As operators look for ways to squeeze more efficiencies from Lower 48 basins, business opportunities are expanding to make use of flared natural gas using electric pressure pumps.
Hydraulic fracturing (fracking) is overwhelmingly done using diesel-powered pumps, each around the size of an 18-wheeler. Conventional fracking isn’t going away, but a niche sector, aka e-fracking, is making inroads in the Permian and Marcellus basins and beyond by using otherwise flared gas and shuttling it to turbines that power electric motors.
Smaller exploration and production (E&P) companies have been slow to adopt the technology, but the bigger operators are taking notice.
EOG Resources Inc., one of the largest producers in the Lower 48, has become a cheerleader for e-fracking. COO Billy Helms said the decision to embrace e-fracking has reduced the company’s environmental footprint and improved profitability.
EOG piloted its first electric fleet, or e-fleet, in the Eagle Ford Shale, and it now uses them in the Permian. Four e-fleets are in operation by EOG. While the overall fracking fleet count in the Lower 48 varies week-to-week, it typically runs a total of 16.
“Our experience with this new technology has been very positive,” Helms said. The electric operations are saving up to $200,000 per well and reduce combustion emissions from completion operations about 35-40%.
Most of the savings are in fuel costs, Helms acknowledged. EOG also is using the technology “where we have readily available infrastructure to be able to access gas as a fuel source,” versus having to truck in diesel. E-fracking also provides EOG “efficiency gains too…We’re always looking for ways to continue to utilize our infrastructure to enable that to be spread into other plays. So I think as you look forward, we will look for opportunities to continue to put those in new plays.”
Earlier this year, Baker Hughes, a GE company (BHGE), had eight e-frack crews deployed in the Permian. The oilfield services (OFS) giant provides mobile and modular gas turbines with packages available in different configurations from 5.6-34.5 MW.
E-fracking can reduce the overall fleet size by up to 40% and consume associated gas that otherwise might be flared, BHGE estimates. Flared gas from oil drilling is a big business opportunity, according to CEO Lorenzo Simonelli.
“Electric frack enables the switch from diesel-driven to electrical-driven pumps powered by modular gas turbine generating units,” Simonelli said. “This alleviates several limiting factors for the operator and the pressure pumping company such as diesel truck logistics, excess gas handling, carbon emissions and the reliability of the pressure pumping operation.”
BHGE estimated there are around 500 fracking fleets total now deployed across North America, nearly all powered by trailer-mounted diesel engines. Each fleet consumes 7 million-plus gallons/year of diesel and emits on average 70,000 metric tons of carbon dioxide. For remote sites, the diesel engines on average require 700,000 tanker truck loads.
The 500 or so diesel frack fleets require a combined 20 million hp of energy, which translates into a potential market to provide 15 GW of electricity using gas-fired turbines.
Midland, TX-based ProPetro Holding Corp.’s DuraStim fracking pump, at 6,000 hydraulic hp (hhp), is designed to offer the equivalent of three times the effective horsepower of a conventional frack unit, while operating at around 10% of the cyclic rate.
Each DuraStim fleet consists of 36,000 hhp and related power equipment. Three fleets are to be delivered this year under dedicated agreements. Among ProPetro’s clients are ExxonMobil’s XTO Energy Inc. and Diamondback Energy Inc., which plan to use the e-fracking pumps in the Permian.
The fleets are designed and manufactured by AFGlobal; ProPetro also has two TM2500 gas turbines from BHGE to power the first two fleets, each generating 30 MW.
“We believe the DuraStim fleets represent the future of our industry and will drive down well costs for our customers while improving safety and the useful life of our equipment and reducing environmental impact,” ProPetro CEO Dale Redman said.
“We are excited that XTO Energy and Diamondback Energy are positioned to be first movers in deploying this transformational technology in the Permian Basin, and we are confident that our long-term relationship with AFGlobal and BHGE will allow us to continue to meet our customers’ evolving needs.”
While e-fracking is making inroads, it’s not widespread. And many of the largest OFS operators, including Halliburton Co., don’t see the value in it — yet.
Evercore ISI’s James West said of the estimated 20 million hp in the United States used for pressure pumping, the e-fracking market today is less than 150,000 hp.
“It’s a very small niche market right now,” he told NGI. “The pricing for pressure pumping services today does not justify the higher capital investment in e-frack, especially as the efficiency and cost savings would mostly accrue to the oil and gas company, rather than the OFS company.”
Sanford Bernstein analyst Bob Brackett said there are e-frack exploration and production (E&P) supporters, led by EOG. However, “the whole concept is a bit of a misnomer,” he told NGI. “It’s really about using cheap natural gas to power a turbine versus burning diesel to the same result.
“The E&P view is that there must be a way to ”share’ the capital commitment given how attractive the relative fuel economics are. So it feels like the big service companies are frustrated at the pricing model and pushing back.”
Halliburton has e-fracking in the Denver-Julesburg Basin. However, there’s no near-term plan to adopt it across the board, CEO Jeff Miller said at the recent Barclays CEO Energy-Power Brokers Conference.
The decision for Halliburton about whether or not to invest in e-fracking fits into three categories.
“First is power,” Miller said. “The second is the pump itself that delivers the frack. And the third is making a return. All three of those matter. And right now, the power piece is what causes all of that to cost more for a service company.”
Compared with diesel, e-fracking tends to underutilize power, the Halliburton chief said.
“It does not make sense to me that long-term service companies will be lugging power around and underutilizing power,” Miller said. “It just doesn’t square for me that we would go buy something that should work 100% of the time, 99% of the time and go use it 40% of the time, and lug it around hoping that what we have bought matches up somehow with the way a client wants to work.”
Halliburton has had “nuanced” conversations, he said, with customers that may “only need X, Y or Z, and I could optimize the power around my saltwater disposal and three or four other things. I had this conversation very recently and I said, ”you are exactly right. You should own and optimize all of that.’”
However, it’s not Halliburton’s business to optimize for a customer for a three-year contract. “That’s a 20-year asset; you could use it for 20 years,” Miller said. “And so…Halliburton will be really slow around e-frack. We know a lot about it. We’ve got a fleet running. We’ve made the mistakes and learned a lot about…what works and doesn’t work.”
The e-frack research and development project now operating “has a contract,” he said. Halliburton is the largest pressure pumper in North America. Switching its massive pressure pumping fleet to e-fracking would cost billions.
“I don’t see that happening,” Miller said. “When I think about electric, we don’t know where it’s going to go over time. I feel pretty confident that the configuration today isn’t sustainable…We have enough equipment that rolls off every year that we have to do something with that. I feel like just our replacement schedule will keep us as competitive as we want to be in that part of the market.
Until the economics work, it “doesn’t make sense to me.”
One of North America’s top drillers, Patterson-UTI Corp. (PTEN), also has no plans to invest in e-fracking fleets because of the high costs to build equipment for an already oversupplied market.
PTEN now runs some of its drilling rigs using natural gas produced at nearby wells, and in the past year it also has begun running some rigs using lithium battery packs in addition to diesel. For e-fracks, however, “the math doesn’t work,” CEO Andy Hendricks said at the Barclays conference.
With OFS operators facing a glut of stacked equipment as E&Ps pull back and become more efficient, the upfront cost to deploy electric fleets could be daunting, according to Tudor, Pickering, Holt & Co. Analysts estimated new e-fracking fleets could cost $40-60 million, versus $30-40 million for diesel systems. Also, because the technology is in its early stages, there is hesitation by operators to deploy capital.
While it may remain a niche for now, there are small gains being made.
Evolution Well Services, based in The Woodlands north of Houston, in July obtained a 30-month agreement to provide dedicated e-fracking services for an onshore E&P.
Last year, CNX Resources Corp. also signed a three-year agreement with Evolution to utilize a 100% e-fracking fleet in Appalachia, the first long-term agreement in the basin for an entirely gas-powered fleet. Evolution provided CNX with a 56,000 hhp fleet, which it said could reduce fuel costs by up to 95% and operate below federal emission standards.
CNX COO Tim Dugan at the time said the agreement had the potential “to be the next step change in the efficiency frontier and exactly the kind of technological disruption we’re focused on across the board.” During the second quarter conference call in July, CNX management said its decision to utilize a 100% electric fleet translated to fuel savings of $180,000/well.
“The improvements in this technology contribute to safety, neighboring communities, and to the bottom line are undeniable,” said Evolution’s Carrie Murtland, vice president of technology and marketing.
Evolution’s electric fleets are powered by a proprietary, built-for-purpose gas-burning turbine generator package designed and packaged by affiliate, Dynamis Power Solutions.
“By employing our own custom turbine generator package, which was purpose-built to reduce mobilization time and increase power output, we have been able to expand our service offering to electrically power a multitude of in-field client needs, beyond just fracturing activities,” said Murtland.
In March, U.S. Well Services Inc. secured a long-term e-frack fleet contract of up to four years with Royal Dutch Shell plc subsidiary SWEPI LP. Shell “was one of the first customers to utilize our electric frack technology,” said CEO Joel Broussard.
In June an electric fleet was deployed for the first of 16 wells in the Permian. The Shell fleet is to be deployed in the Permian next year.
“Our commitment to safe and responsible energy development shapes every decision we make,” said Shell Oil Co. President Gretchen Watkins. “Deploying an electric hydraulic fracturing fleet in the Permian demonstrates our steadfast pursuit to achieving sustainable energy solutions for our business.”
Sourcing the gas also is an expanding sub-sector. Houston-based Certarus Ltd. in August obtained an agreement with a Permian E&P to source compressed natural gas (CNG) from flaring to service its e-fracking fleet.
“We are seeing an increasing trend within completions to use electric hydraulic fracturing as a means of reducing carbon emissions and achieving cost savings,” Certarus Vice President Nathan Ough said.
In the Permian agreement, Certarus plans to displace at least 5.5 million gallons of diesel fuel with CNG; it has an option to expand up to 37.8 million gallons over the term of the contract.
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