Modeling the H2S and CO2 Corrosion Mechanism for Carbon

Steel Under Aggressive Sour Service Conditions

OLI Simulation Conference October 16-17, 2012

Brent Sherar and Rudolf Hausler Blade Energy Partners

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Outline • A recent client request to evaluate the materials selection of a gas well

provided an avenue to investigate CO2/H2S corrosion on carbon steel using the OLI AQE corrosion model.

• Application: Material selection of oil country tubular goods (OCTGs) 1) Evaluate reported water analyses (laboratory results vs. OLI model) 2) Perform corrosion rate assessment of OCTGs

• Corrosion rate analysis resulted in unexpected corrosion behaviour

for selected reservoir conditions » Performed a sensitivity analysis to understand the CO2/H2S/Steel non-

linear interactions » Results were best illustrated via contour plots » Explained the results in light of known corrosion mechanisms » Compared model to literature

• Does OLI qualitatively predict Fe/CO2/H2S interactions correctly? • Are the corrosion rates that OLI predicts accurate?

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1) CORROSION: Establish acceptable general steady-state corrosion rates.

• Based on a production life of 20 years, we have

adopted an acceptable calculated corrosion rate limit of 8 mpy (0.2 mm/a; industry guideline).

2) CRACKING: Determine resistance to sulfide stress cracking (SSC) and stress corrosion cracking (SCC).

3) CHEMISTRY: The tubing material has to perform over a

wide range of temperature/pressure conditions and mineral compositions as these parameters may change over the lifetime of the well.

Criteria for Materials Selection

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3. Corrosion Modeling of a Typical Gas Well

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Reservoir Conditions Corrosion Calculations

• Methane was added to the system in order to generate a total pressure of 3,000 psi.

• Based on previous experience with carbon steel, Blade had initially assumed that 70 psi PCO2

and 250 °F would yield low corrosion rates (< 10 mpy).

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Parameter OLI Lab

Total pressure / psi 3,000 3,100

CO2 partial pressure / psi 70 52.7

H2S partial pressure / psi 2 3.1

[Cl–] / ppm 0, 16,690 15,000

pH at 250 °F and 2 psi PH2S 3.97 4.01†

† Calculated using OLI.

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Reservoir (model) Lab (experimental)

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Methodology

Comparison of carbon steel predicted by the OLI model and lab experimental corrosion rates

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Corrosion rates were calculated at 250 °F and 3,000 psi with 70 psi PCO2, 2 psi PH2S. Predicted carbon steel corrosion rates were ~2X lab (experimental), both values are > 8 mpy cut off.

In order to confirm the predicted corrosion rates, further sensitivity analysis was required.

Reservoir model contains 16,690 ppm chloride and 0 ppm bicarbonate.

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Temperature / °F

~ 70 psi CO2

~ 70 psi CO2 + 2 psi H2S

The effect of H2S on the CO2 corrosion rate of carbon steel at 3,000 psi

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At low temperatures,

H2S significantly suppresses the corrosion rate

Under bottomhole flowing conditions, virtually no change in corrosion rate

H2S suppresses corrosion in the presence of CO2 at low temperature, but passivity is lost at high temperatures.

Reservoir model contains 0 ppm chloride.

4. Corrosion Mechanism

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Corrosion Regimes in CO2/H2S Corrosion

FeS and FeCO3

FeS

FeCO3

A.K. Dunlop, H.L. Hassell, and P.R. Rhodes, CORROSION/83, paper no. 46,1983.

B.F.M. Pots, R.C. John, I.J. Rippon, M.J.J. Simon-Tomas, S.D. Kapusta, M.M. Girgis,

and T. Whitham, CORROSION/02, paper no. 02235, 2002.

B. Kermani, J. Martin, and K. Esakul, CORROSION/06, paper no. 06121, 2006

Main corrosion products

Link between PCO2/PH2S and corrosion processes/products

Can we quantify the effect of H2S on CO2 corrosion at 250 °F?

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• OLI was used to predict carbon steel corrosion rates under a wide range of CO2 and H2S partial pressures at 250 °F and 3,000 psi.

• Upon trying to establish explicit correlations between the corrosion rates and the acid gas partial pressures it was quickly observed that the relationships are non-linear.

• The PCO2/PH2S ratio was identified as a main parameter.

• Both the corrosion rate (CR) and the partial pressure ratio were expressed in the form of contour plots.

Modeling the Effect of H2S and CO2 on Carbon Steel Corrosion

Figure x-axis y-axis z-axis

1 log(PCO2/PH2S) PCO2 log(CR)

2 log(PCO2/PH2S) log(PH2S) log(CR)

Contour plots showing the effect of varying PCO2 + PH2S on carbon steel corrosion rates at 250 °F and 3,000 psi

The black dots represent the calculated corrosion rates for a specific combination of PCO2 or PH2S and PCO2/PH2S ratio. To establish the contour lines a statistical algorithm triangulates between the corrosion rate results of each grid location. 11

< 10 mpy > 560

mpy

110 mpy

Proposed Corrosion Mechanisms

Region 1: Contains the highest corrosion rates; high PCO2, low

PH2S, and high PCO2/PH2S ratio.

CO2 dominant corrosion mechanism forms a poorly protective

FeCO3 film.

Region 2: Moderate to high corrosion rates; wide variation in both PCO2 and PH2S; low to moderate PCO2/PH2S ratios.

The associated mixed FeCO3/FeS deposits are apparently not very protective

Region 3: Lowest corrosion rates; high PCO2 and PH2S; moderate PCO2/PH2S ratios.

H2S and CO2 appear to have a synergistic effect, in which a passive FeS film prevails. 12

5. OLI Corrosion Rate Validation

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Flow Loop Test Conditions

Lab Condition Value

Material X65 carbon steel

Temperature (°F)

86, 122, 167

PCO2 (psi) 14.7

PH2S (psi) 1.5 x 10–3, 1.5 x 10–2 and 1.5 x 10–1

Corrosion rates were determined by continuous LPR monitoring over a 24 hours’ period.

Sweet corrosion rates were compared to the de Waard model (worst case “semi-empirical” approach according to Nesic et al., 1996)

Test Solution (simulated formation water)

B. Kermani, J. Martin, and K. Esakul, CORROSION/06, paper no. 06121, 2006

Species Concentration

(mg/L)

Cl– 52630

Na+ 29500

SO42– 10

HCO3– 500

K+ 380

Ca2+ 3200

Mg2+ 500

CH3COO– 50

pH 5.5 – 5.8

Kermani, et al. also investigated the suppressive effect of low [H2S] on the CO2 corrosion rate and the PCO2/PH2S ratio.

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Kermani, 2006

deWaard and Millams, 1993

OLI

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OLI model is consistent with the experimental results by Kermani.

Comparison of predicted temperature effect on the carbon steel corrosion rate in formation water

B. Kermani, J. Martin, and K. Esakul, CORROSION/06, paper no. 06121, 2006.

S. Nesic, J. Postlethwaite, and S. Olsen, Corrosion, 52 (4), 1996.

PCO2 = 14.5 psi, v = 2 m/s (6.4 ft/s), ID = 25 mm (0.98 in.), pH = 5.5 to 5.8.

CO2 only scenario

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PCO2/PH2S

Kermani - 86 F

Kermani - 122 F

Kermani - 167 F

OLI - 86 F

OLI - 122 F

OLI - 167 F

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CO2-only corrosion region

Low [H2S] has a strong influence on CO2 corrosion by decreasing the general corrosion rate; effect more pronounced at higher temperatures. OLI model is consistent with experimental results; however the PCO2/PH2S ratio is inconclusive.

Comparison of predicted PCO2/PH2S effect on the carbon steel corrosion rate in formation water

PCO2 = 14.5 psi, v = 2 m/s (6.4 ft/s), ID = 25 mm (0.98 in.), pH = 5.5 to 5.8.

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Kermani - 86F

Kermani -122 F

Kermani -167 F

OLI - 86 F

OLI - 122 F

OLI - 167 F

Summary

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OLI was applied to assist in materials selection:

1) Performed corrosion rate assessment of carbon steel under reservoir conditions

2) Performed a sensitivity analysis to understand the

CO2/H2S/Steel interactions

Based on the study, we developed a method via contour plots to express the non-linear CO2/H2S corrosion behavior. OLI corrosion rate predictions are reasonably consistent with the literature.

A. Anderko, R.D. Young, Simulation of CO2 / H2S Corrosion Using Thermodynamic and Electrochemical Models, CORROSION/99, NACE International: Houston, TX, 1999, pp. 99031.