Well Integrity Technical Section

Greetings all,

Question: do you recommend adding corrosion inhibitor to your packer fluid?

We're planning completions with a 27-year design life.  The tubulars exposed to the A annulus (between tubing and casing, below the tree and above the production packer) include Super 13Cr (13-5-2) 95 KSI and carbon steel like P110.  The packer fluid, to be installed in this annulus and left there for life of well (no gas lift, etc) will be ~10 PPG CaCl2 w/ 40% monoethylene glycol (MEG) for hydrate inhibition.  We'll add a biocide and O2 scavenger.  The brine supplier also recommends an amine-based corrosion inhibitor.  This inhibitor sometimes doesn't play well with soft goods like the packer rubber and can be damaging to the formation if there are losses.  I gather some operators are not adding corrosion inhibitors, and some are (?)   

May I ask if you add inhibitor or not, and either way, why?

My thoughts are that without dissolved O2 in the brine, "traditional" corrosion should not be an issue.  But perhaps the inhibitor protects against chloride stress cracking and other possible issues?  I'm not a metallurgist so am out of my depth ...

Thanks in advance,

R

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Ron Nelson
Subsea Completion Consultant
ron@deep-blue.ca
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Ron, 

I'm 100% with you that if you would expect the losses into reservoir at any stage, when packer fluid is introduced into the system, I would better avoid it.

Instead (even that you may already do it, but forgot to mention), spike your pH as high as you can, 10.5-11 range, which will help you to reduce the corrosion rate.

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Sergey Chernenkov
Well Engineering and Operations SME
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Hi Ron

I've worked the past seven years in the Foothill field in Colombia, where conditions are similar to what you described. Our completions are designed for 20–30 years and some wells are already at that age. Tubing is 13Cr and casing is carbon steel. For the annulus we use the following additives: 13 gpt corrosion inhibitor, 0.5 gpt O2 scavenger, 2 gpt biocide, and water. We some times monitor with corrosion logs and results to date have been good.

A few practical points from our experience:

•  We produce gas with ~4% CO2; when there is communication between tubing and annulus, CO2 can dissolve in the brine and lower pH. In our cases the pH drop has not reached a critical level, but higher CO2 concentrations or persistent leaks could accelerate corrosion. We continue using the same formulation for this escenario.
• We haven't seen packer elastomer failures attributable to the annular fluid or inhibitors. However, before adding an inhibitor that may affect, you can perform a compatibility test: immerse representative elastomer samples in your exact annular fluid formulation at reservoir temperature for ~30 days, then inspect for swelling, softening, cracking, or mechanical/property changes.

However if O2 is well controlled and CO2 exposure is minimal, I have listen that many operators run without a dedicated corrosion inhibitor.

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