James Mason's article concerning Fayetteville shale production profiles is interesting, but my own experience in the play leaves me asking questions (OGJ, Apr. 4, 2011, p. 76). I have no real quarrel with Mason's conclusions but do have some questions. And the answers I get from folks with skin in the game seem wildly optimistic in light of the random walk through the well histories of the properties that I have appraised.
I am a geologist and certified appraiser who values mineral property interests for royalty owners; thus, the choice of wells to run declines on are dictated by the clients and the lands that they own. Certainly, I have to consider both the older wells and wells with dismal histories in addition to some very good wells. Overall, I came to the conclusion that there are very few wells capable of making over 1 bcf, with the typical well with an initial production rate of 1 MMcfd of gas barely averaging 0.5 bcf in calculated estimated ultimate recovery (EUR). Since some percentage of the publically reported reserves are proved, undeveloped (PUD), I have a problem reconciling that with the projections previously made of 30-45 bcf or more per unit (the typical drilling unit under Arkansas General Rule B–43 is 1 sq mile).
Further, while B-43 rules allow for 16 wells/section, the mile-long laterals of the more recent wells should and do produce more gas, but clearly if you drill 16 wells 5,280 ft laterally the wells must be spaced a mere 330 ft apart or otherwise stacked laterally in a zone barely 200 ft thick. So how big is the frac zone?
In presentations to the commission, there are numerous schematics suggesting that fracing zone to be 660 ft in width. I am assuming that the vertical extent of fracing may be less defined, and the cross-section of the hole should indicate an oval with the long axis being lateral from the borehole. The area 660 ft x 5,280 ft is 80 acres, which limits the practical well density to eight per section (unit).
But in the 80 or so declines I ran last year there was clear evidence in several areas that wells were communicating. Each well drilled had a lower EUR than its neighbor. This suggests the wells were perhaps sharing a single fracture system and feeding off each others' fractures. As each well is drilled it finds its part of the unit has already surrendered some portion of the reserves.
That, of course, begs the question. Mason suggested that down-spacing to 10-40 acres/well will impact the EUR of the individual wells. I concur heartily with that and suggest that the law of diminishing returns is being tested.
Further, Mason considers that perhaps these wells might be capable of producing for 40 years and observes refracing should improve the EUR. Even using a power law decline analysis, which should increase the ultimate recovery estimate, the long-term gas production impacts the net present value (NPV) very little. Investors rarely have 40-year timelines. We have 20 years of history in shale plays, and the technology of the past 5 years is radically different from that of the 1990s when this technology blossomed.
I am concerned less about the individual well performance than the ultimate recovery and the NPV. I don't see how increasing well density in long lateral wells will increase the EUR of the unit, and, worse, I don't see how that under the most optimistic of conditions such drilling is economic. You might double the EUR yet increase the NPV by a couple of percentage points only. At current pricing with shale plays booming and the potential for LNG to be imported cheaply, the real question is the price of gas. Few recent articles dare consider the economics of the play at $3.50/Mcf gas, which is what the price has been for some time. And that, in my mind, goes a long way towards explaining why Chesapeake and Petrohawk sold their reserves and acreage for $1.90± and went oil hunting.
Siloam Springs, Ark.