Cover Story:
Hydraulic Fracturing Trends
Title of article
Frac innovations accelerate financial and environmental sustainability efforts.
Brian Walzel, Senior Editor
A

s the saying goes, hindsight is 20/20. But as the industry looks back on the past year, it might be hard-pressed to come away with a clear vision of 2020. The oilfield services (OFS) sector, and in particular the hydraulic fracturing market, took the brunt of the blow, with many pressure pumpers seeing almost no work by late spring and early summer.

According to Westwood Energent, the number of frac crews operating in the Permian numbered 18 to 20. Even as pandemic restrictions began being lifted, and demand for oil started to marginally improve by the early fall, the OFS sector remained mostly stagnant as operators worked through their inventory of DUCs.

But as the calendar has flipped to a new year, the fracking industry is both taking stock of lessons learned from 2020 and pushing forward with innovations and technologies designed to optimize efficiencies for both operators and service providers. Meanwhile, as shale producers increasingly put more effort on achieving ESG goals, service providers are bringing to market systems and tools that cut down on emissions and generally reduce the carbon footprint of fracturing operations.

As the North American shale industry slowly recovers from the devastation of 2020, new technologies and frac designs are helping companies achieve greater operational and financial efficiencies. (Source: Universal Pressure Pumping)
As the North American shale industry slowly recovers from the devastation of 2020, new technologies and frac designs are helping companies achieve greater operational and financial efficiencies. (Source: Universal Pressure Pumping)
Cover Story:
Hydraulic Fracturing Trends
Title of article
Frac innovations accelerate financial and environmental sustainability efforts.
Brian Walzel, Senior Editor
A

s the saying goes, hindsight is 20/20. But as the industry looks back on the past year, it might be hard-pressed to come away with a clear vision of 2020. The oilfield services (OFS) sector, and in particular the hydraulic fracturing market, took the brunt of the blow, with many pressure pumpers seeing almost no work by late spring and early summer.

According to Westwood Energent, the number of frac crews operating in the Permian numbered 18 to 20. Even as pandemic restrictions began being lifted, and demand for oil started to marginally improve by the early fall, the OFS sector remained mostly stagnant as operators worked through their inventory of DUCs.

But as the calendar has flipped to a new year, the fracking industry is both taking stock of lessons learned from 2020 and pushing forward with innovations and technologies designed to optimize efficiencies for both operators and service providers. Meanwhile, as shale producers increasingly put more effort on achieving ESG goals, service providers are bringing to market systems and tools that cut down on emissions and generally reduce the carbon footprint of fracturing operations.

As the North American shale industry slowly recovers from the devastation of 2020, new technologies and frac designs are helping companies achieve greater operational and financial efficiencies. (Source: Universal Pressure Pumping)
Although many industry insiders believe the shale industry will likely never again achieve its previous highs in drilling and completions activity, the heartbeat of the fracking industry gained strength toward year-end 2020, and while it might not be at full strength this year, it will continue to pump the lifeblood of the U.S. energy industry.
2021 trends
By most accounts, the fracturing market hit its floor mid-2020. By late fall and winter, operators began to initiate some activity while still maintaining low capex. Stabilized prices for oil and gas have allowed operators to set out their 2021 plans with some amount of certainty.

“It feels like we’re seeing the new normal,” said Michael Segura, vice president of the production enhancement business line with Halliburton. “There’s some stabilization, [and] operators are able to make their forward year plans, so it feels cautiously stable at the moment. Obviously, [the market] will only be a portion of the size it was previously. It’s still generally oversupplied and cost-challenged, and capital discipline is still very strong in operators’ minds.”

The general sentiment, if not formally announced in investor calls, is that producers in 2021 will be focusing on maintaining capital discipline rather than production growth. Even new activity is likely to look much different than it has in the past.

As Akshay Sagar, president of Universal Pressure Pumping explained, producers are looking to avoid long-term commitments with service providers, focusing instead on work packages.

“Customers are trying to get different packages of wells completed,” Sagar said. “Fundamentally, I think a number of things are different. Number one, customers are not willing to make any long-term commitments. What’s called a long-term commitment is really just an extended work package. The package-work format has taken over the committed-work format that used to be the normal format in pressure pumping.”

He said that in an effort to maintain spending flexibility, work packages are smaller, whereas now a one-year deal with a service provider is made up of different packages that producers can get out of any time.

“And they do,” he said.

Additionally, Sagar said operators are often not maintaining a steady pattern of work but instead opting for more concentrated field services.

“Operators want to get production in early, establish cash flow and then take a break,” he said. “That’s not ideal for the industry because any industry, even things like the airline industry, need to be running and not start and stop. So that’s going to be challenging. The industry gets excited as we come off the very, very low point from where we were. So yes, compared to that, it is better. But it’s nowhere near any peak, and we personally don’t think the peak is happening any time soon.”

Although the shale industry may be in for a long uphill climb, service companies continue to bring innovative technologies and systems to the market that enable operational efficiency, improve ESG goals and boost financial returns.

“It feels like we’re seeing the new normal. There’s some stabilization, [and] operators are able to make their forward year plans, so it feels cautiously stable at the moment.”
—Michael Segura, Halliburton
—Michael Segura, Halliburton
E-frac and dual-fuel
The name of the game in unconventional shale development has quickly shifted from production at all costs to maximizing cash flow and reducing emissions to improve ESG performance. Operators have placed a priority on their ESG efforts as financial institutions have prioritized responsible investing.

As producers’ priorities similarly shift, service companies have responded, offering technologies and tools that help reduce emissions in various ways. At the forefront of emission-reducing technologies is frac pump power generation. E-frac and dual-fuel power-generated frac pumps have proven to reduce emissions either by cutting down on the amount of diesel fuel burned at the site or reducing flaring by utilizing excess natural gas to power engine turbines.

However, the two systems have varying degrees of total market penetration and present challenges in terms of cost and short-term value. But trends for the two systems are pointing upward.

One of the latest entries into the e-frac market has been National Oilwell Varco’s (NOV) Ideal fleet. The fleet offers 5,000 hp of electricity-generated power, and it claims a nearly 90% reduction in fuel costs and up to a 40% reduction in total cost of ownership, according to the company.

“When we sat down and looked at this space, we realized it’s an evolving market,” said Travis Bolt, product development manager of pressure pumping equipment with NOV. “We wanted to make our system power agnostic. It can run off of line power, either fully or some percentage of line power. But then it can also support lots of generation technologies whether its multi-reciprocating or whether it’s large single turbines. We really didn’t want to necessarily tie pressure pumping to a particular architecture on the power side.”

Bolt explained that the goal in the creation of the Ideal fleet was how the system can influence the cost of producing a well. That ultimately led to a design that Bolt said provides capabilities for those who might not be familiar with e-frac.

NOV’s Ideal electric frac fleet features 5,000 hp, electricity-drive pumps that can help eliminate costs related to engines and transmissions. (Source: NOV)
“We really wanted to think about simplification, engineering out HSE concerns, engineering out failure modes, understanding that fracturing is still a mechanically intensive process and how we can influence what it means to live with an e-frac fleet long term,” he said. “We understand that you’re still going to have to service the pumps. How do you get to those pumps? How do you pull them out? How do you service them without disrupting the rest of the site? That’s the way that we approached it.”

Meanwhile, Universal Pressure Pumping (UPP) has been a leader in dual-fuel technologies, having first introduced its systems in 2013. UPP’s fleet features 2,250-hp and 2,500-hp quintuplex pumps and can reduce diesel consumption by up to 54% when operated within optimal range.

Sagar said about 60% of the fracking industry is utilizing dual-fuel systems, as e-frac still emerges from its early days.

“I think the majority of the industry is settling on some sort of dual-fuel,” he said. “There will be a sliver of the industry that will focus on electric frac, because that piece of technology in my mind is still very much in evolution and development. No one’s really solved that; it’s the early days, and that’s purely economic. Ourselves, we were one of the first companies to get into dual-fuel a decade ago. That was early days, and now it’s become quite prevalent and the norm.”

UPP’s dual-fuel pressure pumping systems can reduce diesel fuel usage by up to 54%. (Source: Universal Pressure Pumping)
Sagar said UPP is currently designing systems the reduce engine idle time as well as different methods of fluid delivery that can reduce costs as well.

“All of these are going to reduce the amount of fluid we’ll need to pump to achieve efficiency, less repair maintenance and carbon footprint,” he said.

The fully automated frac job
The evolution of e-frac and dual-fuel power generation systems are examples of how hydraulic fracturing in North American shale has transformed since it began in earnest. Ever-growing completion designs and larger sand usage have led to greater efficiencies and production growth. However, the next phase, and the one that could be truly transformational, is the fully automated frac job.

Opinions vary wildly on where the industry is at in terms of the elusive carrot on the stick of the automated frac—some believe it’s here, while others think it’s either still a ways off or perhaps even not possible. What nearly all agree on, however, is that in at least some capacity, frac automation is here.

Among those that believe the fully automated frac job is upon us is Halliburton. Its SmartFleet system was unveiled in October 2020. According to the company, SmartFleet offers operators real-time fracture control while pumping by integrating subsurface fracture measurements, live 3D visualization and real-time fracture commands.

A Halliburton release on the system stated that SmartFleet connects to the reservoir through subsurface sensing to continuously measure cluster uniformity and fracture geometry. The system applies the measurements to make intelligent adjustments that improve fracture placement. SmartFleet also provides users a direct line of sight to live, 3D fracture geometry, projected fracture growth and cross-well interactions.

“When we have historically monitored frac jobs, we recognize that frac performance is inconsistent,” said Eric Holley, senior product line manager with Halliburton. “Fracture outcomes are oftentimes highly variable. That’s from a surface perspective and also subsurface. So one of the key things that we really wanted to do with SmartFleet was tie those together more purposefully, bringing the surface and the subsurface together in one platform. The purpose of SmartFleet is to give an operator more control of fracture outcomes while pumping, both in terms of efficiency and how you pump your job on surface, and control of fracture placement in the subsurface. So it’s really encompassing those key things and delivering consistent frac success.”

Halliburton’s SmartFleet connects to the reservoir through subsurface sensing to measure cluster uniformity and fracture geometry. The system applies the measurements to make intelligent adjustments that improve fracture placement. (Source: Halliburton)
UPP’s Sagar is among those who see the fully automated frac job as a work in progress, and he explained that what some might consider automation might simply be optimization. These include tweaks to such processes as pumping parameters and efficiencies and optimizing fluid chemistries and water usage.

UPP’s PTEN+ system offers 24/7 monitoring and identifies flat time opportunities with live data streaming. Metrics are tracked to the crew level to measure performances.

“We can see what’s going on remotely and have the [subject matter expert] optimize the job,” Sagar said. “The next phase is monitoring equipment health, which we also do remotely.”

As Sagar explained, limited automation consists of sub-components of job automation, which includes individual components like an automated blender where no crew is needed at the site to operate the blending machine.

“And then you come to more complete automation, where you don’t need 15 guys on a job,” Sagar said. “Instead, we’d need three guys on a job. You press a few buttons and everything happens. I think that last phase is probably a while away. For one, it is complex and a large financial investment. And second, we have a DNA problem in the industry where people are uncomfortable taking everyone off the job. People are just uncomfortable that there is no one there to fall back on if you had a problem. So, my opinion is that it’s somewhere between Phase 1 and 2.”

Simul-frac
While the chase for even greater operational efficiencies and cost savings have pushed new innovations in pressure pumping and frac automation, shale companies are also evaluating ways to get the most out of how wells are fractured.

For multiwell pads, zipper fracs are the industry norm: alternating stage sequences on adjacent wells. Now some operators are experimenting and seeing results from pumping two adjacent wells at the same time, an emerging trend known as simul-fracking.

“What you’re doing is simultaneously fracking two wells at the same time while you’re prepping two other wells,” Halliburton’s Segura said. “It’s a significant step forward in efficiency. Essentially, you’re working on four wells simultaneously whereas you would have been on two wells simultaneously in traditional zipper fracking.”

He said that although the idea is to improve efficiencies, with simul-frac “everything gets bigger and more intense.”

“In terms of logistics planning—the ability to feed sand and water to operations, contingency planning, the ability to manage multiple wells simultaneously, the control systems that can track and manage what’s happening in multiple wells—all of the planning and contingencies grow in scale when you go to simul-fracking,” Segura said.

He added that Halliburton started doing this three years ago and has been regularly performing quite a bit of simul-fracking for clients in the Permian Basin and in the Rockies. However, he acknowledged that not every well pad is ripe for the strategy.

“It takes some unique conditions for it to work,” he said. “Operators need to have adequate inventory, or a runway of wells, and it is typically most applicable to four-well pads or greater. The real benefit is completion speed for the operator and less shut-in time for neighboring wells. We see growing interest in it. It will be very applicable in certain places in the market, but I don’t think it will be at all places at all times.”

Additionally, splitting the fracturing operations between two wells requires some initial design alternations, as Halliburton’s Holley explained.

“You can augment the spread with horsepower as needed for different wells,” he said. “And operators can change their completion schemes in terms of number of perfs that they’re shooting and the number of clusters; you can change accordingly to match the rates that you’re putting down the wells. There are some modifications to design, and we have the ability to customize treatments for each well individually, so it’s not a one-for-one split.”

Like Segura, UPP’s Sagar noted that simul-fracs are likely not applicable everywhere, and the decision to initiate the operation is often an economics-driven one. He added that oftentimes the rock is likely to behave differently in a simul-frac than traditional zipper fracs.

“If you use less flow and pressure and you’re going to split it into two wells, then you don’t get exactly the same as if you do it in one well,” he said. “So, will the rock behave the same way? Not always. There are some wells where it will work, and some wells where it would not. We see some companies try; some do not. Some are seeing that their acreage is well set up for simul-frac, but for others it is not. So at the moment, I would call this a new entry into this space in terms of the concept. Some people are testing it out, some have tried and walked away, [and] some have stayed.”