QUESTION AND ANSWER BLOG

This part of the web site consists of a record of questions and answers. Questions asked by operators and engineers regarding boiler plants and their operation and my answers. Right now it's just a string of the ones that I have received recently. I intend to include everyone's hereafter. If it becomes a clumsy mess I'll try to convert it to something more readable.

Perhaps there's an exchange we had that isn't on this page. If so, and you still have the files, or at least the question, please e-mail it to me and I'll get it in here so other people can take advantage of your question.

*************** PLAN FOR A BOILER EXPLOSION *********************

11/13/2015

From: Howard
To: KHeselton
Sent: Fri, Nov 13, 2015 2:33 pm
Subject: Boiler Explosion Case Studies

Hello,

I'm writing to you, looking for information to help me with a task I've been assigned at my place of work. I read an article today entitled "First-Hand Experiences of Incomplete Combustion". It was written by Kenneth E. Heselton in 05/01/2000, of KEH Energy Engineering, and accounted a number of his experiences with boiler furnace explosions, etc. I have been asked to calculate the maximum explosive potential from a potential explosion in the furnace/fire box of one of our water tube boilers here on site. This situation came up during a safety audit and during an emergency response planning session.

The calculations and knowledge to figure this out seems to be getting very complex, especially as I'm dealing with bunker C, and a bit above my skills. However, a number really isn't quite as important as if I were able to give an example of what could happen to a boiler of this size. The boiler in question is a 30 million Btu/hr burning Bunker C/Heavy fuel oil, ignited by diesel fuel.

In the article mentioned, there was an example of a 25 million Btu/hr, gas fired furnace. There was another example of an explosion that blew out the rear of the boiler, etc.

Most of the information I find in internet searches, is in relation to steam explosions, and boiler size is rarely mentioned. I'm mostly looking for real to life examples of damage confined to the furnace area and surrounding area, or an opinion on what one could reasonably expect from an explosion due to incomplete combustion or whatever the cause could be for a fuel build up resulting in an explosion, but short of a full steam explosion. However, I'll gladly consider those as well.

If this is something I can have help with, or perhaps even if I can be steered in the right direction to obtain this information, it would be greatly appreciated.

Thank you very much,
Howard

Howard,

As far as I'm concerned the maximum explosion potential is due to ignition of a mixture of CO and air at the ideal (theoretical perfect) condition where, from literature and test data I've found produces an instantaneous pressure differential of 13.7 psi. it's the value I use for designing ductwork, boiler casings, etc.

The normal peak design pressure for a boiler furnace and casing of a boiler in the range you described is 25 inches water column. That's what I use for leak testing pressurized boilers. Needless to say, a CO explosion will do considerable damage to something that's built to those design pressures.

Failures of the casing and flues normally occur at the corners and designs I developed using those design pressures allow for buckling of the flat surfaces but containment of the explosion. Regrettably those designs haven't been tested so I can't say they work.

Of the combustibles explosions I've analyzed (most of the 29 inspected) the source of the explosion is somewhere near the outlet of the boiler but the pressure wave continues through the flue gas passages as far back as the forced draft fan and up the stack. From my experience you can expect your water tube boiler will, under the worst condition, have splits at the corners and potential movement of the front and rear walls swinging out as much as 30 degrees from normal. Side casings will buckle and split at the top or bottom - or both to become projectiles moving through the boiler room. A building column adjacent to a boiler wall will be bowed unless it's larger than a heavy W8. If your watersides are welded so the flue gas can't slip by and blow off the casing the tube damage will require the boiler be retubed. In one incident of a boiler with welded finwall the steam and water drums were rotated about 3 degrees.

You should be able to use those parameters to produce an estimate of the damage in your boiler room for a combustibles explosion in each boiler. I can't say more because I don't know what's near your boilers. In your evaluation look out for plant equipment common to all the boilers and nearby wiring that could take out the entire plant with an explosion in one boiler.

If you're also asked about steam explosions from something like a tube rupture (I've never heard of a drum rupturing) you can determine the pressure in the furnace based on the flashing of the steam and the supersonic flow out of the end of two tubes the size of the largest boiler tubes in the furnace. I've only seen the results of one rupture of a four inch sidewall tube and was surprised that it did not do much more damage than the typical combustibles explosion to the boiler but the pressure rise was so much greater that all missiles such as pieces of refractory, bricks, bolts, etc. produced damage almost 100 feet away because they were carried out by the expanding steam.

I trust this was helpful. I'm glad to see you're contemplating the effects of a failure and hope that part of the study involves production of a plan to deal with one. Part of it should include some basic preventatives such as not storing anything that can become a missile near or on a boiler and requiring all personnel to always wear safety glasses in the boiler room. It's actually suggested that the owner should provide the safety glasses, including prescription ones because they make a difference in many situations. I can't say hard hats would help that much.

Ken

*************** BOILER WATER TESTING *********************

4/10/2014

Hi Ken,

Since you are from the Baltimore area, is there a place where I could take my boiler water to be tested? I live in Baltimore City in Roland Park and have a hot water boiler. In your book, I noted your concern about City water being sourced from two locations. I can do a pH test myself, but it appears that I want to make sure no other corrosive chemicals exist in my make up water.

Respectfully,
Christopher

Christopher,

I trust you're talking about a residential hydronic heating water boiler and testing the water is not recommended because the cost of testing the water by an outside agency is bound to be more than the cost of draining the system, refilling it, and adding some boiler water treatment chemicals that are recommended for the area where you live. That applies everywhere, not just in the Baltimore area. A hydronic system that's not leaking is usually not subject to corrosion because the water in the system never changes so once any corrosive element in the water acts on a tiny part of the boiler and piping that's the end of it.

Systems with leaks, where makeup water is added regularly,will experience corrosion with each addition of fresh water and that's another matter entirely. Guidance under those conditions is to get the leak fixed and replace the water including fresh chemicals.

Ken

***************** ROUND BOILER MANHOLES *******************

2/14/2014

I have sailed on ship as a trainee engineer . Ship had 2 mitshubishi MB-3E-NS boiler. The manhole doors in water drum and steam drum were on the end plates. These manholes were circular in shape and opened toward inside they were hinged. I read some text they all state that boiler manhole doors are elliptical. Is there any specific reason for manhole to be elliptical apart from ease in taking them out from drum. I think as the manhole door incase of mitshubishi MB-3E-NS are on the end plate the stresses acting does not decide the shape of manhole. Is there any rule governing shape of this door. eagerly waiting for your reply.
Thanking you, yours sincerely

Abhishek

Abhishek, The principal reason for an elliptical opening is means to remove the manhole cover for replacement. While many have been replaced in years past, current material quality, water treatment, and gasket technology has made it highly improbable to have a situation where the cover has to be replaced. I've never seen one replaced but have seen one instance where both the cover and the opening surfaces were so damaged by corrosion and erosion that the boiler was abandoned because of the cost of repairing the opening surface. While it is more normal to have an elliptical opening there's nothing wrong with round ones.

**************** DEAERATORS AND FEEDWATER TANKS ****************

1/22/2014

Hi Ken, Happy 2014 to you! Hope your New Year is starting off well. How’s the bird-watching going? Any new activities you have lined up for 2014 ? (I trust you’re still working on your subsequent boiler book).

Speaking of boilers, I have a boiler-related question for you…I know there are several basic types of feedwater heaters for steam systems (i.e., deaerators, open feedwater heaters, and closed feedwater heaters). I also realize feedwater can be heated using stack economizers (standard single-stage or condensing two-stage).

As far as DA tanks, my understanding is certain systems work better with pressurized DA tanks, others with atmospheric DA tanks. Can you shed some light on these options? (what are the best applications (and the key considerations) for each…when does each work best, etc.):

(A) A deaerator tank (atmospheric or pressurized?)

(B) An open FW heater

(C) A closed FW heater

Also, do you know the relative costs of these 3 options (capital/installation, as well as operations/maintenance). Is a DA tank not as well suited for smaller steam boilers? (say < 300 BHP)

Does it depend more on system pressure than on the boiler size/capacity? And if a system with smaller boiler (say 200-300 HP) doesn’t have a DA tank, is it a worthwhile pursuit to try and retrofit/re-design the system and add one? (or is that cost prohibitive?)

Also curious if the effectiveness (expected natural gas savings) of a stack economizer – say a single-stage one – would differ much, based on whether the system uses a deaerator tank, an open FW heater, or a closed FW heater?

Appreciate any insight you can offer on these topics.
Best,
Michael B

Michael,

The second edition is in the hands of the typesetter and I know she's working on it because she's already sent a couple of e-mails that I had to answer because I forgot to include something.

I trust you read pages 175 to 179 in the first edition. You'll notice I didn't use the words "open" and "closed" anywhere. What's sometimes referred to as an "open" deaerator is a flash deaerator and my opinion of them is at the bottom of the first paragraph in the right column on page 176.

As far as I'm concerned the term "feedwater heater" should be restricted to heat exchangers in the feedwater circuit between the boiler feed pumps and the boiler where the feedwater can be heated to temperatures higher than 212 F. Feedwater heaters use sources of heat that would be wasted anywhere else because of their high temperatures. The most common source of heat for a feedwater heater is bleed steam from a turnbine and there can be several of them in a typical steam cycle. I've also used a feedwater heater to cool very high pressure condensate (over 350 F) because allowing it to flash in the deaerator would result in situations where the flash steam would exceed the heat needed to heat the feedwater.

Maybe I failed to say that feedwater is betweeen the deaerator (if the plant has one, otherwise it's the feed tank over the pumps) and the boiler. When turbine bleed steam (the second edition will explain more about turbine bleed steam) is at a lower temperature than the deaerator saturation temperature it is used to heat condensate colder than the bleed steam temperature to condense the bleed steam and heat up the condensate. These heat water that's eventually feedwater but it's before the water gets to the boiler feed pumps. Heat exchangers that heat the condensate are usually identified as LP Heaters or IP Heaters (LP for low pressure and IP for intermediate pressure) although you'll run into plants where IP Heaters actually heat feedwater. Thats one of the many places in a steam cycle where labels can differ from plant to plant and region to region.

With the exception of vacuum deaerators they not only remove the air and non-condensible gases from the water they also heat the water. Raising the feedwater temperature reduces the temperature difference between the feedwater and the boiler to eliminate damage due to thermal shock. Even so, see Figure 9-30 on page 218. The standard for a deaerator is sufficient size to hold 20 minutes worth of boiler feedwater at full load as a reserve and operating at a temperature that will also eliminate damage due to thermal shock.

A deaerator has a significant contribution to operating cost. It removes the oxygen from the feedwater thereby reducing the cost of oxygen scavenging chemicals and their contribution to scaling of the boiler tubes. It can absorb and use flash steam eminating from high pressure condensate. The significantlly higher cost of a deaerator compared to a boiler feed tank is justified by it reducing operating cost. As to when the economics dictate that I'm not certain because prices have swung so much recently and I haven't been in a position to do some analysis to determine where the breakpoints might be. A deaerator is seldom needed in a low pressure heating plant but a low pressure plant in a production application that doesn't return condensate might be an appropriate application. A heating plant returns most of its condensate so there's little oxygen bearing water introduced. The operating pressure of a deaerator is selected to maintain the plant heat balance. A typical institutional or small industrial plant will typically operate the deaerator at 5 psig - 228 F. [In my original response I failed to mention that a few operate at 2 psig (218 F) but I don't recommend them because any upset can result in the pressure dropping below atmospheric which prevents deaeration.] Then, as boiler operating pressures rise so does the deaerator pressure. Typical step ups are 15 psig - 250 F, 30 psig - 274 F, and 50 psig 298 F, then higher pressures are selected as plant specific.

So, if you want to determine if a deaerator would be beneficial, look at the amount of makeup water that would bring in oxygen, the oxygen content of the condensate where it's contributed by open condensate receivers and tanks and pumps that aren't maintained, and potential to use steam that's otherwise vented but accessible. A water treatment consultant should be able to tell you the amount of scavenger you need for the existing operation and for operation with a deaerator. You can then calculated the difference in chemical costs and estimate any vented steam costs to determine savings and compare it to the cost of the deaerator installation.

Ken

**************** FAILED OPEN STEAM TRAPS ****************

11/11/2013

Hi Ken- Hope you are well as Thanksgiving approaches soon.

I have a simple question for you…when calculating energy loss from failed open steam traps, I have often seen calculations that reference steam trap discharge (in steam loss lbs/hr) such as the table below from the Boiler Efficiency Institute.

Note that the tables are copyrighted material and are not reproduced here, check out the BEI web site

My question is, which enthalpy should be used to calculate the annual therm savings in conjunction with the lbs/hr steam loss?:

A. The latent heat of evaporation, hfg (Btu/lb) from the steam tables for the rated system pressure that serves the line where the trap is located (considering of course, not only inlet pressure of trap, but also outlet pressure);

B. The difference between the total enthalpy of steam, Hg (Btu/lb) at the operating pressure, less the enthalpy of the feedwater, Hf FW(Btu/lb); OR

C. The difference between the total enthalpy of steam, Hg (Btu/lb) at the operating pressure, less the enthalpy of the makeup water, Hf MU(Btu/lb)

As you can see from the below screenshot, this formula uses hfg (Option A) , but I didn’t feel this accurately reflects the therm savings from having to replace “X” number of lbs of steam lost from a failed trap in a given year (my guess was it should be Option B.

Thoughts?
Michael B.

Michael,

As I seem to say in answer to every question, it depends on a lot of factors. I have yet to see a report that states someone successfully determined savings on steam trap losses. Where a few ESCO's got involved they were not successful using such a simple formula.

Think about it. A steam trap can leak and allow steam into a condensate line that may contain enough colder condensate flow to absorb the heat by condensing the steam. In that case there's no loss of heat because the warmer condensate and every pound of the leaking steam is returned to the boiler. On the other hand, in an installation where several traps are leaking the steam and condensate flows to the condensate receiver or boiler feed tank where the mixture flashes to dump some steam out of the tank vent and that loss occurs at 970 btu per pound, period. The challenge there is to obtain flow and temperature measurements of the heated condensate or mix of condensate and leaking steam.

A steam trap can only, and under the best of circumstances, reduce losses to any steam that leaks through the orifice. Thermodynamic traps require a (very small) flow of steam to keep them closed when no condensate is present. That makes them virtually freeze proof provided the condensate load doesn't exceed the capacity of the trap so they have a perfect application.

Once the condensate passes through the trap the liquid is exposed to a pressure that is almost always less than the saturation pressure of the liquid so some of it has to flash to steam absorbing enough heat to lower the temperature of the rest of the liquid to saturation at that point. Since condensate piping will always have resistance to flow the pressure will drop as the liquid moves along and an increasing amount of steam will flash off until the steam and condensate mixture reaches a tank or receiver where the pressure is established by something other than the liquid itself. The pressure can be atmospheric, normally vented tanks, a vacuum produced by air ejectors, or a vessel under pressure such as a flash tank or deaerator. The first two will, of course, emit the steam to atmosphere whether it's flash steam or a leak. Every system has to be analyzed carefully to determine the value of vented steam. It's probably easier to measure it.

Here's a graphic that's going to be in the second edition of the book and you can use it to think about all this.

Low Pressure Steam Cycle

Ken

**************** STEAM BOILER / DRY STEAM ****************

10/3/2013

Dear Sir, My name is Ron K. and I am in the process of making a steam boiler to create dry steam to power a turbine. So far I have dry superheated steam but need to get just a bit more flow. If you are willing, I would send you pictures of the boiler and there are a few questions I would like to ask you. I just purchased your book and find it to be a great help. I am a manufacturing engineer with 40 years of experience but none with steam. I have been to some steam tractor shows in the past years but now really appreciate the great machines of days gone by. Hope to hear from you. Thanks.

Ron

Dear Ron,

I doubt if a picture would help and I'm not about to claim to be a boiler designer so I'm not sure I can help you. Feel free to ask some questions and I may be able to suggest where you could find answers.

Ken

Hi Ken, Thanks for the response. I am building this and using waste oil to make steam. This is what our company makes. Waste oil furnaces. I am having a problem of not getting enough flow. I am about .54 gallons per minute. My target is .64 Gallons per minute. If I increase pump RPM I add flow and lose dry steam. Should I decrease the superheat coil Length cause I am trying to heat too much water? I am learning as I go and your book is such a great help. Some of the areas in the book you say to reread until you get it does make me understand better! Like FLOW. If I start with a smaller nozzle get the temps and then by valves switch to a larger nozzle to lose psi would that work? I have in this boiler 525 feet of 1/2 inch tube, outer coil and 163 feet of the same tube, inner tube/ superheater coil. Another problem is I am the only one here working on this and have very little history with steam. Just reading and trying what I feel might work. Close but not quite there. This will be a future product line and the patents are in place, just have to make it work now. Please feel free to critique what you see. Any help will be greatly appreciated.

Dear Ron,

From the little I am able to learn from your text and photographs I cannot tell much but I think there's a basic item that needs to be covered first.

You haven't mentioned steam conditions and I don't have quick access to the Code books so I can't be positive. If you have not discussed the construction of this boiler with a Code Official you may find yourself well behind in authorization to sell this product. Be it the United States or Canada along with many other countries a boiler larger than a 120 gallon hot water heater and, I'm rather certain, generating superheated steam can only be produced commercially by an organization authorized to build boilers through the authorization to use a "stamp" issued by the ASME (American Society of Mechanical Engineers). If you had that authorization you should be subjected to regular inspections of design and construction by an "Authorized Inspector." In the U.S. they are typically commissioned by the National Board of Boiler and Pressure Vessel Inspectors out of Columbus Ohio. There are other agencies in other countries (you haven't indicated your location) that provide similar protection to their citizens from unauthorized manufacturers. In my experience those inspectors are very knowledgeable and helpful. If you have not done so I strongly suggest you contact the ASME or whatever organization is responsible for boiler safety at your location.

That said, I also can't address your questions for lack of information. I don't know enough of the parameters to begin to address your questions.

Ken

**************** OIL GUN RING SEALS ****************

7/30/2013

Ken, Love your book. We currently use PTFE O-rings for sealing our oil tips in our atomizing oil guns. They fail constantly, can you recommend another O-ring for a Zurn type gun?

Thank you,
Scott K

Scott,

Thanks for saying you love the Boiler Operator's Handbook . I'm tempted to suggest something but, I trust you understand that I can't recommend substituting a product because of the legal ramifications should the substitute fail. If you're trying to get repeated uses of O-rings that Zurn clearly states in their instructions should be replaced each time the oil gun is changed you are going to have to try following their instructions first. If not, I suggest you let Zurn know that you're not happy with the repeated failure of the O-rings and ask them to provide something that's reliable. Should that fail to produce a reliable product you might also consider substituting another manufacturer's oil gun. I'm sure another manufacturer would be glad to supply something that they can stand behind and guarantee if pressed. They might refuse to guarantee boiler performance including NOx emissions but a couple of oil guns is cheaper than a complete burner assembly, worth a try. That is, of course, provided that your Department of the Environment (or similar title) doesn't insist on a complete test to prove the burner performance with the change in oil guns. I could run by a few more options and caveats but those should do for now.

Ken

Ken, Please offer your suggestion as the 1968 Zurn gun is obsolete and Zurn is no longer in business (that I’m aware of or care to know). Also the person that purchased these retired years ago.

We are not married to one particular manufacturer – we go with the best technology. Our primary fuel is Natural Gas, we only use fuel oil as an emergency backup.

Thanks,

Scott

1/25/2014

Scott, I don't recall exactly why but apparently I never replied to your last e-mail regarding the Zurn oil gun o-rings. I apologize for that. Zurn is only one of many manufacturers that have gone out of business or were purchased by another firm in the last few years. You should be able to find a teflon reinforced Viton (tm) o-ring that will do the job but they will have to be replaced regularly.

Ken

Ken,

Thanks for the reply. We have experienced multiple failures occurring within hours of installing O-Rings on these guns during fuel oil firing. The gun tip gets hot, we recently installed steam separators on our atomizing steam. Perhaps this will solve the problem. Can you recommend an alternative to PTFE O-Rings? Probably not I’m guessing.

Thank you,

Scott

Scott,

You didn't say if the o-rings were Viton. If so, then tip temperatures are so high that you may be experiencing other problems with the burners. You never told me what pressure and temperature the steam was at nor what the oil firing temperature is. I'm thinking of a lot of other things that may be contributing to the problem so I'll ask for more information, including those items.

Can you send me a photograph of the o-ring in place on the gun? Also, a photo of the burner from the furnace side? A recent fuel analysis might help as well.

Ken

**************** GAS FLOW METERING WITH POWER MONITOR ****************

7/3/2013

Ken, I spoke with you over the phone yesterday. You answered questions I have been searching for for since January. Thank you.

I mentioned we are trying to develop a gas glow meter capability with our power monitor. If you have a moment, please look at these pictures and tell me if this is even possible.

Very Respectfully,

Mark D G

CPT (P), EN, US Army

MIT Masters Candidate