Drilling advances

As expressed in this space not so long ago, it’s unlikely that any major breakthroughs are forthcoming to further improve the industry’s largely infallible proficiency at destroying rock. That said, the unconventional community continues to struggle with making sure that the right rock is being destroyed in the right place, as wells reach out 2 mi or longer and are typically drilled from crowded pads.

“I think there’s a lot to be done in the drilling space, in terms of how fast we drill these super-long laterals, which is obviously getting more complicated to do,” Schlumberger CEO Paal Kibsgaard told analysts on Jan. 18 while discussing the 2018 progress report. “Just a simple motor solution is obviously largely inferior, compared to the high-end rotary steerable systems.”

Regarding acreage-constrained shale plays, “super-long laterals” is relative. At 20,800 ft, Eclipse Resources’ Mercury B 5H well in the Utica shale is believed to be the unconventional well with the longest lateral drilled to date, far shorter than the world-record 38,514-ft horizontal departure of Exxon Neftegas Ltd.’s Chayvo Z-42 well off Sakhalin Island. Kibsgaard, however, touched on a recurring topic during year-end earnings calls, where service company and contractor talking points discussed new technologies aimed at enhancing well placement and avoiding inter-well communication.

Staying on track. To put in perspective the continuing trend of ever-increasing laterals in unconventional wells, consider that in 2014, the typical land rig required 18,000 ft of tubulars, whereas today, each rig averages more than 22,000 ft of pipe, says drilling contractor Helmerich & Payne, Inc. Aside from the intrinsic hardware demands of longer laterals, the tight subsurface spacing of multi-well pads magnifies the pressure to remain on the programmed path to reach identified targets.

With nearly 900 patents issued in 2018—a 10% y-o-y increase—Halliburton “invested heavily” in its directional drilling portfolio last year, “as wells in the U.S. unconventional basins beat lateral length records, “ says Chairman, President and CEO Jeff Miller. The Centenarian firm’s newly commercialized drilling technologies include the automation-enabled iCruise intelligent RSS, touted as delivering precise steering and accurate well placement. “We designed the new iCruise rotary steerable system from scratch, using the latest material science and digital innovations, with the focus on decreasing operating costs, improving reliability, and reducing maintenance time and expense,” Miller told investors.

Weatherford International, meanwhile, recently rolled out its Magnus RSS, which it describes as combining “reliable, high-performance drilling with precise directional control.” The push-the-bit directional drilling technology comprises, among other features, fully independent pad control, real-time BHA diagnostics and autopilot functionality. In a Feb. 1 conference call, CEO Mark McCollum said “a significant portion of our capex budget is allocated to new Magnus tools.”

Motors have not been ignored, as National Oilwell Varco (NOV) last year debuted what President and CEO Clay Williams described in a Feb. 7 earnings call as “a really unique way of drilling horizontally.” NOV says its SelectShift downhole adjustable motor enables the motor bend setting to be adjusted downhole, and in so doing “improves hole quality and increases ROP throughout all sections of the well,” while eliminating extra trips.

Human aids. As with its contemporaries, Helmerich & Payne continues to actively upgrade its onshore rig fleet to super-spec status, as shale wells grow longer and more complicated. During the fiscal year ended 2018, the contractor converted 54 FlexRigs to super-spec status and plans to upgrade or convert 12 rigs/quarter for the foreseeable future.

“The average lateral today, we think, is around 8,000 ft, which is up from around 6,000 ft in 2015/2016. If that average lateral continues to trend higher, which we suspect it will, and it goes to 8,500 to 9,000 ft, then you begin to put a lot of these older rigs, less-capable rigs in a position where they just can’t perform at the same levels as a super-spec rig does,” CEO John Lindsay said during the FY18 conference call on Nov. 16.

At the same time, he discussed two ancillary technologies that the company recently unveiled to enable precise wellbore landing and quality control “as the industry continues to grow longer laterals on multi-well pads with tighter well spacing.” The MOTIVE bit guidance and MagVAR MWD survey correction software packages are being used on both H&P and competitor rigs, with the former engineered specifically to compensate when the human directional driller’s efficacy is less-than-optimum. “Having a bit guidance system that enhances that directional driller’s capability is a big win,” he said.

Meanwhile, Lindsay said H&P hopes to roll out its new AutoSlide automated directional drilling sliding technology in the Permian basin during first-quarter 2019. The system is “an evolutionary step in drilling automation, eliminating human intervention during slide operations for all sections of a horizontal well.”

As for H&P peers, Patterson-UTI Energy Inc. upgraded one rig in January to go with the 18 rigs converted to super-spec status over 2018. Nabors Industries, at last count, was set to deploy four upgraded super-spec rigs to the Permian basin and Eagle Ford shale during the first quarter. And, in what CEO Kevin Neveu described as a “pivotal year” for technology deployment, Canada’s Precision Drilling in 2018 installed recently tested process automation control (PAC) on 10 super-spec rigs, bringing to 31 the number of rigs now employing the automated platform.

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.