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Coal and shale reservoirs are playing a progressively more important role in unconventional natural gas production and reserves in the United States and worldwide. Shale gas and coal-bed methane now represent 19.4 percent of total dry natural gas production in the United States and 21.9 percent of gas reserves. Shale gas production and reserves exceeded coal-bed methane for the first time in 2008. At first glance coal and shale reservoirs appear to have few similarities and are often treated as separate entities in terms of exploration strategies. Although there are certainly differences between these two reservoir systems, they also have a number of similarities indicating that many, but not all, of the exploration concepts developed for identifying coal-bed methane sweet spots may also be applicable to shale gas reservoirs.

Both coal seams and shale reservoirs are characterized as fractured systems in which the microporous, organic fraction of the coal and the clay and mineral shale matrix have nearly zero permeability. Gas and fluid migration occur through naturally occurring fractures (cleats) in coals and either natural or induced fractures in shales. Natural gas is sorbed to the organic matter in both the coals and shales, but the coals contain more sorbed gas per ton than the shales due to a higher organic content. However, in addition to sorbed gas, shale reservoirs have additional gas stored within the mineral matrix which contributes to additional total gas in the system. This free matrix gas compensates for the lower organic content (relative to coals), and therefore, sorbed gas in shale reservoirs.

Most coal-bed methane wells occur at depths less than 3,000 feet due to permeability restrictions, but the deepest coal-bed methane wells in the world produce from 7,500 feet in the Piceance Basin. Shale gas wells range between 500 feet in the Antrim Shale to 12,000 feet in the Woodford and Haynesville/Bossier shales. Coal and shale reservoirs may contain nearly 100 percent thermogenic or secondary biogenic gases and, regionally, will have a mixing zone that contains both thermogenic and biogenic gas components. Exceptionally high production rates for both coal seams and shales require a certain minimal level of thermal maturity: 0.8 to 1.0 percent in coal beds and more than 1.0 to 1.2 percent in shales.

Recovery factors in coal reservoirs is highly variable ranging from more than 80 percent in high permeability coals to less than 15 percent in lower permeability coal seams; coal seams with less than 1 md permeability are generally not economical. Most commercial coal beds have recovery rates between 30 and 60 percent. Shale gas recovery rates appear to be generally lower than in coal beds, generally ranging between 10 and 20 percent, but recovery rates in the Antrim Shale have been reported to be as high as 60 percent. However, recovery factors for shale reservoirs is more complicated than for coal reservoirs due to the combination of sorbed and matrix gas. Therefore, published recovery factors for many shale plays are still being evaluated indicating that the final range of recovery rates may vary significantly from what is predicted today.

The six key hydrogeologic factors affect coal-bed methane producibility are depositional systems, tectonic/structural setting, coal rank or thermal maturity, gas content, permeability, and hydrodynamics. If all six factors come together in a synergistic way, then exceptionally high coalbed methane producibility may result.

This model was initially developed from three end-member basins that had markedly different properties: (1) Piceance, (2) Powder River, and (3) San Juan basins. The Piceance Basin was characterized by high thermal maturity coal seams (vitrinite reflectance, VR, values exceeding 1.0 percent), exceptionally high gas content (more than 700 scf/ton) values, and low permeability (generally less than 1 md). This low permeability results in marginal production rates over much of the basin. The Powder River Basin is characterized, by thick, laterally extensive coal seams (individual seams >100 ft thick), low thermal maturity (VR values generally <0.5 percent), and low gas content values (generally <32 scf/ton).

However, the presence of exceptionally thick coal seams at shallow depths make drilling costs lower and the economics much better than the Piceance Basin despite the low levels of thermal maturity and gas content values. Therefore, the Piceance Basin represents a high thermal maturity play characterized by predominantly thermogenic gases, whereas the Powder River Basin is recognized as a secondary biogenic coalbed methane play with lower levels of thermal maturity and corresponding gas content ranges.

The prolific San Juan Basin represents an intermediary between the Piceance and Powder River basins. The San Juan Basin is characterized by thick (up to 90 ft net coal) laterally continuous coals of high thermal maturity (VR values 0.80 to 1.5 percent, northern basin). Fresh, meteoric water transported basinward through permeable coal beds has carried microbes that have bioconverted the coal and thermogenic, wet gas components into secondary biogenic methane. This has resulted in fully saturated coals and exceptionally high gas content values (>600 scf/ton) where meteoric recharge has occurred in the northern part of the basin.

These same six hydrogeologic factors can also be applied to shale reservoirs, although the tectonic and structural setting, rock properties, and completion techniques appear to be much more important in shale reservoirs than in coals. As in coal reservoirs, shale gas plays can be characterized using two end members: (1) the Barnett Shale, and (2) Antrim shale, which correspond with the thermogenic (Piceance-type) and secondary biogenic (Powder River-type) plays, respectively. An intermediary, San Juan-type play has not been clearly identified in shale gas plays to-date, but such an intermediary play probably will be less productive than the Barnett Shale due to the physical differences between shale and coal reservoirs. Just as in coal-bed methane, a detailed understanding of the hydrodynamics of the reservoir system will be required to identify potential sweet spots associated with upward flow potential. This is particularly true for the Antrim-and intermediary-type shale gas plays, but understanding hydrodynamics, and the distribution of hydrocarbon and artesian overpressure is an overlooked but important component of shale gas plays.

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