By Brad Buecker, Contributing Editor

Four years ago I wrote about the very successful application of microfiltration for makeup water pretreatment at a former utility.1 The machine replaced an aging clarifier and sand filters, where it greatly reduced operating costs and vastly improved the quality of water being fed to a downstream reverse osmosis (RO) unit. Obviously, however, power generating units have many other fluid systems in which fluid purity is also very critical. These include the condensate/feedwater system, turbine lube oil system, electro-hydraulic control (EHC) system, and others. This article examines fluid purity issues in these systems.

Power plant chemists and other plant personnel typically are aware that contamination which enters steam-generator condensate can potentially cause severe corrosion in the boiler and carryover of contaminants to the steam. Condenser tube leaks are the worst culprit, but impurities may come from other sources. Regardless, corrosion mechanisms in a boiler are exacerbated by the presence of porous deposits, which can serve as concentration sites for impurities that then directly attack the base metal of waterwall tubes.

During normal steam generator operation, condensate/feedwater piping and boiler waterwall tubes develop a layer of iron oxide, which, while being a corrosion product, protects the underlying base metal against further corrosion. Even in the normal course of operation, this corrosion layer will gradually increase in depth, but during periods of chemistry upsets, thermal transients and forced outages, additional corrosion products are generated. And, during the major work often performed at times of scheduled maintenance outages, literally hundreds to thousands of pounds of loose particulates may lodge in the condenser hotwell, condensate and feedwater systems.

Some plants have the capability to remove at least a portion of this debris at start-up. But in many cases particulate removal is inadequate at best, where perhaps the only method is to withdraw material through the drum blowdown. Particulates that cycle through the waterwall tubes will, as the temperature increases to normal load condition, deposit on the tubes. These porous deposits will subsequently influence heat transfer. More importantly, they serve as sites for possible under-deposit corrosion and premature tube failure. Thus, at some plants, and particularly those with once-through steam generators, start-up holds are used to allow debris to be cleaned from the system. These holds may last for days following a particularly intense maintenance outage. As plant personnel well know, any delay in start-up can cost a utility tens to hundreds of thousands of dollars, or more, in lost power production.

An equipment investment that can pay for itself several times over with just the first use is a condensate particulate filter. These straightforward mechanical devices can be easily equipped with filter cartridges that remove particulates in the single-digit micron range at very high efficiencies.

The common location for a particulate filter is just after the condensate pumps, with the filter placed in a valved, bypass loop around the main condensate feed line. The device need not be full flow, as at start-up the condensate circulation is often restricted to half the full-load flow rate or perhaps even less. The devices will remove iron oxide particulates and other “crud” within a short period of time, allowing for potentially significant reductions in hold periods.

At one utility, we once started up a supercritical unit following a boiler chemical cleaning. The only method to remove iron oxide and other particulates from the condensate was filtration through the deep-bed condensate polishers. Not only did this process significantly foul the polisher resin, but four days of filtration were required to reduce the solids, whose original concentration was greater than 1 part-per-million (ppm), to the relatively low parts-per-billion (ppb) concentration necessary to fire the boiler.

To alleviate this difficulty, we ordered a condensate particulate filter designed to handle half of the full-load flow for installation ahead of the condensate polishers. Plant personnel installed the unit and equipped it with 6-micron (absolute) filter cartridges. The filter was first used in 2008 at start-up following another chemical cleaning. Again, the initial particulate concentration was very high. As it turned out, two filter replacements were required during the particulate cleaning process. But the critical point is that the filtration time was reduced from four days to one day. An extra three days of operation on a large supercritical unit paid for the filter, the extra cartridges and the labor costs to install it several times over just after the first use.

Turbine Lube Oil

In simplest terms, both steam turbines and combustion turbines are many tons of machinery rotating at 3,600 rpm. Very tight tolerances are required at journal or roller bearings, which in turn requires high-purity lubrication oil to prevent bearing wear and premature failure. The most common contaminant in lube oil is water. Water may enter through leaking steam seals, heat exchanger tube failures, condensation in the main lube oil tank or other sources. Water can cause corrosion and microbiological fouling in the main lube oil tank and other locations, where the corrosion impurities will then travel to turbine bearings and control valves, piping and so on.

Past equipment that has been used to remove water include gravity precipitation systems with filter bags and settling chambers and centrifuges, which as the name implies, ue circular motion to separate oil and water due to the difference in density.

Typically, these older systems were somewhat efficient at removal of free water but did not effectively remove emulsified or dissolved water from lubricating oils. A more modern process that is capable of removing free water and up to 80 or 90 percent of dissolved water is mass transfer vacuum dehydration. The unit is typically installed in a kidney loop on the main lube oil tank. It uses mild heating of the oil slipstream followed by vacuum dehydration from a small, skid-mounted unit to remove virtually all of the water in the oil. The tiny amount of dissolved water that remains is at much too low a concentration to convert to free water in the lube oil tank.

Varnish Removal

Varnish formation in oil is a subject of great importance at both conventional steam plants and those with combustion turbines. Power Engineering magazine reported on this issue in February 20082 with an article that outlined many of the fundamental varnish removal technologies. However, I have spoken with or heard reports from a number of utilities, in which these conventional technologies gave widely variable results. A process that has been recognized for some time but is now beginning to grab headlines is that of adsorption to remove varnish. Varnish occurs when oil and its additives oxidize and polymerize due to stresses placed on the fluid, which include heat transfer from the equipment, microdieseling, and electrostatic energy transfer from particulate filters.

Varnish polymers can reach high molecular weights, and due to their oxidized nature, will settle on internal components, including servo valves. The latter has become a very troublesome issue in many combustion turbines.

While varnish is only slightly soluble in oil, the fact that it has even some solubility allows it to be removed from systems without the expense and headaches of periodic off-line cleaning. Adsorption is proving to be an effective technology. Adsorption is a film-forming mechanism, where the compound to be removed exhibits an electro-chemical affinity for the surface of the collecting media.

The varnish removal compartment contains multi-layer media, whose surface has been prepared to be especially attractive to the oxidized varnish particles. As varnish comes out on the media, deposits within the lube oil system gradually dissolve and are subsequently removed. Progress of this or other technologies can be tracked via the QSA (Quantitative Spetrophotometer Analysis) test offered by Analysts Inc. based in Los Angeles. The procedure involves filtration of oil samples on a special filter media that collects dissolved varnish to produce a distinct color. The color intensity can be directly related to varnish potential in Table 1.

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A well designed and functioning varnish removal system should reduce the VPR to well below the “normal” value of 35.

Electrohydraulic Control Fluid

Electrohydraulic control (EHC) fluids will also accumulate debris and varnish. A malfunction of turbine control valves due to contaminated control fluid can be a serious issue. The most common compounds utilized as EHC fluids are phosphate esters, for example, organic compounds where the phosphate addition improves fire resistance. A common method for filtering EHC fluid is to pass a slipstream through material such as Fuller’s Earth. However, this process introduces hardness ions to the fluid, which in turn can react with degraded EHC to produce tenacious deposits such as calcium phosphate.

A technology to combat hardness-based deposit formation is to install an ion exchange column on the slipstream, where the exchange media removes the hardness ions. Use of ion exchange for phosphate ester treatment allows the operator to selectively target both acidity and resistivity of the fluid by combining different concentrations of anionic and cationic resins. The flow rate required for these systems is relatively small, resulting in minimal resin volume requirements, where the resin may last for several months before a change-out is needed.

References

1 B. Buecker, “Membrane Magic”; Power Engineering, pp. 26-30, September 2005.

2 F. Guerzoni, “Eliminating Varnish, Power Engineering, pg. 50, February 2009.

Author: Brad Buecker is the Technical Support Specialist with AEC PowerFlow in Kansas City, MO. He previously served as an air quality control specialist and plant chemist for Kansas City Power & Light. Buecker has written many articles on steam generation, water treatment, and FGD chemistry, and he is the author of three books on steam generation topics published by PennWell Publishing. He has an AA in pre-engineering from Springfield College in Illinois and a BS in chemistry from Iowa State University. He is a member of the ACS, AIChE, ASME, and NACE.