PA Resources Kicks Off Lille John Drilling

- PA Resources Kicks Off Lille John Drilling

Friday, September 09, 2011
PA Resources

The oil and gas group PA Resources continues its drilling campaign in Licence 12/06 in the Danish North Sea with the commencement of drilling of an exploration well at the Lille John prospect.

In July an exploration well was drilled on the Broder Tuck prospect on the Danish License 12/06 and gas and condensate was discovered. In August, a side track encountered additional hydrocarbons. The well has now been plugged and abandoned.

The drilling rig ENSCO 70 has mobilized to the Lille John prospect, approximately 8 kilometres south of Broder Tuck, and the drilling of the second exploration well in this drilling programme has now commenced.

The well has targets at three levels; Miocene, Chalk and Middle Jurassic. Lille John is hoped to contain both oil and gas.

The following companies participate in Licence 12/06: PA Resources UK Limited (64%), Nordsøfonden (Danish North Sea Fund) (20%), Danoil Exploration A/S (8%) and Spyker Energy APS (a wholly-owned subsidiary of Spyker Energy Plc) (8%).

Oil & Gas Post

Promote Your Page Too
LINK

African Petroleum Finds Drilling Success Off Liberia

- African Petroleum Finds Drilling Success Off Liberia

Friday, September 09, 2011
African Petroleum

African Petroleum has completed drilling the first well (Apalis-1) in deep water offshore Liberia in Block LB-09.

The results of Apalis-1 confirm Blocks LB-08 and LB-09 (100% owned by African Petroleum) are located in a prospective oil basin, which is a major step forward. The geological and geophysical data have confirmed the critical components of a working hydrocarbon system are present and functioning. The Company is now accelerating a multi well drilling program on the 25+ exploration prospects identified on Blocks LB-08 & LB-09 offshore Liberia and are planning to drill the next well during 4th quarter 2011 and 1st quarter 2012.

Apalis-1 was drilled to a depth of 3665 meters and encountered oil shows in several geological units including the shallower (Tertiary) and deeper (Cretaceous) and petrophysical analysis indicates the presence of hydrocarbons. The well also confirmed the presence of organic oil prone source rocks confirming that Blocks LB-08 & LB-09 are in an attractive oil basin.

No commercial quality reservoir with hydrocarbons was encountered and consequently no well production test was undertaken.

The well was drilled without any technical problems and the costs have been materially under budget.

Having confirmed a working hydrocarbon system with the first well the forward exploration programme will focus on the deeper basinal zone where improved reservoir quality is anticipated in the well-developed Cretaceous fan system.

Karl Thompson, CEO, comments that “This is the first the first ever frontier well in the deep water in Liberia and has confirmed we are exploring in a highly prospective oil basin which was its key objective and we are committed to continuing exploration in the area”.

SIERRA LEONE

The 3D seismic survey underway in Block SL-03 Sierra Leone (100% owned by African Petroleum) to the west of the Anadarko Venus and Mercury discoveries is progressing well and is now 65% complete. The 3D survey is the start of the initial exploration phase in exploring for similar Upper Cretaceous targets as the nearby Mercury and Venus discoveries.

GAMBIA

The interpretation of the 3D seismic survey in The Gambia (60% owned by African Petroleum) is progressing very well and an extensive system of Upper Cretaceous fan systems has clearly been identified.

African Petroleum is one of the largest net exploration holders in the West African Upper Cretaceous Exploration fairway and is making continued progress in acquiring new exploration licences.

Oil & Gas Post

Promote Your Page Too
LINK

Fluor, Shell Kick Off Malampaya Project

- Fluor, Shell Kick Off Malampaya Project

Tuesday, August 30, 2011
Fluor Corporation

Fluor Corporation on Aug. 29 announced today that its Fluor Offshore Solutions unit recently participated in the project kickoff and ceremonial contract signing in Batangas City for the Malampaya next phase development. The Malampaya Deepwater Gas-to-Power project for the Philippine Department of Energy (DOE) (operated by Shell Philippines Exploration on behalf of Service Contract [SC] 38 joint venture partners—Chevron Malampaya and Philippine National Oil Company) is among the most significant in the Philippines because it currently generates up to 40 percent of the power for the main island of Luzon. In addition to DOE, SC38 and Fluor senior executives, Philippine President Benigno Aquino III participated in the event.

“Our depth of talented and skilled project and technical staff in the Philippines developed over the past 20-plus years fits well with Shell’s needs on this project,” said Lee Richardson, vice president of Fluor Offshore Solutions. “Fluor is focused on utilizing local craft and professional labor, and we are pleased to have been selected to work with Shell and their partners on this important project.”

“Fluor is eager to undertake this groundbreaking energy project that will be the first to be designed, engineered, procured, fabricated and installed in the Philippines by local contractors,” said Dan Spinks, general manager of Fluor’s Philippines operations center.

The Malampaya project is in its third phase and encompasses the new installation of a depletion compression platform that is linked by a bridge to the existing shallow water platform. Fluor is responsible for the topsides and substructure. The project is under way with expected completion in late 2015.

Fluor previously provided ongoing engineering services for the existing shallow water platform from 2000 to 2006, and more recently, conducted a hazard and operability (HAZOP) analysis for Shell.

Fluor Offshore Solutions also recently completed offshore projects in the East Timor Sea and off the northeast coast of China.

Oil & Gas Post

Promote Your Page Too
LINK

Cobalt Kicks Off Drilling Ops Offshore Angola

- Cobalt Kicks Off Drilling Ops Offshore Angola

Monday, August 29, 2011
Cobalt International Energy Inc.
by SubseaIQ

Cobalt provided the following update on its West Africa drilling program.

Cobalt has initiated drilling operations on its Cameia No. 1 well in Block 21, Offshore Angola. Well operations are being conducted with the Diamond Ocean Confidence drilling rig. After drilling and evaluating the Cameia-1 prospect, Cobalt will drill the Bicuar-1A well to test the Bicuar prospect, also in Block 21. Both wells are targeting pre-salt objectives.

As previously announced, Cobalt expects each well to take 80 to 100 days to drill and an additional 10 to 20 days to evaluate, if successful. Cobalt is the operator of Cameia and Bicuar and has a 40% working interest in each prospect.

Oil & Gas Post

Promote Your Page Too
LINK

ConocoPhillips Finds New Leaks Off China's Northern Coast

- ConocoPhillips Finds New Leaks Off China's Northern Coast



Aug 26, 2011

ConocoPhillips (NYSE:COP) has found seven new leaks off China's northern coast.

According to the State Oceanic Administration's North China Sea branch, ConocoPhillips found the new leaks near the Platform C of 19-3 Oilfeld in Bohai Bay.

Last week, the company reported nine leaks near the same platform, and is facing legal action for the spills.

ConocoPhillips (NYSE:COP) has a potential upside of 28.9% based on a current price of $64.24 and an average consensus analyst price target of $82.8.

Oil & Gas Post

Promote Your Page Too
LINK

Anadarko Executive: Drilling First Deep-Water Well Off Liberia

- Anadarko Executive: Drilling First Deep-Water Well Off Liberia

Thursday, August 18, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Anadarko plans an aggressive deep-water exploration campaign worldwide over the next year and a half, the head of the company's exploration unit said Wednesday.

"The inventory of opportunities we have is better than it's ever been," Bob Daniels, Anadarko's senior vice president of Worldwide Exploration, said during a speech webcast from an investor conference in Denver. "We will continue with a very aggressive exploration program around the world."

The Houston company's success in Ghana, where it last year brought the vast Jubilee discovery into production, has spread into neighboring West African nations, he said. In addition to offshore exploration in Sierra Leone and the Ivory Coast, Anadarko is drilling Liberia's first deep-water well at the company's Montserrado prospect.

Judging from seismic data and other geologic factors, the Montserrado prospect "is a look-alike" to the Jubilee discovery, Daniels said.

Jubilee is estimated to hold the equivalent of between 600 million and 1.5 billion barrels of oil.

In all, Anadarko plans 15 deep-water exploration and appraisal wells in West African waters, Daniels said.

In East Africa, where Anadarko has already made a huge natural gas discovery off Mozambique, the company holds some 14 million acres. Daniels said Anadarko will bring a second rig to Mozambique in the fourth quarter and anticipates drilling prospects off Kenya, where Anadarko has leased "most of the deep water," next year.

Deep-water exploration is also slated to begin off New Zealand next year, he said.

"In the deep-water Gulf of Mexico, we have an inventory of discoveries and we have a very, very deep portfolio of exploration wells to drill," Daniels said.

The second-largest acreage holder in the U.S. Gulf of Mexico, Anadarko plans five deep-water exploration wells there this year and between six and eight exploration and appraisal wells next year.

In the last three weeks Anadarko has obtained three drilling permits from U.S. regulators, he said.

"That's very good progress in that we now have some confidence that when we apply for a permit we know about how long its going to take," he said. "That allows us to then put rig contracts in place."

Permits have been difficult to come by since last year's deadly Deepwater Horizon disaster. Anadarko was a minority owner of BP's doomed well, which blew out and caused the worst offshore oil spill in U.S. history.

Anadarko said last month that it has agreed to jointly develop its Lucius field in the Gulf with ExxonMobil, which has its own big discoveries a few miles away. Lucius is believed to hold 300 million barrels of high-quality crude and Daniels said he expects the project to be sanctioned by the end of this year with first production planned for 2014.

Copyright (c) 2011 Dow Jones & Company, Inc.

Oil & Gas Post

Promote Your Page Too
LINK

WesternGeco Kicks Off 3D Seismic Survey in Barents Sea

- WesternGeco Kicks Off 3D Seismic Survey in Barents Sea

Thursday, August 18, 2011
Schlumberger Ltd.

WesternGeco has begun acquisition of the Bjørnøya Phase I "Ice Bear" 3D multiclient survey in the highly prospective West Loppa area of the Barents Sea.

Following previous surveys in the area, the Ice Bear survey will extend the existing WesternGeco West Loppa datasets to the North and West.

"The study area is located on the rim of the Bjørnøya Basin, on the west flank of the Loppa High and includes a large downthrown terrace in the North together with other Jurassic faulted structures, all of which have potential," said Phil Davey, WesternGeco Europe & Africa GeoSolutions manager, "Other, separate, but still promising features are seen in the southwestern part of the survey area."

Building on previous 2D datasets, the Ice Bear survey will consist of approximately 2500 sq km of 3D seismic data, acquired using 10 X 7 km streamers. Advanced acquisition techniques coupled with demultiple processing using the WesternGeco 3D GSMP General Surface Multiple Prediction technology will provide high-quality 3D data.

Acquisition commenced on July 10, 2011, and the fast-track data will be available in November 2011 in time for nominations for the 22nd Norwegian Licensing Round. The final processed data will be available for licensing in March 2012 in advance of the applications for the 22nd Norwegian Offshore Licensing Round. Companies are invited to contact WesternGeco to discuss their interest in this program.

Oil & Gas Post

Promote Your Page Too
LINK

Devon Energy's Barnett Shale Bet Pays Off

- Devon Energy's Barnett Shale Bet Pays Off

Monday, August 15, 2011
Fort Worth Star-Telegram, Texas
by Jack Z. Smith

Ten years ago Sunday, Devon Energy made a multibillion-dollar bet on the Barnett Shale.

On Aug. 14, 2001, the Oklahoma City-based oil and gas company announced a deal to acquire Mitchell Energy & Development of Houston for $3.5 billion.

Mitchell Energy, led by legendary oilman George Mitchell, was the pioneering company that cracked the code of the Barnett's dense shale rock by using new hydraulic fracturing techniques and experimenting with horizontal drilling. At the time, it had drilled about 400 wells in the Barnett, and executives saw the potential for 1,200.

But over the decade, Devon would advance the ball significantly with improved horizontal drilling and an expansion of drilling far beyond areas north of Fort Worth where Mitchell Energy had focused. The result would be a drilling boom that by 2008 would draw numerous rivals into the field and make the Barnett the biggest gas-producing area in the U.S. Tarrant and Johnson counties would emerge as the top two gas-producing counties in Texas.

Today, Devon has drilled more than 4,700 wells in the Barnett. The field now accounts for 39 percent of the company's total production, which includes operations that stretch to the Rocky Mountains and into Canada.

In the Barnett, "our drilling costs are down, our production is up and our efficiencies are increasing," said Brad Foster, senior vice president of Devon's Central Division, which includes Barnett operations.

Devon has achieved, or is on the verge of, several Barnett milestones:

It posted record production in this year's second quarter, averaging the equivalent of 1.28 billion cubic feet of gas per day, even while keeping only 12 drilling rigs busy. That's less than a third as many as it ran in 2008, before gas prices cratered.

Devon's total Barnett production since the Mitchell acquisition is expected to hit the equivalent of 3 trillion cubic feet by year's end, spokesman Chip Minty said. It's at 2.8 trillion now.

Despite weak gas prices, now about $4 per 1,000 cubic feet, Devon is realizing solid returns from the Barnett because "our ability to drill wells economically just gets better every year," said Chairman Larry Nichols, who was CEO during the Mitchell acquisition.

A 35-well pad site

Devon's advances in the Barnett are exemplified at a rural 12-acre drilling site in far southwest Tarrant County. The 31st well there was drilled last week by contractor Patterson-UTI Drilling Co.

Devon expects to have 35 producing wells at the site by March, said Jay Ewing, its manager of Barnett well completions.

That will be the most wells ever on a single Barnett Shale pad site, but the project development has "been pretty routine. ... It's been pretty close to plan," Ewing said. Horizontal legs of the wells, called "laterals," will be steered thousands of feet under Benbrook Lake.

Devon estimates that the 350 Barnett wells it drills this year will yield, on average, the equivalent of 3.2 billion cubic feet of gas apiece over their producing lifetimes. By that measure, the 35 at the southwest Tarrant pad site cumulatively would produce 112 billion cubic feet.

That's enough fuel for gas heating and cooking at more than 1.5 million homes for a year, based on American Gas Association data.

If Devon maintains its current drilling pace, it will drill its 5,000th well next year. Less than 1 percent of Devon's Barnett wells have been dry or otherwise not worth putting into production.

Devon, which has more than 600 Barnett employees and an office in downtown Fort Worth, has boosted its Barnett reserves for seven straight years. Proven reserves are now the equivalent of 6.7 trillion cubic feet.

Drilling time slashed

When Devon began drilling in the Barnett in 2002, it took three to six weeks to drill a single horizontal well, said David Fortenberry, Devon vice president of technology.

"The rigs we used were really too small and underpowered for horizontal wells," he said.

Now, with higher-efficiency rigs and much more experience, Devon averages only about 12 days to drill a Barnett well, and "we've actually drilled some wells down in southwest Johnson County in about six days," Foster said.

Drilling-rig design "has improved dramatically in the past 10 years," with rigs now "ideally suited to drill these horizontal wells," Nichols said.

Devon uses a "walking rig" device to scoot a 156-foot-high rig between surface well bores at its southwest Tarrant pad site. If well bores are 20 feet apart, the rig can move that far in just an hour. Without the walking device, it could take two days to disassemble a rig and set it up 20 feet away.

The Barnett wells that Devon has drilled this year have provided "some of the best results we've ever gotten," Nichols said.

Supply rises, prices fall

Ample supplies from dramatic increases in U.S. shale-gas production have kept prices low, as the industry has become "in part ... a victim of our own success," Nichols said.

Devon has dropped to 12 drilling rigs because it can keep production at least flat at that level of activity and because "at this time, the country just doesn't need any more natural gas," Nichols said.

Production declines have been lower than expected in Barnett wells, he said. There will be "steep declines in the first year, but it flattens out a lot sooner than we originally thought" -- often after 12 to 18 months of production, he said.

The Barnett may soon lose its spot as the top gas-producing area, if it hasn't been already, to the Haynesville Shale in northwest Louisiana and East Texas. But Devon has lots more drilling to do in the Barnett.

7,500 drill sites left

Foster said Devon still has "7,500 potential drilling locations," which represent "probably over 20 years of inventory" for future drilling.

About 2,500 are in "the liquids-rich portion of the play," Foster said. Natural gas liquids such as ethane, propane and butane generate higher profit margins.

Future gas prices will determine how many of the 7,500 locations are eventually drilled, he said.

On average, drilling and completing a Barnett well costs Devon $2.8 million. Wells are 6,500 to 9,200 feet deep, and the average lateral length is more than 4,000 feet.

Devon's Barnett production is 78 percent natural gas, 21 percent natural gas liquids, and 1 percent oil.

In announcing Devon's purchase of Mitchell Energy 10 years ago, Nichols said the Mitchell properties "fit perfectly with our long-term objectives."

That appears perhaps even more so now, as Devon has sold international and Gulf of Mexico properties in the last two years as it embraces a new focus on onshore production in North America.

Copyright (c) 2011, Fort Worth Star-Telegram, Texas

Oil & Gas Post

Promote Your Page Too
LINK

TGS Kicks Off Seismic Survey in Faroe-Shetland Basin

- TGS Kicks Off Seismic Survey in Faroe-Shetland Basin

Tuesday, August 02, 2011
TGS-NOPEC Geophysical Co. ASA

TGS has commenced a new multi-client 3D survey in the Faroe-Shetland Basin. The survey covers 2,500 km(2) west of the British Isles over quads 6004, 204 and 205 and is acquired in partnership with PGS.

The new seismic data is being acquired by the PGS Ramform Viking towing 12 X 6,000 m with 75 m separation and utilizes PGS' GeoStreamer Technology. Data acquisition will continue through Q3 2011 and the vessel will return in 2012 to complete the survey. Data processing will be performed by both TGS and PGS. "This is TGS' first investment in a 3D multi-client seismic program west of the British Isles, located in an area with a number of discoveries and further undiscovered hydrocarbon potential," stated Kjell Trommestad, SVP Europe & Russia for TGS.

Oil & Gas Post

Promote Your Page Too

Range Kicks Off Trinidad Well Program

- Range Kicks Off Trinidad Well Program

Thursday, July 28, 2011
Range Resources Ltd.

Range announced that in less than 2 months from the acquisition of 100% of the Trinidad assets, the Company has commenced its 21 development well program utilizing 3 of the Company's rigs and is targeting an increase in production to between 1,400-1,800 bopd, an increase and reclassification of reserves along with extending the limits of the existing fields.

Rig 1 was recently inspected and re-certified for drilling by the Ministry of Energy and has been mobilized to spud in the coming days, Rig 2 is due for inspection and re-certification this week, soon followed by Rig 3, with both then immediately mobilized to join Rig 1 in the development well program.

Range Executive Director Peter Landau commented, "The Company is extremely pleased at the swift progress made since acquiring the Trinidad assets, with the operational team in Trinidad now being able to look to maximize the potential of the assets, something they have wanted to progress for a number of years but were restrained through a lack of capital earmarked for development."

Oil & Gas Post

Promote Your Page Too
LINK

Jubilant Kicks Off Appraisal Ops at India Block

- Jubilant Kicks Off Appraisal Ops at India Block

Tuesday, July 19, 2011
Jubilant Energy N.V.

Jubilant has spudded the Srikantabari well (S-1) on July 18, 2011 in the Tripura block. This is the first well to appraise the Kathachari-1 (K-1) discovery. The well is located 4 kms north east and up-dip from K-1 and 3 kms south west and down dip of the ONGC's discovery in TMD-1 well (flowed approximately 1.7 mmscfd). The well will be deviated by 650 meters to the south west and will be drilled to a total depth of 3100 meters true vertical depth subsea. The well, which is being drilled by Quippo Oil & Gas Infrastructure Limited, is estimated to take 65 days to drill and will cost approximately USD 11 million on gross basis, excluding the testing cost.

The well will be drilled using managed pressure drilling due to high pressure in the region. This well will test the Middle Bhuban Sands encountered in the K-1 well, one zone of which had flowed 5.2 mmscfd. These sands are expected to be encountered approximately 800 meters up-dip of the K-1 sands. The well is the first deviated well to be drilled by Jubilant and is the fourth well to be drilled on the block.

Management's best estimate of gross un-risked prospective resources is 800 bcf for a deviated well compared to previous estimate of 480 bcf for drilling S-1 as a vertical well, as in the deviated well it is expected to encounter an additional sand package.

Further, as part of the Katharchari-1 appraisal program (which was approved by The Director General of Hydrocarbons in February 2011), Jubilant has completed seismic data acquisition of 160 lkm prior to the onset of the rainy season. The remainder of the survey will commence after the rainy season and will be completed by September 2011. This work was carried out in the southern part of the block, in and around the Katharchari-1 discovery well. Pursuant to the initial work program, the total seismic survey length was 137 lkm, which was later extended to 180 lkm.

Jubilant is the operator of this block and holds a 20% participating interest, through its wholly owned subsidiary Jubilant Oil and Gas Private Limited in India.

Oil & Gas Post

Promote Your Page Too
LINK

American Standard Kicks Off Permian Basin Drilling Program

- American Standard Kicks Off Permian Basin Drilling Program

Wednesday, July 13, 2011
American Standard Energy Corp.

American Standard has commenced a 10 net well drilling program in Andrews County, Texas.

ASEN plans to drill the University Andrews 42 #2 well to the Devonian formation and then subsequent wells will be drilled to the Strawn formation and completed in the Strawn, Wolfcamp, Spraberry and Lower Clearfork formations. The Company will own 100% working interests in all 10 wells.

The Company anticipates the Viking Rig #20 to move in the latter part of this week to the University Andrews 42 #2 well to begin this drilling program.

ASEN has engaged Cambrian Management, Ltd. ("Cambrian") to oversee the drilling program and completion of these wells. Cambrian is widely recognized in the industry for its track record for highly successful drilling and completion of Wolfberry wells in the Permian Basin over the past 10 years.

Upon completion, ASEN's wells will be turned over to our affiliated partner XOG Operating for ongoing operations. Utilizing this relationship for our operations will provide cost control and reliable operations with a seasoned operator with 30 years of experience operating in the Permian Basin of west Texas.

ASEN currently produces over 800 barrels of oil equivalent per day (BOEPD) from 27.67 net wells in the Permian, Bakken and Eagle Ford combined. This initial drilling program is expected to increase our net well count by more than 35%, and is expected to increase daily production by more than 100% in the first quarter 2012, to a projected cumulative production of approximately 2,000 BOEPD.

Scott Feldhacker, CEO of ASEN commented on the potential impact of this drilling program on the Company's growth outlook. "We are optimistic that these 10 wells will have a significant impact on the growth prospects for ASEN. We hold a high number of potential drilling sites in the Permian today with 100% working interests, which allow ASEN to control its growth outlook and capital budget expenditures."

Oil & Gas Post

Promote Your Page Too
LINK

Breitling Kicks Off Drilling at Tx. Well

- Breitling Kicks Off Drilling at Tx. Well

Tuesday, July 12, 2011
Breitling O&G Corp.

Breitling O&G has spud the Breitling-Big Tex #2 on July 9, 2011 in Gaines County, Texas. The Breitling-Big Tex #2 is the second of three Big Tex prospect wells to be drilled. A completion rig is moving on location to complete the Big Tex #1 after it reached total vertical depth on July 6, 2011.

Just like the Big Tex #1, the Breitling-Big Tex #2 is a 9,000-foot vertical well within the established Tex-Pac Field and is targeting Lower Clearfork Dolomite beneath 8,500 feet. Secondary objectives include the San Andres, Yates, Glorieta and Abo formations.

Breitling's 3-Well Breitling-Big Tex Prospect was developed after a 75-square-mile 3D seismic shoot was reprocessed and interpreted in 2010. The quality of the new data set after it was re-imaged using Breitling's proprietary Geo3D technology identified features that were not noticeable when the shoot first occurred. In essence, the resultant seismic lines were much more detailed and refined, therefore capturing subsurface images not previously acknowledged.

Management anticipates the first well will reach total depth in about 20 days. Well completion and testing should begin during the first week of August.

Breitling Oil and Gas CEO Chris Faulkner stated, "We are excited to be drilling ahead of our original timelines." Faulkner added, "The Big Tex #1 looks promising and we expect the Big Tex #2 to be relatively the same as far as shows and the logs."

Oil & Gas Post

Promote Your Page Too
LINK

NPD Kicks Off Seismic Survey in Barents Sea

- NPD Kicks Off Seismic Survey in Barents Sea

Friday, July 08, 2011
Norwegian Petroleum Directorate

Just after midnight on July 8, the Norwegian Petroleum Directorate (NPD) started acquisition of seismic data in Norway's new maritime zone in the Barents Sea.

PGS will be conducting the acquisition on behalf of the NPD using the vessel R.V. Harrier Explorer.

This is the first time this area will be systematically mapped. The seismic acquisition activity will continue until the first half of September 2011, with a possible extension of a couple of weeks. The acquisition will be 2D seismic, which means that one long streamer – 8100 meters – is fastened to the vessel. The seismic lines have variable spacing – from 5 to 15 kilometers.

NPD geophysicist and project coordinator Lars Jensen tells us that the sea area to be mapped is quite large. He says that the NPD plans to complete acquisition of seismic data next summer so that the results will be ready in the spring of 2013.

The data acquisition will take place using PGS' GeoStreamer technology. This is a new technology for seismic acquisition, characterized in part by the fact that the streamer is towed somewhat deeper in the water than is the case in conventional seismic acquisition. This means that the cable can withstand higher waves, making the acquisition activity less weather-dependent and thus more efficient.

The Harrier Explorer is coming from Jan Mayen, where the vessel has been shooting seismic for the NPD for about 3.5 weeks. So far, Lars Jensen is pleased with the GeoStreamer technology, and says that the acquisition activity has gone very well and with no weather delays.

The acquisition will start with five SSE-NNW lines. The plan is then to acquire a few lines in the north-south direction in order to complete the southernmost part of the area first.

Daily reports will be issued from Vardø radio stating the position of the seismic vessel for the next 24 hours.

Oil & Gas Post

Promote Your Page Too
LINK

Transocean: Rig Off Ghana Remains Stable after Taking On Water

- Transocean: Rig Off Ghana Remains Stable after Taking On Water

Friday, July 08, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Transocean said Thursday that the deep-water drilling rig off Ghana that was evacuated Wednesday after it took on water remains stable.

The company is working on unmooring the Transocean Marianas, which is anchored some 46 miles offshore, and plans to tow it to sheltered water to inspect damage, spokesman Guy Cantwell said.

It will likely be at least a week before a full damage assessment can be made, Cantwell said.

There have been no injuries and a skeleton crew remain aboard the vessel, Cantwell said. And because the rig was not drilling when it began taking on water, there is no risk of an oil spill.

Transocean owned the Deepwater Horizon, which exploded last year while drilling a well for BP in the Gulf of Mexico, killing 11 and touching off the worst offshore oil spill in U.S. history. Since then Transocean has faced scrutiny over its safety procedures and maintenance of the world's largest offshore drilling fleet.

More than 100 workers were evacuated from the Marianas on Wednesday when it was discovered to have taken on water. A semisubmersible rig, the Marianas floats on large ballast tanks, or pontoons, which are filled with water for stability during drilling and emptied to ease transport. It was built in 1976 and upgraded to drill in depths up to 7,000 feet in 1998.

The rig had been drilling for ENI and was in the process of being moved to drill an exploration well for Kosmos Energy and partners that include Anadarko, Tullow Oil and Ghana's national oil company.

The Marianas was expected to arrive on site next week and Kosmos on Thursday asked Ghana for more time to begin drilling the prospect while it searches for a new rig.

The loss of income from the Marianas, which earned $450,000 a day on its contract with ENI, will likely trim Transocean's earnings by 15 cents per share this year, analysts with Tudor, Pickering, Holt & Co. said in a client note.

"As of now we are assuming rig does not work for rest of 2011," the Houston-based analysts said.

Copyright (c) 2011 Dow Jones & Company, Inc.

Oil & Gas Post

Promote Your Page Too
LINK

Debate on Gas Drillers' Impact Fee Put Off

- Debate on Gas Drillers' Impact Fee Put Off

Wednesday, June 29, 2011
The Morning Call, Allentown, Pennsylvania
by John L. Micek, The Morning Call, Allentown, Pa.

Hours after a threatened veto, Republicans who control the state House pulled the plug Tuesday on a planned debate over a local impact fee for natural gas drillers, saying they'll take up the issue this fall.

The 180-degree turn came as lawmakers worked to put the final pieces of a $27.15 billion budget into place so they could send it to Gov. Tom Corbett before the new fiscal year starts on Friday.

At a news conference, the GOP governor said he wants lawmakers to wait to debate any impact fee bill until after a Marcellus Shale commission submits its report next month on the effects of drilling.

"I have sent this message back: If something gets to my desk, it will be vetoed," Corbett said.

The budget cleared a major hurdle as the Senate voted 30-20 along straight party lines to approve it, positioning it for a vote by the House as soon as Wednesday.

Also on Tuesday, House and Senate Democrats withdrew their opposition to funding bills for Penn State, Temple and Lincoln universities and the University of Pittsburgh, and the veterinary school at the University of Pennsylvania, mustering the two-thirds majority needed for approval.

Democrats in the two chambers withheld their votes for the schools Monday, complaining they hadn't had time to review the details of the sprawling main budget bill. Once that happened overnight and into Tuesday, the Democrats said they were prepared to withdraw their opposition. In short order, the House and Senate separately voted to approve the appropriations.

A key budget bill governing how the state regulates public education and a bill known as the fiscal code, which implements the spending in the main budget, were also moved into place. The House advanced the fiscal code bill, positioning it for a vote Wednesday. The school code bill cleared the Senate on a 33-17 vote and went to the House for approval.

During lengthy debate in the Senate, Democrats repeated arguments that the budget, which trims overall state spending by about 3 percent largely through more than $1.1 billion in cuts to public schools and 18 universities, would result in reduced services for the needy and the aged, tuition hikes for college students and local property tax increases for homeowners.

They also reiterated longstanding complaints that Republicans and the administration had refused to tap a year-end stimulus of as much as $700 million to restore some of the deepest cuts. The spending plan includes more than $100 million in surplus funds.

"This budget recognizes that there are tough, tough choices, I understand that," said Sen. Lisa Boscola, D-Northampton. "But it also includes some bad choices on how to reinvest $27.15 billion for as many Pennsylvania families as we can."

Republicans have said they're not comfortable with all the reductions in the spending plan. But they stressed that the plan "reflects the circumstances of the times," while ducking any major tax increases.

"The document reflects the need for the commonwealth to be fiscally responsible at a time of difficult financial challenges," said Majority Whip Pat Browne, R-Lehigh.

Negotiations continued on two of Corbett's key legislative priorities: authorization of public school vouchers and legislation closing most of the loopholes in a law requiring voter referendums for any school tax hike that outpaces inflation. The governor wants both measures passed before lawmakers start their summer break.

"The House and the Senate have worked with us to reach a final budget," Corbett said. "Because we planned carefully, estimated conservatively, we have a framework to put our budget together."

Corbett has pressed hard to close the loopholes in the "back-end referendum" law, raising the issue in nearly every negotiating session with legislative leaders. Implementing language sponsored by Rep. Seth Grove, R-York, has been attached to a Senate bill currently scheduled for a House vote Wednesday. The governor appeared ready to play hardball with lawmakers, saying "until there is a budget, until I sign one, there is no budget."

Talks on the school-choice bill are continuing, with House leaders saying it's up to the Senate to make the first move. "The Senate has always been in the lead," said House Majority Leader Mike Turzai, R-Allegheny.

Senate President Joe Scarnati, R-Jefferson, said the chamber is "continuing to work with the House to see if there's support" for a school-choice bill and to "see what we can get done before we leave."

House Republicans denied that Corbett's veto threat had anything to do with their decision to put off a vote on an impact fee until the fall. They were complying with his long-stated position that lawmakers delay voting until the Marcellus Shale commission presents its report.

"We'll try to design a legislative package that addresses the full impact of drilling," House GOP spokesman Steve Miskin said.

Scarnati, who spearheaded the push for a drilling fee, said Corbett's veto threat had "changed the dynamic. ... Obviously, it's not going to get done by June 30 if the governor has put his marker down," he said.


Copyright (c) 2011, The Morning Call, Allentown, Pa.

Oil & Gas Post

Promote Your Page Too

BP Gets Two-for-One Deal off Norway

- BP Gets Two-for-One Deal off Norway

Friday, June 24, 2011
Rigzone Staff
by Jaime Kammerzell

BP is combining two separate fields to develop its Skarv and Idun project in the northern Norwegian Sea. The project, which is due to come online in 3Q 2011, is being developed in 350 to 450 m (1,148 to 1,476 ft) of water, between the Norne and Heidrun fields in Production Licenses 212, 262, and 159. The fields contain hydrocarbons at three reservoir levels. BP and its partners estimate total recoverable reserves to be 16.8 MMcm of oil and condensate and 48.3 Bcm of rich gas.

BP serves as the operator with 24% interest, along with partners Statoil with 36%, E.On Ruhrgas Norge AS with 28%, and PGNiG Norway AS with 12%.

Skarv

Amoco, shortly before merging with BP, made an impressive hydrocarbon find in the Donnatello field on Dec. 24, 1997. The Donnatello field, which would later be renamed Skarv, is in 250 to 450 m of water on Norwegian Blocks 6507/5, 6507/6, 6507/3 and 6507/2.

The Maersk Jutlander semisubmersible drilled the well on behalf of Amoco to 4,224 m TD in the early Jurassic formation. Following the discovery, Amoco suspended the well. In 2002, BP contracted the West Alpha semisubmersible to drill the Skarv 6507/5-5 appraisal well, which reached 3,950 m TD and confirmed the 1997 find.

West Alpha

The field's recoverable resources are made up of 80% gas and 20% liquids. Oil will be produced using pressure support from gas injection, and gas will be produced by depletion.

Idun

Statoil discovered the Idun gas field in 1999. Idun is in PL 159, blocks 6507/3-3 in 350 to 450 m of water. The Byford Dolphin semisubmersible drilled the well to 3,830 m and found gas in the Jurassic sandstones. Statoil confirmed the gas discovery with two appraisal wells drilled at 6507/3-3Q and 6507/3-3B to 4,275 m. Statoil then plugged and abandoned the appraisal wells on March 25, 1999.

Field Development Plan

It took nearly 10 years for BP to submit a field development plan to jointly develop the fields. In June 2007, BP proposed a $5 billion plan for development and operation of the Skarv and Idun oil and gas fields to Norwegian authorities. The fields contain hydrocarbons at three reservoir levels with a combined estimate of 106 MMbbl, and 48 Bcm (170 Bcf) of natural gas.

According to the development plan, BP plans for oil production capacity to be 85,000 b/d and gas output at 15 MMscm/d. BP also said that it has identified additional resources in the area, which can be linked back to the Skarv/Idun production facilities at a later date.

BP's concept studies concluded that the best development solution was an FPSO [floating production, storage and offloading] vessel with subsea equipment tie backs. According to the operator, power from shore was considered, but at that time it was not technically feasible in combination with an FPSO.

Thus, BP and its partners are developing the fields with the Skarv FPSO, 16 subsea wells, and an 80 km (50 mile) gas export pipeline connected to the Aasgard Transport System. Shuttle tankers will collect oil from the 875,000 bbl vessel every 10 days.

Skarv FPSO

FPSO

The Skarv FPSO is the biggest vessel ever built for deployment on the Norwegian Continental Shelf.

BP contracted Aker Solutions in November 2005 to perform the project's front-end engineering design (FEED) and detail engineering, procurement, and construction management assistance (EPcma). Aker Solutions also carried out the design (FEED) of the hull, based on its Tentech 975 design, and living quarters.

Samsung Heavy Industry in South Korea carried out the fabrication and installation of the hull and topside.

"Skarv is located at a water depth of 370 m. This is a typical place of operation for an FPSO," said Arne Bjørlo, project director for the Skarv project. "Such vessels are also well suited to a combined oil and gas field, like this one. An FPSO provides the necessary deck space for gas processing facilities, while at the same time allowing for storage of oil."

According to Aker Solutions, the Skarv development includes a number of innovations on previous concepts. "The modules used on the topside are bigger than usual, stretching across the entire width of the deck. This gives us a more effective building process, because each module can be finished separately with a lot less hook-up on assembly," says Bjørlo.

In March 2011, Fairmount Marine tugs, Fairmount Sherpa and Fairmount Summit, delivered the Skarv FPSO to the port in Stord, Norway. The trip took 92 days to tow the FPSO 15,300 nautical miles from Samsung Heavy shipyard in Okpo, South Korea. The Skarv FPSO was installed in April 2011 and the risers and templates will be connected in July 2011.

The Fairmount Summit tugged the Skarv FPSO from the Samsung Heavy shipyard in Okpo, South Korea, to the port of Stord, Norway.

The FPSO has a production capacity of 85 MMb/d and 670 MMcf/d (19 MMcm/d) and is 292 m long, 50.6 m wide and has a towing draught of 12.2 m with a deadweight of 128.000 tons. According to Pat McHugh, Skarv project director, the hull's structure and turret, along with the 15 mooring lines anchored to the seabed, were designed to resist three combined eventualities: a total loss of FPSO power, loss of use of positioning thrusters, and 100-year storm conditions, when the hull is not in its optimal position with respect to the prevailing weather conditions.

Contracts

BP began awarding contracts for the project even before it submitted a development plan in June 2007. In March 2006, BP awarded Kongsberg Maritime a contract for the integrated control systems for safety and automation to the FPSO. The initial contract required Kongsberg to conduct a FEED study with BP and Aker Kvaerner looking at the safety and automation systems. The results were part of the materials submitted for final approval by the Norwegian authorities in early 2007.

That same month, BP signed a letter of intent with Offshore Rig Services ASA for use of the OffRig Pioneer semisubmersible to drill on the Skarv/Idun fields. The contract was subject to approval of the PDO, and was valued between $250 and $500 million, depending on the length of the program, extensions, and options.

BP also awarded Bluewater a FEED study for the Turret Mooring System on the FPSO in 2006. Once the project was approved, Bluewater was awarded an engineering, procurement, and construction (EPC) contract for the Turret Mooring System.

After the Norwegian Authorities approved BP's development plan, the operator awarded VetcoGray a contract to supply subsea production system for the Skarv/Idun field. The $265 million contract includes engineering, construction and testing of 17 wellheads and tree systems and five subsea templates with integrated manifolds, as well as work-over, tie-in, and control systems. VetcoGray also supplied five years of service for the installation, with the option to renew the contract every five years.

In March 2008, VetcoGray then awarded ClampOn a contact for the supply of ClampOn DSP-06 Subsea Particle Monitors and ClampOn DSP Pig Subsea Detectors.

In 4Q 2007, BP awarded Subsea 7 two contracts -- flowline installation and general subsea construction works -- valued at $125 million and $140 million, respectively.

Subsea 7 engineered, fabricated and installed 42 km of single flowlines, which consist of 35 km 12" x 10" diameter clad production flowlines and 7 km 10 inch diameter carbon steel gas injection flowlines. Subsea 7 attached a Direct Electrical Heating (DEH) cable to the 13 km Idun flowline, which is a part of the 35 km production flowlines.

The general construction contract included survey activities, installation of subsea structures, control umbilicals, tie-in and pre-commissioning of all flowlines, risers, control umbilicals, and the gas export pipeline. Subsea 7 also took care of the tie-in spools and protection systems. The Seven Seas vessel carried out most of the work over the course of 300 days.
In December 2007, BP contracted SBM Offshore for the turnkey supply of an internal turret. SBM says the bogie-wheel type design turret is the world's largest turret in terms of mooring loads.

BP awarded the direct electrical heating (DEH) system for the Skarv subsea production pipeline in February 2009 to Nexans, which supplied all cables and dedicated subsea equipment for the DEH system. Nexans installed a 12 in. diameter production pipeline from one of the production wells at the field to the FPSO at Skarv. The distance between the well and vessel was about 13 km. At low production and shut down, a DEH-system will be used to prevent blockage of the pipe.

In 4Q 2009, BP started drilling 11 production wells using the Borgland Dolphin. The contract was extended in June 2010 to continue drilling through late April 2011. BP then arranged for the Polar Pioneer to continue drilling production wells on the Skarv field from April 2011 to May 2013.

Borgland Dolphin

Transocean's Polar Pioneer

Oil & Gas Post

Promote Your Page Too

Canacol Kicks Off Drilling Program in Colombia

- Canacol Kicks Off Drilling Program in Colombia

Wednesday, June 22, 2011
Canacol Energy Ltd.

Canacol announced the start of its heavy oil exploration drilling program on its Tamarin and Cedrela Exploration and Production ("E&P") contracts located in the Caguan - Putumayo Basin in Colombia. The Corporation has 100% working interest and is operator of both contracts, which represent approximately 388,000 net acres. The Corporation plans to drill two stratigraphic wells, one on each of the Tamarin and Cedrela contracts, in a back to back drilling campaign that will commence in mid July 2011. This will be followed by the drilling of five conventional exploration wells, the first to start in late 3Q 2011, and the last to end midyear 2012.

Charle Gamba, President and CEO of the Corporation, commented "The stratigraphic wells will target two large structures recently defined by the new 2D seismic acquired on the Tamarin and Cedrela blocks. These wells, which can be drilled relatively inexpensively compared to conventional exploration wells, have the potential to yield useful information concerning the presence and type of oil, as well as basic reservoir thickness and quality information, in advance of the conventional exploration drilling program the Corporation plans to start in late 3Q 2011. Since the discovery of the Capella heavy oil field by Canacol and its partner in 2008, the Corporation has been able to leverage its proprietary knowledge of the geology and potential of the area. The Corporation is now positioned to execute a significant heavy oil exploration program in this emerging heavy oil play in Colombia."

Tamarin ESTR-1 Stratigraphic Well

The Tamarin ESTR-1 well is planned to be drilled to a depth of 3,260 feet measured depth ("ft md") and will target potential heavy oil bearing reservoirs in the Mirador sandstones, the main producing sandstones in the Corporation's Capella heavy oil field. The Corporation has a 100% working interest and is operator of the Tamarin contract, which represents 68,000 net acres and is located on trend approximately 25 kilometers to the southwest of the Capella heavy oil field.

The Corporation has executed a contract with LT Geoperaciones y Mineria Ltda., a service company that will provide the drilling rig. The Corporation anticipates that the well will take approximately 8 weeks to drill, core, and log. The information that the Corporation anticipates to collect include cores through the prospective reservoir intervals and a full suite of conventional openhole wireline logs. This data will yield information concerning the thickness, porosity, permeability, and fluid content of any prospective reservoir intervals that may be encountered within the well. Given the small size of the wellbore, the Corporation will be unable to flow test any of the prospective reservoirs.

The Corporation is currently constructing the surface location and anticipates that the Tamarin ESTR-1 will commence drilling in mid July 2011.

Cedrela ESTR-1 Stratigraphic Well

The Cedrela ESTR-1 well is planned to be drilled to a depth of 2,600 feet measured depth ("ft md") and will also target potential heavy oil bearing reservoirs in the Mirador sandstones, the main producing sandstones in the Corporation's Capella heavy oil field. The Corporation has a 100% working interest and is operator of the Cedrela contract, which represents 320,000 net acres and is located on trend approximately 50 kilometers to the southwest of the Capella heavy oil field.

The Corporation anticipates spudding the Cedrela ESTR-1 stratigraphic well after the drilling of the Tamarin ESTR-1 well has been completed. The Corporation anticipates that the Cedrela ESTR-1 well will take approximately 8 weeks to drill, core, and log. The same information that the Corporation plans to collect in the Tamarin ESTR-1 well will also be collected in the Cedrela ESTR-1 well.

Forward Plans

The two stratigraphic wells will provide useful information that will be used to pick the final surface locations for the five conventional exploration wells that the Corporation plans to drill back to back on the Tamarin, Cedrela, and Sangretoro contracts starting in late 3Q 2011. The Corporation anticipates that the program will conclude with the fifth well in 2Q 2012.

In the meantime, the Corporation advances its 2D seismic acquisition program on its Sangretoro contract. The Corporation has a 100% operated interest in the contract, which represents 385,000 net acres. Once the seismic is complete, the Corporation is prepared to drill additional stratigraphic wells for information purposes before drilling two conventional exploration wells by the end of 2Q 2012.

The conventional exploration wells will be drilled with a normal drilling rig, which will allow for any potential oil bearing reservoirs to be flow tested.

Oil & Gas Post

Promote Your Page Too

Encana, Petrochina Call Off $5.43B Canadian Shale Deal

- Encana, Petrochina Call Off $5.43B Canadian Shale Deal

Tuesday, June 21, 2011
Encana Corp.

Encana and PetroChina have ended negotiations for a proposed joint venture concerning Encana's Cutbank Ridge business assets after the parties were unable to achieve substantial alignment with respect to key elements of the proposed transaction, including the joint operating agreement.

"After close to a year of exclusive negotiations with PetroChina, we were unable to reach alignment on the planned transaction. The disciplined and determined process we undertook on this one initiative in our multi-faceted and ongoing joint-venture strategy has gone a long way to demonstrate the tremendous value that we have created at Cutbank Ridge and it validates our plans to accelerate recognition of that value. As such, we have determined that the best way for us to advance our plans to unlock value from our Cutbank Ridge business assets is to offer up a variety of joint venture opportunities for portions of the undeveloped resources, and, separately, to examine a transaction with respect to our midstream pipeline and processing assets in the area. Each of these opportunities has the potential for strong long-term growth and value generation. We have an accomplished history of realizing significant value from our enormous resource potential through competitive processes that secure premium joint venture partners. We have retained RBC Capital Markets and Jefferies & Company, Inc. to conduct this process and we look forward to discussing these very attractive opportunities with an array of potential investors in the upcoming months," said Randy Eresman, Encana's President & Chief Executive Officer.

Horn River and Greater Sierra joint venture discussions well underway

In April 2011, Encana announced plans seeking investors in two joint ventures on Encana assets outside Cutbank Ridge in northeast British Columbia, one on undeveloped Horn River shale lands and one in the company's Greater Sierra resource play. Discussions are well underway on these potential transactions as well as a potential divestiture of producing assets in the northern portion of Greater Sierra. Encana expects that these transactions, plus other divestitures and joint venture pursuits that the company has initiated, will generate 2011 proceeds and joint venture investments of between US $1 billion and $2 billion, a level that exceeds Encana's net divestiture target for 2011 of $500 million to $1 billion. That estimate for higher 2011 divestiture and joint venture proceeds does not include any potential investments in Encana's Cutbank Ridge undeveloped resources and associated midstream assets. To reflect this increase, Encana has updated its 2011 guidance for net divestitures to between $1 billion and $2 billion. All other components of Encana's guidance remain unchanged.

Encana on track for 2011

"As we look ahead to the rest of this year, our strong operating performance in the first half of this year and our prudent risk management measures mean that we remain on track to achieve our 2011 production and financial guidance. We expect future natural gas prices to reflect the forward price curve, and, over time, to return to a long-term level of about $6 per thousand cubic feet (Mcf), which we believe reflects the cost of adding new supply. Across Encana, we are relentlessly focused on driving down supply costs, which this year we expect to average about $3.70 per Mcf. Over the next three to five years, we are targeting a supply cost of $3 per Mcf, based on 2011 cost structures. These low cost structures, combined with our continued emphasis on capital discipline and the high grading of our portfolio, help us maximize margins and maintain a healthy balance sheet through the lower end of the price cycle - a market condition that has persisted in North America during the past two years," Eresman said.

Oil & Gas Post

Promote Your Page Too

Rep. Gardner Bill to Help Oil Cos Drill Off The Coast of Alaska Slate

- Rep. Gardner Bill to Help Oil Cos Drill Off The Coast of Alaska Slate

Monday, June 20, 2011
Greely Tribune, Colorado
by Nate A. Miller, Greeley Tribune, Colo.

U.S. Rep. Cory Gardner is the driving force behind legislation slated for a vote in the House this week that would make it easier for oil companies to drill off the coast of Alaska.

"Energy security and job creation is very important to me," the Republican said. "This bill accomplishes both goals."

The bill, H.R. 2021, would streamline the process for air permits on deep-water drilling operations off the coast of the U.S., with the exception of the Gulf of Mexico, which is controlled by the Department of the Interior. It also would require the Environmental Protection Agency to make a ruling on permit requests within six months.

Fort Collins resident Gary Wockner, who is the Colorado program director of Clean Water Action, said the bill is misguided.

"This bill will increase polluters' profits at the expense of public health and the environment," he said.

While it may seem strange for a Colorado congressman to take up the cause of offshore oil drilling in Alaska, Gardner, who serves on the House Energy and Commerce Committee, said it's a good fit.

"We need an all-of-the-above energy policy in this country that lessens our dependence on Middle Eastern oil," he said. "Whether it's natural gas produced in Weld County or oil produced in our deep-water reserves. We need to be doing everything we can to help reduce the price of gasoline and to help ween ourselves off of Middle East oil."

Gardner said permits to drill off the coast of Alaska have become stuck between the EPA and the Environmental Appeals Board, which the EPA created to address administrative appeals involving the major environmental statutes the EPA administers.

"Congress said these permits had to be approved or denied within a limited time frame. The EPA created a bureaucracy without Congress that has delayed some of these permits by as much as six years," he said. "It's the EPA end-run around Congress that's hurting our energy independence."

Gardner's legislation would remove the duplication created by the EPA and appeals board permitting process.

In testimony last month before the subcommittee on Energy and Power of the House Committee on Energy and Commerce, EPA assistant administrator for air and radiation Regina McCarthy said the appeals board ensures all parties are heard and often actually makes the process more efficient.

"Rather than adding a step, the board usually serves as a cheaper, faster, more expert substitute for judicial review," she said. She used the example of a group of subsistence fisherman concerned that an EPA permit didn't address their concerns about air pollution. "They would not be required to hire a lawyer; they could attend oral arguments via video conference; and they would know that their concerns were being heard by experts."

She also said offshore drilling operations can have very real impact on air quality, and it's important to ensure effective, efficient oversight of the operations.

Gardner said the permitting process gives ample time for public comment without the added bureaucracy of the appeals board. He said the permits can be held up even when there aren't health concerns. He gave the example of a Royal Dutch Shell permit for Alaska drilling which he said the EPA held up for six years, even though EPA head Lisa P. Jackson said health concerns weren't an issue.

Gardner estimates the measure, if it becomes law, would create 50,000 jobs across the country -- including some in Colorado -- and help ease the pressure at the pump for drivers by allowing more than 1 million barrels of oil a day to be pumped from Alaska.

Wockner said Gardner should focus on energy solutions Colorado has to offer.

"Rep. Gardner should be worrying about clean energy jobs in northern Colorado, not polluters' profits in Alaska," he said.

Copyright (c) 2011, Greeley Tribune, Colo.

Oil & Gas Post

Promote Your Page Too