MARCH 16, 2015
Almost 3 million gallons of concentrated salt water leaked
in early January from a ruptured pipeline at a natural gas drilling site near
Williston, N.D. The brine, a by-product of the oil and gas extraction method
known as hydraulic fracturing, spilled into two creeks that empty into the
Missouri River, according to news reports. Although a state health official
said the salty water was quickly diluted once it reached the Missouri, the
spill—large by North Dakota standards—raised questions about the contents of
the brine.
Accidental spills like this one occur with some frequency,
so scientists would like to understand the contaminants they release into
waterways and elsewhere in the environment. Their findings could help officials
guide the cleanup of sites or mitigate damage.
For every well they drill, fracking operators pump 3 million
to 5 million gal of water thousands of feet underground. There, the water opens
fissures in the rock, allowing natural gas and oil to seep out of shale
geologic formations. The water gets mixed with additives such as sand and
surfactants to form fracking fluid, which is used to optimize the amount of
fuel extracted.
But what goes down comes up. Shortly after the water gets
injected, it flows back out of the well. The well releases water over its
lifetime, larger volumes in the early stages and smaller quantities later on.
The early-stage water—the so-called flowback—still contains many of the
additives from the fracking fluid.
As oil and gas production continues, water
from the geologic formation mixes with the fracking fluid, bringing with it
brine and other substances from underground. This “produced water” can be many
times saltier than seawater—the salinity varies with the mineral content of the
geologic formation. The flowback and produced water together make up fracking
wastewater.
Operators have limited options for dealing with fracking
wastewater. In Pennsylvania, for example, operators used to be able to take it
to sewage treatment facilities that could clean it up and discharge it into
creeks or rivers.
Because of regulations the state adopted in 2012, that option
is no longer available. Now, companies transport it to sites where the
wastewater gets injected into wells thousands of feet below the surface and
sequestered there. Alternatively, they can store it and treat it as needed for
reuse in subsequent fracking operations.
Even though these deep-well-injection and recycled-water
holding ponds appear to contain the wastewater, as was the case in North
Dakota, accidents happen. “The concern is, if there’s a spill or accident, it
would be important to know what’s in the wastewater,” says Radisav D. Vidic, an
environmental engineer at the University of Pittsburgh who studies wastewater
treatment methods. Leaks could affect the water quality of nearby rivers, he
adds.
But figuring out the composition is no easy task. The
fracking wastewater is a complex mixture of organics, metals, and radioactive
materials. Some of these substances get put into the water as fracking fluid
additives, some are formed during degradation or transformation reactions, and
some come from the underground geologic formations. Many researchers are
working to identify these components and their relative concentrations.
The biggest question is the organic fraction of the
wastewater. Part of the challenge is that oil and gas companies protect their
fracking fluid recipes as closely guarded trade secrets (see article on page
13). Plus, drilling operators sometimes tweak the ratios of fluid additives on
the fly to improve extraction efficiency. Without knowing what went down the
well, it’s hard for researchers to know what chemicals they should search for
in wastewater.
“You will only find what you’re looking for,” says Thomas
Borch, a chemist at Colorado State University who is studying the degradation
of organics in fracking wastewater. “That’s why we need to understand the
degradation pathways of all these compounds.”
Borch and his colleague Jens Blotevogel, an engineer also at
Colorado State, are focused on biocides in fracking wastewater (Environ. Sci.
Technol. 2015, DOI: 10.1021/es503724k). Companies add these compounds to
fracking fluid to kill microbes that might produce corrosive acid or form
well-clogging biofilms.
“We decided these biocides would be one of the
higher-priority chemical groups because they are inherently toxic,” Borch says.
In their initial studies, they homed in on glutaraldehyde. According to the
database at the FracFocus website—where some oil and gas companies disclose
their fluid additives—it’s the most commonly used biocide.
“We are asking what happens to biocides after they have been
injected into these wells,” Borch says. “How fast are the biocides being broken
down? Are they being broken down to intermediate compounds that we need to be
concerned about? How persistent are they?” If scientists can learn what happens
to biocides deep within fracking wells, they can better predict what types of
compounds will surface in the flowback or produced water, he adds.
Borch and Blotevogel are doing detailed studies in reactors
at high temperatures and pressures to learn how these variables, as well as
salt content and pH, influence the degradation kinetics of biocides. They are
also looking at the effect of the shale itself, because it can act as a sorbent
for many of the compounds in the fracking fluid. They find that glutaraldehyde
polymerizes under the high-temperature and high-pressure conditions expected in
a well. Thus, they need to look for dimers, trimers, or even longer molecules
instead of glutaraldehyde in the fracking wastewater.
In addition to their work on biocides, Borch and Blotevogel
are collaborating with E. Michael Thurman and Imma Ferrer at the Center for
Environmental Mass Spectrometry at the University of Colorado, Boulder, to
identify some of the unknown organic components in fracking wastewater. This
group discovered that ethoxylated surfactants, including polyethylene glycols
and linear alkyl ethoxylates, are major components of flowback (Anal. Chem. 2014,
DOI: 10.1021/ac502163k). Drilling companies add these surfactants to reduce the
surface tension of fluid in the well and improve recovery of oil and gas.
The researchers have developed a database of the surfactants
they’ve found with high-resolution mass quadrupole time-of-flight mass
spectrometry. “We can list all the surfactants we’ve seen by molecular formula
and accurate mass,” Ferrer says. She and Thurman are willing to provide access
to the database to other researchers.
The duo isn’t stopping with surfactants. Thurman and Ferrer
are also using high-resolution mass spectrometry to analyze other unknown
organic components in fracking wastewater, such as biocides and gelling agents.
Going forward, use of this type of high-accuracy technique will be key to
identifying the organic unknowns in fracking samples, they contend. “Any time
your research is going to have a large environmental and economic impact you
have to be absolutely certain that you’re identifying the correct compound,”
Thurman says.
WATER LOOP
Fracking operators sometimes analyze wastewater collected
over the lifetime of a well. From here, it either gets treated and recycled for
use at another well or transported to a disposal site where it gets injected
deep underground.
Jenna Luek and coworkers at the University of Maryland
Center for Environmental Science agree. Using ultra-high-resolution Fourier
transform ion cyclotron resonance mass spectrometry to analyze samples of
wastewater from fracking sites in North Dakota and Colorado, they’ve been able
to demonstrate just how complex the organic portion of fracking wastewater can
be.
“There is a huge diversity of chemicals in the produced
water,” Luek says. “We have identified more than 10,000 mass spec peaks, which
can be assigned more than 2,500 chemical formulas.”
Still others are grappling with the unknown organic content
of fracking wastewater. Andrew R. Barron and Samuel J. Maguire-Boyle of Rice
University have analyzed in detail the organic fraction of produced water from
three fracking sites, each in a different shale formation (Environ. Sci.:
Processes Impacts 2014, DOI: 10.1039/c4em00376d). They used gas chromatography
with mass spectrometry detection.
“Shale oil tends to have very low composition of aromatics,
but it was interesting that we actually saw less than you would imagine,”
Barron says. Produced water has an aromatic odor, he says. “It smells like
xylenes.”
But the Rice researchers didn’t find xylenes. Although they
detected other aromatic and asphaltene compounds, they found far more aliphatic
hydrocarbons, mostly linear and branched alkanes and alkenes with chain lengths
ranging from C3 to C44. All these components come from the geologic formations
underground and are probably remnants from the fuel being extracted.
This variation in the produced waters complicates cleanup
efforts. “If you’re going to clean this water up and reuse it, you’re never
going to have one method that’s absolutely perfect,” Barron says.
To better understand treatment options, Karl G. Linden, an
engineering professor at UC Boulder who collaborates with Thurman and Ferrer,
has undertaken a comprehensive analysis of flowback water from a well in
Colorado (Sci. Total Environ. 2015, DOI: 10.1016/j.scitotenv.2015.01.043). He
and his group have also been exploring the compounds that make up the
wastewater’s smell, looking for more than 180 volatile and semivolatile organic
chemicals typically found in water affected by conventional oil and gas
production.
Unlike Barron and Maguire-Boyle, Linden’s team found xylenes
at detectable levels. Of the other volatile compounds, only acetone and
2-butanone were present in significant amounts. These compounds may have been
added to the fracking fluid as solvents or they may have been produced by
microbes as degradation by-products.
The researchers found fewer than 10% of the semivolatile
compounds they were looking for. They also found a high concentration of
dissolved organic matter. Knowing what’s in the water allows Linden to propose
tailored treatment options. For that particular well in Colorado, his group
suggested that removal of iron and the suspended solids followed by
disinfection was appropriate treatment for water that would be recycled and
used at a new well.
Although little is known about the organic contaminants in
fracking wastewater, researchers have a firmer grip on its inorganic
components. They reflect the metals and ions contained within the geologic formations
underground, rock that is well characterized before drilling. Some of those
constituents can be used to distinguish among flowback waters from wells in
different locales.
The team of Avner Vengosh, an environmental geochemist at
Duke University, uses elements such as boron and lithium to track where
wastewater goes after leaks or spills. “We are trying to establish geochemical
and isotopic fingerprints,” Vengosh says, to follow fracking fluid’s movement
in the environment.
Using thermal ionization mass spectrometry, Vengosh and
coworkers showed that fracking flowback water is characterized by distinctive
isotope ratios of boron and lithium and that these are much different from the
ratios in the small amounts of underground water that gets unearthed from
conventional oil and gas wells (Environ. Sci. Technol. 2014, DOI: 10.1021/es5032135).
With knowledge of a formation’s geochemistry, such signatures could be used to
trace spills or leaks back to particular fracking sites.
Vengosh and coworkers have also found elevated iodide,
bromide, and ammonium in fracking and conventional oil and gas wastewater (Environ.
Sci. Technol. 2015, DOI: 10.1021/es504654n). Iodide and bromide are common
components of the brines found in geological formations. But the ammonium was a
surprise. It was not previously known to be associated with oil and gas
wastewater, Vengosh says.
“The level of ammonium in the produced water from different
formations is highly correlated with chloride,” Vengosh says. That suggests
that the ammonium and chloride are associated with each other in the geologic
formations rather than being added to the fracking fluid during drilling
operations.
They found concentrations of ammonium up to 420 mg per L. In
the event of spills, “ammonium would be very toxic to the ecosystem at the
levels we’re talking about,” Vengosh says.
Aside from the ammonium, the high levels of bromide and
iodide are of interest because these substances are difficult to remove from
water, says William A. Mitch, an engineer at Stanford University who
collaborates with Vengosh. At drinking water plants, they can lead to the
formation of harmful brominated and iodinated disinfection by-products.
Mitch and Vengosh wanted to know at what dilutions fracking
wastewater would be a concern if it got into drinking water supplies. Mitch
diluted fracking wastewater from operations in Pennsylvania with water from the
Ohio and Allegheny Rivers and then analyzed the products formed during
processes, such as chlorination or chloramination, used to disinfect drinking
water.
At dilutions as low as 0.01% fracking wastewater, the
by-products formed during chlorination shifted toward brominated and iodinated
by-products (Environ. Sci. Technol. 2014, DOI: 10.1021/es5028184). “When
drinking water plants use these rivers for drinking water supplies, they run
the danger that during disinfection these halides will become incorporated into
the organic matter and make potential carcinogens,” Mitch says.
Such concerns aren’t merely hypothetical. Pennsylvania
formerly allowed sewage treatment plants to accept, treat, and discharge
wastewater from fracking operations. Jeanne M. VanBriesen, an environmental
engineer at Carnegie Mellon University, conducted a three-year study of anion
concentrations, including bromide, at drinking water intake points along the
Monongahela River in Pennsylvania (Environ. Sci. Technol. 2013, DOI: 10.1021/es402437n).
“We documented significantly higher levels of bromide in the
source water than were typical of inland source waters,” VanBriesen says. “You
typically see bromide in source waters of drinking water plants that are near
the ocean.” At the same time she was working on the Monongahela River, the
Pittsburgh Water & Sewer Authority found elevated bromide in the Allegheny
River.
In April 2011, the Pennsylvania Department of Environmental
Protection requested that shale gas drillers stop sending their produced water
to treatment facilities that discharge into surface waters. When VanBriesen
sampled after that request, she saw a significant decrease in the amount of
bromide. That voluntary ban became mandatory in 2012.
On the basis of her findings, VanBriesen suggests fracking
wastewaters shouldn’t be discharged back into the environment. “They are going
to have unintended consequences because of their concentrations of bromide and
iodide,” VanBriesen says. “People are always saying to me, ‘You’re not talking
about much bromide.’ It’s still enough to have a negative impact.”
In the event of a fracking wastewater leak, scientists don’t
worry just about unknown organic compounds or briny inorganics. They also sweat
the naturally occurring radioactive material within the fluid. This radioactive
material, which comes from underground geologic formations, typically ends up
in solids that get filtered out of the wastewater.
“The concern I have at the moment is that most naturally
occurring radioactive-material-loaded waste is basically discharged into
landfills,” Pitt’s Vidic says. “What happens with the [radioactive material]
that gets deposited in the landfill? Is it going to leach out? How much of a
health hazard is it going to cause for people working at a landfill?”
Much of the naturally occurring radioactive material is
radium. To measure radium content, scientists typically add BaCl2 and H2SO4 to
a sample to coprecipitate the radioactive element out as Ba(Ra)SO4. But Michael
K. Schultz, an associate professor of radiology at the University of Iowa, and
colleagues have found that the method doesn’t work well with fracking
wastewater (Environ. Sci. Technol. Lett. 2014, DOI: 10.1021/ez5000379).
“The concentration of barium is so high, roughly a billion
times more than the radium-226 concentration,” Schultz explains. “It turns into
an unworkable situation when you literally have 9,000 mg per L barium in
solution.” Plus, the high salinity of the Marcellus Shale flowback water
samples his team analyzed makes the radium more soluble and less suited to a
precipitation method.
Schultz and coworkers compared several methods and found
that direct measurement of radium by a method called high-purity germanium
gamma spectroscopy is the best option. But the detector for that technique
costs about $100,000. State regulatory laboratories typically can’t afford one,
he says.
Vidic and coworkers have shown that a cheaper method also
works—inductively coupled plasma-mass spectrometry—to analyze high-salinity
wastewater samples (Environ. Sci. Technol. 2015, DOI: 10.1021/es504656q). The
Ra-226 concentration they measured with ICP-MS matched the results they
obtained with gamma spectroscopy.
The levels of radium in fracking wastewater are high enough
to be of concern, Schultz says. And there are other, “daughter” elements that
form during radium decay to worry about.
In a closed system, such as a holding tank or covered
landfill, “you can’t get away from the daughters,” Schultz says. “The total radioactivity
goes up by a factor of about six in 15 days in a closed system because of the
in-growth of radon and other short-lived decay products.”
But at least one state thinks there’s no cause for alarm. In
January, Pennsylvania released the results of a two-year study on the potential
for radiation exposure from oil and gas development. The study concluded that
the public and workers have little risk of radiation exposure.
These analyses have increased what is known about fracking
wastewater, but each study captures a snapshot of only one part of the process.
Linden of UC Boulder hopes to assemble a more comprehensive picture.
He wants to track how the fracking wastewater changes over
the lifetime of a well. He spent more than 18 months trying to convince
drilling companies to let him work with fracking wastewater over time. Now,
he’s found a partner. A small oil and gas company, which he declines to name,
is allowing his group to follow a fracking operation from beginning to end. He
and his collaborators can sample at each step in the process and take as much
water as they want back to the lab.
“It’s a really amazing opportunity. I don’t think many
people get the chance to be at a well site for six months and take as many
samples as they want,” he says. “Our problem is to figure out how to narrow it
down so we don’t go crazy with data.”
With any luck, their data and those from other studies will
give people a head start the next time there’s a 3 million-gal fracking
wastewater spill.
Source:C&EN NEWS
