Water Treatment

HRSG issues: Reemphasizing the importance of FAC corrosion control – Part 3

This is the third installment of a multi-part series on flow-accelerated corrosioon control by Brad Buecker, Buecker & Associates.
HRSG issues: Reemphasizing the importance of FAC corrosion control – Part 3

This is the third installment of a multi-part series by Brad Buecker, Buecker & Associates. Catch up with parts 1 and 2 here.

In the first two parts of this series, we examined the phenomenon of single-phase FAC, which continues to afflict many utility steam generators around the world. A primary culprit in many of these cases is the continued reliance on AVT(R) feedwater chemistry, which, unless copper alloys are present in the feedwater system, is not recommended. 

However, moving away from AVT(R) does not guarantee elimination of FAC, either single-phase or two-phase. Regarding the single-phase FAC, if the dissolved oxygen concentration drops out of the 5-30 ppb range outlined in Part 2, reducing conditions may arise that allow corrosion. Often, this oxygen deficiency appears as patches of gray-black magnetite mixed in with the red color that should otherwise be uniform with proper AVT(O) conditions. As suggested in Part 2, correction may require supplemental oxygen feed to keep the D.O. within the recommended range.

Two-Phase FAC

Besides dissolved oxygen concentration, we have seen that pH has a large impact on FAC potential. Locations exist in both conventional units and HRSGs in which the design and operation will alter either or both of these variables, and initiate two-phase FAC. The most notable spots within conventional units include deaerators and feedwater heater drains. 

Consider a deaerator compartment where the rising injection steam scrubs D.O. from the condensate, producing an agitated vapor with small water droplets in the deaerator vessel. This results in two-phase FAC, where the combination of steam and water exist. 

I have inspected deaerators in which baffle plates exhibited severe wear from flowing, oxygen-deficient water droplets. The figures below illustrate the much different appearance of single-phase and two-phase FAC.

Figure 1.  The “orange peel” look of classic single-phase FAC.  Photo courtesy of ChemTreat.

Figure 2.  Two-phase FAC in a deaerator.  Photo courtesy of Tom Gilchrist (ret.), Tri-State G&T.

Several noticeable contrasts and comparisons are apparent from these two photos. Single-phase FAC typically exhibits a rougher appearance than the two-phase variety. The metal in two-phase FAC often appears to be “sanded” (a concept that we will return to in Part 4.) 

Notice in Figure 2 the presence of both gray magnetite and red hematite. With complete AVT(O), all surfaces should be red. It is the magnetite that is suffering from two-phase FAC.

At this point, think back to Part 2 of this series that discussed how, in the most common type of HRSG – the feed-forward, low-pressure (FFLP) design – dissolved oxygen escapes with steam in the low-pressure evaporator. Two-phase FAC can therefore become quite pronounced in the upper section of the LP drum of these units. 

So, the question naturally arises: “How can such locations be protected from two-phase FAC?”

Per the Sturla diagram shown in Part 1, a key approach is maintaining an elevated pH of 9.6-10.0 in the feedwater. But this brings up another twist to the puzzle. 

For decades, organizations such as EPRI emphasized that only ammonia should be employed as the feedwater pH-conditioning agent. However, in the low-pressure drum of FFLP units, much of the ammonia will partition with the steam, leaving behind water droplets with a lower pH and no oxygen. An ammonia alternative is an alkalizing amine such as ethanolamine (ETA), cyclohexylamine, or others that are less volatile than ammonia. 

Unfortunately, whatever portion of the amine that carries over with steam will break down in the superheater/reheater to small-chain organic acids and carbon dioxide. These acidic compounds may lower the pH of condensed steam to below 9, and the pH is not re-elevated until the condensate reaches the chemical injection point. 

Furthermore, the organic acids raise the cation conductivity (now commonly known as conductivity after cation exchange (CACE)) of the steam and condensate. This issue has caused problems for the commissioning of new units in which the steam turbine manufacturers insist on CACE values <0.2 µS/cm. 

In this author’s opinion, this surrogate measurement for chloride and sulfate is outdated, as these constituents can be measured directly, now with an on-line instrument that requires limited maintenance. (1)

Apart from the issues above, debate raged for years that the organic acids could potentially cause turbine blade and rotor damage.  I am not sure that this debate has totally disappeared. However, research suggests that an ammonia-alkalizing amine blend (a common recommendation is 90% ammonia – 10% ETA) may be a good compromise. The ETA can help mitigate two-phase FAC in the HRSG LP drum by keeping the pH elevated in the water droplets, while minimizing formation of organic acids in the steam.

The importance of iron monitoring

As reported previously in Power Engineering, iron monitoring should be an integral part of a water/steam sampling program, regardless of feedwater chemistry treatment. (2) 

For decades, EPRI-established guidelines have suggested that with proper chemistry, the total iron concentration in boiler feedwater can be maintained below 2 ppb, even for those units on AVT(R).  But if FAC is underway, the iron concentration is typically well above that value.  Thus, regular iron analyses are critical for establishing and maintaining the correct chemistry to control FAC. 

A complicating factor, however, is that typically 90% or greater of the steel corrosion products exist as particulate iron, with only a small fraction as dissolved iron.  So, any analyses must account for the particulate iron. 

Two common techniques are on-line particle counting, and corrosion product sampling (CPS).  The latter incorporates both filtration and ion exchange to capture particulate and dissolved metals, which are then analyzed to determine the metal concentrations.  Common is to collect a sample for a week or so, and then have the filters and ion exchange resin analyzed for results. For conventional units that still have copper-alloy feedwater heater tubes, CPS is a technique to monitor copper corrosion as well.

While these technologies have been successful, other methods have emerged that offer good results at reasonable cost.  Simple colorimetric lab methods have traditionally been used to monitor dissolved iron contamination, but additional procedures are necessary to measure particulate iron.  A combination digestion-reduction-detection bench-top method is particularly useful for simplifying analysis and minimizing contamination.

Figure 3.  Combination reagent, digestion vials and heater block (left); 1” sample cell (center) and spectrophotometer (right).  Photos courtesy of Hach.

Procedures have been developed to provide complete dissolution of particulate magnetite or hematite. The reported detection limit is 1 ppb.

A combination of a simple colorimetric total iron laboratory analysis with a sensitive laser nephelometric analyzer can also provide a method for quantitative, real-time corrosion monitoring. When properly calibrated, the nephelometric readings can be correlated to total iron concentration values. Magnetite and hematite produce a different nephelometric response to visible light. Black magnetite absorbs more and reflects less light than red hematite. Dissolved iron does not produce any nephelometric response. 

Figure 4.  Suspended particles of magnetite (black) and hematite (red) in water. Illustrations courtesy of Hach.

Corrosion products range in size from sub-micron to 10 µm in diameter, with an average diameter of 1 µm [3]. This size range poses a challenge for particle monitoring because nephelometers respond differently to different particle sizes. These variables make it impossible to create a universal nephelometric calibration for quantification of corrosion products. A nephelometric calibration which is appropriate for one location will not be accurate for a different location where corrosion characteristics may be different. 

Therefore, quantification of total iron via nephelometry must be accomplished through site-specific calibration. Variability in water chemistry, phase, and local piping configurations contribute to variable corrosion characteristics. Site-specific calibration ensures that nephelometric response is correlated to the specific corrosion characteristics present at each installation.

Figure 5.  Laser nephelometer mounted on a water panel/view of the sample cell.  Photos courtesy of Hach.

Conclusion

This installment briefly examined two-phase FAC in HRSGs and techniques for its control. Two-phase FAC may also occur in other locations including steam turbine exhaust and in air-cooled condensers. We will examine some of these issues in Part 4. This installment also emphasized the importance of iron monitoring as a tool to ensure that chemical treatment programs are performing properly to minimize FAC.



References

  1. B. Buecker, “Monitoring of Water and Steam Chemistry for Steam Generators”; Chemical Engineering, September 2019.
  2. Buecker, B., Kuruc, K., and Johnson, L., “The Integral Benefits of Iron Monitoring for Steam Generation Chemistry Control”; Power Engineering, January 2019.
  3. Kuruc, K., Johnson, L.,  Proc., Electric Utility Chemistry Workshop 2015, 2015 (Champaign, IL, USA).  University of Illinois, Urbana-Champaign, IL, USA.


About the Author: Brad Buecker is president of Buecker & Associates, LLC, consulting and technical writing/marketing.  Most recently he served as Senior Technical Publicist with ChemTreat, Inc.  He has over four decades of experience in or supporting the power and industrial water treatment industries, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas station.  Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry.  He has authored or co-authored over 250 articles for various technical trade magazines, and has written three books on power plant chemistry and air pollution control.  He may be reached at [email protected].