‘Just Frac It:’ E&Ps Find Oil, Gas Treasure Remaining in L48 Basins

Now 25 years old, the modern, stimulated, horizontal Bakken oil play that has produced more than 6 Bbbl to date began with a bail-out well in eastern Montana in 1996.

The vertical Albin FLB #2-33 was supposed to be opened in the underlying Nisku, but geophysical and other indications while drilling showed the well wasn’t going to pay out if opened there.

Dick Findley, the geologist, and Bob Robinson, the wildcatter, had seen a good oil show from the dolomitic Middle Bakken on their way down to Nisku, though.

So, they plugged back and opened the hole there, hoping to recover enough oil to recoup their cost, at least.

The well—like all other verticals that bailed out in the Bakken during the prior nearly 50 years of Williston Basin oil drilling—was supposed to rapidly decline. A couple of months later, though, it hadn’t quit flowing.

Looking at logs and other records in state archives of other wells in the area that had traveled through the Middle Bakken, Findley mapped what looked like an ancient shoreline full of porosity.

He and Robinson brought in a better capitalized partner, Lyco Energy, which brought in pressure-pumper Halliburton for an equity interest in the 80-square-mile Sleeping Giant prospect.

The plan was to put laterals in the tight Middle Bakken—and frac them.

Harold Hamm, founder of Continental Resources, which already held leasehold along the porosity trend, said in the book, “The American Shales,” in 2014, “Lyco just decided to frac it. Just frac it.”

It was a breakthrough.

Hamm took the play to the North Dakota side of the Williston, growing Continental into a $30 billion E&P.

He told Oil and Gas Investor in 2023, “There are some interesting basins still that have some allure, some of which have been picked over a little bit but no one found anything. That doesn’t mean it’s not there.”

Today, wildcatters are having success in finding new Lower 48 oil and gas plays.

In the Pearsall underlying the Eagle Ford Shale in South Texas, privately held Formentera Partners brought on 1.5-mile wildcats with IPs of 1,499 bbl/d and 1,282 bbl/d. The former had already produced 15,130 bbl when tested, according to the well file.

Bryan Sheffield, managing partner, told OGI the idea behind testing the Pearsall was to put a 2025-minted D&C recipe on the formation, which had last been tested with recipes from the 2010s.

The Dean Formation in the northern Midland Basin overlying Wolfcamp has made more than 15 MMbbl from just a few dozen wells beginning in 2020 in Dawson County. The average production from the wells’ combined 952 months online is 527 bbl/d.

The Utica oil play in eastern Ohio has also liked the modern D&C formula, producing more than 130,000 bbl/d to date in just a few years of rigging back up in the rock that had been abandoned after using the early 2010s recipe.

Tim Parker, CTO for Encino Energy, which led re-entry into the Utica oil window, told OGI, “The data was there to tell you that the play worked, but you had to do the work. You had to sweat it.”

He added that his initial summation to the Encino board was, “I think we’re going to get more than a billion barrels here.” Since then, “it turns out I was wrong: It’s going to be several times that.”

The western Haynesville Shale is making Bossier and Haynesville gas gushers where wildcatters packed up after the enormous Marcellus and eastern Haynesville came online in 2007 and 2008, flush with natural gas.

Comstock Resources has now delineated the modern stimulated, horizontal play in super-deep, super-hot, super-pressured rock to 45 miles wide north of Houston with wells IPing more than 30 MMcf/d.

The Permian Basin’s Woodford and Barnett formations, underlying the typical Wolfcamp targets in the southern Midland Basin, are making 150,000 boe to 250,000 boe in less than 12 months, according to Vital Energy and SM Energy.

Vital’s Barnett tests result in payback in one year at $55/bbl oil, it reported.

Harkey sandstone in Culberson County is an extra zone for Coterra Energy in its mega-well “row” co-developments with Wolfcamp in the northern Delaware Basin.

In Utah, the Uinta Basin has gone horizontal since a surface issue—rather than a subsurface one—has been solved. Until a few years ago, the Uinta’s waxy oil that has to remain warm while transported was virtually capped at about 100,000 bbl/d into the Salt Lake City refining market.

New takeaway-by-rail capacity using insulated tank cars upended this. Production is nearly 200,000 bbl/d now and growing.

U-turn laterals are consistently being made problem-free, eliminating another surface issue. Nearly 100 of these have been deployed in odd-shaped and stranded single-section leaseholds, turning what would have fit just 1-mile laterals into acreage for more economic, 2-mile laterals.

Vital has added 77 U-turn wells to its inventory where acreage configuration would have been sub-economic.

In the eastern Haynesville, Comstock added 113 new 2-mile well locations to inventory.

A lighter-weight proppant is being deployed in Exxon Mobil’s Permian completions, resulting in 15% larger EURs, it reported. While sand is inexpensive, the Exxon Mobil proppant is made from residual petroleum coke from its refineries.

What’s next? Scott Sheffield, who sold Permian pureplay Pioneer Natural Resources to Exxon Mobil in 2024, told OGI this spring, “I don’t think you’re going to find another Wolfcamp or another Spraberry or Bone Springs play with tens of billions of barrels.

“But … the Pearsall play, Uinta play … even the Barnett-Woodford is coming back. … There’s a lot more opportunity out there.”