Duke University Study

Water demand for fracing and flowback, and produced water from fraced wells has soared as longer horizontal wells are being drilled—and if the pace of drilling returns to levels seen a decade ago, future water demand could grow 50-fold by 2030.

Those were the key findings in the analysis of six years of data of water use from more than 12,000 wells in all the major U.S. shale and tight sands plays by researchers at Duke University.

The Duke researchers also combined several databases to estimate the efficiency of both gas-and-oil production and water use. They modeled the data over different future scenarios.

“While the extraction of shale gas and tight oil has become more efficient over time as the net production of natural gas and oil from these unconventional wells has increased, the amount of water used for hydraulic fracturing and the volume of wastewater produced from each well have increased at much higher rates, making fracing’s water footprint much higher,” said Avner Vengosh, professor of geochemistry and water quality at Duke’s Nicholas School of the Environment and a study co-author.

From 2011 to 2016, the water use per well increased up to 770 percent, while flowback (FP) and produced-water volumes generated within the first year of a well’s production increased up to 1,440 percent.

“Recent studies have suggested that intensification of the hydraulic fracturing process through drilling longer horizontal laterals has resulted in increased water use and hydrocarbon production,” the analysis said.


While laterals have increased in length up to 80 percent, helping to bolster production, water use has risen as much as 770 percent. The figures on lateral length and increased water use vary among the basins.

Water demand in a five basins—the Niobrara, Permian, Eagle Ford, Bakken and Marcellus—increased during the six-year period. There was a slight decline in water intensity in the Haynesville Shale, which covers part of Arkansas, Louisiana and Texas.

The analytical model used by the Duke researchers projected that if oil and gas prices rise and production reaches levels comparable to those around 2010, cumulative water use and wastewater volumes could rise up to 50-fold in shale gas-producing regions and by 20-fold in oil-producing regions.

Even if prices and drilling rates remain stable, the models still show a large increase by 2030 in both water use and waste production.

“Previous studies suggested hydraulic fracturing does not use significantly more water than other energy sources, but those findings were based only on aggregated data from the early years of fracing,” Vengosh said.

“After more than a decade of fracing operation, we now have more years of data to draw upon from multiple verifiable sources,” Vengosh said. “We clearly see a steady annual increase in hydraulic fracturing’s water footprint, with 2014 and 2015 marking a turning point where water use and the generation of flowback and produced water began to increase at significantly higher rates.”


Efficiency in drilling has increased production in oil and gas plays, with shale-gas production growing eightfold between 2007 and 2016, and despite the high water intensity of horizontal drilling, the amount of water used for fracing overall nationally is “negligible” in comparison to other industrial water users, the Duke study said.

“On a local scale, however, water use for hydraulic fracturing can cause conflicts over water availability, especially in arid regions such as western United States, where water supplies are limited,” the study said.

The oil-producing Permian Basin in West Texas and New Mexico saw the largest increase in water use, a 770-percent jump, to 42,500 cubic meters of water per well in 2016 from 4,900 cubic meters in 2011. At the same time the length of horizontal wells increased 79 percent to around 2,500 meters. It was the sharpest increase in lateral length among the basins.

The researchers also measured water use for each meter of a lateral well, dividing the amount used by the length of the lateral. By this measure, well-water use in the Permian was up to 29 cubic meters per meter in 2016 from 4.3 cubic meters of water per meter of lateral in gas wells in 2011 and up to 19 cubic meters of water per meter of oil well, a nearly fivefold increase.

Water demand for Permian fracing is projected to grow to 97 billion gallons in 2020 from 29.6 billion gallons in 2016, according to HIS Markit, an energy-consulting group. Last year, a plan by Dan Allen Hughes Jr., CEO of Maverick American Natural Gas LLC, to tap into an aquifer below his 140,000-acre Apache Ranch to provide frac water drew protests from West Texas ranchers and farmers.


Even if prices and drilling rates remain stable, the models still show a large increase by 2030 in both water use and waste production.


“Concern is especially high in semiarid regions, where water withdrawals for hydraulic fracturing can account for a significant portion of consumptive water use within a given region, even contributing to groundwater resource depletion,” the study said. “Overall, there have been calls to increase the use of alternative water sources such as brackish water or recycling FP water, minimizing the strain on local freshwater resources.”

The Marcellus Shale, a natural-gas play in Pennsylvania and West Virginia, had the lowest increase in water use, 20 percent—27,950 cubic meters per well in 2016 up from 23,400 cubic meters in 2011. The increase in lateral length in the Marcellus was 20 percent, similar to the increase in water use.

The Bakken, in North Dakota, has the lowest median water use among the basins, 21,100 cubic feet of water per well in 2016. Water use per well decreased slightly in the Haynesville during the study period.

In all basins, the flowback-water generation was also increasing over time with particularly higher rates after 2014. The study found gas and oil portions of the Eagle Ford region showed a 610-percent increase in FP water in the oil-bearing section reaching 16,900 cubic meters of water per well in 2015 and a 1,440-percent increase in the gas-bearing section to 20,700 cubic meters of water percent well in 2015.


In all basins, the flowback-water generation was also increasing over time with particularly higher rates after 2014.


The smallest increase in FP water occurred in the Niobrara region, where production increased from 1,800 cubic meters per well in 2011 to 2,300 cubic meters per well in 2016, a 28-percent rise.

The produced water over time also presents an environmental challenge as it increases in the concentrations of salts, toxic elements, organic matter and naturally occurring radioactive material.

“Treatment of the FP water to safely return and release to the environment is energy-intensive and expensive; thus, many operators are forced to either recycle the FP water onsite for future hydraulic fracturing operations or reinject it into deep-injection wells,” the analysis said.

spwm jaffe map


There have been multiple environmental challenges in handling frac fluids and produced water that have garnered critics of oil and gas development.

For example, a study by a group of researchers from universities, including Duke, Harvard, the University of Texas and Florida State, looked at wells in Colorado, New Mexico, North Dakota and Pennsylvania and found that 2 percent to 16 percent report spills each year.

Wastewater injection wells have also been linked to a rash of earthquakes in Oklahoma. The state recorded more than 900, many of them small, in 2015.

In another measure of the changing nature of shale-field water management, the Duke researchers calculated the water intensity needed to produce oil and gas by measuring the amount of water to produce a unit of energy by measuring how much water was needed to get a gigajoule. A barrel of oil equals about 6 gigajoules.

The researchers made this measurement during a well’s first 12 months of production, which can account for up to 50 percent of its total output.

The water-use intensity of horizontal drilling and fracing for the first 12 months of a well’s production in 2011 ranged from 7 liters per gigajoule in the Haynesville to 21 liters per gigajoule in the Marcellus. By 2016, the Haynesville figure was 13.5 liters per gigajoules and 33 liters in the Marcellus.

In the oil-bearing Permian, it grew from 11 liters per gigajoule to 28 liters in 2016 to 50 liters per gigajoule in the Eagle Ford in 2015.

For comparison, the researchers said, the average water intensity of conventional natural gas is only 4 liters per gigajoule for drilling and extraction, while coal mining has an average value of 43 liters a gigajoule.

“Water-use intensity is also calculated as the ratio between the volume of water used and the volume of hydrocarbon produced,” the analysis said. “The increase of the water use to hydrocarbon production ratios with time indicates that the intensification of hydraulic fracturing process to increase hydrocarbon production rates involves net addition of water, and thus, the water intensity has increased with time.


The data also showed that the volume of flowback water in the first year in many cases is less than the water used for hydraulic fracturing. The Permian was an exception in this flowback-to-frac-water ratio as its wells produced more flowback than frac water used.


The data showed that the volume of flowback water in the first year in many cases is less than the water used for hydraulic fracturing.


“Regions where the FP water/water use ratios were increasing through time present a growing water management challenge, as the net increase (14 to 770%) in the water use … is coupled with increasing FP water production, growing at even higher rates (60 to 1440%),” the analysis said. “This trend exacerbates water management issues because producers must now manage increasingly large volumes of water for hydraulic fracturing operations as well as larger oil and gas wastewater volumes that need to be adequately disposed.”

While only a fraction of the fresh water used in fracing returns to the surface, the rest remaining in the shale formation, the flowback is highly saline and difficult to treat and is often disposed of as waste. “This means that despite lower water intensity compared to other energy resources, the permanent loss of water use for hydraulic fracturing from the hydrosphere could outweigh its relatively lower water intensity,” the study said.spwm jaffe2Fracing site in the Bakken

There was a “turning point” in 2014 and 2015 as oil prices dropped and producers scaled back on the number of new wells, but increased the water volumes used in wells that were fraced. This meant rates of water use and flowback increased, the analysis said.

Based on increasing trends in both water use and FP water, the study said, “We can see that the overall water footprint of hydraulic fracturing is increasing through time; more water is being used for hydraulic fracturing operations, while, at the same time, comparatively more FP water is being generated.”

The modeling scenarios for the future anticipating a resurgence of drilling activity lead to a projection of up to a 50-fold increase in water demand in shale regions producing natural gas and up to 20-fold in oil producing regions from 2018 to 2030.

“The increase in the water footprint of hydraulic fracturing shown in this study has serious implication for local communities, where increased drilling volume will lead to large instantaneous water demands, and resulting in increasing FP water burdens that will have to be managed into the future,” the study said.

Andrew Kondash, lead author for the study, said that, even if oil and gas prices remain at current levels, the models still predict a large increase in water use and waste production by 2030.

The scenarios also predict particularly high total flowback water production in the Permian and Eagle Ford basins. “The predicted increasing water use and FP water production in the Permian and Eagle Ford basins are alarming given the extreme water scarcity in these regions,” the study says.

Kondash said the study provides “the most accurate baseline yet for assessing the long-term environmental impacts this growth may have, particularly on local water availability and wastewater management.”


Authored by Mark Jaffe