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BP Relied on Cheaper Wells --- Analysis Shows Oil Giant Used 'Risky' Design More Often Than Most

Peers By Russell Gold and Tom McGinty1,310 words19 June 2010The Wall Street JournalJ A1English(Copyright (c) 2010, Dow Jones & Company, Inc.) In recent years, oil giant BP PLC used a well design that has been called "risky" by Congressionalinvestigators in more than one out of three of its deepwater wells in the Gulf of Mexico, significantly moreoften than most peers, a Wall Street Journal analysis of federal data shows. The design was used on the well that exploded in the Gulf of Mexico on April 20, killing 11 workers andcausing America's worst offshore oil spill. The only other major well design, which is more expensive,

includes more safeguards against a natural-gas blowout of the kind that destroyed the Deepwater Horizon. A Journal analysis of records provided by the U.S. Minerals Management Service shows that BP used theless costly design -- called "long string" -- on 35% of its deepwater wells since July 2003, the earliest date thewell-design data were available. Anadarko Petroleum Corp., a minority partner of BP's in the destroyed well,used it on 42% of its deepwater Gulf wells, though it says it doesn't do so in wells of the type drilled by BP. Both companies used the design much more often, on average, than other major Gulf drillers. Out of 218deepwater wells in the Gulf drilled since July 2003, 26% used long-string design. It derives its name from itsuse of a single, long "string" of pipe from the sea floor to the bottom of the well. Other big drillers use long-string design less frequently than BP, according to the Journal's data analysis.Royal Dutch Shell PLC used long string designs on 8% of its wells and Chevron Corp. on 15%. Australianfirm BHP Billiton PLC used long string on 4% of its wells. The insight into BP's record comes amid fierce pressure on the oil giant and its partners, who share billions

in liability in the accident. Anadarko blasted BP Friday in a statement by Chief Executive Jim Hackett, whosaid: "The mounting evidence clearly demonstrates that this tragedy was preventable and the direct result of BP's reckless decisions and actions." A long-string design is cheaper because a single pipe runs the length of the well and can be installed in onestep. But it also can create a dangerous pathway for natural gas to rise unchecked outside the pipe. The alternative, known as liners, is seen as safer because it has more built-in places to prevent oil or gasfrom flowing up the well uncontrolled. "There are more barriers, and the barriers are easier to test," saysGene Beck, an engineer and professor at Texas A&M University. A BP spokesman said long string is widely used and is a perfectly acceptable design, particularly in areaswhere other wells have been drilled and the geology is well understood. "There is nothing inherently unsafeabout long strings," says BP spokesman Andrew Gowers. BP's chief executive, Tony Hayward, told acongressional panel Thursday that "the long string is not an unusual design in the Gulf of Mexico, as Iunderstand it."

Long-string wells are made of a continuous length of steel, which makes the well sturdier over time -- a pointMr. Hayward alluded to in his testimony, noting that the design decision had "to do with the long-termintegrity of the well." The Minerals Management Service signed off on BP's long-string plan for the Horizonwell, he added. "It was approved by the MMS," Mr. Hayward said. Anadarko says it doesn't use long-string design for drilling exploration wells in unfamiliar areas. Thecompany also says it only uses long strings in lower-pressure wells. The well BP was drilling with theDeepwater Horizon was an exploration well, and was well above normal pressure. As minority partner, Anadarko says it didn't have a role in deciding the BP well's design.




"It's not that long strings are unsafe, but they have to be under the right conditions," says Darrell Hollek, Anadarko's vice president of gulf operations. The other method, known as "liner tieback," is more complex and costlier. First, a section of pipe called aliner is placed at the bottom of the well and cemented into place, creating an extra barrier to prevent naturalgas from rising to the surface. Typically, another pipe is connected to the liner to create a pipe to the surface. Chevron's head of North American exploration and production, Gary Luquette, said Chevron typically avoids

long-string design because it offers fewer layers of protection. "You can make choices early on to cut costs,slim down your project to make it economic today and have dire consequences down the road, or you canbuild in that reliability and philosophy of dependability up front and save yourself a lot of headaches in thefuture," Mr. Luquette said. In an internal BP email released by a Congressional committee, a BP drilling engineer in Houston toldcolleagues that the long-string design "saves a good deal of time and money." A letter to BP's CEO, Mr. Hayward, by two Democratic Congressmen ahead of his testimony to their committee on Thursday, said the choice of the long-string design for the Horizon well was one of fivedecisions BP made that posed a trade-off between cost and well safety. Drilling experts say the long-string design can be riskier than liner-tieback, particularly for high-pressurewells. "It was a safe and accepted method, but it is not the most conservative method. The mostconservative would be to make sure there is not a straight shot [for gas] up to the surface, that you cementeverything in place," says Greg McCormack, director of the University of Texas at Austin Petroleum

Extension Service. According to an internal BP well-planning document seen by the Journal, the company expected the wellbeing drilled by the Deepwater Horizon to be high-pressure at least as far back as January. Well-control experts and congressional investigators agree that the well design, by itself, didn't doom theDeepwater Horizon. The design created a pathway for gas to flow up the well, potentially pressuringequipment near the floor of the Gulf. But the well would have been secure if the cement plug at the bottom of the hole had held. Congressional investigators Monday criticized BP for using a long string on that well. "The decision," says aletter from Congressmen Henry Waxman (D., Calif.) and Bart Stupak (D., Mich.), "appears to have beenmade to save time and reduce costs." Using a liner design would have cost an additional $7 million to $10million, according to an internal BP estimate released by the congressmen. The congressmen's letter noted that a long string creates only two barriers to prevent gas from flowing upthe well: cement at the bottom of the well, and a large seal where the well reaches the sea floor. The liner-tieback design adds two more barriers: the cement around the liner and a mechanical seal that attaches theliner to the pipes. Marvin Odum, president of Shell's U.S. operations, said Shell doesn't use a long string for high-risk wells.Shell said many of the times it used long strings in deepwater wells, either it hadn't encountered highpressures in the well, or the well was in an area where Shell had drilled and was comfortable with theconditions. "When it is a high-pressure, deepwater well, we only have one way of doing that way, and that iswith a liner tieback. Period," he says. --- Ben Casselman contributed to this report.




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Unusual Decisions Set Stage for BP Disaster By Ben Casselman and Russell Gold2,902 words27 May 2010The Wall Street JournalJ A1English(Copyright (c) 2010, Dow Jones & Company, Inc.) It was a difficult drill from the start. API Well No. 60-817-44169 threw up many challenges to its principal owner, BP PLC, swallowing expensivedrilling fluid and burping out dangerous gas. Those woes put the Gulf of Mexico project over budget andbehind schedule by April 20, the day the well erupted, destroying the Deepwater Horizon rig and killing 11men. Government investigators have yet to announce conclusions about what went wrong that day. The final stepin the causation chain, industry engineers have said in interviews, was most likely the failure of a crucial seal

at the top of the well or a cement plug at the bottom. But neither scenario explains the whole story. A Wall Street Journal investigation provides the mostcomplete account so far of the fateful decisions that preceded the blast. BP made choices over the course of the project that rendered this well more vulnerable to the blowout, which unleashed a spew of crude oil thatengineers are struggling to stanch. BP, for instance, cut short a procedure involving drilling fluid that is designed to detect gas in the well andremove it before it becomes a problem, according to documents belonging to BP and to the drilling rig'sowner and operator, Transocean Ltd. BP also skipped a quality test of the cement around the pipe -- another buffer against gas -- despite what BPnow says were signs of problems with the cement job and despite a warning from cement contractor Halliburton Co. Once gas was rising, the design and procedures BP had chosen for the well likely gave this perilous gas aneasier path up and out, say well-control experts. There was little keeping the gas from rushing up to thesurface after workers, pushing to finish the job, removed a critical safeguard, the heavy drilling fluid knownas "mud." BP has admitted a possible "fundamental mistake" in concluding that it was safe to proceed withmud removal, according to a memo from two Congressmen released Tuesday night. Finally, a BP manager overseeing final well tests apparently had scant experience in deep-water drilling. Hetold investigators he was on the rig to "learn about deep water," according to notes of an interview with himseen by the Journal. Some of these decisions were approved by the U.S. Interior Department's Minerals Management Service,which has come under fire for what President Obama has called its "cozy relationship" with the oil industry.But in at least one case, the decision made apparently diverged from a plan MMS approved. MMS declinedto comment. Some of BP's choices allowed it to minimize costly delays. "We were behind schedule already," said Tyrone

Benton, a technician who operated underwater robots and worked for a subcontractor. He said that on theday before the accident, a Monday, managers "hoped we'd be finished by that Friday . . . . But it seemed likethey were pushing to finish it before Friday." He added: "They were doing too many jobs at one time." Mr. Benton is suing BP and Transocean claimingphysical injury and mental anguish. BP acknowledges the well was running over budget but says it didn't cut corners. "Safe and reliableoperations remain a priority regardless of how much a well is behind schedule or over budget," spokesman Andrew Gowers wrote in an email. Some workers agree safety was paramount for both BP and Transocean. "Safety was their No. 1 concern.




Protecting the environment was their No. 1 concern," said Darin Rupinski, a Transocean employee whose job was to help keep the rig in place. BP was drilling to tap an oil reservoir it had identified called Macondo, the same name as the cursed town inGabriel Garcia Marquez's novel "One Hundred Years of Solitude." As on many past projects, BP hired adrilling rig from Transocean, the largest deep-water driller. Workers from Transocean and other contractorsdid most of the work, under the supervision of BP employees on the rig and in Houston. BP started working on the well in October, using a different rig. After three weeks natural gas got into thewell, called a "kick." That's not uncommon. But two weeks later a hurricane damaged the rig and it had to betowed to port for repairs. BP started again in January, this time with Transocean's Deepwater Horizon, a warhorse rig that had workedfor BP for years. BP filed a new drilling permit with federal regulators. According to a company document seen by the Journal, BP approved spending $96.2 million and about 78days on the well. The target time was much less -- about 51 days. By April 20, the well was in its 80th day,owing to delays such as one that had begun on March 8. That day, workers discovered that gas was seeping into the well, according to drilling reports from the rigreviewed by the Journal. Workers lowered a measuring device to determine what was happening, but whenthey tried to pull it back up, it wouldn't budge. Engineers eventually told them to plug the last 2,000 feet of the then-13,000-foot hole with cement and continue the well by drilling off in a different direction. The episode took days to resolve, according to drilling reports, not counting backtracking and re-drilling.Each extra l day cost BP about $1 million in rig lease and contractor fees. Other problems arose. The rock was so brittle drilling mud cracked it open and escaped. One person familiar with the matter estimates BP lost at least $15 million worth of the fluid. Still, by mid-April, the well seemed a qualified success. BP was convinced it had found a lot of oil. Untilengineers in Houston could make plans to start pumping it out, the workers on the nearly complete well, in astandard practice, would plug it and temporarily abandon it. One of the final tasks was to cement in place the steel pipe that ran into the oil reservoir. The cement wouldfill the space between the outside of the pipe and the rock, preventing any gas from flowing up the sides. Halliburton, the cementing contractor, advised BP to install numerous devices to make sure the pipe wascentered in the well before pumping cement, according to Halliburton documents, provided to congressional

investigators and seen by the Journal. Otherwise, the cement might develop small channels that gas couldsqueeze through. In an April 18 report to BP, Halliburton warned that if BP didn't use more centering devices, the well wouldlikely have "a SEVERE gas flow problem." Still, BP decided to install fewer of the devices than Halliburtonrecommended -- six instead of 21. BP said it's still investigating how cementing was done. Halliburton said that it followed BP's instructions, andthat while some "were not consistent with industry best practices," they were "within acceptable industrystandards." The cement job was especially important on this well because of a BP design choice that some petroleumengineers call unusual. BP ran a single long pipe, made up of sections screwed together, all the way fromthe sea floor to the oil reservoir. Companies often use two pipes, one inside another, sealed together, with the smaller one sticking into the oilreservoir. With this system, if gas tries to get up the outside of the pipe, it has to break through not justcement but also the seal connecting the pipes. So the more typical design provides an extra level of protection, but also requires another long, expensive piece of pipe. "I couldn't understand why they would run a long string," meaning a single pipe, said David Pursell, apetroleum engineer and managing director of Tudor, Pickering, Holt & Co., an energy-focused investmentbank. Oil major Royal Dutch Shell PLC, in a letter to the MMS, said it "generally does not" use a single pipe. BP's Mr. Gowers said the well design wasn't unusual. BP engineers "evaluate various factors" to determinewhat design to use for each well, he said.




Despite the well design and the importance of the cement, daily drilling reports show that BP didn't run acritical, but time-consuming, procedure that might have allowed the company to detect and remove gasbuilding up in the well. Before doing a cement job on a well, common industry practice is to circulate the drilling mud through thewell, bringing the mud at the bottom all the way up to the drilling rig. This procedure, known as "bottoms up," lets workers check the mud to see if it is absorbing gas leaking in. If

so, they can clean the gas out of the mud before putting it back down into the well to maintain the pressure.The American Petroleum Institute says it is "common cementing best practice" to circulate the mud at leastonce. Circulating all the mud in a well of 18,360 feet, as this one was, takes six to 12 hours, say people who've runthe procedure. But mud circulation on this well was done for just 30 minutes on April 19, drilling logs say, notnearly long enough to bring mud to the surface. This decision could have left gas at the bottom of the well. When workers poured in cement to seal the sides,that gas would have been pushed up the outside of the well. Expanding as it rose, it would have reached thetop, where it either would have pushed against a massive seal on the ocean floor or might have gone evenhigher and reached the bottom of the pipe connecting the well to the drilling rig. BP's Mr. Gowers said the amount of time spent circulating mud is "one of many parameters consideredwhen designing a successful cement job." He said BP's investigation is ongoing. Three offshore engineers the Journal asked to review the drilling reports all pointed to the failure to circulatethe mud completely as a serious mistake. Robert MacKenzie, a former oil-industry cementing engineer nowat FBR Capital Markets, said, "If you have any worries about gas, if you have any worries about getting agood cement job, you should definitely do it." BP also didn't run tests to check on the last of the cement after it was pumped into the well, despite theimportance of cement to this well design and despite Halliburton's warning that the cement might not sealproperly. Workers from Schlumberger Ltd. were aboard and available to do such tests, but on the morning of April 20, about 12 hours before the blowout, BP told Schlumberger workers their work was done, accordingto Schlumberger. They caught a helicopter back to shore at 11 a.m. BP told the Journal Tuesday that the tests weren't run because they were needed only if there were signs of trouble in the cement job, and the work seemed to go smoothly. But the same day, BP officials toldcongressional investigators there were signs before the disaster that the cement might have beencontaminated and that some cementing equipment didn't work properly, according to a memo from twoCongressmen.

The mood aboard the rig on April 20 was upbeat. The work was nearly done, and workers were eager to putthe troublesome well behind them. Some saw indications that managers wanted to wrap up quickly. Kevin Senegal, a subcontractor employeewho cleaned tanks, said he was told to be ready to clean two tanks on a coming shift instead of the usualone. "To me it looked like they were trying to rush everything," he said. A disagreement broke out on the rig on April 20 over the procedures to be followed. At 11 a.m., workers for the half-dozen contractors working on the rig gathered for a meeting. Douglas Brown, Transocean's chief mechanic on the rig, testified Wednesday at a hearing in Louisiana that a top BP official had a "skirmish"with top Transocean officials. The Transocean workers, including offshore installation manager Jimmy Wayne Harrell, disagreed with adecision by BP's top manager about how to remove drilling mud and replace it with lighter seawater. Mr.

Brown said he heard Mr. Harrell say, "I guess that is what we have those pinchers for," referring to a part of the blowout preventer that would shut off the well in case of an emergency. BP won the argument, said Mr. Brown, who is a plaintiff in a suit against BP and Transocean. Mr. Harrelldeclined Journal requests for comment. A little after 5 p.m., to check the well's integrity and whether gas was seeping in, rig workers did what iscalled a "negative pressure test." It was supervised by a BP well-site leader, Robert Kaluza. His experiencewas largely in land drilling, and he told investigators he was on the rig to "learn about deep water," accordingto Coast Guard notes of an interview with him. BP declined to comment on his experience. A lawyer for Mr. Kaluza said he "did no wrong on the Deepwater Horizon."




The test initially strayed from the procedure spelled out in BP's permit, approved by the MMS, according tothe Coast Guard interview with Mr. Kaluza. When the first test results indicated something might be leaking,workers repeated the test, this time following the permitted procedure. The second time, pressure rosesharply, with witnesses saying that the well "continued to flow and spurted," according to notes gathered byBP's investigators that were reviewed by the Journal. BP denies violating its MMS permit. Well-control experts say it's clear gas was leaking into the well, most likely through the seal at the top butpossibly through the bottom or even through a collapsed pipe.

Earlier this month, BP lawyers told Congress the test results were "inconclusive" or "not satisfactory." OnTuesday, according to the Congressmen's memo, BP said it saw signs of "a very large abnormality." Just two things then stood between the rig and an explosive mixture of gas and oil. One was the heavydrilling mud. The other was the blowout preventer near the sea floor. But the BOP had various problems,among them some leaking hydraulics. By 8 p.m., BP was satisfied with the test and had enough confidence to proceed. It was this that may havebeen "a fundamental mistake," a BP official told congressional staffers Tuesday, according to the memofrom two members of Congress. Following BP's instruction, Transocean workers turned to replacing the mud with seawater, according toCoast Guard interviews with Mr. Kaluza and Donald Vidrine, the top BP official on the rig. Removing the mudkeeps it from polluting the sea but also means there's less weight to hold down any gas. BP's plans for the well, approved by the MMS on April 16, called for workers to remove the mud beforeperforming two procedures designed to make sure gas couldn't get into the well. The first called for installing a giant spring to lock the seal at the top of the well in place after removal of themud. There's no evidence in rig-activity logs the spring was ever installed. If gas was coming up the sides of the well, pushing against the seal, this spring would have helped prevent leakage. Second, BP opted to remove the mud before placing a final cement plug inside the well. In documents presented to Congress, BP has hypothesized that gas could have gotten into the inside of thepipe through a failure of the cement at the bottom of the well. BP was planning to set a second, backupcement plug in the well before declaring its work done. But workers began removing mud before setting this plug, leaving little to prevent any gas inside the pipefrom rising to the rig. That plan was approved by the MMS on April 16, according to the permit reviewed by

the Journal. A spokeswoman for the Interior Department, of which the MMS is a part, said it was "looking at everything,from what happened on the rig that night and the equipment that was being used to the safety, testing andbackup procedures." About 9:45, the seawater and remaining mud began to head back up the pipe. Witnesses say they saw mudshooting out of the derrick like water from a firehose. A worker on the rig floor made a frantic call to BP's Mr.Vidrine, who had gone to his office, according to his interview with the Coast Guard. Transocean workers raced to tame the well. Nothing worked. This was no ordinary gas kick. It was far moreferocious. Workers rushed to hit the emergency button to activate the blowout preventer's clamps and detach the rigfrom the well, according to witness accounts. They were too late. Gas flowing out found an ignition source,and an explosion rocked the rig.

Well No. 60-817-44169 was beyond control and on its way to becoming infamous. --- Vanessa O'Connell, Jeffrey Ball, Douglas A. Blackmon, Ana Campoy, Miguel Bustillo and Jennifer Levitzcontributed to this article. License this article from Dow Jones Reprint Service






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Oil Regulator Ceded Oversight to Drillers By Russell Gold and Stephen Power 2,205 words7 May 2010The Wall Street JournalJ A1English(Copyright (c) 2010, Dow Jones & Company, Inc.) Corrections &Amplifications The United Kingdom moved to have different agencies oversee offshore safety and leasing in 1991. A May 7front-page article about the U.S. Minerals Management Service and a Wednesday article about a plan todivide the MMS incorrectly said that the U.K. made the change in 1998. (WSJ May 14, 2010) (END) The small U.S. agency that oversees offshore drilling doesn't write or implement most safety regulations,having gradually shifted such responsibilities to the oil industry itself for more than a decade. Instead, the Minerals Management Service -- now caught up in the crisis of the Deepwater Horizon rig thatfor weeks has sent crude oil gushing into the Gulf of Mexico -- sets broad performance goals for the industry.Oil producers and drilling companies are then free to decide for themselves how to meet those goals,industry executives and former regulators say. A Wall Street Journal examination of the MMS's track record found several instances of the agencyidentifying potential safety problems and then either not requiring follow-up or relying on the industry to crafta solution. In some cases, the industry didn't do its part. The Journal also found that the safety record of U.S. offshore drilling compares unfavorably, in terms of deaths and serious accidents, to other major oil-producing countries. Over the past five years, an offshore oil

worker in the U.S. was more than four times as likely to be killed than a worker in European waters, and 23%more likely to sustain an injury, according to International Association of Drilling Contractors data, which isadjusted for man-hours worked. Asked about The Journal's findings on its safety record and practices, MMS officials said in an interviewWednesday that the agency plans to toughen its oversight. Any new regulations emerging from the currentcrisis "will be a prescriptive regulation," said Lars Herbst, head of the MMS' Gulf of Mexico region. He saidthe agency is unlikely to give the industry much latitude to decide how to make changes. "After this accidentinvestigation is done, I would bet there won't be any performance-based regulation that comes out toaddress any problem that we may uncover," he said. Mr. Herbst questioned the data on deaths, saying the number of working hours could be underreported inthe U.S. That would make the U.S. fatality rate look higher. The agency points out it does conduct numerous inspections. It leases 14 helicopters to ferry inspectors,often unannounced, out to the 3,800 drilling rigs and platforms in the Gulf of Mexico that it oversees. But the

number of rigs inspected has fallen significantly in recent years, according to agency data, from 1,292 in2005 to 760 by 2009. Defenders of the agency say enforcement isn't its primary responsibility. Stephen Allred, who as AssistantSecretary of the Interior oversaw MMS from 2006 to 2009, said the agency does conduct spot inspections of oil rigs, and checks operators' compliance with safety procedures. However, "Their role is not to baby-sit" theoperators, he said. The agency's primary task during inspections is to verify how much oil is being pumped,which is key to another MMS duty, maximizing payments the government receives for oil and gas rights fromenergy producers. In one instance late last year, an oil company complained about the inadequacy of the agency's safetyinvestigations. In November, ATP Oil &Gas Corp. sued MMS alleging it was incomplete in investigating a




fatal accident at an ATP rig. The lawsuit, filed in federal court in Washington, D.C., alleged an MMSinvestigator misstated the accident's location, didn't interview the two eyewitnesses to the event, and told ATP to take corrective action within 14 days without identifying problems that needed to be fixed. The suitwas settled in March, with ATP paying a $20,000 civil penalty, according to a company lawyer. An MMS spokesman declined to comment. An MMS court filing gave denials of some ATP claims, includingthe matter of the accident's location. Some former employees say that MMS, which was founded in 1982 and is part of the Interior Department,has a built-in conflict of interest: It is supposed to be a watchdog that halts drilling when it spots unsafebehavior. But it is also supposed to promote energy independence and to generate government revenuefrom drilling on government lands, including the outer continental shelf. Of MMS's fiscal 2010 budget of $342 million, nearly half comes from the oil industry in the form of fees andrental receipts, known as "offsetting collections." That's one reason why collecting oil and gas royalties isemphasized at the agency, former and current officials say. The U.K. -- home to one of the largest offshore-drilling industries in the world -- has taken a differentregulatory approach. In 1998, after a fire aboard a North Sea platform killed 167 people, the U.K. separatedits offshore safety-oversight agency from the revenue-gathering side. After that change, the U.K.'s safety record improved. The improvements also came at a time of increasedmechanization of rigs, which improved the safety of offshore drilling world-wide. Told of The Journal's findings on MMS's track record, Sen. Bill Nelson (D., Fla.), a longtime opponent of drilling off his state's coast, castigated the agency. "If MMS wasn't asleep at the wheel, it sure was letting BigOil do most of the driving," he said. In the U.S., the MMS has been criticized for giving oil companies too much sway in the royalty area, not justregulatory oversight. A 2008 Interior Department Inspector General report faulted MMS for modifying royaltypayment contracts in ways that "appeared to inappropriately benefit the oil companies." U.S. oil-industry executives and current and former regulators say the U.S.'s self-regulatory approach hasworked for many years. "There has been a very good record in deep water, up until the point of thisaccident," said Mr. Herbst of the MMS. They also argue that offshore operations have become so complicated that regulators ultimately must rely onthe oil companies and drilling contractors to proceed safely. "The regulator sets the frameworks, sets theguidance, monitors and inspects," said Elmer P. Danenberger III, the longtime head of the MMS's offshore

regulatory programs, who retired in December. "But the regulator isn't conducting the operation." Many questions remain about last month's sinking of the Deepwater Horizon, including why the rig caughtfire, why fail-safe devices didn't work and why the industry wasn't better prepared for a spill of thismagnitude. In recent years, oil wells in the U.S. were more likely to go out of control -- as was the case with theDeepwater Horizon's blowout last month -- than in other countries. According to data from the InternationalRegulators' Forum, a group of offshore regulatory bodies, the U.S. reported five major "loss of well control"incidents in 2007 and 2008, the most recent years for which data are available. The five other countries in the forum that reported the data (U.K., Norway, Australia, Canada and theNetherlands) reported no such incidents. Last year, those five nations had roughly half as much drillingactivity as the U.S. Over the past decade, the number of MMS enforcement cases that resulted in penalties ranged from a high

of 66 in 2000 to a low of 20 last year. A report by the agency's inspector general in 2000 found that it seldomreferred safety or environmental violations to the Justice Department for criminal prosecution, even when itshould have done so. To explain its shift toward industry self-regulation, the MMS in a 2005 rule change pointed to a 1996 law thatencouraged federal agencies to "benefit from the expertise of the private sector" by adopting industrystandards. Mr. Herbst also pointed out that the MMS often has a seat on panels setting industry standards. The Journal has identified instances in which MMS didn't follow through on potential safety problems that theagency had asked the industry to examine. In 2000, the agency asked the industry for advice on how to dealwith problems with cement used to keep oil and natural gas from bubbling to the surface and exploding. Adecade later, the industry is still working on its recommendations, according to the American Petroleum




Institute. No regulations have been issued by the agency. Another instance involves "blowout preventers," which are critical devices meant to shut down out-of-controlwells. In 1998, the MMS solicited suggestions to improve the effectiveness of the devices but didn't heedthem. It commissioned Per Holand, a Norwegian researcher, to study the reliability of the devices. In 2002,Mr. Holand recommended that blowout preventers should have two pipe-cutting devices designed to shut off a well, instead of just one, in case one didn't work. His reasoning: The pipe cutters are designed to shear off and plug an out-of-control well pipe. But they don'talways work if they strike one of the thicker joints, where two pieces of pipe fit together. Joints like thesemake up about 10% of the length of the drill pipe, meaning the cutters could fail as much as 10% of the time. A second cutter, however, could ensure that at least one of the two would be able to cut the pipe. The MMS didn't act on Mr. Holand's recommendation. Mr. Holand said he wasn't surprised: Adding a secondcutter costs money, and might make the device too heavy for some older rigs to carry. In 2000, the MMS issued a safety alert saying it expects oil companies to have a backup system to activateblowout preventers if the main activation system fails. A spokesman for MMS says it relied on industryassurances that backup systems were in place, but did no formal survey. Last June, nine years after thesafety alert, the MMS issued an almost identical safety notice, but to date has issued no rule requiring theback-up switches. "I don't recall where that rule-making process ceased," Mr. Herbst said. "It is something that we're going togo back and look at. I don't know yet whether that played into this incident, but I can guarantee we will be

looking at that again." Industry consultants say there are drilling rigs now in the gulf that don't have an automatic "dead manswitch," or a separate, remote-control on-off switch to activate the blowout preventer, because the MMShadn't issued the rule requiring their use. The Deepwater Horizon did have a "dead man switch," but it failed to activate the blowout preventer. TheDeepwater Horizon lacked the separate, remote-control switch that's commonly used in Norway and Brazil. In a decision that gave the industry greater control over regulatory oversight, MMS got out of the business of telling companies what training was necessary for workers involved in keeping wells from gushing out of control. About a decade ago, the agency turned this over to a trade group, the International Association of Drilling Contractors, according to Lee Hunt, president of the Houston-based organization. It representsoffshore drillers such as Transocean Ltd., which owned and operated the Deepwater Horizon. "There was a recognition that everyone has a vested interest in being as safe as possible," Mr. Hunt said. The trade group now accredits training schools to teach rig workers how to avoid blowouts, he says. WhenMMS inspectors visit rigs, Mr. Hunt said, they give "oral examinations" to workers on oil-well control. The MMS has received unwelcome attention for the behavior of employees assigned to a royalty-collectionoffice in Denver, Colo. The Interior Department's inspector general concluded in 2008 that MMS employeesthere broke government rules and created a "culture of ethical failure" by accepting gifts from, and havingsex with, industry representatives. Following the inspector general's report, the Interior Department tookdisciplinary action against more than a half dozen MMS workers, with punishments that ranged from awarning letter to termination. Ethical problems also hit the offshore oil program. In 2009, Donald C. Howard, the former regionalsupervisor of the Gulf of Mexico region for MMS, pled guilty and was sentenced to a year's probation infederal court in New Orleans for lying about receiving gifts from an offshore drilling contractor. Mr. Howarddeclined to comment.

The industry has fought against attempts to return to more rigid rules. In a 2009 letter, the OffshoreOperators Committee and the American Petroleum Institute, two trade groups, argued against proposednew, stricter rules governing safety and environmental compliance. Mandated programs, it said, "quickly become paperwork exercises," not genuine improvements. The ruleshaven't been implemented. Mr. Herbst said the rules would supplement, not replace, existing rules. --- Ben Casselman, John R. Emshwiller and Guy Chazan contributed to this article.




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Oil Well Lacked Safeguard Device --- Officials Say Leak Grows Fivefold By Russell Gold, Ben Casselman and Guy Chazan1,278 words29 April 2010The Wall Street JournalJ A1English(Copyright (c) 2010, Dow Jones & Company, Inc.) Federal officials said Wednesday the oil spill spewing crude into the Gulf of Mexico is five times the size of previous estimates, as a significant new leak was discovered. The Deepwater Horizon oil rig, which exploded and sank last week, didn't have a remote-control shut-off switch used in two other major oil-producing nations as last-resort protection against underwater spills. The lack of the device, called an acoustic switch, could amplify concerns over the environmental impact of offshore drilling after the accident, which led to the loss of 11 lives and has created one of the largest-ever oilspills in U.S. water.

On Wednesday, Rear Adm. Mary Landry said that 5,000 barrels a day were now estimated to be leaking, upfrom the previous estimate of 1,000 barrels. U.S. regulators don't mandate use of the remote-control device on offshore rigs, and the Deepwater Horizon,hired by oil giant BP PLC, didn't have one. With the remote control, a crew can attempt to trigger anunderwater valve that shuts down the well even if the oil rig itself is damaged or evacuated. The efficacy of the devices is unclear. Major offshore oil-well blowouts are rare, and it remained unclear Wednesday evening whether acoustic switches have ever been put to the test in a real-world accident.When wells do surge out of control, the primary shut-off systems almost always work. Remote controlsystems such as the acoustic switch, which have been tested in simulations, are intended as a last resort.Nevertheless, regulators in two major oil-producing countries, Norway and Brazil, in effect require them.Norway has had acoustic triggers on almost every offshore rig since 1993. The U.S. considered requiring a remote-controlled shut-off mechanism several years ago, but drillingcompanies questioned its cost and effectiveness, according to the agency overseeing offshore drilling. Theagency, the Interior Department's Minerals Management Service, says it decided the remote device wasn'tneeded because rigs had other back-up plans to cut off a well. The U.K., where BP is headquartered, doesn't require the use of acoustic triggers. On all offshore oil rigs, there is one main switch for cutting off the flow of oil by closing a valve located on theocean floor. Many rigs also have automatic systems, such as a "dead man" switch as a backup that issupposed to close the valve if it senses a catastrophic failure aboard the rig. As a third line of defense, some rigs have the acoustic trigger: It's a football-sized remote control that usessound waves to communicate with the valve on the seabed floor and close it. An acoustic trigger costs about $500,000, industry officials said. The Deepwater Horizon had a replacementcost of about $560 million, and BP says it is spending $6 million a day to battle the oil spill. On Wednesday,

crews set fire to part of the oil spill in an attempt to limit environmental damage. Some major oil companies, including Royal Dutch Shell PLC and France's Total SA, sometimes use thedevice even where regulators don't call for it. Transocean Ltd., which owned and operated the Deepwater Horizon and the shut-off valve, declined tocomment on why a remote-control device wasn't installed on the rig or to speculate on whether such adevice might have stopped the spill. A BP spokesman said the company wouldn't speculate on whether aremote control would have made a difference. Much still isn't known about what caused the problems in Deepwater Horizon's well, nearly a mile beneath




the surface of the Gulf of Mexico. It went out of control, sending oil surging through pipes to the surface andcausing a fire that ultimately sank the rig. Unmanned submarines that arrived hours after the explosion have been unable to activate the shut-off valveon the seabed, called a blowout preventer. BP says the Deepwater Horizon did have a "dead man" switch, which should have automatically closed thevalve on the seabed in the event of a loss of power or communication from the rig. BP said it can't explain

why it didn't shut off the well. Transocean drillers aboard the rig at the time of the explosion, who should have been in a position to hit themain cutoff switch, are among the dead. It isn't known if they were able to reach the button, which wouldhave been located in the area where the fire is likely to have started. Another possibility is that one of themdid push the button, but it didn't work. Tony Hayward, BP's CEO, said finding out why the blowout preventer didn't shut down the well is the keyquestion in the investigation. "This is the failsafe mechanism that clearly has failed," Mr. Hayward said in aninterview. Lars Herbst, regional director of the Minerals Management Service in the Gulf of Mexico, said investigatorsare focusing on why the shut-off valve failed. Industry consultants and petroleum engineers said that an acoustic remote-control may have been able to

stop the well, but too much is still unknown about the accident to say that with certainty. Rigs in Norway and Brazil are equipped with the remote-control devices, which can trigger the blowoutpreventers from a boat if the electric cables connecting the valves to the drilling rig are damaged. While U.S.regulators have called the acoustic switches unreliable and prone, in the past, to cause unnecessary shut-downs, Inger Anda, a spokeswoman for Norway's Petroleum Safety Authority, said the switches have a goodtrack record in the North Sea. "It's been seen as the most successful and effective option," she said. The manufacturers of the equipment, including Kongsberg Maritime AS, Sonardyne Ltd. and Nautronix PLC,say their equipment has improved significantly over the past decade. The Brazilian government began urging the use of the remote-control equipment in 2007, after an extensiveoverhaul of its safety rules following a fire aboard an oil platform killed 11 people, said Raphael Moura, headof safety division at Brazil's National Petroleum Agency. "Our concern is both safety and the environment,"he said. Industry critics cite the lack of the remote control as a sign U.S. drilling policy has been too lax. "What wesee, going back two decades, is an oil industry that has had way too much sway with federal regulations,"said Dan McLaughlin, a spokesman for Democratic Florida Sen. Bill Nelson. "We are seeing our worstnightmare coming true." U.S. regulators have considered mandating the use of remote-control acoustic switches or other back-upequipment at least since 2000. After a drilling ship accidentally released oil, the Minerals ManagementService issued a safety notice that said a back-up system is "an essential component of a deepwater drillingsystem." The industry argued against the acoustic systems. A 2001 report from the International Association of Drilling Contractors said "significant doubts remain in regard to the ability of this type of system to provide areliable emergency back-up control system during an actual well flowing incident." By 2003, U.S. regulators decided remote-controlled safeguards needed more study. A report commissionedby the Minerals Management Service said "acoustic systems are not recommended because they tend to be

very costly." --- Jeff Fick contributed to this article.




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