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.


Proppant flowback control research has resulted in the development and commercialization of a family of lightweight deformable particles1,2,3. Deformable particles are currently being used to control proppant flowback in wells by mixing and pumping them together with frac sand at a weight/weight concentration of between 12 - 15 percent. Upon applying a closure stress the deformable particles, distributed evenly throughout the proppant pack, dimple against the frac sand and impart a mechanical drag resistance against flow out of the fracture. Lightweight proppants capable of withstanding closure stress are a natural extension of deformable particle research.

A novel lightweight proppant has been developed for stimulation treatments. This lightweight proppant (LWP) is nearly buoyant in an eleven pound per gallon brine. The manufacturing of lightweight proppant is a two part process4. Walnut hulls, used a generation ago as a lightweight proppant, are impregnated with a strong epoxy or resin and then coated with phenolic resins. The outer coating process of the core-hardened walnut hull is very similar to resin coated sand (proppants). The final product is a lightweight particle with an average specific gravity of 1.25 g/cc.

Laboratory tests were run to determine the closure stress at which a lightweight proppant pack would fall below 100 D. The results were:

  • Untreated walnut hulls - 500 psi

  • Combination of Ottawa Sand/Deformable particles (low stress) - 1,700 psi

  • Light-weight proppant - 3,500 psi

  • Combination of Ottawa Sand/Deformable particles (medium stress) - 6, 200 psi

A graph comparing permeability at various closure stresses of the LWP versus Ottawa and Brady sand can be found in Figure 1. The LWP has adequate permeability at low closure stress. Even at closure stresses approaching 4,000 psi it maintains about 75 Darices. The Appalachian Basin has an abundance of low permeability sandstone and in such pay zones the light-weight proppant should provide satisfactory "perm" contrast. In other words, the LWP's permeability in the fracture is many orders of magnitude higher than formation permeability in nearly all cases.

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