use far less water or, in some cases, no
water at all.
Several hydraulic fracturing technologies have been developed over the
past few decades that use little or no
water. In general, waterless fracturing
accounts for less than 3 percent of fracturing jobs in the U.S.
“Even though some of these fractur-
ing methods have been available since
the 1970s, they still simply represent a
niche share of the market,” said Albert
B. Yost II, senior management/technical
advisor for the U.S. Department of En-
ergy’s Strategic Center for Natural Gas
and Oil in Morgantown, W.Va.;
But to move into places that are un-
suitable for–or skeptical of–traditional
hydraulic fracturing, these waterless
methods need to be brought into the
While waterless fracturing is still relatively rare in the U.S., it is more common in operations north of the border.
About 25 percent of the fracturing jobs
in Canada use waterless techniques, and
as many as 40 percent of Canadian horizontal shale wells employ what’s called
“gas-energized” (foamed) fracking. The
method involves using a foamed ;uid
consisting mostly of carbon dioxide,
nitrogen, or methane to deliver both
pressure and the proppant into the underground shale formation.
Water is still part of the foamed ;uid,
however, but it typically is only about
10 to 15 percent of the ;uid.
Gas-energized fracturing has a signi;cant advantage over traditional water-based methods: It requires less proppant, which saves money, and it can can
double oil and gas recovery from a well.
That economic case has led to a surge
in interest in foam-based fracturing in
Expansion Energy, based in Tarry-town, N. Y., has developed an innovative
gas-energized technology that relies on
a cryogenic, non-liquid ;uid phase of
natural gas—also known as cold compressed natural gas. Short for “Vandor’s
Refrigerated Gas Extraction,” Expansion’s VRGE process brings in a mobile
cryogenic plant to a drill site to produce the CCNG from natural gas from
WHAT ARE THE MAIN DIFFERENCES BETWEEN
WATERLESS FRACTURING METHODS?
Albert B. Yost II, senior management/technical advisor for the U.S. Department of Energy’s Strategic
Center for Natural Gas and Oil in Morgantown, W. Va., ran through the options with us.
• NITROGEN;BASED FOAM FRACTURING uses a drill fluid that is mostly nitrogen, surfactants, and 8-25 percent water. Compressed nitrogen and a foaming agent are added to a water-based fracture fluid and injected under pressure. According to Yost, “Foam fracturing is highly suitable for
low-pressure, tight gas formations that are sensitive to water.”
• CO2;BASED FOAM FRACTURING is similar to nitrogen-based foam fracturing but uses compressed carbon dioxide instead of nitrogen. This
process can be limited by the availability of carbon dioxide within reasonable trucking, rail, and pipeline distances of well sites. Chesapeake Energy
recently tested carbon dioxide foam fracturing on a well site in Ohio.
• CO2/SAND FRACTURING uses only sand and carbon dioxide, with no water. A closed-system blender augers sand out of a pressure vessel,
which is then mixed and transported with liquid CO2 down the wellbore. CO2 is pumped as a supercritical liquid instead of a gas and no other additives
are used. This process has been used successfully on hundreds of wells, mostly in Canada.
• STRAIGHT NITROGEN; OR CO2;BASED FRACTURING has been used as an alternative to water-based hydraulic fracturing in shale formations that absorb water and swell, restricting gas flow. The gas is pumped without surfactants or proppant (sand). “This application has also been
successful where the horizontal stress differences make proppant less important, or blockages from previous fracturing fluids need to be removed to
restore production,” Yost said.
• GELLED;LPG FRACTURING uses liquefied petroleum gas (LPG) and sand in a closed-system blender. The system has been used successfully
in South Texas and western Canada. The gelled propane turns into a gas and exits the well along with the natural gas or oil stream produced, eliminating
the need for water to be pumped into a well.