As low oil prices and shrinking profits force companies to rein in spending, fuel costs for onshore E&P operations have some thinking about which option is better—LNG, CNG or field gas, or diesel. The answer is not clear cut or universal.

“Obviously, today in February 2015, the economics of diesel vs. LNG have made the margins very thin, if not taken away altogether, in certain applications,” said Sam Thigpen, president and CEO of TRF Energy. “There are regions around the country where diesel is being delivered for less than what we can bring LNG to the market in that application. So it makes it tough for LNG in the E&P market right now, but it doesn’t mean that it is still not a viable solution in certain regions or for certain applications.”

The availability of dual-fuel engines and dedicated natural gas engines has created more options in the oil patch, giving companies cleaner options for producing oil and gas. Nowadays, companies are taking advantage of the bountiful gas supplies from shale plays, seeing opportunities to use natural gas to power pressure pumping fleets and rotary drilling rigs. The possibility for opening small-scale liquefaction plants in shale basins makes the option even more attractive, opening another revenue stream if produced LNG is sold to other companies nearby.

LNG economics depend more on the diesel delivered price than the commodity price, Thigpen said during Hart Energy’s World LNG Fuels conference.

“Commodity price from a natural gas standpoint can rise by 100% on the market. That change on the LNG price is pretty nominal vs. if diesel drops 50 cents,” he continued. “The economics are really consumed when diesel does drop. In today’s market, field gas is actually where we see a huge opportunity for the E&P companies.”

Diesel can drop to $1.50 delivered in the field, but operators could still save money by using field gas.

However, “for certain applications—dedicated rigs and things of that nature—LNG is not off the table by any means,” Thigpen added. “But we are seeing operators looking at any fuel opportunity to save the most amount of money vs. diesel costs. CNG is still a viable application in certain regions, but it is really project-based.”

Having an all-fuel solution allows E&P companies to analyze which fuel is better for which field, he said.

Noble Perspective

Noble Energy, which is building a $50 million LNG plant in conjunction with the company’s Keota gas processing plant in Colorado’s Weld County, is pushing the use of LNG at its U.S. operations and encouraging its vendors to do the same.

“From our view, field gas in the DJ [Denver-Julesburg] Basin is difficult because it’s rich. Field gas is not as easy as we sometimes think it is. The choice is very basin-specific and very operator-specific,” said Curtis Rueter, manager of LNG and CNG operations for Noble’s onshore U.S. operations. Factors include access to pipeline-quality gas, contract details and treatment required on field gas. “There are some places where it works, but it’s not a universal solution.”

LNG, on the other hand, has several advantages, he said. In addition to helping reduce truck traffic, he said LNG supply is plentiful, it offers consistent product quality to feed drilling rigs and fracks, has a competitive cost, is well suited for highly variable demand loads and can be used across all of the company’s operations.

Currently, Noble has six dual-fuel rigs running—four in the DJ Basin and two in the Marcellus—with plans to receive two additional dedicated rigs in second-quarter 2015. When the company began using dedicated natural gas rigs between 2011 and 2012, he said Noble saved about $1.3 million in fuel costs for the two rigs. Despite the cost savings, there were still some issues: Rig companies at the time were concerned about not only the supply of LNG but also the number of rigs that could run on them and what would happen once the LNG-fueled rigs were released. Then, for Noble, there was and still is the downside of having two fuel systems—the added costs associated with the related infrastructure.

“In today’s economic environment, that cost is really important to consideration,” Rueter said. Other considerations involve mobile LNG storage, regasification and vaporizer costs.

But, “the frack spreads have gone extraordinarily well in terms of dual-fuel systems,” he continued. “We have high substitution rates on those consistently.” Although the LNG usage pattern differs with short, intense fracking times that range from 18 to 30 hours before downtime compared to the nearly constant running of rigs, LNG use as a fuel has worked well. However, there have been some occasional logistical and delivery issues in the wintertime in the Rockies, something the company hopes will be alleviated when the Keota plant opens in the spring.

Another Perspective

Jim Avialis, CEO of Prometheus Energy, looks at rig counts, rig type and diesel prices, among other areas, to help find LNG opportunities in the E&P space. The company supplies LNG in North America to the industrial sector.

“From a natural gas perspective, we say the best economics come with 100% natural gas-dedicated solutions. Dual-fuel economics right now are difficult,” Avialis said. “If field gas is available, it’s terrific. But it is not available everywhere. What we are seeing is that many of our customers want to go to natgas [natural gas] with a combination of LNG and field gas. This is the combination they need that will give them economic savings over diesel, especially as they move from location to location, pad to pad, and gas composition to gas composition.”

Avialis said the company has seen 100% natural gas fleets on not only the drilling side but also the fracking side, along with improvements in the dual-fuel case of the last couple of years.

“We’re seeing a 50% to 65% substitution rate across the board for most conversion kits. What we do anticipate going forward is that the emissions—NOx, SOx, particulates, methane—are going to become more and more important going forward,” he said.

Charles G. Ely, general manager of Dresser Rand’s distributed LNG solutions strategic business unit, addressed environmental concerns and flares at E&P sites.

“It’s wasted energy that can be potentially used for resources for fuel or other things like field gas or for CNG or LNG,” Ely said.

While there is no universal solution for flare mitigation, installing pipe is the preferred method to capture flared gas and bring it into the system for wellhead, CNG or LNG use, he said. But the method is expensive, considering installing a pipeline runs from half a million to $3 million per mile. Plus, there must be sufficient takeaway, and it’s not re-deployable.

However, capturing flare gas at the wellhead is a good option, he noted, if there is enough consumption at the wellhead.

He later pointed out that one flare led to the production of enough LNG to fuel three rigs. “It can be a short-term solution to use rigs and frack spreads as part of your consumption, but long term those flares have to be taken some place farther away where there is more demand.”

After the rigs have left a well site, one solution is to install a gas processing/treatment system to treat the flared gas. “Then, you have a very small, compact liquefaction facility” where LNG can be created at the wellsite and transported locally, creating the advantages of cheap gas and low transportation costs, Ely said. “It allows you to be more competitive and compete with lower diesel gas; you can liquefy [gas]; and it solves your flare problem. It’s a real winner.”

Contact the author, Velda Addison, at vaddison@hartenergy.com.