FOCUS: UNCONVENTIONAL OIL & GAS—Unconventional resource estimates subject to uncertainty, future costs

April 2, 2012
Unconventional resource estimates, especially US natural gas resource estimates, have escalated in recent years. Simultaneously, debate about the accuracy of particular shale play resource assessments also has escalated because these assessments have varied greatly among assessors.

Paula Dittrick
Senior Staff Writer

Unconventional resource estimates, especially US natural gas resource estimates, have escalated in recent years. Simultaneously, debate about the accuracy of particular shale play resource assessments also has escalated because these assessments have varied greatly among assessors.

Lawmakers and investors trying to plan for the future would prefer some degree of precision for US gas resources while resource evaluators are far more comfortable talking about the many uncertainties in these estimates.

Shale gas is seen as an important and even game-changing contributor to future supply, but the size of the resource remains subject to discussion and revision.

"There is no rigorous way of summing the range of estimates for a large number of resource plays," said Richard Nehring, president of Nehring Associates Inc. in Colorado Springs, Colo., and chairman of the Committee on Resource Evaluation for the American Association of Petroleum Geologists.

Nehring has studied reserve and resource estimation for 40 years during which time industry witnessed a transformation from the spectre of gas resource depletion to the emergence of enormous unconventional plays.

Noting that his comments to OGJ reflect his opinions rather than the position of the AAPG, Nehring said evaluators can accurately assess the potential of individual plays, which usually involve a substantial range of potential resources with the high-confidence (lower) estimate being only 20-25% of the low-confidence (higher) estimate.

But when resource estimators combine their estimates for individual shale plays, they usually show only the sum of the mean estimates for each play, totally obscuring the great uncertainty associated with each play.

"Just how much gas supply do we have?" Nehring asks. "We can't make policy on the basis of an assumed 100 years of supply. We may have less than 50 years of supply."

It's important to put resource estimates in context, he emphasized, saying people would be better off if they broadened their understanding of resource estimates instead of expecting firm statements offering a single number.

Such an understanding includes acknowledging the profound uncertainties in resource estimation.

Assessment uncertainties

"Traditionally in the evaluation of oil and gas resources, the focus is on field and reservoir numbers and sizes," Nehring said. "Unconventional resource plays do not lend themselves well to such an approach. They are usually continuous accumulations so traditional field and reservoir designations, designed for discrete accumulations, do not work."

Much debate stems from how long the shale plays will produce and at what levels, he said.

"There are a lot of wells with only 2-3 year production history, and we are trying to estimate how they will produce over 20-30 years," Nehring said. "To be honest, nobody knows…. The uncertainty is legitimate."

Variations in ultimate recovery from wells within a play also can make a significant difference in the amount of recoverable resource, he said.

In some shale plays, projections of ultimate recovery might vary from 4-5 bcf/well to 8-10 bcf/well.

Technically recoverable is a forecast of what amount can be produced using existing technology at the time of the assessment. Meanwhile, completion efficiencies continue to improve with advancements in horizontal drilling and hydraulic fracturing. The ultimate recovery per well, combined with price, determines the revenue per well.

Technically recoverable does not necessarily mean economically recoverable.

Long-term resource estimates run the hazard of uncertainty about the effect of economics, especially price fluctuations, on future shale development and production. Nehring said a ceiling cost inevitably is used in technically recoverable estimates, although that figure is not specified in the resource estimate.

"It makes a huge difference to gas producers," Nehring said. "If gas is below $4/Mcf for the rest of the decade, producers counting on $7-8/Mcf will be left high and dry. Some will go out of business."

Any estimates based on future economics "can be tricky," he said. "Costs tend to vary with price. The cost-curve is a dynamic concept, not a static concept."

Although reserve estimates specify the reserves are commercial at current commodity prices, Nehring noted that resource estimates do not have that constraint.

Marcellus assessments vary

The US Energy Information Administration and the US Geological Survey differed widely in their 2011 resource estimates for the Middle Devonian Marcellus shale of the Appalachian basin.

The EIA's Annual Energy Outlook for 2011 estimated ultimate recovery of 410 tcf in the Marcellus shale while the USGS 2011 assessment gave a mean estimate of 84 tcf of undiscovered, technically recoverable gas and 3.4 billion bbl of technically recoverable natural gas liquids.

USGS's gas estimate included a range of 43-144.1 tcf (95% to 5% probability, respectively), and an NGL range of 1.6-6.2 billion bbl (95% to 5% probability, respectively).

In an early release of the AEO2012, EIA said 141 tcf. The agency revised its Marcellus shale estimate using new geologic data from USGS and recent production data.

"EIA's estimate of Marcellus resources is substantially below the estimate used for AEO2011 and falls within 90% confidence range in the August 2011 USGS assessment, although it is higher than the USGS mean value," the agency said. Release of the complete AEO2012 was expected in April.

"Because of the uncertainties inherent in any energy market projections, the reference case results should not be viewed in isolation," EIA said in a Jan. 23 AEO2012 early release overview. "Readers are encouraged to review the alternative cases when the complete AEO2012 publication is released."

Meanwhile, Resources for the Future researchers are examining primary components in estimating shale gas resources, RFF Center for Energy Economics and Policy Director Alan Krupnick told industry representatives in Houston on Feb. 23.

"The two agencies made no attempt to reconcile their estimates before publication. Since then, they have had discussions," Krupnick said of the 2011 Marcellus resource estimates. The same issue could arise again unless the two agencies establish a working group in which they communicate with each other, he said.

Brenda Pierce, USGS spokeswoman, said the two agencies have discussed differences in Marcellus resource estimates, but there is no formal taskforce or working group appointed to do this.

"We do talk to EIA often, but we also really are doing different assessments," Pierce said. USGS provides technically recoverable resource estimates based on current conditions. EIA estimates ultimate recovery. USGS currently has no plans to reassess the Marcellus.

Krupnick attributes the differences in resource assessments to how the two agencies calculate geologic potential, well spacing, and average eventual ultimate recovery.

EIA in its AEO2011 used 8 wells/sq mile while the USGS used 4.3 wells/sq mile. For geologic potential, EIA said 36% weighted average while USGS said less than 50%. For average EUR, EIA said 1.6 bcf/well while USGS said 1.2 bcf/well.

USGS assesses geologic characteristics to determine the potential of untested play areas. It uses well production data and also used EURs from outside the Marcellus to extrapolate EURs inside the Marcellus.

Industry has suggested the USGS method does not fully apply to repeatability, Krupnick said.

EIA cites industry presentations and white papers for well spacing, average EUR, and well success rates. For the AEO2012, EIA will draw on USGS for size of play, geologic potential, and well spacing.

EIA performed its own EUR calculations using production data from 2008-11 only. USGS includes all available results, including prehorizontal drilling in the shale plays.

"The problem is that these wells only have a few years of experience," Krupnick said of shale plays.

He said the new EIA approach might be preferred over the USGS approach because including production before 2008 in estimating decline curves could bias an average EUR downward. Improvements in horizontal drilling technology could increase EUR over time.

Krupnick said shales vary from play to play, field to field, and even well to well within a field. He also said the assessments are not pure engineering because economic assumptions are prevalent throughout the process.

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About the Author

Paula Dittrick | Senior Staff Writer

Paula Dittrick has covered oil and gas from Houston for more than 20 years. Starting in May 2007, she developed a health, safety, and environment beat for Oil & Gas Journal. Dittrick is familiar with the industry’s financial aspects. She also monitors issues associated with carbon sequestration and renewable energy.

Dittrick joined OGJ in February 2001. Previously, she worked for Dow Jones and United Press International. She began writing about oil and gas as UPI’s West Texas bureau chief during the 1980s. She earned a Bachelor’s of Science degree in journalism from the University of Nebraska in 1974.