Orchestrating the drilling of a deepwater high-pressure, high-temperature (HPHT) well is accompanied with a certain degree of optimism. Yet, forgive your neighborhood regulator for taking a more fatalistic view of your project, says Russell Hosman, technical advisor for Gulf of Mexico Regional Field Operations at the U.S. Bureau of Safety and Environmental Enforcement (BSEE).
“Industry looks at projects based on their probability of success, while BSEE looks at projects based on their probability of failure,” he said, in opening the World Oil HPHT Drilling, Completions and Production Conference on Sept. 26 in Houston. “We look at projects, based on the fact you have identified your failure modes, and you have recognized that you can make mistakes. We require that you have barriers, because we make the assumption that you are going to fail, and you have to prove you are prepared for failure.”
Noting the unequivocal link between deepwater and HPHT, Hosman gave an insider’s look at the myriad regulatory hoops that must be navigated before an operator gets the green light to mobilize a floater to location. While BSEE generally defines HPHT as any well with bottomhole pressure and temperature of at least 1,500 psi and 350°F, he said applications under evaluation come with pressures up to 27,000 psi, requiring mud densities of 22 lb/gal. The core role of the nation’s chief offshore regulatory agency is recognizing the potential risks to “people and the environment” that these challenges pose. The industry, in turn, must find solutions to the identified problem areas.
“No matter what happens, I want dual mechanical barriers. We don’t consider liquids a barrier, as liquids are conditional, temporary barriers and not a permanent barrier. What makes HPHT approval so difficult is that the HPHT equipment is the barrier,” he explained. “Other conditions of approval is that you understand your failure modes, and can tell me you can sense when you have a failure and how you’ll mitigate that failure.”
Anadarko Petroleum, for one, looked toward the cosmos, teaming up with NASA to pinpoint risk factors in subsea BOP stacks for ultra-extreme conditions. “Who better to identify the probability of failure of something that has never been deployed before,” Jim Raney, Anadarko’s director of engineering and technology, said as part of a panel discussion.
Although removed from deep water, McMoRan’s twin Davy Jones shelf wells, completed in 2012, nevertheless helped advance the qualification of HPHT equipment for subsea wells, Hosman said. “The surface trees were rated to 25,000 psi and 450°F,” he said. “This isn’t subsea equipment, but the lessons learned by going through the process of designing and building this HPHT equipment, I think, was an important process for the entire industry.”
“Are they insane?” By the time operators began dipping their bits into the outer reaches of the Gulf in the early 1990s, Hosman had been working for a major operator developing a “brand new, multi-billion-dollar project” offshore California. “We were operating in a very hostile regulatory environment and sold our first 120 MMbbl of oil for $6/bbl. At the same time, I’m seeing companies venture into the deepwater Gulf of Mexico, and I’m thinking ‘are you people insane?’ I don’t know whether they made money in the 1990s, but what they were doing was developing the processes, equipment and technology (for deep water).”
Hosman said shortly after joining BSEE’s predecessor (MMS) in 2002, rising oil prices sparked a stampede into the deep water. “There was an explosion into the deep water, and industry was ready to pursue deep water, because they’d been working on the technology already. Adding to this explosion, in my opinion, was a positive regulatory environment. Our internal environment has changed somewhat,” he said.
The case for MPD. Meanwhile, the assorted technologies developed under the managed pressure drilling (MPD) umbrella clearly embrace BSEE’s custodial mission, says Robert Ziegler, Weatherford’s global director of well control technologies. “Statistics show that you are five times more likely to get struck by lightning than losing well control with MPD,” he said during the panel discussion on HPHT challenges. “What’s very important is that we know that if our automated pressure control system is exceeded, we can activate conventional well control.”
Hosman concurs. “All the pieces are here. Closed-loop MPD equipment would reduce the probability of taking a large kick tremendously.”
That is not to say, however, that obtaining approval for an MPD deepwater application is a slam dunk, said Fred Brink, BSEE chief of District Operations Support (DOS), in a separate presentation on Sept. 19. While MPD with a surface BOP is somewhat common in the Gulf of Mexico, the use of subsea MPD falls under the category of new technology, making the go-ahead a rocky path, he told the IADC Drilling Engineering Committee’s (DEC) quarterly technology forum in Houston. “If something is brand new, it’s hard to get it approved. We don’t want to be the last, but we definitely don’t want to be the first,” he said. “I’ve never seen a request for using MPD from surface to TD, as usually it’s segregated into hole sections.”
Brink said that BSEE has no qualms about using MPD, providing the well remains in a constant overbalanced condition. “BSEE’s stance on MPD is that if done right, it can mitigate the risks and costs associated with drilling wells with narrow downhole environmental limits by practically managing annular hydrostatic pressure,” he said. “We’re not against it, but be aware we’ll make you go through hoops.”
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