Spending on rig maintenance still seen as critical, but investments in automation, directional drilling are also being prioritized to deliver faster, more consistent wells
By Linda Hsieh, Managing Editor
Kevin Neveu is President and CEO of Precision Drilling.
North American onshore drillers have already made such significant advances in performance over the past decade that it seems like remaining improvements can only be incremental, sometimes measured in hours or even minutes. Where are drilling contractors like Precision looking to for the next step-change?
I would say there are two main things that are on my mind, and the first is wide-scale adoption of industrialized principles. When there’s industrialization, like the kind we see in the unconventionals where we’re mass-producing a large number of identical wells, it really allows you to optimize each step of the process and make significant improvements in efficiency.
Probably between a quarter to a third of our customers have already adopted discrete process management systems. I think we’ll see more of them move toward better industrialized processes, which will produce further efficiency gains across the industry.
The second thing that comes to mind is automation of the drilling process. I don’t mean automation of pipe handling but automating what the driller does with the control system and eliminating elements of human variance. This involves using software to capture the best practices of the best driller and repeating that well after well.
At Precision, we’re already using process automation on 20 of our rigs. We’re able to automate multiple repetitive processes performed by the driller. We can include two to three, or even 20 to 30, repeatable sequences into one algorithm, allowing the software to run the controls in the most optimized way possible, ensuring the shortest and most consistent cycle times. This process change leads to increased predictive capability and efficiency. We’re already demonstrating better cycle times, which we foresee translating into 5% to 8% faster wells.
Do you have plans to roll out this type of automation to additional rigs in Precision’s fleet?
We do, but first we’re looking to achieve 100% uptime in the software. We want to make sure it is fully field hardened, which means it won’t react unpredictably to all the variables that can occur in the field, whether it’s a lightning strike or a vibration sensor failing on a rig. We’ve been going through a 14-month field-hardening process, and we’re getting down to the last straws. We expect to have the software fully hardened by early 2018, and then we will roll it out across our entire AC fleet of about 106 rigs, which we expect to take two to three years, depending on customer demand.
How is the driller impacted from having this type of automation on the rig?
We find that the driller doesn’t have to focus so much on making sure he times a 14-step process perfectly. He can more closely monitor the operation of the equipment, watch his crew more closely and better observe the overall drilling cycle. He’s freed up to operate in a more intelligent supervisory role, by eliminating the hours spent mechanistically timing the pressing of different buttons.
My analogy would be parallel parking a car. If you have to parallel park your car 300 times a day, you would get very good at it, but there would likely be better uses of your time. As the driver, you would sit back, watch the surroundings and make sure the system is doing a good job. Many things the driller does during normal drilling operations, whether it’s making connections or tripping out, tend to be quite mechanistic and repetitive.
Also, I think this type of automation provides a good opportunity for drillers to put more attention to crew training and development. I’d like to see them spend more time managing and training the crew on the rig, and monitoring safety and functional performance on the rig floor.
How does this change the way you approach training for the driller?
Clearly this technology change is challenging us to evolve how we approach driller training. Our drillers are already highly skilled with our Amphion control systems on our AC rigs. They are familiar with touchscreens and computer displays and how these applications control the critical components on the rig. The process automation control technology does not eliminate the need for them to be competent drillers; that is a given. The increased competency requirement will relate to increased process automation control software, analysis and process management skills. It definitely increases the skill level required for the driller, not decreases it. We have in-house training programs already developed with classes ongoing, and we believe we can train existing Precision drillers to operate the software.
There seems to be growing belief that changes to the traditional dayrate model are needed so that rewards are more strongly linked to performance. What are your thoughts on how drilling contractors’ business model might or should evolve in the coming years?
The market has been linked to performance for quite a while and certainly during this downturn. If you look at the drop in activity going back to late 2014 and through 2016, as well as the rebound in late 2016 and 2017, the market has tightened up, and the supply and pricing for Tier 1 high-performance rigs is higher than the average rig. In fact, dayrates for the better-quality rigs and better-quality drilling contractors are higher than dayrates for lower-quality drilling contractors and lower-quality rigs, which is a trend we expect to continue as the market strengthens.
When you start to talk about very specific performance or incentive bonuses, I’m more skeptical. It seems that once we buy into any kind of performance incentive and we work toward a new, higher level of performance, the incentive is removed once that new, higher level of performance becomes sustainable. I would rather compete on the merits of the rig as a whole, rather than set benchmarks where incentives will be removed once they’re achieved.
Having said that, it’s fair to say that Precision has been involved with several different business models – performance contracts, turnkey contracts, footage contracts. I just think the dayrate model allows the better-performing rigs to earn better returns.
We’re also seeing more onshore drilling contractors acquiring directional drilling capabilities. What’s driving this trend?
Our drillers have been drilling these horizontal wells for going on a decade. In many cases, they can handle the directional job without a lot of support from a directional driller, and many contractors have recognized that. Precision actually invested in our first directional drilling kits and companies back in 2011, so we’ve been doing this for quite a while. The downturn created challenges around pricing for the service, but in the long term I think drillers can manage directional drilling as well or even better than independent directional service providers. That’s driving a lot of the action around integration of directional drilling with the rig. Going forward, I think the trend will continue.
What kind of response are you seeing from operators? Do they think it’s more logical for the drilling contractors to take on this piece rather than hire a third party?
There’s a mixed view. Operators have managed a highly fractured supply network of oil services for a long time, and many operators view themselves as excellent drilling project managers. They like the option of choosing the rig, the directional service, the mud company, the bit company, the logging company, etc. They like being able to mix and match their services as they see fit. Then there are other companies who are measuring performance very carefully, and they see the benefit of integrated directional services through the cost savings and efficiencies gained.
I believe that the more sophisticated customers, who measure more aspects of the drilling program, are further down that industrialized process, and they are inclined to let the driller do the directional drilling. It’s really an efficiency game more than a price game.
What have been some key learnings from Precision’s alliance with Schlumberger on directional drilling equipment and software?
We have seen very good success running directional drilling advisory software in partnership with Schlumberger and Pason. It’s being used both as quality control check on directional drilling and as a full directional drilling advisory software package. Late in 2018, we’ll be looking to integrate that software with our automation platform so we can move toward true automated drilling. We could be beta-testing that by late 2018 or early 2019.
Looking farther down the road beyond the immediate two to three years, what additional services at the well site do you envision drilling contractors possibly taking on?
There’s a range of things we could take on, such as drill bits or drilling mud. I don’t think our customers are anxious to see that happen today, but it’s possible if drillers can show efficiency gains. If the driller can prove that we can drill the wells faster, more consistently, more predictably and in a more repeatable fashion by integrating additional services, our customers will be receptive.
Do you see a move by operators to ask their contractors to take on more responsibilities on the rig?
Nothing widespread. There are some cases where operators want drilling contractors to bundle services – but those are largely aimed at cutting prices, not improving efficiency. The focus on price has been so intense in the last couple of years that sometimes the focus on efficiency is lost, and that’s not a good thing.
Have you seen that changing since the activity upturn in 2017?
It depends a lot on sentiment and mood. If the sentiment and mood is negative and there’s a lot of uncertainty, then our customers tend to focus on price and cost cutting. If our customers are moving back into growth mode, growing in a disciplined and efficient manner becomes very important, and efficiency and performance tend to matter more.
In the current low-price environment, what types of capital expenditures do you consider to add the most value for drilling contractors?
Above all, keeping our operating rigs fully functional is the most important. We never want to starve our operating rigs; we want to keep all of our rigs running at peak performance levels, so spending on maintenance throughout the cycle is critically important.
Beyond that, we can look at additional investments. When we began to build our fleet of Super Triple rigs in 2010, we expected well pads to get larger and wells to get longer, so we built our rigs with those considerations in mind. The rigs were all constructed to be easily convertible to pad walking, to long-reach horizontal wells and to automation. Because of that, our upgrades have been relatively inexpensive. For 2018, we’ve budgeted between 10 to 20 upgrades for around C$30 million.
So no plans for additional newbuilds at all?
Nothing in our current visibility. Dayrates haven’t gotten high enough yet, and neither has contract duration. But if WTI moves into the low- to mid-$60s, we could see a market later in 2018 that might support newbuilds.
What other investments do you think drilling contractors will have to make in the coming years to stay competitive?
There are certain benefits to having a rig fleet that is one spec, or one design across the fleet. If you have a fleet of rigs that are dissimilar in nature, it is difficult to offer a standard automation package. Going forward, I think you’ll see a continued move by most to standardize their rigs – the hardware, as well as the software – so that automation becomes a standard bolt-on rather than a custom-fit for every rig.
If you think about drilling the same wells over and over and rigs on multiple well pads, the concept of industrializing the process really leads you toward standardized drilling, equipment and software.
Are drilling contractors considering interoperability as they look at automation platforms for their rigs?
That’s definitely a concern. Precision is actually not coding its own software. We’re working with National Oilwell Varco and using an open platform they developed whereby operators can load their own apps onto that platform. It’s designed to be open and to encourage other service companies or E&P companies to connect with their own apps. This will easily facilitate interoperability.
Rapid increases in rig count, like we saw in the earlier part of 2017, can really put an industry’s safety culture to the test. How do you think the North American onshore industry did in terms of safety during that activity ramp-up? Any lessons learned that could be applied for the next upturn?
It was a challenge across the industry to sustain the excellent performance the industry achieved by the end of 2016. In the US, the industry got down to about 400 rigs, then more than doubled in size to 930 rigs. We brought back a lot of experienced people, but we also recruited a lot of new people to the rigs. I think we all learned about the importance of orientation and mentorship for new employees and managing that inflow of people back into the industry.
We also do an exhaustive investigation for every single safety incident should one occur, and we learn from each incident. Until we’re running every rig injury free, we’re going to be in a high learning mode. DC