Corrosion and scaling in carbon

steel casing and tubingMarion Seiersten, Institute for Energy Technology

My background:

• Ensure safe use of C-steel, but use CRA when required

• Prediction models: Corrosion rate, risk of scaling, nucleation and

growth of solids

200 - 300°C

<150°C

10

00

-2

00

0 m

>300°C

Outline

Corrosion of carbon steel

• Fundamentals

• Modelling

• Inhibition

Scaling

• How corrosion my affect scaling

Geothermal and oil and gas synergies

Corrosion of carbon steel

Mechanisms in anaerobic aqueous solutions

Acid corrosion: 2

22 ( ) ( ) ( ) ( , )H aq Fe s Fe aq H aq g

3

2 3

2 2

( ) ( )

( )

( ) ( )

H aq HCO aq

H CO aq

CO aq H O l

2

( ) ( )

( )

H aq HS aq

H S aq

3

3

( ) ( )

( )

H aq CH COO aq

CH COOH aq

The acids provide H+ and keep the

pH low (3.5-5.5)

Oil and gas production:

Gas and oil phases are reservoirs for CO2 and H2S

Geothermal:

CO2 and H2S limited to dissolved amount when the fluid is water

Corrosion prediction models

• Quite a number for CO2 corrosion

• Limited to temperature <150°C and

3.5<pH<6.5

• Most of them are OK on the primary

mechanism (H+ reduction with Fe

oxidation)

• The ability to predict secondary effects

varies

• Predicting H2S corrosion is a challenge

Secondary effects: Corrosion products on the

surface, steel quality, other effects of H2S than

contribution to pH buffering,

Norsok M-506 used on a

geothermal problemSeiersten and Nyborg, EUROCORR 2016,

Paper No. 67987

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

-1500 -1000 -500 0

Co

rro

sio

n r

ate

[m

m/y

]

Depth [m]

Estimated corrosion rate

High flow, high CO2 and Ca2+

Low flow, high CO2 and Ca2+

Low flow, low CO2 and Ca2+

Why is H2S corrosion less predictable than CO2 corrosion?

Solid corrosion products

• Can be protective if they

form a dense continuous

film

• Enhance localised corrosion

if the film is not dense

• There are a range of

sulphides, thermodynamics

not well known and kinetic

factors affect the formation

10 bar CO2, 10 bar H2S, 100 g/L

NaCl, 0.2 g/L NaHCO3, 14 days

Steel

110 °C

130 °C

Mackinawite

Fe(1+x)S +

Pyrrhotite

(Fe(1-x)S) /

troilite

(FeS)

Pyrrhotite/

troilite

Tjelta and

Kvarekvål,

EUROCORR

2016, Paper

No. 63777

H2S – Sulphide stress cracking (SSC)

Factors that affect the susceptibility

of metallic materials:

• Materials properties

• H2S partial pressure

• In situ pH

• Concentration of dissolved Cl- (or

other halide)

• Presence of elemental sulphur or

other oxidant

• Temperature

• Galvanic effects

• Mechanical stress

• Time of exposure

Inhibiting corrosion

Steel pipe wall

Polar head group

Hydrocarbon chain

Synergist

• Filmer: Organic molecules

with polar head group and

hydrocarbon chain

• Synergist

• Solvent

• Biodegradable

Inhibitor 1

Inhibitor 2

Baseline

0.1

1

10

100

80 °C100 °C

120 °C150 °C

Co

rro

sio

n r

ate

, mm

/y

Temperature

Corrosion inhibitor efficiency

Inhibitor efficiency as function of temperature in low

salinity brines (200 ppm inhibitor)• Inhibitor 1 (Inh1): 20% Oleic imidazoline, 5 % thioglycolic acid

• Inhibitor 2 (Inh2): 20% Cocoalkyl quat, 5 % thioglycolic acid(Palencsár, A. et al. CORROSION/2013, Paper no. 2610)

• Efficiency may decrease

with increasing temperature

• Oil may enhance efficiency

• Deposits may decrease

efficiency

• Behaviour may depend on

salt content of brine

• Qualification at relevant

conditions required

Selecting corrosion inhibitor stage 1

• Establish the conditions Temperature, pressure, fluid composition,

flow rates and water chemistry

• Use corrosion prediction model to

estimate uninhibited corrosion rate

• Estimate flow regime Shear rate, likelihood of top of the line

corrosion, fines, deposits, etc.

• Propose a corrosion inhibitor or

select more corrosion resistant

material

0.01

0.1

1

10

100

0 50 100 150 200

Co

rro

sio

n r

ate

[m

m/y

]

Temperature [ C]

Shear stress 5 PapCO2=3bar, 0 alk pCO2=3bar, 5 mM alk.

pCO2=0.3bar, 0 alk pCO2=0.3 bar, 5 mM alk

CO2 corrosion rate Calculated by NORSOK M-506 (none

commercial model) available from Norsk

Standard (www.standard.no)

Normal corrosion allowance

Selecting corrosion inhibitor (CI) stage 2

• Testing and qualification

• Define conditions – field

relevance vs. complexity

• Optimize CI concentration

• Determining inhibited corrosion

rate

• Based on uninhibited and inhibited

corrosion rate set inhibitor availability

and corrosion allowance

Measure corrosion rate

Bubble test

Selecting corrosion inhibitor (CI) stage 2

• Testing and qualification

• Define conditions – field

relevance vs. complexity

• Optimize CI concentration

• Determining inhibited corrosion

rate

• Based on uninhibited and inhibited

corrosion rate set inhibitor availability

and corrosion allowance

Measure corrosion rate

Autoclave testCorrosion loop

Effect of scale on corrosion

• Siderite (FeCO3) protects carbon

steel

• Require high HCO3- concentration to

form

• Proven to 150 °C, but above?

• Other scales as protective?

• Protective scale and scale inhibition?

• Scale and corrosion inhibition?

Steel

Cross-section pictured in SEM

Complex scaling

• Sulphate – chemistry and

temperature

• Carbonate –chemistry and pressure

(temperature)

• Silicate – chemistry and

temperature

• “Exotic” scale – sulphides, halite,

PbS, Pb,…

Scale and corrosion products retrieved

from geothermal well at Soultz- sur-

Foret (Cross-section pictured in SEM)

(Ba,Sr)SO4

Fe3O4

PbS +

Carbonate scale affected by corrosion

2

22 ( ) ( ) ( ) ( , )H aq Fe s Fe aq H aq g

3

2 3

2 2

( ) ( )

( )

( ) ( )

H aq HCO aq

H CO aq

CO aq H O l

pH

increase

Consumed by corrosion

Estimating CO2 corrosion rate and scaling in

geothermal wells

5.8

5.9

5.9

6.0

6.0

6.1

6.1

6.2

6.2

6.3

6.3

-1500 -1000 -500 0

pH

Depth [m]

pH

High flow, high CO2 and Ca2+

Low flow, high CO2 and Ca2+

Low flow, low CO2 and Ca2+

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.1

-1500 -1000 -500 0

Co

rro

sio

n r

ate

[m

m/y

]

Depth [m]

Corrosion

High flow, high CO2 and Ca2+

Low flow, high CO2 and Ca2+

Low flow, low CO2 and Ca2+

Corrosion pH Scale0.9

1.0

1.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

-1500 -1000 -500 0

SR

Depth [m]

CaCO3 saturation ratio

High flow, high CO2 and Ca2+

Low flow, high CO2 and Ca2+

Low flow, low CO2 and Ca2+

2 23

( )

Ca CO

SP

a aSR

K calcite

Some corrosion resistant alloys in brine with CO2 and H2S

Within in the blue and green areas: Corrosion rate ≤ 0.05 mm/y and no SSC or SCC

From Craig, B.D and Smith, L.:

Corrosion Resistant Alloys (CRAs) in the oil

and gas industry – selection guidelines

update, 3rd Edition, 2011

Monitoring corrosion and scale

• Produced water analysis

• Weight change coupons

• ER (Electrical Resistance)

probes

• FSM (Field Signature Method)

• Ultrasonic

• Radiography

• Electrochemical

measurements

• Calliper measurement –

intelligent pigging

• Tracer technology

Geothermal and oil and gas synergies in

corrosion and scaling – Modelling

• CO2 corrosion models have a proven record

within their limits

• Thermodynamic equilibrium models are able to

predict risk of scaling

• Challenges:

• Stochastic behaviour: Pitting corrosion,

nucleation and growth of solids

• High temperature

• Complex production fluids – high salt content

Questions?

marions@ife.no