Robin Buckner
Price Staff Writer
The miniboom of exploration and development in the Arkoma basin of Arkansas and Oklahoma continues apace.
Spawned by two major gas discoveries within the last 4 years, the Arkoma play has sustained a strong drilling pace in contrast with overall declines in both states.
The basin has maintained a fairly steady level of activity during the last 51/2 years, based on the number of applications for permits to drill (APDS) filed.
The average number of Arkoma basin APDs filed since the beginning of 1986 has varied only slightly, with a low of 41/month during January-May this year vs. a high of 54/month in 1988, reports Dwights Energydata Inc., Oklahoma City. By contrast, the number of APDs filed statewide since first quarter 1986 is down 62% in Arkansas and 54% in Oklahoma.
While as recently as late 1990 there were reports of rig shortages in the area, operators now say contractors are keeping up with the level of permitting.
Cambro-Ordovician Arbuckle and overthrusted Pennsylvanian Spiro-Wapanucka have been the focus of the boom, but older fields in the basin also have benefitted from attention drawn to the area.
Although levels of success experienced in the new plays has varied, most operators agree the basin overall offers at least another 10-20 years of drilling activity.
One key to the fairly constant high level of activity is the increase in gas pipeline capacity in the basin. While few expect a significant hike in overall U.S. gas prices the next couple of years, increased competition among pipelines in the basin has driven up wellhead prices there.
However, there are signs the miniboom may be fading. Lowered reserves estimates of what has been discovered and a lack of success in once promising areas has reined the brisk clip of drilling. One well on the Arkansas side of the basin may prove to be the key to whether the miniboom continues.
WILBURTON ARBUCKLE
Some operators believe the Arbuckle play to date is a disappointment because Wilburton field remains the sole Arbuckle producing area in the basin. Others say the Arbuckle just hasn't been drilled enough in the right spots.
The number of Arbuckle tests being permitted is down compared with last year, and whether or not the deep play rejuvenates may depend on the results of OXY USA Inc.'s 1 Danville USA A, considered by industry a key well in the Arkansas portion of the basin (see map, OGJ, Oct. 1, 1990, p. 34).
In July 1988, ARCO Oil & Gas Co. estimated Wilburton's Arbuckle reserves at 500-600 bcf of gas underlying a 12 sq mile area, or 4250 bcf/well (OGJ, Aug. 1, 1988, p. 28). As of March this year, 14 Wilburton Arbuckle wells had produced about 176 bcf, Dwights reports, and some think the reservoir is half depleted.
A former ARCO employee stands by the July 1988 reserves estimate, but the company won't comment on the issue.
"The bloom is off the Arbuckle flower in Oklahoma," said Calvin L. Badon, vice-president and general manager of Anadarko Petroleum Corp.'s Midcontinent region.
"Some people are a little disappointed in the size of Wilburton. Initial estimates were inflated. Now many people think it's 350 bcf, in that range," he said.
Richard Pratt, Anadarko division reservoir engineer, notes the cut in reserve estimates probably is due to the usual uncertainties in a new field's early development.
Wilburton Arbuckle wells have an extremely high productive capacity. In addition, there were no specific state enforced production limits for the reservoir until the Oklahoma Corporation Commission established field rules at ARCO's request Feb. 1, 1991, retroactive to May 1, 1990.
ARBUCKLE DISAPPOINTMENTS
Badon said since Wilburton's discovery in 1987, Arbuckle tests have been drilled on seismic highs throughout the basin and have come in on structure as expected, but no pay was present.
Amoco Production Co.'s 1 Devil's Backbone about 10 miles southwest of Poteau in LeFlore County, Okla., was drilled on a seismically defined structure, but the reservoir was tight.
Larry Townley, Anadarko's division exploration manager, said Wilburton probably isn't the only productive Arbuckle that will be found in the Arkoma but said his company needs some encouragement.
Other operators are looking for encouragement as well.
One year ago there were nine deep Arbuckle wells permitted across the thrust belt (see map, OGJ, June 4, 1990, p. 60). At the end of May this year there were no deep Arbuckle tests permitted south of the Choctaw fault.
Mobil Oil Corp. recently plugged the deepest well in the basin, its 21,935 ft 1 Green Bay Packaging Co., in LeFlore County.
ARCO lost the hole at 15,910 ft at 1 Ulysses, south of Wilburton, en route to a proposed 20,250 ft in the Arbuckle, Petroleum Information reported.
At last report ARCO was testing Arbuckle perforations in its 2 E.V. Enis in Wilburton field. But the company plans no further development of Arbuckle in the field.
ARCO, which recently acquired the former TXO Production Corp.'s extensive leasehold in the area (OGJ, May 13, p. 38), continues to maintain a commitment to Arbuckle exploration in the Arkoma basin. ARCO plans more Arkoma Arbuckle wells into next year, although one official noted the possibility the Wilburton structure might be unique in the basin.
Operators hope encouraging news about the Arbuckle will come from the eastern end of the basin in Yell County, Ark., where Oxy is drilling below 8,500 ft in its proposed 21,000 ft 1 Danville. Oxy and partners plan to penetrate the entire Arbuckle section and expect to reach projected depth in February 1992.
"We are awaiting the results of that well prior to making any other decisions about the Arbuckle in the Arkoma basin," said Sara Foland, Amoco's eastern Arkoma exploration manager.
Foland pointed out the well will give industry much needed eastern control for the Arbuckle.
Townley said, "Most companies are taking a wait and see attitude about the Arbuckle ... The Danville is a very important well."
SPIRO FAIRWAY
While the jury is still out on the Arbuckle, the overthrusted Spiro-Wapanucka play continues to explode eastward across the basin. It is an expensive play, but potential reserves are good, and it may offer decades of development potential.
A fairway 6 miles wide and 35 miles long has been identified that has potential for offering reserves of 6-30 bcf/well, Townley said.
He cites dramatic improvements in seismic acquisition and processing technology as a key factor in the play's development.
Industry is continually challenged by the play, which first was perceived as possibly a continuous 35 mile stretch of Spiro gas.
John Walker, geologist with Esco Exploration Inc., Tulsa, said operators are becoming more selective about what acreage they acquire and drill, and lease prices are more reflective of potential.
Lease prices remain high in the fairway, typically $600800/acre but sometimes as much as $3,000/acre.
Dry hole costs to drill overthrusted Spiro at 14,00016,500 ft surpass $2 million, while drilling and completing an overthrusted Spiro well costs $3-3.5 million.
Drilling activity is being driven by forced pooling, creating a situation in which working interest owners may be forced to participate in several multimillion dollar wells at one time.
With several wells going, an operator may know one well missed the pay but still has a commitment in an offset, which may already be in progress.
Townley said operators are beginning to rethink the amount of acreage a Spiro dry hole condemns. That's because reservoir properties vary over short distances.
"The ideal situation would be if you could have an identical working interest in all these wells, and just be in all of them," Townley said.
SPIRO ACTION
Anadarko has been in the play since 1988, amassing about 80,000 acres across the basin.
The company plans to participate in as many as 25 development wells and 8-10 wildcats in 1991, all targeting overthrusted Spiro-Wapanucka.
The well that started the play and opened South Hartshorne field, Amoco's 1 Zipperer, produced more than 18 bcf from overthrusted Spiro in its first 2 years on stream, Dwights data show.
Currently there is a flurry of activity around South Panola field and Amoco's 1 Jack Bauman Unit, which flowed about 30 MMcfd of gas from first repeated Spiro at 13,784-834 ft. An east offset, Amoco 1 Raymond Smith Unit, flowed Spiro gas at a rate of 28 MMcfd.
Mobil recently entered the play, staking 1-8 Peachland Creek about 10 miles southeast of Wilburton. Proposed depth is 17,000 ft.
While the thrust of the play is to the east, a few operators continue to search for the southern limit.
AnSon Co., Oklahoma City, has the southernmost producer in the South Panola area to date. Its 1 -1 0 Golden flowed 25.1 MMcfd of gas from Spiro below 15,978 ft.
As of the first week of June, Amoco was logging its 1 -A Last Chance, a proposed 15,500 ft Spiro well about 3 miles southwest of Hartshorne in Latimer County, Okla., Pi reports. Amoco declined comment on the well's likely results, but the wildcat could mark a new southern limit for production in the vicinity.
Townley noted companies are leasing at the south and west ends of the play, and productive limits could very well extend farther south than the current main areas of activity.
MATURE AREA
Development of more mature fields farther north in the basin has been boosted by the more risky play to the south, whose strong gas wells attracted increased pipeline capacity.
Infill drilling in Kinta and Red Oak-Norris fields accounts for most of the activity. The geology is known, acreage costs are typically $200-400/acre, and completed well costs are $400,000 to $1.1 million.
Devon Energy Corp., Oklahoma City, attributes its 75% increase in net production the last 6 years to its infill drilling program in the Arkoma basin.
Devon Exploration Manager Jeff Hall said his company participates in about 25 Arkoma wells/year and encounters few surprises.
The infill program offers a very economic, low risk means to develop reserves that can exceed 10 bcf/well, he said.
Potential pay zones in Red Oak-Norris and Kinta fields include Pennsylvanian Booch, Hartshorne, Atoka, Spiro, and Cromwell at depths of 3,500-11,000 ft. Several Atoka zones are present across the area, and wells with as many as five pay zones have been drilled.
Amoco, the largest lessee in the vicinity, recently completed a dual zone producer in Red Oak-Norris less than 1/2 mile from a well that has produced more than 20 bcf from the same zones, Pi said.
Amoco's 2-9 Yancy, about 4 miles northwest of Red Oak in Latimer County, flowed a combined 12.1 MMcfd of gas from Pennsylvanian Red Oak at 7,495-7,670 ft and Pennsylvanian Fanshawe at 6,980-7,074 ft.
LESS FRANTIC
The pace of activity is a little less frantic in the mature northern area of the basin.
Devon cites long standing, favorable nonconsent clauses in many operating agreements that take some of the force out of forced pooling. The clause allows a lessee to not participate in a well until the operator has recouped 200% of drilling costs and 100% of tangible equipment costs. The nonparticipating lessee can then assume his working interest at no cost.
These agreements and dealing with prudent operators make the play a lot more attractive, Devon said.
Hall noted the burst of Arbuckle activity brought a flurry of new operators to the basin who took farmouts from majors companies and promoted marginal prospects.
"We're back to the solid operators who have been in the Arkoma and will continue to be in the Arkoma," he said.
"I don't see this slowing down. As you drill more wells it always becomes more complex. You start to see the thrust faulting, you recognize additional reservoirs from pressure data, you see greater opportunities. The day will come when it's drilled up, but people said the Arkoma was drilled up in the 1970s."
PIPELINES PROLIFERATE
Lack of pipeline capacity is no longer a deterrent to drilling in the Arkoma basin. A major pipeline project was recently completed, and others are planned for the near term.
There is a significantly greater capability to transport gas from the basin than was available just 2 years ago.
In 1990, Arkla Energy Resources, Shreveport, completed its 36-42 in. Line AC extending 225 miles from eastern Oklahoma to eastern Arkansas, with current capacity of 800 Mmcfd of gas (OGJ, Feb. 11, p. 26).
Arkla plans to increase compression on its AC line to boost capacity to 1 bcfd by third quarter 1991.
Natural Gas Pipeline Co. of America's $51 million, 105 mile AG line was completed in 1990, adding another 350 MMcfd of capacity in the area. NGPC already has plans to increase capacity on that line by 300 MMcfd.
Oklahoma-Arkansas Pipeline Co. plans to increase area transportation capacity by 500 MMcfd with its proposed $273 million, 352 mile pipeline from Pittsburg County, Okla., to Tate County, Miss. (OGJ, Sept. 3, 1990, p. 22).
Meanwhile, Southwestern Energy Co. has begun construction of its $73 million, 258 mile Noark project in Arkansas, with initial capacity of 141 MMcfd. Noark has firm transportation contracts for 91 MMcfd.
TOO MUCH OF A GOOD THING?
There are indications the pipeline boom may be too much of a good thing.
Kidder, Peabody & Co. Inc. disclosed in a stock offering prospectus for Panhandle Eastern Corp., operator and 20% equity interest owner in the Oklahoma-Arkansas line, is "reviewing competitive alternatives to the Oklahoma-Arkansas pipeline project."
A separate Kidder Peabody industry report noted Arkla's AC line was being "underutilized."
Arkla reports current throughput of 500-600 MMcfd in its AC line.
The Kidder Peabody report said deterioration of the Midcontinent-Gulf Coast price differential has resulted in discounting on pipeline transportation volumes.
WELLHEAD PRICES
Wellhead gas prices remain a big question mark for future activity levels.
Increased Arkoma basin gas pipeline capacity has brought increased competition for purchases, and gas prices in the area have risen 4-7/Mcf during the last year, noted Darryl G. Smette, Devon's vice-president of marketing and administrative planning.
"Historically, spot market prices have been lowest in the Rocky Mountains and second lowest in eastern Oklahoma. If you look at what has happened since the AC line went on, you see it's Rocky Mountains the lowest, then western Oklahoma. Eastern Oklahoma has moved ahead of western Oklahoma and is coming up to par with other Midcontinent areas," he said.
Devon typically receives $1.10-1.30/Mcf for Arkoma gas. Smette noted prices usually increase slightly in June, but that didn't happen this year.
He also said Devon isn't bullish on gas prices and predicted it will be next year before prices rebound.
The promotion of natural gas as a clean fuel could have a minor effect on prices by 1993 and a more pronounced effect by 1995, Smette said.
So far, low gas prices don't seem to have affected the pace in the Arkoma.
While the larger companies may, for a limited time, be able to bear the financial burden of low prices, smaller companies must evaluate prospects using current prices.
Competition plays a big part in keeping activity going in spite of low prices. "Our preference would be to wait until gas prices come up,"
Anadarko's Badon said. "it can be economic at a lower gas price, but we all are depending on a future increase in gas prices. If we thought it would forever be this low, we would have to rethink our investment decisions.
"We believe gas will be a very significant part of the energy situation in years ahead. Our company and many others are dedicated to that belief, and with that idea we are out here exploring. But if I could defer it a couple of years, I would."
Copyright 1991 Oil & Gas Journal. All Rights Reserved.