Drilling advances

Automated managed pressure drilling (MPD) has emerged as the go-to methodology for drilling the world’s prickliest wells. Why then, is that same technology not an industry standard for taking human frailties out of the well control space?

“What it all boils down to are the barriers that exist, and how to remove them,” says Blaine Dow, drilling engineering marketing and technology manager for M-I SWACO, a Schlumberger company. “It’s not an open dialogue in the industry as yet, but we want to go there. Procurement exercises are actually forcing this move, in some cases, as we’re seeing certain companies saying ‘this is something I truly want.’”

Indeed, regulatory, liability and responsibility barriers aside, Dow told the latest IADC Drilling Engineering Committee (DEC) quarterly technology forum in Houston that low oil prices and stacked rigs surprisingly are making more drilling contractors “suddenly get excited about putting MPD on their rigs.”

“That is what’s happening today. We’ve got some operators saying, ‘If I’m going to drill a deepwater well, who knows if I’m going to encounter an MPD scenario or not, but I’m going to be sure my rig is ready, or I’m going to procure another rig.’ We have so many inquiries coming from drilling contractors right now, asking how to put MPD on their rigs. It’s at a fever pitch. We’ve never seen anything like it,” Dow said.

Game-changer-in-waiting? The September forum focused exclusively on barriers in well control, where even the seemingly rudimentary measurements for confirming same remain an open question. “This (key measurements) is actually a huge topic and remains an industry issue, in that there are many, many aspects to consider,” said Bob Pilko, strategic relationships director for Blade Energy Partners. “An industry consortium is actually working on this right now.”

On the other hand, if GE Oil & Gas has its way, technology borrowed from the health care sector will eventually replace reaction with a pre-kick alert. Bob Judge, GE’s director of product management, said that an annular flowmeter the company is developing aims to solve a time-worn problem with kick detection by measuring “what is coming out of the well and compare that to what we’re pumping in the well.”

The technology comprises “specially arranged” ultra-sonic transducers that will provide real-time monitoring of flow and mud trends, regardless of whether the drill pipe is actually in the hole. The meter would be deployed at the bottom of the riser and closer to the problem, with flow measurements validated to prevent over-reaction to false positives.

Pointing to the “infinite combination of variables characterizing a kick,” Judge said the development program steered away from strict adherence to accuracy and more toward pattern recognition, which still provides “an indication of what’s going on inside the well.”

GE is trying to line up an onshore or subsea pilot test for the annular flowmeter, which is adapted from work undertaken by an internal health care team to measure human blood flow. In keeping with the medical analogy, Judge said that when it comes to well control, the oil field historically has been “treating the symptom, but we need to fundamentally determine what is causing the problem.” That, he said, underpins the development initiative.

Getting on board. Until then, Dow says automated, MPD-enabled well control remains a field-tested solution in search of universal acceptance. Obviously, getting global regulatory jurisdictions onboard is a major hurdle. He pointed specifically to the Gulf of Mexico, where regulations do not explicitly prohibit automated MPD for well control, but the inference is clear, in that the notice to leasees (NTL) subtly suggests that wells not fall statically below pore pressure. “That’s the preference, though it’s not written that way,” Dow said. “That takes out a whole bunch of operational capabilities an MPD system can bring to an operation, by using that ECD (equivalent circulating density) effect to help manage a narrow (drilling) window.”

Then, there are the compelling matters of liabilities and specific operational responsibilities, once the MPD system is installed. The liability factor can be simply resolved, he said, by acknowledging that as the rightful owner, the drilling contractor is responsible for the MPD equipment. A thornier issue is defining specific roles and responsibilities. Typically, subject matter experts (SME) would be called upon to execute an MPD or underbalanced drilling job, but the dynamic changes when the contractor owns the equipment. “We have to spend some time as an industry to figure out how the baton gets passed,” Dow said. “Does the drilling contractor become responsible and own the MPD space, or the well control space, or both spaces together? Does that mean there’s a bridge of SME, who help carry the baton across? The industry will have to determine that before something bad happens.”

To be sure, he said the benefits are palpable, as illustrated in an onshore well in western Canada. There, an automated MPD system conducted full well control circulation on the fly, after which the well was drilling ahead with a higher mud weight, some four hours after an influx was detected. “At best, it would have taken 16 hours to manage it in a classic well control scenario, or in a worse case, you get stuck, possibly costing weeks of downtime,” he said.

“As an evangelist of MPD, I don’t care who owns the equipment, I want to see more people drilling with MPD, and not just because it means more money for my company. I truly believe it’s the best way to drill a well.”

About the Authors

Jim Redden

Contributing Editor

Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.