Finding The Next Big Shale Play

Can the U.S. capitalize on its experience to keep the shale revolution going? The answer depends on three factors, according to a group of researchers and industry experts.
By Patrick C. Miller | September 05, 2017

The global transformation of energy supplies brought about by the success of oil and gas from U.S. shale plays such as the Permian, the Bakken, the Eagle Ford, the Marcellus and the Niobrara is well known. But are there other shale plays in the U.S. that could provide additional reserves and future energy stability?

In early August, BP announced a significant new source of natural gas from the Mancos Shale play in New Mexico’s San Juan Basin. A highly productive well was brought online that achieved an average 30-day initial production rate of 12.9 million cubic feet per day, the highest in the past 14 years within the basin.

“This result supports our strategic view that significant resource potential exists in the San Juan Basin, and gives us confidence to pursue additional development of the Mancos Shale, which we believe could become one of the leading shale plays in the U.S.,” said Dave Lawler, CEO of BP’s U.S. Lower 48 onshore business.

Not everyone was surprised by BP’s results. The Mancos was among the emerging U.S. shale plays studied under the unconventional resources program of the Research Partnership to Secure Energy for America (PRSEA)—an organization headquartered in Houston that supports oil and gas development.

“These projects were basically looking at what you can do to add reserves,” says Tom Williams, RPSEA president. “There’s a lot more than just the rock that’s going to make emerging shales work. We’ve been putting together a project and proposal team to really look at all the factors. It could be economics, infrastructure, regulations—all kinds of variables.”

In addition to the Mancos, the other shale plays studied by RPSEA include the Rogersville in Kentucky and West Virginia; the Black Warrior in western Alabama and northern Mississippi; the Tuscaloosa Marine in Louisiana and Alabama; the New Albany in Illinois, Indiana and Kentucky; and parts of the Eastern Great Basin in Utah and Colorado. All of RPSEA’s studies and reports are publicly available on the organization’s website at

Robert Clarke, Lower 48 upstream research director for Wood Mackenzie, has spent years studying exploratory shales for the Houston-based analytics firm. The Mancos Shale Play has been on Wood Mackenzie’s radar as one to watch.

Clarke says that unlike many companies strapped for exploration capital in the low-oil price environment, BP is different because of its acreage position in the Mancos Shale and its focus on trying different well completion techniques there.

“Out of the gate, BP is ripping and roaring,” Clarke notes. “They’re off to a great start, but we’ll have to give it six to 18 months to have a firm external panelist opinion on how the Mancos will unfold.”

Three Key Factors
What are the key factors to consider in evaluating a shale play?

“You’ve got to have the geology before anything else,” Williams says. “If you have the geology, what other factors could either allow you to make the play commercial or what could you do to impact those?”
Clarke lists three primary factors Wood Mackenzie considers in determining a shale play’s potential.

“It’s the companies, it’s the commercial conditions and then it’s the quality of the rock,” he says. “When we look at a shale play to understand if it’s got legs underneath it for large commercial development, those are the three most important factors.”

The competency and experience of the companies exploring the play are key considerations.

“If it’s a Chesapeake or a Devon or an EOG all in the same basin—all drilling exploratory wells and sharing data to some degree—that’s a much more positive sign than if it’s just three or four micro-cap companies trying to drill on the fly,” Clarke explains.

For successful commercial operations, he says a basin with an existing supply chain, available infrastructure, good inter-basin differentials and favorable fiscal terms—such as royalty rates and taxes—all work to keep costs manageable. Finally, access to core samples and empirical geological data on pressure gradients, minerology and hydrocarbons are key to determining the quality of the rock, according to Clarke.

The Powder River Basin in Wyoming and Colorado is one shale play in the U.S. that he says comes the closest to meeting these criteria.

“There are some areas of the Powder River Basin that are oilier that we think can break even around $40 a barrel,” he relates. “People got excited about the Powder River Basin about a year ago when it got branded as a Permian lookalike in the sense that you have six or seven intervals that are stacked in the strat column. When you model it in three dimensions, you can see the depth.”

Targets of Opportunity
Vello Kuuskraa, president of Advanced Resources International Inc. in Arlington, Virginia, examined emerging U.S. shale plays in his presentation at the 2017 Unconventional Resource Technology Conference. He listed the Mowry Shale of the Powder River Basin and the Mancos Shale in the San Juan Basin as two of the most promising plays.

“In my view, the great bulk of new shale reserve and resource additions for the next decade will come from searching for additional production horizons in existing basins, pushing the technology envelope and turning from vertical to horizontal drilling.”

Kuuskraa lists the Alpine High—a liquids-rich, wet gas play—in the southwestern Delaware Basin as one of the most recent, high-visibility exploration successes. Others shale plays showing potential are: the Moorefield in the Arkoma Basin of Oklahoma and Arkansas; the Cotton Valley in western Louisiana and eastern Texas; the Spraberry tight oil formation in the Midland Basin of Texas; the Haynesville in Texas and Louisiana; and the Meramec and the Cana-Woodford in Oklahoma’s Anadarko Basin.

The Rogersville Shale Play that stretches from eastern Kentucky into West Virginia provides an example of a formation with potential, but lacks the three key factors of strong E&P company support, sound commercial conditions and reliable data on the resource. Williams says Kentucky is eager to develop the Rogersville to replace lost coal mining jobs.

Data-Driven Decisions
David Harris with the Kentucky Geological Survey and head of the energy and minerals section at the University of Kentucky explains why the Rogersville Shale—despite showing promise—has yet to thrive. What’s known as the Rome Trough of the Rogersville was the subject of a 2002 scientific study based on a single core drilled by Exxon in the 1970s.

“We knew we had a likely source rock that was mature and that had generated hydrocarbons,” Harris says. “We determined that we had a new petroleum system in the deeper part of the section sourced by the Rogersville Shale.”

When the shale boom took off in 2009, some E&P companies looked at the earlier study and considered the Rogersville a potential unconventional play. Although a number of wells have been drilled in Kentucky and West Virginia, the cores and much of the data from them remains confidential.

“The take-home point is that there’s really not much hard information on this play that’s been released yet,” Harris notes. “It will be released through the state regulatory agency five years from whenever it was completed for the stratigraphic test permit.”

Most of the wells drilled in the Rogersville are depleted or have been shut in, according to Harris. The one well for which production data is available shows a steep decline rate for gas and no natural gas liquids produced.

Harris says the Rogersville is a technical success because E&Ps have recovered hydrocarbons from the play. However, between the lack of solid data and low oil prices, he doesn’t foresee substantial development in the near future.

“We’re still sort of hoping that it works out and is successful,” he says, “But right now, it’s too early to say for sure.”

Williams points out that well-production data with disappointing results doesn’t necessarily mean a shale play lacks potential.

“For example, some of the wells drilled in the Tuscaloosa Marine Shale showed low recovery rates,” he notes. “We know that the wells they drilled and produced didn’t have a good completion strategy. What can you do to increase the recovery? Maybe it’s a different sand volume or frack volume or spacing or orientation—all those variables. It’s like trying to solve a puzzle.”

State policies are another factor impacting shale play development.

“You can’t even get a permit in the Illinois Basin to do hydraulic fracturing,” Williams says. “On the New York side of the Marcellus, they’re trying to keep people from doing fracking. It doesn’t matter how good the rock is in those two states if you can’t get a permit.”

Clarke says there’s much to be learned from the experience of developing successful shale plays.

“The simple way to say it is that you get really good at drilling wells in a basin by drilling wells in a basin,” he explains. “I don’t think anything trumps field learning in an unconventional play. If it’s a play with fantastic rock, but there’s only one company there drilling one or two wells a year with no one else to share data with, it’s going to go at a snail’s pace compared to other plays.”

Clarke concludes that for an emerging shale play to be successful, it takes “lots of rigs, lots of companies, lots of consortia, lots of knowledge and lots of information that flows to the service companies” to overcome the steep learning curve that accompanies the development of unconventional oil and gas.

Author: Patrick C. Miller
Staff Writer, North American Shale magazine