TVA
Operations Continuing Training
Tennessee Valley Authority
TVA
Kingston Unit’s 1-9 Boiler Tube Leak Recognition

Table of Contents Units 1-9

Table of Contents........................................................................................................................2

Terminal Objectives....................................................................................................................3

Enabling Objectives.....................................................................................................................3

System Overview.........................................................................................................................4

Introduction

In this self study module, the participant will be provided with a basic review of Boiler Tube Leak Recognition that will lead the participant to an operational understanding of Kingston’s Boilers.

Terminal Objective

Upon successful completion of this training course, the AUO and UO will be able to discuss and display relevant knowledge of the Boiler system here at KIF. Successful completion of this training module requires a score of 80% or higher on training exams.

Enabling Objectives

* Describe the boiler water quality and the provisions to control the boiler water quality

* Describe steam quality and how it is determined

* Describe Sootblower Erosion on WaterWalls

* Explain common operating practices that can cause boiler tube leaks and prevention techniques.

* Identifying Boiler Tube Leaks

* Identify the different root causes within the boiler that will lead to a boiler tube leaks.

* Describe a Boiler Tube Failure and the consequences that may occur.

* Describe Short-Term Overheating in SH/RH Tubing

* Describe Short-Term Overheating in WaterWall Tubes

Describe the boiler water quality and the provisions to control the boiler water quality.

Maintaining high water quality is of the utmost importance to the proper operation of a steam plant because impurities can quickly destroy the boiler and turbine. Poor water quality can damage or plug water-level controls, and cause unsafe operating conditions. During normal operation of a boiler plant, the water must be conditioned by heating, by the addition of chemicals, and by blow-downs, to prevent operating difficulties. Inadequate water conditioning results in scale formation, corrosion, carry over, foaming, and priming.

Scale - Consist of a deposit of solids on the inside of the heating surfaces such as tubing. The formation of scale is caused by a group of impurities initially dissolved in the boiler feed water, this can cause over heating of tubes.

Corrosion - The result of low-alkaline boiler water, the presence of free oxygen, or both. As corrosion proceeds, the metal thickness is reduced and stress is further increased.

Carry-over - Continuous entrainment of relatively small quantities of boiler water solids with the steam. Carry over increases with pressure and temperature.

Foaming - Condition resulting from formation of bubbles on the surface of the boiler water in the steam drum. This makes the separation of steam and water more difficult.

Priming - The propulsion of liquid into the steam drum by almost explosive boiling of the water at heating surfaces. This decreases the energy efficiency of the steam, and increases sodium.

Water conditioning is accomplished by adding chemicals directly into the boiler. Chemical feed pumps located in the basement pump phosphate into the boiler drum through a chemical feed line. The line runs the entire length of the drum, and has small holes distributed evenly across it for uniform distribution. During normal operation, the chemical feed pumps will not be running, unless we have a low boiler water PH. A PH level is maintained in the feed water, by ammonia pumps, through an ammonia injection line. These pumps will constantly be running when the unit is online. The ammonia injection line is in the condensate system after the hot well pump discharge.

The ammonia also helps remove oxygen since ammonia is an oxygen scavenger. The water lab has control of both pumps. Another method of water conditioning is through the continuous blow down line. The blow down provides a means whereby the total dissolved solids can be removed from the boiler. The amount is controlled by a needle valve just before the continuous blow down tank. Also our hot well is a deaerating type which helps remove oxygen from the condensate, and our #4 heater is a dearerating heater which helps remove any gases or non-condensables.

Describe steam quality and how it is determined.

Steam quality is the proportion of saturated steam “vapor” in a saturated condensate “liquid” mixture. A steam quality of 0 indicates 100 % liquid, “condensate” while a steam quality of 100 indicates 100 % steam. One pound of steam with 95 % steam and 5 % percent of liquid entrainment has a steam quality of 0.95.

Steam quality is important because moisture in the steam will cause damage to our turbines, and super-heater. When water is heated to the boiling point in a closed vessel, the vapor released causes the pressure to rise. With the rise in pressure, the temperature at which the water boils will also rise. Superheated steam is steam with a temperature higher than that of saturated steam at the same pressure. At 1825 psi, the saturation temperature is about 623 *F. At Kingston, we accomplish superheated steam by first heating the condensate and feed water through low and high pressure heaters through the economizer into the drum. As it exits the drums, it comes back through the water wall tubes of the boiler, through either forced or natural circulation, back into the drum. At this point, we will be above the saturation temperature, and most moisture should already be removed.

To ensure all moisture is removed, as it re-enters the drum, it goes through a primary and secondary separator. By the time it leaves the secondary separator, it is 99.5% dry steam. It then goes through a chevron separator before entering the super heater, as 99.9% dry steam. It is very important to know the degree of superheated steam before emitting steam to roll the turbine. At Kingston, one permissive prior to rolling the turbine is 50-100 degrees superheated steam. We know that any steam leaving the drum, is going to be nearly 100% dry steam. We also know the main steam stop valve is the first valve in line coming out of the super heater. So for determining the degree of superheat, we take the temperature at the top of the drum, and subtract it from the temperature at the main steam stop valve and that difference is the degree of superheated steam.

Boiler Steam Flow Units 5-9
Describe Sootblower Erosion on WaterWalls

Perhaps the most common type of erosion in boilers is sootblower erosion. As the name of this mechanism implies, damage occurs near or in the direct path of sootblower discharge, as well as in the furnace corners opposite wall blowers.

IDENTIFICATION KEYS

1. Wall thinning caused by external tube surface wastage. * 2. Little or no ash deposits on the tube. * 3. A layer of rust on the tubes shortly after boiler washdown, indicating that the protective scale has been removed by erosion. * 4. An erosion pattern on the tubes radiating from the center of the sootblower. * 5. Thermal fatigue cracking may be present if there is water in the sootblowing system.

COMMON LOCATIONS of FAILURES

* In a circular pattern around the wall blowers. * In the furnace corners adjacent to a wall blower.

MECHANISM

Sootblower erosion causes accelerated tube wastage by direct material removal, and the removal of the protective fireside oxide. Improper alignment and operation are the most common source of damage.

POST FAILURE IDENTIFICATION

Determine whether the failure has occurred near a wall blower and shows a wastage pattern consistent with erosion. *
Confirm that the appearance of the failure includes such features as:
Thin-edged rupture, a pinhole shape, or a long, thin blowout.

MECHANISM
When flow is interrupted, the normal cooling effect of the water no longer occurs and the tube metal temperature rapidly rises. As the strength of the tube metal decreases, swelling of the tube wall begins and failure can occur within minutes.

POST FAILURE IDENTIFICATION

1. Determine whether the failure has occurred in a location that is typical of short-term overheating. * 2. Confirm that the appearance of the failure includes such features as: * Considerable swelling (> 5%) of the tube wall. * Ductile fracture with a “fish-mouth” appearance.

Explain common operating practices that can cause boiler tube leaks and prevention techniques. Over heating or rapid heating during unit startups/shutdowns can lead to high cyclic strains on the boiler tubing. Not prewarming the boiler on startups, not opening boiler drains to allow for removal of water from tube low points on startups, not properly controlling critical boiler limits, and excessive firing ramp rates will lead to future tube failures. The following are points on the boiler that will be monitored with a trend in dataware throughout a startup or shutdown.

* Drum Metal Temperature Difference(Bottom vs Top) * Maximum Drum Metal Rate of Change * SH Furnace Startup Probes(startup) * RH Furnace Startup Probes(startup) * SH Steam Rate of Change * RH Steam Rate of Change * SH Outlet Header Steam Temperature Differential * RH Outlet Header Steam Temperature Differential * Steam Temperature At Superheater Outlet * Steam Temperature At Reheater Outlet * Boiler Generating Tube

Units 1-4 Boiler Units 5-8 Boiler

Abnormal Operation

Many abnormal occurrences can happen on units that can cause temperature, pressure, and megawatts to fluctuate. The operator must understand that this puts a massive stress on the boiler. The operator must recognize the steam and metal condition that are going on inside the boiler and take appropriate actions. This may mean further reducing load, initiating a Master Fuel Trip, or tripping the turbine and coming offline.
The key is to recognize the damage that will be caused if continuing to operate outside of the boiler metal limitations and make conservative decisions to protect the boiler.

Units 1-4

Superheater (SH) and reheater (RH) tubes operate in a regime where creep is significant and oxidation resistance is important. SH/RH tube design involves a choice of wall thickness and alloy type to withstand the expected pressures and temperatures and still provide at least a minimum specified level of life. Creep damage is strongly dependent on stress level and on tube metal temperature. Therefore conditions which are only a slight departure from design levels leading to increased stress or increased temperature will result in a shortened tube life.
The operator shall maintain the Superheat and Reheat outlet header temperatures at
1025 degrees. The combination of blowing IRs, Tilts, and Attemperators will be utilized to maintain the proper setpoint.

Creep damage is strongly dependent on stress level and on tube metal temperature. Therefore conditions which are only a slight departure from design levels leading to increased stress or increased temperature will result in a shortened tube life. Units 5-8 Boiler

Units 5-8 Boiler

A common cause of overheating in the pendant section occurs when slag builds up on one side of the furnace. This may be due to an IK being out of service for extended periods of time. The slag build up acts as an insulator and causes the opposite wall to absorb the heat. This may be evident if one side spray valve has a considerable amount more flow than the other.

Steam Temperature Limits

Normal operating SH/RH Steam Outlet Temperature is 1025 deg F, and should be maintained at normal operating temperatures by conventional means such as burner tilts, attemperation, and blowing of IR soot blowers. Immediately reduce load if Left Side, Right Side, or Common Outlet SH/RH Steam Temperature is above 1078 deg F. If temperature continues to rise, or cannot be reduced by reducing load, the fire shall be tripped if two out of the three SH/RH Outlet Steam
Temperature indications are above 1100 deg F for 15 minutes.

Units 1-4

Units 5-9

Upper Steam Temperature Limit for Immediate Boiler Trip = 1150 deg F

If slag is allowed to accumulate on one side of the boiler(Possibly due to IK being out of service), then the opposite side will increase in temperature. This will cause that side of the steam feeding to the outlet header to be overheated and cause long term overheating of the tubes. The maximum steam temperature differential between
‘Left(A)’ and ‘Right(B)’ sides will be no greater than 50°F.

The maximum rate of rise/decrease in boiler superheat or reheat outlet temperature is
100°F/hr. This can be monitored in Dataware by trending the “SH Steam Rate of
Change” and “RH Steam Rate of Change” points. The Unit Operator must be proactive in the steam temperature control and ensure tilts are in the upper range when temperature starts to fall below 1025 degrees as MW load is decreased. The attemperators flow shall be reduced to zero flow as the unit starts the load reduction.
Anticipation of steam temperature decreasing and the rate of change must be managed by the unit operator.

Boiler Metal Temperature

The maximum rate of rise/decrease in boiler metal temperature as measured at any point on the boiler is 100°F/hr. This will not only protect the drum metal as expansion takes place, but also the waterwall tubes as they are cooled or heated. Careful attention to this temperature limit must be monitored when the unit is brought offline for a tube leak repair.

There are two points in Dataware that will be useful in monitoring this.(“Drum Metal Rate of Change” and “Boiler Generating Tube”). The
Boiler Generating Tube temperature will help to monitor how quickly the waterwall tubes are being cooled.

Flue Gas Limit

Under normal conditions, the cooler steam that is flowing through a boiler tube acts as a conductor of heat so as to remove heat from the tube. Initially during a unit startup there is a lack of steam flow through the superheater tubes. There will be no flow through the reheater section until the turbine has been reset and rolled. To protect these tubes a limit on the flue gas temperature must be strictly adhered to. During unit startups, probes must be manually installed on the 4th floor of the SH and RH furnace above the fire ball.

Maximum gas temperature will be limited to 900 degrees before generator synchronization. Careful coordination must be done when synchronizing the generator and starting pulverizer feeders. Starting and loading the feeders too early before synchronizing will overheat the tubes.

Water Chemistry

Definitions:

Conductivity: A measure of the waters’s ability to conduct electricity in cooling water. It indicates the amount of dissolved minerals in water and is measured in micro-mhos.

pH: is the measure of the degree of acidiy or basicity of solution. The pH scale ranges from, 0 to 14, with zero being the most acidic and 14 the most alkaline.

Scale: A layer of coating on boiler tubes caused by impurities such as calcium, magnesim and silica commonly found in water. When the water is heated the impurites percipitate and are left behind coating the boiler tubes. Magnetite: A thin layer of iron ions created by the elevated steam temperature reacting with the boiler wall steel. This thin coating provides a protective layer on the inner tube walls that will prevent corrosion.

Silica: A hard, unreactive, colorless compound, that occurs as the mineral quartz and as a principal constituent of sandstone. Silica forms a dense porcelain-like scaling that cannot even be removed with acid.
Silica scaling also has a very low thermal conductivity. Because of its low thermal conductivity, a 0.5mm build up of silica can reduce thermal transfer.

Pitting: Corrosion in the boiler tube due to dissolved oxygen being present in the boiler water. The dissolved oxygen causes small but deep pinpoint holes that eventually penetrate boiler tube walls and cause failure.

pH Control
Properly maintaining boiler water pH is essential. Running boiler water in the alkaline(base) range will lead to scaling on boiler tubes.
Running the pH level extremely high causes the water to be caustic and can dissolve the protective magnetite film coating the tubes.

Running the pH level too low causes the water to be acidic which leads to thinning of tubes and possible etching of the tube surfaces. In terms of potential damage to the boiler system, low pH is the most serious type of water quality transient. Because the damage is immediate and potentially catastrophic, it should be considered as critical as firing a boiler without water.

Dissolved Oxygen

The most common source of corrosion is the boiler is dissolved oxygen. The importance of eliminating oxygen as a source of pitting is essential in improving boiler tube life.
Makeup water introduces appreciable amounts of oxygen into the system. Oxygen can also enter the feed water system from any place in the condensate system which is under vacuum. Oxygen can be removed from the system either mechanically or chemically. The mechanical method would be the use of the steam jet air pump and a deaerator. The deaeration process uses live steam and mechanical agitation by spray water across trays to encourage dissolve oxygen to escape the from the water. The liberated dissolved oxygen is continuously remove from the deaerator all with a small amount of steam through a small vent on the side of the dearator.

Hotwell Dissolved Oxyen limit for normal operation: < 20ppb

Dissolved Oxygen is also measure on the Deaerator outlet. This can be used to show the effective operation of the dearator itself.

Hotwell Cation Conductivity

Dissolved solids can affect the corrosion reation by increasing the electrical conductivity of the water. This is due to the mineral deposit that are common in untreated water such as metals and silica. The higher the dissolved solids concentration, the greater shall be the conductivity and more is the likelihood of corrosion. The process of the filter plant,
RO plant, and the demineralization trailer removes these solids to ensure the makeup water applied to the condenser will not cause corrosion in feedwater piping and boiler tubes. Increasing cation conductivity indicates that contaminants are entering the condensate/feedwater cycle. High cation conductivity is particularly damaging to plants using Equilibrium Phosphate Treatment because the low phosphate concentrations used do not provide very much buffering or sludge precipitating capacity.

Moderate increases in cation conductivity are commonly caused by the ingress of raw water into the condensate system, typically from leaking condenser tubes. However, rapidly increasing cation conductivity indicates more severe contamination problems.
Contamination can also result from inadequate flushing of the system after chemical cleaning. Contamination causes rapid damage to system components, first striping away the protective metal oxide coating and then attacking the base metal. Depending on the severity of the contamination, it may be necessary to remove the unit from service, drain, and flush the system before returning the unit to service. Three separate measuring points are provide in the system to allow for pinpoint the ingression point of contaminants. Identifying Boiler Tube Leaks

Early tube leak detection increase personnel safety, helps the plant to schedule shut down for repairs, and increases plant availability. This will eliminate the need for forced outages which can be quite costly. Early detection will also reduce the secondary damage to other tubes in the area. Regularly monitor of the following data points is key in recognizing a leak.

Furnace Draft and ID Fan Damper Position

As a leak becomes more apparent, the rapid flashing of hot water to steam within the fireside area or section occupies a greater volume, therefore boiler induced draft fan dampers will open up in order to maintain the furnace pressure at -0.5 in wc. As a leak progressively worsens, typically the boiler furnace pressure will become less stable.
Large tube blowouts will be indicated immediately by the furnace going hard on pressure. Another good indicator is the O2 in the furnace with the leak will start to decrease and can be seen by the mismatch in O2 readings between furnaces. Spikes in stack opacity will be another indication to observe.

Vacuum Drag/Makeup

The extra volume of water that will need to be replaced when a tube leak occurs may vary depending on the severity of the leak. Very small leaks may be hard to notice if that unit is supplying gland seal water or the building heat steam. Monitoring normal daily usage and vacuum drag flow rate will be a good indication that points to a problem. Dataware trends should be utilized to show daily make up flow rate.

Drum Level/Feedwater Flow/Boiler Feed Pump Amps

A tube leak in the waterwall will cause a sudden decline in boiler drum level. This might be one of the first indications the operator may notice, due to the multiple drum level indications on the unit. The decline in drum level will cause boiler feed pumps demand to increase, thus increasing the amps on the pumps. The operator will be able to see an increase in separation between steam flow and feedwater flow. The steam flow will remain virtually the same, while feedwayer flow with increase. This will be one of the major concerns the operator must deal with. If the operator takes no actions on reducing steam flow they run a risk of tripping the feed pumps on high amperage by the action of the 4160V overcurrent relays.

Drum Pressure/Firing Rate

This might be a little harder to pinpoint unless it is an immediate rupture. The boiler drum pressure will drop if a steam tube develops a leak. If the LDC is running in Turbine Follow +
MW, this will cause the steam valves to pinch off to maintain pressure at 2020psi. The Boiler
Master will start firing harder to bring the megawatts back to target setpoint. This will cause the pulverizers to run with higher than normal amperes.

Phosphate Pump Starts

One of the best indicators of a tube leak is pulling a daily trend up of the number of starts the phosphate pump has had in a 24 hour period. The below diagram clearly shows the increase of chemicals added into the boiler cycle to maintain proper pH went up when a leak developed.

Boiler Inspections

The Assistant Unit Operator shall walk the entire length of the boiler, opening various inspection ports, listening for the blowing sound caused by leaks and water running down side of the boiler. Soot blowing system being discharged with aid in reducing background noise during the inspection. Inspections shall be done each shift in the economizer hoppers to verify the absence of water that would indicate a leak in the backpass. The Assistant Unit Operator emptying boiler bottoms shall listen as well and watch for any signs of water running down from inside the boiler.

Describe the process of a routine inspection of a boiler.

* Wear proper PPE * long sleeve FR clothing * hard hat * safety glasses * ear plugs * steel toed boots

Always notify the UO and tell him you are going up on the boiler, and let him know when you are off the boiler. * Ensure radio is in good working order

* Use a boiler glass when opening inspection doors to look into the furnace

* Starting at the Drum elevation, walk down the boiler and look for abnormal conditions and listen for unusual sounds

* Check the coal bunkers for proper level

* Verify the boiler drains are closed

* Ensure no doors are open on the boiler

* Ensure the coal bunker dust collector is running

* Ensure no soot blowers are stuck in the furnace

* Ensure nobody is around the boiler (passed out/down due to heat) * Ensure no objects are placed on the buckstays

Check the following: * Drum level * Drum level should be “0” inches * Drum level will trip at +20“ and -20“ * Drum pressure * If pressure gets high boiler safeties will lift (2060, 2090, 2100, 2110, 2120 psi) * SH outlet pressure * If pressure gets high boiler safeties will lift (1950 psi) * RH outlet pressure * If pressure gets high boiler safeties will lift (415 psi) * Oil levels in air preheaters (upper, lower, and gear box). * Ensure none of the oil guns are leaking oil * Ensure lighting off oil Christmas tree is lined up and ready for use if needed * Ensure no bolts are loose or backing out of the buckstays * Inspect transport pipes: * for coal leaks * ensure they are hot and not plugging

Identify the different root causes within the boiler that will lead to a boiler tube leaks.
Boiler tube failures continue to be the leading cause of forced outages in fossil-fired boilers. To get your boiler back on line and reduce or eliminate future forced outages due to tube failure, it is extremely important to determine and correct the root cause. Experience shows that a comprehensive assessment is the most effective method of determining the root cause of a failure. A tube failure is usually a symptom of other problems. In addition to evaluating the failure itself, you should investigate all aspects of boiler operation leading to the failure to fully understand the cause.

Describe a Boiler Tube Failure and the consequences that may occur.
The failure of boiler tubes appeared in the form of bending, bulging, wearing or rupture, decarburization, carburization causing leakage of the tubes. The failure can be caused by one or more modes such as overheating, SCC, hydrogen embrittlement, creep, flame impingement, sulfide attack, weld attack, dew point attack, hot corrosion, etc.

If the boiler tube breaks into two or more pieces, it is called a fracture failure. A fracture failure occurs by means of the formation and propagation of cracks resulting in the separation of two or more parts. Several factors that may produce this type of failure are mechanical stresses, environmental or chemical influences, or the effect of heat on the boiler tube. For a failure to be identified as a fracture failure, the item does not have to be completely broken. One small imperfection can jeopardize the entire system.

Failures may be prevented by fixing or modifying the cause of a failure. This can be demonstrated in the example of a brittle fracture being the mode of failure. The corresponding cause of the brittle fracture may be temperature, presence of micro-cracks, or state of stress in the metal. In a failure analysis investigation, each question must be answered as completely as possible.

Describe Short-Term Overheating in SH/RH Tubing

Short-term overheating in superheat/reheat (SH/RH) tubing occurs when the normal flow of cooling steam is blocked. Excessive temperatures and subsequent tube failure can occur in a short period of time. This is distinct from long-term overheating/creep, which is gradual and long-term damage that occurs primarily as a result of the insulating characteristics of steam-side oxide scale and/or prematurely because of poor initial design.

* Fractured surface and the appearance of failure: * usually thin-edged, ductile final features. * Swelling of tube without ovalization. * “Fish-mouth” appearance of tube rupture. * * Internal scale is not necessarily thick. Depends on the age of the tube failure. * * External scaling is not necessarily thick. * * Swelling, stretch marks on tube material after the removal of scale/deposits. * * Any wall thinning is a result of the bulging of the tube material. * * Any tube material degradation depends on the material and the maximum temperatures reached. * * Localized hardening near the rupture is likely.

COMMON LOCATIONS of FAILURES

The most common location of failure is near the bottom bends in vertical loops of the SH/RH. Failures have also occurred in outlet tube legs. Failures can occur at any point in the tube if maintenance materials are left inside the tube.

MECHANISM
Short-term overheating occurs when the normal cooling effects of the steam in the superheat/reheat are no longer operating. The steam flow may be restricted or blocked due to exfoliated oxide scale or maintenance materials, such as rags, mandrels or files, being left in the tube. Additionally, condensate laying in the bottom bends of the element can prevent steam flow, especially during rapid boiler starts. As a result, the tube metal temperature rises rapidly. Failure can occur within a matter of minutes if the blockage is significant. Pronounced local bulging occurs because of the increased ductility of the material. The eventual rupture, as it occurs at very high temperatures without any cooling, is ductile with the concurrent characteristics.

Describe Short-Term Overheating in WaterWall Tubes

Short-term overheating in waterwalls occurs because of abnormal coolant flow or excessive combustion gas temperature. The subsequent high tube metal temperature results in a rapid failure.

IDENTIFICATION KEYS

1. A considerable increase (> 5%) in the inside or outside tube diameter. The swelling may extend over a great length of the tube. * 2. A ductile final fracture with a thin-edged fracture surface and a “fish-mouth” appearance.

COMMON LOCATIONS of FAILURES

Failures usually don’t occur where the interruption of the tube flow occurs, but in the higher heat flux zone above. Failure locations include: * 1. Above places where flow has been partially or completely blocked by prior maintenance activities such as:

* Where welds repairs or installations have been made and weld splatter or over-penetration has been left in the tube. * Where tools or materials have been left in the tube. * In inlet headers or mud drums where material such as nuts, bolts, and other debris plug orifices. * 2. Above those orifices in lower waterwalls where blockage or restricted flow results from deposition of feedwater corrosion products across the orifice. *
3. Locations, such as horizontal tubing, which are affected when a “slug” of steam comes down the downcomer from the steam drum.

On November 6, 2007 at approximately 0800 hours, two (2) operations employees (Mathew
Indeglia, and Philip Robinson) and one maintenance employee (Mark Mansfield) were working to tag out a pulverizer seal air fan under boiler #3. At 0846 hours, a series of division wall tubes catastrophically failed within the east furnace lower slope dead air space. The steam boiler was operating at 1900 PSI at the time of the failure. The furnace lower slope dead air space was normally under a slight negative pressure. The failure of tubes within the furnace lower slope dead air space caused that space to become rapidly pressurized resulting in a secondary explosive rupture of the boiler casing around that space. It is believed that the tubes failed in a pattern and manner as shown in this report as “apparent pattern of failure”. The failure caused ash and steam/hot water, at a temperature of approximately 600°F, to be released toward the immediate area where the three employees were standing. Based on witness accounts, the three (3) employees were able to leave the area of the failure on their own, however, they all suffered extensive burn injuries. All 3 died within 24 hours of the explosion.

Autopsies on Matthew Indeglia, Mark Mansfield, and Phil Robinson were performed by Dr.
John Parker of the Office of the Chief Medical Examiner. Dr. Parker determined that all three victims drowned in their own secretions as a result of damage to the bronchi, trachea and lungs. Dr. Parker also determined that each victim suffered significant burns.

As a result of the boiler failure, the boiler was immediately shut down and the facility managers began the process of shutting down the remaining 3 boilers. Due to the massive release of asbestos caused by the failure, the area was sealed off in accordance with the Division of
Occupational Safety requirements.

On November 19, 2007, the Department revoked the certificate of inspection for boilers #1 through #4 in accordance with Massachusetts General Law Chapter 146.

Boiler #3 was constructed in 1957 by the Babcock and Wilcox Company. The boiler is considered a high pressure (operating at 2,000 PSI) water tube boiler, which utilizes coal as the primary source of fuel. The boiler is approximately 130 feet high, and hangs from the top of the building structure and expands down. The boiler is equipped with an economizer, which is a bank of tubes located in the boiler flue gas path designed to increase the boiler feedwater temperature before it enters the boiler. It also has a primary and secondary superheater that takes saturated steam from the steam drum, located at the top of the boiler, in order to supply high quality dry steam to the steam turbine. The boiler also has a reheat superheater, which takes steam from a stage in the steam turbine and reheats it. It is then returned back to the turbine.

The boiler has 4 waterwalls (tubes that are lined up to cover each of the 4 furnace walls). The boiler has 4 coal burner levels, each of which contain 4 burners (16 burners total). The boiler is equipped with 4 coal pulverizers. Each pulverizer supplies coal to 4 burners. Each burner mixes air with the coal, which is ignited as it exits the burner. The products of combustion heat the water in the waterwalls and then flow through the secondary superheater, reheat superheater, primary superheater and finally past the economizer and out through components that reduce plant air emissions.
The steam produced in the boiler supplies steam to a steam turbine that drives a generator, which generates electricity. After the steam has passed throught the turbine, the steam is condensed. The condensate is heated and pumped back into the boiler in one large steam/water loop.

The boiler water is treated with chemicals to prevent component corrosion and to ensure that a high quality steam is produced.

The boiler runs under a balanced draft (the furnace pressure in the boiler is slightly negative). In order to maintain a balanced draft, the boiler is equipped with a forced draft fan that supplies air to the boiler, and an induced draft fan, which is located between the boiler and the stack. Fan dampers are used to maintain proper draft.

Because excess air results in improper combustion, “tramp air” (uncontrolled air entering the boiler from unintended locations) is minimized by a wet ash system. The waterwalls bend toward the bottom of the boiler to form a slope that directs the ash to a water filled hopper. The configuration of the waterwalls create a space within the boiler where there is no combustion. If properly maintained, the waterwalls are designed to minimize the amount of ash that accumulates in this space. This space is commonly referred to as a dead air space. If the spaces between the tubes are not tight or filled with a refractory material, boiler ash can fill the void space.

DENE, like most plants, use water to wash boilers down before an internal inspection. The dead air space is a location where water from water washing can enter and combine with the ash. This combination can become corrosive to metal if not cleaned or maintained periodically.

The following page gives a pictoral overview of this boiler.