O&M

HRSG issues: Reemphasizing the importance of FAC corrosion control – Part 2

This is the second installment of a multi-part series by Brad Buecker on flow-accelerated corrosion control.
HRSG issues: Reemphasizing the importance of FAC corrosion control – Part 2

This is the second installment of a multi-part series by Brad Buecker, Buecker & Associates.

This first part of this series provided an introduction to the danger of flow-accelerated corrosion, and in particular single-phase FAC that occurs in the feedwater systems and related locations of utility steam generators. (Read Part 1.) The primary influences are:

  1. Flow disturbances such as elbows, reducing fittings, and similar spots for flow alteration
  2. A reducing environment generated by oxygen scavengers
  3. Temperature
  4. pH
  5. Load changes that can move FAC to other locations at conditions below full load

Here, we will focus on a the influence of reducing agents on FAC, and the oxygen scavenger mindset that simply will not disappear.

Reducing agent fundamentals

Figure 1.  The familiar gray-black magnetite layer that forms on carbon steel boiler internals at unit startup.

When carbon steel boiler tubes and internals are placed into service, the steel develops a protective layer of magnetite (Fe3O4) via a process known as the Schikorr reactions.

The fundamental Schikorr chemistry is:

            Fe + 2H2O ® Fe(OH)2 + H2­            Eq. 1

            3Fe(OH)2 ® Fe3O4 + 2H2O + H2­     Eq. 2

The magnetite layer protects the underlying steel from corrosion. However, dissolved oxygen (D.O.) in the feedwater will convert the magnetite to non-protective rust (hydrated Fe2O3). D.O. will also convert the protective cuprous oxide (Cu2O) layer on copper alloys to cupric oxide (CuO). Copper exists in a +2 oxidation state in CuO, which makes it susceptible to reaction with ammonia, and dissolution from the metal substrate. 

For these reasons, oxygen scavengers/reducing agents became standard to not only remove residual dissolved oxygen that escaped deaerators, but also to passivate oxidized carbon steel and copper alloys.

One of the first practical chemicals to be used in steam generators was sodium sulfite (Na2SO3). The compound reacts with oxygen to produce sodium sulfate:

            2Na2SO3 + O2 ® 2Na2SO4                                         Eq. 3 

The primary advantages of sodium sulfite are that it is a common and inexpensive chemical, is non-toxic, and can be used to treat boiler water in which the steam is extracted for food processing or other Food and Drug Administration-regulated applications. Sodium sulfite is primarily used in low-pressure industrial boilers (<600 psig), because it adds too many dissolved solids to high-pressure boiler water, and at high temperatures can degrade into corrosive compounds. 

For utility and industrial boilers that operate at pressures above 900 psig, alternative chemicals are more suitable for oxygen scavenging.  The workhorse for many years was hydrazine (N2H4), which reacts with oxygen as follows:

            N2H4 + O2 ® 2H2O + N2­                                         Eq. 4   

Hydrazine proved advantageous because it does not add any dissolved solids to the feedwater, it reacts with oxygen in a one-to-one weight ratio, and it is supplied in liquid form at 35% concentration. A primary benefit of hydrazine is that it will passivate oxidized areas of piping and tube materials as follows:

            N2H4 + 6Fe2O3 ® 4Fe3O4 + N2­ + 2H2O                  Eq. 5

            N2H4 + 4CuO ® 2Cu2O + N2­ + 2H2O                     Eq. 6

Hydrazine residuals were typically maintained at relatively low levels of perhaps 20 to 100 part-per-billion (ppb). 

Given the simplified chemistry of hydrazine, it was once considered the ideal oxygen scavenger. However, for years the chemical has been a suspected carcinogen and is now registered as a hazardous compound. This difficulty led to development of alternative reducing agents including carbohydrazide (N4H6CO), hydroquinone (C6H4(OH)2), and methyl ethyl ketoxime (C4H9NOH). These products also passivate metals.

A reducing agent combined with ammonia for feedwater pH control constituted the AVT(R) chemistry mentioned in Part 1.  

In general, for systems without any copper alloys (which includes nearly all HRSGs), the ideal feedwater pH range is in the mid- to upper-9s, with some adjustment for HRSG design, as will be examined in a later article. For older, conventional steam generators that may still have copper-alloy feedwater heater tubes, a lower pH range of 9.0-9.3 is usually recommended to balance corrosion control of carbon steel and copper.   

Moving on from AVT(R)

Almost two decades before the 1986 failure that alerted U.S. researchers to FAC, chemists had discovered that the controlled injection of oxygen into the high-purity (cation conductivity ≤0.15 µS/cm) feedwater of supercritical boilers (in units with no copper-alloy feedwater heater tubes) would reduce carbon steel corrosion to extremely low levels. This methodology became known as oxygenated treatment (OT). 

Based on these results, the Electric Power Research Institute (EPRI) developed a program to replace AVT(R) for utility drum units. 

The new program was coined “all-volatile treatment oxidizing [AVT(O)].”  With AVT(O) chemistry, oxygen scavenger feed is eliminated, and a small residual concentration (5 to 30 parts-per-billion (ppb)) of dissolved oxygen is maintained at the economizer inlet. (1) As with AVT(R), ammonia or an ammonia/neutralizing amine blend is still utilized for pH control. High-purity condensate (cation conductivity ≤0.2 µS/cm) is a requirement for AVT(O), but when proper conditions are established, magnetite becomes overlaid and interspersed with a tighter-bonding oxide, known variously as a-hematite or ferric oxide hydrate. It is noticeable for its distinct red color.

Figure 2.  Properly passivated surfaces in a unit with AVT(O).  Photo courtesy of Dan Dixon, formerly of Lincoln Electric System and now with EPRI.

In original AVT(O) programs, the primary source of dissolved oxygen was that which entered condensate from air in-leakage at the condenser shell or piping penetrations into the shell. The volume reduction of collapsing turbine exhaust steam as it flows through the condenser generates a very strong vacuum, which will pull in air from even the smallest openings. 

However, with very tight condensers the oxygen concentration may not be sufficient to carry through the entire feedwater network. Situations may arise where insufficient dissolved oxygen is present to keep carbon steel properly passivated, resulting in the potential for FAC, even in the absence of reducing agents. 

At some plants, tech staff or operators had to close the deaerator vents to stop oxygen loss from that location, and in some cases plant personnel have taken a page from the OT chemistry book, and have installed oxygen feed systems to maintain sufficient D.O. concentrations at the economizer. 

A special case arises for many HRSGs. Consider the most common HRSG design, the feed forward, low-pressure (FFLP) type. The low-pressure circuit essentially serves as a feedwater heater for the intermediate- and high-pressure evaporators. Typically, a small volume of steam is extracted from the LP evaporator. Most of the dissolved oxygen in the LP feedwater flashes off with the steam, leaving behind IP and HP feedwater that can induce FAC in the economizers of these evaporators. Direct oxygen injection may be required to correct this deficiency.

Changing the oxygen scavenger mindset

Even with three decades-plus of data, a frequent reaction at new combined cycle plants is to install oxygen scavenger feed systems for the HRSGs. Scavengers are not recommended for these (typically) all-ferrous feedwater systems, but the mindset persists. 

It is the author’s hope that this series will help to swing that mindset in a different direction. In part 3, we will examine the phenomenon of two-phase FAC, which may require added chemistry adjustments. 

References

  1. For years, guidelines suggested a 5-10 ppb D.O. concentration at the economizer inlet.  However, this is a very narrow window, and some experts have concluded that 5-30 ppb is much more manageable and actually provides better passivation control.  This data was included in the pre-workshop seminar of the 40th Annual Electric Utility Chemistry Workshop, June 6, 2022, Champaign, Illinois.


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].