Study Gives Barnett Shale a Revised Future

American Association of Petroleum Geologists (AAPG)

The potential for shale zones as producing reservoirs rather than only seals or source rocks was not high on the minds of operators back in 1981.

The now-legendary oilman George Mitchell had his own ideas.

He determined that the Mississippian-age Barnett shale in the Fort Worth basin in north-central Texas had the capability to be a big-dog producer of natural gas locked within the dense formation.

Following some less-than-impressive drilling efforts yielding lackluster wells, Mitchell assembled a team of experts at Mitchell Energy to work with him to devise the particular hydraulic fracturing technology needed to coax economical production from the Barnett.

No one realized they were embarking on a close-to-two-decade endeavor to attain success.

The Barnett subsequently was dubbed a “17-year overnight sensation.”

But this hugely productive shale can be considered as the virtual lightening bolt that ignited the ensuing U.S. shale boom.

True, even though it continued kicking out massive volumes of gas, the Barnett soon faded from front-page glory as it became overshadowed by the excitement generated by the later shale darlings such as the Marcellus, Eagle Ford and the like – but this old dog still hunts.

Bad News, Good News

The Barnett play once again triggered an onslaught of media attention late in February with the announcement of a new study of the Barnett conducted by the Bureau of Economic Geology (BEG) at the University of Texas at Austin. The study was funded by the Alfred P. Sloan Foundation.

Scott Tinker
Scott Tinker

“I must have done 20 interviews the day after the announcement,” said past AAPG president Scott Tinker, director of the BEG and co-principal investigator of the assessment along with Svetlana Ikonnikova, energy economist at the BEG. “The phone was ringing all day.”

The study’s results indicate that production from the Barnett will decline through 2030 – a fact that many newspapers highlighted – but also that until then there’s still an enormous resource and huge potential, even with the current low prices.

So, is the glass half-empty, or half-full?

Tinker noted that the study integrates engineering, geology and economics in a numerical model that enables scenario testing based on a multiple of input parameters.

In the base case using $4 gas, the assessment forecasts a cumulative 44 TCF of recoverable reserves from the Barnett through 2050 based on already-drilled wells and the wells to be drilled through 2030.

The base case also shows annual production declining in a predictable curve from the current peak of 2 TCF per year to about 900 BCF per year by 2030.

The BEG effort is unique in its approach.

“Other assessments of the Barnett have relied on aggregate views of average production, offering a ‘top-down’ view of production,” Tinker said. “The BEG study takes a ‘bottoms-up’ approach, beginning with the production data from every well and then determining what areas remain to be drilled.”

This “bottoms-up” MO, Tinker said, provides a more accurate and comprehensive picture of the basin.

A Unique Approach

The team examined production from more than 16,000 wells drilled in the Barnett play through mid-2011.

“We divided this into 10 productive tiers, and then divided those by high and low Btu liquids and dry gas,” Tinker said. “What we’re showing is at $3.50 to $4 gas, operators have kind of retreated from the poorer quality rock, tiers 5 to 10, back to tiers 1 to 4 and are drilling fewer wells but still making money because of better rock quality and higher EURs.

“These are good wells because they are in the better areas,” he emphasized, “so the aggregate field production didn’t decline even with fewer wells.

“Drilling in the better rock is cost-effective even at lower prices.”

If you’re wondering how many locations remain before all of the good rock is drilled, the BEG assessment is optimistic.

The forecast is there are a number of locations in what is included in the top half of the tiers in the $4 base case, according to Tinker.

“We looked at every well, all 16,000 wells, and this had not been done before,” he said. “We looked at decline curves on each and the per-well economics. This let us then ask where there are still more locations to drill.

“That’s what’s unique about our work, which included a dozen people working for a year and a half.

“We think this will tighten down the range of error or uncertainty going forward, combining engineering and geology with rigorous economics and then the bottoms-up approach of every well,” Tinker said.

He added that this helps to narrow the range of error, depending on presumptions in the model, noting “we do have assumptions.”

“We’re very clear to call the 44 TCF our base case,” he emphasized. “We can go higher or lower on lots of different assumptions.

“Even if we just let existing wells already drilled in the play decline and not drill another, we would still approach almost 20 TCF total from the Barnett,” he noted. “It has produced about 13 TCF to date, so that would be another seven to eight TCF from wells already drilled.

“We’ll see another 10,000 wells drilled,” Tinker asserted, “and most will be in the better areas because those have been tested now.”

The BEG is on track to complete similar studies of three other major U.S. shale gas basins by the end of 2013.

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