Stimulation treatment designs must provide a delicate balance between completion effectiveness and economical viability. Service company research and development dollars have historically been spent to find the most cost effective treatment fluid for tight, gas-bearing zones. Typically, the focus of this research has been on fracturing fluids and viscous fluid proppant transport.

Thin banking fluids have been proven to be a cost effective fluid for tight gas zones in the Appalachian Basin, but significantly longer and more effective propped fractures are tough to achieve due to poor proppant transport. There are several factors that affect proppant transportation in a fracture, but one most often overlooked is proppant density. In a paradigm shift from focusing on fluid properties for proppant transport to focusing on proppant characteristics for proppant transport, recent technological advances have been applied as a solution for the Appalachian Basin's cost cutting – production enhancement dilemma. In several detailed case histories from New York, Pennsylvania, Ohio and Northern West Virginia, a novel lightweight proppant has been pumped in an effort to achieve the balance of a more effective fracture within tight economical constraints. The treatment effectiveness of the new lightweight proppant will be analyzed to determine if this new technology truly is a cost effective, production enhancing tool for one of the toughest basins to operate in based on well economics.

Stoke's Law calculations indicate that a lightweight proppant with a specific gravity of 1.25 g/cc will have a terminal settling velocity four times less than white Ottawa sand of the same mesh size, 20/40. A simple single phase gas simulator was used to determine initial flow rates and cumulative production for a series of different fracture lengths. It is clear from the simulations that if greater apparent acting fracture lengths can be achieved, flow rates will be increased and reserve-to-production ratios will be decreased.

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