October 2021

Water Management

Advanced methods for controlling boiler tube corrosion and fouling—Part 1

Many heavy industrial plants, such as refineries and petrochemical facilities, require steam for numerous processes, including powering turbines, providing energy for a variety of unit operations and even heating buildings in some locations.

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

Many heavy industrial plants, such as refineries and petrochemical facilities, require steam for numerous processes, including powering turbines, providing energy for a variety of unit operations and even heating buildings in some locations. However, as the authors and their colleagues have frequently observed, steam generators and their auxiliary systems are often not given the same attention as other plant processes. Only after failures occur do plant personnel begin to understand the importance of reliable makeup water preparation, impurity control in boiler feedwater and condensate return, and careful selection of internal boiler water treatment programs.

Common boiler corrosion and failure mechanisms include tube overheating, caustic gouging, acid phosphate corrosion and hydrogen damage, all of which are accentuated and often initiated by boiler tube deposits. Deposition can be problematic in both direct-fired and waste heat boilers. As an example of the latter, this article includes a discussion of corrosion in olefins plant transfer line exchangers (TLEs), which quench cracked hydrocarbons and generate steam in the process.

Part 1 of this two-part article series focuses on condensate return and feedwater corrosion protection, as corrosion products from these locations are often the most troublesome impurities that can reach the boilers.

A core principle: Minimizing deposit formation

For steam generators in virtually all industries, a core principle for boiler protection is minimizing deposit formation in boiler tubes and other internals. Even with seemingly proper boiler water chemistry control, deposits can influence and enhance reactions at the tube surface to generate corrosive compounds. Corrosive and deposit-forming compounds and corrosion products may be introduced to steam generators via a variety of pathways. The most prominent pathways are:

  • Inadequate feedwater and condensate return chemical treatment
  • Upsets in makeup water treatment systems that allow impurities to enter boiler feedwater
    • The flip side to this issue is a modification in makeup water treatment that may solve some problems but introduce others
  • Cooling water in-leakage from a steam condenser or other water-cooled heat exchanger into condensate
  • Process chemical leaks into condensate return.

A definite purpose lies behind the order of this list, as the first two issues may accentuate the following two. Examples follow.

Corrosion control in condensate/feedwater systems

Since the advent of steam use for industrial purposes, and as boiler pressures and temperatures increased with evolving technology, a key focus has been condensate/feedwater system corrosion, transport of corrosion products to boilers, and the effects of deposition on boiler corrosion and heat transfer.

Carbon steel is the primary material for most condensate and feedwater systems. A large facility may have many miles of carbon steel piping and other equipment. Common corrosive agents in these systems are dissolved oxygen (DO) and carbonic acid, which damage material and release iron oxide to the condensate (FIG. 1 and FIG. 2).

FIG. 1. Oxygen attack of a carbon steel feedwater line.
FIG. 2. Carbonic acid grooving in a condensate return pipe.

Even with good chemistry control, some carbon steel corrosion will occur. The majority of corrosion products, generally over 90%, exist as iron oxide particulates that will travel to the boiler without some form of filtration. The products then deposit on the boiler tubes, usually on the hot side. Reduced heat transfer is one difficulty with iron oxide deposition, and it leads to increased costs for fuel firing. Tube overheating is potentially much more troublesome (FIG. 3).

FIG. 3. Influence of deposits on boiler tube wall temperatures. The increase in wall temperature can degrade metal integrity and lead to premature failures from metal deformation.

Adding to these difficulties is the porous nature of iron oxide particulates, which allow water to penetrate through various channels. As the water approaches the tube surface, temperatures increase. The water boils off, leaving other species behind. This phenomenon is known as wick boiling (FIG. 4).

FIG. 4. An illustration of wick boiling. 

Boiler water impurities, including treatment chemicals, can concentrate many times at the tube surface and induce corrosion (sometimes severe) that may lead to rapid boiler tube failures. A common reaction in boilers subject to contaminant ingress is shown in Eq. 1:

MgCl2 + 2H2O→Mg(OH)2↓ + 2HCl                                                                (1)

One product of this reaction is hydrochloric acid (HCl). While HCl can cause general corrosion in and of itself, the compound will concentrate under deposits where reaction of the acid with iron generates hydrogen, which in turn can lead to hydrogen damage in the tubes. In this mechanism, atomic hydrogen penetrates into the steel and reacts with carbon atoms to generate methane (CH4), as shown in Eq. 2:

4H + Fe3C→ 3Fe + CH4↑                                                                               (2)

Gaseous methane and hydrogen molecule formation induces cracking, greatly weakening the steel’s strength. Hydrogen damage is troublesome because it cannot be easily detected. After hydrogen damage has occurred, the plant staff may replace tubes only to find that other tubes continue to rupture (FIG. 5).

FIG. 5. Hydrogen damage. Note the thick-lipped failure with little metal loss from direct corrosion.

One may consider an important twist to this example. As will be discussed later, sodium phosphate compounds, and sometimes even straight caustic (NaOH), are added to boiler water to maintain alkalinity and minimize general corrosion. However, under heavy deposits, sodium hydroxide concentrations can rise to much higher levels than in the bulk boiler water. The concentrated NaOH attacks the boiler metal and protective magnetite film via the following reactions, shown in Eqs. 3 and 4:

Fe + 2NaOH→ Na2FeO2 + H2↑                                                                                 (3)

Fe3O4 + 4NaOH→ 2NaFeO2 + Na2FeO2 + 2H2O                                                         (4)

The upshot of these examples is that chemistry throughout the steam generation system requires careful control to minimize corrosion and corrosion product transport. Modern methods for this purpose are examined in the next section.

Feedwater and condensate return system protection

A critical requirement for steam generating systems is proper pH control to minimize general corrosion. An extremely informative graph of the effects of pH and temperature on carbon steel corrosion was prepared a half century ago and is shown in FIG. 6.

FIG. 6. Influence of temperature and pH on iron dissolution from carbon steel.1

This research was conducted in high-purity water samples. A key aspect of this chart is the influence of pH on carbon steel corrosion, which greatly decreases with pH elevation from 8.75 to 9.6. Note that the results were based on pH adjustment with ammonia (NH3), the common feedwater pH-conditioning chemical for power plants, especially those with no copper alloys in the feedwater system. Ammonia raises the pH via the reaction shown in Eq. 5:

NH3 + H2O ↔ NH4+ + OH                                                                                      (5)

Eq. 5 is an equilibrium reaction; therefore, the alkalinity increase is limited, minimizing excessive steel corrosion in the event of a chemical feed upset.

Complications arise in many industrial condensate systems as they have multiple metallurgies, often including copper alloy heat exchanger tubes. Ammonia and dissolved oxygen in combination are very corrosive to copper. Furthermore, the optimum pH range for general copper corrosion control is 8.8–9.1, somewhat lower than the pH range for carbon steel. In systems with both carbon steel and copper alloys, a balanced pH range of 9–9.3 is often recommended. Accordingly, for many industrial units, neutralizing amines may replace ammonia. Neutralizing amines are small-chain organic molecules with an ammonia group attached to or embedded within the compound (FIG. 7).

FIG. 7. Common neutralizing amines.

Some of the amines have a higher basicity than ammonia and can raise the pH to higher levels if necessary. Another important property of these chemicals is the distribution ratio—i.e., the amount of amine that carries over with steam vs. the amount that remains in the water. The ratios vary with boiler temperature and pressure, but some products tend to remain in the boiler water while others significantly partition with the steam. Careful selection of a blended product can provide comprehensive pH conditioning to the boilers, steam system and condensate return network.

Also important for condensate/feedwater treatment is choosing an oxygen scavenger/metal passivation chemical. Industry-standard practice, especially in the power industry, had been to remove all dissolved oxygen from feedwater to minimize the corrosion shown in FIG. 1 and protect copper alloys, if present. Accordingly, almost all steam-generating systems were equipped with a mechanical deaerator and oxygen scavengers/reducing agent feed systems. However, the last four decades have seen a number of high-pressure feedwater piping failures, some of which have caused fatalities.

Researchers have learned that the reducing environment produced by oxygen scavengers is the prime ingredient for single-phase, flow-accelerated corrosion (FAC) of carbon steel. The attack occurs at flow disturbances, such as elbows in feedwater piping and economizers, feedwater heater drains, locations downstream of valves and reducing fittings, attemperator piping, and, most notably for combined-cycle heat recovery steam generators (HRSGs), in low-pressure evaporators, where the waterwall tubes (i.e., harps) have many short-radius elbows. These locations correspond to the temperature influence shown in FIG. 5. Single-phase FAC has an orange-peel texture, as shown in FIG. 8.

FIG. 8. Surface view of single-phase FAC. Note the orange-peel texture.

Gradual metal loss occurs at FAC locations until the pipe wall in the affected zone can no longer withstand the fluid pressure. Sudden failure is the result, accompanied by the release of high-temperature water (FIG. 9).

FIG. 9. Photo of tube wall thinning caused by single-phase FAC.

The combination of ammonia or neutralizing amine feed, along with one of the volatile oxygen scavengers/reducing agents described previously, is known in the power industry as all-volatile treatment reducing [AVT(R)].

European and Russian facilities began moving away from AVT(R) in power units in the late 1960s and early 1970s. Researchers and chemists at supercritical power plants discovered that in high-purity feedwater (cation conductivity ≤ 0.15 µS), the deliberate injection of a small amount of oxygen (to establish a DO concentration of 50 ppb–300 ppb) and elimination of oxygen scavenger feed would cause the grayish-black magnetite (Fe3O4) layer on carbon steel surfaces to become interspersed and overlaid with a different oxide layer, known variously as α-hematite and ferric oxide hydrate. With rigorously maintained chemistry, this oxide forms a much tighter bond than magnetite and greatly minimizes FAC. The program gained the name of oxygenated treatment (OT) and was adapted as the replacement for AVT(R) at many supercritical units around the world, although it is unacceptable for units with copper-alloy tubed feedwater heaters, as the combination of oxygen and ammonia will cause severe copper alloy corrosion.

Subsequently, the Electric Power Research Institute (EPRI) developed a program to replace AVT(R) for drum units with AVT(O), which stands for all-volatile treatment oxidizing. If the condensate/feedwater system contains no copper alloys (which is true for virtually all modern HRSGs), then AVT(R) is not recommended. In brief, with AVT(O) chemistry, as with OT, the oxygen scavenger feed is eliminated. A small residual concentration (5 ppb–10 ppb) of dissolved oxygen is required at the economizer inlet. Ammonia or an ammonia/neutralizing amine blend is still utilized for pH control. High-purity condensate (cation conductivity ≤ 0.2 µS/cm) is required for AVT(O), but when proper conditions are established, the magnetite becomes overlaid and interspersed with the tighter-bonding α-hematite. The layer is noticeable for its distinct red color (FIG. 10).

FIG. 10. Properly passivated surfaces in a unit on AVT(O). Photo courtesy of Dan Dixon, Lincoln Electric System.

OT and AVT(O) have proven so successful that the major power chemistry research organizations strongly recommend the elimination of oxygen scavengers in all power steam generators unless the feedwater system contains copper alloys.

However, AVT(O) and OT often cannot be employed at industrial plants because the feedwater does not meet the purity limits previously listed. Dissolved oxygen would cause serious carbon steel corrosion. Also, many industrial heat exchangers have copper alloy tubes, which, as has been noted, can suffer serious attack from the combination of ammonia (including ammonia generated by neutralizing amine decomposition) and oxygen. Amine/oxygen scavenger treatment is required in these cases to minimize corrosion.

This issue and others must be factored into the selection and monitoring of condensate/feedwater treatment programs, including those at industrial plants that have switched to high-purity makeup systems but still see impurity ingress from the condensate return.

Formerly, sodium softening to remove hardness was the primary treatment method at many industrial plants. This fundamental technique had both advantages and disadvantages, with low cost being a primary benefit. However, softening system upsets or inadequate effluent monitoring may cause severe boiler tube scaling, as the authors and their colleagues have observed at many facilities. A dramatic example is shown in FIG. 11.

FIG. 11. Severe calcium carbonate (CaCO3) scaling in a low-pressure boiler tube. This is the same scale that appears in home hot water systems.

In many cases, notably at refineries and similar industrial facilities with high-pressure boilers, the modern makeup arrangement is reverse osmosis (RO), perhaps followed by ion exchange (IX) demineralization. However, at any plant where a change is made from softened to higher-purity water, careful evaluation of feedwater treatment chemistry is recommended. Simple sodium-softened water still contains the alkalinity from the raw supply. This alkalinity can help protect the feedwater piping. Without feedwater treatment modifications, a change to high-purity water may lead to the corrosion issues noted previously, including FAC.

Continuing evolution of film-forming products

Research and development continues to improve film-forming products (both amine-based and those based on other compounds with alternative active groups) for steam system metal protection. Decades ago, filming amine chemistry was applied to steam generators, with a common compound being octadecylamine (ODA, C18H39N). The amine group attaches to the metal surface, and the hydrophobic organic “tail” extends into the fluid to shield the metal (FIG. 12).

FIG. 12. General illustration of filming amine attachment to metal surfaces.2

However, poor control and lack of knowledge often lead to problems with ODA applications, including formation of gelatinous spheroids, or “gunk balls” in the common vernacular, which fouled steam generators. More advanced amine and non-amine film-forming products (FFP) have been developed. Most of these operate best in mildly basic conditions, so neutralizing amine treatment is still necessary. Product feed is based on the residual concentration that best protects metal surfaces. Regular iron monitoring can be very important in evaluating and fine-tuning programs. Some products will actually cause dissolution of porous iron oxide deposits during initial application, which can sometimes be falsely assumed as base metal corrosion.

Much of the effort to date has been concentrated in the power industry, and literature2 provides details of a recent successful case study of a film-forming amine (FFA) application. This chemistry is also expanding into the refining and petrochemical industries. Successful products provide true corrosion inhibition by forming a chemical barrier on the metal surface. They do not offer a panacea for poor chemistry control; however, they do offer strong potential for comprehensive steam generator corrosion protection. The authors hope to provide more details in the near future with an article devoted to this technology.

With the wide variety of intermediate and final products generated at industrial plants, the possibilities for contaminant leakage into condensate return are enormous. Impurities may include complex organics, strongly acidic or basic compounds, mineral salts and many others.

One way to minimize impurity transport to boilers is by equipping the condensate return system with a dump line so that an excursion shown by instrument readings (e.g., specific conductivity) will open a valve and allow the condensate to be drained rather than returned to the steam generators. Some plants employ total organic carbon (TOC) analyzers to monitor return condensate. If neutralizing amines are utilized for pH adjustment, the contributing TOC from the amine is taken into consideration, and a target TOC is selected for dumping. Dumping can involve a large loss of water and may require special makeup water system design to handle periodic high makeup requirements. An alternative idea—albeit one that requires additional funding and staffing—is to place a condensate polisher on the return line to the boilers. The choice of equipment and polishing process will depend on the impurities to be removed and mechanical conditions such as flowrate, temperature and pressure, but a number of options are available, including:

  • Ion exchange resins, with some flexibility of selection for particular contaminants
  • Particulate removal by fabric or mechanical filters.

Ion exchange resins can be specifically designed to remove a variety of dissolved ions, ranging from primary cations and anions to other trace constituents. However, some resins may be limited by temperature, as some anion resins begin to break down at temperatures not much higher than 100°F.

Direct filtration is a straightforward technique, particularly if system corrosion generates a significant amount of iron oxide or other metal particulates. A prime example comes from the power industry, where air-cooled condensers (ACC) are sometimes chosen as an alternative to cooling towers and water-cooled condensers for water conservation. ACC units require a huge amount of carbon steel piping to effectively cool turbine exhaust steam, and even with the best chemical treatment programs, the process still introduces a large amount of iron oxide particulates to the condensate.

Recommendations

Proper boiler protection starts with reliable makeup water system operation and good control over corrosion and impurity ingress in condensate return systems. Key principles include:

  • Maintaining and controlling makeup systems to provide consistent effluent. Upsets can send many scale-forming or corrosive ions and compounds to the boiler, including hardness, aggressive anions and silica.
  • Controlling chemistry consistently for unit protection. While consistent makeup water quality is important, many impurities and corrosion products can enter the condensate return from leaking condensers and process heat exchangers. Condensate return dumping and polishing methods are available for mitigating these difficulties.
  • Monitoring systems consistently. The importance of monitoring cannot be overstated. Upsets have been known to cause boiler tube failures within days, and sometimes even hours. Continuous online instruments are available for complete steam generation chemistry monitoring. Intelligent water management software is also 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.

All systems are different. Like all technologies, due diligence is necessary to determine the feasibility for utilizing these methods. Equipment manuals and guides should always be consulted before making changes to systems and treatment processes. HP

LITERATURE CITED

  1. Sturla, P., Proc., Fifth National Feedwater Conference, 1973, Prague, Czechoslovakia.
  2. Stuart, D., “Mitigating flow-accelerated corrosion with film-forming chemistry in HRSGs,” Power Engineering, April 2021, online: www.power-eng.com

The Authors

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