Hydraulic fracturing technology, or “fracking,” in today’s public use of the word, has been applied in the oil patch for more than 60 years, reportedly being used on more than one million producing wells.
There was nary a raised eyebrow from the public in general for much of this time.
Today, as we all know, it has become a kind of household word – either good or bad, depending on who’s talking.
The current brouhaha in California over regulation of hydraulic fracturing versus an outright ban is the latest example of conflict.
(In late September California Gov. Jerry Brown signed into law regulations for the practice that will require permits for those who want to use the technique.)
Controversy aside, it’s now widely recognized that the remarkable hydrocarbon production boom from the various “unconventional” shale formations would not have happened without this dynamic technology.
Reservoir stimulation via injecting large volumes of water with the appropriate additives into the target reservoir zone to enable/enhance hydrocarbon flow is essential to acquire commercial production from these complex, dense rocks.
Long before the shale bonanza, the value of hydraulic fracturing was apparent when it successfully enhanced production early on from conventional tight formations, such as the familiar, long-productive Cotton Valley in east Texas.
These type reservoirs continue to benefit from fracturing applications.
One of the most controversial aspects of this technology is the water itself – and the concerns extend beyond the much-hyped but unproven accusations of contamination of drinking water from the injected fluid.
They include the need to learn more about the amounts of water used and its sources, among other issues.
The shale gas boom was birthed in Texas, where the pioneering, now-famous Barnett Shale play in the Fort Worth region continues producing, joined by numerous other shale plays in the state.
Texans are long accustomed to the use of freshwater for waterflooding, particularly in west Texas. The now-commonplace use of hydraulic fracturing uses far greater volumes of water, from various sources.
This relatively dry state has a burgeoning population placing increased demand on its water supply, while its vital petroleum industry activity will depend on more water in order to continue increasing hydrocarbon production.
A look at the basics of water consumption and use can provide info about what’s happening in the Gulf Coast region – and what’s to come.
The Texas Water Development Board (TWDB) funded a study about hydraulic fracturing and water resources in 2011. This was followed by an update in 2012, funded by the industry, when more plays were available for added data. The study results were passed to the TWDB.
“We have compiled water consumption and use for the year 2011 (about 82,000 acre-feet used) and compared it to an older analysis done for the year 2008 (about 36,000 acre-feet),” said Jean-Philippe “J.P.” Nicot, research scientist at the Bureau of Economic Geology, University of Texas at Austin.
“A private database compiling water use information is complemented by industry data to access freshwater consumption, recycled water use and brackish water use,” Nicot noted.
He emphasized that contrasts in climatic conditions (in the state) control the amount of surface water versus groundwater being used (for hydraulic fracturing) and the reliance on non-fresh water and recycling/re-use.
“Generally, toward the east, more surface water is used,” Nicot said. “To the south and west, more groundwater is used, with a significant amount of this being brackish.
“The amount of recycled water used for hydraulic fracturing is generally low across the state,” he noted.
“An important element on how much recycled water is used for new hydraulic fracturing operations is the amount available for recycling,” he said. “The amount is generally low for producing shales.
“Pore space of productive shale contains mostly hydrocarbons and little water,” Nicot pointed out. “But the shales could produce a significant amount of water if they include water bearing intervals, or if the over- or underlying strata is an aquifer.”
Use Versus Consumption
Industry water use pegged at 82,000 acre-feet (about 80 percent consumed) in 2011 is relatively low compared to state water use of about 15 million acre-feet. In contrast, the state’s water consumption tallies about 12 million acre-feet.
Nicot emphasized the distinction between use and consumption.
“If you’re fracturing a well and you need five million gallons, then that’s used,” he said. “If half of that comes from flowback from another well, then that water is not new but has been used elsewhere.
“Consumed means the amount of water that disappears from the system,” he noted. “Used is the amount of water the industry needs to run its business.
“Consumed is relative,” he said. “The bottom line is, it’s water that is lost to the system.
“How much you need for fracking and how much is new water – that’s the difference,” Nicot stated.
For now, the future annual peak water use is projected as a broad peak that plateaus at approximately 125,000 acre-feet per year during the 2020s. Nicot noted that the addition of other oil and gas industry useage, e.g., waterflooding and drilling, ups the projected maximum water use to about 180,000 acre-feet per year during the 2020-30 decade, with a much lower consumption.
More Work to Do
Nicot and his colleagues continue to work on the water issue overall.
“In this work, we carried out an estimation of water use by the oil and gas industry in Texas as a result of oil and gas produced through hydraulic fracturing,” he noted.
“However, access to actual sources of the hydraulic fracturing water, even in broad terms – such as surface water, ground water, recycled – and to water quality is difficult because the regulatory structure was not focused on those aspects until recently,” Nicot said.
“Interviews and discussions with operators helped fill in the information gap.”