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Analysis

Rollback: The Trump Administration Proposes to Thin Offshore Drilling Safety Rules

Examining the fine print
(Animated illustration: CJ Ostrosky / POGO)

This is part two of a three-part investigation into offshore drilling safety. Read part one here. Read part three here.

Six years after the Deepwater Horizon oil rig exploded in the Gulf of Mexico, killing 11 people and unleashing one of the worst environmental disasters in the nation’s history, the Obama Administration put in place a set of rules intended to prevent future blowouts.

Now, two and half years after those safety rules were adopted, the Trump Administration has proposed undoing many of them.

Based on a Project On Government Oversight examination of the fine print, what follows are highlights of the Trump Administration’s proposal. To put the proposed changes in context, POGO also has drawn on technical analyses of what went wrong in the Deepwater Horizon disaster and more recent offshore accidents.

The proposed regulatory rollback focuses largely on blowout preventers (also known as BOPs), the devices that are supposed to seal the well in an emergency and prevent a drilling problem from escalating into a catastrophe.

The proposal was drafted by the Interior Department’s Bureau of Safety and Environmental Enforcement (BSEE, pronounced “Bessie”), which said in an official public notice that its goal was “reducing unnecessary regulatory burdens.”

The Trump Administration’s plan would roll back specific requirements meant to ensure that, when needed, blowout preventers would actually do the job.

BSEE said its plan includes adopting standards written by the oil and gas industry and aligning its regulations with those standards. That’s also what the industry has been seeking.

For example, in a May 2017 letter to the Interior Department and a September 2017 presentation to BSEE, the American Petroleum Institute (API) and other industry groups asked the government to defer to an industry standard known as API Standard 53, “Blowout Prevention Equipment Systems for Drilling Wells.”

“The requirements that exceed the provisions of API Standard 53 (API 53) . . . are unnecessary, will not improve safety and will increase risks to operations, which is why, we recommend using the requirements in API 53 as the primary best practice,” the industry groups said in the letter.

“Eliminate any requirements that exceed API 53,” they said in their presentation.

The Obama Administration drew upon API standards even as it ratcheted up requirements for BOPs. Some of the Obama provisions could end up being changed before they’ve kicked in.  

API has described the Trump Administration’s proposal as a needed improvement over the Obama rules.

“BSEE’s proposed revision of the well-control rule will move us forward on safety, help the government better regulate risks and better protect workers and the environment,” Erik Milito, an API official who handles regulatory and legislative matters, said in a statement the organization sent POGO in August 2018.

Federal agencies are generally required to use technical standards developed outside the government. However, in evaluating whether to use industry standards, federal guidance says, agencies should consider “the level of protection the standard provides or is expected to provide for public health, welfare, safety, and the environment."

API 53 includes this general requirement: Blowout preventers “shall provide a means to . . . shear the drill pipe or tubing and seal the wellbore.”

In other words, the industry standard says blowout preventers should be able to prevent blowouts.

It’s hard to argue with that general proposition, which borders on a statement of the obvious. But the Administration’s plan would roll back specific requirements meant to ensure that, when needed, blowout preventers would actually do the job.

That’s not all. The Administration’s plan would weaken rules meant to avert the kind of crises that call for blowout preventers, and it would weaken rules meant to deal with worst-case scenarios in which blowout preventers fail.

BSEE says its proposal “would not increase the safety or environmental risks” of offshore drilling. If the Bureau is wrong about that, the costs could be profound—even in strictly economic terms.

BP, the giant oil company that shared responsibility for the Deepwater Horizon spill, reported that, as of the end of last year, its liabilities and other costs from the deadly disaster had reached $65.8 billion.

Blowout Preventer Information

Current Rules:

When applying for a permit to drill, offshore operators must submit a complete description of the BOP system and its components, including, for each “ram BOP” and at the maximum anticipated pressure, “settings needed to achieve an effective seal.”

(BOPs include components known as “rams,” which are meant to block the flow of oil and gas and contain or “seal” wells. So-called “shear rams” are meant to cut well pipes, too. The equipment should be able to withstand the pressure exerted by oil and gas escaping up the well from highly pressurized natural reservoirs beneath the ocean floor.)

Proposed Change: 

BSEE would change “settings needed to achieve an effective seal of each ram BOP” to “settings needed to close each ram BOP.” (Emphasis added)

BSEE’s Explanation:

The Bureau said the revision would more closely match the API 53 standard promulgated by the oil industry and “would be adequate to meet” that standard, achieving the same result.

Why It Matters:

Closing one of a BOP’s components is not necessarily the same as achieving an effective seal. (If it was, why bother to change the wording?)

If part of the BOP closes but doesn’t stop the flow of oil or gas, or if it stops the flow only temporarily, a runaway oil spill could result.

When a rig owned by Hercules Offshore Inc. was destroyed in a 2013 blowout, the crew attempted to seal the well. According to a BSEE analysis of the blowout, the flow from the well subsided but then quickly resumed. A review of rig sensor data indicated that “the closed blowout preventers had begun leaking after initial indications that they had been successfully closed,” a separate investigation found.

Investigators could not determine conclusively whether the BOP temporarily closed. However, they concluded that, even if it had, a combination of “high pressure in the well” and a loss of the hydraulic power used to control the BOP ultimately “would have allowed the blind shear rams to begin to leak continuously.”

Further, API Standard 53, one of the industry standards incorporated in BSEE’s regulatory proposal, gives an oblique definition of when a BOP can be considered closed:

“A BOP can be considered closed when the regulated operating pressure has initially recovered to its nominal setting or other demonstrated means.”

Real-Time Monitoring

Current Rules:

Current rules require that, beginning in April 2019, offshore operators will have to be able to monitor from shore real-time data on well operations, including information about the blowout preventer and conditions in the well.

Proposed Change:

The proposal would delete this paragraph:

You must transmit these data as they are gathered, barring unforeseeable or unpreventable interruptions in transmission, and have the capability to monitor the data onshore, using qualified personnel in accordance with a real-time monitoring plan, as provided in paragraph (c) of this section. Onshore personnel who monitor real-time data must have the capability to contact rig personnel during operations. After operations, you must preserve and store these data onshore for recordkeeping purposes as required in §§ 250.740 and 250.741. You must provide BSEE with access to your designated real-time monitoring data onshore upon request. You must include in your APD [application for permit to drill] a certification that you have a real-time monitoring plan that meets the criteria in paragraph (c) of this section.

BSEE’s Explanation:

BSEE says it would still require the ability to gather and monitor real-time well data but would remove “many of the prescriptive real-time monitoring requirements” to “allow company-specific approaches.”

Why It Matters:

In the 2010 Deepwater Horizon disaster and the 2013 blowout that destroyed the Hercules rig, people working on the rigs didn’t realize a crisis was building until it was too late. In each case, once the well blew, chaotic and life-threatening conditions on the rig made it difficult for the crew to manage the situation. Onshore monitoring could provide a backstop. Also, after any disaster, it could help investigators figure out what went wrong and why—and who was responsible. It could be the equivalent of having the flight data recorder or cockpit voice recorder from an airplane—the so-called black box—backed up on the ground in real time in case of a crash.

Failure Analyses

Current Rules:

When BOPs fail, offshore operators must ensure that an investigation and failure analysis are performed within 120 days of the failure to determine what caused it. Then, they must ensure that the results and any corrective action are documented.

The information is used in an annual report on BOP failures published by the government and mandated in the aftermath of the Deepwater Horizon disaster.

Proposed Change:

The investigation and failure analysis would have to begin within 120 days. Companies would then have another 120 days to complete it—if they are required to complete it at all. BSEE indicated that it is considering “whether specifying a completion date for the failure analysis is appropriate.”

BSEE’s Explanation:

The Bureau said it found “that certain operations would not be able to meet the original timeframes.” It cited “unknown situations that could arise,” including situations involving “the availability of the equipment.”

Why It Matters:

“Understanding the root cause of equipment component failures is key to preventing reoccurrence and addressing any existing issues with equipment design, maintenance practices, and/or established procedures,” the government said in the most recent annual report on BOP failures.

When the Deepwater Horizon exploded, BP should have been prepared to deal with a blowout in the Gulf of Mexico.

Compliance with the requirement is already a problem. According to the annual report, failure analyses are not always performed as expected. More specifically, for BOP failures in 2017 that resulted in an unplanned extraction of the BOP, only 12 of the 18 components that failed—two-thirds—were sent to shore for further analysis by the manufacturer or a third party. The government expected a root cause failure analysis in every instance, the report said.

Disaster Preparedness and Oil-Spill Response Contingency Plans

Current Rules

In case the blowout preventer fails, drilling companies must have on hand all equipment needed to regain control of the well, including an array of specified equipment to contain the spill at its source. The listed equipment includes so-called “containment domes” and “capping stacks” to put a lid on the well, and vessels to capture the leaking oil.

Proposed Change:

The list of items drillers must have available to contain and control a spill would cease to be binding. The listed items would serve as “examples” of the types of equipment that may be appropriate “rather than universal requirements.”

BSEE’s Explanation:

Instead of taking a one-size-fits-all approach, companies could make “well-specific determinations” as to what equipment they should have ready.

Why It Matters:

When the Deepwater Horizon exploded, BP should have been prepared to deal with a blowout in the Gulf of Mexico.  As the runaway spill and subsequent investigations revealed,  it was not. Though BP had a contingency plan, that plan mentioned walruses among the native wildlife in need of attention, indicating that at least part of the plan was borrowed from one meant for far-away Alaskan waters. Federal regulators had approved BP’s contingency plan, walruses and all. “There is little in that approval to suggest that BP and MMS [the Minerals Management Service, predecessor to BSEE] gave close scrutiny to the contents of the Oil Spill Response Plan,” a presidential commission said in its report on the spill. It took 87 days to cap BP’s well. By then, more than 130 million gallons of oil are estimated to have gushed into the Gulf.

Certification

Current Rules:

When applying for a permit to drill, an offshore operator must submit a certification confirming information about the BOP and its capabilities. The certification must come from a “BSEE-approved verification organization”—essentially, a private auditor or inspector such as an engineering firm that meets a set of qualifications.

Proposed Change:

The certification would no longer have to confirm that the BOP “is designed and suitable for the specific equipment on the rig and for the specific well design” or that the BOP “will operate in the conditions in which it will be used.”

BSEE’s Explanation:

The wording proposed for deletion is redundant in light of other requirements.

Why It Matters:

BOPs can be useless if they don’t match the equipment used on a particular rig. For example, the blowout preventer on the Deepwater Horizon was no match for a type of drillpipe frequently used on the rig, according to an investigation by the U.S. Chemical Safety Board. According to the Board, a company manual for the Deepwater Horizon’s blowout preventer said the blind shear rams had to be capable of shearing the highest grade and heaviest drillpipe used on the rig. Despite that requirement, the Deepwater Horizon BOP “was not capable of reliably shearing” the 6⅝-inch drillpipe generally used in the well, the Board reported. According to the Board, emails show that at least one Deepwater Horizon supervisor knew about the problem.

Verification

Current Rules:

When applying for a permit to drill, an offshore operator must submit a certification confirming information about the BOP and its capabilities. The certification must come from a “BSEE-approved verification organization”—essentially, a private auditor or inspector such as an engineering firm that meets a set of qualifications.

Proposed Change:

The organization performing the verifications would no longer have to be approved by the regulator.

BSEE’s Explanation:

The industry has long used “independent third parties” to vouch for offshore equipment, and, based on past experience, there is no need for the bureau to review and approve them.

Why It Matters:

Rig workers have pleaded guilty to criminal charges of falsifying BOP test results, illustrating why it could be useful to have someone check key information about the equipment.  

BSEE-approved inspectors might be more reliable than inspectors not vetted by the Bureau.

In April 2016, before the requirement for BSEE-approved inspectors was adopted, the Interior Department’s Office of Inspector General reported concerns “regarding the technical competency” of management at a firm conducting BOP verifications.

The report compiled observations from people whose names are redacted. One opined that “the verification process has reverted to a business being run by accountants versus technical experts.”

A recurring theme in the inspector general’s report was the firm’s willingness to please its customers, companies that conduct offshore oil and gas operations, as POGO describes in an accompanying story.

For example, one person “had heard of situations where a non-technical manager in [the firm] would sign a document that a technical engineer refused to sign because a ‘customer needed it,’ and [the firm] was in the business of ‘taking care of the customer,’” the report said. “He believes that this type of customer ‘accommodation’ is not living up to the intent/spirit of the law, which as he articulated before, was to ensure another Deepwater Horizon explosion does not happen again,” the report said.

Requiring that third parties preserve their BSEE-approved status would give them cover to stand up to clients’ demands, said Roger L. McCarthy, a member of the National Academy of Engineering who has investigated disasters such as the Deepwater Horizon blowout. “Once you remove that . . . then it’s just, What does he do to please the client?” McCarthy said.

Reports

Current Rules:

Every 12 months, offshore operators must submit a “Mechanical Integrity Assessment Report” on their blowout preventer. The report must be completed by a BSEE-approved verification organization and must cover a list of points.

For example, it must verify that all maintenance, repairs, and replacement parts meet regulatory requirements and manufacturer specifications; identify any gaps in the maintenance and inspection record; and confirm that any modifications to the equipment wouldn’t impair it.

Proposed Change:

Those yearly reports would no longer be required.

BSEE’s Explanation:

In light of other requirements, the reports would be redundant.

Why It Matters:

A thorough mechanical integrity assessment might have detected profound problems with the BOP on the Deepwater Horizon.

The rig was owned by Transocean and was being used on a BP well when it exploded and sank in the Gulf of Mexico in 2010. After the blowout, it took a Transocean representative almost 10 days to realize that the BOP’s plumbing differed from the diagrams on which BP and Transocean had been relying as they tried in vain to trigger one of the BOP’s rams through a hydraulic panel, the national commission appointed to review the disaster later reported.

“Without properly recording the change, Transocean had reconfigured the BOP; the panel that was supposed to control that ram actually operated a different, ‘test’ ram, which could not stop the flow of oil and gas,” the commission reported.

What’s more, a critical valve in the BOP had been miswired, potentially rendering the valve inoperable, the U.S. Chemical Safety Board reported.

Test Duration

Current Rules:

BOPs must be subjected to a variety of pressure tests at different intervals to make sure they could contain a blowout. For some tests, if BSEE representatives are unable to witness the tests, the results must be submitted to the regulator.

Proposed Change:

One test currently requires the BOP to seal for 30 minutes at the maximum internal pressure that it is designed to contain. BSEE would shorten the test from 30 minutes to 5 minutes.

BSEE’s Explanation:

“BSEE believes the historical data indicates that five minutes is adequate to demonstrate effective sealing.”

Why It Matters:

In a blowout, a BOP could have to contain a well for longer than five minutes. (To be sure, it could also have to contain a well for longer than 30 minutes.)

The inspector general report from 2016 cited above said that a firm conducting BOP verifications allegedly faced pressure from customers to shorten pressure tests from 10 minutes—apparently a practice at the time for the tests at issue in that report—to 5 minutes. One of the people interviewed in the inspector general’s investigation reportedly said that he told the verification firm that it “would need to fire him before he signed a BOP verification that only conducted a five minute pressure test.”

That person reportedly told his employer “that, based on his extensive experience and expertise in testing BOPs, he believed it to be absolutely necessary to conduct a ten minute pressure test in order to ensure the BOP did not have any small leaks.”

(The inspector general report was written shortly before the Obama Administration finalized the 2016 blowout preventer regulations.)

In the 2013 incident that destroyed a rig owned by Hercules Offshore Inc., there was a lull of 14 minutes after BOP components were activated, an investigation found. Then the blowout continued unchecked.

Five minutes is “not long enough to test something,” said Don McClelland, chief technical officer of the firm Offshore Inspection Group. Based on a test of only five minutes, “you don’t know if it’s going to hold,” he said.

Test Pressure

Current Rules:

BOPs must be subjected to a variety of pressure tests at different intervals to make sure they could contain a blowout. For some tests, if BSEE representatives are unable to witness the tests, the results must be submitted to the regulator.

Proposed Change:

BSEE would also reduce the amount of pressure that the equipment must withstand in certain pressure tests.

The pressure involved in a test of the so-called “deadman system,” which is supposed to automatically seal the well when crucial systems fail, would be reduced to 1,000 pounds per square inch (psi). “This revision would require confirmation of closure through a 1,000 psi pressure test held for 5 minutes,” the BSEE proposal says. The pressure involved in another test, to be performed under water using a remotely operated vehicle (ROV), would also be reduced to 1,000 psi. Currently, the pressure levels required for those tests, based on variables, could be much higher—for example, the maximum pressure the BOP is expected to encounter plus an extra 500 psi for good measure, or the maximum pressure the BOP is designed to contain.

BSEE’s Explanation:

BSEE says conducting these tests at higher pressures is not necessary and that the equipment will undergo other tests. It also says the changes would shorten the tests, save time, and cause less wear to the BOP. The purpose of the test involving the remotely operated vehicle is to “verify operability” of the vehicle, BSEE says.

Why It Matters:

BOPs could face much higher pressures than 1,000 psi.

For instance, in January 2017, when the casing burst in a well operated by Fieldwood SD Offshore LLC, the estimated internal pressure on the casing was more than 2,000 psi, a BSEE investigation later found. A contributing cause of the accident, BSEE concluded, was that the BOP was “only tested to 1000 psi.”

During the 2013 blowout that set fire to a rig owned by Hercules Offshore Inc., the pressure in the BOP rose to more than 4,000 psi, a BSEE report said.

And, according to the national commission that investigated the Deepwater Horizon disaster, months after the explosion, and after the gusher was finally capped, pressure in that well was logged at 6,920 psi.

Regulatory Oversight of Tests

Current Rules:

BOPs must be subjected to a variety of pressure tests at different intervals to make sure they could contain a blowout. For some tests, if BSEE representatives are unable to witness the tests, the results must be submitted to the regulator.

Proposed Change:

Test results would no longer have to be submitted to BSEE when BSEE is unable to witness the testing.

BSEE’s Explanation

Eliminating that requirement would “minimize the associated burden for BSEE to review those submittals.”

But, if BSEE asked to review the results, it would still have access to them.

Why It Matters

Another backstop and potential source of accountability would be removed.

Frequency of Tests

Current Rules:

BOPs must be pressure tested at intervals of 14 or 30 days, depending on the component.

Proposed Change:

BSEE has signaled that it is reconsidering the testing schedule. It has requested public comment on whether the frequency should be increased or decreased.

BSEE’s Explanation:

“In recent years, the industry has raised concerns related to the benefits of pressure and functional testing of subsea BOPs when compared to the costs and potential operational issues.”

BSEE has generally expressed concern that testing could cause wear and tear on BOPs.

Why It Matters:

Testing less frequently could reduce wear and tear, and it could save companies time and money. It could also increase the odds that the equipment wouldn’t work when needed.

Emergency Systems

Current Rules:

Rigs using underwater BOPs must be equipped with systems that can shut the well in an emergency if the usual controls are somehow cut off, including systems that would work automatically.

The emergency systems are known as “autoshear,” “deadman,” and “Emergency Disconnect Sequence (EDS).”

Proposed Change:

The following requirement would be deleted: “The control system for the emergency functions must be a fail-safe design once activated.”

BSEE’s Explanation:

The explanation BSEE gave for this proposal in a public notice seems like a non-sequitur. BSEE said the proposal is “based upon a better understanding of the third party verifications and documentation of the shearing requirements.”

Why It Matters:

In a fire or explosion on an oil rig, the crew members responsible for operating the BOP and the systems ordinarily used to control it could be disabled. People could be injured or killed, and the rig’s control lines could be disconnected from the BOP sitting on the ocean floor—as in the case of the Deepwater Horizon. In those scenarios, a reliable back-up could be crucial.

Hydraulics

Current Rules:

BOPs depend on hydraulic pressure to close a well. Under current rules,  for “subsea” BOPs—those that rest on the ocean floor—a supply of hydraulic fluid must be stored in subsea containers known as “accumulators.” The subsea containers must hold enough hydraulic fluid to power the BOP even if the flow of hydraulic fluid from the rig is lost.

The current rules explain the objective this way: “to provide fast closure of the BOP components and to operate all critical functions in case of a loss of the power fluid connection to the surface.”

Proposed Change:

BSEE would delete the phrase, “in case of a loss of the power fluid connection to the surface.”

Also, as stated in the notice of proposed rulemaking, “BSEE would remove the reference to the subsea location of the accumulator capacity.”

BSEE’s Explanation:

“BSEE understands that the accumulator system works together with the surface and subsea accumulator capacity to achieve full functionality,” BSEE said in a public notice. The revision “helps reduce the non-critical accumulator capacity on the BOP stack subsea,” BSEE added.

BSEE said adding underwater hydraulic containers adds weight to the BOP, potentially affecting its stability.

BSEE also said changing the accumulator requirements would be a major cost savings for industry.

The entire BOP system would still be covered by an industry standard, “API Standard 53,” BSEE said.

Why It Matters:

In the Deepwater Horizon disaster, as a result of leaks in the hydraulic system, the accumulators may not have been able to supply the power needed to close the well, a study by the Berkeley-based Center for Catastrophic Risk Management said.

“Six redundant means of activating the BOP high pressure BSR [blind shear ram] failed,” the study said. “There were similar redundant systems and processes to assure that the BOP was properly maintained and functional. All of these systems and processes failed.”

The U.S. Chemical Safety Board put it this way: “A fire and explosion like the one on the DWH [Deepwater Horizon] could damage power and communication cables and the conduit line carrying hydraulic fluid from the rig . . . .” The Deepwater Horizon BOP had two sets of shear rams to close the well, but the deadman system “was capable of closing only one of them due to accumulator limitations,” the board added.

The provision that BSEE would alter stated why it was necessary to place hydraulic capacity under water: “to provide fast closure of the BOP components and to operate all critical functions in case of a loss of the power fluid connection to the surface.”

Cutting Bent Well Pipes

Current Rules:

The current rules include several provisions that essentially promote the BOP’s ability to cut through a well pipe that has bent, buckled, or been knocked out of the center of the well.

For example, one provision says subsea BOPs must be able to “mitigate” compression of the pipe.

Another provision says that, by the spring of 2023, underwater BOPs must be equipped with mechanisms that can position an off-kilter pipe where the BOP’s blades can shear it.

A third provision requires verification that, in mandatory testing, the outermost edges of shearing blades were able to cut the pipe—not just that the blades could cut a pipe if it was positioned in their sweet spot.

Proposed Change:

BSEE would delete those three provisions.

BSEE’s Explanation:

BSEE cited technological advances in available shearing equipment and said it believes oil and gas companies “will continue to substitute new components for old ones” to comply with ongoing requirements.

“BSEE believes that, since newer shearing blades can center pipe, it is unnecessary to require a pipe centering mechanism,” the notice of proposed rulemaking says.

Why It Matters:

What if oil and gas companies haven’t adopted the newer technologies?

By way of background, a federal investigation found that the Deepwater Horizon’s blowout preventer failed to seal the well the night of the blowout because the drill pipe had buckled.

“[B]ecause the drill pipe was buckled and off-center inside the blowout preventer,” the U.S. Chemical Safety Board reported, the pipe was “only partially cut.”

That failure “directly led to the massive oil spill and contributed to the severity of the incident on the drilling rig,” the Board reported in 2014. The Board said the same conditions that buckled the drill pipe during the Deepwater Horizon accident could occur at other drilling rigs.

Shear Rams

Current Rules:

BOPs used underwater must have several different mechanisms for sealing wells. Those include two “shear rams”—which, as a last resort, are supposed to cut through the well pipe and block the flow of oil or gas.

Under the current rules, both shear rams must be capable of shearing the pipe and other structures such as electric lines.

Proposed Change:

Instead of requiring that each of the two shear rams be independently capable of cutting the pipe and other structures, BSEE would require that the combination of the two shear rams be able to do the job.

BSEE’s Explanation:

The change “would better align” the requirement with a standard promulgated by the American Petroleum Institute.

BSEE says that some shears have difficulty cutting some of these elements, while other shears have difficulty cutting other elements.

“BSEE is aware that certain casing shears still have difficulty shearing electric-, wire-, or slick-line, while certain blind shear rams have difficulties shearing larger casing sizes.”

Why It Matters:

The proposed change would eliminate the extra layer of safety.

As noted above, in the Deepwater Horizon disaster, multiple systems failed, a study by the Center for Catastrophic Risk Management said.

“Six redundant means of activating the BOP high pressure BSR [blind shear ram] failed,” the study said. “There were similar redundant systems and processes to assure that the BOP was properly maintained and functional. All of these systems and processes failed.”

“We need two independent blind shear rams to work as two independent systems,” said Najmedin Meshkati, a University of Southern California engineering professor who worked on a National Academy of Engineering study of the Deepwater Horizon disaster and the rig’s blowout preventer. Otherwise, the two shear rams could be vulnerable to the same mode of failure, he said. “We need to have redundancy” so that “if one of them fails, the other could work,” Meshkati said.

Alternative Devices

Current Rules:

For BOPs installed at the surface, if the blind shear rams are unable to cut various wires and cables in the well, the BOP must have an alternative device for cutting those.

Proposed Change:

BSEE would no longer require the alternative device.

BSEE’s Explanation:

“The alternative cutting device is no longer necessary because the currently commercially available shear rams have increased design capabilities, which are capable of shearing these types of lines.”

Why It Matters:

The fact that shear rams with increased capabilities are “commercially available” does nothing to prevent a blowout unless oil and gas companies use the newer models.

Safety Margin

Current Rules:

When drilling, energy companies must maintain a balance of forces within the well. To prevent oil and gas from rising uncontrollably, they pour a column of heavy fluid into the well. The fluid sits atop the oil and gas and holds it in check. If fluid the drillers use is not heavy enough, the oil and gas can escape in a blowout. If the fluid used is too heavy, the resulting pressure could crack the rock formation that holds the oil and gas, making it difficult to control the well. Under current rules (which allow for some exceptions), drillers must keep the pressure within a specifically quantified range, expressed through something known as the “drilling margin” or “safe drilling margin.”

Proposed Change:

BSEE is considering changing the specified drilling margin—or rewriting the rules to refrain from prescribing any margin. The Bureau asked for comment on those and other possibilities.

BSEE’s Explanation:

Prescribing a standard margin may not take into account the characteristics of each well, BSEE said. It may be better to use a case-by-case approach, BSEE said.

Why It Matters:

Malcolm Sharples, president of Offshore Risk & Technology Consulting, argued that there should be some prescribed drilling margin.

"If you take all the limits away, you have people perhaps doing foolish things they should not be doing," Sharples said.

“Eliminating this provision in my opinion, is the most egregious of any change suggested,” David M. Pritchard, a petroleum engineer who specializes in drilling hazards management, said by email.

For drilling companies, adhering to the safety margin can consume time and money. Under the current rules, if they can’t stay within the prescribed margin, they must suspend work.

Options BSEE is considering could give drillers greater latitude—potentially including the freedom to drill more dangerously.