NATURAL GAS:

Beyond the boom, unanswered questions about the life of new wells

Second in a series. See the first part here.

As energy companies began to sink horizontal wells into the Barnett Shale of north-central Texas a decade ago, a distinctive production curve appeared that has become a strong visual symbol in the debate about the future of the vast U.S. shale gas resources.

Gas production shot up to 1,600 million cubic feet per day in the first three months of an average Barnett well's life -- four times the top output level for conventional, vertically drilled wells, according to IHS Inc., a leading energy analysis firm.

And then just as quickly, production plunged. After a year's time, output had dropped by half, to 800 million cubic feet daily. The number was down to 200 million cubic feet daily after seven years.

That steeply spiked decline curve with its shrinking tail end is a signature of other U.S. shale plays, a picture that figures critically in the question of how much natural gas will flow in decades to come. The initial burst of new gas from horizontal shale gas wells gives a dramatic boost to supply. But the thinning deliveries in the out years mean that new wells, or reworked old ones, are required to maintain supply.

The issue is, will gas prices be high enough to pay for the continuing exploration, drilling and infrastructure that will be required to keep a growing supply of natural gas coming over decades from shale plays with their distinctive characteristics?

"The bottom line is that there is substantial natural gas" still to be produced from Barnett, said Scott Tinker, director of the University of Texas, Austin's Bureau of Economic Geology, which is probing the prospects of Barnett's shale gas production. He sees plenty of projects coming along in the next few years, even at $4 gas.

"Is there 100 years? Not in the Barnett, unless technology radically changes and/or price goes up tremendously. There is a lot of gas in the Barnett still, but you'd need a very high price to get it or completely different technology.

"So the question is really, at a certain price, how many more wells can be drilled in the field. That limits you to a certain quality of rock. At a higher price, you could open up more of the lower-quality," he said. His team's model, to be released this spring, will allow analysts to assume a certain price, and other key factors, and get a production estimate from a field under that scenario.

While there are still unknowns about the size of the U.S. shale gas resource, the estimates of potential future production are even more chancy, experts agree, given the intersecting imponderables of gas prices, drillers' profits, technology advances and investment strategies in years to come.

The unanswered questions overhang today's debates about exporting liquefied natural gas and becoming overly dependent on natural gas for electricity production. Today's cheap shale gas is pushing more costly energy sources -- nuclear, renewables and biofuels -- further toward the sidelines, making some officials and experts worry about an overdependence on gas.

The sharp inflection points for shale gas wells result from the unique characteristics of the shale gas resource and the methods of producing it, noted John Staub, who heads the oil and gas estimates for the Energy Information Administration. Drillers force water and chemicals under high pressure deep into the earth, fracturing shale rock to create pathways for confined gas or oil to move to well pipes. As pressure drops and the initial flows peter out, the exploration and production company must wait to see what else comes, or drill a new nearby well, or refrack the old one.

"Until you get past that change in slope, you can't quite know what the tail is going to look like. You need 24 months, three years of data, four years of data to get to that point," Staub said. Most shale gas wells are just approaching that age.

Gauging a productive well's life

The only shale gas play with a decade's track record is the Barnett Shale, found more than a mile below the Dallas-Fort Worth region, where the pioneering work of George Mitchell and his Mitchell Energy Co. established the potential of horizontal drilling and hydraulic fracturing.

Shale gas production took off in the Barnett formation around 2005, and by the next year, production totaled 3.1 billion cubic feet a day, a significant fraction of the nation's consumption, averaging 23 bcf per day. The total jumped to 5.6 bcf in 2011 before flattening out last year, according to Bentek Energy reports. January production from Barnett dropped to about 5.3 bcf, said Bentek analyst Ryan Smith.

The economic impact has been dramatic. Gas production from the Barnett Shale added $133 billion to the Texas economy in 2008 alone and has helped create more than 99,000 jobs, according to the industry-supported energyfromshale.com.

"We don't expect a really steep decline. It should be fairly flat for the next five years," Bentek's Smith said. The flattened production results from a sharp reduction in drilling activity, itself the result of low prices, he said. "We believe there are ample drilling locations still in Barnett." But how much of the gas can be profitably produced at natural gas prices below $4 or $6 per thousand cubic feet -- the most common forecast for prices levels in this decade?

Tinker's team at the University of Texas, Austin, is seeking that answer. While Barnett's life has limits, the picture isn't complete unless you add in other basins across the United States where shale gas lies, Tinker said. Stack them together and you get a portfolio of prospects. "And that probably is at least a 50-year, and more likely a 100-year picture. Somewhere in there," he said.

"You have a well, and it has a certain shape of decline. You have a basin, and that's a collection of wells that have been drilled through time. The basin's performance history doesn't look like the decline for a single well because you're stacking a bunch of wells in. Oftentimes, a simplistic mistake that is made is to say the basin is going to decline the way a well does," Tinker said.

Arthur Berman sees it differently. A frequently quoted skeptic of the shale boom, Berman runs Labryinth Consulting in Sugarland, Texas.

About three-quarters of the expected ultimate production from a Barnett Shale well is produced within a well's first five years of life, he said. That indicates a commercial life of less than 15 years, half the productive life of conventional wells.

Could there be positive surprises? "The only way that could be is if a well starts out at high rate, and stabilizes quickly," Berman said.

"If you start at 10 million cubic feet a day and it levels out for a long time at 3 million to 4 million, that's going to be substantial. That's not what we've seen so far," he said. "Based on what we know, in Barnett, Haynesville, Fayetteville, I'm going to tell you the probability of that is very close to zero," he said, naming shale plays in Louisiana and Arkansas. "By the time you get to the tail, the volume is very small."

"In Utica, Marcellus, maybe those have a different decline curve," he said of the Appalachian shale plays. "Then, great. That's a whole new ballgame. But based on what we know, I don't see the tails having a lot of value."

"Who finances the production in the tail?" asks consultant Richard Nehring, president of Nehring Associates Inc. in Colorado Springs, Colo. Who will pay several million dollars to refrack a well if the original well has pulled out the best production from a "sweet spot"? "If you haven't made your money back in three years, or five, you're not going to," he predicts.

Hope from surge of research, technology

The current approaches to re-fracking in the Barnett are only economic in a limited number of cases, Tinker reports.

"To some degree, people are speculating about what happens in second five years, 10 years and beyond. Because this is fairly new development, it's hard -- even in the Barnett," Nehring said.

"We do not have a lot of low-cost gas. We have a reasonable amount of moderate cost gas and quite a bit of high cost gas, anything above $8 to $10" per one thousand cubic feet, Nehring said. He estimates that perhaps 5 to 10 percent of the nation's vast potential gas supply can be developed at current prices for natural gas of below $4 per thousand cubic feet.

Tinker said pessimistic outlooks for shale gas do not take account of gains in horizontal drilling and fracking methods and technology, which are improving results. The most experienced drilling companies have reported lengthening horizontal legs into shale rock, increasing production. Average drilling times are declining, lowering average well costs, industry officials say.

The potential of the shale gas resource is attracting a surge of research, Tinker said. Improved artificial proppants, required to keep open fractured spaces for oil and gas movement, are getting better and cheaper, he said. Research at the university's Advanced Energy Consortium includes work on nanoparticles introduced with proppants in the fracking process, to give a clear picture of oil and gas flows.

"These technologies are changing so fast," said economist Alan Krupnick, director of Resources for the Future's Center for Energy Economics and Policy. "It's an art form on how to get the most gas out of a given well, and we are still in the relatively early stages of learning how to do this.

"It's not worth getting so much into the weeds on an individual set of estimates, because they are likely to be wrong," added Krupnick, who heads an RFF study of shale gas development.

Based on technology changes, which go in one direction, the estimates are likely to be low, he said. "We may also find out some things that lead us to think that we're overestimating, for example, if the decline curves fell more rapidly than we expect.

"Eventually, natural gas prices are going up," he said. Oil prices may come down. Both will interact with changing prices for renewable energy, and advances in energy conservation. Drillers' innovations will lower costs. Unproductive geology may raise costs. Fracking water supplies may become scarce or regulations may shrink opportunities.

"The right question is, how expensive is natural gas going to be relative to alternatives, and what does that portend for other things we care about like energy security, environmental quality and climate change?" Krupnick concludes. The answers will come on their own timetables.