Operators find the odds stacked in their favor in western Oklahoma and the northern Texas Panhandle, where a series of stacked formations is producing crude oil, gas liquids and big returns. Companies that took an early gamble on this emerging play have turned it into something closer to a sure bet. Because it includes several producing zones, the play hasn’t latched onto a firm name. You could call it the Marmaton-Cleveland-Tonkawa stacked tight-formation Anadarko Basin oil/gas-liquids play. Accurate, but not very catchy. So most just call it the Marmaton play, or sometimes the Cleveland.
But whatever you call it, call it a moneymaker. Successful players get returns ranging from 40% to 80%. Well expenses have come down nicely, with most operators seeing drilled-and-completed costs of $3 million to $3.5 million per well. At the same time, initial production (IP) rates have climbed as companies figure out best approaches to the play. Some wells average more than 1,000 barrels of oil equivalent per day (BOE/d) in the first 30 days; a few make twice that.
Horizontal drilling and hydraulic fracturing pull the lever and spin the wheels here. Low porosity (tight) formations that might have been ignored in earlier years now respond to hydrofracture stimulation, producing generous yields. “We have opened a whole new world with horizontal drilling and modern fracture stimulation,” says Earl Reynolds, president of Chaparral Energy LLC in Oklahoma City.
While the oil potential of these formations has been known for 60 years, the industry only recently unlocked their productive capacity.
“It’s an amazing thing. As a geologist working out here in the 1980s and 1990s, you saw a lot of zones you’d drill through, but you’d never consider completing a well in one of them,” notes Rob Johnston, executive vice president for Apache Corp.’s Central region in Tulsa, Oklahoma.
The play to date centers on six counties: Lipscomb, Ochiltree and Hemphill counties in the Texas Panhandle, Beaver County in the Oklahoma Panhandle and Oklahoma’s Ellis and Roger Mills counties along the Texas border. It does edge into surrounding counties, but as you go south, most wells target Granite Wash, and northeast, the Cherokee formation group. Move east into Dewey County in Oklahoma and you’ll run into the Cana-Woodford shale.
Significant players include Apache, Chaparral Energy, Jones Energy Inc. in Austin, Texas, Unit Corp. in Tulsa, Midstates Petroleum Co. Inc. in Houston and Mewbourne Oil Co. in Tyler, Texas. Chesapeake Energy Corp., Oklahoma City, has drilled wells in the area but doesn’t consider this play a core asset, and in fact sold off its interest in Chaparral Energy for $215 million in January. EOG Resources Inc. in Houston, Le Norman Operating—a unit of Oklahoma City-based Templar Energy LLC—and a handful of smaller companies also work parts of the play.
Picking a favorite
Development by lateral wellbores gives the Marmaton different characteristics in different areas. Companies typically pick one favorite from these tight formations to drill horizontally.
A key to understanding this play: Which formation does an operator drill into, where, and why?
For Jones Energy, this is a Cleveland tightsands play. According to Jonny Jones, chairman and chief executive officer, the company has been active in the region for more than 25 years. He calls the Cleveland the “primary driver” for the company. Jones Energy has completed more Cleveland wells in the area than any other operator, and operates eight rigs in the play.
“We’ve been drilling horizontal Cleveland wells since 2004,” he says. “It’s like so many plays—2004 was really early for horizontal drilling. Ten years ago, we were struggling to get four-stage fracs off.” Things have changed in a big way. Jones Energy now approaches the play by incorporating up to 23 frac stages for a single lateral up to 5,000 feet long, with three frac clusters per stage, a change introduced by the company late last year.
“In essence, that means you’re fracing each stage three times. It’s basically an attempt to get to 69 frac stages. EOG was a leader in doing this in the Bakken,” Jones says. “This is the first time anyone has tried that quantum change in the Cleveland.”
The company uses close to 7 million pounds of proppant over all the frac clusters in one well. Such a novel approach has attracted keen interest from other operators. Jones Energy is testing the approach and hadn’t released results, but “our early experience is that this is flattening the decline rate instead of steepening it,” Jones says. Increased fracturing contacts more of the rock face.
Per-well expenses increase with the new frac technique, pushing a typical Jones Energy authorization for expenditure (AFE) from $3.1 million to around $4 million in the Cleveland.
The increase in AFE is material, Jones acknowledges, and he notes that well-level returns will have to be higher than those using its previous completion technique, to justify continuing the incremental capital spend.
In analyzing the Cleveland “we focused a lot on depositional environment” and the company approaches development from a geoscience perspective, according to Jones, who holds a master’s degree in geology. He says identifying the best zones in the formation and staying in zone while drilling is critical.
“We actually have geologists steer our wells instead of engineers, which I think is really unusual in the industry,” Jones says. “Obviously, there’s also engineering support where you would expect it to be.”
Jones Energy has ramped from drilling 45 wells in the play in 2008 to 72 Cleveland wells last year. It plans to drill around 100 wells here in 2014, assuming the current eight-rig pace. The ramp-up has been a function of technological improvements as well as the ability to make acquisitions in the region, Jones says. The company has made three acquisitions in the play, spending close to $700 million since 2009. That build-up included bringing Crusader Energy Group out of bankruptcy and acquiring assets from Chalker Energy Partners LP and Sabine Oil & Gas LLC.
Substantial acreage in the play is held by deeper production and Jones Energy’s holdings of 91,000 net acres in the Cleveland are largely held by production (HBP). That’s important to understanding how companies enter the play, or expand in it, which Jones sees as a consolidation process. “You’re not going to grow it by getting leases,” he says.
In much of this play, operators have multiple tight formations to analyze. Chesapeake Operating Inc., part of Chesapeake Energy, submitted a drilling permit request last year listing 10 potential target formations in just a 2,200-foot interval.
To enjoy the rest of this article, read the March 2014 issue of Oil and Gas Investor.