|A modern sample panel arrangement. Photo courtesy: Swan Analytical Instruments|
Brad Buecker and Dan McGee, Kiewit Power Engineers
A century-plus of steam-generated power production has shown the importance of water and steam chemistry. Just one boiler tube failure in a conventional unit or heat recovery steam generator (HRSG) can cost a power producer many thousands of dollars in lost production and materials replacement. Some failures have even caused fatalities, which is the ultimate price. Yet at many plants, and especially new facilities, the philosophy is to operate with minimal staff. Often, operators handle many of the technical duties at the plant including makeup water production and water/steam chemistry monitoring. But even small chemistry upsets, if chronic or undetected, can cause major problems in high-temperature steam generators. This article examines the recent development of an intelligent system to provide automation for water/steam chemistry monitoring and chemical feed control. As with any process, some human interaction is always required, but the technology outlined below offers plant operators and engineers a much-increased comfort level when it comes to dealing with the sometimes very complex issue of water/steam chemistry and proper treatment. The rewards are improved system performance and reliability, and bottom-line.
A Brief Review of Water/Steam Chemistry Fundamentals
The primary material of construction for condensate/feedwater piping, economizers and boiler waterwall tubes is mild carbon steel. Carbon steel will suffer from general corrosion in either acidic or strongly basic conditions. Thus, steam generators are typically operated in a mildly alkaline environment, with a condensate/feedwater pH range of 9.2 to 9.6, and a boiler water pH range of typically 9.0 to 9.8 depending upon the desired chemistry. The recommended condensate/feedwater program for today’s steam generators consists of ammonia or perhaps an amine feed to maintain pH within the desired range. Oxygen scavengers are not recommended unless the feedwater system contains copper-alloy feedwater heater tubes, as this chemistry induces the potential for flow-accelerated corrosion (FAC). FAC-induced failures have killed a number of plant personnel in the last three decades, with many other units, including HRSGs, suffering from severe FAC issues.
For boiler water control, EPRI’s phosphate continuum program is still the most popular choice, in which only tri-sodium phosphate (Na3PO4) is utilized, with perhaps a bit of caustic (NaOH) at unit startup if the boiler water pH is below 9. Some plant chemists solely use caustic for boiler water pH control, but in either case, the free caustic concentration must be maintained below 1 part-per-million (ppm) to minimize the potential for under-deposit caustic corrosion.
Complicating any water/steam chemistry program is the potential for contaminant introduction from such sources as leaking condenser tubes, a malfunctioning makeup water treatment system or contaminated chemical feed. Even small condenser tube leaks will introduce very problematic impurities, such as chloride, to condensate. Impurities can then concentrate under deposits and in crevices in the boiler to cause pitting, hydrogen damage, crevice corrosion and corrosion fatigue.
In addition to these difficulties, poor chemistry control of condensate/feedwater and boiler water can lead to carryover or direct introduction of impurities to steam. Contaminants such as silica, chloride and sulfate may cause scale formation in the turbine, or induce pitting, stress corrosion cracking (SCC) and corrosion fatigue in turbine blades and rotors.
Additional information regarding the extreme importance of proper chemistry monitoring and control may be found in many references, but the heart of this discussion outlines technology that can guide operators and technical personnel along the correct path.
Figure 1 shows a list of the most important parameters in which on-line monitoring provides for proper chemistry control and chemical feed in a steam generator.
In today’s climate, where capital funds may be tight, plant designers often cannot select a sample panel and system with all of these analyses. The following discussion outlines the most important on-line analyses, and why they are so important.
Condensate Pump Discharge
The condensate pump discharge (CPD) is a critical monitoring point, as steam surface condensers are the most likely source for major contamination. Condenser tube leaks on unpolished systems have been known to cause boiler tube failures within days, sometimes even hours.
Recommended on-line analyses are:
- Degasified Cation Conductivity (D.C.C.)
- Dissolved Oxygen (D.O.)
Degasified cation conductivity is a method to quickly detect contaminant in-leakage from failed condenser tubes. In drum-type steam generators, the cation conductivity should be maintained at less than 0.2 µS/cm.
Sodium monitoring is an excellent and recommended complement to D.C.C. In a condenser with no leaking tubes, sodium levels in the condensate should be very low (<3 ppb), and in many cases less than 1 ppb.
Dissolved oxygen analyses are important for monitoring air in-leakage to the condenser. Ideally, if the condenser air removal system is operating at maximum efficiency, dissolved oxygen levels should be below 10 ppb. A sudden increase in dissolved oxygen may indicate a problem at or near the condenser, which allows excess air, including carbon dioxide, to enter the system. Condensers may have as many as 400 penetrations, so the potential for air in-leakage is great.
Feedwater/ Economizer Inlet
Feedwater chemistry can have a significant impact on boiler operation for several reasons. First, excessive feedwater contamination will reduce the boiler cycles of concentration and require increased blowdown. Second, improper control of feedwater chemistry may cause corrosion of feedwater piping and heat exchanger tubes, which will introduce iron oxide particles and copper corrosion products to the boiler. Third, in many steam-generating systems feedwater is sprayed into main and reheat steam for temperature control. Contaminants are directly introduced to the superheater and turbine via spray attemperation.
Recommended feedwater analyses include:
- Dissolved Oxygen
- Specific Conductivity
- Degassed Cation Conductivity
- Iron (particulate)
The optimum feedwater pH for systems containing mixed copper and iron metallurgy is 9.0 to 9.3, while for strictly iron-based systems the range is higher at 9.2 to 9.6. The pH is controlled by ammonia feed, which in turn is typically controlled by specific conductivity.
Measurement of degassed cation conductivity and sodium supplement the condensate pump discharge analyses to ensure that excessive impurities are not reaching the steam generator. It is also important to ensure that impurities are not being introduced to main and reheat steam via attemperator sprays.
Iron sampling is quite important to ensure that the chemical treatment program is operating effectively. Ideally, the iron concentration should remain below 2 ppb.
An emerging trend in the industry is use of online particulate monitoring to keep track of steel corrosion and iron oxide transport to the steam generator. For those units with copper-alloy feedwater heater tubes in which an oxygen scavenger/metal passivator is required, the combination of iron and copper analyses are quite important to control feed of the reducing agent.
Along with condensate pump discharge, the boiler water sample is the most important of all, especially for drum-type units. This is due to high temperatures and the concentrating effect caused by recirculation of the boiler water.
These factors greatly influence potential corrosion and scaling mechanisms. Furthermore, high concentrations of dissolved solids in the boiler water can introduce excessive contaminants to the steam, where they may form deposits and/or corrode superheater tubes and turbine components.
Recommended boiler water analyses include:
- Specific Conductivity
- Degassed Cation Conductivity
- Phosphate (for those units on phosphate treatment)
The most important analysis is pH. It must be maintained within a fairly narrow range (typically 9.0 to 10.0) to prevent corrosion. This measurement is the one criteria that, if the reading drops below 8.0, calls for immediate unit shutdown, provided the value is accurate and not caused by instrument error. A sudden drop in pH, most likely preceded by a sudden rise in CPD cation conductivity and sodium, is a quick indicator of a condenser tube leak. Also, pH analyses combined with those of phosphate and ammonia (typically by grab sampling) can provide a direct indication if the phosphate treatment program is within guidelines.
Specific and degassed cation conductivity analyses provide direct indication of the amount of impurities in the boiler water, and with some mathematical manipulation can be utilized to calculate the concentration of the harmful corrosive agents sulfate and particularly chloride.
Although EPRI lists silica as an optional analysis, it could easily be placed in the core analysis category.
Silica must be held below pressure-dependent limits, as silica will vaporize, carry over with steam, and precipitate in the turbine.
This effect becomes dramatic as pressure increases. For example, in a 900 psi boiler the recommended maximum drum water silica concentration is 2.8 ppm. In a 2,400 psi boiler, the recommended maximum is 0.21 ppm. Boiler water silica readings, and also those of other impurities, can be compared to steam sample analyses, as described below, to determine threshold limits of boiler water impurity concentrations.
Main and Reheat Steam
Main and reheat steam analyses indicate not only what impurities exist due to carryover from the boiler water, but also those impurities introduced via spray attemperators.
For new units, the primary sampling criteria is cation conductivity, where a common turbine manufacturer limit for warranty issues is ≤0.2 µS/cm.
Recommended analyses include:
- Degassed Cation Conductivity
Although silica is shown as an optional parameter, it is the authors’ belief that it belongs in the core parameter category. The recommended limit is ≤10 ppb, as silica in higher concentrations can precipitate on turbine blades and influence the aerodynamics of the turbine.
Sodium is a measurement that is typically utilized to track mechanical carryover of impurities in the steam.
Now, the topic turns to a core concept of this article, discussion of a method to maximize the ability of plant personnel to monitor chemistry and to provide, within practical limits, automatic chemical feed and control.
Automated Data Evaluation
A key to the successful implementation and operation of the chemistry monitoring and chemical feed systems is ensuring that the data is acted upon promptly to prevent chemistry upsets and to keep conditions within proper control parameters.
The system that is being developed is designed to accept continuous on-line readings and, via algorithms incorporated into the plant distributed control system (DCS), perform several functions. First, a properly designed system will provide continuous, real-time readouts of system chemistry from the condensate/feedwater system through the boiler, superheater and into the steam turbine. This data gives operators and technical personnel instantaneous access to complete steam generator conditions.
Figure 2 shows a basic schematic of a three-pressure HRSG with analytical data displays that can be readily incorporated into DCS logic and displayed on screens in the control room and anywhere else throughout the plant.
This represents only part of the solution. All systems can be configured to immediately alarm plant personnel if any sample exceeds recommended chemistry guidelines.
In many cases, chemistry excursions may be minor and easily correctable. However, some alarms are vital.
If boiler water pH drops below 8.0, immediate unit shutdown is necessary unless an error is discovered in the instrument.
If condensate pump discharge degassed cation conductivity and sodium on rise above normal limits of 0.2 µS/cm and 3 parts-per-billion (ppb), respectively, unit shutdown within four hours may be required. (Such readings indicate a major condenser tube leak, in
Power Engineerng Issue Archives
View Power Generation Articles on PennEnergy.com