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 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. 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.
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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 Producers began to understand items within the formation mixes with that the water from a well fracture water and becomes saturated in that is flowing back could be the water. The longer the water is in contact put into the next well without with the formation, typically the higher the affecting the productivity. salt content of the water.
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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
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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 The industry is continuing different level at which they start to settle to evolve with better water out. The calcium chloride, for example, will management practices. stay in suspension above 11 pounds per gallon.
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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
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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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