SmarTrend Market Close Wrap-up -- April 11, 2011
The major U.S. equity indices closed mixed Monday ahead of first-quarter corporate-earnings season and after the IMF said that higher gas prices could slow the pace of the U.S. economy.
The IMF lowered its outlook for U.S. economic growth to 2.8% in 2011. It had previously forecast 3% growth for the U.S.
In corporate news, Alcoa (NYSE:AA) reported Q1 EPS of $0.28, ex-items, ahead of consensus estimates of $0.27 per share. Revenues for the quarter rose 22% year-over-year to $6.0 billion, missing consensus estimates of $6.07 billion.
The Dow Jones Industrial Average (DJI) closed 0.01% higher at 12,381.11, the S&P500 (INX) closed 0.28% lower at 1,324.46, and the Nasdaq Composite (IXIC) closed 0.32% lower at 2,771.51.
Monday, April 11, 2011
Commodity Corner: Oil Falls on Lower GDP Forecasts
Commodity Corner: Oil Falls on Lower GDP Forecasts
Monday, April 11, 2011
Rigzone Staff
by Matthew V. Veazey
Crude oil for May delivery fell 2.5 percent Monday to $109.92 a barrel after the International Monetary Fund (IMF) lowered its projections for real gross domestic product growth this year.
The IMF anticipates world GDP to increase by 4.4 percent this year, compared to 5.0 percent for 2010. In addition, the organization expressed concerns about high unemployment and commodity prices, along with the need to advance fiscal and financial repair and reform measures—particularly in the U.S. "To make a sizable dent in the projected medium-term deficits, broader measures such as Social Security and tax reforms will be essential," the IMF stated in regard to fiscal consolidation and entitlement reforms in the U.S.
Also in the case of the U.S. economy, the IMF lowered its GDP growth rate projection for 2011 to 2.8 percent. Earlier this year, the projection was 0.2 percentage points higher.
The IMF also noted that global demand needs to be "rebalanced." To illustrate this imbalance, it pointed out that global GDP is on course to grow by 2.4 percent this year in advanced economies and a whopping 6.5 percent in emerging and developing economies. In the case of the latter group, the organization cautioned that effects of the boom—growing production approaching capacity constraints as well as large food and energy price increases pressuring wages upward—could cause these economies to overheat.
Front-month crude traded within a range from $110.05 to $113.46 Monday. The IMF report is available here
May natural gas briefly traded below the $4.00 per thousand cubic feet mark Monday—and investors treated the dip to $3.99 as a buying opportunity. By the end of the day, natural gas had surged to $4.16 before settling at $4.11. In comparison, gas settled at $4.04 on Friday.
May gasoline slipped by six cents Monday to settle at $3.20 a gallon. It peaked at $3.27 and bottomed out $3.19.
Monday, April 11, 2011
Rigzone Staff
by Matthew V. Veazey
Crude oil for May delivery fell 2.5 percent Monday to $109.92 a barrel after the International Monetary Fund (IMF) lowered its projections for real gross domestic product growth this year.
The IMF anticipates world GDP to increase by 4.4 percent this year, compared to 5.0 percent for 2010. In addition, the organization expressed concerns about high unemployment and commodity prices, along with the need to advance fiscal and financial repair and reform measures—particularly in the U.S. "To make a sizable dent in the projected medium-term deficits, broader measures such as Social Security and tax reforms will be essential," the IMF stated in regard to fiscal consolidation and entitlement reforms in the U.S.
Also in the case of the U.S. economy, the IMF lowered its GDP growth rate projection for 2011 to 2.8 percent. Earlier this year, the projection was 0.2 percentage points higher.
The IMF also noted that global demand needs to be "rebalanced." To illustrate this imbalance, it pointed out that global GDP is on course to grow by 2.4 percent this year in advanced economies and a whopping 6.5 percent in emerging and developing economies. In the case of the latter group, the organization cautioned that effects of the boom—growing production approaching capacity constraints as well as large food and energy price increases pressuring wages upward—could cause these economies to overheat.
Front-month crude traded within a range from $110.05 to $113.46 Monday. The IMF report is available here
May natural gas briefly traded below the $4.00 per thousand cubic feet mark Monday—and investors treated the dip to $3.99 as a buying opportunity. By the end of the day, natural gas had surged to $4.16 before settling at $4.11. In comparison, gas settled at $4.04 on Friday.
May gasoline slipped by six cents Monday to settle at $3.20 a gallon. It peaked at $3.27 and bottomed out $3.19.
RAM to Test Productivity of Osage Play
RAM to Test Productivity of Osage Play
Monday, April 11, 2011
RAM Energy Resources Inc.
RAM updated on activity in its Mississippian oil play in Osage County, Oklahoma. Approximately $5.4 million, or 15%, of RAM's 2011 capital expenditure budget totaling $35 million is allocated to the company's 56,320 acre concession, a part of the broad Mississippi Chat / Mississippi Solid / Arbuckle oil play in the region. Interpretation of the first phase of 3-D seismic, acquired in 2010, and initial drilling results indicated that a substantial portion of the acreage surveyed could be prospective. Although the Mississippi Chat has been the company's primary objective to date, the company's practice is to drill through the Chat and through the Mississippi Lime formation in order to gather additional science for future development. The initial wells drilled have encountered Chat zones 40-70 feet thick and porosities ranging from 20% to 35%. Similarly, initial wells have drilled through Mississippi Lime zones of 100 feet, or more, in thickness with a porosity range similar to the 5% to 15% range of porosities experienced by other operators in the western portions of the play.
"We are encouraged with the initial results from our Osage concession and have allocated a large proportion of our capital budget to test the productivity of the area. The combination of rig availability, relatively low drilling cost per well and ample infrastructure in the area allows us to aggressively pursue the play in the coming year," said Larry Lee, CEO of RAM.
Stepped up Pace of Drilling Planned in Osage Mississippian Exploration Play
Following the drilling of the company's three initial vertical wells in the concession during 2010, the company drilled the Farmland #1 during the first quarter 2011, targeting the Mississippi Chat formation. Currently the company is evaluating cores taken from the well. Also during the first quarter 2011, the Surber #3-SWD, a salt water disposal well, was drilled to service existing and future producing wells in the area. In the Surber #2-Twin, drilled during the first quarter near the Surber #3 SWD, core samples have been taken and casing set. RAM is awaiting the evaluation of the core data prior to completing.
The Rickets #3 well and the Surber #1 well, which were drilled to the Mississippi Chat formation late in 2010, have been fracture stimulated in order to test the impact of the slick water frac technique on reservoir permeability, thus advancing the science and knowledge associated with completion techniques in the area. Completion of the salt water disposal well facilitated the ability to fracture these and other planned wells in the area. The company has spud the next well in the series, the Surber #2-27, approximately one section to the west of the Surber #2-Twin. This offset to the Surber #1 and Surber #2-Twin is an exploration well targeting the continuation of the Mississippi Chat formation through seismic identification and sample cuttings from a previously drilled well by another operator. In mid-April the Farmland #2-16, an exploratory well, is scheduled to spud, also targeting the Mississippi Chat. The well, located approximately 2 sections northwest of the Surber #2-Twin, has been permitted and the location built. Immediately following the drilling of this well, the rig is scheduled to move to the location of the Christiansen #3-2. This exploration well is scheduled for a spud date later in April. The well targets the Arbuckle formation and will evaluate the Mississippi Chat and Lime formations. Two wells initially planned for the fourth quarter, the Surber #1-35 and the Rickets #1-35, are now likely to be drilled late in the second quarter as a result of rig availability. The drilling permit application process is underway for both of these wells. The location of the wells is anticipated to be immediately south of the successful Surber #1 well drilled in late 2010 which recorded an initial production rate of 80 barrels of oil per day (BOPD) in the Mississippi Chat formation.
Subsequently, in the third quarter 2011, the company plans to drill the Farmland #1-20 exploration well located southwest of the Farmland #2-16. At the northern boundary of RAM's initial seismic survey, the company plans to drill three wells; the Kendrick #1-27, the Stuart #1-28 and the Jones #1-33. These three exploration wells are designed to test the productivity of the Mississippi Chat and Lime formations in this unexplored part of the concession. If commercial potential exists, then RAM is likely to also drill another salt water disposal well to service these and potentially other future wells in this area of the lease. Archeological studies are proceeding on these wells which are precursors of the drilling permitting process.
In May 2011 the company plans to initiate acquisition of a second round of 3-D seismic on its Osage concession adjoining that of its first round of seismic acquisition. This second phase of 3-D seismic acquisition is planned to cover an additional 19,840 acres in the company's concession and is anticipated to add additional drilling prospects principally for 2012 and beyond when interpreted, later in 2011.
Advantaged Revenue Stream
Within the broad Mississippian play, the portion of the area covering RAM's Osage concession appears to yield primarily oil. Accordingly, commercialization of the company's acreage could add significantly to RAM's already above-industry-average mix of oil and oil-price driven natural gas liquids (NGL) in its hydrocarbon mix. The proportion of crude and NGLs as a percent of total BOE produced rose to 66% in December 2010 (adjusted to exclude assets sold in December 2010). Similarly, based on RAM's proved reserves at year-end 2010, oil and NGLs accounted for 64 percent of total proved reserves.
Monday, April 11, 2011
RAM Energy Resources Inc.
RAM updated on activity in its Mississippian oil play in Osage County, Oklahoma. Approximately $5.4 million, or 15%, of RAM's 2011 capital expenditure budget totaling $35 million is allocated to the company's 56,320 acre concession, a part of the broad Mississippi Chat / Mississippi Solid / Arbuckle oil play in the region. Interpretation of the first phase of 3-D seismic, acquired in 2010, and initial drilling results indicated that a substantial portion of the acreage surveyed could be prospective. Although the Mississippi Chat has been the company's primary objective to date, the company's practice is to drill through the Chat and through the Mississippi Lime formation in order to gather additional science for future development. The initial wells drilled have encountered Chat zones 40-70 feet thick and porosities ranging from 20% to 35%. Similarly, initial wells have drilled through Mississippi Lime zones of 100 feet, or more, in thickness with a porosity range similar to the 5% to 15% range of porosities experienced by other operators in the western portions of the play.
"We are encouraged with the initial results from our Osage concession and have allocated a large proportion of our capital budget to test the productivity of the area. The combination of rig availability, relatively low drilling cost per well and ample infrastructure in the area allows us to aggressively pursue the play in the coming year," said Larry Lee, CEO of RAM.
Stepped up Pace of Drilling Planned in Osage Mississippian Exploration Play
Following the drilling of the company's three initial vertical wells in the concession during 2010, the company drilled the Farmland #1 during the first quarter 2011, targeting the Mississippi Chat formation. Currently the company is evaluating cores taken from the well. Also during the first quarter 2011, the Surber #3-SWD, a salt water disposal well, was drilled to service existing and future producing wells in the area. In the Surber #2-Twin, drilled during the first quarter near the Surber #3 SWD, core samples have been taken and casing set. RAM is awaiting the evaluation of the core data prior to completing.
The Rickets #3 well and the Surber #1 well, which were drilled to the Mississippi Chat formation late in 2010, have been fracture stimulated in order to test the impact of the slick water frac technique on reservoir permeability, thus advancing the science and knowledge associated with completion techniques in the area. Completion of the salt water disposal well facilitated the ability to fracture these and other planned wells in the area. The company has spud the next well in the series, the Surber #2-27, approximately one section to the west of the Surber #2-Twin. This offset to the Surber #1 and Surber #2-Twin is an exploration well targeting the continuation of the Mississippi Chat formation through seismic identification and sample cuttings from a previously drilled well by another operator. In mid-April the Farmland #2-16, an exploratory well, is scheduled to spud, also targeting the Mississippi Chat. The well, located approximately 2 sections northwest of the Surber #2-Twin, has been permitted and the location built. Immediately following the drilling of this well, the rig is scheduled to move to the location of the Christiansen #3-2. This exploration well is scheduled for a spud date later in April. The well targets the Arbuckle formation and will evaluate the Mississippi Chat and Lime formations. Two wells initially planned for the fourth quarter, the Surber #1-35 and the Rickets #1-35, are now likely to be drilled late in the second quarter as a result of rig availability. The drilling permit application process is underway for both of these wells. The location of the wells is anticipated to be immediately south of the successful Surber #1 well drilled in late 2010 which recorded an initial production rate of 80 barrels of oil per day (BOPD) in the Mississippi Chat formation.
Subsequently, in the third quarter 2011, the company plans to drill the Farmland #1-20 exploration well located southwest of the Farmland #2-16. At the northern boundary of RAM's initial seismic survey, the company plans to drill three wells; the Kendrick #1-27, the Stuart #1-28 and the Jones #1-33. These three exploration wells are designed to test the productivity of the Mississippi Chat and Lime formations in this unexplored part of the concession. If commercial potential exists, then RAM is likely to also drill another salt water disposal well to service these and potentially other future wells in this area of the lease. Archeological studies are proceeding on these wells which are precursors of the drilling permitting process.
In May 2011 the company plans to initiate acquisition of a second round of 3-D seismic on its Osage concession adjoining that of its first round of seismic acquisition. This second phase of 3-D seismic acquisition is planned to cover an additional 19,840 acres in the company's concession and is anticipated to add additional drilling prospects principally for 2012 and beyond when interpreted, later in 2011.
Advantaged Revenue Stream
Within the broad Mississippian play, the portion of the area covering RAM's Osage concession appears to yield primarily oil. Accordingly, commercialization of the company's acreage could add significantly to RAM's already above-industry-average mix of oil and oil-price driven natural gas liquids (NGL) in its hydrocarbon mix. The proportion of crude and NGLs as a percent of total BOE produced rose to 66% in December 2010 (adjusted to exclude assets sold in December 2010). Similarly, based on RAM's proved reserves at year-end 2010, oil and NGLs accounted for 64 percent of total proved reserves.
Koch to Facilitate Eagle Ford Production
Koch to Facilitate Eagle Ford Production
Monday, April 11, 2011
Koch Pipeline Co., L.P.
Koch Pipeline Company, L.P. plans to build a crude oil pipeline from Pettus, Texas to Corpus Christi, Texas to move more Eagle Ford production. Current plans include a 20-inch line, which is currently in the permitting and right-of-way acquisition phase and should be complete in mid-2012.
"With this large-diameter line in operation, Koch Pipeline will have increased its system capability from Karnes County to the Corpus Christi-area to about 250,000 barrels per day," said Kim Penner, president of Koch Pipeline.
The completion of the line is timed with affiliate Flint Hills Resources' updates to an Ingleside terminal that will have the capacity to ship up to 200,000 barrels per day of production via barge to other Gulf Coast markets.
Koch Pipeline is constructing a station near Helena in Karnes County along with connections to tank batteries in Karnes and DeWitt counties as well as a 16-inch pipeline from Helena to Pettus. The 16-inch pipeline will connect to the new line announced today at Pettus.
"With several new lines, our legacy system and arrangements with Arrowhead Pipeline and NuStar Logistics, we are addressing producers' needs to move crude oil and condensate to market," Penner said. "We continue to evaluate major South Texas pipeline projects, including a project to connect producers in Western counties."
Monday, April 11, 2011
Koch Pipeline Co., L.P.
Koch Pipeline Company, L.P. plans to build a crude oil pipeline from Pettus, Texas to Corpus Christi, Texas to move more Eagle Ford production. Current plans include a 20-inch line, which is currently in the permitting and right-of-way acquisition phase and should be complete in mid-2012.
"With this large-diameter line in operation, Koch Pipeline will have increased its system capability from Karnes County to the Corpus Christi-area to about 250,000 barrels per day," said Kim Penner, president of Koch Pipeline.
The completion of the line is timed with affiliate Flint Hills Resources' updates to an Ingleside terminal that will have the capacity to ship up to 200,000 barrels per day of production via barge to other Gulf Coast markets.
Koch Pipeline is constructing a station near Helena in Karnes County along with connections to tank batteries in Karnes and DeWitt counties as well as a 16-inch pipeline from Helena to Pettus. The 16-inch pipeline will connect to the new line announced today at Pettus.
"With several new lines, our legacy system and arrangements with Arrowhead Pipeline and NuStar Logistics, we are addressing producers' needs to move crude oil and condensate to market," Penner said. "We continue to evaluate major South Texas pipeline projects, including a project to connect producers in Western counties."
Tanzania Defers Offshore O&G Bidding Round until 2012
Tanzania Defers Offshore O&G Bidding Round until 2012
Monday, April 11, 2011
Dow Jones Newswires
by Nicholas Bariyo
Tanzania has postponed its fourth deep-offshore bidding round to 2012, said state oil company Tanzania Petroleum Development Corp.
The bidding round was to be opened April 12, and was expected to include 13 blocks sitting between 1,200 meters and 3,500 meters of water depth.
"The round has been postponed to give more time for preparations," TPDC said in a statement. "This will include proper demarcation of new blocks using additional new seismic."
TPDC didn't specify the exact date of the new round.
Currently, Tanzania has licensed 12 deepwater blocks and recent exploration works have encountered at least 7.5 trillion cubic feet of natural gas. The country is yet to discover commercial oil reserves.
Sebastian Shana, TPDC's principal petroleum geologist, said at least 13 new blocks have been demarcated, including new areas and relinquished acreage.
Geologists believe that Tanzanian oil and gas exploration areas share similar geological properties with Uganda's Lake Albertine Rift basin, where around 1 billion barrels of oil reserves have been discovered.
Exploration companies already licensed in Tanzania include Shell's local subsidiary Shell International, Orca Exploration, Dominion Gas and Oil, Tullow Oil and Tower Resources.
Monday, April 11, 2011
Dow Jones Newswires
by Nicholas Bariyo
Tanzania has postponed its fourth deep-offshore bidding round to 2012, said state oil company Tanzania Petroleum Development Corp.
The bidding round was to be opened April 12, and was expected to include 13 blocks sitting between 1,200 meters and 3,500 meters of water depth.
"The round has been postponed to give more time for preparations," TPDC said in a statement. "This will include proper demarcation of new blocks using additional new seismic."
TPDC didn't specify the exact date of the new round.
Currently, Tanzania has licensed 12 deepwater blocks and recent exploration works have encountered at least 7.5 trillion cubic feet of natural gas. The country is yet to discover commercial oil reserves.
Sebastian Shana, TPDC's principal petroleum geologist, said at least 13 new blocks have been demarcated, including new areas and relinquished acreage.
Geologists believe that Tanzanian oil and gas exploration areas share similar geological properties with Uganda's Lake Albertine Rift basin, where around 1 billion barrels of oil reserves have been discovered.
Exploration companies already licensed in Tanzania include Shell's local subsidiary Shell International, Orca Exploration, Dominion Gas and Oil, Tullow Oil and Tower Resources.
Breezer Initiates Re-Opening of Jackson Lease Well
Breezer Initiates Re-Opening of Jackson Lease Well
Monday, April 11, 2011
Breezer Ventures Inc.
Breezer has initiated the re-opening of well #6 of the Jackson lease which is the Company's first well, of an accumulation of ten oil and gas wells which are specified for a complete rehabilitation and production development program, based in West Texas.
The initial work to re-open this well is almost complete as the field operator, Whitt Oil and Gas, has reached the last cement plug to be drilled before reaching the Moran Sand. The project managers and field operators advised, "They expect to drill into the prolific Moran Sand sometime today or tomorrow." Then they will continue to deepen the former Magnolia/Mobil Oil well #6 into the Moran Sand and Moran Lime.
The Jackson lease was the heart of the old Magnolia/Mobil Oil Red Horse Field first discovered in 1961. Two separate engineering reports indicate that there were significant oil and gas reserves to be developed from the original formation as well as from a deeper segment within the Moran Sands and Moran Lime. The field operator and project manager have expressed optimism at what results they expect from the deeper portion of the formation. The well is on the highest structural position of the Moran Sand and Moran Lime situated on the 870 acre lease and this should prove to be very prolific.
Breezer Ventures has 10 existing and plugged oil and gas wells on the Jackson lease that are currently in for rehabilitation and reactivation on the Jackson Lease, which contains 870 acres, is situated on the western side of the Bend Arch of the Fort Worth Basin. The lease is situated 5 miles north of Baird, Texas.
Monday, April 11, 2011
Breezer Ventures Inc.
Breezer has initiated the re-opening of well #6 of the Jackson lease which is the Company's first well, of an accumulation of ten oil and gas wells which are specified for a complete rehabilitation and production development program, based in West Texas.
The initial work to re-open this well is almost complete as the field operator, Whitt Oil and Gas, has reached the last cement plug to be drilled before reaching the Moran Sand. The project managers and field operators advised, "They expect to drill into the prolific Moran Sand sometime today or tomorrow." Then they will continue to deepen the former Magnolia/Mobil Oil well #6 into the Moran Sand and Moran Lime.
The Jackson lease was the heart of the old Magnolia/Mobil Oil Red Horse Field first discovered in 1961. Two separate engineering reports indicate that there were significant oil and gas reserves to be developed from the original formation as well as from a deeper segment within the Moran Sands and Moran Lime. The field operator and project manager have expressed optimism at what results they expect from the deeper portion of the formation. The well is on the highest structural position of the Moran Sand and Moran Lime situated on the 870 acre lease and this should prove to be very prolific.
Breezer Ventures has 10 existing and plugged oil and gas wells on the Jackson lease that are currently in for rehabilitation and reactivation on the Jackson Lease, which contains 870 acres, is situated on the western side of the Bend Arch of the Fort Worth Basin. The lease is situated 5 miles north of Baird, Texas.
TGS Strengthens PMS Position with Stingray Acquisition
TGS Strengthens PMS Position with Stingray Acquisition
Monday, April 11, 2011
TGS-NOPEC Geophysical Co. ASA
TGS has entered into an agreement to acquire 100% of the shares of Stingray Geophysical Limited (Stingray). The transaction will provide TGS with a strong position in the rapidly growing market for Permanent Reservoir Monitoring (PRM) solutions. The acquisition will substantially increase TGS' addressable market through access to production seismic spending from large international oil companies as well as national oil companies (NOCs), while maintaining its successful asset light model.
Robert Hobbs, CEO of TGS said, "The age of "easy to find" oil is over, forcing oil companies to increase investment in their existing fields to extend production and increase recovery factors. The acquisition of Stingray allows TGS to access a larger portion of the reservoir optimization market. The combination of TGS and Stingray will leverage both companies' strengths to create a powerful PRM offering to the industry."
Martin Bett, Managing Director of Stingray added, "TGS brings complementary capabilities, a global organization, established seismic project management skills and financial strength to Stingray. As a part of TGS, Stingray is now well positioned to deliver innovative PRM solutions that will assist our clients to increase production and reserves whilst decreasing risk and costs of their Enhanced Oil Recovery programs."
The 4D seismic market, of which PRM is an integral and increasing part, was estimated to be over USD 1 billion in 2010 with the majority of data being acquired by towed streamers (source: ODS PetroData). Expectations are for the 4D market to exceed USD 2.5 billion within the next four years (source: Stingray estimate). New PRM installations are expected to trend towards optical versus electrical solutions due to the expected increase in reliability and flexibility that this technology offers, especially in deep water.
The transferred assets include 11 employees and an extensive portfolio of intellectual property. All management team members and employees of Stingray will continue as employees of TGS.
The consideration for 100% of the shares is based on an initial payment of USD 45 million and incremental payments of up to USD 35 million based on the success in commercializing the technology.
The transaction is expected to complete in April 2011.
Monday, April 11, 2011
TGS-NOPEC Geophysical Co. ASA
TGS has entered into an agreement to acquire 100% of the shares of Stingray Geophysical Limited (Stingray). The transaction will provide TGS with a strong position in the rapidly growing market for Permanent Reservoir Monitoring (PRM) solutions. The acquisition will substantially increase TGS' addressable market through access to production seismic spending from large international oil companies as well as national oil companies (NOCs), while maintaining its successful asset light model.
Robert Hobbs, CEO of TGS said, "The age of "easy to find" oil is over, forcing oil companies to increase investment in their existing fields to extend production and increase recovery factors. The acquisition of Stingray allows TGS to access a larger portion of the reservoir optimization market. The combination of TGS and Stingray will leverage both companies' strengths to create a powerful PRM offering to the industry."
Martin Bett, Managing Director of Stingray added, "TGS brings complementary capabilities, a global organization, established seismic project management skills and financial strength to Stingray. As a part of TGS, Stingray is now well positioned to deliver innovative PRM solutions that will assist our clients to increase production and reserves whilst decreasing risk and costs of their Enhanced Oil Recovery programs."
The 4D seismic market, of which PRM is an integral and increasing part, was estimated to be over USD 1 billion in 2010 with the majority of data being acquired by towed streamers (source: ODS PetroData). Expectations are for the 4D market to exceed USD 2.5 billion within the next four years (source: Stingray estimate). New PRM installations are expected to trend towards optical versus electrical solutions due to the expected increase in reliability and flexibility that this technology offers, especially in deep water.
The transferred assets include 11 employees and an extensive portfolio of intellectual property. All management team members and employees of Stingray will continue as employees of TGS.
The consideration for 100% of the shares is based on an initial payment of USD 45 million and incremental payments of up to USD 35 million based on the success in commercializing the technology.
The transaction is expected to complete in April 2011.
Tap Oil Divests Carnarvon Interests
Tap Oil Divests Carnarvon Interests
Monday, April 11, 2011
Tap Oil Ltd.
Tap Oil has agreed to sell its interests in a portfolio of non-core assets in the Carnarvon Basin to companies in the Sydney based and privately owned Hardie Energy Group. As consideration for the assignments, the companies will pay Tap $2,000,000. Further details of the assets and the assignments are set out in the attached schedule.
The completion of the sale of the portfolio is subject to joint venture and government approvals, with an effective date of 1 February 2011.
Tap's Managing Director/CEO Troy Hayden said, "While still having tangible value, these interests are better placed in the hands of companies like the Hardie Energy Group.
"The sale of these interests allows our technical staff to focus on our three core areas: being Zola and WA-351-P, Carnarvon Basin; Gulf of Thailand; and Ghana."
The Hardie Energy Group is a significant shareholder in fellow Sydney based explorer Energetica Resources Pty Ltd, which holds nearby acreage in the Carnarvon Basin and will manage the asset interests going forward.
Monday, April 11, 2011
Tap Oil Ltd.
Tap Oil has agreed to sell its interests in a portfolio of non-core assets in the Carnarvon Basin to companies in the Sydney based and privately owned Hardie Energy Group. As consideration for the assignments, the companies will pay Tap $2,000,000. Further details of the assets and the assignments are set out in the attached schedule.
The completion of the sale of the portfolio is subject to joint venture and government approvals, with an effective date of 1 February 2011.
Tap's Managing Director/CEO Troy Hayden said, "While still having tangible value, these interests are better placed in the hands of companies like the Hardie Energy Group.
"The sale of these interests allows our technical staff to focus on our three core areas: being Zola and WA-351-P, Carnarvon Basin; Gulf of Thailand; and Ghana."
The Hardie Energy Group is a significant shareholder in fellow Sydney based explorer Energetica Resources Pty Ltd, which holds nearby acreage in the Carnarvon Basin and will manage the asset interests going forward.
Utica, Upper Devonian Reserves in Pa. May Match Marcellus' Bounty
Utica, Upper Devonian Reserves in Pa. May Match Marcellus' Bounty
Monday, April 11, 2011
The Philadelphia Inquirer
by Andrew Maykuth
Natural gas drillers are accelerating exploration of several Appalachian rock formations that sandwich the Marcellus Shale beneath Pennsylvania, and some experts say the new discoveries may be as prolific as the Marcellus itself.
"What we've got is Marcellus times two," said Terry Engelder, the Pennsylvania State University geosciences professor whose Marcellus Shale estimates in 2008 first drew public attention to the region's shale gas potential.
Since The Inquirer reported in May that drillers had found recoverable gas in the Utica and Upper Devonian Shales, several operators have become more openly optimistic about a potential natural gas triple play in the region. The new discoveries add momentum to an industry that is rapidly reshaping the economy and the environment of large swaths of rural Pennsylvania.
"A year ago, I didn't have a feeling the tests were going to be as large as I've seen," Engelder said. "The implications of this are just amazing."
Range Resources Corp., the Texas company that drilled the first Marcellus well in 2004, is bullish about multiplying output from its acreage, mostly in southwestern Pennsylvania.
"The Utica and Upper Devonian could combine to equal the Marcellus," Range spokesman Matt Pitzarella said, though he cautioned that the estimates were preliminary.
At least four gas drillers, including Range, told investors this year they were exploring the formations, which lie above and below the Marcellus in a geological layer cake.
The expanding outlook of shale gas reserves goes far beyond Pennsylvania.
Worldwide estimates of gas reserves are growing because of revolutionary advances that couple horizontal-drilling techniques with hydraulic fracturing to unlock gas in long reaches of tight rocks.
The U.S. Energy Information Administration on Tuesday said technically recoverable shale gas worldwide could add 40 percent to global gas supply. China, South Africa, Argentina, and Australia have big reserves. So do Mexico and Canada.
According to the administration, American natural gas reserves are now at the highest level in 40 years. By 2035, shale gas will account for 46 percent of U.S. natural gas production.
Though gas burns cleaner than coal or oil, the escalation of an industrial extraction process that produces large volumes of toxic wastewater has raised fears about the trade-offs of shale gas. President Obama has championed natural gas development, but only if it can be done without endangering water supplies.
"It's a little disheartening the industry is wringing its hands in excitement when they clearly haven't figured out how to drill in the current shale without creating problems," said David Masur, executive director of PennEnvironment, a lobbying organization.
Pennsylvania regulators on Wednesday pressed Western Pennsylvania water suppliers to expand the scope of tests to screen for radioactive pollutants and other contaminants from the natural gas drilling industry.
So far, 2,748 Marcellus wells have been drilled in Pennsylvania -- 399 in the first three months of 2011. Experts say 50,000 wells could be drilled in the coming decades, not counting wells in other formations.
"We're still in the early stages of this," Masur said.
Awareness of the presence of gas in other Appalachian formations -- even deep ones -- is hardly new. Some operators, such as Anadarko Petroleum Corp., were attracted to Pennsylvania to explore other deep formations and then switched to the Marcellus. Range's first Marcellus well had targeted a deeper formation called the Lockport Dolomite.
The potential of the Marcellus has eclipsed all other formations. In the last 150 years, operators have produced 47 trillion cubic feet of gas from Appalachian wells, Pitzarella said. By comparison, the Marcellus Shale is believed to contain 500 trillion cubic feet, though the amount eventually recovered will be less.
In recent months, operators have begun to focus capital on some of the other formations.
Atlas Energy Inc. executives, before their company was sold to Chevron Corp., told analysts they were exploring the Utica formation and the Upper Devonian Shale.
"Both of these shale packages are prevalent throughout Western Pennsylvania and New York, where we have over 630,000 net acres," Atlas president Richard D. Weber said in August.
Consol Energy Inc., a Pennsylvania coal producer that last year moved aggressively into natural gas, said it had a promising Utica well last year in eastern Ohio.
Brandon Elliott, Consol's vice president for investor relations, told investors on Feb. 28 that a vertical well produced 1.5 million cubic feet of gas from a 200-foot-thick Utica layer 8,450 feet below the surface.
That production, which required no hydraulic fracturing, "actually would be greater than any of our other vertical wells that we drilled in the Marcellus," Elliot said.
Consol has budgeted $35 million to drill six more Utica wells later this year, he said.
Ultra Petroleum Corp. of Houston says the Utica Shale appears to be uneconomical beneath its acreage in northern Pennsylvania. But it plans to drill into a shallower Upper Devonian formation, the Geneseo Shale, this month.
"We're optimistic about this target, and we feel it has the potential to add significant value across a large part of our Pennsylvania acreage position," Douglas Selvius, Ultra's director of exploration, told investors.
John H. Pinkerton, chief executive of Range Resources, says he believes a lot of other companies will follow his lead into the Utica and Upper Devonian Shales.
Range is attracted to the additional shales because all three layers lie under much of its prime 700,000 Marcellus acres -- making those mineral leases equal in value to 1.5 million acres in other shale regions.
Pinkerton said production costs for the new wells would be lower than those of the original wells because many will use the same infrastructure -- the same well pads, roads, and pipelines now being installed for the Marcellus wells.
"The incremental cost to develop the Upper Devonian and Utica will be reduced by approximately one-third versus the development of these zones on a stand-alone basis," Pinkerton told analysts in March. "We believe this will allow us to continue to drive down the cost of the entire play."
The new shales also seem more promising in Western Pennsylvania areas where the Marcellus produces "wet gas" that contains liquid fuels in addition to natural gas. Those areas are considered attractive in the current market because liquids, which are valued according to oil prices, which are soaring, fetch a premium.
Some analysts say the Utica and Upper Devonian Shales have limited promise.
Subash Chandra, a Jeffries & Co. managing director, said the Utica formation "is not going to work" in much of Pennsylvania because it may not contain attractive quantities of natural gas in its deepest parts.
"The real Utica play is in Ohio, where it's shallower," he said.
As Marcellus drillers have discovered, not all shale acreage is created equal.
Encana Corp., a Canadian driller, last year pulled up stakes in Luzerne County, near Wilkes-Barre, after its wells produced disappointing results, marking what may be the productive boundary of the Marcellus.
According to industry experts, some deep Marcellus pockets on its eastern edges are "baked" -- they received too much heat over the ages and no longer contain commercial quantities of natural gas.
Monday, April 11, 2011
The Philadelphia Inquirer
by Andrew Maykuth
Natural gas drillers are accelerating exploration of several Appalachian rock formations that sandwich the Marcellus Shale beneath Pennsylvania, and some experts say the new discoveries may be as prolific as the Marcellus itself.
"What we've got is Marcellus times two," said Terry Engelder, the Pennsylvania State University geosciences professor whose Marcellus Shale estimates in 2008 first drew public attention to the region's shale gas potential.
Since The Inquirer reported in May that drillers had found recoverable gas in the Utica and Upper Devonian Shales, several operators have become more openly optimistic about a potential natural gas triple play in the region. The new discoveries add momentum to an industry that is rapidly reshaping the economy and the environment of large swaths of rural Pennsylvania.
"A year ago, I didn't have a feeling the tests were going to be as large as I've seen," Engelder said. "The implications of this are just amazing."
Range Resources Corp., the Texas company that drilled the first Marcellus well in 2004, is bullish about multiplying output from its acreage, mostly in southwestern Pennsylvania.
"The Utica and Upper Devonian could combine to equal the Marcellus," Range spokesman Matt Pitzarella said, though he cautioned that the estimates were preliminary.
At least four gas drillers, including Range, told investors this year they were exploring the formations, which lie above and below the Marcellus in a geological layer cake.
The expanding outlook of shale gas reserves goes far beyond Pennsylvania.
Worldwide estimates of gas reserves are growing because of revolutionary advances that couple horizontal-drilling techniques with hydraulic fracturing to unlock gas in long reaches of tight rocks.
The U.S. Energy Information Administration on Tuesday said technically recoverable shale gas worldwide could add 40 percent to global gas supply. China, South Africa, Argentina, and Australia have big reserves. So do Mexico and Canada.
According to the administration, American natural gas reserves are now at the highest level in 40 years. By 2035, shale gas will account for 46 percent of U.S. natural gas production.
Though gas burns cleaner than coal or oil, the escalation of an industrial extraction process that produces large volumes of toxic wastewater has raised fears about the trade-offs of shale gas. President Obama has championed natural gas development, but only if it can be done without endangering water supplies.
"It's a little disheartening the industry is wringing its hands in excitement when they clearly haven't figured out how to drill in the current shale without creating problems," said David Masur, executive director of PennEnvironment, a lobbying organization.
Pennsylvania regulators on Wednesday pressed Western Pennsylvania water suppliers to expand the scope of tests to screen for radioactive pollutants and other contaminants from the natural gas drilling industry.
So far, 2,748 Marcellus wells have been drilled in Pennsylvania -- 399 in the first three months of 2011. Experts say 50,000 wells could be drilled in the coming decades, not counting wells in other formations.
"We're still in the early stages of this," Masur said.
Awareness of the presence of gas in other Appalachian formations -- even deep ones -- is hardly new. Some operators, such as Anadarko Petroleum Corp., were attracted to Pennsylvania to explore other deep formations and then switched to the Marcellus. Range's first Marcellus well had targeted a deeper formation called the Lockport Dolomite.
The potential of the Marcellus has eclipsed all other formations. In the last 150 years, operators have produced 47 trillion cubic feet of gas from Appalachian wells, Pitzarella said. By comparison, the Marcellus Shale is believed to contain 500 trillion cubic feet, though the amount eventually recovered will be less.
In recent months, operators have begun to focus capital on some of the other formations.
Atlas Energy Inc. executives, before their company was sold to Chevron Corp., told analysts they were exploring the Utica formation and the Upper Devonian Shale.
"Both of these shale packages are prevalent throughout Western Pennsylvania and New York, where we have over 630,000 net acres," Atlas president Richard D. Weber said in August.
Consol Energy Inc., a Pennsylvania coal producer that last year moved aggressively into natural gas, said it had a promising Utica well last year in eastern Ohio.
Brandon Elliott, Consol's vice president for investor relations, told investors on Feb. 28 that a vertical well produced 1.5 million cubic feet of gas from a 200-foot-thick Utica layer 8,450 feet below the surface.
That production, which required no hydraulic fracturing, "actually would be greater than any of our other vertical wells that we drilled in the Marcellus," Elliot said.
Consol has budgeted $35 million to drill six more Utica wells later this year, he said.
Ultra Petroleum Corp. of Houston says the Utica Shale appears to be uneconomical beneath its acreage in northern Pennsylvania. But it plans to drill into a shallower Upper Devonian formation, the Geneseo Shale, this month.
"We're optimistic about this target, and we feel it has the potential to add significant value across a large part of our Pennsylvania acreage position," Douglas Selvius, Ultra's director of exploration, told investors.
John H. Pinkerton, chief executive of Range Resources, says he believes a lot of other companies will follow his lead into the Utica and Upper Devonian Shales.
Range is attracted to the additional shales because all three layers lie under much of its prime 700,000 Marcellus acres -- making those mineral leases equal in value to 1.5 million acres in other shale regions.
Pinkerton said production costs for the new wells would be lower than those of the original wells because many will use the same infrastructure -- the same well pads, roads, and pipelines now being installed for the Marcellus wells.
"The incremental cost to develop the Upper Devonian and Utica will be reduced by approximately one-third versus the development of these zones on a stand-alone basis," Pinkerton told analysts in March. "We believe this will allow us to continue to drive down the cost of the entire play."
The new shales also seem more promising in Western Pennsylvania areas where the Marcellus produces "wet gas" that contains liquid fuels in addition to natural gas. Those areas are considered attractive in the current market because liquids, which are valued according to oil prices, which are soaring, fetch a premium.
Some analysts say the Utica and Upper Devonian Shales have limited promise.
Subash Chandra, a Jeffries & Co. managing director, said the Utica formation "is not going to work" in much of Pennsylvania because it may not contain attractive quantities of natural gas in its deepest parts.
"The real Utica play is in Ohio, where it's shallower," he said.
As Marcellus drillers have discovered, not all shale acreage is created equal.
Encana Corp., a Canadian driller, last year pulled up stakes in Luzerne County, near Wilkes-Barre, after its wells produced disappointing results, marking what may be the productive boundary of the Marcellus.
According to industry experts, some deep Marcellus pockets on its eastern edges are "baked" -- they received too much heat over the ages and no longer contain commercial quantities of natural gas.
Halliburton Gets ExxonMobil Contract in Iraq - Shares Down 2.4%
Halliburton Gets ExxonMobil Contract in Iraq - Shares Down 2.4%
Shares of Halliburton (HAL) are down as the company said it has been awarded a contract by Exxon Mobil (XOM) Iraq Limited to provide drilling services for 15 wells in the West Qurna oil field located in Southern Iraq.
Halliburton will provide a range of well construction services utilizing three drilling rigs to safely deliver the wells, the company said in a statement.
Halliburton shares are down 2.35%, or $1.12, to $47.02.
Shares of Halliburton (HAL) are down as the company said it has been awarded a contract by Exxon Mobil (XOM) Iraq Limited to provide drilling services for 15 wells in the West Qurna oil field located in Southern Iraq.
Halliburton will provide a range of well construction services utilizing three drilling rigs to safely deliver the wells, the company said in a statement.
Halliburton shares are down 2.35%, or $1.12, to $47.02.
Aussie Official to Unions: Don't Be Greedy in Wage Demands
Aussie Official to Unions: Don't Be Greedy in Wage Demands
Monday, April 11, 2011
Asia Pulse Pte. Ltd.
Australian Resources Minister Martin Ferguson says workers' unions should not be greedy in their wage demands for workers at oil and gas plants.
A reported 30 percent jump over two-and-a-half years in the cost of hiring an offshore welder, for example, was not a sustainable rate, Mr. Ferguson said.
That kind of wage rise had already placed pressure on the offshore building industry and unions should heed some advice, he said.
"Don't kill the golden goose," Mr. Ferguson told ABC Radio on Monday.
"We are talking about a sector of industry that is now exceptionally well paid and we've got to see a stronger commitment - and I've raised this with industry - to apprenticeship training."
Mr. Ferguson was the president of the peak national union body, the Australian Council of Trade Unions, between 1990 and 1996.
He said both sides had to accept a dampening in the spiraling cost of wages and accept "a bit of give and take".
Mr. Ferguson said take-home pay wasn't the only factor to be considered.
"There are far more important issues such as training young Australians in creating long-term career opportunities through decent apprenticeships," he said.
"The wage increases that have occurred in offshore construction are unsustainable.
"Industry knows it, the commonwealth government knows it and some sections of the union movement know it."
Monday, April 11, 2011
Asia Pulse Pte. Ltd.
Australian Resources Minister Martin Ferguson says workers' unions should not be greedy in their wage demands for workers at oil and gas plants.
A reported 30 percent jump over two-and-a-half years in the cost of hiring an offshore welder, for example, was not a sustainable rate, Mr. Ferguson said.
That kind of wage rise had already placed pressure on the offshore building industry and unions should heed some advice, he said.
"Don't kill the golden goose," Mr. Ferguson told ABC Radio on Monday.
"We are talking about a sector of industry that is now exceptionally well paid and we've got to see a stronger commitment - and I've raised this with industry - to apprenticeship training."
Mr. Ferguson was the president of the peak national union body, the Australian Council of Trade Unions, between 1990 and 1996.
He said both sides had to accept a dampening in the spiraling cost of wages and accept "a bit of give and take".
Mr. Ferguson said take-home pay wasn't the only factor to be considered.
"There are far more important issues such as training young Australians in creating long-term career opportunities through decent apprenticeships," he said.
"The wage increases that have occurred in offshore construction are unsustainable.
"Industry knows it, the commonwealth government knows it and some sections of the union movement know it."
Politicians Push to Revise Oil Project Review Process
Politicians Push to Revise Oil Project Review Process
Monday, April 11, 2011
The Bakersfield Californian
by John Cox
Kern County politicians are urging Gov. Jerry Brown to ease what the local oil industry sees as a clampdown on certain drilling-related activities that state regulators view as environmentally risky.
Members of the local delegation say inexperienced bureaucrats in Sacramento have held up job creation by withholding approval of numerous oil field projects rather than keeping to longstanding if informal collaboration with industry.
State oil regulators acknowledge a slowdown in project approvals, but they blame a combination of staffing limitations, complex engineering issues and the need to follow state and federal laws protecting California drinking water.
While friction between local oil producers and regulators has remained almost constant in recent years, this latest escalation stands out both for its timing and political reach. With oil prices approaching all-time highs and employment low, newly seated local politicians are pressing Brown to prod a department that many contend has taken a more cautious direction since a leadership change in 2009.
The specific activities at issue, underground injection projects, involve pumping nonlethal fluids into new or existing oil fields. Sometimes these projects reinject substances that already exist underground, such as water or hydrogen sulfide that come up during the oil production process. Other underground injection projects introduce steam and other materials that make oil easier to draw up from below.
Slow approvals
The state Division of Oil, Gas and Geothermal Resources says it received 55 underground injection project applications in 2008, and that 93 percent of them have since been approved. In 2009, 52 applications came in, 71 percent of which have won DOGGR's approval. Fully 100 projects were formally proposed last year; 27 percent of them have been approved. (One proposed project may serve 10 or more producing oil wells.)
Most of California's proposed injection wells are in Southern California. Only 30 percent of 158 pending projects are proposed in Kern County, according to DOGGR.
DOGGR says state worker furloughs account for much of the backlog. And while a division spokesman stated that staff are mindful of industry's impatience amid strong oil prices, such projects are discretionary and require engineering analysis to make sure what is injected does not spread to unintended surrounding areas.
Spokesman Don Drysdale also noted that the division must ensure that oil fields are not damaged to the point that future generations cannot continue to recover oil.
"The division is doing its best to balance the needs of this important industry with the needs of Californians for effective environmental oversight for public health and safety," Drysdale wrote in an email.
A spokesman for the state Natural Resources Agency, which has oversight authority over the division, emphasized that DOGGR is only following the legal process, which he said is not supposed to be informal.
Special care must be taken to ensure that injected fluids do not spill out from abandoned wells nearby, spokesman Richard Stapler said.
Oil industry representatives say the state is being overcautious. Before the September 2009 arrival of Elena Miller, a lawyer who leads DOGGR as California's oil and gas supervisor, oil producers would appeal project rejections to a working group composed of various state regulators and industry representatives. They say compromises were usually worked out at such meetings.
But now, industry representatives say, not only has a wide degree of local discretion been replaced with micromanaging in Sacramento, but the division refuses to issue rejections, thereby removing the opportunity for appeal.
Les Clark, executive vice president of Bakersfield's Independent Oil Producers Agency, said a new state law governing oil spills, known as AB 1960, has complicated the review process. Still, he blames Miller for "overkill" with regard to safety, saying she insists on measures that make projects far too expensive.
Clark also said Miller and her staff have been inconsistent in what they ask of producers.
"Every time you talk with her it's a different story," he said.
Miller could not be reached for comment.
Several oil producers operating in Kern County declined to comment on the record. One that did, Chevron, cited progress in working with DOGGR.
"While we have experienced delays, we have provided extensive technical information that DOGGR requested and have began receiving permits and are getting people back to work," Chevron spokeswoman Carla Musser wrote in an email. "We are continuing to work with DOGGR on obtaining permits."
Politicians get involved
Local politicians have met with Gov. Brown's staff in an attempt to come to a resolution. They do not necessarily agree about what should be done, however.
Assemblywoman Shannon Grove, R-Bakersfield, suggested firing Miller outright.
"The governor needs to replace her with somebody who understands the oil industry," Grove said.
Two other local representatives -- State Sen. Jean Fuller, R-Bakersfield, and Sen. Michael Rubio, D-Bakersfield -- said they favor creating a clear path of approval for the industry.
Fuller said that if DOGGR's policy has changed, then the industry needs to know how.
"If it's not that, if it's a manpower issue, then we need to look at the manpower issue," she said.
Rubio said producers need to know how long the review process will take, and that more control should be given to DOGGR's local staff.
"I'm confident that very soon there will be a solution," he said, referring to comments made by the governor's staff. Fuller, Grove and the office of Assemblyman David Valadao, R-Hanford, also expressed expectations for a prompt resolution.
Efforts to reach the governor's office were unsuccessful.
Monday, April 11, 2011
The Bakersfield Californian
by John Cox
Kern County politicians are urging Gov. Jerry Brown to ease what the local oil industry sees as a clampdown on certain drilling-related activities that state regulators view as environmentally risky.
Members of the local delegation say inexperienced bureaucrats in Sacramento have held up job creation by withholding approval of numerous oil field projects rather than keeping to longstanding if informal collaboration with industry.
State oil regulators acknowledge a slowdown in project approvals, but they blame a combination of staffing limitations, complex engineering issues and the need to follow state and federal laws protecting California drinking water.
While friction between local oil producers and regulators has remained almost constant in recent years, this latest escalation stands out both for its timing and political reach. With oil prices approaching all-time highs and employment low, newly seated local politicians are pressing Brown to prod a department that many contend has taken a more cautious direction since a leadership change in 2009.
The specific activities at issue, underground injection projects, involve pumping nonlethal fluids into new or existing oil fields. Sometimes these projects reinject substances that already exist underground, such as water or hydrogen sulfide that come up during the oil production process. Other underground injection projects introduce steam and other materials that make oil easier to draw up from below.
Slow approvals
The state Division of Oil, Gas and Geothermal Resources says it received 55 underground injection project applications in 2008, and that 93 percent of them have since been approved. In 2009, 52 applications came in, 71 percent of which have won DOGGR's approval. Fully 100 projects were formally proposed last year; 27 percent of them have been approved. (One proposed project may serve 10 or more producing oil wells.)
Most of California's proposed injection wells are in Southern California. Only 30 percent of 158 pending projects are proposed in Kern County, according to DOGGR.
DOGGR says state worker furloughs account for much of the backlog. And while a division spokesman stated that staff are mindful of industry's impatience amid strong oil prices, such projects are discretionary and require engineering analysis to make sure what is injected does not spread to unintended surrounding areas.
Spokesman Don Drysdale also noted that the division must ensure that oil fields are not damaged to the point that future generations cannot continue to recover oil.
"The division is doing its best to balance the needs of this important industry with the needs of Californians for effective environmental oversight for public health and safety," Drysdale wrote in an email.
A spokesman for the state Natural Resources Agency, which has oversight authority over the division, emphasized that DOGGR is only following the legal process, which he said is not supposed to be informal.
Special care must be taken to ensure that injected fluids do not spill out from abandoned wells nearby, spokesman Richard Stapler said.
Oil industry representatives say the state is being overcautious. Before the September 2009 arrival of Elena Miller, a lawyer who leads DOGGR as California's oil and gas supervisor, oil producers would appeal project rejections to a working group composed of various state regulators and industry representatives. They say compromises were usually worked out at such meetings.
But now, industry representatives say, not only has a wide degree of local discretion been replaced with micromanaging in Sacramento, but the division refuses to issue rejections, thereby removing the opportunity for appeal.
Les Clark, executive vice president of Bakersfield's Independent Oil Producers Agency, said a new state law governing oil spills, known as AB 1960, has complicated the review process. Still, he blames Miller for "overkill" with regard to safety, saying she insists on measures that make projects far too expensive.
Clark also said Miller and her staff have been inconsistent in what they ask of producers.
"Every time you talk with her it's a different story," he said.
Miller could not be reached for comment.
Several oil producers operating in Kern County declined to comment on the record. One that did, Chevron, cited progress in working with DOGGR.
"While we have experienced delays, we have provided extensive technical information that DOGGR requested and have began receiving permits and are getting people back to work," Chevron spokeswoman Carla Musser wrote in an email. "We are continuing to work with DOGGR on obtaining permits."
Politicians get involved
Local politicians have met with Gov. Brown's staff in an attempt to come to a resolution. They do not necessarily agree about what should be done, however.
Assemblywoman Shannon Grove, R-Bakersfield, suggested firing Miller outright.
"The governor needs to replace her with somebody who understands the oil industry," Grove said.
Two other local representatives -- State Sen. Jean Fuller, R-Bakersfield, and Sen. Michael Rubio, D-Bakersfield -- said they favor creating a clear path of approval for the industry.
Fuller said that if DOGGR's policy has changed, then the industry needs to know how.
"If it's not that, if it's a manpower issue, then we need to look at the manpower issue," she said.
Rubio said producers need to know how long the review process will take, and that more control should be given to DOGGR's local staff.
"I'm confident that very soon there will be a solution," he said, referring to comments made by the governor's staff. Fuller, Grove and the office of Assemblyman David Valadao, R-Hanford, also expressed expectations for a prompt resolution.
Efforts to reach the governor's office were unsuccessful.
Cos Lining Up Leases for Marcellus Shale Properties
Cos Lining Up Leases for Marcellus Shale Properties
Monday, April 11, 2011
Knight Ridder/Tribune Business News
by Bill Utterback, Beaver County Times, Pa.
The race to find natural gas in the Marcellus shale shelf below Beaver County has become a paper chase.
Since Jan. 1, nearly 1,100 properties have been leased by two gas-producing firms, according to the Beaver County Recorder of Deeds records.
Only one new well has been drilled in 2011, and only three well-drilling permits have been issued, according to state Department of Environmental Protection records.
Overall, Beaver County has produced nearly 1,800 leases with natural gas firms and two operating wells, one struck in Marion Township in 2009 and the other struck near Lime Kiln Road in South Beaver Township in January.
The ratio of wells to leases could soon increase.
"There's no question the natural gas is there ... and the extractable amount may be greater than the original estimates," Kent Moors, a gas and energy analyst with Duquesne University's Institute for Energy and the Environment, said.
"They'll come to get the gas," Thomas Anderson, a geologist and natural gas specialist with the University of Pittsburgh. "They may not get to all those properties, but they get to a lot of them."
Moors said that "information" and a depressed natural gas market may have temporarily quieted production in Beaver County.
"There are a couple of things going on ... there's been a difference of opinion as to where the sweet spots are," Moor said, adding that as more information about Pennsylvania's potential is gathered, more firms are transferring resources from other parts of the country to Pennsylvania.
The Chesapeake Appalachia firm, headquartered in Tulsa, now holds lease agreements for more than 1,300 Beaver County properties, more than 1,000 of them acquired since Jan. 1, more than 75 since April 1.
In 2011, Chesapeake has entered lease agreements for property in Big Beaver, Brighton Township, Center Township, Chippewa Township, Darlington Township, Greene Township, Hanover Township, Hookstown, Industry and Potter Township, according to the recorder of deeds records.
Range Resources, based in Fort Worth, has nearly 500 lease agreements in Beaver County, 57 of them acquired in 2011. Range Resources has signed property deals in Big Beaver, Brighton Township, Daugherty Township, Franklin Township, Hanover Township, Independence Township, Marion Township, Raccoon Township and New Sewickley Township in 2011.
Together, the two firms have reserved properties in 17 Beaver County communities in less than four months.
Range Resources has acquired leases on 153 properties in Allegheny County since Jan. 1, including 47 in Findlay Township, 41 in North Fayette Township and 25 in Moon Township.
"It could be that (firms) have been busy (drilling) in other areas. They have their hands full right now," Anderson said. "They're doing a ton of drilling in Washington County right now, but that doesn't mean that the natural gas in Beaver County isn't very, very attractive to them."
Monday, April 11, 2011
Knight Ridder/Tribune Business News
by Bill Utterback, Beaver County Times, Pa.
The race to find natural gas in the Marcellus shale shelf below Beaver County has become a paper chase.
Since Jan. 1, nearly 1,100 properties have been leased by two gas-producing firms, according to the Beaver County Recorder of Deeds records.
Only one new well has been drilled in 2011, and only three well-drilling permits have been issued, according to state Department of Environmental Protection records.
Overall, Beaver County has produced nearly 1,800 leases with natural gas firms and two operating wells, one struck in Marion Township in 2009 and the other struck near Lime Kiln Road in South Beaver Township in January.
The ratio of wells to leases could soon increase.
"There's no question the natural gas is there ... and the extractable amount may be greater than the original estimates," Kent Moors, a gas and energy analyst with Duquesne University's Institute for Energy and the Environment, said.
"They'll come to get the gas," Thomas Anderson, a geologist and natural gas specialist with the University of Pittsburgh. "They may not get to all those properties, but they get to a lot of them."
Moors said that "information" and a depressed natural gas market may have temporarily quieted production in Beaver County.
"There are a couple of things going on ... there's been a difference of opinion as to where the sweet spots are," Moor said, adding that as more information about Pennsylvania's potential is gathered, more firms are transferring resources from other parts of the country to Pennsylvania.
The Chesapeake Appalachia firm, headquartered in Tulsa, now holds lease agreements for more than 1,300 Beaver County properties, more than 1,000 of them acquired since Jan. 1, more than 75 since April 1.
In 2011, Chesapeake has entered lease agreements for property in Big Beaver, Brighton Township, Center Township, Chippewa Township, Darlington Township, Greene Township, Hanover Township, Hookstown, Industry and Potter Township, according to the recorder of deeds records.
Range Resources, based in Fort Worth, has nearly 500 lease agreements in Beaver County, 57 of them acquired in 2011. Range Resources has signed property deals in Big Beaver, Brighton Township, Daugherty Township, Franklin Township, Hanover Township, Independence Township, Marion Township, Raccoon Township and New Sewickley Township in 2011.
Together, the two firms have reserved properties in 17 Beaver County communities in less than four months.
Range Resources has acquired leases on 153 properties in Allegheny County since Jan. 1, including 47 in Findlay Township, 41 in North Fayette Township and 25 in Moon Township.
"It could be that (firms) have been busy (drilling) in other areas. They have their hands full right now," Anderson said. "They're doing a ton of drilling in Washington County right now, but that doesn't mean that the natural gas in Beaver County isn't very, very attractive to them."
KazMunaiGas Scoops Up 4 Blocks
KazMunaiGas Scoops Up 4 Blocks
Monday, April 11, 2011
JSC KazMunai Gas Exploration Production
KazMunaiGas announced agreements reached with the JSC National Company KazMunayGas ("NC KMG") to acquire four hydrocarbon exploration contracts.
As per the agreement, KMG EP acquires the following four contracts: Temir, Teresken, Karaton-Sarkamys and the territory adjacent to Uzen and Karamandybas.
Temir and Teresken blocks are located in the Aktobe region in close proximity to the assets of Kazakhoil Aktobe LLP and Kazakhturkmunai LLP, as well as other assets, which may be of interest to KMG EP. The geographic location of the contract area has several advantages, including infrastructure and logistics.
The territory adjacent to Uzen and Karamandybas is located in the area of operations of Uzenmunaigas production facility. Block Karaton-Sarkamys is located in the Atyrau region 100km south-west of the Kulsary deposit in the area of operations of Embamunaigas production facility.
The acquisition cost of the four contracts is USD $40 million. The transactions will be financed from KMG EP's own funds.
According to the Company's estimates, the geological resources on four blocks are around 1.5 billion barrels of oil equivalent.
The terms of the contracts on the territory adjacent to Uzen and Karamandybas, Karaton-Sarkamys block and Temir, is 6 years from 2010, with the right of extension until 2019. With regard to the Teresken block, the license is for 6 years, starting in 2006, with the right of extension until 2015.
Significant synergies can be achieved through the use of the existing infrastructure of Embamunaigas and Uzenmunaigas production facilities in Atyrau and Mangistau regions, which will help to optimize capital and operating costs.
It is anticipated that the acquired assets will enhance the quality of the Company's on-shore projects portfolio and, in case of successful exploration, will increase the Company's recoverable reserves in the medium term, including Uzen and Emba groups of fields.
Askar Balzhanov, CEO of KMG EP, said, "The acquisition of these contracts is another step towards the implementation of the Company's strategy to grow via acquisitions and expansion of exploration. KMG EP has repeatedly stated its intention to purchase these four blocks, and now the agreement is reached. The Company will continue its search for highly promising assets, acquisition of which will serve the interests of all shareholders."
The acquisition was approved by the Board of Directors of KMG EP and the Board of Directors of NC KMG. Approvals of the Government regulators have been received.
The closing of the deal is expected in the second quarter of the current year.
Monday, April 11, 2011
JSC KazMunai Gas Exploration Production
KazMunaiGas announced agreements reached with the JSC National Company KazMunayGas ("NC KMG") to acquire four hydrocarbon exploration contracts.
As per the agreement, KMG EP acquires the following four contracts: Temir, Teresken, Karaton-Sarkamys and the territory adjacent to Uzen and Karamandybas.
Temir and Teresken blocks are located in the Aktobe region in close proximity to the assets of Kazakhoil Aktobe LLP and Kazakhturkmunai LLP, as well as other assets, which may be of interest to KMG EP. The geographic location of the contract area has several advantages, including infrastructure and logistics.
The territory adjacent to Uzen and Karamandybas is located in the area of operations of Uzenmunaigas production facility. Block Karaton-Sarkamys is located in the Atyrau region 100km south-west of the Kulsary deposit in the area of operations of Embamunaigas production facility.
The acquisition cost of the four contracts is USD $40 million. The transactions will be financed from KMG EP's own funds.
According to the Company's estimates, the geological resources on four blocks are around 1.5 billion barrels of oil equivalent.
The terms of the contracts on the territory adjacent to Uzen and Karamandybas, Karaton-Sarkamys block and Temir, is 6 years from 2010, with the right of extension until 2019. With regard to the Teresken block, the license is for 6 years, starting in 2006, with the right of extension until 2015.
Significant synergies can be achieved through the use of the existing infrastructure of Embamunaigas and Uzenmunaigas production facilities in Atyrau and Mangistau regions, which will help to optimize capital and operating costs.
It is anticipated that the acquired assets will enhance the quality of the Company's on-shore projects portfolio and, in case of successful exploration, will increase the Company's recoverable reserves in the medium term, including Uzen and Emba groups of fields.
Askar Balzhanov, CEO of KMG EP, said, "The acquisition of these contracts is another step towards the implementation of the Company's strategy to grow via acquisitions and expansion of exploration. KMG EP has repeatedly stated its intention to purchase these four blocks, and now the agreement is reached. The Company will continue its search for highly promising assets, acquisition of which will serve the interests of all shareholders."
The acquisition was approved by the Board of Directors of KMG EP and the Board of Directors of NC KMG. Approvals of the Government regulators have been received.
The closing of the deal is expected in the second quarter of the current year.
India to Develop Vessels to Explore Ocean Floor for Resources
India to Develop Vessels to Explore Ocean Floor for Resources
Monday, April 11, 2011
Knight Ridder/Tribune Business News
by Jacob P. Koshy, Mint, New Delhi
India plans to spend '500 crore in developing a series of specialized vessels capable of scouring deep ocean floors for minerals, metals and gas hydrates.
Several South Asian nations, including Sri Lanka, Myanmar and India, have laid claim to large but little explored swathes of the Indian Ocean for exclusive mining rights. A United Nations (UN) body is expected to decide on this later this decade.
Experts say India's limited fossil fuel resources made it necessary for the nation to develop deep-sea technological capabilities within the decade.
"We have to adequately prepare ourselves with such technology for in the future countries are unlikely to share such know-how," said a Planning Commission official, who did not want to be identified. "By the time the UN decides, we should have at least three-to-five indigenous developed vehicles that can explore the sea at different depths."
An official in the science and technology ministry, who also did not want to be identified, confirmed the program.
Key untapped mineral resources in the sea include polymetallic nodules and cobalt-rich manganese crust. The nodules, which resemble coal, contain copper, cobalt, nickel and manganese and are viewed as potential resources to meet increasing global demand for these metals. Gas hydrates are crystalline solids consisting of gas molecules, usually methane, each surrounded by a cage of water molecules, akin to ice.
According to preliminary government estimates, India has access to about 0.5 million sq. km in the Indian Ocean, which could be worth about '5,000 crore in resources.
Currently only Chennai-based National Institute of Ocean Technology has developed a robotic crawler that can plunge to 5,000m and be remote-controlled by ship to scour precious metals and minerals.
Only four other countries-- China, France, the US and Russia--have robotic vehicles that plumb those depths.
Although several private companies--mostly American--have developed robotic vehicles for similar purposes, renting them is enormously expensive.
"Along with the cost of the ship and man-days spent in launching the vehicle, it can work out to several lakhs a day," said Ananda Ramadoss, a senior researcher at the institute and a key scientist associated with developing the robotic vehicle.
Bharath Rajeshwar, a defence analyst who specializes in international mining agreements, said it was high time India embarked on a strategic, technology program to tap the ocean's wealth.
"We can't afford to go at the same pace as India's space program. The race for precious metals is going to get more vicious over the decade with a rise in electronics hardware," said Rajeshwar. "India can't afford to be an importer (of metals) forever."
Monday, April 11, 2011
Knight Ridder/Tribune Business News
by Jacob P. Koshy, Mint, New Delhi
India plans to spend '500 crore in developing a series of specialized vessels capable of scouring deep ocean floors for minerals, metals and gas hydrates.
Several South Asian nations, including Sri Lanka, Myanmar and India, have laid claim to large but little explored swathes of the Indian Ocean for exclusive mining rights. A United Nations (UN) body is expected to decide on this later this decade.
Experts say India's limited fossil fuel resources made it necessary for the nation to develop deep-sea technological capabilities within the decade.
"We have to adequately prepare ourselves with such technology for in the future countries are unlikely to share such know-how," said a Planning Commission official, who did not want to be identified. "By the time the UN decides, we should have at least three-to-five indigenous developed vehicles that can explore the sea at different depths."
An official in the science and technology ministry, who also did not want to be identified, confirmed the program.
Key untapped mineral resources in the sea include polymetallic nodules and cobalt-rich manganese crust. The nodules, which resemble coal, contain copper, cobalt, nickel and manganese and are viewed as potential resources to meet increasing global demand for these metals. Gas hydrates are crystalline solids consisting of gas molecules, usually methane, each surrounded by a cage of water molecules, akin to ice.
According to preliminary government estimates, India has access to about 0.5 million sq. km in the Indian Ocean, which could be worth about '5,000 crore in resources.
Currently only Chennai-based National Institute of Ocean Technology has developed a robotic crawler that can plunge to 5,000m and be remote-controlled by ship to scour precious metals and minerals.
Only four other countries-- China, France, the US and Russia--have robotic vehicles that plumb those depths.
Although several private companies--mostly American--have developed robotic vehicles for similar purposes, renting them is enormously expensive.
"Along with the cost of the ship and man-days spent in launching the vehicle, it can work out to several lakhs a day," said Ananda Ramadoss, a senior researcher at the institute and a key scientist associated with developing the robotic vehicle.
Bharath Rajeshwar, a defence analyst who specializes in international mining agreements, said it was high time India embarked on a strategic, technology program to tap the ocean's wealth.
"We can't afford to go at the same pace as India's space program. The race for precious metals is going to get more vicious over the decade with a rise in electronics hardware," said Rajeshwar. "India can't afford to be an importer (of metals) forever."
Google Shares Down 0.4%; Firm Agrees to Take Stake in German Solar Project
Google Shares Down 0.4%; Firm Agrees to Take Stake in German Solar Project
Shares of Google (GOOG) are down in mid-day trading as the company will pay $5.1 million to buy nearly half of a 18.7 megawatt solar project near Berlin, Bloomberg reports.
A German private-equity company agreed to sell the Internet search giant a 49% stake in the project.
Google shares are down 0.39%, or $2.25, to $575.91.
Shares of Google (GOOG) are down in mid-day trading as the company will pay $5.1 million to buy nearly half of a 18.7 megawatt solar project near Berlin, Bloomberg reports.
A German private-equity company agreed to sell the Internet search giant a 49% stake in the project.
Google shares are down 0.39%, or $2.25, to $575.91.
Sector Update: Energy Shares Lower; Crude Futures Slip Under $110 a Barrel
Sector Update: Energy Shares Lower; Crude Futures Slip Under $110 a Barrel
Energy shares are mixed to lower in mid-day trading as crude oil futures slipped throughout the morning to trade under $110 a barrel.
Light, sweet crude oil for May delivery is trading down 2.6% to $109.86 a barrel. In other energy futures, heating oil was down 1.79% to $3.26 a gallon while natural gas was up 1.44% to $4.09 per million British thermal units.
In mid-day energy news, shares of BHP Billiton (BHP) are higher as Bloomberg reports the world's largest mining company squelched speculation that it plans to buy Royal Dutch Shell's stake in Woodside Petroleum.
The Sunday Times reported Sunday that BHP was in talks with Shell, who was being advised by UBS.
BHP shares are up 1.6%, or $1.62, to $102.92.
Energy shares are mixed to lower in mid-day trading as crude oil futures slipped throughout the morning to trade under $110 a barrel.
Light, sweet crude oil for May delivery is trading down 2.6% to $109.86 a barrel. In other energy futures, heating oil was down 1.79% to $3.26 a gallon while natural gas was up 1.44% to $4.09 per million British thermal units.
In mid-day energy news, shares of BHP Billiton (BHP) are higher as Bloomberg reports the world's largest mining company squelched speculation that it plans to buy Royal Dutch Shell's stake in Woodside Petroleum.
The Sunday Times reported Sunday that BHP was in talks with Shell, who was being advised by UBS.
BHP shares are up 1.6%, or $1.62, to $102.92.
Paradigm to Acquire Navarro County Lease
Paradigm to Acquire Navarro County Lease
Monday, April 11, 2011
Paradigm O&G Inc.
Paradigm has entered into a Letter of Intent Agreement to acquire the Skinner Lease located in Navarro County, Texas.
The Skinner lease is a 70 acre lease that was previously producing 450 barrels of oil per month from 11 existing wellbores. Initially the property produced at a rate of 1500 barrels of oil per month. The Lease comes complete with fully equipped pumping units on the well bores and the necessary infrastructure to allow for production turn on.
The Company plans to rework the existing wells and test each well utilizing their Transportable Enhanced Oil Recovery Platform (T-EOR) to determine each wells production rate. Additional enhanced oil recovery techniques will then be applied. The Company believes initially production rates of 450 barrels per month can be achieved with upward growth expected with further treatment and methods.
"Since the released our Joint Venture Oil Production Program that utilizes the Transportable Enhanced Oil Recovery Platform, we have been introduced to a number of opportunities in Navarro County. With the recent signing of 2 Joint Venture Oil Production agreements and the Oil production acquisition LOI we announced on April 5, 2011 it makes sense to build our portfolio in this region," said Paradigms President and CEO Ron Polli, "We are excited about the number of opportunities we are reviewing that appear to fit our criteria and as a result are attempting to advance our activities to enable us grow our portfolio and asset value."
A definitive purchase agreement is to be completed over the next 45 days at which time terms of the agreement will be disclosed. On closing of the definitive agreement, Paradigm will be assigned the lease and operate the property under their bond.
Monday, April 11, 2011
Paradigm O&G Inc.
Paradigm has entered into a Letter of Intent Agreement to acquire the Skinner Lease located in Navarro County, Texas.
The Skinner lease is a 70 acre lease that was previously producing 450 barrels of oil per month from 11 existing wellbores. Initially the property produced at a rate of 1500 barrels of oil per month. The Lease comes complete with fully equipped pumping units on the well bores and the necessary infrastructure to allow for production turn on.
The Company plans to rework the existing wells and test each well utilizing their Transportable Enhanced Oil Recovery Platform (T-EOR) to determine each wells production rate. Additional enhanced oil recovery techniques will then be applied. The Company believes initially production rates of 450 barrels per month can be achieved with upward growth expected with further treatment and methods.
"Since the released our Joint Venture Oil Production Program that utilizes the Transportable Enhanced Oil Recovery Platform, we have been introduced to a number of opportunities in Navarro County. With the recent signing of 2 Joint Venture Oil Production agreements and the Oil production acquisition LOI we announced on April 5, 2011 it makes sense to build our portfolio in this region," said Paradigms President and CEO Ron Polli, "We are excited about the number of opportunities we are reviewing that appear to fit our criteria and as a result are attempting to advance our activities to enable us grow our portfolio and asset value."
A definitive purchase agreement is to be completed over the next 45 days at which time terms of the agreement will be disclosed. On closing of the definitive agreement, Paradigm will be assigned the lease and operate the property under their bond.
Bering to Drill Eagle Ford Wells
Bering to Drill Eagle Ford Wells
Monday, April 11, 2011
Bering Exploration Inc.
Bering will initially drill four test wells on its Eagle Ford shale play in Central Texas. The results from these initial wells will help with the design and development of a more in depth drilling program for the remaining 116 potential wells locations. These initial four wells will target the Eagle Ford, Austin Chalk, Buda and Edwards zones and based upon current prices have gross potential reserves of $11,000,000. Bering will retain a 100% working interest and an 80% net revenue interest with a two year lease term.
The Eagle Ford Shale is a shale rock formation located in multiple counties in South Texas. It underlies the Austin Chalk and is considered by geologists to be the "source rock," or the original source of hydrocarbons (oil and gas) that are now found in the Austin Chalk. Industry leaders have been quoted as saying that it has the "perfect mineralogical makeup for shale play" and one of the world's largest oil & gas companies has already called it the sixth largest domestic oil discovery in the U.S. history.
"We are very excited to begin this initial drilling program," stated Steven Plumb, Chief Financial Officer of Bering. "We expect to obtain the drilling permits in the near term and hope to be drilling soon after that. If these first four wells are successful then we expect this prospect to add significant value to our company and shareholders."
Monday, April 11, 2011
Bering Exploration Inc.
Bering will initially drill four test wells on its Eagle Ford shale play in Central Texas. The results from these initial wells will help with the design and development of a more in depth drilling program for the remaining 116 potential wells locations. These initial four wells will target the Eagle Ford, Austin Chalk, Buda and Edwards zones and based upon current prices have gross potential reserves of $11,000,000. Bering will retain a 100% working interest and an 80% net revenue interest with a two year lease term.
The Eagle Ford Shale is a shale rock formation located in multiple counties in South Texas. It underlies the Austin Chalk and is considered by geologists to be the "source rock," or the original source of hydrocarbons (oil and gas) that are now found in the Austin Chalk. Industry leaders have been quoted as saying that it has the "perfect mineralogical makeup for shale play" and one of the world's largest oil & gas companies has already called it the sixth largest domestic oil discovery in the U.S. history.
"We are very excited to begin this initial drilling program," stated Steven Plumb, Chief Financial Officer of Bering. "We expect to obtain the drilling permits in the near term and hope to be drilling soon after that. If these first four wells are successful then we expect this prospect to add significant value to our company and shareholders."
Crimson Fires Up Production at Eagle Ford Play
Crimson Fires Up Production at Eagle Ford Play
Monday, April 11, 2011
Crimson Exploration Inc.
Crimson announced the successful completion of the Littlepage McBride #1 (53.0% WI), located in Karnes County, TX and targeting the Eagle Ford Shale, commencing production in the first week of April at a gross daily rate of 876 barrels of oil and 717 Mcf of natural gas on a 14/64th choke with 2,845 psi of flowing tubing pressure. The well was drilled to a total measured depth of 15,885 feet, including a 4,800 foot lateral, and was finalized, from spud to first production, in 70 days. The Littlepage McBride represents Crimson's first well on its 1,250 gross acre position in Karnes County, which is adjacent to other significant drilling and producing activity in the oil window of the Eagle Ford play. The Company intends to follow its restricted rate philosophy, currently being utilized in the East Texas Haynesville play, in its Eagle Ford program and does not anticipate increasing the rate further, although the well performance to date suggests it is capable of much higher rates.
Allan D. Keel, President and Chief Executive Officer, commented, "The successful completion of the Littlepage McBride validates Crimson's position in the oil bearing window of the Eagle Ford Shale in Karnes County. Given this initial success in Karnes County and current crude oil prices, Crimson plans to reallocate additional capital to accelerate drilling activities in Karnes County in 2011 to optimize cash flows and shareholder return on oil weighted opportunities. We have also been fortunate enough to have obtained scheduling commitments from our drilling and completion services providers that will enable us to pursue our drilling plans for all of 2011 without delay risks related to the tight market for those services."
In Liberty County, TX, the Catherine Henderson #A-9 (66.0% WI) commenced production at the end of March at a gross daily rate of 9.6 Mmcfe, or 4.4 Mmcf, 578 barrels of condensate and 286 barrels of natural gas liquids on a 12/64th choke and 7,200 psi of flowing tubing pressure. This well was drilled to a total measured depth of 13,150 feet in the Cook Mountain formation. Crimson is currently drilling below 12,850 feet on the Catherine Henderson B-4 (64.0% WI) toward a total measured depth of 13,500 feet and is scheduled to spud the Catherine Henderson A-10 (66.0% WI) in May.
In our Bruin Prospect Area of San Augustine County, TX, we have successfully completed 14 stages of frac on the Kodiak #1 well (70% WI) in the Mid Bossier Shale and expect initial production to begin within the next two weeks. Completion operations have commenced in the Haynesville Shale formation on the Blue #1 well (70.7% WI), also in the Bruin Prospect Area, with initial production expected around the first of May.
We anticipate spudding the KM Ranch #1 well, our first Eagle Ford well in Zavala County, TX, by the beginning of May. We have approximately 4,675 gross acres (50% WI) in Zavala County that we believe to be prospective in the oil window of the Eagle Ford Shale. This operated well is expected to be drilled to a total measured depth of approximately 12,500 feet, with a projected 5,500 foot lateral.
Monday, April 11, 2011
Crimson Exploration Inc.
Crimson announced the successful completion of the Littlepage McBride #1 (53.0% WI), located in Karnes County, TX and targeting the Eagle Ford Shale, commencing production in the first week of April at a gross daily rate of 876 barrels of oil and 717 Mcf of natural gas on a 14/64th choke with 2,845 psi of flowing tubing pressure. The well was drilled to a total measured depth of 15,885 feet, including a 4,800 foot lateral, and was finalized, from spud to first production, in 70 days. The Littlepage McBride represents Crimson's first well on its 1,250 gross acre position in Karnes County, which is adjacent to other significant drilling and producing activity in the oil window of the Eagle Ford play. The Company intends to follow its restricted rate philosophy, currently being utilized in the East Texas Haynesville play, in its Eagle Ford program and does not anticipate increasing the rate further, although the well performance to date suggests it is capable of much higher rates.
Allan D. Keel, President and Chief Executive Officer, commented, "The successful completion of the Littlepage McBride validates Crimson's position in the oil bearing window of the Eagle Ford Shale in Karnes County. Given this initial success in Karnes County and current crude oil prices, Crimson plans to reallocate additional capital to accelerate drilling activities in Karnes County in 2011 to optimize cash flows and shareholder return on oil weighted opportunities. We have also been fortunate enough to have obtained scheduling commitments from our drilling and completion services providers that will enable us to pursue our drilling plans for all of 2011 without delay risks related to the tight market for those services."
In Liberty County, TX, the Catherine Henderson #A-9 (66.0% WI) commenced production at the end of March at a gross daily rate of 9.6 Mmcfe, or 4.4 Mmcf, 578 barrels of condensate and 286 barrels of natural gas liquids on a 12/64th choke and 7,200 psi of flowing tubing pressure. This well was drilled to a total measured depth of 13,150 feet in the Cook Mountain formation. Crimson is currently drilling below 12,850 feet on the Catherine Henderson B-4 (64.0% WI) toward a total measured depth of 13,500 feet and is scheduled to spud the Catherine Henderson A-10 (66.0% WI) in May.
In our Bruin Prospect Area of San Augustine County, TX, we have successfully completed 14 stages of frac on the Kodiak #1 well (70% WI) in the Mid Bossier Shale and expect initial production to begin within the next two weeks. Completion operations have commenced in the Haynesville Shale formation on the Blue #1 well (70.7% WI), also in the Bruin Prospect Area, with initial production expected around the first of May.
We anticipate spudding the KM Ranch #1 well, our first Eagle Ford well in Zavala County, TX, by the beginning of May. We have approximately 4,675 gross acres (50% WI) in Zavala County that we believe to be prospective in the oil window of the Eagle Ford Shale. This operated well is expected to be drilled to a total measured depth of approximately 12,500 feet, with a projected 5,500 foot lateral.
BHP Billiton Shoots Down Woodside Speculation
BHP Billiton Shoots Down Woodside Speculation
Monday, April 11, 2011
Dow Jones Newswires
by Robb M. Stewart & Ross Kelly
BHP Billiton on Monday quashed speculation it is preparing a multibillion-dollar bid for Woodside, even as an Australian state premier said he was directly aware of moved by unspecified companies to take over the gas producer.
BHP said in a brief statement said it knows of no basis for the speculation and that the market is "currently fully informed of all material information."
Speculation has been growing since Woodside's largest shareholder, Shell, sold some of its investment in the Australian company. Analysts have suggested BHP Billiton is a natural suitor for Woodside given its desire to expand its own oil and gas operations and Australia's reluctance to let key strategic assets fall into foreign hands. Shell's 2001 attempt to acquire Woodside outright was knocked back by Australian lawmakers on national-interest grounds.
Colin Barnett, premier of resource-rich Western Australia state, said in a press conference at an energy conference in Perth he is aware of takeover moves for Woodside as well as media reports of BHP's interest. He didn't give specifics about the companies involved.
"Woodside seems to be under siege," said Barnett in a speech given earlier in the day to energy industry executives at the conference. "I just urge you, hands off Woodside."
Woodside Chief Executive Don Voelte said the company continued to discuss with Shell how it would sell its remaining 24% stake in Woodside, but he has no knowledge of a takeover bid. "With the continuous disclosure laws in Australia, we can't hide this stuff," Voelte told reporters.
A spokeswoman for Shell in Perth declined to comment.
BHP Billiton on Monday completed the Australian off-market portion of a planned US$10 billion buyback program, buying US $6.3 billion in its own shares at a 14% discount to the market price.
The Melbourne-based company has bought US $7.8 billion in shares in Australia and the U.K. since it reinstated a buyback program late last year after abandoning a US $38.6 billion bid for Canada's Potash Corp of Saskatchewan (POT). It said it expects to repurchase a further US $2.2 billion in shares before the end of 2011.
In its statement on the Woodside speculation, BHP said it hasn't relied on a confidentiality exception in Australian listing rules. Under those rules, a repurchase program would require full disclosure from a company on anything that might affect its share price.
Woodside has four operating or planned gas-export projects that face Asia, at a time when major markets including China are striving to minimize use of coal and crude oil because of worsening pollution, and scrutiny of nuclear power is intensifying in the wake of the crisis at Japan's Fukushima nuclear plant, damaged in last month's earthquake and tsunami.
Shell in November sold a 10% stake in the Perth-based company for about US $3.3 billion, sparking speculation that BHP might buy Shell's remaining 24% stake in Woodside and launch a takeover bid.
BHP's relationship with Woodside dates back decades, and both are involved in operating the North West Shelf liquefied natural gas terminal in Western Australia state and the proposed Browse LNG project nearby. The companies' boards know each other well--Woodside Chairman Michael Chaney was a director of BHP between 1995 and 2005.
Woodside's shares have risen about 12% since the start of the year.
Monday, April 11, 2011
Dow Jones Newswires
by Robb M. Stewart & Ross Kelly
BHP Billiton on Monday quashed speculation it is preparing a multibillion-dollar bid for Woodside, even as an Australian state premier said he was directly aware of moved by unspecified companies to take over the gas producer.
BHP said in a brief statement said it knows of no basis for the speculation and that the market is "currently fully informed of all material information."
Speculation has been growing since Woodside's largest shareholder, Shell, sold some of its investment in the Australian company. Analysts have suggested BHP Billiton is a natural suitor for Woodside given its desire to expand its own oil and gas operations and Australia's reluctance to let key strategic assets fall into foreign hands. Shell's 2001 attempt to acquire Woodside outright was knocked back by Australian lawmakers on national-interest grounds.
Colin Barnett, premier of resource-rich Western Australia state, said in a press conference at an energy conference in Perth he is aware of takeover moves for Woodside as well as media reports of BHP's interest. He didn't give specifics about the companies involved.
"Woodside seems to be under siege," said Barnett in a speech given earlier in the day to energy industry executives at the conference. "I just urge you, hands off Woodside."
Woodside Chief Executive Don Voelte said the company continued to discuss with Shell how it would sell its remaining 24% stake in Woodside, but he has no knowledge of a takeover bid. "With the continuous disclosure laws in Australia, we can't hide this stuff," Voelte told reporters.
A spokeswoman for Shell in Perth declined to comment.
BHP Billiton on Monday completed the Australian off-market portion of a planned US$10 billion buyback program, buying US $6.3 billion in its own shares at a 14% discount to the market price.
The Melbourne-based company has bought US $7.8 billion in shares in Australia and the U.K. since it reinstated a buyback program late last year after abandoning a US $38.6 billion bid for Canada's Potash Corp of Saskatchewan (POT). It said it expects to repurchase a further US $2.2 billion in shares before the end of 2011.
In its statement on the Woodside speculation, BHP said it hasn't relied on a confidentiality exception in Australian listing rules. Under those rules, a repurchase program would require full disclosure from a company on anything that might affect its share price.
Woodside has four operating or planned gas-export projects that face Asia, at a time when major markets including China are striving to minimize use of coal and crude oil because of worsening pollution, and scrutiny of nuclear power is intensifying in the wake of the crisis at Japan's Fukushima nuclear plant, damaged in last month's earthquake and tsunami.
Shell in November sold a 10% stake in the Perth-based company for about US $3.3 billion, sparking speculation that BHP might buy Shell's remaining 24% stake in Woodside and launch a takeover bid.
BHP's relationship with Woodside dates back decades, and both are involved in operating the North West Shelf liquefied natural gas terminal in Western Australia state and the proposed Browse LNG project nearby. The companies' boards know each other well--Woodside Chairman Michael Chaney was a director of BHP between 1995 and 2005.
Woodside's shares have risen about 12% since the start of the year.
Coastal Strikes Oil Pay at Bua Ban North
Coastal Strikes Oil Pay at Bua Ban North
Monday, April 11, 2011
Coastal Energy Co.
Coastal announced the successful results of the Bua Ban North A-03 exploration well.
The Bua Ban North A-03 well was drilled to 5,346 feet TVD and made a discovery in the Miocene interval. The well encountered 125 feet of net pay with 28% average porosity. The A-03 tested a fault block which is south of and deeper than the Miocene discoveries in the A-01 and A-04 wells. The Company estimates that this fault block contains approximately 20 million barrels of oil in place.
The Company plans to suspend the well and then complete it with a workover rig once the MOPU arrives on location in mid-May to begin production testing.
Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The A-03 well not only significantly increases the oil in place at Bua Ban North A, but reinforces the prospectivity of this part of the basin. Coastal has now discovered an estimated 55 million barrels of oil in place with four wells in less than two months.
"We are moving the rig to Bua Ban North B while the MOPU is being mobilized to Bua Ban North A. Not only will we begin testing further Miocene targets, but we will also test the highly prospective Oligocene and Eocene targets in the northern part of the basin. During this time, we will also be able to fully evaluate the data from the first four Bua Ban North A wells and formulate a larger scale field development plan, including horizontal wells."
Monday, April 11, 2011
Coastal Energy Co.
Coastal announced the successful results of the Bua Ban North A-03 exploration well.
The Bua Ban North A-03 well was drilled to 5,346 feet TVD and made a discovery in the Miocene interval. The well encountered 125 feet of net pay with 28% average porosity. The A-03 tested a fault block which is south of and deeper than the Miocene discoveries in the A-01 and A-04 wells. The Company estimates that this fault block contains approximately 20 million barrels of oil in place.
The Company plans to suspend the well and then complete it with a workover rig once the MOPU arrives on location in mid-May to begin production testing.
Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The A-03 well not only significantly increases the oil in place at Bua Ban North A, but reinforces the prospectivity of this part of the basin. Coastal has now discovered an estimated 55 million barrels of oil in place with four wells in less than two months.
"We are moving the rig to Bua Ban North B while the MOPU is being mobilized to Bua Ban North A. Not only will we begin testing further Miocene targets, but we will also test the highly prospective Oligocene and Eocene targets in the northern part of the basin. During this time, we will also be able to fully evaluate the data from the first four Bua Ban North A wells and formulate a larger scale field development plan, including horizontal wells."
TD Reached at Premier's Ca Rong Do Appraisal
TD Reached at Premier's Ca Rong Do Appraisal
Monday, April 11, 2011
Premier Oil plc
Premier announced that the CRD-2X appraisal well in block 07/03 Vietnam has been drilled to a TD of 3785 meters MDRT, appraising the Miocene sands discovered in 2009 with the CRD-1X well.
The well was deepened from the preliminary TD of 3109 meters MDRT to evaluate the Oligocene which was not tested by the CRD-1X well. Two drill stem tests of the hydrocarbon bearing sands in the Oligocene section have been conducted. The first zone tested flowed gas and condensate at rates of 9.7 mmscfd and 870 bopd respectively through a 40/64 inch choke. The second zone tested flowed gas and condensate at rates of 17 mmscfd and 1730 bopd respectively through a 56/64 inch choke.
The well will now be sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands.
Simon Lockett, Chief Executive Officer, commented, "We are encouraged by the hydrocarbon flow rates from the Oligocene section in Ca Rong Do, which in addition to the previously proven Miocene reservoirs, provide further exploration upside across the area. We look forward to the result of the sidetrack well which will provide additional data to determine the hydrocarbon distribution in this part of the Ca Rong Do structure."
Monday, April 11, 2011
Premier Oil plc
Premier announced that the CRD-2X appraisal well in block 07/03 Vietnam has been drilled to a TD of 3785 meters MDRT, appraising the Miocene sands discovered in 2009 with the CRD-1X well.
The well was deepened from the preliminary TD of 3109 meters MDRT to evaluate the Oligocene which was not tested by the CRD-1X well. Two drill stem tests of the hydrocarbon bearing sands in the Oligocene section have been conducted. The first zone tested flowed gas and condensate at rates of 9.7 mmscfd and 870 bopd respectively through a 40/64 inch choke. The second zone tested flowed gas and condensate at rates of 17 mmscfd and 1730 bopd respectively through a 56/64 inch choke.
The well will now be sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands.
Simon Lockett, Chief Executive Officer, commented, "We are encouraged by the hydrocarbon flow rates from the Oligocene section in Ca Rong Do, which in addition to the previously proven Miocene reservoirs, provide further exploration upside across the area. We look forward to the result of the sidetrack well which will provide additional data to determine the hydrocarbon distribution in this part of the Ca Rong Do structure."
Egdon Commences Drilling Ops at Keddington Field
Egdon Commences Drilling Ops at Keddington Field
Monday, April 11, 2011
Egdon Resources plc
Egdon announced the start of drilling operations at the Keddington oil field on Lincolnshire License PEDL005(Remainder).
Egdon holds a 75% interest in and is operator of the PEDL005(Remainder) license. The joint venture partners are Terrain, holding a 15% interest and Alba, a wholly owned subsidiary of Nautical Petroleum, with a 10% interest.
The Keddington-4 well will be drilled as a re-entry and horizontal sidetrack from the Keddington-1Z "donor" well, which was drilled by Candecca Resources in 1998. This oil production well has been shut-in since the drilling of Keddington-3 and 3Z in April 2010. Keddington-4 is planned to penetrate approximately 200 meters of producing Unit 1 sandstone in a new horizontal section. The well is also planned to penetrate the deeper "Namurian" sandstones, which had gas indications in Keddington-3 to provide additional information on this potential gas bearing zone.
The British Drilling and Freezing Limited BDF28 drilling unit began mobilizing to the site on April 1, and operations began on April 4. The plugging-back of the existing well has been completed and the drilling of the sidetrack commenced at 0700 hours on April 9, from a kick-off depth of 2080 meters. The well is intended to be drilled directionally to a total measured depth of around 2750 meters. Drilling and completion operations are expected to last a total of around three weeks.
The well is expected to be completed for free-flowing or pumped production using the existing surface production facilities shortly after the rig is released from the site.
Keddington-4 is designed to increase total field production at a time of high oil prices and provide additional reservoir information in an untested part of the structure to factor into the investment decision on the scale of the gas to electricity generation project planned for the field. This is expected to provide an important additional revenue stream and eventually will enable unconstrained production of oil from the field.
Production from the adjacent Keddington-3z well has been suspended for safety reasons during the drilling operations and will resume once the rig has been demobilized from site and the flow characteristics of Keddington-4 has been determined.
Monday, April 11, 2011
Egdon Resources plc
Egdon announced the start of drilling operations at the Keddington oil field on Lincolnshire License PEDL005(Remainder).
Egdon holds a 75% interest in and is operator of the PEDL005(Remainder) license. The joint venture partners are Terrain, holding a 15% interest and Alba, a wholly owned subsidiary of Nautical Petroleum, with a 10% interest.
The Keddington-4 well will be drilled as a re-entry and horizontal sidetrack from the Keddington-1Z "donor" well, which was drilled by Candecca Resources in 1998. This oil production well has been shut-in since the drilling of Keddington-3 and 3Z in April 2010. Keddington-4 is planned to penetrate approximately 200 meters of producing Unit 1 sandstone in a new horizontal section. The well is also planned to penetrate the deeper "Namurian" sandstones, which had gas indications in Keddington-3 to provide additional information on this potential gas bearing zone.
The British Drilling and Freezing Limited BDF28 drilling unit began mobilizing to the site on April 1, and operations began on April 4. The plugging-back of the existing well has been completed and the drilling of the sidetrack commenced at 0700 hours on April 9, from a kick-off depth of 2080 meters. The well is intended to be drilled directionally to a total measured depth of around 2750 meters. Drilling and completion operations are expected to last a total of around three weeks.
The well is expected to be completed for free-flowing or pumped production using the existing surface production facilities shortly after the rig is released from the site.
Keddington-4 is designed to increase total field production at a time of high oil prices and provide additional reservoir information in an untested part of the structure to factor into the investment decision on the scale of the gas to electricity generation project planned for the field. This is expected to provide an important additional revenue stream and eventually will enable unconstrained production of oil from the field.
Production from the adjacent Keddington-3z well has been suspended for safety reasons during the drilling operations and will resume once the rig has been demobilized from site and the flow characteristics of Keddington-4 has been determined.
KazMunaiGas to Acquire 4 Exploration Contracts
KazMunaiGas to Acquire 4 Exploration Contracts
Monday, April 11, 2011
JSC KazMunai Gas Exploration Production
KazMunaiGas announced agreements reached with the JSC National Company KazMunayGas ("NC KMG") to acquire four hydrocarbon exploration contracts.
As per the agreement, KMG EP acquires the following four contracts: Temir, Teresken, Karaton-Sarkamys and the territory adjacent to Uzen and Karamandybas.
Temir and Teresken blocks are located in the Aktobe region in close proximity to the assets of Kazakhoil Aktobe LLP and Kazakhturkmunai LLP, as well as other assets, which may be of interest to KMG EP. The geographic location of the contract area has several advantages, including infrastructure and logistics.
The territory adjacent to Uzen and Karamandybas is located in the area of operations of Uzenmunaigas production facility. Block Karaton-Sarkamys is located in the Atyrau region 100km south-west of the Kulsary deposit in the area of operations of Embamunaigas production facility.
The acquisition cost of the four contracts is USD $40 million. The transactions will be financed from KMG EP's own funds.
According to the Company's estimates, the geological resources on four blocks are around 1.5 billion barrels of oil equivalent.
The terms of the contracts on the territory adjacent to Uzen and Karamandybas, Karaton-Sarkamys block and Temir, is 6 years from 2010, with the right of extension until 2019. With regard to the Teresken block, the license is for 6 years, starting in 2006, with the right of extension until 2015.
Significant synergies can be achieved through the use of the existing infrastructure of Embamunaigas and Uzenmunaigas production facilities in Atyrau and Mangistau regions, which will help to optimize capital and operating costs.
It is anticipated that the acquired assets will enhance the quality of the Company's on-shore projects portfolio and, in case of successful exploration, will increase the Company's recoverable reserves in the medium term, including Uzen and Emba groups of fields.
Askar Balzhanov, CEO of KMG EP, said, "The acquisition of these contracts is another step towards the implementation of the Company's strategy to grow via acquisitions and expansion of exploration. KMG EP has repeatedly stated its intention to purchase these four blocks, and now the agreement is reached. The Company will continue its search for highly promising assets, acquisition of which will serve the interests of all shareholders."
The acquisition was approved by the Board of Directors of KMG EP and the Board of Directors of NC KMG. Approvals of the Government regulators have been received.
The closing of the deal is expected in the second quarter of the current year.
Monday, April 11, 2011
JSC KazMunai Gas Exploration Production
KazMunaiGas announced agreements reached with the JSC National Company KazMunayGas ("NC KMG") to acquire four hydrocarbon exploration contracts.
As per the agreement, KMG EP acquires the following four contracts: Temir, Teresken, Karaton-Sarkamys and the territory adjacent to Uzen and Karamandybas.
Temir and Teresken blocks are located in the Aktobe region in close proximity to the assets of Kazakhoil Aktobe LLP and Kazakhturkmunai LLP, as well as other assets, which may be of interest to KMG EP. The geographic location of the contract area has several advantages, including infrastructure and logistics.
The territory adjacent to Uzen and Karamandybas is located in the area of operations of Uzenmunaigas production facility. Block Karaton-Sarkamys is located in the Atyrau region 100km south-west of the Kulsary deposit in the area of operations of Embamunaigas production facility.
The acquisition cost of the four contracts is USD $40 million. The transactions will be financed from KMG EP's own funds.
According to the Company's estimates, the geological resources on four blocks are around 1.5 billion barrels of oil equivalent.
The terms of the contracts on the territory adjacent to Uzen and Karamandybas, Karaton-Sarkamys block and Temir, is 6 years from 2010, with the right of extension until 2019. With regard to the Teresken block, the license is for 6 years, starting in 2006, with the right of extension until 2015.
Significant synergies can be achieved through the use of the existing infrastructure of Embamunaigas and Uzenmunaigas production facilities in Atyrau and Mangistau regions, which will help to optimize capital and operating costs.
It is anticipated that the acquired assets will enhance the quality of the Company's on-shore projects portfolio and, in case of successful exploration, will increase the Company's recoverable reserves in the medium term, including Uzen and Emba groups of fields.
Askar Balzhanov, CEO of KMG EP, said, "The acquisition of these contracts is another step towards the implementation of the Company's strategy to grow via acquisitions and expansion of exploration. KMG EP has repeatedly stated its intention to purchase these four blocks, and now the agreement is reached. The Company will continue its search for highly promising assets, acquisition of which will serve the interests of all shareholders."
The acquisition was approved by the Board of Directors of KMG EP and the Board of Directors of NC KMG. Approvals of the Government regulators have been received.
The closing of the deal is expected in the second quarter of the current year.
Circle Oil Briefs Operations at Al Amir Lease
Circle Oil Briefs Operations at Al Amir Lease
Monday, April 11, 2011
Monday, April 11, 2011
Circle Oil plc
Circle Oil announced an update regarding the Al Amir SE-7X water injector well located to the west of the Al Amir SE-4X well in the Al Amir Development Lease. Al Amir SE-7X, which started drilling on 27 November 2010, has been successfully sidetracked and has now reached target depth ("TD") at 15,600 ft measured depth ("MD") in the Lower Rudeis.
The main objectives for this well were to provide water injection support into the Kareem sands and to delineate the Kareem oil-water contact, which is required for technical reasons including resource estimation. The Kareem sands were encountered between 10,664 and 10,852 ft MD and these have been successfully cased off.
The Main Shagar Sands, encountered between 10,738 and 10,770 ft MD, were water bearing and of excellent reservoir quality. As a result Al Amir SE-7X should provide a good initial water injection well. The overlying sand stringers from 10,664 to 10,718 ft MD have indicated oil saturations on logs.
This places the deepest oil in Al Amir SE for the Kareem at approximately 10,200 ft Sub Surface, which positively corresponds with the latest estimates for the oil-water contact calculated using formation pressure data. Additional work is to be undertaken to refine this elevation. The well has been plugged back to 11,180 ft MD and is being completed as a water injector in the Kareem sands to support the updip oil producers. A further development well and water injection wells form the immediate drilling program for the Al Amir SE field.
The secondary objective of the well was to evaluate the Lower Rudeis thin sand stringers with indicated hydrocarbon saturations between 15,553 and 15,567 ft MD, which were previously encountered in the Al Amir SE-6X well. Log analysis by the operator identified 6 ft of pay with an average 10% porosity and a hydrocarbon saturation of 68%.
The decision was taken not to test this interval due to mechanical problems, but to conduct further drilling to properly evaluate the productivity of the Lower Rudeis sands.
In the drilling of the up-hole section of Al Amir SE-7X, sand stringers with potential hydrocarbon saturations containing 6 ft of potential pay were encountered in the South Gharib (5,634 to 5,645 ft MD) and a further 4 ft of potential pay in the Belayim (8,400 to 8,404 ft MD). These zones will be the subject of further evaluation in future drilling which will be undertaken to properly evaluate these positive occurrences for additional hydrocarbons in the NW Gemsa block.
During 2010 four successful wells were drilled and completed:
In addition, construction is now underway to construct facilities together with an 8-inch gas pipeline to the nearby facilities for gas export and the sale of gas and associated liquids. These facilities are expected to be completed by year end, with an associated increase in gas and liquids production.
The current production rate from the NW Gemsa fields of Geyad and Al Amir SE is approximately 7,500 bopd gross as fluid off-take from the fields is controlled in line with best reservoir management practice as the water flood is initiated, becomes operational and is proven to be effective in maximizing recovery rates. By mid 2012 the production rate is expected to rise to approximately 12,000 bopd gross as water flood operations become effective.
Gross production from start up in February 2009 through to the end of February 2011 was 4.6 MMBO. Work is currently underway on an independent third party report on ultimate recoverable resources for NW Gemsa. The results are expected during the second quarter of 2011 and will be incorporated within the Annual Report for 2010. The NW Gemsa permit, in which Circle Oil holds a 40% interest, has been a very successful venture for the Company.
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 North West Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest); and Sea Dragon Energy (10% interest).
The main objectives for this well were to provide water injection support into the Kareem sands and to delineate the Kareem oil-water contact, which is required for technical reasons including resource estimation. The Kareem sands were encountered between 10,664 and 10,852 ft MD and these have been successfully cased off.
The Main Shagar Sands, encountered between 10,738 and 10,770 ft MD, were water bearing and of excellent reservoir quality. As a result Al Amir SE-7X should provide a good initial water injection well. The overlying sand stringers from 10,664 to 10,718 ft MD have indicated oil saturations on logs.
This places the deepest oil in Al Amir SE for the Kareem at approximately 10,200 ft Sub Surface, which positively corresponds with the latest estimates for the oil-water contact calculated using formation pressure data. Additional work is to be undertaken to refine this elevation. The well has been plugged back to 11,180 ft MD and is being completed as a water injector in the Kareem sands to support the updip oil producers. A further development well and water injection wells form the immediate drilling program for the Al Amir SE field.
The secondary objective of the well was to evaluate the Lower Rudeis thin sand stringers with indicated hydrocarbon saturations between 15,553 and 15,567 ft MD, which were previously encountered in the Al Amir SE-6X well. Log analysis by the operator identified 6 ft of pay with an average 10% porosity and a hydrocarbon saturation of 68%.
The decision was taken not to test this interval due to mechanical problems, but to conduct further drilling to properly evaluate the productivity of the Lower Rudeis sands.
In the drilling of the up-hole section of Al Amir SE-7X, sand stringers with potential hydrocarbon saturations containing 6 ft of potential pay were encountered in the South Gharib (5,634 to 5,645 ft MD) and a further 4 ft of potential pay in the Belayim (8,400 to 8,404 ft MD). These zones will be the subject of further evaluation in future drilling which will be undertaken to properly evaluate these positive occurrences for additional hydrocarbons in the NW Gemsa block.
During 2010 four successful wells were drilled and completed:
- Geyad-2X ST completed as a producer in February;
- Al Amir SE-5X completed as a producer in March;
- Al Amir SE-6X completed as a producer in July; and
- Al Ola-1X completed as a producer in December.
In addition, construction is now underway to construct facilities together with an 8-inch gas pipeline to the nearby facilities for gas export and the sale of gas and associated liquids. These facilities are expected to be completed by year end, with an associated increase in gas and liquids production.
The current production rate from the NW Gemsa fields of Geyad and Al Amir SE is approximately 7,500 bopd gross as fluid off-take from the fields is controlled in line with best reservoir management practice as the water flood is initiated, becomes operational and is proven to be effective in maximizing recovery rates. By mid 2012 the production rate is expected to rise to approximately 12,000 bopd gross as water flood operations become effective.
Gross production from start up in February 2009 through to the end of February 2011 was 4.6 MMBO. Work is currently underway on an independent third party report on ultimate recoverable resources for NW Gemsa. The results are expected during the second quarter of 2011 and will be incorporated within the Annual Report for 2010. The NW Gemsa permit, in which Circle Oil holds a 40% interest, has been a very successful venture for the Company.
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 North West Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest); and Sea Dragon Energy (10% interest).
Max Petroleum Encounters Oil Pay at Zhana Makat Well
Max Petroleum Encounters Oil Pay at Zhana Makat Well
Monday, April 11, 2011
Max Petroleum plc
Max Petroleum announced that the ZMA-ET1 appraisal well in the Zhana Makat Field has reached a total depth of 1,472 meters, with electric logs indicating 22 meters of net oil pay in three Triassic sandstone reservoirs at depths ranging between 1,282 and 1,410 meters.
Reservoir quality appears excellent with porosities ranging from 18 to 26%. These reservoirs were the primary objective of this well, which appears to have successfully extended Triassic production and reserves into the southern end of the Field.
The Company is running production casing in the well, after which the Sun ZJ-30 drilling rig will move on to drill the ZMA-ET2 appraisal well further to the south of the ZMA-ET1 well, attempting to further extend Triassic production and reserves in Zhana Makat. The Company will complete and test the ZMA-ET1 well using a workover rig over the next several weeks and will announce production test results as soon as practicable.
Monday, April 11, 2011
Max Petroleum plc
Max Petroleum announced that the ZMA-ET1 appraisal well in the Zhana Makat Field has reached a total depth of 1,472 meters, with electric logs indicating 22 meters of net oil pay in three Triassic sandstone reservoirs at depths ranging between 1,282 and 1,410 meters.
Reservoir quality appears excellent with porosities ranging from 18 to 26%. These reservoirs were the primary objective of this well, which appears to have successfully extended Triassic production and reserves into the southern end of the Field.
The Company is running production casing in the well, after which the Sun ZJ-30 drilling rig will move on to drill the ZMA-ET2 appraisal well further to the south of the ZMA-ET1 well, attempting to further extend Triassic production and reserves in Zhana Makat. The Company will complete and test the ZMA-ET1 well using a workover rig over the next several weeks and will announce production test results as soon as practicable.
Gran Tierra Ups 2011 Capital Spending to Develop S. American Assets
Gran Tierra Ups 2011 Capital Spending to Develop S. American Assets
Monday, April 11, 2011
Gran Tierra Energy Inc.
Gran Tierra announced capital spending plans on the recently acquired Petrolifera Petroleum Limited ("Petrolifera") assets.
Gran Tierra Energy intends to spend approximately $55 million on the newly acquired assets with approximately $25 million in Colombia, $14 million in Peru and $16 million in Argentina. Drilling and completion costs are expected to amount to $41 million, including $14 million in Colombia, $13 million in Peru and $14 in Argentina. Seismic costs total $12 million, mostly in Colombia and facilities costs total $2 million, mostly in Argentina.
This capital program is in addition to the $299 million 2011 capital program previously announced for Colombia, Peru, Brazil and Argentina by Gran Tierra Energy, which remains unchanged. This new combined capital program of approximately $355 million for 2011 is expected to be funded from existing cash reserves and cash flow.
"Our evaluation of the new assets under management indicates that there is significant potential to grow reserves and production in the coming years. With appropriate allocation of capital, we believe we can unlock significant value from these assets," said Dana Coffield, President and Chief Executive Officer of Gran Tierra Energy.
"In Colombia, Gran Tierra Energy intends to delineate a potential gas production platform in the Lower Magdalena basin, prepare for 2012 exploration drilling in Peru, and reverse production declines in Argentina where both oil and gas prices have consistently been rising."
Colombia
Gran Tierra Energy plans to spend approximately $14 million on drilling in Colombia, including one exploration well and one delineation well with the intention of evaluating a potential gas production platform in the Lower Magdalena Basin.
Sierra Nevada Block (100% working interest and operator)
Following Gran Tierra Energy's announcement of its offer to acquire Petrolifera, GLJ Petroleum Consultants Ltd. ("GLJ") independent resource evaluators, estimated 101.5 billion cubic feet ("BCF") of United States Securities and Exchange Commission ("SEC") compliant 3P natural gas reserves (15.6 BCF 1P and 34.3 BCF 2P) at the Brillante discovery well drilled in 2010. GLJ's estimate is effective December 31, 2010.
A delineation well in the Brillante discovery is planned for the third quarter of 2011 to further define the significant potential of this discovery. A regional gas market evaluation is underway, as well as an evaluation of transportation options in the area.
The La Pinta-1 well, drilled in 2010, encountered good oil shows while drilling in the Upper Porquero reservoirs. Gran Tierra Energy plans to re-enter this well and perforate this zone to test its oil potential in the third quarter of 2011.
Gran Tierra Energy also intends to acquire approximately 170 square kilometers of 3D seismic in preparation for future exploration and development drilling on the Sierra Nevada Block.
Magdelena Block (100% working interest and operator)
Testing operations on the San Angel-1 well continue and, contingent upon successful test results, Gran Tierra Energy may acquire approximately 150 square kilometers of 3D seismic in the area.
Turpial Block (50% working interest and operator)
One exploration well is planned for the Turpial Block to evaluate the heavy oil reservoirs encountered by stratigraphic drilling in the 1970's.
Peru
In 2011, Gran Tierra Energy intends to spend approximately $13 million in preparation for drilling in early 2012.
Block 107 (100% working interest and operator)
Gran Tierra Energy believes significant resource potential exists on Block 107 in Peru. One exploration well is planned for the second quarter of 2012, with 2011 spending dedicated to planning and purchase of long lead items in preparation for 2012 drilling.
Argentina
Capital spending in Argentina will initially focus on reversing production declines on properties in the Neuquen Basin. Gran Tierra Energy plans to spend $14 million on drilling and completions in Argentina.
Puesto Morales / Puesto Morales Este (100% working interest and operator)
Gran Tierra Energy plans to conduct work-over programs on approximately 16 wells, along with drilling approximately six development wells, including three producers and three new water injectors. Gran Tierra Energy believes it can improve recovery in the existing reservoirs by minimizing water channeling in the waterflood project through the use of polymer. The budgeted work program may be adjusted to accommodate results during implementation of the program.
Production and Reserves
Including the Petrolifera assets, Gran Tierra Energy anticipates average production in 2011 to range between 17,500 and 19,000 barrels of oil equivalent ("BOE") per day, net after royalty, weighted approximately 95% to oil.
Monday, April 11, 2011
Gran Tierra Energy Inc.
Gran Tierra announced capital spending plans on the recently acquired Petrolifera Petroleum Limited ("Petrolifera") assets.
Gran Tierra Energy intends to spend approximately $55 million on the newly acquired assets with approximately $25 million in Colombia, $14 million in Peru and $16 million in Argentina. Drilling and completion costs are expected to amount to $41 million, including $14 million in Colombia, $13 million in Peru and $14 in Argentina. Seismic costs total $12 million, mostly in Colombia and facilities costs total $2 million, mostly in Argentina.
This capital program is in addition to the $299 million 2011 capital program previously announced for Colombia, Peru, Brazil and Argentina by Gran Tierra Energy, which remains unchanged. This new combined capital program of approximately $355 million for 2011 is expected to be funded from existing cash reserves and cash flow.
"Our evaluation of the new assets under management indicates that there is significant potential to grow reserves and production in the coming years. With appropriate allocation of capital, we believe we can unlock significant value from these assets," said Dana Coffield, President and Chief Executive Officer of Gran Tierra Energy.
"In Colombia, Gran Tierra Energy intends to delineate a potential gas production platform in the Lower Magdalena basin, prepare for 2012 exploration drilling in Peru, and reverse production declines in Argentina where both oil and gas prices have consistently been rising."
Colombia
Gran Tierra Energy plans to spend approximately $14 million on drilling in Colombia, including one exploration well and one delineation well with the intention of evaluating a potential gas production platform in the Lower Magdalena Basin.
Sierra Nevada Block (100% working interest and operator)
Following Gran Tierra Energy's announcement of its offer to acquire Petrolifera, GLJ Petroleum Consultants Ltd. ("GLJ") independent resource evaluators, estimated 101.5 billion cubic feet ("BCF") of United States Securities and Exchange Commission ("SEC") compliant 3P natural gas reserves (15.6 BCF 1P and 34.3 BCF 2P) at the Brillante discovery well drilled in 2010. GLJ's estimate is effective December 31, 2010.
A delineation well in the Brillante discovery is planned for the third quarter of 2011 to further define the significant potential of this discovery. A regional gas market evaluation is underway, as well as an evaluation of transportation options in the area.
The La Pinta-1 well, drilled in 2010, encountered good oil shows while drilling in the Upper Porquero reservoirs. Gran Tierra Energy plans to re-enter this well and perforate this zone to test its oil potential in the third quarter of 2011.
Gran Tierra Energy also intends to acquire approximately 170 square kilometers of 3D seismic in preparation for future exploration and development drilling on the Sierra Nevada Block.
Magdelena Block (100% working interest and operator)
Testing operations on the San Angel-1 well continue and, contingent upon successful test results, Gran Tierra Energy may acquire approximately 150 square kilometers of 3D seismic in the area.
Turpial Block (50% working interest and operator)
One exploration well is planned for the Turpial Block to evaluate the heavy oil reservoirs encountered by stratigraphic drilling in the 1970's.
Peru
In 2011, Gran Tierra Energy intends to spend approximately $13 million in preparation for drilling in early 2012.
Block 107 (100% working interest and operator)
Gran Tierra Energy believes significant resource potential exists on Block 107 in Peru. One exploration well is planned for the second quarter of 2012, with 2011 spending dedicated to planning and purchase of long lead items in preparation for 2012 drilling.
Argentina
Capital spending in Argentina will initially focus on reversing production declines on properties in the Neuquen Basin. Gran Tierra Energy plans to spend $14 million on drilling and completions in Argentina.
Puesto Morales / Puesto Morales Este (100% working interest and operator)
Gran Tierra Energy plans to conduct work-over programs on approximately 16 wells, along with drilling approximately six development wells, including three producers and three new water injectors. Gran Tierra Energy believes it can improve recovery in the existing reservoirs by minimizing water channeling in the waterflood project through the use of polymer. The budgeted work program may be adjusted to accommodate results during implementation of the program.
Production and Reserves
Including the Petrolifera assets, Gran Tierra Energy anticipates average production in 2011 to range between 17,500 and 19,000 barrels of oil equivalent ("BOE") per day, net after royalty, weighted approximately 95% to oil.
Halliburton Secures ExxonMobil Contract for West Qurna Development
Halliburton Secures ExxonMobil Contract for West Qurna Development
Monday, April 11, 2011
Halliburton
Halliburton has been awarded a contract by ExxonMobil Iraq Limited (EMIL) to provide drilling services for 15 wells in the West Qurna (Phase I) oil field located in Southern Iraq.
Halliburton will provide a complete range of well construction services utilizing three drilling rigs to safely deliver the wells.
Joe Rainey, president of Halliburton's Eastern Hemisphere operations, said, "This contract award is a testament to the ongoing success of our Eastern Hemisphere growth strategy and is in addition to work awarded in this field by this customer in 2010."
Monday, April 11, 2011
Halliburton
Halliburton has been awarded a contract by ExxonMobil Iraq Limited (EMIL) to provide drilling services for 15 wells in the West Qurna (Phase I) oil field located in Southern Iraq.
Halliburton will provide a complete range of well construction services utilizing three drilling rigs to safely deliver the wells.
Joe Rainey, president of Halliburton's Eastern Hemisphere operations, said, "This contract award is a testament to the ongoing success of our Eastern Hemisphere growth strategy and is in addition to work awarded in this field by this customer in 2010."
Seadrill Adds Ultra-Deepwater Dual Derrick Drillship to Fleet
Seadrill Adds Ultra-Deepwater Dual Derrick Drillship to Fleet
Monday, April 11, 2011
Seadrill Ltd.
Seadrill has exercised an option to build a new ultra-deepwater dual derrick drillship at the Samsung yard in South Korea. Total project price is estimated at US $600 million (includes project management, drilling and handling tools, spares, capitalized interest and operations preparations). The delivery is scheduled for the third quarter 2013.
The new unit is similar to the two drillships Seadrill ordered from Samsung in November 2010 with enhanced water depth capacity, technical capabilities as well as increased accommodation capacity compared to previous generation drillships.
The dynamic positioning drillship, will be capable of operations in water depths up to 12,000 feet, and will have a hook load capability of 1,250 tons. This rig is also outfitted with seven ram configuration of the BOP (Blow Out Preventer) stack, especially targeting operations in challenging areas such as the Gulf of Mexico, Brazil and West Africa. Furthermore, the drillship will be equipped with a 165 ton capacity heave compensated crane enhancing the unit's operational flexibility and facilitating lifts on the seabed in water depths up to 3,000 meters.
Seadrill has simultaneously secured an extension of the maturity date for a further option agreement to build its seventh drillship to be delivered from Samsung since 2008. Seadrill has currently no specific plan to exercise this option, but might consider it if the strong underlying trend currently seen in the deep water market continues.
Alf C Thorkildsen, Chief Executive Officer of Seadrill Management AS, said, "The decision to add another ultra-deepwater newbuild to our modern fleet is based on the recent improvement in market outlook for ultra-deepwater units, with significantly more tender activities. The new drillship has an attractive delivery window, a favorable construction price and payment schedule and an equipment specification list that will meet our customers' future needs. We have had excellent experience with the Samsung yard and this design and are confident that the unit will be delivered on time and budget once again."
"The strengthening of Seadrill's equity basis through the recently announced bond conversion creates financial flexibility for growing the company further without raising additional equity. The current long-term dayrates give a healthy return on the investment, with further upside if the market strengthens as a result of the strong trend in the oil price.
The project will based on current dayrates and anticipated financing increase Seadrill's dividend capacity going forward. The ordering of the new drillship further confirms Seadrill's commitment to remain a growth company, with the target of reaching US $3 billion in EBITDA in the coming years."
Monday, April 11, 2011
Seadrill Ltd.
Seadrill has exercised an option to build a new ultra-deepwater dual derrick drillship at the Samsung yard in South Korea. Total project price is estimated at US $600 million (includes project management, drilling and handling tools, spares, capitalized interest and operations preparations). The delivery is scheduled for the third quarter 2013.
The new unit is similar to the two drillships Seadrill ordered from Samsung in November 2010 with enhanced water depth capacity, technical capabilities as well as increased accommodation capacity compared to previous generation drillships.
The dynamic positioning drillship, will be capable of operations in water depths up to 12,000 feet, and will have a hook load capability of 1,250 tons. This rig is also outfitted with seven ram configuration of the BOP (Blow Out Preventer) stack, especially targeting operations in challenging areas such as the Gulf of Mexico, Brazil and West Africa. Furthermore, the drillship will be equipped with a 165 ton capacity heave compensated crane enhancing the unit's operational flexibility and facilitating lifts on the seabed in water depths up to 3,000 meters.
Seadrill has simultaneously secured an extension of the maturity date for a further option agreement to build its seventh drillship to be delivered from Samsung since 2008. Seadrill has currently no specific plan to exercise this option, but might consider it if the strong underlying trend currently seen in the deep water market continues.
Alf C Thorkildsen, Chief Executive Officer of Seadrill Management AS, said, "The decision to add another ultra-deepwater newbuild to our modern fleet is based on the recent improvement in market outlook for ultra-deepwater units, with significantly more tender activities. The new drillship has an attractive delivery window, a favorable construction price and payment schedule and an equipment specification list that will meet our customers' future needs. We have had excellent experience with the Samsung yard and this design and are confident that the unit will be delivered on time and budget once again."
"The strengthening of Seadrill's equity basis through the recently announced bond conversion creates financial flexibility for growing the company further without raising additional equity. The current long-term dayrates give a healthy return on the investment, with further upside if the market strengthens as a result of the strong trend in the oil price.
The project will based on current dayrates and anticipated financing increase Seadrill's dividend capacity going forward. The ordering of the new drillship further confirms Seadrill's commitment to remain a growth company, with the target of reaching US $3 billion in EBITDA in the coming years."
Chevron Sells Shell Stake in Wheatstone Project
Chevron Sells Shell Stake in Wheatstone Project
Monday, April 11, 2011
Monday, April 11, 2011
Chevron Corp.
Chevron announced the signing of agreements with Shell Development (Australia) Pty Ltd to bring Shell into the Chevron-operated Wheatstone Project as a natural gas supplier and equity participant.
George Kirkland, vice chairman, Chevron Corporation, said, "Chevron is pleased to welcome another participant into the Wheatstone Project. The Wheatstone hub will provide a reliable new source of energy to Australia and the region. It will also further enhance Chevron's position as a leading supplier of liquefied natural gas (LNG) in Asia-Pacific."
Under the unitization agreement with Chevron's Australian subsidiaries, Shell will assume an 8 percent participating interest in the Wheatstone and Iago natural gas fields in the Chevron-operated permits WA-253-P, WA-17-R and WA-16-R, located offshore northwest Australia.
The Wheatstone and Iago gas fields will supply Trains 1 and 2 of the Wheatstone Project, located onshore at Ashburton North in Western Australia.
Shell will also assume a 6.4 percent participating interest in the project facilities, with Chevron remaining project operator.
Chevron Australia managing director, Roy Krzywosinski, said front-end engineering and design (FEED) activity on the Wheatstone Project is nearing completion.
"The Wheatstone Project is set to become one of Australia's largest resource projects and Australia's first LNG hub. A final investment decision is expected in the second half of this year once environmental approvals and other associated agreements are finalized with various levels of government."
The first phase of the Wheatstone Project consists of two LNG processing trains with a combined capacity of 8.9 million tonnes per annum (MTPA) and a domestic gas plant.
George Kirkland, vice chairman, Chevron Corporation, said, "Chevron is pleased to welcome another participant into the Wheatstone Project. The Wheatstone hub will provide a reliable new source of energy to Australia and the region. It will also further enhance Chevron's position as a leading supplier of liquefied natural gas (LNG) in Asia-Pacific."
Under the unitization agreement with Chevron's Australian subsidiaries, Shell will assume an 8 percent participating interest in the Wheatstone and Iago natural gas fields in the Chevron-operated permits WA-253-P, WA-17-R and WA-16-R, located offshore northwest Australia.
The Wheatstone and Iago gas fields will supply Trains 1 and 2 of the Wheatstone Project, located onshore at Ashburton North in Western Australia.
Shell will also assume a 6.4 percent participating interest in the project facilities, with Chevron remaining project operator.
Chevron Australia managing director, Roy Krzywosinski, said front-end engineering and design (FEED) activity on the Wheatstone Project is nearing completion.
"The Wheatstone Project is set to become one of Australia's largest resource projects and Australia's first LNG hub. A final investment decision is expected in the second half of this year once environmental approvals and other associated agreements are finalized with various levels of government."
The first phase of the Wheatstone Project consists of two LNG processing trains with a combined capacity of 8.9 million tonnes per annum (MTPA) and a domestic gas plant.
Statoil Starts Up Taps at Peregrino Field
Statoil Starts Up Taps at Peregrino Field
Monday, April 11, 2011
Statoil
Last week Statoil started oil production at the large Peregrino field offshore Brazil. Production will gradually ramp up to a plateau of 100,000 barrels of oil equivalent per day.
The move makes Statoil an important long-term operator and partner in Brazil's attractive and growing oil and gas industry.
"We are proud to announce the safe and efficient start-up of Statoil's largest international operatorship to date. The project team and our partners have done an excellent job in delivering a complex project according to the plan and below costs .
With the Peregrino field in full operation Statoil will be the second-largest operator in Brazil, and it offers us an excellent opportunity for future growth in the country.
The Peregrino field is a legacy asset and will contribute significantly to both Statoil and Brazil's oil production for many years to come," said Helge Lund, president and CEO of Statoil.
The Peregrino field is located 85 kilometers offshore Brazil in the Campos basin at about 100 meters of water depth in licenses BMC-7 and BMC-47.
The first phase of the development includes two drilling and wellhead platforms and a large floating production, storage and offload unit (FPSO). A total of 37 wells are planned, all of them using advanced horizontal well technology to maximize recovery.
The field contains 300 to 600 recoverable million barrels of oil equivalents, with a significant yet-to-find potential. An exploration well is currently being drilled at Peregrino South to explore this potential. Following completion of this well, one additional well will be drilled in the area.
Statoil's country manager in Brazil, Kjetil Hove, commented that the start up of production at Peregrino is an important milestone for the company, "The development and start up is the result of very competent colleagues' tireless efforts and excellent cooperation with partners and authorities. We now look forward to continue working with our Brazilian partners to run safe and reliable operations and to unlock the resource potential of the larger Peregrino area."
"The Peregrino field showcases our project management, execution and subsurface and reservoir management skills. We are using our experience gained at the Norwegian continental shelf to share competence and experience and to create value locally in Brazil," added Hove.
The field was discovered in 1994. Statoil acquired a 50% stake in the discovery in 2005, and the remaining 50% and its operatorship in 2008. The Peregrino development plan was approved by the Brazilian authorities in 2007.
In May 2010 Statoil sold a 40% stake of the Peregrino field to the Sinochem Group. Statoil holds 60% ownership and the operatorship of the field and Sinochem the remaining 40%. The closing of the transaction is pending governmental approvals.
Monday, April 11, 2011
Statoil
Last week Statoil started oil production at the large Peregrino field offshore Brazil. Production will gradually ramp up to a plateau of 100,000 barrels of oil equivalent per day.
The move makes Statoil an important long-term operator and partner in Brazil's attractive and growing oil and gas industry.
"We are proud to announce the safe and efficient start-up of Statoil's largest international operatorship to date. The project team and our partners have done an excellent job in delivering a complex project according to the plan and below costs .
With the Peregrino field in full operation Statoil will be the second-largest operator in Brazil, and it offers us an excellent opportunity for future growth in the country.
The Peregrino field is a legacy asset and will contribute significantly to both Statoil and Brazil's oil production for many years to come," said Helge Lund, president and CEO of Statoil.
The Peregrino field is located 85 kilometers offshore Brazil in the Campos basin at about 100 meters of water depth in licenses BMC-7 and BMC-47.
The first phase of the development includes two drilling and wellhead platforms and a large floating production, storage and offload unit (FPSO). A total of 37 wells are planned, all of them using advanced horizontal well technology to maximize recovery.
The field contains 300 to 600 recoverable million barrels of oil equivalents, with a significant yet-to-find potential. An exploration well is currently being drilled at Peregrino South to explore this potential. Following completion of this well, one additional well will be drilled in the area.
Statoil's country manager in Brazil, Kjetil Hove, commented that the start up of production at Peregrino is an important milestone for the company, "The development and start up is the result of very competent colleagues' tireless efforts and excellent cooperation with partners and authorities. We now look forward to continue working with our Brazilian partners to run safe and reliable operations and to unlock the resource potential of the larger Peregrino area."
"The Peregrino field showcases our project management, execution and subsurface and reservoir management skills. We are using our experience gained at the Norwegian continental shelf to share competence and experience and to create value locally in Brazil," added Hove.
The field was discovered in 1994. Statoil acquired a 50% stake in the discovery in 2005, and the remaining 50% and its operatorship in 2008. The Peregrino development plan was approved by the Brazilian authorities in 2007.
In May 2010 Statoil sold a 40% stake of the Peregrino field to the Sinochem Group. Statoil holds 60% ownership and the operatorship of the field and Sinochem the remaining 40%. The closing of the transaction is pending governmental approvals.
Schlumberger launches telemetry-enabled slickline platform
Schlumberger launches telemetry-enabled slickline platform
11 April 2011
Scandinavian Oil and Gas
Houston. Schlumberger has declared the launch of LIVE* digital slickline services. At their core is a slickline cable engineered to deliver two-way digital communication. Coupled with an extensive suite of purpose-built downhole modules, LIVE technology enables tool and well information to be measured and transmitted to surface in real time.
"LIVE digital slickline services enable oil and gas producers to manage well intervention and workover programs with increased knowledge, accuracy and certainty when running slickline," said Claude Durocher, vice president, Schlumberger Slickline Services, which now integrates the Geoservices slickline organization.
"While maintaining the benefits of standard slickline simplicity, digital slickline provides a new level of real-time precision and control to an expanded range of services, delivering an increased level of quality, safety and efficiency."
In parallel with LIVE slickline, a number of purpose-built downhole tools have been developed with all data available at surface in real time.
Basic tool measurements include toolstring shock, deviation, movement and head tension. Additional measurements of gamma ray and casing collar location (CCL) enable precise depth correlation relative to reservoir or completion architecture. The option of borehole pressure and temperature measurements is also available.
A surface-controlled interactive jar and tool release device brings precision to any slickline jarring and fishing operation. To complete the digital slickline platform, additional tools have been developed, capitalizing on telemetry functionality and control capabilities. These allow electro-hydraulic explosive-free tool setting, surface-activated perforation control, and complete production logging to be carried out safely and efficiently.
More than 450 field operations have been performed to date in North America, Europe, Africa and Asia in a wide range of well types, fluids and deviations, including borehole temperatures up to 275 deg F, pressures up to 8000 psi and depths down to 16,000 feet.
11 April 2011
Scandinavian Oil and Gas
Houston. Schlumberger has declared the launch of LIVE* digital slickline services. At their core is a slickline cable engineered to deliver two-way digital communication. Coupled with an extensive suite of purpose-built downhole modules, LIVE technology enables tool and well information to be measured and transmitted to surface in real time.
"LIVE digital slickline services enable oil and gas producers to manage well intervention and workover programs with increased knowledge, accuracy and certainty when running slickline," said Claude Durocher, vice president, Schlumberger Slickline Services, which now integrates the Geoservices slickline organization.
"While maintaining the benefits of standard slickline simplicity, digital slickline provides a new level of real-time precision and control to an expanded range of services, delivering an increased level of quality, safety and efficiency."
In parallel with LIVE slickline, a number of purpose-built downhole tools have been developed with all data available at surface in real time.
Basic tool measurements include toolstring shock, deviation, movement and head tension. Additional measurements of gamma ray and casing collar location (CCL) enable precise depth correlation relative to reservoir or completion architecture. The option of borehole pressure and temperature measurements is also available.
A surface-controlled interactive jar and tool release device brings precision to any slickline jarring and fishing operation. To complete the digital slickline platform, additional tools have been developed, capitalizing on telemetry functionality and control capabilities. These allow electro-hydraulic explosive-free tool setting, surface-activated perforation control, and complete production logging to be carried out safely and efficiently.
More than 450 field operations have been performed to date in North America, Europe, Africa and Asia in a wide range of well types, fluids and deviations, including borehole temperatures up to 275 deg F, pressures up to 8000 psi and depths down to 16,000 feet.
Statoil temporarily suspended production at Njord and Visund
Statoil temporarily suspended production at Njord and Visund
11 April 2011
Scandinavian Oil and Gas
Oslo. Production on the Njord field in the Norwegian Sea has been temporarily suspended as a safety precaution due to internal damage to flexible risers. The damage was detected during a scheduled inspection.
Statoil has also found it necessary to conduct special investigations at Visund, and this installation will therefore also be shut down today.
In the autumn of 2010, faults were discovered on some of the risers on the Njord A platform. An extraordinary inspection programme was therefore initiated. The inspection was performed visually by means of video camera that was sent down the risers.
Suspended production Risers are pipes that carry oil and gas between the seabed and the installation. They are constructed of multiple layers of plastic and steel.
The current challenges are limited to a specific type of riser technology.
Internal damage of this type does not threaten the structural integrity of the risers, but over time it will reduce resistance to leakage. The risers are therefore immediately removed from operation when damage is detected.
'Damaged risers will be shut down until they have been repaired or replaced. The rest will be shut down until they have been inspected and found satisfactory,' says Jannicke Hilland, Head of Joint Operations.
Njord has been shut down since 1 April, whereas Visund will be shut down today. The shutdown results in suspended production on the fields. The total field production for Njord is some 70 000 barrels of oil equivalent (boe), whereas the production on the Visund field totals about 50 000 boe. The inspection is still in progress, and the production will be phased in as the risers have been inspected and approved.
The Norwegian Petroleum Directorate (NPD) and the Petroleum Safety Authority Norway (PSA) have been informed of the matter.
Other installations Equivalent risers are in use also on other installations on the Norwegian continental shelf: Veslefrikk, Snorre A and B, Norne, Åsgard A and B and Glitne are Statoil-operated fields belonging to this category. On these installations, however, the risers are connected to a pipeline system on the seabed which reduces the risk of damage.
There have been no known incidents or observations in the operating period that suggest damage to risers here.
Risers on all installations are subject to continuous monitoring and routine inspections in keeping with applicable inspection programmes.
Statoil had a meeting with the PSA this afternoon, describing the riser challenges. The company has also appointed a taskforce to identify actions that solve the operating challenges that the involved risers present. The taskforce addresses challenges across the Statoil group.
11 April 2011
Scandinavian Oil and Gas
Oslo. Production on the Njord field in the Norwegian Sea has been temporarily suspended as a safety precaution due to internal damage to flexible risers. The damage was detected during a scheduled inspection.
Statoil has also found it necessary to conduct special investigations at Visund, and this installation will therefore also be shut down today.
In the autumn of 2010, faults were discovered on some of the risers on the Njord A platform. An extraordinary inspection programme was therefore initiated. The inspection was performed visually by means of video camera that was sent down the risers.
Suspended production Risers are pipes that carry oil and gas between the seabed and the installation. They are constructed of multiple layers of plastic and steel.
The current challenges are limited to a specific type of riser technology.
Internal damage of this type does not threaten the structural integrity of the risers, but over time it will reduce resistance to leakage. The risers are therefore immediately removed from operation when damage is detected.
'Damaged risers will be shut down until they have been repaired or replaced. The rest will be shut down until they have been inspected and found satisfactory,' says Jannicke Hilland, Head of Joint Operations.
Njord has been shut down since 1 April, whereas Visund will be shut down today. The shutdown results in suspended production on the fields. The total field production for Njord is some 70 000 barrels of oil equivalent (boe), whereas the production on the Visund field totals about 50 000 boe. The inspection is still in progress, and the production will be phased in as the risers have been inspected and approved.
The Norwegian Petroleum Directorate (NPD) and the Petroleum Safety Authority Norway (PSA) have been informed of the matter.
Other installations Equivalent risers are in use also on other installations on the Norwegian continental shelf: Veslefrikk, Snorre A and B, Norne, Åsgard A and B and Glitne are Statoil-operated fields belonging to this category. On these installations, however, the risers are connected to a pipeline system on the seabed which reduces the risk of damage.
There have been no known incidents or observations in the operating period that suggest damage to risers here.
Risers on all installations are subject to continuous monitoring and routine inspections in keeping with applicable inspection programmes.
Statoil had a meeting with the PSA this afternoon, describing the riser challenges. The company has also appointed a taskforce to identify actions that solve the operating challenges that the involved risers present. The taskforce addresses challenges across the Statoil group.
Oil moves through $113 a barrel
Oil moves through $113 a barrel
April 11, 2011
Elsewhere across the Middle East, however, political unrest raged over the weekend, killing dozens and leaving many wounded.
April 11, 2011
By Virginia Harrison , MarketWatch
SYDNEY (MarketWatch) — Crude-oil futures edged back up in electronic trading on Monday, but news of a possible peace agreement in Libya helped limit gains in Asian trading hours.
The benchmark contract for Nymex light sweet crude for May delivery /quotes/comstock/21n!f:cl\k11 (CLK11 112.42, -0.37, -0.33%) added 27 cents, or 0.2%, to $113.06 a barrel.
The benchmark contract for Nymex light sweet crude for May delivery /quotes/comstock/21n!f:cl\k11 (CLK11 112.42, -0.37, -0.33%) added 27 cents, or 0.2%, to $113.06 a barrel.
Gadhafi meets with African leaders
A delegation from the African Union meets with Libyan leader Moammar Gadhafi over the weekend in a diplomatic effort to stop the bloodshed in Libya. Video courtesy of Reuters.
Crude prices have increased by more than 23% this year, according to data from FactSet.
A delegation from the African Union meets with Libyan leader Moammar Gadhafi over the weekend in a diplomatic effort to stop the bloodshed in Libya. Video courtesy of Reuters.
Crude prices have increased by more than 23% this year, according to data from FactSet.
Prolonged geopolitical uncertainty and violence in North Africa and the Middle East has been a driving factor behind the soaring oil price.
But on Monday, there were reports that embattled Libyan leader Col. Moammar Gadhafi had agreed to a cease-fire put forward by the African Union.
The reports cited South African President Jacob Zuma as saying Gadhafi had accepted a peace plan to end the conflict in Libya, which began after violent protests broke out in February. See report on Libyan peace plan.
Asian stocks struggle to eke out gains as investors worry about surging oil prices
Asian stocks struggle to eke out gains as investors worry about surging oil prices
April 11 ,2011
By AssociatedPress
HONG KONG — Most Asian stock markets fell Monday as investors continued to worry about soaring oil prices and Japan’s struggle to recover from its worst-ever earthquake.
Japan’s Nikkei 225 stock average dipped 0.5 percent to 9,717.84 while South Korea’s Kospi edged down 0.3 percent to 2,121.49. Benchmarks in Taiwan, Singapore and India also fell while Hong Kong’s Hang Seng index was nearly flat at 24,397.44.
Australia’s S&P/ASX 200 was up 0.7 percent at 4,972.70 while mainland China’s Shanghai Composite Index rose 0.7 percent to 3,051.38.
Oil prices hovered at 30-month highs near $113 a barrel Monday in Asia as traders eyed a wobbly U.S. dollar and fresh Middle East tension.
“Oil prices are now at levels that have historically acted as a marked constraint on global output,” Daragh Maher, a foreign exchange strategist at Credit Agricole CIB, said in a research note.
Benchmark oil for May delivery slipped 11 cents to $112.68 a barrel in electronic trading on the New York Mercantile Exchange. The contract rose $2.49, or 2.3 percent, to settle at $112.79 on Friday and set new 30-month highs almost every day last week.
Oil-related stocks were benefiting from the rising prices. Sinopec, Asia’s largest refiner by capacity, was up 2.4 percent to $4.10 Hong Kong dollars while PetroChina, the country’s biggest oil and gas producer, jumped 4 percent.
Companies with big fuel bills, like airlines, were suffering. Korean Air Lines Co. Ltd. dropped 3.7 percent, Qantas Airways Ltd. fell 2.7 percent, and Cathay Pacific Airways Ltd. was down 0.9 percent.
Oil moved higher as the dollar plunged against other major currencies. Oil is traded in dollars and tends to rise when the greenback falls and makes crude cheaper for investors holding foreign currency.
Some analysts were warning investors to avoid shares in Japanese automakers, whose production was severely curtailed by power outages and supply chain disruptions following the March 11 earthquake and tsunami. The twin disasters decimated the country’s northeastern coast, causing $310 billion in damage, killing up to 25,000 people and setting off a radiation leak at a nuclear power plant that was still not under control.
“We have turned bearish on the auto sector,” Citigroup Global Markets said in a report. The company said that the full extent of damage to the industry “is being underestimated by the market ... and we would avoid the sector as things stand.”
Shares of Toyota Motor Corp., the world’s No. 1 automaker, tumbled 2.5 percent. Nissan Motor Corp. drooped 2.2 percent, and Honda Motor Corp., slid 1.9 percent.
Japanese shares also fell after a report showed that machinery orders fell 2.4 percent in February, before the devastating earthquake and tsunami struck. Orders had risen 4.2 percent in January.
Chinese shares rose after the country reported a small trade surplus of $140 million in March, up from a deficit of $7.3 billion the month before.
“Chinese trade balance figures came out above analysts’ forecasts and provided some support to the Shanghai Composite, which is currently the best performer in the region,” said Chris Weston, a research analyst at IG Markets.
Oil prices are a concern in China, but there’s “still much liquidity, which means the stock market can still go higher,” said Linus Yip, chief strategist at First Shanghai Securities.
In New York on Friday, stocks were weighed down by oil prices as well as the threat of a government shutdown. But that risk was averted after the market closed when lawmakers agreed to a last-minute deal to cut about $38 billion in federal spending.
The Dow Jones industrial average lost 0.2 percent to close at 12,380.05. The Standard & Poor’s 500 index slipped 0.4 percent to 1,328.17. The Nasdaq composite lost 0.6 percent to 2,780.42.
In currencies, the dollar slipped to 84.79 yen from 84.89 yen late Friday. The euro stood at $1.4460, up from $1.4435 late Friday, its strongest level since January 2010.
April 11 ,2011
By AssociatedPress
HONG KONG — Most Asian stock markets fell Monday as investors continued to worry about soaring oil prices and Japan’s struggle to recover from its worst-ever earthquake.
Japan’s Nikkei 225 stock average dipped 0.5 percent to 9,717.84 while South Korea’s Kospi edged down 0.3 percent to 2,121.49. Benchmarks in Taiwan, Singapore and India also fell while Hong Kong’s Hang Seng index was nearly flat at 24,397.44.
Australia’s S&P/ASX 200 was up 0.7 percent at 4,972.70 while mainland China’s Shanghai Composite Index rose 0.7 percent to 3,051.38.
Oil prices hovered at 30-month highs near $113 a barrel Monday in Asia as traders eyed a wobbly U.S. dollar and fresh Middle East tension.
“Oil prices are now at levels that have historically acted as a marked constraint on global output,” Daragh Maher, a foreign exchange strategist at Credit Agricole CIB, said in a research note.
Benchmark oil for May delivery slipped 11 cents to $112.68 a barrel in electronic trading on the New York Mercantile Exchange. The contract rose $2.49, or 2.3 percent, to settle at $112.79 on Friday and set new 30-month highs almost every day last week.
Oil-related stocks were benefiting from the rising prices. Sinopec, Asia’s largest refiner by capacity, was up 2.4 percent to $4.10 Hong Kong dollars while PetroChina, the country’s biggest oil and gas producer, jumped 4 percent.
Companies with big fuel bills, like airlines, were suffering. Korean Air Lines Co. Ltd. dropped 3.7 percent, Qantas Airways Ltd. fell 2.7 percent, and Cathay Pacific Airways Ltd. was down 0.9 percent.
Oil moved higher as the dollar plunged against other major currencies. Oil is traded in dollars and tends to rise when the greenback falls and makes crude cheaper for investors holding foreign currency.
Some analysts were warning investors to avoid shares in Japanese automakers, whose production was severely curtailed by power outages and supply chain disruptions following the March 11 earthquake and tsunami. The twin disasters decimated the country’s northeastern coast, causing $310 billion in damage, killing up to 25,000 people and setting off a radiation leak at a nuclear power plant that was still not under control.
“We have turned bearish on the auto sector,” Citigroup Global Markets said in a report. The company said that the full extent of damage to the industry “is being underestimated by the market ... and we would avoid the sector as things stand.”
Shares of Toyota Motor Corp., the world’s No. 1 automaker, tumbled 2.5 percent. Nissan Motor Corp. drooped 2.2 percent, and Honda Motor Corp., slid 1.9 percent.
Japanese shares also fell after a report showed that machinery orders fell 2.4 percent in February, before the devastating earthquake and tsunami struck. Orders had risen 4.2 percent in January.
Chinese shares rose after the country reported a small trade surplus of $140 million in March, up from a deficit of $7.3 billion the month before.
“Chinese trade balance figures came out above analysts’ forecasts and provided some support to the Shanghai Composite, which is currently the best performer in the region,” said Chris Weston, a research analyst at IG Markets.
Oil prices are a concern in China, but there’s “still much liquidity, which means the stock market can still go higher,” said Linus Yip, chief strategist at First Shanghai Securities.
In New York on Friday, stocks were weighed down by oil prices as well as the threat of a government shutdown. But that risk was averted after the market closed when lawmakers agreed to a last-minute deal to cut about $38 billion in federal spending.
The Dow Jones industrial average lost 0.2 percent to close at 12,380.05. The Standard & Poor’s 500 index slipped 0.4 percent to 1,328.17. The Nasdaq composite lost 0.6 percent to 2,780.42.
In currencies, the dollar slipped to 84.79 yen from 84.89 yen late Friday. The euro stood at $1.4460, up from $1.4435 late Friday, its strongest level since January 2010.
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