1. Corrosion and Materials Degradation in CO2 Pipeline Transport & Well Injection
IEA Greenhouse Gas R&D Programme
2nd Working Group Meeting on CO2 Quality & other Relevant Issues,
Cottbus 7th Sept 2009
M Billingham, INTETECH Ltd

2. Oxy-Fuel Flue Gas after Purification
Compnt
Low Purity
High Purity
Corrosion risks
CO2
~ 95%
> 99%
Controls basic material selection
Water
<< dew-point O2
~ 1%
ppm ?
Increased pitting risk
Ar, N2
2- 5%
Trace
None
SOx, NOx
Acid, oxidising
H2S
Not in oxy-fuel gases
Pitting, H - damage
Impurites after cyrogenic purification
Before – more SOx, NOx, Cl, Hg
Combination of very high CO2 pressure and these impurities not like anything else – oilfield CO2 injection experience is usually in reducing / oxygen free conditions

3. Pipeline Materials Operate dry
No corrosion, impurities not significant - use carbon & alloy steel
Corrosion allowance for short upsets
Strict control of dewatering on startup and continuous process monitoring
Practice proven by US CO2 pipelines
Typical pipeline experience is ~ ppm water maximum

4. Injection Well As for pipeline, dry in normal operation
Reservoir water will move back to well bore during shut-ins & on abandonment – corrosion risk
Need for long-term integrity after injection phase completed (1000’s years ?)

5. Downhole Materials – wetted parts
Injection tubing could be replaced or removed
Permanent tubing, casing, valves, packers
Leakage past primary pressure barriers ?
Completion diagram

7. Injection Well Conditions
Acid, pH ~ 2
Saline aquifers > 200g/l chlorides
Gas reservoirs ~ 20 – 100 g/l chlorides
Warm, ~ °C
Very high carbon steel corrosion rates:
Corrosion Resistant Alloys ?
Picture of corroded tubing

8. Injection Well Materials
But: Oxidants + Chlorides + low pH =
Pitting Corrosion
Stress - corrosion cracking
Trace oxygen is significant for pitting of CRAs (ppm in gas / ppb in water) - down to levels in “pure” cyrogenically-separated gases
After final shut-in, oxygen might disappear, but pitting may continue…
Oxygen pp is high for low purity fluid: 1% x 400 bar
High pressure makes situation worse..

9. CCS injection is potentially more severe
Similar conditions
Oilfield water injection & seawater systems
Temperature & Cl are lower, less acidic
Natural gas storage in salt caverns
CO2 & O2 content is lower, less acidic
Geothermal
Usually oxygen-free down-hole
CCS injection is potentially more severe
All these are less severe than Oxyfuel CCS in one or other respect.
Seawater – oxygen, can be hot, but seawater is alkaline & only ~ 3.5% NaCl
Gas storage – very high Cl content but only trace oxygen & CO2, not really acidic,
Geothermal – hot and high chloride, some CO2, but often reducing with trace H2S
Combined with long-term integrity, CCS is beyond current experience.
Note – current CO2 injection for 2ndry recovery is usually oxygen-free using geological CO2

10. For comparison… For raw (aerated) seawater typically,
Super-duplex, 6Mo stainless to ~ 40°C
625, C276, 686, higher temperatures
Titanium used at any temperature
Crevice & pitting attack on Alloy 625 at 60°C in very saline brines & 500 ppb dissolved oxygen; C276 pits slightly under same conditions
Data from CAPCIS – Intertek, 2008.

11. Candidate Materials - wetted parts
High Chlorides :
Very high alloy CRAs (C276, Alloy 686 etc); Ti
Lower Chlorides:
High alloy CRAs (Alloy 625 & similar)
Need for testing in service conditions
Picture of well completion diagram

13. Non-metallics
CO2 requires different polymers compared to hydrocarbon service
SOx etc levels low wrt polymer aging over normal lifetimes
Very long life needed for downhole packers & seals – beyond O&G experience

14. Summary - Corrosion Issues
Pipeline & Upper Injection Well
Water content critical - operate dry
Other impurities not critical
Carbon & alloy steels
Lower Injection Well
Potentially wetted & with chlorides
Oxygen content (+ SOx, NOx) critical
High Ni-base alloys or Titanium – testing needed