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www.intetech.com
Corrosion and Materials Degradation in CO2 Pipeline Transport & Well
InjectionIEA Greenhouse Gas R&D Programme
2nd Working Group Meeting on CO2 Quality & other Relevant Issues,
Cottbus 7th Sept 2009
M Billingham, INTETECH Ltd
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Oxy-Fuel Flue Gas after Purification
Compnt Low Purity High Purity Corrosion risks
CO2 ~ 95% > 99% Controls basic material selectionWater << dew-point
O2 ~ 1% ppm ? Increased pitting risk
Ar, N2 2- 5% Trace None
SOx, NOx Trace Trace Acid, oxidising
H2S Not in oxy-fuel gases Pitting, H - damage
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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
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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 ?)
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Downhole Materials – wetted parts
Injection tubing could be replaced or removed
Permanent tubing, casing, valves, packers
Leakage past primary pressure barriers ?
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Injection Well Conditions
Acid, pH ~ 2 Saline aquifers > 200g/l chlorides Gas reservoirs ~ 20 – 100 g/l
chlorides Warm, ~ 70 -120 °C
Very high carbon steel corrosion rates: Corrosion Resistant Alloys ?
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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…
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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
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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
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Candidate Materials - wetted partsHigh Chlorides :
Very high alloy CRAs (C276, Alloy 686 etc); Ti
Lower Chlorides:
High alloy CRAs (Alloy 625 & similar)
Need for testing in service conditions
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6 8 10 12 14
Solubility Parameter (cal cm3)0.5
NBR
HNBR
FKM
FEPM
EPDM
Hydrocarbons
CO2
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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
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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