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Brazil government fails to benefit blocking oil firms

Posted on June 21, 2012 at 6:41 am by Bloomberg

International oil companies looking to start exploring Brazil, home to the largest discoveries in the past decade, can’t get near the crude.

Brazil has repeatedly delayed the sale of exploration areas since 2007, leaving Exxon Mobil Corp. (XOM) and Royal Dutch Shell Plc (RDSA) shut out of an offshore area that holds at least $5 trillion of oil. Meanwhile Petroleo Brasileiro SA (PETR4), the state-run company that pumps more than 90 percent of the country’s crude, is struggling to develop deposits it has already found. Petrobras’s output grew 1.5 percent in 2011, the slowest pace in four years.

Companies including Total SA (FP) have accelerated exploration off the coast of West Africa, where the geology is similar to Brazil and which holds large discoveries in deep waters. OGX Petroleo & Gas Participacoes SA, controlled by billionaire Eike Batista, began exploring in Colombia amid delays in offering new exploration tracts in Brazil.

“Brazil is someplace where we would like to be more present; at the same time we are in 130 countries, it’s not one against the other, it’s one plus,” Total Chief Executive Officer Christophe de Margerie said in a June 18 interview in Rio de Janeiro. “I hate to say it but if it doesn’t work it doesn’t work. We would like it to work.”

Petrobras this month increased its five-year spending plan 5.3 percent to $236.5 billion, the biggest in the oil industry, to develop deposits in waters as deep as 2,800 meters (9,200 feet) and trapped under a layer of salt.

Price-to-Earnings

Petrobras trades at 6.81 times its estimated 2013 earnings, compared with a ratio of 9.74 for Exxon, 7.12 for Shell and 6.28 for Total, according to data compiled by Bloomberg.

Revenue at the Brazilian producer totaled $150.7 billion in the trailing 12 months, less than Exxon’s $442.9 billion, Shell’s $480.2 billion and Total’s $236.2 billion.

While a legislation change in 2007 put Petrobras in charge of all new contracts in the so-called pre-salt area off Brazil, the company hasn’t been able to extract oil fast enough to meet targets. Petrobras cut its long-term production guidance by 11 percent to 5.7 million barrels a day in 2020. Output will remain within 2 percent of 2011 levels until 2014, it said on June 14.

The lack of new exploration areas in Brazil has encouraged some companies to concentrate on other regions such as offshore Africa, where Tullow Oil Plc (TLW) and Cobalt International Energy Inc. (CIE) have made discoveries in deep waters. Last year, Anadarko Petroleum Corp. (APC) announced plans to sell all its Brazil blocks, granted before the 2007 legislation change, as it boosts investment in natural-gas projects in Africa.

Bid Rounds

“The absence of bid rounds is affecting all oil companies in Brazil,” Joao Clark, the head of Ecopetrol SA (ECOPETL)’s Brazilian operations, said in an April 17 interview in Rio de Janeiro. “We need new blocks, we have to improve our portfolio.”

Exxon quit its only Brazilian block this year after drilling three dry holes in deep waters, Patrick McGinn, a company spokesman, said by e-mail from Irving, Texas. The explorer is seeking more opportunities in the country, he said.

Petrobras is failing to meet output goals after new offshore wells didn’t compensate for declines at older fields. That jeopardizes its 2020 target. Brazil is counting on the company to provide national energy self-sufficiency to meet demand from a growing economy. Petrobras pumped 93 percent of the country’s oil and 99 percent of its gas in April.

Pre-Salt Zone

Foreign producers including Exxon and Total, with little acreage in Brazil, are seeking to eat into that share as fields dwindle in other areas such as the North Sea and Alaska’s North Slope. Brazil hasn’t auctioned any offshore permits since before announcing the potential of the pre-salt zone in 2007 and hasn’t sold any blocks at all since 2008, when it sold tracts on land.

“I understand quite well the anxiety of those companies,” Petrobras Chief Executive Officer Maria das Gracas Silva Foster told reporters in Rio on Feb. 13, the day she was promoted to the role. “For them it might be really important. For Petrobras, it makes no difference. We have a lot of work to do.”

Brazil probably won’t offer any areas in the region until 2013 because lawmakers are debating how to distribute future revenues, Marco Antonio Almeida, the Energy Ministry’s oil and gas secretary, said in a May 3 telephone interview from Brasilia. The pre-salt auctions will only occur after Congress votes on how to distribute the royalties from future output, the Energy Ministry said in an e-mailed response to questions.

Political Wrangling

The combination of political wrangling, requirements to buy locally built equipment and Petrobras’s budget constraints may even push new rounds to 2014 at the earliest, according to Christopher Garman, a Latin America analyst at Eurasia Group.

“The sentiment within the upper levels of government is they already have their hands full,” Garman said by phone from Washington. “What is really hurting the decisions of international oil companies to stay is the lack of a pipeline of new opportunities.”

Petrobras is required to have a minimum 30 percent stake in new pre-salt blocks. That means the Rio de Janeiro-based company can sign contracts before knowing who it will work with, making it hard to set up the auctions, Almeida said. “It’s a situation that doesn’t exist anywhere else in the world,” he said.

The lack of auctions has put a premium on existing permits. Companies that bought exploration areas before the discovery of Lula — the field previously known as Tupi, which was the Americas’ largest oil discovery in more than three decades — have seen the value of those areas increase as a result of oil- price gains and scarcity of acreage, Peter Gaw, head of oil, gas and chemicals at Standard Chartered Bank, said in an interview.

BG, Repsol

BG Group Plc (BG/) owns 25 percent of Lula, while Portugal’s Galp Energia SGPS SA (GALP) has a 10 percent stake. Repsol SA owns 25 percent of a neighboring block. Their properties, purchased years before anyone knew what they were worth, have since attracted global peers to the south Atlantic.

China Petrochemical Corp., Asia’s biggest refiner, has agreed to invest $12.3 billion to become a minority partner with Repsol and Galp in Brazil. BP Plc (BP/), who skipped the first pre- salt auctions, paid Devon Energy Corp. $3.2 billion last year for nine blocks in the country.

Petrobras doesn’t need to worry about the timing of new sales because oil will only gain in value in coming decades, Silvio Sinedino Pinheiro, elected to the company’s 10-member board by workers this year, said in an April 11 interview at its headquarters.

“Here at Petrobras we talk a lot about if it makes more sense to sell now at $100 a barrel, or sell in 30 years when it costs $200 a barrel,” he said.

Source

BP Acquires New Offshore Acreage in Brazil

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BP announced today that the Brazilian National Petroleum Agency (ANP) has approved its farm-in to four deepwater exploration and production concessions operated by Petróleo Brasileiro S.A. (Petrobras) in the Brazilian equatorial margin.

BP Energy do Brasil Ltda. is taking a 40 per cent interest in each of the blocks, located in the Barreirinhas and Ceará basins, from Petrobras.

The move will give BP access to four new concession blocks in Brazil: BM-BAR-3 and BM-BAR-5 in the Barreirinhas basin, and BM-CE-1 and BM-CE-2 in the Ceará basin. Together the blocks cover a total area of 2,113 square kilometres.

“BP is building on our strengths in exploration and the deepwater and these four new blocks bring exciting new exploration opportunities, adding to the already significant position we hold in Brazil,” said Bob Dudley, BP group chief executive. “I am pleased that this also deepens our strong relationship with Petrobras, one of the world’s leading deepwater operators.”

Guillermo Quintero, BP Brazil President added: “Over the past year, in addition to acquiring ten upstream concessions from Devon Energy in May, we have made major investments in biofuels and expanded our aviation business in Brazil. I am delighted with this continued growth of our presence in Brazil.”

Following the farm-in, BP will hold concessions in 14 blocks in Brazil, operating six. BP will be a partner with Petrobras in nine of these concession areas: the Xerelete field, BM-C-34 and BM-C-35 (in the Campos basin); BT-PN-2 and BT-PN-3 (in the Parnaíba basin); BM-BAR-3 and BM-BAR-5 (in the Barreirinhas basin) and BM-CE-1 and BM-CE-2 (in Ceará basin).

Source

BP Gets Approval for South China Sea Exploration

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The Ministry of Commerce, People’s Republic of China, has granted consent to British Petroleum (BP), for an exploration drilling in the South China Sea in partnership with CNOOC, China Daily reveals today.

BP and the block operator CNOOC signed a deal for the exploration at the 43/11 deepwater block in South China Sea in January last year, but the agreement was subject to the Government’s approval.

This is BP’s second project in the deep waters of South China Sea after it had bought a stake in the Block 42/05 from Devon Energy China Ltd., in September 2010.

China daily reports that the partners in the project plan to use China’s first and only home made deepwater semi-submersible drilling rig Offshore Oil 981.

Asked when the exploration drilling would begin, BP China President Chen Liming told Reuters: “When we start depends on many factors, such as whether the drilling rig is ready. We hope to start drilling there by the end of the year.”

BP has been operating in China since the early 1970s and has business activities which include offshore gas production, chemical joint ventures, LPG import and marketing, oil product and lubricant retailing, chemicals joint ventures manufacturing ,technology licensing etc. According to China Daily, the British oil giant has so far invested more than USD 5 billion into China.

Articles

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New Frontiers: the attention turns to some up-and-coming plays

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If 2008 was the Year of the Shales, 2011 is shaping up to be the Year of Liquids-Rich Plays–and there are still four months to go.

A major recurring theme in second-quarter conference calls was oil companies’ news of positions amassed or initial test wells drilled in new shale and unconventional fields containing oil and natural gas liquids.

Plays such as the Tuscaloosa Marine Shale, Mississippi Lime, Lower Smackover/Brown Dense and Utica shales–both in Ohio and to the west in Michigan–are lining up to be the emerging fields of 2012 and 2013, analysts said.

“We’ll see a movement in some of these plays and it’s not going to slow down–if anything, it will be a pretty tight market for services, fracturing crews and pipeline access,” Michael Bodino, head of energy research for Global Hunter Securities, said.

Arguably, the Utica Shale was the showpiece of the quarter, particularly because its cachet resembles that of Northwest Louisiana’s giant Haynesville Shale, which took Wall Street by storm when Chesapeake Energy trumpeted it in March 2008.

Chesapeake again took the lead in showcasing the Utica late last month, relating the news that the play economically “looks similar, but is likely superior to the Eagle Ford Shale in South Texas…because of the quality of the rock and location of the asset” near eastern US population centers, CEO Aubrey McClendon said.

Like the Eagle Ford, which stands out as one of the US’ most sizzling shale plays at present, the Utica has oil and “dry” natural gas and “wet gas” (gas liquids) windows, he said.

Jeff Ventura, chief operating officer at Range Resources, which pioneered the Marcellus Shale in Pennsylvania, said his company already has drilled two Utica wells. At least on its acreage, Utica is at the bottom of a pancake stack of three play zones, with the Upper Devonian Shale on top and the Marcellus in the middle. The Upper Devonian shales contain about as much gas in place as the Marcellus zone, Ventura said, adding that the Marcellus gas field has been called one of the US’ largest.

Both Range and Chesapeake also have scored success in Northern Oklahoma’s Mississippi Lime play. “In the past year it has become more clear that we have a major play on our hands,” said McClendon, with Chesapeake holding 1.1 million acres there, running six rigs, aiming for 10 rigs by year-end and 30 to 40 by end-2014 or 2015.

Range’s Ventura suggested the play, found at relatively shallow depths of 5,000-6,000 feet, is also highly profitable; it boasts a 100% rate of return at $100/b oil, and he added that even at $90/b it yields a roughly 80% return. Range, which has completed seven horizontal wells, sees its main near-term activity there as nailing the optimal lateral length and well spacing.

Ventura said liquids make up 70% of a well’s recoverable hydrocarbons. McClendon estimated 415,000 barrels of oil equivalent per well, at an average finding cost to date of roughly $11/b, which he called “very, very attractive results.”

—–

Meanwhile, in its late July conference call, Southwestern Energy CEO Steven Mueller said his company has acquired 460,000 net acres in an unconventional horizontal play targeting the Lower Smackover Brown Dense formation.

“This happens to be almost the exact same number of acres we had when we announced the Fayetteville Shale play back in August 2004,” Mueller said. That news kicked off an industry rush to that gas play, Mueller said.

But having reviewed the results of more than 70 wells that penetrated the Brown Dense zone, “we currently have more data about [it] than we had on the Fayetteville Shale when it was announced,” he said.

Mueller said the Brown Dense is an oil reservoir in Northern Louisiana and Southern Arkansas, at 8,000-11,000 foot depths and below the Haynesville Shale which is also a gas play. Brown Dense is “extensive over a large area and ranges in thickness from 300 to 530 feet,” he said.

Southwestern plans its first Smackover/Brown Dense well in Columbia County Arkansas, before the end of September, with a second well later in the year in Claiborne Parish, Louisiana.

In addition, Goodrich Petroleum in early August said it had begun drilling the Buda Lime, beneath the Eagle Ford. The small company averaged a respectable 900 boe/d oil from those wells, against 800 boe/d from its 11 Eagle Ford wells so far.

Rob Turnham, Goodrich chief operating officer, also touted the Tuscaloosa Marine Shale, along the horizontal Mississippi-Louisiana border, where both Encana and Devon Energy have large positions and are drilling wells. Tuscaloosa “has a lot of similarities to the Eagle Ford–similar permeability and porosity” of the rocks, he said. Goodrich will begin drilling in early 2012.

He said nine older wells in the play have flowed oil but “none of them have been properly stimulated.” If the vertical wells were to be taken horizontally several thousand feet, fractured with current technology, and properly stimulated, “we’re very optimistic,” said Turnham.–Starr Spencer in Houston

Original Article

Emerging Shale Oil Plays

By Peter Staas
8/11/2011

As the shale oil and gas revolution has picked up steam over the past several years, several important trends have emerged that will separate the winners from the losers.

The combination of depressed natural gas prices in North America and robust oil prices has prompted independent producers to ramp up drilling activity in fields rich in oil, condensate and natural gas liquids (NGL) while reining in operations in Louisiana’s Haynesville Shale and other dry-gas plays. By many accounts, natural gas production has become incidental to these higher-value hydrocarbons.

Besides focusing on a company’s production mix, investors must also evaluate the economics and quality of a producer’s acreage. first movers in oil- and liquids-rich plays have the opportunity to snap up the best acreage at a fraction of the costs incurred by late entrants.

For example, Marathon Oil Corp (NYSE: MRO) recently paid $3.5 billion for 141,000 acres (about $21,000 per acre) in the Eagle Ford Shale from Hilcorp Resources Holdings LP. The deal surpassed the $16,000 per acre that Korea National Oil Corp paid to Anadarko Petroleum Corp (NYSE: APC) to establish a foothold in this liquids-rich shale play.

The elevated prices that latecomers have paid for acreage illustrate the importance of being an early mover in these plays. This strategy has paid off for EOG Resources (NYSE: EOG), the leading oil producer in North Dakota, the Eagle Ford Shale and the Niobrara Shale. Lower entry prices translate into more financial flexibility and superior margins for producers that snap up the best acreage at pre-boom prices.

Readers of The Energy Strategist can attest to the importance of focusing on early movers that have acquired the best acreage.

My colleague Elliott Gue added Petrohawk Energy Corp (NYSE: HK) to the publication’s model Portfolio on May 10, 2010, citing the company’s acreage in the Eagle Ford Shale, a liquids-rich field in South Texas that the firm discovered in 2008. The stock represented a compelling value at the time; investors had overlooked this asset and the potential for the firm to grow its liquids output, focusing instead on its leasehold in the Haynesville Shale and exposure to natural gas prices. Elliott also highlighted the stock as one of his top takeover targets of 2010.

A year later, Elliott’s investment thesis panned out: Australian mining giant BHP Billiton (NYSE: BHP) announced that it would acquire Petrohawk Energy in an all-cash deal worth $12.1 billion. Readers who followed Elliott’s call booked a 92 percent gain.

With these advantages in mind, producers are constantly on the lookout for the next liquids-rich shale play that offers attractive margins. Here’s a brief rundown of some of the emerging shale plays in which North American producers have accumulated acreage.

1. Tuscaloosa Marine Shale

In recent quarters, a handful of independent exploration and production (E&P) outfits have touted their acreage in the Tuscaloosa Marine Shale (TMS), a formation that stretches from Texas to Louisiana and Mississippi. The field is far from a new discovery; famed Mississippi wildcatter Alfred Moore spearheaded drilling in the TMS in the 1960s.

The play’s proximity to the Haynesville Shale should make it easier for producers to redirect drilling rigs from the out-of-favor dry-gas play and limits bottlenecks associated with a lack of midstream infrastructure. Despite boasting similar geologic characteristics to the Eagle Ford, the TMS is far from a slam dunk, which explains the low prices that early movers have paid to build an acreage position.

Goodrich Petroleum Corp (NYSE: GDP), for example, amassed about 74,000 acres, paying an average of $175 per acre. Meanwhile, Devon Energy Corp (NYSE: DVN) has accumulated 250,000 acres on the Louisiana-Mississippi border at an average cost of $180 per acre.

Thus far, early movers in the TSM have yet to report drilling results, though management teams have indicated that these tests have been encouraging. Devon Energy recently completed drilling, coring and logging its first vertical well in the play and plans to sink its first horizontal well later this year. Denbury Resources (NYSE: DNR) and its partner EnCana Corp (TSX: ECA, NYSE: ECA) are at a similar stage in their drilling program and plan to sink a horizontal well in September.

During EnCana’s conference call to discuss second-quarter results, Executive Vice-President Jeff Wojahn described its TMS assets as “a promising liquids-rich opportunity” based on “how the rock breaks, the hydrocarbon content and gas in place, and the like.”  Management also pegged the drilling costs for its first horizontal well–a 12,000-feet deep vertical shaft with a 7,500-foot lateral segment–at about $8 million.

Meanwhile, Goodrich Petroleum’s CEO provided a bit more color on his outlook for the TSM during the Q-and-A portion of the firm’s Aug. 4 conference call:

We’re very comfortable today with what we see from a geologic standpoint of going ahead and drilling wells. In fact we don’t really even see much need, at least in most of our acreage, for pilot holes. There [are] sufficient amounts of historical vertical wells that have been drilled through the Tuscaloosa Marine Shale that we’re comfortable going out and drilling today. I would characterize at least in our view that the sole or the largest single risk to the play is just one of the economic performance versus well costs. We know the Tuscaloosa is present, sufficiently thick, thoroughly oil saturated. It’s just a little unproven in that no one has drilled yet a well that’s demonstrated in the EUR horizontally that would match up to costs. And that’s just [be]cause there haven’t been really many or any of them out there that have done that.

Drilling results in this frontier play could provide a meaningful upside catalyst for these E&P operators. At the same time, if the play proves uneconomic to produce or drilling results disappoint, the low cost of acreage provides a degree of downside protection.

2. Utica Shale

Management teams from several E&P firms also touted the potential of the Utica Shale, a formation that lies beneath the Marcellus Shale but extends from Tennessee into Canada. Thus far, the Marcellus has attracted the most attention from investors and producers, though interest has picked up in the Utica–particularly the shallow portion in Ohio and Western Pennsylvania.

For example, Devon Energy has assembled an 110,000-acre leasehold in the play’s oil window and recently noted that a vertical test well indicated that the formation features excellent permeability. During Devon Energy’s conference call to discuss second-quarter results, the head of its exploration and production operations noted that the play’s oil window “could offer some of the best economics in the play.”

CEO Aubrey McClendon and his team at Chesapeake Energy (NYSE: CHK) likewise highlighted the firm’s position in the Ohio portion of the Utica during the company’s July 29 conference call. One of the first movers in the play, Chesapeake quietly amassed 1.25 million net acres–by far the largest position in the field–and drilled some of the first test wells, including nine verticals and six horizontals. Over this period, the company has also analyzed 3,200 feet of core samples and more than 2,000 well logs.

McClendon compared this portion of the Utica Shale to the Eagle Ford in South Texas, noting that the field includes three phases: a dry-gas zone in the east; a wet-gas window in the middle; and an oil-rich phase on the western side.

The outspoken CEO boldly suggested that the emerging field would generate better returns than the red-hot Eagle Ford: “[W]e believe the Utica will be economically superior to the Eagle Ford because of the quality of the rock and location of the asset.”

Not only is much of the company’s acreage already held by production, but the relative shallowness of these oil and gas reserves should limit drilling costs. Although management demurred from sharing well results, McClendon did indicate that his team was sufficiently encouraged to ramp up the rig count from one at the beginning of 2011 to eight units by year-end. At the same time, the play will require a substantial investment in midstream infrastructure to process and transport the oil, NGLs and natural gas to market.

3. Neuquen Basin

In The Future of Shale Gas is International, we opined that major international oil and natural gas companies were investing heavily in US shale plays to gain experience that would translate to fields outside the US. Argentina’s Neuquen Basin is home to one of the most-promising international shale oil plays.

Spanish energy giant Repsol (Madrid: REP, OTC: REPYY) in July announced that its Bajada de Anelo X-2 exploration well had yielded 250 barrels of oil per day from the Vaca Muerte shale formation.

US operator EOG Resources added 100,000 acres in the Neuquen Basin to its exploration portfolio in the second quarter and plans to sink two wells in this acreage in early 2012. During a recent conference call, CEO Mark Papa noted that he expected results from the play to help operators overcome a lack of hydraulic fracturing and other equipment in the country:

[T]he major service companies are in a process of shifting additional frac [hydraulic fracturing] equipment down there, and for the first couple wells, it’s going to be kind of one-off deals that we’ll have to schedule months and months in advance to get the fracs done. But our logic is if this shale turns out to be something that is commercial and productive, that you’ll see, particularly the major service companies, just move equipment in there in a 2013 through 2015 time frame. We’re pretty optimistic about the quality of that shale. We charged our people with the only way we’d go outside North America is if we could find a shale–an oil shale that we thought looked superior to the Eagle Ford, and we believe we’ve found one there. So time will tell.

Original Article

Devon sees great potential with Tuscaloosa Shale oil play in Louisiana

August 3, 2011

By Phaedra Friend Troy

US independent Devon Energy (NYSE:DVN) has completed its first well in the emerging Tuscaloosa Shale oil play in the panhandle of Louisiana.

Located along the Louisiana-Mississippi border, the Tuscaloosa Shale is stratigraphically equivalent to the Eagle Ford Shale in South Texas, which is producing oil, liquids and natural gas. Situated in 200- to 400-foot-thick formations, the Tuscaloosa Shale ranges from depths of 11,000 to 14,000 feet below the surface.

During the company’s first quarter announcements, Devon revealed that it had quietly bought 250,000 acres of leasehold from individuals in the Tuscaloosa Shale oil play in Louisiana. Paying $180 an acre, Devon serves as the operator of the effort.

With first drilling starting in May 2011, Devon has completed its first well into the source rock, an assessment well drilled vertically to gather information about the formation. The company completed drilling, coring and logging operations on the Lane 64-1 assessment well.

Devon has since spud its second well in the Tuscaloosa Shale; and this one is a horizontal well. The Beech 68-1H is updip from the first well, and Devon plans to obtain additional core and log data before drilling the lateral and completing the well as its first horizontal in the Tuscaloosa Shale.

“We will have to find out through drilling, but we think there’s some potential there because of the history of producing oil there,” Chip Minty, media relations manager for Devon told PennEnergy.

An innovator in shale development, Devon first became active in the Barnett Shale in Central Texas in 2001, when the company bought Mitchell Energy & Development Corp. 10 years ago. Devon was one of the first firms to employ horizontal drilling and hydraulic fracturing to extract hydrocarbons trapped in the tight formations.

Over the last year, Devon has also purchased acreage in the Utica Shale in Ohio and Michigan, as well as the Niobrara Shale play.

Original Article

Two energy firms plan Tuscaloosa Marine Shale play

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By TED GRIGGS
Advocate business writer
Published: May 6, 2011

Two energy companies announced plans this week to drill or complete four horizontal wells in the Tuscaloosa Marine Shale, an oil-rich formation that straddles the middle of Louisiana.

A third independent, Amelia Resources LLC of The Woodlands, Texas, has signed a deal with an unnamed partner to help develop the more than 110,000 acres Amelia has under lease.

Devon Energy officials said Wednesday the Oklahoma City-based company has leased around 250,000 acres in the shale. Devon plans to drill two wells in the formation this year, the first of them this quarter.

On Thursday, Dallas-based Denbury Resources announced a joint venture with an unnamed partner that will complete one well and drill another at no cost to Denbury. In late 2009, Denbury acquired Encore Acquisition Co., which had drilled some wells in the shale.

In a news release, Denbury Chief Executive Officer Phil Rykhoek said the company will retain a small interest in future activities in the shale.

“We continue on our oil-focused program and expect many good things in the near future,” he said.

LSU researchers have estimated the Tuscaloosa Marine Shale holds 7 billion barrels of oil.

During Wednesday’s conference call with stock analysts and investors, Devon Executive Vice President of Exploration and Production David Hager said the formation lies 11,000 to 14,000 feet underground and is 200 feet to 400 feet thick.

Hager said Devon believes it can use fracturing technology — pumping in water, sand and chemicals to crack the shale — to increase production in the formation.

The state plans to hold a hearing, possibly by next month, on whether to approve Devon’s request to use hydraulic fracturing for a well near Ethel in East Feliciana Parish. “Fracking” has drawn criticism from environmentalists who say the process contaminates the water supply and places a heavy burden on the resource. The oil and gas industry says those claims are inaccurate.

Hager said vertical wells drilled in the formation had initial production rates of 300 barrels per day.

The three or four horizontal wells drilled in the shale three years ago, which were shorter than Devon plans to drill, tested at rates of up to 500 barrels per day, Hager said.

Those are all reasons for encouragement, Hager said. But Devon needs to get more information on the oil play, including whether the formation can be fractured, and there are risks associated with Devon’s investment.

Still, the company has spent less than $50 million on its leases, and if Devon is successful the company “can create an awful lot of value,” he said.

Kirk Barrel, president of Amelia Resources, said drilling a longer horizontal segment, or lateral, exposes the wellbore to as much rock as possible, and that means the well can produce more oil.

Barrel, author of a blog on the Tuscaloosa Marine Shale, said one of Encore’s wells was drilled horizontally out to 4,100 feet; a typical horizontal section is 4,000 to 5,000 feet long.

However, in the two wells it fractured, Encore only did three stages, Barrel said. Devon’s plans show the company plans to do 13- to 15-stage fracks, which in theory should substantially increase production.

In the south Texas Eagle Ford Shale, “a distant cousin” geologically of the Tuscaloosa Marine Shale, some drilling companies have done 20-stage fracks, Barrel said. In North Dakota’s Baaken Shale, some wells have had 40-stage fracks.

Matt Ross, a spokesman for the Louisiana Oil and Gas Association, said in multistage fracturing, the initial fracturing is done around the point where a well levels out horizontally.

The subsequent fracks are spaced throughout the rest of the horizontal section, Ross said. The spacing depends on the drilling company’s preference.

Meanwhile, Barrel said his firm has placed a significant amount of acreage with an unnamed partner.

Barrel said he could not disclose how much acreage Amelia now has under lease; in February that was more than 110,000 acres.

Amelia is still in the process of adding to its acreage, Barrel said, and he did not know when the partnership might begin drilling.

Original Article

Drilling: U.S. Embargo May Hinder Oil-Spill Response in Cuban Waters

Platts – A long-standing embargo imposed by the United States on Cuba could make it more difficult to clean up potential oil spills as the Caribbean nation prepares to drill in deep water 50 miles from the shores of Florida, according to the head of an international drilling trade group. Lee Hunt, the president of the International Association of Drilling Contractors (IADC), made his comments to Platts Energy Week (http://www.plattsenergyweektv.com/), the independent, all-energy television news and talk program airing Sundays in the United States.

Hunt said that the U.S. embargo on Havana has required drillers there to use second-hand equipment to avoid buying it from U.S. companies. “The impact of the embargo has to do if something goes wrong, and what kind of resources can be mobilized to cap or stem the flow of a runaway well or to contain a spill.”

Cuba has been a target of a U.S. embargo since 1962. A subsequent U.S. law allows foreign companies working with Cuba to use only 10% U.S.-made equipment, or face sanctions on their operations in the United States.

Spanish-owned Repsol plans deepwater drilling off the Cuban coast later this year using a drilling rig built in China specifically to avoid the embargo.

“What the contractor has had to do is shop around its used inventory to locate a piece of equipment that falls outside the restrictions of the embargo, so the embargo, in effect has forced the drilling contractors working in Cuba to go to second-level equipment,” Hunt said.

Hunt’s comments come a little more than one year after the anniversary of the 2010 Macondo well blowout in the Gulf of Mexico resulted in the worst oil spill in U.S. history.  A report from the Interior Department found that human failure was the primary cause of the disaster, but that a malfunctioning blowout preventer was a major contributing factor to the magnitude of the spill.

“It is unnerving that as we work here in the Gulf of Mexico with the Department of Interior and the [Bureau of Ocean Energy Management, Regulation and Enforcement] that as we seek the gold-plated standard for the United States, the impact of the embargo is to force our neighbor, drilling very, very close to our shores, to go into a secondary market for parts, service and supply.”

Cuban officials have been very supportive of drilling safety, Hunt said. “What we are hearing from Cuban officials is a great deal of respect for the various regulatory schemes in the world, and in particular the new ones emerging in the U.S.,” Hunt said. ‘They are attempting to follow what can be communicated as best practices.”

The interview with Hunt was shortly before the U.S. announced it would allow the Cuban officials to attend a conference in Trinidad next month sponsored by the U.S.-based IADC to discuss Cuba’s deepwater drilling plans. Permission from the United Sates was required because IADC is a U.S. group and the embargo prohibits U.S. citizens from meeting with Cuban officials. The full interview may be accessed here.

As plans for deepwater drilling ramp up off the Cuban coast, the presence of a delegation from Havana including the country’s top drilling regulator would mark the first time they have discussed that drilling in an international forum. The IADC hopes to use the forum to discuss international best practices with Cuban officials.

In a segment entitled Iraq Plays Catch-up on Oil, Platts Baghdad-based correspondent Ben Lando reported on Iraq’s race to rebuild its oil infrastructure and play a bigger role in oil and natural as markets.

In this week’s Energy Watch segment, Platts Energy Week featured Devon Energy’s William Whitsitt, executive vice president for public affairs, on the topic of a new national database on fluids used in shale gas drilling. Whitsitt spoke about his company’s participation in a new voluntary database. Platts Gas Daily Associate Editor Bill Holland offered an update on the latest developments in the Marcellus Formation, the rich shale gas region that stretches from New York to West Virginia.

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