Unconventional gas reservoirs in the United States are hinting at mind-boggling reserves.

Unconventional resources have been around for a long time. In fact, the first commercial hydrocarbon production in the United States was a Devonian Shale gas well drilled in Fredonia, N.Y., in 1821, some 40 years before Col. Drake drilled his famous Pennsylvania oil well. Indeed, by 1926, the Appalachian Devonian Shale play was quoted as the largest known occurrence of natural gas in the world. Surely technology and know-how should have allowed us to fully exploit gas shales by now. So why have oil companies waited so long to "discover" tight gas, coalbed methane and gas shales and commence their widespread development?
There is not a single answer to this question. Figure 1 charts annual production from the current significant continuous unconventional plays through 2003. Updating this to the present would undoubtedly show acceleration in total production rates. The continuous plays have the characteristic that they cover large areas and can be exploited by simple pattern drilling. While productivity does vary from area to area, dry holes are not anticipated except for mechanical reasons. This is a very different risk profile than for conventional resources, which require a number of dry holes to be drilled for each discovery.
Note that 1990 marked the start of the unconventional production acceleration. This was a period of generally modest gas prices, in the US $1.50/Mcf to $2.25/Mcf range, and it was not until about 2000 that gas prices started their ascent. So we cannot go back to 1990 and say prices were the driver. However, the presence of Section 29 tax credits (or perhaps their impending expiry) was a powerful incentive and perhaps is the main reason that the United States has come so far with unconventional development while the rest of the world has had little activity.
Tight sands
So called "basin-centered gas deposits" are a class of tight sands which display gas-bearing sequences that may be several thousand feet thick. Early attempts to produce these sands were confronted by very poor flow rates and rapid declines. Commercial development did not occur until the requirement for multi-staged fracturing was understood and the technology fine-tuned for each situation. Once that occurred, pattern drilling commenced, and economies of scale could occur.
Another interesting phenomenon is observed: As development progressed, the average recovery per well increased, and basic economics also improved. This is observed in most unconventional plays and is related to the large-scale nature of developments involving thousands of wells, allowing the ability to reduce per-unit costs and fine-tune technologies. In other words, because of the initially marginal nature of the economics, operators must make their own luck.
In the Piceance Basin's Mesaverde play, initial per-well recoveries averaged about 0.5 Bcf. As the play evolved, average recoveries in the same valley area improved to 1.5 Bcf/well, a threefold increase. This immediately raises the question - can this kind of improvement be anticipated to continue in the future? Since we are dealing with a gas-bearing column more than 1,000 ft (305 m) thick, there is a lot of gas initially in place, in this case probably around 150 Bcf/sq mile. Recovery of this gas depends upon two factors: the recovery per well and the number of wells drilled in each square mile.
Conventional gas well spacing starts at 640 acres, or one well per square mile. So early wells that recovered 0.5 Bcf on a 640-acre spacing recovered less than 1% of the gas in place. As time passed, it was recognized that such low recoveries meant that tight gas wells probably drained a small area, and this justified downspacing. As each section was infilled with more wells, it was noticed that not only did the wells not interfere with each other appreciably, but improving know-how and technology refinement actually improved per-well results. In the Piceance, spacing is now down to 10 acres, which appears to be the level at which adjacent wells start to drain each other, making it the optimal spacing to maximize gas recovery. As a result, we now have 64 wells per square mile and average recoveries of 96 Bcf, representing about 65% recovery factor of gas in place.
Rounding to 100 Bcf/sq mile for discussion purposes, it is understandable how companies that know these plays become very excited. Once the play productivity is proved, large areas can be infill-drilled at low risk, creating a portfolio of thousands of drilling locations and potential reserves additions in the trillions of cubic feet. Once the operation is in place, it is basically a mining operation. Encana has been vocal in promoting this concept. From a reserves addition viewpoint, each round of down-spacing adds reserves equivalent to that which have been developed before, until a spacing is reached where the wells begin to interfere. In the Jonah field in Wyoming, there are ongoing experiments at 5-acre spacing, meaning 128 wells per square mile will be required.
Of course, companies are very nervous about booking such large numbers in the proved category, so it is common to see the reserves quoted as 3P (proved + probable + possible) to acknowledge that it will take many years to drill the thousands of wells needed to produce these large gas volumes, and a lot of things can change in that time. Still, world-class numbers are being reported at the 3P level in the Piceance by Williams Energy (5.5 Tcf) and Encana (7.1 Tcf) and in Wyoming by Ultra (4.7 Tcf).
Shale gas
Despite having the longest tenure as a commercial gas source in comparison to tight sands and coalbed, it is fair to say that shale gas has the most complex production mechanism and is still the most poorly understood. After all, in conventional plays we look for a thick shale for a cap rock to seal the hydrocarbon accumulation. Now we need to produce out of the seal. How is that possible?
The first thing to note is that the productive Paleozoic black gas shales are not mud-rocks, and in fact clay minerals are a minority component. Rather, these shales have a high silica content often comprised of clay-sized silica (dust) floating in a sea of kerogen (organic matter). The silica is often concentrated in thin laminae that are brittle and thus form a storage site and permeability conduit when naturally fractured. The organic matter and clay minerals act as adsorption sites, so the gas content involves both free and adsorbed components. The gas itself is the result of in-situ generation from the organic matter, so the shale is unique in being the source, seal, reservoir and trap all at once with little or no migration. The rocks are "dry," which may assist the ability of gas to flow in a single-phase system. On top of that, the Paleozoic shales are epiric sea deposits, which have widespread and uniform geographic distribution, satisfying the continuous criterion easily. The major unknown is the degree and distribution of natural fracturing. However, once a gas shale play is established by experimenting to find the optimal drilling and completion technologies, large areas can be potentially productive.
The Barnett Shale play in the Fort Worth basin is an example of a current hot development with more than 3,000 wells drilled in recent years, proving multi-Tcf potential. Ultimate recoveries are speculative since the play has not been down-spaced, and re-fracturing has proven effective in accomplishing significant reserves adds. Age-equivalent units such as the Fayetteville Shale in Arkansas are in the early evaluation stages and hold the potential for similar results.
Are they for real?
The answer is a resounding yes.
Perhaps the initial euphoria of early estimates such as 5,000 Tcf in tight sands in the Green River basin have left many people skeptical. But activity in the past 10 years has yielded amazing results measured in Tcf - something nobody would have guessed for the over-drilled onshore United States, and certainly rivaling conventional results. While the pros include multi-Tcf reserves potential and low risk, the cons include the need to drill many wells and employ costly completion technologies, so there is a minimum gas price that is required to justify each play. But in this boom-and-bust industry, that's really nothing new.

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