modeling the h s and co corrosion mechanism for carbon ... · brent sherar and rudolf hausler blade...
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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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Co
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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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Temperature (°F)
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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Co
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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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PCO2/PH2S
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.