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Nabors owns and operates one of the world"s largest land-based drilling rig fleets and is a provider of offshore platform rigs in the United States and numerous international markets. Nabors also provides directional drilling services, performance tools, and innovative technologies for its own rig fleet and those of third parties. Leveraging our advanced drilling automation capabilities, Nabors" highly skilled workforce continues to set new standards for operational excellence and transform our industry.

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Managed Pressure Drilling (MPD) is an adaptive process used to more precisely control the annular pressure profile throughout the wellbore while drilling. Converting conventional atmospheric drilling to a closed circulating loop system enables the driller to optimize mud weight and rate of penetration (ROP), more quickly detect influx and fluid loss, and discriminate wellbore ballooning and breathing. This results in lower mud product cost, less stuck pipe, and potentially fewer casing strings.

The MPD process is executed by controlling flow conditions to maintain bottom-hole pressure according to a modeled pore pressure and fracture gradient drilling window. While the benefits of conventional MPD techniques are well known offshore, the economics of engineering, mobilization and rig-up, and additional specialized personnel requirements are not supported in cost-sensitive drilling programs such as unconventional land drilling.

Nabors’ fit-for-purpose MPD equipment and integrated rig services enables a new concept to leverage today’s advanced land rig infrastructure including drives, manifolds, tanks, pumps, and gas handling equipment. Engineering and integrating MPD capabilities into the rig with unique automated workflows unlocks advantages in capital requirements, eliminates the need for pre-job surveys and engineering, and minimizes high mobilization and rig-up costs.

Through the advanced integration and automation of MPD services, the need for third-party service providers is also eliminated. Benefits include increased safety, less HSE exposure, lower cost, reduced pad footprint, more efficient rig moves, and more transparent performance analytics. For all of these reasons, scalability of MPD services is now more cost-effective for land drilling operations.

The work on the drilling floor of the PaceR801 rig revolves around a stout robot methodically picking up sections of pipe and moving them precisely over the drilling center to rapidly connect the pipe.

While it is one of many technological advances on the rig Nabors bills as “the world’s first fully automated land rig,” the robot is the one “that gets most people interested and excited,” said Travis Purvis, senior vice president, global operations for Nabors Industries Ltd.

As of 18 October, the PaceR801 had completed the first well on an ExxonMobil pad and was drilling the lateral on the second well of the three-well pad. After the third is done, the extended test will move to the next pad.

It is risky to announce who came in first in a competitive race in a secretive business. But Nabors stands out because the PaceR801 has an automated drilling floor, a range of other automated functions above and below ground, and most significantly, it is the only one using its rig to drill producing wells for a customer.

Jason Gahr, operations manager for unconventional drilling at ExxonMobil, said the research collaboration “demonstrates the ability to optimize drilling using the combined power of robotics, automation, computing, and data.”

The companies’ interests range from automating more drilling functions by retrofitting rigs, to wanting to hire the rig, whose name is frequently shortened in conversations to R801.

It was created to show off the fruits of a 5-year drive to create a totally automated version of its Pace high-specification rig. Nabors likens it to the concept cars built by automakers to show off their vision of the future and to promote innovation within the company.

In this case, it is a vision of the near future. While the automated drilling floor is new, much of the rest is recently proven technology. Two of the drilling automation programs used—Nabors’ SmartSLIDE and SmartNAV—are already on 30% of the Nabors fleet, said Austin Groover, director of operations for smart products at Nabors. Those applications, which manage drilling of the curve and directional drilling, plus a third that automates drilling a stand of pipe, SmartDRILL, have been used by ExxonMobil for 2 years.

Maximizing the performance of a rig with multiple proven technologies plus a new one such as a robotic drilling floor required developing a system that coordinates the movements of those apps and the rig hardware while drilling.

A rig floor video would show the robot reaching over to pick up the next piece of hardware—normally a 45-ft segment of pipe that had been measured and its threads doped previously by the system. The arm then moves it over the well center and holds it vertically in place while other machines recognize the thread pattern and spin the pipe to connect it with the right level of torque. Then another application takes over to lower the drillstring to the bottom and resume drilling according to ExxonMobil’s specifications.

The number of steps actually required is far greater than one wordy, oversimplified paragraph can express. ExxonMobil is now working with Nabors to see if the innovation will translate into improved performance.

Occidental Petroleum’s goal for automation is to “capture knowledge,” said John Willis, vice president for drilling and completions for onshore and carbon sequestration for Occidental, in in his keynote address at the recent IADC Advanced Rig Technology Conference (ART) covered by the IADC Drilling Contractor.

The industry has been working toward this point for more than a decade. Work on Nabors’ drilling floor robot dates to 2008 when Equinor initially funded a Norwegian startup, Robotic Drilling Systems AS. Nabors acquired it in 2017 after the equipment was evaluated on a Norwegian test rig.

“The robot and automation can identify what we call ‘odd objects,’” like a bottomhole assembly and get it when needed, said Josh Price, West Texas area manager for Nabors, during a presentation at a recent meeting of the IADC Advanced Rig Technology committee.

The robot made by Nabors’ Canrig unit can expand its capabilities by choosing from an array of tools, including one that can grip and spin a stand of pipe. It also can handle casing, opening the door for automating completions as well.

There has been little demand for mechanical pipe-handling systems for land rigs because “humans can move really fast,” said Paul Pastusek, drilling mechanics advisor for ExxonMobil, while speaking at the ART committee meeting.

Nonetheless, Nabors’ Purvis said the automated system will outperform the status quo on two critical measures that motivated Nabors’ CEO Anthony Petrello to approve the development of the R801.

While there are no people on the drilling floor, the crew there previously will still be working on the rig to perform inspections, maintenance, repairs, and rig moves.

Training will be required as rigs get increasingly automated. The Nabors statement said automation will “provide reskilling opportunities for Nabors employees and the broader industry workforce.”

So, how fast can Nabors’ automated rig connect pipe? The short answer is: They are not saying. The news release about the test said, “Consistent with the practices of drillers and operators on test pads, Nabors and ExxonMobil do not plan to publish performance data and results.”

A description of the robot on the Nabors website said it is capable of pipe connection times—from slips to slips—of less than 1 minute. It added the qualifier “based on early studies.”

The speed estimates are in line with those made by Huisman, which has built a land rig with automated pipe handling for Sirius Well Manufacturing Services, a drilling services joint venture between Shell and the China National Petroleum Co.

Purvis said the R801 is drilling faster than high-performance rigs 5 years ago. Since then drilling has gotten faster so they will need to do better eventually. But the systematic testing program does not sound as though it is designed to set speed records early on.

When comparing automated drilling to traditional crews, it is useful to recall the fable of the tortoise and the hare, where a steady effort beat the faster runner.

When 1-day drilling records are announced, no mention is made of the rig’s performance on the next day. Chances are they are not as fast based on the connection-time data gathered by monitoring programs. They observe that the speed of the work varies from crew to crew and from day to day for each crew.

Drillers at the controls are feeling a different form of performance pressure—a growing number of routines required by customers’ evaluations of the best way to manage drilling. Either way, it is hard for workers to consistently execute specific routines over long shifts, day after day.

In automated drilling, the human inputs include the drilling plan and the system software. The companies are analyzing drilling performance as they go and making changes driven by their observations.

In his keynote speech at ART, Willis described the problems faced when trying to interconnect equipment based on different proprietary designs. “When we go to try to buy automation, it’s really hard to get,” Willis said “We’re largely limited to what’s available from individual drilling contractors. It’s very difficult, if not impossible, to take something from another third party and add that to a rig. And none of our rigs have what we would consider to be a full system of automation today,” he said.

A drilling contractor would respond that this new approach to drilling requires new contract terms. Those agreements would rethink the traditional relationships, with longer-term contracts priced to reward drillers for investing in rigs that cut the days required to drill a well and improve the quality of the hole.

Based on its analysis, ExxonMobil lists 150 parameters to be programmed into rigs working for the company, covering everything from the weight on bit while drilling to rate for starting to drill, Pastusek said.

He is looking forward to a future where the systems can adjust the setpoints based on drilling data revealing unexpected changes. “Rather than preprogramming those, we will allow them to be adaptive,” Pastusek said. It is something Groover would also like to see. “There is a further opportunity to tie in more downhole data to surface automation that would be the next iteration of automation,” he said.

The number of sensors on rigs and drilling equipment continues to soar, and suppliers like Halliburton are working on improving the data gathered while drilling. Its new generation of measurement-while-drilling (MWD) tools will handle downhole processing of the data gathered, allowing it to be fed directly into an automated control system.

While the volume and quality of the data is growing, the amount that can be delivered in real time to the surface is generally limited to what can be sent using mud pulses, which deliver a limited amount of data and only work when the mud pumps are on.

“We hear that wired pipe is the holy grail with fast two-way communication. The reality is wired pipe has been around for 15-plus years,” said Paul Cooper, product manager, Halliburton Sperry Drilling, during an interview about the new MWD system called iStar.

“This is happening today; they are running it in the Eastern Hemisphere in a couple countries,” said Neila Kadri Bebaud, strategic business manager, Halliburton Sperry Drilling. She said there “have been 70 automated rotary steerable runs without any human involvement.”

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A high percentage of mud motors are considered to be run out of spec by industry standards. The challenge has been to build a reliable motor that can withstand the stresses of more weight on bit, differential pressure, and rotary RPM.

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