Commodity Corner: Crude Climbs on Weaker Dollar
Tuesday, April 19, 2011
Rigzone Staff
by Saaniya Bangee
Crude futures retreated Tuesday's earlier losses as the dollar weakened against foreign currencies.
Light, sweet crude gained $1.03 to settle at $108.15 a barrel. Tuesday marks the last trading session for the May contract.
Reaching as low as $105.50 a barrel, oil prices reversed course soaring in afternoon trading. As the dollar weakened, the euro gained strength on speculation that the European Central Bank will further increase interest rates. Additionally, strong economic data from France and Germany outweighed fears of Greece restructuring its debt. A weaker greenback increases crude's appeal amongst foreign buyers, making it cheaper.
Prices also bounced back from Monday's lows after Treasury Secretary Timothy Geithner assured there was "no risk" that the U.S. government debt would lose its top-tier rating.
Meanwhile in the Middle East, OPEC Secretary General Abdullah Al-Badri said there isn't a shortage of oil in the global market, even after the supply disruptions in Libya. OPEC believes an increase in crude production will not decrease oil prices worldwide.
Likewise, natural gas futures for May delivery rose to two-week highs settling at $4.26 per thousand cubic feet. The 12.4-cent increase came on a surprising surge in the Midwest's heating demand Tuesday. An unusual drop in weather across most of the Northwest and upper-Midwest and unexpected warmth in the south has increased demand for fuel. The intraday range for natural gas was $4.13 to $4.28 Tuesday.
As retail gasoline rose, May gasoline continued to decline, trading down 1.97 cents Tuesday. Futures settled at $3.23 a gallon increasing concerns that fuel costs will hinder economic recovery and decrease demand for motor fuel in the U.S. Gasoline prices peaked at $3.259 a gallon, before bottoming out at $3.198 Tuesday.
Tuesday, April 19, 2011
AGR Clinches North Sea Drilling Campaign
AGR Clinches North Sea Drilling Campaign
Tuesday, April 19, 2011
AGR Petroleum Services
AGR Petroleum Services is to undertake a multi-well, multi-client drilling campaign valued at £3 million on behalf of three international operators, utilizing the semi-submersible drilling rig WilPhoenix.
The largest independent well management firm will drill four wells across the UK Central North Sea and West of Shetland having first pioneered this ground breaking drilling model in the North Sea in 2005.
Well management and drilling services will be carried out for Faroe Petroleum, Hurricane Exploration and Antrim Energy Inc, building on AGR Petroleum Services' longstanding relationship with the rig owner to provide excellent client rates.
Ian Burdis, Vice President of Well Management AGR Petroleum Services, said, "This is a significant drilling campaign and we look forward to working closely with our returning clients and Awilco Drilling Ltd to deliver a successful outcome.
"The nature of these contract wins reinforces how we have positioned ourselves as a key player in the industry through an innovative approach to creating relationships with both clients and suppliers and use of a highly experienced workforce."
Tuesday, April 19, 2011
AGR Petroleum Services
AGR Petroleum Services is to undertake a multi-well, multi-client drilling campaign valued at £3 million on behalf of three international operators, utilizing the semi-submersible drilling rig WilPhoenix.
The largest independent well management firm will drill four wells across the UK Central North Sea and West of Shetland having first pioneered this ground breaking drilling model in the North Sea in 2005.
Well management and drilling services will be carried out for Faroe Petroleum, Hurricane Exploration and Antrim Energy Inc, building on AGR Petroleum Services' longstanding relationship with the rig owner to provide excellent client rates.
Ian Burdis, Vice President of Well Management AGR Petroleum Services, said, "This is a significant drilling campaign and we look forward to working closely with our returning clients and Awilco Drilling Ltd to deliver a successful outcome.
"The nature of these contract wins reinforces how we have positioned ourselves as a key player in the industry through an innovative approach to creating relationships with both clients and suppliers and use of a highly experienced workforce."
Aker Scores EPC Gig for Statoil's Vigdis Development
Aker Scores EPC Gig for Statoil's Vigdis Development
Tuesday, April 19, 2011
Aker Solutions
by SubseaIQ
Aker Solutions has received notification that Statoil has exercised options for the engineering, procurement and construction of three subsea work-over systems for use on the Norwegian Continental Shelf. Aker Solutions estimates the contract value of these three extensions to be a total of approximately NOK 1.25 billion ($228MM).
In February, Statoil awarded Aker Solutions a contract for one workover system to be used on the Vigdis North East development on the Norwegian Continental Shelf. It is options from this contract which have been exercised.
Workover equipment is used on every subsea well, for installing equipment and preparing the well for production. During field life, workover equipment is used during the maintenance of subsea wells to improve oil recovery.
"We are pleased to receive additional awards for our new modularized workover systems. This contract will strengthen Akers Solutions' position as one of the major providers of well access services on the Norwegian continental shelf. Our equipment provides safe and efficient well access for downhole operations, resulting in increased oil recovery," said Mads Andersen, executive vice president of Aker Solutions' subsea business area.
The workover systems project will be managed at Aker Solutions' Tranby Technology and Manufacturing Centre outside Oslo in Norway. The manufacturing of the well control package and riser elements will be completed at Tranby and the workover control module out of Aberdeen.
Tuesday, April 19, 2011
Aker Solutions
by SubseaIQ
Aker Solutions has received notification that Statoil has exercised options for the engineering, procurement and construction of three subsea work-over systems for use on the Norwegian Continental Shelf. Aker Solutions estimates the contract value of these three extensions to be a total of approximately NOK 1.25 billion ($228MM).
In February, Statoil awarded Aker Solutions a contract for one workover system to be used on the Vigdis North East development on the Norwegian Continental Shelf. It is options from this contract which have been exercised.
Workover equipment is used on every subsea well, for installing equipment and preparing the well for production. During field life, workover equipment is used during the maintenance of subsea wells to improve oil recovery.
"We are pleased to receive additional awards for our new modularized workover systems. This contract will strengthen Akers Solutions' position as one of the major providers of well access services on the Norwegian continental shelf. Our equipment provides safe and efficient well access for downhole operations, resulting in increased oil recovery," said Mads Andersen, executive vice president of Aker Solutions' subsea business area.
The workover systems project will be managed at Aker Solutions' Tranby Technology and Manufacturing Centre outside Oslo in Norway. The manufacturing of the well control package and riser elements will be completed at Tranby and the workover control module out of Aberdeen.
Expro Names New COO
Expro Names New COO
Tuesday, April 19, 2011
Expro Names New COO
Expro announced the appointment of Michael Jardon as its new Chief Operating Officer. He replaces Chris Mawtus, who has assumed the new role of Service Quality Director for Expro.
Mr. Jardon joins Expro from his current position as North America President of Vallourec & Mannesmann USA, a business offering premium tubular solutions to the oil and gas industry. This follows a highly successful 16-year career with Schlumberger. His appointment takes effect from May 1st.
At Vallourec & Mannesmann, Mr. Jardon led the organization's commercial activities across the energy and industry segments in North America, directing global research and development, as well as managing sales and strategy for the region.
With Schlumberger, he held senior roles in wireline, completions, well testing and subsea, culminating in three years as Vice President Well Testing and Subsea, responsible for North and South America. Before this, he held the role of Vice President Operations Support for Schlumberger's Well Completions and Productivity businesses which included responsibility for supporting global operations and driving overall Quality, Health, Safety and Environmental (QHSE) performance. While with Schlumberger, Mr. Jardon lived in the US, South America and the Middle East.
Expro Chief Executive Officer Charles Woodburn said, "Throughout his career, Mike has demonstrated exceptional operational leadership, as well as a passion for developing new business, introducing new technologies to market, and developing and mentoring people. We enter a new financial year with high expectations for Expro and real confidence that our business is well positioned for a period of sustained growth. Mike's experience, track record and enthusiasm will ensure he is a truly outstanding addition to the Expro leadership team."
Tuesday, April 19, 2011
Expro Names New COO
Expro announced the appointment of Michael Jardon as its new Chief Operating Officer. He replaces Chris Mawtus, who has assumed the new role of Service Quality Director for Expro.
Mr. Jardon joins Expro from his current position as North America President of Vallourec & Mannesmann USA, a business offering premium tubular solutions to the oil and gas industry. This follows a highly successful 16-year career with Schlumberger. His appointment takes effect from May 1st.
At Vallourec & Mannesmann, Mr. Jardon led the organization's commercial activities across the energy and industry segments in North America, directing global research and development, as well as managing sales and strategy for the region.
With Schlumberger, he held senior roles in wireline, completions, well testing and subsea, culminating in three years as Vice President Well Testing and Subsea, responsible for North and South America. Before this, he held the role of Vice President Operations Support for Schlumberger's Well Completions and Productivity businesses which included responsibility for supporting global operations and driving overall Quality, Health, Safety and Environmental (QHSE) performance. While with Schlumberger, Mr. Jardon lived in the US, South America and the Middle East.
Expro Chief Executive Officer Charles Woodburn said, "Throughout his career, Mike has demonstrated exceptional operational leadership, as well as a passion for developing new business, introducing new technologies to market, and developing and mentoring people. We enter a new financial year with high expectations for Expro and real confidence that our business is well positioned for a period of sustained growth. Mike's experience, track record and enthusiasm will ensure he is a truly outstanding addition to the Expro leadership team."
O&G UK Disappointed after UK Tax Talks
O&G UK Disappointed after UK Tax Talks
Tuesday, April 19, 2011
Dow Jones Newswires
by Alexis Flynn
The group representing major U.K. oil and gas producers said Thursday it was disappointed following talks with Chancellor of the Exchequer George Osborne on the impact a large tax increase on North Sea production would have on the industry.
Oil & Gas UK Chief Executive Malcolm Webb said, "Notwithstanding the Chancellor's requirement to raise money, [we] explained why both the unexpected nature and the scale of the increase to between 62% and 81% tax has damaged investor confidence and will hamper investment, maximum recovery of the U.K.'s oil and gas and job creation. Disappointingly, the Chancellor has a different view."
However, Webb said the Treasury requested further talks on how a mooted price floor mechanism, which would see the tax lowered in the event that prices dropped substantially, would work in practice. He said that it also wanted to discuss new and further field allowances, as well as continued dialogue on issues around decommissioning, to be concluded by Budget 2012.
A Treasury spokesperson told Dow Jones Newswires, "Today's meeting was constructive and while the Chancellor was clear that there would be no change in policy, he agreed to work closely with industry on the three areas for discussion set out in the Budget; setting the trigger price, stability in decommissioning and field allowances to support further investment."
Tuesday, April 19, 2011
Dow Jones Newswires
by Alexis Flynn
The group representing major U.K. oil and gas producers said Thursday it was disappointed following talks with Chancellor of the Exchequer George Osborne on the impact a large tax increase on North Sea production would have on the industry.
Oil & Gas UK Chief Executive Malcolm Webb said, "Notwithstanding the Chancellor's requirement to raise money, [we] explained why both the unexpected nature and the scale of the increase to between 62% and 81% tax has damaged investor confidence and will hamper investment, maximum recovery of the U.K.'s oil and gas and job creation. Disappointingly, the Chancellor has a different view."
However, Webb said the Treasury requested further talks on how a mooted price floor mechanism, which would see the tax lowered in the event that prices dropped substantially, would work in practice. He said that it also wanted to discuss new and further field allowances, as well as continued dialogue on issues around decommissioning, to be concluded by Budget 2012.
A Treasury spokesperson told Dow Jones Newswires, "Today's meeting was constructive and while the Chancellor was clear that there would be no change in policy, he agreed to work closely with industry on the three areas for discussion set out in the Budget; setting the trigger price, stability in decommissioning and field allowances to support further investment."
Chevron Bids High to Extend Footprint in Norwegian Sea
Chevron Bids High to Extend Footprint in Norwegian Sea
Tuesday, April 19, 2011
Chevron Corp.
by SubseaIQ
Chevron Upstream Europe has successfully bid for the exploration rights in four blocks awarded in the Norwegian 21st Licensing Round.
The blocks are located in the Outer Vøring Basin in the Norwegian Sea, approximately 335 miles (540 kilometers) west of the coast of Bodø, in 6824 feet (2080 meters) of water. Chevron Norge AS has been appointed as the operator with a 40 percent equity in Production License PL598 comprising the blocks 6601/6 and 9 and 6602/4 and 7. The other participants in the blocks are ExxonMobil Exploration & Production Norway AS with 30 percent equity interest, Idemitsu Petroleum Norge AS with 10 percent equity interest and Petoro AS with 20 percent equity interest.
"Chevron is committed to building a focused portfolio of key exploration prospects worldwide," said Guy Hollingsworth, President of Chevron Europe, Eurasia and Middle East. "We view the deep waters of the Norwegian Sea as an area of significant resource potential and this acquisition advances our strategy of pursuing attractive and high-impact growth opportunities." Hollingsworth added, "This is Chevron's second award in the deep water of the Norwegian Sea and as operator, we look forward to working with our partners and bringing our technical expertise and capabilities to this high-potential area."
"Rick Cohagan, Managing Director of Chevron Upstream Europe said, "We are very pleased with the partnership which will complement the strengths of the four companies – Chevron's exploration experience from the West of Shetland and ExxonMobil, Petoro and Idemitsu's significant regional knowledge and long-term operational experience in the Norwegian Sea. We appreciate the strengthened license criteria imposed by the Ministry of Petroleum and Energy in Norway deep water operations and we will continue to apply Chevron's safety standards in all aspects of our operations."
Tuesday, April 19, 2011
Chevron Corp.
by SubseaIQ
Chevron Upstream Europe has successfully bid for the exploration rights in four blocks awarded in the Norwegian 21st Licensing Round.
The blocks are located in the Outer Vøring Basin in the Norwegian Sea, approximately 335 miles (540 kilometers) west of the coast of Bodø, in 6824 feet (2080 meters) of water. Chevron Norge AS has been appointed as the operator with a 40 percent equity in Production License PL598 comprising the blocks 6601/6 and 9 and 6602/4 and 7. The other participants in the blocks are ExxonMobil Exploration & Production Norway AS with 30 percent equity interest, Idemitsu Petroleum Norge AS with 10 percent equity interest and Petoro AS with 20 percent equity interest.
"Chevron is committed to building a focused portfolio of key exploration prospects worldwide," said Guy Hollingsworth, President of Chevron Europe, Eurasia and Middle East. "We view the deep waters of the Norwegian Sea as an area of significant resource potential and this acquisition advances our strategy of pursuing attractive and high-impact growth opportunities." Hollingsworth added, "This is Chevron's second award in the deep water of the Norwegian Sea and as operator, we look forward to working with our partners and bringing our technical expertise and capabilities to this high-potential area."
"Rick Cohagan, Managing Director of Chevron Upstream Europe said, "We are very pleased with the partnership which will complement the strengths of the four companies – Chevron's exploration experience from the West of Shetland and ExxonMobil, Petoro and Idemitsu's significant regional knowledge and long-term operational experience in the Norwegian Sea. We appreciate the strengthened license criteria imposed by the Ministry of Petroleum and Energy in Norway deep water operations and we will continue to apply Chevron's safety standards in all aspects of our operations."
Atlantic Petroleum to Enter Next Phase at Faroes License
Atlantic Petroleum to Enter Next Phase at Faroes License
Tuesday, April 19, 2011
Atlantic Petroleum P/F
Atlantic Petroleum has approved the work program that enables Faroes License 014 to progress into the next exploration phase.
Following technical work over the last two years, and an assessment of the prospectivity of Faroes Licenses 013 and 014, the Company has decided to approve the work program that enables Faroes License 014 to progress into the next exploration phase.
The work carried out identified which areas should be retained and which had high impact exploration structures. Based on the studies, the southern area of the license 014 will be retained, which contains the Marselius structures. The northern part of License 014 will be relinquished as this area has no mapped structures. License 013 will also be relinquished in accordance with the license terms and conditions as the prospectivity on the blocks within this license is limited in Atlantic Petroleum's view.
The work commitment on License 014 consists of acquiring a new infill 2D seismic survey to complement the seismic data shot in 2006 and to create a pseudo 3D volume over the retained area. This work program will be carried out before January 17, 2013. Atlantic Petroleum holds 40% equity in License 014 while Sagex holds the remaining 60% and is the operator of the license.
Ben Arabo, CEO, commented, "Atlantic Petroleum is committed to exploration in the Faroe Islands, so in line with focusing on acreage with high impact potential we are pleased to be moving forward with License 014 where we hope to progress towards drillable prospects by January 2013. The further work on License 014 will compliment Atlantic Petroleum's active program on the Faroese shelf where technical work on Faroes License 016 is on-going and with a planned well to be drilled on License 006 this summer with partners Statoil and ExxonMobil."
Tuesday, April 19, 2011
Atlantic Petroleum P/F
Atlantic Petroleum has approved the work program that enables Faroes License 014 to progress into the next exploration phase.
Following technical work over the last two years, and an assessment of the prospectivity of Faroes Licenses 013 and 014, the Company has decided to approve the work program that enables Faroes License 014 to progress into the next exploration phase.
The work carried out identified which areas should be retained and which had high impact exploration structures. Based on the studies, the southern area of the license 014 will be retained, which contains the Marselius structures. The northern part of License 014 will be relinquished as this area has no mapped structures. License 013 will also be relinquished in accordance with the license terms and conditions as the prospectivity on the blocks within this license is limited in Atlantic Petroleum's view.
The work commitment on License 014 consists of acquiring a new infill 2D seismic survey to complement the seismic data shot in 2006 and to create a pseudo 3D volume over the retained area. This work program will be carried out before January 17, 2013. Atlantic Petroleum holds 40% equity in License 014 while Sagex holds the remaining 60% and is the operator of the license.
Ben Arabo, CEO, commented, "Atlantic Petroleum is committed to exploration in the Faroe Islands, so in line with focusing on acreage with high impact potential we are pleased to be moving forward with License 014 where we hope to progress towards drillable prospects by January 2013. The further work on License 014 will compliment Atlantic Petroleum's active program on the Faroese shelf where technical work on Faroes License 016 is on-going and with a planned well to be drilled on License 006 this summer with partners Statoil and ExxonMobil."
Nextraction to Develop Viking, Bakken Oil Properties
Nextraction to Develop Viking, Bakken Oil Properties
Tuesday, April 19, 2011
Nextraction Energy Corp.
Nextraction announced its 2011 plans to develop its light oil projects in Alberta and Montana. The development will include drilling two horizontal wells, the re-completions of existing wells in the Provost Field in Alberta, Canada, acquiring 22 miles of three dimensional (3-D) seismic data and the drilling of the initial well on the Saturn acreage located in the Williston Basin of eastern Montana, USA.
In addition, the Company reported completion of its initial well on the Pinedale Anticline produced at an average rate of 104 barrels of oil equivalent (BOE) while continuing to flow back frac fluids at year-end 2010.
Nextraction's President, Mark S. Dolar stated, "This is a very exciting time for Nextraction. We achieved our goal of establishing production and proving reserves at our Pinedale property and look to build on that base as we plan to increase daily production rates at Provost by drilling new horizontal wells and re-completing existing wells. We will follow the Provost drilling with development on the Saturn acreage. The Provost Field is known for short term payouts and impressive internal rates of return while Saturn contains potential for large scale, long life development." Mr. Dolar continued, "We remain debt free and we have the opportunity to generate significant cash flow and increase our net reserves while maintaining our current share structure."
Plans for development are as follows:
Provost Pool - Alberta, Canada
The Company plans to drill two, 810 meter Viking formation wells, off-setting existing wells with cumulative production of 665,000 barrels of oil. The wells are being licensed to drill horizontal legs of at least 900 meters in length each. The Company also plans to re-complete existing wells on the property to test a zone in the Viking formation that has yet to be tested by implementing new fracing technologies to the zone. Estimated cost for the project is $3 million (net to the Company).
The Company is a 50% interest owner in the project, but receives 100% of the revenue until it receives $1.4 million in production revenue or re-payment (as a loan to its joint venture partner). The Company will fund and operate the drilling of the first two development wells on the property and will receive 50% of the revenue from production. For all subsequent operations, the Company participates as a 50% interest owner.
Saturn Project - Montana, USA
The Company has completed permitting a 22 square mile area for three dimensional (3-D) seismic work and plans to acquire the data in the second quarter. A well is planned to be drilled based on interpretation of the seismic testing on the 35 section property. The Company's expected expenditures for the Saturn seismic program is $900,000 for the 22 square mile acquisition (a 15 square mile program was previously estimated to cost $500,000-$650,000) and estimated cost to drill, core and complete the 2,350 meter test well is $1.2 million.
The Company will look to develop the project as a multi-well program based on appropriate test well data. The properties are being developed under terms of a Seismic Option and Farm-out Agreement. Under the terms of the agreement, the Company will operate the project and fund 75% of the data collection costs for the seismic program. Prior to commencing the first core test well, its partner will have the option to participate as a 25% interest owner. Should the partner participate in the drilling of the well, the before payout interest will be shared 75% by Nextraction and 25% by the partner, after payout interests will be shared 52.5% by Nextraction and 47.5% by the partner. If the partner does not participate in the well, Nextraction will own 100% before payout and 70% after payout.
Pinedale - Wyoming, USA
After an initial 24 hour flow rate of 3 million cubic feet of gas per day from the upper 400 feet of net sand in the Lance and Tertiary formations from the Company's 100% owned Noble 6-24 well, the well produced and flared 8,074 MCFG, 28 Barrels of Condensate and 166 barrels of water/frac fluids from 11 days of production in December, 2010.
The Company became the operator of the project on February 1, 2011. In assuming operations, the Company will have the ability to develop the properties in a more efficient and cost effective manner and assist in lifting fluids from the well. The Company placed an electric compressor on location in mid-March to assist in lifting fluids that are known to produce with the natural gas and condensate on the Anticline. Nextraction predicts that with this compressor, daily production should average in the range of 800-1,000 mcfgpd and 20 barrels of condensate from the unconventional tight sands. Without compressor assistance, the well averages 400 mcfgpd and 8 barrels of condensate. The producing intervals in the well remain over-pressured, which indicates that the well should perform at the anticipated rates once completion fluids are drawn from the well.
To further enhance future drilling locations, the Company has also acquired 3-D seismic and plans to obtain 2-D seismic on the property in this year.
Mr. Dolar commented, "By completing the first well in Pinedale, we have taken great steps toward development of this project. As our knowledge of Pinedale increased, we realized that the use of artificial lift is essential for removing associated water production that flows with the gas and condensate. The decision to place an electric compressor on site to assist in drawing down the water levels and increase gas production from the well also lessens our carbon footprint and assists in our compliance with clean air requirements. As seismic is completed on Pinedale, we will determine the next strategy for development to enhance value to the Company."
Tuesday, April 19, 2011
Nextraction Energy Corp.
Nextraction announced its 2011 plans to develop its light oil projects in Alberta and Montana. The development will include drilling two horizontal wells, the re-completions of existing wells in the Provost Field in Alberta, Canada, acquiring 22 miles of three dimensional (3-D) seismic data and the drilling of the initial well on the Saturn acreage located in the Williston Basin of eastern Montana, USA.
In addition, the Company reported completion of its initial well on the Pinedale Anticline produced at an average rate of 104 barrels of oil equivalent (BOE) while continuing to flow back frac fluids at year-end 2010.
Nextraction's President, Mark S. Dolar stated, "This is a very exciting time for Nextraction. We achieved our goal of establishing production and proving reserves at our Pinedale property and look to build on that base as we plan to increase daily production rates at Provost by drilling new horizontal wells and re-completing existing wells. We will follow the Provost drilling with development on the Saturn acreage. The Provost Field is known for short term payouts and impressive internal rates of return while Saturn contains potential for large scale, long life development." Mr. Dolar continued, "We remain debt free and we have the opportunity to generate significant cash flow and increase our net reserves while maintaining our current share structure."
Plans for development are as follows:
Provost Pool - Alberta, Canada
The Company plans to drill two, 810 meter Viking formation wells, off-setting existing wells with cumulative production of 665,000 barrels of oil. The wells are being licensed to drill horizontal legs of at least 900 meters in length each. The Company also plans to re-complete existing wells on the property to test a zone in the Viking formation that has yet to be tested by implementing new fracing technologies to the zone. Estimated cost for the project is $3 million (net to the Company).
The Company is a 50% interest owner in the project, but receives 100% of the revenue until it receives $1.4 million in production revenue or re-payment (as a loan to its joint venture partner). The Company will fund and operate the drilling of the first two development wells on the property and will receive 50% of the revenue from production. For all subsequent operations, the Company participates as a 50% interest owner.
Saturn Project - Montana, USA
The Company has completed permitting a 22 square mile area for three dimensional (3-D) seismic work and plans to acquire the data in the second quarter. A well is planned to be drilled based on interpretation of the seismic testing on the 35 section property. The Company's expected expenditures for the Saturn seismic program is $900,000 for the 22 square mile acquisition (a 15 square mile program was previously estimated to cost $500,000-$650,000) and estimated cost to drill, core and complete the 2,350 meter test well is $1.2 million.
The Company will look to develop the project as a multi-well program based on appropriate test well data. The properties are being developed under terms of a Seismic Option and Farm-out Agreement. Under the terms of the agreement, the Company will operate the project and fund 75% of the data collection costs for the seismic program. Prior to commencing the first core test well, its partner will have the option to participate as a 25% interest owner. Should the partner participate in the drilling of the well, the before payout interest will be shared 75% by Nextraction and 25% by the partner, after payout interests will be shared 52.5% by Nextraction and 47.5% by the partner. If the partner does not participate in the well, Nextraction will own 100% before payout and 70% after payout.
Pinedale - Wyoming, USA
After an initial 24 hour flow rate of 3 million cubic feet of gas per day from the upper 400 feet of net sand in the Lance and Tertiary formations from the Company's 100% owned Noble 6-24 well, the well produced and flared 8,074 MCFG, 28 Barrels of Condensate and 166 barrels of water/frac fluids from 11 days of production in December, 2010.
The Company became the operator of the project on February 1, 2011. In assuming operations, the Company will have the ability to develop the properties in a more efficient and cost effective manner and assist in lifting fluids from the well. The Company placed an electric compressor on location in mid-March to assist in lifting fluids that are known to produce with the natural gas and condensate on the Anticline. Nextraction predicts that with this compressor, daily production should average in the range of 800-1,000 mcfgpd and 20 barrels of condensate from the unconventional tight sands. Without compressor assistance, the well averages 400 mcfgpd and 8 barrels of condensate. The producing intervals in the well remain over-pressured, which indicates that the well should perform at the anticipated rates once completion fluids are drawn from the well.
To further enhance future drilling locations, the Company has also acquired 3-D seismic and plans to obtain 2-D seismic on the property in this year.
Mr. Dolar commented, "By completing the first well in Pinedale, we have taken great steps toward development of this project. As our knowledge of Pinedale increased, we realized that the use of artificial lift is essential for removing associated water production that flows with the gas and condensate. The decision to place an electric compressor on site to assist in drawing down the water levels and increase gas production from the well also lessens our carbon footprint and assists in our compliance with clean air requirements. As seismic is completed on Pinedale, we will determine the next strategy for development to enhance value to the Company."
FOGL Signs Heads of Agreement for Falklands Deepwater Drilling Program
FOGL Signs Heads of Agreement for Falklands Deepwater Drilling Program
Tuesday, April 19, 2011
Falkland O&G Ltd.
FOGL has signed heads of agreement with Borders & Southern Petroleum plc ("B&S") ("B&S Heads of Agreement") to share a rig to drill in the first half of 2012 (the "Rig Contract").
Deepwater exploration program expected to commence in first quarter 2012
FOGL has signed the B&S Heads of Agreement outlining the key terms relating to the sharing of a rig to commence drilling the Loligo prospect in the first quarter of 2012. FOGL is also considering taking up the second option slot in the drilling contract in the event that it is able to secure either a farminee and/or additional funding. The rig is currently expected to arrive in the Falkland Islands in the fourth quarter of 2011. FOGL expects to access the rig for the third well slot in the combined B&S and FOGL program and commence drilling in the first quarter of 2012.
FOGL intends to drill its next well on the Loligo complex (a prospect within the Tertiary Channel play which has estimated Pmean reserves of 4,700 mmbbls). The Loligo complex comprises several reservoir objectives which have previously been referred to as the Loligo prospect, together with a number of additional underlying reservoir targets.
FOGL is considering a second drilling slot and, should it do so, there are a number of options for the second well, depending principally on the results from Loligo itself and from B&S's wells. If Loligo proves successful, FOGL could drill an appraisal well on Loligo, or alternatively another prospect within the Tertiary Channel play such as Nimrod (Pmean reserves of 1,500mmbbls) or Vinson (Pmean reserves of 733 mmbbls). If the Loligo results are disappointing, the most likely drilling candidates are within the Mid Cretaceous fan play, with the Scotia prospect (Pmean reserves of 1,060 mmbbls) being FOGL's preferred option. In the event of success for B&S on its Darwin prospect, FOGL may consider drilling the nearby Inflexible prospect (Pmean reserves of 250 mmbbls). A summary of all of the FOGL prospects which are potential drilling options and on which site surveys have now been acquired are given in Appendix 1.
FOGL is also continuing its farm-out discussions with interested parties. FOGL believes that a suitable farminee would further strengthen its financial position and allow an additional well to be drilled as part of this campaign.
Tim Bushell, Chief Executive of FOGL, said,"I am delighted to have entered into a heads of agreement for a rig contract to enable us to commence our deepwater exploration program. The successful fund raising puts us in a strong position to fully evaluate the Loligo prospect and also provides us with the financial strength to develop additional drilling options.
"We are also excited by the results of our recent technical work which has identified two new prospects within the Hersilia complex. Seismic amplitude analysis (AVO), together with the encouraging reservoir results from the Toroa well, has substantially reduced the risk on Scotia and Hero, which each have over 1 billion barrels of potential prospective resources. Site surveys have been completed over these two prospects and we are about to acquire new 2D seismic data over the area to aid final prospect selection."
Tuesday, April 19, 2011
Falkland O&G Ltd.
FOGL has signed heads of agreement with Borders & Southern Petroleum plc ("B&S") ("B&S Heads of Agreement") to share a rig to drill in the first half of 2012 (the "Rig Contract").
Deepwater exploration program expected to commence in first quarter 2012
FOGL has signed the B&S Heads of Agreement outlining the key terms relating to the sharing of a rig to commence drilling the Loligo prospect in the first quarter of 2012. FOGL is also considering taking up the second option slot in the drilling contract in the event that it is able to secure either a farminee and/or additional funding. The rig is currently expected to arrive in the Falkland Islands in the fourth quarter of 2011. FOGL expects to access the rig for the third well slot in the combined B&S and FOGL program and commence drilling in the first quarter of 2012.
FOGL intends to drill its next well on the Loligo complex (a prospect within the Tertiary Channel play which has estimated Pmean reserves of 4,700 mmbbls). The Loligo complex comprises several reservoir objectives which have previously been referred to as the Loligo prospect, together with a number of additional underlying reservoir targets.
FOGL is considering a second drilling slot and, should it do so, there are a number of options for the second well, depending principally on the results from Loligo itself and from B&S's wells. If Loligo proves successful, FOGL could drill an appraisal well on Loligo, or alternatively another prospect within the Tertiary Channel play such as Nimrod (Pmean reserves of 1,500mmbbls) or Vinson (Pmean reserves of 733 mmbbls). If the Loligo results are disappointing, the most likely drilling candidates are within the Mid Cretaceous fan play, with the Scotia prospect (Pmean reserves of 1,060 mmbbls) being FOGL's preferred option. In the event of success for B&S on its Darwin prospect, FOGL may consider drilling the nearby Inflexible prospect (Pmean reserves of 250 mmbbls). A summary of all of the FOGL prospects which are potential drilling options and on which site surveys have now been acquired are given in Appendix 1.
FOGL is also continuing its farm-out discussions with interested parties. FOGL believes that a suitable farminee would further strengthen its financial position and allow an additional well to be drilled as part of this campaign.
Tim Bushell, Chief Executive of FOGL, said,"I am delighted to have entered into a heads of agreement for a rig contract to enable us to commence our deepwater exploration program. The successful fund raising puts us in a strong position to fully evaluate the Loligo prospect and also provides us with the financial strength to develop additional drilling options.
"We are also excited by the results of our recent technical work which has identified two new prospects within the Hersilia complex. Seismic amplitude analysis (AVO), together with the encouraging reservoir results from the Toroa well, has substantially reduced the risk on Scotia and Hero, which each have over 1 billion barrels of potential prospective resources. Site surveys have been completed over these two prospects and we are about to acquire new 2D seismic data over the area to aid final prospect selection."
Homeland Resources to Drill Well at Smoky Hill Project
Homeland Resources to Drill Well at Smoky Hill Project
Tuesday, April 19, 2011
Homeland Resources Ltd.
Homeland Resources has elected to participate in the drilling of the first offset development well at the successful Smoky Hill Project in Southern Oklahoma.
The target area for the Marshall-2 development well is located directly offset the original Marshall-1 oil and gas discovery well which is currently flowing 320 barrels of oil per day. The Marshall-2 development well is expected to test the same productive pay zones encountered in the first well.
"We continue to be encouraged by the significant production rates from each of our first three wells. Another well directly offset the Marshall-1 is the first step of our long-term plan to fully exploit each of these new pool discoveries," said Armando Garcia, President of Homeland Resources. "In addition to plans at the Marshall, the Company and its partners are currently evaluating potential development drilling locations offset other recent discoveries. We intend to begin drilling at those locations as soon as possible."
Total flow rates for the three wells currently producing at the Smoky Hill Project has averaged 405 barrels of oil and 100 mfc of natural gas per day for the past month, and flow rates continue to be strong. The Company expects only minimal, if any, production decline in the near future.
Each prospect location at the Smoky Hill Project was selected based on positive anomalies from a proprietary database of 3-D seismic surveys conducted by Homeland and its partners. Expected total program reserves to be developed at the Smoky Hill Project could be in the range of 750,000 BO and 0.15 BCFG.
Further information regarding drilling of the Marshall-2 offset well and other Homeland Resources activities will be released as it becomes available.
Tuesday, April 19, 2011
Homeland Resources Ltd.
Homeland Resources has elected to participate in the drilling of the first offset development well at the successful Smoky Hill Project in Southern Oklahoma.
The target area for the Marshall-2 development well is located directly offset the original Marshall-1 oil and gas discovery well which is currently flowing 320 barrels of oil per day. The Marshall-2 development well is expected to test the same productive pay zones encountered in the first well.
"We continue to be encouraged by the significant production rates from each of our first three wells. Another well directly offset the Marshall-1 is the first step of our long-term plan to fully exploit each of these new pool discoveries," said Armando Garcia, President of Homeland Resources. "In addition to plans at the Marshall, the Company and its partners are currently evaluating potential development drilling locations offset other recent discoveries. We intend to begin drilling at those locations as soon as possible."
Total flow rates for the three wells currently producing at the Smoky Hill Project has averaged 405 barrels of oil and 100 mfc of natural gas per day for the past month, and flow rates continue to be strong. The Company expects only minimal, if any, production decline in the near future.
Each prospect location at the Smoky Hill Project was selected based on positive anomalies from a proprietary database of 3-D seismic surveys conducted by Homeland and its partners. Expected total program reserves to be developed at the Smoky Hill Project could be in the range of 750,000 BO and 0.15 BCFG.
Further information regarding drilling of the Marshall-2 offset well and other Homeland Resources activities will be released as it becomes available.
Boeing Partners with South Carolina Electric & Gas on Solar Units
Boeing Partners with South Carolina Electric & Gas on Solar Units
Apr 19, 2011
A new partnership for Boeing (BA) will enable the American multinational aerospace and defense corporation to operate as a 100% renewable energy site. Boeing said today that has entered into an energy partnership with South Carolina Electric & Gas. Under this arrangement, South Carolina Electric & Gas will install a solar generation system and dedicate the power from the system to the Boeing site. The solar generation system is comprised of thin-film solar laminate panels and will be installed on the new Boeing 787 Final Assembly building roof. The installation will be the largest in the Southeast by production capacity, and the sixth largest in the U.S., providing up to 2.6 megawatts of electrical power for the site. According to the company that's enough to power approximately 250 homes. Shares for Boeing are up 0.37% to $73.06.
Apr 19, 2011
A new partnership for Boeing (BA) will enable the American multinational aerospace and defense corporation to operate as a 100% renewable energy site. Boeing said today that has entered into an energy partnership with South Carolina Electric & Gas. Under this arrangement, South Carolina Electric & Gas will install a solar generation system and dedicate the power from the system to the Boeing site. The solar generation system is comprised of thin-film solar laminate panels and will be installed on the new Boeing 787 Final Assembly building roof. The installation will be the largest in the Southeast by production capacity, and the sixth largest in the U.S., providing up to 2.6 megawatts of electrical power for the site. According to the company that's enough to power approximately 250 homes. Shares for Boeing are up 0.37% to $73.06.
Tendeka Installs DTS at ADCO's HZ Well
Tendeka Installs DTS at ADCO's HZ Well
Tuesday, April 19, 2011
Tendeka
Tendeka has successfully installed its innovative harsh environment Oryx-XR distributed temperature sensing (DTS) monitoring system on a horizontal power water injection well in the United Arab Emirates for ADCO (Abu Dhabi Company for Onshore Oil Operations).
The project is the first high profile extreme reach horizontal injector DTS installation by Tendeka in the Middle East. The horizontal open section of the well was 10,000ft long.
Designed to overcome the toughest monitoring challenges, the Oryx-XR has a sensing range to 12km, and can provide a temperature resolution as fine as 0.010C.
The autonomous, low powered device provides temperature samples every meter along a fiber, with a wide operating temperature window of between -50C to 650C, and can operate by solar or wind power. The permanent, standalone unit contains the sensing optoelectronics and operates remotely with an intuitive, user-friendly software interface, making it a simple-to-use and easily transportable system.
The Oryx-XR features an inbuilt multiplexing module with either two or four channels, enabling up to four single ended measurements or two double-ended measurements.
Completion tubing of 3 ½" and 4 ½" with a DTS cable was successfully run to total depth in the 10,000ft 6 1/8" horizontal hole, the hanger was landed and the packer installed. The project was completed successfully.
The system, will provide ADCO with dynamic injection profile data to effectively monitor the injectivity performance of the well and enable optimization of the injection process
Tendeka Vice President-MENA Region Mark Watson said, "What could have been a challenging project actually turned out to be a very straight forward one, thanks to the skill and experience of those people involved.
"The completion tubing with the DTS cable attached ran smoothly with very low friction and the installed hanger and packer tested with no problems. The Oryx-XR was designed to deal with some of the toughest monitoring situations, such as horizontal well activity and increasingly complex wells, and it has proven its ability to meet those challenges."
Tuesday, April 19, 2011
Tendeka
Tendeka has successfully installed its innovative harsh environment Oryx-XR distributed temperature sensing (DTS) monitoring system on a horizontal power water injection well in the United Arab Emirates for ADCO (Abu Dhabi Company for Onshore Oil Operations).
The project is the first high profile extreme reach horizontal injector DTS installation by Tendeka in the Middle East. The horizontal open section of the well was 10,000ft long.
Designed to overcome the toughest monitoring challenges, the Oryx-XR has a sensing range to 12km, and can provide a temperature resolution as fine as 0.010C.
The autonomous, low powered device provides temperature samples every meter along a fiber, with a wide operating temperature window of between -50C to 650C, and can operate by solar or wind power. The permanent, standalone unit contains the sensing optoelectronics and operates remotely with an intuitive, user-friendly software interface, making it a simple-to-use and easily transportable system.
The Oryx-XR features an inbuilt multiplexing module with either two or four channels, enabling up to four single ended measurements or two double-ended measurements.
Completion tubing of 3 ½" and 4 ½" with a DTS cable was successfully run to total depth in the 10,000ft 6 1/8" horizontal hole, the hanger was landed and the packer installed. The project was completed successfully.
The system, will provide ADCO with dynamic injection profile data to effectively monitor the injectivity performance of the well and enable optimization of the injection process
Tendeka Vice President-MENA Region Mark Watson said, "What could have been a challenging project actually turned out to be a very straight forward one, thanks to the skill and experience of those people involved.
"The completion tubing with the DTS cable attached ran smoothly with very low friction and the installed hanger and packer tested with no problems. The Oryx-XR was designed to deal with some of the toughest monitoring situations, such as horizontal well activity and increasingly complex wells, and it has proven its ability to meet those challenges."
Beach Briefs Interruption at Tantanna Pipeline
Beach Briefs Interruption at Tantanna Pipeline
Tuesday, April 19, 2011
Beach Energy Ltd.
Beach has been informed by Santos that the pipeline between the Tantanna facility and the Gidgealpa facility has been interrupted due to integrity concerns and is currently being assessed.
The pipeline operated by Beach that feeds the Tantanna facility and transports all the crude oil from the PEL 92 Western Flank oil fields (Beach 75% and Operator, Cooper Energy 25%), remains fully operational. The current capacity of the Beach operated pipeline is approximately 6,000 barrels of oil per day (4,500 barrels of oil per day net to Beach).
Beach is considering all its options at this stage and has started to mobilize trucks to transport the oil from Tantanna to Moomba in the interim. Success to date at Parsons-3, Parsons-4 and Butlers-2 in PEL 92, underpins the Western Flank drilling campaign that is targeting a net increase in reserves to Beach of 6 million barrels of oil.
Tuesday, April 19, 2011
Beach Energy Ltd.
Beach has been informed by Santos that the pipeline between the Tantanna facility and the Gidgealpa facility has been interrupted due to integrity concerns and is currently being assessed.
The pipeline operated by Beach that feeds the Tantanna facility and transports all the crude oil from the PEL 92 Western Flank oil fields (Beach 75% and Operator, Cooper Energy 25%), remains fully operational. The current capacity of the Beach operated pipeline is approximately 6,000 barrels of oil per day (4,500 barrels of oil per day net to Beach).
Beach is considering all its options at this stage and has started to mobilize trucks to transport the oil from Tantanna to Moomba in the interim. Success to date at Parsons-3, Parsons-4 and Butlers-2 in PEL 92, underpins the Western Flank drilling campaign that is targeting a net increase in reserves to Beach of 6 million barrels of oil.
Kodiak Charges Ahead in Three Forks, Bakken Development
Kodiak Charges Ahead in Three Forks, Bakken Development
Tuesday, April 19, 2011
Kodiak O&G Corp.
Kodiak O&G provided an interim corporate update.
Interim Operations Update
Kodiak currently operates a two-rig-drilling program in the Williston Basin and anticipates taking delivery of a third rig within the next two weeks. The Company is currently negotiating to contract a fourth rig for delivery in the fourth quarter of 2011. Additionally, Kodiak controls a 40% to 50% working interest in wells being drilled by a non-operated drilling rig as part of its Dunn County, N.D. area of mutual interest with ExxonMobil.
Bakken/Three Forks Development: McKenzie County, N.D. (37,000 gross and 27,000 net acres) - Bakken producer records initial production (IP) rate of 3,042 BOE/d
The Koala #9-5-6-5H well [Kodiak operated – 95% working interest (WI) /78% net revenue interest (NRI)], an 8,967-foot horizontal lateral, was successfully completed in 24 stages in the middle Bakken Formation. During a 24-hour period, the well recorded production of 2,526 barrels of oil (BO) and 3.10 million cubic feet of natural gas (MMcf), or 3,042 barrels of oil equivalent (BOE). Kodiak completed the 24-hour production test utilizing an average 38/64" choke with average flowing casing pressure of 1,800 psi. Since coming online, the well had cumulative production of 7,340 BO and 7.5 MMcf, or 8,590 BOE in the first five days of production while continuing to recover frac load during well flowback.
Three Forks producer records IP rate of 2,327 BOE/d
The first well completed on the pad, the Koala #9-5-6-12H3 [Kodiak operated – 95% WI/78% NRI], a 9,171-foot horizontal lateral, was successfully completed in 22 stages in the Three Forks Formation. During a 24-hour period, the well recorded production of 1,919 BO and 2.45 MMcf, or 2,327 BOE. Kodiak completed the 24-hour production test utilizing a 36/64" choke with average flowing casing pressure of 1,400 psi. Since coming online, the well had cumulative production of 8,251 BO and 10.57 MMcf, or 10,012 BOE in the first nine days of production while recovering the frac load during well flowback. Koala #9-5-6-12H3 production was temporarily curtailed due to surface facility constraints while completion work on the second well on the pad, the Koala #9-5-6-5H, was completed.
The Three Forks well, the Koala #9-5-6-12H3, was drilled 700 feet from the Bakken well, the Koala #9-5-6-5H, in an ongoing effort to evaluate communication between the middle Bakken and the Three Forks Formation. By successfully completing the Koala #9-5-6-12H3 well, Kodiak now demonstrates the productive potential of the Three Forks Formation as an oil-prone reservoir system on this part of its McKenzie County core operating area.
The Company currently has one well, the Koala #3-2-11-14H, awaiting completion in McKenzie County as part of a two-well pad, and is drilling ahead on the Koala #3-2-11-13H well [both Kodiak operated – 50% WI/41% NRI]. These two well bores are being drilled approximately 1,300 feet apart in the middle Bakken in an effort to test well bore density within the drilling unit. These wells are projected to be completed in the second quarter 2011. Once the well is down, the rig will be moved to drill the Koala #2-25-36-15H [Kodiak operated – 66% WI/53% NRI], the first well of a two-well pad.
Bakken/Three Forks Development: Dunn County, N.D. (56,000 gross and 34,000 net acres) - Drilling and Completion Activity
Kodiak currently has two gross wells (1.0 net) which are expected to be completed in the second quarter 2011. Additionally, Kodiak has drilled and is awaiting completion of three gross wells (1.95 net wells) off of an existing four-well pad, and is currently drilling the final well from the pad, the Skunk Creek (SC) #2-24-25-16H [Kodiak operated – 97% WI/79% NRI]. Completion operations are projected to commence on this four-well pad in the third quarter 2011. Once drilling is completed on the four-well pad, the rig will move to the SC #12-10-11-9H well [Kodiak operated – 97% WI/79% NRI], the first of a two-well pad.
On its non-operated portion of lands in Dunn County, Kodiak has participated in the drilling of two gross wells (1.0 net well) that are currently waiting on completion. Two additional wells are currently being drilled from a two-well pad in which Kodiak has a 50% and 44% WI (41% and 36% NRI).
In conjunction with its first quarter 2011 operational and financial results news release expected to be issued after the close of trading on May 5, 2011, the Company intends to furnish a comprehensive operations update, including its per-well tabular data that includes working interest, net revenue interest, lateral length and 30/60/90/180 and 360-day production rates.
Dedicated Fracture Stimulation Team
The Company has formally executed a two-year agreement with its pressure-pumping service company whereby Kodiak will have a dedicated crew for 14 days per month, reconciled on a quarterly basis, commencing in the third quarter 2011.
Management Comment
Commenting on ongoing operations, Kodiak's President and CEO Lynn A. Peterson said, "Our drilling and completion operations in both McKenzie and Dunn counties continue to move forward. We are very pleased with the results from the two-well pad in McKenzie County, our first two operated wells in this area. The well results are important in that we have now demonstrated the productive potential in the Koala project area for both the middle Bakken and Three Forks Formations. Equally important is that we have drilled these high-working-interest wells in a manner that will allow us to evaluate communication between the two formations, as we obtain additional production history.
"The execution of a formal agreement with our pumping service company should provide continued improvement in the timing of our well completions. Utilization of pad drilling allows for successive completions improving our efficiencies through reduced time for equipment mobilization and demobilization between wells. We look forward to expanding this agreement to include more days as we move into the second half of the year and bring our fourth drilling rig under contract."
Borrowing Base Re-determined at $75 Million
Kodiak also announced that is has completed its semi-annual re-determination of its borrowing base under its $200 million senior secured revolving line of credit facility with Wells Fargo Bank, N.A. As a result, the Company's borrowing base has been increased to $75 million from the previously available $50 million. There are currently no borrowings under the facility and Kodiak is in compliance with the financial covenants under the credit facility.
"The increase in our borrowing base is reflective of our continued success in the Williston Basin," said James Henderson, Kodiak's Chief Financial Officer. "Our cash balances, operating cash flow and expanded revolving line of credit provide the Company with liquidity and balance sheet flexibility as we execute on growth-oriented development drilling in 2011 and into 2012."
Tuesday, April 19, 2011
Kodiak O&G Corp.
Kodiak O&G provided an interim corporate update.
Interim Operations Update
Kodiak currently operates a two-rig-drilling program in the Williston Basin and anticipates taking delivery of a third rig within the next two weeks. The Company is currently negotiating to contract a fourth rig for delivery in the fourth quarter of 2011. Additionally, Kodiak controls a 40% to 50% working interest in wells being drilled by a non-operated drilling rig as part of its Dunn County, N.D. area of mutual interest with ExxonMobil.
Bakken/Three Forks Development: McKenzie County, N.D. (37,000 gross and 27,000 net acres) - Bakken producer records initial production (IP) rate of 3,042 BOE/d
The Koala #9-5-6-5H well [Kodiak operated – 95% working interest (WI) /78% net revenue interest (NRI)], an 8,967-foot horizontal lateral, was successfully completed in 24 stages in the middle Bakken Formation. During a 24-hour period, the well recorded production of 2,526 barrels of oil (BO) and 3.10 million cubic feet of natural gas (MMcf), or 3,042 barrels of oil equivalent (BOE). Kodiak completed the 24-hour production test utilizing an average 38/64" choke with average flowing casing pressure of 1,800 psi. Since coming online, the well had cumulative production of 7,340 BO and 7.5 MMcf, or 8,590 BOE in the first five days of production while continuing to recover frac load during well flowback.
Three Forks producer records IP rate of 2,327 BOE/d
The first well completed on the pad, the Koala #9-5-6-12H3 [Kodiak operated – 95% WI/78% NRI], a 9,171-foot horizontal lateral, was successfully completed in 22 stages in the Three Forks Formation. During a 24-hour period, the well recorded production of 1,919 BO and 2.45 MMcf, or 2,327 BOE. Kodiak completed the 24-hour production test utilizing a 36/64" choke with average flowing casing pressure of 1,400 psi. Since coming online, the well had cumulative production of 8,251 BO and 10.57 MMcf, or 10,012 BOE in the first nine days of production while recovering the frac load during well flowback. Koala #9-5-6-12H3 production was temporarily curtailed due to surface facility constraints while completion work on the second well on the pad, the Koala #9-5-6-5H, was completed.
The Three Forks well, the Koala #9-5-6-12H3, was drilled 700 feet from the Bakken well, the Koala #9-5-6-5H, in an ongoing effort to evaluate communication between the middle Bakken and the Three Forks Formation. By successfully completing the Koala #9-5-6-12H3 well, Kodiak now demonstrates the productive potential of the Three Forks Formation as an oil-prone reservoir system on this part of its McKenzie County core operating area.
The Company currently has one well, the Koala #3-2-11-14H, awaiting completion in McKenzie County as part of a two-well pad, and is drilling ahead on the Koala #3-2-11-13H well [both Kodiak operated – 50% WI/41% NRI]. These two well bores are being drilled approximately 1,300 feet apart in the middle Bakken in an effort to test well bore density within the drilling unit. These wells are projected to be completed in the second quarter 2011. Once the well is down, the rig will be moved to drill the Koala #2-25-36-15H [Kodiak operated – 66% WI/53% NRI], the first well of a two-well pad.
Bakken/Three Forks Development: Dunn County, N.D. (56,000 gross and 34,000 net acres) - Drilling and Completion Activity
Kodiak currently has two gross wells (1.0 net) which are expected to be completed in the second quarter 2011. Additionally, Kodiak has drilled and is awaiting completion of three gross wells (1.95 net wells) off of an existing four-well pad, and is currently drilling the final well from the pad, the Skunk Creek (SC) #2-24-25-16H [Kodiak operated – 97% WI/79% NRI]. Completion operations are projected to commence on this four-well pad in the third quarter 2011. Once drilling is completed on the four-well pad, the rig will move to the SC #12-10-11-9H well [Kodiak operated – 97% WI/79% NRI], the first of a two-well pad.
On its non-operated portion of lands in Dunn County, Kodiak has participated in the drilling of two gross wells (1.0 net well) that are currently waiting on completion. Two additional wells are currently being drilled from a two-well pad in which Kodiak has a 50% and 44% WI (41% and 36% NRI).
In conjunction with its first quarter 2011 operational and financial results news release expected to be issued after the close of trading on May 5, 2011, the Company intends to furnish a comprehensive operations update, including its per-well tabular data that includes working interest, net revenue interest, lateral length and 30/60/90/180 and 360-day production rates.
Dedicated Fracture Stimulation Team
The Company has formally executed a two-year agreement with its pressure-pumping service company whereby Kodiak will have a dedicated crew for 14 days per month, reconciled on a quarterly basis, commencing in the third quarter 2011.
Management Comment
Commenting on ongoing operations, Kodiak's President and CEO Lynn A. Peterson said, "Our drilling and completion operations in both McKenzie and Dunn counties continue to move forward. We are very pleased with the results from the two-well pad in McKenzie County, our first two operated wells in this area. The well results are important in that we have now demonstrated the productive potential in the Koala project area for both the middle Bakken and Three Forks Formations. Equally important is that we have drilled these high-working-interest wells in a manner that will allow us to evaluate communication between the two formations, as we obtain additional production history.
"The execution of a formal agreement with our pumping service company should provide continued improvement in the timing of our well completions. Utilization of pad drilling allows for successive completions improving our efficiencies through reduced time for equipment mobilization and demobilization between wells. We look forward to expanding this agreement to include more days as we move into the second half of the year and bring our fourth drilling rig under contract."
Borrowing Base Re-determined at $75 Million
Kodiak also announced that is has completed its semi-annual re-determination of its borrowing base under its $200 million senior secured revolving line of credit facility with Wells Fargo Bank, N.A. As a result, the Company's borrowing base has been increased to $75 million from the previously available $50 million. There are currently no borrowings under the facility and Kodiak is in compliance with the financial covenants under the credit facility.
"The increase in our borrowing base is reflective of our continued success in the Williston Basin," said James Henderson, Kodiak's Chief Financial Officer. "Our cash balances, operating cash flow and expanded revolving line of credit provide the Company with liquidity and balance sheet flexibility as we execute on growth-oriented development drilling in 2011 and into 2012."
Transeuro: Testing Ops Underway at Ukraine Well
Transeuro: Testing Ops Underway at Ukraine Well
Tuesday, April 19, 2011
Transeuro Energy Corp.
Transeuro updatde on its Ukraine operations as follows:
Operations are now underway for 'Test 2' of the four test program to fully appraise the 400m of reservoir drilled in the Karl-101 well. This second test will assess the C14 interval, with 40 meters of perforations over the interval from 3,333 to 3,396 meters, representing around 20% of the reservoir thickness. This interval is known to contain numerous 'reservoir sections' and 'fracture zones' and is therefore expected to flow strongly after perforating, similar to Test 1. For this reason the Company is not planning to acidize during the testing phase, but will defer the acidizing until the well is put on production. The test will involve a 24 hour flow period, followed by a 48 hour shut in to record down hole pressure data. Samples of gas and condensate will be collected during the flow period for analysis.
After completing 'Test 1' extended operations were required to recover the packer and perforating guns from the wellbore, however this was finally achieved and established that all the guns fired as planned. In order to proceed with 'Test 2' the perforation intervals of 'Test 1' have been temporarily suspended below a drillable bridge plug so that the interval can be accessed later for production. Samples of gas and condensate were collected and have been sent for analysis. The down hole pressure recorders were recovered and confirm that a stable flow was achieved during 'Test 1' of 0.5 mmcf/d (14,000 m3/d) equivalent to 108 boepd with condensate. 'Test 1' represented approximately 15% of the reservoir thickness.
Tuesday, April 19, 2011
Transeuro Energy Corp.
Transeuro updatde on its Ukraine operations as follows:
Operations are now underway for 'Test 2' of the four test program to fully appraise the 400m of reservoir drilled in the Karl-101 well. This second test will assess the C14 interval, with 40 meters of perforations over the interval from 3,333 to 3,396 meters, representing around 20% of the reservoir thickness. This interval is known to contain numerous 'reservoir sections' and 'fracture zones' and is therefore expected to flow strongly after perforating, similar to Test 1. For this reason the Company is not planning to acidize during the testing phase, but will defer the acidizing until the well is put on production. The test will involve a 24 hour flow period, followed by a 48 hour shut in to record down hole pressure data. Samples of gas and condensate will be collected during the flow period for analysis.
After completing 'Test 1' extended operations were required to recover the packer and perforating guns from the wellbore, however this was finally achieved and established that all the guns fired as planned. In order to proceed with 'Test 2' the perforation intervals of 'Test 1' have been temporarily suspended below a drillable bridge plug so that the interval can be accessed later for production. Samples of gas and condensate were collected and have been sent for analysis. The down hole pressure recorders were recovered and confirm that a stable flow was achieved during 'Test 1' of 0.5 mmcf/d (14,000 m3/d) equivalent to 108 boepd with condensate. 'Test 1' represented approximately 15% of the reservoir thickness.
Bristow Lands Statoil Contract
Bristow Lands Statoil Contract
Tuesday, April 19, 2011
Statoil
Statoil has awarded Bristow Norway a new contract for offshore helicopter services running from Stavanger Airport, Norway. The estimated value of the contract is over NOK 1 billion.
All installations with helicopter flights from Stavanger will be served under this contract. Statoil's helicopter flights from Stavanger go to the Sleipner, Draupner, Volve and Glitne fields in the North Sea.
The contract covers the use of two dedicated Sikorsky S92 helicopters.
Bristow currently holds the contract for these flights, using the same type of helicopter.
Both helicopters will be upgraded to the latest standard prior to the commencement of the new contract.
"Statoil has undertaken a large-scale upgrade of our helicopter park in recent years, using the latest proven technological solutions. Well suited for offshore flights this type of helicopter will bring our employees offshore in a safe and secure manner," said Jannicke Hilland, senior vice president of joint operations on the Norwegian continental shelf (NCS) in Statoil.
The contract duration is for five years, coupled with the possibility of three one-year options. Planned start-up is in March 2013.
"There is increasing competition within helicopter service, which we look upon as a very positive development. This deal is based on competition and secures helicopter capacity for Statoil for many years to come," said Gunn Vik, who heads up procurement for operations and maintenance in Statoil.
Statoil has contracts in effect with both Bristow Norway and CHC Norway for helicopter services on the NCS. Helicopter types S92 and Eurocopter EC225 are used for such flights from a total of six helicopter bases located on the Norwegian coast – from Hammerfest in the north to Stavanger in the south.
Tuesday, April 19, 2011
Statoil
Statoil has awarded Bristow Norway a new contract for offshore helicopter services running from Stavanger Airport, Norway. The estimated value of the contract is over NOK 1 billion.
All installations with helicopter flights from Stavanger will be served under this contract. Statoil's helicopter flights from Stavanger go to the Sleipner, Draupner, Volve and Glitne fields in the North Sea.
The contract covers the use of two dedicated Sikorsky S92 helicopters.
Bristow currently holds the contract for these flights, using the same type of helicopter.
Both helicopters will be upgraded to the latest standard prior to the commencement of the new contract.
"Statoil has undertaken a large-scale upgrade of our helicopter park in recent years, using the latest proven technological solutions. Well suited for offshore flights this type of helicopter will bring our employees offshore in a safe and secure manner," said Jannicke Hilland, senior vice president of joint operations on the Norwegian continental shelf (NCS) in Statoil.
The contract duration is for five years, coupled with the possibility of three one-year options. Planned start-up is in March 2013.
"There is increasing competition within helicopter service, which we look upon as a very positive development. This deal is based on competition and secures helicopter capacity for Statoil for many years to come," said Gunn Vik, who heads up procurement for operations and maintenance in Statoil.
Statoil has contracts in effect with both Bristow Norway and CHC Norway for helicopter services on the NCS. Helicopter types S92 and Eurocopter EC225 are used for such flights from a total of six helicopter bases located on the Norwegian coast – from Hammerfest in the north to Stavanger in the south.
Crown Point Resumes Drilling Ops in Golfo San Jorge Basin
Crown Point Resumes Drilling Ops in Golfo San Jorge Basin
Tuesday, April 19, 2011
Crown Point Ventures Ltd.
Crown Point advised that drilling and production operations have resumed at El Valle in the Golfo San Jorge Basin. The labor dispute which forced the Santa Cruz basin wide shut down has been resolved and normal operations in the basin are resuming. Crown Points drilling operation has resumed and today is recommencing production operations.
Crown Point's first well of a 6 well program has been drilled to total depth and is waiting to be logged. Once logging has been completed Crown Point expects to case the well as a potential oil well. The five remaining wells will be drilled sequentially.
Tuesday, April 19, 2011
Crown Point Ventures Ltd.
Crown Point advised that drilling and production operations have resumed at El Valle in the Golfo San Jorge Basin. The labor dispute which forced the Santa Cruz basin wide shut down has been resolved and normal operations in the basin are resuming. Crown Points drilling operation has resumed and today is recommencing production operations.
Crown Point's first well of a 6 well program has been drilled to total depth and is waiting to be logged. Once logging has been completed Crown Point expects to case the well as a potential oil well. The five remaining wells will be drilled sequentially.
Nextraction to Develop Viking, Bakken Oil Properties
Nextraction to Develop Viking, Bakken Oil Properties
Tuesday, April 19, 2011
Nextraction Energy Corp.
Nextraction announced its 2011 plans to develop its light oil projects in Alberta and Montana. The development will include drilling two horizontal wells, the re-completions of existing wells in the Provost Field in Alberta, Canada, acquiring 22 miles of three dimensional (3-D) seismic data and the drilling of the initial well on the Saturn acreage located in the Williston Basin of eastern Montana, USA.
In addition, the Company reported completion of its initial well on the Pinedale Anticline produced at an average rate of 104 barrels of oil equivalent (BOE) while continuing to flow back frac fluids at year-end 2010.
Nextraction's President, Mark S. Dolar stated, "This is a very exciting time for Nextraction. We achieved our goal of establishing production and proving reserves at our Pinedale property and look to build on that base as we plan to increase daily production rates at Provost by drilling new horizontal wells and re-completing existing wells. We will follow the Provost drilling with development on the Saturn acreage. The Provost Field is known for short term payouts and impressive internal rates of return while Saturn contains potential for large scale, long life development." Mr. Dolar continued, "We remain debt free and we have the opportunity to generate significant cash flow and increase our net reserves while maintaining our current share structure."
Plans for development are as follows:
Provost Pool - Alberta, Canada
The Company plans to drill two, 810 meter Viking formation wells, off-setting existing wells with cumulative production of 665,000 barrels of oil. The wells are being licensed to drill horizontal legs of at least 900 meters in length each. The Company also plans to re-complete existing wells on the property to test a zone in the Viking formation that has yet to be tested by implementing new fracing technologies to the zone. Estimated cost for the project is $3 million (net to the Company).
The Company is a 50% interest owner in the project, but receives 100% of the revenue until it receives $1.4 million in production revenue or re-payment (as a loan to its joint venture partner). The Company will fund and operate the drilling of the first two development wells on the property and will receive 50% of the revenue from production. For all subsequent operations, the Company participates as a 50% interest owner.
Saturn Project - Montana, USA
The Company has completed permitting a 22 square mile area for three dimensional (3-D) seismic work and plans to acquire the data in the second quarter. A well is planned to be drilled based on interpretation of the seismic testing on the 35 section property. The Company's expected expenditures for the Saturn seismic program is $900,000 for the 22 square mile acquisition (a 15 square mile program was previously estimated to cost $500,000-$650,000) and estimated cost to drill, core and complete the 2,350 meter test well is $1.2 million.
The Company will look to develop the project as a multi-well program based on appropriate test well data. The properties are being developed under terms of a Seismic Option and Farm-out Agreement. Under the terms of the agreement, the Company will operate the project and fund 75% of the data collection costs for the seismic program. Prior to commencing the first core test well, its partner will have the option to participate as a 25% interest owner. Should the partner participate in the drilling of the well, the before payout interest will be shared 75% by Nextraction and 25% by the partner, after payout interests will be shared 52.5% by Nextraction and 47.5% by the partner. If the partner does not participate in the well, Nextraction will own 100% before payout and 70% after payout.
Pinedale - Wyoming, USA
After an initial 24 hour flow rate of 3 million cubic feet of gas per day from the upper 400 feet of net sand in the Lance and Tertiary formations from the Company's 100% owned Noble 6-24 well, the well produced and flared 8,074 MCFG, 28 Barrels of Condensate and 166 barrels of water/frac fluids from 11 days of production in December, 2010.
The Company became the operator of the project on February 1, 2011. In assuming operations, the Company will have the ability to develop the properties in a more efficient and cost effective manner and assist in lifting fluids from the well. The Company placed an electric compressor on location in mid-March to assist in lifting fluids that are known to produce with the natural gas and condensate on the Anticline. Nextraction predicts that with this compressor, daily production should average in the range of 800-1,000 mcfgpd and 20 barrels of condensate from the unconventional tight sands. Without compressor assistance, the well averages 400 mcfgpd and 8 barrels of condensate. The producing intervals in the well remain over-pressured, which indicates that the well should perform at the anticipated rates once completion fluids are drawn from the well.
To further enhance future drilling locations, the Company has also acquired 3-D seismic and plans to obtain 2-D seismic on the property in this year.
Mr. Dolar commented, "By completing the first well in Pinedale, we have taken great steps toward development of this project. As our knowledge of Pinedale increased, we realized that the use of artificial lift is essential for removing associated water production that flows with the gas and condensate. The decision to place an electric compressor on site to assist in drawing down the water levels and increase gas production from the well also lessens our carbon footprint and assists in our compliance with clean air requirements. As seismic is completed on Pinedale, we will determine the next strategy for development to enhance value to the Company."
Tuesday, April 19, 2011
Nextraction Energy Corp.
Nextraction announced its 2011 plans to develop its light oil projects in Alberta and Montana. The development will include drilling two horizontal wells, the re-completions of existing wells in the Provost Field in Alberta, Canada, acquiring 22 miles of three dimensional (3-D) seismic data and the drilling of the initial well on the Saturn acreage located in the Williston Basin of eastern Montana, USA.
In addition, the Company reported completion of its initial well on the Pinedale Anticline produced at an average rate of 104 barrels of oil equivalent (BOE) while continuing to flow back frac fluids at year-end 2010.
Nextraction's President, Mark S. Dolar stated, "This is a very exciting time for Nextraction. We achieved our goal of establishing production and proving reserves at our Pinedale property and look to build on that base as we plan to increase daily production rates at Provost by drilling new horizontal wells and re-completing existing wells. We will follow the Provost drilling with development on the Saturn acreage. The Provost Field is known for short term payouts and impressive internal rates of return while Saturn contains potential for large scale, long life development." Mr. Dolar continued, "We remain debt free and we have the opportunity to generate significant cash flow and increase our net reserves while maintaining our current share structure."
Plans for development are as follows:
Provost Pool - Alberta, Canada
The Company plans to drill two, 810 meter Viking formation wells, off-setting existing wells with cumulative production of 665,000 barrels of oil. The wells are being licensed to drill horizontal legs of at least 900 meters in length each. The Company also plans to re-complete existing wells on the property to test a zone in the Viking formation that has yet to be tested by implementing new fracing technologies to the zone. Estimated cost for the project is $3 million (net to the Company).
The Company is a 50% interest owner in the project, but receives 100% of the revenue until it receives $1.4 million in production revenue or re-payment (as a loan to its joint venture partner). The Company will fund and operate the drilling of the first two development wells on the property and will receive 50% of the revenue from production. For all subsequent operations, the Company participates as a 50% interest owner.
Saturn Project - Montana, USA
The Company has completed permitting a 22 square mile area for three dimensional (3-D) seismic work and plans to acquire the data in the second quarter. A well is planned to be drilled based on interpretation of the seismic testing on the 35 section property. The Company's expected expenditures for the Saturn seismic program is $900,000 for the 22 square mile acquisition (a 15 square mile program was previously estimated to cost $500,000-$650,000) and estimated cost to drill, core and complete the 2,350 meter test well is $1.2 million.
The Company will look to develop the project as a multi-well program based on appropriate test well data. The properties are being developed under terms of a Seismic Option and Farm-out Agreement. Under the terms of the agreement, the Company will operate the project and fund 75% of the data collection costs for the seismic program. Prior to commencing the first core test well, its partner will have the option to participate as a 25% interest owner. Should the partner participate in the drilling of the well, the before payout interest will be shared 75% by Nextraction and 25% by the partner, after payout interests will be shared 52.5% by Nextraction and 47.5% by the partner. If the partner does not participate in the well, Nextraction will own 100% before payout and 70% after payout.
Pinedale - Wyoming, USA
After an initial 24 hour flow rate of 3 million cubic feet of gas per day from the upper 400 feet of net sand in the Lance and Tertiary formations from the Company's 100% owned Noble 6-24 well, the well produced and flared 8,074 MCFG, 28 Barrels of Condensate and 166 barrels of water/frac fluids from 11 days of production in December, 2010.
The Company became the operator of the project on February 1, 2011. In assuming operations, the Company will have the ability to develop the properties in a more efficient and cost effective manner and assist in lifting fluids from the well. The Company placed an electric compressor on location in mid-March to assist in lifting fluids that are known to produce with the natural gas and condensate on the Anticline. Nextraction predicts that with this compressor, daily production should average in the range of 800-1,000 mcfgpd and 20 barrels of condensate from the unconventional tight sands. Without compressor assistance, the well averages 400 mcfgpd and 8 barrels of condensate. The producing intervals in the well remain over-pressured, which indicates that the well should perform at the anticipated rates once completion fluids are drawn from the well.
To further enhance future drilling locations, the Company has also acquired 3-D seismic and plans to obtain 2-D seismic on the property in this year.
Mr. Dolar commented, "By completing the first well in Pinedale, we have taken great steps toward development of this project. As our knowledge of Pinedale increased, we realized that the use of artificial lift is essential for removing associated water production that flows with the gas and condensate. The decision to place an electric compressor on site to assist in drawing down the water levels and increase gas production from the well also lessens our carbon footprint and assists in our compliance with clean air requirements. As seismic is completed on Pinedale, we will determine the next strategy for development to enhance value to the Company."
Antrim Begins Pre-Drilling Site Surveys in North Sea
Antrim Begins Pre-Drilling Site Surveys in North Sea
Tuesday, April 19, 2011
Antrim Energy Inc.
Antrim has contracted the survey vessel Kommander Jack and has commenced work to obtain site surveys in preparation for the 2011 UK North Sea drilling program.
Surveys will be obtained over the West Teal, Carra and Erne prospects, located in the Greater Fyne Area in Blocks 21/24b, 21/28b and 21/29d. The West Teal and Carra surveys are expected to confirm the surface drilling locations for two wells targeting the Jurassic Fulmar and Eocene Tay formations respectively, as previously disclosed on March 28, 2011. The West Teal prospect (Antrim 100%) is located in the northeast portion of the Greater Fyne Area approximately 3 km west of the Teal Field. The Carra prospect (Antrim 100 %) is located adjacent to and southeast of the Fyne Field. The Erne survey in Block 21/29d (Antrim 100%) has been added to the program to identify a surface location for a contingent well on that feature, an oil prospect in the Eocene Tay Formation located between the Fyne and NW Guillemot fields at a drilling depth of 6,500 ft.
Well project management and drilling services, including management of the site survey, are being provided to Antrim by AGR Petroleum Services. The site surveys should be completed in May in preparation for the exploration drilling program scheduled to start mid-year 2011. This exploration drilling program is in addition to the planned appraisal well to be drilled on the Fyne Field later this year, as announced on April 04, 2011.
Tuesday, April 19, 2011
Antrim Energy Inc.
Antrim has contracted the survey vessel Kommander Jack and has commenced work to obtain site surveys in preparation for the 2011 UK North Sea drilling program.
Surveys will be obtained over the West Teal, Carra and Erne prospects, located in the Greater Fyne Area in Blocks 21/24b, 21/28b and 21/29d. The West Teal and Carra surveys are expected to confirm the surface drilling locations for two wells targeting the Jurassic Fulmar and Eocene Tay formations respectively, as previously disclosed on March 28, 2011. The West Teal prospect (Antrim 100%) is located in the northeast portion of the Greater Fyne Area approximately 3 km west of the Teal Field. The Carra prospect (Antrim 100 %) is located adjacent to and southeast of the Fyne Field. The Erne survey in Block 21/29d (Antrim 100%) has been added to the program to identify a surface location for a contingent well on that feature, an oil prospect in the Eocene Tay Formation located between the Fyne and NW Guillemot fields at a drilling depth of 6,500 ft.
Well project management and drilling services, including management of the site survey, are being provided to Antrim by AGR Petroleum Services. The site surveys should be completed in May in preparation for the exploration drilling program scheduled to start mid-year 2011. This exploration drilling program is in addition to the planned appraisal well to be drilled on the Fyne Field later this year, as announced on April 04, 2011.
Offshore Platform Worker Dies
Offshore Platform Worker Dies
Tuesday, April 19, 2011
BOEMRE
The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) is responding to a report of a fatality at Hilcorp Energy Company's West Cameron Block 643 Platform A, a natural gas production platform approximately 129 miles offshore Louisiana, south of Lake Charles, in about 375 feet of water. The platform has not been in production since 2008 and operations to plug and abandon its wells were underway. According to the company's report, at approximately 4:00 a.m., an employee of Alliance Oilfield Services working for Hilcorp was assisting in abandonment operations when he fell through a deck opening. The victim was assisted by first responders on the platform, then med-evaced by helicopter for emergency medical attention. He was later pronounced dead at the hospital.
BOEMRE inspectors attempted to fly to the platform this morning, but were unable to reach the site due to fog. They will attempt to fly to
the facility again tomorrow to conduct an investigation into the cause of the accident.
"This was a tragic accident. Our thoughts and prayers are with the family of the deceased employee, as well as his friends and colleagues. This tragic accident underscores why we are fully committed to working with the industry to ensure the highest safety standards on offshore facilities," said BOEMRE Director Michael R. Bromwich.
Tuesday, April 19, 2011
BOEMRE
The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) is responding to a report of a fatality at Hilcorp Energy Company's West Cameron Block 643 Platform A, a natural gas production platform approximately 129 miles offshore Louisiana, south of Lake Charles, in about 375 feet of water. The platform has not been in production since 2008 and operations to plug and abandon its wells were underway. According to the company's report, at approximately 4:00 a.m., an employee of Alliance Oilfield Services working for Hilcorp was assisting in abandonment operations when he fell through a deck opening. The victim was assisted by first responders on the platform, then med-evaced by helicopter for emergency medical attention. He was later pronounced dead at the hospital.
BOEMRE inspectors attempted to fly to the platform this morning, but were unable to reach the site due to fog. They will attempt to fly to
the facility again tomorrow to conduct an investigation into the cause of the accident.
"This was a tragic accident. Our thoughts and prayers are with the family of the deceased employee, as well as his friends and colleagues. This tragic accident underscores why we are fully committed to working with the industry to ensure the highest safety standards on offshore facilities," said BOEMRE Director Michael R. Bromwich.
Peabody Energy Posts Strong Q1 Results, Beats EPS By $0.07
Peabody Energy Posts Strong Q1 Results, Beats EPS By $0.07
Apr 19, 2011
Peabody Energy (NYSE:BTU) reported Q1 EPS of $0.67, beating the consensus estimate for $0.60 per share. Revenue for the quarter was up 15% year-over-year to $1.74 billion, in-line with the consensus estimate.
Peabody Energy Chairman and Chief Executive Officer Gregory H. Boyce said, "Peabody delivered significant increases in revenues, operating profit, EBITDA and net income in the first quarter. Peabody is advancing multiple growth initiatives to serve the high-growth Asian markets. During the quarter, we made significant progress on a number of Australian mine expansions, entered into Chinese development agreements, expanded Indonesian supply sources, and announced a major throughput agreement for a proposed Western U.S. export facility."
Apr 19, 2011
Peabody Energy (NYSE:BTU) reported Q1 EPS of $0.67, beating the consensus estimate for $0.60 per share. Revenue for the quarter was up 15% year-over-year to $1.74 billion, in-line with the consensus estimate.
Peabody Energy Chairman and Chief Executive Officer Gregory H. Boyce said, "Peabody delivered significant increases in revenues, operating profit, EBITDA and net income in the first quarter. Peabody is advancing multiple growth initiatives to serve the high-growth Asian markets. During the quarter, we made significant progress on a number of Australian mine expansions, entered into Chinese development agreements, expanded Indonesian supply sources, and announced a major throughput agreement for a proposed Western U.S. export facility."
Petrobras Commences EWT at Brava Area
Petrobras Commences EWT at Brava Area
Tuesday, April 19, 2011
Petrobras
Petrobras has started the Extended Well Test (EWT) of the Brava area, in the Campos Basin pre-salt, in the Production Concession area of Marlin field, located 170 km from the city of Macaé, RJ.
The EWT which is expected to last two years and have a daily production of 6,000 barrels of oil per day is being done by well 6-MRL-199-RJS, interconnected to platform P-27, which was already under production at Marlin field. This is the third reservoir to produce oil in the Campos Basin pre-salt. The first reservoir was in the Jubarte field in September of 2008; subsequently, in July of 2010, Petrobras started to produce in a reservoir in the Baleia Franca field's pre-salt.
The Brava EWT will enable Petrobras to obtain more information about the reservoir's characteristics, which will assist in the preparation of the definitive production development project. This data will also be important to study the characteristics of new wells in the Marlim and Voador fields.
Tuesday, April 19, 2011
Petrobras
Petrobras has started the Extended Well Test (EWT) of the Brava area, in the Campos Basin pre-salt, in the Production Concession area of Marlin field, located 170 km from the city of Macaé, RJ.
The EWT which is expected to last two years and have a daily production of 6,000 barrels of oil per day is being done by well 6-MRL-199-RJS, interconnected to platform P-27, which was already under production at Marlin field. This is the third reservoir to produce oil in the Campos Basin pre-salt. The first reservoir was in the Jubarte field in September of 2008; subsequently, in July of 2010, Petrobras started to produce in a reservoir in the Baleia Franca field's pre-salt.
The Brava EWT will enable Petrobras to obtain more information about the reservoir's characteristics, which will assist in the preparation of the definitive production development project. This data will also be important to study the characteristics of new wells in the Marlim and Voador fields.
Aker Lands EPC Gig for Statoil's Vigdis Development
Aker Lands EPC Gig for Statoil's Vigdis Development
Tuesday, April 19, 2011
Aker Solutions
by SubseaIQ
Aker Solutions has received notification that Statoil has exercised options for the engineering, procurement and construction of three subsea work-over systems for use on the Norwegian Continental Shelf. Aker Solutions estimates the contract value of these three extensions to be a total of approximately NOK 1.25 billion ($228MM).
In February, Statoil awarded Aker Solutions a contract for one workover system to be used on the Vigdis North East development on the Norwegian Continental Shelf. It is options from this contract which have been exercised.
Workover equipment is used on every subsea well, for installing equipment and preparing the well for production. During field life, workover equipment is used during the maintenance of subsea wells to improve oil recovery.
"We are pleased to receive additional awards for our new modularized workover systems. This contract will strengthen Akers Solutions' position as one of the major providers of well access services on the Norwegian continental shelf. Our equipment provides safe and efficient well access for downhole operations, resulting in increased oil recovery," said Mads Andersen, executive vice president of Aker Solutions' subsea business area.
The workover systems project will be managed at Aker Solutions' Tranby Technology and Manufacturing Centre outside Oslo in Norway. The manufacturing of the well control package and riser elements will be completed at Tranby and the workover control module out of Aberdeen.
Tuesday, April 19, 2011
Aker Solutions
by SubseaIQ
Aker Solutions has received notification that Statoil has exercised options for the engineering, procurement and construction of three subsea work-over systems for use on the Norwegian Continental Shelf. Aker Solutions estimates the contract value of these three extensions to be a total of approximately NOK 1.25 billion ($228MM).
In February, Statoil awarded Aker Solutions a contract for one workover system to be used on the Vigdis North East development on the Norwegian Continental Shelf. It is options from this contract which have been exercised.
Workover equipment is used on every subsea well, for installing equipment and preparing the well for production. During field life, workover equipment is used during the maintenance of subsea wells to improve oil recovery.
"We are pleased to receive additional awards for our new modularized workover systems. This contract will strengthen Akers Solutions' position as one of the major providers of well access services on the Norwegian continental shelf. Our equipment provides safe and efficient well access for downhole operations, resulting in increased oil recovery," said Mads Andersen, executive vice president of Aker Solutions' subsea business area.
The workover systems project will be managed at Aker Solutions' Tranby Technology and Manufacturing Centre outside Oslo in Norway. The manufacturing of the well control package and riser elements will be completed at Tranby and the workover control module out of Aberdeen.
Range Boosts Production in 1Q 2011
Range Boosts Production in 1Q 2011
Tuesday, April 19, 2011
Range Resources Corp.
Range provided an operations update. First quarter production volumes averaged 545.5 Mmcfe net per day, a 17% increase over the prior-year period and 1% higher than fourth quarter 2010. The record production marked the Company's 33rd consecutive quarter of sequential production growth. Production was 79% natural gas, 16% natural gas liquids (NGLs) and 5% crude oil. Targeted drilling to the liquids-rich portion of the Marcellus Shale play in Pennsylvania and the Midcontinent regions drove the production growth. First quarter 2011 production was 16% NGLs versus 12% for first quarter of 2010.
The Company also announced that its preliminary first quarter 2011 commodity price realizations (including the impact of cash-settled hedges and derivative settlements which would correspond to analysts' estimates) averaged $5.46 per mcfe. This represents a 2% decrease from the prior-year period, but a 2% increase as compared to the fourth quarter 2010. Preliminary first quarter production and realized prices by each commodity are: natural gas – 429.9 Mmcfe per day ($4.40), natural gas liquids – 14,338 barrels per day ($47.96) and crude oil – 4,924 barrels per day ($81.35).
Commenting on the announcement, John Pinkerton, Range's Chairman and CEO, said, "Despite the unusually cold weather conditions we incurred in the first quarter, we were able to reach the mid-point of our production guidance. Adjusting for the weather related downtime, we would have exceeded the high end of our guidance. Our operating teams did an outstanding job battling some of the most brutal weather conditions we have experienced in many years. Looking ahead, due to the terrific drilling results so far this year, combined with the progress of the infrastructure projects, we are well on track to reach our production growth target for the year. In addition, the Barnett sale is on schedule to close at the end of the month."
Marcellus Shale Division
We exited the first quarter at approximately 260 Mmcfe per day net from the Marcellus Shale, up from approximately 200 Mmcfe per day at year-end 2010. During the first quarter, the Marcellus Division brought online 26 horizontal wells in southwest Pennsylvania, 15 of which were located in the liquids-rich area of the play. The initial production rates of the 15 new wells averaged 7.4 (6.3 net) Mmcf per day of natural gas and 452 (384 net) barrels of NGLs and condensate per day or 10.1 (8.6 net) Mmcfe per day. An additional 16 wells were completed in southwest Pennsylvania during the first quarter that are awaiting connection to the gathering system. In northeast Pennsylvania, Range brought on its first five wells in Lycoming County at a combined initial production rate of 45 (39 net) Mmcf per day in mid-February.
Due to the outstanding performance of its existing wells combined with the initial performance of the newly connected wells, Range's Marcellus production has temporarily outgrown the existing infrastructure. In southwestern Pennsylvania, the third expansion of the gas processing facilities has been completed and is in the testing phase. This 200 Mmcf per day of additional processing capacity is expected to commence operation in May. With this expansion, Range's total processing capacity will expand to 350 Mmcf per day. Later in the third quarter, Range's processing capacity is scheduled to increase again to 390 Mmcf per day. In northeast Pennsylvania, the next expansion of the Lycoming County gathering system is scheduled to be completed late in the third quarter which will tie in an additional 20 wells.
Range has entered into two memorandums of understanding exploring options to sell ethane from the liquids-rich area in southwest Pennsylvania. Range plans to complete firm ethane sales agreements in the next 12 months covering a significant portion of its projected ethane production.
Midcontinent Division
First quarter activity for the Midcontinent Division focused on drilling operations in several key areas. One rig remains active in the Texas Panhandle, where two Granite Wash wells and one vertical St. Louis exploratory well are undergoing completion. Range's original horizontal St. Louis Lime well continues to perform above expectations. After 12 weeks of production, the well has produced more than 1.0 Bcfe with current rates still at 13.0 Mmcf of natural gas and over 900 barrels of liquids per day or 18.4 (5.6 net) Mmcfe per day. Activity in the Ardmore Basin Woodford play continues with four wells in various stages of completion. Production from these liquids-rich completions is expected to reach sales by the end of the second quarter. One operated rig is currently running in the play, along with additional non-operated activity. Drilling also continues in the Mississippian Lime play of northern Oklahoma with one operated rig and one non-operated rig in the Woodford "Cana" Shale play of the Anadarko Basin.
Appalachian Division
During the first quarter of 2011, the Appalachian Division continued to focus on tight gas sand and coal bed methane (CBM) drilling projects on its 350,000 (235,000 net) acres in Virginia. All of this acreage is either owned or held by production allowing for discretionary drilling with no lease expiration issues. In 2011, Range plans 50 tight gas sand wells, 15 CBM wells and 15 horizontal wells targeting the Huron Shale, Berea and Big Lime formations in Virginia. For the first quarter, the division drilled 5 (4.5 net) vertical tight gas sand wells and one CBM well in the Nora field. Also in the quarter, Range performed 8 recompletions of behind-pipe pays to continue to maximize production on existing wells.
Southwest Division
In the first quarter the Southwest Division drilled its first Penn Shale well in the Conger Field of West Texas where Range has approximately 91,000 net acres. The well has a lateral length of 4,000 feet and will be completed with a multi-stage fracture treatment later in the second quarter.
Tuesday, April 19, 2011
Range Resources Corp.
Range provided an operations update. First quarter production volumes averaged 545.5 Mmcfe net per day, a 17% increase over the prior-year period and 1% higher than fourth quarter 2010. The record production marked the Company's 33rd consecutive quarter of sequential production growth. Production was 79% natural gas, 16% natural gas liquids (NGLs) and 5% crude oil. Targeted drilling to the liquids-rich portion of the Marcellus Shale play in Pennsylvania and the Midcontinent regions drove the production growth. First quarter 2011 production was 16% NGLs versus 12% for first quarter of 2010.
The Company also announced that its preliminary first quarter 2011 commodity price realizations (including the impact of cash-settled hedges and derivative settlements which would correspond to analysts' estimates) averaged $5.46 per mcfe. This represents a 2% decrease from the prior-year period, but a 2% increase as compared to the fourth quarter 2010. Preliminary first quarter production and realized prices by each commodity are: natural gas – 429.9 Mmcfe per day ($4.40), natural gas liquids – 14,338 barrels per day ($47.96) and crude oil – 4,924 barrels per day ($81.35).
Commenting on the announcement, John Pinkerton, Range's Chairman and CEO, said, "Despite the unusually cold weather conditions we incurred in the first quarter, we were able to reach the mid-point of our production guidance. Adjusting for the weather related downtime, we would have exceeded the high end of our guidance. Our operating teams did an outstanding job battling some of the most brutal weather conditions we have experienced in many years. Looking ahead, due to the terrific drilling results so far this year, combined with the progress of the infrastructure projects, we are well on track to reach our production growth target for the year. In addition, the Barnett sale is on schedule to close at the end of the month."
Marcellus Shale Division
We exited the first quarter at approximately 260 Mmcfe per day net from the Marcellus Shale, up from approximately 200 Mmcfe per day at year-end 2010. During the first quarter, the Marcellus Division brought online 26 horizontal wells in southwest Pennsylvania, 15 of which were located in the liquids-rich area of the play. The initial production rates of the 15 new wells averaged 7.4 (6.3 net) Mmcf per day of natural gas and 452 (384 net) barrels of NGLs and condensate per day or 10.1 (8.6 net) Mmcfe per day. An additional 16 wells were completed in southwest Pennsylvania during the first quarter that are awaiting connection to the gathering system. In northeast Pennsylvania, Range brought on its first five wells in Lycoming County at a combined initial production rate of 45 (39 net) Mmcf per day in mid-February.
Due to the outstanding performance of its existing wells combined with the initial performance of the newly connected wells, Range's Marcellus production has temporarily outgrown the existing infrastructure. In southwestern Pennsylvania, the third expansion of the gas processing facilities has been completed and is in the testing phase. This 200 Mmcf per day of additional processing capacity is expected to commence operation in May. With this expansion, Range's total processing capacity will expand to 350 Mmcf per day. Later in the third quarter, Range's processing capacity is scheduled to increase again to 390 Mmcf per day. In northeast Pennsylvania, the next expansion of the Lycoming County gathering system is scheduled to be completed late in the third quarter which will tie in an additional 20 wells.
Range has entered into two memorandums of understanding exploring options to sell ethane from the liquids-rich area in southwest Pennsylvania. Range plans to complete firm ethane sales agreements in the next 12 months covering a significant portion of its projected ethane production.
Midcontinent Division
First quarter activity for the Midcontinent Division focused on drilling operations in several key areas. One rig remains active in the Texas Panhandle, where two Granite Wash wells and one vertical St. Louis exploratory well are undergoing completion. Range's original horizontal St. Louis Lime well continues to perform above expectations. After 12 weeks of production, the well has produced more than 1.0 Bcfe with current rates still at 13.0 Mmcf of natural gas and over 900 barrels of liquids per day or 18.4 (5.6 net) Mmcfe per day. Activity in the Ardmore Basin Woodford play continues with four wells in various stages of completion. Production from these liquids-rich completions is expected to reach sales by the end of the second quarter. One operated rig is currently running in the play, along with additional non-operated activity. Drilling also continues in the Mississippian Lime play of northern Oklahoma with one operated rig and one non-operated rig in the Woodford "Cana" Shale play of the Anadarko Basin.
Appalachian Division
During the first quarter of 2011, the Appalachian Division continued to focus on tight gas sand and coal bed methane (CBM) drilling projects on its 350,000 (235,000 net) acres in Virginia. All of this acreage is either owned or held by production allowing for discretionary drilling with no lease expiration issues. In 2011, Range plans 50 tight gas sand wells, 15 CBM wells and 15 horizontal wells targeting the Huron Shale, Berea and Big Lime formations in Virginia. For the first quarter, the division drilled 5 (4.5 net) vertical tight gas sand wells and one CBM well in the Nora field. Also in the quarter, Range performed 8 recompletions of behind-pipe pays to continue to maximize production on existing wells.
Southwest Division
In the first quarter the Southwest Division drilled its first Penn Shale well in the Conger Field of West Texas where Range has approximately 91,000 net acres. The well has a lateral length of 4,000 feet and will be completed with a multi-stage fracture treatment later in the second quarter.
Samson O&G Updates Ops at North Stockyard Oilfield
Tuesday, April 19, 2011
Samson O&G Ltd.
Samson O&G advised on the three active wells in the North Stockyard Oilfield.
The Earl #1-13H has been under flow back since April 13th but the 19 frac plugs have yet to be drilled out. The flow rates will be published later this week when the plugs are expected to be removed. A work over rig is already being mobilized to the Earl well site, and is presently expected to initiate the plug drill out either late Tuesday or Wednesday of this week.
After completing the drill out of the Earl well, the work over rig will move to the Rodney #1-14H location and conduct the drill out of the plugs in that well.
Separately, the drilling rig that is to drill the Everett #1-15H well is currently being mobilized to the well site. The rig move is being hampered by poor weather conditions and the spring thaw of the well sites. Upon completion of the mobilization, the rig owner is planning to undertake repairs to the rig before commencing drilling, so the spud is currently expected to occur the last week of April.
PACCAR Beats Q1 Earnings Estimates, Revenue up 53% YoY
PACCAR Beats Q1 Earnings Estimates, Revenue up 53% YoY
Apr 19, 2011
PACCAR (NASDAQ:PCAR) reported Q1 EPS of $0.53, beating the consensus estimate for $0.49 per share. Revenues for the quarter were up 53% year-over-year to $3.04 billion, beating the consensus estimate for $2.97 billion.
Mark Pigott, chairman and chief executive officer said, "PACCAR reported improved revenues and net income for the first quarter of 2011. PACCAR's results reflect the benefits of stronger truck sales in Europe and North America and an improvement in financial services profit and parts revenues worldwide. The higher utilization of PACCAR's truck facilities contributed to increased gross margins. North American and European economies are recovering, with the exception of the residential and commercial construction markets in the United States. Our on-highway customers are benefiting from increased freight tonnage and freight rates which are driving improved fleet productivity. I am very proud of our 19,000 employees who have delivered excellent results to our shareholders and customers."
Apr 19, 2011
PACCAR (NASDAQ:PCAR) reported Q1 EPS of $0.53, beating the consensus estimate for $0.49 per share. Revenues for the quarter were up 53% year-over-year to $3.04 billion, beating the consensus estimate for $2.97 billion.
Mark Pigott, chairman and chief executive officer said, "PACCAR reported improved revenues and net income for the first quarter of 2011. PACCAR's results reflect the benefits of stronger truck sales in Europe and North America and an improvement in financial services profit and parts revenues worldwide. The higher utilization of PACCAR's truck facilities contributed to increased gross margins. North American and European economies are recovering, with the exception of the residential and commercial construction markets in the United States. Our on-highway customers are benefiting from increased freight tonnage and freight rates which are driving improved fleet productivity. I am very proud of our 19,000 employees who have delivered excellent results to our shareholders and customers."
Harley-Davidson Reports Mixed Q1, Misses EPS By $0.02, Revenue Up 2.5% YoY
Harley-Davidson Reports Mixed Q1, Misses EPS By $0.02, Revenue Up 2.5% YoY
Apr 19, 2011
Harley-Davidson (NYSE:HOG) reported Q1 EPS of $0.51 today, missing the consensus estimate for $0.53 per share. Revenue for the quarter was up 2.5% year-over-year to $1.06 billion, beating the consensus estimate for $1.05 billion.
Harley-Davidson, Inc. President and CEO Keith Wandell said, "We are pleased by the growth of our dealers' new motorcycle sales on a worldwide basis, led by strength in Europe, even as we continue to encounter some headwinds in the U.S. related to the challenging macro-economic conditions."
Apr 19, 2011
Harley-Davidson (NYSE:HOG) reported Q1 EPS of $0.51 today, missing the consensus estimate for $0.53 per share. Revenue for the quarter was up 2.5% year-over-year to $1.06 billion, beating the consensus estimate for $1.05 billion.
Harley-Davidson, Inc. President and CEO Keith Wandell said, "We are pleased by the growth of our dealers' new motorcycle sales on a worldwide basis, led by strength in Europe, even as we continue to encounter some headwinds in the U.S. related to the challenging macro-economic conditions."
KazMunaiGas Finalizes Transaction for Ural Stake
Tuesday, April 19, 2011
JSC KazMunaiGas Exploration Production
KazMunaiGas announced the closing of the transaction to acquire a 50% stake in Ural Group Limited (UGL) from Exploration Venture Limited (EVL). UGL owns the exploration license for the block Fedorovskiy through 100% stake in LLP "Ural Oil and Gas" (UOG).
As previously announced, the deal price was subject to adjustment for EVL's work program financing obligations until the deal close. The final acquisition price is US $164.4m, including US $61.3m for shares and US $87.8m of shareholder loans (as of January 1, 2010) and US $15.3m - adjustment for EVL's work program financing until the deal close (2010 and 1Q11).
Earlier the acquisition was approved by the Board of Directors of KMG EP and the Board of Directors of EVL. All regulatory approvals have also been received.
Heritage Highlights 2010 Activities
Heritage Highlights 2010 Activities
Tuesday, April 19, 2011
Heritage Oil plc
Heritage Oil announced its results for the twelve months ended December 31, 2010. All figures are in US dollars unless otherwise stated.
Tony Buckingham, Chief Executive Officer, commented, "The sale of the Ugandan Assets in 2010 has provided Heritage with a strong balance sheet for activities within the current portfolio and the ability to appraise further opportunities to generate value for shareholders. We remain active across the portfolio with seismic programs and drilling planned for 2011, including a multi-well exploration and appraisal drilling program in Kurdistan commencing in July. In addition, we are progressing with discussions with the Kurdistan Regional Government for the fast-track development of the Miran Field."
Tuesday, April 19, 2011
Heritage Oil plc
Heritage Oil announced its results for the twelve months ended December 31, 2010. All figures are in US dollars unless otherwise stated.
- 2010 Operational Highlights
- Discovered the largest gas field in Iraq in the last 30 years
- Highly productive Jurassic reservoir intervals tested in the Miran West-2 well at a restricted cumulative flow rate of over 75 million cubic feet per day ("MMscfd")
- Estimated gross P90-P50 in-place volumes of 6.8-9.1 Trillion Cubic Feet ("TCF"), with a P10 upside of 12.3 TCF for Miran West
- Management estimates Heritage has mean net risked contingent and prospective resources in Miran West and Miran East of 744 million barrels of oil equivalent ("MMboe"), based on a 75% working interest
- Miran development options being considered with first export production targeted for 2015 using planned regional infrastructure
- Achieved nearly a twelvefold increase in contingent resources from 53 MMbbls to 605 MMboe following the successful testing of hydrocarbons
- Completed 3D seismic acquisition offshore Tanzania; data currently being processed
- Further development work in Russia, production increased 65% in 2010
- 2010 Financial Highlights
- Completed the disposal of interests in Block 3A and Block 1, Uganda, (the "Ugandan Assets") for which Tullow Uganda Limited ("Tullow") paid a cash consideration of $1.45 billion, including $100 million for a contractual settlement, and Heritage received and retained $1.045 billion
- Cash at year end of $598 million
- Special dividend of 100 pence per share paid in August 2010
- Outlook
- Rig contract to drill Miran West-3 well signed in April, well scheduled to spud July 2011
- Exploration drilling to commence on Miran East in Q4 2011
- 3D seismic data being processed for Tanzania with a view to establishing a drilling location
- Mali 2D seismic data currently being acquired with a well expected to be drilled in early 2012
- Malta 2D seismic data to be acquired during summer 2011
- Well in Pakistan planned for H2 2011
- Development options being reviewed for Kurdistan which include a phased development for oil, condensate and gas
- First horizontal well to be drilled in Q2, 2011, in the Zapadno Chumpasskoye Field, Russia, which should help to provide a material increase in production
Tony Buckingham, Chief Executive Officer, commented, "The sale of the Ugandan Assets in 2010 has provided Heritage with a strong balance sheet for activities within the current portfolio and the ability to appraise further opportunities to generate value for shareholders. We remain active across the portfolio with seismic programs and drilling planned for 2011, including a multi-well exploration and appraisal drilling program in Kurdistan commencing in July. In addition, we are progressing with discussions with the Kurdistan Regional Government for the fast-track development of the Miran Field."
Texon Secures Rig for Tyler Ranch
Texon Secures Rig for Tyler Ranch
Tuesday, April 19, 2011
Global Petroleum Ltd.
Texon has secured a rig for Tyler Ranch EFS #2H, the second Eagle Ford horizontal well in which Global Petroleum Limited ("Global") has an interest.
Tyler Ranch EFS #2H is located immediately north of the first Eagle Ford well ("Tyler Ranch EFS #1H"). The first Eagle Ford well had an initial production rate of 1,200 bopd and has produced 51,719 bo and 66.9 mmcfg or 62,866 boe in the past 120 days. Tyler Ranch EFS #2H is expected to begin drilling in mid May and take 30 days to drill.
Global has a 7.939% working interest (5.95% NRI) in Tyler Ranch EFS #1H and Tyler Ranch EFS #2H. A successful Eagle Ford well will be able to use the tanks and other production facilities already in place for the first Eagle Ford well.
The fraccing and testing for Tyler Ranch EFS #2H is scheduled for August.
Tuesday, April 19, 2011
Global Petroleum Ltd.
Texon has secured a rig for Tyler Ranch EFS #2H, the second Eagle Ford horizontal well in which Global Petroleum Limited ("Global") has an interest.
Tyler Ranch EFS #2H is located immediately north of the first Eagle Ford well ("Tyler Ranch EFS #1H"). The first Eagle Ford well had an initial production rate of 1,200 bopd and has produced 51,719 bo and 66.9 mmcfg or 62,866 boe in the past 120 days. Tyler Ranch EFS #2H is expected to begin drilling in mid May and take 30 days to drill.
Global has a 7.939% working interest (5.95% NRI) in Tyler Ranch EFS #1H and Tyler Ranch EFS #2H. A successful Eagle Ford well will be able to use the tanks and other production facilities already in place for the first Eagle Ford well.
The fraccing and testing for Tyler Ranch EFS #2H is scheduled for August.
Otto Spuds Duhat-1 Well
Otto Spuds Duhat-1 Well
Tuesday, April 19, 2011
Otto Energy Ltd.
Otto has commenced drilling the Duhat-1 well with the official spud of the well April 19.
The DESCO Rig-1 drilling unit is being used for the well which is expected to take approximately 27 days to reach target depth of 1,000 meters.
DUHAT-1 WELL BACKGROUND INFORMATION
Service Contract Summary:
The Duhat-1 well is programmed to reach a total depth of 1,000 meters and will test potential hydrocarbon accumulations within the sandstones of the Miocene Tagnocot formation of the San Isidro anticline. Pre-Spud "success case" volumetric estimates are in the range of 12 to 263 MMbbl Oil Initially in Place with a P50 estimate of 76 MMbbl.
With its programmed total depth (T.D) of 1,000m, the Duhat-1 will be the only modern deep exploration well in northwest Leyte. Hydrocarbon shows in several of the shallow wells drilled in the block and the presence of numerous oil seeps in the area indicate the presence of an active petroleum system. A success at Duhat-1 could be followed-up by additional exploration drilling on nearby look-alike structures.
The minimum reserves volume required for an economic discovery in the area is less than 1 MMbbl recoverable.
Otto Energy successfully executed a farm-out agreement with SWAN Oil and Gas in January 2011 and is now awaiting approval of the Philippine Department of Energy for this assignment.
Tuesday, April 19, 2011
Otto Energy Ltd.
Otto has commenced drilling the Duhat-1 well with the official spud of the well April 19.
The DESCO Rig-1 drilling unit is being used for the well which is expected to take approximately 27 days to reach target depth of 1,000 meters.
DUHAT-1 WELL BACKGROUND INFORMATION
Service Contract Summary:
- OEL (through its wholly-owned subsidiary NorAsian Energy Ltd) 40% Interest and Operator
- Area 3,320 km2
- Work commitment in the current sub-phase requires drilling of 1 exploration well by July 2011
- This license has recently been farmed down from 80% Working Interest to 40% to SWAN Oil and Gas Ltd in exchange for a US $1.5 mm contribution to the Duhat-1 well, to be drilled Q2 2011
The Duhat-1 well is programmed to reach a total depth of 1,000 meters and will test potential hydrocarbon accumulations within the sandstones of the Miocene Tagnocot formation of the San Isidro anticline. Pre-Spud "success case" volumetric estimates are in the range of 12 to 263 MMbbl Oil Initially in Place with a P50 estimate of 76 MMbbl.
With its programmed total depth (T.D) of 1,000m, the Duhat-1 will be the only modern deep exploration well in northwest Leyte. Hydrocarbon shows in several of the shallow wells drilled in the block and the presence of numerous oil seeps in the area indicate the presence of an active petroleum system. A success at Duhat-1 could be followed-up by additional exploration drilling on nearby look-alike structures.
The minimum reserves volume required for an economic discovery in the area is less than 1 MMbbl recoverable.
Otto Energy successfully executed a farm-out agreement with SWAN Oil and Gas in January 2011 and is now awaiting approval of the Philippine Department of Energy for this assignment.
Reef Resources to Test Flows at Ausable Well
Reef Resources to Test Flows at Ausable Well
Tuesday, April 19, 2011
Reef Resources Ltd.
Reef Resources has agreed to complete and flow test the Ausable #5 well in SW Ontario, Canada.
A decision has been made to mechanically complete the well and to conduct flow tests on the basis of the existing data. Further analysis of electric logs and cores from the wells will continue.
Following production testing; the well will be connected to the existing central production facility and placed on production as an oil and natural gas liquids (NGL) producer. The Company's objective is to have the well on production within the next four to six weeks.
Due to the presence of extensive oil and natural gas liquids pay zones in the Ausable #5 well, the Company will now begin detailed scheduling for the drilling of the Ausable #6, #7, #8 and #9 wells and the expansion of the Ausable production facility. Currently it is hoped to complete this additional work by the end of 2011.
The Company will issue additional status reports during the testing and completion of Ausable #5 and as plans for the full Enhanced Oil Recovery and Natural Gas Liquids Program (EOR) are finalized. The Ausable reef is currently on production and is generating revenue from the initial EOR program which commenced in 4th quarter 2010 through the Ausable #1 and #4 wells.
Company President, Arnie Hansen, commented, "We see this as a turning point in the development of the Ausable Reef as the results of the well fully support our geological model and demonstrate the viability of the EOR scheme. We look forward to a busy period over the remainder of the year as we plan and execute the necessary well program."
Tuesday, April 19, 2011
Reef Resources Ltd.
Reef Resources has agreed to complete and flow test the Ausable #5 well in SW Ontario, Canada.
A decision has been made to mechanically complete the well and to conduct flow tests on the basis of the existing data. Further analysis of electric logs and cores from the wells will continue.
Following production testing; the well will be connected to the existing central production facility and placed on production as an oil and natural gas liquids (NGL) producer. The Company's objective is to have the well on production within the next four to six weeks.
Due to the presence of extensive oil and natural gas liquids pay zones in the Ausable #5 well, the Company will now begin detailed scheduling for the drilling of the Ausable #6, #7, #8 and #9 wells and the expansion of the Ausable production facility. Currently it is hoped to complete this additional work by the end of 2011.
The Company will issue additional status reports during the testing and completion of Ausable #5 and as plans for the full Enhanced Oil Recovery and Natural Gas Liquids Program (EOR) are finalized. The Ausable reef is currently on production and is generating revenue from the initial EOR program which commenced in 4th quarter 2010 through the Ausable #1 and #4 wells.
Company President, Arnie Hansen, commented, "We see this as a turning point in the development of the Ausable Reef as the results of the well fully support our geological model and demonstrate the viability of the EOR scheme. We look forward to a busy period over the remainder of the year as we plan and execute the necessary well program."
Circle Oil Notes Drilling Preps at Egyptian Well
Circle Oil Notes Drilling Preps at Egyptian Well
Tuesday, April 19, 2011
Circle Oil plc
Circle Oil announced an update regarding the Geyad-3C appraisal/development well together with details on the future development of the NW Gemsa Concession.
Geyad-3C Update
Geyad-3C, located to the south-east of the Geyad-1X ST well in the Geyad Development Lease, is planned to be drilled to a total depth ("TD") of 5,911 ft measured depth ("MD") in the Upper Rudeis. The well is currently rigging up and preparing to commence drilling. The main objective for this well is to appraise and bring into production the oil bearing Shagar and Rahmi sandstones of the Kareem Formation. In the Geyad-1X ST well both zones were tested in May 2009 at a combined sustained rate of 2,809 bopd and 3.04 MMscf/d of gas from the Rahmi sandstones on a 64/64" choke and the well was put on production. In Geyad-2 ST, the Shagar sands were tested at a sustained rate of 3,850 bopd and 4.62 MMscf/d of gas on a 48/64" choke and the well was put on production. Secondary objectives of the Geyad 3-C well are to penetrate and evaluate the hydrocarbon potential of the overlying South Gharib and Belayim formations.
NW Gemsa Concession
Following the drilling of Geyad-3C, further intensive exploration, appraisal and development drilling is planned over the next eighteen months. A program of water injection wells will be drilled, as required, to support oil production in both the Al Amir SE and Geyad fields.
The NW Gemsa Concession, containing the Al Amir and Geyad Development Leases, covering an area of over 260 square kilometers, lies about 300 kilometers southeast of Cairo in a partially unexplored area of the Gulf of Suez Basin. The concession agreement includes the right of conversion to a production license of 20 years, plus extensions, in the event of commercial discoveries. The NW Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest); and Sea Dragon Energy (10% interest).
Tuesday, April 19, 2011
Circle Oil plc
Circle Oil announced an update regarding the Geyad-3C appraisal/development well together with details on the future development of the NW Gemsa Concession.
Geyad-3C Update
Geyad-3C, located to the south-east of the Geyad-1X ST well in the Geyad Development Lease, is planned to be drilled to a total depth ("TD") of 5,911 ft measured depth ("MD") in the Upper Rudeis. The well is currently rigging up and preparing to commence drilling. The main objective for this well is to appraise and bring into production the oil bearing Shagar and Rahmi sandstones of the Kareem Formation. In the Geyad-1X ST well both zones were tested in May 2009 at a combined sustained rate of 2,809 bopd and 3.04 MMscf/d of gas from the Rahmi sandstones on a 64/64" choke and the well was put on production. In Geyad-2 ST, the Shagar sands were tested at a sustained rate of 3,850 bopd and 4.62 MMscf/d of gas on a 48/64" choke and the well was put on production. Secondary objectives of the Geyad 3-C well are to penetrate and evaluate the hydrocarbon potential of the overlying South Gharib and Belayim formations.
NW Gemsa Concession
Following the drilling of Geyad-3C, further intensive exploration, appraisal and development drilling is planned over the next eighteen months. A program of water injection wells will be drilled, as required, to support oil production in both the Al Amir SE and Geyad fields.
The NW Gemsa Concession, containing the Al Amir and Geyad Development Leases, covering an area of over 260 square kilometers, lies about 300 kilometers southeast of Cairo in a partially unexplored area of the Gulf of Suez Basin. The concession agreement includes the right of conversion to a production license of 20 years, plus extensions, in the event of commercial discoveries. The NW Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest); and Sea Dragon Energy (10% interest).
Petronas Sells Cairn India Stake for $2.1B
Petronas Sells Cairn India Stake for $2.1B
Tuesday, April 19, 2011
Dow Jones Newswires
by Ankur Relia, Raghavendra Upadhyaya & Eric Yep
Malaysia's Petroliam Nasional Berhad, or Petronas, Tuesday said it exited Cairn India by selling its entire 14.94% stake in the oil and gas explorer for about $2.1 billion.
Petronas held 283.4 million shares in the Indian unit of Cairn through its overseas arm Petronas International Corp.
"The transaction brings to a close a successful association as a shareholder with Cairn India since 2006," Petronas said in a statement.
Petronas had raised its holding in Cairn India to 14.94% in 2009-10 after acquiring a 2.3% stake from Cairn Energy.
Petronas didn't reveal the names of the buyers but a person with knowledge of the matter told Dow Jones Newswires that the stake was sold to India-focused miner Vedanta and institutional investors in India via block deals.
Bank of America Merrill Lynch was the sole adviser on the deal, said the person, who declined to be named.
The stake sale by Petronas brings Vedanta closer to its goal of acquiring a majority stake in Cairn India as analysts don't expect a big response to Vedanta's open offer. Petronas' sale may also allow Edinburgh-based explorer Cairn Energy to retain a larger stake in Cairn India.
In August last year, Vedanta had offered to buy a 51%-60% stake in the Indian unit of Cairn Energy, in a deal expected to cost up to $9.6 billion.
The deal is awaiting approval from the Indian government.
Cairn Energy owns a 62.37% stake in Cairn India.
Vedanta has proposed to acquire up to 51% of Cairn India from its U.K. parent for INR405 a share. Vedanta unit Sesa Goa launched an open offer on April 11 for up to 20% of Cairn India from minority shareholders at INR355 a share. The open offer price doesn't include the INR50 non-compete fee that Vedanta had offered to Cairn Energy.
The open offer closes on April 30. Shares of Cairn India, which had earlier risen to as much as INR370, closed up 2.3% on Tuesday at INR344.25.
Vedanta, Cairn Energy and Cairn India didn't immediately respond to queries.
Earlier Tuesday, data on Factset showed that about 283.43 million shares of Cairn India were traded through block deals on the Bombay Stock Exchange. The three largest deals were for 265.19 million shares traded at a weighted average price of INR331.08 apiece, 12.08 million shares at INR331.08 each and 5.07 million shares at INR331.07 apiece.
The CNBC-TV18 television channel reported, citing sources it didn't name, that Vedanta bought an 11% stake in Cairn India from Petronas.
Cairn Energy has extended by more than a month the deadline for the stake sale to Vedanta to May 20 in order to accommodate the completion of the open offer and as an Indian ministerial panel scrutinizes the deal.
Cairn India holds stakes in 10 oil and gas blocks in India, including the huge RJ-ON-90/1 oil block at Barmer in western Rajasthan state. The block's output of 125,000 barrels a day accounts for about 17% of India's total crude production.
Tuesday, April 19, 2011
Dow Jones Newswires
by Ankur Relia, Raghavendra Upadhyaya & Eric Yep
Malaysia's Petroliam Nasional Berhad, or Petronas, Tuesday said it exited Cairn India by selling its entire 14.94% stake in the oil and gas explorer for about $2.1 billion.
Petronas held 283.4 million shares in the Indian unit of Cairn through its overseas arm Petronas International Corp.
"The transaction brings to a close a successful association as a shareholder with Cairn India since 2006," Petronas said in a statement.
Petronas had raised its holding in Cairn India to 14.94% in 2009-10 after acquiring a 2.3% stake from Cairn Energy.
Petronas didn't reveal the names of the buyers but a person with knowledge of the matter told Dow Jones Newswires that the stake was sold to India-focused miner Vedanta and institutional investors in India via block deals.
Bank of America Merrill Lynch was the sole adviser on the deal, said the person, who declined to be named.
The stake sale by Petronas brings Vedanta closer to its goal of acquiring a majority stake in Cairn India as analysts don't expect a big response to Vedanta's open offer. Petronas' sale may also allow Edinburgh-based explorer Cairn Energy to retain a larger stake in Cairn India.
In August last year, Vedanta had offered to buy a 51%-60% stake in the Indian unit of Cairn Energy, in a deal expected to cost up to $9.6 billion.
The deal is awaiting approval from the Indian government.
Cairn Energy owns a 62.37% stake in Cairn India.
Vedanta has proposed to acquire up to 51% of Cairn India from its U.K. parent for INR405 a share. Vedanta unit Sesa Goa launched an open offer on April 11 for up to 20% of Cairn India from minority shareholders at INR355 a share. The open offer price doesn't include the INR50 non-compete fee that Vedanta had offered to Cairn Energy.
The open offer closes on April 30. Shares of Cairn India, which had earlier risen to as much as INR370, closed up 2.3% on Tuesday at INR344.25.
Vedanta, Cairn Energy and Cairn India didn't immediately respond to queries.
Earlier Tuesday, data on Factset showed that about 283.43 million shares of Cairn India were traded through block deals on the Bombay Stock Exchange. The three largest deals were for 265.19 million shares traded at a weighted average price of INR331.08 apiece, 12.08 million shares at INR331.08 each and 5.07 million shares at INR331.07 apiece.
The CNBC-TV18 television channel reported, citing sources it didn't name, that Vedanta bought an 11% stake in Cairn India from Petronas.
Cairn Energy has extended by more than a month the deadline for the stake sale to Vedanta to May 20 in order to accommodate the completion of the open offer and as an Indian ministerial panel scrutinizes the deal.
Cairn India holds stakes in 10 oil and gas blocks in India, including the huge RJ-ON-90/1 oil block at Barmer in western Rajasthan state. The block's output of 125,000 barrels a day accounts for about 17% of India's total crude production.
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