Researchers at the University of Texas at Austin (UT) say they have arrived at a simple method to model decline rates of shale natural gas wells in the Barnett Shale that could also be applied to other plays, as well as oil wells in tight formations.
The researchers came up with “a simple scaling theory” to estimate production from Barnett wells that have been hydraulically fractured (hydrofractured). They relied on 10 years of gas production data provided by IHS CERA.
“With our model at hand, you can better predict how much gas volume is left and how long it will take until that volume will be depleted,” said Tad Patzek, professor and chair in the Department of Petroleum and Geosystems Engineering in UT’s Cockrell School of Engineering. “We are able to match historical production and predict future production of thousands of horizontal gas wells using this scaling theory.”
According to the scaling law for gas wells, production first declines as 1 over the square root of time, and then declines exponentially. “The result is a surprisingly accurate description of gas extraction from thousands of wells in the United States’ oldest shale play, the Barnett Shale,” the researchers said in the paper “Gas production in the Barnett Shale obeys a simple scaling theory,” published this week in the Proceedings of the National Academy of Sciences.
“By analyzing the basic physics underlying gas recovery from hydrofractured wells, we calculated a single curve that should describe how much gas comes out over time, and we showed that production from thousands of wells follows this curve,” said Michael Marder, professor of physics in UT’s College of Natural Sciences.
The same techniques are being used to model declines in the Haynesville, Fayetteville and Marcellus shales, Patzek told NGI’s Shale Daily. He said the “general conclusion” is that the methodology is “absolutely transferable” after making adjustments to account for variances such as different pressures among the plays.
“Haynesville, for example, will be at 10,000 psi while Fayetteville, depending on whether you are shallow or deep, will be much at lower pressure,” he said. “The physical properties of the gas and the rock will change from one shale to another but the same theory…holds.”
Results from the other plays could be available early next year. Look for results from the Fayetteville first, then the Haynesville, followed by the Marcellus.
“It was pleasing and surprising to see that so many wells follow essentially the same master curve, which means that the central theory that we have come up with captures most of the first order physics, the most important physics of the process. That’s very reassuring,” Patzek said.
The methodology could also work for modeling decline rates of oil wells in tight formations, he said. “That’s another thing that we’re working on. In a way, oil production is simpler to model than gas…”
Marder told NGI’s Shale Daily that he’s particularly interested in problems in physics that have to do with the idea of universality. “I think it’s a very powerful idea and often not fully appreciated,” he said. “It’s that systems that look very, very different in superficial ways can sometimes act almost exactly the same if just the minimal conditions are met.
“And that seems to be the case here. Even within a given shale play, there’s every reason to believe that the geometries that you create through the hydrofracturing process are incredibly complicated. And yet at the end of the day, well after well after well acts as if it’s something very simple. I think it’s more surprising that there’s uniformity from well to well within a given play than that the different shale plays would end up being the same.”
Frank Male, a UT graduate student in physics, also participated in the research, which generated estimates about the Barnett that were part of a recent assessment of the play’s reserves released earlier this year by UT’s Bureau of Economic Geology (see Shale Daily, March 1).
Until now, estimates of shale gas production have primarily relied on models established for conventional oil and gas wells, which behave differently from the horizontal wells in gas-rich shales, the researchers said.
They estimate that the ultimate gas recovery from a sample of 8,294 horizontal wells in the Barnett Shale will be between 10 Tcf and 20 Tcf during the lifetime of the wells. The study’s well sample is made up of about half of the 15,000 existing wells in the Barnett Shale.
“We are able to predict when the decline will begin. Once decline sets in, gas production goes down rapidly,” Patzek said.
Production declines happen because of pressure diffusion, which causes pressures around a well to drop and gas production to decrease. The time at which gas pressure drops below its initial value everywhere in the rock between hydrofractures is called its interference time. “On average, it takes five years for interference to occur, at which point wells produce gas at a far lower rate because the amount of gas coming out over time is proportional to the amount of gas remaining,” the researchers said.
Using two parameters — a well’s interference time and the original gas in place — the researchers were able to determine the universal decline curve and extrapolate total gas production over time.
They found that the scaling theory accurately predicted the behavior of about 2,000 wells in which production had begun to decrease exponentially within the past 10 years. The remaining wells examined were too young for the model to predict when decreases would set in, but the model enabled the researchers to estimate upper and lower production limits for well lifetime and the amount of gas that will be produced by the wells.
“For 2,057 of the horizontal wells in the Barnett Shale, interference is far enough advanced for us to verify that wells behave as predicted by the scaling form,” Patzek said. “The production forecasts will become more accurate as more production data becomes available.”
As a byproduct of their analysis, the researchers found that most horizontal wells for which predictions are possible underperform their theoretical production limits. They reached a tentative conclusion that many wells are on track to produce only about 10% of their potential.
Well production could be greatly improved if hydrofractures connected better to natural fractures in the surrounding rock, they said. The process of hydrofracturing creates a network of cracks, like veins, in rocks that was previously impermeable, allowing gas to move. If there are high porosity and permeability within those connected cracks and hydrofractures, then a well is high producing. By contrast, if the connection with hydrofractures is weak, then a well is low producing.
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