Chlorine Dioxide Corrosion Issues

..."Dissolved hydrogen sulfide (H2S) is the most troublesome acid gas found in flowback water. H2S arises from the growth of sulfate-reducing bacteria (SRB) in the formation. If left unchecked, H2S can lead to equipment and wellbore corrosion. Corrosion byproducts in the form of metal sulfides subsequently precipitate and compromise formation integrity. Additionally, H2S is a hazardous material and creates environmental and safety risks, even at part-per-million levels. H2S can be scavenged from flowback with chemical additives. However, this can quickly become expensive. The best way to mitigate H2S in flowback is by prevention. Many operators add conventional liquid biocides to freshwater/flowback blends at the frack pad to inhibit or slow the growth of downhole microorganisms like SRB and acid-producing bacteria. Successful control of downhole bacteria with conventional liquid biocide is mixed. This is due to a number of factors, including the short half-life of biocides downhole, the inadequate removal of solid nutrients from waters sent downhole that feed microbial growth and the incomplete sterilization of topside water used in fracturing operations.

Chlorine dioxide

One of the most rapidly growing water treatment technologies in the oil field is sterilization by the addition of chlorine dioxide gas to freshwater used in fracturing operations. The practice is borrowed from other industries where chlorine dioxide is used to sterilize drinking water. The appeal of chlorine dioxide is that it is inexpensive and fast-acting. Unlike conventional liquid biocides, chlorine dioxide is a small molecule that can easily penetrate bacterial cell walls and biofilms.

Chlorine dioxide also can be used for treating flowback. Of course, it can be used to kill incipient bacteria in flowback, but this use requires a careful understanding of the chemistry, reaction kinetics and mode of action. Unlike other industries, or even the treatment of freshwater in the oil field, the complex water composition complicates the disinfection of flowback with chlorine dioxide. If not managed properly, competing reactions can dilute or minimize the ability of chlorine dioxide to kill bacteria."...

Now I don't have any experience in fracking water treatment systems, but your TDS sounds very high to me....What treatment system are you using?

..."Water flowing back from the formation will inevitably contain suspended, insoluble particulate matter. If suspended solids remain in recycled water, these will nurture the growth of subterranean microorganisms, cause damage to the proppant/sand pack and negatively affect permeability. To illustrate the significance, consider a fracturing operation that will use 160,000 bbl of a 1:1 flowback/freshwater blend, in which the flowback contains a seemingly small amount of suspended solids, 350 ppm. Left untreated, the blend will deliver nearly 5 tons of solids into the formation.

However, by employing technologies to reduce the level of suspended solids to 10 ppm, the amount of solids going downhole will drop to less than 600 lb. The most common approaches for managing solids are mechanical clarification techniques that include inclined plate separators, centrifuges and filters. Performance of these devices is often enhanced by the addition of supplemental chemical additives."...

https://www.epmag.com/treatment-flowback-reuse-emerging-oilfield-practice-779766#p=2

Thanks for the prompt feedback. Excellent information.

If there is any H2S in the water, it will immediately react with the Chlorine Dioxide to form a soluble sulfate. We monitor H2S closely for safety reasons.

5H2S + 8ClO2 + 4 H2O = 5SO4² + 8Cl- + 18H+

As far as the recycled water, TDS can reach values above 300,000 ppm at times, however flowback/produced water that is commonly reused for Fracturing is usually below 150,000 ppm.

Recycled water usually undergoes, de-oiling, some basic oxidation to remove Iron and Manganese and then a biocide is applied. TDS is mostly left untouched. Solid control via clarifiers or DAF systems is common and at times a settling pond is used to decant solids. Typically TSS is below 30 ppm when water is reused.

The corrosion issues we have seen have been very intense with high pressure iron being damaged beyond repair in a matter of days (+/- 15 days). We are trying to figure out the mechanism.

Chlorine Dioxide alone should not be this corrosive at concentrations below 20 ppm, however Chlorine may, specially in the presence of high amounts of Chlorides. Any data on this "enhanced" corrosiveness would be appreciated.

Regards,

Wow that's really fast corrosion....it almost sounds like electrostatic discharge...

http://www.ogj.com/articles/print/volume-108/issue-41/drilling-production/esp-conclusion-multiple-factors-affect-electrical.html

Is it possible the problem is with high pressure iron bits being sub quality or exposed to ,,,whatever, that would weaken the robust nature of the material in this environment?

Thanks,

I will look at electrostatic discharge phenomena.

<...electrostatic discharge...> in a fluid of 150,000ppm TDS?

I think they meant to refer to electrolytic discharge, a galvanic corrosion issue where there is effectively no resistance in circuit.

What type specifically is the material being corroded?

What is the appearanc of the corrosion? Pictures would be great.

pH ranges?

Describe the typical failure characteristics.

What are the temerature ranges?

You need to check the incoming H2S level, since this gets oxidized to sulfuric acid, which is corrosive in the extreme, and this reaction makes a lot of acid.

The nature of the wetted materials is not stated, nor is the fluid temperature, both of which are highly significant in ensuring corrosion resilience.

It is likely that the dissolved species, which makes the fluid look like rather concentrated seawater as far as can be determined so far, render the fluid somewhat aggressive, and far more so than any additive can impart in addition to the principal dissolved species. Given that the fluid is invariant from that stated in the original post it is the correct selection of the wetted materials that is now open to question.

Materials compatibility databases are widely published, and an example of one is here (usual disclaimer); generally, naval bronze, glassfibre-reinforced polyester and many other plastics are immediately suitable for seawater at ambient temperatures, as are most elastomers.

These databases enable correct selection of wetted materials to be based upon substantial and general practical experience rather than local <...theory...>.

These are typically high pressure jobs, pressures between 10,000 psi and 15,000 are common. The fluid is produced water from oil wells that has undergone some simply treatment. Around 15 ppm Chlorine Dioxide is added on the fly for biocidal control. Water has cooed down to ambient temperature by the time it is used, typically between 80 and 90 degrees.

The material that failed was high pressure treating iron. 3" , 1502 WECO HAMMER UNION, Material is a 4130 Carbon Steel.

We have been doing this type of work with fresh water for years without any abnormal corrosion. Now that we are using more of this produced (recycled) water, we have seen sporadic corrosion events where relatively new iron components were pitted in a mater of weeks, where normally we can get years of service.

Only difference is the high TDS water.

Thanks.

If formerly the same materials were handling the same additions under similar condition, there may be levels of manganese species in the water that were formerly much lower/negligible. Manganese compounds can exaserbate chlorine corrosions such that levels that previously were of little concern without manganese, become problematic.

Good information. We will look into the Manganese concentrations.

Thank you.

No doubt some of others' comments are useful, but are you sure there's anything to blame other than TDS? Going from fresh to water with 50-100,000 ppm TDS is going to exacerbate corrosion risk.

Are there other materials you could consider? Stainless steel isn't perfect even with ordinary sea water, but some types are better than others.

When I was into seawater filtration for downhole injection, 80s N. Sea, pipework was usually cupronickel, which was fine, and internally coated vessels (mostly deep-bed sand filters). That was for pressure up to about 10bar, before the downhole pumps, but if you also have problems with low-pressure stuff it might help. Incidentally filtration was a lot better than 30ppm. Expressed as removal % rather than ppm, typically 95% removal > 2 micron. Raw seawater was only about 5ppm suspended solids. It was given a good slug of chlorine (5ppm) at the winning pumps, which improved filtration no end.

What is the pH of the recycled water, and what are the total free chlorine & chloride levels (or other similar halide) of the made up water?

Do you have means to independently test for ClO2 and HOCl? Best look into that, as it appears you are onto something with mention of improper ClO2 generating conditions.

Of course, the recycled well brines are highly corrosive in their own right. How much H2S is returning with the brine? Is the ClO2 reacting with sour gas and creating some acid that is even more acidic?

Even if none of the usual unusual causes are responsible brine is corrosive just because of the high salt content, with oxygen present.

The pH of the water is usually between 7.7 and 8.0. No H2S was detected and in any case, the ClO2 would immediately react with it as discussed previously.

There is likely a series of different factor causing the increased corrosion. We know the brine will add to the corrosion, obviously chlorine or HOCL in the water will be corrosive as well.

What we are trying to figure out is if there is a synergistic component at work here.

Chlorine + Brine?

Chlorine + Brine + Manganese?

Chlorine + Brine + Manganese +other?

Unfortunately there are several other components added to the water during the frac process, including of course, abrasive proppants (Silica Sand). Fact is the corrosion rates were at least 10 times more than normal (non scientific estimate).

Thanks to all for the input.

Regards,

I agree you should perhaps look for manganese, and possibly other metals that could be in the brine, especially if like manganese, they have multiple accessible oxidation states, thereby possibly turning these into redox catalysts in situ.