More Tweaks Than Transformation in Rewrite of Well Control Rule
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The sound bites after the release of the final version of the revised US offshore well control rule suggested big changes were coming soon.
A statement from the environmental group Public Citizen said, “The Trump administration is once again putting corporate profits over safety by gutting the primary offshore drilling safety measure put in place to prevent the next massive oil spill.”
In a speech covering the administration’s record on offshore regulation, Scott Angelle, director of the Bureau of Safety and Environmental Enforcement (BSEE), said that promoting “homegrown domestic energy is what we are going to be about.”
Both comments were delivered shortly after the release of the final version of a revised well control rule, which clearly is a hot-button issue for many. It drew more than 100,000 comments from the industry and citizens, many of whom sent notes opposing changes to the 2016 rule.
It sounded about as earth-shaking as regulatory reform can be. The reality, however, was more tweaks than transformation.
“There were not any breathtaking issues that everyone was gobsmacked by,” said Glenn Legge, a Houston attorney with the firm HFW. Still, the lawyer who advises offshore energy clients on regulation, said his clients are keenly interested in the changes in the notice.
“Everybody is looking at the changing regulatory scheme and trying to assess it and address those issues,” he said.
There is no predicting how the rule that went into effect in mid-July will ultimately play out. The variables include the enforcement priorities of regulators and interpretations of hundreds of pages of regulations that could take offshore drilling regulation in unexpected directions.
A look at changes in three high-profile sections of the revised rule, though, suggest caution by the BSEE staffers charged with revising the 2016 rule. That version of the well control rule included major changes based on investigations of the blowout that destroyed the Deepwater Horizon rig, killed 11 workers, and triggered an oil spill that lasted for months.
While energy growth is a priority for this administration, after making that point Angelle quickly added that, “No amount of money or oil production will ever be worth it to do it in an unsafe, non-environmentally sensitive way.”
The changes are generally on the industry wish list, but many are clarifications of past rules or come with strings attached. For example, one rule will allow some operators to reduce the frequency of blowout preventer (BOP) pressure tests to every 21 days rather than every 14 days. But to qualify they must create a system to predict when equipment is likely to fail and study the cause of repeated failures.
“We need to drive reliability. We are trying to drive performance by ensuring that the BOP stack is getting analyzed as much as possible,” said Fred Brink, the lead writer on the rule revision.
The revisions continue to require that BOPs be able to center pipe to enable a clean cut, and add that this requirement may be satisfied using shearing rams with a V- or W-shape designed to do so.
The 2019 revisions require real-time monitoring during operations offshore. Although the new regulations don't contain as much detail as the prior well control rule, the current rule requires operators to submit a monitoring plan that must be approved by BSEE.
Another change eliminated an effort to create an approved list of third-party BOP inspection services, which BSEE has never done. Instead, they will stick with a rule saying inspectors need to be from a technical classification society, a licensed professional engineering firm, or be a registered professional engineer capable of performing the required checks.
Legge said the people he talks to in the industry do not want to be hamstrung by prescriptive rules. But the attorney whose career includes representing Cameron after it was sued as the maker of the Deepwater Horizon BOP, said the industry recognizes the need to lower the risk of drilling offshore.
“We are believers. We all learned. There were painful but worthwhile lessons learned from Deepwater Horizon,” Legge said.
Three sections have gotten the most attention:
Safe Drilling Margins. When the revised rule was first proposed, BSEE said it was considering “whether it should adhere to its practice of identifying a specific drilling margin.”
The final rule did not change the margin rules used when reviewing drilling permit requests. It requires that the drilling plan ensure a 0.5 pounds per gallon margin during drilling. And if that margin cannot be guaranteed—in exploration wells the margin of error in downhole pressure estimates is too large to assure that margin—the operator can seek permission from BSEE for a plan demonstrating how the well can be safely drilled.
The big change here is that the revised rule allows an operator to file a plan covering multiple wells rather than seeking regulatory permission before each well is drilled.
“Whenever you buy a lease, you invested a lot of money and time into developing this lease,” Brink said. “This allows them to get an approval based off of their anticipated well design.”
Over time, more sophisticated drilling methods that provide more precise well control may allow BSEE to change drilling regulations.
Brink said his normal day job, the chief of district operations support, includes providing interpretations of regulations, such as how to apply the rule when new drilling technology is introduced. That includes the slowly growing use of managed-pressure drilling, which combines more precise fluid flow measurements and the ability to quickly react to changes.
“BSEE agrees that technology is improving and could help justify a performance-based drilling margin at some point. However, BSEE would need to obtain and evaluate more research and data before it can develop and adopt a performance-based drilling margin,” the rule said.
21-Day Testing. The revised pressure-testing rule offers a carrot to entice operators and drillers to use new data-driven tools to substantially improve BOP reliability.
The incentive is an opportunity to pressure-test BOP equipment every 21 days, rather than every 14 days. That could represent a substantial saving because Brink estimates that each test interrupts drilling for about 8 hours. Over 365 days of drilling time, being allowed to extend the testing interval from 14 to 21 days would mean about nine fewer tests.
With rig rates as high as $500,000 a day, that could represent a substantial saving. Winning permission to do so will require convincing BSEE that a system is in place providing predictive maintenance system and failure analysis. The cost of that added effort could be covered by savings on BOP downtime, which is a major cost offshore. For BSEE the point is to ensure the BOP works when it is needed to prevent a disaster.
The proposal stirred up a debate over whether a 14-day testing requirement is safer than a 21-day interval, even when no improvements in the maintenance program are required.
In Brazil, the United Kingdom, the Netherlands, and Denmark, offshore testing is required every 21 days, without the strings attached by the new US rule. One commenter submitted an analysis of the reliability of BOPs in countries with the 21-day rule, vs. every 14 days, and concluded there was “no reduction in BOP reliability.”
While BSEE did not question the statistical analysis, comparing results in places using different regulatory philosophies is tricky. BSEE will gather data based on experience in the US Gulf of Mexico (GOM), where it has been monitoring a pilot program in the GOM combining 21 days testing and an aggressive monitoring and maintenance program.
While Brink declined to identify the companies involved in that program, Shell recently offered a look at a BSEE-approved pilot program it has been running in the GOM, during a conference in San Francisco.
The project, which included Transocean and an unnamed equipment maker, followed a plan that appears to follow the key points in BSEE’s rules summary:
- Continuously monitored the condition of BOP components
- Performed an analysis after every failure
- Developed monitoring tools and analysis methods
- Delivered quarterly reports to regulators
For example, pressure-monitoring data were analyzed using a “physics-based” model able to distinguish between normal pressure changes and leaks, the presentation said.
One slide showed how a pressure test allowed the partners to identify deteriorating elastomers in the annular preventer. The test results were confirmed when they found the parts were deteriorating during an inspection.
In another case, Shell reported that an analysis of a part that had repeatedly failed led to a change in maintenance procedures to avoid damage that had occurred during previous repairs. This program saved Shell money by reducing downtime on the four, high-performance drillships, three of which were in Transocean’s fleet.
Real-Time Monitoring. The change in this section is a clarification: onshore monitoring does not require staffing a drilling monitoring center. This reflects the development of real-time monitoring since 2016, which has made it possible to access monitoring data on a laptop or smartphone anywhere with a secure Internet connection.
While building and staffing real-time monitoring centers made economic sense for companies with major drilling programs in the GOM, such as BP or Shell, it did not for independents drilling fewer wells with fewer employees.
“We want to ensure that we’re using the most up-to-date technology, and not requiring a brick-and-mortar-type building if it is not needed,” Brink said.
The rule requires operators to have a system enabling qualified personnel to monitor what is going on. While Brink said it does not explicitly state the person doing real-time monitoring needs to be on land, the language is “implying that rig and monitoring personnel has to be in two separate locations.”
There is no change in what needs be tracked: BOP control systems, fluid-handling systems ensuring accurate fluid-flow measurements, and any downhole tools in use. The rules cover BOPs located subsea, on floating facilities, or in high-pressure/high-temperature environments.
“I would say the majority are doing some portion of the [required] monitoring. I do not think most companies are doing all three aspects that are required by the regulation,” Brink said. The priority now is to reach a level where all three of those requirements are met by all.
While the general compliance date for the 2019 rule is 60 days after the mid-May publication of the final rule, BSEE “can determine alternative compliance dates are appropriate for certain provisions,” Legge said.
While he recognizes data and analysis can improve performance by providing early warning of problems, he sees the value in taking the time to get this new technology right.
“The thing about any digitized process is garbage in, garbage out. We have got to have the correct data an analytics” to accurately understand and react to what is going on in the well,” Legge said.
More Tweaks Than Transformation in Rewrite of Well Control Rule
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
07 June 2019
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