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Understanding and Controlling CO2 Corrosion through Materials Research

By J. Soltis, K. Lichti and A. Crisford, Quest Integrity Group

As seen in the September 2012 issue of Oil & Gas Australia.  Download the PDF version here.

 

Corrosion is defined by NACE International as "the degradation of a material, usually a metal, because of a reaction with its environment”. For oil and gas operators, CO2 corrosion is an on-going concern, as the industry relies primarily on the ability to use carbon steels within their facilities. 

Wet CO2-containing environments are encountered throughout the oil and gas industry, often in the presence of hydrocarbons that may or may not inhibit corrosion depending on the water content, but also with varying levels of other corrodants, such as chloride and H2S, and other factors including temperature, pressure, scaling capacity and fluid velocity.  Combinations of these environmental conditions present a host of damage processes ranging from scaling to general or localized corrosion and erosion corrosion. 

The study of CO2 corrosion is often industry specific as the at-risk environments have unique combinations of chemical and physical conditions.  Quest Integrity Group recognizes many similarities that allow predictive models to be used across a wide range of industries, with adjustments for individual applications.

Research to develop models that can reliably predict the risk of CO2 corrosion under complex environmental conditions is on-going. The 1975 de Waard and Milliams model1 that combined the effects of CO2 partial pressure and temperature together with the environment tendency to form either siderite or magnetite to predict the corrosion rate of carbon steel, has since had a variety of enhancements and refinements proposed2. 

The model enhancements have become increasing fundamental to reduce the reliance on historical single industry experience and improve predictions for present day applications.  These fundamental studies are enhanced by industrial experience, laboratory experiments and corrosion tests for verification of the models.

Application of these theoretical models to industrial applications is illustrated in Figure 1 for a CO2-containing environment under high and low flow conditions.  Temperature dependent behavior is evident with the maximum corrosion rates expected at the transition temperature of about 70-80°C.  Many oil and gas process environments fall outside of the conditions considered in these models and prediction becomes problematic.

 

Figure 1: Dependence of corrosion rate of conventional carbon steel on
temperature, and partial pressure of CO2 and flow rates

 

An example of this is CO2 removal processes.  These typically involve preferential absorption of CO2 into either potassium carbonate solution or amine in an absorber with recovery by boiling in a regenerator.

The potassium carbonate process has a high corrosion rate for carbon steel and anodic inhibition is used for corrosion control.  Typically 1% V2O5 is used to control the Redox Potential of the solution so that iron oxides are preferentially stabilized rather than iron carbonates.  This effect is demonstrated in Figure 2.  The lower potential experienced at low concentration of V5+ species, together with the lower pH when CO2 is absorbed, requires tight control on the process so that the corrosion reaction is outside the region where non-protective iron carbonate is stable. 

 

Diagram A

Diagram B

 

 

Figure 2. (a.) Pourbaix diagram for rich (4 mol/kg) and lean (2 mol/kg shaded region) potassium carbonate, benfield solution.  (b) Illustration of variation in redox potential as a function of available V5+ with 1% V2O5 in solution3. function of available V5+ with 1% V2O5 in solution3.

 

CO2 removal using amines is also used for many gas purification processes; for example, they are used in ammonia plants4However, it is important to realize that amine breakdown products, such as heat stable salts, can be very corrosive, and thus control of the solution chemistry is an essential requirement for corrosion control.

Many oil and gas process environments have low levels of H2S that dominate corrosion reactions and corrosion rates.  H2S levels as low as 1x10-8 mol/kg for the potassium carbonate example in Figure 2 can stabilize protective iron sulfides that reduce the risk of CO2 corrosion, as seen in Figure 3. 

Figure 3: Effect of low levels of H2S on the corrosion product stability of iron based oxides and sulfides with CO2/H2S ratio of 1100/1.

 

Under these conditions, a 90% reduction in the CO2 corrosion rate would be predicted5.  Recent Quest Integrity research is focused on the problematic formation and behavior of siderite- based (FeCO3) protective layers with and without environmental modifications in collaboration with a number of research institutes and universities.

The focus is to use in-situ synchrotron X-ray diffraction techniques to investigate the structure and composition of the surface scale formed during CO2 corrosion of carbon steel at temperatures where protective scales can be easily formed.  These scales are generally pure siderite, but secondary phases such as Fe(OH)2CO3 can also be formed under certain conditions6.

The aim of the work is to improve the predictive capabilities of the CO2 corrosion models so that materials and process conditions can more reliably be specified for new environments and to improve our ability to identify operating windows that minimize the risk of corrosion in existing oil and gas facilities. 

With a growing database of industrial experience and our wealth of in-house materials research expertise, Quest Integrity is well positioned to assist the oil and gas industry. 

For more information, please visit www.QuestIntegrity.com.

References

1. C. deWaard, D.E. Milliams, Paper No. F1, 1st Int. Conf. on Internal and External Protection of Pipes, University of Durham, UK (1975).

2. R. Nyborg, Paper No. 10371, Corrosion 2010, NACE International Inc., Houston, TX (2010).

3. P.T. Wilson, K.A. Lichti, C.J. Moss, The Corrosion Chemistry of Benfield CO2 Removal Plant, Australasian Corrosion Association Annual Conference, Perth, Western Australia (2004).

4. J.R. Widrig, D.H. Timbres, Fitness-for-Service of CO2 Absorbers in Ammonia Plants, Paper 4E, AICHE 54th Annual Ammonia Symposium (2007).

5. K.-L.J. Lee, A Mechanistic Modeling of CO2 corrosion of Mild Steel in the Presence of H2S, PhD Thesis, Ohio University  (2004).

6. M. Ko, N. Laycock, B. Ingham, D.E. Williams, In-situ Synchrotron X-Ray Diffraction Studies of CO2 Corrosion of Carbon Steel, in print, Corrosion (2012).

 

 

 

 

 

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