18 Jon Kvarekvýl IFE V

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04.03.2014

Corrosion Control in SourGas Pipelines

Jon KvarekvålInstitute for Energy Technology (IFE)

Tekna Flow Assurance, 3-4 March 2014



04.03.2014 2

H2S/CO2 corrosion impact on flow assurance

• Main cause of leaks, workovers, shutdowns and accidents.• Tubing, flowlines, pipeline, process facilities ++

• Estimated annual cost ca. 10 billions USD 1998 (NACE CoC)• Ca. 30 billions USD today? (NACE worldwide CoC ongoing)

• More than 90% of cost onproactive measures:

• Corrosion mitigation• Monitoring

• Inspection



Sour fields characteristics

• Sour natural gas: > 5.7 mg/m3

H2S• Up to 90% H 2S wells actually produced (Canada)

• Sour service limits for materials selection: > 3 mbar H 2S

• 40% of remaining gas reserves worldwide.

• H2S is toxic, reactive and corrosive.

• Corrosion control: Economy = environment• Chemical – inhibition, pH stabilization

• Internal coatings (FBE)

• Mechanical - pigging

• Natural corrosion control – no treatment

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Internal corrosion

• Unprotected water-wet carbon steel corrodes vigorously in H 2S/CO 2 environments.

• Protection required: Surface layers, inhibitor films, oil/HC wetting,coating .



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CO2/H2S corrosion regimes

pCO 2/pH 2S=20

CO 2 REGIME

SWEET

H2S REGIMESOUR

CO 2 + H 2S REGIMEMIXED

pCO 2

pH 2S

pCO 2/pH 2S=500

Ref. Shell IP/GS



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H2S/CO2 corrosion morphology

• Uniform/general corrosion• FeS layers – more or less

protective

• Localized corrosion/pitting• ”Wide/shallow pits” –

ASTM def.

• ”Localized general corrosion”

• Moderate/high penetration

rates, 1-10 mm/y

Ref. Saudi Aramco, Choi et al 2006



Gas/condensate multiphase pipeline

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High risk corrosion zones

• Characterized by unknowns: Inhibitor availability, mass transport,local water chemistry, temperature, …

• UDC - Under-deposit corrosion• Accumulation and deposition of solid particles bottom-of-line

• TLC - Top-of-line corrosion• Water condensation on upper sector of pipeline

• Other areas with recurring breakdown and loss of protective

corrosion layers.

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Under-deposit corrosion (UDC)

• Inert solids (sand, clays, FeCO 3, …)

• Conductive/reactive solids (FeS, S …)

• FeS particle formation scenario

• 1 km 36” sour gas pipeline, average corrosion rate of 0.1 mm/y• 0.3 m 3 iron per year, corresponding to 0.7 m 3 FeS

• Assuming 70% captured as surface layers

• 100 m 2 surface covered with a 5 mm FeS deposit

• NACE Task Group 380 – report on different UDC test methods.

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UDC experimental scenario• 25 ° C, 10 bar CO 2, 10 bar H 2S, 14 days.

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UDC – inert/active particle mixSand:FeS 5:1 0.5 mm/y Sand:FeS 1:1 3.7 mm/y

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Iron sulfide polymorphism

Name Formula Lattice Structure

Iron monosulfidesAmorphous FeS Fe(HS) 2, FeS x NanocrystallineMackinawite Fe 1+xS, x = 0.005-0.025 TetragonalCubic FeS FeS Cubic

Troilite FeS HexagonalPyrrhotite Fe 1-xS, x = 0.005-0.1 Hexagonal/monocl.

Intermediate iron sulfidesSmythite Fe 9S11 , Fe 7S8 HexagonalGreigite Fe 3S4 Cubic

Iron disulfidesMarcasite FeS 2 OrthorhombicPyrite FeS 2 Cubic



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Pitting caused by elemental sulfur (So)

Ref. Canspec

non-stoichiometrice- conducting FeS

layer

Ref. Alberta Sulfur Research



14

Top-of-line corrosion (TLC)

• Top-of-line corrosion (TLC) occurs on areas with water condensation.

• Typical in the first few kilometers of pipelines with high inlet temperatures.

• The water condensation rate is reduced when the gas phase temperaturedecreases.

• TLC risk usually estimated with multiphase flow models and corrosion models.• Sweet TLC rate dependent on the water condensation rate and the amount of

iron that can be dissolved in the condensing water:

•Corrosi on rate Condensation rate * Dissolved iron concentr ation in cond ensed water

• The above expression not verified for sour TLC, and does probably not applysince FeS supersaturation is rapidly achieved under most conditions.



TLC Possible rate-determining parameters• Water condensation rate (and glycol content)

• Low MEG level in condensed water phase (>10 %)

• Corroding surface temperature• Affects electrochemical reaction (corrosion) rates, FeS precipitaion etc.

• Gas convection and diffusion• Supply of water vapor and acid gases not an issue in pipelines, maybe

in stagnant lab tests.

• Supply of organic acids with low vapor pressures may be limited bytransport through the gas phase.

10.06.2004 15



pH stabilization in sour service

• Addition of alkaline chemicals to increase pH and enhanceformation of protective layers.

• NaOH, NaHCO 3, MDEA, …

• Numerous JIPs and bilateral research projects 1999-2007• Key findings published through NACE.

• Max. H 2S level 0.02 bar (NORSOK)

• Severe localized corrosion at higher H 2S levels (>0.1 bar)

• Applicable only in MEG systems, not with KHI.

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Protective pH-stabilized corrosion layer• 0.02 bar H 2S, 2 bar CO 2, 60 oC, pH 6.5, 50% glycol, CR ~ 0.01 mm/y, FeS 1-x



2D flow model

Flow direction

Pre-flow section Test specimen



2D flow model - mesh



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Disturbed flow effect2D model of flow velocity streamlines around flow obstacle.

Flow 1 m/s



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Disturbed flow effect - pitting



Sour corrosion inhibition

• Active components: Quaternary amines, imidazolines,polyamines, …

• Water-dispersible or oil-soluble

• High dose rates, ~1000 ppm residuals typical• Sweet systems 30+ ppm

• Continuous + batch treatment• + sulfur solvent if necessary

• Localized corrosion inhibition efficiency more important than WL

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Hasbah/Arabiyah-Wasit pipeline treatment plan• Wasit gas plant – 260 km subsea pipelines

• Processing Capacity: 2500 MMscfd of non-associated gas

• Production Capacity: 1710 MMscfd of Sales Gas .• + 4200 MTD of Elemental Sulfur , 600 MW of Electrical Power

• Flow improvement: FBE coating (+ chemicals)

• Corrosion protection: Secondary purpose, primary barrier

• Corrosion inhibition: Continuous + Batch, monthly pigging

• Corroding agents 8% CO 2, 4.4% H 2S, elemental sulfur

• Accepted CR<0.1 mm/y, 98% inhibitor availability

• Hydrate inhibition: MEG, 25/75 reclaim/reboil

• Sulfur solvent: Diesel/HDO 0.5-2% load

04.03.2014



04.03.2014



Spray pigging for TLC control / batch inh.

10.06.2004 25



TLC spray test equipment

• Hastelloy autoclave

• 2 L volume

• Coupon holder withcooling chamber

• Air/liquid cooling

• 25 mm ∅ x 3 mmX65 coupons

• Exposed area:

~5 cm2

• Spray option

10.06.2004 26



27

TLC spray testing70 ° C, 10.8 bar CO 2, 5.8 bar H 2S, 50 wt-% MEG, HDO, 10 days. 10s spray pulse.

Baseline 0.4 mm/y (2.8 mm/y) Batch inhibited, >0.01 mm/y



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Inherent protection - CO2 vs. H2S/CO2

0.1

1

10

100

0 20 40 60 80 100

Time / h

C o r r o s i o n r a

t e / ( m m

/ y )

0 0.2 0.4 0.6 0.8 pH2S /p CO2

• 3.4 bar CO 2+H2S, 120oC, pH~5, jet impingement ca. 900 Pa



04.03.2014 29

Stratified corrosion layer3.5 bar H 2S , 7 bar CO 2, pH ~ 4, 120 oC, CR ~ 1 mm/y



04032014 30

Summary

• Corrosion mitigation in sour HC production is challenging wrt selection,optimization, dosage and availablity of chemicals.

• pH stabilization has been qualified for MEG systems up to 0.02 bar H 2S.• Localized corrosion risk at higher H 2S levels

• Corrosion inhibition is applicable in most sour systems (incl. systemswith elemental sulfur)

• High inhibitor dose rates may be required

• The most effective actives are less «green»…

• FeS particle production may be a threat to flow assurance even withacceptable corrosion rates.

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18 Jon Kvarekvýl IFE V