The extremity of incompatible waters in the oil & gas industry

Who would have thought "waters" could be incompatible? Water is water, right? Well if you're in the Oil & Gas industry, no it's not and the issue can be a very invasive and expensive problem. Incompatibility results in downhole formation scale, downhole equipment scale to throughout the facilities. Calcium Carbonate and Iron Sulfate are more common and result in their own set of complications. However, if an environment is created for Calcium Sulfate, or Strontium Sulfate or worse yet Barium Sulfate (NORM), we have a whole new level of issues. Solutions typically range from HCL acid treatments on the more cost-effective side, to mechanical clean outs, to chemical conversion of the scale both expensive end of options. If the wellbore gets completely plugged off with the more aggressive scales, there goes the investment entirely. I have conversations with my customers every day and up until now there really hasn't been a solution, until now.

Each formation water has a different chemical make-up than the other; these waters are incompatible and a great environment for scale when mixed. Now mix with recycled produce water used in prost frac operations and it's more complicated. In this process the incompatible waters are tested, and a liquid scale inhibitor is deployed to combat all of the aforementioned. Inhibiting the scale versus removing the scale is always more cost-effective. I sell liquid scale inhibitors by the way.

Cost effective until it's not. What do you mean? Remember that liquid scale inhibitor I mentioned? Keep that in mind here (liquid). Drilling well's that may produce from multiple zones unintendedly (is it really a straight line), drilling vertical wells with intended multizone targets or targeted horseshoe/U-turn wells producing from several targeted zones creates a perfect environment for all types of scale (how long does the liquid scale inhibitor stay down there before it completely flows back)? We readily test for this, and the results are all over the place.

Now take this environment and decrease the period between Flow Back to Production, do we, or can we accurately determine how much of that liquid scale inhibitor is remaining in solution to protect our downhole tools and facilities? Why does it matter? It matters because the Production side of operating the well can be hit immediately with decreased production and increased LOE expenses as result of aggressive scale. Up until now, new technology in scale inhibitor chemistry has not made it cost effective enough to justify deploying during completion.

Let's complicate the environment more, due to negative economic factors, smaller diameter sized casing is run with larger ESP's resulting in ineffective cap strings as result of available space in the casing. This means the pump intake is protected but nothing else.

Let's sum this up: incompatible waters (formation/injected), decreased flowback periods, decreasing casing size, while only using a liquid scale inhibitor. So where am I going with this?

The company I work for, Finoric, LLC has developed two types of cost-effective solid-state SOLUTIONS that provides either 1+ years or up to 5 years of scale protection.

• Scalegone Live - 95% highly active, dual phosphorus internally matrix bonded scale inhibitor, 40% more cost-effective versus liquid inhibitor. Slow release providing immediate and long-term protection Scalegone - 80% active, dual encapsulated dual phosphorus internally matrix bonded Slow release providing immediate and long-term protection

Both of these designed to be placed with the proppant during fracturing operations delivering scale inhibitors where they are needed most providing a steady source of scale inhibition. They are both also compatible with all known proppants and aqueous fracturing fluids including slickwater, linear, and cross-linked gels.