By Brad Buecker, Contributing Editor
Steam generating power plant personnel know that many fluids are utilized throughout the process. These fluids must be of proper chemical and physical makeup, and must be conditioned correctly to minimize or prevent corrosion, deposition, mechanical failures and other difficulties within the steam generator. This article considers water. Part II, to be published in November, will consider lubricating oils and hydraulic fluids, including broad-brush reminders of the technologies and process to keep fluids in pristine condition.
A steam generator requires high-purity water to function properly. Very critical is preparation of makeup water and conditioning of the condensate and boiler water. Cooling water treatment is also critical. Not to be forgotten is wastewater that escapes from the system and exits the plant.
Makeup Water
The high temperatures and pressures in a steam generator require water with dissolved ion concentrations in the low part-per-billion range. Treatment starts with the makeup stream. All water that enters a boiler originally had to come from a raw water source that contains many impurities. Amongst the many bad actors that exist in raw water are the hardness ions, calcium and magnesium, corrosive ions including chloride and sulfate, silica, and many others. Raw waters, and especially surface supplies, contain varying levels of suspended solids (dirt, mud, colloids) that will also cause major problems.
A typical makeup water system removes impurities in a step-wise process. First comes suspended solids. Clarification/sand filtration was once the dominant technique, but microfiltration (MF) and ultrafiltration (UF) are becoming more popular for suspended solids removal.1 MF and UF are membrane filtration techniques that are very good at removing the common suspended solids in raw water. Suspended solids pretreatment is critical for downstream operation of reverse osmosis systems.
Clarification, MF, and UF do not remove dissolved ions. Nowadays, most makeup water designs include reverse osmosis (RO). RO is a membrane process where the angstrom-sized pores and the water boundary that forms within these pores prevents the passage of ions. Modern membranes are capable of removing 99 percent of the ions from the inlet feed. RO units require careful monitoring and data analysis to determine if suspended solids, microbiological fouling, or other factors are affecting membrane performance. Periodic cleaning is a must with these systems, but where good pretreatment reduces cleaning frequency.
The final step is ion exchange. If an RO is located upstream, the ionic loading on a demineralizer is low, but without RO, the IX unit must remove many ions. Regardless, a properly designed demineralizer will produce water with the low-ppb dissolved ion concentrations necessary for boiler makeup. Although a number of scenarios exist for demineralizer configurations, virtually all employee strong acid cation (SAC) and strong base anion (SBA) resins in the process. SAC resins exchange cations (sodium, magnesium, calcium, potassium and others) for hydrogen ions (H+) and SBA resins exchange anions (bicarbonate, chloride, sulfate and others) for hydroxyl ions (OH-). H+ and OH- combine to produce H2O. Periodic regeneration of the cation resin with acid (sulfuric, typically) and the anion resin with caustic is necessary to keep the resins in proper working order.
Condensate/Feedwater
With pristine makeup water, the condensate should be pure and usually is. However, Darth Vader may be lurking around the corner in the form of a condenser tube leak. All of the ions taken out by the makeup system will be reintroduced if raw cooling water enters the condensate. If the cooling water system is of the open recirculating typel that is, cooling tower impurity concentrations will be several times that of the cooling water makeup. Even small condenser leaks can initiate serious corrosion underneath porous deposits in boiler tubes, but severe leaks can cause acid formation and immediate corrosion. Boiler tube failures have been known to occur within days of a major condenser tube leak.
A full flow condensate polisher will remove dissolved ions, and this equipment is standard for once-through steam generators. Condensate polishers utilize cation and anion exchange resins similar to demineralizers, but where the resins treat a much larger stream of course. For steam generators without polishers, which includes many drum units, close monitoring of condensate chemistry and quick repairs of a tube leak(s) constitute the only reliable method of minimizing waterwall damage.
As was mentioned, porous deposits on waterwall tubes are a leading cause of corrosion due to their ability to concentrate impurities within the deposit at the tube surface. The typical major constituent of porous deposits is iron oxide, much of which is introduced during scheduled unit outages for boiler tube work and/or chemical cleanings. A condensate particulate filter can serve excellently well on unit startup to remove particulates at the condensate pump discharge. Some utilities are even using these devices during normal operation.
Feedwater chemistry control is vital to prevent additional metal corrosion and transport of corrosion products to the boiler. Space does not prevent a detailed discussion here, but treatment programs have steadily evolved in the last two decades. Most once-through units around the world are now on oxygenated treatment (OT), which establishes a very dense protective layer of ferric oxide hydrate (FeOOH) on feedwater piping. The barrier is typically much tougher than the magnetite film (Fe3O4) that forms with oxygen scavenger programs. For other units, where OT or its cousin all-volatile oxygenated treatment [(AVT(O)] are not possible, detailed guidelines are available for chemical treatment that minimizes iron and copper corrosion in the feedwater system. Operation at an alkaline regime a bit above pH 9, with carefully controlled oxygen scavenger feed is the norm for these programs.
Boiler Water
The old coordinated and congruent phosphate programs for drum units have for the most part been discredited, especially for high-pressure boilers. The primary problem was phosphate deposition on waterwall tubes, which led to wildly variable bulk boiler water chemistry and direct corrosion of the tube metal by the phosphate deposits. Popular replacement programs include EPRI’s phosphate continuum, and in some cases caustic treatment, the latter of which is very common in Europe. Careful monitoring and control of these programs is necessary to prevent tube corrosion, but also because they operate at such low concentrations of treatment chemicals that a condenser tube leak can easily destroy the chemistry.
Steam
Significant research, much of it by the Electric Power Research Institute, has been undertaken in the last several decades regarding the effects of steam impurities on turbine operation and rotor/blade corrosion. The limit on such impurities as chloride and sulfate has been steadily lowered until now it is in the very low ppb range. Other impurities that cause serious problems include copper and silica. In drum units, the two methods of transport are mechanical and vaporous carryover. Mechanical carryover is typically the result of excessive impurities in the boiler water, poor unit operation, or failure of steam separating devices. Vaporous carryover may also be due to poor boiler water chemistry, copper corrosion in the feedwater system, or other factors. Careful and reliable monitoring of steam chemistry is the best method to determine if excess carryover is present. Then, corrections can be made.
Cooling Water
We have seen that cooling water in-leakage via the condenser can cause very serious problems in the steam generator. Thus, it is vital to prevent corrosion, fouling, and scaling of condenser tubes, and cooling tower fill for that matter. A well maintained and operated biocide system is necessary to prevent microbiological fouling. The most common treatment chemicals are gaseous chlorine, liquid bleach, and bromine generated from a chlorine (or bleach) and bromide salt reaction. Common is two-hour treatment per day per unit at a plant, although in some areas of the country environmental regulators have greatly lowered the amount of residual halogen that can exit the condenser or the cooling tower blowdown. It may be necessary to install a chemical feed system at the discharge for feed of a reducing agent to neutralize the biocide. Supplementary non-oxidizing biocides can be of benefit to control organisms. These non-oxidizers may be particularly helpful for systems with cooling towers, where bacteria, fungi, and algae are all often present. Common non-oxidizers include DBNPA, gluteraldehyde, isothiazoline, and quaternary amines.
Corrosion and scale control programs are much more sophisticated than in the past, where specialty polymers can assist conventional treatments to minimize difficulties. Deposits that are more easily controlled now include calcium carbonate, calcium sulfate, calcium phosphate, and compounds containing silica.
Wastewater
Some power plants, especially in arid climates have moved to zero liquid discharge. But at many others, waste streams are still a fact of life. These streams include boiler blowdown, cooling tower blowdown, RO reject, roof and floor drains, flue gas desulfurization purge, and others. Contaminants or chemistry that have been regulated for a long time include suspended solids, oil and grease, and pH. Now, however, other compounds are beginning to show up in permit guidelines. Already appearing are copper, boron, and mercury. Wastewater treatment plants will become more complicated as regulations become tighter. Clarification and metals removal by pH adjustment may become somewhat common, as might fine filtration to remove heavy metals particulates.
References: 1B. Buecker, “Membrane Magic”; Power Engineering, Vol. 109, No. 9, September 2005.
Author: Brad Buecker is a contributing editor for Power Engineering. He currently serves as Technical Support Specialist for AEC PowerFlow, Kansas City, MO. His experience includes serving as an air quality control specialist and plant chemist for Kansas City Power & Light Co.’s La Cygne, Kansas power station. He also served as a chemist, flue gas desulfurization engineer, and results engineer at City Water, Light & Power, Springfield, Ill.