Hanna Oil Searches for ‘Big Payday’ Wells in Arkoma Basin

The Arkoma Basin
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It all started with the Lincoln II. The gas well single-handedly catapulted Fort Smith-based Hanna Oil & Gas Co. to early success when it was discovered in Crawford County in 1971.

With an initial open-flow rate of 175 million cubic feet per day, the well now produces 400,000 cubic feet of natural gas to boost Hanna’s average daily production to 17 million cubic feet.

“It was a terrific well that changed our company forever and is still today our best well,” said Bill Hanna, president and CEO of Hanna Oil.

With 160 wells in operation, a working interest in about 1,000 wells and more than 60,000 acres under lease in the Arkoma Basin, the privately held company continues to increase its holdings in the shadow of publicly traded exploration giants like Southwestern Energy Co. and XTO Energy Inc.

“We are opportunity-driven,” Hanna said. “We don’t have a stranglehold on any particular play [rock] type. We like to think we are versatile enough that we can learn, and over time, if it’s something we think we can do well, we’ll certainly pursue it.”

Hanna’s father, Jim Hanna, founded the company in the early 1960s, having come to the Fort Smith area to start up an office for Bridwell Oil Co. of Wichita Falls, Texas. Jim Hanna spent about a year with Bridwell after the move and then quit.

“He went out and started buying oil and gas leases and trading them, and he did that for about 10 years,” Hanna said.

The elder Hanna is semi-retired now, and his son has been president of the company for five years.

Although Hanna would not disclose annual revenue figures, he said the company’s success can be measured by production increases.

Twenty years ago, Hanna operated 40 wells. By the mid-1990s, Hanna had 100 and today it operates about 160.

“I’ve been here 19 years, and over that period of time, production has gone from 9 million cubic feet a day to about 17 million,” said Ron Robbins, exploration and operations manager for Hanna.

Hanna Oil opened an office in Canada in 1987. The eight-employee venture in Calgary, Alberta — Hanna Oil & Gas Co.-Canada Inc. — functions as a separate entity that owns about 300,000 acres of mineral rights.

The Canada arm doesn’t operate its own wells there. It generates prospects and partners with other investors to search for oil. Hanna said the Canada oil exploration accounts for about one-third of the combined revenue of the two companies.

“We have a real long-term approach to our business,” Hanna said. “We plant seeds to root 20 to 30 years from now. We’re not in it to sell it. We’re in it to build a good long-lasting multi-generational family business.”

Cost of Drilling

“We have to pay more for leases today than we did 10 or even two years ago,” Hanna said.

Bonuses associated with leases, Hanna said, are up 100 percent from what they were five to seven years ago.

The cost of bonuses depends on location, Hanna said.

“If you are in early and talking to a landowner who hasn’t leased in 20 years, then you can lease the land for $25 per acre,” Hanna said of the bonuses. “But if it’s a hot play and four companies are after that person, then you can pay up to $250 an acre or higher.”

Hanna said one-time bonuses associated with leases can climb into thousands of dollars per acre.

The state mandates that a company must have 640 acres under lease to start the drilling process for a well.

Typically, a primary lease term will range from three to five years, Hanna said. If production is established during that primary lease term, then the lease lives as long as that well produces.

Landowners typically get a cut of 12.5 percent to 25 percent of production in a lease agreement.

About one-third of the wells drilled in the Arkoma Basin end up being dry, Robbins said.

The company drilled 20 wells in each of the last two years. On average for each of those years, Robbins said, four wells ended up “dry holes,” four wells were “big payday” wells, and the other 12 wells were considered “break-even” wells.

It costs about $750,000 to drill one 7,000-foot well, he said.

In recent years, regulation changes from the Arkansas Oil and Gas Commission have increased productivity by more than 50 percent in some areas of the basin.

“All of these wells drain in very small pockets of reservoirs, so we have to drill quite a few of them and the spacing needed to be changed,” Robbins said.

Rocking the Rocks

Pennsylvanian-aged turbidities are what Hanna Oil is seeking in a basin that stretches 90 miles from east to west and 40 miles north to south. In other words, sand deposited 250 million years ago in a deep-water setting that ended up being structurally complex — or, basically, rocks with the right kind of cracks in them.

Consulting geologist Ted Beaumont said reservoir-quality rocks that have the double threat of permeability and porosity are the secret to natural gas extraction.

“Once you have a source, if it is producing gas it will migrate into rocks or sediments that have pore spaces between the drains of the sediment that has enough permeability so that gas can flow into the well bore [drill hole].”

To date, the Arkansas Oil and Gas Commission has issued more than 38,000 permits to drill for oil, gas and brine wells in the state.

“Hanna has found a niche in the Middle Atoka area of the Basin [largely in Logan and Yell counties],” said Charlie Wohlford, owner of Wolf Exploration in Fort Smith and former president of Thomas C. Mueller Inc., an exploration company that sold to XTO Energy in March. Mueller had about 100,000 acres under lease in the Arkoma Basin.

“Gaining access to land and the maturity of the basin limit the number of prospects you can generate,” Wohlford said.

The basin is broken into shallow wells where the key formations are about 2,000 to 2,500 feet deep, he said. The Fairway area of the basin has wells that are 4,000 to 6,000 feet deep. The Middle Atoka region, where Hanna drills, has wells that range from 6,000 to 8,000 feet. Cost-effectiveness varies in different areas.

Wohlford said, for example, there are areas in the Middle Atoka where it will take seven to 12 days to drill a 7,000-foot well. Even though the wells are shallower in the Fairway, it will take longer to drill due to the nature of the site.

“Your drilling days are directly proportional to cost,” Wohlford said. “What equalizes things is that the reserve potential in the Fairway is normally higher than in the Middle Atoka play.”

Future Production

A decade ago, natural gas was selling for $2 per thousand cubic feet, and now it’s more like $6 per thousand cubic feet, Robbins said.

“Now, with the higher-price environment we’ve been able to spread out a bit and explore more efficiently,” Robbins said.

Selling gas has gone from a long-term contract business to marketing the product by the day or even hourly, he said.

Ed Retchford, geology supervisor for the Arkansas Geological Commission, said the “hot” prospect in the Arkoma Basin right now is the Fayetteville Shale play being pursued by the exploration division of Southwestern Energy Co.

“They are looking at an entirely different unconventional target for gas production,” Retchford said. “It lies underneath the Pennsylvanian section that has produced for the last 100 years.”

To date, Southwestern has drilled 16 wells in its Fayetteville Shale play and plans to drill 160 to 170 wells in Fayetteville Shale in 2005. That’s compared to the 86 it plans to drill in the rest of the Arkoma Basin.

“It may add significant value to our land leases in other areas of the basin,” Robbins said.

Retchford said the prospect isn’t without problems, namely less pipeline infrastructure in that area of the basin (eastern). Even though a shale well is drilled at about half the depth of a typical sandstone well, the drilling requires tighter spacing because shale is a tighter rock with less permeability and porosity, Retchford said.