The Appalachian Basin Marcellus Gas Play: Its History of Development, Geologic Controls on Production, and Future Potential as a World-class Reservoir
Published:January 01, 2012
William A. Zagorski, Gregory R. Wrightstone, Douglas C. Bowman, 2012. "The Appalachian Basin Marcellus Gas Play: Its History of Development, Geologic Controls on Production, and Future Potential as a World-class Reservoir", Shale Reservoirs—Giant Resources for the 21st Century, J. A. Breyer
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The Middle Devonian Marcellus Shale play is rapidly evolving into a major shale-gas target in North America with the potential to rival or exceed other established shale plays in terms of production rates, economic potential, and total extent. The Marcellus Shale is one of the largest shale plays in North America, with a potentially prospective area of approximately 114,000 km2 (44,000 mi2). Based on industry drilling trends and reported test rates, two major core areas have emerged, each with its unique combination of controlling geologic factors. The reserve potential for the play is enormous, with estimates ranging from 50 tcf to more than 500 tcf, defining the Marcellus Shale as a major world-class hydrocarbon accumulation.
The organic-rich black shales of the Marcellus Shale were deposited in a foreland basin roughly paralleling the present-day structural front. The Marcellus Shale accumulated in an environment highly conducive to the production, deposition, and preservation of the organic-rich sediments.
Key geologic and technical factors defining the Marcellus Shale play are similar to other shale-gas plays and include thermal maturity, reservoir pressure, play thickness, porosity, permeability, gas in place, the role of natural fracturing, mineralogy, depth, structural style, target landing issues, and the ability to be fractured. One key factor is reservoir pressure, as the Marcellus Shale benefits from a significant overpressured profile in the most prospective areas. The classification of structural setting and style is critical for the identification of natural fracture trends and potential geologic hazards that include faulting and fracturing in structurally complex areas.
Since 2004, coinciding with the initial Marcellus discovery in Washington County, Pennsylvania, more than 7100 Marcellus wells have been permitted or drilled through June 2010 in the Appalachian Basin, and activity is expected to escalate during the next several years. Reported initial production rates for vertical wells range from 0.100 to more than 5.0 million cubic feet (gas) per day (mmcfpd) and from 0.300 to more than 26.000 million cubic feet (gas equivalents) per day (mmcfepd) for horizontal completions. Although the play is still in its infancy, reported production rates and reserves compare very favorably with other established North American shale plays.
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Shale Reservoirs—Giant Resources for the 21st Century
In the early 1970s, most exploration geologists in the United States considered subeconomic or marginally economic petroleum resources such as coalbed methane, shale gas, and tight-gas sands as unconventional resources (Law and Curtis, 2002). Tax incentives and federally funded research beginning in the late 1970s helped make these resources economically viable in the last two decades of the 20th century. Economics aside, two important geologic attributes characterize most unconventional petroleum resources (Law and Curtis, 2002). Conventional petroleum systems are buoyancy-driven accumulations found in structural or stratigraphic traps, whereas most unconventional systems exist independent of a water column and are generally not found in structural or stratigraphic traps.
Shale reservoirs are not new. The first commercial hydrocarbon production in the United States was from a well drilled in 1821 in a shale gas reservoir. By 2000, more than 28,000 wells had been drilled in shale gas reservoirs. Rising gas prices and technological advancements in horizontal drilling and hydraulic fracturing associated with the development of the Barnett Shale led to a boom in shale gas development in the early years of the 21st century. Now the exploitation of shale reservoirs is turning to natural gas liquids, condensate, and oil. Far from being isotropic and homogeneous, as once naively envisioned, shale reservoirs are complexly layered accumulations of fine-grained sediment. Geologic variation on scales ranging from that of stratal architecture to that of lamination within individual beds must be understood in order to locate and exploid areas of higher production within shale reservoirs. Shale reservoirs remain largely geologic plays - notmerely lease plays or strictly engineering plays made possible by improvements in drilling and completion technology.