November 2021

Water Management

Advanced methods for controlling boiler tube corrosion and fouling—Part 2

In Part 1 of this article, the authors covered techniques for minimizing corrosion and contaminant ingress from condensate return and feedwater to industrial steam generators.

Kraetsch, K., Buecker, B., ChemTreat, Inc.

In Part 1 of this article, the authors covered techniques for minimizing corrosion and contaminant ingress from condensate return and feedwater to industrial steam generators. While some corrosion mechanisms can cause severe damage to condensate and feedwater piping, heat exchangers and other equipment, the release of corrosion products or the transport of other impurities to the boilers can also cause major problems. This article examines internal boiler treatment programs, which include several critical functions, including:

  • pH control within a mildly alkaline range to minimize general corrosion
  • Reaction with impurities to keep contaminants in suspension and minimize deposition on boiler internals.

As suggested in Part 1, even well-treated boilers may have chemistry underneath existing deposits that varies greatly from the bulk boiler water, and severe corrosion under these deposits may lead to tube failures and unit outages. This article includes a direct example of this scenario.

Internal boiler water treatment

As power generation units increased in number and size in the 1930s, tri-sodium phosphate (Na3PO4, or TSP) became a popular water conditioning chemical for drum boilers. At that time, phosphate treatment served two primary functions. The first was to establish moderately alkaline conditions in the boiler to minimize general corrosion of carbon steel boiler tubes, drums and headers (Eq. 1):

Na3PO4 + H2O } Na2HPO4 + NaOH                                                               (1)

This function is still critical today.

The second function of phosphate was—and in some cases, still is, for industrial boilers—control of hardness ingress. Phosphate will react with hardness to form soft sludges that may be blown down, as opposed to the hard scale shown in FIG. 11 of Part 1. However, as high-pressure units evolved in the last century, some boilers were plagued by under-deposit caustic corrosion generated by the rather high concentrations of TSP needed for scale control. This led to the development of coordinated and congruent phosphate treatment programs that were often a blend of tri- and di-sodium phosphate (DSP), but sometimes included a small amount of monosodium phosphate (MSP). DSP and MSP will shift Eq. 1 to the left and reduce the NaOH concentration.

The development of congruent treatment was also influenced by the discovery that sodium phosphates become reversely soluble at temperatures above approximately 250°F (FIG. 13).

FIG. 13. Solubility of tri-sodium phosphate as a function of temperature.

In high-pressure boilers, most of the phosphate added for pH and, if necessary, hardness control may precipitate on boiler internals. This precipitation, known as “hideout,” is accentuated by boiler tube deposits. Congruent treatment was developed to maintain similar sodium-to-phosphate ratios between the chemical remaining in solution with that in precipitate, although this often does not occur.

Even so, phosphate treatment remains a strong choice for industrial boilers, particularly because the potential for hardness ingress to many industrial units is much greater than for utility units. TSP is now the only phosphate species recommended for power boilers and is applied at low concentrations to minimize hideout. Industrial boiler treatment should be evaluated on a case-by-case basis. If heavy deposits are present, then chemistry control may “run on the razor’s edge,” so to speak. If only TSP is used, then excess hydroxide could potentially concentrate under the deposits and generate caustic attack. Conversely, under a congruent program, acid phosphate compounds might form and attack the tube metal.

As the following example illustrates, significant improvements are often possible if dispersion polymers are added to boiler water treatment formulations. This example also highlights the difficulties with localized hot spots that often exist in specialized steam generators. Such locations can accentuate deposition and under-deposit corrosion.

Specialty boiler influence on corrosion

Certain unit processes produce waste heat or high-temperature product gas that is utilized for steam generation. Examples include syngas from ammonia production, the offgas of steel and annealing furnaces, cement kiln flue gas, etc. Waste heat boiler design is often unique and may include localized high heat transfer zones. These features can significantly influence corrosion issues and boiler water treatment.

A prime example from the refining industry is pyrolysis effluent gas from cracking furnaces, which is quickly cooled in transfer line exchangers (TLEs). Normally associated with ethylene production, TLEs also can be found in petrochemical industries that produce syngas from methane steam reformation, such as methanol, acetic acid, formaldehyde and others. The TLE cools the pyrolysis gas to prevent further hydrocarbon cracking, generating steam for other unit operations in the process.

A TLE is similar to a fire-tube boiler, with the cracked gas stream on the tube side and water on the shell side. The design incorporates a steam drum and operates under natural, thermally induced boiler water circulation. Many different designs are available from various manufacturers, and the design geometry can be either horizontal or vertical (FIG. 14).

FIG. 14. Basic flow diagrams of horizontal and vertical TLEs. Primary TLEs are heated with pyrolysis gas. Some systems may also have secondary TLEs heated with the partially cooled gas from the primary TLEs.

In many configurations, several TLEs are attached to a common steam drum. The boiler water from the steam drum flows through downcomers to several TLEs in a natural circulation arrangement, with the resulting steam/water mixture returning to the steam drum via riser tubes. Temperature-resistant materials are often used for ferrule inserts on the inlet of the hot gas path to protect the thicker tubesheets, which are also coated with refractory. Horizontal TLEs may include individual blowdown lines that tie into the common continuous blowdown from the steam drum. These boilers offer a classic example of problems that can occur in localized high heat flux zones (FIG. 15).

FIG. 15. Localized corrosion in a high heat flux zone of a TLE.

The authors’ company has investigated numerous TLE tube failures with visible metal wastage that occurred just inside the tube sheet and under deposits. Corrosion evaluation requires detailed metallurgical analyses, as some mechanisms, most notably acid phosphate corrosion and caustic attack, have similar morphologies even though they are far apart on the pH spectrum. The bulk water chemistry may be satisfactory, but heavy deposits on the tube surface can still initiate and perpetuate corrosion.

Three primary areas of focus exist for facilities looking to alleviate such problems:

  1. Maintaining consistent feedwater purity
  2. Establishing an internal boiler water treatment program with reduced phosphate concentrations to minimize hideout
  3. Selecting effective polymers to aid in the dispersion of iron (and copper, where applicable) corrosion products transported from elsewhere.

A dispersion polymer is recommended in all TLEs or similar waste heat boilers. However, the thermal stability of dispersion polymers becomes very challenging as pressures exceed 1,200 psi. Blended phosphate/polymer products perform well up to approximately 1,800 psi; other blends are available that function at even higher pressures. However, the proper choice can be made only after a thorough evaluation of system operating conditions (with pressure being a prime factor), metallurgy, feedwater quality and other factors. Polymer supplements are not a ticket for operating outside of American Society of Mechanical Engineers (ASME) guidelines, however. Regardless of chemical treatment, hardness, for example, can be very problematic in high-pressure boilers. Note: A revision to the existing ASME boiler guidelines is being finalized, and it may be released this year.

Notes on steam system protection

This two-part article series focused on methods for minimizing corrosion and deposition within the condensate/feedwater systems and boilers of steam generating systems. While these issues are extremely important, protecting the steam system may be even more critical, particularly if the steam powers turbines. Steam turbines are highly tuned mechanical devices that are extremely expensive to repair or replace after mechanical or chemical failure, and may hobble a plant for months, if not longer.

Additionally, solids carryover into steam can induce deposition and corrosion in superheaters, which may cause heat exchanger failure even in industrial steam generators without turbines.2 Depending on unit pressure, some steam chemistry guidelines call for impurity limits at low parts-per-billion (ppb) levels. Steam chemistry control is, therefore, an integral part of any steam generator chemistry program.

Takeaway

A summary of key principles for internal boiler water treatment and corrosion/scale control follows:

  • Careful selection of an internal boiler water treatment program is recommended. The choice of phosphate treatment often depends greatly on makeup quality. Maintaining low phosphate concentrations is now common practice for avoiding hideout.
  • Dispersion polymers can be effective up to approximately 1,800 psi to sequester metals transported to boilers. These contaminants can be removed via blowdown. Minimizing iron and copper deposition will help reduce the risk of under-deposit corrosion.
  • Proper boiler water chemistry control is also critical for preventing carryover and other impurity ingress to steam. Some contaminants can cause major damage, particularly if the steam drives turbines for electrical or mechanical output.3
  • The importance of monitoring cannot be overstated. Upsets have been known to cause boiler tube failures within days, sometimes even hours. Continuous online instruments are available for complete steam generation chemistry monitoring. Intelligent water management software is available for tracking and analyzing data and providing reports and alarm notices to plant personnel. This program is also well suited for monitoring other plant water systems, including cooling water.

Each system is different and has unique treatment needs, and due diligence is necessary for determining the feasibility for utilizing these methods. Equipment manuals and guides should always be consulted, and a water treatment professional contacted, before changes are made to systems and treatment processes. HP

LITERATURE CITED

  1. Kraetsch, K. and B. Buecker, “Advanced methods to control boiler tube corrosion and fouling–Part 1,” Hydrocarbon Processing, October 2021.
  2. Buecker, B., “Condenser chemistry and performance monitoring: A critical necessity for reliable steam plant operation,” Proceedings of the 60th Annual International Water Conference, October 18–20, 1999, Pittsburgh, Pennsylvania.
  3. Shulder, S., B. Buecker and A. Sieben, “Fossil power plant cycle chemistry,” Pre-conference seminar, 39th Annual Electric Utility Chemistry Workshop, June 4–6, 2019, Champaign, Illinois.

The Authors

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