Low natural gas prices have driven down Fayetteville Shale drilling activity and production, but the Arkansas dry gas play has plenty more to give, and the rigs will be coming back to get it when natural gas has a $5 handle, the Arkansas Geological Survey’s Ed Ratchford told NGI.
“Who wants to go out and drill a bunch of $3 million wells at $3 gas. It’s not that the resource isn’t there; the resource is there. It’s not as attractive,” said Ratchford, who is the Survey’s fossil fuels supervisor. For now, producers have turned away from the Fayetteville’s dry gas, moving into wet gas plays where they can supplement returns with the sale of liquids.
The year-over-year growth rate of Fayetteville production was more than 62% in January 2010 and nearly 97% in September of that year, but has been declining nearly every month since, according to data from the Arkansas Oil & Gas Commission (AOGC) and NGI calculations. Last February, the growth rate turned negative for the first time at minus 1.4%, but in March it was up at 0.2% over March 2012 (see NGI, June 17).
While the rate of production growth has slowed, it’s still growth, and it’s coming despite a significant drop in the number of rigs plying the play. According to the Baker Hughes rig count, there were 12 rigs running in the Fayetteville as of June 14. That’s down 8% from one month ago and 33% from one year ago.
“The continued production growth, in spite of the sharply lower rig count, is explained by the truly remarkable gains in rig productivity and operating efficiencies as the transition towards the full development mode in many areas is beginning to bear fruit,” said an April Arkansas Geological Survey report on the play. “In 2013, Southwestern Energy projects to drill its average well in just 6.5 days, re-entry to re-entry, compared to 11 days in 2010. The comparison is even more impressive given that the average length of the lateral is expected to increase by over 10%.”
Ratchford said the Fayetteville is about one-third of the way to maturity in terms of the number of producing wells it could ultimately support. “The play will accommodate, I think, 20,000 wells and that’s basically looking at 80-acre spacing,” he said. “There’s no point of continuing to drill, saturate everything with a bunch of drilling at these kind of gas prices.”
The leading Fayetteville producers by far, according to AOGC data, are Southwestern Energy Co., BHP Billiton Ltd. and ExxonMobil Corp.’s XTO Energy. During 2012, Southwestern achieved 724.8 Bcf in Fayetteville gas sales, good for 70.3% of the play’s total sales that year. BHP sold 155.7 Bcf (15.1%) and XTO Energy sold 147.9 Bcf (14.3%). The remaining 0.3% of sales, or 2.4 Bcf, was spread among nine much smaller players.
“None of those companies are going anywhere,” Ratchford said. “They’re not going away. They’re not going to have a fire sale on Fayetteville acreage. It’s just that the gas prices are really marginal. Geologists have done too good a job of finding shale gas and we have no national energy policy…to utilize it.”
Last month, Southwestern CFO Robert Craig Owen talked enthusiastically about all that remains to be done in the Fayetteville.
“We have thousands and thousands of well locations,” he said at the UBS Global Oil and Gas Conference (see NGI, May 27). “We’ll be drilling at this pace for many years to come, assuming the [Nymex] strip pricing that we have today. We do plan to drill close to 400 wells this year and that certainly, of all of our operations, can flex more than any others as we need to respond to gas prices, one way or the other.”
Ratchford said most of the people he’s talked with about the Fayetteville say it will take $5 gas to drive producers back to the play again. “People don’t talk about it being in decline at all. It’s just low gas prices. People are just backing off.”
Fayetteville costs have held relatively steady, Ratchford said, but producers have been continually doing more with the same amount of resources. Drilling times have continued to decline while laterals have grown in length and fracturing stages have grown in number. “Completed lateral length has increased 82% over the last four years while holding total well costs flat at about $2.8 million, the Survey report said.
“I’d say it’s still looked at as kind of an early to medium kind of play [as far as maturity],” Ratchford said. “There are so many more high-quality areas left to drill.”
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