Commodity Corner: Oil Tops $111 a Barrel
Wednesday, April 20, 2011
Rigzone Staff
by Saaniya Bangee
Crude futures soared Wednesday to settle above $111 a barrel. The 2.9 percent jump came on government data showing a decrease in U.S. crude stockpiles and a weaker dollar.
Crude prices settled up at $111.45 a barrel Wednesday, marking the first trading session for the June contract. In its weekly inventory report, the U.S. Energy Department reported that oil inventories fell by 2.3 million barrels last week. Analysts, on the other hand, were expecting an increase in supplies.
Meanwhile, the dollar continued to decline Wednesday against major and emerging market currencies speculating that U.S. interest rates would remain at record lows. The euro soared to a 15-month high against the dollar, while the Australian dollar surged to its highest since 1983. Due to the recent increase in interest rates in Europe and Asia, the greenback has been facing tremendous pressure.
The intraday range for light, sweet crude was $107.96 to $111.66 a barrel.
Front-month futures for natural gas also rose Wednesday, settling at $4.31 per thousand cubic feet. Natural gas prices peaked at $4.34, before bottoming out at $4.27 Wednesday. The Energy Information Administration's (EIA) weekly natural gas storage data is scheduled to be released early Thursday morning.
May gasoline gained almost 4 cents, ending Wednesday's trading session at $3.277 a gallon. Analysts predict gas prices to increase once driving demand picks up for the summer. According to the U.S. Transportation Department, U.S. highway miles driven increased by 0.9 percent in February compared to the previous year. Prices fluctuated between $3.23 and $3.28 Wednesday.
Wednesday, April 20, 2011
Controversial 'Horizontal Fracking' Remains Legal in Idaho
Controversial 'Horizontal Fracking' Remains Legal in Idaho
Wednesday, April 20, 2011
Knight Ridder/Tribune Business News
by Rocky Barker, The Idaho Statesman, Boise
Though the only natural gas drilling company active in Idaho today has no plans to employ a method blamed around the country for polluting drinking water, industry officials say other companies could one day.
That was enough to keep Gov. Butch Otter and the other state elected officials who make up the Idaho Oil and Gas Conservation Commission from banning the practice Tuesday.
Bridge Resources, the Canadian-based exploratory company that has discovered natural gas in Payette County, said it only will use a "mini-fracking" procedure to stimulate flows of some of its wells.
But David Hawk, representing Snake River Oil and Gas, a subsidiary of Weiser-Brown, another exploration company, pointed to the Chainman Shale formation in Nevada, which has already gained interest from oil and gas explorers and may extend into Idaho.
"People are looking at southern Idaho," Hawk said. "I'd hate to forestall anything."
The commission approved temporary rules Tuesday that allow Bridge Resources to become the first natural gas driller in the state.
Idaho Conservation League Program Director Justin Hayes offered several amendments he said would protect groundwater. One would prohibit horizontal fracking, where fluids are pumped into shale formations at high pressure to allow natural gas to permeate through for recovery.
"Let's just keep those doors closed," Hayes said.
Bridge would inject only vertically, at high pressure, a mixture of gel and sand into the sandstone formation where the company has found gas to clean out the reservoir near the well bore. This process props open fractures and entices gas to flow more freely.
Hayes wanted drillers to ensure their liquids were not carcinogenic and were not a threat to children. Kim Parsons, Bridge Resources' explorations manager, said the rules as written and the company's own practices will ensure its very limited fracking poses no threat to groundwater.
An impermeable shale formation lies between the drill head area, where the fracking will take place thousands of feet below the surface, and the groundwater closer to the surface.
Parsons said other industries on the surface -- such as agriculture -- use far more dangerous compounds that have far more opportunities to leach into the groundwater.
"We invite the rest of industry to come up to our level of groundwater protection," Parsons said.
The commission, made up of Gov. Butch Otter, Secretary of State Ben Ysursa, Attorney General Lawrence Wasden, state schools chief Tom Luna and State Controller Donna Jones, voted unanimously for the temporary fracking rules. Over the summer, the Idaho Department of Lands will hold a series of meetings to develop permanent rules.
Bridge Resources and its partner, Paramax Resources Ltd., both of Canada, have drilled 11 wells in Payette County. Three of the 11 wells can produce at economic levels naturally. Four require stimulation through fracking, officials said. The other four were dry.
Bridge officials said they could go into production before the end of 2011. That could mean money for schools from state land royalties and for other programs from state severance taxes.
Wednesday, April 20, 2011
Knight Ridder/Tribune Business News
by Rocky Barker, The Idaho Statesman, Boise
Though the only natural gas drilling company active in Idaho today has no plans to employ a method blamed around the country for polluting drinking water, industry officials say other companies could one day.
That was enough to keep Gov. Butch Otter and the other state elected officials who make up the Idaho Oil and Gas Conservation Commission from banning the practice Tuesday.
Bridge Resources, the Canadian-based exploratory company that has discovered natural gas in Payette County, said it only will use a "mini-fracking" procedure to stimulate flows of some of its wells.
But David Hawk, representing Snake River Oil and Gas, a subsidiary of Weiser-Brown, another exploration company, pointed to the Chainman Shale formation in Nevada, which has already gained interest from oil and gas explorers and may extend into Idaho.
"People are looking at southern Idaho," Hawk said. "I'd hate to forestall anything."
The commission approved temporary rules Tuesday that allow Bridge Resources to become the first natural gas driller in the state.
Idaho Conservation League Program Director Justin Hayes offered several amendments he said would protect groundwater. One would prohibit horizontal fracking, where fluids are pumped into shale formations at high pressure to allow natural gas to permeate through for recovery.
"Let's just keep those doors closed," Hayes said.
Bridge would inject only vertically, at high pressure, a mixture of gel and sand into the sandstone formation where the company has found gas to clean out the reservoir near the well bore. This process props open fractures and entices gas to flow more freely.
Hayes wanted drillers to ensure their liquids were not carcinogenic and were not a threat to children. Kim Parsons, Bridge Resources' explorations manager, said the rules as written and the company's own practices will ensure its very limited fracking poses no threat to groundwater.
An impermeable shale formation lies between the drill head area, where the fracking will take place thousands of feet below the surface, and the groundwater closer to the surface.
Parsons said other industries on the surface -- such as agriculture -- use far more dangerous compounds that have far more opportunities to leach into the groundwater.
"We invite the rest of industry to come up to our level of groundwater protection," Parsons said.
The commission, made up of Gov. Butch Otter, Secretary of State Ben Ysursa, Attorney General Lawrence Wasden, state schools chief Tom Luna and State Controller Donna Jones, voted unanimously for the temporary fracking rules. Over the summer, the Idaho Department of Lands will hold a series of meetings to develop permanent rules.
Bridge Resources and its partner, Paramax Resources Ltd., both of Canada, have drilled 11 wells in Payette County. Three of the 11 wells can produce at economic levels naturally. Four require stimulation through fracking, officials said. The other four were dry.
Bridge officials said they could go into production before the end of 2011. That could mean money for schools from state land royalties and for other programs from state severance taxes.
Lamprell Appoints New CFO
Lamprell Appoints New CFO
Wednesday, April 20, 2011
Lamprell plc
As announced earlier, Chief Financial Officer of Lamprell will step down by the end of this year, the Company is pleased to confirm that it has agreed terms for the appointment of Jonathan Cooper as Chief Financial Officer. It is anticipated that Jonathan will join the Company in the latter part of 2011. In the meantime, Scott Doak will continue in the role of Chief Financial Officer and will facilitate the handover to Jonathan in due course.
Jonathan has been Finance Director at Sterling Energy plc since 2008. Previously he was Finance Director at Gulf Keystone Petroleum. He started his career at KPMG, before joining Dresdner Kleinwort Benson, having graduated from Leeds University with a Bachelor’s degree and PhD in mechanical engineering.
Jonathan Silver, Chairman, said, "I would like to welcome Jonathan Cooper to Lamprell. His extensive experience in the oil and gas sector will be very useful to Lamprell as it continues to explore the exciting opportunities that lie ahead. I am confident that Jonathan will make a strong contribution to Lamprell and assist the Company to enhance its record of increasing shareholder value."
In accordance with the UK Listing Rules, the Company confirms that there are no further details that are required to be disclosed under paragraph LR 9.6.13 R of the UK Listing Rules in respect of Jonathan Cooper.
Wednesday, April 20, 2011
Lamprell plc
As announced earlier, Chief Financial Officer of Lamprell will step down by the end of this year, the Company is pleased to confirm that it has agreed terms for the appointment of Jonathan Cooper as Chief Financial Officer. It is anticipated that Jonathan will join the Company in the latter part of 2011. In the meantime, Scott Doak will continue in the role of Chief Financial Officer and will facilitate the handover to Jonathan in due course.
Jonathan has been Finance Director at Sterling Energy plc since 2008. Previously he was Finance Director at Gulf Keystone Petroleum. He started his career at KPMG, before joining Dresdner Kleinwort Benson, having graduated from Leeds University with a Bachelor’s degree and PhD in mechanical engineering.
Jonathan Silver, Chairman, said, "I would like to welcome Jonathan Cooper to Lamprell. His extensive experience in the oil and gas sector will be very useful to Lamprell as it continues to explore the exciting opportunities that lie ahead. I am confident that Jonathan will make a strong contribution to Lamprell and assist the Company to enhance its record of increasing shareholder value."
In accordance with the UK Listing Rules, the Company confirms that there are no further details that are required to be disclosed under paragraph LR 9.6.13 R of the UK Listing Rules in respect of Jonathan Cooper.
Penspen Welcomes New Head of Offshore
Penspen Welcomes New Head of Offshore
Wednesday, April 20, 2011
The Penspen Group
The Penspen Group announced the appointment of Colin Cross as Head of Offshore. Previously Subsea and Pipelines Manager at KBR / Granherne and g3baxi partnership ltd., Colin will be in charge of Penspen's Offshore London division, with key responsibility for international business development for Subsea and Pipelines engineering projects.
Ernie Lamza, Penspen's Director of Offshore, said, "Penspen is delighted to welcome Colin on board to head up its offshore London team. I have no doubt he will be an excellent addition to Group and help us build on the 400% growth we have already seen in recent years."
Colin Cross, speaking about his appointment, said, "Penspen has a long track record of delivering successful subsea and pipelines projects and I thoroughly look forward to developing and expanding the group, building on such excellent recent achievements as receiving the Queen's Award for Enterprise and the award of Nexen's Golden Eagle FEED Project."
Wednesday, April 20, 2011
The Penspen Group
The Penspen Group announced the appointment of Colin Cross as Head of Offshore. Previously Subsea and Pipelines Manager at KBR / Granherne and g3baxi partnership ltd., Colin will be in charge of Penspen's Offshore London division, with key responsibility for international business development for Subsea and Pipelines engineering projects.
Ernie Lamza, Penspen's Director of Offshore, said, "Penspen is delighted to welcome Colin on board to head up its offshore London team. I have no doubt he will be an excellent addition to Group and help us build on the 400% growth we have already seen in recent years."
Colin Cross, speaking about his appointment, said, "Penspen has a long track record of delivering successful subsea and pipelines projects and I thoroughly look forward to developing and expanding the group, building on such excellent recent achievements as receiving the Queen's Award for Enterprise and the award of Nexen's Golden Eagle FEED Project."
Samson Tiara Gets Green Light to Open Training Facility
Samson Tiara Gets Green Light to Open Training Facility
Wednesday, April 20, 2011
P.T. Samson Tiara
Samson Tiara has received OPITO approval for its new training facility in Senipah, Kalimantan, Indonesia. This will mark the first time internationally accredited safety training will be available in the area.
The OPITO approval for the Senipah training facility covers 4 courses: Tropical Basic Offshore Safety Induction and Emergency Training (T-BOSIET), Tropical Further Offshore Emergency Training (T-FOET), Travel Safely by Boat (TSBb) and Further Travel Safely by Boat (FTSBb).
Mr. David Donaldson, Managing Director of P.T. Samson Tiara commented, "We are pleased to continue our tradition of being a company of firsts. Samson Tiara was the first to offer properly simulated H.U.E.T training in Indonesia in 1994 and continued on to become the first to offer OPITO’s internationally recognized training in Indonesia in 2004. Now, in 2011, we are proud to be the first to offer OPITO training to the rapidly growing Oil & Gas sector in Kalimantan."
This new facility, approximately sixty kilometers from Balikpapan, will allow P.T. Samson Tiara to provide high quality, internationally accredited offshore safety and survival training to the hundreds of companies operating in the area, training that until now was only available from our facility in Cilegon, Banten.
Wednesday, April 20, 2011
P.T. Samson Tiara
Samson Tiara has received OPITO approval for its new training facility in Senipah, Kalimantan, Indonesia. This will mark the first time internationally accredited safety training will be available in the area.
The OPITO approval for the Senipah training facility covers 4 courses: Tropical Basic Offshore Safety Induction and Emergency Training (T-BOSIET), Tropical Further Offshore Emergency Training (T-FOET), Travel Safely by Boat (TSBb) and Further Travel Safely by Boat (FTSBb).
Mr. David Donaldson, Managing Director of P.T. Samson Tiara commented, "We are pleased to continue our tradition of being a company of firsts. Samson Tiara was the first to offer properly simulated H.U.E.T training in Indonesia in 1994 and continued on to become the first to offer OPITO’s internationally recognized training in Indonesia in 2004. Now, in 2011, we are proud to be the first to offer OPITO training to the rapidly growing Oil & Gas sector in Kalimantan."
This new facility, approximately sixty kilometers from Balikpapan, will allow P.T. Samson Tiara to provide high quality, internationally accredited offshore safety and survival training to the hundreds of companies operating in the area, training that until now was only available from our facility in Cilegon, Banten.
Gazprom, ENI to Conclude Elephant Stake Buy after Libyan Unrest
Wednesday, April 20, 2011
Dow Jones Newswires
by Jacob Gronholt-Pedersen
Gazprom plans to acquire a 33% stake in ENI's Elephant field in Libya has been delayed, and will be finalized when the situation stabilizes in the North African country, Gazprom said Wednesday in a press release.
The announcement came following a meeting in Moscow between Gazprom Chief Executive Alexei Miller and ENI CEO Paolo Scaroni.
The two also discussed France's Electricite de France and Germany's Wintershall joining the South Stream project.
Apache Plugs, Abandons Zola Well Offshore AU
Apache Plugs, Abandons Zola Well Offshore AU
Wednesday, April 20, 2011
Tap Oil Ltd.
Tap Oil provided the following update on the Zola-1 exploration well, offshore Carnarvon Basin, Western Australia.
The Zola-1/Zola-1 ST1 well is located in permit WA-290-P, immediately south of the giant Gorgon gas field in the Carnarvon Basin, Western Australia. The well is being drilled in 285m of water.
Data gathered to date in Zola-1 and Zola-1 ST1 has confirmed a significant gas discovery in the Mungaroo formation. The well results indicate that volumetrically the greater Zola structure could be at the upper end of Tap's pre drill estimates of 1 – 2 Tcf.
Progress
During the period from 06:00 hours WST on April 13, 2011 to 06:00 hours WST on April 20, 2011 the wireline logging program was completed and the well is currently being plugged and abandoned as planned.
Forward Plan
Complete the plugging and abandonment of the well as planned and release the rig.
Barring any unforeseen circumstances, this will be the last Zola-1 Well Drilling Update.
Background
The Zola prospect is a very large Triassic tilted fault block on trend with the giant Gorgon gas field and was one of the largest undrilled structural features in the Carnarvon Basin. The well is testing the gas potential of several top and intra Mungaroo formation sands – the primary reservoir at Gorgon.
Located close to existing and developing gas infrastructure, Zola could have multiple potential development options. Any development at Zola could also encompass the overlying Antiope gas discovery (estimated at ~120 Bcf).
WA-290-P Joint Venture Participants
Wednesday, April 20, 2011
Tap Oil Ltd.
Tap Oil provided the following update on the Zola-1 exploration well, offshore Carnarvon Basin, Western Australia.
The Zola-1/Zola-1 ST1 well is located in permit WA-290-P, immediately south of the giant Gorgon gas field in the Carnarvon Basin, Western Australia. The well is being drilled in 285m of water.
Data gathered to date in Zola-1 and Zola-1 ST1 has confirmed a significant gas discovery in the Mungaroo formation. The well results indicate that volumetrically the greater Zola structure could be at the upper end of Tap's pre drill estimates of 1 – 2 Tcf.
Progress
During the period from 06:00 hours WST on April 13, 2011 to 06:00 hours WST on April 20, 2011 the wireline logging program was completed and the well is currently being plugged and abandoned as planned.
Forward Plan
Complete the plugging and abandonment of the well as planned and release the rig.
Barring any unforeseen circumstances, this will be the last Zola-1 Well Drilling Update.
Background
The Zola prospect is a very large Triassic tilted fault block on trend with the giant Gorgon gas field and was one of the largest undrilled structural features in the Carnarvon Basin. The well is testing the gas potential of several top and intra Mungaroo formation sands – the primary reservoir at Gorgon.
Located close to existing and developing gas infrastructure, Zola could have multiple potential development options. Any development at Zola could also encompass the overlying Antiope gas discovery (estimated at ~120 Bcf).
WA-290-P Joint Venture Participants
- Tap (Shelfal) Pty Ltd 10.00%
- Apache Northwest Pty Ltd (Operator) 30.25%
- Santos Offshore Pty Ltd 24.75%
- OMV Australia Pty Ltd 20.00%
- Nippon Oil Exploration (Dampier) Pty Ltd 15.00%
RWE Dea Picks Up Licenses on Norwegian Shelf
RWE Dea Picks Up Licenses on Norwegian Shelf
Wednesday, April 20, 2011
RWE Dea AG
RWE Dea Norge has been awarded two licenses in the recent licensing round by the Norwegian Government. This further strengthens the company's long-term commitment on the Norwegian Shelf.
RWE Dea was awarded a 30% share in the license PL609 in the Barents Sea and a 15% share in the license PL596 in the Norwegian Sea. "License PL609 is located due East of the Skrugard discovery and enlarges RWE Dea's portfolio in this very promising area," explained Hugo Sandal, Managing Director of RWE Dea. "PL596 is a license on the Atlantic Margin and positions RWE Dea for this play."
These two new licenses add up to RWE Dea Norge's already promising and solid license portfolio in Norway. In January, RWE Dea Norge has already been awarded three licenses on the Norwegian Shelf, of which one is in the North Sea and two are in the Norwegian Sea. Norway plays an important in role in RWE Dea's strategic target to boost its annual gas and oil production to more than 70 million barrel of oil equivalents by 2016.
Wednesday, April 20, 2011
RWE Dea AG
RWE Dea Norge has been awarded two licenses in the recent licensing round by the Norwegian Government. This further strengthens the company's long-term commitment on the Norwegian Shelf.
RWE Dea was awarded a 30% share in the license PL609 in the Barents Sea and a 15% share in the license PL596 in the Norwegian Sea. "License PL609 is located due East of the Skrugard discovery and enlarges RWE Dea's portfolio in this very promising area," explained Hugo Sandal, Managing Director of RWE Dea. "PL596 is a license on the Atlantic Margin and positions RWE Dea for this play."
These two new licenses add up to RWE Dea Norge's already promising and solid license portfolio in Norway. In January, RWE Dea Norge has already been awarded three licenses on the Norwegian Shelf, of which one is in the North Sea and two are in the Norwegian Sea. Norway plays an important in role in RWE Dea's strategic target to boost its annual gas and oil production to more than 70 million barrel of oil equivalents by 2016.
Shoal Point Updates Ops
Shoal Point Updates Ops
Wednesday, April 20, 2011
Shoal Point Energy Ltd.
Shoal Point reported that the 3K39 well is currently being logged in advance of potential open hole testing, and a 5 1/2" (140 mm) casing string will be run in anticipation of completion for production. 50 meters of cores collected in the well have been shipped for analysis. The well was deviated to an average angle of 56 degrees and lies within 100 metes of the previously drilled 2K39 well. Further results are expected to be released in May, 2011.
Shoal Point 2K39 and Long Point M-16
Shoal Point has received the results of geological and technical studies carried out by independent consultants on data from its EL 1070 property in western Newfoundland. Principle among these are petrophysical (log analysis) studies on pre-existing wells by NuTech Energy Alliance of Humble, Texas. In these studies, digital data sets from open hole and cased hole logging runs were provided to NuTech, who specialize in the analysis of bypassed pay and unconventional reservoirs. For locations of the 2K-39 and M-16 wells, please refer to the attached map.
Wednesday, April 20, 2011
Shoal Point Energy Ltd.
Shoal Point reported that the 3K39 well is currently being logged in advance of potential open hole testing, and a 5 1/2" (140 mm) casing string will be run in anticipation of completion for production. 50 meters of cores collected in the well have been shipped for analysis. The well was deviated to an average angle of 56 degrees and lies within 100 metes of the previously drilled 2K39 well. Further results are expected to be released in May, 2011.
Shoal Point 2K39 and Long Point M-16
Shoal Point has received the results of geological and technical studies carried out by independent consultants on data from its EL 1070 property in western Newfoundland. Principle among these are petrophysical (log analysis) studies on pre-existing wells by NuTech Energy Alliance of Humble, Texas. In these studies, digital data sets from open hole and cased hole logging runs were provided to NuTech, who specialize in the analysis of bypassed pay and unconventional reservoirs. For locations of the 2K-39 and M-16 wells, please refer to the attached map.
Treaty Purchases 2 Producing Leases in Tx.
Treaty Purchases 2 Producing Leases in Tx.
Wednesday, April 20, 2011
Treaty Energy Corp.
Treaty Energy has acquired two additional leases in Texas, the SHOTWELL W. F. and the SHOTWELL "C" leases.
Treaty indicated that production on these leases is currently 4.18 barrels of oil per day. These leases require no work over and were purchased for their current production value, but more important to Treaty Energy is the additional 30 virgin well drilling sites which will be added to the list of wells that Treaty's new Failing 1500 CF Drilling Rig will start drilling when permits are granted to do so. Private financing to fund the drilling had been arranged prior to the acquisition of the Failing Drilling Rig.
Stephen L. York, Treaty Energy's Vice President of Acquisitions and Operations, stated, "These leases are two of the most advanced small leases in the Country. Scientific evaluations have been done as an experiment to see what can be achieved with a maximum effort and scientific approach. Fluid levels have been 'shot,' water flooding plains logged, and geology available."
Mr. York stated further, "The upside to this acquisition is that Treaty now has an additional 138 acres to drill on, which represents 30 or more virgin well sites."
Treaty Energy's CEO and Chairman, Andrew V. Reid, stated, "I am very pleased with the progress Steve is making on the development of Treaty Energy's rapidly growing base of leases and production of oil in Texas."
Treaty indicated that it will follow with an SEC Form 8-K on a timely basis, which will include all aspects of this purchase.
Wednesday, April 20, 2011
Treaty Energy Corp.
Treaty Energy has acquired two additional leases in Texas, the SHOTWELL W. F. and the SHOTWELL "C" leases.
Treaty indicated that production on these leases is currently 4.18 barrels of oil per day. These leases require no work over and were purchased for their current production value, but more important to Treaty Energy is the additional 30 virgin well drilling sites which will be added to the list of wells that Treaty's new Failing 1500 CF Drilling Rig will start drilling when permits are granted to do so. Private financing to fund the drilling had been arranged prior to the acquisition of the Failing Drilling Rig.
Stephen L. York, Treaty Energy's Vice President of Acquisitions and Operations, stated, "These leases are two of the most advanced small leases in the Country. Scientific evaluations have been done as an experiment to see what can be achieved with a maximum effort and scientific approach. Fluid levels have been 'shot,' water flooding plains logged, and geology available."
Mr. York stated further, "The upside to this acquisition is that Treaty now has an additional 138 acres to drill on, which represents 30 or more virgin well sites."
Treaty Energy's CEO and Chairman, Andrew V. Reid, stated, "I am very pleased with the progress Steve is making on the development of Treaty Energy's rapidly growing base of leases and production of oil in Texas."
Treaty indicated that it will follow with an SEC Form 8-K on a timely basis, which will include all aspects of this purchase.
AES Corp Acquiring DPL Inc For $4.7 Billion
AES Corp Acquiring DPL Inc For $4.7 Billion
Apr 20, 2011
DPL Inc. (NYSE:DPL) announced early this morning that it has entered into a definitive agreement to merge with The AES Corporation (NYSE:AES) in which AES will acquire DPL in a transaction with an enterprise value of $4.7 billion.
Under the terms, AES will acquire all outstanding shares of DPL for approximately $3.5 billion, or $30 per share, which represents an 8.7% premium over DPL's closing share price on April 19th, 2011.
The board of directors for each company has unanimously approved of the deal, which is expected to close in the next 6 to 9 months, subject to approval by DPL's shareholders and receipt of regulatory approvals.
Shares of AES are trading up 3.69% at $12.93.
Apr 20, 2011
DPL Inc. (NYSE:DPL) announced early this morning that it has entered into a definitive agreement to merge with The AES Corporation (NYSE:AES) in which AES will acquire DPL in a transaction with an enterprise value of $4.7 billion.
Under the terms, AES will acquire all outstanding shares of DPL for approximately $3.5 billion, or $30 per share, which represents an 8.7% premium over DPL's closing share price on April 19th, 2011.
The board of directors for each company has unanimously approved of the deal, which is expected to close in the next 6 to 9 months, subject to approval by DPL's shareholders and receipt of regulatory approvals.
Shares of AES are trading up 3.69% at $12.93.
OGX Strikes Oil in Campos Appraisals
OGX Strikes Oil in Campos Appraisals
Wednesday, April 20, 2011
OGX S.A.
by SubseaIQ
OGX has identified the presence of hydrocarbons in the Albian section of 3-OGX-40D-RJS well and in the Albian-Cenomanian section of the well 3-OGX-41D-RJS, both appraisal wells from the Pipeline and Waikiki accumulations, respectively.
"The wells OGX-40 and OGX-41 confirmed the successful OGX delimitative campaign in the Campos Basin and reinforced the Company's base case to develop the 4.1 billion barrels already discovered in the Campos Basin," stated Paulo Mendonça, Executive General Officer and Exploration Officer of OGX.
"The accumulations of Pipeline and Waikiki are among the priorities to be developed for production, due to the advanced stage of the discoveries' delimitation and the quality of the reservoirs," commented Reinaldo Belotti, Production Officer of OGX.
The well OGX-40 found an oil column of approximately 204 meters with a net pay of about 107 meters in carbonate reservoirs in the Albian section. The well OGX-41 discovered an oil column of approximately 148 meters with a net pay of about 92 meters, also in carbonate reservoirs in the Albian-Cenomanian section.
The well OGX-40D is the second appraisal well in the Pipeline accumulation discovered by the well OGX-2A. The first appraisal well of the accumulation was the OGX-36, which also confirmed the presence of oil and contributed to its delimitation. The well OGX-41D is the second appraisal well of the Waikiki accumulation, discovered by the well OGX-25, with OGX-35 being the first appraisal well. The discoveries' evaluation plans for the Pipeline and Waikiki will soon be proposed to ANP.
It is worth noting that wells OGX-40 (Pipeline) and OGX (Waikiki), as well as the wells OGX-35 (Waikiki), OGX-36 and OGX-39HP (both in the Pipeline accumulation), would increased OGX's contingent resources area, in case the certification happened at this moment.
Both wells are deviated and pilots for horizontal wells, in which drill-stem tests could be performed to verify the productivity of these areas, as was done recently for the Waimea accumulation, where exceptional results were obtained.
The OGX‐40D well is located in the BM‐C‐41 block and is situated about 79 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 130 meters. The Sea Explorer rig initiated drilling activities there on March 28, 2011.
The OGX‐41D well is located in the BM‐C‐39 block and is situated about 89 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 104 meters. The Ocean Lexington rig initiated drilling activities there on April 3, 2011.
Wednesday, April 20, 2011
OGX S.A.
by SubseaIQ
OGX has identified the presence of hydrocarbons in the Albian section of 3-OGX-40D-RJS well and in the Albian-Cenomanian section of the well 3-OGX-41D-RJS, both appraisal wells from the Pipeline and Waikiki accumulations, respectively.
"The wells OGX-40 and OGX-41 confirmed the successful OGX delimitative campaign in the Campos Basin and reinforced the Company's base case to develop the 4.1 billion barrels already discovered in the Campos Basin," stated Paulo Mendonça, Executive General Officer and Exploration Officer of OGX.
"The accumulations of Pipeline and Waikiki are among the priorities to be developed for production, due to the advanced stage of the discoveries' delimitation and the quality of the reservoirs," commented Reinaldo Belotti, Production Officer of OGX.
The well OGX-40 found an oil column of approximately 204 meters with a net pay of about 107 meters in carbonate reservoirs in the Albian section. The well OGX-41 discovered an oil column of approximately 148 meters with a net pay of about 92 meters, also in carbonate reservoirs in the Albian-Cenomanian section.
The well OGX-40D is the second appraisal well in the Pipeline accumulation discovered by the well OGX-2A. The first appraisal well of the accumulation was the OGX-36, which also confirmed the presence of oil and contributed to its delimitation. The well OGX-41D is the second appraisal well of the Waikiki accumulation, discovered by the well OGX-25, with OGX-35 being the first appraisal well. The discoveries' evaluation plans for the Pipeline and Waikiki will soon be proposed to ANP.
It is worth noting that wells OGX-40 (Pipeline) and OGX (Waikiki), as well as the wells OGX-35 (Waikiki), OGX-36 and OGX-39HP (both in the Pipeline accumulation), would increased OGX's contingent resources area, in case the certification happened at this moment.
Both wells are deviated and pilots for horizontal wells, in which drill-stem tests could be performed to verify the productivity of these areas, as was done recently for the Waimea accumulation, where exceptional results were obtained.
The OGX‐40D well is located in the BM‐C‐41 block and is situated about 79 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 130 meters. The Sea Explorer rig initiated drilling activities there on March 28, 2011.
The OGX‐41D well is located in the BM‐C‐39 block and is situated about 89 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 104 meters. The Ocean Lexington rig initiated drilling activities there on April 3, 2011.
Lucas Sees Production Increae in 4Q10
Lucas Sees Production Increae in 4Q10
Wednesday, April 20, 2011
Lucas Energy Inc.
Lucas reported that production for the 4th quarter 2010-11 (January 2011 through March 2011) was up approximately 15% over the production for the 3rd quarter 2010-11 (October 2010 through December 2010). In the 4th quarter, Lucas had gross production of 19,898 bbls of oil as compared to 17,343 bbls of oil in the 3rd quarter. Improvement in production during the 4th quarter was due to workovers, improved trucking, and field operational changes. This is gross production from the wells and not net to the interest of Lucas (after royalty and joint venture partners interests). Also, these figures are for wells only operated by Lucas, and do not include the production from the Hilcorp operated Hagen Eagle Ford wells. Further, sales may differ from production, and will be reported in the Annual Report on Form 10-K for the fiscal year ended March 31, 2011.
"Lucas Energy has moved into production improvement after two years of increasing its Eagle Ford asset base," commented William A. Sawyer, President and CEO of Lucas Energy, who continued, "We anticipate continued improvement in our production, revenues, and bottom line."
The 3rd quarter saw slow movement of oil off of the Lucas operated leases due to a shortage of trucking as a result of the Eagle Ford activity. This shortage continued through February 2011. As a result, many wells had to be shut in until the oil was removed and sold. This condition appears to have eased up in March 2011.
Wednesday, April 20, 2011
Lucas Energy Inc.
Lucas reported that production for the 4th quarter 2010-11 (January 2011 through March 2011) was up approximately 15% over the production for the 3rd quarter 2010-11 (October 2010 through December 2010). In the 4th quarter, Lucas had gross production of 19,898 bbls of oil as compared to 17,343 bbls of oil in the 3rd quarter. Improvement in production during the 4th quarter was due to workovers, improved trucking, and field operational changes. This is gross production from the wells and not net to the interest of Lucas (after royalty and joint venture partners interests). Also, these figures are for wells only operated by Lucas, and do not include the production from the Hilcorp operated Hagen Eagle Ford wells. Further, sales may differ from production, and will be reported in the Annual Report on Form 10-K for the fiscal year ended March 31, 2011.
"Lucas Energy has moved into production improvement after two years of increasing its Eagle Ford asset base," commented William A. Sawyer, President and CEO of Lucas Energy, who continued, "We anticipate continued improvement in our production, revenues, and bottom line."
The 3rd quarter saw slow movement of oil off of the Lucas operated leases due to a shortage of trucking as a result of the Eagle Ford activity. This shortage continued through February 2011. As a result, many wells had to be shut in until the oil was removed and sold. This condition appears to have eased up in March 2011.
Cooper Spuds Second Butlers Well
Cooper Spuds Second Butlers Well
Wednesday, April 20, 2011
Cooper Energy Ltd.
Cooper announced that the Butlers-3 appraisal/development well in PEL92 spudded at 3:30 pm April 19, 2011. The current operation is drilling ahead in the surface hole at 395 meters.
Butlers-3 is the second appraisal/development well on the Butlers Oil Field in the current PEL92 back to back eleven well drilling program and follows the successful appraisal of the northern extent of the field by Butlers-2. Butlers-3 is targeting the Namur oil reservoir 0.3km to the northwest of the Butlers-1 discovery well. The well will be drilled to a total depth of about 1,360 meters and is expected to take 9 days to drill and complete.
The Butlers oil field is currently producing approximately 1,400 barrels of oil per day from the Namur reservoir via the Butlers-1 well. It is expected that additional Butlers' development wells will more efficiently drain the field and accelerate production. The drilling will be accompanied by an upgrade of the Butlers surface facilities to handle the increased production. Oil production from Butlers is exported via the pipeline to Tantanna and then exported to Moomba.
Wednesday, April 20, 2011
Cooper Energy Ltd.
Cooper announced that the Butlers-3 appraisal/development well in PEL92 spudded at 3:30 pm April 19, 2011. The current operation is drilling ahead in the surface hole at 395 meters.
Butlers-3 is the second appraisal/development well on the Butlers Oil Field in the current PEL92 back to back eleven well drilling program and follows the successful appraisal of the northern extent of the field by Butlers-2. Butlers-3 is targeting the Namur oil reservoir 0.3km to the northwest of the Butlers-1 discovery well. The well will be drilled to a total depth of about 1,360 meters and is expected to take 9 days to drill and complete.
The Butlers oil field is currently producing approximately 1,400 barrels of oil per day from the Namur reservoir via the Butlers-1 well. It is expected that additional Butlers' development wells will more efficiently drain the field and accelerate production. The drilling will be accompanied by an upgrade of the Butlers surface facilities to handle the increased production. Oil production from Butlers is exported via the pipeline to Tantanna and then exported to Moomba.
AED Receives Extension for Rombebai PSC Contract
AED Receives Extension for Rombebai PSC Contract
Wednesday, April 20, 2011
AED Oil Ltd.
AED announced that AED Rombebai B.V. as 100% operator of the Rombebai Block in Papua, Indonesia has received an extension of the exploration period for its current production sharing contract (PSC) until July 15, 2013.
AED Oil Executive Chairman Mr David Dix said, "This extension is a very positive event for the Company. It provides us with increased certainty of control over an asset with outstanding commercial potential. We believe this certainty will leave us well placed to attract and negotiate with potential farm-out partners who can work with us to develop this world-class prospect."
The Rombebai prospect contains the Gesa structure, which is a world-class prospective resource where AED is targeting in excess of 7 Tcf of gas. In addition to the significant gas potential within Rombebai, we believe there is also the real possibility of a major oil find.
Rombebai has an excellent path to market with the potential to become a major liquefied natural gas development similar to the nearby BP Tangguh LNG development. AED has become increasingly optimistic about Rombebai. Our initial assessment had suggested the presence of biogenic gas only; however recent analysis of previous drilling results suggests the presence of hydrocarbons.
New seismic data and interpretation work has significantly increased the prospectivity of the Gesa structure. Recent studies suggest oil as well as thermal gas potential indicated by oil fluorescence in Gesa 1 and 2, and from oil analyzed in hydrocarbon seeps.
Our 2011 geological and geographical program will focus on reprocessing data and performing detailed AVO studies to better quantify the hydrocarbon type and distribution, as well as sampling oil seeps in the region.
AED plans to recommence farm-out discussions with interested parties, with a view to conducting drilling operations at the Kare-1 well upon obtaining the required forestry permits.
AED believes that the additional time will allow the following activities to be performed before the time at which for a Plan of Development is required to be submitted in respect of the Rombebai Block:
Key terms of the extension are as follows:
Wednesday, April 20, 2011
AED Oil Ltd.
AED announced that AED Rombebai B.V. as 100% operator of the Rombebai Block in Papua, Indonesia has received an extension of the exploration period for its current production sharing contract (PSC) until July 15, 2013.
AED Oil Executive Chairman Mr David Dix said, "This extension is a very positive event for the Company. It provides us with increased certainty of control over an asset with outstanding commercial potential. We believe this certainty will leave us well placed to attract and negotiate with potential farm-out partners who can work with us to develop this world-class prospect."
The Rombebai prospect contains the Gesa structure, which is a world-class prospective resource where AED is targeting in excess of 7 Tcf of gas. In addition to the significant gas potential within Rombebai, we believe there is also the real possibility of a major oil find.
Rombebai has an excellent path to market with the potential to become a major liquefied natural gas development similar to the nearby BP Tangguh LNG development. AED has become increasingly optimistic about Rombebai. Our initial assessment had suggested the presence of biogenic gas only; however recent analysis of previous drilling results suggests the presence of hydrocarbons.
New seismic data and interpretation work has significantly increased the prospectivity of the Gesa structure. Recent studies suggest oil as well as thermal gas potential indicated by oil fluorescence in Gesa 1 and 2, and from oil analyzed in hydrocarbon seeps.
Our 2011 geological and geographical program will focus on reprocessing data and performing detailed AVO studies to better quantify the hydrocarbon type and distribution, as well as sampling oil seeps in the region.
AED plans to recommence farm-out discussions with interested parties, with a view to conducting drilling operations at the Kare-1 well upon obtaining the required forestry permits.
AED believes that the additional time will allow the following activities to be performed before the time at which for a Plan of Development is required to be submitted in respect of the Rombebai Block:
- Drilling and testing and evaluation on the result of the Kare-1
- Drilling further exploratory/delineation well pending results from Kare-1
- Geological and geophysical studies to confirm and certify any hydrocarbon reserves discovered
- Acquisition & processing of further seismic as required.
Key terms of the extension are as follows:
- To continue to perform drilling operations and activities as per the current 2011 approved work program in relation to drilling the exploration well Kare-1 by November 15 2011 (a condition which may be waived if AED has made significant progress in drilling preparations for this well)
- If the exploration well is a "dry well," AED Rombebai B.V. may apply to continue to explore the Rombebai Block for the remainder of the exploration period
- If within the exploration period, AED Rombebai B.V. discovers an economic hydrocarbon reserve to be developed, then AED Rombebai B.V. may submit an additional request for a maximum of a further twelve months effectively for the purpose of determining commerciality of the Block
- AED Rombebai B.V. will relinquish the Rombebai Block if economic hydrocarbons are not discovered during the exploration period
- The term of the PSC remains unchanged at 30 years.
MOL to Extend Upstream Portfolio to Romania
MOL to Extend Upstream Portfolio to Romania
Wednesday, April 20, 2011
MOL
MOL has signed Concession Agreements with the Romanian National Agency for Mineral Resources for three exploration blocks. As announced on July 5, 2010, EX-1 (Voivozi), EX-5 (Adea) and EX-6 (Curtici) were awarded at the 10th Licensing Round to the consortium of MOL and Expert Petroleum. MOL is the operator of the projects, with 70% participating interest in the blocks, while Expert Petroleum holds the remaining 30%.
The blocks have a combined area of 3,434 square km and are located in the Pannonian basin, next to the Hungarian border. The exploration period is divided to a three-year initial term and an optional three-year phase. The initial work program includes 2D and 3D seismic measurements to be followed by drillings. Besides the good oil and gas potential, some of the blocks have unconventional potential as well.
The agreements are subject to the approval of the Romanian Government.
Zoltán Áldott, Executive Vice President of Exploration and Production Division commented, "We are pleased to extend our international upstream portfolio to Romania, where we have already been present as an important downstream player. We believe that we can benefit from our experience in the exploration of the Pannonian basin gathered during many decades and we look forward to commence the work as soon as practicable."
Szabolcs I. Ferencz, MOL Romania CEO added, "MOL Group has long term investment plans for Romania. Deploying upstream projects in Romania match perfectly with developing our filling stations network and logistics facilities."
Wednesday, April 20, 2011
MOL
MOL has signed Concession Agreements with the Romanian National Agency for Mineral Resources for three exploration blocks. As announced on July 5, 2010, EX-1 (Voivozi), EX-5 (Adea) and EX-6 (Curtici) were awarded at the 10th Licensing Round to the consortium of MOL and Expert Petroleum. MOL is the operator of the projects, with 70% participating interest in the blocks, while Expert Petroleum holds the remaining 30%.
The blocks have a combined area of 3,434 square km and are located in the Pannonian basin, next to the Hungarian border. The exploration period is divided to a three-year initial term and an optional three-year phase. The initial work program includes 2D and 3D seismic measurements to be followed by drillings. Besides the good oil and gas potential, some of the blocks have unconventional potential as well.
The agreements are subject to the approval of the Romanian Government.
Zoltán Áldott, Executive Vice President of Exploration and Production Division commented, "We are pleased to extend our international upstream portfolio to Romania, where we have already been present as an important downstream player. We believe that we can benefit from our experience in the exploration of the Pannonian basin gathered during many decades and we look forward to commence the work as soon as practicable."
Szabolcs I. Ferencz, MOL Romania CEO added, "MOL Group has long term investment plans for Romania. Deploying upstream projects in Romania match perfectly with developing our filling stations network and logistics facilities."
Ensign De-Mobilizes Rig from Cooper Basin
Ensign De-Mobilizes Rig from Cooper Basin
Wednesday, April 20, 2011
Rodinia Oil Corp.
Rodinia Oil announced that Ensign Australia has begun de-mobilizing its heavy triple Rig #16 from the Cooper Basin, South Australia. Ensign International is mobilizing the rig to the Officer Basin in South Australia for Rodinia.
Drilling Program Update
Ensign International's Rig #16 has begun mobilizing for the approximately 2,000 kilometer journey to the Officer Basin to commence drilling of Mulyawara 1, the first well in Rodinia's exploratory drilling program. Mulyawara 1 is expected to spud in mid-May and drilling is expected to take approximately six weeks.
Mulyawara 1 is located in the northwest corner of PEL 253 (South Australia) and will test a structure of approximately 36.3 square kilometers (per horizon) in size identified on seven seismic lines. This well will target five potential reservoirs, the deepest of which is the aeolian Pindyin sandstone (also called the sub-salt unit). Rodinia has an 80% working interest in this well and prospect and is the operator.
Rodinia's contract with Ensign International includes four firm wells with the option for up to four additional wells in the Officer Basin.
Wednesday, April 20, 2011
Rodinia Oil Corp.
Rodinia Oil announced that Ensign Australia has begun de-mobilizing its heavy triple Rig #16 from the Cooper Basin, South Australia. Ensign International is mobilizing the rig to the Officer Basin in South Australia for Rodinia.
Drilling Program Update
Ensign International's Rig #16 has begun mobilizing for the approximately 2,000 kilometer journey to the Officer Basin to commence drilling of Mulyawara 1, the first well in Rodinia's exploratory drilling program. Mulyawara 1 is expected to spud in mid-May and drilling is expected to take approximately six weeks.
Mulyawara 1 is located in the northwest corner of PEL 253 (South Australia) and will test a structure of approximately 36.3 square kilometers (per horizon) in size identified on seven seismic lines. This well will target five potential reservoirs, the deepest of which is the aeolian Pindyin sandstone (also called the sub-salt unit). Rodinia has an 80% working interest in this well and prospect and is the operator.
Rodinia's contract with Ensign International includes four firm wells with the option for up to four additional wells in the Officer Basin.
AMR Corporation Reports Q1 Earnings Just About In-Line
AMR Corporation Reports Q1 Earnings Just About In-Line
Apr 20, 2011
AMR Corporation, (NYSE:AMR) the parent company of American Airlines, reported a Q1 EPS loss of $1.31, slightly narrow than the $1.32 loss analysts had expected. Revenues for the quarter were up 9.2% year-over-year to $5.5 billion, in-line with the consensus estimate.
"High fuel prices remain one of the biggest challenges to our industry and our company. We believe our steps to aggressively increase revenues, reduce capacity, control non-fuel operating costs, and bolster liquidity will help us to better manage the challenges we currently face," said AMR Chairman and CEO Gerard Arpey. "While we clearly must achieve better results as we continue to strengthen our business, we have made some meaningful progress. I want to thank our people for their commitment to serving our customers, and I am confident that our overall strategy positions American well to address our current challenges and sets the stage for long-term success."
Apr 20, 2011
AMR Corporation, (NYSE:AMR) the parent company of American Airlines, reported a Q1 EPS loss of $1.31, slightly narrow than the $1.32 loss analysts had expected. Revenues for the quarter were up 9.2% year-over-year to $5.5 billion, in-line with the consensus estimate.
"High fuel prices remain one of the biggest challenges to our industry and our company. We believe our steps to aggressively increase revenues, reduce capacity, control non-fuel operating costs, and bolster liquidity will help us to better manage the challenges we currently face," said AMR Chairman and CEO Gerard Arpey. "While we clearly must achieve better results as we continue to strengthen our business, we have made some meaningful progress. I want to thank our people for their commitment to serving our customers, and I am confident that our overall strategy positions American well to address our current challenges and sets the stage for long-term success."
Range Enters HOA to Acquire Trinidad Blocks
Range Enters HOA to Acquire Trinidad Blocks
Wednesday, April 20, 2011
Range Resources Corp.
Range has entered into a binding Heads of Agreement ("HOA") to acquire through SOCA Petroleum ("SOCA") its right to purchase a 100% interest in a Trinidad holding company whose two wholly owned subsidiaries hold production licenses for three blocks in producing onshore oilfields in Trinidad together with a local drilling company.
The production acreage and operating wells cover the Morne Diablo, Beach Marcelle and South Quarry oilfields, with the total acreage covering 16,253 gross acres on the southern coast of onshore Trinidad. Current production from the fields is approximately 600 bopd, however Range believes a minimal work program could potentially lift production to more than 4,000 bopd within 36 months on the known reserves.
In addition to the holding company parent of two subsidiaries holding production licenses for the onshore acreage, the proposed Range acquisition also includes a 100% interest in a wholly owned drilling company (located in Trinidad), which owns onshore drilling equipment and related facilities.
The Company is planning to use company-owned drilling rigs and equipment and, with cashflow from existing production supplemented by a well advanced financing facility (to be finalized) to fund its development and exploration program which aims to increase the production from 600 bopd to 4,000 bopd within 36 months from known reserves without taking into account any exploration upside.
In addition to the known reserves, significant potential exists in the deeper Herrera Formation. The Deeper Herrera Formation will be a primary target of future drilling using company-owned drilling rigs, which are capable of reaching the depth of these formations. Subject to the successful drill testing of this formation, the Company is ultimately targeting an increase in the production level to between 8,000 - 10,000 bopd.
Range's Executive Director, Peter Landau commented today, "With the recent strength and growth in Range's asset base and market capitalization, the 100% acquisition represents an incredible opportunity to compliment Range's asset base of good value exposure to early stage, low risk production / mature exploration opportunities whilst retaining significant exposure to considerable measurable exploration upside."
"Onshore Trinidad is a low cost, high operating margin environment with oil production sold at the wellhead and transported to the Pointe-a-Pierre Refinery, which has capacity for all additional planned production."
"The Company believes that there is significant potential for value enhancement given the known management team and will target (subject to exploration success) an ultimate production profile of up to 10,000 bopd over the next 2-3 years," he added.
Consideration
Under the terms of the Agreement with SOCA Petroleum, Range will pay the following to acquire the remaining 90% interest in SOCA that it doesn't already own:
The placement is scheduled to settle on April 27, 2011, other than 4,426,271 shares which are scheduled to settle on May 10, 2011.
Technical Overview of Trinidad assets to be acquired
Historical and current oil production is from the Forest and Cruse Formations which are shallow fluvio-deltaic reservoirs with current total estimated Proved plus Probable plus Possible Reserves (3P) (on SOCA's and third parties' licenses) of 20 million barrels of oil (MMbo) (Forest A. Garb & Associates report1). Current production is approximately 600 bopd from the Morne Diablo, South Quarry and Beach Marcelle fields.
Significant potential exists in the Deeper Herrera Formation. The Deeper Herrera Formation is a Miocene-aged deepwater turbidite. Production is typically found in the northeast to southwest thrusted structures to the east and north of the subject acreage, where the Penal field has produced more than 60 MMbo to date. 3D Seismic was used to identify prospective drilling locations in the license area that have a further undiscovered oil potential of 100 MMbo.
The Deeper Herrera Formation will be a target of future drilling using company-owned drilling rigs, which have the capability to reach these formations.
Wednesday, April 20, 2011
Range Resources Corp.
Range has entered into a binding Heads of Agreement ("HOA") to acquire through SOCA Petroleum ("SOCA") its right to purchase a 100% interest in a Trinidad holding company whose two wholly owned subsidiaries hold production licenses for three blocks in producing onshore oilfields in Trinidad together with a local drilling company.
The production acreage and operating wells cover the Morne Diablo, Beach Marcelle and South Quarry oilfields, with the total acreage covering 16,253 gross acres on the southern coast of onshore Trinidad. Current production from the fields is approximately 600 bopd, however Range believes a minimal work program could potentially lift production to more than 4,000 bopd within 36 months on the known reserves.
In addition to the holding company parent of two subsidiaries holding production licenses for the onshore acreage, the proposed Range acquisition also includes a 100% interest in a wholly owned drilling company (located in Trinidad), which owns onshore drilling equipment and related facilities.
The Company is planning to use company-owned drilling rigs and equipment and, with cashflow from existing production supplemented by a well advanced financing facility (to be finalized) to fund its development and exploration program which aims to increase the production from 600 bopd to 4,000 bopd within 36 months from known reserves without taking into account any exploration upside.
In addition to the known reserves, significant potential exists in the deeper Herrera Formation. The Deeper Herrera Formation will be a primary target of future drilling using company-owned drilling rigs, which are capable of reaching the depth of these formations. Subject to the successful drill testing of this formation, the Company is ultimately targeting an increase in the production level to between 8,000 - 10,000 bopd.
Range's Executive Director, Peter Landau commented today, "With the recent strength and growth in Range's asset base and market capitalization, the 100% acquisition represents an incredible opportunity to compliment Range's asset base of good value exposure to early stage, low risk production / mature exploration opportunities whilst retaining significant exposure to considerable measurable exploration upside."
"Onshore Trinidad is a low cost, high operating margin environment with oil production sold at the wellhead and transported to the Pointe-a-Pierre Refinery, which has capacity for all additional planned production."
"The Company believes that there is significant potential for value enhancement given the known management team and will target (subject to exploration success) an ultimate production profile of up to 10,000 bopd over the next 2-3 years," he added.
Consideration
Under the terms of the Agreement with SOCA Petroleum, Range will pay the following to acquire the remaining 90% interest in SOCA that it doesn't already own:
- US $52m upon formal completion of the acquisition (scheduled to happen imminently upon all necessary closing actions being completed);
- The issue of 35,842,293 fully paid ordinary shares upon completion; and
- The potential issue of two parcels of a further 17,921,146 fully paid ordinary shares upon production from the SOCA licenses reaching 1,250 bopd and 2,500 bopd respectively.
The placement is scheduled to settle on April 27, 2011, other than 4,426,271 shares which are scheduled to settle on May 10, 2011.
Technical Overview of Trinidad assets to be acquired
Historical and current oil production is from the Forest and Cruse Formations which are shallow fluvio-deltaic reservoirs with current total estimated Proved plus Probable plus Possible Reserves (3P) (on SOCA's and third parties' licenses) of 20 million barrels of oil (MMbo) (Forest A. Garb & Associates report1). Current production is approximately 600 bopd from the Morne Diablo, South Quarry and Beach Marcelle fields.
Significant potential exists in the Deeper Herrera Formation. The Deeper Herrera Formation is a Miocene-aged deepwater turbidite. Production is typically found in the northeast to southwest thrusted structures to the east and north of the subject acreage, where the Penal field has produced more than 60 MMbo to date. 3D Seismic was used to identify prospective drilling locations in the license area that have a further undiscovered oil potential of 100 MMbo.
The Deeper Herrera Formation will be a target of future drilling using company-owned drilling rigs, which have the capability to reach these formations.
Global Energy Commences Seismic Acquisition in Colombia
Global Energy Commences Seismic Acquisition in Colombia
Wednesday, April 20, 2011
Global Energy Development plc
Global Energy has begun planning the acquisition of 100 square kilometers of new 3D seismic over the Company's Bolivar Association Contract area.
The Company has previously reprocessed existing seismic over the contract area and made an exhaustive interpretation. The acquisition and interpretation of the new seismic data will enable the Company to validate the previous interpretation and establish the optimum position of the future wells scheduled to be drilled on the contract area.
Although the major structural elements of the block have been delineated using older vintage 2D seismic, the much higher resolution data gained from a 3D survey will identify the smaller features and ensure proper placement of lateral wellbores in the fractured reservoirs. Using the current "fairway" concept, it is necessary to locate the exact position of the various faults in order to identify areas of maximum natural fracture density. A portion of the 3D will be designed to image the Crisol gas cap, in order to determine the continuity and limits of that reservoir should the injection of associated gas become necessary in the future.
The Company has engaged Third Coast Enterpises, Inc. to aid in the design of an approximately 100 square kilometer 3D survey and is currently in the process of soliciting bids for selection of an acquisition company.
Once the design phase is finished and an acquisition company is selected, the Company plans to move to the permitting and acquisition phase of the projects which is expected to take approximately one to two months.
Wednesday, April 20, 2011
Global Energy Development plc
Global Energy has begun planning the acquisition of 100 square kilometers of new 3D seismic over the Company's Bolivar Association Contract area.
The Company has previously reprocessed existing seismic over the contract area and made an exhaustive interpretation. The acquisition and interpretation of the new seismic data will enable the Company to validate the previous interpretation and establish the optimum position of the future wells scheduled to be drilled on the contract area.
Although the major structural elements of the block have been delineated using older vintage 2D seismic, the much higher resolution data gained from a 3D survey will identify the smaller features and ensure proper placement of lateral wellbores in the fractured reservoirs. Using the current "fairway" concept, it is necessary to locate the exact position of the various faults in order to identify areas of maximum natural fracture density. A portion of the 3D will be designed to image the Crisol gas cap, in order to determine the continuity and limits of that reservoir should the injection of associated gas become necessary in the future.
The Company has engaged Third Coast Enterpises, Inc. to aid in the design of an approximately 100 square kilometer 3D survey and is currently in the process of soliciting bids for selection of an acquisition company.
Once the design phase is finished and an acquisition company is selected, the Company plans to move to the permitting and acquisition phase of the projects which is expected to take approximately one to two months.
Bowleven Hits Hydrocarbons Offshore Cameroon
Bowleven Hits Hydrocarbons Offshore Cameroon
Wednesday, April 20, 2011
BowLeven plc
Bowleven announced that the Sapele-1ST well drilling in the Douala Basin, offshore Cameroon has encountered a total of 23 meters of net hydrocarbon-bearing pay in the Omicron objectives based on the results of drilling, conventional wireline logs, samples of reservoir fluid and pressure data. A testing program is expected to commence shortly.
Highlights
Sapele-1ST drilling update
The principal objective of Sapele-1ST was to appraise the Deep Omicron oil discovery encountered in the Sapele-1 exploration well. The well was also designed to intersect both the Upper and Lower Omicron objectives.
The well was drilled to a TVD of 3,634 meters (4,483 meters measured depth) in water depths of around 25 meters approximately 2 kilometers South East from the Deep Omicron oil discovery in the original vertical well.
Bowleven, as operator, provides updates for the reservoir sections encountered at Sapele-1ST below:
Upper Omicron
1.4 meters of net pay were intersected overlying approximately 24 meters of high quality reservoir which following sampling was confirmed as water bearing.
Lower Omicron
The well has intersected a log evaluated hydrocarbon interval that is interpreted to comprise fair quality thinly interbedded reservoir units. Provisional net pay is estimated to be approximately 11 meters, based on conventional wireline logs, with an average porosity of 17%. Fluid samples acquired during logging activities indicate the presence of light oil/gas condensate as reservoir fluid.
Deep Omicron
The well has intersected a log evaluated hydrocarbon interval that is interpreted to comprise high quality thinly interbedded reservoir units. Although less well developed at this location and with a corresponding lower net to gross ratio than the Sapele-1 motherbore, the provisional net pay is conservatively estimated to be approximately 10 meters, based on conventional wireline logs, with an average porosity of 19%. In addition, initial interpretation indicates that certain pay intervals identified in the original Sapele-1 well have been eroded at the Sapele-1ST location. It was not possible to recover, it is believed due to borehole conditions, reservoir fluid samples and pressure data from Deep Omicron. Consequently, pressure communication could not be confirmed from logging activities. The GC tracer however indicates the presence of a light high GOR oil.
Forward plan
Further detailed analysis, including test data, is now required to assess the implications of the Sapele-1ST well on current resource estimates. The impending Sapele-2 appraisal well results will also be integral to this process. The Company is now preparing to conduct a drill stem testing program at Sapele-1ST. Following testing the intention is to release the Noble Tommy Craighead rig for a mandatory recertification process.
Due to the stratigraphic nature of the Omicron discoveries further appraisal will be required and is already underway and planned. The Sapele-2 well, intended to appraise both the Lower and Deep Omicron discoveries, is currently drilling with the Vantage Sapphire Driller rig and is expected to take a further 15 to 20 days (excluding testing). The rig is available for up to three well slots after Sapele-2 with the location selection process factoring in both ongoing technical evaluation and well results.
Kevin Hart, Chief Executive of Bowleven plc, commented, "We are pleased with the results so far on Sapele-1ST (sidetrack). The initial log evaluation is encouraging as it endorses the presence of light oil and gas condensate in the Lower and Deep Omicron fairways encountered with the original Sapele-1 well. Preparations are now underway for a testing program at Sapele-1ST to assess connectivity and deliverability. Given their stratigraphic nature, further evaluation, including appraisal drilling, is required to fully understand sand distribution within these tertiary fairways however results to date are promising in the context of Sapele and the Douala Basin as a whole."
Wednesday, April 20, 2011
BowLeven plc
Bowleven announced that the Sapele-1ST well drilling in the Douala Basin, offshore Cameroon has encountered a total of 23 meters of net hydrocarbon-bearing pay in the Omicron objectives based on the results of drilling, conventional wireline logs, samples of reservoir fluid and pressure data. A testing program is expected to commence shortly.
Highlights
- 23 meters of log evaluated net hydrocarbon pay encountered in the Omicron objectives at Sapele-1ST.
- Preparing for testing program at Sapele-1ST.
- Sapele-2 well progressing on schedule.
Sapele-1ST drilling update
The principal objective of Sapele-1ST was to appraise the Deep Omicron oil discovery encountered in the Sapele-1 exploration well. The well was also designed to intersect both the Upper and Lower Omicron objectives.
The well was drilled to a TVD of 3,634 meters (4,483 meters measured depth) in water depths of around 25 meters approximately 2 kilometers South East from the Deep Omicron oil discovery in the original vertical well.
Bowleven, as operator, provides updates for the reservoir sections encountered at Sapele-1ST below:
Upper Omicron
1.4 meters of net pay were intersected overlying approximately 24 meters of high quality reservoir which following sampling was confirmed as water bearing.
Lower Omicron
The well has intersected a log evaluated hydrocarbon interval that is interpreted to comprise fair quality thinly interbedded reservoir units. Provisional net pay is estimated to be approximately 11 meters, based on conventional wireline logs, with an average porosity of 17%. Fluid samples acquired during logging activities indicate the presence of light oil/gas condensate as reservoir fluid.
Deep Omicron
The well has intersected a log evaluated hydrocarbon interval that is interpreted to comprise high quality thinly interbedded reservoir units. Although less well developed at this location and with a corresponding lower net to gross ratio than the Sapele-1 motherbore, the provisional net pay is conservatively estimated to be approximately 10 meters, based on conventional wireline logs, with an average porosity of 19%. In addition, initial interpretation indicates that certain pay intervals identified in the original Sapele-1 well have been eroded at the Sapele-1ST location. It was not possible to recover, it is believed due to borehole conditions, reservoir fluid samples and pressure data from Deep Omicron. Consequently, pressure communication could not be confirmed from logging activities. The GC tracer however indicates the presence of a light high GOR oil.
Forward plan
Further detailed analysis, including test data, is now required to assess the implications of the Sapele-1ST well on current resource estimates. The impending Sapele-2 appraisal well results will also be integral to this process. The Company is now preparing to conduct a drill stem testing program at Sapele-1ST. Following testing the intention is to release the Noble Tommy Craighead rig for a mandatory recertification process.
Due to the stratigraphic nature of the Omicron discoveries further appraisal will be required and is already underway and planned. The Sapele-2 well, intended to appraise both the Lower and Deep Omicron discoveries, is currently drilling with the Vantage Sapphire Driller rig and is expected to take a further 15 to 20 days (excluding testing). The rig is available for up to three well slots after Sapele-2 with the location selection process factoring in both ongoing technical evaluation and well results.
Kevin Hart, Chief Executive of Bowleven plc, commented, "We are pleased with the results so far on Sapele-1ST (sidetrack). The initial log evaluation is encouraging as it endorses the presence of light oil and gas condensate in the Lower and Deep Omicron fairways encountered with the original Sapele-1 well. Preparations are now underway for a testing program at Sapele-1ST to assess connectivity and deliverability. Given their stratigraphic nature, further evaluation, including appraisal drilling, is required to fully understand sand distribution within these tertiary fairways however results to date are promising in the context of Sapele and the Douala Basin as a whole."
Dudley: The Lessons of Deepwater Horizon
Dudley: The Lessons of Deepwater Horizon
Wednesday, April 20, 2011
The Wall Street Journal
by Bob Dudley
A year ago [Wednesday, April 20], the Deepwater Horizon drilling rig exploded, killing 11 men and causing the largest offshore oil spill in U.S. history. At BP we regret that the accident happened and the impact it has had on the environment of the Gulf Coast and people living there.
From the start, we committed to pay all legitimate claims and work to restore the damage caused by the oil spill. We pledged to cooperate fully with all investigations into the cause of the accident. Finally, we said we would work to embed the lessons learned into the fabric of our organization and share those lessons with our industry colleagues and government regulators.
One year on, where do we stand with regard to those commitments?
First, we are paying claims. BP set aside $20 billion in a fund to compensate individuals, businesses and governments that were impacted, as well as for natural resource damages. So far, more than $5 billion in claims and other payments has been paid out of that fund.
In cooperation with federal and state government scientists, we're conducting a thorough assessment of the spill's environmental impact.
We've created a $500 million fund to support further scientific research on the spill's long-term impact. And we're supporting efforts by the region's governors to restore key industries, such as tourism and seafood.
But we know that we must do more than make good on the economic losses from the spill. BP has to change as well. The steps we have taken so far include:
In the last few months, we have shut down several platforms to request modifications consistent with BP's standards. One of these was our Holstein platform in the Gulf of Mexico, which was shut down after we discovered incorrect specifications for some bolts.
BP engineers and technicians have traveled to Russia, Angola, Australia, Brazil and elsewhere to share what we've learned about the accident with government policy makers, regulators, academics, industry partners and the general public.
Changing BP alone, however, is not enough. There are lessons from Deepwater Horizon for the entire industry. As the commission appointed by President [Barack] Obama to investigate the accident concluded, "Deepwater energy exploration and production, particularly at the frontiers of experience, involve risks for which neither industry nor government has been adequately prepared, but for which they can and must be prepared in the future."
In conjunction with the other major oil and gas companies that operate in the U.S., BP has joined the Marine Well Containment Corporation, a specially created entity designed to maintain preparedness for any future spills in the Gulf of Mexico. We've donated specialized equipment developed during last summer's containment effort, so that all of industry is better prepared.
Looking ahead, it is important to keep in mind that the global demand for energy will rise inexorably in coming decades--nearly 40% by 2030, according to BP estimates. That's roughly twice the current energy consumption of the entire U.S. Even as energy companies develop alternatives, the world will still need a large volume of oil.
Given the maturity of many existing fields, much of that oil will need to come from newer sources, such as the deep water. Right now, around 7% of the world's oil supplies are coming from the deep water, a total we expect will rise to nearly 10% by the end of this decade. That means we must have better safety technology, more effective equipment and the capability to deal with a blowout in the deep water.
BP gets it. BP is changing. We are committed to working together with our industry colleagues and government regulators to ensure a safer, stronger energy future.
LINK
The Gulf of Mexico Oil Spill
Latest Deepwater Horizon Headlines
Wednesday, April 20, 2011
The Wall Street Journal
by Bob Dudley
A year ago [Wednesday, April 20], the Deepwater Horizon drilling rig exploded, killing 11 men and causing the largest offshore oil spill in U.S. history. At BP we regret that the accident happened and the impact it has had on the environment of the Gulf Coast and people living there.
From the start, we committed to pay all legitimate claims and work to restore the damage caused by the oil spill. We pledged to cooperate fully with all investigations into the cause of the accident. Finally, we said we would work to embed the lessons learned into the fabric of our organization and share those lessons with our industry colleagues and government regulators.
One year on, where do we stand with regard to those commitments?
First, we are paying claims. BP set aside $20 billion in a fund to compensate individuals, businesses and governments that were impacted, as well as for natural resource damages. So far, more than $5 billion in claims and other payments has been paid out of that fund.
In cooperation with federal and state government scientists, we're conducting a thorough assessment of the spill's environmental impact.
We've created a $500 million fund to support further scientific research on the spill's long-term impact. And we're supporting efforts by the region's governors to restore key industries, such as tourism and seafood.
But we know that we must do more than make good on the economic losses from the spill. BP has to change as well. The steps we have taken so far include:
- Creating a central safety and operational-risk organization reporting directly to me. This organization has the mandate and resources to drive safe, reliable operations that comply with regulations, and it has the authority to intervene in our operations anywhere in the world. We are also linking the management of employees' performance and reward directly to safety and to compliance with BP's standards.
- We will not use rigs on our projects that do not conform to our standards. We have either turned away rigs or are negotiating for modifications to particular rigs that will bring them up to our standards.
In the last few months, we have shut down several platforms to request modifications consistent with BP's standards. One of these was our Holstein platform in the Gulf of Mexico, which was shut down after we discovered incorrect specifications for some bolts.
BP engineers and technicians have traveled to Russia, Angola, Australia, Brazil and elsewhere to share what we've learned about the accident with government policy makers, regulators, academics, industry partners and the general public.
- We have also asked recently retired Adm. Frank "Skip" Bowman to join our board of directors. A former head of the U.S. nuclear navy, he has spent his entire career dealing with safety-related issues in a sector admired for its safety record.
Changing BP alone, however, is not enough. There are lessons from Deepwater Horizon for the entire industry. As the commission appointed by President [Barack] Obama to investigate the accident concluded, "Deepwater energy exploration and production, particularly at the frontiers of experience, involve risks for which neither industry nor government has been adequately prepared, but for which they can and must be prepared in the future."
In conjunction with the other major oil and gas companies that operate in the U.S., BP has joined the Marine Well Containment Corporation, a specially created entity designed to maintain preparedness for any future spills in the Gulf of Mexico. We've donated specialized equipment developed during last summer's containment effort, so that all of industry is better prepared.
Looking ahead, it is important to keep in mind that the global demand for energy will rise inexorably in coming decades--nearly 40% by 2030, according to BP estimates. That's roughly twice the current energy consumption of the entire U.S. Even as energy companies develop alternatives, the world will still need a large volume of oil.
Given the maturity of many existing fields, much of that oil will need to come from newer sources, such as the deep water. Right now, around 7% of the world's oil supplies are coming from the deep water, a total we expect will rise to nearly 10% by the end of this decade. That means we must have better safety technology, more effective equipment and the capability to deal with a blowout in the deep water.
BP gets it. BP is changing. We are committed to working together with our industry colleagues and government regulators to ensure a safer, stronger energy future.
LINK
The Gulf of Mexico Oil Spill
Latest Deepwater Horizon Headlines
Deepwater Horizon Spurs Development of Spill Prevention Systems
Deepwater Horizon Spurs Development of Spill Prevention Systems
The Deepwater Horizon oil spill disaster in April 2010 prompted the creation of oil spill response systems for use in the Gulf of Mexico and in the North Sea. Two oil spill prevention systems are now available for oil and gas producers in the Gulf of Mexico, and a well capping device is currently under construction in the UK that will be used as part of the UK oil and gas industry's oil spill response efforts.
HWCC has signed an agreement with Helix Energy Solutions Group, which will provide primary components of the well containment response system. The Helix Fast Response System (HFRS), which has been developed using Helix Energy Solutions Group assets that were deployed in the Deepwater Horizon incident, is expected to be fully operational for water depths of up to 10,000 feet by this summer.
Twenty-three deepwater Gulf operators comprise the HWCG consortium; these operators represent two-thirds of the deepwater operators in the Gulf of Mexico and approximately half of all deepwater oil and gas production in the Gulf. Members include Anadarko Petroleum Corp.; Apache Corp.; ATP Oil & Gas; BHP Billiton; Cobalt International Energy; Deep Gulf Energy; Eni; Energy Resource Technology GOM; Hess Corp.; LLOG Exploration Company; Marathon Oil Company; Marubeni Oil & Gas; Murphy Exploration & Production; Newfield Exploration Company; Nexen Petroleum; Noble Energy; Plains Exploration & Production; Repsol E&P USA; Statoil; Stone Energy; Walter Oil & Gas Corporation; Woodside Energy; and W&T Offshore.
Capping Stack, Marine Well Containment Co.ExxonMobil, ConocoPhillips and Chevron announced the plan to build and develop the system last July; since then, BP, Anadarko Petroleum Corp., Apache Corp., BHP Billiton, Shell, Hess Corp. and Statoil have joined MWCC. These 10 companies operated approximately 70 percent of deepwater wells drilled in the U.S. Gulf of Mexico between 2007 through 2009. The non-profit, stand-alone organization is open to all companies operating in the U.S. Gulf of Mexico.
Helix used the lessons it learned from its participation in containing the Deepwater Horizon oil spill to its approach to containment efforts in the future. While coordinating and idea sharing is very important to making advances, Kratz noted that the U.S. government can assist the industry by minimizing the cost of capital by reinvigorating programs specifically designed to advance maritime industrial development. A familiar program of this type is the U.S. Maritime Administration (MARAD)'s loan guarantee program. Kratz said MARAD could help responsibly and within fiscal constraints, and has a "proven track record for bringing innovative vessel designs to market.
"As we have seen, the most innovative vessel designs will be the most useful going forward," Kratz said. The Q4000, built in Texas with MARAD financing, provides an excellent example, and was instrumental in bringing the Macondo blowout under control, Kratz said.
The Q4000 Drilling PlatformHaving a diverse array of players in upstream oil and gas has allowed for technological innovation. "When the government fails to respond appropriately to permitting concerns or creates significant doubt which undermines business confidence, it saps potential investment capital necessary to innovate," Kratz said.
The cap is modular in design, with specifications that allow it to be deployed in the widest range of possible oil spill scenarios that could typically be encountered in the UK Continental shelf including west of Shetland.
The device has an overall working pressure rating of 15,000 psi, and is capable of capping a well flowing up to 75,000 b/d and in water depths of up to 5,500 feet. Capping should be achieved within 20-30 days of the incident, depending on weather and well site conditions.
LINK
The Gulf of Mexico Oil Spill
Latest Deepwater Horizon Headlines
Wednesday, April 20, 2011
Rigzone StaffThe Deepwater Horizon oil spill disaster in April 2010 prompted the creation of oil spill response systems for use in the Gulf of Mexico and in the North Sea. Two oil spill prevention systems are now available for oil and gas producers in the Gulf of Mexico, and a well capping device is currently under construction in the UK that will be used as part of the UK oil and gas industry's oil spill response efforts.
Helix Well Containment Group
The Helix Well Containment Group (HWCG) plans to conduct a third tabletop exercise in late May to increase its members' coordination and preparedness for a subsea well containment incident. The group already has conducted two tabletop exercises this spring. The most recent exercise in late March brought together more than 225 technical professionals from the oil and gas industry.HWCC has signed an agreement with Helix Energy Solutions Group, which will provide primary components of the well containment response system. The Helix Fast Response System (HFRS), which has been developed using Helix Energy Solutions Group assets that were deployed in the Deepwater Horizon incident, is expected to be fully operational for water depths of up to 10,000 feet by this summer.
Twenty-three deepwater Gulf operators comprise the HWCG consortium; these operators represent two-thirds of the deepwater operators in the Gulf of Mexico and approximately half of all deepwater oil and gas production in the Gulf. Members include Anadarko Petroleum Corp.; Apache Corp.; ATP Oil & Gas; BHP Billiton; Cobalt International Energy; Deep Gulf Energy; Eni; Energy Resource Technology GOM; Hess Corp.; LLOG Exploration Company; Marathon Oil Company; Marubeni Oil & Gas; Murphy Exploration & Production; Newfield Exploration Company; Nexen Petroleum; Noble Energy; Plains Exploration & Production; Repsol E&P USA; Statoil; Stone Energy; Walter Oil & Gas Corporation; Woodside Energy; and W&T Offshore.
Marine Well Containment Company
The Marine Well Containment Company (MWCC) in February launched its interim rapid response system to capture and contain oil from potential underwater well blowouts in the deepwater Gulf. The system can operate in up to 8,000 feet of water and process up to 60,000 b/d of fluid. Work is underway to expand the system to operate in up to 10,000 feet of water and process up to 100,000 b/d, with components to be delivered in 2012.Capping Stack, Marine Well Containment Co.
Cooperation, Encouragement of Innovation Needed
The private sector worked hand in glove with the U.S. Coast Guard's research and development division and U.S. Navy research centers to assess technology, particularly for surface containment applications, said Owen Kratz, Helix president and chief executive officer, while testifying before Congress on April 4. "The NOAA also had tremendous value to bring to bear," said Kratz. "We certainly encourage those government agencies to work closely with industry organizations like the HWCG and Marine Well Containment Corporation established by some of the major integrated oil companies."Helix used the lessons it learned from its participation in containing the Deepwater Horizon oil spill to its approach to containment efforts in the future. While coordinating and idea sharing is very important to making advances, Kratz noted that the U.S. government can assist the industry by minimizing the cost of capital by reinvigorating programs specifically designed to advance maritime industrial development. A familiar program of this type is the U.S. Maritime Administration (MARAD)'s loan guarantee program. Kratz said MARAD could help responsibly and within fiscal constraints, and has a "proven track record for bringing innovative vessel designs to market.
"As we have seen, the most innovative vessel designs will be the most useful going forward," Kratz said. The Q4000, built in Texas with MARAD financing, provides an excellent example, and was instrumental in bringing the Macondo blowout under control, Kratz said.
The Q4000 Drilling Platform
UK Well Capping Device
Energy industry association Oil & Gas UK in March confirmed that construction of a well capping device was underway at Cameron Ltd., in Leeds, UK. The capping device will become a key element of the UK offshore oil and gas industry's oil spill response contingency plans. Completion of the device is due this summer.The cap is modular in design, with specifications that allow it to be deployed in the widest range of possible oil spill scenarios that could typically be encountered in the UK Continental shelf including west of Shetland.
The device has an overall working pressure rating of 15,000 psi, and is capable of capping a well flowing up to 75,000 b/d and in water depths of up to 5,500 feet. Capping should be achieved within 20-30 days of the incident, depending on weather and well site conditions.
LINK
The Gulf of Mexico Oil Spill
Latest Deepwater Horizon Headlines
Deepwater Horizon: One Year Later
Deepwater Horizon: One Year Later
Wednesday, April 20, 2011
Rigzone Staff
by Jaime Kammerzell
A year ago today, an explosion on Transocean's Deepwater Horizon ultra-deepwater semisubmersible, positioned at the Macondo Prospect in Mississippi Canyon Block 252, in the Gulf of Mexico, took the lives of 11 men and caused the largest marine oil spill in history.
At 9:45 p.m. on April 20, 2010, while plugging the well for later production, seawater erupted from the marine riser onto the rig, shooting 240 ft into the air. A combination of mud, methane gas, and water quickly followed. The gas then ignited, causing explosions onboard. Attempts to activate the blowout preventer failed. Survivors said they had less than five minutes to escape after the alarm went off. Multiple ships attempted to put out the fire, but it could not be extinguished. After burning for 36 hours, the Deepwater Horizon sank in about 5,000 ft of water on April 22, 2010.
A total of 126 people were onboard the Deepwater Horizon at the time of the explosion. Only 115 evacuated. Those who were able to escape took lifeboats to the M/V Damon B Bankston workboat nearby, which had been servicing the Deepwater Horizon. The US Coast Guard searched for three days.
Although BP was the operator of the Mocondo field, it was working with Transocean and Halliburton to plug the well for later completion as a subsea producer. BP believes that Transocean and Halliburton share the blame for the disaster.
According to Transocean, its employees had been performing routine work and did not notice any problems leading up to the explosion. Halliburton had finished running production casing and cementing 20 hours before the blowout. Transocean's CEO, Steven Newman, pointed his finger at Halliburton when he said, "there was a sudden, catastrophic failure of the cement, the casing or both."
When the semisubmersible sank, it left the well gushing oil out of the riser into the Gulf of Mexico. The resulting oil slick covered about 28,958 sq mi and reached beaches in Louisiana, Mississippi, Alabama and Florida by June 9th, when BP reported that it had lost more than $82 billion, close to half its value.
BP began drilling two relief wells on May 2 and May 16. In an attempt to stop the oil spill sooner, BP also tried using remotely operated underwater vehicles to close the BOP valves on the well head. This failed. BP then tried to place a 125 tonne containment dome over the largest leak to pipe oil to a storage vessel on the surface, but this attempt failed when gas leaked from the pipe and mixed with the cold water, which formed methane hydrate crystals that blocked the opening at the top of the dome. Pumping heavy drilling fluids into the BOP to restrict oil flow and permanently seal it with cement failed as well.
BP then tried positioning a riser insertion tube into the burst pipe. This worked adequately until the damaged riser could be capped on June 3rd. A washer plugged the end of the riser and diverted it to the insertion tube. Gas was flared and oil was stored on board the Discoverer Enterprise drillship. But this solution didn't last long. A second containment system, which connected directly to the BOP, was installed on June 16. The oil and gas were diverted to the Q4000 service vessel where it was burned. This worked well, so the Discoverer Clear Leader drillship and Helix Producer I FPSO joined in the effort, offloading oil to the Evi Knutsen and Juanita tankers. Two more vessels, the Seillean FPSO and Toisa Pices well testing vessels processed oil and offloaded to the Loch Rannoch shuttle tanker.
BP was pleased with this solution and announced on July 5, 2010, that it was recovering about 25,000 b/d and flaring 57.1 Mcf/d. However, the government estimated that the cap only captured about half of the leaking oil. BP made further adjustments to its cap solution and replaced the original cap on July 10 with a Flange Transition Spool and a 3 Ram Stack. On July 15, BP tested its new and improved cap by shutting off pipes that brought oil to the surface ships. This allowed the total pressure of the gushing oil to flow into the cap. The cap contained the oil and stopped the leak.
Meanwhile, BP continued to drill the two relief wells, which took four months to reach the Macondo well on September 15. BP pumped cement into the well 17,977 ft below the sea floor to permanently seal it. It took three days to complete. BP then permanently completed and abandoned the initial Macondo well as well as the two relief wells.
Though the oil has stopped gushing into the GOM, the aftermath remains today. Aside from the environmental and fishing and tourism impact, offshore exploration and production has been slow to return to pre-disaster levels. This is due mainly to governmental restraints.
On May 27th, President Obama instituted a temporary moratorium on offshore drilling in 500 ft or more of water, which also suspended drilling on 33 wells already in progress. He also implemented new standards for equipment and procedures.
The US Department of the Interior then issued tighter standards for barriers at underwater wells and BOPs on June 8, 2010. At the same time, the Interior Department started requiring CEOs of drilling companies to certify that their operations comply with the new regulations, including equipment testing and personnel training. Drilling in less than 500 ft of water resumed under the new standards. However, the deepwater drilling ban remained in effect until June 22, when a US federal judge in New Orleans lifted the moratorium saying it was "a blanket, generic, indeed punitive moratorium," as well as a potential harm to the economy, businesses and workers.
In response, Interior Secretary Salazar immediately issued a new order that contained additional information showing why the moratorium was necessary. The Interior Department defended Salazar's actions, saying Interior Secretary Ken Salazar "has merely fulfilled his continuing duty to manage the [Outer Continental Shelf] by reanalyzing the previously directed suspensions, evaluating new information on the adequacy of safety and environmental protection standards for OCS lease operations in the Gulf of Mexico, and issuing a new decision."
Interior Secretary, Ken SalazarThe deepwater ban went in effect again until November 30, 2010. However, President Obama lifted the drilling ban in deepwater GOM waters on Oct. 11, 2010. Salazar said in a statement that drilling in waters deeper than 500 ft can resume if operators follow the new Drilling Safety Rule.
"Under these new rules, operators will need to comply with tougher requirements for everything from well design and cementing practices to blowout preventers and employee training," Salazar said. "They will also need to develop comprehensive plans to manage risks and hazards at every step of the drilling process, so as to reduce the risk of human error."
Though the drilling ban was lifted in October, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) didn't approve the first post-moratorium deepwater drilling permit until Feb. 28, 2011.
On Jan. 11, 2011, the White House released a report of its investigation of the oil spill. The report stated, "BP, Halliburton, and Transocean did not adequately identify or address risks of an accident…As a result, officials made a series of decisions that saved BP, Halliburton, and Transocean time and money—but without full appreciation of the associated risks."
Transocean and Halliburton attempted to sidestep the blame and pointed fingers at BP saying they were just following orders. Halliburton further criticized BP for its failure to run a cement bond log test.
In March, US Investigators, who hired Det Norske Veritas (DNV) to examine the failed blowout preventor, released a report that found a piece of drill pipe that was trapped inside the blowout preventer kept it from closing. The report didn't blame BP, Transocoean or Halliburton for the equipment failure. It simply focused on the cause of the failure.
According to a Reuters report from April 3, 2011, BP will be resuming its operations in the GOM in July 2011. The operator will be restricted to maintaining or increasing production on existing platforms. BP will not be permitted to drill exploration wells.
LINK
The Gulf of Mexico Oil Spill
Latest Deepwater Horizon Headlines
Wednesday, April 20, 2011
Rigzone Staff
by Jaime Kammerzell
A year ago today, an explosion on Transocean's Deepwater Horizon ultra-deepwater semisubmersible, positioned at the Macondo Prospect in Mississippi Canyon Block 252, in the Gulf of Mexico, took the lives of 11 men and caused the largest marine oil spill in history.
At 9:45 p.m. on April 20, 2010, while plugging the well for later production, seawater erupted from the marine riser onto the rig, shooting 240 ft into the air. A combination of mud, methane gas, and water quickly followed. The gas then ignited, causing explosions onboard. Attempts to activate the blowout preventer failed. Survivors said they had less than five minutes to escape after the alarm went off. Multiple ships attempted to put out the fire, but it could not be extinguished. After burning for 36 hours, the Deepwater Horizon sank in about 5,000 ft of water on April 22, 2010.
A total of 126 people were onboard the Deepwater Horizon at the time of the explosion. Only 115 evacuated. Those who were able to escape took lifeboats to the M/V Damon B Bankston workboat nearby, which had been servicing the Deepwater Horizon. The US Coast Guard searched for three days.
Although BP was the operator of the Mocondo field, it was working with Transocean and Halliburton to plug the well for later completion as a subsea producer. BP believes that Transocean and Halliburton share the blame for the disaster.
According to Transocean, its employees had been performing routine work and did not notice any problems leading up to the explosion. Halliburton had finished running production casing and cementing 20 hours before the blowout. Transocean's CEO, Steven Newman, pointed his finger at Halliburton when he said, "there was a sudden, catastrophic failure of the cement, the casing or both."
BP began drilling two relief wells on May 2 and May 16. In an attempt to stop the oil spill sooner, BP also tried using remotely operated underwater vehicles to close the BOP valves on the well head. This failed. BP then tried to place a 125 tonne containment dome over the largest leak to pipe oil to a storage vessel on the surface, but this attempt failed when gas leaked from the pipe and mixed with the cold water, which formed methane hydrate crystals that blocked the opening at the top of the dome. Pumping heavy drilling fluids into the BOP to restrict oil flow and permanently seal it with cement failed as well.
BP then tried positioning a riser insertion tube into the burst pipe. This worked adequately until the damaged riser could be capped on June 3rd. A washer plugged the end of the riser and diverted it to the insertion tube. Gas was flared and oil was stored on board the Discoverer Enterprise drillship. But this solution didn't last long. A second containment system, which connected directly to the BOP, was installed on June 16. The oil and gas were diverted to the Q4000 service vessel where it was burned. This worked well, so the Discoverer Clear Leader drillship and Helix Producer I FPSO joined in the effort, offloading oil to the Evi Knutsen and Juanita tankers. Two more vessels, the Seillean FPSO and Toisa Pices well testing vessels processed oil and offloaded to the Loch Rannoch shuttle tanker.
BP was pleased with this solution and announced on July 5, 2010, that it was recovering about 25,000 b/d and flaring 57.1 Mcf/d. However, the government estimated that the cap only captured about half of the leaking oil. BP made further adjustments to its cap solution and replaced the original cap on July 10 with a Flange Transition Spool and a 3 Ram Stack. On July 15, BP tested its new and improved cap by shutting off pipes that brought oil to the surface ships. This allowed the total pressure of the gushing oil to flow into the cap. The cap contained the oil and stopped the leak.
Meanwhile, BP continued to drill the two relief wells, which took four months to reach the Macondo well on September 15. BP pumped cement into the well 17,977 ft below the sea floor to permanently seal it. It took three days to complete. BP then permanently completed and abandoned the initial Macondo well as well as the two relief wells.
Though the oil has stopped gushing into the GOM, the aftermath remains today. Aside from the environmental and fishing and tourism impact, offshore exploration and production has been slow to return to pre-disaster levels. This is due mainly to governmental restraints.
On May 27th, President Obama instituted a temporary moratorium on offshore drilling in 500 ft or more of water, which also suspended drilling on 33 wells already in progress. He also implemented new standards for equipment and procedures.
The US Department of the Interior then issued tighter standards for barriers at underwater wells and BOPs on June 8, 2010. At the same time, the Interior Department started requiring CEOs of drilling companies to certify that their operations comply with the new regulations, including equipment testing and personnel training. Drilling in less than 500 ft of water resumed under the new standards. However, the deepwater drilling ban remained in effect until June 22, when a US federal judge in New Orleans lifted the moratorium saying it was "a blanket, generic, indeed punitive moratorium," as well as a potential harm to the economy, businesses and workers.
In response, Interior Secretary Salazar immediately issued a new order that contained additional information showing why the moratorium was necessary. The Interior Department defended Salazar's actions, saying Interior Secretary Ken Salazar "has merely fulfilled his continuing duty to manage the [Outer Continental Shelf] by reanalyzing the previously directed suspensions, evaluating new information on the adequacy of safety and environmental protection standards for OCS lease operations in the Gulf of Mexico, and issuing a new decision."
Interior Secretary, Ken Salazar
"Under these new rules, operators will need to comply with tougher requirements for everything from well design and cementing practices to blowout preventers and employee training," Salazar said. "They will also need to develop comprehensive plans to manage risks and hazards at every step of the drilling process, so as to reduce the risk of human error."
Though the drilling ban was lifted in October, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) didn't approve the first post-moratorium deepwater drilling permit until Feb. 28, 2011.
On Jan. 11, 2011, the White House released a report of its investigation of the oil spill. The report stated, "BP, Halliburton, and Transocean did not adequately identify or address risks of an accident…As a result, officials made a series of decisions that saved BP, Halliburton, and Transocean time and money—but without full appreciation of the associated risks."
Transocean and Halliburton attempted to sidestep the blame and pointed fingers at BP saying they were just following orders. Halliburton further criticized BP for its failure to run a cement bond log test.
In March, US Investigators, who hired Det Norske Veritas (DNV) to examine the failed blowout preventor, released a report that found a piece of drill pipe that was trapped inside the blowout preventer kept it from closing. The report didn't blame BP, Transocoean or Halliburton for the equipment failure. It simply focused on the cause of the failure.
According to a Reuters report from April 3, 2011, BP will be resuming its operations in the GOM in July 2011. The operator will be restricted to maintaining or increasing production on existing platforms. BP will not be permitted to drill exploration wells.
LINK
The Gulf of Mexico Oil Spill
Latest Deepwater Horizon Headlines
United Technologies Beats Estimates, Raises 2011 Guidance
United Technologies Beats Estimates, Raises 2011 Guidance
Apr 20, 2011
United Technologies Corp (NYSE:UTX) reported Q1 2011 EPS of $1.11 today, beating the consensus estimate for $1.07 per share. Revenues for the quarter were up 10.8% to $13.34 billion, higher than the consensus estimate for $12.83 billion.
The company raised its full year 2011 EPS expectation to $5.25 to $5.40, from $5.20 to $5.35 previously, vs. the consensus estimate for a $5.36 per share profit.
Louis Chenevert, UTC Chairman & Chief Executive Officer said, "This was another solid quarter for UTC with broad-based acceleration in organic growth, as well as strong earnings momentum and cash generation. Nearly 20 percent growth in earnings per share reflects excellent conversion, especially as we continued to increase our investments in game changing products and technologies."
Apr 20, 2011
United Technologies Corp (NYSE:UTX) reported Q1 2011 EPS of $1.11 today, beating the consensus estimate for $1.07 per share. Revenues for the quarter were up 10.8% to $13.34 billion, higher than the consensus estimate for $12.83 billion.
The company raised its full year 2011 EPS expectation to $5.25 to $5.40, from $5.20 to $5.35 previously, vs. the consensus estimate for a $5.36 per share profit.
Louis Chenevert, UTC Chairman & Chief Executive Officer said, "This was another solid quarter for UTC with broad-based acceleration in organic growth, as well as strong earnings momentum and cash generation. Nearly 20 percent growth in earnings per share reflects excellent conversion, especially as we continued to increase our investments in game changing products and technologies."
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