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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