Realities of shale play reserves: Examples from the Fayetteville Shale

Arthur E. Berman and Lynn Pittinger

When asked about the production life of shale gas wells, Chesapeake Energy CEO Aubrey McClendon recently explained, “Yes, that’s 65 years. And I believe that’s our standard across all shale plays, which is actually a pretty interesting point to talk about” (Second Quarter Earnings Call, Aug. 4, 2009).

It certainly is, and it helps us understand the optimistic reserves that operators like Chesapeake claim for these plays.

The reserve levels claimed by operators and analysts for shale plays are difficult to justify by standard decline curve analysis unless production is projected decades beyond any reasonable economic limit. Companies and analysts that take an optimistic view of shale gas reserves commonly show pro forma group decline curves to justify their reserve estimates. The type curves for the Fayetteville Shale predict reserves that cannot be supported by the underlying data.

In order to understand the disparity among reserve estimates for shale plays, Lynn Pittinger and I evaluated the individual decline trends for Fayetteville Shale horizontal wells. We also normalized group-average decline projections for the same well set to understand how the two methods differed. The group curve-fitting approach resulted in higher Estimated Ultimate Recovery (EUR) predictions than the individual decline-curve analysis, but both methods estimated considerably lower reserves than those claimed by major operators in the play.

Southwestern Energy Company is the leading operator in the Fayetteville Shale play with about 700 producing horizontal wells. Southwestern and other key operators claim average per-well EUR of 2-3 Bcf and drilling and completion cost of $3 million per well.

From our decline-curve analysis of about 1,300 individual horizontal wells, we determined that the average EUR for a Fayetteville Shale well is 0.85 Bcf. Southwestern Energy has the highest average EUR at 1.04 Bcf/well, followed by Chesapeake at 0.68 Bcf, Petrohawk at 0.63 Bcf and XTO at 0.59 Bcf. Most of Southwestern Energy’s wells are located on a broad structural nose, and this seems to explain their superior results compared to other key operators with less favorable structural positions.

Next, we estimated average EUR using a group decline “curve-fitting” method. We normalized well rates to their first month of production, and averaged monthly production for wells that were active in each producing month. This approach resulted in an average EUR of 1.3 Bcf/well.

The higher EUR that resulted from the group decline method is produced by an apparent flattening in the hyperbolic- shaped decline trend of the averaged data. We believe that this represents an artifact of the method, and does not reflect true EUR. The decline trends for individual wells are commonly segmented, and follow a steep initial trend and later, a flatter exponential decline. The apparent hyperbolic decline pattern seen in the group-method data probably results from summing many individual wells with this segmented decline profile. The curvature of the resulting hyperbolic group decline curve–determined by the hyperbolic exponent b–results in more flattening of the decline than what is observed in any of the individual wells. Increased rates from the many workovers that occur in Fayetteville Shale wells further contribute to flattening of the group-decline curve.

Consequently, we believe that individual decline-curve analysis provides a more precise accounting of changes in decline trends than group-decline methods. We acknowledge, however, the potential for underestimating reserves using this method because of the lack of publicly available flowing-tubing pressure information and the limited production data for recently drilled wells.

Chesapeake showed a pro forma hyperbolic decline curve for a typical Fayetteville horizontal well in a presentation to investors in October 2008. The well began with an IP of 2.15 MMcfd and had an EUR of 2.2 Bc£ The decline curve has a hyperbolic exponent b value of 1.4, a degree of flattening seen in less than 1% of the individual well trends analyzed. It would take 65 year produce the stated 2.2 Bcf, but most of the individual wells that we analyzed reach an economic limit in less than 15 years. The effect of projecting production 50 years beyond the economic limit adds substantially to the EUR–in this case it almost doubles–but none of the production is commercial past year 15.

The enthusiasm for plays like the Fayetteville Shale is perplexing. It can only be explained by the urgency that companies feel to add large reserves at almost any cost. The reserves claimed by some shale play operators cannot be supported by either the individual or group decline methods that we used in this evaluation. It seems that the most convincing evidence for the success of shale plays should be found in the balance sheets of the various E&P companies rather than in their long-term reserves. Yet many of these companies appear financially tentative with high debt, ongoing asset sales to raise cash, and large impairment writedowns in recent quarterly reporting.

If our evaluation of decline rates is correct, the true reserves of the Fayetteville Shale play will be evident in just a few years. At the very least, it seems appropriate that operators and investors should take a more cautious approach, and abandon the “gas factory” paradigm that dominates shale-play thinking. And one last interesting point to talk about: They must acknowledge the need to reduce both cost and commercial risk through better geotechnical science.


  • Anonymous

    The fact that these wells can be fractured multiple times throughout the life of the well, some frac which have brought the well righ back up to the original IP is an important point not addressed in this article.

  • Dear Anonymous,

    No wells returned to their original IP as far as I am aware unless they had to be re-fraced in the first few months of production. I did not note that any wells returned to their intitial rate while declining the 1,300 horizontal wells in the play. Many returned to or somewhat exceeded the rate before the re-frac, but that is a different case.

    If you send me an e-mail [email protected], we can discuss this and other topics more fully and I can send you graphs and data.


  • David

    I have always marveled at the “economics” of shale plays. The only surprise in your article is that D&C costs average $3,000,000. I would have guessed closer to 4-5.

    In reference to the previous post, at what point is the cost of the “next” frac not recoverable in future production gains? I would bet that would happen long before 15 years have elapsed.

    Thank you for an excellent article.

  • Anonymous

    Sports and other commenters,

    Thank you for your comments. This is a pretty old post. You might want to look at the main blog for more recent information:

    All the best,


  • Commenters,

    Thank you for your comments. This is a pretty old post. You might want to look at the main blog for more recent information:

    All the best,


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