How Low Can Producers Go in a Race to Drive Down Costs? – Mark Hislop

 

 

 

North American energy producers are in a technology race against falling prices

BY MARK HISLOP

Up and down the Interstate 20 highway outside of Midland, Texas, the yards of oilfield service companies are full of idle equipment. The same is true in every North American oil town: Red Deer, Alberta; Estevan, Saskatchewan; Williston, North Dakota; Bakersfield, California. To some, the quiet that hangs like a shroud over these formerly bustling communities signals the beginning of the end for fossil fuels. But what the critics forget, or simply don’t understand, is that the energy industry has been tested by the vagaries of the market before. And this time, as every time, the industry is responding by driving down costs and becoming more competitive.

Up and down the Interstate 20 highway outside of Midland, Texas, the yards of oilfield service companies are full of idle equipment. The same is true in every North American oil town: Red Deer, Alberta; Estevan, Saskatchewan; Williston, North Dakota; Bakersfield, California. To some, the quiet that hangs like a shroud over these formerly bustling communities signals the beginning of the end for fossil fuels. But what the critics forget, or simply don’t understand, is that the energy industry has been tested by the vagaries of the market before. And this time, as every time, the industry is responding by driving down costs and becoming more competitive.

Ed Hirs is an energy economist with the University of Houston and, as the managing director of Hillhouse Resources in the Niobrara play, he’s also an oil man. With more than 30 years in the oil patch, Hirs has seen his share of booms and busts. He says that companies with experienced management teams that manage capital prudently and do well with upfront geology and engineering work will exit this downturn in good shape for the next boom.

“What’s going to happen in this bust is what always happens,” he says. “The really well-managed and efficient producers are going to get better and bigger, and the inefficient ones are going to fall by the wayside.”

Part of managing in a downturn means squeezing suppliers for every nickel possible. Art Berman, a Houston petroleum geologist and consultant, agrees that most of the decline in North American production costs is due to service companies lowering their prices. “Service costs have come down hugely,” he says. Berman points to savings of 40 percent or more on recent projects for his U.S. clients.

The same applies in the Alberta oil sands, according to Kevin Birn, director for IHS Energy, who last year wrote a significant study on the competitive structure of the oil sands industry. “The reservoirs are always king when it comes to oil,” Birn says. “If you have the best land, the best deposits, you’ll probably have one of the more efficient facilities.” The rapid buildout of the oil sands since 2000 almost quadrupled production, leading to skyrocketing prices for labor, materials, and services. But all those roads, powerlines, and work camps are now bought and paid for, so much of the infrastructure to produce the oil sands is already in place. “In the oil business, once you get over the hurdle of building a facility, you can generally enjoy good times, even when prices are low. In our study, some of the oil sands operations break even below $20 WTI, on a cash cost basis,” he says. “That’s a much lower threshold than what a lot of people think about when they look at the oil sands.”

What about the impact of new technology? Birn says the oil sands has always been a technology play. “It’s not easy oil because you had the challenge of separating the oil from sand and clay. On the SAGD side, operating costs were fairly constant because they adopted new technologies—wedge wells, better downhole monitoring of steam chambers, lots of incremental improvements.” Now that so many of the facilities have been constructed, Birn says the challenge going forward will be to make those huge capital investments pay for themselves. “One technology isn’t going to work for everybody. That reservoir will be a bit different for each company.”

While Hirs, Berman and Birn all acknowledge that technology is a key part of the oil and gas landscape, Mark Mills of the Manhattan Institute and petroleum engineer Charlotte Batstone say the industry is ripe for another technological revolution. At the center of that revolution is Big Data and analytics.

The extraction industry is inherently conservative and risk-averse, according to Mills. When oil is at $100 per barrel, no one wants to “mess with the golden goose” by taking risks with a new technology that might backfire and cost millions. “When the money goes away and you’re done firing people, that’s when it’s easier to get someone’s attention for a new technology,” Mills says. Shale 2.0, as Mills called it in a 2015 study for the Center for Energy Policy and the Environment, will be data-driven, its growth trajectory will look more like a Silicon Valley company, and its facilities will look more like factories than traditional extraction sites. Mills says that shale production today has generated “hundreds of petabytes” of data—the equivalent of the entire global digital healthcare domain—that will be mined for insights into how to improve shale production processes.

Batstone likes the Shale 2.0 model, but says Mills doesn’t go far enough with it, and focuses too narrowly on data and analytics. She recalls her years at Georgia Tech studying the principles of continuous improvement with a professor who helped turn Toyota into a world-class manufacturer after the Second World War. Batstone argues that the manufacturing analogy absolutely works for horizontal wells and hydraulic fracturing, and notes that process improvement ideas like Six Sigma are finding their way into the oil and gas industry. “Even in the last four or five years we’ve seen a whole new world of ideas and new technologies to make things more efficient—a smaller footprint, faster, cheaper, better in every way.” Batstone’s argument is supported by a March study from the U.S. Energy Information Administration that shows upstream production costs actually peaked in 2012, and were dropping even before oil prices plunged. Those costs have come down by 25 to 30 percent due to changes in technology that have “affected drilling efficiency and completion, supporting higher productivity per well and lowering costs,” according to the report.

Atanu Basu is at the forefront of the shale data revolution as the CEO of Austin, Texas-based Ayata Prescriptive Analytics. “What is happening in oil and gas is happening in few other industries,” he says. “Sensors are recording and reporting everything, everywhere, as often as you want it. You get the data, the numbers—video and images are becoming invaluable. Things are proliferating at a much faster pace than we anticipated.”

Basu points to fracking as an example of the work his company has done for American shale producers over the last two years. “We prescribe a custom recipe to get the most out of a well. There are hundreds of variables—sand volume, water pressure, and so on. And we prescribe settings for those hundreds of variables. We get on average a 13 percent improvement over the first 12 months of production.”

A 2014 Nexen fracking project near Horn River, B.C., illustrates Batstone’s point. The Calgary-based energy company saved tens of millions of dollars by working closely with Trican Well Services to improve mundane things like site layout, water sourcing and pump repair. Specialized software was used to design a practical lease layout. Using high-hydrogen sulfide-produced water for eight percent of the project’s needs—Trican thinks 50 percent might be the practical future limit—required special pump metallurgy. Extra pumps were kept on location, with a few rigged in and ready to go when a working pump failed. Trican even kept a mechanic on site working in a designated maintenance area to keep everything functioning smoothly. In the end, the job achieved 91 percent pumping efficiency, a record in the region. More innovations, like extending the bi-fuel pilot which saw the project’s pumps run on a combination of diesel and natural gas, are planned for the next Nexen Horn River fracking operation. “There’s a huge push to reduce spending,” says Nexen engineer Lyndsey Thomas. “We’re in a low-price environment, which requires fostering new ideas, new technology.” Dave Browne, Trican’s vice-president of communications says the company pores over the data generated from its fracking jobs, looking for trends that will help the next project. Trican analysts may not

use an analytics software as sophisticated as Ayata, but the principle is the same: Gain insights that will improve efficiency next time.

Technology and innovation have always been a big part of the oil patch. But the pace and intensity of those innovations seem to be accelerating. And if Mills, Batstone and Basu have called it correctly, North American oil and gas producers could be on the cusp of a new age of lower costs and higher productivity.

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