Commodity Corner: Crude Climbs on Equities, Mideast
Tuesday, March 29, 2011
Rigzone Staff
by Saaniya Bangee
Crude futures advanced 0.8 percent Tuesday on stronger equities and doubts on whether Libyan rebels can resume crude exports within a week.
Tuesday's stock market rally helped oil prices snap out of a 3-day slump, settling at $104.79 a barrel. The 81-cent gain came in anticipation of increased oil demand in the U.S. As the first quarter for 2011 nears close, the Dow Jones Industrial Average and the Standard & Poor's 500 Index both gained 0.7 percent in afternoon trading.
Earlier Tuesday, prices fell to $102.70 a barrel on Libyan rebels' promise to swiftly return crude exports to markets. Traders remain weary as to how quickly and capable Libya will be in resuming exports, along with the remaining uncertainty in the Middle East.
Meanwhile, natural gas futures for April delivery fell by 3.1 percent to settle at $4.24 per thousand cubic feet. The April contract expired at Tuesday's settlement, which traders seized as an opportunity to cash out previous profits.
The Energy Information Administration reported 66.67 billion cubic feet a day, 0.5 percent lower, for U.S. natural gas production in the lower 48 states. The drop was still 6.8 percent higher from year-earlier levels.
Natural gas prices fluctuated between $4.195 and $4.37 Tuesday.
Front-month gasoline ended up Tuesday, settling at a session high of $3.05 a gallon. The session bottomed out at $3.01 a gallon.
Tuesday, March 29, 2011
China #1 In Clean Energy Investment, U.S. Slips Behind Germany To #3
China #1 In Clean Energy Investment, U.S. Slips Behind Germany To #3
The Pew Environmental Group today released the 2010 edition of "Who's Winning the Clean Energy Race?" The report showed China retaining its #1 spot on the list, having invested $54.4 billion in 2010, up from $39.1 billion in 2009.
Germany jumped the U.S. to come in at #2, investing $41.2 billion, even though American investment increased 51% to $34 billion. The top 3 were far ahead of the rest of the pack, with Italy, at $13.9 billion, and Brazil, at $7.6 billion, rounding out the top 5.
The report also noted that China is the world's leading producer of wind turbines and solar energy units, and that the country overtook the U.S. as the nation with the most installed clean energy capacity in 2009.
Total worldwide installed wind energy capacity grew 20.6% in 2010 to 193 gigawatts, with global solar capacity increasing a whopping 65.3% to 43 gigawatts.
The Pew Environmental Group today released the 2010 edition of "Who's Winning the Clean Energy Race?" The report showed China retaining its #1 spot on the list, having invested $54.4 billion in 2010, up from $39.1 billion in 2009.
Germany jumped the U.S. to come in at #2, investing $41.2 billion, even though American investment increased 51% to $34 billion. The top 3 were far ahead of the rest of the pack, with Italy, at $13.9 billion, and Brazil, at $7.6 billion, rounding out the top 5.
The report also noted that China is the world's leading producer of wind turbines and solar energy units, and that the country overtook the U.S. as the nation with the most installed clean energy capacity in 2009.
Total worldwide installed wind energy capacity grew 20.6% in 2010 to 193 gigawatts, with global solar capacity increasing a whopping 65.3% to 43 gigawatts.
Noble Energy Seeks 2nd Deep-Water Gulf Drilling Permit -CEO
Noble Energy Seeks 2nd Deep-Water Gulf Drilling Permit -CEO
Tuesday, March 29, 2011
Dow Jones Newswires
Tuesday, March 29, 2011
Dow Jones Newswires
by Ryan Dezember
Noble, which late last month received the first permit to drill in the Gulf of Mexico's deep waters since the deadly Deepwater Horizon disaster, is seeking permits to drill another prospect of the coast of Louisiana, Chief Executive Charles Davidson said.
"The outlook for the deep-water Gulf of Mexico is certainly much brighter today than it was a few months ago," Davidson told investors during a conference here. "We continue to see a lot of opportunities to drill in the deep-water Gulf of Mexico."
The Houston oil and gas explorer on Feb. 28 was awarded a permit to resume drilling its Santiago prospect, located in about 6,500 feet of water about 70 miles southeast of Venice, La.
Noble had been drilling the Santiago well, which it owns with BP and private explorers Red Willow Production Co. and Houston Energy Partners, when U.S. regulators shut down deep-water drilling in response to the April 20, 2010 Deepwater Horizon explosion and the subsequent oil spill.
Since giving Noble a permit, U.S. regulators have issued drilling permits for five other deep-water wells, each to a different operators. Noble officials say they expect to begin drilling the Santiago well in the next several weeks.
"We're not over the hump by any means," Davidson said. "There's going to be a lot of work to get the industry back to the full pace that it needs to be, but we're certainly taking some good steps here in the last month or so."
Noble has asked regulators to also let it begin drilling its Deep Blue prospect, which is west of Santiago and was also underway when the government halted such operations, Davison said.
"We're still working through the permitting process on Deep Blue," Davidson said.
Noble was also the first producer to win government permission to complete a well after the Deepwater Horizon disaster, and the company expects production from that well, located near Santiago, to begin late this year or early 2012. Noble's share of its output is expected to be between 7,000 and 8,000 barrels of oil per day, Davidson said.
"The outlook for the deep-water Gulf of Mexico is certainly much brighter today than it was a few months ago," Davidson told investors during a conference here. "We continue to see a lot of opportunities to drill in the deep-water Gulf of Mexico."
The Houston oil and gas explorer on Feb. 28 was awarded a permit to resume drilling its Santiago prospect, located in about 6,500 feet of water about 70 miles southeast of Venice, La.
Noble had been drilling the Santiago well, which it owns with BP and private explorers Red Willow Production Co. and Houston Energy Partners, when U.S. regulators shut down deep-water drilling in response to the April 20, 2010 Deepwater Horizon explosion and the subsequent oil spill.
Since giving Noble a permit, U.S. regulators have issued drilling permits for five other deep-water wells, each to a different operators. Noble officials say they expect to begin drilling the Santiago well in the next several weeks.
"We're not over the hump by any means," Davidson said. "There's going to be a lot of work to get the industry back to the full pace that it needs to be, but we're certainly taking some good steps here in the last month or so."
Noble has asked regulators to also let it begin drilling its Deep Blue prospect, which is west of Santiago and was also underway when the government halted such operations, Davison said.
"We're still working through the permitting process on Deep Blue," Davidson said.
Noble was also the first producer to win government permission to complete a well after the Deepwater Horizon disaster, and the company expects production from that well, located near Santiago, to begin late this year or early 2012. Noble's share of its output is expected to be between 7,000 and 8,000 barrels of oil per day, Davidson said.
Musings: Are The Shale Resource Estimates Realistic Or Fantasy?
Musings: Are The Shale Resource Estimates Realistic Or Fantasy?
Tuesday, March 29, 2011
Parks Paton Hoepfl & Brown
Tuesday, March 29, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks
Maybe you've seen the advertisements from various financial newsletters touting the investment potential of companies involved in developing the Bakken oil shale formation that spreads across North Dakota and Montana and into the neighboring Canadian provinces of Saskatchewan and Manitoba. The claims, which several years ago appeared outrageous, of the Bakken containing eight times the amount of oil as in Saudi Arabia or 21-times the reserves held by Kuwait seem less than fantasy today.
These newsletters began trumpeting the financial impact of the Bakken for various oil exploration companies active in the formation following the 2008 U.S. Geological Service (USGS) revised estimate for the basin's reserve potential suggesting it might contain between 3.0-4.3 billion barrels, a 25-fold increase over the organization's prior estimate made in 1995, which said the field might contain 151 million barrels.
The USGS stated that the Bakken formation is estimated to be larger than all other current USGS oil field assessments in the Lower 48. The agency called it the largest "continuous" oil accumulation ever assessed. This means the oil is spread rather evenly across the basin as opposed to being located in discrete deposits. The next largest continuous oil deposit is the Austin Chalk trend stretching from Louisiana to central Texas that is estimated to contain 1.0 billion barrels.
Jeff Hume, president and chief operating officer of Continental Resources was quoted in an article not long ago suggesting that there could be as much as 24 billion barrels of reserves in the Bakken formation.
Exhibit 1. Bakken Is U.S. Largest Continuous Oil Field
Source: EIA
The success the domestic exploration and production companies have had in the Bakken has been partially responsible for U.S. oil production growing over the past two years to the highest level in over a decade.
Exhibit 2. Domestic Oil Production Up Last Two Years
Source: EIA
North Dakota's oil production reached a peak last November at 356,697 barrels per day from 5,099 producing wells. Over the past three years, monthly oil production in North Dakota has grown by more than 2.5 times. Production is off slightly in January to 342,088 barrels per day from 5,061 wells. While we can't be certain, we suspect the traditionally harsh winter in that region of the country impacts oil production efforts, especially since the infrastructure to produce much of this additional oil has not kept pace with the rising production.
There have been media stories about the dramatic increase in the number of railroad tanker cars hauling Bakken production to refineries. We are also aware of some of the oil making its way by truck across the US-Canadian border to shipping facilities there. All of that will change as new pipelines are constructed.
Exhibit 3. North Dakota's Oil Production Soaring
Source: North Dakota Natural Resource Department
More important is the growth in drilling, which will be critical for boosting the state's oil and gas production in the future. The most recent Baker Hughes rig count showed 153 working rigs in North Dakota, more than double the count merely 14 months earlier.
According to Mark Williams, senior vice president of exploration and development for Whiting Petroleum, "All current and planned projects could take us up to 1.1 million barrels a day."
The most important factor in the growth of Bakken oil production has been the application of drilling and well completion techniques learned from drilling the gas shales – horizontal wells with longer lateral sections and a greater number of hydraulic fracturing treatments. Estimates are that by applying these technologies, Bakken wells that were drilled only a few years ago might produce 100,000-200,000 barrels over their lifetime but are now getting 400,000-700,000 barrels out of the deposits. Even though the cost to drill and complete these newer wells is greater than for the older wells, the economics of greater production, especially at today's $100 per barrel oil price, are extremely attractive.
These newsletters began trumpeting the financial impact of the Bakken for various oil exploration companies active in the formation following the 2008 U.S. Geological Service (USGS) revised estimate for the basin's reserve potential suggesting it might contain between 3.0-4.3 billion barrels, a 25-fold increase over the organization's prior estimate made in 1995, which said the field might contain 151 million barrels.
The USGS stated that the Bakken formation is estimated to be larger than all other current USGS oil field assessments in the Lower 48. The agency called it the largest "continuous" oil accumulation ever assessed. This means the oil is spread rather evenly across the basin as opposed to being located in discrete deposits. The next largest continuous oil deposit is the Austin Chalk trend stretching from Louisiana to central Texas that is estimated to contain 1.0 billion barrels.
Jeff Hume, president and chief operating officer of Continental Resources was quoted in an article not long ago suggesting that there could be as much as 24 billion barrels of reserves in the Bakken formation.
Exhibit 1. Bakken Is U.S. Largest Continuous Oil Field
Source: EIA
The success the domestic exploration and production companies have had in the Bakken has been partially responsible for U.S. oil production growing over the past two years to the highest level in over a decade.
Exhibit 2. Domestic Oil Production Up Last Two Years
Source: EIA
North Dakota's oil production reached a peak last November at 356,697 barrels per day from 5,099 producing wells. Over the past three years, monthly oil production in North Dakota has grown by more than 2.5 times. Production is off slightly in January to 342,088 barrels per day from 5,061 wells. While we can't be certain, we suspect the traditionally harsh winter in that region of the country impacts oil production efforts, especially since the infrastructure to produce much of this additional oil has not kept pace with the rising production.
There have been media stories about the dramatic increase in the number of railroad tanker cars hauling Bakken production to refineries. We are also aware of some of the oil making its way by truck across the US-Canadian border to shipping facilities there. All of that will change as new pipelines are constructed.
Exhibit 3. North Dakota's Oil Production Soaring
Source: North Dakota Natural Resource Department
More important is the growth in drilling, which will be critical for boosting the state's oil and gas production in the future. The most recent Baker Hughes rig count showed 153 working rigs in North Dakota, more than double the count merely 14 months earlier.
According to Mark Williams, senior vice president of exploration and development for Whiting Petroleum, "All current and planned projects could take us up to 1.1 million barrels a day."
The most important factor in the growth of Bakken oil production has been the application of drilling and well completion techniques learned from drilling the gas shales – horizontal wells with longer lateral sections and a greater number of hydraulic fracturing treatments. Estimates are that by applying these technologies, Bakken wells that were drilled only a few years ago might produce 100,000-200,000 barrels over their lifetime but are now getting 400,000-700,000 barrels out of the deposits. Even though the cost to drill and complete these newer wells is greater than for the older wells, the economics of greater production, especially at today's $100 per barrel oil price, are extremely attractive.
Australia Players Still Pursuing Cooper Basin Shale Gas Potential
Australia Players Still Pursuing Cooper Basin Shale Gas Potential
Tuesday, March 29, 2011
Rigzone Staff
by Karen Boman
Despite once-in-a-generation rainfall and flooding that disrupted exploration and production activity last year, Australia-based oil and gas producers are forging ahead this year with plans this year to drill for and develop the Cooper Basin's conventional and unconventional oil and gas resources.
Santos Ltd., noted that reports of the death of Australia's onshore Cooper Basin, which stretches across the northeast corner of South Australia into southwestern Queensland, are "greatly exaggerated" as the basin contains unconventional gas resource potential of more than 39,000 petajoules (PJ) and booked contingent resources of about 5,000 pj. Santos reports that undeveloped unconventional shale gas resources lay beneath the developed conventional resource Moomba basin, while tight gas and deep coal exist below shale gas. Gross gas thickness in the Cooper is approximately 1,600 feet.
Another Australia-based oil and gas company, Beach Energy, reports it has an aggressive exploration and development program planned for this year in its Cooper Basin holdings, and better land access for these activities following the Cooper Basin floods of last year, which washed out roads and prevented companies from accessing work sites.
The company currently operates 19 oil fields in the Cooper-Eromanga with five gas discoveries awaiting development and owns an approximate 21% interest in the Cooper Basin project operated by Santos. Since late 2006, Beach has participated in more than 100 oil wells operated by Santos, delivering net reserves of 4 million barrels. Beach Energy is in discussions with Santos, to supply its Gladstone liquefied natural gas (LNG) project.
Cooper Basin Beach said its Cooper Basin position will allow it to tap the growing eastern Australian gas markets while also feeding the growing LNG demand in Asia. Beach noted that current Australian gas demand is approximately 700 pj per year, with around 100 pj to come from the Cooper Basin. Demand for more Cooper Basin gas is anticipated as domestic gas demand for use in power generation is expected to grow to around 1,100 pj by 2025.
The company estimates the Nappamerri Trough, which runs beneath its PEL 218 license, holds potential gas in place of more 200 Tcf, and holds properties similar to the best U.S. shale plays. Beach has drilled off-structure to determine the trough's deep basin gas potential, and found the target section thicker than anticipated at 1,289 feet and the target section gas saturated and over-pressured. Beach noted that no water bearing permeable sections were intersected in the target zone and immediately above and below target; the lack of water in these zones will assist in fracture stimulation.
The company has drilled two wells in PEL 218, which contains the Nappamerri Trough. The shale and sandstone target area for Beach's Encounter-1 well was 30 percent thicker than expected; Beach also spudded the Holdfast-1 well in January of this year.
Beach notes it has had encouraging results to date and expects material resource booking to take place this year. Results will assist in the design of future activities, including fracture stimulation in this year's second quarter and a pilot well program in the third or fourth quarter.
The company also sees near-term growth opportunities for oil in the Western Flank of the Cooper Basin. Beach began an operated 16-well development program here last month to accelerate production and will drill 12 exploration/appraisal wells with prospects ranging from .5 million barrels to 5.5 million barrel (gross).
The Cooper/Eromanga Basin Drillsearch, which holds significant interests in the Cooper Basin, will began a five-well drilling program next month at its PEL91 license in Cooper's Basin's Western Flank. The five prospects, whose primary targets are the Namur and Birkhead channel, have estimated recoverable mean barrels of between 430,000 and 1.1 million. These prospects were defined using 3D seismic analysis; historically, Drillsearch has had 50 percent success rates using 3D seismic. Multiple commercial discoveries have been made on adjacent permits, and Drillsearch anticipates a short development cycle for the wells.
The company anticipates a formal award at mid-year for nine blocks in southwest Queensland, which will expand its Cooper Basin holdings. Drillsearch expects potential farm-outs of select areas starting in this year's second quarter.
Drillsearch is planning a significant drilling program for its estimated wet gas resources of 11.5 million BOE in the Cooper Basin. The company has made 10 gas/condensate discoveries in the area, including four declared commercial, and will pursue potential pilot development of the Middleton, Brownlow and Canunda discoveries. In the near term, the company plans a five well appraisal, development and near-field exploration program in PEL106B and PEL107.
Bengal Energy reports it has defined numerous leads and prospects on the Tookoonooka exploration permit ATP 732P, which the Queensland government announced a final grant of title to for Bengal effective April 1. Bengal will begin gather seismic data on the block and plans to drill between five and eight wells over the next 18 months. The company said the large block is offset by producing oil and gas fields, and features seven different play types, including four conventional light oil plays, two conventional gas and gas liquid plays, and one unconventional gas play.
The company also reports finding new potential fairway for oil-bearing Cretaceous Murta sandstones in its Cuisinier 1 discovery well, which began production in May 2010. Three wells are awaiting completion and testing either this month or in April, with the Cuisinier 3 cased as a potential oil well.
Tuesday, March 29, 2011
Rigzone Staff
by Karen Boman
Despite once-in-a-generation rainfall and flooding that disrupted exploration and production activity last year, Australia-based oil and gas producers are forging ahead this year with plans this year to drill for and develop the Cooper Basin's conventional and unconventional oil and gas resources.
Santos Ltd., noted that reports of the death of Australia's onshore Cooper Basin, which stretches across the northeast corner of South Australia into southwestern Queensland, are "greatly exaggerated" as the basin contains unconventional gas resource potential of more than 39,000 petajoules (PJ) and booked contingent resources of about 5,000 pj. Santos reports that undeveloped unconventional shale gas resources lay beneath the developed conventional resource Moomba basin, while tight gas and deep coal exist below shale gas. Gross gas thickness in the Cooper is approximately 1,600 feet.
Another Australia-based oil and gas company, Beach Energy, reports it has an aggressive exploration and development program planned for this year in its Cooper Basin holdings, and better land access for these activities following the Cooper Basin floods of last year, which washed out roads and prevented companies from accessing work sites.
The company currently operates 19 oil fields in the Cooper-Eromanga with five gas discoveries awaiting development and owns an approximate 21% interest in the Cooper Basin project operated by Santos. Since late 2006, Beach has participated in more than 100 oil wells operated by Santos, delivering net reserves of 4 million barrels. Beach Energy is in discussions with Santos, to supply its Gladstone liquefied natural gas (LNG) project.
Cooper Basin
The company estimates the Nappamerri Trough, which runs beneath its PEL 218 license, holds potential gas in place of more 200 Tcf, and holds properties similar to the best U.S. shale plays. Beach has drilled off-structure to determine the trough's deep basin gas potential, and found the target section thicker than anticipated at 1,289 feet and the target section gas saturated and over-pressured. Beach noted that no water bearing permeable sections were intersected in the target zone and immediately above and below target; the lack of water in these zones will assist in fracture stimulation.
The company has drilled two wells in PEL 218, which contains the Nappamerri Trough. The shale and sandstone target area for Beach's Encounter-1 well was 30 percent thicker than expected; Beach also spudded the Holdfast-1 well in January of this year.
Beach notes it has had encouraging results to date and expects material resource booking to take place this year. Results will assist in the design of future activities, including fracture stimulation in this year's second quarter and a pilot well program in the third or fourth quarter.
The company also sees near-term growth opportunities for oil in the Western Flank of the Cooper Basin. Beach began an operated 16-well development program here last month to accelerate production and will drill 12 exploration/appraisal wells with prospects ranging from .5 million barrels to 5.5 million barrel (gross).
The Cooper/Eromanga Basin
The company anticipates a formal award at mid-year for nine blocks in southwest Queensland, which will expand its Cooper Basin holdings. Drillsearch expects potential farm-outs of select areas starting in this year's second quarter.
Drillsearch is planning a significant drilling program for its estimated wet gas resources of 11.5 million BOE in the Cooper Basin. The company has made 10 gas/condensate discoveries in the area, including four declared commercial, and will pursue potential pilot development of the Middleton, Brownlow and Canunda discoveries. In the near term, the company plans a five well appraisal, development and near-field exploration program in PEL106B and PEL107.
Bengal Energy reports it has defined numerous leads and prospects on the Tookoonooka exploration permit ATP 732P, which the Queensland government announced a final grant of title to for Bengal effective April 1. Bengal will begin gather seismic data on the block and plans to drill between five and eight wells over the next 18 months. The company said the large block is offset by producing oil and gas fields, and features seven different play types, including four conventional light oil plays, two conventional gas and gas liquid plays, and one unconventional gas play.
The company also reports finding new potential fairway for oil-bearing Cretaceous Murta sandstones in its Cuisinier 1 discovery well, which began production in May 2010. Three wells are awaiting completion and testing either this month or in April, with the Cuisinier 3 cased as a potential oil well.
Government Tries to Clarify Offshore Drilling Rules
Government Tries to Clarify Offshore Drilling Rules
Tuesday, March 29, 2011
Houston Chronicle
The federal government on Monday issued a five-page memo meant to clarify rules for offshore drilling, in response to oil and gas industry complaints that new mandates imposed since last year's Gulf spill are muddled.
The federal Bureau of Ocean Energy Management, Regulation and Enforcement also said it would reopen a public comment period to help guide the agency's possible rewrite of a drilling safety rule put in place last October.
"Our goal remains the same as it has been from day one: to ensure that offshore operations are conducted as safely as possible," said Michael Bromwich, the bureau's director. "This guidance document gives deep-water drilling operators additional information to help address some of the recurring issues that have been raised in our ongoing discussions with industry."
The document covers several areas but focuses on a major source of industry complaints: confusion about the wording of the October offshore drilling safety rule. That measure adopted two sets of recommended practices for emergency equipment and well design that had been developed by the American Petroleum Institute.
The problem was that instead of rewriting those mandates in their own words, government regulators simply referenced API documents and specified that any time the API recommended practices said "should" it now meant "must" under the interim drilling safety rule.
Industry representatives complained that the changes affected more than 14,000 discretionary provisions in 80 different standards, and in some cases, those new requirements were conflicting.
For instance, API's recommended well construction practices sometimes offer operators an array of options that might make sense, but the language of the rule seemed to make all of those options mandatory.
"There are areas where it says you should do this or you should do that," said Al Reese Jr., the chief operating officer of Houston-based ATP Oil & Gas. "But I can't turn left and turn right at the same time."
His company navigated the process and received a permit to resume a deep-water pro-ject in the Gulf of Mexico.
A positive step
The new guidance document clarifies that operators are allowed to select "any of the appropriate options," without getting special permission from the bureau.
It also suggests that oil and gas companies maintain documentation demonstrating they evaluated the recommended practices, even when the government's rule doesn't make them mandatory.
Erik Milito, the upstream director at the American Petroleum Institute, called the announcement a positive step.
"Ensuring a clear, consistent and efficient process for offshore regulatory requirements and for approvals of permits is a crucial component to steadily increasing offshore production," he said.
'Departure documents'
With Monday's memo, the ocean energy bureau also formalized a process it has used in approving six deep-water drilling projects in the Gulf of Mexico -- "departure documents" that specify how individual operators are not strictly following the API recommended practices incorporated in the drilling safety rule.
The ocean energy bureau said that whenever oil companies intend to deviate from the recommended practices incorporated in the rule, they must get approval to use alternate procedures or equipment.
The bureau said that it is evaluating potential revisions to the drilling safety rule "in light of comments received from the public and other considerations."
The government said that it will reopen the public comment period, probably within a month, giving people another chance to tell the bureau what works and what doesn't.
Any rewrite of the rule would take months, or longer.
Tuesday, March 29, 2011
Houston Chronicle
by Jennifer A. Dlouhy
The federal Bureau of Ocean Energy Management, Regulation and Enforcement also said it would reopen a public comment period to help guide the agency's possible rewrite of a drilling safety rule put in place last October.
"Our goal remains the same as it has been from day one: to ensure that offshore operations are conducted as safely as possible," said Michael Bromwich, the bureau's director. "This guidance document gives deep-water drilling operators additional information to help address some of the recurring issues that have been raised in our ongoing discussions with industry."
The document covers several areas but focuses on a major source of industry complaints: confusion about the wording of the October offshore drilling safety rule. That measure adopted two sets of recommended practices for emergency equipment and well design that had been developed by the American Petroleum Institute.
The problem was that instead of rewriting those mandates in their own words, government regulators simply referenced API documents and specified that any time the API recommended practices said "should" it now meant "must" under the interim drilling safety rule.
Industry representatives complained that the changes affected more than 14,000 discretionary provisions in 80 different standards, and in some cases, those new requirements were conflicting.
For instance, API's recommended well construction practices sometimes offer operators an array of options that might make sense, but the language of the rule seemed to make all of those options mandatory.
"There are areas where it says you should do this or you should do that," said Al Reese Jr., the chief operating officer of Houston-based ATP Oil & Gas. "But I can't turn left and turn right at the same time."
His company navigated the process and received a permit to resume a deep-water pro-ject in the Gulf of Mexico.
A positive step
The new guidance document clarifies that operators are allowed to select "any of the appropriate options," without getting special permission from the bureau.
It also suggests that oil and gas companies maintain documentation demonstrating they evaluated the recommended practices, even when the government's rule doesn't make them mandatory.
Erik Milito, the upstream director at the American Petroleum Institute, called the announcement a positive step.
"Ensuring a clear, consistent and efficient process for offshore regulatory requirements and for approvals of permits is a crucial component to steadily increasing offshore production," he said.
'Departure documents'
With Monday's memo, the ocean energy bureau also formalized a process it has used in approving six deep-water drilling projects in the Gulf of Mexico -- "departure documents" that specify how individual operators are not strictly following the API recommended practices incorporated in the drilling safety rule.
The ocean energy bureau said that whenever oil companies intend to deviate from the recommended practices incorporated in the rule, they must get approval to use alternate procedures or equipment.
The bureau said that it is evaluating potential revisions to the drilling safety rule "in light of comments received from the public and other considerations."
The government said that it will reopen the public comment period, probably within a month, giving people another chance to tell the bureau what works and what doesn't.
Any rewrite of the rule would take months, or longer.
DNS Outlines Strategy to Aid UK Companies in Decommissioning Work
DNS Outlines Strategy to Aid UK Companies in Decommissioning Work
Tuesday, March 29, 2011
Rigzone Staff
by Karen Boman
Decom North Sea (DNS), an industry body established in 2010 to assist UK companies in obtaining work opportunities in future North Sea decommissioning activity, now has more than 120 members, and is stepping up effort to help companies pursue decommissioning work opportunities.
DNS Chief Executive Brian Nixon said, "With around £1billion of decommissioning expenditure forecast annually for the UK North Sea by 2015 and only 7% of projects completed to date, there is a clear need for us to support our supply chain to secure maximum business potential.
"Compelling support was recorded for Decom North Sea to look at increasing current activities, namely networking events which provide value to our members; regional and topical focus groups; industry communication and knowledge sharing; mapping the supply chain strengths and capabilities; further development of appropriate contracting models: and facilitating introductions across the industry."
In addition, a range of more strategic initiatives and opportunities have been identified and prioritized including the following:-
In line with the priorities identified, DNS has organized a program of events, seminars and share fairs in collaboration with regional energy development organizations and government agencies, with activity covering the north-east, Highlands and Central Belt in Scotland, and the north-east and south-east in England where most of the potential supply chain for the decommissioning market is based.
DNS Board Chairman Murdo MacIver said, "One of the principle reasons for setting up Decom North Sea was to provide a mechanism for sharing non commercial information and to establish a platform that would allow companies from across the industry to obtain consistent and clear information. The recent strategy consultation, which involved all the new directors recently voted onto the board, has fully supported this and it is great to see some real drive and enthusiasm from the board in delivering these strategic objectives."
Tuesday, March 29, 2011
Rigzone Staff
by Karen Boman
Decom North Sea (DNS), an industry body established in 2010 to assist UK companies in obtaining work opportunities in future North Sea decommissioning activity, now has more than 120 members, and is stepping up effort to help companies pursue decommissioning work opportunities.
DNS Chief Executive Brian Nixon said, "With around £1billion of decommissioning expenditure forecast annually for the UK North Sea by 2015 and only 7% of projects completed to date, there is a clear need for us to support our supply chain to secure maximum business potential.
"Compelling support was recorded for Decom North Sea to look at increasing current activities, namely networking events which provide value to our members; regional and topical focus groups; industry communication and knowledge sharing; mapping the supply chain strengths and capabilities; further development of appropriate contracting models: and facilitating introductions across the industry."
In addition, a range of more strategic initiatives and opportunities have been identified and prioritized including the following:-
- provision of detailed and reliable market intelligence drawn from existing industry sources and filtered to be easily accessible by DNS members – (an industry led workgroup has now been established to lead this initiative)
- facilitate groups of members to share information, form alliances, address technologies etc.
- research decommissioning in other sectors including nuclear and salvage, to study how they deal with timing uncertainty, identify areas for transfer of experience, cross business opportunities etc. – (a first workshop on nuclear synergies has been held, with a separate group reviewing the salvage industry)
- be active with governments, regulators and operators on behalf of DNS membership
- understand capabilities and gaps relating to people, processes and technologies, and then put in place mechanisms to address the issues and opportunities – (a skills steering group is now in place)
- promote existing capability, new capacity, case studies etc.
- engage with the financial investment community to understand their drivers – promote awareness of members capabilities and needs, facilitate introductions
- look overseas to identify market opportunities and to promote member capabilities.
In line with the priorities identified, DNS has organized a program of events, seminars and share fairs in collaboration with regional energy development organizations and government agencies, with activity covering the north-east, Highlands and Central Belt in Scotland, and the north-east and south-east in England where most of the potential supply chain for the decommissioning market is based.
DNS Board Chairman Murdo MacIver said, "One of the principle reasons for setting up Decom North Sea was to provide a mechanism for sharing non commercial information and to establish a platform that would allow companies from across the industry to obtain consistent and clear information. The recent strategy consultation, which involved all the new directors recently voted onto the board, has fully supported this and it is great to see some real drive and enthusiasm from the board in delivering these strategic objectives."
Iraq, Shell Resolve Last Obstacle to $12B Gas Deal -Official
Iraq, Shell Resolve Last Obstacle to $12B Gas Deal -Official
Tuesday, March 29, 2011
Dow Jones Newswires
Tuesday, March 29, 2011
Dow Jones Newswires
by Hassan Hafidh
The Iraqi Oil Ministry and Shell have removed the last obstacle preventing them from signing a long-awaited $12 billion joint-venture deal, a senior Iraqi oil official said Tuesday.
The main dispute was over the rights of export. Shell, along with its partner Japan's Mitsubishi, wanted to handle exports, while under current Iraqi hydrocarbon laws the Iraqi State Oil Marketing Organization should do so.
"The issue is nearly resolved," Ali H. Khudhier, head of the state-run South Gas Company told Dow Jones Newswires in an interview in his office in Zubair, south of Basra.
"Shell wanted to handle exports, but now it is agreed that SOMO would handle export," he said. Shell, however, has asked for further discussions as it needs to install an export mechanism, he said.
Last week, the energy committee at the Iraqi council of ministers asked the Oil Ministry to review the Shell draft deal which aims to capture and exploit millions of cubic feet a day of gas flared from four super-giant oil fields near Basra.
The gas project is crucial to Baghdad's ambitious oil expansion that will also boost much-needed power generation in Iraq.
"Once the energy committee approves the recent changes, we need to sit with Shell to adjust these changes in the draft contract," Khudhier said. He preferred not to give a specific date for signing the deal, but he said it could happen in a matter of weeks.
The joint venture--Basrah Gas Co, or BGC--will process associated gas produced from three supergiant Iraqi fields--Rumaila, West Qurna 1 and Zubair--all located in Basra. The three fields are being developed by international oil companies.
"We are expecting these three fields to produce up to 3 billion cubic feet a day in the coming six to seven years," Khudhier said.
In total, the three fields are currently producing some 1.05 billion cubic feet a day, but only 450 million cubic feet a day are utilized while the rest is flared, he said.
The project is vital to Shell's strategy of positioning itself as a leading gas supplier and producer in the Middle East. After domestic needs are met, an LNG terminal will be built in the Gulf to handle the export of 600 million cubic feet a day.
"The extra gas will be exported to East Asia and Gulf states including Kuwait and the United Arab Emirates," Khudhier said.
He also said Iraq could revive a disused pipeline to export gas to Kuwait. "If the Kuwaitis want to import gas from us, we are ready to supply them," he said. Iraq used to export an average of 200 million cubic feet a day gas to neighboring Kuwait, but sales were suspended when Iraq invaded its neighbor in 1990.
Iraq is home to 126 trillion cubic feet of gas, but produces only around 1.5 billion cubic feet a day--of which 700 million cubic feet a day are burned for lack of infrastructure.
The main dispute was over the rights of export. Shell, along with its partner Japan's Mitsubishi, wanted to handle exports, while under current Iraqi hydrocarbon laws the Iraqi State Oil Marketing Organization should do so.
"The issue is nearly resolved," Ali H. Khudhier, head of the state-run South Gas Company told Dow Jones Newswires in an interview in his office in Zubair, south of Basra.
"Shell wanted to handle exports, but now it is agreed that SOMO would handle export," he said. Shell, however, has asked for further discussions as it needs to install an export mechanism, he said.
Last week, the energy committee at the Iraqi council of ministers asked the Oil Ministry to review the Shell draft deal which aims to capture and exploit millions of cubic feet a day of gas flared from four super-giant oil fields near Basra.
The gas project is crucial to Baghdad's ambitious oil expansion that will also boost much-needed power generation in Iraq.
"Once the energy committee approves the recent changes, we need to sit with Shell to adjust these changes in the draft contract," Khudhier said. He preferred not to give a specific date for signing the deal, but he said it could happen in a matter of weeks.
The joint venture--Basrah Gas Co, or BGC--will process associated gas produced from three supergiant Iraqi fields--Rumaila, West Qurna 1 and Zubair--all located in Basra. The three fields are being developed by international oil companies.
"We are expecting these three fields to produce up to 3 billion cubic feet a day in the coming six to seven years," Khudhier said.
In total, the three fields are currently producing some 1.05 billion cubic feet a day, but only 450 million cubic feet a day are utilized while the rest is flared, he said.
The project is vital to Shell's strategy of positioning itself as a leading gas supplier and producer in the Middle East. After domestic needs are met, an LNG terminal will be built in the Gulf to handle the export of 600 million cubic feet a day.
"The extra gas will be exported to East Asia and Gulf states including Kuwait and the United Arab Emirates," Khudhier said.
He also said Iraq could revive a disused pipeline to export gas to Kuwait. "If the Kuwaitis want to import gas from us, we are ready to supply them," he said. Iraq used to export an average of 200 million cubic feet a day gas to neighboring Kuwait, but sales were suspended when Iraq invaded its neighbor in 1990.
Iraq is home to 126 trillion cubic feet of gas, but produces only around 1.5 billion cubic feet a day--of which 700 million cubic feet a day are burned for lack of infrastructure.
Desire Spuds Ninky Well
Desire Spuds Ninky Well
Desire announced that the 14/15-3 exploration well on the Ninky prospect was spudded at 02.45 BST on March 29, 2011.
The prospect is a combined structural dip and stratigraphic pinch-out trap with multiple reservoir targets within the Barremian source rock interval. The well has a planned total depth of circa 2,620 meters and drilling operations are expected to take approximately 30 days.
Desire announced that the 14/15-3 exploration well on the Ninky prospect was spudded at 02.45 BST on March 29, 2011.
The prospect is a combined structural dip and stratigraphic pinch-out trap with multiple reservoir targets within the Barremian source rock interval. The well has a planned total depth of circa 2,620 meters and drilling operations are expected to take approximately 30 days.
Ithaca Recommences Drilling at Jacky Field
Ithaca Recommences Drilling at Jacky Field
Tuesday, March 29, 2011
Ithaca Energy Inc.
Tuesday, March 29, 2011
Ithaca Energy Inc.
by SubseaIQ
Ithaca announced that drilling of the J03 well on the Jacky field has now recommenced.
The Energy Enhancer drilling unit is now fully operational following successful repair to the drilling mud handling system onboard the rig. Production from J01 was briefly suspended to complete the 'top hole section' of the J03 well and then immediately reinstated. The J03 well has now been drilled to approximately 2,400 feet measured depth and drilling operations are scheduled to last approximately a further 60 days.
The Energy Enhancer drilling unit is now fully operational following successful repair to the drilling mud handling system onboard the rig. Production from J01 was briefly suspended to complete the 'top hole section' of the J03 well and then immediately reinstated. The J03 well has now been drilled to approximately 2,400 feet measured depth and drilling operations are scheduled to last approximately a further 60 days.
Dragon Oil's Lam Well Knighted Dual Producer
Dragon Oil's Lam Well Knighted Dual Producer
Tuesday, March 29, 2011
Tuesday, March 29, 2011
Dragon Oil plc
Dragon Oil announced the completion and initial testing of the Dzheitune (Lam) 28/152 and B/153 development wells. The Dzheitune (Lam) 28/152 well was drilled to a depth of 3,768 meters and completed as a dual producer by the NIS rig. The short string tested at the initial rate of 2,091 barrels of oil per day ("bopd") with the long string testing at 1,372 bopd. The NIS rig has skidded to the next slot and spudded the Dzheitune (Lam) 28/154 well.
The Dzheitune (Lam) B/153 well was drilled by the Iran Khazar rig to the depth of 3,668 meters and completed with dual strings. The short string tested at the initial rate of 1,080 bopd while the initial test result from the long string was 1,348 bopd. The Iran Khazar rig has skidded to the next slot on the Dzheitune (Lam) B platform and spudded the Dzheitune (Lam) B/155 well.
Dr. Abdul Jaleel Al Khalifa, Chief Executive Officer, commented, "I am pleased to report the successful completion and solid initial test results of the Dzheitune (Lam) 28/152 and B/153 development wells, the first two wells of this year's 11-well drilling program to have been put into production. Both rigs, the NIS rig and the Iran Khazar rig, are already drilling the next two wells.
"Following the transition over to the new 30-inch trunkline and associated in-field pipelines, we are continuing to see strong average daily production rates in excess of 57,000 bopd in February and March 2011."
The Dzheitune (Lam) B/153 well was drilled by the Iran Khazar rig to the depth of 3,668 meters and completed with dual strings. The short string tested at the initial rate of 1,080 bopd while the initial test result from the long string was 1,348 bopd. The Iran Khazar rig has skidded to the next slot on the Dzheitune (Lam) B platform and spudded the Dzheitune (Lam) B/155 well.
Dr. Abdul Jaleel Al Khalifa, Chief Executive Officer, commented, "I am pleased to report the successful completion and solid initial test results of the Dzheitune (Lam) 28/152 and B/153 development wells, the first two wells of this year's 11-well drilling program to have been put into production. Both rigs, the NIS rig and the Iran Khazar rig, are already drilling the next two wells.
"Following the transition over to the new 30-inch trunkline and associated in-field pipelines, we are continuing to see strong average daily production rates in excess of 57,000 bopd in February and March 2011."
Lansdowne to Commence Seismic Survey Offshore Ireland
Lansdowne to Commence Seismic Survey Offshore Ireland
Tuesday, March 29, 2011
Lansdowne O&G plc
by SubseaIQ
Lansdowne has signed a contract with Polarcus Limited ("Polarcus") for the acquisition of 3D seismic surveys over the Rosscarbery, Amergin and Midleton Prospects in the North Celtic Sea, offshore Ireland, covering an aggregate area of approximately, 300 square km.
The Lansdowne survey is expected to commence in early July and will follow on from the 3D seismic survey acquisition by Polarcus over the Barryroe oilfield in which Lansdowne has a 20% interest.
Tuesday, March 29, 2011
Lansdowne O&G plc
by SubseaIQ
Lansdowne has signed a contract with Polarcus Limited ("Polarcus") for the acquisition of 3D seismic surveys over the Rosscarbery, Amergin and Midleton Prospects in the North Celtic Sea, offshore Ireland, covering an aggregate area of approximately, 300 square km.
The Lansdowne survey is expected to commence in early July and will follow on from the 3D seismic survey acquisition by Polarcus over the Barryroe oilfield in which Lansdowne has a 20% interest.
Antrim Inks Rig, Services Contract for Greater Fyne Area
Antrim Inks Rig, Services Contract for Greater Fyne Area
Tuesday, March 29, 2011
Tuesday, March 29, 2011
Antrim Energy Inc.
Antrim has signed a Letter of Award with AGR Peak Well Management Limited ("AGR") to provide well project management and drilling services, including the provision of the semi-submersible drilling rig, WilPhoenix, for the drilling of two wells within the Greater Fyne Area, in the UK Central North Sea. The estimated duration for the drilling of the two wells is 50 days, not including testing. A site survey of both locations will be initiated in the next three weeks. Both wells are scheduled to be drilled mid year 2011.
The first well will target the Jurassic Fulmar Formation at approximately 10,400 ft true vertical depth (TVD) on the West Teal Prospect, Block 21/24b (Antrim 100%). The West Teal Prospect has a light oil target (37 degrees API) delineated by 3-D seismic and a previous discovery well drilled in 1991. The original discovery well encountered a gross oil column up to 140 ft thick in the Fulmar Formation but was abandoned after mechanical problems while conducting a cased hole test. The West Teal Prospect is structurally up dip and approximately 4 km west of the Teal Field, which has produced approximately 55 million barrels of oil to date.
The second well is expected to target the Eocene Tay Formation at a depth of approximately 6,000 ft on the Carra Prospect, Block 21/28b (Antrim 100%). The Carra Prospect is a medium gravity target (25 degrees API) delineated by 3-D seismic, on trend and 4 km from the West Guillemot Field. If successful, a discovery on either of these prospects would add significant resources to the scheduled development of the Fyne Field, located 3 km to the northwest of Carra.
Antrim intends to use the proceeds from its recent equity issue to fund the drilling program but will also invite participation from industry partners.
The first well will target the Jurassic Fulmar Formation at approximately 10,400 ft true vertical depth (TVD) on the West Teal Prospect, Block 21/24b (Antrim 100%). The West Teal Prospect has a light oil target (37 degrees API) delineated by 3-D seismic and a previous discovery well drilled in 1991. The original discovery well encountered a gross oil column up to 140 ft thick in the Fulmar Formation but was abandoned after mechanical problems while conducting a cased hole test. The West Teal Prospect is structurally up dip and approximately 4 km west of the Teal Field, which has produced approximately 55 million barrels of oil to date.
The second well is expected to target the Eocene Tay Formation at a depth of approximately 6,000 ft on the Carra Prospect, Block 21/28b (Antrim 100%). The Carra Prospect is a medium gravity target (25 degrees API) delineated by 3-D seismic, on trend and 4 km from the West Guillemot Field. If successful, a discovery on either of these prospects would add significant resources to the scheduled development of the Fyne Field, located 3 km to the northwest of Carra.
Antrim intends to use the proceeds from its recent equity issue to fund the drilling program but will also invite participation from industry partners.
Titan Acquires Interest in Petrobakken-Operated Wells
Titan Acquires Interest in Petrobakken-Operated Wells
Tuesday, March 29, 2011
Titan O&G Inc.
Titan has acquired an interest in five producing oil wells operated by Petrobakken.
The wells are located on 800 acres of land approximately 80 miles northwest of Edmonton in the Leaman area. Current gross production is approximately 60 barrels of oil a day and there is potential for another well to be drilled in the future.
"We are very pleased to have achieved our goal of becoming a producing oil company," said Jarnail Dhaddey, President of Titan. "We are also very pleased to be associating with industry leaders and look forward to using these relationships to build Titan's producing resource base and to enhance shareholder value in the coming months."
Tuesday, March 29, 2011
Titan O&G Inc.
Titan has acquired an interest in five producing oil wells operated by Petrobakken.
The wells are located on 800 acres of land approximately 80 miles northwest of Edmonton in the Leaman area. Current gross production is approximately 60 barrels of oil a day and there is potential for another well to be drilled in the future.
"We are very pleased to have achieved our goal of becoming a producing oil company," said Jarnail Dhaddey, President of Titan. "We are also very pleased to be associating with industry leaders and look forward to using these relationships to build Titan's producing resource base and to enhance shareholder value in the coming months."
Technip Secures Engineering Contract Offshore UAE
Technip Secures Engineering Contract Offshore UAE
Tuesday, March 29, 2011
Tuesday, March 29, 2011
Technip
Technip was awarded an engineering services contract by ZADCO (a joint venture company between ADNOC, ExxonMobil and JODCO) for the UZ 750 project, one of the major offshore field development projects in the United Arab Emirates. The project aims at increasing by 2015 the oil production of the Upper Zakum field (located in the Gulf, 84 kilometers offshore Abu Dhabi) to 750,000 barrels of oil per day and to sustain this production target for at least 25 years.
The contract covers:
The contract covers:
- front-end engineering design for process units on four artificial islands, including gas separation, gas lift compression, booster gas compression, as well as power generation, utilities, interconnecting pipelines and modification of existing facilities,
- procurement services for long lead items.
Statoil Preps NCS Fast-Track Projects for Production
Statoil Preps NCS Fast-Track Projects for Production
Tuesday, March 29, 2011
Tuesday, March 29, 2011
Statoil
This will be the year Statoil is planning and realizing several fast-track developments on the Norwegian continental shelf (NCS). Two new projects are being launched these days, namely Gamma/Harepus and Snorre B template.
A plan for development and operation (PDO) of Gamma/Harepus is to be submitted in first quarter 2012, allowing production start-up in the fourth quarter of 2013, at the same time as the Snorre B template.
"The time has really come to industrialize the NCS by moving faster from concept to development," said Ivar Aasheim, head of the field development cluster of Development and Production Norway (DPN).
An active year
"We have come a long way in one year," he said.
"The concept has been established, deliveries with long delivery time have been secured for the first projects, construction of modules has started, and new candidates are continuously being included in our portfolio. We aim to have close to five fields in operation at the turn of the year 2012/2013 and to maintain this level in the years ahead."
After submitting the PDO for Visund South in January the list of planned fast-track projects is as follows: Visund South, Katla, Vigdis North-East, Gygrid, Fossekall and Dompap, Vilje South, Visund North, Gamma/Harepus and Snorre B template.
Unique position
"We have a unique position on the NCS as operator of a large part of the infrastructure in the established areas, allowing us to establish robust and profitable solutions for marginal fields that would otherwise not have been developed," underlined Aasheim. “But this requires greater awareness of costs and standardized solutions."
"This is the beginning of a new era on the NCS, as we move from large and tailored solutions to standardized solutions and work processes to achieve economies of scale," maintained Aasheim.
A plan for development and operation (PDO) of Gamma/Harepus is to be submitted in first quarter 2012, allowing production start-up in the fourth quarter of 2013, at the same time as the Snorre B template.
"The time has really come to industrialize the NCS by moving faster from concept to development," said Ivar Aasheim, head of the field development cluster of Development and Production Norway (DPN).
An active year
"We have come a long way in one year," he said.
"The concept has been established, deliveries with long delivery time have been secured for the first projects, construction of modules has started, and new candidates are continuously being included in our portfolio. We aim to have close to five fields in operation at the turn of the year 2012/2013 and to maintain this level in the years ahead."
After submitting the PDO for Visund South in January the list of planned fast-track projects is as follows: Visund South, Katla, Vigdis North-East, Gygrid, Fossekall and Dompap, Vilje South, Visund North, Gamma/Harepus and Snorre B template.
Unique position
"We have a unique position on the NCS as operator of a large part of the infrastructure in the established areas, allowing us to establish robust and profitable solutions for marginal fields that would otherwise not have been developed," underlined Aasheim. “But this requires greater awareness of costs and standardized solutions."
"This is the beginning of a new era on the NCS, as we move from large and tailored solutions to standardized solutions and work processes to achieve economies of scale," maintained Aasheim.
Keppel Delivers Rig Four Months Ahead of Schedule
Keppel Delivers Rig Four Months Ahead of Schedule
Tuesday, March 29, 2011
Keppel Corp. Ltd.
Keppel FELS has delivered Alpha Star, the second of two DSSTM 38 semisubmersible rigs, to Brazil's Queiroz Galvão Óleo e Gás (QGOG) four months ahead of schedule and with zero lost time incidents.
This continues Keppel FELS track record of delivering its rigs on time or ahead of schedule. It is the third early delivery this year, following the early delivery of the semisubmersible drilling tender, West Jaya, to Seadrill and of the KFELS N Class rig, Rowan Stavanger, for Rowan Companies.
Mr. Tong Chong Heong, CEO of Keppel Offshore & Marine, said, "This is our second safe and early delivery to QGOG and a sterling record for our company. This outstanding achievement is a demonstration of the great teamwork and synergy we have built with QGOG. It brings to fore the excellence of our efficient processes, project management, innovative methods and the Can-Do spirit which we apply on all our projects.
"We are glad to be able to send Alpha Star off early to contribute to Brazil's exploration and production efforts, enabling QGOG to anticipate its service from Petrobras. Our philosophy is to provide maximum value to our customers and we look forward to supporting QGOG as they expand their foothold in the deepwater drilling segment."
The rig has been chartered by Petrobras for six years to support exploration and production activities offshore Brazil.
Mr. Leduvy Gouvea, Chef Executive Officer of Queiroz Galvão Óleo e Gás said, "With this early delivery, we are able to start work earlier for Petrobras, and reinforce our status as the premier drilling operator in Brazil. We are confident that Alpha Star will be just as successful as its sister rig, the DSSTM 38 Gold Star, which is performing successfully for Petrobras in Brazil.
"Through the various projects we have been working on, they have proven to be an exceptional partner, delivering projects which exceed expectations and enabling us to efficiently serve the fast-growing oil and gas exploration industry. They share our commitment to provide technologically advanced and high quality products to our customers in a reliable and safe manner."
Jointly developed and owned by Keppel's Deepwater Technology Group and Marine Structure Consultants, the DSSTM 38 design is in the league of some of the world's most advanced drilling semisubmersibles.
Designed to maximize uptime with reduced emissions and discharges, a DSSTM 38 rig is well-suited to handle the operational requirements in the deepwater "Golden Triangle" region, which comprises Brazil, Africa and the Gulf of Mexico.
Tuesday, March 29, 2011
Keppel Corp. Ltd.
Keppel FELS has delivered Alpha Star, the second of two DSSTM 38 semisubmersible rigs, to Brazil's Queiroz Galvão Óleo e Gás (QGOG) four months ahead of schedule and with zero lost time incidents.
This continues Keppel FELS track record of delivering its rigs on time or ahead of schedule. It is the third early delivery this year, following the early delivery of the semisubmersible drilling tender, West Jaya, to Seadrill and of the KFELS N Class rig, Rowan Stavanger, for Rowan Companies.
Mr. Tong Chong Heong, CEO of Keppel Offshore & Marine, said, "This is our second safe and early delivery to QGOG and a sterling record for our company. This outstanding achievement is a demonstration of the great teamwork and synergy we have built with QGOG. It brings to fore the excellence of our efficient processes, project management, innovative methods and the Can-Do spirit which we apply on all our projects.
"We are glad to be able to send Alpha Star off early to contribute to Brazil's exploration and production efforts, enabling QGOG to anticipate its service from Petrobras. Our philosophy is to provide maximum value to our customers and we look forward to supporting QGOG as they expand their foothold in the deepwater drilling segment."
The rig has been chartered by Petrobras for six years to support exploration and production activities offshore Brazil.
Mr. Leduvy Gouvea, Chef Executive Officer of Queiroz Galvão Óleo e Gás said, "With this early delivery, we are able to start work earlier for Petrobras, and reinforce our status as the premier drilling operator in Brazil. We are confident that Alpha Star will be just as successful as its sister rig, the DSSTM 38 Gold Star, which is performing successfully for Petrobras in Brazil.
"Through the various projects we have been working on, they have proven to be an exceptional partner, delivering projects which exceed expectations and enabling us to efficiently serve the fast-growing oil and gas exploration industry. They share our commitment to provide technologically advanced and high quality products to our customers in a reliable and safe manner."
Jointly developed and owned by Keppel's Deepwater Technology Group and Marine Structure Consultants, the DSSTM 38 design is in the league of some of the world's most advanced drilling semisubmersibles.
Designed to maximize uptime with reduced emissions and discharges, a DSSTM 38 rig is well-suited to handle the operational requirements in the deepwater "Golden Triangle" region, which comprises Brazil, Africa and the Gulf of Mexico.
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