POWER & ENERGY

In the age of advanced controls, understanding the fundamentals of power and recovery boiler operation is necessary to prevent disaster

BY WILLIAM L. REEVES

Operator Attention Critical to Preventing Boiler Failure

After paper machines and pulp dryers, power and recovery boilers are often the most expensive assets in a paper or pulp mill. The operating reliability and availability of these boilers are 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 causes of catastrophic boiler failure include the following:

• Fuel explosion
• Low water incident
• Poor water treatment
• Contaminated feedwater
• Improper blowdown techniques
• Improper warm-up
• Impact damage to tubes
• Severe overfiring
• Improper storage
• Pulling a vacuum on the boiler.

Such unburned fuels can ignite in a very rapid or explosive manner. These events can be avoided by following a simple rule: Never add fuel to a dark, smoky furnace. Instead, the burners should be "tripped" and the furnace purged thoroughly with air. Once this is done and the ignition problems corrected, the burners can be relighted.

Many fuel explosions occur after a combustion problem causes a burner trip. For example, when a fuel oil atomizing tip clogs, the resulting unstable flame can lead to flame failure. If during successive attempts to relight the burner, fuel oil is sprayed into the furnace, a large inventory of vaporized fuel can accumulate in the furnace. A successful relight can ignite this potentially explosive inventory. This same condition-the accumulation of unburned fuel-can arise if a burner that has poor atomization characteristics is operated for long periods of time.

LOW WATER INCIDENTS. At temperatures above 800F, carbon steel undergoes degradation that destroys its strength and integrity. Since typical furnace temperatures exceed 1,800F, the cooling effect of water inside the boiler tubes is critical to prevent catastrophic damage. Continued firing of a boiler with insufficient water will literally melt boiler tubes, with the results like those shown in Figure 1.

Typical industrial boilers are "natural circulation" units that rely on changes in the density of water as it heats and vaporizes to provide the circulation. As the saturated water removes heat from the tubes, the water turns to steam, causing it to rise to the boiler steam drum. The void created by the rising steam is filled with hot water flowing down in downcomer tubes.

This natural circulation pattern is totally dependent upon the proper water level in the steam drum so that an adequate water supply is available to downcomer tubes. Modern boilers are equipped with automatic low water trip devices which ensure that fuel firing is halted whenever the water level falls below the level required for proper circulation cooling.

Boiler trips due to low water levels are not rare events. They are generally caused by an interruption in feedwater flow. On the other hand, low water incidents that result in damage (i.e., boiler firing continued despite a low water condition), are rare and totally unnecessary. While it can be caused by the failure of typically redundant low water trip devices, the most common cause of low water-related damage is the disabling of the automatic trip devices for various reasons.

To improve reliability, redundant low water trip systems include both conductive-type and float actuated-type devices. Another critical element in these systems is a push button bypass that allows routine verification of trip device functionality. The bypass system allows operators to blowdown the "dead legs" of the devices, purging them of sludge or other build-up and allowing the operator to get an alarm trip, thus verifying the integrity of the trip devices without actually tripping the unit.

POOR WATER TREATMENT. Boiler feedwater is treated to remove harmful constituents. These anionic and cationic compounds can cause scale to accumulate in boiler elements, which can eventually lead to overheat-type tube failures.

The need for proper feedwater treatment is well established. Consider the comparison of a boiler and a pot of boiling water on the stove. Depending on the amount of solids (calcium and magnesium hardness) in the water, a hard scale residue is often visible on the bottom of the pot once the water has boiled away.

This same phenomenon occurs inside a boiler and, if left unchecked, can destroy it. As explained earlier, boiler tubes rely on water to maintain a proper operating temperature (i.e., keep them cool by removing heat transferred through the tube wall). A buildup of deposits inside the tubes produces an insulating layer, which both inhibits the heat transfer process and the convection-driven water flow through the tubes. If this continues long enough, localized overheating of the tube and eventual failure results.

To prevent formation and growth of these deposits in tubes, the concentration and type of solids in the boiler feedwater must be maintained within acceptable limits. The higher the operating pressure and temperature of the boiler, the more stringent the requirements for proper feedwater treatment.

Low-pressure boilers typically use ion exchange water softeners to remove calcium and magnesium hardness. In higher pressure and temperature boilers, which typically drive steam turbines, total demineralization is necessary, including the removal of other constituents such as silica. If not removed, silica vaporizes in the steam and is deposited on equipment such as turbine blades. A "state-of-the-art" demineralization system is shown in Figure 2.

CONTAMINATED FEEDWATER. In most pulp and paper mill settings, boiler feedwater is a mixture of freshly treated boiler water and steam condensate returned from users throughout the mill. Both of these make-up streams can be contaminated by process upsets or system failures. Common feedwater contaminants include the following:

• Oxygen
• Oils
• Miscellaneous metals and chemical compounds
• Resin.

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 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.

The inadvertent introduction of acid and caustic into the water side of a boiler can have a devastating effect. The presence of either of these chemicals can cause a multitude of different types of corrosion and destruction of metal integrity. Most commonly, these chemicals find their way into a boiler as a result of equipment failure, poor design, or operator error. Particular attention should be given to the operation of the demineralized water treatment system where both acid and caustic are the active treatment agents. The importance of proper maintenance and operator training cannot be overemphasized.

Undetected contamination of returned condensate is another common cause of boiler feedwater contamination. The most common cause of condensate contamination is equipment failure. In the case of catastrophic failure, speed and degree of contamination can be significant. For this reason, prudent boiler operations demand continuous monitoring of the quality of condensate being returned from the process.

Contaminants can include metals such as copper and iron, 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-related leaks in equipment such as heat exchangers, pump and gland seals, etc.

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's internal piping or lateral screens. An inexpensive and very worthwhile method to guard against 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 resin, which is very expensive.

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 provide operators with both historical data against which to judge current operations and also timely warning of changes in feedwater quality.

IMPROPER BLOWDOWN TECHNIQUES. The concentration of suspended solids in boiler water is reduced through the proper operation of a continuous purge ("blowdown") system and by performing intermittent bottom blowdowns on a regular basis. High conductivity or other contamination of the boiler feedwater can create problems such as drum level instability and foaming, leading to nuisance water level alarms and moisture carryover in the steam and superheater fouling.

A well-designed continuous blowdown system will constantly monitor boiler water conductivity and adjust the blowdown rate to maintain the target control range. Intermittent bottom blowdown of wall headers and the mud drum is critical to remove any accumulated sludge.

On the other hand, a lengthy blowdown of furnace wall headers while firing the boiler can cause overheat damage related to the interruption of the natural water circulation. Instead, the furnace wall header blowdown valves should be operated ("stroked") each time the boiler is shut down prior to the system reaching atmospheric pressure.

IMPROPER WARMUP. Reacting to time pressures while returning a boiler to service (i.e., after a shutdown), operators and their managers are sometimes tempted to take a shortcut with the boiler's recommended startup cycle. The resulting improper warm-up can be one of the most severe hardships a steam boiler may face.

Going through the cycle of startup, operation, and shutdown for any boiler creates higher equipment stresses and, consequently, more severe maintenance problems 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 startup and operation are the essential criteria for prolonging life and reducing the possibility of failure.

A typical boiler is constructed of different types of materials, including very thick drum metal, thinner tube metal, refractory and insulation materials, and thick iron castings. These different materials all heat and cool at different rates. Sometimes the differences are substantial.

These differences in expansion and contraction can also be important when a component is exposed to different temperatures. For example, in a steam drum operating at a normal water level, the bottom half of the drum is cooled by water while the top half is initially cooled by air and eventually-once boiling begins-by steam.

If one begins to fire the boiler from a cold start, the water will heat up very quickly in the drum. 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 can become longer than the top, causing the drum to warp. This phenomenon, when severe, is called "drum humping" and can lead to stress fractures of the generating tubes between the steam and mud drums.

Refractory damage is the most prevalent damage associated with rapid warm-up of a boiler from a cold start. Refractory transfers heat very slowly and, therefore, heats much slower than metal. Also, as the air inside the furnace cools (i.e., during shutdown), moisture is absorbed from the air into the refractory. When returning the boiler to operation, gradual warm-up is required to prevent refractory from cracking from differential thermal expansion and to allow the absorbed moisture to be driven from the refractory without spalling damage. The standard warm-up curve (Figure 3) for a typical boiler does not increase the boiler water temperature more than 100F per hour.

IMPACT DAMAGE TO TUBES. When you take a look at a boiler under construction, it is clear that all parts are not created equally. This is particularly true for 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.

Considering that the thickness of the tubes in industrial boiler applications may be as little as 0.095 in. to 0.120 in., it is not difficult to visualize how easily these tubes can be damaged. The most common causes of damage are the following:

Sharp objects impacting the tube during fabrication or maintenance activities

Poor sootblower alignment

Sootblowing with wet steam (which results in tube erosion).

During the design of a new boiler, one of the biggest "bangs for the buck" is specifying increased tube thicknesses. The associated, often minimal price premium provides an additional margin of safety in the event that tube damage does occur. Also, when boiler tubes are bent, the tube thickness decreases in the bend, thus reducing design margin over the code requirement.

SEVERE OVERFIRING. For many manufacturing plants, maximizing production availability and throughput is the key to profitability. This mindset requires that every piece of equipment be pushed to its maximum capability.

Operating steam boilers beyond their maximum continuous rated (MCR) capacity has long been an issue of discussion. For many years, boiler manufacturers have rated their equipment to have a specific MCR on a continuous operating basis with a 2-hour to 4-hour peak rating (often times at 110% of MCR). The question that is frequently raised is, "If the boiler will operate at 110% of MCR for four hours, why can't it operate at 110% continuously?" The answer to this good question is complex.

In the design of a steam generating system, safety and performance margins are built into the peripheral equipment of the boiler to ensure that the assembled system meets performance guarantees. These margins include such items as additional fan volume and static capability, pump capacity and TDH margins, oversized material handling systems to accommodate operating logistics, etc. Designers of steam generating systems want to make certain 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 the entire system results in the capability of firing the boiler above and beyond the peak 110% MCR rating. Without the self-limiting capability of the auxiliary equipment, demands to maximize production might otherwise result in continuous (and potentially severe) overfiring of the equipment.

The physical limitations of the boiler (e.g., furnace size, steam piping, etc.) can cause sudden and dramatic changes that limit the boiler's operating capacity. Other, less obvious physical limitations of the boiler may also lead to problems associated with severe overfiring. These may include the following:

Short- or long-term overheat damage to refractory, tube metallurgy, breeching, etc.

Long-term erosion of boiler tubes, baffles, breeching, and particulate cleanup devices

Long-term corrosion of furnace wall and superheater tubes

Steam moisture and solids carryover that causes problems with superheater tubes, steam turbine blades, and other process equipment.

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

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 rated 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 rates through 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-term and long-term effects of running at higher temperatures can result in the degradation of the tube metallurgy and strength.

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

Most well-designed steam generating equipment is capable of operating above its MCR. Operating peripheral equipment at their physical limits does not often create problems. But operating the steam boiler above its MCR continuously may cause long-term maintenance problems and their associated costs, which are not easily detectable during the short term. In situations where the production demands warrant overfiring the steam generating equipment, the business decision should be based on the relative value of the incremental production and increased maintenance costs.

IMPROPER STORAGE. Improper storage of a boiler can lead to corrosion on either the fireside or waterside. Fireside corrosion damage often occurs on a boiler that is in "cold standby" and which has previously fired sulfur-laden fuels. In such a boiler, there are areas where ash has not been removed from the tube surface during normal sootblower operation.

The most vulnerable areas are where the tubes enter the drum at tube-baffle interfaces and at 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 severe, rendering an otherwise sound tube inadequate.

"Hot storage" of the boiler prevents this type of 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 temperatures of the boiler tubes above the acid dew point.

PULLING A VACUUM. While 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 and 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. Carefully following a few common practices can reduce the risk of boiler damage.

Frequently observe the burner flame to identify combustion problems early.

Investigate the cause of any trip before repeated attempts to relight burners.

Before lighting a burner, 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!

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 preferred, other water quality standards based on operating pressures and temperatures as recommended by ABMA should be followed. Never use untreated water in a boiler.

Blow down all the dead legs of the low water trips, water column, etc., on a regular basis to prevent sludge buildup in these areas, which otherwise may lead to device malfunction. Never-under any circumstance-disable a low water trip.

Verify that (1) the water leaving the deaerator is free of oxygen, (2) the deaerator is operating at the proper pressure, and (3) the storage tank water is at saturation temperature. A continuous vent from the deaerator is necessary to allow the discharge of non-condensable gases.

Continuously monitor the quality of condensate coming back from the process to enable immediate dumping of the condensate to sewer in the event of a catastrophic process equipment failure.

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 blow down a furnace wall header while the boiler is operating.

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.

The deaerator internals 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 will immediately flash to steam in the event of a rupture, filling the boiler room with deadly steam.

The boiler's warm-up curve should be strictly followed. The standard boiler warm-up curve (Figure 3) does not increase the boiler water temperature more than 100F per hour. It is not unusual for a continuous minimum fire to exceed this maximum warm-up rate. Consequently, during startup, the burner must be intermittently fired to ensure that this rate is not exceeded.

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

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

When a boiler is shut down for an extended period of time, it should be kept in hot standby. 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.

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