A Haynesville Shale Symposium

Arthur E. Berman and Lynn Pittinger
Reprinted with permission from World Oil, October 2009 issue

Presentations at the GCAGS (Gulf Coast Association of Geological Societies) Haynesville Shale Symposium underscored the great uncertainty about reservoir performance and resulting economic aspects about the play. While operators claim early success based on IP (Initial Production) rates and the impressive cumulative production of a few wells, my coauthor, Lynn Pittinger, and I are concerned about the extremely high decline rates and the lack of evidence for hyperbolic flattening seen for most wells.

Ductility of the reservoir and its subsequent compaction as pressure is reduced suggest that ultimate recoveries may be sub-commercial. Formation damage from the loss of millions of gallons of treatment water to the reservoir is another concern.

“Haynesville Shale and Other Shale Plays—a Symposium” was the opening technical session of the GCAGS Annual Meeting in Shreveport, Louisiana on September 27, 2009. There were many outstanding presentations at the all-day session, a few samples of which follow.

Dan Buller, Principal Petrophysicist for Halliburton’s Southeast Technology Team, explained that the Haynesville is a “soft” shale with low Young’s Modulus and Poisson’s Ratio. Because of this, cross-linked gel fracture stimulations are twice as effective as slick-water stimulations. Subtle increases in shale brittleness due to higher calcite composition are important when choosing zones to perforate and stimulate. Formation damage during stimulation treatment is also a factor in reservoir performance. Fracture stimulations can use as much as 3 to 10 million gallons of water, but only 30% of the fluid is typically recovered.

Li Fan, Chief Reservoir Engineer with Schlumberger Consulting Services, showed simulations that determine critical performance factors in the Haynesville. An abnormally high-pressure gradient (0.7-0.9 psi/ft) distinguishes the Haynesville from other shale plays. It may also explain the extremely high decline rates, as pressure depletion transfers stress to the rock and allows proppant-filled and open fractures to compress, thereby reducing the effective reservoir permeability.

In preparation for my presentation at the meeting, Lynn and I updated our reserve forecasts for the Haynesville Shale. EUR projections were made for 67 wells based on standard rate versus time decline-curve analysis. Major challenges include the limited production history and lack of access to producing pressures. We recognize that our reserve estimates may be somewhat pessimistic because the average decline curve consisted of only seven months of data. Without pressure data, we do not know if for some wells decreasing flow rates represent depletion or flow against high production system pressures.

We forecast a sub-commercial average EUR for the Haynesville Shale because of the extreme rates of production decline. Most wells with an IP of more than 10 MMcfd have a decline rate of 25% per month. The average EUR in our study is 1.72 Bcf/well, compared to the 6.5-7.5 Bcf/well reported by many operators. Only two wells of the 67 evaluated have an EUR greater than 6.0 Bcf. At the same time, seven wells have already produced more than 2 Bcf and one has exceeded 4 Bcf.

Petrohawk has the best well performance with an average EUR of 3.4 Bcf/ well (19 wells evaluated). Chesapeake has the most wells on production (29 wells evaluated) but we project an average EUR of only 1.2 Bcf/well. In our study, one-half of the wells followed an exponential decline trend with little-to-no subsequent flattening. The remaining wells had a low-to-moderate flattening trend modeled by hyperbolic decline. Only wells with the lowest IP rates and EUR predictions followed a hyperbolic decline rate similar to those published by major operators in the play.

Values of the hyperbolic exponent b in our sample set ranged 0.1-0.7 with an average value of 0.26. This is consistent with our findings in the more mature Barnett and Fayetteville Shale plays, but is much less than what is found in operator type decline-curves, where values approaching 1.0 or greater are typical.

The amount of hyperbolic flattening assumed in reserve estimates deserves special attention. A production profile with a 10 MMcfd IP and 25%/month decline in the first six months, and a hyperbolic b exponent of 0.5 reaches an economic limit of 2,000 Mcf/month in six years, yielding an EUR of 2.1 Bcf. The same initial decline rate modeled with a sub-sequent hyperbolic flattening with exponent b=1.0 reaches the economic limit in 45 years with an EUR of 5.2 Bcf.

Constrained to the same initial decline in the first six months, raising b from 0.5 up to 1.0 extends the economic well life by 39 years and raises EUR by 143%. Another important consideration about hyperbolic flattening is that production after 10 years increases EUR by 42% but only increases the net present value by 7% (discounted at 10%/year). Large volumes of gas are included in the finding and development costs that have little impact on the value to investors. Much of what is claimed and apparently booked as reserves is predicated on the assumption of hyperbolic flattening. This cannot be supported by individual well decline-curve analysis, at least not with the production histories given so far.

At some point, shale operators and their auditors must be held accountable based on results. And while it is too early to predict the future commercial outcome of the Haynesville Shale play, there are many reasons to take a cautious approach to drilling. Our concerns that the play may be marginally commercial were shared by many presenters and participants at the recent GCAGS symposium.

Data provided courtesy of IHS Inc. However, the analysis and opinions expressed here are solely those of the authors and do not represent those of IHS or any other organization.