By Brad Buecker, Contributing Editor
Via well-engineered use of the waste heat from power and steam generation processes, net efficiencies of perhaps 80 percent are possible at combined heat and power (CHP) plants. However, just like conventional power generation, proper water/steam treatment and monitoring are also important at CHP facilities. This article touches upon these issues at CHP facilities that are or will be powered by combustion turbines with heat recovery steam generators (HRSGs) for process steam and/or power generation.
The Combustion Turbine, Core of the Process
Back in the heyday of large power plant construction, primarily from the 1950s through the 1970s, the most popular technologies were complex coal-fired or nuclear facilities, with hydro power providing much of the remainder. Concerns regarding nuclear safety, global climate change, and quite frankly, cost, have seen movement away from large steam generators to smaller units, and in many cases decentralized power. The core of many new systems is the combustion turbine (CT), a simplified outline of which is shown below.
A CT operates similarly to a jet engine via the following steps, which are part of a fundamental thermodynamic cycle, the Brayton Cycle.
- Inlet air is compressed and injected into the turbine. The compressor is attached to the turbine shaft, and thus the compressor and turbine rotate in unison.
- Fuel, typically natural gas but occasionally fuel oil, is injected and ignited in the compressed air stream.
- The expanding gas drives the turbine.
- Hot exhaust, at 850oF or higher, exits the turbine.
Key advantages of a combustion turbine include very fast start times, low capital cost as compared to coal or nuclear, simplicity of fuel feed, and minimal operations and maintenance issues. These benefits are quite important in the power industry, especially the fast start times during peak power periods when demand skyrockets. For CHP facilities, an added requirement is energy efficiency. Capture of the combustion turbine waste heat is very important for high efficiencies, and this has been accomplished in the power industry via combined-cycle plants, where net efficiencies of modern units are at or near 60 percent, with condensing turbines. CHP efficiencies may be even higher, but in all cases that utilize steam generation, proper water/steam chemistry control is essential for unit reliability.
Combined-Cycle Energy Generation
The downside to simple-cycle operation is that the units are only about 35 percent efficient.
Much energy escapes with the turbine exhaust. This is where the combined-cycle design shines forth. A heat recovery steam generator (HRSG) is placed at the exhaust of the combustion turbine or turbines to utilize the exhaust heat for steam production. While many HRSG designs are available, the most common is the multi-pressure, drum-type unit as typified in the schematic below.
In this particular design, the condensate is split between the circuits, with a relatively small flow to the low-pressure (LP) steam network and the bulk of the flow to the intermediate pressure (IP) and high-pressure (HP) circuits. Steam extraction may be taken from any of the circuits, or, as is most efficient, from a non-condensing turbine. A less complex scenario that may be better for co-generation applications is a combustion turbine with a single-pressure HRSG perhaps without a steam turbine, where the HRSG operation is less complex than with multi-pressure units.
Net efficiencies of combined-cycle units for power production have closed in on 60 percent, while up to 80 percent efficiency is reportedly possible for co-generation. However, as I have learned through experience, at facilities where power production may only be part of the process, water/steam treatment and chemistry monitoring are a neglected task due to focus on process issues. This neglect has come back to haunt many plant operators and technical personnel, when water/steam side upsets (both short- and long-term) have caused corrosion, scaling, and failures that sometimes cost a large plant seven figures or more in lost production and repairs.
Don’t Neglect HRSG Chemistry
The following discussion sums up a number of the most important details of steam generator chemistry that have become known over the past decades, and particularly within the past 20 years.
For dedicated power generating units, the condenser is typically the most troublesome source of contaminant in-leakage. Impurity introduction via a condenser tube leak has been known to cause boiler tube failures within weeks, and sometimes even days or hours. The most notorious impurity is chloride, which in the steam generator will concentrate under deposits and cause acidic corrosion and hydrogen damage. On-line monitoring of condensate chemistry is absolutely essential to detect impurity ingress and take corrective action.
Unless the condensate/feedwater system of a high-pressure steam generator contains copper alloys, the use of oxygen scavengers is highly discouraged. These are now known to propagate flow-accelerated corrosion (FAC) in feedwater systems, economizers, and the low-pressure evaporator of HRSGs, among other locations. FAC-induced failures have caused a number of fatalities at power plants in the last 25 years. Modern programs utilize ammonia or sometimes an amine for pH control, but allow the oxygen that leaks in through the condenser to remain. This oxygen, when the chemistry is carefully controlled, will actually cause the carbon steel feedwater piping to develop a very protective oxide layer.
The most common treatment for IP and HP circuits in HRSGs is the program known as phosphate continuum, and most commonly at the low end of a 1 to 10 parts-per-million (ppm) phosphate range. This program was developed by the Electric Power Research Institute in response to problems with earlier phosphate programs, and calls for the use of only tri-sodium phosphate with perhaps a slight amount of caustic at startup. Alternatives include straight caustic treatment (at less than 1 ppm free sodium hydroxide) and all-volatile treatment, where only the ammonia or amine utilized for feedwater pH control provides the treatment for the steam generator circuits.
Not to be neglected is steam chemistry and monitoring of this process fluid. Carryover of impurities such as chloride and sulfate salts, silica, and other impurities can result in fouling and corrosion of turbine components. The salts in particular will concentrate at the phase transition zone in the last stages of a low-pressure condensing turbine, where, if the turbine is exposed to a moist atmosphere during outages, pitting and stress corrosion cracking may occur.
For CHP plants that distribute steam to process heat exchangers, district heating, or other similar applications, condensate return chemistry is a critical item. In the first place, some boiler water chemistry programs (particularly in low-pressure units with relaxed chemistry requirements) allow carbon dioxide to carry over with steam. This CO2 will then condense with water in the condensate return system to generate corrosive conditions. Any oxygen that carries over or otherwise enters the condensate return system significantly increases the corrosion rate. The condensed steam may accumulate many impurities including iron oxide and other corrosion products, organic compounds, and non-metallic suspended solids. Condensate filtration and polishing are often a mandatory requirement to prepare this water for return to the steam generator. Techniques that may be needed include filtration by activated carbon, particulate filtration by membrane or disk media, and ion exchange.
Another often overlooked issue is the damage that can occur during shutdown periods. Improper steam generator layup can cause excessive corrosion that not only damages components but generates massive amounts of corrosion products that travel to the steam generator and deposit on boiler tube surfaces.  Ideally, for short-term shutdowns where water remains in the steam generator, nitrogen blanketing should be utilized to protect the system from air in-leakage. If nitrogen blanketing is not an option, then other wet lay-up procedures should be established. Also, very reliable technologies now exist to remove dissolved oxygen from steam generator fill water. This is an important issue, particularly for units that face frequent shutdowns and layups, and where demineralized water and condensate are stored in atmospherically-vented tanks.
Plant Effluent Issues
In the April issue of Power Engineering, I wrote about increasingly stringent effluent guidelines that are being imposed at many plants. A full repetition is not needed here, but as a reminder, plant owners and operators may see some of the following constituents, with discharge limits of course, in their future effluent guidelines.
- Heavy metals including chromium, zinc, and copper
- Total dissolved solids (TDS)
Quite commonly, the majority of plant effluent comes from cooling tower blowdown, with often plant drains, boiler blowdown, reverse osmosis reject, and other less voluminous or more transient flows mixed in. Effluent suspended solids, oil & grease, and residual oxidizing biocide concentrations have been regulated for years, but the additional items outlined above and others that are being contemplated have made proper evaluation and engineering of water and wastewater treatment systems critically important. A few quick examples of current issues include:
- Very stringent guidelines on copper discharge (with limits in the low part-per-billion range) at some plants.
- A ban on discharge of phosphorus in some locations, currently or potentially forcing a change in cooling tower chemistry programs from well-known inorganic/organic phosphate methods to polymer-based programs. 
- Very limited ammonia discharge, which, when coupled with the increasing use of reclaim water (secondary or tertiary-treated municipal wastewater) for makeup, can be quite problematic. Reclaim water also causes difficulties regarding phosphorus, both with respect to its effect on cooling tower chemistry and with regard to discharge in the blowdown.
- Sulfate limits can seriously interfere with a common cooling tower makeup treatment method in which sulfuric acid is injected to the makeup to remove bicarbonate alkalinity.
Brad Buecker is a process specialist with Kiewit Power Engineers in Lenexa, Kansas.
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