Erosion Rate Calculations of Carbon Steel Due to High Velocity Steam

[cacofes]

In northern Canada SAGD (Steam Assisted Gravity Drainage) operations are becoming very popular to produce heavy oil out of tar sands. This process requires injection of steam at very high temperatures into the producing formation. The company that I work for is experiencing erosion in fittings and valves at wellheads. Common material used is carbon steel 1018. Could anybody tell me if there is any type of model or software that could calculate metal loss due to erosion from high velocity steam?

 

[metengr]

For your specific application, I would recommend that you calculate real time erosion rates based on periodic thickness testing of selected fittings and valves. You can purchase a D-meter or hire out NDT (ultrasonic thickness testing) to obtain thickness data on a periodic basis (minimum 3 week intervals).

We have used field thickness data to calculate erosion rates for boiler tubing to predict tube weld repair or replacement. There is no substitute for real-time erosion data that can be converted to a rate in mils per year (change in thickness/time interval).

As a side note, have you considered upgrading material to a 5% Cr- 1%Mo alloy steel? We have used 5% Cr- 1% Mo fittings and valve bodies on HP feed water heater drains to increase erosion resistance from steam flashing. Once you calculate erosion rates for your fittings and valve bodies, you can decide if you need to upgrade material.

 

[stanweld]

Is steam superheated? It appears that you may be getting some condensation at the well head valves. metengr's recommendations of 5%Cr alloy is a good one but, I would recommend also using 1 1/4 Cr-1/2 Mo alloy and 2 1/4 Cr- 1 Mo alloys as well. These alloys have long history in steam service.

 

[EdStainless]

In cases of high velocity steam (dry and clean) even very small amounts of Cr (0.25%) give dramatic life improvement.

When there is two phase flow, then higher Cr is needed to help 'strengthen' the passive film. This is where the 2% Cr alloys would be a good option. These are the traditional high performance boiler tube materials and they work well.

Most of the research on this subject has been in hte nuclear power industry. Much of the work was done at Chalk River.

On the production side, much of the tubular for these systems is being converted to 41003, a modified 12% Cr that has a mixed ferritic/matensitic structure. This is needed because of the additional corroison and erosion issues in the produced fluids.

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Corrosion never sleeps, but it can be managed.

http://www.trenttube.com/Trent/tech_form.htm

 

[metengr]

Nuclear power plant feedwater systems are susceptible to erosion/corrosion (a.k.a Flow Accelerated Corrosion or FAC) related to 2-phase flow. This is a completely different wastage mechanism than erosion from steam flow impingement - single phase flow. For steam flow impingement you need much higher amounts of Chromium in comparison to FAC protection.

 

[davefitz]

as meteng said, the main loss is due to an interaction of erosion and corrosion.

The most commmon corrosice activity is caused by having an alternating range of pH and O2 content. If one opearates with zero O2 and high pH, then magnetite forms. Magnetite is a weak scale whcih can be easily removed by erosion, and once the oxide scale is lost, then the erosive action of the high velocity fluid is amplified.

This corrosive action is furhter amplified if there then occurs periods of high O2 and /or low pH. The occurance of these upsets will remove the magnetite .

The best corrosive protection was found by use of the "combined oxygenated treatment " method- so long as gthe fluid is always moving and is not stagnant, excess O2 and medium pH ( 6.5 < pH <8.5) will cause a hematite scale to form , which is very strong and corrosion resistant.

Raising the Cr content to 1% will generally cause the erosive-corrsion life to be extended by a factor of about 7. However, the piping will then need to be PWHT after welding.

 

[rmw]

I suspect that in the application, unlike the power industry which is interested in getting the steam to the turbine inlet nozzles at the hightest temperature/pressure possible, the reinjection does not emphasize insulation, etc., that the power industry does. So, that said, I suspect that there is a problem of two phase flow due to the steam piping losing heat prior to the well head, and moisture formation, which is the FAC agent mentined above.

Check your piping for proper velocities, and insulation integrity, as well as the metallurgical recommendations made above, all of which were excellent.

rmw

 

[cacofes]

Thanks everyone for your valuable comments. We are currently evaluating some of your suggestions and comments with our integrity group.