Appearance:

Hydrogen damage can produce a "window opening" and thick-edged split fracture appearance.  The thick-edged fracture surface will outline the region of hydrogen damage. Hydrogen damage failures are thick-lipped, limited ductility fractures on the fire side of the tube.  Often the first appearance will be in the highest heat release regions of the furnace, just downstream of circumferential butt welds.  The ID of the weld disturbs the fluid flow and promotes rapid deposit build-up.  

Internally, hydrogen damage typically appears as intergranular cracking along with grain boundary fissures. Hydrogen becomes trapped underneath tenacious deposits and reacts with the carbon in the steel form methane. The methane molecule is much bigger than the hydrogen molecule; this causes pressure at the grain boundaries, resulting in grain boundary fissures and cracks. Patterns of decarburization are also present.

The root cause of hydrogen damage can be verified by chemicals in the boiler, and in the amount of deposition on the boiler tubes.  Tube sampling is performed to measure the relative thickness and amounts of deposit buildup on the heated side of the internal surface.  Tube sampling practices and test methods are detailed in ASTM Standards D 887-82 and D 3483-78. 

Potential sources of corrosive chemicals include in-leakage from the condenser, malfunction of the boiler water conditioning facilities, and errors in the boiler chemical cleaning process.  In-depth review of chemical control logs, on-line water chemistry records, and instrumentation alarms can be performed.

Corrective actions involve the restoration of boiler water chemistry to the proper values and the consideration of boiler chemical cleaning. Chemical cleaning should be considered when the boiler water pH has been below 7 for more than one hour due to the ingress of saline condenser cooling water or acidic chemicals into the boiler from a breakdown of boiler water conditioning facilities.  Chemical cleaning is performed to remove the internal deposits and to stop further generation of hydrogen on the tube surface.  If significant wall thinning has occurred, the tube will have to be replaced to prevent a ductile type fracture later in service.

One of the problems of hydrogen damage is that it is often invisible until the first failure occurs, and by then it may be found universally throughout the boiler. The thick deposits form rapidly when the pH is out of the control range.  Boilers should be kept clean to prevent thick water-side deposits from developing.  The boiler water needs to be carefully controlled at all times.  When known pH excursions occur, the boiler should be immediately shut down and chemically cleaned.

Periodically clean the boiler tubes to reduce the risk of under-deposit corrosion. Avoid the combination of oxygen and moisture when the unit is idle (short-term or long-term). Carefully dry the unit with the igniters before opening it to the atmosphere.  Periodic tube sampling from representative areas can mitigate serious waterside issues. Use rifled tubing in the high-heat flux areas to reduce under-deposit corrosion. Prevent the source of contamination in the case of thick deposit. Shutdown the unit immediately in the case of contamination ingress. Reduce flow disruptions in the tubes. For example, avoid using backing rings during butt welding. Select a unit-specific feedwater treatment program. Equilibrium phosphate control can be adopted for drum units operating ~2500 psi. Use of mono or di-sodium phosphate should be avoided.  Keep the amount of particulate iron oxide as low as possible by blowdown to prevent build-up of thick scales. Note that heavy blowdowns may offset the feedwater chemistry, which may promote other issues.    Monitor high-heat flux zones for under-deposit corrosion. Perform non-destructive examination to identify under-deposit corrosion and hydrogen damage, specifically on the hp evaporator tubes, slope tubes, roof tubes and high heat flux zones. All hydrogen-damaged tubes should be replaced. Note that chemical cleaning cannot remove these extremely thick and tenacious deposits. In the event of a major contamination, shutdown the plant and perform chemical cleaning. Prolonged operation during this time can adversely affect the pressure parts. Pad welding should be avoided on hydrogen-damaged and corrosion fatigued tubes and also on thin-wall tubes (less than 0.125”) because of the possibility of burn-through, which causes flow disruption. Also, copper not removed prior to welding (from waterside deposits) can diffuse into the tube, resulting in embrittlement. 

In order for cracking to develop, two factors are necessary: 1) a boiler-water pH that is strongly basic or, more commonly, strongly acidic; and 2) thick, usually localized, water-side deposits that promote under-deposit corrosion.  The deposits may be small, perhaps the size of a quarter.

Hydrogen damage occurs in all steam-generating units that operate above about 1000 psi, but is more common in the higher-pressure units, those operating above 1800 psi.

Related Mechanisms:

Under deposit corrosion, caustic gouging, and acid phosphate corrosion.

Removing deposits via chemical cleaning is considered a necessary part of boiler maintenance. The objective of a chemical cleaning is to safely remove all the deposits from the inside of the boiler tubes.  In higher-pressure boilers, the major deposit removed is magnetite, and some copper.

Chemical cleaning can improve the boiler heat rate and reduce the number of tube failures. It typically improves the stability of boiler chemistry. However, there are also down sides to chemical cleaning.

One of the most common criteria is the deposit loading on the inside of the water wall tube. The plant will take two or three boiler tube samples from the high heat flux areas of the boiler and have the deposit loading analyzed on each. An average of the hot-side loading on the tubes is compared against a chart. This is still the best way to determine the need to use chemical cleaning, assuming that there have been no major contamination incidents since the last chemical cleaning.

In the past, some boiler operators cleaned based on time — either the number of operating hours or the number of years since the last chemical cleaning. This is probably the worst way to determine the need to use chemical cleaning.

Deposits do not form on boiler tube walls at a uniform rate over time.  Immediately after a chemical cleaning, the boiler tubes create a protective film of magnetite that limits further corrosion of the base metal.  This quickly adds 3 to 5 or so grams/ft.2 of deposits to the boiler. Over time, new deposits collect on top of this protective layer. These deposits typically come from the boiler feed water. Boiler start-ups and shutdowns can ⁱadd a tremendous amount of deposit to the boiler tube wall. The number of start-ups is a better predictor of tube deposit density than operating hours.  Time-based cleanings do not consider water chemistry (good or bad) or the amount of deposits since the last cleaning. It may be that the water chemistry control has been particularly poor and the deposit loading is high. In that case, the frequency should be increased. The opposite might also be true, and the chemical cleaning can be put off for years.

This criterion is often overlooked, particularly by those who clean on a set time schedule. If there is a major contamination of the boiler water, a chemical cleaning must be performed at the next opportunity, preferably before the unit is restarted. The most common contamination incidents are calcium hardness in the boiler from a condenser tube leak or demineralizer/softener malfunction.  This contamination creates corrosion cells that lead to caustic gouging and hydrogen embrittlement. In these cases, the high risk of major water wall damage outweighs the risks associated with chemical cleaning.

The need to use chemical cleaning is the result of corrosion products building up on the boiler tube walls. The more corrosion products generated in the boiler and feed water system, the more often the unit will require chemical cleaning.  Reducing corrosion in these areas can improve overall boiler chemistry and extend the time between cleanings.

A large percentage of the corrosion products on boiler tube walls come in from the feed water system during start-up. Improving lay-up and start-up practices can mean the difference between needing to clean with chemicals every three years and every 12 years. Find a knowledgeable consultant or chemical vendor that will help you develop better lay-up and start-up practices and get out of the chemical cleaning cycle.

Typical locations water-cooled carbon steel tubes can experience hydrogen damage include:

1) Areas experiencing flow disruptions, such as welded joints with backing rings or protrusions, bends, or deposits

2) Horizontal or inclined tubing

3) High heat flux areas

4) Tubes located above burner elevation

5) Tubes located below nose arch area

6) Roof tubes

7) Lazy circuits