Boilers, Nuclear, Reciprocating Engines

To the Editor:

Issue 5 and Volume 115.

The Letter to the Editor in the February issue by a manufacturer of emission control technologies contained two errors that require a response.

First, the authors claim that the cost to bring a 1 MW diesel generator into compliance with new EPA emissions regulations at between $10,000 and $20,000. While this may represent the cost of the actual equipment needed to be installed for these retrofits, it is not representative of the total installed cost.

One must be sure to factor in the installation costs, labor, startup and commissioning, as well as before and after testing by a certified independent testing company. Also, do not forget the rental of a load bank so that testing can be done at full rated nameplate, as required by the rule.

I have solicited bids for all these activities and am finding that a turnkey, all-in bid to perform all of these activities ranges from $60,000 to $70,000 for a 1,600 kW machine. Size makes little difference in total cost for units of these sizes.

The second error is one in which the authors assert that in cases where the owner is receiving revenue as part of a utility curtailment program, such revenue would produce a less than one-year simple payback.

There are two problems with this thinking. Simple payback is a poor method of analyzing a project’s financial viability. There are other better financial analysis tools available.

The more important issue is that in this example the revenue from the utility curtailment program was already accounted for in the original justification for the generator project. The addition of this emissions equipment yields no additional revenue. In fact, there are considerable added operations and maintenance costs. So the simple payback calculation on this project is a capital cost divided by zero, which we all know is infinity. There is no payback.

Ervin Root, P.E.
Consulting Engineer

The Author Responds

Our estimate for the cost of a 1 MW system was based on the assumption that many RICE NESHAP compliance projects will not require an invasive solution. Therefore, our focus was around the more common “splice in” Diesel Oxidation Catalyst solution or replacement of an existing silencer with an integrated silencer and catalyst solution. These solutions don’t require major demolition, new piping and significant amounts of installation labor. As systems get larger there is no question that complexity and costs will increase.

We used payback as our measure of ROI because that is the method most of our customers used to justify their capital expenditures. We agree there may be better financial measures to use and already incorporate those measures on our on-line RICE NESHAP ROI calculator.

We agree that there is no additional revenue created because of the engine retrofit. However, engine owners and operators who receive a financial benefit from load curtailment or peak shaving contracts have an alternative choice: cancel their contracts and reclassify the engine as emergency use and therefore avoid the capital costs required to bring the engine into RICE NESHAP compliance for non-emergency use engines. This choice would eliminate the revenue stream. For an engine owner or operator to properly analyze whether to keep or end their load curtailment or peak shaving contract, the revenue stream kept intact after engine retrofit for RICE NESHAP compliance needs to be used to justify the new capital expenditure.

Chad Kaderabek
Marketing Manager, Universal Acoustic
and Emission Technologies


Correction: In the April issue story “NOx Reducing Technologies,” references to John Zink/TODD Combustion should also refer to the parent manufacturing company, Coen Company, Inc.


To the Editor:

A nuclear power plant is designed from two perspectives: 1) the nuclear steam supply system (NSSS) supplier must design the power plant to generate power in a safe, reliable and (hopefully) economical manner and 2) the architect/engineer must design all the supporting systems and structures to ensure that the operational and emergency systems remain operable as per the specifications for the plant. In the case of Japan’s Fukushima units (and other nuclear plant installations) the AE, in association with the utility, was to design two sources of off-site power in the event that an emergency plant shutdown was encountered.

These supposedly redundant sources of power should have been able to provide the needed power for continued cooling of the plants. Obviously, these power sources were not designed to withstand the events that occurred.

As another power source safeguard that is designed into all NSSS, redundant diesel generators are installed at each unit with adequate capacity to provide the needed power for safe cool-down of the reactor. However, for the units to operate they need fuel, so the AE must design and build a safe and reliable source of fuel. From the limited input I have been able to research, the fuel source(s) were swept away by the tsunami. If that is the case, where is the scrutiny of this engineering and construction effort?

The last issue that appears to be hampering corrective action following this cascade of failures is flooding of the instrumentation room. This installation again is an AE design-and-build part of a nuclear power plant.

I can understand that being a “Monday morning quarterback” on this tragedy is not being fair, but neither is the lack of public disclosure into these failure mechanisms instead of continued “black balling” the nuclear plant design.

Len Kube
Management Consultant


To the Editor:

An error appeared in your March 2011 issue in the article “Steam Boiler Inspections Using Remote Field Testing” by Mynor Celis, P.E. This article detailed several different failure and degradation modes of boiler tubing and described methods of detection and inspection. The “Graphitization” section included errors, whose source appears to be confusion with another failure mechanism.

Of particular concern is the statement “Graphitization occurs internally, with the graphite detaching from the steel reducing the total wall thickness.” There is no reduction of wall thickness as graphitization occurs. Graphitization occurs internally within the material at the microstructural level where iron carbide dissociates into iron and free carbon. It would be unfortunate to have a reader conclude, due to a lack of wall thinning in a particular tube section, that the tube section was free of graphitization.

The “Prevention” section notes that “A good metal passivation program and treating the boiler feed water with phosphate will reduce the probability of graphitization.” Graphitization is purely a time-temperature transformation mechanism occurring in carbon steels and is unrelated to boiler chemistry. It is well understood that the use of materials containing at least 0.5 percent chromium will eliminate the potential for graphitization, regardless of the operating parameters.

As further evidence of a confusion of mechanisms, Figure 8, identified as a tube experiencing graphitization, uses a visual examination of the ID surface as evidence of graphitization. Currently this mechanism can only be positively characterized by microstructural examination whereby discrete graphite nodules are identified. Bend tests are also performed as a test to determine the material’s loss of ductility due to graphitization.

Brian J. Miles, P.E.
Department Head – NDT/Materials
Laboratory Services – Consumers Energy


To the Editor:

The article “Coal Ash Handling Rules: Changes Generators Face,” (March 2011) was an interesting discussion of solutions to ash handling situations. We all know that

there are a variety of equipment solutions available. What needs to be done is for generators to look at solutions on an individual plant basis instead of cookie-cutter equipment approaches. Each plant has its own unique set of problems that should be looked at to find the best, most economical, long-term solutions. An engineering approach would result in better fitting systems with lower maintenance costs and lower energy use. Coal-fired power generators need a more complete evaluation of the situations they have to deal with on a daily and long-term basis.

As EPA rules become more stringent and it gets harder to build new economical coal-fired power plants, we are going to find ourselves retrofitting older units to meet power demand. Dry ash systems for both fly ash and bottom ash are necessary for the continued life of some older units. Whether adding baghouses, silos or upgrading pneumatic systems to prevent spills and leakage, or moving the ash conditioning away from the plant, a well-designed plan is required.

Richard J Didelot
Manager, Sales
LB Industrial Systems L.L.C.

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