steam digest 2002

8/8/2019 Steam Digest 2002

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U.S. Department of Energy

Energy Efficiency and Renewable Energy

STEAM DIGEST

2002Compiled for the

INDUSTRIAL TECHNOLOGIES PROGRAMBy the

ALLIANCE TO SAVE ENERGY

Bringing you a prosperous future where energy is clean,

abundant, reliable, and affordable

A compendium of articles

on the technical and

financial benefits of steam

efficiency, presented

by stakeholders in the

U.S. Department of Energys

BestPractices Steam efforts.


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Acknowledgements

The Steam Digest 2002 is the third annual compilation of articles dedicated to steam system effi-ciency. The U.S. Department of Energys (DOE) Office of Energy Efficiency and Renewable Energysponsors the BestPractices Steam program, which either directly or indirectly facilitated the creation

of all the articles contained in this volume.

Since its inception, the BestPractices Steam program has been led by Mr. Fred Hart of DOE.Dr. Anthony Wright continues to direct the evolution of the programs technical content, notablyincluding the development of software such as the Steam System Scoping Tool and the SteamSystem Assessment Tool. Mr. Christopher Russell of the Alliance to Save Energy conducts out-reach on behalf of the program, making sure that program materials are properly distributedamong state energy programs, utilities, trade associations, industry media, and the Internet.Ms. Kristin Lohfeld continues in this capacity as of March 2003. Mr. Carlo LaPortaof Future-Tec covers too many tasks to mention, and now is duly recognized.

Mr. Fred Fendt of Rohm & Haas now serves as Chair of the BestPractices Steam Steering Commit-tee. Ms. Debbie Bloom of ONDEO-Nalco continues as Vice-Chair. These individuals participateon the BestPractices Steam Steering Committee:

Bob BessetteCouncil of Industrial Boiler Owners

Victor BogosianNational Board of Boiler andPressure Vessel InspectorsCharles CottrellNorth American Insulation Manufacturers

AssociationBeverly FranceIndustrial Interactions

Elodie Geoffroy-MichaelsTurbosteamRobert GriffinEnbridge Consumers GasGlen HahnSpirax SarcoBill HamanIowa Energy CenterTom HenryArmstrong Services, Inc.Walter JohnsonAssociation of Energy Engineers

Michele JonesNational Insulation AssociationSandra KhalilConsultant

Anthony MartocciBethlehem Steel

Jim MooreTA EngineeringChristina MuddMaryland Energy Administration

Kelly PaffelPlant Evaluations & SupportMiriam PyeNew York State Energy Research &

Development AuthorityDoug RileyMillennium ChemicalsMike SandersSunocoThomas ScheetzBASF

John Todd

Yarway Corp.

We offer grateful recognition to each author for his or her contribution to this compendium. Specialthanks go to Ms. Sharon Sniffen of ORC Macro for assisting with the publication of this volume.


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TABLE OF CONTENTS

INTRODUCTIONChristopher Russell, Alliance to Save EnergyFred Hart, U.S. Department of Energy

Dr. Anthony L. Wright, Oak Ridge National Laboratory

3ENERGYEFFICIENCYAND INDUSTRIALBOILER EFFICIENCY: AN INDUSTRYPERSPECTIVERobert Bessette, Council of Industrial Boiler Owners

Consideration of energy efficiency for industrial boilers, more often than not, is simplified and categorized to a one-size-fits-all approach. This article addresses the four factors most critical for assessing energy efficiency in the industrialpowerhouse supplying energy to make products for the benefit of customers in a highly competitive international mar-

ketplace. 5

DECISION CLIMATEFOR STEAM EFFICIENCY: UPDATE DECEMBER 31, 2002Carlo La Porta, Future-Tec

The Performance Evaluation and Policy Subcommittee of the BestPractices Steam Steering Committee issues a periodic

compilation of data that the Energy Information Administration, U.S. Department of Energy, reports in its Short-TermEnergy Outlook. The author selected data relevant to industrial decision makers concerned with supply and price ofenergy purchased for industrial fuel. The ulterior purpose is to help frame decisions that will encourage more invest-

ment to improve efficiency of industrial steam systems. 17

AN ANALYSISOF STEAM PROCESS HEATER CONDENSATE DRAINAGE OPTIONSJames R. Risko, TLV Corporation

The production and reliability performance of steam process heaters can be significantly affected by the condensatedrainage design that is employed. The current variety of drainage options can be confusing to a system designer who isunaware of the reasons for each specific design. This paper provides us an understanding of the various types and why

they may be used. 23

COMBUSTION CONTROLSTRATEGIESFOR SINGLEAND DUALELEMENT POWER BURNERSDavid C. Farthing, Federal Corporation

Todays economic and environmental demands dictate that we get the greatest practical efficiencies from our plants. Theuse of more advanced automatic control systems for combustion control has proven to be an excellent example of

systems and process automation success. 29

REDUCE FUELCOSTS - USETHE PROPER AIR-TO-FUELRATIOIN BOILER COMBUSTIONChristopher Russell, Alliance to Save EnergyTony Tubiolo, Alliance to Save Energy

Opportunities for combustion improvement projects involve any or all of the following: boiler tune-ups, combustioncontrol repair, burner repair, and repairs to existing oxygen trim systems. With an average payback period of less than

half a year, optimizing steam system combustion is a proven and effective way to reduce operating costs. 37

INSULATION IMPROVES ECONOMIC RETURNSIN MANUFACTURINGChristopher Russell, Alliance to Save Energy

Mechanical insulation plays a role in optimizing a plants valuable energy resources. Two tip sheets, part of a series ofBestPractices Steam tip sheets that currently numbers 19, discuss the benefits of mechanical insulation and demonstrate

the calculation of energy savings that it provides. 35


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SAFETYISSUESIN FOSSILUTILITYAND INDUSTRIALSTEAM SYSTEMSOtakar Jonas, Ph.D., P.E., Jonas, Inc.

The U.S. National Board of Boiler and Pressure Vessel Inspectors reports that 296 power plant boiler-related accidents(including 56 injuries and 7 deaths) occurred in 2001. This report presents results of recent surveys of safety issues in

fossil utility and industrial steam systems.

39

THE HUMAN SIDEOF ENERGYEFFICIENCY: THE VALUEOF TRAININGRachel Madan, Alliance to Save Energy

Many plant managers concentrate their efforts solely on technical improvements, ignoring the tremendous savings that

can arise through low-risk, low-tech solutions such as training for proper maintenance and operation. 43

PRELIMINARYRESULTSFROMTHE INDUSTRIALSTEAM MARKET ASSESSMENTGlenn P. McGrath, P.E., CEM, Resource DynamicsDr. Anthony L. Wright, Oak Ridge National Laboratory

This paper discusses fuel use and potential energy savings in the steam systems of three steam-intensive industries: pulpand paper, chemical manufacturing, and petroleum refining. The results indicate that to generate steam, the pulp andpaper industry used 2,221 trillion Btu, the chemical manufacturing industry used 1,548 trillion Btu, and the petroleum

refining industry use 1,676 trillion Btu. Preliminary results from the effort to determine potential steam system fuelsavings are discussed.

45RESULTSFROMTHE INDUSTRIALASSESSMENT CENTER (IAC) STEAM TOOLBENCHMARKING SUPPORT PROJECTDr. Anthony L. Wright, Oak Ridge National LaboratoryDr. Kurt Bassett, South Dakota State UniversityDr. Herbert Eckerlin, North Carolina State UniversityDr. Ahmad Ganji, San Francisco State UniversityDerek Hengeveld, South Dakota State UniversityDr. Richard Jendrucko, University of Tennessee, KnoxvilleDr. Dragoljub Kosanovic, University of Massachusetts, AmherstDr. Wayne Turner, Oklahoma State University

The U.S. Department of Energys (DOE) Office of Industrial Technology (OIT) BestPractices effort is developing anumber of software tools to assist industrial energy users to improve the efficiency of their operations. One of thesoftware tools developed is the Steam System Scoping Tool. Based on actual plant assessment experience, several DOEIndustrial Assessment Centers (IACs) evaluate the Steam System Scoping Tool in this paper. 53

PROSTEAM - A STRUCTURED APPROACHTO STEAM SYSTEM IMPROVEMENTAlan Eastwood, Linnhoff March Ltd.

A spreadsheet-based steam cost model gives plant managers a clear and reliable understanding of their system and of anyoperational constraints. Models allow managers to identify and prioritize improvement opportunties before capital andother scarce resources are committed. ProSteam is one such analytical tool. 59

STEAM SYSTEM IMPROVEMENTSAT DUPONT AUTOMOTIVE MARSHALLLABORATORYAndrew Larkin, P.E., C.E.M., Trigen-Philadelphia Energy Corporation

Modifications to increase energy efficiency, reduce steam system maintenance costs, and implement small scale cogen-eration are all cited in a Trigen-Philadelphia Energy Corporation recommendation for a campus composed of severalbuildings that are served by a district stream loop. 69


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CLOSED-LOOP ENERGYMANAGEMENT CONTROLOF LARGE INDUSTRIALFACILITIESRonald L. Childress, Jr., Automation Applications, Inc.

This is a case study of a closed-loop control system installed and running at a pulp and paper facility in the southeast. Afuzzy logic, rule-based control system optimally loads multiple steam turbines for maximum electrical generation, whileproviding steam to the process. A Sell Advisor calculates Make-Buy decisions based on real-time electrical prices, fuelprices, and boiler loads.

75AN INTRODUCTIONTO STEAM OUTSOURCING

Tom Henry, Armstrong Service Inc.One evolving trend in the boiler replacement business is the movement to outsource the equipment, installation, andoperation and maintenance--called the build, own, operate, and maintain (BOOM) market. Energy service companies(ESCOs) and lending institutions are developing services that respond to this emerging need. 85


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Steam Digest 2002

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IntroductionChristopher Russell, Alliance to Save Energy

Fred Hart, U.S. Department of Energy

Dr. Anthony L. Wright, Oak Ridge National Laboratory

Why steam?

Steamor more specifically the heat that steamprovidesplayed a role in the production of vir-tually everything in the room around you. Thatincludes the paper and ink in this document. Ittempered the adhesives and fibers in wood-prod-uct desks and cabinets. Steam helped to manu-facture your chair: plastics in the handles, foamcushioning in the seat, and the fabric covering aswell as the pigments that color each of those items.Nuts, bolts, screws, and other metal fixtures werepre-heated with steam so that corrosion-retardingchemicals could be applied to them. The wallsthat surround you are probably made of eithersheetrock or paneling, both of which were pressedfrom a steam-heated slurry of raw materials. Paintson your walls, pencils, and filing cabinets includepolymers with a molecular structure that couldonly be assembled by high-temperature chemicalreactions (again, facilitated by steam). The elec-tric light by which you read was almost certainlyproduced by a steam turbine, fired by coal, natu-ral gas, oil, or nuclear energy. And that bag ofpotato chips? The potatoes were peeled in a

large, pressurized vat that accepted steam injec-tion for 62 seconds, at which point the pressurewas removed and the liquid content of the pota-toes literally blew the skin off, leaving the potatowhole.

That was only a short list of steam products.

Steam use in manufacturing can, and should, bepart of any attempt by policy makers to addressresource conservation, industrial competitiveness,energy market structure, and climate change. Thefollowing are facts that will substantiate1 :

Thirty-five percent of all fuel consumed byindustry for energy purposes is devoted to rais-ing steam.

Fuels consumed by steam systems (industrial,commercial and institutional) are roughly ninequadrillion Btu, or about one tenth of nationalprimary fuel demand for everything, includ-ing transportation.

A one percent improvement in industrialenergy efficiencywhich is technically easyto accomplishwould return to energymarkets a volume of fuel sufficient to satisfythe non-transportation energy needs of 3.2million households.

BestPractices Steam is a U.S. DOE program that

promotes steam efficiency. The program does notregulate or compel action on anyones part. In-stead, it simply identifies, documents, and com-municates best-in-class steam management tech-nologies and practices. These findings are madefreely available in a series of reference documents,tip sheets, case studies, diagnostic software, andmoreeither printed or available for Internetdownload.

The articles in Steam Digest 2002represent a vari-ety of operational, design, marketing, and programassessment observations. Readers are encouragedto also consult the 2000 and 2001 editions foradditional reference. Please contact:

U.S. DOE Office of Energy Efficiency &Renewable Energy Resource Room:(202) 586-2090;

EERE Clearinghouse:[email protected](800) 862-2086;

http://www.oit.doe.gov/bestpractices/steam; or

http://www.steamingahead.org .

1 All data from U.S. DOE Energy Information Administra-

tion
mailto:[email protected]://www.oit.doe.gov/bestpractices/steamhttp://www.oit.doe.gov/bestpractices/steamhttp://www.oit.doe.gov/bestpractices/steamhttp://www.steamingahead.org/http://www.steamingahead.org/http://www.steamingahead.org/http://www.oit.doe.gov/bestpractices/steammailto:[email protected]


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Steam Digest 2002Energy Efficiency and Industrial Boiler Efficiency: An Industry Perspective

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Energy Efficiency andIndustrial Boiler Efficiency:

An Industry PerspectiveRobert Bessette, Council of Industrial Boiler Owners

Energy efficiency for industrial boilers is a highlyboiler-specific characteristic. No two boilers arealike. There are two identically designed, con-structed side by side, stoker fired boilers in Indi-ana burning the same fuel that have very differentperformance characteristics. Like twin teenagers,they are not the same. Consideration of energyefficiency for industrial boilers, more often thannot, is simplified and categorized to a one-size-fits-all approach. Just as when considering teen-agers, this does not work. While parents wouldlike to believe their teenager is gifted and talentedand in the 80th percentile of the population, weknow that is not necessarily the case. We alsoknow, as for boilers, the average teenager is notrepresentative of a widely diversified population.If you think it is, ask any parent with teenagers oran industrial boiler operator. While the variablesassociated with energy efficiency are more limitedthan those associated with a teenager, they are inno way any less complicated.

Four factors are critical for assessing energy effi-ciency in the industrial powerhouse supplying en-

ergy to make products for the benefit of custom-ers in a highly competitive international market-place. These are:

1. fuel type,2. combustion system limitations,3. equipment design, and4. steam system operation requirements.

Furthermore, the industrial facilitys complexity,location, and objective complicate them. It isimportant for the industrial company to remem-ber, unlike the utility, that energy is a smaller por-

tion of the final product price. However, withoutenergy there is no final product or service. Need-less to say, without products or services there is noneed for people to do the work.

This white paper will address the efficiency-relatedaspects of the four primary factors affecting theindustrial boiler and the factors affecting applica-tion of combined heat and power systems to in-dustrial facilities. A copy of the Background Paper

on the Differences Between Industrial and UtilityBoilers is included as an appendix to help un-derstand the diversity of the industrial boilerpopulation. From the EPA Boiler MACT Da-tabase, there are about 22,000 industrial-com-mercial and institutional boilers with greaterthan ten million Btus per hour heat input.

NEWVS. EXISTING UNITS

Before investigating specifics of industrial boilerefficiency considerations, it is important to un-derstand that once a boiler is designed, con-structed, and installed, it can be difficult and costlyto improve its efficiency above the design. Onthe other hand, as will be discussed below, changesin fuel, load, and operation can easily impact over-all efficiency. Because of the high cost of the en-ergy plant, boilers and associated systems usuallyare purchased for the life of a facility with ample

margin for future growth and process variability.With proper maintenance, boiler life is indefinite.In most cases, it will outlive the process it origi-nally was designed for but not the facility. Forexample, a facility that was producing eight tracktapes changed to produce cassette tapes and is nowproducing CDs and DVDs. The boiler will stillbe there meeting new demands.

With todays technologies it is possible to designboilers to handle a wide range of requirements andpossibilities. However, in most cases this is eco-nomically impossible if a process is to survive in a

competitive world. It could be like building a newhome with a heat pump and a furnace capable ofburning natural gas and a furnace capable of burn-ing oil to cover the heating, air conditioning, hotwater, and other household needs. The cost of allof this equipment would break the budget. It isevident that an average person probably could af-ford only one of these devices. If the person triedto buy all three, they would not be able to affordthe house.

New units are purchased with a guaranteed effi-ciency at a Maximum Continuous Rating (MCR)for a specific design fuel producing a specifiedquantity of steam or hot water at a specified tem-perature and pressure. Any changes in these char-acteristics change the operating efficiency. A guar-antee over a wider range of fuel, capacity, and tem-perature and pressure is technically possible. How-ever, as mentioned, it may not be economicallyjustifiable for a given facility. In the end, a newunit may be defined only as one that is designed,


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purchased and installed, but never run at theguarantee conditions other than to pass accep-tance tests. In the real world almost nothingoperates at the design specifications.

ANNUALAVERAGEVS. MCR DESIGN

If you start from cold water have you ever watchedhow long it takes to get it boiling? I believe it wasBen Franklin who said, A watched pot neverboils. It does, but it takes the addition of 1,000Btu per pound of water before it does. After that,considering losses from the teapot or boiler, Btufor Btu, is converted to steam where you use it orlose it. In systems that have a heavy cyclic load,the operator can either start up or shut down theboiler as needed (for a period lasting 2 to 5 hourseach way) without the loss of much of the initialenergy. However, for periods longer than this,much if not all of the initial 1,000 Btus are lost.

On the other hand, the operator can keep it atpressure to ensure rapid response by supplyingenough heat to compensate for losses in the sys-tem. Here, efficiency is zero, but the initial 1,000Btus are maintained. In both cases there is in-creased energy loss and the inability to meet ormaintain MCR efficiency. In facilities like a col-lege campus, with a heating load, where heat isneeded every morning so the students will havewarm classes to go to, hot showers to wake upwith, and hot food in the cafeteria serving lines, itis better to keep the boiler hot, lose the efficiency,and keep the students, their professors and their

parents happy. In a large hospital performingmany major surgeries per day using autoclaves tosterilize surgical instruments, should a system bedesigned to handle the maximum number of sur-geries expected or a smaller number thus limitingthe number of people that can be helped in anyone day? Obviously, the system must be designedto meet the maximum capacity of the hospital.Here it is impossible to deliver both MCR effi-ciency conditions and optimum patient service.There also are losses associated with low load op-eration that will be discussed in greater detail un-

der the Systems Operation section below.

Each facilitys needs will be different. Steam loadrequirements will change for different facilities.Departures from MCR conditions will vary widelydepending upon facility process needs. Subse-quently, the annual average efficiency, and forsome, the hourly average efficiency will be less thanthe MCR efficiency of the design. Differences

between actual efficiency, an annual average, andMCR can be as much as 40 percent or moredepending upon the facility. Any considerationof industrial boiler efficiency must consider dif-ferences between real, actual, and design effi-ciencies.

The ability of a particular process to use steam

efficiently complicates this factor. With steam af-ter it is produced you use it or loose it. Inefficien-cies inherent for various process factors can be asimportant as the inefficiencies associated with theboiler.

FUELTYPE

Mother Nature is miraculous. Naturally occur-ring fuel (gas, oil, wood, coal and biomass) is vari-able. The plants, animals, bugs and other crittersthat formed the fuel underwent tremendous

change at different locations and over differenttime periods. Elemental compositions of fuel[moisture (H

2O), carbon (C), hydrogen (H), ni-

trogen (N), chlorine (Cl), sulfur (S), oxygen (O)and ash] can vary as much as 30 percent or morefrom an annual average basis depending upon theirinherent composition and degree of fuel refiningor preparation. Any variations in fuel composi-tion from the original design of the system willdirectly affect boiler efficiency. In most cases withboiler design these days, variations of less than oneor two percent from the design fuel compositionwill have virtually no perceptible impact on effi-

ciency. For this discussion, the Btu per pound,gallon, or cubic foot of the coal, oil, or gas respec-tively may be a better, however over simplified,way of looking at it.

Even natural gas can vary between 900 and 1,100Btu/cu. ft. depending upon the methane content.Over the years technology has allowed gas com-panies to blend gas and control its Btu and com-position to a level of around 1,000 Btu/cu. ft. (+or one or two percent) on an annual averageand hourly average basis. This, along with its

deliverability, ignitability and controllability is agood reason why natural gas is used as a primaryfuel for home heating, hospitals and commercialinstallations. The very high hydrogen content(high hydrogen to carbon ratio) of natural gas thatburns to form water removes a significant amountof heat from the process and can seriously impactthe overall efficiency of the boiler as comparedwith other fuels.


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Crude oil is refined to remove the highly valu-able portion for industrial feedstocks for plas-tics and other products, for gasoline, aviationfuel and diesel fuel for transportation, and forhome heating oil with very low variability. Thevariability of each of these premium productscan be equal to or better than that of naturalgas. Industrial fuel products are the leftovers

from refining and can have increasing variabil-ity as the quality goes from a No. 2 oil to a No.6 or high asphaltene Bunker C grade oil or roadgrade asphalt or petroleum coke. In such cases,variation in viscosity (burning something likeblack strap molasses or hot maple syrup forthe liquids coke is a solid more like coal) canhave a serious impact on combustion efficiencyand overall boiler efficiency. Variation in fuelcharacteristics on an hourly average basis maybe better or equal to that of natural gas. How-ever, variations in fuel characteristics betweenshipments over the year may increase the an-nual average variation to somewhere in the rangeof five percent. Because oil has a lower hydro-gen content (decreasing with increasing grade)than natural gas, the overall boiler efficiency as-sociated with burning fuel oils usually is higherboth at MCR and annual average. Oils are verygood boiler fuels.

Coal, our most abundant fuel, can be mined withnew technologies and coal preparation plants toremove rock (contaminants) captured in the pro-cess to a plus or minus 10 percent natural vari-

ability within a given seam. However, differentcoal seams vary tremendously from lignite at 4,000Btu per pound with seven percent hydrogen and35 percent moisture to anthracite with 14,000 Btuper pound with two percent hydrogen and threepercent moisture. With low hydrogen contents(low hydrogen to carbon ratio), coal is the mostefficient energy source for conversion of Btus intousable energy.

Blends of various coal seams and the inability toremove contaminants, if there is no preparationplant, can lead to fuel quality variations of 10 per-

cent or more on an hourly basis and 20 to 30 per-cent on an annual basis. Coal fired systems nor-mally are designed to handle up to a plus or mi-nus 10 percent variability without visible degra-dation of performance. Because of the diversityof coal types, locations, and characteristics, dif-ferent types of combustion systems are used toburn fuel and generate energy. The following sec-tions will look at this aspect in more detail.

Wood and biomass are solid fuels with both highhydrogen to carbon and high moisture content(greater than 40 percent). Because of energyloss due to moisture from the combustion ofhydrogen and conversion of moisture to vapor(1,000 Btu per pound), it is very difficult toobtain efficiencies, either MCR or annual aver-age, equal to or approaching those of natural

gas, never mind oil or coal. A very good annualaverage efficiency for a wood or biomass unitmay be in the 60 percent range. While fuelproperty variations may be better than coal, thesevariations usually occur in the moisture content with a direct and major impact on boiler effi-ciency.

Fuel characteristics determine the design of a par-ticular unit. Fuel changes, especially in hydrogenand moisture content outside the range of one ortwo percent for natural gas, three to five percentfor oil and 10 percent for coal and other solidfuels, will have an impact on efficiency, both MCRand annual average. When fuels are switched, theinteraction of the new fuel and the boiler oftenproduces negative impacts on either the load orthe boiler efficiency. These effects often are am-plified because of limitations encountered in spe-cific areas of the boiler where these adverse inter-actions occur. A good analogy would be a truckthat comes onto a superhighway that has bridgeclearances more suitable for cars. When the truckapproaches a bridge, it has to slow down to en-sure that it can pass under a place where the clear-

ance is adequate. This causes traffic to move slowerbecause the highway was not designed with thetruck in mind.

COMBUSTION SYSTEMS

Efficient fuel burning (combustion) requires at-tention to the entire combustion apparatus. Be-cause some problem areas are common to all typesof combustion systems, those areas will be dis-cussed before reviewing specific system problems.

Good combustion is the ability to mix air and fuel,with as little excess air as possible, at a high enoughtemperature to sustain the process and completelyburn the fuel (complete carbon conversion) withminimum environmental emissions. Good com-bustion also includes the ability to generate maxi-mum usable energy consistent with process needs,safety, and economics. This is a complex processof matching fuel combustion characteristics, ig-nition, including pyrolysis, and char burn outfor heavy liquid and solid fuels, with the time,


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temperature and turbulence available from thefurnace absorption profile and combustion sys-tem capabilities design. All this has to be ac-complished with the safety of operators and fa-cility personnel in mind.

Each year, the news media inform us of boiler ex-plosions that kill people be it a steam tractor at

a county fair or an industrial or utility powerhousein the center of a city. A typical 100,000 poundsper hour steam boiler requires about 125 millionBtus (MMBtu) of fuel input each hour. That isequivalent to approximately 1,100 gallons of gaso-line, 125,000 cu. ft. of natural gas, and a littlemore than 900 gallons of kerosene. What we haveis a controlled explosion where we take energy outand use it for beneficial purposes. There can beproblems with this. Safety must always be ournumber one priority.

Combustion systems, while they may seem simple,are very complex. Included in Appendix B isChapter 3, Combustion, of the CIBO EnergyEfficiency Handbook. Here additional details ofday to day concerns for optimizing and maintain-ing combustion efficiency are presented.

EQUIPMENT DESIGN

Industrial boiler equipment is as varied as the prod-ucts and processes it serves. A better understand-ing of this is given in Appendix A, DifferencesBetween Industrial and Utility Boilers. Boilers

are one means of extracting energy from controlledfuel combustion. There are watertube, firetube,field-erected, and packaged shop-assembled unitsfrom very small to very large. The concept issimple, like a teapot. Boil water to make steam.However, the actual process is complex. Turning100,000 pounds of water (thats 12,500 gallons,1,250 fish tanks or a swimming pool) to steameach hour brings with it many complications.

It is impossible to capture each and every Btu fromcombustion in the boiler. For example, some getaway to the atmosphere. Industry has devised waysto capture most of the Btus economically. As anold farmer might say, they capture everything butthe squeal. Of course, today it could be possibleto capture that on a CD if it had a use. It is notdone and probably will not be done because itwould cost more to buy a CD recorder and takemore energy to run the CD recorder than the valueof the squeal. The same thing happens withenergy. Some of it gets away and that varieswith the boiler, the fuel, and the plant require-ments. If it can be used cost effectively, it is.

A discussion of some of these losses is includedin Appendix C, Chapter 4: Boilers of the CIBOEnergy Efficiency Handbook.

SYSTEM OPERATIONS

The ideal situation would be to be able to operate

the boiler or energy device at the design MCR. Ifeverything were perfect, one could design a unitthat would have a relatively flat efficiency curveacross the load range. A tangentially fired boilerwith tilting burners could adjust tilts to achievethe same exit gas temperature with the same levelof excess air and the same combustion efficiencyat all operating loads (the three main determi-nants of boiler efficiency). However, this typeunit is used primarily in the utility industry onlarger boilers.

CIBOs Energy Efficiency Handbook points out

(at the bottom left of page 26 in Chapter 5, Con-trols under Oxygen Loop), that most burners re-quire more excess air at low loads than at highbecause there is less effective fuel to air mixing.This is due to mixing characteristics of flowstreams and the fact that less total reacting gas isnow filling the furnace volume. Air infiltrationaggravates this condition because infiltrated airdoes not mix with the fuel at all. These factorscause mixing problems and also lower the bulkflame temperature, which, in turn, slows downcombustion reactions. As a result, the higher ex-cess air at lower loads causes a decrease in boilerefficiency due to the additional air that must bewarmed up to stack temperature and exhaustedto the atmosphere. For natural gas firing, thisimpact is not too bad. An estimate of a five per-cent efficiency drop from full load to 25 percentload probably is reasonable for a modern, tight,package boiler with full combustion controls. Onthe other hand, an old stoker with no air controlsleaves the airflow fixed and drops load by reduc-ing fuel input. In such cases there could be morethan 200 percent excess air at low loads causingboiler efficiency to drop from about 85 percent at

high load to around 60 percent at low load.

The problem with generalizations is that there areso many factors including fuel type, as-receivedcondition of the fuel, boiler type, control system,amount of air leakage, maintenance status of theunit, and more. Larger units tend to suffer lessthan smaller units because they have multipleburner sets that can be turned off completely atlow loads leaving remaining burners to run as ifthey were at full load. Also, larger units tend


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to be newer and have better control systems toadjust the operation thus reducing losses in ef-ficiency associated with lower loads.

At the risk of oversimplifying the problem, ifwe assume a relatively new unit, firing coal, oil,or gas we can use the following ranges:

It is sufficient to say that under normal opera-tion, efficiency is lower than guaranteed effi-ciency of the new unit operating at MCR. How-ever, for comparative reasons, design modifica-tions or operational and fuel changes that im-

pact MCR efficiency should have a proportionalimpact on actual efficiency the facility is achiev-ing on an annual average basis.

COMBINED HEATAND POWER

Ideally, energy is used most efficiently when fuelis combusted at a high temperature and high tem-perature Btus are converted to electricity or me-chanical energy in a gas turbine, internal combus-tion engine, or back pressure steam turbine fol-lowed by the use of the lower temperature Btus to

meet process needs through heat transfer.

Electricity, mechanical energy, and heat are dif-ferent forms of energy. Scientists have shown thatdifferent forms of energy have different qualitiesbased upon the ability to perform useful work.Scientists tell us that electricity and mechanicalenergy produce work more effectively than heatenergy. In other words, a Btu worth of electricalor mechanical energy has more value than a Btuworth of heat energy (similar to money where aU.S. dollar is worth more than a Canadian dol-lar). Furthermore, a higher temperature Btu has

more value than a lower temperature Btu becauseit can be converted more efficiently into more valu-able electrical and mechanical energy. However,both electrical and mechanical energy must be pro-duced from some other energy source.

Starting with fuels, industry accomplishes con-version by burning the fuel and releasing heat. An engine then converts heat energy into me-chanical or electrical energy. If combustion oc-

curs inside an engine, it converts heat energy tomechanical energy that can be used to drive apump, fan, compressor, or electrical generator.Exhaust leaving the engine is hot. This exhaustcontains over half of the Btus released duringinitial combustion of the fuel and it can exceed1,000 oF. If none of the exhaust heat is used,the device is known as a simple cycle. If heat is

recovered from the exhaust for the additionalutilization, the combination of the engine andother devices is known as a cogeneration systemor a combined cycle system.

Efficiencies for simple cycles vary dependingupon the design, size, and location of the en-gine (gas turbine, internal combustion engine).This also translates into a range of efficienciesfor combined cycles. As with boiler efficienciesone size does not fit all. Example efficiencies forconversion to electricity in simple and combinedcycles are as follows:

An examination of the electricity generation ef-ficiency table shows that when electricity is theonly product, maximum Btus recovered areabout 40 percent for simple cycles and 54 per-cent for combined cycles. The increased effi-ciency for the combined cycle shows that onlyabout 25 percent of the exhaust heat can be con-verted to electricity with modern technology.The difference between 40 percent conversion

for the simple cycle and 25 percent additionalconversion illustrates the difference in value be-tween low temperature heat and high tempera-ture heat.

The concept of combined heat and power pro-vides further efficiency improvements over pro-ducing only electricity using exhaust heat di-rectly in the manufacturing process. Manymanufacturing processes require heat at tempera-tures between 250oF and 700oF. The Btus pro-

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10

vided by the exhaust from the above applica-tions are at temperatures that match these tem-perature requirements well. Hence, by convert-ing high temperature, high quality Btus to me-chanical or electrical energy and taking the lowertemperature, lower quality Btus to meet pro-cess temperature needs, the energy in fuel canbe used most effectively and efficiently. With

this combination, from 60 percent to 85 per-cent of the Btus in the fuel can be recovered andused effectively.

After comparing these efficiencies with boiler ef-ficiencies listed in Table 1, on the surface nothingseems to have been gained. However, the gaincomes when one considers that for electricity gen-erated at a central plant or for mechanical energyto run a compressor, fan, or pump, from 60 per-cent to 75 percent of the Btus are lost. Under aconventional system, a boiler or other combus-tion device is still required to provide heat for thefacility or manufacturing process. For those thatmay want a more technical discussion of combinedheat and power and efficiency, the followingshould help provide additional insight.

COMBINED HEATAND POWER EFFICIENCY

The most common expression of efficiency is acomparison of the desired output of a process tothe input. Electrical power generation efficiencyis a relatively simple concept because electricalpower is the only desired output and fuel energy

is the only input.

Equation 1:

Efficiency =electrical generation

=Electrical Power Produced / Fuel Energy Input =Energy Desired / Purchased Energy

A very common type of electrical generation sys-tem consists of a boiler and a steam turbine ar-rangement. In this arrangement the boiler servesto input fuel energy into water to produce steam.The steam exits the boiler with a very high energy

content. As an example, the boiler may add 1,450Btu of fuel energy to every pound of water pass-ing through the component. The steam turbineserves to convert this thermal steam energy intomechanical or shaft energy. The turbine is veryeffective at this conversion process; in fact, nearly100 percent of the steam energy extracted by theturbine is converted into shaft energy. However,this excellent efficiency only applies to the ther-mal energy extracted by the turbine. The turbine

actually leaves the vast majority of thermal en-ergy in the exhaust steam. As an example, a steamturbine may extract 450 Btus of thermal energyfor every pound of steam passing through theturbine. This energy is readily converted intoelectrical energy with excellent efficiency, nearly100 percent. However, recall the boiler input1,450 Btus of thermal energy into every pound

of steam. Therefore, 1,000 Btus remain in eachpound of steam exiting the turbine. This steamexiting the turbine is not useful to the powergeneration system and is discarded from the sys-tem. The steam energy is discarded by coolingor condensing the steam. This gives rise to thedescription of this system as a condensing tur-bine system. The desired output of this sys-tem is the 450 Btus of electrical energy and theinput is the fuel-input energy (1,450 Btus offuel energy). The efficiency of this system wouldbe as follows.

Equation 2:

electrical generation= 450 Btu / 1,450 Btu = 31%

Industrial systems utilizing combined heat andpower arrangements have a need for the thermalenergy discharged from the turbine. This providesthe basis for the advantage of combining heat andpower generation systems. If the 1,000 Btus inevery pound of steam can be used in a productivemanner the fuel utilization efficiency can dramati-cally increase. In a combined heat and power sys-tem there are two desired products, electricity and

thermal energy. The fuel utilization efficiencyequation will take the following form.

Equation 3:

CHP= Electrical Power Produced +

Useful Thermal Energy / Fuel Energy Input

In theory, this efficiency could reach 100 percent,in reality, inefficiencies result in maximum effi-ciencies approaching 70 percent. Note that thisefficiency considers thermal energy equal in valueto power. This may not be the case because power

is normally more valuable (easily usable) than ther-mal energy, but thermal energy is valuable. Somecommon examples where steam could be morevaluable than electricity are sterilizing hospital in-struments, making paper and steam tracing chemi-cal lines. Other mechanisms are utilized to pro-duce electrical power; however, current conven-tional mechanisms consuming fuel (combustionturbines and reciprocating internal combustionengines) result in very similar arrangements.


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Condensing steam turbines with the ability tocondense unneeded steam are often incorporatedinto industrial combined heat and power sys-tems to allow the system to be balanced. In otherwords, if the demand for thermal energy dimin-ishes and the demand for electrical energy in-creases, steam can be passed through a condens-ing steam turbine to produce the additional

power while maintaining a more uniform andefficient load and without venting the steam.The fuel energy utilization efficiency of operat-ing the condensing turbine returns to the lowvalue described above (31 percent and evenmuch less) for that portion of the steam con-densed. In order for condensing power to becost effective, the fuel cost must be significantlyless than the electricity cost. In fact, becausethe industrial facility will generate condensingpower less efficiently than the large utility, inthe evaluation, to produce electricity throughcondensing, efficiency losses must balanceagainst process needs, availability requirements,and alternative electricity purchasing costs orsales revenues.

Example:Consider an industrial facility requiring both ther-mal energy and electricity. The facility currentlypurchases electricity from the local power genera-tor and fuel from the fuel supplier. The local powergenerator purchases fuel from the same fuel sup-plier as the industrial customer. The local powergenerator purchases 100 units of fuel and con-

verts this into 31 units of electrical energy. Thiselectrical energy is consumed in the industrial fa-cility. The industrial facility purchases 100 unitsof fuel and converts it into 80 units of thermalenergy. A combined heat and power system couldbe operated at the industrial complex to supplythe same amount of electrical and thermal energy.The combined heat and power system might re-quire 143 units of fuel energy to supply the samethermal and electrical demands as the 200 unitsof fuel originally required. This is a 28 percentreduction in fuel consumption.

To give you an idea of relative cost, comparisonof the use of natural gas and electricity for homeheating may be beneficial. Assuming the sameamount of energy is needed to keep the homewarm on a very cold day (some temperature lessthan freezing outside), a simple calculation canhelp understand the differences. We can look atthe energy costs in dollars per MMBtu delivered.

Natural gas is normally sold in cents per therm(100,000 Btu). Multiply this by 10 and we have$/MMBtu.

For natural gas, if you pay 62 cents per therm,you pay $0.62/therm x 10 therm/MMBtu =$6.20/MMBtu.

Electricity is normally sold in cents per Kilowatt(kW). Multiply this as dollars by 293 kW/MMBtugives dollars per MMBtu, something that is di-rectly comparable to the cost of other energysources.

For electricity, if you pay 10 cents per kW, youpay $0.10/kW x 293 kW/MMBtu = $29.30/MMBtu.

Thank goodness for heat pumps when the tem-perature is in the proper range. Here they are about300 percent efficient and that lowers the heatingcost to about $9.80 per MMBtu.

APPLICATIONOF COMBINED HEATANDPOWER SYSTEMS

The discussion above explained advantages ofcombined heat and power systems using gas tur-bines, internal combustion (IC) engines, com-bined with boilers to show how these systems useBtus released from fuel combustion more effi-ciently. A common combined heat and power

system (perhaps the oldest for industrial applica-tions) consists of generating high temperature,high-pressure steam and running it through a backpressure steam turbine to produce electricity. Hotexhaust from the turbine goes to the process touse the lower temperature Btus. This section cov-ers applications of various combined heat andpower systems to show that selection of the opti-mum system depends upon the resources andneeds of the facility.

The main factors that determine the type of en-ergy supply system for a given facility are:

Fuel availability; Proportion of plant energy needed in the form

of electrical, mechanical and heat; Extent and frequency in supply requirements

for steam; and Market for surplus electricity.


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Fuel availabilityFuel availability depends upon the geographi-cal location of the facility, products produced,cost of various fuels, and compatibility of vari-ous fuels with plant processes. Some exampleindustries that demonstrate this relationship are:pulp and paper, cane sugar processing, refiner-ies, ammonia plants, and batch chemical plants.Contrary to popular opinion, there are areas inthis country where natural gas is not availablebut where there are abundant supplies of coalor other fuels.

Pulp and paper and cane sugar processing are ex-amples of industries that produce a fuel byproductused for some or all of their energy supply. Thepulp and paper industry burns bark and woodfrom trees that provide feedstock for making pulpand paper. It also burns pulp residue that other-wise would be wasted. The sugar industry burns

bagasse, which is leftover material after sugar hasbeen squeezed out of sugar cane. These fuels aresolid biomass. The paper industry supplementsfuels with coal, another solid fuel that is burnedeasily with biomass. Other biomass fuels includepalm fronds, peanut shells, rice hulls, hog manure,and poultry litter. If it has Btu value, someonecan use it, and probably is using it for a fuel togenerate valuable energy and eliminating a poten-tially serious waste disposal problem.

Refineries process crude oil, and use fuelbyproducts (gas, heavy oil, and coke) for most of

their energy requirements. These fuels are supple-mented with small quantities of natural gas.

Ammonia plants use natural gas with some of theirbyproduct purge gas. Natural gas is both a fueland the feedstock.

Batch chemical plants use a variety of fuels (natu-ral gas, oil and coal) mainly depending upon thegeographical location of the plant.

Need for electrical, mechanical, and

heat energyThe proportion of energy in the forms of electric-ity, mechanical energy, and heat energy is impor-tant in determining the extent to which a com-bined heat and power system can be applied at agiven facility. When there is little need for electri-cal or mechanical energy, a combined heat andpower system may not be practical. Using theindustrial examples, the following observations arepertinent. If there is no need for thermal (heat)

or mechanical energy at a location, there is nopossibility for a combined heat and power sys-tem.

The pulp and paper industry needs heat in theform of steam to operate digesters that makepulp and to provide heat for drying paper. Theindustry needs electrical energy to run paper

machines and mechanical or electrical energy torun debarking machines, pumps, and compres-sors. Due to these requirements, a pulp andpaper mill often uses combined heat and power.Steam from boilers goes through backpressureturbines to make electricity; then exhaust steamgoes to digesters and paper dryers to provideprocess heat.

Due to fuel availability and steam and electric pro-cess requirements, use of gas turbines is not nor-mally practical in a combined heat and power ap-plication in this industry where energy efficiencymaximization is of prime importance. Becausethe fuels contain high moisture levels, the ther-mal efficiency of the combined heat and powersystem within these facilities is inherently lowerthan in other applications.

Refineries require both electricity and heat energy.Recently, many refineries have added gas turbineswith heat recovery steam generators (waste heatboilers). Electricity runs pumps, fans, and com-pressors inside the refinery, and steam from thewaste heat boilers provide heat for refinery opera-

tions such as distillation units, reboilers, and othermachinery that demand electricity and steam.Surplus electricity not used within the plant is soldto the electrical power grid. With available fuels,the combined heat and power system can attainvery high efficiencies for refinery applications.

Another form of cogeneration involves the use ofpetroleum coke that is burned in a circulating flu-idized bed boiler to generate steam. Steam goes toa backpressure turbine to make electricity and ex-haust steam goes to the refinery to provide heatfor refinery operations.

When discussing combined heat and power regu-lators, plant managers often concentrate on elec-tricity generation followed by the use of the re-sidual heat to produce steam. Although this is atypical combined heat and power scenario, it isnot always the most efficient or effective use oftechnology at a given facility. For example, am-monia plants require a lot of mechanical energyto compress gases to very high pressure. For


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this case, it is better to use a gas turbine to drivethe compressor(s) rather than use a large elec-tric motor. The exhaust from the gas turbinecontains high levels of oxygen as well as hightemperature. This exhaust can be used to firemore fuel in a furnace that produces hydrogenfor the ammonia process. In this case, thepower is mechanical energy and the residual

heat is converted directly to chemical energy andsteam in the furnace. Due to process require-ments it is not wise to make electricity with thegas turbine and send it to an electric motor todrive the compressor.

Batch chemical plants have varying needs for elec-tricity, mechanical energy, and heat dependingupon the product produced. The suitability andselection of various combined power and heat andpower systems may vary widely depending uponprocess needs.

Extent and frequency in supplyrequirements for steamCombined heat and power systems are less likelyto be practical in small plants where steam require-ments change rapidly. Many batch chemical plantshave this characteristic. It is counterproductiveto run a gas turbine or IC engine to produce elec-tricity and to throw Btus into the atmosphere inthe form of vented surplus steam.

Market for surplus electricityIn some cases, the need for electricity or heat isout of balance. Electricity must be generated insurplus quantities to produce enough steam forprocess use. In these cases, electricity must be sal-able at a price that exceeds the money needed tobuild the combined heat and power unit at thefacility. Industry operates at low profit marginsand cannot afford to give free electricity to otherusers. However, there is one thing for certain, ifthere is a need for steam there is a possibility forcombined heat and power.

INTERNALCOMBUSTION ENGINESAND

TURBINE CONSIDERATIONS WITH WASTEHEAT BOILERSOR HEAT RECOVERYSTEAMGENERATORS

Modern internal combustion (IC) engines usedto generate electricity with either fired or unfiredheat recovery boilers maintain their simple cycleefficiency, which is the highest efficiency of com-mercial technologies under real-world ambient

temperatures and elevations above sea level. Co-generation applications that recover the maximumamount of waste heat created by the generation ofthe electrical component of the plant achieve over-all efficiencies in excess of 80 percent on a highheating value (HHV) basis. Simple cycle ther-mal efficiencies can exceed 41 percent on a HHVbasis, i.e., those when only electricity is being

generated and no waste heat recovery is occur-ring.

Cogeneration applications favor gas turbine tech-nology when the process requires a massive amountof high temperature steam. Gas turbines createlarge quantities of high temperature exhaust gas,resulting in the need to generate large quantitiesof high temperature steam in order to achieve ac-ceptable overall plant thermal efficiencies. If usesfor the large quantity of high quality steam areavailable, then gas turbine technology usually isused.

In the other on-site situations requiring smalleramounts of steam and higher quantities of pro-cess hot water, modern IC engine technology pro-vides the best economic returns for the owner andis the technology of choice.

As discussed previously, the reason that gas andoil have lower boiler efficiencies than coal is be-cause these fuels have progressively higher hydro-gen contents that generate water during combus-tion. This water is boiled and heated up to stack

temperature where it is emitted into theatmosphere. (The water in this instance is formedas a vapor, as it contains the latent heat but doesnot pass through the boiling process in the com-bustion process). That moisture loss takes heataway from the energy available to boil the waterinside the tubes to make steam for productive use.If there is moisture present with the fuel, such assurface water or humidity, that water also is lostto the stack and causes an efficiency loss. (Yes, theefficiency varies with the time of year and theweather.) Recognizing this loss, boilers are ratedbased on a higher heating value of the fuel. This

efficiency includes unrecovered heat from allow-ing water vapor to exit the boiler.

Gas turbine advocates attempt to avoid this com-plexity by referring to the lower heating value ofthe fuel and doing all of their calculations at ISOconditions (59F and one bar and constant rela-tive humidity). In the real world, gas turbineslose efficiency faster than steam turbines as loadis decreased, and lose output particularly fast as


19/92


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ambient temperatures and altitudes increase.Efficiencies presented in this white paper are allbased on the higher heating value to provideadequate comparisons.

SUMMARYAND CONCLUSIONS

Owners and operators of industrial facilities striveto operate at optimum efficiencies. However, un-like the utility industry that produces a single prod-uct, industrial facilities are more complex. Boil-ers designed for such facilities are much more di-versified in order to meet widely differing require-ments. These different requirements naturallycreate optimal efficiencies that vary widely fromindustry to industry and from facility to facility.The one-size-fits-all approach often used by regu-lators to encourage increased energy efficiency sim-ply does not work because this approach does notconsider the many specific factors that affect en-

ergy efficiency.

This white paper has discussed major factors thatsignificantly affect achievable energy efficiencieswithin various industrial facilities. Fuel type andavailability, combustion system limitations, equip-ment design, steam system operation require-ments, energy requirement mix, and outside mar-ket forces all affect the achievable efficiency of anindustrial facility.

Fuel type and availability has a major effect. Fu-els with high heating values, high carbon to hy-

drogen ratios, and low moisture content can yieldefficiencies up to 25 percent higher than fuels thathave low heating values, low carbon to hydrogenratios, and high moisture contents. A rule ofthumb for the efficiency hierarchy in descendingorder is coal, heavy fuel oil, light fuel oil, naturalgas, and biomass. From these rankings, it is obvi-ous that fuel availability plays a major role.

Factors such as combustion system limitations andequipment design limit the types of fuels that rea-sonably can be used within a given boiler. Be-cause the design of older boilers is fixed, switch-ing fuels often leads to significant losses in effi-ciency or capacity. In some cases changing fromone fuel to another, such as natural gas to fuel oil,may improve efficiency.

Steam system requirements often have signifi-cant adverse impacts on achievable efficienciesespecially for potential combined heat and power

applications. Widely different steam demandscan lead to periods where the boiler is kept run-ning on idle in certain industries. Becausethe boiler produces little or no steam under theseconditions, its operating efficiency is close tozero. The alternative of shutting the boiler downto conserve energy in fact wastes energy and of-ten is not practical.

When possible, the application of combined heatand power produces large improvements in effi-cient energy usage. Use of high temperature en-ergy to produce electrical or mechanical energyfollowed by the use of remaining lower tempera-ture energy to meet process heat requirements isthe ideal. Industries such as the paper industryhave utilized combined heat and power for morethan a half century. The highest efficiencies areachieved by systems combining IC engines or gasturbines with boilers or process heaters. How-ever, these systems are not suitable for every facil-ity. Factors such as fuel availability, the facilitysrelative needs for electrical, mechanical, and heatenergy, steam demand and demand cycles and themarket for surplus power have major effects onwhether or how combined heat and power maybe applied at a given facility. Even where com-bined heat and power is applied, one size does notfit all, and various applications can have widelydifferent efficiencies.


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Appendix AAppendix AAppendix AAppendix AAppendix A

SizeThe average new industrial boiler is a dwarf com-pared to the giant utility boiler. Todays typicalutility unit produces 3,500,000 pounds of steaman hour; the industrial boiler 100,000. In fact,most industrial boilers range in size from 10,000to 1,200,000 pounds of steam per hour.

The size of the utility boiler allows it to enjoy sig-nificant economies of scale, especially in the con-trol of emissions that simply are not available tothe industrial unit.

Smaller industrial boilers are more numerous andtailored to meet the unique needs and constraintsof widely varying industrial processes. There areabout 70,000 industrial boilers in use today com-pared to approximately 4,000 utility boilers. Yet,all the small industrial units combined produceonly a fraction of the steam compared with largeutility boilers. In addition, the nations utility boil-ers consume over 10 timeOs as much coal as theindustrial boilers.

Industrial units produce less than 10 percent ofthe emissions from the nations boiler population,but because of their smaller size and uniquenessmust pay more than utilities to remove a givenamount of emissions.

Steam ApplicationA utility boiler has one purposeto generate steamat a constant rate to power turbines that produceelectricity. Industrial boilers, on the other hand,have markedly different purposes in different in-

DIFFERENCES BETWEEN INDUSTRIALANDUTILITYBOILERS

dustries. Even at a single installation, applica-tion of steam from an industrial boiler can changedramatically with the seasons, when steam orhot water is used for heating, as well as fromday to day and hour to hour, depending uponindustrial activities and processes underway at agiven moment and their demand for steam. Thepossibility of such widely fluctuating demand

for steam in most industrial processes means thatthe industrial boiler does not, in the great ma-jority of cases, operate steadily at maximum ca-pacity. In general, the industrial boiler will havea much lower annual operating load or capacityfactor than a typical utility boiler. As a result,any added control costs have a much greater af-fect on the final output steam cost.

In contrast, a typical utility boiler, because of aconstant demand for steam, operates continuouslyat a steady-state rate close to maximum capacity.This basic difference in operation is reflected inproportionately lower operating costs than is thecase for similarly equipped industrial boilers. Evenwhen peaking units operate to meet utility loadswings during the days or for seasonal peak de-mands, the utility units load swings are more con-trolled and can be balanced over the complete elec-tric production and distribution grid.

In the event of unscheduled downtime for a givenunit, utility electrical generating facilities have avariety of backup alternatives. Industry, on theother hand, rarely has a backup system for steam

generation. Because of the desire to keep costs forsteam production as low as possible, industry re-quires a high level of reliability from its boilers.Industrial boilers routinely operate with reliabil-ity factors of 98 percent. Any drop in reliabilityfor an industrial system causes loss in productionand related revenues. Combustion and add-oncontrol technologies can interfere with system re-liability.

DesignUtility boilers primarily are large field erected pul-verized coal, No. 6 oil or natural gas fired high

pressure high temperature boilers with relativelyuniform design and similar fuel combustion tech-nologies. Industrial boilers, on the other hand,incorporate combustion systems including highpressure and low pressure, large and small, fielderected and shop assembled package boilers de-signed to burn just about anything that can beburned alone or along with conventional fuels. In-dustrial boilers use many different types of com-bustion systems. Some of these different designs

Industrial and utility boilers are significantlydifferent. Yet, because both generate steam,legislators and requlators tend to treat themthe same.

Major differences between industrial andutility boilers are in three principal areas:

% boiler size% boiler steam application% boiler design


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include many different types of stokers, bub-bling and circulating fluidized bed combustionsystems, and conventional coal, oil and gas com-bustion systems. In fact, the designs of indi-vidual industrial boilers regardless of fuel or com-bustion type can vary greatly, depending uponapplication of steam and space limitations in aparticular plant. On the other hand, facilities at

a utility plant are designed around the boilersand turbine(s) making application of emissioncontrols significantly more cost effective.

CONCLUSION

Differences between industrial and utility boilersare major. These differences warrant separate de-velopment of laws and regulations that apply toeach. Treating them both in the same fashion,simply because they both generate steam, inevita-bly results in unfair and inappropriate standards.

Accordingly, the Council of Industrial BoilerOwners believes that government should recog-nize the basic differences between industrial andutility boilers and should tailor requirements totheir individual natures and to the unique situa-tions within which each operates.

COUNCILOF INDUSTRIALBOILER OWNERS

The Council of Industrial Boiler Owners(CIBO) is a broad-based association of in-

dustrial boiler owners, architect-engineers,related equipment manufacturers, and uni-versity affiliates consisting of over 100 mem-bers representing 20 major industrial sec-tors. CIBO members have facilities locatedin every region and state of the country;and, have a representative distribution ofalmost every type boiler and fuel combina-tion currently in operation. CIBO wasformed in 1978 to promote the exchangeof information within industry and betweenindustry and government relating to energyand environmental equipment, technology,

operations, policies, laws and regulations af-fecting industrial boilers. Since its for-mation, CIBO has taken an active interestand been very successful in the developmentof technically sound, reasonable, cost-effec-tive energy and environmental regulationsfor industrial boilers.


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Steam Digest 2002Decision Climate for Steam Efficiency: Update December 31, 2002

17

Decision Climate for SteamEfficiency: UpdateDecember 31, 2002Carlo La Porta, Future-Tec

ABSTRACT

The Performance Evaluation and Policy Subcom-mittee of the BestPractices Steam Steering Com-mittee issues a periodic compilation of data thatthe Energy Information Administration, U.S.Department of Energy, reports in its Short-TermEnergy Outlook. The author selected data rel-evant to industrial decision makers concerned withsupply and price of energy purchased for indus-trial fuel. The ulterior purpose is to help frame

decisions that will encourage more investment toimprove the efficiency of industrial steam systems.

DATAFROM U.S. DEPARTMENTOFENERGYSHORT-TERM ENERGYOUTLOOK

Weather ImpactsDespite an 11 percent increase in cooling degreedays during summer 2002, high utility demandfor fuel to make electricity did not create a spikein natural gas prices. Natural gas spot prices did,however, exceed $3.00 per thousand cubic feet inAugust and rose to $3.90 in November. Popula-tion-weighted heating degree days for October andNovember were 16 percent higher compared tonormal in the Northeast United States and wereeight percent higher than normal nationally. Thewinter after January is projected to be warmer thannormal. A 12 percent colder winter of 2002-2003will increase demand for heating oil, gas and elec-tricity, and hold or pressure fuel prices upwardand EIA has predicted that natural gas will be$1.50 more per 1,000 cubic feet than last winter.

Industrial ProductionU.S. GDP is projected to be 2.3 percent higher in2002 compared to 2001 and grow 2.6 percent in2003. Manufacturing production fell in 2001 by4.3 percent, was projected to fall another 0.4 per-cent in 2002, then rise 3.4 percent in 2003. U.S.business inventory dropped $36.2 billion ($1996)in 2001, and another $14.8 billion ($1996) is theprojected drop for 2002. A gain of $6.7 billion isforecast for 2003.

PetroleumThe benchmark West Texas Intermediate oil spotprice rose by $1.40 per barrel in August comparedto July, averaging $28.40 per barrel (bbl) for themonth. At that time OPEC was producing 1.8million barrels per day over its quota and the Oc-tober average price for OPEC oil was $27.60 perbarrel. Iraqi production had fallen by 1.2 millionbarrels per day in August compared to August2001. A political crisis in Venezuela cut its oilexports severely in December, which increasedmarket uncertainty and put more upward pres-sure on oil prices. These conditions pushed oilprices above $30 per barrel by the end of 2002.The New York Mercantile Exchange price on De-cember 31, 2002, for light sweet crude deliveriesin February 2003 was $31.37/bbl. The Februarydelivery price actually had dropped $1.35 per bar-rel based on news that an OPEC country had in-dicated OPEC production might increase to bring

prices down. The EIA forecast has assumed thatOPEC will increase production to keep the pricein its desired range between $22-$28/bbl. Econo-mists are concerned about continued slow recov-ery in U.S. economic growth and EIA has droppedits U.S. GDP growth rate projection from 4.1per-cent in 2003 to 3.0 percent. Still, EIA expectsU.S. demand for petroleum products to rise 3.9percent in 2003.

lautcA detcejorP

1002 2002 3002

%0.0 %4.0 %8.1

Table 1: World Oil Demand Growth(italics signify forecast)

In 2002, average daily U.S. oil production willhave fallen one tenth of one percent (0.10 %) to5.8 million barrels per day. In 2003 domestic pro-duction is projected to fall by 3.5percent to a levelof 5.6 million barrels per day. With oil importsprojected to average 10.5 million barrels per day

in 2002, the U.S. will have depended on foreignoil for 64.4 percent of its supply.

Distillate Fuel OilLast winter, due to mild weather, the industrialdownturn and expanded reliance on natural gas,distillate demand fell 230,000 barrels per day, orsix percent, and inventories rose. By late Novem-ber 2002, the distillate inventory fell below theminimum average amount for the last five years,

All data: U.S. DOE-EIA


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18

due to the colder October and November.Tightened supply with predicted higher oilprices and recovering industrial demand should

push the price for distillate up about 10 centsper gallon.

Natural GasIn March 2002, EIA predicted that during sum-mer 2002, natural gas wellhead spot prices perthousand cubic feet would fall below $2.00. In-stead, the wellhead price averaged $2.83 in thethird quarter and for all of 2002, the average willbe close to $3.00 per thousand cubic feet. Spotprices hit $4.00 per thousand cubic feet in No-vember, and rose significantly in December. Janu-ary and February delivery prices on December 18th

were $5.28 and $5.25 per million Btu. Thesehigher prices should continue throughout the win-ter months. The winter delivery prices contrastwith the average wellhead price EIA projects forall of 2003, which is $3.69 per thousand cubicfeet. Overall demand for gas in 2003 is projectedto rise 3.6 percent. Earlier in 2002, EIA projected

9991 0002 1002 2002 3002

detropmIliOedurC 62.71$ 27.72$ 10.22$ 37.32$ 49.32$

topS.retnIsaxeTtseW 52.91$ 92.03$ 59.52$ 39.52$ 69.52$

Table 2: Average Annual U.S. Energy Prices, EIA Base Case (Nominal Dollars per Barrel)(italics signify forecast)


2002tsuguAfodneskcotS slerrabnoillim031

2002rebmevoNfodneskcotS slerrabnoillim021)2002yraunaJnahtrewolslerrabnoilim81~(

Table 3: Status of Distillate Oil Stocks Inventory, Late 2002

industrial demand for natural gas to rise by 9.6percent in 2002, and another 6.3 percent in 2003.Domestic dry gas production in 2002 should

be 1.6 percent lower than 2001. EIA projectsit to rebound by 2.7 percent in 2003 as de-mand rises and inventories fall to normal. Work-ing natural gas in storage was 2.95 trillion cu-bic feet in November, nine percent below thelevel at the same time in 2001. Through 2003,natural gas in storage is predicted to be abovethe five year average until the end of the year,when it will drop below it.

Active rigs drilling for natural gas were 43 percentlower in August 2002 than 12 months previously.

Although no gas price spike ($9.00/MCF) is fore-seen similar to the one that occurred in winter2001, the EIA projection range plotted for 2003now indicates that the base case wellhead priceshould be well over $4.00 per thousand cubic feetin early 2003, and the range shows that it couldpossibly reach a high of near $6.00 before falling

0002 1002 2002 3002

dnameD.S.UlatoT 44.32 14.22 12.22 11.32

dnameDlairtsudnIlaunnA .a.n 00.9 68.9 34.01

Table 4: Natural Gas Demand (trillion cubic feet) (italics signify forecast)


1002 2002

htnomrepnoitcudorpcitsemodegarevA tfnoillirt26.1 3 tfnoillirt95.1 3

htnomrepstropmiteN tfnoillirt03.0 3 tfnoillirt82.0 3

Table 5: Summary of Natural Gas Production, 2001-2002



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as summer approaches. The lower boundary ofthe predicted range for 2003, is about $2.50 dur-ing the summer months. In other words, gas priceuncertainty remains pretty high. The drilling rigcount remains low, and the gas industry is finding

that many wells dug from existing bore holes aredelivering gas for a shorter period of time thanhistorically. Some speculation about adequate gassupplies has begun to surface, but the gas indus-try appears confident that higher prices will en-sure adequate supply.

CoalIn the March 2002 DOE Short-Term EnergyOutlook, the only EIA statement regarding coalpredicted a continuing slow price decline through2003. The September report did not mention coal.Demand for coal is set by the utility sector, which

consumes 87percent of U.S. coal production (56percent of electricity is generated by coal plants).Total U.S. coal supply, net of imports and exports,was 1,090.4 million short tons in 2001 and wasforecast to drop to 1,054.7 million short tons in2002, and drop again in 2003, to 1,052.6 millionshort tons. Demand for coal was projected to rise0.8 percent in 2002 and 1.1 percent in 2003.

Total industrial coal consumption for coke plantswas 26.1 million short tons in 2001 and shoulddecline to 23.5 million short tons in 2002. EIAexpects coke plant consumption to recover some-what to 24.3 million metric tons in 2003. Non-utility independent power producer demand forcoal, excluding cogeneration, was 150.6 millionshort tons in 2001, and is forecast to grow to 192.7million short tons in 2002 and 197.1 million shorttons in 2003. Retail and general industry use,which was 67.5 million short tons in 2001, is fore-cast to drop slightly to 65.3 million short tons in2002 and decline again in 2003 to 65.0 millionshort tons. Western low sulfur coal production is

1002enuJ-rpA 2002enuJ-rpA egnahC

repaP 39.14$ 88.34$ %6.4+

slacimehC 83.63$ 20.04$ %0.01+

*lateMyramirP 14.72$ 91.82$ %8.2+

seirtsudnIllA.gvA 98.13$ 34.33$ %8.4+

]utBMM/43.1$=34.33$laocsuonimutibnottrohsreputBMM52tA[ekocsedulcxE*

Table 6: Coal Receipt Prices ($/short ton) at Selected Manufacturing North American Indus-try Classficiation System Category


forecast to rise 2.5 percent per year through thenext two decades while higher sulfur eastern coalproduction is projected to remain level. Con-trary to EIAs expectation that coal prices willcontinue a decline, over the last 12 months, for

all industries, they have actually risen 4.8 per-cent.

Restructuring of electric utilities is expected tokeep pressure on coal producers and railroads tocut costs. The coal industry may further consoli-date in response to a utility movement to negoti-ate shorter term contracts for coal. Coal produc-ers may need to take steps to manage a higher levelof risk and coal futures markets are being createdin some regions. In short, restructuring in theelectric power sector could have a spillover effecton the stable coal market.

IMPLICATIONSFOR MARKETING INDUSTRIALSTEAM EFFICIENCY

The U.S. electric power sector, which reached arecord production high in August (source: EdisonElectric Institute), demonstrated its flexibility toadjust to fuel price changes. In 2002, total oil-fired generation is expected to be 30 percent lowerthan in 2001, while natural gas use is projected toincrease 7.2 percent compared to 2001. In theindustrial sector, unlike utilities, natural gas domi-

nates energy consumption. EIA 1998 data for allmanufacturing industries show the following fuelconsumption figures, in trillion Btu, in Table 7.

Environmental emissions associated with conven-tional coal combustion remain a brake on fuelswitching, unless industry were to adopt coal gas-ification or best available technologies to controlair pollution.


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Industrial firms may be feeling somewhat se-cure about gas supply. The California utilitycrisis was partly created by trader manipula-tions and supply has met demand this year with-out strain. Furthermore, gas imports only ac-count for 15 percent of U.S. demand, almost allof which comes from Canada, which increasesconfidence in domestic supply stability. It isnot likely that industry is very aware of a debatenow being conducted about the timing of glo-bal peak oil and gas production, and the impactthat a two percent per year increase in natural

gas use in the U.S. will have on supply if thepeak in gas use occurs in 15 years rather than35. The gas industry believes it will be able todeliver 30 trillion cubic feet per year, but thereis more need to track trends at this time for de-cision makers.

Gas industry conditions in the U.S. have estab-lished a dynamic that promotes cyclical pricemovements. First, short-term supply and demandfor gas is relatively inelastic. In periods of scarcityor abundance of supply, prices move a great deal.

Second, gas producers experience large fluctuationsin cash flows, investments and available suppliesat the wellhead due to the large price movements.This perpetuates the situation. Third, the gas in-dustry is likely to over-invest relative to gas de-mand when prices are high and under-invest whenthey are low. This is due to the significant amountof time between changes in price and changes inwellhead gas supply, typically 6 to 18 months. Fi-nally, some gas producers are now experiencingmore rapid dropoffs in production from new natu-ral gas wells. If production declines faster thananticipated in these new wells, producers may get

caught short if they have cut investment in devel-oping new capacity. The near-term outlook forindustrial users is to expect significant price fluc-tuations. It may be some time, if ever, before themarket sees $2.00 per thousand cubic feet gas.

Government policy is also likely to have a largerimpact on natural gas supply and therefore, de-mand. Estimated total undiscovered, technicallyrecoverable natural gas resources off the coasts ofthe mainland U.S. are about 235 trillion cubic

feet. Of this amount, about 60 trillion cubicfeet are currently inaccessible due to policy. TheRocky Mountain resources currently on federallands and inaccessible represents another 30 tril-lion cubic feet. A third factor will be importsof liquefied natural gas (LNG). They have beenrising rapidly and in the future could rise andfall to mitigate price swings related to domesticsupply. In short, there is more uncertainty aboutnatural gas supply now than in recent years andindustry decision makers should follow trends with more attention when making decisions

about energy-related investments in their plants.

Congress adjourned in 2002 without passing na-tional energy legislation. With the Republicansnow holding both Houses, an energy bill shouldemerge in this session. The Bush administrationhas also adjusted New Source Review EPA regula-tions that may make it easier for companies toinvest in equipment upgrades that will includemore efficiency. It should be noted that the sup-ply-oriented National Energy Strategy documentthe Bush administration produced had little to say

about industrial efficiency, but the energy legisla-tion could include financial incentives for energyconservation investments that will pertain to in-dustry. The picture will not become clearer untilCongress organizes and the FY2003 appropria-tions bills are finally passed. In the meantime,potential to promote steam efficiency to reduceNO

Xemissions and enhance compliance with

clean air requirements is growing stronger in cer-tain areas of the U.S.

Near-term gas price is another matter and EIAhas forecast a significant increase in gas prices in

2003 as the economy recovers and colder weatherincreases demand this winter. Prices will also beaffected by the decline in U.S. gas production in2002 and the inevitable link with current oil prices,which at the end of 2002 have gone over $30 perbarrel. Will these higher prices stimulate invest-ment in steam efficiency? Probably not. Com-pany managers are contending with excess pro-duction capacity, lower sale prices for their prod-ucts and serious erosion of their stock value. Thiseconomic environment is more likely to stimu-

saGlarutaN LGN&GPL laoC)ezeerb&ekoc.lcxe(

liOleuFlaudiseR liOleuFetallitsiD

446,6 531 341,1 753 331

Table 7: U.S. Industrial Fuel Consumption (Trillion Btu), 1998



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late quick and easy cost cutting. Given a thin-ning of staff capabilities in many companies, en-ergy conservation may have a hard time gettingon the quick and easy cost cutting list. In-deed, training companies have indicated thatcompanies are restricting travel, a sign that thegeneral environment for increasing efficiencyremains difficult. Conservation proponents

might argue that low interest rates should jus-tify borrowing to invest in energy saving projectsthat would lower bottom-line costs and repaythe loans easily. Unfortunately cost cutting toretain profits on a smaller volume of sales prob-ably will not stimulate allocation of internal capi-tal for energy efficiency improvements.

Looking a little further ahead, an intervention inIraq might disrupt oil supply for a short time, butIraqs one to two million barrels per day of oil salescan easily be made up by OPEC. Iraq has verylarge oil reserves, so if the S. Hussein governmentis replaced, Iraqi oil sales could double in a shorttime and prices would then drop. If high gasolineprices triggered, as usual, consumer action to con-serve energy, industry may respond for a shortwhile by deciding to give more priority to energyinvestments. The likelihood that oil price riseswould be short-lived suggests, however, that morestimulus to invest in steam efficiency will result ina true rebound from the downturn in the indus-trial sector.

REFERENCES

1. U.S. Department of Energy, Energy InformationAdministration: EIA Annual Energy Outlook 2002with Projections to 2020.

2. Web page: Short Term Energy Outlook March2002 www.eia.doe.gov/emeu/steo/pub/contents.html.
http://www.eia.doe.gov/emeu/steo/pub/contents.htmlhttp://www.eia.doe.gov/emeu/steo/pub/contents.htmlhttp://www.eia.doe.gov/emeu/steo/pub/contents.htmlhttp://www.eia.doe.gov/emeu/steo/pub/contents.htmlhttp://www.eia.doe.gov/emeu/steo/pub/contents.html


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Steam Digest 2002An Analysis of Steam Process Heater Condensate Drainage Options

23

An Analysis of SteamProcess Heater CondensateDrainage Options James R. Risko, TLV Corporation

ABSTRACT

The production and reliability of performance ofsteam process heaters can be significantly affectedby the condensate drainage design that is em-ployed. The current variety of drainage optionscan be confusing to a system designer who is un-aware of the reasons for each specific design. Anunderstanding of the various types and why theymay be used follows.

BACKGROUND

For simplicity, the terminology process heateris intended to mean any steam heat exchanger,coil, or kettle which uses steam as the primaryfluid to transfer heat to a product. While gener-ally intended for production purposes, this ter-minology can also be used to refer to HVAC ap-plications. The reason that all of these heater typescan be grouped together is because even thoughthey incorporate different exchanger designs on

the product side, they all are intended to transfersteam heat in an efficient and cost effective heat-ing manner. In that sense, they all use the steamto provide a certain level of heat transfer and drainthe by-product, condensate, away from the heaterso that new steam can be introduced and con-trolled to heat additional product.

What is intriguing about this simple goal is thatthere are currently a variety of installation designsto accomplish the removal of that condensate, andthese provide various levels of production perfor-mance depending on the environmental condi-

tions of the specific heater application. What canbe confounding is that some of these drainageoptions may work very well in one scenario, andyet fail miserably in another depending on theconditions. When successful in a previouslytroublesome application, a particular installationdesign may create a sense of comfort within anengineering department and later become a

standard practice for a facility. Later it can havedecidedly mixed results when used for an appli-cation for which it cannot perform well enoughto meet design expectations. This situation mayhave tremendous energy and production impli-cations and can usually be easily identified inadvance.

IDENTIFYINGTHE SYMPTOMS

Telltale signs for those installations with unsuit-able condensate drainage include:

Condensate being visibly wasted from the heatexchanger discharge side, either from a hoseconnection at the strainer, or an opened unionor drain valve on the steam traps outlet pip-ing. In this case, the condensate is no longeravailable to be returned through the returnline, and its valuable energy is needlessly sac-

rificed to grade so that required productionperformance levels can be achieved.

The presence of severe hammering in the ex-changer itself or in the return piping down-stream of the heater. There are a variety ofcauses for this type of hammering, but in theworst case its cause can be attributed to sig-nificant amounts of preventable steam loss.

Product variance much greater than expecta-tions.

Dramatic temperature stratification of theheaters exterior surface where steam is shell-side.

A higher than average maintenance require-ment for head gasket or tube bundle failure.

COURSEOF ACTION

The optimum solution is to specify a condensatedrainage design that removes all condensate fromthe heater rapidly. This is where confusion overthe best design has traditionally

steam digest 2002

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