_INFORMATION SHEET

A. While the specific causes of boiler explosions are often unclear, COMNAVSEASYSCOM has stated:

1. That human error is a factor in almost all boiler explosions.

a. That all boiler explosions have been preceded by one or more warning signs that should have alerted the operators to the hazardous conditions.

B. Definition of Boiler Explosion

1. The events that constitute an explosion are stated in Chapter 221 of the Naval Ships Technical Manual (NSTM):

"Ignition of combustible fuel‑air mixtures in a boiler may be either controlled (burning fuel at determined rate at or near atomizer tip) or uncontrolled (explosion). In an explosion, an accumulated combustible mixture ignites almost simultaneously, creating a force which exceeds the yield strength of the boiler furnace, casing or uptake, causing structural damage. Symptoms or indications are a sudden loud explosion in the boiler furnace or uptakes. The basic cause of all boiler explosions is the accumulation of unburned fuel or combustible vapors at some point in the system."

2. Basic Cause of Boiler Explosions and Flarebacks

a. Chapter 221 of NSTM states that the basic causes of all boiler explosions and flarebacks are:

(1) Improper balance of fuel and air

(2) Improperly assembled atomizer

(3) Failure to secure fuel supply to atomizers promptly when fires are extinguished

(4) Leakage of burner valves

(5) Wet atomizing steam

(6) Failure to follow proper light‑off procedures, including incorrect purging

(7) Repeated unsuccessful light‑off attempts

(8) Failure to purge furnace properly, including furnace, boiler and uptake areas

(9) Excess or insufficient combustion air

(10) Failure to open air register immediately after burner ignition

(11) Inadequate soot blowing, which results in economizer gas‑side restrictions.

3. When Boiler Explosions Occur

a. 1978 through 1994, in excess of 40 boiler explosions have occurred in U.S. Navy ships. The most recent one being USS America. Of these, 78% of all explosions occurred during the transition to steady‑state operation, while only 16% occurred after a steady‑state condition had been attained.

4. The Analysis of an Explosion

a. An explosion requires the following three ingredients:

(1) Fuel

(2) Oxygen

(3) Ignition Source

b. There must be a source which permits unburned oil to enter a boiler. The following are some examples of the various ways oil may enter a boiler in an unburned state.

(1) If a burner is secured, oil could enter a boiler if a safety shut off valve and a fuel oil manifold valve were not closed properly or could not be satisfactorily secured.

(2) Poor combustion of an operating burner or burners. If poor combustion is occurring, some of the supplied oil may not burn. Poor combustion may result from numerous causes, such as:

(a) An atomizer in unsatisfactory condition due to dirt or as a result of wear, poor fabrication or incorrect assembly.

(b) Incorrect burner settings.

(3) If ignition of a burner at light‑off does not occur. The amount of oil entering the boiler is a function of the time oil is permitted to be atomized by the burner with no ignition occurring. This situation might develop at initial light‑off of the boiler, while lighting off a burner with other burners in operation, or it could occur while switching from air assisted atomization to steam assist atomization.

(4) Anytime fires are lost in an operating boiler. If the loss of fires is not due to a loss of supply fuel oil, the amount of oil which enters a boiler would be a function of:

(a) The time between the loss of fires and the time the fuel supply is cut‑off

(b) The firing rate of the boiler which gives the amount of oil being fired per unit of time (e.g., lbs/hrs).

c. Once unburned oil is in the boiler, the oil must be vaporized for it to be potentially explosive. Diesel fuel, the fuel used in Naval boilers and which is referred to as DFM, is a liquid in its natural state. The liquid oil must be in a vapor state before it can effect an explosion. Heat must be added to the oil in order to vaporize it. The degree of vaporization is a function of the amount of heat transmitted to the oil and thus can be considered to be a function of the temperature of the sources providing heat. Vaporization of the oil must occur without the oil burning. Heat may come from any of the following sources:

(1) The "hot" firesides of the boiler. During operation this would include the refractory and the outer walls of boiler tubes. During light‑ off with protection steam on the boiler, this would include the outer walls of the tubes which would be at a temperature approximately equal to the saturation temperature of the protection steam.

(2) A torch at light‑off.

(3) An operating burner.

(4) Steam from a steam assist burner. If burner ignition for a steam assist burner did not occur, the oil going into the boiler could be vaporized by the steam itself.

d. Oil in the atomized state has a greater propensity to vaporize than oil which has not been atomized. A given amount of atomized oil has a greater amount of surface area than an equal amount of oil existing in a pool. Therefore, because of better heat transfer, greater efficiency is realized when going from the atomizer to the vaporized state than from the unatomized to the vaporized state. Thus, a correlation exists between the quality of atomization and the ease of vaporization.

5. Air must be available for an explosion. Air can enter a boiler through open burner registers or:

EXCESS AIR = Volume of air supplied to boiler exceeding theoretical air (stoichiometric air)

Stoichiometric air is the theoretical amount of air which will cause all the fuel to burn. However, normally, air must be provided above stoichiometric conditions to cause complete combustion of fuel. Therefore, whenever combustion is taking place, there will always be some "free" air available in the boiler.

a. Once the proper amount of fuel vapor and free air for an explosion exist in a boiler, an ignition source at a high enough temperature and energy level must be available to cause the explosion. Some typical ignition sources in a boiler include:

(1) A torch which is available at initial burner light‑off.

(2) Hot Refractory.

(3) The flame from an operating burner.

(4) A burning pool of oil. If unburned oil got into a boiler and burned (did not vaporize), the fire from the pool of oil could be a source of ignition.

b. It must be realized that these above ignition sources could be at temperatures which could cause unburned oil entering the boiler to burn before the oil could vaporize. If the oil did not vaporize an explosion would not occur. Normally, if the firesides of a boiler were at a high temperature, most of the oil which was not consumed at an operating burner, would probably burn when entering the boiler. Since explosions require oil vapors and ignition sources at sufficient temperatures and energy levels, a question which must be asked is, "How does unburned fuel vaporize and not burn in the presence of an ignition source, which could be at a temperature that could burn the fuel?". There are at least three general ways for that to occur:

(1) An external substance(s) which will not permit the oil to burn is involved.

(2) There are temperature zones in a boiler (for some conditions) which are too low to cause burning, but will allow for the vaporization of unburned oil.

(3) For some conditions, though burning of unburned oil does occur, not all of the oil burns and that part that does burn vaporizes.

c. Throughout the lesson reference has been given to the term "explosive mixture". It is important that this term be understood when referring to a boiler fuel oil explosion. An explosion can occur if the percentage of fuel in a fuel‑air mixture (by volume) falls between two levels:

(1) These two levels are referred to as the lower explosive limit (L.E.L.) and upper explosive limit (U.E.L.). A condition where too little fuel vapors exist (conversely too rich in air), will not be explosive and the percentage of fuel in a fuel‑air mixture will be less than the L.E.L.

(2) An explosive mixture will also not exist if the amount of fuel is high (conversely air deficient), causing the percentage of fuel in a fuel‑air mixture to exceed the U.E.L. An explosive condition can be described as follows:

L.E.L. < FUEL/FUEL + AIR < U.E.L.

Where: L.E.L. = Lower Explosive Limit

U.E.L. = Upper Explosive Limit

(3) The explosive limits of DFM are:

(a) L.E.L. = 0.6% by volume DFM vapor to oxygen

(b) U.E.L. = 4.0% by volume DFM vapors to oxygen

6. Boiler Explosion Scenarios

a. Operating Boiler ‑ Dark Stack Condition. A dark stack condition indicates that combustibles exist in a boiler. The combustibles and any air left over after combustion are respective sources of fuel and air for an explosion. Ignition sources could include hot refractory or the fires of operating burners. The calculations show that the percentage of fuel in the mixture exceeded the U.E.L. for the mixture. This is due primarily to a deficiency of available "free" air and has the effect of impeding explosions by diluents (C0₂, H₂0, N₂) in the mixture. The addition of air such as, for example, to clear the stack could dilute the mixture down into the explosive range. If a boiler initially had a clear stack that changed to a dark stack, the mixture would go up through the explosive range.

b. Operating Boiler ‑ White Stack Condition. When smoking white, vaporized oil and possibly pools of oil exist in a boiler. In this condition, a boiler would be operating with excess air conditions. Thus, fuel and air would be available for an explosion. Also large amounts of air in flue gases would result in small percentages of diluents in flue gases. Hot refractory, fired burners or burning pools of oil could act as ignition sources. A white smoke condition could indicate that a boiler mixture was very close to its U.E.L. and thus, would be potentially explosive. In addition, experience has shown that attempting to correct a white stack condition by lowering combustion air could cause the mixture to go into the explosive range for a period.

c. Operating Boiler ‑ All Fires Lost. When fires are lost and oil continues to go into a boiler, the oil could vaporize depending upon the temperatures within the boiler. If combustion air is permitted to enter the boiler with oil, an explosive mixture will exist in the boiler almost as soon as fires are lost. Securing of the oil will take the mixture out of the explosive range. Inadvertent raising of oil flow could be especially dangerous as this would permit the stoichiometric ratio between the fuel and air to be approached which may maximize the explosive force. Very near the stoichiometric ratio for natural gases, the maximum explosive force will occur.

d. The addition into the boiler when fires are lost of a diluent, such as nitrogen (N₂) could take the boiler out of the explosive range. The addition of the diluent will change the U.E.L. and L.E.L. of the mixture and the percentage of fuel and diluent in the mixture can be kept below the new L.E.L. If a loss of oil causes loss of fires, a flareback (a rapid burning) will probably occur if the oil goes back into the boiler. Since both an explosion and a flareback are dangerous, fires should be satisfactorily monitored continuously.

e. Operating Boiler ‑ Some Fires Lost. If a portion of operating burners lost fires, unburned oil would enter the boiler. Depending upon the average boiler temperature, the incoming oil could vaporize. Air would be available through the registers of the burners that lost fires. Ignition sources would include hot refractory and stable burner flames. Thus, the ingredients for an explosion exist when a portion of fires are lost. However, explosive mixtures generally do not tend to develop when this occurs. It appears that, for most conditions the percentage of diluents in boiler flue gases will Probably be at levels which will not permit explosive mixtures to evolve in the boiler as a whole. It is possible that explosive mixtures could develop in isolated, stagnant boiler areas. Because the loss of a portion of fires could cause explosive mixtures to form in isolated boiler areas, the need to develop individual flame scanners and fuel shut‑off valves is being considered.

f. Initial Burner Light‑off ‑ No Ignition. Initial burner light‑off occurs when a single burner is lit‑off and no other burners are lit‑off in the boiler. Initial burner light‑off could take place in:

(1) A relatively cold boiler wherein the temperature of the boiler would be no higher than the temperature of protection steam flowing through the boiler.

(2) A hot boiler that may have recently been in operation.

In either case, no combustion would be taking place prior to light‑off attempts. If light‑off attempts were not successful while using recommended fuel oil and windbox pressures and the incoming oil vaporized, the fuel‑air mixture within a boiler would go into an explosive range. In a cold light‑off, heat for vaporization would be available from boiler tube walls (if protection steam was on a boiler) and the only ignition source would be the light‑off torch. In a hot boiler, hot boiler firesides could vaporize unburned oil and ignition sources would include the light‑off torch and hot refractory. Therefore, it appears that an explosion would more likely result from unsuccessful light‑offs in a hot boiler than in a cold boiler.

NOTE: If vaporized oil or oil pools existed in a boiler prior to light‑off, an explosion could occur when initial burner light‑off was attempted. The mixture could initially be vapor rich (above the U.E.L.). The opening of a burner register would permit air into the boiler, thereby diluting the mixture into the explosive range. A light‑off torch or a lit‑off burner could ignite the mixture.

g. Subsequent Burner Light‑off ‑ No Ignition. Subsequent burner light‑off occurs when a burner is being lit‑off with fires existing in the boiler. This condition is similar to an operating boiler losing some, but not all fires. The diluents that are in the products of combustion will, in general, tend to not permit explosive mixtures to develop in the boiler as a whole. Such a condition, however, does not preclude explosive mixtures developing in isolated stagnant areas of boilers. Since the recognition of an unsuccessful subsequent light‑off is more difficult than recognizing an unsuccessful initial light‑off, the importance of developing satisfactorily individual flame scanners and fuel shut‑off valves is even further demonstrated.

NOTE: Like an initial burner light‑off with vaporized oil or pools in the boiler, a subsequent burner light‑off under these conditions would also be dangerous. The open register of a burner to be lit‑off could provide enough air to put the mixture into the explosive range. Existing fires would be available as an ignition source.

h. Purging ‑ Fuel Vapors in Boilers. Boilers are purged with air to eliminate combustible gases from boilers. The fuel‑air mixture in a boiler, prior to purging, is vapor rich (above the U.E.L.). Purging will ultimately remove the vapors. As the purge air removes the vapors, the percentage of fuel in the mixture will decrease, but the mixture must pass through the explosive range. The time the mixture remains in the explosive range is a function of the purge air rate. The longer the mixture takes to go through the explosive range and an ignition source is present, the greater the chance for an explosion to occur. The use of high purge air rates, which can be attained with steam driven forced draft blowers (FDB's), will probably take a mixture through an explosive range fast enough to avoid an explosion. Thus, the use of FDBs to purge vapors from boilers may be satisfactory. However, when purging with a limited air capacity, which would be the case when using electrical blowers, a mixture could stay within the explosive range for a relatively long period wherein the chance for an explosion increases. If only limited air is available for purging, a two step procedure which includes boiler cool down followed by purging may be a possible method to safely remove vapors from a boiler. With fuel vapors in a boiler, secure all air and fuel to the boiler. Permit the boiler to cool sufficiently so that no ignition sources would be available to ignite the mixture. Following this cool down period, purge with the limited air supply. It should be noted that testing will be required to ascertain necessary cool down periods.

i. Purging ‑ Oil Pools in Boilers. Purging should not be performed with oil pools in a boiler. Purging will not remove oil pools from a boiler. Oil pools have to be removed by hand. A hot boiler will, of course, have to be cooled before removal of oil. Purging of a hot boiler could likely increase the chance of an explosion. Though some oil in a pool will vaporize as a result of heat in a boiler, purging could accelerate vaporization. Purging will remove vapors from a boiler, thereby permitting space in the boiler for the formation of new vapors. The purge air will also tend to dilute the percentage of vapors in the boiler. Depending upon the purge air and evaporation rates, the fuel vapor ‑ air mixtures could either go into or pass through an explosion range, Since a hot boiler would likely have ignition sources available, detonation of the mixture could occur when the mixture goes into the explosive range. Purging a hot boiler with oil pools using an inert gas (e.g. N₂) may be required until a boiler cools enough to eliminate any ignition sources. Satisfactory inspection devices are necessary to determine if oil pools in a boiler under any operating condition.

7. Potentially Explosive Conditions (PEC's)

a. Atomizer Hardware Problems:

(1) Excessive wear in atomizer

(2) Incorrect assembly of atomizer

(3) Dirty or clogged atomizer

(4) Incorrect positioning of atomizer tip in diffuser throat

b. Atomizing Steam Problems:

(1) Atomizing steam pressure too low

(2) Wet atomizing steam

c. Fuel‑Air Mixture Problems

(1) Improper fuel‑air mixture

(2) Fuel oil pressure too low

d. Excess Combustion Air:

(1) Increase in air supply due to forced draft blower (FDB) malfunction

(2) Too much combustion air

(3) White smoke

e. Insufficient Combustion Air:

(1) Decrease in air supply due to FDB malfunction

(2) Insufficient combustion air

(3) Black smoke

(4) Air register door not opened after light‑off

f. Leaks and Fuel Accumulation:

(1) Fuel oil leaking into firebox

(2) Unburned fuel oil in firebox

g. Water in Fuel‑Air Mixture:

(1) Water in fuel oil at atomizer

(2) Sputtering fires

h. Miscellaneous:

(1) Incorrect operation of the automatic combustion control (ACC) system

(2) Brief interruption of fuel flow to burner

(3) Loss of flame

NOTE: Excessively worn, incorrectly assembled, dirty, or clogged atomizers can cause unburned fuel oil to accumulate in the furnace. These conditions can also cause incomplete combustion and black smoke. This smoke differs from black smoke caused by insufficient air in that it is irregular and streaked in appearance. The importance of properly maintaining atomizers is stressed in Chapter 221 of the NSTM:

"As far as possible, operating personnel must maintain the atomizers in their original mechanical condition and polished finish."

i. Personnel Training:

(1) Failure to Heed Warning Signals.

Advisory 45 states that : "Review of circumstances surrounding boiler explosions indicates they have all been preceded by one or more warning signs which should alert operating personnel to the hazard that is present." The advisory listed the most common danger signals:

(2) One or more unsuccessful attempts to light fires.

(3) Sputtering fires and/or fires going out.

(4) Irregular or streaked black smoke coming from the stack.

(5) Fogging of the firebox inspection device and/or fuel vapor coming from the light‑off port.

(6) Presence of white smoke coming from the stack.

8. Ignoring Sputtering Fires.

a. Sputtering fires or fires going out can clearly be an explosion hazard, yet one CV lost fires nine times in 48 hours without an explosion. The cause was water in the fuel oil.

b. The MMR personnel present when this incident occurred were annoyed but did not seem to be aware of the explosion threat. Indeed, it would probably, be difficult to convince some of these personnel that "sputtering fires or fires going out" is an explosion hazard, even though another CV recently had a minor explosion due to loss of fires caused by water in the fuel oil.

9. Ignoring White Smoke.

a. Although white smoke may signal one of the most dangerous of the potentially explosive conditions, several personnel clearly did not consider white smoke a threat. One BTC expressed near‑contempt for concern about white smoke, stating that he once steamed with white smoke all the way to the "Med" without any problem. Some other personnel expressed a similar feeling, but none felt as strong as this BTC.

b. One MPA on a CV expressed some confusion about the threat of white smoke, because none of his boilers could be lit‑off without white smoke being present for as long as several hours. Guidance on this problem was not available until issuance of the latest edition of Chapter 221 of the NSTM, which states:

(1) "When lighting off a cold boiler using distillate fuel, some smoking can be expected. Attempt to minimize the smoke and adjust the air."

c. Failure to use the Engineering Operational Procedures (EOP).

(1) One problem with this is that operating and training documents are not interchangeable; each has its own requirements for effectiveness. In particular, the EOP explicitly assumes that the user is a trained watchstander. Therefore, certain background information that a trained operator would know is not included. For example, the EOP contains no information on valve location, and most gauges are not even shown. For these reasons, the EOP will not be effective as a training guide.

d. Failure of Burner Observation and Prompt Detection of Flame Failure.

(1) Burners are infrequently observed, and little emphasis seems to be placed on inspection of fires by the burnerman.

(2) Most instrumentation available in console booths does not permit diagnosis of specific combustion problems. Prompt detection of loss of flame, for example, requires direct observation of fires, which does not occur consistently. Babcock and Wilcox (1975) state:

"The majority of furnace explosions result from failure to detect a loss of ignition, even though other indicators, such as dropping boiler pressure, steam temperature, and exit‑gas temperature, show that fuel is either not being burned or is being burned incompletely. This emphasizes the fact that nothing takes the place of seeing the fires."

(3) The quotation above implies that the flame must be watched from the boiler front. However, "seeing the fires" can be done in other ways:

(a) "On‑the‑spot burner observations with today's large centrally controlled stations is no longer practical. Hence, reliable remote indication of positive ignition on all burners must be relayed to the operator at the central control point."

(b) In other words, what is needed is either direct flame observation at the boiler front or positive flame indication in the console booth.

e. Failure to interpret flame conditions.

(1) The color of cobalt‑tinted glass is not defined, but, presumably, this refers to the blue‑colored pigment, "cobalt‑blue".

(2) Problems exist with the glass of the inspection port; boilers with more than one color glass, as well as soot‑covered glass. One CV had three different colors of glass on the same boiler; one was blue, which may be the "cobalt tinted glass" referred to above. When asked why blue glass was used, the reply was that blue was all they could get, since the correct replacement was not available in the supply system.

(3) Another CV boiler had inspection port glass with part of the tint scraped away. MMR personnel explained that they had given a "new recruit" instructions to clean the glass, and he had "cleaned" off the coating that gave the glass its tint.

(4) The personnel interviewed on both ships seemed unconcerned about use of different colors of observation port glass. However, glass color can be very important, because the criteria for evaluating the appearance of the flame given in Chapter 221 of the NSTM are defined almost exclusively by flame color. Flame color can be an important evaluation criteria for determination of combustion efficiency. It is obvious that the color of the flame seen outside the boiler depends strongly on the color of the glass through which the observer is looking.

10. Ignoring Black Smoke

(a) Heavy black smoke, while not in itself explosive, can be an indicator of extremely poor combustion processes in which raw fuel is being deposited in the Boiler. Operators should be very suspicious of heavy black smoke conditions which do not respond to the normal methods of Air-Fuel ratio correction, or which are accompanied by odd flame appearance or other signs, such as boiler panting or smoke pouring from the casings. Additionally, in December 1991, a Heavy Black Smoke EOCC procedure was forwarded to all applicable ships. This casualty control procedure requires securing the Boiler after TWO minutes of heavy black smoke.

(b) In two previous heavy black smoke explosions, the explosion occurred upon the addition of diluting combustion air to the boiler furnace. This indicates that the boiler gas sides were fuel rich. Such fuel rich gas mixtures will not explode because of a lack of oxygen for combustion, but they can become explosive by the addition of air. For this reason, the procedure for securing after two minutes was established.

11. Interpretation of Flame Colors

a. COLOR

(1) "Incandescent White".

(2) "Bright White".

(3) "Incandescent and dazzling white" (applies at very high rates of combustion).

(4) "Dazzling white".

(5) Flame color changes from "pale yellow" to "yellow orange red".

(6) "Only a softening intensity of the dazzling white flame" (applies at very high rates of combustion).

(7) "Yellowish-orange to golden".

b. MEANING

(1) Considerable excess air.

(2) Considerable excess air.

(3) Considerable excess air.

(4) Water in oil or leaky tube.

(5) Reduction in percentage of excess air.

(6) Reduction in percentage of excess air.

(7) Well designed installation operating in good condition with a minimum of excess air.

12. The color criteria summarized are very imprecise and subjective. For example, how do "yellow‑orange" and "orange‑red" differ from "golden"? What does "only a softening in intensity of the (dazzling) white flame" look like? Do "dazzling white", "incandescent White" and "bright white" all look alike?

a. This comment is not intended as a criticism of the boiler manual; rather, the point is that a written or verbal description is not sufficient to describe flame color precisely. What is needed is a demonstration using actual flames together with expert commentary to show clearly how to interpret flame color and determine their meaning for combustion efficiency. However, since burnermen typically have not received any training in interpreting flame appearance, it is perhaps understandable that they do not closely monitor flame color.

b. Flame pattern is another aspect of flame appearance that is important, but that may also be neglected. The flame should have a complete circular shape centered on the atomizer tip and the back wall of the furnace should be "just discernible" through the flame. Only the latter aspect of flame pattern is mentioned in Chapter 221 of the NSTM. The interview data collected during this study show that burnermen are aware that flame pattern is important, but observation shows that flame pattern is not often monitored.