Drilling advances

An industry having an intimate history with hopes dashed can find it easy to empathize with Calvin Holt.

The Chevron senior drilling advisor’s staunch advocacy for managed pressure drilling (MPD) was dampened after a recent land well, where excessive downtime, valve failures and other issues contributed to an eventual benefit-cost ratio of <1. “Certainly, we believe in the benefits of MPD. It’s simple, precise and value-driven. But this last well sort of knocked me back.”

Similarly, ConocoPhillips’ inaugural onshore use of MPD to drill a troublesome asset ended with inordinate downtime and a blown budget, which “kind of left a sour taste in everyone’s mouth about MPD,” said J.D. Samuell, global wells, MPD subject matter expert. Seven years on, however, MPD is a mainstay on half of the operator’s rigs worldwide, which Samuell expects to rise to 75% by 2020.

The operator representatives joined service providers and contractors in March at the IADC Drilling Engineers Committee (DEC) technology forum in Houston, to examine what is needed to re-cast MPD from a supporting role for wells too prickly to drill otherwise to a fixture on the main stage. The consensus on what will drive wholesale adoption: Having fit-for-purpose MPD hardware, controls and processes integrated into the rig, where MPD would be viewed through the same lens as the top drive. Or, as Dwayne Barnwell, a product line manager for National Oilwell Varco (NOV), puts it, “having the equipment always on the rig, always commissioned, and always ready to use by simply having the driller turn it on.”

Holt can relate, given the rig-up downtime and delivery issues experienced on the ill-fated well. “The rig-up plan was well-documented, and obviously a lot of lessons learned went into it, but unfortunately that never showed up on location,” he said. “Getting the RCD (rotating control device) hooked up to the flowline costs us a day, minimum. Anybody who has a solution to get the RCD hooked up to the flowline in an hour or less, you have a market.”

He conceded that some of the setbacks were self-induced, pointing specifically to an overly restrictive operations matrix—borne out of an abundance of caution—that prohibited using the MPD choke manifold to deal with unexpected nuisance gas, leading to invisible lost time. “I knew down deep that once we got MPD out there, we would show folks that we could let the shackles off, but we never got to that stage,” he said.

Last resort. ConocoPhillips turned to MPD in 2012 after a number of unsuccessful attempts to land casing and maintain wellbore stability in an onshore play featuring unstable cap rock. “We were able to drill it for about 12 years, until we started having issues getting casing to bottom,” Samuell said. “We tried everything from changing the trajectory, the mud, the BHAs, doing rock studies and even running a steerable drilling liner. We thought the ultimate solution could be MPD, so we tried it.”

While delivering “a hint of success” after drilling two sections in two wells, Samuell said equipment issues “overshadowed the results.” He suggested that the economic ramifications were foreshadowed, when the modified offshore MPD system showed up at the onshore location with a “small army” of seven hands and complex hardware, including dual hydraulic chokes.

First mistake, says NOV’s Barnwell. “When you try to force an offshore package onto a land rig, you bring all the personnel to run it and all the complexity. On a land rig, you can achieve 90% of what you want to achieve with a simple, single-choke system operated by the driller.”

ConocoPhillips re-visited MPD in 2014, with less-convoluted, land-focused systems now requiring only a two-person crew. Since then, tripping and drilling speeds have doubled, mud costs have dropped, and the company is able to drill longer laterals to “maximize pad drilling,” Samuell says. In another onshore asset, with a 40% failure rate in landing casing, “there hasn’t been a failed casing run in the five years we’ve been applying this technology.”

Value personified. To see the value-driven implications of MPD-enabled rigs, Nabors Drilling says to look no farther than its experiences in Wyoming, where well control problems, narrow drilling windows, and high torque and drag created all manner of difficulties in getting wells and casing to programmed depth. Initially chosen to curb excessive oil-base mud (OBM) losses, MPD has reduced losses by well over half, and has since enabled operators to go from four to three casing strings, said Nabors Senior Operations Engineer Adam Keith, in analyzing 10 of the more than 70 wells that the contractor has drilled in Wyoming.

“One of the reasons MPD has become standard in the area is the ability to consistently eliminate a casing string and reach target depth with a single mud weight,” he said. “We are now batching two wells and trying to go to a two-string design, by extending the surface casing to a long string and eliminating the intermediate string altogether.”

“This is not a constant bottomhole pressure technique. Our main objective was to reduce mud density and be constantly hydrostatically underbalanced, and that way MPD keeps you overbalanced all the time and gives you a lot more leeway into extending how far you can drill with a single mud weight,” he said.

Elsewhere, with a more than 40% overall increase in ROP, MPD in combination with solids-free brine is transitioning to a “must have” in Alberta’s Deep basin and Duvernay shale plays, says Leiro Medina, V.P. of technology for Canada’s Beyond Energy Services. WO

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.