Produced water management has been a growing concern, but it has been turning from a liability to a resource. This is due to growing infrastructure driving down the cost of storage and logistics, while frac fluid chemistry has improved. Produced water reuse also has been simplified. Reuse has become bacteria, iron and sulfide control, performed by an oxidizer and some solids control. Most operators are already performing solids control and oil/water separation in their gathering systems.
Reuse systems. Depending on the efficiency of the solids control and oil/water separation, there may be some secondary solids control and oil/water separation included for reuse. These secondary systems vary, depending on the risk acceptance of the individual operator. In general, exclusive of the secondary systems, your reuse program becomes a pit with oxidation and solids control. This oxidation is driven by aeration in your pits, which we discussed last column, and a chemical oxidizer. This simple approach has driven reuse costs down below that of disposal injection wells.
That’s not to say reuse is going to replace disposal injection wells. There will always be the risk of low oil prices reducing completion activity, which reduces demand for produced water reuse. Today, with higher prices, takeaway capacity has reduced completion activity, limiting the opportunity for reuse. With the many risks that can reduce completion activity, there will always be a need for saltwater disposal wells (SWDs); but I digress, let’s get back to reuse and frac fluid compatibility.
Compatibility issues. You may ask, “what’s all the fuss with compatibility” or “what do you mean by compatibility?” Well, there are two categories of compatibility we will discuss: Your fluid’s compatibility with your frac additives, and your frac additives with each other. Your fluid’s compatibility with your frac additives is a question of fluid (i.e. water) quality, which is a blend of produced water from multiple wells and a blend of a brackish water and how it affects the frac additives. The most common problems are associated with scale, iron and bacteria control. What typically happens is that a sample is taken, and someone in a lab determines a dose rate for an additive. This process assumes your water quality never changes, but it does. So, from the beginning, the process is flawed, but assuming it isn’t, what are the concerns? Higher salt content increases friction, so there is a point where you may switch to a salt-tolerant friction reducer (FR). Soluble iron in your fluid, for example, can interact with your FR or scale inhibitor(SI). You need to understand this, and control and monitor for soluble iron. Fluctuating, total dissolved solids (TDS) can mean your SI dose rate is no longer effective or you need more FR; you need to understand this as well.
Then we have frac additives interacting with each other. This is where your biocide reacts with your FR or SI. Developing a frac additive program that assumes you have a stable, consistent fluid may just be the beginning of your problem—you may have interactions between your biocide and FR and SI that you haven’t even evaluated.
So, what’s the answer? You need to first take your fluid, which is a blend, and determine what blend range you expect in the field. You need to try to keep this blend range as narrow as possible. You then need to create goals for important parameters like iron, sulfides, bacteria, possibly sulfates, TDS and TSS. This means you will need some ability for blend control in the field and some form of real-time testing to know you are meeting your quality goals. This now puts you on the road to frac fluid compatibility.
The next step is to review your additives. We mentioned that oxidizers are a common approach to bacteria, iron and sulfide control, but they also interact with FR and SI. You need to determine what residual level of oxidizer you have, and is it degrading your FR or SI. This problem isn’t just oxidizers. Non-oxidizing biocides also interact with FR and SI. So how do I do this?
For FR, you need to do a friction loop test. This test will determine, by showing increases in friction, whether something is degrading your FR. You need to perform this test with each additive, to see if the additives, themselves, are interacting with each other and causing friction increases. For your SI, the best test is the Dynamic Tube Block Test. Some people like using predictive scale model software, but this type of software ignores residual scale inhibitor left in your produced water, which is there. Predictive models also ignore compatibility issues that occur between additives, making your SI ineffective. These two tests will help you determine whether something is degrading your FR or SI. They will also start you on the way to optimizing your chemical use at the frac.
This is a complicated issue, and it requires a much deeper analysis. Blend management isn’t simple. You have a produced water source that is changing from the flowback stage to a more consistent level of TDS. You have multiple wells at different TDS levels and a blend that you never keep consistent, because you’re focused on supplying enough water and less concerned about quality. The result is a highly variable water quality, and this creates compatibility concerns and challenges. You need discipline in your blend management. Use your blend to reduce your SI. Good blending requires some automation and some real-time analysis.
In terms of friction loop and tube block testing, you should perform these at different additive concentrations, so you can see how dose rate affects compatibility. If a change is needed during the performance of the frac, you want to know ahead of time what your dose rate limits should be. We really only have scratched the surface here, but feel free to e-mail me, if you have any questions.
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