Call Art Berman a shale skeptic. It's not that he doesn't think there's a lot of recoverable natural gas deep within the rock. It's just that he doesn't believe producers are being up front about how much it ultimately will cost to recover.
Berman, who holds a master's degree from the Colorado School of Mines, has worked in the energy industry for more than 30 years. His commentary, "Lessons from the Barnett Shale suggest caution in other shale plays," which was published in the August edition of World Oil, has made Berman's findings something of a cause celebre among shale proponents and critics. Basically, Berman thinks the decline rates in shale plays are much steeper than producers have acknowledged.
The U.S. Geological Survey estimates that the Barnett Shale holds an estimated 26 Tcf of recoverable reserves. However, Berman's analysis shows that only around 10 Tcf will be produced, and of that, close to 7 Tcf -- 70% -- will be noncommercial even at $7/Mcf gas prices.
"I've been telling this story for a while, and I'll continue to tell it," Berman told NGI. "I think it's the truth, and I've presented it enough, and people have given me hard questions, which I've answered. It's made me more confident of my findings, as weird as it sounds. Most of the people whom I've presented this to, most people think it's right on. Those that don't have a vested interest in promoting sort of a misleading story."
Berman's research, which is based mostly on his analysis of the Barnett Shale, is at odds with public data presented by some of the biggest shale players in the country. But the consultant, who heads Labyrinth Consulting Services in Sugar Land, outside Houston, contends his analysis is solid.
"The Barnett story hasn't fundamentally changed," Berman said. "We've looked at it and looked at it and looked at it, and it's a marginal play. An average horizontal well in that play has an estimated ultimate recovery [EUR] of less than a Bcf. Some wells are fantastic, some are less than fantastic. But overall the average well has a EUR of 0.95 Bcf.
"Everybody says, 'Look at the core areas, the sweet spots, you're not being fair, you're being negatively selective.' That's totally untrue."
Berman's findings are based on a control group of 2,000 gas wells in the Barnett. He said he selected the wells about two and a half years ago because these were the only wells that had been drilled horizontally and that had enough production history to evaluate at that time. "It wasn't selective," he said. "That's all there were." He recently "relooked" at the redistribution of the wells, and he found that there was a slight bias of the data toward the core areas, because that's what producers first tapped. "The play hadn't really expanded out to the really marginal areas as it has today."
In analyzing the core areas of the Barnett play, "yeah, they're better, but not so much better," he said. "The core areas around Denton, Wise, Tarrant counties [in Texas] are about 25% better than average...In Johnson County [Texas] they're about 15% better. The best wells, all of the best wells, are in those areas. But there are a lot of really crummy wells too."
Just days ago Berman sat down with the vice president of an onshore gas producer with more than 100 Barnett Shale wells. They compared EUR data, and Berman said the executive acknowledged that their evaluation of the Barnett data was similar to his. "He said, 'Honestly, we have about 10 good wells and they carry all the other wells.'"
For this onshore producer, the Barnett's output proved marginal enough that the company chose not to secure acreage in the touted Haynesville and Marcellus shales, Berman told NGI. "He said the land prices were too high and the plays were marginal at best to have to pay tens of thousands of dollars before they made any money."
The Barnett EUR conclusions are "not very interpretive," Berman said. "In the end, the conclusions are that there's not more than 100-200 MMcfe EUR of difference in how you project the remaining months or years of production. I tell people, 'If you don't believe me, double my number. If it's not 0.95, then make it 1.8. It takes 1.5 Bcf to break even at $7 gas. If I'm way wrong, and the average number is higher and you can only make 1.8, I'd say to put your money into a savings account...
"The point of it all is that operators are claiming their wells are making 2.5 to 3.3 Bcf [per] well. Some have wells that make that much. But a lot more wells never make that much."
Many producers operating in the gas shales are using a hyperbolic decline curve in their presentations to investors, he said. A hyperbolic decline curve has three constants: the initial production (IP) rate, the initial decline rate (defined at the same time as the IP rate), and the "hyperbolic exponent," which is the rate of change of the decline rate over time.
"Based on the hyperbolic decline curve, the step rate that gets flatter and flatter, and it almost doesn't decline," Berman said. "The problem with that whole concept is, most of wells do not do that in the Barnett. They decline just like ordinary, run-of-the-mill gas production that we see in hundreds of thousands of wells around the country...
"There's no hyperbolic decline in 95% of the Barnett wells...Hyperbolic decline cannot be supported. It's not real. It's a concept. It's not supported by the underlying wells. I think that people are incorrectly including transient flow in their hyperbolic fitting but that is incorrect"
One prominent shale producer "violates every principle" of the "appropriate hyperbolic decline," in the type of curves it publishes for investors, Berman claimed. "They are not only unsupportable in theory and practice, but if you put them on a witness stand in a group of peers, they'd be drummed out of town. It's beyond theoretical limits."
However, Berman said he wasn't "implying that anybody is being deceptive, or that they are lying. I'm just saying that when they do this kind of group analysis, summing and averaging things, it often gives you a result that doesn't look at all like the underlying work...You can take two different linear trends, and when they are summed and averaged, they look like a hyperbolic decline. The problem is that none of the wells that underlie the type curve look like that."
Berman said, "It's not a question of whether I'm right or I'm wrong. I've explained in painful detail how I do the work. It hasn't been explained how companies and how operators do their work. I've heard their claims, and it doesn't make sense to me or to many others...I've presented my case, and I've explained how I've done it. Where are [the producers]? Why aren't they coming forward and saying how they've done it, and explain how they've done it?"
Berman and his team have begun to analyze the Fayetteville Shale, and so far, "it's just like the Barnett. It's a very mediocre play. Southwestern Energy [the leading producer in the play] does a better job of their wells than other operators I've looked at in terms of EURs...but the wells are still subcommercial."
Yes, he admits that the IP rates on shale wells are "getting better. But if you spend more on fracturing [fracing], you'll get a high IP rate. But so what? What does that have to do with cumulative production or EURs? If you talk to the chief reservoir engineers at the major service companies, they'll tell you that slick water fracs are good for one thing: high IP rates."
It's too early, he said, to do a conclusive EUR analysis for the Haynesville Shale, but "the decline rates are breathtaking...20% a month decline rates for some wells...And they are spending so much money, not $3 million a well like in the Barnett but $7-10 million a well, and leases up to $20,000-30,000 for an acre. Acreage adds a million to well costs. You'll need 6-7 Bcf to break even in the Haynesville.
"A couple of wells have already made 4 Bcf, and that's pretty nice cumulative production, but at $6-7/Mcf, it won't pay out. I'm not saying the Haynesville might not turn around and get better. I hope it does. I'm an explorer, and I do believe operators that survive will figure out how to make money.
"But this 'factory' concept, the 'manufacturing' concept that 'we drill on a grid and maybe do geology and geophysics' is crazy," he said. "Geology and geophysics are what they need to do. The party line now is, 'We've got 100,000 acres and it's all good.' But these are reservoirs are not homogeneous and isotropic..."
"It's all a question of money when it comes down to it. I have no doubt the gas is there. But there's a big difference between resources and reserves. Whether we have 100 years of gas ultimately becomes a question of if we can produce it commercially and my sense is, based on that primary consideration, I believe that a number of companies' claims are exaggerated. I don't doubt that many of the claims by companies are legitimate. But producers have to be careful about how they distinguish the technically recoverable resources from reserves. Reserves have to be commercial, and not just producible, on a full-cycle cash flow basis."
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