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 tight-sands 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.

Drilling the lime

Most prospective formations are low-porosity, Pennsylvanian-age sands in the Lower Missourian and Upper Des Moines, geologically speaking. But things are a little different in the Oklahoma Panhandle, where Chaparral Energy and Unit Corp. have drawn attention for oily Marmaton lime wells.

“These stacked reservoirs have been drilled vertically for years,” Chaparral's Reynolds says. “There are multiple stacked carbonate benches in the Marmaton sequence and they've all produced vertically. As you move into Beaver County, the carbonate is shallower and is considered a shelf.”

This area is in the shallower part of the play. Well depths here average around 6,000 feet true vertical depth, and decline curves are less steep than in other parts of the play. “Most of the production stream is oil, 90%, and the gas we produce is liquids-rich,” Reynolds notes.

“From Chaparral's perspective, we've tested only the Marmaton and the Morrow in our (Oklahoma) Panhandle acreage. We have drilled the Cleveland over in Lipscomb County,” he says.

Not that horizontal carbonate drilling choices are limited to Beaver County. The Marmaton lime is present in Ochiltree County, Texas, where Chaparral also has an acreage position. The overall formation contains several layers of distinct carbonate limestone deposition, or benches. “We're talking about five different carbonate benches we could be drilling,” Reynolds says.

Chaparral also has bolstered its position through acquisition, closing in December 2013 on the purchase of 2,000 BOE/d of production and 66,000 net acres in the Marmaton Panhandle play from Cabot Oil & Gas Corp. for about $160 million. That essentially doubled the company's Marmaton holdings to 126,000 acres.

“We think our economics are in excess of 50% rate of return,” Reynolds says of an area where Chaparral obviously feels comfortable that it has established a workable approach.

Still, operators across the play continue to tinker with well spacing, number of fracture stages and other variables, looking for the magic numbers that will optimize drilling and production. Chaparral has experimented with extended-length laterals.

“We have drilled some 10,000-foot laterals,” Reynolds says. “We've had some that have been really good for us. And we've had some that performed about the same as a regular lateral. We're still evaluating where we're going with lateral length.”

Oklahoma's Marmaton and Mississippi plays are Chaparral's main focus, along with improved oil recovery efforts, according to Reynolds. “We're putting COinto the ground with some of these old waterfloods and we've gotten really good results,” he says.

Going forward, Chaparral plans to concentrate on developing its Marmaton holdings in the play. The company will drill about 50 wells in the stacked-pay play this year. Reynolds doesn't rule out evaluating other possibilities, and even moving into additional areas.

“We're going to concentrate on growing our position in our core areas. There are absolutely opportunities to expand, and we'll look at those as they come up,” he says.

Tonkawa action

For Apache Corp., this is mostly a Tonkawa play. The company has drilled more than 100 Tonkawa wells, almost all on the Oklahoma side, more than any other operator. As of last reported data, it holds 310,000 net acres prospective for Tonkawa and has 2,795 potential well locations.

Active throughout most of the play area, Apache started drilling Marmaton formation wells last year. It also drilled a number of Cleveland sands wells, mostly in Ochiltree County, and reported success with a handful of wells in the play's Cottage Grove formation.

“The Cottage Grove has been great for us,” Johnston says. “Last year we drilled our first deep Cottage Grove well, in Beckham County, Oklahoma. It was the 3-30H Simmons and it was in excess of 2,000 BOE per day.”

That well went to 10,400 feet true vertical depth. This isn't the deep Anadarko Basin of past activity, when operators sent vertical holes far below 20,000 feet to reach Hunton targets. When people in this play talk about deep wells, they're talking about wells that extend below 10,000 feet.

Johnston finds many things to like about the tight-sands formations Apache is developing in its Central region. “There are good things to be said about the semi-unconventionals like tight sands, compared to the real unconventionals like the shales,” he says, including more predictable drilling and completion results and a less steep decline curve.

In its Central region, the company plans to increase overall production 20% year-over-year through organic drilling, and will bump up spending on drilling and completion to $1.6 billion in 2014, according to Johnston. Apache probably will average 34 rigs running in the region during the year, up from a high of 25 rigs last summer.

Operators have solved many pieces of the puzzle over the past couple of years, but not all of them, Johnston notes. One thing they've found out is which way to drill the wells. “As a result of the stress regimes, there tends to be a preferred permeability direction. That's why you'll see 99% of these wells drilled north-south,” he says.

“We still have our share of problems. We figured out what works in a lot of ways and then we tried to figure out how to do things cheaper. The problem is, when you try to do things cheaper, you aren't always sure what to do.”

A problem cropping up in this horizontal play and others is the possibility of borehole damage or collapse when one well is being completed while an adjacent well is undergoing hydrofracturing. Johnston says operators routinely share completion schedules and other information in the play.

“We have literally knocked off adjacent producing wells. We've pumped into other companies' wells and they've pumped into ours. Most do come back. But, it's best to let your neighbors know what you're doing,” he says.

The Midcontinent went through a sharp drop in drilling activity as natural gas prices declined in 2008-2009. Oklahoma's active rotary rig count plummeted from more than 200 to around 75. Johnston says he was in Argentina at the start of 2009 and when he came back in the middle of the year, “nothing was happening. We had zero wells drilling.” As part of today's Midcontinent renaissance, Apache added 125 positions in its Central region last year alone.

Buying in

Midstates Petroleum entered this play in 2013 by acquiring assets from Tulsa-based Panther Energy LLC for $620 million. The deal brought the company about 36.4 million BOE in proved reserves and roughly 280 gross wells producing 8,000 BOE/d, 67% liquids.

It also acquired 140,000 net acres, with 102,000 acres in Texas and 38,000 in Oklahoma. The acreage is positioned in areas with multiple stacked oil targets and more than 700 currently identified horizontal drilling locations. About 60% of that acreage is held by existing production.

Midstates has been mostly a Cleveland sands driller but also drills other oil-prone formations, typically between 6,000 to 8,000 feet true vertical depth.

“When we acquired Panther Energy to get into the play, we didn't buy the company. We bought the Anadarko assets. What made the Anadarko Basin particularly attractive to us was the stacked pays, and the acreage we acquired gives us the opportunity to drill a number of them on the same acreage,” says Tom Thiele, vice president of Midstates' Midcontinent region in Tulsa.

“Since we took over the operation, we've ramped up drilling in the Cleveland, Marmaton, and Cottage Grove. We're also developing plans for other formations, such as the Tonkawa,” he says.

As part of the asset acquisition, Midstates also picked up additional working interest from Panther Energy's partners, giving the company more operational control and a cleaner entry into the play. “We're planning to drill at least 60 wells in the stacked-pay play in 2014, all horizontal,” Thiele says. “We're currently running five rigs and drilling wells with working interests from 60% to 85%.”

He expects to keep those five rigs running in the play during 2014, and another five in the company's Mississippian play.

Midstates entered the Midcontinent region in 2012 with a $650-million acquisition of producing properties and undeveloped acreage from Eagle Energy Exploration LLC in the Mississippi Lime oil play in Oklahoma. Thiele said Midstates has “had great success in drilling horizontal wells on our Mississippian Lime acreage since we closed on those properties in October 2012 and more than doubled our production out there.”

The company is initially drilling each of the tight-pay target formations at four wells per section spacing. Like other operators in the play, it looks for ways to optimize drilling and production efficiency. Thiele says Midstates is focused on reducing drilling and production costs to improve returns.

“Even though you can't predict what each well will do, you have a real good idea of what your average production will be. Your profit margin depends on how well you can keep the operating expenses under control,” Thiele says.

As a general rule, horizontally drilled and fractured wells show steep declines in initial production. That's certainly the case in this play, where a well might settle in at 75 to 150 BOE/d after 18 months and then go into a much gentler decline. A secret of success is to keep the drillbits spinning.

“Our acreage position stretches for miles and covers several counties. The key is to build up that base production with low decline rates to support your development,” Thiele says. “It's all about well count and time.”

Given healthy prices for liquids production, operators seem likely to keep stacking their chips on this play. Multiple drilling objectives present multiple opportunities, and no companies have reported serious problems in developing these prospects. A play with a solid future? Don't bet against it.