Well Integrity Technical Section

Hi dear,

Well is completed with 2-7/8" tubing with SPMs and 7" production casing.

Case 1: Tubing/casing annulus is filled with completion fluid with anticipated 3% CO2.

Case 2: Initiating gas injection containing 3% Co2 with corrosion inhibitor in tbg/csg annulus.

In which case production casing is more vulnerable to CO2 corrosion. Kindly share any SPE or NACE paper on it, if it is available.

Regards

------------------------------
Lajpat Rai
Petroleum Engineer
United Energy Pakistan Ltd
Karachi City
------------------------------

Hi Lajpat,

Dry CO2 is not corrosive, so if you keep water out of it (say <500 ppm) your B annulus should be safe above the liquid surface when injecting. On the other hand if you allow CO2 in a brine you will have corrosion. The rate will depend on partial pressure (i.e. total pressure x3%). I'm not sure how effective you'll be with inhibiting, so unless you have 13Cr production casing I'd say case 1 is much worse.

Mind that having a short gas cap with CO2 is safer than a CO2 saturated completion fluid.

Best regards,

Matteo

------------------------------
Matteo Loizzo
Well integrity consultant
Berlin
------------------------------

The potential for metal-loss corrosion of casing in gas-lift annuli has been a regular question for North Sea oil production where gas lift with ~3 mol% CO2 (+/-) in the gas is common.

Generally....ignoring unknowns such as BHT, completion fluid chemistry, tubing metallurgy, inhibitor use....the experience is that metal-loss corrosion of casing is not a practical problem for gas-lift annuli PROVIDED the lift gas is reliably dehydrated below its water dew-point temperature. This experience includes hydrocarbon gas containing ~3 mol% CO2.

This can be rationalised by considering three zones in the annulus:

1. Flowing 'dry' gas above the active gas-lift valve.
2. The gas/liquid interface.
3. A static, residual water-phase below the active gas-lift valve.

Interestingly:-

1. Lab tests with corrosion inhibitor showed some inhibitors had a tendency to cause pitting corrosion that did not occur without the inhibitor. Inhibitors were assessed as having no benefit but this will be specific to each case. Generally, inhibitors are not necessary.  (Most inhibitors are surface active so may interfere with the formation of protective scales that are beneficial in static conditions).
2. A search of OnePetro (https://www.onepetro.org/) for "gas-lift annulus casing corrosion" returned 5,751 hits but, in a quick review, I found none that address your questions explicitly. This is taken to confirm that gas-lift does not generally cause metal-loss corrosion of the casing.

I hope this helps.
------------------------------
Edward Wade
Metallurgical Engineer
MetalEcosse Ltd.
UK
------------------------------

From my experience I'm thinking that there is a greater risk of corrosion from channelled fluids outside the 7" production casing.  It would be necessary to verify with cased hole well integrity logs to verify whether there are corrosion cells outside the casing.  The advantage of condition monitoring well integrity will not only lead to greater return on asset value but allows for effective and reliable decommissioning operations of the well at the end of its life.  Build a list of process hazards relative to well integrity now and the return will be in the process risk management certainty through a condition monitoring strategy that incorporates simulation for understanding.  
------------------------------
Wayne Needoba
LIS Thailand Co. Ltd.
KarawaraWA
------------------------------

Hi Wayne,

External corrosion is in fact very much specific to particular geologies, and not frequent overall. You need overpressured aquifers (gas helps) and high CO2 content; if you're in a volcanic area you may even get H2SO4 to eat away your casing, but that's rare.

Running ultrasonic logs for external corrosion may fool you, although generally by no more than a couple of mm. So you need a proper diagnostic process and plenty of data.

As for simulations, I wholeheartedly agree with you: that's why I've been building a toolbox of models to understand and predict annular integrity issues.

Best regards,

Matteo
------------------------------

Matteo Loizzo
Well integrity consultant
Berlin
------------------------------

Hi Wayne,

External corrosion is in fact very much specific to particular geologies, and not frequent overall. You need overpressured aquifers (gas helps) and high CO2 content; if you're in a volcanic area you may even get H2SO4 to eat away your casing, but that's rare.

Running ultrasonic logs for external corrosion may fool you, although generally by no more than a couple of mm. So you need a proper diagnostic process and plenty of data.

As for simulations, I wholeheartedly agree with you: that's why I've been building a toolbox of models to understand and predict annular integrity issues.

Best regards,

Matteo
------------------------------

Matteo Loizzo
Well integrity consultant
Berlin
------------------------------