By Brad Buecker

During the heyday of coal-fired power plant construction and operation in the last century, many lessons were learned regarding correct water/steam chemistry control in high-pressure, fossil-fuel steam generators. Even seemingly minor issues had the potential to cause serious problems, and some corrosion-induced failures led to injuries and death of plant personnel.

Progress in transferring these lessons to the combined cycle power industry has often been slow, and a number of outdated chemistry concepts continue to appear in the specifications for new combined cycle plants. Some problems are magnified by the unique geometrical features of heat recovery steam generators (HRSGs) as compared to their coal unit counterparts.

This article will examine three of the most important issues in this regard, as outlined below:

• Unless the condensate/feedwater system of the HRSG contains copper alloys (very rare), an oxygen scavenger should not be part of the chemical treatment program. Use of oxygen scavengers, a more accurate term is reducing agent, induces flow-accelerated corrosion (FAC) of plain carbon steel. FAC has caused catastrophic piping and tube failures at a number of facilities over the last three decades, and it continues to occur at many plants.
  
• Tri-sodium phosphate has served as the primary chemical for boiler water treatment in many base-loaded coal units, and the chemistry is often employed in HRSGs. Even at steady load, phosphate treatment is problematic due to the phenomenon known as phosphate hideout. In cycling units, hideout may make phosphate chemistry extremely difficult to control.
• While a strong focus should always be placed on operating chemistry, off-line chemistry control is frequently neglected. Air in-leakage into water-filled steam generator networks during down times can significantly damage tubes, piping, turbine blades and rotors, and other equipment. Given the regular cycling nature of most power plants in today’s environment, the potential for air ingress and subsequent corrosion may be extensive.

Forget the Oxygen Scavenge

When this author began his power career in 1981, common wisdom said that any dissolved oxygen which entered the condensate/feedwater system of utility boilers was harmful. At that time, large base-loaded steam generators were the norm. Such units were typically designed with extensive condensate/feedwater networks with perhaps a half-dozen feedwater heaters. A common material for feedwater heater tubes was some type of copper alloy. The prevalent thinking was that any dissolved oxygen (D.O) would cause feedwater system and boiler corrosion, and indeed dissolved oxygen can be very troublesome if copper alloys are present or if oxygen accumulates in stagnant areas. Therefore, virtually all feedwater systems for conventional high-pressure steam generators included a deaerator for oxygen removal. A properly-functioning deaerator can lower D.O. levels to 7 parts-per-billion (ppb).

Even this residual D.O. concentration was still considered harmful, so supplemental chemical deaeration was a nearly universal process at most plants. Hydrazine (N2H4), typically supplied as a liquid in 35 percent concentration, was once the common reducing agent/oxygen scavenger. Feedwater hydrazine residuals of perhaps 20 to 100 parts-per-billion (ppb) were sufficient. Hydrazine treatment was coupled with feed of ammonia or an amine to maintain feedwater pH within a mildly alkaline range, 8.8 to 9.1 for mixed-metallurgy feedwater systems and 9.1 to 9.3 for all-ferrous systems.

 

NH3 + H2O ⇔ NH4+ + OH-

This program is known as all-volatile treatment reducing [AVT(R)], and was designed to maintain the protective magnetite (Fe3O4) coating that forms on steel when a unit is placed in operation.

Hydrazine has long been a suspected carcinogen, so alternative chemicals such as carbohydrazide, methyl ethyl ketoxime, and others emerged as alternatives. All still had the same purpose, to establish a reducing environment in the feedwater circuit, thus inhibiting oxidation of metal. AVT(R) became a standard in the industry.

“This changed in 1986. On December 9 of that year, an elbow in the condensate system ruptured at the Surry Nuclear Power Station [near Rushmere, Virginia.] The failure caused four fatalities and tens of millions of dollars in repair costs and lost revenues.” [1]. Researchers learned from this accident and others that the reducing environment produced by oxygen scavenger feed results in single-phase flow-accelerated corrosion (FAC).

The general effect of single-phase FAC is outlined in the next illustration..

The attack occurs at flow disturbances, e.g., elbows, valves, etc., in feedwater piping, HRSG low-pressure (and to some extent intermediate-pressure) evaporators and economizers, attemperator piping, and similar locations. As the following figure illustrates, pH and temperature also have a large influence on FAC; the latter of which explains why LP economizers and evaporators, and attemperator lines, are particularly susceptible.

Corrosion reaches a maximum at 300o F and is highly influenced by pH. This author has attended several presentations by the well-known steam generation chemistry expert, Dr. Barry Dooley (formerly of the Electric Power Research Institute [EPRI] and now with Structural Integrity Associates), who has commented on the numerous FAC-damaged HRSGs he has seen around the world, many with only a few years of operation. The reason; lack of understanding of this chemistry.

 

So, what are solutions to this issue? Nearly a half century ago, researchers in Europe developed a program known as oxygenated treatment (OT) to minimize carbon steel corrosion in supercritical steam generators. The key component of the program was, and still is, deliberate injection of oxygen into the condensate/feedwater network to establish oxygen residuals of up to 150 ppb. What chemists discovered is that in very pure feedwater (cation conductivity ≤ 0.15 μS/cm), the oxygen will intersperse and overlay magnetite to generate a tenacious and very insoluble film of ferric oxide hydrate (FeOOH). OT greatly minimizes single-phase FAC and can lower feedwater iron concentrations to 1 ppb or less. OT is now the preferred feedwater treatment for most once-through utility steam generators around the world.

Although OT has been successfully applied to some drum boilers, another program has emerged (thanks to research at EPRI) that is very popular for condensate/feedwater treatment in drum units. It is known as all-volatile treatment oxidizing [AVT(O)]. AVT(O) relies on oxygen that enters the condensate from condenser air in-leakage to establish the protective FeOOH layer. But to re-emphasize, OT and AVT(O) are not permissible for feedwater systems containing copper alloys, as the oxygen would simply be too corrosive to the metal. Copper alloys in HRSGs are virtually non-existent, making the issue moot in almost all cases for these units.

Now consider Figure 4, which is the basic schematic of the most common type of HRSG; the design EPRI designates as a feed forward low-pressure (FFLP) HRSG. In this configuration, the low-pressure circuit essentially serves as a feedwater heater for the intermediate-pressure (IP) and high-pressure (HP) evaporators.

 

When EPRI researchers developed AVT(O), they took into account the pH effect on carbon steel dissolution, as was previously illustrated in Figure 3. AVT(O) guidelines [3] for the HRSG shown above are as follows:

• Condensate pump discharge D.O. concentration: ≤20 ppb
• Economizer inlet D.O. range: 5-10 ppb
• Recommended LP economizer inlet pH25C range: 9.6-10.0
• Condensate/feedwater cation conductivity: ≤0.2 μS/cm

As with OT, the condensate must be quite pure to allow oxygen to generate the FeOOH protective layer rather than cause pitting. However, the normal cation conductivity limit with AVT(O) is a bit more relaxed at ≤ 0.2 μS/cm.

The amount of air in-leakage required to establish the recommended limit of ≤20 ppb D.O. in the condensate is not a hard and fast value, and depends upon several factors including the effectiveness of the condenser air removal system. The key point is to maintain the 5 to 10 ppb D.O. concentration at the economizer inlet. If sufficient D.O. is not available from condenser air in-leakage, a supplemental feed of pure oxygen may be required. When proper AVT(O) chemistry has been established, the internal surfaces will develop a uniform “rugged red” color, as shown in the following photo.

The requirement for a constant small concentration of dissolved oxygen in the feedwater is why mechanical deaeration has been eliminated in some new plant designs. And at existing plants with deaerators, in some cases the plant chemists have had the operators close the deaerator vents to maintain the required feedwater D.O. residual for a successful AVT(O) program.

Even with the accumulation of experience regarding AVT(O) and its benefits, the author regularly sees a call for an “oxygen scavenger” chemical feed system in new combined cycle plant specifications. Altering this mindset has been a difficult task, but hopefully continued articles and papers will alert new owners and developers to FAC and the correct chemistry to control it.

 

Also of note is that a metallurgical approach is available to control FAC, particularly the single-phase version. The addition of even a slight amount of chromium to carbon steel greatly inhibits the corrosion mechanism. Fabricating susceptible locations such as economizer and evaporator elbows from 1¼ or 2¼ chrome steel will virtually eliminate single-phase FAC. However, doing so does add a bit of cost to the project, which may cause some owners and designers to turn away from what can be a practical solution to the problem.

Brief mention must be made of the seemingly high pH range recommended in the AVT(O) guidelines above. In accordance with FFLP HRSG design, phosphate or caustic cannot be employed for alkalinity control in the LP circuit due to the potential for direct transport of these compounds to steam via the attemperator sprays. But, as feedwater enters the drum a substantial portion of the ammonia will flash off with the steam, which lowers the pH of remaining water droplets in what is a two-phase fluid mixture in the upper portions of the drum. Impingement of the droplets on drum surfaces can lead to the appropriately-named corrosion mechanism of two-phase FAC. Establishing a feedwater pH within the range of 9.6 to 10.0 helps to maintain reasonable alkalinity in the water droplets even with some ammonia flash-off.

In some HRSG designs, the LP evaporator is an independent circuit. The terminology for this configuration is stand-alone low-pressure (SALP) HRSG. Tri-sodium phosphate or caustic is permissible for chemical treatment in the LP evaporator of these steam generators. A lower feedwater pH range of 9.2-9.8 is allowed due to the presence of the solid alkali in the LP evaporator. This in turn allows for reduced ammonia feed to the condensate.

 

The Complexity of Phosphate Treatment

The alkalinity induced by ammonia feed to the condensate will carry through to the HRSG, and can maintain a basic pH although some of the ammonia will flash off in the LP evaporator. But regardless of the residual ammonia concentration that remains in the HRSG evaporators (and this goes for conventional units as well), ammonia-generated alkalinity offers virtually no protection in the event of impurity ingress, say from a condenser tube leak. Common for years has been feed of tri-sodium phosphate (TSP) to boiler drums to establish more permanent alkalinity. The primary chemical reaction is:

Na3PO4 + H2O ⇔ NaH2PO4 + NaOH

The caustic alkalinity (NaOH) generated by this treatment helps to counteract the influence of the (usually) minor concentrations of chloride and sulfate that may enter the condensate.

However, it has long been known that a considerable difficulty arises with tri-sodium phosphate chemistry due to the variable solubility of this chemical with temperature.

The graph clearly shows that solubility increases as temperatures rise to 300o F, but then declines rapidly and is virtually negligible at the temperatures of high-pressure boilers. As a unit comes up in load, TSP precipitates leaving very little residual in the boiler water. The common name given to this deposition is “hideout.” Then, if boiler load is reduced or especially if the unit comes off line, the TSP re-dissolves. In the middle of the last century, coordinated phosphate treatment, later modified to congruent phosphate treatment, came along as a method to stabilize chemistry due to hideout. In both programs, TSP was blended with di-sodium phosphate (Na2HPO4) and occasionally a small amount of mono-sodium phosphate (NaH2PO4) in an attempt to balance the chemistry of the deposits with that of the bulk boiler water. Subsequent operating experience and research showed that coordinated and congruent chemistry were flawed and led to formation of acidic phosphate deposits that attacked the base metal. Thus, TSP has become the only recommended phosphate species for high-pressure steam generators. Regardless, hideout causes swings in boiler water chemistry, including pH, and can make chemistry control problematic. Even at base-loaded plants, hideout presents difficulties and though the plant may have plenty of on-line instrumentation to monitor boiler water conditions, much extra effort may be required to control chemistry. [4]

So, what recourse do HRSG technical personnel and/or operators have to avoid these problems? Chemists at some plants, most notably existing coal plants, have switched to caustic as the chemical for boiler water pH control. However, caustic treatment requires very careful monitoring as iron is an amphoteric material, meaning that carbon steel will corrode at high pH as well as low. The recommended maximum free caustic concentration in high-pressure steam generators is 1 part-per-million (ppm). [3] For plants without trained chemistry personnel, caustic control may be very difficult.

 

 

A method to avoid phosphate or caustic chemistry issues is to employ full-flow condensate polishing, which provides a barrier of protection for the steam generators and allows simplified boiler water chemistry. We have already noted that the alkalinity generated by ammonia feed to the condensate system transports to the steam generator, but that impurity ingress will almost immediately destroy ammonia-based chemistry. Minimize the chances of boiler water contamination with condensate polishing, and now the AVT(O) feedwater chemistry program also becomes acceptable for the boiler. (For more discussion regarding condensate polishing, please refer to the author’s article in the current issue of Power Engineering, [5] which was distributed to all Power-Gen attendees.) An item that the author and colleagues regularly encounter with new project development is elimination of a condensate polisher from initial plant design or during the purchasing process as an easy method to reduce capital costs. This is short-sighted thinking.

Off-Line Protection

Much focus, and rightly so, is given to on-line chemistry issues, as upsets while a unit is at pressure and temperature can be quite problematic. However, plant designers, owners, operators, and technical personnel often tend to overlook corrosion issues that can arise when units are off-line. Given the transition of the power industry from base-loaded operation to high cycling duty, these issues have been magnified. Much of the following discussion is extracted from reference 6, which the author and a colleague from the combined cycle industry prepared for Power Engineering magazine in 2012, and whose ideas are still completely valid.

Both conventional units and HRSGs are a complex maze of waterwall piping, superheater and reheater tubing, boiler drums, and other equipment. When a unit is taken off-line, the water inside the circuits contracts slightly in volume. The volume change draws in outside air. Now, stagnant conditions with oxygen saturation, at least at water-air interfaces, have been established.

Oxygen attack is extremely serious for several reasons. The corrosion mechanism itself can induce severe metal loss in those areas of high oxygen concentration.

 

The attack often takes the form of pitting, where the concentrated corrosion may result in through-wall penetration and equipment failure in a short period of time. Also of concern is that off-line oxygen attack generates corrosion products that then carry over to the steam generator during startups. Deposition of iron oxides within evaporator waterwall tubes leads to loss of thermal efficiency and, much more importantly, establishes sites for under-deposit corrosion. These corrosion mechanisms may include acid-induced hydrogen damage, [3] direct phosphate corrosion, and caustic gouging. In fact, cases have been known of both under-deposit acid and caustic corrosion in the same unit. [7]

Another method by which oxygen can infiltrate steam generators is at startup when condensate or fresh demineralized water is needed for filling or boiler top-off. Usually this water is stored in atmospherically-vented tanks and absorbs oxygen and carbon dioxide. Subsequent injection of oxygen-saturated makeup into a cold steam generator induces additional corrosion.

Perhaps the most critical item of all, at least with respect to the greatest potential for catastrophic damage, is exposure of the low-pressure turbine to atmospheric conditions during short-term shutdowns. If a unit comes off-line, and condenser vacuum is broken, outside air, humidified by standing water in the condenser hotwell, will permeate the low-pressure (LP) turbine. “So what?” is a reply this author has heard more than once. The answer lies in the fact that even with proper boiler water chemistry and operation, trace quantities of salts, and most notably chloride salts, still carry over with steam. Superheated steam remains dry during its passage through most of the turbine, but some condensation begins in the last few rows of the LP turbine. This location is known as the phase transition zone (PTZ). The salts in the steam precipitate in the PTZ, and these compounds, especially if subjected to humid air during shutdowns, will initiate pitting of the turbine blades, blade attachments, and rotors. Pitting in itself is a very troublesome corrosion mechanism, but with turbine blades, and especially the long blades in a LP turbine, pitting can evolve into stress corrosion cracking and corrosion fatigue. These corrosion mechanisms may in turn lead to blade failure, and if this happens with a turbine spinning at 3,600 rpm, catastrophic results are guaranteed.

 

Per reference 6, at the Lincoln Electric System (LES) Terry Bundy combined-cycle plant utility personnel have implemented several very effective techniques to prevent oxygen ingress and corrosion. Primary power is produced by two GE LM 6000 combustion turbines and two Nooter-Eriksen dual pressure HRSGs (no reheat) feeding a 26 MW steam turbine. Feedwater chemistry is AVT(O), with ammonium hydroxide injection to maintain feedwater pH within a range of 9.6 to 10. High-pressure evaporator chemistry is based on EPRI’s phosphate guidelines, with tri-sodium phosphate as the only phosphate species. The phosphate control range is 1 to 3 parts-per-million (ppm). The HP evaporator pH control range is 9.5 to 10. Free caustic concentrations are maintained at or below 1 ppm to minimize the risk of caustic gouging.

“An individual who enters a confined space where nitrogen has not been purged may pass out nearly intantaneously due to lack of oxygen.”

For off-line protection of the HRSGs, first and foremost is nitrogen blanketing during the last stages of shutdown and subsequent short-term wet layups. Introduction of nitrogen to key spots in steam generators before the pressure has totally decayed will minimize ingress of air. Then, as the system continues to cool, only nitrogen enters void spaces. At Terry Bundy, the nitrogen injection points are at the steam drum vents. For more complicated systems, including conventional coal-fired units, additional locations for nitrogen protection include feedwater heaters, the deaerator, and superheaters. It is also possible to protect the LP turbine and condenser with nitrogen, but another method for longer-term layups is outlined shortly.

One question that often arises is how best to store or generate nitrogen. Certainly it can be provided from nitrogen bottles delivered by local gas-supply or welding firms. Liquid nitrogen is another possibility. LES personnel selected a different method, nitrogen generation via pressure-swing adsorption (PSA).

The process utilizes a carbon molecular sieve, which, when compressed air (130 psig at Terry Bundy) is introduced, adsorbs oxygen, carbon dioxide, and water vapor, but allows nitrogen to pass through. The nitrogen is collected in receivers for use as needed. At regular intervals pressure is released allowing O2, CO2, and H2O to desorb from the material, at which time these gases vent to atmosphere. The table below outlines nitrogen purity from this system as a function of production rate.

During wet layups nitrogen is applied at a pressure of 5 psig to the LP and HP drums when unit pressure has decayed to this level. Also, nitrogen is utilized to “push” water from an HRSG during dry layup draining. A nitrogen pressure of 5 psig is maintained during the dry layup, provided no major tube work is required. An obvious major concern with nitrogen blanketing is safety. Of course, elemental nitrogen is not poisonous, as it constitutes 78 percent by volume of our atmosphere. However, an individual who enters a confined space where nitrogen has not been purged may pass out nearly instantaneously due to lack of oxygen. Death can occur within minutes.

Another important point with regard to wet layup chemistry is periodic water circulation to minimize stagnant conditions that can concentrate oxygen in localized areas. Both Terry Bundy HRSGs have circulating systems installed on the high-pressure and low-pressure circuits for use during wet layups. Each circuit utilizes one of two redundant pre-heater recirculation pumps (100 gpm capacity), which normally are in service during HRSG operation to mitigate acid dew point corrosion of external tube surfaces. Valves and piping have been modified to allow for seamless transition from layup circulation to normal operation. Sampling/injection systems are available to allow operators to test the layup chemistry for pH and dissolved oxygen concentration (using colorimetric ampules), and to inject ammonium hydroxide if the pH needs to be raised. Also, modifications made in each boiler drum allow the layup water to bypass the drum baffle, promoting circulation and minimizing short-circuiting via the downcomers. The pumps are typically started once drum pressure drops below 50 psig, and remain in service for the duration of the layup.

Dissolved Oxygen Removal from Condensate and Makeup Water

As was previously noted, demineralized water is commonly stored in atmospherically-vented tanks. If untreated, oxygen-saturated water enters the steam generator during boiler fills or per demand for makeup during normal operation. Several methods are possible to limit oxygen ingress to storage tanks and steam generators, and Terry Bundy personnel selected a gas transfer membrane technology to remove oxygen from makeup water.

As the makeup flows along the hollow fiber membranes in the vessel, gases pass through the membrane walls but the water is rejected. The technology is capable of reducing the D.O. concentration to less than 10 parts-per-billion (ppb).

Protecting the Steam Turbine

Previously noted is the corrosion that can occur in the LP steam turbine if it is exposed to moist, atmospheric conditions. Nitrogen blanketing is one method to prevent attack, but another practical method to combat this corrosion, and one that has been adopted at Terry Bundy, is dehumidified air (DHA) injection to the condenser during all but short-term (<72 hours) layups.

 

This particular DHA system is capable of providing 700 standard cubic feet per minute (SCFM) of 100oF air at 10 percent relative humidity to the condenser and low-pressure turbine. The process can lower the relative humidity of the surroundings from 100 percent to less than 30 percent in just a few hours. The common flow path is injection at the LP steam injection point with extraction at the condenser hotwell. DHA is initially applied in a once-through mode until an acceptable humidity is attained, at which time bypass valves are opened allowing for recirculation of the exhaust air to the dehumidifier. This procedure is in stark contrast to the author’s observations at a number of plants, in which, when the unit came off for an extended outage, the hotwell was not completely drained and still contained standing water. Such conditions are ideal (in the worst sense of the word) for subjecting the LP turbine, and the precipitated salts in the PTZ, to a humid, oxygen-laden environment.

Summary

This article outlined several of the most important modern chemistry aspects to maximize HRSG operation and reliability, including control techniques for flow-accelerated corrosion, complexities regarding boiler water treatment, and the importance of off-line corrosion control. One key point to re-emphasize is that during normal operation a small amount of dissolved oxygen is vital for proper feedwater chemistry, but when the unit is off-line or being filled for a return to service, oxygen ingress can be quite destructive. (Seems rather paradoxical, doesn’t it?) Any power plant is an expensive facility that provides vital electricity to the grid. These valuable assets need to be protected with the most modern technologies and chemistry programs available.

 

Author

Brad Buecker is Senior Technical Publicist at ChemTreat.