A lot of environmental concerns regarding unconventional oil and gas exploration center around water usage and recycling. From surface evaporation ponds to deep well injections, the industry has long struggled with safe disposal of water that comes as a result of shale exploration. Today we are discussing produced and flowback water purification with Terry Beasy, the Vice-President of Business Development at Heartland Technology Partners.

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INTERVIEW
Produced and flowback water - the
challenge, the solution
Terry Beasy, Vice-President of Business
Development, Heartland Technology Partners
A lot of environmental concerns regarding unconventional oil and
gas exploration center around water usage and recycling. From
surface evaporation ponds to deep well injections, the industry
has long struggled with safe disposal of water that comes as a
Monica Thomas (Shale Gas International: Heartland Technology Partners develops and
markets proprietary wastewater treatment technology. So in the context of shale gas and
oil development this would be flowback and produced water. Can you just briefly explain
what these two types of water are and what is the difference between them?
Terry Beasy (Heartland Technology Partners): Flowback water is the water that immediately
comes back up the well-casing after the fracturing process of a stranded gas formation. Once the
hydraulic fracturing process is completed a percentage of the water used comes back to the surface
in the form of flowback water.
Produced water, on the other hand, is water that remains in contact with the gas reservoir or
formation in other words downhole – and it becomes saturated over time with the constituents that
the reservoir is made of. During production, as the gas comes through the fissures in the formation
and up the well bore, it brings a degree of that water back up with it over time as the well produces
gas. This stops once gas production ceases – the water will no longer be forced up and will stay in
the formation.
MT: And what is the difference between the two types of water in terms of makeup?
TB: To fully understand the chemical makeup of the flowback and produced water, one needs to
understand a bit about how these reservoirs we are trying to tap were formed – many years ago.
result of shale exploration. Today we are discussing produced and flowback water purification with
Terry Beasy, the Vice-President of Business Development at Heartland Technology Partners.

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The once stranded gas reserves are typically a several-year-old underground ocean-bottom. So what
happened at some time in the Earth’s evolvement is the magma from a volcano or other interaction
flowed over the seafloor during that time and captured some water as well as plant and animal life,
along with the salt that may settled out of the seawater, and it encapsulated and stranded that
material. This is the gas that we are tapping into now with new drilling technology.
So if you imagine this reservoir as an old seafloor, with animal and plant material degraded and
pressure-cooked into methane gas, then you will realize that there must be a very saline environment
with trapped water as well. Consequently, when disturb those formations and fracture the rock and
you pump some water into these deposits,
what happens is that the salt and other
items within the formation mixes with
fracture water and becomes saturated in
the water. The longer the water is in contact
with the formation, typically the higher the
salt content of the water.
One way to think about it is in terms of weight. Water in its pure form weighs 8.33 pounds a gallon.
Once you start adding minerals to water, the weight will increase. This is why flowback water will
often be between 8.1 and 9.6 pounds per gallon – because the amount of salt and other minerals in
the formation has weighed up the water so much.
For water that stays in the formation for longer the weight can go up to about 9.6 pounds per gallon
or higher.
Now obviously within the salt in the formation there are also other chemicals like barium, strontium
or iron and they also get dissolved into the water.
So when we look at flowback water – which stays in the formation for a shorter time – it will be
lighter in pounds per gallon and have less downhole constituents than produced water which has
remained for longer in the formation. To take iron as an example; typically flowback water would have
a lower percentage of the iron content than the produced water.
In other words, flowback water is lighter and relatively cleaner than produced water.
MT: With the produced water, obviously it’s highly saline, but my understanding is that it
also contains some radioactive materials like the NORM?
TB: That depends on whether there was radioactive material in the formation or the host rock. There
is a great variation across the various plays in various geologic regions. Some areas will be high in
sodium chloride, while other will be high in calcium chloride. Some areas will be high in barium, some
areas will be relatively low in barium. In the same way, some areas will have a very small amount of
“ ’’Producers began to understand
that the water from a well
that is flowing back could be
put into the next well without
affecting the productivity.

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radioactive material while others will have a little bit more.
However, in general, the radioactivity of the material – which usually comes up in the form of radium
chloride - based on its amount is very, very small.
MT: I understand that with both flowback and produced water there are issues with
disposal. Can you tell us more about the challenges that poses?
TB: One thing to understand is that not all flowback and produced water needs to be disposed of. A
lot of it can be blended with fresh water and immediately reused in fracking operations.
In the early years of the hydro fracturing process there was a concern that reusing the water that
flowed from the formation would impair the formation’s ability to produce gas. Overtime producers
began to understand that the water from a well that is flowing back could be put into the next well
without affecting the productivity of that well.
MT: Would that be untreated flowback water?
TB: Yes. The untreated flowback water is blended with fresh water and then reused as fracturing
fluid. This is to dilute the concentration of chemicals and reduce the salinity of the water.
When it comes to produced water, the only real difference is the amount of salt – or the weight of
the water – with the produced water being heavier than flowback water. This is why producers are
continuing to evolve the technology of blending it with fresh water and reducing the amount of salt
content.
So the industry is continuing to evolve with better water management practices.
MT: With both flowback and produced water being increasingly reused in hydraulic
fracturing, one would be excused in wondering – why do we need to treat this water? Can’t
it just all be reused?
TB: With extensive drilling and fracturing, what ends up happening is the amount of water produced
by the formation exceeds the amount of water required for fracking. There is a considerable surplus
of water. This situation is further exacerbated by the high volume of fresh water that is required to
dilute the water in order to recycle it.
This is what creates the need for the safe disposal of produced water and the industry quickly found
that this situation is a serious liability for the E&P companies. Especially that the early method of
disposal involved storing the water in open surface ponds where natural sunlight and temperature
would evaporate the water. Apart from them posing an environmental risk of leaks or spills, the
rainfall in the area of the Marcellus shale tends to be high enough to offset evaporation making the
solution also very inefficient.

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Another problem was caused by the fact that over time these salts settle, creating a sludge at the
bottom of the impoundments that is then very hard to get rid of. Once the water was pumped out,
you had to go into this lined pond to clean out that sludge and dispose of it, at the same time running
the risk of damaging the lining of the pond.
Disposing of the sludge posed another problem. The material at the bottom of the pond would be
liquid while landfills accept only solid waste. This is why the material would be first mixed with
sawdust or paper pulp to absorb the remaining part of the water and also reduce the radiation.
Obviously, adding material to the sludge would increase the volume of the waste thereby increasing
the expense associated with disposing of it.
Altogether, the cost associated with the disposal of the sludge, or the salt, and the cost of relining
the pond along with the environmental liability of the solution, were the main reasons why a lot of
producers have quit using surface impoundments in some areas to store produced water.
MT: So what is the major difference between the evaporation pits and the technology
offered by Heartland?
TB: Our system evaporates the water with all of the constituents – the salts, the radioactive
materials, the iron, and other chemical compounds – in a closed, skid-mounted container eliminating
the risk of contamination or spills – so that’s one big difference.But another big difference with our
equipment is that we operate under different principles than the pond.
What you have to remember is that the salts, the sodium chloride is very water-soluble. So you
could keep adding sodium chloride to water and with a little bit of mechanical motion it will stay in
suspension until the water reaches about 10 pounds per gallon. As you go over 10 pound per gallon,
the salt can no longer stay dissolved in the water so the salt starts to settle out. All the complex
materials - the different salts; the radium chloride, the barium, the sodium chloride, the calcium
chloride, the strontium – they all have a
different level at which they start to settle
out. The calcium chloride, for example, will
stay in suspension above 11 pounds per gallon.
In the old system, some of the salts will remain diluted in the water that is then taken out and
reused in the next well. With our technology we use all of the salts, increasing their concentration to
the point where they start to settle, freeing up the water, which gets rejected into the atmosphere.
MT: Apart from the obvious environmental benefits does your system offer any efficiencies
in terms of costs?
TB: Yes, the environmental benefits are considerable – especially when we compare our Concentrator
with evaporation pits. We store produced water in steel tanks inside a secondary containment – not
“ ’’The industry is continuing
to evolve with better water
management practices.

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affected by rainfall - with double-leak protection to protect the environment. Also, the salts – when
removed from the water – are in a much more condensed, solid form and therefore are stored in a
tank that takes up much less volume, making the disposal cheaper, cleaner, and less risky.
When it comes to other efficiencies, what you need to understand first is that while deep well
injections are an EPA-approved method of disposal of produced and flowback water, the areas
suitable for these injections, in terms of geological structure, are typically at different depths
and may not be where the gas is being explored. This is because gas wells are drilled into rock
formations that are under pressure – otherwise the gas would not be forced to the surface. These
formations are sometimes not suitable for deep injection wells and. If you look at the Marcellus Shale
in Pennsylvania, the closest volume of injection wells is in the state of Ohio. Some states are also
prohibiting deep injection well injection.
Consequently, a lot of the costs associated with deep well disposal are transportation costs.
Our technology works right there at the well-site. To illustrate, let’s take an example of just one of
our machines running. It would process 30 thousand gallons per day of produced water and put out
about 4-5 thousand gallons of the concentrated material that was with the water. So there’s about a
6 to 1 reduction in the cost of trucking. That already is a very considerable saving.
But it’s not only about the costs. The Marcellus formation underlies a mountainous region that
lacks quality roads. So not only do we save our clients’ money on trucking but we also remove the
inconvenience – and potential hazards – of trucking water over long distances on unimproved roads.
MT: I wanted to ask about the adoption-rate of your solutions. Where is this technology
being currently used and where do you see it being used in the future?
TB: Currently this technology is predominantly used in the United States and that can be true both
in oil plays and natural gas plays because modern oil wells are also hydro-fracked and also have a
water component that comes up with the crude oil.
In a lot of different areas the United States leads the environmental scene with regulations from the
EPA and state agencies and, as the shale renaissance spreads worldwide, other countries look to the
U.S. to learn from past mistakes to create a regulatory body to better protect the environment.
As this drive toward shale continues, we are working with European partners to bring our technology
to the emerging gas and oil business worldwide.
Published: 7th September, 2015

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