Are you familiar with an article called CO2 erosion & corrosion of pipeline steel (API X65) in oil and gas conditions - A systematic approach by Xinming Hu and Anne Nevillea (source: Wear Volume 267, Issue 11, 29 October 2009, Pages 2027-2032 ICAP 2008). Could you please comment?
A systematic study of pipeline steel (API X65) degradation due to erosio & corrosion containing sand in a CO2 saturated environment has been carried out. This work focuses on the total API X 65 material loss, corrosion, erosion and their interactions (synergy) as a function of environmental parameters (temperature, flow velocity and sand content) to enable the critical conditions, which move the damage mechanism from a flow-induced corrosion regime to erosion & orrosion regime, to be determined.
The experimental results show that the effect of API corrosion in enhancing erosion, often referred to as the synergy, is significant and accounts for a high proportion of the deviation of measured material loss from the prediction derived from established CO2 corrosion models. Ways forward to improve erosion & corrosion prediction are discussed.
Regards, Jim Ash
Comment by Kate Stuart on 28 Dec 2009 at 15:35:59
Unfortunately I don't have access to the article, can you attach it?
Secondly, there is few work on X steels in CO2 environment that really contains hard and rigorous figure. The most rigorous statements I found so far are as follows:
Corrosion of pipelines is an important issue. Dry CO2 does not corrode the carbon-manganese steels generally used for pipelines, as long as the relative humidity is less than 60 per cent; this conclusion continues to apply in the presence of O2, N2, NOx and SOx contaminants, which would probably be components of any CO2 produced by a CCS process. CO2 that contains CO as a contaminant can induce corrosion. Seiersten wrote:
â€œThe corrosion rate of carbon steel in dry supercritical CO2 is low. For AISI 1080 values around 0.01 mm/y have been measured at 90-120 bar [9-12 MPa] and 160- 180Â°C during 200 days. Short-term tests confirm this. In a test conducted at 3 and 22Â°C at 140 bar CO2, 800 to 1000 ppm H2S, the corrosion rate for X-60 carbon steel was measured to less than 0.5 micrometer/y [0.0005 mm/y]. Field experience also indicates very few problems with transportation of high-pressure dry CO2 in carbon steel pipelines. During 12 years, the corrosion rate in an operating pipeline amounts to 0.25-2.5 micrometer/y [0.00025 to 0.0025 mm/y]â€
The water solubility limit in high-pressure CO2 (50 MPa) is 2000 ppm at 30Â°C. Methane lowers the solubility limit, and H2S O2 and N2 may have the same effect. Corrosion is much faster if free water is present. Seiersten measured a 0.7 mm/y corrosion rate in 150 to 300 hours exposure at 40Â°C in water equilibrated with CO2 at 95 bars, and higher rates at lower pressures, and she found little difference between carbonmanganese steel (API grade X65) and 0.5 chromium corrosion-resistant alloy.
It follows that a CCS scheme ought to dry the CO2 as far upstream as possible, with no liquid and a vapour phase water content below 4.8Ã—10-4 kg/m3, the level allowed in a current specification for pipeline quality CO2.
Hope this helps, Kate
Comment by Saravan on 03 Mar 2010 at 10:35:19
The information you have given about corrosion of X-Steels was amazing. I have some questions about it.
1) When it is said dry CO2 is non-corrosive .....what % of water content is required to make it corrosive.
2) I am dealing with a fluid 99% CO2 and 0.8-1.4ppm of H2S. What do you think the corrosion rate of a X-52 steel would be for this fluid???
3) My partial pressure range is 44 bar and temperature is 44 deg celsius according to thermodynamics of CO2 the fluid remains as gas in this state. So what kind of corrosion can I expect in this case????
Your reply would be greatly appreciated.
Comment by Kate Stuart on 03 Mar 2010 at 16:52:37
1) If water reaches the saturation point in the CO2, water will condense on the pipeline surface. The liquid water - carbon dioxide mixture will drive the corrosion by the significant concentration of the species. If water stays in the gas phase - hence below the saturation point - the concentration is a 1000 fold lower (density difference between gas and liquid). This fact can be traced back in the corrosion rates found(!)
I believe that for H2O in CO2 the minimum saturation point is 1000 ppm at 30 degrees Celsius at a pressure 50 bar (see other thread on this subject).
I don't dare to say what happens as a function of temperature, I expect the saturation point to decrease as a function of temperature (e.g. 500 ppm at 200 degrees Celsius). But you may want to ask Composite Analytica to carry out some thermodynamic simulations (see CheFEM).
2) My gut feel is that you do not have to worry about this, also see the previous statements.
3) Currently, the figures given above give the best indication of the difference between gas and liquid state. But I do not know the exact difference between API X65 and API X52.
Kind Regards, Kate Stuart
Comment by Saravan on 09 Mar 2010 at 13:52:18
Your reply was very useful. Your professionalism is greatly appreciated.
Thank You very much.
Comment by Rodney Bennet on 30 Jan 2010 at 18:16:06
Today I read in the Dutch Newspaper that the Canadian pipeline (which has just become operational) requires a Carbon Dioxide purity of 95% to transport the stuff economically. Do not have the slightest idea on the composition of the remainder 5% (perhaps methane and a few heavier products?). The pipeline is indeed made from X65 steel. According to the newspaper, they are pretty satisfied with the project and are looking for other projects which may include longer pipelines (this one is 204 miles, at the current oil price longer pipelines are becoming economically attractive also).