CAUSES OF DAMAGE TO BOILER

HOW TO DESTROY A BOILER

This article written for the National Board of Mechanical Inspectors covers the four most common ways to "destroy a boiler," including fuel explosions, low-water conditions, poor water treatment, and improper warm-up.

The design and construction of power and recovery boilers represent one of the largest capital expenditures in the industrial utilities arena. The operational reliability and availability of these boilers is often critical to the profitability of the facility. Safe operation of these units requires careful attention to many factors. Failure to follow a few well-established practices can, and likely will, result in a catastrophe. The most common ways to "destroy a boiler" include the following:

· Fuel Explosions

· Contaminated Feedwater

· Low-Water Conditions

· mproper Blowdown Techniques

· Poor Water Treatment

· Improper Storage

· Improper Warm-up

· Pulling a Vacuum on the Boiler

· Impact Damage to Tubes

· Flame Impingement

· Severe Overfiring

Fuel Explosions

One of the most dangerous situations in the operation of a boiler is that of a fuel explosion in the furnace. The photo above shows the complete devastation of a utility boiler.

Conditions have to be just right for an explosion to occur and when a boiler is properly operated, it is not possible for such an event to take place. The most common causes of a fuel explosion are:

Fuel-rich mixtures - The danger of a fuel-rich mixture is that high concentrations of unburned fuel can build up. When this unburned fuel ignites, it can do so in a very rapid or explosive manner. Fuel-rich mixtures can occur any time that insufficient air is supplied for the amount of fuel being burned. Never add air to a dark smoky furnace. Trip the unit, purge thoroughly, then correct the problem. By adding air with a fire in the unit, you may develop an explosive mixture. While it is dangerous to have too rich a mixture, the reverse is not true. A lean mixture which results in more air than necessary, while not efficient, is not dangerous.

Poor atomization of oil - Just as fuel-rich mixtures could allow accumulation of unburned combustibles, any inventory of a combustible fuel in the furnace can result in an explosion. Boilers are blown up every year as a result of poor atomization of oil which results in incomplete combustion and can lead to unburned oil puddling on the floor of the furnace. To prevent this, the oil tips must be clean, the oil temperature must be correct, the oil viscosity must be in spec, and the atomizing steam (or air) pressure and fuel oil pressure must be properly adjusted.

Improper purge - Many of the explosions occur after a combustion problem which has resulted in a burner trip. Consider the following example: suppose that the oil tip becomes plugged, which disturbs the spray pattern, causing an unstable flame that results in a flame failure. The operator attempts to relight the burner without investigating the cause and during successive attempts to relight the burner, oil is sprayed into the furnace.

The oil on the hot furnace floor begins to volatize and release its combustible gases when the operator initiates another trial for ignition. The pilot then ignites the large inventory of unburned combustible gases in the furnace, which produces the explosion.

This entire scenario can be prevented by:

· Investigating the cause of the trip before attempts to relight.

· Allowing the furnace to purge thoroughly. This is particularly important if oil has spilled into the furnace. The purge will evacuate the inventory of unburned gases until the concentration is below the explosive limits. Purge, purge, purge!

Low-Water Conditions

The potential for severe and even catastrophic damage to a boiler as a result of low-water conditions is easy to imagine considering that furnace temperatures exceed 1,800°F, yet the strength of steel drops sharply at temperatures above 800°F. The only thing that allows a boiler to withstand these furnace temperatures is the presence of water in all tubes of the furnace at all times that a fire is present. Low-water conditions will literally melt steel boiler tubes with the result closely resembling a spent birthday candle, as shown above.

Typical industrial boilers are "natural circulation" boilers and do not utilize pumps to circulate water through the tubes. These units rely on the differential density between hot and cold water to provide the circulation. As the water removes heat from the tubes, the water temperature increases and it rises to the boiler steam drum. Eventually, sufficient heat is transferred and steam is generated. Colder feedwater replaces the water that rises, which creates the natural circulation. A typical boiler circulation (as shown below) will illustrate:

1. Boiler feedwater being introduced into the steam drum.

2. Cooler water sinking through tubes called "downcomers."

3. Water absorbing heat from the tubes, then the heated water rising to the steam drum.

Due to the critical need for water, modern boilers are equipped with automatic low-water trip switches. Some older boilers may not have these relatively inexpensive devices. If your boilers do not have low-water trips, run, don't walk, to the phone and initiate their installation. You have an accident and expensive repairs waiting to happen. The needed repairs can range from retubing to total destruction of the unit if the drums overheat. In the event of low water, the low-water trips will trip the burner (or fuel flow for solid fuel boilers) and shut down the forced draft fan. This shuts down the heat input.

The trips should be installed at a water level that will prevent damage. Normal operating level is generally near the centerline of the steam drum. Low-water trips are generally installed approximately 6" lower, but the manufacturer's drawings usually indicate normal and minimum water levels which vary from unit to unit.

The potential for damage is more critical with solid fuel-fired boilers. A gas/oil boiler has no inventory or bed of fuel. When you trip the burner, for all practical purposes, the heat input immediately stops. With solid fuel units, however, a fairly large mass of bark, coal, etc., is still on the grate and even though starved of air by the loss of the forced draft fan, these units have more "thermal inertia" and will continue to produce some heat.

The control of the boiler drum level is tricky and even the best tuned control systems cannot always prevent a low-water condition. The "water level" in a steam drum is actually a fairly unstable compressible mixture of water and steam bubbles that will shrink and swell with pressure changes and will actually shrink momentarily when more "cold" feedwater is added.

Some common causes of low-water conditions include:

· Feedwater pump failure

· Control valve failure

· Loss of water to the deaerator or make-up water system

· Drum level controller failure

· Drum level controller inadvertently left in "manual" position

· Loss of plant air pressure to the control valve actuator

· Safety valve lifting

· Large, sudden change in steam load

Unfortunately, an alarming number of boilers equipped with low-water trips are destroyed each year. Common reasons:

Disabled trip circuits - very common - a $39 jumper cable will readily foil the best-made plans (with repairs often exceeding $100,000, this represents an attention-grabbing return on investment for a $39 expenditure!). A typical scenario involves disabling the trips to eliminate nuisance trips due to improperly tuned controls, etc. This is a "band-aid" to cover the real problem and should never be allowed.

Inoperative trip switches - the trip switches should be blown down regularly to remove sludge. These switches are installed in "dead legs" where no circulation occurs. Sludge will eventually plug the piping or the switch itself.

Have you checked your trips today? Nuisance trips should not be a concern with a properly tuned boiler with proper drum internals, so this is not a valid reason to disable low-water trips. Dysfunctional low-water trips should be a "no go" item and should be corrected before the boiler is fired.

Poor Water Treatment

Boiler feedwater is treated to protect it from two basic problems: the buildup of solid deposits on the interior or water side of the tubes, and corrosion.

Prevention of scaling or buildup - The need for proper feedwater treatment is obvious if you will consider the comparison of a boiler and a pot of boiling water on the stove. The boiler is actually an oversized distillery in that the water that enters the boiler is vaporized to steam, leaving the solids behind. Depending on the amount of solids in the water, or hardness, the residue is sometimes visible when a pot containing water is boiled until all water is vaporized.

This same thing occurs inside the boiler and, if left unchecked, can destroy it. Boilers rely on the water to protect the steel boiler tubes from the temperatures in the furnace which greatly exceed the melting point of the tube material. A buildup of deposits inside the tubes will produce an insulating layer which inhibits the ability of the water to remove the heat from the tube. If this continues long enough, the result is localized overheating of the tube and eventual blowout.

In order to prevent the buildup of deposits on the tubes, the level of solids in the boiler feedwater must be reduced to acceptable limits. The higher the operating pressure and temperature of the boiler, the more stringent the requirements for proper feedwater treatment. Refer to the table below for the maximum recommended concentration limits in the water of an operating boiler according to ABMA.

Unless a power generation turbine is involved, or the water quality is particularly bad, most industrial boilers operate at sufficiently low pressures to enable the use of simple water softeners for feedwater treatment. At higher pressures and when turbines and superheaters are involved, more complex feedwater treatment systems such as reverse osmosis, demineralizer systems, etc., are required to treat the feedwater. A state-of-the-art demineralization system is shown in the photo on the opposite page.

Solids are also removed from the boiler through proper operation of the continuous blowdown system and by the use of intermittent or bottom blowdown on a regular basis. Blowdown flows reduce the solids by dilution.

High conductivity or contamination of the boiler feedwater can create other problems such as drum level instability and foaming. This can result in high or low-water alarms and an increase in the carryover of moisture droplets into the steam header since the moisture separator of the drum cannot handle the resultant carryover.

Prevention of corrosion - The most effective method of controlling corrosion is proper deaeration of the water. The removal of oxygen from the water drastically reduces the potential for corrosion. This is most often accomplished through the use of deaerators. These units typically utilize steam to both preheat the feedwater and remove the oxygen, carbon dioxide, and other gases from the make-up water. Oxygen scavenging chemicals are also commonly injected into the deaerator to provide an additional measure of protection. Additionally, the boiler steam drum, or feedwater, has generally supplied chemicals at a controlled rate for even further protection. A qualified water treatment specialist is invaluable in determining the best method for your plant and your site-specific water requirements.

Preventive measures - In order to prevent problems with poor water treatment, the following are recommended:

Verify that your boiler feedwater is of sufficient high quality for the temperatures and pressures involved. Water quality standards based on operating pressures and temperatures as recommended by ABMA should be followed.

Verify that the water leaving the deaerator is free of oxygen, that the deaerator is operated at the proper pressure, and that the water is at saturation temperature for the pressure.

Verify proper operation of the water treatment systems on a regular basis. Loss of resin from a softener or demineralizer can create problems if the resin escapes into the feedwater. Such resins can melt on the tube surfaces, resulting in overheated tubes, etc.

Never use untreated water in a boiler.

Adjust continuous blowdown to maintain the conductivity of the boiler water within acceptable limits and blow down the mud drum on a regular basis.

It is also important to blow the sludge out of all the dead legs of the low-water trips, water column, etc., on a regular basis to prevent sludge buildup in these areas. The buildup of sludge can disable the low-water trips.

The boiler water side should be inspected on a regular basis. Should any signs of scaling or build up of solids on the tubes be noted, adjustments to the water treatment should be made.

The water side of the deaerator should be inspected on a regular basis for corrosion. This is an important safety issue because a deaerator can rupture from corrosion damage. All the water in the deaerator would immediately flash to steam in the event of a rupture.

Proper treatment of the boiler feedwater is absolutely critical to enable a normal life expectancy of the unit. This is one of the most serious boiler "destroyers."

Improper Warm-up

This is a common problem because management and production often exert extreme pressure on utilities to complete forced or scheduled outages so that production can resume. As soon as the boiler is "capable" of producing steam, they want it.

The improper warm-up of a steam boiler is one of the most severe hardships a boiler must endure. Going through the cycle of start-up, operation, and shutdown for any boiler creates higher equipment stresses and, consequently, much more maintenance-type issues than continuous operation at maximum rated capacity. Any piece of equipment such as a boiler, airplane fuselage, or combustion engine that undergoes an extreme transformation from ambient out of service conditions to operating conditions is subject to fatigue and failure. Good design and the process of making a slow transition between these conditions is essential for prolonging boiler life and reducing the possibility of failure.

A typical boiler is constructed of different types of materials which operate in totally different environments, including:

Drums and headers fabricated of thick metal which contain water and steam,

Tubes fabricated of much thinner metal which contain water and steam,

Refractory materials that are exposed to high furnace temperatures on one side and cooling from water, steam, and air on the other side,

Insulation materials which are specially designed to operate at a much higher temperature on one side than on the other side, and

Thick cast-iron castings such as access doors that are refractory-lined which see the full temperature of the furnace on one side and ambient air cooling on the other side.

By design, all of these materials heat up and cool down at a much different rate. This situation is made much worse when a component is exposed to different temperatures. For example, a steam drum that is operating at normal water level has the bottom half of the drum cooled by water and the top half by air initially and steam eventually. If one starts to fire the boiler from a cold start, the water will heat up very quickly in the drum and the bottom half of the drum will expand much more quickly than the top half which is not in contact with water. Consequently, the bottom of the drum will become longer than the top, causing the drum to warp. This phenomenon called "drum humping" can lead to stress fractures of the generating tubes between the steam and mud drums.

Refractory damage is the most prevalent damage associated with a quick warm-up of a boiler from a cold start. Refractory by design transfers heat very slowly and therefore heats up much more slowly than metal. Also, as the air inside the furnace and refractory cool, moisture is absorbed from the air in the refractory. A gradual warm-up is required to prevent refractory from cracking; this allows adequate time for the moisture to be driven from the refractory. Trapped moisture quickly becomes steam and causes the refractory to spall as the steam escapes.

The standard warm-up curve for a typical boiler does not increase the boiler water temperature over 100°F per hour. It is not unusual for a continuous minimum fire to exceed this maximum warm-up rate. Consequently, the burner must be intermittently fired to ensure that this rate is not exceeded.

Correct planning and education will allow a boiler to be started properly, which will prolong the boiler life and eliminate costly maintenance repairs.

The second article of a three-part series describing some potentially catastrophic events that power and recovery boilers are prone to if not properly maintained.

IMPACT DAMAGE TO TUBES

When you take a look at a boiler under construction, it is clear that all parts are not created equal. This is particularly true with the boiler tubes that make up the furnace and convection sections. Just as a chain is no stronger than its weakest link, the failure of a single tube with a value of only a few hundred dollars can easily require the shutdown of a multimillion dollar boiler facility.

When you consider that the tube thickness for the pressures commonly associated with many industrial boiler plants is often 0.120", 0.095", or less, it is easy to visualize how easily these tubes can be damaged.

Common Causes of Tube Damage

Impact the tube with a sharp object - The tube material is fairly soft and even a cold chisel dropped from a few feet away can result in a gouge and a localized thin spot on the tube. Any added stress can cause the unit to fail when it is pressurized and can also serve as a point of concentrated corrosion. This type of damage is common when boiler convection sections are mechanically cleaned of hard buildups, or when refractory repairs or repairs to other tubes are made. The simple drop of a hand tool can result in thousands of dollars in repairs as well as potential downtime of the unit.

Sootblower alignment - Sootblowers use high velocity jets of steam to blow the soot from the tubes. One of the pre-start-up checklist items for any boiler should be to verify the proper orientation and alignment of the sootblower lance to insure that the jets are blowing between the tubes and not blowing directly on the tubes during sootblower operation. Sootblower alignment is done when the unit is cold. Therefore, when aligning the sootblower lance, the thermal expansion of both the boiler and the sootblower lance must be taken into consideration.

Sootblowing with wet steam - Although a direct jet of steam striking the tubes as a result of out-of-alignment sootblowers is bad enough, the damage is compounded if wet steam is utilized. A direct blast of high pressure condensate can quickly cut through the thin tube surfaces, resulting in tube failure. The most common cause of wet steam is inadequate warm-up and draining of the sootblower lines. Proper sootblowing techniques require that the entire steam line supplying steam to the sootblowers be preheated to remove all condensate from the lines.

Corrosion - Fireside corrosion damage often occurs on a boiler that is in cold standby and that has previously fired sulfur-laden fuels. There are, inevitably, areas of the boiler where ash is not removed from the tube surface during normal sootblower operation. One of the most vulnerable areas is the interface where the tubes enter the drum at tube-baffle interfaces and refractory-to-tube interfaces. When the boiler is hot, corrosion is generally not a problem since moisture is not present; however, upon shutdown, this ash and refractory can absorb moisture and concentrated corrosive attack will occur over time in these areas. This will commonly cause boilers, which are subject to extensive periods of cold storage, to be damaged to the point that retubing is necessary. Localized pitting can be quite deep, rendering an otherwise sound tube in need of at least partial replacement.

Preventive Measures

· Make sure that all personnel who interact with boilers understand that thin tubes are quite fragile. Encourage workers to report any accidental damage so that it can be inspected or repaired as necessary.

· When possible, store a standby boiler in a hot condition to prevent fireside corrosion of the tubes.

· Hot storage techniques, such as utilizing mud drum heaters or routing the blowdown from an operating boiler through the inactive unit, are generally sufficient in keeping the temperatures of the tubes above the corrosion dew point.

SEVERE OVERFIRING

One doesn't have to spend much time in manufacturing plants to realize that maximizing production availability and output are some keys to profitability. This mindset requires that every piece of equipment be pushed to its maximum capability right up to the point of its self-limits or failure. Most equipment simply will not run any faster or produce any more product due to physical limitations.

The operation of steam boilers beyond their Maximum Continuous Rated (MCR) capacity has long been an issue of heated discussion. For many years, boiler manufacturers have rated their equipment to have a specific MCR on a continuous operating basis with a two- to four-hour peak rating, often times at 110 percent of MCR. The $64,000 question that is always raised is, "If the boiler will operate at 110 percent of MCR for 4 hours, why can't it operate at 110 percent continuously?" The answer to this good question is complex and is somewhat like trying to answer the question, "How high is high?"

In the design of a steam generating system, margins are built into the peripheral equipment of the boiler to ensure the capability of meeting performance guarantees. These margins include such items as additional fan volume and static capability, pump capacity and TDH (Total Discharge Head) margins, oversized material handling systems to accommodate operating logistics, etc. Any good designer/builder of steam generating systems wants to ensure that no piece of auxiliary equipment is the limiting factor to the boiler producing the MCR, or peak capacity, using the worse case contract fuels. Typically, the conservative design of all equipment results in the capability of overfiring the boiler above and beyond the peak 110% MCR rating. Without the self-limiting capability of the auxiliary equipment, management demands put upon steam plant superintendents to maximize production often result in continuous and sometimes severe overfiring of the equipment.

Sometimes the physical limitations of the boiler, such as furnace size or steam piping, will cause sudden and dramatic problems such as emissions or pressure drop problems that limit the boiler operating capacity. However, other physical limitations of the boiler itself may not be so obvious. These limitations lead to other problems associated with severe overfiring, which may include:

· short- or long-term overheating damage to refractory, tube metallurgy, breeching, etc.;

· long-term erosion of boiler tubes, baffles, breeching, and particulate clean-up devices;

· long-term corrosion of furnace wall and superheater tubes; and

· steam moisture and solids carryover causing problems with superheater tubes, steam turbine blades, and other process equipment.

Certainly, the fuels being fired have a dramatic effect upon the potential problems associated with severe overfiring in the list above. Erosion problems are typically associated with firing solid fuels such as coal, wood, sludge, plant waste, etc., that have ash and particulate constituents. The overfiring condition increases the gas weights and velocities which have a square function relationship to pressure drop and the effects of erosion. Severe eddy effects can be generated in boiler back passes that result in dramatic localized erosion problems.

Boiler designers carefully consider the heat flux through furnace wall tubing and membrane as well as the surface operating temperatures of tube walls, refractory, etc. Overfiring the furnace results in higher heat flux through the furnace walls and higher surface temperature of the refractory. The total steam flow relates to certain downcomer flows and pressure drops to ensure adequate cooling of furnace wall panels, etc. Overfiring the boiler results in higher flow rate demands in downcomer circuits which raises the pressure drop, thus impeding flow. The combination of these two conditions can result in a substantial increase in the tube and membrane operating temperatures. The short- and long-term effects of running at higher temperatures can result in the degradation of the tube metallurgy and strength.

Corrosion problems can be compounded when undesirable compounds in oil and solid fuels come in contact with tubes operating at higher operating temperatures. Also, overfiring oil burners can result in flame impingement on furnace wall tubing, resulting in localized corrosion.

In summary, most well-designed steam generating equipment is capable of being operated above MCR. Operating peripheral equipment at their physical limits does not often create problems. Conversely, operating the steam generator continuously above MCR may cause long-term maintenance problems resulting in associated costs that are not easily detectable during the short term. In situations where the production demand warrants overfiring the steam generating equipment, it may be a good business decision to suffer the short- and long-term increased maintenance costs to get the extra production.

CONTAMINATED FEEDWATER

Contaminated feedwater, which is a combination of both make-up and condensate returns, is a complex issue in this three-part series. Entire books have been written on this subject and its effects. This article will only try to create an awareness of some common problems. Common feedwater contaminants include:

· Oxygen

· Excessive boiler treatment chemicals

· Oils

· Miscellaneous metals and chemical compounds

· Resin

Dissolved oxygen is a common and constant threat to boiler tube integrity. The use of modern, sophisticated chelant water treatment programs has dramatically improved the cleanliness of boiler heat transfer surfaces to such an extent that essentially bare-metal conditions exist. Since only a thin magnetic oxide film remains on boiler metal surfaces, oxygen control is extremely important. The typical boiler plant is equipped with a deaerating feedwater heater to remove the majority of oxygen. In boilers operating below 1,000 psig, the oxygen scavenger, sodium sulfite, is continuously fed to the storage tank of the deaerator and the scavenger is necessary to ensure the absence of free oxygen.

One of the most serious types of oxygen corrosion is oxygen pitting, which is the concentrated pitting and corrosion of a very small area. A tube failure can occur even though only a relatively small amount of corrosion and loss of metal has been experienced. Because of the rapid and catastrophic effects of oxygen corrosion, boiler feedwater should be checked periodically to ensure that the deaerating heater and oxygen scavenger are eliminating free oxygen in the boiler feedwater.

A chelant boiler water treatment program that is not properly maintained to ensure proper dosages of chelating chemicals can result in problems with the consequences that these chemicals are intended to prevent. Chelant corrosion or attack develops only when excess concentrations of sodium salt is maintained many times above the control level over a period of many months. The resultant attack is a dissolving or thinning of metal, unlike oxygen pitting. The attack concentrates on areas of stress within the boiler such as: rolled tube ends, baffle edges, tube welds, threaded members, and other non-stress relieved areas. Here again, proper monitoring of the boiler water treatment program dosages and residuals can prevent this type of problem.

The inadvertent introduction of acid and caustic can cause the most devastating immediate damage to a boiler. The presence of either of these chemicals can cause a multitude of different types of corrosion and destruction of metal integrity. These chemicals are commonly unintentionally introduced into a boiler for the following reasons:

· Equipment failure or malfunction - A typical problem might be leaking regenerant isolation valves or failure of an automatic controller that results in an inadequate rinse cycle.

· Poor water treatment system design - Double block and bleed valve systems should be used wherever any regenerant chemicals are introduced into the water system to protect against damage due to valve failure.

· Poor water treatment system training and operations - If operators are not properly trained and cognizant of the importance of operating these often sophisticated systems properly, they could be responsible for pumping concentrated acid and caustic into the boiler. A less likely problem might be improperly carrying out the regeneration of water treating equipment such as improper rinsing of residual acid and caustic.

When operating a demineralized water treatment system, the importance of proper maintenance and operator training to prevent these types of catastrophic events cannot be overemphasized.

The undetected contamination of condensate returns is another common problem that leads to boiler feedwater contamination. Contaminants can vary from metals such as copper and iron to oils and process chemicals. Heavy metal contamination is usually a function of the construction materials of the process equipment and the condensate system. Oils and process chemicals are generally introduced into the condensate system due to process equipment failures or corrosion-caused leaks in equipment such as heat exchangers, pump and gland seals, etc. The biggest risk associated with condensate system contamination is a catastrophic failure of a piece of process equipment, which results in the introduction of significant quantities of undesirable chemicals or compounds into the boiler. For this reason, prudent boiler operations should include continuous monitoring of the quality of condensate being returned from the process.

Another problem that sometimes causes severe boiler fouling is the introduction of ion exchange resin into the boiler feedwater system. This is frequently caused by the failure of the ion exchange vessel internal piping or lateral screens. Depending upon the operating pressure of the boiler and type of resin, this problem can result in a severe coating of resin material on boiler surfaces. An inexpensive and very worthwhile method to alleviate the chance of this type of contamination is to install a resin trap on the outlet of any ion exchange vessel. Resin traps not only protect the boiler from contamination, but they also prevent the loss of very expensive resin in the event of a failure.

Boiler feedwater contamination can be a slow, degenerative process or an instantaneous, catastrophic event. Routine and efficient maintenance procedures will greatly mitigate the chances of both types of occurrences. Consistent boiler water and feedwater quality monitoring and testing provides operating personnel not only with historical data, but also with timely warning any time feedwater quality changes dramatically.

Improper Blowdown Techniques

The concentration of undesirable solids in boiler water is reduced through proper feedwater treatment and the proper operation of a continuous purge ("blowdown") system, and by performing intermittent bottom blowdowns on a regular basis.

The sodium zeolite water softening process is the predominant method of water treatment for boilers operating at low pressures with saturated steam. In this ion exchange process, harmful scale-producing calcium and magnesium ions are exchanged for sodium ions. The resultant water has a total dissolved solids concentration equal to the previous combined total of sodium, magnesium, and calcium concentrations.

The main purpose of blowdowns is to maintain the solids concentration of the boiler water within certain acceptable limits. A blowdown system is shown in Figure 1. The blowdown rate can be determined by several factors which include total dissolved solids, suspended solids, silica, and alkalinity. Table 1 shows these maximum recommended concentration limits in the water of an operating boiler according to American Boiler Manufacturers Association (ABMA).

As the operating pressure increases, the limits become substantially more stringent, which can potentially require an extremely high blowdown rate if sodium zeolite softening is the feedwater treatment method. To substantially lower the blowdown rate and control the concentration of silica, a total demineralized water treatment system should be used. A demineralized water treatment system removes the anions and cations instead of substituting them for other ions. This results in very low blowdown rate requirements.

The continuous blowdown rate is set to control the boiler water within these ABMA-recommended acceptable limits. A well-designed continuous blowdown system will constantly monitor boiler water conductivity (solids concentrations) and adjust the blowdown rate to maintain the control range. If the boiler water exceeds the recommended limits, potential problems can occur which include scale and sludge formation, corrosion, and moisture carryover due to foaming and poor steam drum separation equipment performance. When this occurs, solids and silica are carried over in the steam. This results in silica and scale formation on the superheater and other process equipment, including steam turbine blading. This foaming phenomena associated with high conductivity can also cause drum level instability leading to nuisance water level alarms and potential boiler trips.

Sometimes it is necessary to perform intermittent bottom blowdowns to dramatically reduce solid concentrations in the boiler water. Also, intermittent bottom blowdowns of water wall headers and the mud drum are critical to remove potential sludge buildup to keep all water circuitry clear. Generally, the only bottom blowdown that can be performed while the unit is being fired is from the mud drum. The blowdown of lower water wall headers, particularly the furnace wall headers, should not be performed while the unit is being fired. This action could potentially result in water wall tube overheat damage due to the interruption of the boiler’s natural circulation. The lower water wall headers should be routinely blown down every time the unit is brought out of service after fuel firing has been halted and the unit is still under pressure. Care should be taken to perform a blowdown of a limited duration to maintain visibility of the boiler water level in the sight glass. Additional bottom blows can be performed once feedwater is added to raise the level back up in the sight glass.

The single biggest problem caused by poor blowdown practices is the failure to periodically blowdown the boiler water columns. This results in sludge and debris buildup in the water columns, which renders the low water trips inoperative. All well-designed boiler installations should include a push-button momentary low water trip override system located at the water column blowdown valves. This system allows the low water trip devices to be blown down, thus cleaning the system and verifying that the low water trip alarm is activated without causing an actual boiler trip.

Improper Storage

Steam plant operations frequently require the long-term storage of boilers either used as standby units or units operated only during maintenance periods. Attention to proper storage techniques can be critical to maintaining boiler longevity as a standby unit. The improper storage of a boiler can lead to corrosion on either the fire or water sides.

Fireside corrosion damage often occurs on a boiler that is in cold standby and that has previously fired sulfur-laden fuels. There are inevitably areas of the boiler where ash is not removed from the tube surface during normal sootblower operation. One of the most vulnerable areas is the interface where the tubes enter the drum at tube-baffle interfaces and refractory-to-tube interfaces. When the boiler is hot, corrosion is generally not a problem since moisture is not present; however, upon shutdown, this ash and refractory can absorb moisture and concentrated corrosive attack will occur over time in these areas. Localized pitting can be quite deep, rendering an otherwise sound tube in need of at least partial replacement.

When possible, store a standby boiler in a hot condition to prevent fireside corrosion of the tubes. Hot storage techniques such as utilizing mud drum heaters or routing the blowdown from an operating boiler through the inactive unit is generally sufficient to keep the temperature of the boiler tubes above the acid dew point. These same techniques for keeping a boiler hot are critical if a unit is required to quickly move from standby status to operation in the event of another unit failure. Maintaining the boiler in hot standby will prevent problems associated with improper warm-up.

A boiler stored in hot standby with the unit full of water must be properly managed to prevent oxygen corrosion of the unit. The unit must be slowly brought down in rating while raising the water level as high in the gauge glass as possible while still delivering export steam to the line. As the steam pressure stabilizes at the hot standby pressure, make sure deaerated feedwater is introduced into the unit to maintain the water at the proper level so that immediate firing can commence when necessary.

If a unit is in cold wet standby, follow the procedures above in bringing the unit out of service. The most effective way to control corrosion is to build up a sodium sulfite concentration of 100 ppm in the boiler water. A nitrogen source should be attached to the drum vent once the pressure is almost depleted. Pressurizing the boiler to 5 psig with a nitrogen blanket system will ensure that oxygen will not be introduced into the boiler. Cold storage is recommended using the wet procedures above; however, if dry storage is necessary, make sure that ample quantities of desiccant are placed in the drums and that the waterside is closed up tight.

Flame Impingement

Flame impingement is a subtle problem that is primarily characteristic of high-capacity package boilers. Since shipping clearances dictate the design geometry of package boilers, the boilers naturally get long and narrow as size increases. This results in a significant challenge for burner manufacturers to shape the flame so that it is long and narrow, while simultaneously trying to stage combustion to mitigate NOx formation.

When the flame washes the furnace side walls, the result is potential corrosion on the tubes at the flame interface, particularly if firing heavy oils with contaminants. The corrosion is accelerated due to high metal temperatures associated with flame impingement and chemical deposits placed on the tubes resulting from quenching the flame when it touches the tube wall. Water treatment problems can accentuate the problems associated with flame impingement because internal deposits at this localized high temperature zone are formed on the inside tube wall driving the tube operating temperature even higher.

Pulling A Vacuum

When boilers are designed to operate at very high pressures, they are not designed to operate under even the slightest vacuum. A potential vacuum is created when a boiler is shut down. As the unit cools, the steam condenses and water level drops, which allows the pressure to drop.

If the steam drum vent is not open when the unit is cooling, a vacuum condition can result. A vacuum on a boiler can cause problems with leaks on rolled tube seats of generating tubes, which are designed for a mechanical fit to withstand positive pressures.

Preventive Measures

In conclusion, some common practices that should be followed in order to avoid "destroying a boiler" include:

o Frequent observation of the burner flame to identify combustion problems early.

o Investigate the cause of any trip before numerous attempts to relight.

o Before lighting a boiler, always purge the furnace thoroughly. This is particularly important if oil has spilled into the furnace. The purge will evacuate the inventory of unburned gases until the concentration is below the explosive limits. If in doubt, purge, purge, purge!

o Verify that the water treatment system is operating properly, producing boiler feedwater of sufficiently high quality for the temperatures and pressures involved. Although zero hardness is always an absolute criteria, other water quality standards based on operating pressures and temperatures as recommended by ABMA should be followed. Never use untreated water in a boiler.

o Blowdown all the dead legs of the low water trips, water column, etc., on a regular basis to prevent sludge buildup, which leads to device malfunction. Never under any circumstance disable a low water trip.

o Verify that the water leaving the deaerator is free of oxygen, that the deaerator is operated at the proper pressure, and that the storage tank water is at saturation temperature. A continuous vent from the deaerator is necessary to allow the discharge of non-condensable gases.

o Continuously monitor the quality of condensate coming back from the process to enable the diversion of the condensate in the event of a catastrophic process equipment failure.

o Adjust continuous blowdown to maintain conductivity of the boiler water within required operating limits and operate the mud drum blowdown on a regular basis (consult your water treatment specialist). Never blowdown a furnace wall header while the boiler is operating.

o The boiler waterside should be inspected on a regular basis. If there are any signs of scaling or buildup of solids on the tubes, water treatment adjustments should be made and the boiler should be mechanically or chemically cleaned.

o The deaerator internals should be inspected for corrosion on a regular basis. This is an important safety issue because a deaerator can rupture from corrosion damage. All the water in the deaerator will immediately flash to steam in the event of a rupture, filling the boiler room with deadly steam.

o The boiler's warm-up curve should be strictly followed. The standard warm-up curve for a typical boiler is not to increase the boiler water temperature over 100°F per hour. It is not unusual for a continuous minimum fire to exceed this maximum warm-up rate. Consequently, during start-up, the burner must be intermittently fired to ensure that this rate is not exceeded.

o Make sure all personnel working on boilers understand that the thin tubes are quite fragile. Encourage workers to report any accidental damage so that it can be inspected and/or repaired as necessary.

o If production demands necessitate overfiring of the boiler, make periodic assessments of potential effects of overfiring and communicate these to management.

o When a boiler is shut down for an extended period of time, a nitrogen blanket system should be used to prevent the introduction of air and oxygen into the boiler during cooling and storage, and sodium sulfite should be injected to react with any free oxygen in the boiler water. When a boiler is stored dry, desiccant should be placed in the boiler drums along with the nitrogen blanket to absorb any free moisture.

o Always ensure that the steam drum vent valve is opened whenever the boiler pressure is less than 5 psig.

Identifying Pressure Vessel Nozzle Problems From the Cracking Pattern

Category : Operations

Summary: The following article is a part of the National Board Technical Series. This article was originally published in the Summer 1999 National Board BULLETIN. (6 printed pages)

Pressure vessels of “thin” shell construction that are fabricated from 1/2” thick or less steel plate material are routinely used in the power generation, chemical, petroleum, and food processing industries. Some of these vessels are subjected to relatively severe operating conditions that include chemical attack, rapid pressure and temperature fluctuations, and steam/water hammer. As a consequence, many owners or operators perform scheduled nondestructive testing of the units to determine a vessel’s mechanical integrity.

Many of these pressure vessels act as an accumulation point, requiring the units to be equipped with one to two dozen nozzles that penetrate the shell and/or heads. These nozzles are often secured to the pressure vessel with fillet welds on both the ID and OD surfaces of the unit. An acceptable vessel examination procedure includes testing the circumferential welds, the longitudinal welds, and all these nozzle welds.

The most common form of weld nondestructive testing is visual examination, but an increasing number of owners or operators are testing their pressure vessels by the wet fluorescent magnetic particle technique, which is a more sensitive test procedure. This examination technique can detect surface and slightly subsurface indications in the material. It is not unusual to find many more indications by wet fluorescent magnetic particle than by visual examination. However, because wet fluorescent magnetic particle examination is not required by the original code construction, the integrity of the code still remains. A vessel’s perceived integrity only becomes questionable after cracking is found in a vessel that has been examined by the wet fluorescent magnetic particle technique for the first time in its operating life. A more complete resolution of the vessel’s mechanical integrity assessment should be performed by evaluating the indications or cracks found during testing.

Finding indications in the welds and plate material often presents the dilemma of what to do next. If the indications are cracks and not plate defects, (such as laps, which compromise the minimum wall thickness of the vessel, or are long and relatively deep) then the obvious answer is to repair the cracks. Many times, cracking in a weld is interpreted as a poor quality weld. To minimize further problems, the old weld is removed and replaced by a new weld.

Regrettably, many cracks are either repaired or new welds are installed without knowing the cause that initiated the cracking in the first place. This lack of knowledge can sometimes result in further cracking of the same area. Repairing cracks without eliminating the cause of the cracking can be a short term solution to a long-term problem. The following three examples demonstrate how the cracking pattern around the smaller nozzles (less than 2”) in a pressure vessel can help identify the source of the problems. These examples are used only as an illustration of the evaluation process and are not to be implied as the only causes resulting in nozzle cracking.

Cracking Due to an External Load

Cracking as the result of abnormally high nozzle loads that have exceeded the anticipated or designed nozzle loading is generally characterized by the appearance of “stretch marks” around the weld in the base metal as shown in Figure 1. The cracks usually follow the contour of the weld and tear the surrounding base metal due to the weld filler metal having a higher tensile strength than the base metal. Prior weld repairs to the same area indicate a persistent problem and are identified by the arrows in Figure 1.

The most common cause of a high external load is the result of a poorly designed or a poorly functioning support system. This deficiency occurs when the loads are transferred from the support system to the nozzles. These types of loads can result from adding a piece of equipment to the nozzle or connecting piping without modifying the existing support arrangement. In addition, high loads can result from a malfunctioning pipe support or added restraint. A visual examination of the support system within the first 30 feet of the nozzle or pressure vessel will usually identify this sort of problem.

Many vessels are subjected to thermal expansion because of the temperature increase that occurs under normal operation. Thermal expansion causes the vessel to increase in size which means the equipment and piping connected to the nozzles must also be able to move with the vessel. Vessels that are supported and fixed at one end should have a sliding support on the other end that enables the vessel to slightly expand and contract. The “stretch mark” pattern around the nozzle shown in Figure 1 was caused by the addition of a fixed restraint to the hi-lo water level drain piping. This fixed restraint was the result of the piping being routed through an undersized hole in the floor plate. Because the movement of the piping was restricted by the floor plate, eventually it caused the drain pipe to bend which resulted in frequent cracking of the nozzle in the ID of the unit as shown in Figure 2. In other cases that resulted in a similar crack pattern, restraints had been added to stand pipes, level transmitters, and chemical feed lines because of either vibration or long pipe connections to the vessel.

Cracking Due to Lack of Penetration

Lack of penetration is the lack of adequate weld filler metal deposit at the root of the joint. The root of a nozzle joint is the interface between the nozzle wall and the shell or head. This type of cracking will propagate through the weld in the same pattern as the root, but will break the surface of the weld in a radial direction around the nozzle if the crack encounters a weld defect such as porosity, slag inclusions, or lack of fusion as shown in Figures 3 and 4. This orientation change in the cracking can add confusion to the evaluation of the problem. The repair consists of removing all of the fillet weld and preparing the area for welding with a small diameter welding rod such as a 3/32” diameter rod.

Cracking Due to Chemical Attack

Chemical attack of the weld typically occurs in the heat-affected zone (HAZ) in the toe of the weld. The attack occurs at this location because of the slightly different microstructure created by the welding process. The general appearance of this type of cracking is circumferential at the toe of the weld and around most or all of the outer diameter of the weld. The cracking pattern is similar to one that can result from fatigue. However, because it is a chemical attack it will occur in nearly all the welds in a particular zone of the vessel, such as the locations above or below the liquid level. The cracking pattern from chemical attack is different from fatigue cracking which usually occurs at specific locations that have a recurring or cyclic tensile load applied to the area. In the case of chemical attack, a solution would be to repair the weld and make adjustments to the chemical input.

Remember, any long-term repair should remove all signs of the defect and discourage other defects from returning.