The biggest meeting of the year dedicated solely to the topic of drilling automation revealed that the ultimate barrier facing this emerging development is not the technology. It’s how the business of drilling is done.
This is according to many of the technical professionals that participated in a recent symposium held jointly by SPE’s Drilling Systems Automation Technical Section (DSATS) and the IADC’s Advanced Rig Technology Committee.
The annual event held in conjunction with the IADC/SPE International Drilling Conference and Exhibition departed from its usual format of speakers issuing well-rehearsed presentations.
Instead, it took on the form of a multipronged focus group that saw dozens of participants hailing from operators, drilling contractors, and service companies who huddled into the four corners of a conference ballroom in Galveston, Texas. Their chief objective was to help update the DSATS’s “roadmap” that identifies which technological breakthroughs are needed to bring about a true step change in drilling automation by 2025.
But as that year draws near, the odds of reaching most of the key milestones are dimming, and so, the symposium leaders decided to instead look toward what should be achieved by 2030.
What DSATS wants to see become possible in the coming years is a rig in which “well plans are uploaded into an interoperable drilling system that automatically delivers a quality wellbore into the best geological location.”
Though we have seen pieces of drilling automation come together in recent years—among others, this includes automated rig floors and automated rotary steerable systems (RSS)—we have not seen a truly automated rig as outlined above.
And few of those attending the meeting expressed optimism that such a development is within reach.
“We are not trending toward hitting this vision in 2025,” said Esben Thorup, who was speaking from the perspective of an offshore drilling contractor. “We see pilot projects heading in the right direction, but wide adoption of automation is not happening.”
Thorup is the head of digital innovation with Maersk Drilling (and soon to be Noble Corp. upon the impending finalization of a $3.4 billion merger announced in November 2021). He was one of several panelists tapped to lead the four focus groups and offer back to the entire gathering some key points raised during those discussions.
For Thorup, the biggest thorn in the side of drilling automation is the business case, or lack thereof.
“We would absolutely love to put automation systems on all of our rigs,” he said while noting that some automated components have been deployed on Maersk’s rigs. “But we are not necessarily being rewarded often.”
Dan Hoffarth, CEO of onshore contractor Citadel Drilling, led another group and seemed to echo his offshore counterpart in asking the big question of the day: “Does our business model work as individual companies?”
Hoffarth said his group discussion centered on a “lack of incentive to innovate.” Where there is an incentive, he said it’s usually a carrot-and-stick proposition that “creates a lack of balance” for service providers, especially when performance metrics are not well defined.
This imbalance poses a significant risk for first movers and is one that investors may not be too keen on either. Hoffarth noted that the firms which must shoulder the costs of automation development are almost all publicly traded.
“And in many cases, we share the same shareholders,” he said, adding, “If my shareholder doesn’t get a return that they expect is equal to the return they can get by investing in one of the other companies that are represented on the site, I can’t have a business case.”
New Models Need Buy-In
Ideas on how to create a solid business driver for increased automation include adopting blockchain-enabled “smart” contracts that build trust in how key performance indicators are tracked, bounties for those who deliver technology breakthroughs, and bonus pools that are shared among the companies responsible for delivering a more productive or lower-cost well.
Mark Anderson, vice president of drilling contractor Ensign Energy Services, suggested that such schemes may be what it takes to get multiple companies to align their interests; however, “those are not well developed [models] right now in our industry.”
Embracing these ideas is considered to be critical by many experts because no one company holds all the cards when it comes to rig automation—though it has been attempted.
About 6 years ago, Schlumberger envisioned itself becoming a one-stop shop for drilling automation with its highly touted “rig of the future.” In an ideal world, the service company would have provided operators with an automated rig and all the ancillary services to go along with it—in essence, making contracting and risk-taking a simpler proposition.
“Well, that has failed,” said Anderson, referencing the fact that the “rig of the future” is now a thing of the past after being mothballed by the service giant a few years after its proposal. “So, we’re going to be in this multiparty system for a while,” he concluded.
Among the issues with half a dozen or more companies working in tandem to drill each new well is that it becomes difficult to properly assign credit for a job well done. The same is true for assigning blame when things break down.
Anderson spoke to this while using RSS as a prime example. In the US onshore sector, RSS providers have in the past decade seen their market share rise from next to nothing to about half of every foot that is drilled today.
That’s remarkable uptake, but the downside Anderson highlighted is that RSS providers depend on mud-pumping companies as well as the drilling contractors to do their job right so the RSS technology will hold up. As he pointed out, if the RSS tool fails downhole, then the liability is not shared by those other service providers.
“It’s up to the tool company and the operator to sort that out while the drilling contractor still gets paid,” he said.
Such interdependencies will be even more pronounced with a fully automated rig that requires accurate data gathering and reliable equipment operation. That means the industry first needs to establish an equitable way to share liability amongst the various players involved in each project.
This is also a problem for when things go as planned or better than expected.
In the case of a “record-setting” well—be it defined by drilling speed or lateral distance—there is such a thing as “success stealing.”
The drill-bit maker might claim it was their product that led to a new bar being set. Or it might be the mud company that claims credit, or the directional driller, or the drilling contractor.
Or, as Anderson put it, “The operator says, ‘Well, we planned the whole thing.’ And so, is it really possible to identify what led to success?”
Right now, the answer is in the eye of the beholder. But for companies to invest more and take bigger risks on rig automation, who to reward and by how much is a major issue that will have to be ironed out.
Onshore vs. Offshore
One of the groups also dug into the differences involved with trying to automate an onshore rig and an offshore rig. The technology capability requirements are roughly equal, but onshore and offshore drilling have different economic demands.
Pål Skogerbø, the chief technology officer with drilling systems developer MHWirth, said his group discussion highlighted that “the ability to pay [for automation] is much less on an onshore rig,” he said, adding that operational priorities are also contrasting. “We concluded that onshore is more about consistency and speed, while offshore is much more about reducing risk and avoiding mistakes.”
What this boils down to is that the type of automation technologies that are tested and ultimately proven out will vary depending on if the rig stands on land or above thousands of feet of water. For the former, it might be a software that helps send a bit back to bottom as fast as possible while for the latter it might be a system that removes personnel from a rig’s most dangerous “red zones.”
In terms of what the onshore and offshore arenas are likely to place an equal weight on, Skogerbø said participants agreed that it is on the ability of automated systems to perform “consistent operations.” This, he said, would “make a lot of sense” for both sectors to prioritize as a chief deliverable from the technology.
Consistency might refer to the quality of the wellbore. In which case, the next problem becomes how to quantify it.
The symposium participants did not draw consensus on exactly how to do that, but Skogerbø said, “We sort of agreed that without a number there, it’s hard to say what there is really to gain.” He then suggested that a 30% improvement in overall rig efficiency might be an enticing figure for operators.
That might be just the ticket for the offshore sector, but it was later pointed out by Anderson that when it comes to the US onshore sector “where you’re drilling a mile a day, what could be the upside to join automation?”
“I don’t think it’s going to be 30% faster,” he said. Then speaking to “task saturation” he added, “When you’re drilling a mile a day, your driller is a busy person and you’re going to ask him to also operate a system from a third party that he might not be really familiar with?”
Changing From Within
Concerns were also raised about the internal structure and culture of companies that are ambitioning toward automation. One participant spoke about the inherent resistance to change that exists within most companies and how some people feel threatened by automation. These sentiments can be heightened when affected personnel are not involved in the technology development process.
Moray Laing, a strategic business director at Halliburton, added another wrinkle to this discussion by relating how technical teams might make what they view as the best technology choice and “then we get to procurement, and they say, ‘the cheapest bid wins.’ So, procurement has to be a part of this process.”
In addition to enhancing inclusivity, Laing said other changes need to be made in order to allow for greater experimentation and adoption of emerging technologies. “That’s missing from most of our contracts—our contracts are all about finite goals and outcomes, which is why you end up with very fine KPIs,” he said.
His suggestion is that DSATS attempt to take a more active role in helping to show the industry what a better contract, one that encourages automation development, looks like.
Later at the drilling conference, a paper was presented that tries to do that. IADC/SPE 208776 was coauthored by Laing and several other members of DSATS who outline examples of contracting models that could be compatible with automation adoption.
Representing the offshore side of the business, they cite two projects that used a gainsharing model. In both examples, an “alliance board” made of key representatives of all the companies involved were used to enhance communication, operational and cost oversight, and guide the projects toward the best economic outcomes.
Importantly, the gainsharing approach can also be used to establish what “bonuses and losses are shared between the alliance partners based upon a ‘most likely cost’ for drilling and completing the well.”
In this model, the best-case and worst-case outcomes for all parties are capped at the onset. The alliance model is also considered to encourage “lean practices and digitalization to reduce process waste, improve workflow, drive quality, and innovation with greater flexibility.”
The paper’s onshore example comes from the US unconventional sector and involved an “outcome-based” model which led to the drilling contractor and operator working closely together for the past several years to develop technology that would achieve the sought-after improvements.
One of the first objectives tackled together in 2017 was the use of software that allowed the operator’s real-time operations center to geo-steer up to six rigs per directional driller. To further improve on this model, the two companies’ supply chain groups later adopted a vested contract.
“The goal was to better frame and standardize the things that neither stakeholder wanted to change to allow better focus and exchange value on improvement opportunities,” the paper reads. “This approach set up a win/win situation” in which the high value placed by the operator on safety, quality, delivery, and cost was just as valuable to the drilling contractor.
Oil Prices Working Against Automation
At multiple points during the symposium, it was said that to make the investment in automation worthwhile for drilling contractors also requires longer-term contracts.
However, locking into contracts that extend beyond the typical 3- or 6-month spans is all too easily undermined by low oil prices—something participants were reminded happened just 2 short years ago during the onset of the COVID-19 pandemic.
This is a blade that cuts both ways, though, as high oil prices also challenge the industry’s discipline to stay on course.
“At $40/bbl nobody is developing anything—there’s just no money in the R&D budgets,” argued Hoffarth from Citadel. “And anything over $90/bbl, we’re just putting pipe in the ground and pumping as fast we can. So, we depend on a sweet spot in the commodity price in order to advance automation.”
It was also highlighted that between the US and Canadian onshore sectors, there are about 800 active rigs (as of early April) while more than 1,000 are believed to be sitting on the sidelines in equipment yards as a result of two oil-price crashes separated by only about 5 years.
This represents a major barrier for onshore automation in particular since the first priority for most drilling contractors is to bring those stacked rigs back into service before making a major investment in new technology.
One participant stressed that is also the reason why retrofitting rigs with automated components, i.e., a piecemeal approach, is simply more realistic in the foreseeable future than is a fleet of fully automated rigs that are built from the ground up.
Dimitrios Pirovolou, an engineering manager of managed pressure drilling at Weatherford and chairman of DSATS, told the participants that none of the issues raised were a big surprise to him.
However, he did say that DSATS is a technical body. And as such, the all-volunteer group will need to “walk a very fine line” in how it plans to help the industry overcome the business hurdles it faces.
That said, the fact that the impassioned conversation focused so heavily on the business problems—as opposed to the technology problems, of which there remain plenty—was for Pirovolou in itself a sign of how mature the rig automation space has become.
“I think that there is progress here,” he said, “because at least now we all realize that there is a technical side and a business side and that we need to work to reconcile the two—that was not the point 15 years ago.”
For Further Reading
IADC/SPE 208776 History, Disruptors and Future of Changing Well Construction Business Models by John de Wardt, De Wardt and Company; Robert Wylie, xnDrilling; Moray Laing, Halliburton; Matt Isbell, Hess Corporation; Karma Slusarchuk, Parker Wellbore; Arnfinn Groette, Aker BP; and Scott Boone, Nabors Drilling.