Drilling Innovations: Hardware Evolution Moving Rigs Toward Automation Revelation

[Editor's note: This article originally appeared in the February 2020 issue of E&P magazine. Subscribe to the magazine here.]

The evolution of the land drilling rig has historically revolved around making these workhorses of the oil and gas industry more powerful, more capable and more efficient. The first two challenges are being met through improved mechanics and robust hardware that have taken rig capabilities into the stratosphere with so-called “super-spec” units, complete with 1,500-hp drawworks, a 750,000-lb hookload rating, 7,500-psi mud circulating system and multiple well pad capabilities. The last challenge has been built into both emerging mechanical designs as well as complex new software initiatives that are enabling drilling rigs a level of autonomy—and safe, repeatable functionality—never seen before. Rig hand functions are being turned over to rig apps that can offer single-button control over everything from making up pipe to maximizing engine performance.

Land driller Patterson-UTI runs Cortex, its operating system for its APEX drilling rigs, and its suite of apps to control and/or monitor everything from drilling automation to vibration mitigation. The Genesis app is used to control the rig’s generators and engines, which now boasts an eco-friendly hybrid design.

“Eco-Cell is making a hybrid out of our drilling rig,” said Patterson-UTI CEO Andy Hendricks at the September 2019 Barclays CEO Energy-Power Conference. “It is a bank of lithium-ion batteries that can replace an entire generator system on the rig. It can store energy when we have extra. Granted, this is a lot of batteries, and it is a large structure at the well site. But we’ve been testing this for over a year now, and we’ve seen improvements in emissions and reduced fuel usage. It’s a way to run a drilling rig in a hybrid mode. We can run it off batteries when we need to, or we can power off diesel if we need to.” 

Drilling rigs have come a long way over the past decade. Manual tasks have been automated. Procedural tasks have been streamlined. Some rigs can walk, and more and more rigs now share components that talk to one another via high-speed data transfers. All of this is leading to a world where the average unconventional well will be drilled by a fully automated robotic drilling unit. While there are still giant hurdles to clear, both technological and cultural, a future featuring unmanned iron in the oil field could become as common as the smartphone.

Cantankerous casing connections no more
During low points in the oil field’s cyclical nature, talk between operators and service companies tends to shift more toward efficiencies—getting the most bang for fewer dollars—than searching for the next big technological breakthrough. It becomes more about getting the most out of what a company has versus plowing investment dollars into making dreams come true. While the softening of the onshore rig market in the U.S. is painful for some, for others it can prove to be a motivator behind the evolution of drilling equipment. Rigs have become bigger, faster, more powerful and smarter in recent years. With that, the push to become safer and more affordable advances.

Through its 2017 acquisition of Tesco, Nabors Industries has matured its tubular services offerings to include added functionality to existing equipment and a software suite allowing clients to manipulate that hardware like no other time in history. Using the rig as its canvas, Nabors is moving the needle on automation by introducing new ways to move manpower out of the equation and introduce a safer, streamlined operation. The focal point centers on the further integration of the Casing Drive System (CDS) into the driller’s fleet.

“We believe in the future we’re heading toward full automation,” said Brad Riley, CDS integration champion at Nabors. “Every major drilling contractor is looking at the same thing. We’re all looking at ways we can enhance our product line offering, offer more things to our customers, and doing so with automation to reduce the amount of manpower. To be quite honest, in the casing running portion of it, the more people we can get away from the rotary table, the better. A lot of the injuries that casing companies see across the Lower 48 come from running tongs. There are a lot of moving parts. A lot of pinch points. It is our vision to never have a set of tongs back on a Nabors rig, if possible. Fully integrated from surface to production strings, we’ve been highly successful getting some of that done thus far.”

The CDS is a hydraulically actuated tool. A valve bank is installed on the rig’s top drive that matches up with a block on the CDS. The rig’s hydraulics are plumbed directly into the tool giving the driller full control to make up casing connections. A new software system, developed by Nabors in concert with subsidiary Canrig, allows the driller to make up a connection by touching a single button. The button engages a cross-thread detection sequence for which parameters were predetermined and set in the software. If there is an issue, a signal is sent to stop the connection makeup, the pipe can be backed out and the thread can be checked. If no crossthread is detected, the makeup continues at a predetermined speed. When the required torque is achieved, the top drive knows to slow the connection. Another benefit of this automation is the integration of autofill, a service that
balances string weight on the fly. 

“Whenever companies are making up pipe, usually they have to stop maybe four to five different times, maybe more, in a production string and fill for 30 minutes to an hour to be able to get the added string weight,” Riley explained. “We can incorporate that into the one-button setting to where you can autofill your pipe on the fly. We pump at predetermined strokes into the casing itself. The pumps shut off as you are conveying pipe down to the rig floor. By the time you are releasing the tool and running back up for your next joint of pipe, there is little to no fluid coming out of the tool, so you’re not getting mud all over the rig floor or on anything else.”

To date, Nabors has released the new CDS system across the Lower 48 and has valve banks installed on 61 rigs. As of early September, the contractor was running integrated casing jobs on 23 rigs: 10 in the Permian Basin of West Texas, a couple in both South and East Texas, a few in North Dakota and one in Oklahoma. All of Nabors’ rigs in the continental U.S. can support the CDS modifications.

“We’ve identified the newer rigs as the best candidates because we would have to upgrade some of the software that is on the rigs,” Riley said. “The biggest thing that ends up happening is not a structural or mechanical issue. It is a software upgrade that the older rigs would need in order to run the system. We are very pleased with the success we’ve had on the X rigs, the B rigs and F rigs. We’ve been very pleased with what we’ve experienced so far on those.”

The system is allowing casing jobs that typically could call for six hands to be done with just three. The run times are matching those done with more people, while the autofill feature is saving more time, usually up to 2 to 3 hours. Rigup times are also quicker. 

“For the Nabors plan going forward, we’d love to have CDS operations on every Nabors rig in the Lower 48,” Riley said.

Pushing the bit? Get slick
A rig fleet’s higher end is making meaningful advancements toward things such as automation integration. Specialty service companies have been looking to push the envelope in other critical areas with tool and software advancements that bring in a well faster, safer and on budget while also offering the type of advanced construction and optimal landing efficiency that will pay dividends into its production phase of life. After all, a well that hits paydirt is great, but a well that offers a clear path to the heart of the formation is that much better. In 2016 Weatherford began looking at customer needs when it came to rotary steerable systems (RSS) to get a punch list of requirements that would end up
being the backbone of its Magnus system.

“Most of our engineering over the past three years—as we perpetually think we are coming out of this downturn—most of those efforts and R&D investment have gone into technology where we’ve spent a significant amount of time with our customers upfront to understand their drivers and core requirements,” said Etienne Roux, president of drilling and evaluation at Weatherford. “We’ve reduced the number of engineering projects being worked on significantly, took out all of the ‘nice to have, we’re going to reinvent the toaster’ type things and talked to our customers about what is actually needed and what their priorities are.”

When it came to RSS, three things that clients were looking for were the ability to transmit torque to the drillbit from these larger, more powerful rigs and new mud motor designs (for motorized RSS applications), ways to prevent stuck/lost tools downhole, and better efficiency and utilization. On paper, Weatherford started formulating a robust design that was both slick and modular. Up until that point, the contractor had never had its own push-the-bit system. The company invited customers in-house and within 11 months had an 8.5-in. prototype tool in the market. That first field test (i.e., drilling a real well) occurred in April 2017 at a test location in Oklahoma. The first commercial run with Magnus would happen a year later.

“We designed a tool that is very slick,” Roux said. “We have not lost a tool to date in hole. Not a single Magnus tool has been lost, and so with a large fleet of the 6.75-inch-sized tools deployed in the U.S. and globally, we feel like we’ve achieved that key requirement. To talk about what’s new and the technology, the control system resolves for the spatial orientation of the tool at a rate that is pretty much industry-leading and therefore drills a very smooth well and a wide variety of downhole conditions.

“We actually put our imaging tools behind these tools to show our customers with wire diagrams how the wells are being drilled. Why can I say ours is smoother? We’re the only company with the three pads of the rotary steerable tool completely independently actuated combined with the continuous rotation of the system. Any other push-the-bit system as it rotates and drills those pads are going to fire all the time. With ours, the way the mud is directed to the pad is what we call true independent control, and we designed it like that for three reasons—to be able to have the smoother wellbore, to be able to switch on or off the pads from surface during the drilling process (i.e., when drilling out the shoe) and also our tool is modular. If that tool comes out of the hole and one of those pads needed to be replaced, I don’t necessarily have to send it to a repair center. I can courier a control module to the well site, snap it back into the collar, function test it and be back drilling again. This is truly differentiating. It helps our turnaround speed. It helps with the way we plan and drill wells.”

Weatherford has embraced the fact that RSS has become commoditized. “There is no point in fighting it. The oil field is becoming commoditized. Customers look at their economics. They want to throw cash off. They need technology that is going to enable them to produce at the most efficient rate. They don’t want to pay $40,000 per day for a rotary steerable tool anymore, which in some cases on land is two-thirds of the day rate of the rig. It is just not going to happen,” Roux continued.

“Everybody is piling into the RSS tool supply market. The rig contractors, independent service contractors and private-equity back individuals all have an RSS tool now that they can rent out or bundle with say the rig contract or other discreet services (with varying degrees of success). I’m not even going to fight that. Weatherford will have fit-for-purpose technology whether you’re a rig contractor, an operator or an independent provider. You take the technology to your customer, which most of the time is our customer, and deliver the well. Magnus is out now with the 6.75-inch fleet that drills in 83⁄8-inch to 8¾-inch sections. We are commercially drilling with our 9.5-inch tool in the U.S., Mexico and Middle East (drilling 12.25-inch sections). We’ve just released our 11-inch tool that
drills all the way up to 17.5-inch and, ultimately, will be drilling hole sizes beyond 17.5 inches as well. The 4.75-inch version of Magnus [was scheduled to] hit the market toward the end of the fourth quarter [of 2019],” Roux said.

Since the launch of Magnus, the technology has been deployed in a wide range of land and offshore applications globally, including long 24,000-plus-ft laterals in the Permian Basin, various U.S. and Canadian land plays, Latin America, Europe and the Middle East.

Rise of the robot rigs
The future is always in motion, flush with both the best kinds of optimism and the worst kinds of uncertainty. When it comes to the land drilling fleet, one that is emerging quickly onto the scene is the integration and implementation of increasing automation. Tasks once performed by human hands are now being conducted by machines. This is happening for two main reasons: the technology to achieve successful automation is here and the drives toward increased safety and more predictable, lower cost wells. The assimilation of automation has been a deliberate and thoughtful task throughout the drilling industry. Companies have been taking measured, yet meaningful steps introducing different facets of automation on the journey toward the first fully robotic rig.

“I don’t think it is a binary thing where we can just jump to fully automated rigs,” said Shawn DeVerse, vice president of commercial strategy at H&P. “We have the technology today to automate a lot of actions and decisions being handled by humans. To leverage that at a greater scale, it requires a cultural shift in the industry. It requires people to change their art or their practice. It is more of a change management thing or a cultural thing versus executive commitment or money.”

Machine learning, the Internet of Things and all of these 21st-century buzzwords are contributing to the notion that one day in the not-too-distant future the industry will have the option to contract a fully automated drilling rig to work on its programs. Not unlike the changes going on inside the automotive business with the new intelligence packages (e.g., lane assist, adaptive cruise control, auto-braking, etc.), the drilling industry is approaching the equivalent of the driverless car. But when does what some consider a novelty become a fully realized tool of the trade?

“The time frame by which we measure success is a key aspect,” DeVerse said. “Some technology yields an immediate benefit you can see and measure instantly. That time of technology is quickly adopted because the value proposition is clearly demonstrated in the results. At the same time, those types of technologies are rarely game-changing and are usually incremental improvements to the process. When we talk about technologies that are disruptive or transformative, those are the ones that are often difficult to measure success. A lot of the benefits tend to be somewhat intangible because we don’t have data to measure those metrics, or sometimes there are many different variables involved making it hard to extract the one you are trying to evaluate and compare that to success. Other times, we don’t even know what the true value is going to be until actually adopting the technology. When we moved from flip phones to smartphones, we didn’t recognize or see that it would completely change the way people conduct their lives. You are just not aware of that benefit. It is hard to predict.”

DeVerse continued, “From an autonomous drilling standpoint, there are some very direct, measurable benefits such as lower costs with de-manning and performance efficiencies by having more consistencies with your slide execution or a lower tool failure rate. Again, those are the smaller benefits. To truly see the transformation, you have to be in it for the long term and really ride through this on a conceptual basis before really big impacts occur.

“The challenge right now is there is so much scrutiny on the oil and gas industry to prove immediate results and return on investments,” he said. “It is hard on the customers to invest in these things where the benefit isn’t clear or it is very long term. It creates this challenge—how do we, as a solutions company, invest and create these solutions that require real investment, real resource and real attention while at the same time demonstrate the value to our customers in a way that they can ride this journey with us and commit to the long term. That is a very difficult thing to achieve.”

Industry appetite is a major roadblock on the path to robotic rigs. Both contractors and clients must be committed to the changes ahead, which will likely come with a fair share of early struggles. Working through the maturation process will take time and money. Operators and service companies must work together and be interdependent on one another for progress to occur.

“If you look at where we’re going next, which is leading into our autonomous drilling platform, you start to take these automated components and integrate them in a way that they become synergistic,” DeVerse said. “Then you start to optimize the whole workflow. You start incorporating all of the different decision-making components—well planning on the fly, geosteering, drilling optimization—with all of these things together and you start to create a truly optimized state.”

The early evolution toward full automation focused on the hardware itself. Today, the industry is focused on the intelligence, the decision-making that drives the actual control of the drilling rig and trying to integrate that entire drilling workflow into one cohesive process. When you look at it in terms of steps, you have data input that comes from your well plan, and then you have real-time data telling information about wellbore geometry and rock characteristics. There are multiple sources of input. Historically, the decision-making process has been fragmented into numerous specialty disciplines (i.e., directional drillers, mud engineers, drilling engineers and company men) with everyone using different sets of data to drive the decision-making process.

“Whenever you try to optimize this in a linear fashion, you don’t always get the best outcome,” DeVerse said. “When you optimize one step in the process, it usually comes at the expense of another step down the line or something that’s happening in parallel. The way we’re approaching this problem is to take all of these sources of information and evaluate them holistically. Whenever we leverage computer intelligence, we can actually handle all of these different streams of information. The way we are tackling the decision-making process is we try to simulate what impact each decision point or action has on the economics of the wellbore.”

Higher predictability and efficiency will drive profit and return on investment for operators. This has been a key driver to the levels of automation achieved by the industry to date.

“When you start evaluating the drilling process, the rig starts to become a key that can unlock greater economic potential in the wellbore,” DeVerse said. “There are definitely some technologies we are working on that will take this to the next level [and] that will definitely be game-changing from our belief. Our anticipation is when we come out with those, it will drive adoption much faster than what we see today.”

Read E&P's other "Drilling Innovations" cover stories from the February issue:

Software Driving Hardware To New Levels Of Efficiency

Innovation grows exponentially for downhole drilling tools

Multilaterals provide an unconventional approach to shale reservoirs