GSF Labrador Gets New Look

- GSF Labrador Gets New Look

Monday, June 20, 2011
Scheldepoort B.V.

Scheldepoort B.V. has been awarded a contract to convert the GSF Labrador into an accommodation unit. The project will commence when the rig arrives in Vlissingen at the end of June and will take approximately 4 months. Among other things the main scope of work is the removal of the complete drilling package from the rig, such as the derrick, cantilever, cement and mud tanks, all drilling equipment and redundant cabling and piping.

Scheldepoort will build a new accommodation block weighing in at 400 tons which will be placed on the deck. The current accommodation facilities will be completely refurnished and new life saving equipment will be installed. The rig will be fitted with sponsons in order to comply with stability regulations. In addition, a complete survey as well as a painting program will be executed. After delivery the accommodation rig will go into service in the coastal waters of Denmark.

The GSF Labrador is an independent leg cantilever jackup rated to work in water depths up to 300'. The CFEM T-2005-C designed unit entered service in 1983. Transocean cold stacked the unit in August 2010.

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Operators Look to Unlock Tuscaloosa Marine Shale Potential

- Operators Look to Unlock Tuscaloosa Marine Shale Potential

Monday, June 06, 2011
Rigzone Staff
by Karen Boman

The Tuscaloosa Marine shale play, located on the border of southwestern Mississippi and northeast Louisiana, could emerge as the next big oil shale play as oil and gas producers shift their focus from gas to oil drilling and seek to unlock unconventional resources in unexplored shale plays.

The Louisiana Department of Natural Resources Office of Conservation will hold a public hearing on June 7 in Baton Rouge to approve a drilling production unit that Devon Energy has applied for in the Tuscaloosa play near Ethel in East Feliciana Parish.

Devon holds 250,000 acres in the Tuscaloosa Marine shale play. Devon spokesperson Chip Minty said it is still too early to quantify the liquids content of this acreage. The company plans to drill two horizontal wells this year on its Tuscaloosa shale acreage, which Devon officials said is stratigraphically equivalent to the Eagle Ford shale play and has a low average acreage cost of $180/acre. The company will have a rig on site in this year's second quarter.

The company's Tuscaloosa activity is part of Devon's goal of identifying and establishing large acreage positions in highly economic plays at reasonable prices. "We have continued building these new venture positions and now have roughly 850,000 net acres and a handful of new plays, primarily targeting oil and liquid rich gas," the company said.

The Tuscaloosa shale on Devon's acreage is approximately 200 to 400 feet thick, at depths of 11,000 to 14,000 feet across Devon's acreage position. Oil production has been established, up dip in the play from the Tuscaloosa Shale, said David Hager, Devon's executive vice president of exploration and production, during Devon's first quarter 2011 earnings conference call in early May. "We plan to utilize horizontal drilling and fracture simulation to enhance the productivity of the reservoir in both the oil and liquids-rich portion of the play."

Denbury Resources recently signed a small joint venture covering its Tuscaloosa Marine Shale acreage wherein the partner will complete one well and drill another at no cost to us, leaving Denbury with a small retained interest in future activities. Denbury in late 2009 agreed to acquire EnCore, which had drilled four horizontal wells targeting the Tuscaloosa Marine Shale play in 2007 and 2008. The JV will allow Denbury to develop this acreage it acquired with the EnCore acquisition.

The first Tuscaloosa Marine shale well was tested in 1975; to date, five well have been tested and produced. The Tuscaloosa Shale has an unproven unconventional resource estimate of 7 billion barrels of oil, according to a report by researchers at Louisiana State University in Baton Rouge.

The marine shale section lies between sands of the upper and lower Tuscaloosa sections and varies in thickness from 500 feet in southwestern Mississippi to more than 800 feet in the southern part of the Florida parishes in Louisiana. The Tuscaloosa Marine Shale is very similar in geology to the Eagle Ford, and is believed to have the same potential for development and production.

Brammer Engineering and Indigo II Louisiana Operating hold permits in the same area as the Tuscaloosa shale. Indigo Chairman and Chief Executive Officer Bill Pritchard said he sees potential for Tuscaloosa shale production in the acreage it received from Roy O. Martin Minerals, Louisiana's largest private landowner, in exchange for equity in Indigo.

The company put together about 240,000 acres in central Louisiana, of which half has been leased to timber companies; Indigo will focus its Tuscaloosa exploration efforts on the remaining half. Indigo drilled the Bentley Lumber 32-1 vertical well, and will drill the Indigo Bentley Lumber 23H-1 horizontal well in July.

The company's acreage is northwest of the area where Devon and EnCore have drilled, but the interval Indigo is targeting sits above the Edwards carbonate formation; to the east, the Eagle Ford/Tuscaloosa play overlies the main body of the Lower Tuscaloosa sandstone. Indigo's acreage features a higher percentage of calcite, which makes it more brittle and easier to frack. The company set intermediate casing just above the shale and drilled with oil based mud. "That and the fact that we are more calcitic through the section allowed us to drill through the TMS [Tuscaloosa Marine Shale] without incident," Pritchard said.

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Analysis: Another Look at The Bird

Analysis: Another Look at The Bird

Thursday, April 14, 2011
Rigzone Staff
by Trey Cowan

In a January 5, 2011 article, we dubbed the Dow Jones Transportation Index (DJT) the canary in the coal mine based on its predictive properties relative to oil price declines.

Par for the course, the recent decline in WTI crude prices was in fact preceded by a pullback in the DJT last week. Specifically, the DJT fell 3% for the week ending April 8th. Crude futures were advancing last week (improving 4%). With the last two daily declines, oil prices are now 6% below their recent peak closing price of $112.73, set last Friday on April 8th.

Given their lagging tendency, relative to the Dow Jones Transportation Index, we would expect this recent correction in oil prices to find its bottom soon.

Why this pattern occurs is really no mystery. The transportation markets are a leading indicator of the market's perception on economic activity. Higher fuel prices at some point curtail activity levels across the board, effectively diminishing demand for not just fuel but all goods and services. Should we see a dramatic pullback in the transportation index beyond the recent low set in March, barring other factors extant to macroeconomic conditions, then we would expect oil to retrace back to levels of $90 per barrel seen at onset of the year.

We are already starting to see signs that higher gasoline prices are causing a shift in consumer behavior. At the pump, gas station owners have begun to report that the frequency of customers and volume of gasoline purchases is dropping on a weekly basis. The numbers support these claims as the MasterCard Spending Pulse, which tracks sales at 140,000 gas stations, reports gasoline consumption has been falling for the past 6 weeks straight.

Back in January we warned of this phenomenon regarding demand destruction in our article "Panning Out". Here is what we said:
There is a real threshold that causes consumers to modify their driving patterns (i.e. a shrinking discretionary budget giving way to a reduction in miles driven) that could stall the current economic recovery underway.

Assuming that the average amount of annual discretionary spent per US household is approximately $1,000, then a $0.75 per gallon increase in gas prices would absorb practically all the discretionary budget for a two-car family. Using average 2010 gasoline prices as the base, this would imply that US drivers will see their discretionary budgets evaporate once gasoline prices top $3.50 per gallon.

As demonstrated in the following chart, you can see that what is occurring today corresponds with our January prediction.

Sustained energy demand destruction, in our opinion, would likely spread to other areas of the economy. So, while government officials look to higher energy prices as a means to spur innovation in alternative energy sources, the trade-off could be a derailment of the current economic recovery. While we do not have a calamity or supply disruption that at other times would merit tapping the Strategic Petroleum Reserve, a whole-hearted dismissal of utilizing this tool puts the United States' energy policy in a game of chicken with our economic recovery.

Offshore Officials Get In-Depth Look

Offshore Officials Get In-Depth Look

Thursday, April 14, 2011
Houston Chronicle
by Jennifer A. Dlouhy

The top U.S. officials in charge of offshore oil and gas exploration on Wednesday got a close-up look at the first deep-water drilling project approved since last year's oil spill.

Interior Secretary Ken Salazar and his chief offshore regulator, Michael Bromwich, spent two hours examining new safety systems -- including one spurred by the spill -- on the Ensco 8501 rig that is about to begin drilling a bypass well for Noble Energy in the Gulf of Mexico.

They touched drilling fluids hauled from pits on the semisubmersible rig, interviewed workers about their jobs and studied the systems used as a last line of defense against surging oil and gas.

Afterward, Salazar said he was impressed that "testing capabilities have been significantly enhanced since a year ago."

"We're starting to see the beginning of a significant change in the culture that holds great promise," Salazar added.

Within days, the Ensco 8501 is set to begin drilling the well in Noble Energy's Santiago prospect 70 miles southeast of Venice, La., resuming work that started just four days before the blowout of BP's Macondo well and destruction of the Deepwater Horizon drilling rig last April 20.

Houston-based Noble drilled more than 7,000 feet below the seafloor in 6,500 feet of water before it was forced to plug the well under a moratorium on deep-water drilling that took effect weeks after the Macondo blowout.

The new bypass drilling is meant to get around the plugs in the original well.

Although Noble Energy is the operator of the project, with a 23.25 percent working interest, BP owns 46.5 percent of it. The other partners in the project are Red Willow Offshore and Houston Energy Deepwater Ventures.

Noble Energy secured its permit to resume work at the site on Feb. 28, becoming the first of 10 deep-water projects blocked by last year's ban that now have gotten the green light. So far, drilling has begun on just one: a well in Shell Oil's Cardamom Deep discovery 137 miles off the Louisiana coast.

One hundred twenty-three people now are working at the Noble Energy well, including 78 who work for Ensco and others employed by about a half-dozen other contractors.

Workers on the rig -- built as a collaboration between Ensco and Noble two and a half years ago -- stressed the safety practices onboard. At one point, an Ensco worker reminded Salazar and Bromwich to don protective glasses and earplugs.

 

Blowout preventer

Inside the drilling shack at the heart of the rig, the two officials pressed workers to answer questions about the blowout preventer designed as a final barrier against loss of well control. A four-month examination of the blowout preventer used at BP's well concluded it was unable to slash through off-center drill pipe, seal the well hole and trap oil underground.

Although blowout preventers are built to shear through drill pipe, they can't cut through thick joints connecting pipe. That means drillers must know whether narrow pipe or joints are passing through the device.

 

'Give me comfort?'

Salazar wanted to know what would ensure that pipe joints weren't in the way.

"What will give me comfort that in this rig, that will not happen?" he asked.

Don Williamson, the rig manager, stressed that the driller always knows the position of the pipe.

The Hydril blowout preventer being used at the Noble Energy well is two and a half years old -- the same age as the rig itself.

After last year's spill, the government stepped up testing requirements for blowout preventers, including access points called hot stab panels that allow remote controlled vehicles to operate equipment deep beneath the surface.

On the Ensco 8501, that meant installing new equipment from Oceaneering that allows the workers on the surface to conduct quicker, more efficient tests of the hot stab function.

"It's greatly enhanced our ability to test the stabs on the surface," said Rusty Critselous, a drill site leader for Noble Energy. "With this little unit, our hot stab lines are shorter and the testing process is quicker."

 

'New and better ways'

Bob Bemis, Noble Energy's vice president of environmental, health and safety, said the federal mandate prompted the change.

"That regulation is causing us to develop new and better ways to develop these testing techniques," Bemis said.

Bromwich, director of the Interior Department's Bureau of Ocean Energy Management, Regulation and Enforcement, observed later that it was gratifying that the federal requirements had spurred innovation, but said he would prefer the industry to have its own incentives for safety improvements.

"What's been missing from the industry over the last several decades has been the drive to innovate for safety without new requirements," Bromwich said.

The backdrop for the visit Wednesday was continuing tension between the oil industry and the Obama administration.

Oil industry representatives have complained that the administration is moving too slowly to restart offshore drilling following last year's spill.