Before Dallas-based Plano Petroleum LLC acquired its acreage position in the Anadarko Basin in Roger Mills and Ellis counties, Oklahoma, the Marmaton reservoir was an uphole and uneconomic oil zone on the way to deeper, conventional gas targets below. No modern horizontal wells had been attempted previously, and the best vertical Marmaton completion in the field, in the 1980s, produced a grand total of 8,000 barrels of oil after fracture stimulation.

When Plano exited five years later, it had drilled nine Marmaton wells producing some 4,000 barrels of oil equivalent (BOE) per day gross, and the economics exceeded even the best oil plays in the U.S. The company's application of seldom-used mapping techniques, combined with experimental completion methods, set its results nearly 50% above even the larger operators that operated alongside it.

“The techniques utilized by Plano in this Marmaton field not only validated over 100 horizontal locations on the Plano block, but can be utilized by other operators to significantly expand the economic limits of the field and result in the drilling of hundreds of additional horizontal locations in the coming years,” says Cory Richards, Plano chief executive.

Oil and Gas Investor has awarded Plano Petroleum its 2012 Excellence Award for Best Field Rejuvenation.

Secondary objective

The Marmaton, sometimes referred to as the Lower Cleveland, is a low-permeability, Pennsylvanian-age sandstone found at an average depth of 9,500 feet in western Oklahoma. It averages 54 feet thick with a porosity of 9%. Estimates are that it holds 10 million barrels of oil in place per section.

Yet even with such ample resource, only a handful of vertical wells had tested the zone, and then only as a secondary objective of deeper Morrow penetrations. Those tests yielded three to five barrels of oil per day.

“That was it,” says Richards. “The results were very poor. A couple had modern fracs, and still didn't produce well.”

Thus, it is no surprise that when Richards approached private-equity provider Kayne Anderson for funding with 4,000 Anadarko Basin acres in 2007, the primary target was the Tonkawa formation. The Cherokee, Cleveland and Marmaton were upside.

Plano drilled three initial wells into the Tonkawa with varying economic results due to the wells being “underfraced” and using the wrong completion design —gel rather than slickwater—per Richard's analysis. Then, before more wells could be drilled to test the concept, the bottom fell out of the price of gas, and the highly variable gas-to-oil ratio of the Tonkawa scuttled further appraisal.

“With the economics associated with the gas play not very good, we shifted to another target,” he says.

In the meantime, EOG Resources Inc. had drilled an initial Marmaton horizontal well about 15 miles north of Plano's position with success—it produced 800 barrels of oil per day on initial production (IP). Two additional EOG wells also showed similar results. But three others underperformed, instead producing copious amounts of water with little oil or gas.

An isopach density map across the Marmaton, typically used as an indicator of productivity, shows consistent porosity across the play. So why the extreme variability in results?

Mapping resistivity

The question intrigued the Plano team. One of Richards' previous companies, Grayhawk Energy, had succeeded in turning a fringe extension of the Granite Wash play into an economic program using resistivity data to indicate productive zones. Maybe the same technique could be used here.

“The porosity values in the Marmaton sandstone were fairly consistent,” says Richards, “but there were significant variations in resistivity values. We had developed a technique to map resistivity in the Granite Wash. It was successful there, and I decided to try it here.”

Using electric logs from historical vertical drilling as early as the 1950s, Plano's exploration manager, Gary Hampton, mapped the region using a resistivity value of 30 ohms or above. He overlayed that map with another in which formation thickness exceeded 35 feet. The intersection—revealing an areal target about 25 miles long and 10 miles wide—indicated a sweet spot for highest potential production, the Plano team believed.

EOG's six results supported the thesis: The three wells to the north fell within the resistivity cutoff; the three to the east fell outside this core.

“Once we made that map, we had an explanation as to why the two areas EOG had drilled—both with good porosity—performed so differently. Their area to the north had the combination of good porosity and high resistivity. Resistivity is low in that eastern area.”

The resistivity isopach mapping technique “held the key for delineation of a large-scale oil-bearing reservoir” that had previously proved to be noncommercial, he says.

With its treasure map in hand, Plano's land manager, Jaymie Munchinski, led an effort to double the company's acreage position to 7,600 net acres, including some nonoperated interests with EOG to be able to share results. By now, other operators such as Chesapeake Energy Corp., Apache Corp., Primary Natural Resources and Mewbourne Oil Co. were active in the play as well.

Plano drilled its first horizontal Marmaton well based on this knowledge in August 2011. The Nelwyn 1H-7, in Southern Ellis County, flowed 570 barrels of oil and 1.5 million cubic feet of gas per day on IP. It produced 102,000 barrels of oil equivalent (BOE) its first year.

“Being a small company with not as much capital as the big boys, it was imperative for us to go to school and make sure of our geologic picture—measure twice, cut once,” Richards says. “Other components of the Marmaton reservoir were relatively static. The delta, the thing that varied, was the resistivity, which was a direct indicator of hydrocarbon saturation.”

Intensifying completions

That need for cost efficiency extended to the drilling program as well. With about $50 million of committed capital, the upstart company couldn't afford expensive misses either. It leaned on local Canadian, Texas, firm Hadaway Consulting & Engineering, with experience in several hundred horizontal Anadarko Basin wells, to maximize success.

“A lot of the efficiencies…were on their recommendations,” says Rick Stevens, co-founder and president of Plano.

To ensure that all stages within the Marmaton lateral were successfully fracture-stimulated, Plano completed its wells from toe to surface with high-strength casing, enabling additional burst rating during completion. Running the casing all the way back to the surface eliminated the possibility of a liner hanger leaking during the completion.

A “perf-and-plug” technique was utilized over an open-hole packer system to reduce risk of failed stages, and the company increased the overall amount of proppant put into the well-bore. It did this by increasing the amount of sand per stage, and increasing the number of stages in the same lateral length. At the end of the program, wells were completed with 4,200-foot laterals with up to 20 stages, with perf clusters spaced 48 feet apart.

“We knew we had fewer at-bats than the larger companies. It cost more to do it the way we did, but we had 100% success in each stage we attempted in the nine Marmaton horizontal wells, without abandoning a single stage. We had to have that certainty of results,” says Richards.

Side-by-side comparison

The results are telling. Plano points to a side-by-side comparison of two Marmaton wells in the core area and spaced 160 acres apart, one operated by Plano, the other by another operator. The wells were completed one week apart.

The Plano completion produced 47% more oil and gas during the first 60 days online.

Plano's well featured a perf-and-plug completion with 17 stages, 93,000 barrels of fluid, 3.4 million pounds of sand and a 70- to 80-barrels-per-minute treating rate. The adjacent well was completed using an open-hole packer method with 15 stages, 48,000 barrels of fluid, 2.1 million pounds of sand at a 54 to 56 barrels per minute treating rate.

“The difference is the completion technique,” notes Richards. “The incremental production in the first two months of Plano's well compared to the offsetting well more than paid for the additional completion costs—and the Plano well was producing at a higher rate at the end of the 60-day test period.”

In another comparison of six Plano-operated wells measured against six nonoperated wells, all within the defined Marmaton core, Plano's wells produced on average 10,400 BOE per well more than the other wells during the first 30 days of production. At the end of the 30 days, the Plano wells were producing just under 700 BOE per day, the nonoperated wells, 300.

“Take 10,000 times $80 a barrel, and that's a lot of money in the first 30 days. The wells pay for their incremental costs in the first 60 days,” says Richards. “The economic value of this incremental production has a significant impact on the economic performance of the wells.”

The next big thing

Plano's Charlotte 1H-13 well was its last and best in the Marmaton play. Plano pumped a 20-stage fracture stimulation that resulted in an IP of 1,030 barrels of oil and 5.2 million cubic feet of gas, or 1,880 BOE per day. The well's $5.3-million cost was 40% paid out after two and a half months. “It was a phenomenal well.”

Basing estimates on a reserve report by Cawley, Gillespie & Associates, Richards calculates the internal rate of return over the nine-well program at 70% to 80%, which trumps returns of other onshore U.S. marquee oil plays.

Plano exited the position in December 2012 to a private company active in the area for an undisclosed price, but north of $125 million, Richards confirms. Plano has since recapitalized with $200 million from Kayne Anderson and combined with Earl Michie's Terrace Petroleum, based in Midland, Texas, to form PT Petroleum, targeting the Delaware Basin.

But he hasn't forgotten the Marmaton, where he believes Plano's unique strategies can be used to identify additional productive regions in the formation.

“It's a bigger play than that map,” he says, referring to Plano's initial target area. “We think there are other areas where this will work, and we may well be active in those areas.”