A tale of two plays

It’s a study in contrasts for Louisiana’s two major oil and gas plays, with Tuscaloosa Shale interest waning while hopes for Haynesville surge.

By  Sam Barnes - August 11, 2021

Louisiana’s two predominant oil and gas plays, Tuscaloosa Marine Shale and Haynesville Shale, have taken starkly divergent paths over the past decade. While poor market conditions have made the TMS too risky for most drillers, Haynesville rig counts are on the rise due to burgeoning liquefied natural gas exports.

Patrick Courreges, communications director at the Louisiana Department of Natural Resources, says recent DNR data tells the tale. There’s currently only one active drilling permit in the TMS and dozens in the Haynesville play. “We’re seeing about 30-odd rigs split between Haynesville Shale and the Cotton Valley formation,” he says. “That has been fairly steady.”

The shale play boom began with little fanfare about a decade ago. For the first time, advances in horizontal drilling and hydraulic fracturing enabled oil producers to access what had before been commercially unavailable. The relatively high oil and natural gas prices at the time provided the incentive for experimentation and risk-taking, and U.S. production began to surge.

The massive TMS, which covers 8 million acres in Louisiana and Mississippi, has long tantalized oil companies and economic development officials, but idiosyncratic extraction challenges and the 2014 price plunge have kept it from realizing its economic potential.

TMS isn’t completely dead, but “it’s lying in the grave,” says David Dismukes, executive director of LSU’s Center for Energy Studies. One of the biggest challenges is that development there never really got off the ground before the price drop “so no one was able to de-risk the play” in terms of geology, output and expected outcomes.

That lack of geological knowledge has become the play’s Achilles heel. “TMS has a lot of geological characteristics that make it unique and interesting, but producers don’t like unique and interesting,” Dismukes adds. “It’s deeper, in the 14,000- to 16,000-foot range, and it really doesn’t have the stacked layers like in the Permian Basin. The rock also has a clayish, spongy characteristic that makes it hard to get the pressures that are needed.”

Another problem is that most oil and gas companies still have large backlogs of debt and aren’t willing to take risks. “When 2014 happened, it just changed the world,” he says. “The business model for shale differs from other developments. You have to go out and grab big blocks of real estate and you have to get out there first.

“In 2013-14, they essentially borrowed money to secure the mineral rights, then the rug was pulled out from under them.”

Tuscaloosa blues

Cracking the TMS code was the initial focus of LSU’s Tuscaloosa Marine Shale Graduate Research Consortium when it was created in 2013. And while the group has been mostly inactive in recent years, Richard Hughes, a professor in the university’s petroleum engineering department, is attempting to reboot the effort to tackle the geology, rock mechanics and reservoir engineering sides of the TMS puzzle. The consortium already has the tools it needs. “Earlier proposals led us to build some capabilities within our department, including the purchase of a permeator and some rock mechanics measurement tools to enable us to do the work,” Hughes says.

It is an admittedly tough nut to crack, since the shale within the TMS is softer and has less natural fracturing. Nonetheless, it’s estimated 7 million barrels of oil are hard to resist. “We hope to perform some rock mechanics testing to determine if there’s a stress orientation or a way to frack the marine shale in a manner that’s better,” Hughes says. The group also hopes to look at fluid properties within the reservoir to determine the mix of oil and gas.

More recently, a group of researchers at UL-Lafayette received a $9.7 million U.S. Department of Energy grant to study the TMS in much the same manner. Led by ULL professor Mehdi Mokhtari, the consortium hopes to find “sweet spots” in the play that have higher contents of oil and gas, while also studying engineering techniques for extracting oil and gas from the formation’s extraordinarily tiny pores.

Hughes says his group will likely collaborate with ULL, with the overriding goal of bringing down production costs. “The TMS is probably double the price of Eagle Ford in Texas,” Hughes says. “It’s some $60 to $80 as opposed to $20 to $40. That’s because Eagle Ford is more brittle and fractures more easily. To get more out of the TMS, we need to understand more about the interrelationship of the rocks.”

Eric Smith, associate director of the Tulane Energy Institute in New Orleans, says the geology of the TMS will continue to make it far too expensive and risky, and no research or improvements in technology will change that much. “The shale is very soft and requires a lot of proppant to keep it open,” Smith says. “Every other place has been able to thrive on these lower prices.

“I don’t see some ‘barn burner’ technologies coming along that’s going to cut the cost,” he adds. “That’s not in the cards. We might find another 10-15 percent reduction by standardizing the drilling procedures or by doing more pad drilling, etc. But that won’t be enough.”

Kirk Barrell, president of New Orleans-based exploration and production company Amelia Resources LLC, is more optimistic, saying TMS has gotten a bad rap. As evidence, he points to Encana Corp.’s 15 successful wells in 2014. Unfortunately, they were overshadowed by more recent failures—Australis Oil & Gas of Perth, Australia, had four of its six wells fail as it attempted to manage the job remotely.

Barrell says the Australis attempt cast a “dark cloud” over the TMS. “It set the perception back by about five years,” he adds. “Now, the financial community thinks the TMS can’t be drilled consistently.” Emboldened by $70-a-barrel oil, Amelia Resources recently secured about 100,000 acres in “geologically superior” areas of the play and is currently marketing them to prospective drillers.

Haynesville a shining light

Meanwhile, there’s an entirely different reality underway in northwest Louisiana. Haynesville Shale has hitched its wagon to the growing LNG export business and the dry gas it offers has made it very attractive.

“You just don’t get dry holes (in Haynesville),” says DNR’s Courreges. “They know how to drill it, know how to fracture it, and how to get the best out of it. Louisiana is now at 3 trillion feet a year in gas production, with the bulk of that coming from Haynesville.”

Having an export customer is the primary reason. Tellurian acquired some 1.5 trillion cubic feet of natural gas in the Haynesville play to supply its planned Driftwood LNG project south of Lake Charles, and also constructed a pipeline from the play. In the process, Tellurian hopes to control costs and circumvent impending pipeline shortages. “People find a way if the need is great enough,” Courreges says. “After all, they used to think that shale was too risky, but somebody figured it out.”

Tulane’s Smith expects to see more activity in Haynesville as the LNG market picks up in the post-pandemic world. “Haynesville is a dry gas, pure play, so you don’t need a processing plant to separate any other liquids,” Smith adds. “The other attraction is that you’re creating your own reservoir, so you can get a shorter turnaround time between your investment and fully exploiting a particular well. It has a much better response time.”