A key argument for fracturing without water is that the water left behind causes damage that reduces long-term production.
It is clear that fracturing does add to the water in the reservoir, with water flowing back often only 30% of what was pumped into the well. Waterless alternatives, which are now all based on natural gas liquids (NGL) or mixtures of oil and carbon dioxide, are designed to flow out with the gas and oil produced, leaving nothing behind.
But there is no way to observe where the fracture water goes in formations, in which water is typically present. And there is little data comparing similar wells fractured with water and alternatives, such as propane.
When Ian Palmer, a petroleum consultant with Higgs-Palmer, looks at the issues, he sees trade-offs.
Water left in the fractures can reduce the permeability of the narrow network of cracks, effectively reducing the area within the fracture network producing oil and gas, while hydrocarbon-based fluids are soon gone.
“Theoretically, water will always be a problem in shale gas, since it causes ‘damage’ by reducing gas permeability. This is due to surface tension or capillary effects, also called wicking or phase trapping,” said Palmer, who has taught the SPE completions, fracturing, and production training class. “In small pores, such as in shale, a lot of pressure has to be applied to remove such water.”
The advantage on this point goes to waterless, he said. But water has the ability to create larger, complex networks of fractures and also deliver more sand or ceramic proppant to some of those cracks to keep them open, Palmer said. Water gets the edge on those points.
Anecdotal evidence from unconventional fields suggests that the relationship between the sort of fluid used for fracturing and production is neither simple nor well understood. For example, Utica shale wells where flowback was delayed to allow the wells to soak for months produced gas at five times the rate of those where flowback occurred immediately after fracturing.