High purity water and the steam produced from it constitute the lifeblood of most process plants. Equipment failures and curtailed production due to water/steam issues can cost a site hundreds of thousands of dollars or more annually. Much worse, some failures can cause injury or death. So, here, we’ll examine several of the most important issues related to proper water treatment and chemistry control in steam generators.
Let’s begin with a case history. A number of years ago, a colleague and I visited an organic chemicals plant in the Midwest that every two years or so had to replace the steam superheater bundles in four 550-psig package boilers due to internal scaling. We first were shown a recently removed bundle; roughly ¼-in.-thick deposits covered the internal tube surfaces. We then inspected the boilers and immediately noticed foam issuing from the saturated steam sample lines. Subsequent investigation revealed that total organic carbon (TOC) levels in the condensate return to the boilers sometimes reached 200 ppm — ASME guidelines  call for a maximum TOC concentration of 0.5 ppm in boilers of this pressure. So, it was easy to see why much foam existed in the boiler water and why impurities carried over to the superheaters on a continual basis.
The Impact Of Impurities
Impurities cause corrosion, scaling and other problems. These become more severe as boiler pressures and temperatures increase. Fortunately, the power industry has learned some lessons that directly apply to chemical plants, particularly ones that generate high-pressure steam for process needs or electrical generation. For example, Tables 1 and 2 summarize guidelines developed by the Electric Power Research Institute (EPRI) for makeup water effluent and condensate pump discharge (CPD) for heat recovery steam generators (HRSGs) .
An examination of the effects of some of these impurities reveals why the limits are so low. Consider chlorides. Even small amounts that enter the steam generator, say, from a condenser tube leak or contaminated condensate return, if chronic and not neutralized by the boiler-water treatment program, will concentrate under deposits on boiler internals. Chloride salts in the high temperature boiler environment can react with water per:
MgCl2 + 2H2O + heat → Mg(OH)2↓ + 2HCl (1)
The hydrochloric acid produced may cause general corrosion by itself — worse yet, the acid will accumulate under deposits, where it can react with iron to generate hydrogen. The hydrogen gas molecules penetrate into the metal wall where they then combine with carbon atoms in the steel to generate methane (CH4):
2H2 + Fe3C → 3Fe + CH4↑ (2)
Formation of the gaseous methane and hydrogen molecules causes cracking in the steel, greatly weakening its strength (Figure 1). Hydrogen damage is very troublesome because it’s not easily detected. After such damage has occurred, the plant staff may replace tubes only to find that other tubes continue to rupture. I once was part of a team that had to deal with hydrogen damage in a 1,250-psig utility boiler. Operations personnel insisted on running the unit for several weeks with a known condenser leak. Even though the team did its best to maintain adequate boiler water chemistry, the ultimate outcome was extensive hydrogen damage that required a complete boiler retubing.