Noble to Build 4th High-Spec Newbuild This Year

- Noble to Build 4th High-Spec Newbuild This Year

Thursday, September 01, 2011
Noble Corp.

Noble announced that a subsidiary has exercised its option with Hyundai Heavy Industries Co. Ltd. ("HHI") for the construction of an additional ultra-deepwater drillship, the fourth such drillship to be ordered this year subject to the parties executing an agreed form of construction contract, which is expected to occur within the next several weeks. The additional ultra-deepwater drillship, to be named at a later date, will be constructed on a fixed price basis at HHI's shipyard in Ulsan, Korea, with expected delivery from the shipyard during the second half of 2014. Following shipyard delivery, the unit is expected to undergo the customary 90-120 day period for mobilization and acceptance prior to being ready to commence a contract. The rig is uncontracted at this time.

The delivered cost of the new drillship is expected to be $630 million and includes the turnkey construction contract, Company furnished equipment, project management and spares, but excludes capitalized interest. The construction contract contains favorable payment terms that incentivize on-time delivery.

"We continue to see an increase in deepwater demand, both near and longer-term," said David W. Williams, Chairman, President and Chief Executive Officer, Noble Corporation. "This view is bolstered not only by geologic successes in the traditional regions offshore the U.S. Gulf of Mexico and Brazil, but also by emerging regions offshore West Africa, Indonesia, the Black Sea, India and eastern Africa. With the addition of this fourth HHI newbuild drillship, by 2014 Noble will have one of the newest, most versatile and technologically advanced floater fleets in the industry with a total of 28 units, 16 of which will be dynamically positioned."

The new drillship announced Wednesday is based on a Hyundai Gusto P10000 hull design and is designed for operations in waters of up to 12,000 feet, but will be delivered fully equipped to operate in up to 10,000 feet of water. The unit will be equipped with DP-3 station keeping, the ability to handle two complete BOP systems, and multiple parallel activity features that improve well construction and overall project efficiencies, including a heave compensated construction crane to facilitate deployment of subsea production equipment. The drillship will also have accommodations for up to 210 personnel, in addition to a number of other operational enhancements beyond the shipyard's base specifications.

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Aker Solutions to Create 500 UK Jobs Next Year

- Aker Solutions to Create 500 UK Jobs Next Year

Friday, August 19, 2011
Aker Solutions

Aker Solutions aims to create 500 new UK jobs over the next year. In a bid to grow its business substantially, Norway-listed Aker Solutions is set to recruit 300 staff to its Aberdeen operation and create 200 positions at the company's newly established west-London engineering office.

The move follows a successful start to the year for the oil and gas engineering and technology services company, which has increased its order backlog by 19 percent since January 1st. It said that market outlook for both the UK and Norwegian North Sea as well as Brazil, West Africa and Asia Pacific remains strong.

"Last year we decided to take a much more proactive recruitment approach. Since then our strategy has been to man up ahead of the big waves of work that we know are coming. That offers much greater predictability for our customers and ourselves," said Alan Brunnen, a managing director with Aker Solutions in Aberdeen. The company aims to recruit 300 new employees in Aberdeen alone.

The majority of positions in Aberdeen are for the subsea technology business where 200 new posts will be created. A further 70 positions are being recruited to support work for maintaining and upgrading North Sea oil platforms in order to extend their field life. Aker Solutions' well service business, which provides technologies and services aimed at increasing oil recovery from producing wells, requires a number of technical and ancillary personnel. As does the drilling technology business, which provides drilling systems and life-cycle services to support new generation drilling assets that are entering the UK North Sea.

New London office

By tapping into the London oil and gas market, Aker Solutions in the next year aims to hire approximately 200 engineering personnel to its new London offices with a target of 500 by the end of 2015. Located in Chiswick Park, this global engineering hub will support field development projects for the North Sea and worldwide.

"Our company has had a historical presence in London, so this is a re-entry to an engineering market we know very well. So far we have received more than 2 000 job applications, which underlines that there is scope to grow this business rapidly," said Valborg Lundegaard, head of engineering in Aker Solutions.

Alan Brunnen added, "We anticipate that workload levels will remain high over the coming years, which is why we are staffing up our UK organization now. We want to be well placed to capitalize on future opportunities that arise in our markets".

Aker Solutions is one of Scotland's largest employers with a workforce of more than 2 500 people. In addition the company has smaller offices and facilities in Great Yarmouth, Maidenhead, Stockton-on-Tees and Whitstable. The company employs 17 000 employees plus 6 000 contract staff in 30 countries worldwide, and has annual revenues of approximately GBP 3.9 billion.

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Pennsylvania Shale Gas Output to More Than Double This Year - Study

- Pennsylvania Shale Gas Output to More Than Double This Year - Study

Thursday, July 21, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Natural gas production from Pennsylvania's Marcellus Shale should reach the equivalent of 3.5 billion cubic feet per day this year, more than double 2010's output, according to new research by a trio of Pennsylvania State University professors.

The study, released Wednesday, further estimates that production in the state from the deeply-buried rock formation will rise to the equivalent of 6.7 billion cubic feet per day in 2012 and 17.5 bcfe in 2020.

That level of production would make the Pennsylvania basin the largest supplier of natural gas in the U.S., able to meet about 25% of the country's demand, said Kathryn Klaber, who heads the Marcellus Shale Coalition, an oil and gas industry advocacy group.

The Marcellus Shale underlies parts of several Mid-Atlantic and Midwestern states but production is centered in Pennsylvania.

In 2010 1,405 wells were drilled there, yielding the equivalent of 1.3 billion cubic feet of gas per day, according to the study. The professors, who obtained data from producers through the advocacy group, said that 2,300 wells are planned to be drilled this year and forecast that the number will steadily rise to about 2,500 a year by 2020.

While producers have focused on Pennsylvania with some forays into Ohio and West Virginia, several are eying an expansion into New York.

Many initially believed that southwest Pennsylvania held the most productive fields. But a string of recently drilled wells in northern Pennsylvania have made exploration in New York -- where a ban on hydraulic fracturing, the controversial technique needed to crack open the energy-bearing rock, was recently lifted -- more attractive.

Twenty-four of Pennsylvania's 25 highest producing wells are in counties that border New York, according to the Pennsylvania Department of Environmental Protection.

In May, Houston-based Cabot Oil & Gas said two of its wells in that border area are producing nearly 30 million cubic feet of natural gas per day -- significantly more than any previous Pennsylvania wells.

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

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Taiwan's Oil Company to Invest $1.18B A Year

- Taiwan's Oil Company to Invest $1.18B A Year

Tuesday, July 19, 2011
Dow Jones Newswires
TAIPEI

Taiwan's state-run Taiwan's state-owned CPC, said Tuesday it will invest NT$34 billion ($1.18 billion) annually in the next five years to acquire and explore overseas energy resources.

CPC plans to spend NT$30 billion a year on acquiring oil and gas fields mainly in Africa and the Asia Pacific region while the rest will go on oil exploration, it said.

As a result, the company expects to be able to boost its daily crude output from 12,000 barrels daily at present to 27,000 barrels a day from 2012, a company official said.

The company is in talks to buy oil and gas fields in Africa and Australia, with expectations that deals can be concluded by late this year or early next year, she said.

CPC started exploring oil reserves abroad in the 1970s and its latest venture in Chad is estimated to have at least 100 million barrels in reserves.

CPC supplies about 700,000 barrels of crude oil a day or about 60% of Taiwan's daily usage, of which only 1% is produced by itself and the rest is imported.

Taiwan doesn't have any oil resources of its own and is dependent on imports mainly from the Middle East and Africa.

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

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Toyota Motor Estimates 31% Drop Full Year Net Profit

- Toyota Motor Estimates 31% Drop Full Year Net Profit



Jun 10, 2011

Toyota Motor (NYSE:TM) said today it expects its net profit to fall by almost a third this year, as production continues to be disrupted 3 months after the massive earthquake and tsunami that struck Japan on March 11th.

The company predicted its profit for the full year ending in March 2012 would decline 31% to $3.5 billion.

Analysts had been expecting a profit of $5.28 billion, and the company reported $5.1 billion in profit for the year ending March 2011.

The company expects full year sales to decline 2%, and said global production wouldn't recover completely until November.

Toyota Motor has a potential upside of 14.3% based on a current price of $80.84 and an average consensus analyst price target of $92.4.

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Commissioner Seeks to Complete Rule-Making on Fracturing Bill a Year Early

- Commissioner Seeks to Complete Rule-Making on Fracturing Bill a Year Early

Friday, June 03, 2011
Rigzone Staff

Texas Railroad Commissioner (TRC) David Porter said would push the Railroad Commission (RRC) to complete the entire rule-making process requiring disclosure of chemicals used in hydraulic fracturing a year ahead of the deadline set in recent legislation.

The Texas Legislature on May 31 sent a bill to Governor Rick Perry on requiring the RRC to write disclosure rules for hazardous chemicals by July 1, 2012. The bill requires the RRC to complete rule-making for all other chemicals used in the process by July 1, 2013.

"In order for Texans to maintain confidence in the oil and gas industry, it is important for us to get this done as quickly as possible," said Porter. "Hydraulic fracturing has been an economic driver for Texas, creating hundreds of thousands of jobs and adding billions of dollars to local economies. We are currently seeing record activity in the Eagle Ford Shale due to hydraulic fracturing which is why I am creating a task force to study these very issues. We need to assure the public that hydraulic fracturing is safe and responsible – and has been for the past sixty years – and we need to do it now."

The RRC will begin the rule-making process at its next open conference this month and will hold open meetings throughout the state in coming months to garner public comment.

Porter said the agency may increase the number of members on TRC's newly formed Eagle Ford shale task force from the original plan for between 15 to 18 members due to the quality of applications. TRC is reviewing applications now and hopes to have selected all members of the voluntary task force, which will include a mix of energy industry members, local environmental groups, elected officials and landowners in the Eagle Ford shale area of South Texas, by the end of June.

TRC decided to form the Eagle Ford shale task force to head off the perception and communication problems encountered with the Barnett shale gas drilling boom hit Texas. "We're trying to be proactive, not reactive," Porter said.

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CNOOC: Confident Will Achieve Full Year Output Target this Year

- CNOOC: Confident Will Achieve Full Year Output Target this Year

Friday, May 27, 2011
Dow Jones Newswires
by Yvonne Lee

CNOOC expects to meet its full-year output target despite the shutdown of four oil fields in the Bohai Bay last month due to a malfunction, Chief Executive Yang Hua said Friday.

Cnooc said in March it planned to raise crude-oil and natural gas output in 2011, targeting production of 355 million-365 million barrels of oil equivalent, up 8%-11% from 328.8 million barrels in 2010.

The company is also targeting oil and gas output growth at a compound annual rate of 6%-10% between 2011 and 2015.

In April, four of Cnooc's oil fields with a total production capacity of about 39,000 barrels a day were shut down following a malfunction at a vessel in the Bohai Bay caused by rough sea conditions.

Yang also said he expects the company to drill four to six deep-water wells in the South China Sea this year, and added that the company plans to accelerate oil exploration in deep-water wells over the next four years.

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

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Quicksilver Resources Counting On A Big Year

- Quicksilver Resources Counting On A Big Year

Tuesday, May 24, 2011
Fort Worth Star-Telegram, Texas
by Jack Z. Smith

Quicksilver Resources CEO Glenn Darden expects 2011 to be "a breakout year" as the company advances into the development phase of its Horn River Basin project in Canada, moves into oil exploration and continues amping up natural gas production from North Texas' Barnett Shale.

"It looks like it's going to be a fabulous year," Darden said at last week's annual shareholders meeting of the Fort Worth-based natural gas producer, which has a healthy $500 million capital budget for 2011. "We're moving more toward oil, but we're still a gas company, and we'll always be a gas company," Darden told shareholders at the downtown Fort Worth Club.

Quicksilver will soon start to show "how valuable Horn River is," as it completes more natural gas wells in cold, remote northeast British Columbia and benefits from new pipeline links allowing it to transport more gas to market more cheaply, Darden said. The company is also testing for oil there.

With 130,000 net acres leased at Horn River, Quicksilver has drilled eight natural gas wells there and completed four, which cumulatively are producing 30 million cubic feet a day. It expects to complete the other four wells this coming winter, when drilling equipment can be transported on ice roads. In warm weather equipment bogs down in the swamplike terrain called muskeg.

Horn River potential

Quicksilver estimates that each Horn River well will have an exceptional "estimated ultimate recovery," or lifetime output, ranging from 8.8 billion to 19.4 billion cubic feet of gas. Those numbers far exceed the 1 billion to 5 billion cubic feet estimated for most Barnett Shale gas wells, although operating costs are considerably lower in the Barnett.

Quicksilver's latest annual report said Horn River "appears to be the largest gas find in the company's history and has the potential to quadruple our current total company reserves." The company estimates that it could recover 10 trillion cubic feet of natural gas from Horn River, or nearly double what it expects from the Barnett.

As of Dec. 31, Quicksilver's proved reserves were equivalent to 2.9 trillion cubic feet of natural gas, with 2.6 trillion from the Barnett. The reserves are 99 percent natural gas and natural gas liquids such as propane and butane.

Getting more 'oily'

Crude oil accounts for a tiny 1 percent of Quicksilver's reserves, but that could rise. U.S. energy producers are increasingly focusing on oil and natural gas liquids, which command higher prices than natural gas. Quicksilver is pushing this year to become more "oily."

The company expects to complete a horizontal well in the Exshaw formation at Horn River this summer, with oil the target instead of natural gas. Quicksilver has "gotten great oil shows" there, Darden said, from both the Exshaw and from natural gas in the Muskwa and Klua formations below it.

Darden said Quicksilver's biggest thrust into oil this year will be in the emerging Niobrara play in the Green River Basin, where the company has 200,000 net acres leased in northwest Colorado. The company expects to drill up to six exploratory wells there this year.

"We're in oily country, and we're very excited about it," Darden said. "The Niobrara has about 1,500 feet of thickness, so it's a very big target."

Quicksilver is also launching some oil prospecting in the Bakken formation in northern Montana, where it has 175,000 net acres.

The company is also "targeting multiple formations" in the Delaware Basin in West Texas that could yield oil, said Rick Buterbaugh, Quicksilver's vice president for investor relations and corporate planning. These targets include the Bone Springs formation that is attracting increasing attention.

The company has 54,000 net acres leased in Culberson, Reeves, Jeff Davis and Presidio counties and expects to acquire more.

Quicksilver can move quickly in West Texas by re-entering "noncommercial natural gas wells" the company drilled in the West Texas portion of the Barnett Shale, Buterbaugh said. The clay content in the Barnett zone made the results from fracking "less than desired," Buterbaugh said.

With the new oil plays, Quicksilver has "some very high-potential prospects that can really change the look of this company," Darden said.

The company has had lackluster earnings the past two years, primarily because of weak gas prices and related write-downs. The company's stock (ticker: KWK) closed Friday at $14.44, up 14 cents. The stock is down about 2 percent this year.

Quicksilver, however, generally has been a low-cost operator and profited from the sale of its majority interest in Quicksilver Gas Services, which helped trim its debt to a manageable $1.7 billion, with major debt maturing in late 2015. It had 65 cents of debt per 1,000 cubic feet of reserves as of Dec. 31, down 44 percent from $1.17 two years earlier.

Barnett still mainstay

The company's bread-and-butter revenue source this year should continue to be the Barnett Shale, where Quicksilver hopes to boost production by 20 percent. Some of the company's biggest gas wells, with estimated lifetime production of 4 billion to 5.5 billion cubic feet, are in the Alliance and Lake Arlington areas, but smaller wells in the southern Barnett provide more natural gas liquids.

Although natural gas prices have barely topped $4 per 1,000 cubic feet, Darden said Quicksilver will benefit by hedging most of its 2011 gas production at just under $6.

In the company's annual report, Darden said Quicksilver doesn't believe today's abnormal price disparity between oil and natural gas will continue. And at the shareholders meeting he said company officials believe its stock is undervalued.

"We believe this presents a tremendous opportunity to invest in natural gas at the bottom of the cycle," he concludes in the annual report.

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

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Repsol to Begin Offshore Cuba Drilling Later This Year

- Repsol to Begin Offshore Cuba Drilling Later This Year

Friday, May 20, 2011
Rigzone Staff
by Karen Boman

Saipem-owned semisubmersible Scarabeo 9 is set to leave Keppel Shipyard in Singapore next month or July and arrive offshore Cuba sometime in September to drill the Jaguey prospect for Repsol in 5,300 feet of water, a little bit deeper than the Macondo well, said Jorge Pinon, a visiting fellow with the Florida International University Latin America and Caribbean Center's Cuban Research Institute.

The Jaguey well will be drilled to more than 20,000 feet approximately 55 to 60 miles south of Key West, Florida and 22 miles north of Havana, said Pinon, who is a former president of Amoco Oil Latin America; he retired in 2005 from BP, which acquired Amoco. According to RigLogix, Scarabeo 9 will earn a day rate in the low-$470,000s.

While Cuba opened its offshore Gulf of Mexico zone for drilling five years ago, Repsol and other operators who hold interests in Cuban blocks, including Malaysia's Petronas and Russia's Gazprom, encountered difficulty starting their drilling programs as the U.S. embargo on Cuba meant that rigs used to drill in Cuban waters must be outfitted with no more than 10 percent of U.S components.

Operators then ordered the Scarabeo 9, which has been outfitted to meet U.S. embargo requirements. The rig is expected to be used for drilling five to seven exploratory wells. Repsol will use the Scarabeo 9 to drill two exploratory wells for Repsol, Petronas is expected to use the rig to drill two wells. Venezuelan state energy company PDVSA and Angola state energy company Sonangol might pick up the rig for drilling offshore Cuba as well.

Last year's Macondo oil spill has raised concerns about what would happen if an oil spill occurred offshore Cuba. A spill here would threaten Key West and the U.S. East Coast; The embargo means that, if an emergency arises or if a piece of equipment is needed, international oil companies operating offshore Cuba could not turn to U.S. based companies in these situations. The U.S. also does not have a spill agreement with Cuba as it does with Mexico, with drill exercises conducted twice a year. Pinon noted that companies with interests offshore Cuba would ask for a general license to allow them access to U.S. Gulf Coast companies and assets in both situations.

The embargo means that Repsol and other companies have to bring in workers for planned exploratory programs offshore Cuba are being brought in from Norway, the UK and Canada. "Utilizing workers from the U.S Gulf Coast would be the most economic and closest, but the embargo doesn't allow that," Pinon said.

Pinon said that the Cuban government has adapted into their regulations many of the regulations that came out of Bureau of Ocean Energy Management, Regulation and Enforcement since the Macondo oil spill and will use many of the lessons BP learned from Macondo for exploratory drilling offshore Cuba. Cuban officials discussed drilling and safety plans at a conference in Trinidad and Tobago two weeks ago.

Cuba is seeking to explore for and develop its oil resources in order to reduce its dependency on oil imports from Venezuela, Pinon said. According to a U.S. Geological Survey in 2004, a mean of 4.6 billion barrels of undiscovered oil and a mean of 9.8 Tcf of undiscovered gas lie in the North Cuba Basin of northwestern Cuba.

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Deepwater Horizon: One Year Later

Deepwater Horizon: One Year Later

Wednesday, April 20, 2011
Rigzone Staff
by Jaime Kammerzell

A year ago today, an explosion on Transocean's Deepwater Horizon ultra-deepwater semisubmersible, positioned at the Macondo Prospect in Mississippi Canyon Block 252, in the Gulf of Mexico, took the lives of 11 men and caused the largest marine oil spill in history.

At 9:45 p.m. on April 20, 2010, while plugging the well for later production, seawater erupted from the marine riser onto the rig, shooting 240 ft into the air. A combination of mud, methane gas, and water quickly followed. The gas then ignited, causing explosions onboard. Attempts to activate the blowout preventer failed. Survivors said they had less than five minutes to escape after the alarm went off. Multiple ships attempted to put out the fire, but it could not be extinguished. After burning for 36 hours, the Deepwater Horizon sank in about 5,000 ft of water on April 22, 2010.

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A total of 126 people were onboard the Deepwater Horizon at the time of the explosion. Only 115 evacuated. Those who were able to escape took lifeboats to the M/V Damon B Bankston workboat nearby, which had been servicing the Deepwater Horizon. The US Coast Guard searched for three days.

Although BP was the operator of the Mocondo field, it was working with Transocean and Halliburton to plug the well for later completion as a subsea producer. BP believes that Transocean and Halliburton share the blame for the disaster.

According to Transocean, its employees had been performing routine work and did not notice any problems leading up to the explosion. Halliburton had finished running production casing and cementing 20 hours before the blowout. Transocean's CEO, Steven Newman, pointed his finger at Halliburton when he said, "there was a sudden, catastrophic failure of the cement, the casing or both."

When the semisubmersible sank, it left the well gushing oil out of the riser into the Gulf of Mexico. The resulting oil slick covered about 28,958 sq mi and reached beaches in Louisiana, Mississippi, Alabama and Florida by June 9th, when BP reported that it had lost more than $82 billion, close to half its value.

BP began drilling two relief wells on May 2 and May 16. In an attempt to stop the oil spill sooner, BP also tried using remotely operated underwater vehicles to close the BOP valves on the well head. This failed. BP then tried to place a 125 tonne containment dome over the largest leak to pipe oil to a storage vessel on the surface, but this attempt failed when gas leaked from the pipe and mixed with the cold water, which formed methane hydrate crystals that blocked the opening at the top of the dome. Pumping heavy drilling fluids into the BOP to restrict oil flow and permanently seal it with cement failed as well.

BP then tried positioning a riser insertion tube into the burst pipe. This worked adequately until the damaged riser could be capped on June 3rd. A washer plugged the end of the riser and diverted it to the insertion tube. Gas was flared and oil was stored on board the Discoverer Enterprise drillship. But this solution didn't last long. A second containment system, which connected directly to the BOP, was installed on June 16. The oil and gas were diverted to the Q4000 service vessel where it was burned. This worked well, so the Discoverer Clear Leader drillship and Helix Producer I FPSO joined in the effort, offloading oil to the Evi Knutsen and Juanita tankers. Two more vessels, the Seillean FPSO and Toisa Pices well testing vessels processed oil and offloaded to the Loch Rannoch shuttle tanker.

BP was pleased with this solution and announced on July 5, 2010, that it was recovering about 25,000 b/d and flaring 57.1 Mcf/d. However, the government estimated that the cap only captured about half of the leaking oil. BP made further adjustments to its cap solution and replaced the original cap on July 10 with a Flange Transition Spool and a 3 Ram Stack. On July 15, BP tested its new and improved cap by shutting off pipes that brought oil to the surface ships. This allowed the total pressure of the gushing oil to flow into the cap. The cap contained the oil and stopped the leak.

Meanwhile, BP continued to drill the two relief wells, which took four months to reach the Macondo well on September 15. BP pumped cement into the well 17,977 ft below the sea floor to permanently seal it. It took three days to complete. BP then permanently completed and abandoned the initial Macondo well as well as the two relief wells.

Though the oil has stopped gushing into the GOM, the aftermath remains today. Aside from the environmental and fishing and tourism impact, offshore exploration and production has been slow to return to pre-disaster levels. This is due mainly to governmental restraints.

On May 27th, President Obama instituted a temporary moratorium on offshore drilling in 500 ft or more of water, which also suspended drilling on 33 wells already in progress. He also implemented new standards for equipment and procedures.

The US Department of the Interior then issued tighter standards for barriers at underwater wells and BOPs on June 8, 2010. At the same time, the Interior Department started requiring CEOs of drilling companies to certify that their operations comply with the new regulations, including equipment testing and personnel training. Drilling in less than 500 ft of water resumed under the new standards. However, the deepwater drilling ban remained in effect until June 22, when a US federal judge in New Orleans lifted the moratorium saying it was "a blanket, generic, indeed punitive moratorium," as well as a potential harm to the economy, businesses and workers.

In response, Interior Secretary Salazar immediately issued a new order that contained additional information showing why the moratorium was necessary. The Interior Department defended Salazar's actions, saying Interior Secretary Ken Salazar "has merely fulfilled his continuing duty to manage the [Outer Continental Shelf] by reanalyzing the previously directed suspensions, evaluating new information on the adequacy of safety and environmental protection standards for OCS lease operations in the Gulf of Mexico, and issuing a new decision."

Interior Secretary, Ken Salazar

The deepwater ban went in effect again until November 30, 2010. However, President Obama lifted the drilling ban in deepwater GOM waters on Oct. 11, 2010. Salazar said in a statement that drilling in waters deeper than 500 ft can resume if operators follow the new Drilling Safety Rule.

"Under these new rules, operators will need to comply with tougher requirements for everything from well design and cementing practices to blowout preventers and employee training," Salazar said. "They will also need to develop comprehensive plans to manage risks and hazards at every step of the drilling process, so as to reduce the risk of human error."

Though the drilling ban was lifted in October, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) didn't approve the first post-moratorium deepwater drilling permit until Feb. 28, 2011.

On Jan. 11, 2011, the White House released a report of its investigation of the oil spill. The report stated, "BP, Halliburton, and Transocean did not adequately identify or address risks of an accident…As a result, officials made a series of decisions that saved BP, Halliburton, and Transocean time and money—but without full appreciation of the associated risks."

Transocean and Halliburton attempted to sidestep the blame and pointed fingers at BP saying they were just following orders. Halliburton further criticized BP for its failure to run a cement bond log test.

In March, US Investigators, who hired Det Norske Veritas (DNV) to examine the failed blowout preventor, released a report that found a piece of drill pipe that was trapped inside the blowout preventer kept it from closing. The report didn't blame BP, Transocoean or Halliburton for the equipment failure. It simply focused on the cause of the failure.

According to a Reuters report from April 3, 2011, BP will be resuming its operations in the GOM in July 2011. The operator will be restricted to maintaining or increasing production on existing platforms. BP will not be permitted to drill exploration wells.


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Musings: Updated 2011 Hurricane Forecast Still Calls for Active Year

Musings: Updated 2011 Hurricane Forecast Still Calls for Active Year

Tuesday, April 12, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks


The latest forecast update from Professors Philip Klotzbach and William Gray of the Department of Atmospheric Science at the Colorado State University (CSU) says the upcoming hurricane season is expected to see above-average activity. The April 6th forecast is slightly lower than their December 2010 forecast largely due to uncertainty about the sea surface temperatures in both the South Pacific and South Atlantic oceans that can assist or retard the development and strengthening of tropical storms.

The forecasting team has developed a new April methodology based on a data collected from 1982-2010. There are four predictors employed in the model with two of them based on sea surface temperatures in the Atlantic and Pacific oceans. The Pacific Ocean for most of the past year has been cooler than normal, which helped contribute to the Atlantic basin’s storm activity last year mostly turning north before reaching the U.S. In general, sea surface temperatures in the eastern and central tropical Pacific Ocean have been 0.50C-1.00C below average.

Exhibit 21.  Pacific Ocean Sea Surface Temperatures Low


Source:  Colorado State University

On the other side of the globe, Atlantic Ocean sea surface temperatures remain at or above average levels. They have cooled recently but most likely that has been caused by a shift from a negative phase for the North Atlantic Oscillation to a positive phase. Atmospheric conditions currently are conducive for an active hurricane season as wind shear, a force that can limit the development and strengthening of tropical storms, across the basin has been well below average over the past two months.

Exhibit 22.  Atlantic Ocean Temperatures Near Normal
   
Source:  Colorado State University

With these conditions, the CSU forecasting team began looking for analog years to help fine-tune their forecast. They were looking for years generally characterized by weak to moderate La Niña conditions and above-average tropical Atlantic and far North Atlantic sea surface temperatures during February and March. They found five seasons that met these conditions. Four of them had either neutral or La Niña conditions during the hurricane season and all four of them were very active years. Those four years were 1955, 1996, 1999 and 2008.

Exhibit 23.  Analog Years For Hurricane Forecast
   
Source:  Colorado State University, PPHB

The forecasters also found 2006, which had the same February-March conditions. That year, however, experienced an unexpected El Niño, which greatly reduced hurricane activity.

The CSU team anticipates 2011 to be slightly more active than what was experienced in the average of these five analog years due to the very active season predicted by their new statistical model. It is interesting that there were only two analog years that fit the parameters for both the December 2010 and April 2011 forecasts, and those years were 1999 and 2008.

Exhibit 24.  Latest Hurricane Forecast Down Slightly

Source:  Colorado State University, PPHB

The CSU forecast calls for a total of 16 named storms, down one from the December 2010 forecast total. It also expects there to be nine hurricanes and five major hurricanes. The total number of storm days will be down by five, from 85 to 80, with a similar reduction for each of the other storm categories.

In terms of landfall probabilities, the forecast calls for a 72% probability of a storm hitting the entire U.S. coastline compared to the 52% average for the past century. There is a 48% chance of a landing on the East Coast including the Florida peninsula compared to the historic 31% rate.  For the Gulf Coast from the Florida Panhandle to Brownsville, Texas, there is a 47% chance of a tropical storm landfall versus the historical average of 30%. Despite the higher probabilities, nature is such that it is impossible to forecast with any degree of accuracy until a storm is on its way whether it will reach land.  For the offshore energy industry, it will need to be on alert this hurricane season, although if the current pace of permitting continues, there won’t be too many offshore rigs to have to worry about this fall. Is that a backhanded positive?

Download the PDF Musings041211.pdf

Kuwait Oil Spends $5.41B A Year on Capex

Kuwait Oil Spends $5.41B A Year on Capex

Monday, April 04, 2011
Dow Jones Newswires

by  Alex Delmar-Morgan & Wayne Ma

Kuwait Oil Company, responsible for the Gulf state's oil and gas exploration and production, is spending around 1.5 billion Kuwaiti dinars ($5.41 billion) on new capital expenditure every year, the group's chairman and managing director said Monday.

"On average we are spending about 1.5 billion Kuwaiti dinars a year on capital," Sami Al-Rushaid told reporters at an energy event in Kuwait.

He didn't elaborate on what the money was invested in.

Organization of Petroleum Exporting Countries member Kuwait is the world's fourth largest oil producer currently pumping around 2.2 million barrels a days and sits on about 10% of the world's crude reserves.