Perhaps nothing can fray the nerves on a floater quite like a failure in the subsea BOP stack. Oftentimes, however, what at first is a frightening glitch turns out to be a perceived issue, which nonetheless can lead to enormously expensive and wholly unnecessary reactive measures, says Garry Davis, president and CEO of BOP Risk Mitigation Services.
“From our experience and study, we’re dealing with the most reliable pieces of equipment on a rig, and that’s the BOP,” he says. “We don’t have a significant reliability problem you can attach to the BOP, but we do have a significant issue with the mean time to repair, because it’s not simple to shut this piece of equipment down, bring it to surface, affect the repairs, re-test it and then resend it to bottom.”
Adopting what is touted as the industry’s first standardized technology-based subsea BOP rapid risk assessment system, Davis said, could go a long way to calm nerves, save money and, above all, safely drill a deepwater well to programmed depth. Davis provided an overview of the system during the IADC Drilling Engineering Committee (DEC) quarterly technology forum in November, which examined the “Impact of Advances in Technology on Equipment Performance and Reliability.”
In short, he said the HMI-controlled virtual environment simulator provides contractors and operators access to comprehensive information on potential BOP failure modes, with the equipment’s capabilities clearly spelled out prior to placing the stack in service. Moreover, as part of the system’s fault finding, troubleshooting and fault verification components, failures at varying degrees can be inputted into the simulator, enabling the user to visualize how the overall integrity of the BOP is affected. The initiative has received regulatory blessing, having been designated as a STAR (Safety, Technology and Review) by the U.S. Bureau of Safety and Environmental Enforcement’s (BSEE) Best Available and Safest Technology (BAST) section.
Costly and emotional issue. The project was initiated seven years ago to address, what Davis described as a significant problem in the industry. “When we have a problem with the well control equipment, how do we react to that information and what information is required for us to assess (the problem) and report it to the regulators, both in the U.S. and abroad,” he said.
In the systems studied over the four-year validation phase of the BOP risk assessment system, 25% of stack pulls were identified as unnecessary, “meaning they still had the technical justification to maintain in-service status,” Davis said. “That came with a price tag of over $32 million to the drilling contractor alone, so you can easily double that for the operator.”
“The emotional and financial emphasis on how we resolve these issues, and whether to maintain in-service status or pull the stack, becomes quite a complex problem when you’re interacting with multiple parties with different objectives,” he said.
“One thing I ask when I’m doing a risk mitigation for a client is, have I breached my minimum capabilities for well control by industry standards? You’d be surprised that not many people really, truly know the answer to that question,” he said. “My second question is, has my regulatory minimal requirement been breached? Believe it or not, that seems to be a difficult question to answer.”
Consequently, what started out as a straightforward proposition turned out to be anything but. “As we moved forward with the development of this, we thought it would be a rather simple solution, but we ran into many roadblocks,” Davis said. “How do we effectively communicate with all the parties involved in this decision-making process, with a simplistic method that everybody can understand? We apply this methodology to get the answers quickly, make the discussion as simple as possible so everybody is on the same page, and then move forward to the operational considerations on what we are going to do to make sure we safely construct the well.”
The risk assessment technology breaks down a subsea BOP system to its simplest form, Davis says, including clearly labeling every component that could possibly create a failure, all encapsulated in a single drawing. “We create failures and can show the outcome of an escalation of an event,” he said.
Documenting WCE failures. With respect to failures, at last count a sweeping database built as part and parcel of a joint industry project (JIP) has recorded more than 6,000 events over the past three years where well control equipment (WCE) failed to perform as designed. Sponsored jointly by the IADC and International Association of Oil and Gas Producers (IOGP), the so-called RAPID-S53 (Reliability & Performance Information Database) JV was put together in 2015, specifically to collect details of non-compliant WCE events. In compliance with API Standard 53, the gathered data eventually can be used to improve WCE reliability and efficient operation. One of the ongoing initiatives is to accumulate sufficient experience data to eventually be in the position to predict the mean time between failure (MTBF) for certain WCE components.
In a separate DEC presentation, Mark Siegmund, BP senior subsea engineer and the then- chairman of the JIP, said the latest data available shows 2,040 events reported in 2017, of which 1,475 were discovered while the BOP stack was being inspected, maintained, tested and otherwise not in service. Based on 2017 reports, a “typical” offshore rig could be expected to experience 20 WCE events/yr, but only six while in actual operation.
The RAPID-S53 JIP has grown steadily from seven drilling contractors at its inception to now include 14 contractors, 12 operators, and 3 original equipment manufacturers (OEM).
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