementary tax charge on their profits to 32% from 20% will hurt investment in the North Sea.
The measure was introduced in response to the rise of oil prices above $100 a barrel, but De Vivies said there is no justification for imposing the tax on gas fields, for which the price is equivalent to $55 a barrel.
"[They] will have to give extra incentives to gas fields," which make up the bulk of remaining U.K. resources, or face declining investment, he said. Total is reviewing all of its potential new projects in the U.K. following the change, he said.
Total Chief Executive Christophe de Margerie will meet soon with U.K. Chancellor of the Exchequer George Osborne to discuss the tax increase, De Vivies said.
Dow Jones Newswires put De Vivies' comments to the U.K. Treasury, who responded by referencing statements made by ministers in the wake of last week's meeting.
Energy and Climate Change Secretary Chris Huhne said at the time: "We're going to be considering some of the points that they [the industry] made. There are elements of what the Chancellor announced which were up for consultation, including the issue of the oil price at which the fair fuel stabilizer operates."
Separately, RWE Dea, the oil and natural gas unit of German utility RWE, said Wednesday the planned tax increase is "unpleasant" and should be retracted.
"We've learned about the U.K. government's plan to increase the tax and indeed found ourselves very flatfooted," said RWE Dea Chief Executive Thomas Rappuhn at the company's annual press conference in Hamburg.
Wednesday, April 06, 2011
Dow Jones Newswires
by James Herron
The U.K. government appears willing to consider measures to mitigate the effect of a recent large increase in tax on oil and gas producers, following a meeting with oil industry representatives last week, a senior executive at French oil company Total said Wednesday.
Representatives of the Department of Energy and Climate Change and the Treasury "realized that the concerns of industry are real...not just a selfish reaction," said Patrice de Vivies, Total's vice president of Exploration and Production in northwestern Europe.
Oil companies and many industry analysts have said the increase in the supplementary tax charge on their profits to 32% from 20% will hurt investment in the North Sea.
The measure was introduced in response to the rise of oil prices above $100 a barrel, but De Vivies said there is no justification for imposing the tax on gas fields, for which the price is equivalent to $55 a barrel.
"[They] will have to give extra incentives to gas fields," which make up the bulk of remaining U.K. resources, or face declining investment, he said. Total is reviewing all of its potential new projects in the U.K. following the change, he said.
Total Chief Executive Christophe de Margerie will meet soon with U.K. Chancellor of the Exchequer George Osborne to discuss the tax increase, De Vivies said.
Dow Jones Newswires put De Vivies' comments to the U.K. Treasury, who responded by referencing statements made by ministers in the wake of last week's meeting.
Energy and Climate Change Secretary Chris Huhne said at the time: "We're going to be considering some of the points that they [the industry] made. There are elements of what the Chancellor announced which were up for consultation, including the issue of the oil price at which the fair fuel stabilizer operates."
Separately, RWE Dea, the oil and natural gas unit of German utility RWE, said Wednesday the planned tax increase is "unpleasant" and should be retracted.
"We've learned about the U.K. government's plan to increase the tax and indeed found ourselves very flatfooted," said RWE Dea Chief Executive Thomas Rappuhn at the company's annual press conference in Hamburg.
California Oil Industry Looks to Replenish Ranks
California Oil Industry Looks to Replenish Ranks
Wednesday, April 06, 2011
The Bakersfield Californian
Wednesday, April 06, 2011
The Bakersfield Californian
by John Cox
The upturn in oil prices has worsened a shortage of experienced engineers and other science professionals ready to work in Kern's suddenly bustling petroleum industry.
People in the industry say large local producers are scrambling to recruit and train young people to replace engineers and geologists nearing retirement age.
The effort is hampered by the industry's notoriously unsteady employment pattern: Many young oil engineers were let go about a decade ago when crude prices languished and drilling work tapered off. Many entered different fields and never looked back.
Local factors have made the situation particularly acute. Cal State Bakersfield has an industry-oriented geology department, but the university produces no engineers. Also, attracting fresh graduates from outside the area can be difficult because of Bakersfield's reputation as a sleepy ag town.
"I'd like to hire an engineer myself and I don't really know where to look," Bakersfield oil producer Chad Hathaway said, adding that he'd be in high demand now if he had stayed in engineering school.
The severity of the shortage tracks closely with gasoline prices, said Jackie Flesher, co-owner of ProSearch Associates, an executive technical recruitment service in Bakersfield. Two years ago, she said, nobody needed an oil engineer; now she has 25 such positions to fill.
"It's very cyclical," she said. "They do get laid off and they do get hired back."
One of the largest producers operating locally, Occidental Petroleum Corp., is looking to fill more than 50 positions in Bakersfield ranging from engineering to safety jobs. It hasn't been easy.
"We acknowledge there is a shortage of qualified technical professionals available to work within the oil and gas industry," Oxy spokeswoman Susie Geiger wrote in an email. "In light of that, we want to bring our new employees up to speed faster than before." To that end, she wrote, the company is developing a two- to five-year program intended to accelerate new employee training.
That's a key challenge facing not only oil producers but utilities and others in the local energy industry, said Robin Fleming, senior manager of business development at the Kern Economic Development Corp., which helps grow and retain local businesses. She said all the large producers operating here are investing in recruitment and building up work experience.
"There is a ramp-up to try and get those people in for training," she said.
Some of that is happening at a very early stage. A local initiative headed by KEDC's nonprofit foundation promotes energy professions among high school girls who have expressed an interest in math, science and engineering. Called the Alliance for Women in Energy, it arranges for local energy professionals to mentor these students and show them the benefits of working in oil, wind energy and utilities.
While these students could go on to pre-engineering programs at Bakersfield College and CSUB, there is no way for them to earn an oil engineering degree in Kern County -- yet.
Last fall CSUB won a $3.7 million U.S. Department of Education grant for the creation of a computer engineering degree that university spokesman Robert Meszaros said will serve as a stepping stone for future engineering programs.
Such graduate engineering programs do not exist locally partly because of a lack of money but also because of engineering programs at Fresno State and Cal Poly San Luis Obispo, Meszaros said.
But CSUB does offer undergraduate and post-graduate geology degrees -- and the local oil industry makes good use of them.
"We get inquiries weekly from people who have jobs they're looking to fill," said Robert Horton, chairman of CSUB's department of geological sciences. He added that most of the inquiries come from the oil industry.
Something that makes the program of particular value to the local industry, Horton said, is the fact that the graduates are accustomed to the Kern County lifestyle. He said that's important to Bakersfield-area employers, who otherwise must convince job candidates of the high quality of life here.
But perhaps the bigger challenge goes back to the cyclical nature of the industry. Times may be good now, but projects will eventually dry up if prices hit the dirt again, as happened in the late 1990s.
Les Clark, executive vice president of Bakersfield's Independent Oil Producers Agency, said the industry lost a lot of good people back then.
"Right now I think the oil industry is a good place to go get yourself a job," he said. "It's the ups and downs that really get us."
People in the industry say large local producers are scrambling to recruit and train young people to replace engineers and geologists nearing retirement age.
The effort is hampered by the industry's notoriously unsteady employment pattern: Many young oil engineers were let go about a decade ago when crude prices languished and drilling work tapered off. Many entered different fields and never looked back.
Local factors have made the situation particularly acute. Cal State Bakersfield has an industry-oriented geology department, but the university produces no engineers. Also, attracting fresh graduates from outside the area can be difficult because of Bakersfield's reputation as a sleepy ag town.
"I'd like to hire an engineer myself and I don't really know where to look," Bakersfield oil producer Chad Hathaway said, adding that he'd be in high demand now if he had stayed in engineering school.
The severity of the shortage tracks closely with gasoline prices, said Jackie Flesher, co-owner of ProSearch Associates, an executive technical recruitment service in Bakersfield. Two years ago, she said, nobody needed an oil engineer; now she has 25 such positions to fill.
"It's very cyclical," she said. "They do get laid off and they do get hired back."
One of the largest producers operating locally, Occidental Petroleum Corp., is looking to fill more than 50 positions in Bakersfield ranging from engineering to safety jobs. It hasn't been easy.
"We acknowledge there is a shortage of qualified technical professionals available to work within the oil and gas industry," Oxy spokeswoman Susie Geiger wrote in an email. "In light of that, we want to bring our new employees up to speed faster than before." To that end, she wrote, the company is developing a two- to five-year program intended to accelerate new employee training.
That's a key challenge facing not only oil producers but utilities and others in the local energy industry, said Robin Fleming, senior manager of business development at the Kern Economic Development Corp., which helps grow and retain local businesses. She said all the large producers operating here are investing in recruitment and building up work experience.
"There is a ramp-up to try and get those people in for training," she said.
Some of that is happening at a very early stage. A local initiative headed by KEDC's nonprofit foundation promotes energy professions among high school girls who have expressed an interest in math, science and engineering. Called the Alliance for Women in Energy, it arranges for local energy professionals to mentor these students and show them the benefits of working in oil, wind energy and utilities.
While these students could go on to pre-engineering programs at Bakersfield College and CSUB, there is no way for them to earn an oil engineering degree in Kern County -- yet.
Last fall CSUB won a $3.7 million U.S. Department of Education grant for the creation of a computer engineering degree that university spokesman Robert Meszaros said will serve as a stepping stone for future engineering programs.
Such graduate engineering programs do not exist locally partly because of a lack of money but also because of engineering programs at Fresno State and Cal Poly San Luis Obispo, Meszaros said.
But CSUB does offer undergraduate and post-graduate geology degrees -- and the local oil industry makes good use of them.
"We get inquiries weekly from people who have jobs they're looking to fill," said Robert Horton, chairman of CSUB's department of geological sciences. He added that most of the inquiries come from the oil industry.
Something that makes the program of particular value to the local industry, Horton said, is the fact that the graduates are accustomed to the Kern County lifestyle. He said that's important to Bakersfield-area employers, who otherwise must convince job candidates of the high quality of life here.
But perhaps the bigger challenge goes back to the cyclical nature of the industry. Times may be good now, but projects will eventually dry up if prices hit the dirt again, as happened in the late 1990s.
Les Clark, executive vice president of Bakersfield's Independent Oil Producers Agency, said the industry lost a lot of good people back then.
"Right now I think the oil industry is a good place to go get yourself a job," he said. "It's the ups and downs that really get us."
Toyota Sells Its Millionth Prius In The U.S.
Toyota Sells Its Millionth Prius In The U.S.
Toyota Motor Co (NYSE:TM) announced today it has sold its 1 millionth Prius hybrid in the United States. The company has sold more than 2 million in total across the globe over the last decade, including the U.S.
The car-maker said the Prius has been the top selling hybrid in the U.S. since it began selling 11 years ago.
The Prius is powered by both a gasoline engine and an electric motor, and can get up to 51 miles per gallon in the city and 48 mpg on the highway.
The car has become increasingly popular as gas prices have gone up. Sales in Japan tripled in 2009, becoming the country's best selling car and overtaking the U.S. as the largest market for the vehicle.
Shares of Toyota Motor are trading down 0.58% at $77.18.
Toyota Motor Co (NYSE:TM) announced today it has sold its 1 millionth Prius hybrid in the United States. The company has sold more than 2 million in total across the globe over the last decade, including the U.S.
The car-maker said the Prius has been the top selling hybrid in the U.S. since it began selling 11 years ago.
The Prius is powered by both a gasoline engine and an electric motor, and can get up to 51 miles per gallon in the city and 48 mpg on the highway.
The car has become increasingly popular as gas prices have gone up. Sales in Japan tripled in 2009, becoming the country's best selling car and overtaking the U.S. as the largest market for the vehicle.
Shares of Toyota Motor are trading down 0.58% at $77.18.
EIA Deems Shale Gas 'Global Phenomenon'
EIA Deems Shale Gas 'Global Phenomenon'
Wednesday, April 06, 2011
Wednesday, April 06, 2011
Energy Information Administration
Initial assessments of 48 shale gas basins in 32 countries suggest that shale gas resources, which have recently provided a major boost to U.S. natural gas production, are also available in other world regions. A new EIA-sponsored study reported initial assessments of 5,760 trillion cubic feet (Tcf) of technically recoverable shale gas resources in 32 foreign countries, compared with 862 Tcf in the United States.
In 2010, U.S. shale gas production reached 4.87 Tcf (23 percent of total U.S. natural gas production), compared with 0.39 Tcf in 2000. This shows both the rapid growth and absolute importance of the shale gas resource to the United States. Rising production from shale gas resources has been credited with both lower natural gas prices and declining dependence on imported natural gas. As is often the case with resource development, shale gas production also has raised local environmental concerns, largely centering on the amount of water used in the fracturing process and the need to handle, recycle, and treat fracturing fluids in a manner that addresses the risk of spills that can potentially affect water quality. EIA's Annual Energy Outlook 2011 Reference case also reflects the growing importance of U.S. shale gas. It projects that shale gas will account for about 46 percent of U.S. natural gas production in 2035.
Do other countries have similar opportunities to develop shale gas? To begin to address that question, EIA sponsored Advanced Resources International, Inc., to assess 48 gas shale basins in 32 countries, containing almost 70 shale gas formations. This effort has culminated in the report: World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States.
Technically recoverable natural gas resources in the assessed basins totaled 5,760 Tcf. Adding the estimated U.S. shale gas technically recoverable resources (862 Tcf) to the assessments in the study gives a total of 6,622 Tcf. For comparison, most current estimates of world technically recoverable natural gas resources include few if any of the resources assessed in this study and total about 16,000 Tcf.
"Adding identified shale gas resources to current estimates of other gas resources increases total world technically recoverable resources by over 40 percent, to more than 22,000 trillion cubic feet," said EIA Administrator Richard Newell.
Estimates of shale gas resources in other parts of the world are highly uncertain. The practicality of using such resources has only recently become apparent, and many countries are just now beginning to understand how to conduct assessments of how much shale gas they may have. Nonetheless, the aggregate estimate is probably quite conservative, since the study excluded several major types of potential shale gas resources:
In 2010, U.S. shale gas production reached 4.87 Tcf (23 percent of total U.S. natural gas production), compared with 0.39 Tcf in 2000. This shows both the rapid growth and absolute importance of the shale gas resource to the United States. Rising production from shale gas resources has been credited with both lower natural gas prices and declining dependence on imported natural gas. As is often the case with resource development, shale gas production also has raised local environmental concerns, largely centering on the amount of water used in the fracturing process and the need to handle, recycle, and treat fracturing fluids in a manner that addresses the risk of spills that can potentially affect water quality. EIA's Annual Energy Outlook 2011 Reference case also reflects the growing importance of U.S. shale gas. It projects that shale gas will account for about 46 percent of U.S. natural gas production in 2035.
Do other countries have similar opportunities to develop shale gas? To begin to address that question, EIA sponsored Advanced Resources International, Inc., to assess 48 gas shale basins in 32 countries, containing almost 70 shale gas formations. This effort has culminated in the report: World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States.
Technically recoverable natural gas resources in the assessed basins totaled 5,760 Tcf. Adding the estimated U.S. shale gas technically recoverable resources (862 Tcf) to the assessments in the study gives a total of 6,622 Tcf. For comparison, most current estimates of world technically recoverable natural gas resources include few if any of the resources assessed in this study and total about 16,000 Tcf.
"Adding identified shale gas resources to current estimates of other gas resources increases total world technically recoverable resources by over 40 percent, to more than 22,000 trillion cubic feet," said EIA Administrator Richard Newell.
Estimates of shale gas resources in other parts of the world are highly uncertain. The practicality of using such resources has only recently become apparent, and many countries are just now beginning to understand how to conduct assessments of how much shale gas they may have. Nonetheless, the aggregate estimate is probably quite conservative, since the study excluded several major types of potential shale gas resources:
- Nations outside the 32 countries studied. These include Russia and the Middle East, which have very large resources of conventional gas.
- Some shale basins in the countries studied. In many cases, no estimates are possible yet for these basins.
- Offshore resources.
AIDEA Invests in Cook Inlet Rig
AIDEA Invests in Cook Inlet Rig
Wednesday, April 06, 2011
Buccaneer Energy Ltd.
Buccaneer advised that the board of the Alaskan Industrial Development and Export Authority (AIDEA) voted unanimously to invest up to US $30.0 million, as a joint owner, in the acquisition of a jack-up rig.
A Joint Ownership Agreement (JOA) is expected to soon be executed between the Company's subsidiary Kenai Offshore Ventures, LLC (KOV) and AIDEA. The joint project has been named Project Endeavour.
The JOA contains 15 Conditions Precedent that must be finalized prior to draw down of the AIDEA investment. The Company considers 5 of the Condition Precedents to be Material Conditions Precedent and these are listed in Schedule 1. The Company is confident that all the Condition Precedents can be met in a timely manner.
AIDEA's involvement and investment is as a Preferred Owner of the jack-up rig with an initial 85.7% interest in the Joint Project. KOV will be the sole Common Owner with a 14.3% initial interest in the Joint Project.
The following are the main features of AIDEA's Preferred Ownership interest:
The Company anticipates that the total cost of the acquisition, modification and mobilization of the jack-up rig to the Cook Inlet from its current location will be approximately US $85.0 million.
Wednesday, April 06, 2011
Buccaneer Energy Ltd.
Buccaneer advised that the board of the Alaskan Industrial Development and Export Authority (AIDEA) voted unanimously to invest up to US $30.0 million, as a joint owner, in the acquisition of a jack-up rig.
A Joint Ownership Agreement (JOA) is expected to soon be executed between the Company's subsidiary Kenai Offshore Ventures, LLC (KOV) and AIDEA. The joint project has been named Project Endeavour.
The JOA contains 15 Conditions Precedent that must be finalized prior to draw down of the AIDEA investment. The Company considers 5 of the Condition Precedents to be Material Conditions Precedent and these are listed in Schedule 1. The Company is confident that all the Condition Precedents can be met in a timely manner.
AIDEA's involvement and investment is as a Preferred Owner of the jack-up rig with an initial 85.7% interest in the Joint Project. KOV will be the sole Common Owner with a 14.3% initial interest in the Joint Project.
The following are the main features of AIDEA's Preferred Ownership interest:
- AIDEA's 85.7% Preferred Ownership interest in the Joint Project will be repurchased over a period of 6 years using cash flow generated by contracting of the rig for drilling operations. AIDEA's Preferred Ownership interest will be canceled as it is repurchased so that on conclusion of the repurchase program KOV will be the 100% owner of the jack-up rig;
- AIDEA will be paid a fixed annual dividend of 8.0%, paid semi-annually in arrears, on the Preferred Owner's outstanding balance of the Principal Repurchase;
- AIDEA's Preferred Ownership interest will be repurchased by way of an annual payment, in arrears. The repurchase schedule commences when the jack-up rig is delivered to the Cook Inlet ready for drilling operations; and
- Any dividend payment or Principal Repurchase that is not made in a 12 month period will accrue to the following 12 months.
The Company anticipates that the total cost of the acquisition, modification and mobilization of the jack-up rig to the Cook Inlet from its current location will be approximately US $85.0 million.
Exclusive Use Rights
Buccaneer will have the first right of refusal to utilize the rig until the conclusion of the 2013 drilling season i.e. November 2013. Under the terms of the JOA Buccaneer has committed to drilling a minimum of 4 wells in the Cook Inlet using the acquired jack-up rig.Breitling Wraps Up Ops at Tx. Well
Breitling Wraps Up Ops at Tx. Well
Wednesday, April 06, 2011
Breitling O&G Corp.
Breitling announced that the Breitling-Turner #1 in Hardeman County, Texas is being completed as a possible oil and gas producer after reaching a total vertical depth of 7,900 feet.
The well was subsequently logged by Halliburton and based on analysis by Breitling's engineers and geologists as well as Halliburton's analysis of the Turner #1 logs. Chris Faulkner, CEO of Breitling Oil and Gas, said, "We have a couple of good-looking zones in this well and both had good porosity and permeability, and we look forward to another successful completion."
Wednesday, April 06, 2011
Breitling O&G Corp.
Breitling announced that the Breitling-Turner #1 in Hardeman County, Texas is being completed as a possible oil and gas producer after reaching a total vertical depth of 7,900 feet.
The well was subsequently logged by Halliburton and based on analysis by Breitling's engineers and geologists as well as Halliburton's analysis of the Turner #1 logs. Chris Faulkner, CEO of Breitling Oil and Gas, said, "We have a couple of good-looking zones in this well and both had good porosity and permeability, and we look forward to another successful completion."
Halliburton Awarded Gig for Statoil's HP/HT Fields Offshore Norway
Halliburton Awarded Gig for Statoil's HP/HT Fields Offshore Norway
Wednesday, April 06, 2011
Halliburton
Wednesday, April 06, 2011
Halliburton
by SubseaIQ
Halliburton has been awarded several contracts by Statoil to provide services for two high-pressure/high-temperature (HP/HT) fields offshore Norway. Halliburton estimates that these significant multiyear awards have the potential to exceed more than $200 million in value.
Under these contracts, Halliburton will provide directional drilling, logging-while-drilling, cementing, drilling fluids, and completion equipment and services at the Gudrun and Brynhild fields. Drilling is scheduled to start in the third quarter of 2011.
Halliburton's proven HP/HT technology will be key in enabling the development of the Gudrun oil and natural gas field, where temperatures exceed 150°C (302°F). Statoil is operator of the Gudrun field, which is planned for startup in the first quarter of 2014. The Brynhild HP/HT oil and gas discovery is approximately three kilometers east of the Gudrun field.
"We are proud to have been awarded these technically challenging contracts for Gudrun and Brynhild," said Brady Murphy, Halliburton's vice president for the Europe/West Africa Region. "These awards, together with our recent HP/HT wins in other offshore basins, reflect Halliburton's technology investment and proven performance in challenging well conditions. This will be an important contribution to further development offshore Norway."
Under these contracts, Halliburton will provide directional drilling, logging-while-drilling, cementing, drilling fluids, and completion equipment and services at the Gudrun and Brynhild fields. Drilling is scheduled to start in the third quarter of 2011.
Halliburton's proven HP/HT technology will be key in enabling the development of the Gudrun oil and natural gas field, where temperatures exceed 150°C (302°F). Statoil is operator of the Gudrun field, which is planned for startup in the first quarter of 2014. The Brynhild HP/HT oil and gas discovery is approximately three kilometers east of the Gudrun field.
"We are proud to have been awarded these technically challenging contracts for Gudrun and Brynhild," said Brady Murphy, Halliburton's vice president for the Europe/West Africa Region. "These awards, together with our recent HP/HT wins in other offshore basins, reflect Halliburton's technology investment and proven performance in challenging well conditions. This will be an important contribution to further development offshore Norway."
Alberta Will Tighten Oil-Sands Regulation
Alberta Will Tighten Oil-Sands Regulation
Wednesday, April 06, 2011
The Wall Street Journal
Wednesday, April 06, 2011
The Wall Street Journal
by Edward Welsch
The Alberta government said Tuesday it intends to set new environmental standards -- including outlining specific benchmarks for water contamination -- for areas affected by Canada's vast and growing oil-sands production in the western part of the country.
The provincial government also said it would set aside more than 7,700 square miles of land in the region for conservation. The move will require the cancellation of 10 oil-sands leases
The government didn't provide the names of the companies that would see their leases canceled under the new regional development plan for the Lower Athabasca region.
The government said that producing projects wouldn't be affected, only projects under development. That means that output won't be immediately affected. The companies would be compensated for their costs in purchasing and developing the leases.
Canada largely delegates regulation of its oil and natural-gas industry to the provincial level, so the new regulations signal significant new regulatory oversight for an industry that's been growing quickly in recent years. Alberta has been a big promoter of oil-sands development, and officials in both the U.S. and Canada have touted the industry's potential to ramp up output to feed American demand.
The oil-sands industry already accounts for about half of the 1.9 million barrels a day of oil that is exported to the U.S. Output is widely expected to double in size during this decade. But that growth rate partly depends upon the industry's ability to defend its environmental record.
Environmental groups have attacked the industry on several fronts, including criticism of the surface damage caused by strip mining and tailing ponds involved in some oil-sands production and the industry's higher greenhouse-gas emissions, compared to more conventional methods of extracting oil from the ground.
Last month, the Canadian government proposed a plan to revamp environmental monitoring for oil sands in response to criticism of the current system.
Part of the plan announced Tuesday will be benchmarks for assessing whether nearby water is being contaminated by the production cycle. The targets are expected to be roughly in line with water-contamination limits set by the U.S. Environmental Protection Agency, the government said. If those limits are breached, further review will be mandated.
The government said it would soon begin a 60-day consultation period with stakeholders and communities, and expected the new regulations to be in force by 2013. A time-line for implementation of the new monitoring system is expected by June.
The provincial government also said it would set aside more than 7,700 square miles of land in the region for conservation. The move will require the cancellation of 10 oil-sands leases
The government didn't provide the names of the companies that would see their leases canceled under the new regional development plan for the Lower Athabasca region.
The government said that producing projects wouldn't be affected, only projects under development. That means that output won't be immediately affected. The companies would be compensated for their costs in purchasing and developing the leases.
Canada largely delegates regulation of its oil and natural-gas industry to the provincial level, so the new regulations signal significant new regulatory oversight for an industry that's been growing quickly in recent years. Alberta has been a big promoter of oil-sands development, and officials in both the U.S. and Canada have touted the industry's potential to ramp up output to feed American demand.
The oil-sands industry already accounts for about half of the 1.9 million barrels a day of oil that is exported to the U.S. Output is widely expected to double in size during this decade. But that growth rate partly depends upon the industry's ability to defend its environmental record.
Environmental groups have attacked the industry on several fronts, including criticism of the surface damage caused by strip mining and tailing ponds involved in some oil-sands production and the industry's higher greenhouse-gas emissions, compared to more conventional methods of extracting oil from the ground.
Last month, the Canadian government proposed a plan to revamp environmental monitoring for oil sands in response to criticism of the current system.
Part of the plan announced Tuesday will be benchmarks for assessing whether nearby water is being contaminated by the production cycle. The targets are expected to be roughly in line with water-contamination limits set by the U.S. Environmental Protection Agency, the government said. If those limits are breached, further review will be mandated.
The government said it would soon begin a 60-day consultation period with stakeholders and communities, and expected the new regulations to be in force by 2013. A time-line for implementation of the new monitoring system is expected by June.
Gran Tierra Updates Ops in South America
Gran Tierra Updates Ops in South America
Wednesday, April 06, 2011
Colombia
Drilling and logging of the San Angel-1 natural gas exploration well in the Magdalena Block of the Lower Magdalena Basin has been completed. Gas shows were encountered over two intervals totaling 415 feet (gross). Wireline logs and repeat formation tester data was not conclusive in quantifying reservoir quality or gas saturation. Testing operations have been initiated and are expected to be completed in late April, 2011.
The Moqueta-5 delineation well is expected to start drilling this week from the same well pad as the Moqueta-4 delineation well. New 3D seismic acquisition is expected to start in June 2011 and will assist in the site location for the Moqueta-6 delineation well expected to start drilling in the fourth quarter, 2011. The Moqueta to Costayaco flow line is currently under construction with the first long-term production test anticipated to start in May.
Development of the Costayaco field continues with the drilling of Costayaco-12 and -13. Costayaco-12 was completed and placed on production at approximately 600 barrels of oil per day. Completion and testing operations are currently ongoing at Costayaco-13. Both wells are expected to be converted to water injectors once the oil reserves are depleted around their respective drainage areas.
In connection with the acquisition of Petrolifera, Gran Tierra Energy initially assigned no value to investments that Petrolifera held in Asset Backed Commercial Paper ("ABCP") given concerns over the liquidity of the investment. Gran Tierra Energy subsequently sold the ABCP and received a net amount of US $22.7 million including accrued interest.
Wednesday, April 06, 2011
Gran Tierra Energy Inc.
Gran Tierra announced a drilling and operations update in the Putumayo and Lower Magdalena Basins of Colombia, an acreage update in Argentina, and a general Corporate update.
Gran Tierra announced a drilling and operations update in the Putumayo and Lower Magdalena Basins of Colombia, an acreage update in Argentina, and a general Corporate update.
Colombia
Magdalena Block, Lower Magdalena Basin (100% working interest and Operator)
Drilling and logging of the San Angel-1 natural gas exploration well in the Magdalena Block of the Lower Magdalena Basin has been completed. Gas shows were encountered over two intervals totaling 415 feet (gross). Wireline logs and repeat formation tester data was not conclusive in quantifying reservoir quality or gas saturation. Testing operations have been initiated and are expected to be completed in late April, 2011.Chaza Block, Putumayo Basin (100% working interest and Operator)
The Canangucho-1 exploration well reached total true vertical depth of 9,667 feet on March 23, 2011. After the evaluation of wireline logs, it was determined that the T Sandstone and Caballos formations were water bearing. The Canangucho well was plugged and abandoned.The Moqueta-5 delineation well is expected to start drilling this week from the same well pad as the Moqueta-4 delineation well. New 3D seismic acquisition is expected to start in June 2011 and will assist in the site location for the Moqueta-6 delineation well expected to start drilling in the fourth quarter, 2011. The Moqueta to Costayaco flow line is currently under construction with the first long-term production test anticipated to start in May.
Development of the Costayaco field continues with the drilling of Costayaco-12 and -13. Costayaco-12 was completed and placed on production at approximately 600 barrels of oil per day. Completion and testing operations are currently ongoing at Costayaco-13. Both wells are expected to be converted to water injectors once the oil reserves are depleted around their respective drainage areas.
Guayuyaco Block, Putumayo Basin (70% Working Interest and Operator)
The Juanambu-3 development well began drilling on March 3, 2011. Drilling operations are expected to be completed in April, 2011.Rumiyaco Block, Putumayo Basin (100% Working Interest and Operator)
Environmental permitting has been approved for the Rumiyaco-1 exploration well in the Rumiyaco Block of the Putumayo basin. Civil construction work is expected to start in April, 2011 and the well is expected to begin drilling in July, 2011.Argentina
Gran Tierra Energy has successfully farmed out a 50% interest in its Santa Victoria block (2,091.5 km2 or 516, 815.3 acres) in the Noroeste Basin of northwestern Argentina to Apache Corporation ("Apache"). Both Gran Tierra Energy and Apache have agreed to proceed into the second exploration phase, which has a work commitment that will be fulfilled with an exploration well. Gran Tierra Energy, as operator, is interested in testing the gas potential of the Permo-Carboniferous reservoirs, a proven play in nearby wells.Corporate Update
Subsequent to closing the acquisition of Petrolifera Petroleum Ltd. ("Petrolifera") on March 18, 2011, company average production has been approximately 18,000 barrels of oil equivalent per day ("BOEPD"), net after royalty ("NAR"), weighted 95% to light oil. Oil production in Colombia has averaged approximately 15,000 barrels of oil per day ("BOPD") NAR, while oil production in Argentina has averaged approximately 2,300 BOPD NAR and gas production has averaged approximately 4 million standard cubic feet per day, or approximately 700 BOEPD.In connection with the acquisition of Petrolifera, Gran Tierra Energy initially assigned no value to investments that Petrolifera held in Asset Backed Commercial Paper ("ABCP") given concerns over the liquidity of the investment. Gran Tierra Energy subsequently sold the ABCP and received a net amount of US $22.7 million including accrued interest.
Lundin Strikes Oil at Tellus Prospect
Lundin Strikes Oil at Tellus Prospect
Wednesday, April 06, 2011
Lundin Petroleum AB
Lundin operator of production license 338, has completed well 16/1-15 on the Tellus prospect as an oil discovery, using semisub Bredford Dolphin. The well has been successfully tested and a comprehensive logging and coring program has been acquired. The well will now be sidetracked to appraise the Tellus discovery to ensure it will be included in the Luno development program.
Oil was proven in a 50 meter column including a 3 meter thick lower Cretaceous sandstone with excellent reservoir quality overlying porous, fractured basement. The oil is of the same type as found in Luno, and the Tellus discovery is most likely a northern extension of the Luno field.
Two successful reservoir tests have been completed. The first test was perforated in a fractured basement interval and produced 650 BOPD, through a 40/64" choke. This is the first successful full scale basement test on the Norwegian continental shelf. The second test was perforated in the overlying sandstone interval and produced 3900 BOPD through a 40/64" choke. This test showed very good flow properties and good pressure support.
An estimate of the discovered resources will be announced once the sidetrack has been completed.
Lundin Petroleum is the operator of PL338 with 50 percent interest. Partners are Wintershall Norge ASA with 30 percent and RWE Dea Norge AS with 20 percent interest.
Ashley Heppenstall, President and CEO of Lundin Petroleum commented, "We are very pleased with this latest discovery which has proven a likely extension of the Luno field. The location of the Tellus discovery to the Luno field will allow us to fast track the development of Tellus by including it into the Luno development plan.The basement discovery is also material and has the potential to open further prospectivity in the Greater Luno area and provides us with excellent data in relation to the earlier Luno South basement discovery."
Wednesday, April 06, 2011
Lundin Petroleum AB
Lundin operator of production license 338, has completed well 16/1-15 on the Tellus prospect as an oil discovery, using semisub Bredford Dolphin. The well has been successfully tested and a comprehensive logging and coring program has been acquired. The well will now be sidetracked to appraise the Tellus discovery to ensure it will be included in the Luno development program.
Oil was proven in a 50 meter column including a 3 meter thick lower Cretaceous sandstone with excellent reservoir quality overlying porous, fractured basement. The oil is of the same type as found in Luno, and the Tellus discovery is most likely a northern extension of the Luno field.
Two successful reservoir tests have been completed. The first test was perforated in a fractured basement interval and produced 650 BOPD, through a 40/64" choke. This is the first successful full scale basement test on the Norwegian continental shelf. The second test was perforated in the overlying sandstone interval and produced 3900 BOPD through a 40/64" choke. This test showed very good flow properties and good pressure support.
An estimate of the discovered resources will be announced once the sidetrack has been completed.
Lundin Petroleum is the operator of PL338 with 50 percent interest. Partners are Wintershall Norge ASA with 30 percent and RWE Dea Norge AS with 20 percent interest.
Ashley Heppenstall, President and CEO of Lundin Petroleum commented, "We are very pleased with this latest discovery which has proven a likely extension of the Luno field. The location of the Tellus discovery to the Luno field will allow us to fast track the development of Tellus by including it into the Luno development plan.The basement discovery is also material and has the potential to open further prospectivity in the Greater Luno area and provides us with excellent data in relation to the earlier Luno South basement discovery."
Marathon to Sell Stake in Niobrara Shale Play
Marathon to Sell Stake in Niobrara Shale Play
Wednesday, April 06, 2011
Marathon Oil Corp.
Marathon Oil has signed an agreement with Marubeni Denver Julesburg, a subsidiary of Marubeni Corp., under which Marathon will assign a portion of its interest in the Niobrara shale play within the DJ Basin of southeast Wyoming and northern Colorado. Under terms of the agreement, Marubeni will receive a 30 percent undivided working interest in Marathon's approximately 180,000 net acres in the DJ Basin for a total consideration of $270 million, or $5,000 per acre. The companies expect to close this transaction by April 28, 2011.
"Marathon is pleased to partner with Marubeni as we prepare to explore and evaluate the full potential of this emerging, liquids-rich resource play," said Dave Roberts, Marathon's executive vice president, Upstream. "Our significant acreage position in the DJ Basin reinforces our strategy of targeting unconventional, oil-focused resource plays in the U.S. that provide low-risk, scalable growth opportunities. It also allows us to apply expertise developed over the past several years in other unconventional shale plays such as the Bakken formation in North Dakota."
Marathon began leasing acreage in the DJ Basin in 2010. The Company is currently acquiring 2-D and 3-D seismic data and expects to participate in eight to 12 gross exploration wells by the end of the year. Marathon will be operator of the jointly owned leasehold.
Wednesday, April 06, 2011
Marathon Oil Corp.
Marathon Oil has signed an agreement with Marubeni Denver Julesburg, a subsidiary of Marubeni Corp., under which Marathon will assign a portion of its interest in the Niobrara shale play within the DJ Basin of southeast Wyoming and northern Colorado. Under terms of the agreement, Marubeni will receive a 30 percent undivided working interest in Marathon's approximately 180,000 net acres in the DJ Basin for a total consideration of $270 million, or $5,000 per acre. The companies expect to close this transaction by April 28, 2011.
"Marathon is pleased to partner with Marubeni as we prepare to explore and evaluate the full potential of this emerging, liquids-rich resource play," said Dave Roberts, Marathon's executive vice president, Upstream. "Our significant acreage position in the DJ Basin reinforces our strategy of targeting unconventional, oil-focused resource plays in the U.S. that provide low-risk, scalable growth opportunities. It also allows us to apply expertise developed over the past several years in other unconventional shale plays such as the Bakken formation in North Dakota."
Marathon began leasing acreage in the DJ Basin in 2010. The Company is currently acquiring 2-D and 3-D seismic data and expects to participate in eight to 12 gross exploration wells by the end of the year. Marathon will be operator of the jointly owned leasehold.
Tethys Oil Reports Heavy Oil Discovery in Oman
Tethys Oil Reports Heavy Oil Discovery in Oman
Wednesday, April 06, 2011
Wednesday, April 06, 2011
Tethys Oil AB
Tethys Oil reported that work on well SE-7 on Block 4 onshore the Sultanate of Oman has been completed. The well encountered several intervals of heavy oil, but no flows were established. The rig has moved to Block 3 to drill the Farha South-7 well.
SE-7 successfully reached a total depth of 1,890 meters, where the main target was to test the presence of oil in the Khufai section in the southern part of the Saiwan East structure. The well identified a more than 90 meter thick column of intermittent heavy oil saturation in the upper parts of the Khufai. A limited test program was run, using a wireline MDT tool, but no flows were established. As expected heavy oil was also encountered in the shallower Buah, Miqrat and Amin formations. SE-7 has been temporarily suspended for possible testing and further study.
The rig has been moved to drill the Farha South-7 well ("FS-7") on Block 3, an appraisal well designed to test for the presence of oil in the Lower Al Bashir section nearby the Farha South-3 well, in the Farha South field. The drill site is located 425 meters southwest of FS-3, drilled in early 2009.
Tethys has a 30 percent interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East B.V. with 20 percent and the operator CC Energy Development S.A.L. (Oman branch) holding the remaining 50 percent.
SE-7 successfully reached a total depth of 1,890 meters, where the main target was to test the presence of oil in the Khufai section in the southern part of the Saiwan East structure. The well identified a more than 90 meter thick column of intermittent heavy oil saturation in the upper parts of the Khufai. A limited test program was run, using a wireline MDT tool, but no flows were established. As expected heavy oil was also encountered in the shallower Buah, Miqrat and Amin formations. SE-7 has been temporarily suspended for possible testing and further study.
The rig has been moved to drill the Farha South-7 well ("FS-7") on Block 3, an appraisal well designed to test for the presence of oil in the Lower Al Bashir section nearby the Farha South-3 well, in the Farha South field. The drill site is located 425 meters southwest of FS-3, drilled in early 2009.
Tethys has a 30 percent interest in Blocks 3 and 4. Partners are Mitsui E&P Middle East B.V. with 20 percent and the operator CC Energy Development S.A.L. (Oman branch) holding the remaining 50 percent.
Beach Completes Drilling at Holdfast Shale Well
Beach Completes Drilling at Holdfast Shale Well
Wednesday, April 06, 2011
Wednesday, April 06, 2011
Beach Energy Ltd.
Beach has successfully completed drilling and evaluation of the Holdfast-1 shale gas well, with production casing to follow. This well is the second of Beach's two well shale evaluation program targeting the Roseneath-Epsilon-Murteree (REM) shale sequence in PEL 218 in the Cooper Basin.
Extensive coring was undertaken at Holdfast-1 with over 350 meters of the target shale sequence and adjacent strata recovered. Analysis of the Holdfast-1 core will commence immediately. A thorough evaluation is currently being undertaken on core from the Encounter-1 well, which intersected a thicker sequence of shale than initially prognosed.
The thickness of the REM target section at Holdfast-1 is in line with pre-drill estimates and confirms that the REM sequence thickens off structure. The REM section as well as the tight sands of the Daralingie and Patchawarra (outside structural closure) are interpreted to be gas saturated. At Encounter-1, the sandstones of the Toolachee formation (also outside structural closure) have been interpreted as gas saturated and as a result will also be evaluated at Holdfast-1. These tight sands outside of structural closure potentially add to the resource in PEL 218.
In mid May, Encounter-1 and Holdfast-1 are scheduled to be fracture stimulated with up to eight fraccing intervals planned. These wells will then be flow tested, the information from which, along with the analysis of the core from both wells, will likely result in a resource addition for both wells in Q3 2010.
PEL 218 Permian Joint Venture - Beach (90% and operator), Adelaide Energy (10%)
Extensive coring was undertaken at Holdfast-1 with over 350 meters of the target shale sequence and adjacent strata recovered. Analysis of the Holdfast-1 core will commence immediately. A thorough evaluation is currently being undertaken on core from the Encounter-1 well, which intersected a thicker sequence of shale than initially prognosed.
The thickness of the REM target section at Holdfast-1 is in line with pre-drill estimates and confirms that the REM sequence thickens off structure. The REM section as well as the tight sands of the Daralingie and Patchawarra (outside structural closure) are interpreted to be gas saturated. At Encounter-1, the sandstones of the Toolachee formation (also outside structural closure) have been interpreted as gas saturated and as a result will also be evaluated at Holdfast-1. These tight sands outside of structural closure potentially add to the resource in PEL 218.
In mid May, Encounter-1 and Holdfast-1 are scheduled to be fracture stimulated with up to eight fraccing intervals planned. These wells will then be flow tested, the information from which, along with the analysis of the core from both wells, will likely result in a resource addition for both wells in Q3 2010.
PEL 218 Permian Joint Venture - Beach (90% and operator), Adelaide Energy (10%)
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