Robust drilling and production activity in the Eagle Ford, Permian Basin, Granite Wash, and other oil-producing areas of Texas has unleashed high demand for frac water and a surge of produced water as wells come online. A single large Eagle Ford frac job can require as much as 11.5 million gallons of water – enough to submerge a one-acre plot of land under more than 30 feet of water. After the frac job, a sizable proportion of this fluid flows back and must be collected and either disposed of or reused. And after that, once a well begins producing, an average of 10 barrels of produced water will likely accompany each barrel of oil produced.
Texas now produces nearly 3 million barrels per day of crude oil and condensate – more than Mexico or Kuwait. But it must deal with more than 10 times this much produced water each day. Indeed, data from the Argonne National Laboratory suggest that as early as 2007, the state’s oil and gas fields produced a volume of water equivalent to nearly 22 percent of all water used by municipalities in Texas that year. Yet this massive potential resource has – to date – gone largely unused because treating oily, salty water was too expensive.
Now, however, technological improvements, along with economic and regulatory incentives for oil producers to reduce freshwater use in their Texas operations, are changing produced water from a nuisance into a valuable commodity. For instance, Apache Corporation now has produced water recycling operations in several of its Permian basin operations, led by the Barnhart area of Irion County. The company now recycles all produced water from its Barnhart operations and no longer uses freshwater for fracing operations in that area.
Treatment technologies have advanced dramatically in recent years, and treating produced water now costs a fraction of what trucking and disposal does. Fracing is only one potential end use for treated produced water. Some companies may even be able to purify the water to drinking-level quality at a cost still comparable to that at which major Texas cities such as San Antonio have recently acquired freshwater supplies.
Three core factors drive the growth of produced water treatment and recycling in the Texas oil patch.
The first is cost. In early 2014, when the Barnhart recycling program was already well underway, Apache personnel disclosed that it cost the company between $2.00 and $2.50 per barrel to dispose of water in the Barnhart area, but only $0.29 per barrel to recycle it. Apache’s costs are lower because it cleans – but does not desalinate – brackish and salty produced water.
Technological breakthroughs are now on the cusp of allowing salty water to be purified to drinking-level quality at a price roughly comparable to disposal costs in most major oil play areas. For instance, STW says that while it traditionally cost $4.00 to $8.00 per barrel to desalinate oilfield water, its newly licensed Salttech system can do so for as little as $1.50 to $2.00 per barrel. The company claims Salttech can purify “normal” brackish water or seawater into freshwater for approximately $0.14 to $0.15 per barrel ($1,100-$1,350 per acre-foot).
Drought and public perception form the second factor. In June 2013, the water wells supplying the town of Barnhart, Texas, located 90 miles southeast of Midland, went dry. While Barnhart’s water supply woes likely came from drought, not fracing, operators drilling and fracing in the area would clearly face severe public perception problems if they maintained freshwater-intensive operations while the town went dry. As such, recycling programs are driven not only by falling costs, but also by the need to reduce the burden oilfield operations can place on local water supplies.
Water use impacts from fracing tend to be locally concentrated. Researchers at Texas A&M’s Bush School estimate that in the 21-county Eagle Ford region, oilfield water use accounts for nearly 13 percent of all water use in those counties, much higher than the statewide average. The disproportionate use of locally supplied water comes in large part because trucking water is very expensive and permitting long-distance water supply pipelines takes time, risks political opposition, and can run afoul of local groundwater conservation districts’ restrictions on water exports.
Third, regulatory changes that make it easier to treat, transfer, and reuse oilfield produced water have catalyzed activity in the sector. In particular, Texas Railroad Commission Rule 3.8 (which came into effect in April 2013) dramatically reduced the regulatory burden on produced water recycling operations by:
allowing operators to recycle water for fracing oilfield uses without a permit; allowing treated fluids to be stored in cost-effective large pits; allowing the distilled water derived from purifying produced water to be used permit free for “any manner other than discharge to waters of the state”; and allowing operators to transfer fluids for recycling between leases without a permit.
Produced water reuse rates vary across the major oilfields in Texas. As treatment options become cheaper than trucking and injection fees in many areas and favorable regulations coincide with pressure to wean fracing operations off of freshwater use, water recycling rates will likely rise in the major Texas oil plays. Based on the rapid evolution of recycling technologies and increasing value of purified water for resale to farm, industrial, and potentially municipal users, this author believes that within five years, the Texas oil patch could recycle as much as one-third of its produced water. The effects will be profound because wastewater injected down disposal wells is permanently removed from the hydrological cycle, while recycled produced water that is kept above ground will be a net addition to the cycle – a critical contribution in a rapidly growing state struggling with long-term water shortages.