With Automation in Hand Drillers Demand a Raise
Rigs drilling faster earn less money per foot because they are contracted by the day. But at least they are still working. Now service companies are developing new rigs with more automated functions, and want increased rates based on the productivity gains achieved.
Drilling automation advances now appearing on rigs would seem to offer a great opportunity for service companies to demand a raise. The likely answer from oil companies, though, remains no.
The argument that oil companies need to pay for much needed technology advances collides with a brutal North American onshore rig market where shrinking demand keeps a lid on fees, according to drilling and service company experts on a panel at the recent SPE Annual Technical Conference and Exhibition.
The cost-cutting pressure has been on since the oil price crash that started in 2014. In this survival-of-the-fittest market, high-efficiency, modern rigs have won out. While the number of rigs working in the Permian Basin is down 20%, the number of wells and feet drilled is little changed. As a result, the bottom line for drilling contractors has suffered because the survivors are reducing the number of days of pay per well.
Drilling rigs with digital control systems that can consistently drill a curve faster, and smoother than a directional driller can, are an example of digitally controlled systems appearing on rigs. New contract terms rewarding service companies for delivering those efficiency gains are not part of that advance.
“There is so much focus on supply chain savings,” said Duane Cuku, vice president of sales for Precision Drilling. As a result, “The operator is really accustomed to flying first class on a coach ticket.”
Drillers would like to break this downward spiral by negotiating better terms for the next leap in drilling technology—programmable digital control systems capable of consistently executing complex programs to efficiently increase the penetration rate, change the well path, or run casing.
Rather than a hardware advance, like the top drive, the combination of digital controls and data analysis provides flexible, programmable tools that allow improving performance over time. Making the most of these tools requires cooperative efforts by operators, drillers, and service companies.
“Digital technologies are progressing and we are at the cusp of a tipping point. Automation and digitization will allow the future of well construction,” said Kevin Neveu, president and chief executive officer for Precision Drilling.
Digital tools tested onshore will eventually migrate offshore. Matt Isbell, drilling optimization advisor for Hess, said the company expects to use what it is learning about drilling better holes onshore to help it improve its performance when drilling with the more complex well designs used offshore.
Measures of Success
The panelists said that increasing automation is becoming the norm on rigs, but the conversation kept coming back to being paid for new technology.
“I am here to talk about money, not technology,” said Lars Olesen, vice president for product management at Pason Systems. The company made a name for itself selling data storage, but now customers in this competitive sector expect them to “do more with my data.”
Drillers saw their pay per well decrease as they drilled faster, and payoff for automation that reduces headcounts appears limited. Reducing costs has some value. Olesen estimated that if a digital innovation takes one person off the job site that “gets 1/10th of the value of a saving.”
Far more valuable are more productive wells due to better hole quality. Engineers talk about the cost of badly drilled wells, but Olesen said persuading an oil company to pay for a wellbore that was well done “is an enormous effort and you have to do it every well and it becomes impossible thing to do.”
Offshore, Maersk Drilling used high volume downhole data in the North Sea to improve the stability of the holes drilled, cuttings clearing, and fluid losses. Other benefits included greater drilling and completion efficiency plus better wellbore placement, said Morten Norderud-Poulsen, senior director of technical organization at Maersk Drilling.
What is lacking is a way to measure the value of those gains. “Paying for performance requires measuring key performance indicators (KPI) agreed to by all parties, and it is not clear how to calculate KPIs,” he said.
Among the barriers are the short-term contracts that make it difficult to tap into the value of software that allows incremental improvements over time based on the experience gained from drilling many wells. Safety can also be a benefit, but how do you measure it? “It is hard to put a value on the mistake that does not happen because there are procedural limits in place,” Cuku said.
An example of a working automation-technology partnership has been Hess’ multiyear relationship with Nabors, which has included customer support for Nabors automation development program.
While the speakers at the panel sessions talked about new contract models that share risks and rewards among operators, drillers, and service companies, Isbell said the company’s deal with Nabors is pretty basic.
“What is in our contract would not be surprising to anyone,” Isbell said. It does include rewards for top-quartile performance, which is common in its service contracts.
The partnership is part of a drilling improvement program that has integrated Nabors rig leaders into the process. “We have made some investments, (and) we have some skin in the game on key metrics going forward,” Isbell said.
While service companies want to be paid for improved performance, some of the ideas offered for doing so are unpalatable.
One is the fixed-priced turnkey deal. That approach rewards a service provider willing to take the considerable risk of cost overruns if they are confident they can do the job cheaper.
Schlumberger has invested heavily in automation and discovered ways to improve performance. Based on its experience, Schlumberger engineers have some different ideas about what drilling parameters to use.
“If we are using a performance model, let’s have a conversation on (drilling) limits,” said Rodrigo Gallo, drilling automation champion at Schlumberger. The problem was, when Schlumberger said it needed to set the drilling parameters, the operator responded, “No, no, no, that is my well,” he said.
A long-term deal that locks in a rate formula based on the current low day rates is also a problem. “Given the low rates now it is a weird time to lock in rates,” Cuku said.
Despite the low pay, Olesen said: “Automation technology will continue moving forward no matter what.”