Steam Digest 2001 - NREL · Glenn Hahn, Spirax Sarco ... This program resulted in a 17 percent reduction in energy use on a per pound of product basis, saving 3.25 trillion Btus and

For additional informationon BestPractices Steam, contact:

FRED HARTOffice of Industrial TechnologiesU.S. Department of Energy202 586-1496

CHRISTOPHER RUSSELLSenior Program Manager for IndustryThe Alliance to Save Energy202 530-2225

Visit the OIT Steam Web site at:www.oit.doe.gov/bestpractices/steamwww.steamingahead.org

For information about otherOIT Programs call:

OIT ClearinghousePhone: (800) 862-2086Fax: (360) 586-8303http://www.oit.doe.gov

Office of Industrial TechnologiesEnergy Efficiency andRenewable EnergyU.S. Department of EnergyWashington, D.C. 20585

DOE/SBP001November 2001 Rev.

OFFICE OF INDUSTRIAL TECHNOLOGIESENERGY EFFICIENCY AND RENEWABLE ENERGY � U.S. DEPARTMENT OF ENERGY

ALLIANCE TO SAVE ENERGYTHIRD DECADE OF LEADERSHIP

A compendium of articles

on the technical and

financial benefits of steam

efficiency, presented

by stakeholders in the

U.S. Department of Energy�s

BestPractices Steam efforts.

STEAM DIGEST

Steam Digesttttt

Compiled and produced for

OFFICE OF INDUSTRIAL TECHNOLOGIESENERGY EFFICIENCY and RENEWABLE ENERGY U.S. DEPARTMENT OF ENERGY

THE ALLIANCE TO SAVE ENERGYTHIRD DECADE OF LEADERSHIP

Steam Digest

20012001

by

TABLE OF CONTENTS

INTRODUCTIONFred Hart, U.S. Department of EnergyChristopher Russell, Alliance to Save EnergyAnthony Wright, Oak Ridge National Laboratory, September 2001 3BESTPRACTICES STEAM RESOURCES AND TOOLS: “OLD” NEWS IS “NEW” NEWS!Anthony Wright, Oak Ridge National LaboratoryFred Hart, U.S. Department of EnergyChristopher Russell, Alliance to Save EnergyDavid Jaber, (formerly with) Alliance to Save Energy

The mission, purpose, and products of the U.S. Department of Energy’s BestPractices Steam program are reviewed here. 5BEST PRACTICES IN STEAM SYSTEM MANAGEMENTFred Hart, U.S. Department of EnergyDavid Jaber, (formerly with) Alliance to Save Energy

Common areas in which to look for savings opportunities in steam generation, distribution, end use, and recovery areoutlined in this article. 11

BEST PRACTICES: THE ENGINEERING APPROACH FOR INDUSTRIAL BOILERSNatalie R. Blake, ONDEO Nalco

Boiler best practices represent the Engineering Approach for boilers–a way to examine mechanical, operational andchemical aspects of the systems (pretreatment through condensate) to ensure reliable boiler operations with no surprises. 17

PERFORMING A STEAM SYSTEM CHECKUP: A THREE-STEP CHECKUP IDENTIFIES

POTENTIAL OPPORTUNITIES FOR IMPROVEMENTSAnthony Wright, Oak Ridge National LaboratoryGreg Harrell, University of Tennessee at KnoxvilleGlenn Hahn, Spirax Sarco

To protect steam systems and ward off potential problems, operators and plant energy managers need to perform a“checkup” on their steam system. This checkup can improve the productivity and profitability of plant operations and/or assess the status of operations. 23

THE STEAM SYSTEM SCOPING TOOL: BENCHMARKING YOUR STEAM OPERATIONS

THROUGH BEST PRACTICESAnthony Wright, Oak Ridge National LaboratoryGlenn Hahn, Spirax Sarco

Plant managers can use the Steam Scoping Tool to assess their steam system operations while also discovering opportu-nities for enhancing efficiency. This article reviews the development and use of this easy-to-use spreadsheet tool. 27

THE ENBRIDGE CONSUMERS GAS “STEAM SAVER” PROGRAMBob Griffin, Enbridge Consumers Gas

A Canadian gas utility’s audit of 41 steam plants summarizes the frequency of common problems, solutions, and pay-back performance. 33

A HIGHLY SUCCESSFUL HOLISTIC APPROACH TO A PLANT-WIDE ENERGY

MANAGEMENT SYSTEMFrederick P. Fendt, Rohm and Haas Company

Rohm and Haas’ Deer Park, Texas, plant implemented a unique energy management program that has proven to behighly successful. This program resulted in a 17 percent reduction in energy use on a per pound of product basis, saving3.25 trillion Btus and $15 million annually. This article discusses this program, its history, and the managementprocesses that make it successful. 43

CELANESE CHEMICALS CLEAR LAKE PLANT ENERGY PROJECTS ASSESSMENT

AND IMPLEMENTATIONJoel Weber, (formerly with) Celanese Chemicals

The Clear Lake Plant of Celanese Chemicals has implemented a strategy to reduce energy consumption during itsproduction processes. This case study discusses practical reductions in steam, fuel, and electricity use. 49

SAVINGS IN STEAM SYSTEMS (A CASE STUDY)Rich DeBat, Armstrong Service, Inc.

This hands-on case study of a chemical manufacturing plant exemplifies the process, documentation, and recommenda-tions involved in an industrial steam system audit. 51

STEAM SYSTEM DIAGNOSTICSJohn Todd, Yarway/Tyco

Proper diagnosis of steam trap operations and maintenance requires a thorough understanding of other steam systemcomponents beyond the trap itself. This article provides a comprehensive overview of related elements. 63

ULTRASONIC TESTING TIPS FOR STEAM TRAPS AND VALVESBruce Gorelick, Enercheck Systems, Inc.

This article offers some testing tips to run a cost-effective steam distribution maintenance program. 69RELIABLE SYSTEMS AND COMBINED HEAT AND POWERDavid Jaber, (formerly with) Alliance to Save EnergyRichard Vetterick, TRC Energy

This article gives a comprehensive definition of combined heat & power (CHP) systems and reviews its attributes. Italso provides guidance for choosing various types of CHP applications. 71

BUSINESS BENEFITS FROM PLANT ENERGY ASSESSMENTS AND ENERGY

MANAGEMENTDavid Jaber, (formerly with) Alliance to Save Energy

The benefits of energy management are not limited to utility and fuel cost savings. There are also positive implicationsfor improved productivity, increased equipment life, decreased risk of financial penalties, and increased order turn-around. This article provides reference information and suggests the steps needed to improve plant performance. 77

USE SPREAD-SHEET BASED CHP MODELS TO IDENTIFY AND EVALUATE ENERGY

COST REDUCTION OPPORTUNITIES IN INDUSTRIAL PLANTSJimmy Kumana, Consultant

Cutting edge steam technology includes combined heat and power plants. Facilities managers must examine the eco-nomics of such plants before committing capital resources. This article demonstrates financial analysis techniques thatuse common spreadsheet applications. 81

JUSTIFYING STEAM EFFICIENCY PROJECTS TO MANAGEMENTChristopher Russell, Alliance to Save Energy

Plant managers need to convince top management that steam efficiency is an effort that creates value. This articlesuggests ways to demonstrate steam efficiency’s impact on corporate and financial goals. 89

STEAM CHAMPIONS IN MANUFACTURINGChristopher Russell, Alliance to Save EnergyAnthony Wright, Oak Ridge National Laboratory

The responsibilities related to industrial steam management evolve with changes in corporate, regulatory, and technol-ogy environments. This suggests a new set of managerial skills and accountability. The “steam champion” conceptoutlines what may be involved. 93

AcknowledgementsThe Steam Digest 2001 owes its existence to the U.S. Department of Energy’s Office of IndustrialTechnologies (OIT), led by Deputy Assistant Secretary Denise Swink. Special Assistant Marsha Quinnenables us to interact effectively throughout OIT. Mr. Fred Hart of DOE provides dedicated pro-gram management for the steam effort, while Mr. Christopher Russell of the Alliance to Save Energyleads program marketing and outreach. Dr. Anthony Wright of Oak Ridge National Laboratoryleads our technical agenda. Ms. Rachel Madan of the Alliance provides additional program support.A steering committee consisting of steam experts from industry, business, government, trade associa-tions, and national labs provides guidance to our effort. Mr. Bill Pitkin of the National InsulationAssociation is the Chair of this Steering Committee. His rapport with government and businessleaders greatly facilitates all of our accomplishments. Ms. Debbie Bloom of ONDEO Nalco is ViceChair and a peerless referee of our technical content. Mr. Fred Fendt of Rohm & Haas is the committee’sExecutive-at-Large, giving voice to the energy end-user’s perspective. Mr. Glenn Hahn of SpiraxSarco provides multifaceted leadership within the Steam and the overall BestPractices steering com-mittee structures.

Bob BessetteCouncil of Industrial Boiler OwnersCharles CottrellNorth American Insulation Manufacturers AssociationLee DoranNational Board of Boiler and Pressure Vessel InspectorsBeverly FranceIndustrial InteractionsElodie Geoffroy-MichaelsTurbo SteamRobert GriffinEnbridge Consumers GasBill HamanIowa Energy CenterTom HenryArmstrong Services, Inc.Ron HoltSwagelok

All of our steering committee members volunteer their time to BestPractices Steam, and our apprecia-tion is underscored here. A previously unheralded contributor to the program is Mr. Carlo LaPortaof Future Tech, who is the “utility in-fielder” on our management team.

We thank each author for his or her contribution to this compendium. Mr. David Jaber providedseveral articles; he has since left the employ of the Alliance to Save Energy and we wish him well in hisnew endeavors.

As was the case last year, a note of thanks goes to Ms. Sharon Sniffen of ORC Macro International,whose staff gave Steam Digest 2001 this final form.

Walter JohnsonAssociation of Energy EngineersMike MakofskyShannon EnterprisesAnthony MartocciBethlehem SteelJim McDermottYarway Corp.Kelly PaffelPlant Evaluations & SupportMiriam PyeNew York State Energy Research & Development AuthorityDoug RileyMillennium ChemicalsMike SandersSunocoThomas ScheetzBASFJohn ToddYarway Corp.

Each of these individuals provided a unique and valuable contribution to the BestPractices SteamSteering Committee throughout 2001:

Steam Digest 2001

3

IntroductionFred Hart, U.S. Department of EnergyChristopher Russell, Alliance to Save EnergyAnthony Wright, Oak Ridge National LaboratorySeptember 2001

BestPractices Steam, which began in 1997 as theSteam Challenge, is one component of the U.S.Department of Energy’s Energy ManagementBestPractices industrial technology assistance ef-fort. BestPractices spearheads the implementa-tion approach for the Industries of the Future(IOF) program. The activities of BestPracticesare broad based, covering all aspects of the IOFprogram and include energy assessments, spon-sorship of emerging technologies, and energymanagement. BestPractices activities assist thenine IOF industries to identify and realize theirbest energy efficiency and pollution preventionoptions from a systems and life-cycle cost perspec-tive. In the interest of documenting and com-municating best-in-class applications of industrialenergy technologies, this volume is made freelyavailable to the industrial community. It is hopedthat it will influence plant management for thebetterment of U.S. industrial energy consump-tion, productivity, competitiveness, and share-holder value.

Steam Digest 2001 chronicles our contributionsto the industrial trade press over the past year. Asin last year’s Steam Digest, we present articles thatcover technical, financial, and managerial aspectsof steam optimization. A number of these ar-ticles detail plant- or company-specific successstories. Other articles describe technical oppor-tunities and how to measure their impact on plantperformance.

Through 2001, BestPractices Steam continued tomake progress in developing tools to assist steamusers in achieving system improvements. In onesense, our progress can be measured in the num-ber and quality of resources produced. Instru-ments such as the spreadsheet-based Steam ScopingTool and the 3E Plus insulation evaluation soft-ware have become popular with plant managersas diagnostic tools. A series of Steam Tip Sheets—now numbering 16—are useful one-page refer-ences that identify distinct energy saving oppor-tunities and demonstrate the calculation of related

financial impacts. Case studies are an in-depthdemonstration of site-specific experiences withsteam optimization programs. The ongoing con-duct of workshops and trade show participationmakes the BestPractices name visible on a regionalbasis.

Additionally, the Steam Clearinghouse providesbasic reference, assistance, and referral to callerswho use the toll-free number. Steam users, con-sultants, vendors, and utilities all use the Clear-inghouse at no cost to obtain the resources de-scribed here. The Steaming Ahead newsletter andcompanion website (www.steamingahead.org)provide the steam community with regular up-dates on program progress. The public may alsodownload software and references from thatwebsite. There are more tools to come in the fu-ture: results of the Steam Market Assessment, de-velopment of detailed Steam Technical Fact Sheets,and enhancements to our Steam Workshops.

While the product and service offerings ofBestPractices Steam are many and varied, the cur-rent challenge is to get this information in the righthands. Energy efficiency is not an end in itself,but a means toward the very goals sought daily byplant managers and their corporate leaders. Bothtechnical and business leaders need access toBestPractices Steam in order for our informationto be thoroughly effective. This is our leadingmandate for 2002, and beyond.

For more information, please contact:

U.S. DOE Office of Industrial TechnologiesResource RoomPhone: (202) 586-2090

The OIT ClearinghouseEmail: [email protected]: (800) 862-2086

Or visit our websites:

The U.S. Department of Energy’s Office ofIndustrial Technologies:http://www.oit.doe.gov/bestpractices/steam

The Steaming Ahead resource page:http://www.steamingahead.org

Steam Digest 2001BestPractices Steam Resources and Tools: “Old” News is “New” News!

5

BestPractices SteamResources and Tools: “Old”News is “New” News!Anthony Wright, Oak Ridge National LaboratoryFred Hart, U.S. Department of EnergyChristopher Russell, Alliance to Save EnergyDavid Jaber, (formerly with) Alliance to Save Energy

ABSTRACT

The U.S. Department of Energy Office of Indus-trial Technology (DOE-OIT) BestPractices effortsaim to assist U.S. industry in adopting near-termenergy-efficient technologies and practices throughvoluntary, technical assistance programs on im-proved system efficiency. The BestPractices Steameffort, a part of the DOE-OIT effort, has identifiedand documented an extensive group of steam sys-tem resources and tools to assist steam system usersto improve their systems. This paper describes the“new” news that BestPractices Steam is assemblingfrom the “old” news about opportunities and tech-niques to improve steam systems.

INTRODUCTION

In his 1947 classic text, “The Efficient Use of Steam,”Sir Oliver Lyle noted that:

“There are three fundamental things, andthree only, that should guide our steameconomy, and we should strive after themwith might and main:

(1) Prevent the escape of heat.(2) Reduce the work to be done.(3) Use the heat over again.” [1]

More than 50 years later, Sir Lyle’s “old” news isbeing translated into “new” news in a national ef-fort to improve the U.S. industrial economy throughimprovements to industrial process steam systems.

The U.S. Department of Energy (DOE) Office ofIndustrial Technology (OIT) BestPractices effortsaim to assist U.S. industry in adopting near-termenergy-efficient technologies and practices throughvoluntary, technical assistance programs on im-proved system efficiency. There are nine industrygroups - designated Industries of the Future (IOFs)

- that are the focus of the OIT efforts. TheseIOFs include Agriculture, Aluminum, Chemi-cals, Forest Products, Glass, Metal Casting,Mining, Petroleum, and Steel. BestPracticesefforts cover motors, compressed air, steam, andcombined heat and power systems.

The overall goal of the BestPractices efforts isto assist steam users in adopting a systems ap-proach to designing, installing and operatingboilers, distribution systems, and steam appli-cations. BestPractices Steam is led by the DOE-OIT and the Alliance to Save Energy, and issupported by a Steering Committee of steamsystem users, steam system service providers, andrelevant trade associations.

One of the major 1999 goals of the BestPracticesSteam effort was to identify and document anextensive group of steam system resources andtools. There were three main objectives in iden-tifying and documenting these tools and re-sources:

1. To create an information base to “make thecase” for the opportunities available to sig-nificantly enhance industrial steam systems.

2. To identify resources to assist steam systemusers to improve their steam systems.

3. To identify what new resources and toolscan be created to assist steam system usersin the future.

This article describes the outstanding “new”news that is being created from “old” news byBestPractices Steam.

TECHNICAL TOOLS AND INFORMATION

Technical References and Technical ToolsTwo types of steam system technical informa-tion have been collected:

1. A listing of available steam system techni-cal ref-erences and standards.

2. A listing of available steam system techni-cal tools.

The members of the BestPractices Steam Steer-ing Committee and Subcommittees provided in-formation on key references and tools that they


6

used in their work or that they knew about. Thisinformation was assembled and put onto theBestPractices Steam website for future use bysteam system users and service providers. A sum-mary of the information collected is noted be-low:

1. A list of 82 steam technical references andstandard documents has been compiled.These documents have been categorized onthe website under the categories of genera-tion, distribution, end use, recovery, and to-tal steam system. The listing provides thedocument name, author, and a brief descrip-tion of the document.

2. A list of 66 steam technical tools has also beencompiled. The technical tools have been cat-egorized on the website under the categoriesof diagnostic equipment (11), guidelines (19),and software products (36).

Steam TipsA Steam Energy Tip is a brief (typically one page)writeup of a best practice - including a descrip-tion, an example application, and suggested ac-tions for applying the improvement opportunity.

The Georgia Tech Industrial Energy ExtensionService developed a series of Steam Tip fact sheets.During the past year, BestPractices Steam hasadapted the Georgia Tech Steam Tip sheets andhas now published 16 of these:

Improve Boiler Combustion EfficiencyInspect Steam TrapsRecover Heat from Boiler BlowdownMinimize Boiler BlowdownRemovable Insulation on Valves & FittingsWaste Steam for Absorption ChillersFlash Condensate to Low-Pressure SteamMinimize Boiler Short-Cycling LossesInsulate Distribution an d Condensate LinesEconomizers for Waste Heat RecoveryClear Boiler Water-side Heat Transfer ServicesReturn Condensate to the BoilerDeareators in Industrial Steam SystemsVapor Recompression to Recover WasteSteamUse Vent Condenser to Recover Flash SteamBenchmark the Fuel Cost of Steam Genera-tion

These Steam Tips can be printed and/or down-loaded from the BestPractices Steam website.

NAIMA 3E-Plus Insulation SoftwareThe North American Insulation ManufacturersAssociation (NAIMA) 3E-Plus software programquantifies the economic thickness of an insula-tion application through heat flow calculations,and estimates greenhouse gas reductions resultingfrom insulation improvements. An IBM-PC DOSversion of this program is available from ourwebsite; and a new Windows version is anticipatedin the near future.

Energy Efficiency HandbookThe Council of Industrial Boiler Operators(CIBO) developed an Energy Efficiency Hand-book. This handbook was prepared to help steamsystem owners and operators get the best energy-efficient performance out of their steam systems.The handbook provides information and helpfuloperational tips on many aspects of steam systemoperation, including water treatment, boiler op-erations and controls, heat recovery, and cogen-eration. The Energy Efficiency Handbook can beobtained from the BestPractices Steam website.

BEST PRACTICES AND CASE STUDIES

A best practice is a preferred and/or excellent wayof performing an activity.

A case study is a detailed description of an indus-trial project that produced energy savings, eco-nomic benefit, etc.

Documenting new and presently available bestpractices and case studies is one of the best waysto create awareness about opportunities for im-proving industrial steam systems.

Documenting New Case StudiesDuring the past year, BestPractices Steam has col-laborated with the following organizations todocument their recent steam system improvementefforts in the form of case study writeups:

Chemical Manufacturer’s Association (CMA)1997 Energy Efficiency Award WinnersMobil Energy ManagementBethlehem Steel


7

Georgia PacificBabcock and WilcoxTexas Instruments

These case studies are developed by: a) obtaininginitial information about the improvement effortfrom individual companies; b) reviewing the in-formation to verify that the stated energy savingsare realistic; c) preparing draft case studies for re-view; and d) revising and finalizing the case studywriteups.

Table 1 summarizes some of the annual savingsthat have been achieved in the industrial case stud-ies that we have documented to date. The infor-mation in the table illustrates that significantsteam system energy improvements and cost sav-ings are possible, with short paybacks, from im-provements that many steam users could maketo their steam systems.

Detailed case study writeups for the efforts sum-marized in Table 1 are available on our website,or from the Steam Clearinghouse.

Available Best Practices, Case StudyInformationThere are numerous reports and articles publishedin trade publications, technical journals, and con-ference proceedings documenting available steamsystem best practices and case studies. We haveinitiated an effort to document available best prac-tices and case study publications; we obtained thisinformation primarily from members of our Steer-ing Committee.

At the present time, we have documented 40 avail-able best practices publications and 18 availablecase study publications on our website. We haveidentified the information source for each docu-ment (for example, a reprint from a trade maga-zine), the application in the steam system for thedocument, and the purpose of the best practicesor case study. Additional best practices and casestudies can be submitted on-line through thewebsite.

aNalco, Vulcan, Velsicol, and Texas Petrochemical are CMA Energy Efficiency Award winners.

Table 1. Summary of Selected Steam Case Study Improvement Results

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8

TRAINING

The BestPractices Steam Training Subcommitteeinitiated an effort to identify steam trainingcourses available in the U.S. Prior to this effort,the extent of available steam training in the U.S.was not known. This was not an effort to en-dorse particular training programs over others.

The Training Subcommittee has now identifiedan extensive list of available steam training courses,and this list is documented on our website. Atthe present time, we are aware of 80 steam train-ing courses that are being provided by 31 differ-ent organizations.

One outcome of identifying available steam train-ing is that there appears to be a need for operatortraining and/or training guidelines for operatingand maintaining boiler systems. Based on thisidentified need, the National Board of PressureVessel Inspectors is in the process of developingan operator course.

AWARENESS RESOURCES

The Awareness Resources listed below (availableat no cost) have been developed to assist steamsystem users and service providers to obtain the“new” news from the BestPractices Steam efforts.

Web siteAll of the technical resource and tool informa-tion assembled by BestPractices related to steamsystems is available on our website at:www.oit.doe.gov/bestpractices/steam andwww.steamingahead.org

In addition, information on resources and toolsthat are available for the overall DOE-OIT effortis available from the following web address:http://www.oit.doe.gov/techdeliv.shtml

ClearinghouseThrough Washington State University, a Clear-inghouse has been set up that can be contacted toobtain OIT BestPractices publications and tech-nical assistance on steam system related questions.The contact information for the Clearinghouseis: Phone: (800) 862-2086Email: [email protected]

Steaming Ahead NewsletterEach month, BestPractices Steam publishes thison-line newsletter (available on the website) toprovide information on activities being performed,future steam system workshops and conferences,and other information of interest to the steam sys-tem user and service provider community. Seewww.steamingahead.org

Energy Matters NewsletterEnergy Matters is a bimonthly OIT publicationthat focuses on energy savings opportunities formotor, steam, compressed air, and combined heatand power systems. It is available by subscriptionfor free; information on subscribing to EnergyMatters is available from the DOE-OIT web siteor through the Clearinghouse.

Steam Awareness WorkshopsBestPractices Steam has conducted steam aware-ness workshops designed to make steam usersaware of the opportunities available to improvetheir steam systems. Most of the workshops havebeen co-sponsored by the Alliance to Save Energyand a steam service provider. Typical formats forthese workshops have included:

1. Presentations on the BestPractices Steam ef-forts and opportunities to improve industrialsteam systems.

2. Presentations on other energy and productiv-ity improvements available through govern-ment and private sources.

3. Steam user presentations on specific improve-ments they have made to their process sys-tems.

More than a dozen of these workshops have suc-cessfully been conducted, and we plan to conductat least this many additional workshops this year.

FUTURE RESOURCES AND TOOLS

BestPractices Steam is developing additional re-sources and tools to assist steam users. Major re-sources and tools under development are describedbelow.

Steam System Opportunity AssessmentA major industrial steam system market assessmenthas recently been initiated by DOE-OIT. The


9

Steam System Opportunities Assessment will havefour major objectives:

1. To develop baseline information on U.S. pro-cess industry steam generation, use, and op-portunities for steam system improvements.

2. To identify steam system design, mainte-nance, and management practices presentlyused by U.S. process industry.

3. To develop a methodology to assess the ef-fectiveness of efforts to influence U.S. indus-try to improve their steam system operations.

4. To educate and influence industry and gov-ernment decision makers on the benefits thatcan be realized from steam system efficiencyimprovements.

This effort will establish parameters describingthe industrial market for steam efficiency im-provements. It is anticipated that the Opportu-nity Assessment will take one to two years to com-plete.

Steam Systems SourcebookBestPractices Steam has developed a Steam Sys-tems Sourcebook to increase awareness of energysaving opportunities in industrial steam systems.The Sourcebook is intended to increase aware-ness of energy efficiency opportunities amongplant engineers, facility managers, and systemoperators.

The Sourcebook contains three main sections:

1. A “Steam Basics” section that describes thefundamentals of steam system operation.

2. A “Fact Sheet” section that provides greaterdetails regarding specific steam system per-formance improvement opportunities.

3. A “Where to Find Help” section that describeswhere steam system users can obtain furtherinformation to assist their system improve-ment efforts.

Steam System Survey GuidelinesBestPractices Steam has developed a set of SteamSystem Survey Guidelines for use by steam sys-tem users. The specific audience for these guide-lines is users who are not sure how to initiate asteam system improvement program. The Sur-vey Guidelines cover the following topical areas:

1. Steam System Profiling (how much steam doyou use, how much are your fuel costs, howdoes improved boiler efficiency translate tosaved costs, etc.).

2. Steam Generation.3. Steam Distribution and Losses.4. Steam Utilization.

Each section of the guidelines includes discussionof improvement opportunities and examples thatusers can follow to quantify the possible improve-ments in their individual systems.

CONCLUSION

In developing a comprehensive set of steam sys-tem resources and tools, BestPractices could nothave said it any better than Sir Oliver Lyle did:

“All thermal devices deserve investigation,deserve a careful estimate of their probablecost, and deserve a conscientious calcula-tion of the return they may bring.” [1]

BestPractices Steam is committed to developingtools and resources to help steam system users cre-ate “new” news of energy and productivity im-provements in their process steam systems.

For more information contact:

Dr. Anthony WrightOak Ridge National LaboratoryEmail: [email protected]: (865) 574-6878

Fred HartU.S. Department of EnergyEmail: [email protected]: (202) 586-1496

Christopher RussellAlliance to Save EnergyEmail: [email protected]: (202) 530-2225

REFERENCES

1. Oliver Lyle, 1947 The Efficient Use of Steam, Her Majesty’sStationery Office.

Steam Digest 2001Best Practices in Steam System Management

11

Best Practices in SteamSystem ManagementFred L. Hart, U.S. Dept of EnergyDavid Jaber, (formerly with) Alliance to Save Energy

Achieving operational excellence is a continuoustask for all manufacturers working to reduce costsand keep their plants profitable. Luckily, manyopportunities exist for industrial plants to cutcosts without jeopardizing jobs or the environ-ment. For example, over 50 percent of the inputfuel used by the U.S. manufacturing sector is usedto generate steam. More importantly, in a typi-cal facility, a 20 to 30 percent improvement insteam system efficiency, i.e., the ability to meettheir steam needs with 20 to 30 percent less fuel,is possible. At an estimated annual cost of $18billion for fuel, alone, in the 33,000 boilers usedby industry, reducing steam fuel use can improveprofits nationally. [1] The chemicals industry canparticularly benefit as it is very steam intensive;steam production accounts for over 50 percentof fuel used by the sector. Other sectors whichreally benefit through steam system improvementsinclude pulp and paper, food processors, steelmills, petroleum refining, and textiles.

Common areas in which to look for savings op-portunities in steam generation, distribution, enduse and recovery are outlined below.[2] By deter-mining which are the most appropriate at a givenplant, a good start can be made on improving theproductivity and reliability of the plant, while cut-ting unnecessary costs.

STEAM GENERATION

Demand ReductionThe boilers may well be producing more steamthan is needed for the end uses. Evaluation ofdemand is especially important when downstreamimprovements such as insulation and condensatereturn are implemented - lower loss means lowergeneration needs. At Nalco Chemical Company’sClearing Plant in Bedford Park, Illinois, a pro-cess engineer determined that a steam header pres-sure of 125 psig was no longer necessary due tochanges in the some of the plant’s processes. Ateam of personnel from the maintenance, utili-

ties, and production departments evaluated thefeasibility of reducing the header pressure and de-cided to incrementally decrease header pressurewhile monitoring the effects of this change on sys-tem performance.

The pressure was reduced twice, first to 115 psig,and then to 100 psig. After determining no detri-mental impacts on system operation, Nalco nowoperates the system at 100 psig, resulting in an-nual energy savings of 8 percent, far exceedinginitial expectations, and saving $142,000 annu-ally along with reduced carbon emissions. For thiswork, the plant received a 1997 Chemical Manu-facturers Association Energy Efficiency Award.[3]

In addition to a straight boiler generation reduc-tion, a specific end use pressure might be reduced.As part of their Operational Excellence Program,Vulcan Chemicals, a business group of the VulcanMaterials Company, implemented a process opti-mization project involving two chloromethaneproduction units. This four-month project re-quired no capital investment and resulted in a re-duction in process steam demand and significantcost savings. Vulcan lowered the steam systempressure in the first distillation column from 35to 26 psig. This gave them a lower condensingtemperature that requires less reflux during com-ponent separation. Average reboiler steam demandper unit of product decreased by almost 6 percentand resulted in yearly cost savings of $42,000. Thisplant also received a Chemical Manufacturers As-sociation Energy Efficiency Award in 1997 for theproject.[4]

Boiler Tune-UpThe major areas of opportunity in boiler tune-upencompass excess air and blowdown optimization.Optimum excess air minimizes stack heat loss fromextra air flow while ensuring complete fuel com-bustion. Stack temperature and flue gas oxygen(or carbon dioxide) content are the primary indi-cators of the appropriate excess air level; an ad-equately-designed system should be able to attaina 10 percent excess air level. The required actionis to monitor flue gas composition regularly withgas absorbing test kits or computer-based analyz-ers. Highly variable steam flows or fuel composi-tion may require an on-line oxygen analyzer, alsocalled oxygen trim control.

Steam Digest 2001Best Practices in Steam Systems Management

12

Optimizing boiler blowdown helps keep steamquality high for effective production, while re-ducing fuel and water treatment expenses.Blowdown rates typically range from 4 to 8 per-cent. Relatively pure feedwater may require less,where high solids content water requires more.Extensive operating practices have been developedby an AIChE sister organization, the AmericanSociety for Mechanical Engineers. Theseblowdown practices depend on operating pres-sures, steam purity needs, and water deposit sen-sitivity of the system. For best blowdown results,investigate the ASME guidelines and also lookinto continuous blowdown control systems tohelp maintain optimal blowdown levels.

Clean Heat TransferScale build-up can cause safety hazards from heatexchanger tube failure and boiler metal overheat-ing, in addition to excess fuel use of up to 5 per-cent. Heat transfer surfaces can be kept relativelyclean by pretreating boiler makeup water withwater softeners, reverse osmosis, and/or deminer-alizers, treating returned condensate, if needed,and adopting proper blowdown practices. Re-move existing scale either mechanically or throughacid cleaning. It can also be useful to consult aspecialist in water treatment.

Auxiliary EquipmentIn addition to the automatic blowdown controlsystem and oxygen trim control already men-tioned, other equipment which can increase boilerefficiency include economizers, blowdown heatrecovery systems, and controls. Economizerstransfer heat from the flue gas to the feedwater,and are appropriate when insufficient heat trans-fer (assuming heat transfer is clean of scale) existswithin the boiler to remove combustion heat.Good boiler candidates are those above 100 boilerhorsepower. Determine the stack temperature andminimum stack temperature to avoid corrosion(250° C if natural gas is the fuel; 300° C for coaland low sulfur oils; and 350° C for high sulfuroils) after tuning boiler to manufacturer specifi-cations. This will help indicate whether or notan economizer makes sense economically in theplant.

Blowdown heat recovery systems preheat boilermake-up water using the blowdown water re-moved and make sense in continuous boiler

blowdown systems. Blowdown waste heat can berecovered simply with a heat exchanger, or in aflash tank. For controls, an oxygen trim controlsystem provides feedback to the burner controlsto automatically minimize excess combustion airfor an optimum air to fuel ratio. This can result infuel savings of 3 to 5 percent and is useful wherefuel composition is highly variable.

STEAM DISTRIBUTION

Steam LeaksSteam leaks can be dangerous in higher-pressuresystems, above and beyond the significant energywaste they represent. Steam leaks are often foundat valve stems, unions, pressure regulators, equip-ment connection flanges, and pipe joints. Thefirst step is to conduct a steam leak survey. Largesteam leaks are visible and ultrasonic detectors canidentify even very small leaks. Tag the leaks anddetermine which can be repaired by your mainte-nance staff and which require service technicians.

Steam TrapsIn steam systems that have not been maintainedfor 3 to 5 years, from 15 to 30 percent of trapsmay have failed, and regularly-scheduled mainte-nance should reduce this to under 5 percent oftraps. The cost of one medium-sized steam trapthat failed to open in an average pressure systemmight be $3,000 per year and more. Traps can betested by a range of means, including visual in-spection, listening to the sound, pyrometers, andultrasonic and infrared detectors.

For optimum performance, establish a regular trapinspection, testing, and repair program that in-cludes a reporting mechanism to ensurereplicability and provides for documenting energyand dollar savings. Velsicol Chemical’sChestertown, Maryland, facility implemented apreventive maintenance (PM) program to iden-tify energy losses in their steam system. Velsicol’sPM program inventoried the plant’s steam traps,trained system operators to identify failed traps,and improved communication between mainte-nance and production personnel so that failed trapswere quickly repaired or replaced. This programalso identified improperly sized traps or traps ofthe wrong type and planned their replacement.


13

Implementing the program saves Velsicol over$80,000 annually at an initial cost of just $22,000.It also reduced energy consumption on a per pro-duction unit basis by 28 percent, and had a pay-back of just over 2.5 months. The plant receiveda 1997 Chemical Manufacturers Association En-ergy Efficiency Award for the project. The effortreduced annual CO

2 emissions by 2,400 tons. Yet

another benefit was the reduced worker exposureto treatment chemicals.[5] A large Rohm andHaas methyl methacrylate plant in Kentucky,implementing a similar program, saved nearly$500,000 each year.

InsulationInsulation helps ensure proper steam pressure forproduction and can reduce radiative heat loss fromsurfaces by 90 percent.[6] The Department ofEnergy (DOE) Industrial Assessment Center pro-gram demonstrated a savings potential rangingfrom 3 percent to as high as 13 percent of totalnatural gas usage on average through insulationinstallation. The optimum insulation thicknesscan be calculated with the DOE 3E+ softwareprogram. Depending on pipe size and tempera-ture, needed insulation thickness may range fromone inch to over eight inches. For steam systemsspecifically, common insulating materials includefiberglass, mineral fiber, calcium silicate, and cel-lular glass. Material choice depends on moisture,temperature, physical stress, and other environ-mental variables.

Appropriate actions include: first, insulate steamand condensate return piping, boiler surfaces, andfittings over 120 degrees Fahrenheit; second, con-duct a survey of the overall facility steam systemevery five years for deteriorated and wet insula-tion; and third, repair or replace damaged insu-lation. As an example, Georgia Pacific’s plywoodplant in Madison, Georgia, insulated several steamlines leading to its pulp dryers. Using 3E+, theydetermined an optimal insulation for their steamlines and installed mineral fiber insulation. Geor-gia Pacific found this made their work environ-ment safer and improved process efficiency. To-gether with steam trap maintenance, the plantreduced its fuel costs by roughly one-third overthe year and also lowered emissions — 9.5 mil-lion lbs. of carbon dioxide (carbon equivalent),3,500 lbs. of SOx, and 26,000 lbs of NOx on anannual basis.[7]

STEAM RECOVERY

Condensate ReturnReturn of high purity condensate reduces boilerblowdown energy losses and makeup water. Thissaves 15 to 18 percent of the fuel used to heat thecool makeup water, saves the water itself, and savestreatment costs and chemicals. Reduced conden-sate discharge into the sewer system also reducesdisposal costs. Repair condensate return pipingleaks for best results. If the condensate return sys-tem is absent, estimate the cost of a condensatereturn system and install one if economically jus-tified.

Flash Steam RecoveryWhen the pressure of saturated condensate is re-duced, a portion of the liquid “flashes” to steamat a lower pressure. This can be intentionally doneto generate steam or unintentionally. Flash steamcontains anywhere from 10 to 40 percent of theenergy content of the original condensate depend-ing on the pressures involved.

Often the steam is vented and lost; however, a heatexchanger can be placed in the vent. Inspect ventpipes of receiver tanks and deaerators for exces-sive flash steam plumes and install heat exchang-ers.

As an example illustrating the economics of steamand condensate recovery, the Bethlehem SteelBurns Harbor plant returned a portion of its warmcondenser cooling water exhaust stream to theboiler feedwater and rerouted low pressure wastesteam into a steam turbine generator. This alongwith a turbine rebuild results in annual savings ofapproximately 40,000 MWh of electricity, 85,000MMBtu of natural gas, and nearly $3.3 million.With a cost of $3.4 million more than a standardmaintenance overhaul, the project had a simplepayback of just over one year.[8] The project alsoreduced high-temperature water discharge into theharbor and decreased coke-oven and blast-furnacegas emissions by 27,200,000 lbs. of carbon equiva-lent, 294,000 lbs. of SOx, 370,000 lbs of NOx,11,600 lbs. of PM

10, 1,450 lbs of VOCs, and

14,000 lbs of CO.

Steam Digest 2001Best Practices in Steam Systems Management

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PUTTING IT ALL TOGETHER

The above tips point out the power of taking asystems approach to energy management. Re-turning condensate and recovering heat from theend of the process makes true steam demand as-sessment, clean heat transfer maintenance, envi-ronmental emissions control, and fuel use mini-mization at the boiler easier. Pursuing the sys-tems approach can be facilitated by using the re-sources of the DOE Office of Industrial Tech-nologies, which is the source of most of the aboveguidance. DOE assistance focuses on helping in-dustry in developing and adopting energy-effi-cient technologies and practices through volun-tary technical assistance programs on plant-wideenergy efficiency. Areas of focus include indus-try-specific emerging technologies, industrialsteam systems, electric motors, drives and pumps,industrial compressed air systems, and combinedheat and power systems.

In conjunction with the Alliance to Save Energyand industry steam experts, a network of resourceshas been established to help steam-using indus-trial plants adopt a systems approach to design-ing, installing and operating boilers, distributionsystems, and steam applications. Benefits of thesystems approach include lower operating costs,lower emissions, increased plant operation reli-ability, and increased productivity. Specific re-sources include:

Tip sheets.Case studies.Answers to technical questions.Databases of training opportunities, techni-cal tools, references and standards.Workshops which bring together publicmanu-facturing resources, private-sector en-ergy management assistance, and peer net-working opportunities.Plant-wide assessment opportunities.Technical papers.Project financing guidance tools.Publicity and awards through case study data.

Existing resources are available through the In-dustries of the Future Clearinghouse ((800) 862-2086, [email protected]), the website(www.oit.doe.gov/bestpractices/steam) and the

OIT resource room at (202) 586-2090. Theseresources also include a Sourcebook providing acomprehensive steam system overview and refer-ences and a Steam Scoping software tool provid-ing guidance on how to profile and assess steamsystems.

Case studies in particular have a lot of power, andmany of these are specific to the chemical indus-try. Internally, case studies help foster success rep-lication for other company facilities as well asachieve internal company recognition. Externally,the company can receive recognition as an indus-try leader. DOE is available for assistance in casestudy documentation.

CONCLUSION

Too many manufacturing facilities are not achiev-ing their full potential because of poorly operatedand maintained steam systems. Steam efficiencylies at that rarely visited intersection of improvedeconomic performance, greater energy-efficiency,and environmental benefit. By taking advantageof available public and private energy managementresources, any manufacturer can benefit.

Continuous improvement and maintenance ofsteam system efficiency through monitoring andmaintenance leads to greater reliability, cost effec-tive production and price competitive products.The following steps help pursue the systems ap-proach: 1) Walk through your entire steam sys-tem by performing an audit, 2) Document theaudit results and make appropriate improvementsas outlined here; and 3) Develop and implementa program for ongoing maintenance. The longterm benefits of system efficiency require continu-ous improvement through proper operating andmaintenance practices. This prevents a systemfrom degrading into a mode of poor performance.

Heightened awareness of operating costs and per-formance implications is key to understanding theimportance of steam system management. Addi-tional ways to discover and capture savings op-portunities are by sharing experiences within andoutside the company, and increasing interactionbetween facility operations and management toreconcile production and engineering facts withthe financial and corporate priorities.


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Fred HartU.S. Department of EnergyEmail: [email protected]: (202) 586-1496

REFERENCES

1. Unpublished research of the Alliance to Save Energy,1999. Calculated from GRI boiler data and MonthlyEnergy Review fuel cost data.

2. The suggestions and facts used in the savings opportuni-ties areas come from the U.S. Department of EnergyEnergy Tips tip sheet series and can be consulted forfurther information.

3. U.S. Department of Energy, April 1999. ReducingSteam Header Pressure Provides Attractive Operating CostSavings, 2 pp.

4. U.S. Department of Energy, July 2000. Reducing SteamPressure Saves $42,000 Annually At Vulcan Chemicals,DOE/ORNL-002, 4 pp.

5. U.S. Department of Energy, April 1999. Improved SteamTrap Maintenance Increases System Performance and De-creases Operating Costs, DOE/ORNL-003, 4 pp.

6. U.S. Department of Energy, September 1995. IndustrialInsulation for Systems Operating Above Ambient Tempera-ture, ORNL/M-4678, 12 pp.

7. U.S. Department of Energy, November 1998. The Chal-lenge: Increasing Process and Energy Efficiency at a PlywoodPlant, ORNL/SC-CS2, 4 pp.

8. U.S. Department of Energy, April 1999. The Challenge:Improving Steam Turbine Performance at a Steel Mill, DOE/GO-10099-763, 4 pp.

Steam Digest 2001Best Practices: The Engineering Approach for Industrial Boilers

17

ABSTRACT

A plant’s boilers represent a large capital invest-ment, as well as a crucial portion of overall plantoperations. It is important to have systems andprocedures in place to protect this investment, aswell as plant profitability. Boiler best practicesrepresent “The Engineering Approach for Boil-ers”—a way to examine mechanical, operationaland chemical aspects of the systems (pretreatmentthrough condensate) to ensure reliable boiler op-erations with no surprises.

INTRODUCTION

All industrial plants have boilers of one type oranother, often more than one type. Whether theplant in question has one small boiler, or manylarge ones, the boilers are an essential element ofevery plant, regardless of plant size or of productproduced. With skyrocketing fuel and energycosts, maintaining both boiler reliability and con-sistent system performance while minimizingenergy costs can be a challenge and an opportu-nity for any utility operation. The EngineeringApproach provides a framework to examine allaspects of boiler best practices to optimize sys-tem performance, and total cost of operations.

Implementing the Engineering Approach assistsin gathering information to measure and trackprogress, to initiate further improvements, andto allow benchmarking and norming of systemsacross corporations and within industries.

There are several steps in the effective implemen-tation of the Engineering Approach, or best prac-tices for boilers. This article will discuss the phi-losophy of the Engineering Approach, as well asexamples of its implementation, and the benefitsreceived from it both in terms of system opera-tion, and in terms of total cost of operations.

WHAT IS THE ENGINEERING APPROACH?

The Engineering Approach represents the formal-ization of ONDEO Nalco’s approach to servingour customers. It is fundamentally a customer-centric method of doing business that permits themanagement of knowledge of the customer’s wa-ter system, and knowledge of the impact that wa-ter systems can have on process operations, envi-ronmental performance, and overall costs. Thisengineering knowledge is used to significantlybuild value for the customer.

The fundamental elements of the Engineering Ap-proach are mechanical (M), operational (O) andchemical (C) considerations. This provides a sys-tem that:

Is independent of personnel movement to newassignments (customer or consultant).Focuses on results.Is proactive in the prevention of problems.Identifies opportunities to reduce total costof operation (TCO) for the plant.

The Engineering Approach represents best prac-tices for boilers in that it provides a benchmarkfor continuous improvement of our customers’ sys-tems. With the Engineering Approach we pro-vide recommendations for optimizing total costof operations (TCO) by considering all relevantfactors.

WHY IMPLEMENT THE ENGINEERING

APPROACH?

Individual plant management is increasingly be-ing asked by their corporate offices to considerfinancial results, TCO, quality, environmentalhealth and safety, and manpower effectiveness.The order of importance may have changed overthe past few years, and may be different from in-dustry to industry, but all plants are focusing moreand more on the environment, safety, budgets, andperformance.

Water treatment can have an impact on all areas ofa utility budget. Actual water treatment costs,however, usually only represent 2 to 3 percent ofoverall costs, as seen in Figure 1. Although watertreatment chemicals represent a small portion of

Best Practices: TheEngineering Approachfor Industrial BoilersNatalie R. Blake, ONDEO Nalco


18

Chemicals3%

Misc6% Water

8%

Electricity22%

Manpower23%

Fuel38%

the utility budget, they have a major impact onall areas of a utility budget. Water touches most,if not all, of the key process units, and can have amajor impact on production rates, maintenancecosts, and overall plant profitability.

Unexpected boiler outages will limit, or even stop,production. Poorly run boiler systems will be veryenergy inefficient, and may even result in envi-ronmental problems with emissions. Addition-ally, running ineffectively may actually shortenboiler life, or at a minimum increase maintenancecosts. In any case, plant profitability suffers, andboth short- and long-term viability may bebrought into question.

All is not lost, however. ONDEO Nalco’s strat-egy is to become part of the solution, the totalcost reduction solution, partnering with our cus-tomers to become a generator of profit and a re-ducer of total costs. Best practices, or the Engi-neering Approach, provide the means as well asthe tools to bring this about.

Having an in-depth understanding of the me-chanical components of the water systems, andspecifically the boilers, provides a good startingpoint. The mechanical survey is then followedby statistical analysis of operational control capa-bility, so that we have a statistical understandingof the actual control capability of the system.Finally, having a thorough understanding of thereal stresses on the water chemistry of the system

completes the picture.

Completing surveys of the plant, and specificallyof the boiler operations with the MOC approachoften leads to a new perspective on the system.Results of surveys, statistical analysis, and waterchemistry modeling provide an impartial frame-work to evaluate and improve the overall systemoperation and cost.

Some examples of mechanical system aspects areheat flux, determining thermal limits, and iden-tifying problem areas. Operational factors includeexamining control charts and process capability,identifying control problems, and looking at au-tomation. Chemical aspects of the system involvelooking at modeling (water chemistry, treatmentchemicals, and so on), determining control lim-its for the system, and examining treatment alter-natives.

The current approach in some plants may be toskip the mechanical and operational steps, andjust focus on chemical solutions. Standard per-formance, basic control needs of the water chem-istry, and chemical costs are what are considered.But you then have to ask whether you have totalsystem management and whether there is reliabil-ity in the mechanical operations and recommen-dations. What assurances are there that chemicalprogram success can be predicted? Are key per-formance factors being considered and tracked?Can total costs (and possible reductions) be cal-

Figure 1. Typical Cost Distribution in the Utility Area


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culated, or just costs associated with chemicaltreatment?

The Engineering Approach uses a variety of da-tabases for data analysis. Information gatheredabout the system from surveys is input into thedatabase, and is continually updated. This helpsprovide system management, reliability, predict-ability, and TCO reduction. It also allows us tobenchmark and norm against other plants, otherindustries, and so forth.

How and what was your system designed to do?Mechanically, consider piping, blowdown tanks,and economizer. Is your system capable of oper-ating the way you want? How and what was yourcurrent water treatment program designed to do?The Engineering Approach goes beyond MOC,however. Data, with their financial implications,are compiled so that real value is addressed.

The complete MOC approach provides an ob-jective look at the system with information, whichthen helps to facilitate decisions at all levels inthe plant. Choices for change are clear and docu-mented, whether for mechanical, operational, orchemical segments of the operations. In addi-tion, each choice has a cost and a return associ-ated with it, allowing for project prioritizationand tracking. Plant management can truly an-swer the questions of “how much,” “how sure,”and “how soon” the savings can be realized.

Probably the best way to explain the power ofthe Engineering Approach is to relate some reallife experiences in applying the approach in ourcustomers’ plants, using plant personnel.

EXAMPLES OF BEST PRACTICES – THE

ENGINEERING APPROACH FOR BOILERS

Boiler Water Chemistry out of the ControlBoxA plant was experiencing continual out-of-specification readings for their coordinatedphosphate boiler program; that is, they werefrequently “out of the box” with respect to theircontrol range. There was no immediately ob-vious reason for the lack of control, and it re-sulted in the operators making manual adjust-ments to the blowdown to try to improve their

control. This, in turn, resulted in periodic en-ergy and water loss through excessive blowdown,and variation in cycles of concentration.

As there was no clear reason, and it appeared to berelated to boiler cycles, plant personnel started totalk about hideout. This is a serious concern, andwas important to determine the real reason forthe lack of control.

The Engineering Approach, looking at best prac-tices, was chosen for problem solving. The firstthing done was to complete a mechanical surveyof the boiler system, focusing on everything thatcould be influencing the boiler reading. Thefeedwater system was examined, including rawwater treatment, demineralization, the deminer-alized water storage tanks, the condensate system,and the boiler itself. The goal was to determine ifthere were additional unauthorized water streamsbeing brought into the system, whether proper pre-treatment was occurring, whether there was un-expected contamination, and its source, and soforth.

Following the mechanical survey, an operationalsurvey was performed. This involved statisticalanalysis of the plant’s control capability in criticalcontrol parameters such as pH, cycles, phosphate,chemical feed, conductivity, etc. This will help toexplain why there is a control problem in this boilersystem.

The parameters tested daily by the operators forfeedwater, condensate, and boiler water were ex-amined. The historical deaerator operation waslooked at, as well as its maintenance logs. His-torical data on condensate return and contami-nant concentration were analyzed, as were resinreplacement history, and regeneration practices.

All laboratory testing methods were reviewed in-cluding frequency, adherence to procedures, in-strumentation, calibrations, test methods chosen,sample gathering, and so forth. This was done tomake sure that the data being analyzed was statis-tically accurate, and that correct conclusions wouldbe drawn.

Both ONDEO Nalco and plant personnel did themechanical and operational surveys. This madesure that the systems were properly surveyed, and


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nothing was overlooked.

Finally, a chemical audit was done for the systemto examine both the program choice, as well asthe program application. This included feed lo-cation, sampling location, injection methods, etc.This data was examined separately, and in con-junction with the mechanical and operationalsurvey results.

After examining all the data gathered from thevarious surveys, the conclusion was that there wereno mechanical issues that were affecting the lackof control of the internal treatment. The chemi-cal program being used was the technically cor-rect choice given the feedwater pretreatment andwater quality.

Furthermore, if operated properly, the system wasin fact capable of being in control during a muchlarger percentage of the time than was being ex-perienced (<50%). The operators were not tak-ing the holding time of the boiler into accountwhen making blowdown adjustments, and wereoften “chasing their tail” when trying to movethe boiler parameters “into the box.” In fact, mostof the problems were caused by the operators over-reacting to changes in test results from the boilerwater chemistry.

The boiler was experiencing frequent load swingsdue to plant operation. These load swings couldnot be evened out due to plant configuration andrequirements. Surveys also showed that themanual control of the feedwater treatment prod-ucts was exacerbating the problems as manualadjustments made as the load was swinging werenot necessarily timely.

Actions taken to improve the situation includedoperator training. Training on holding time andthe length of time it would take to have a changebe seen gave operators a better understanding ofwhat was going on in the boiler system. Manage-ment and the operators agreed that, except in caseof emergency, blowdown rate changes would onlybe made on the day shift. This allowed the plantto stop exaggerating the changes.

The feedwater treatment was also automated, pro-viding more consistent feedwater treatment, eventhrough large load swings for the boiler.

Results from this relatively simple “MOC” studywere very positive. The percent of time the boilerspent “in the box” increased from <50% to >90%,and a project is in place to study whether it is pos-sible to improve this further.

With the training, the operators understood theoverall system much better. They were able toreduce the amount of reacting they did, and weremuch happier on the job. It also freed operators’time for more value-added proactive projects.

Automation improved overall system operation,and resulted in feed optimization, even with fairlylarge swings in steam load. This, in turn, alloweda minimization of feed—no “overfeed” was re-quired to ensure system protection.Additional savings were realized by the plantthrough optimized blowdown. This reduced bothwater and energy usage resulting in reduction oftotal cost of operation for the utility department,and improved boiler operations through consis-tent cycles of concentration.

Through the use of the Best Practices Engineer-ing Approach (mechanical – operational – chemi-cal), the plant saw good returns with a small in-vestment in time and money. The investment wasfor surveys and data analysis and some automa-tion equipment. The plant was able to eliminatehideout as a possible cause for the problem, im-prove overall operations, and reduce overall costof the operation through optimization of theirexisting systems, rather than through a reductionin chemical price/pound. There was no quantifi-cation of what the plant saved through increasedreliability and extended lifetime for the boiler.

By looking at the overall operations rather thanjust looking for a quick band-aid, the plant wasable to quickly optimize operations and savemoney. This resulted in a very happy customer,an optimized system, and a better partnership be-tween the customer and ONDEO Nalco. We wereseen to provide a value-added service through ouron-site technical representative acting as a con-sultant to the customer and using our best prac-tices—The Engineering Approach.


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Iron and Copper Corrosion in a CondensateSystemA plant on the West Coast was experiencing corro-sion in their condensate system. The system is pri-marily mild steel, although there are copper-contain-ing portions. Due to plant operation, there are con-stant steam load swings resulting in pH swings in thecondensate system. Both copper and mild steel cor-rosion were detected.

The operators adjusted the condensate treatment (neu-tralizing amine) to maintain acceptable pH to mini-mize corrosion, with the focus on mild steel.

Again, a mechanical survey was done of the conden-sate system, followed by looking at all the data. Steamload swings were correlated with pH swings and cor-rosion results. A chemical survey was also performedwhich looked at the particular neutralizing amine cho-sen, its application point, the average dosage, and thefrequency of changes in dosage to maintain minimizedmild steel corrosion (optimized pH). The historicalcopper and iron levels in the condensate were alsoanalyzed.

The surveys indicated that no mechanical changes wereneeded, and that all testing procedures, equipment,calibrations, and frequency of testing were all accept-able.

When system operation was analyzed, it became ap-parent that the pH swings that were causing the prob-lem would continue, and the system would continueto have sections that were at low pH (5.5-7). Moreneutralizing amine could not simply be added to in-crease the pH as this would unacceptably raise thepH elsewhere in the boiler system. This restrictionneeded to be taken into account in examination ofthe system. The chemical program chosen was notcapable of properly protecting the system under thegiven conditions. As the operation could not change,changes to the chemical program were considered.

After careful examination of a variety of neutralizingamines (different blends, different neutralizing abil-ity), a supplemental program was suggested. The origi-nal neutralizing amine was retained, and a new non-amine film former was chosen as a supplement in thelow pH areas of the system. The product works inthe pH range of 5-7, which will meet the system’s mildsteel protection needs in the low pH regions, but will

not raise pH in other areas of the system, protectingthe copper areas.

Within twenty-four hours of implementing thechemical program, both iron and copper levels inthe condensate dropped dramatically. In fact plantpersonnel commented on the Millipore pads, andhow clean they looked through the first day—fromalmost black, to grey, to almost clean!

Again, through a careful examination of all poten-tial factors, a solution was arrived at that met theneeds of the plant, with good results. If the opera-tional information had not been analyzed, it is pos-sible that the chosen solution might have been justto feed more neutralizing amine, definitely the wronglong-term overall solution.

SUMMARY

There are many opportunities to improve overallplant as well as boiler system performance, efficiency,and safety while reducing the total cost of opera-tions. Boiler best practices and the Engineering Ap-proach provide useful tools to achieve these goals,and make sure that no stone is left unturned in mak-ing the system reliable. By looking at mechanical,operational, and chemical aspects of the systems, allpotential problems and opportunities for improve-ment can be identified, whether in performance,total cost of operation, profitability, or safety.

Incorporating all aspects of the system provides acomprehensive approach. Regardless of the source,problems can be solved/prevented without creatingothers in other parts of the system. In fact, oftenstarting with a mechanical survey, followed by sta-tistical analysis of operational data, will eliminateproblems that may be masking issues with the chemi-cal treatment. Costs associated with improvements(chemical, capital, operational) can then be deter-mined/justified, and agreement obtained from man-agement to prioritize projects, and then track andcomplete them.


Natalie R. BlakeONDEO NalcoEmail: [email protected]: (630) 305-1000

Steam Digest 2001Performing a Steam System Checkup: A Three-Step Checkup Identifies Potential Opportunities for Improvements

23

Performing a SteamSystem Checkup:A Three-Step CheckupIdentifies PotentialOpportunities forImprovementsAnthony L. Wright, Oak Ridge National laboratoryGreg Harrell, University of Tennessee at KnoxvilleGlenn Hahn, Spirax Sarco

Everyone knows the value of visiting the doctorfor a yearly physical checkup. However, some-times people put off this checkup – risking healthproblems.

To protect steam systems and ward off potentialproblems, operators and plant energy managersneed to perform a “checkup” on their steam sys-tem. This checkup can improve the productivityand profitability of plant operations and/or assessthe status of operations.

The Department of Energy (DOE) Office of In-dustrial Technology’s (OIT) BestPractices Steameffort is developing a set of steam survey guide-lines to help steam users evaluate and improve theirsteam systems. The guidelines focus on improve-ments steam users can make without relying onthe help of outside consultants. Circumstancesthat warrant outside assistance are also identified.

Improvement opportunities in the areas of boilerefficiency, steam generation, steam distribution,steam utilization, steam losses, and heat and con-densate recovery are discussed. Sample calcula-tions and methods for estimating improvementopportunities are presented.

Plants can benefit from a three-step steam systemcheckup process that includes:

Steam system profiling.Identifying potential opportunities for im-provement.Reviewing maintenance practices.

The BestPractices guidelines discuss steam system

profiling and identify opportunities for improve-ment. Maintenance practice review goes a stepbeyond the guidelines to ensure the plant retainsany improvements.

STEAM SYSTEM PROFILING

Profiling issues focus on utility/steam costs andcalculating benefits of improvements. In steamsystem profiling, the first step involves a series ofquestions to gain a better understanding of thesteam system:

Is the fuel cost for generating steam in thesystem known and measured?Are steam/product benchmarks known andmeasured?Are critical steam system operational param-eters measured?

Fuel Cost For Generating SteamDetermining the fuel cost to make steam at afacility can be an eye-opener. In many steamsystems, the fuel cost can be 80% or more of thetotal cost to operate the steam system.

For example, if an industrial boiler generates100,000 pounds (lb) of steam per hour, and thefuel cost to make steam is $4.00 per 1,000 lb.,then the total cost for continuous steam genera-tion for one year would be $3.5 million. If 10percent of the fuel costs could be cut each yearthrough operating improvements, $350,000 couldbe saved in energy costs.

Two methods can be used to calculate fuel coststo generate steam. The first entails calculating thefuel price, fuel energy content, steam productionrate, steam energy addition and boiler efficiency.The second entails calculating the fuel feed rateper hour and the fuel price. Both methods pro-vide a benchmark for the magnitude of energysavings possible in a steam system.

Steam/Product BenchmarkingMany industrial users measure and track steam/product benchmarks – for example, the poundsof steam needed to make a given unit of product– to benchmark their productivity. They trackthis benchmark with what other facilities in theircompany do, with what their competitors do, and


24

with how the benchmark varies in a facility overtime. Steam/product benchmarking is anexcellent way to monitor productivity and thepossible effect of steam system improvements onproductivity.

Steam System MeasurementsTo monitor a steam system and diagnose potentialproblems, it is important to measure certain keyparameters. These key parameters include boilerfuel flowrate; feedwater and makeup water flowrates; chemical input flow rates; steam flow rates(out of the boiler and at key locations in the steamsystem); blowdown; boiler flue gas temperature,O

2 content and CO content; boiler efficiency;

steam quality out of the boiler, and condensateflow rate.

Remember, what is not measured cannot be man-aged.

IDENTIFYING OPPORTUNITIES

This section of the checkup involves a review ofsome of the basic areas of steam system opera-tion. This review can provide excellent opportu-nities for improving steam use and operationsproductivity. The opportunities discussed herefall into three areas: total steam system, boilerplant and steam distribution, and end use andrecovery.

Total Steam SystemThe following questions will help identifyoperating practices and improvementopportunities for a total steam system:

Are the steam traps in the steam system cor-rectly selected, tested, and maintained?Is the effectiveness of the water treatment pro-gram reviewed?Are the steam system’s major components wellinsulated?Are steam leaks quickly identified and re-paired?Is water hammer in the steam system detectedand eliminated?

Steam traps serve three important functions insteam systems: preventing steam from escapingfrom the system before its heat is used; removing

condensate from the system; and ventingnoncondensable gases. Poor steam trap selection,testing, and maintenance can result in many sys-tem problems, including water hammer, ineffec-tive process heat transfer, steam leakage, and sys-tem corrosion. An effective steam trap selectionand maintenance program often offers paybacksin less than six months.

An effective steam system water treatment pro-gram reduces the potential for waterside foulingproblems in boilers; is critical to minimizing boilerblowdown and resulting energy losses; can reducethe generation of wet steam; and greatly reducesthe potential for corrosion problems throughoutthe steam system. Most effective water treatmentprograms include mechanical treatment such asfiltration and deaeration, as well as chemical treat-ment. Problems in this area can lead to equip-ment failure and downtime – consultation with achemical treatment specialist on an ongoing basisis advised.

Steam system insulation – on piping, valves, fit-tings, and vessels – also serves many importantpurposes. Insulation keeps steam energy withinthe system to be used effectively by processes. Itcan reduce temperature fluctuations in the system.Insulation also helps prevent burns to personnel.

Two main approaches are used to improve steamsystem insulation. The first approach is to deter-mine the economic insulation thickness requiredfor the operations. This can be done using a toolsuch as 3E-Plus software. The second approachinvolves system insulation surveys to identify ex-posed surfaces that should be insulated and/orremoved, as well as any disturbed or damaged in-sulation.

Steam leaks can result from failures associated withimproper piping design, corrosion problems, andvalves. In high-pressure industrial steam systems,the energy costs associated with steam leaks canbe substantial.

For example, for a steam system operated continu-ously, a 1,000 lb-per-hour steam leak, at a steamcost of $4.00 per 1,000 lb, would mean a yearlyenergy loss of $35,000. This leak rate would beexpected with a 3/8-inch-diameter hole in a 300-psig steam system, or a ½-inch-diameter hole in a


25

150-psig steam system. Steam leak repair is essen-tial.

Water hammer in a steam system also is a seriousconcern. It can lead to failure and rupture of pipingand valves and, in many cases, to significant injuryto personnel from contact with steam and conden-sate.

There are two main types of water hammer. One iscaused by condensate accumulation in steam distri-bution piping, followed by transport of this con-densate by high-velocity steam. The other is causedby a pressure pulse resulting from steam collapse(rapid condensation) in condensate return lines andheat exchange equipment. Water hammer in a steamsystem always necessitates repair.

Boiler PlantThese questions can help identify operating practicesand improvement opportunities:

Is the boiler efficiency measured and are thetrends charted?Is installation of heat recovery equipment on theboilers – feedwater economizers, combustion airpreheaters, blowdown heat recovery – investi-gated?Is high-quality steam generated in the boilers?

First, the major sources of inefficiency in boiler op-erations must be identified. The major losses in aboiler are typically associated with combustion andflue gas energy losses, blowdown losses, and refrac-tory insulation losses. Although an understandingof blowdown and refractory insulation losses is im-portant, these losses are not as problematic as com-bustion and flue gas energy losses.

Second, the efficiency of the boilers must be mea-sured, and flue gas temperature, flue gas O

2 content

and flue gas CO content also must be measured regu-larly. Measurement and control of excess O

2 are criti-

cal to minimizing boiler combustion energy losses.Charting the flue gas temperature trends can indi-cate other potential problems in the boiler. Forexample, elevated flue gas temperatures might indi-cate waterside or fireside fouling problems.Third, if the plant runs multiple boilers, it shouldoperate them using a strategy that minimizes the to-tal cost to generate steam for the facility. For ex-

ample, one strategy would be to use the boiler thatoperates with the highest efficiency for the longestpossible time.

In some boilers, high flue gas temperatures and highcontinuous blowdown rates can provide opportuni-ties for installation of heat recovery equipment.Feedwater economizers and combustion air preheaterscan be installed, under appropriate conditions, to ex-tract excess flue gas energy and effectively increase theboiler efficiency. Blowdown heat recovery equipmentcan also be installed, for some systems, to extract heatfrom the blowdown stream that would be otherwiselost. An economic analysis is needed to determinethe feasibility of the opportunity, and qualified pro-fessionals should design and install the equipment.

The quality of the boiler steam also is important.High-quality dry saturated steam has 100 percentquality (the amount of steam divided by the total waterand steam, expressed as a percentage) and containsno water droplets. Wet steam has a lower quality andcontains water droplets. Generating wet steam in yourboiler can cause many system problems, includinginefficient process heat transfer, steam trap failures,equipment failure by water hammer, corrosion, anddeposits and erosion.

Some typical causes for creation of wet steam andboiler carryover are wide swings in boiler water level,reduced operating pressure, boiler overload and poorboiler total dissolved solids (TDS) control [1]. A criti-cal step to ensuring generation of high-quality steamis to measure steam quality out of the boiler. Thistypically is done using a steam calorimeter.

Steam Distribution, End Use, and RecoveryThese questions will help identify operating practicesand improvement opportunities for steam distribu-tion, end use, and recovery:

Can pressure reducing valves (PRVs) be replacedwith backpressure turbines in the steam system?Are steam end-user needs being considered?How much available condensate is recovered andused?Is high-pressure condensate being utilized to pro-duce usable low-pressure steam?

In many steam systems, PRVs are used to providesteam at pressures lower than those generated from


26

the boiler. A steam system potentially can be im-proved by minimizing the flow of steam throughPRVs. One way to do this is to replace PRVswith backpressure turbines that provide low-pres-sure steam and generate electricity for use. Deanalyses must be performed to evaluate this typeof opportunity.

Steam end-user needs also must be considered.In many industrial steam systems, process steamusers are being asked to handle different productparameters, including weights and dryness, pro-cess temperatures and process flows. At the sametime, they are required to maintain safe and effi-cient operations. Steam process operators needto attend to proper equipment installation andprocess control, measurement of process inputsand outputs, and measurement of individualproduct metrics (unit of product per pound ofsteam needed).

Recovering and returning a substantial portionof your condensate to the boiler can have bothenergy and chemical treatment benefits. Con-densate is hotter than makeup water, so less en-ergy is required to convert condensate to steam.Condensate also requires significantly less chemi-cal treatment than makeup water, so chemicaltreatment costs associated with returning conden-sate are reduced. Increased condensate return alsocan reduce boiler blowdown, because fewer im-purities are resident in condensate, and minimizeblowdown energy losses.

REVIEWING MAINTENANCE PRACTICES

If an effective system maintenance program is inplace, the operating practices and operational im-provements discussed here can provide benefitsto plant steam operations year after year. Majorareas requiring maintenance include steam traps;boiler performance; water treatment; piping, heatexchangers, pumps, motors, and valves; and ther-mal insulation.

CONCLUSION

This article includes only some of the criticalsteam system areas that should be monitored andreviewed. Other important resources for improv-ing operations include steam system consult-

ants and service providers who can perform sys-tem assessments, troubleshoot performanceproblems and identify additional improvementopportunities. The DOE BestPractices Steameffort also offers tools and resources to assist steamusers in improving their operations. These re-sources are available on DOE’s website atwww.oit.doe.gov/bestpractices/steam.

REFERENCES

1. Glenn Hahn, October 1999. “Not-So-CandidCamera,” Engineered Systems, pp. 80.


Glenn HahnSpirax SarcoEmail: [email protected]: (610) 606-7087

Dr. Greg HarrellEnergy Management InstituteEmail: [email protected]: (423) 471-6098


Steam Digest 2001The Steam System Scoping Tool: Benchmarking Your Steam Operations Through Best Practices

27

ABSTRACT

The U.S. Department of Energy Office of In-dustrial Technology (DOE-OIT) BestPractices ef-forts aim to assist U.S. industry in adopting near-term energy- efficient technologies and practicesthrough voluntary technical-assistance programson improved system efficiency. The BestPracticesSteam effort, a part of the DOE-OIT effort, hasdeveloped a new tool that steam energy manag-ers and operations personnel can use to assess theirsteam operations and improve their steam energyusage - the Steam System Scoping Tool. Thispaper describes how the tool was developed, howthe tool works, and the status of efforts to im-prove the tool in the future.

INTRODUCTION

The U.S. Department of Energy (DOE) Officeof Industrial Technology (OIT) BestPracticesefforts aim to assist U.S. industry in adoptingnear-term energy-efficient technologies and prac-tices through voluntary technical-assistance pro-grams on improved system efficiency. There arenine industry groups - designated Industries ofthe Future (IOFs) - that are the focus of the OITefforts. These IOFs include Agriculture, Alumi-num, Chemicals, Forest Products, Glass, MetalCasting, Mining, Petroleum, and Steel.BestPractices efforts cover motors, compressed air,steam, and combined heat and power systems.

The overall goal of the BestPractices Steam effortis to assist steam users in adopting a systems ap-proach to designing, installing, and operatingboilers, distribution systems, and steam applica-tions. BestPractices Steam is supported by a Steer-

ing Committee of steam system users, steam sys-tem service providers, and relevant trade associa-tions. Within BestPractices Steam, a BestPracticesand Technical (BPT) subcommittee works to de-velop tools and resources to promote the overallBestPractices Steam mission.

In the summer of the year 2000, the BPT sub-committee completed the development of and re-leased a new tool called the Steam System ScopingTool. This tool was developed for use by steamsystem energy managers and steam system opera-tions personnel in IOF plants. The purpose ofthe Scoping Tool is to assist industrial users to:

Evaluate their steam system operations againstidentified best practices.Develop a greater awareness of opportunitiesavailable for improving steam system energyefficiency and productivity.Compare their Scoping Tool self-evaluationresults with those obtained by others.

This article describes how the Steam SystemScoping Tool was developed, presents an overviewof the major components of the tool, and discusseshow the present version of the tools is being evalu-ated and used.

HOW THE STEAM SYSTEM SCOPING TOOL

WAS DEVELOPED

In 1999, one of the goals the Steam BPT sub-committee set for itself was to develop a set of“Steam Assessment Guidelines” that steam userscould apply to assess their steam operations. Whatthe subcommittee initially envisioned as a set ofguidelines ultimately became what is now theSteam System Scoping Tool. The authors of thispaper (who co-chair the Steam BPT subcommit-tee) lead the activities of the subcommittee to de-velop the tool.

The major elements of the process that was usedto develop the Steam System Scoping Tool con-sisted of the following:

1. An initial list of steam system best practicefocus areas and questions was developed bythe subcommittee co-chairs. This list was then

The Steam SystemScoping Tool:Benchmarking YourSteam OperationsThrough Best PracticesAnthony Wright, Oak Ridge National LaboratoryGlenn Hahn, Spirax Sarco


28

circulated to BPT subcommittee members forcomment and addition. Subcommitteemembers have a variety of technical special-ties - for example, boiler systems, water treat-ment systems, steam traps, etc. Based on sub-committee review comments the focus areasand questions were modified; this review andcomment process was performed a numberof times.

2. Once there was preliminary agreement on fo-cus areas and questions, a set of possible re-sponses to Scoping Tool questions and sug-gested scores for these responses were devel-oped. Suggested scores were chosen to re-flect how well a specific steam system bestpractice was followed in a facility. These sug-gested question responses and scores wereagain reviewed by members of the BPT sub-committee.

3. As key focus areas, questions, and score re-sponses were developed, an approach for cat-egorizing the focus areas and questions wasdeveloped. Based on subcommittee mem-ber input, it was ultimately decided that themain categories should be profiling, totalsteam system, boiler plant, and distribution/end use/recovery.

Utilizing the expertise and input of the subcom-mittee members, the first evaluation version ofthe Steam System Scoping Tool was completedand released in August 2000.

OVERVIEW OF THE STEAM SCOPING TOOL

The present version (now called evaluation ver-sion 1.0c) of the Steam System Scoping Tool is ina Microsoft Excel spreadsheet format. TheScoping Tool includes seven individualworksheets:

1. Introduction2. Steam System Basic Data3. Steam System Profiling4. Steam System Operating Practices: Total

Steam System5. Steam System Operating Practices: Boiler

Plant6. Steam System Operating Practices: Distribu-

tion, End Use, Recovery7. Summary Results

The Steam System Scoping Tool is completed byanswering the questions in Worksheets #2 through#6. When a steam user completes Worksheet #2,profiling information about the steam system iscompiled. Some of the types of profiling infor-mation that can be entered into the Steam SystemBasic Data worksheet include:

Total annual steam production.Total steam generation capacity.Average steam generation rate.Distribution of fuel sources used to makesteam.Types of steam measurements made in theplant.Types of heat engines operated.

Answering the questions in Worksheets #3 through#6 assists steam users to perform self-evaluationsof their steam systems. Table 1 illustrates the keyimprovement areas and the total scores availablefor those areas in the present version of the ScopingTool. The present version of the Tool contains atotal of 25 questions in the improvement areaslisted in Appendix 1.

Appendix 2 shows an example screen from one ofthe Scoping Tool worksheets - the worksheet forSteam System Profiling. It also shows the actualquestions asked in the Tool under the areas ofsteam costs, steam/product benchmarks, and steamsystem measurements, and the Tool scores avail-able for different answers to these questions.

Once questions in Worksheets #2 through #6 arecompleted, the Tool automatically summarizes theanswers that were provided. The user can see andprint a summary of the Scoping Tool results usingthe Summary Results Worksheet #7.

Performing a steam system self-assessment usingthe Steam Scoping Tool can help users evaluatesteam system operations against the best practicesidentified in the tool, and can help the users iden-tify opportunities to improve steam system op-erations.


29

Through December 31, 2000, more than 100 re-quests have been made for the Scoping Tool.

The present version of the Tool is still being des-ignated as an “evaluation” version because the sub-committee is attempting to obtain end user sug-gestions for improving it. One effort underwayto get end user feedback is through a Steam ToolBenchmarking project being performed with sixof the U.S. DOE Industrial Assessment Centers(IACs). There are 26 IACs, located at universitiesaround the country, that perform comprehensiveindustrial assessments at no cost to small and me-dium-sized manufacturers. Six of these IACs - atthe University of Massachusetts-Amherst, theUniversity of Tennessee-Knoxville, OklahomaState University, San Francisco State University,South Dakota State University, and North Caro-lina State University - are each performing three1-day plant steam assessments utilizing the SteamSystem Scoping Tool. Feedback from these 18steam assessments will be used to improve thepresent version of the Tool.

A web-based version of the Steam Scoping Tool isavailable through the IOF BestPractices websiteat www.oit.doe.gov/bestpractices/. Steam userscan complete the Scoping Tool directly on line,print the results, and submit the results directly toan on-line database that is integrated with the webversion of the Tool.

FUTURE DEVELOPMENT EFFORTS FOR THE

STEAM SYSTEM SCOPING TOOL

The overall vision for the continued developmentand usefulness of the Steam System Scoping Toolis as follows:

1. Over the next six months, user feedback willbe obtained to confirm the usefulness of theTool, and to obtain suggestions for improve-ments to the Tool.

2. Based on Scoping Tool results that users pro-vide to BestPractices Steam, it will be possibleto develop benchmarks of averages responsesto the Scoping Tool questions.

3. Finally, the next step in the development ofthe Steam Scoping Tool is to expand its capa-bilities - so that, when steam users find areaswhere improvement is needed, the Tool willprovide guidance to the users.

CONCLUSIONS

The Steam System Scoping Tool was developedto encourage steam system energy managers andoperations personnel to evaluate their steam sys-tem operations and develop a greater awareness ofopportunities that may be available for improv-ing energy efficiency and productivity. In addi-tion, steam users are encouraged to provide theirScoping Tool results to BestPractices Steam, so thatresults from the users can be summarized. AllScoping Tool results obtained from steam userswill be held in strict confidence.

ACKNOWLEDGMENTS

BestPractices Steam would like to thank and ac-knowledge Spirax Sarco Inc. for co-directing theoverall effort to develop the Steam Scoping Tool,and the following organizations who participateon the Steam Best Practices and Technical sub-committee and who assisted in reviewing and de-veloping the Scoping Tool:

Armstrong International, Inc.Construction Engineering Research LabDupontElectric Power Research InstituteEnbridge Consumers Gas in CanadaEnercheck Systems, Inc.Energy Research and Development CenterInstitute of Textile TechnologyIowa Energy CenterInstitute of Paper Science and TechnologyJohns ManvilleLawrence Berkeley National LaboratoryNALCO ChemicalOak Ridge National LaboratoryRock Wool Manufacturing Inc.Sappi Fine Paper, North AmericaVirginia Polytechnic InstituteWashington State University


Glenn HahnSpirax SarcoEmail: [email protected]: (610) 606-7087


30


OIT ClearinghouseEmail: [email protected]: (800) 862-2086


31

APPENDIX 1. Summary Of Key Improvement Areas And Available Scores In The Steam System Scoping Tool

IMPROVEMENT WHAT TO DO AVAILABLE AREA SCORE

STEAM SYSTEM PROFILING

Steam Costs Identify what it costs at your facility to produce steam (in units of $/1000 lbs) and use 20this as a benchmark for evaluating opportunities for improving your steam operations.Start by determining what your fuel costs are to make steam, then add other costsassociated with your operations (chemical costs, labor, etc).

Steam/Product Identify how much steam it takes to make your key products. Then track this benchmark: 20Benchmarks a) with what other facilities in your company do; b) with what your competitors do; and

c) with how this benchmark varies in your operations over time.

Steam System Identify key steam operational parameters that you should monitor and ensure that you 50Measurements are adequately measuring them.

STEAM SYSTEM OPERATING PRACTICES

Steam Trap Implement a comprehensive program to correctly select, test, and maintain your 40Maintenance steam traps.

Water Treatment Implement and maintain an effective water treatment program in your steam system. 30Program

System Insulation Ensure that the appropriate major components of your steam system are well insulated. 30Determine the economic insulation thickness for your system components, and performsystem insulation reviews to identify exposed surfaces that should be insulated and/orunrestored or damaged insulation.

Steam Leaks Identify and quickly repair steam leaks in your steam system. 10

Water Hammer Detect and quickly eliminate water hammer in your steam system. 10

Maintaining Effective Establish and carry out a comprehensive steam system maintenance 20Steam System program.Operations

BOILER PLANT OPERATING PRACTICES

Boiler Efficiency Measure/trend/look for opportunities to improve your boiler efficiency. 35

Heat Recovery Evaluate installation of heat recovery equipment in your boiler plant. 15Equipment

Generating Dry Ensure that you generate high-quality dry steam in your boiler plant. 10Steam

General Boiler Ensure that your boilers perfrom their functions without large fluctuations in operating 20Operation conditiions.

STEAM DISTRIBUTION, END USE, RECOVERY OPERATION PRACTICES

Minimize Steam Investigate potential to replace pressure-reducing valves with back-pressure turbines in your 10Flow Through PRVs steam system.

Recover and Utilize Determine how much of your available condensate you recover and utilize. 10Available Condensate

Use High-Pressure Investigate use of high-pressure condensate to produce useable low-pressure steam. 10Condensate to MakeLow-Pressure Steam

TOTAL AVAILABLE STEAM SCOPING TOOL SCORE 340


32

APPENDIX 2. Steam Scoping Tool Example Screen - Steam System Profiling

Steam Costs

What To Do Identify what it costs at your facility to produce steam (in units of $/1000 lbs.), and use this as a benchmarkfor evaluating opportunities for improving your steam operations. Start by determining what your fuel costs are to makesteam, then add other costs associated with your operations (chemical costs, labor, etc.)

Why Important Understanding the cost to make steam can be an eye-opener—producing steam is not free! Anyopportunity that reduces the amount of steam generated saves money, so understanding the cost to make steam is a keystep to being able to quantify improvement opportunities.

ACTIONS SCORE YOUR SCOREDo you monitor your fuel cost to generate steam in terms of yes 10($) / (1000 lbs. of steam produced)? no 0How often do you calculate and trend your fuel cost to generate at least quarterly 10steam? at least yearly 5

less than yearly 0

Steam/Product Benchmarks

What To Do Identify how much steam it takes to make your key products. Then track this benchmark: a) with what otherfacilities in your company do; b) with what your competitors do; and c) with how this benchmark varies in your operationsover time.

Why Important The bottom line of your operation is how effectively you make your products, and steam use has animpact on your productivity. Steam/product benchmarking is an excellent way to monitor productivity and how steamimprovements translate to improved productivity.

ACTIONS SCORE YOUR SCOREDo you measure your steam/product benchmark in terms of lbs. yes 10of steam needed/unit of product produced? no 0How often do you measure your steam/product benchmark - in terms at least quarterly 10of lbs. of steam needed/unit of product produced? at least yearly 5

less than yearly 0

Steam System Measurements

What To Do Identify key steam operational parameters that you should monitor and ensure that you are adequatelymeasuring them.

Why Important You can’t manage what you don’t measure! Measurement of key steam system parameters assists youin monitoring your system, diagnosing potential system problems, and ensuring that system improvements continue toprovide benefits to your operations.

ACTIONS SCORE YOUR SCORE

Do you measure and record critical energy?Steam Production Rate (to obtain total steam) yes 10Fuel Flow Rate (to obtain total fuel consumption) yes 6Feedwater Flow Rate yes 6Makeup Water Flow Rate yes 4Blowdown Flow Rate yes 2Chemical Input Flow Rate yes 2

no to all above 0How intensely do you meter your steam flows? by major user/ 20

CHOOSE ONE OF FIVE ANSWERS equipmentby process unit 10by area or bldg. 5by entire plant 2not at all 0

Steam Digest 2001The Enbridge Consumers Gas “Steam Saver” Program

33

ABSTRACT

This paper describes the Enbridge Consumers GasSteam Saver Program. It gives results for a four-year period up to the end of December, 2000. Itwas presented at the March 2001 Energy confer-ence sponsored by CIPEC, Natural ResourcesCanada and The Canadian Auto PartsManufacturer’s Association.

In Canada, medium-sized and large-sized steamplants consume approximately 442 billion cubic feet(12.5 billion cubic metres) of natural gas annually.This is 25% of all natural gas delivered to all cus-tomers. (Small steam plants and hydronic heatingboilers consume another 15 percent.)

Enbridge Consumers Gas, a local gas distributioncompany located in Toronto, has approximately 400industrial and institutional customers who ownmedium-sized or large-sized steam plants.

During the past four years, Enbridge has devel-oped a comprehensive steam energy efficiency pro-gram called “Steam Saver.” This program is aimedat these 400 customers. The heart of this programis the boiler plant audit and performance test.

This paper describes the fuel-saving results for 41medium-sized and large-sized boiler plants whereaudits have been completed and projects have beenimplemented.

INTRODUCTION

Enbridge Consumers Gas is a natural gas distribu-tor whose franchise service area includes the GreaterToronto area, Ottawa, Eastern Ontario and theNiagara Penninsula. The gas utility has 1.4 millioncustomers including 1200 large volume customers.

In 1994, the Ontario Energy Board required thetwo main gas utilities in this province to imple-ment energy efficiency programs.

In 1997, Enbridge Consumers Gas introducedthe “Steam Saver Program,” a boiler plant auditwhich is aimed at large volume industrial and in-stitutional customers with steam plants.

Since 1997, 41 steam plants have been auditedand 1.4 billion cubic feet (40 million cubic metres)of energy-saving opportunities have been identi-fied. This represents 12 percent of the total natu-ral gas consumed by these plants.

In 1999, several new programs were introducedto focus on other opportunities to save steam en-ergy. These programs include Steam Trap Sur-veys, Steam Pressure Reduction, CombustionTune-ups and Plant Metering. These new pro-grams have identified further savings.

The role of the gas utility is to facilitate the iden-tification and implementation of fuel-savingprojects. The utility is in a unique position to dothis by virtue of its existing sales force, knowledgeof the market, and its reputation for providingunbiased technical assistance.

THE PRICE OF NATURAL GAS

Since the beginning of this program, the price ofnatural gas and other fuels to large industrial cus-tomers has increased dramatically. As a conse-quence, the average financial payback period forthe entire range of steam-saving projects identi-fied has dropped from three years to a simple pay-back of 1.1 years:

The Enbridge ConsumersGas “Steam Saver”ProgramBob Griffin, Enbridge Consumers Gas

THE STEAM BOILER POPULATION

Ontario is the most heavily industrialized prov-ince in Canada. With a population of 12 millionpeople and an industrial base of some 5000 manu-facturing companies (larger than 50 employees),it can be compared in size and industrial outputwith Michigan or Ohio.

Year Burner Tip Price ofNat. Gas ($ per CU M)

Average Payback onSteam Saving Prj.

1997199819992000

$0.10$0.12$0.16$0.30

3.1 years2.7 years2.0 years1.1 years


34

All major industrial sectors are represented. Theautomotive, pulp and paper and steel industriesare particularly large energy and steam users. Foodand beverage processors and the petrochemicalindustry are also heavy steam consumers.

The Enbridge Consumers Gas franchised servicearea includes approximately one-third of theProvince’s industry and half of its large institu-tions.

TABLE 1: Boiler Population for Steam Plants with Annual Fuel Consumption GreaterThan 70 Million Cubic Feet (2 million cubic metres) of Natural Gas

Note: All figures exclude large electric utility plants. BCF/YR = Billion Cubic Feet per Year B CU M/YR = Billion Cubic Metres per Year

TABLE 2: Fuel Consumed by Medium-sized and Large-sized Boiler Plants--Ontario

Note: Most plants burning wood co-fire with natural gas. Most oil is consumedby customers with interruptible gas contracts operating under gas curtailment conditions.

The Steam Saver program is aimed at industrialconsumers and also medium-sized and large-sizedinstitutions such as hospitals, defense bases anduniversities. These facilities have central heatingplants which are increasingly moving to co-gen-eration to supplement steam production and ab-sorption chilling to level out the seasonal demand.

FUEL CONSUMPTION IN BOILER PLANTS

While the foucs of Enbridge’s efforts to improveefficiency in steam plants is natural gas, steam ef-ficiency can equally be applied to plants whichburn other fuels. Any of the efficiency programsdescribed here can be applied to oil, wood, or coalfired plants.

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In Ontario, fuel consumption in the target mar-ket (medium-sized and large-sized plants) breaksdown approximately as follows:


35

THE “STEAM SAVER” PROGRAM

The Regulatory and Financial BackgroundThe Ontario Energy Board (O.E.B.) is the regu-lating agency for the two gas utilities and theelectric utilities in this Province. In 1994, theO.E.B. required the gas utilities to implementenergy efficiency programs for all market sectors.In 1999, the O.E.B. and Enbridge negotiated aspecial financial arrangement called the “SharedSavings Mechanism”. This arrangement sets tar-gets in terms of natural gas volumetric savingswhich must be implemented by Enbridge eachfiscal year. If Enbridge fails to meet the annualtarget, it pays a heavy financial penalty which islevied through the rate base. On the other hand,if the utility exceeds the target, it receives a sig-nificant financial reward by the same means. Thepenalty or reward is directly proportional to theenergy efficiency volume shortfall or excess com-pared to the target figure. The formula for calcu-lating the penalty or reward is complex. In gen-eral it is based on the estimated societal benefits.Enbridge’s share of the total benefit is a percent-age of the total figure. This arrangement hasprovided a major financial incentive for Enbridgeto implement energy efficiency programs.

Description of the Steam Saver ProgramThe Steam Saver Program began in 1997 as asingle activity-the steam plant audit and perfor-mance test. It has since been expanded to in-clude specific programs designed to achieve sav-ings sooner, for smaller customers, and at less cost.The performance test and audit is still the largestactivity but programs such as the Steam Trap Sur-vey are generating rapidly growing results. A newprogram, The Combustion Tune-up Program, hasreceived an excellent early response from custom-ers.

The Steam Plant Performance Test andAuditWhy Do a Boiler Plant Audit? The purpose ofthe steam plant performance test and audit is:

To identify fuel savings opportunitiesProvide economic data to the customer(Benchmarking)

Who Qualifies for an Audit? All customers hav-ing boiler plants which consume more than 2million CU M/YR (70 million CU FT/YR) ormore of natural gas qualify.

Who is Responsible for the Audit? After theEnbridge Energy Management Consultant (EMC)sells an audit to a customer he assumes the projectresponsibility for organizing the field work andcoordinating the report.

Enbridge contracts with outside specialized steamengineering consultants to do the audit, but par-ticipates in the testing and site work. Enbridgesupplies and maintains combustion analyzers andother test equipment.

How is an Audit Done? The audit field work andreport proceed according to a standard format(which can be tailored for specific customer re-quirements and circumstances). Here is the stan-dard procedure and report format which has beendeveloped over three years:

1. Field Work First -This is a crucial part of theprocess. The auditors must establish a friendlyrelationship with the plant management and op-erators. There is often an air of suspicion in boilerplants because of the fear of criticism or job loss.The watchword here is diplomacy.

The Enbridge EMC spends two or three days inthe customer’s plant with the outside engineeringconsultant.

Combustion Tests are done on all boilers takingcombustion and temperature readings at four orfive points between low and high fire.

The boiler plant is inspected with a view to iden-tifying problems or losses. Features such as econo-mizers, air pre-heaters, blow down heat recovery,excessive venting and instrumentation are all con-sidered.

The boiler plant supplies its records to the audi-tors. These may include a wide variety of daily ormonthly operating reports, operators’ logs, watertreatment records and even previous test reports.Many plants have very poor records or almost noneat all.


36

2. The Audit Report - The audit report is com-pleted by the steam consulting engineer togetherwith the Enbridge EMC who usually writes partof the report.

The standard report comprises eight sections asfollows:

Executive SummaryA listing of energy saving opportunities completewith savings and capital cost estimate.

Section 1-Plant Energy HistoryA summary of operating data for the past year.We rely heavily on the hourly gas consumptioninformation from the utility gas meter (TheMetretek System). Combustion test results andsteam plant log data are also employed. The re-sult is a comprehensive report on fuel consump-tion, steam production, peaks and averages, blowdown rate, water make-up, electricity and so on.

This section also includes cost data andbenchmarking for the larger plants.

Section 2-Equipment ListNameplate and rating data from all boilers andother major equipment in the plant.

Section 3-Combustion Test DataCalculation of losses using the ASME power testcode method and efficiency graphs for all boilers.

Section 4-Plant Inspection ReportObservations and comments on the plant design,equipment condition, and suggestions for im-provements to save energy

Section 5-Steam Loads and DistributionObservations about the steam distribution sys-tem and comments on the nature of loads. Spotobvious opportunities to save such as excessiveventing of condensate receivers, condensate notreturned, uninsulated piping and so on.

Section 6-Water TreatmentA general review of the water treatment records.Comments on blow-down, maintaining targetlevels of sulphite, PH and alkalinity.

Section 7-Savings and Capital CostCalculations showing the savings estimates foreach project.

Section 8-Safety IssuesComments on conditions such as high carbonmonoxide levels in flue gas, natural gas leakageand steam leakage.

The Cost Of Doing A Steam PlantPerformance Test And AuditThe following is the average direct cost of 41 au-dits completed to date. It excludes administrativeand marketing costs.

Steam Engineering Consultant Fee $ 8,500Travel Expenses $ 600Enbridge EMC’s Time $ 4,250 Total $ 13,350

Note: The Average Hourly Rate is $ 85/HR

Enbridge pays two thirds of the consultant fee upto a maximum of $5,000. On average, therefore,Enbridge pays the maximum of $5000 and thecustomer pays $3,500 for the audit.

Results Of 41 Steam Plant PerformanceTests And AuditsThe results of 41 steam plant audits performedsince 1997 are shown in Table 3 (see next page).Twenty six of the audits were industrial custom-ers. The remaining 15 customers are central heat-ing plants in hospitals, universities, one nationaldefense base and other federal government facili-ties.

WHERE DO THE SAVINGS COME FROM?

Table 4 (located on page 35) provides a break-down of the results of the steam plant auditsand other programs by type of project.

The top projects in terms of savings identified are:

Boiler Room Capital ProjectsThe payback on major boiler replacement projectsis now 3.2 years, down from 7.5 years in 1999.Enbridge’s role in affecting energy savings is towork with customers who are making major in-vestments at the planning stage in order to pro-


37

vide technical and financial assistance to optimizeefficiency. Boiler sizing and selection, heatrecovery, metering, and other decisions come intoplay.

Combustion ImprovementsCombustion improvements are almost universallyrequired. The payback on projects such as boiler

TABLE 3: Total Results Of Steam Plant Performance Tests And Audits Excluding NewPrograms For 1999

tune-up, repair of burners, fuel air ratio compo-nents and blowers is less than one year.

Heat Recovery ProjectsNew economizers, blow-down heat recovery andcondensing heat recovery projects identified thelargest single category of improvement. The av-erage payback of 1.1 years is very attractive.

Steam Distribution System Improvementsand Trap RepairTrap repairs, replacement, improved condensatereturn and other projects are an attractive invest-ment with an average simple payback of 0.4 years.

NEW STEAM SAVER PROGRAMS

Several new Steam Saver programs were intro-duced in 1999. The purpose was to take advan-tage of the findings of the Steam Plant Auditswhich are summarized in Table 4; that is, to tar-get the main savings areas without having to con-duct an expensive study oF the boiler plant. This

also allows Enbridge to extend the Steam SaverProgram to smaller plants and to reduce thesales/implementation cycle time.

The Steam Trap SurveyThe steam trap manufacturers have considerabletechnical expertise in the application and testingof steam traps.

Many steam distribution systems are poorly de-signed and maintained, resulting in major lossesof energy in steam and condensate.

Our approach has been to team up with the steamtrap manufacturers, including Spirax Sarco,Preston-Phipps (Armstrong) and Nutech (TLV)to conduct steam trap surveys.

Enbridge funds 50% of the survey cost. The sur-vey is conducted by the supplier’s technicians.

This includes tagging all traps, testing all trapsand providing a critique of the system design prob-lems where applicable.

Besides leaking traps, there are a range of com-mon problems found:

Condensate return pump failure and conden-sate dumping to drain.Condensate return lines too small causingback-up of condensate into coil or heat ex-changer.

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lliBsaGlaunnA noilliM001$ ____

deifitnedIstcejorPsgnivaSforebmuN 302 ____

deifitnedIsgnivaSleuFlaunnA RY/TFUCnoilliB4.1 RY/MUCnoilliM1.04

deifitnedIsgnivaSralloDlaunnA noilliM0.21$ ____

lliBsaGlaunnAfosgnivaStneCreP %21 ____

deifitnedIstcejorPfotsoClatipaC noilliM5.31 ____

deifitnedIstcejorPfokcabyaPegarevA sraey1.1 ____

detnemelpmIstcejorPsgnivaSforebmuN 93 ____

detnemelpmIsgnivaS.loVsaGlaunnA RY/TFUCnoilliM873 RY/MUCnoilliM7.01

detnemelpmIsgnivaSralloDlaunnA noilliM2.3$ ____


38

TABLE 4: Steam Saver Programs Summary of Results By Type of Project

NORMALIZED FUEL COST $0.30 PER CU M

IDENTIFIED SAVINGS PROJECTS IMPLEMENTED

NO. TYPE OF PROJECT NO. OF ANNUAL DSM ANNUAL TOTAL CAPITAL AVERAGE ANNUAL ANNUALPROJECTS SAVINGS SAVINGS INVESTMENT PAYBACK SAVINGS SAVINGSIDENTIFIED CU M / YR $ YEARS CU M/YR $/YR

BOILER PLANT AUDITS

1 Combustion Improvements 45 6,076,909 $1,823,073 $725,700 0.40 3,065,890 $919,767Boiler tune-up, Combustion control repair,Burner repair, Repair existing oxygen trim system

2 Boiler Room Capital Projects 43 7,384,603 $2,215,381 $7,022,400 3.17 2,862,507 $858,752Replace old boiler, add summer boiler, changefeed-water pump, new feedwater system, newdeaerator, new flue gas uptake damper, turbinerepair, controls improvements

3 Heat Recovery and Economizer Projects 37 1 1,809,148 $3,542,744 $4,054,322 1.14 1,973,473 $592,042Add new economizer, repair existing economizer,add new condensing heat recovery economizer,add new blow down heat recovery system

4 Operating Changes in Boiler Room 22 4,305,097 $1,291,529 $112,732 0.09 1,791,242 $537,373Reduce deaerator venting, reduce boilerblow-down, shut down boilers on weekends andoff-hours, use existing F.W. turbine, fewerboilers operating

5 Steam Distribution Piping and Condensate 37 6,658,379 $1,997,514 $686,500 0.34 1,020,457 $306,137Improvements (Excluding Steam TrapProgram) New steam piping, new condensatepiping and receivers, consolidate steam pipingof different pressures, repair condensate pumps,new control valves, recover flash steam fromtanks, includes repairs to steam process equipment

6 Building HVAC Changes and Capital Projects 7 2,535,190 $760,557 $490,000 0.64 0 $0New air handler controls, new temperature setback controls, close building doors in winter,turn off steam heaters in summer, convertsteam coils to direct firing-natural gas

7 Insulation Improvements 3 885,650 $265,695 $286,000 1.08 0 $0Insulate oil storage tanks, insulate steam piping

8 Other Projects 9 405,000 $121,500 $75,000 0.62 0 $0Clean boiler waterside, improve water treatment, clean heatexchangers

TOTAL BOILER PLANT AUDITS 203 40,059,976 $12,017,993 $13,452,654 1.12 10,713,569 $3,214,071

9 Steam Pressure Reduction 6 1,814,490 $544,347 $0 1,814,490 $544,347Central Heating Plants

10 Steam Trap Survey Program 38 4,116,753 $1,235,026 $548,961 2,327,712 $698,314

11 New Boiler Plant Program 2 525,000 $157,500 $1,307,352 400,000 $120,000

12 Metering and Monitoring Program 2 476,000 $142,800 $185,000 476,000 $142,800Install new steam, gas, water meters, repairand calibrate existing, install computerizeddata acquisition system

TOTAL OTHER PROGRAMS 48 6,932,243 $2,079,673 $2,041,313 5,018,202 $1,505,461

TOTAL RESULTS BY TYPE OF PROJECT 251 46,992,219 $14,097,666 15,493,967 1.10 15,731,771 4,719,531


39

Wrong type of trap for the application, over-sized or undersized traps.No strainers.Missing piping insulation.

TABLE 5. Results of Steam Trap Surveys

The Steam Pressure Reduction ProgramThis program is aimed at central heating plantswhere steam is produced at 100 to 250 psig, dis-tributed to remote locations, and then reducedin pressure to 15 psig or lower.

Theoretically, energy is saved when the mainsteam pressure is reduced because:

The boiler stack temperature is reduced.Piping radiation losses are reducedLeaks in traps and other sources are reduced.

The success of this measure depends on the factthat most central heating plants are over-sized.Boiler tubes and steam piping can accommodatethe increase in the specific volume of the steamwithout undue pressure loss. We have conductedinitial tests at six plants and are now monitoringthe benefits over a longer period. The true sav-ings have ranged from 3 percent of the total gasconsumption to 8 percent in one case. It appearsthat savings are greatest when the pressure is re-duced below 70 psig.

The New Boiler Plant ProgramThe boiler population is aging. In Ontario,records indicate that the average age of registeredsteam boilers is 26 years.

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tnemtsevnIlatipaC 169,845$

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detnemelpmIstcejorP 91

detnemelpmIsgnivaS 313,896$

Most new boilers sold are for replacement, al-though there are a few green-field boiler plantprojects every year.Many replacement boilers are installed withoutproper analysis, planning or attention to energyefficiency features.

The Enbridge New Boiler Program is designed tomotivate owners to plan properly and consider en-ergy saving features. This program provides fi-nancial incentives to companies who plan to in-stall new or replacement boilers if they includethe following package of energy efficiency mea-sures:

1. Right Sizing the Boilers - In the past, boilerplants were much oversized by design. This wasjustified on the basis of future growth. Manyplant owners are now paying a high penalty forthe added losses of operating the boiler plant onlow fire.

Enbridge offers technical help to customers insizing based on load analysis and fuel consump-tion history. We have unique expertise in fore-casting plant and heating loads and apply this ex-perience at no charge to customers who are plan-ning replacement or expansion of boiler plants.

2. Economizers - Economizers can improve an-nual boiler efficiency by as much as 5 percent.However an engineering analysis which takes ac-count of the load profile is required to correctlyestimate the savings attributable to the additionalinvestment required to install an economizer.

3. Blow Down Heat Recovery - Part of the NewBoiler Plant package is to consider implement-ing blow-down heat recovery in the new boilerplant.

4. Fuel and Steam Metering - One of the mostneglected areas of the boiler plant is metering.New plants are encouraged to invest in steam andfuel metering. This is part of the incentive pack-age offered to owners of new boiler plants.

The Boiler Combustion Tune-Up ProgramUnnecessary combustion losses account for nearly2 percent of the total fuel consumed by steamboiler plants. There is an existing infrastructure


40

TABLE 6: Total Results Of Steam Saver Program Including New Programs to End of Year 2000

of boiler service companies who are capable oftesting and repairing boiler combustion problems.

This program is designed to encourage steam plantowners to maintain the combustion of their boil-ers through their present boiler service companiesor to do it themselves.

Enbridge has designed a program which pays theowner to test and tune-up his boilers twice peryear.

The terms of this program are that the owner mustsubmit combustion test results in order to be paid.The incentive grant is:

$ 130 per boiler per tune-up for boilerssmaller than 600 boiler horse power

$ 230 per boiler per tune-up for boilers 600boiler horsepower and larger.

Metering and Energy Management forBoiler PlantsMetering of fuel and steam is an often-neglectedaspect of steam plant operation. The boiler plantshould be regarded by corporate managementas a cost center.

Fuel now accounts for 85 percent of the cost ofoperating a boiler plant.

It is imperative in most cases that the fuel input tothe boiler plant be reported regularly. This is a

bare minimum for responsible cost management,yet this requirement is often not met.

Low cost data acquisition systems make it fea-sible to automatically collect fuel consumptionand other boiler plant data and produce regularreports for management use.

The average cost of operating a large boiler plantaccording to Steam Saver audits of manned plantsis over $5 million per year. Enbridge offers in-centive grants to steam plant operators who areprepared to install metering and energy manage-ment systems.

CONCLUSIONS

In the past three years, The Steam Saver Programhas demonstrated that, on average, fuel savingsof 14 percent of total annual fuel consumptioncan be achieved. The 251 projects identified in89 plants have shown an average payback of 1.1years.

73 of these projects saving 554 million cubic feet(15.7million cubic metres) of natural gas annu-ally have been implemented. This represents 4percent of total fuel consumption. Enbridge cus-tomers are saving $4.7 million annually on theseprojects.

The rate at which savings are identified andimplemented is growing rapidly. This is due to:

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41

The growing effectiveness of the EnbridgeEnergy Management consultants.Capital projects require an average of 18months to implement. There are moreprojects in the pipeline now after four yearsof conducting audits.Recently, the rapid rise in natural gas priceswhich has motivated plant owners to bettermanage their energy costs.New programs introduced in 1999 were de-signed to accelerate the process of implement-ing energy saving projects. These are nowshowing results.

The best projects for saving energy in a steam plantare:

Combustion improvements.Heat recovery projects.Steam trap and distribution system mainte-nance and repair.Boiler replacement with proper sizing, selec-tion, and metering.

STEAM COST AND PLANT BENCHMARKING

The steam plant audits include a feature whichprovides each customer with an estimate showingthe cost of steam and other plant operating vari-ables, compared to the average steam plant. Thisis a useful tool for management to benchmark theiroperation. The average cost of steam for 15 largesteam plants in year 2000 was $13.72 per thou-sand lb. This is an increase of 70 percent over1999. Table 7 (see next page) gives details onaverage and total steam costs for these plants.


Bob GriffinEnbridge Consumer GasEmail: [email protected]: (416) 495-5298


42

TABLE 7 - Steam Cost

Average Cost and Performance for 15 Large Boiler PlantsYear 1999 vs. Year 2000

AVERAGE PLANT PERFORMANCE

Date of Audit

Type of Steam Load

Installed Boiler Capacity (LB/H)

Rated input of “ON” boilers (BTU/HR)

Annual Gas Consumption (MILLION CU M)

includes equivalent btu value of oil

Average Hourly Gas Cons. (CU M/HR)

Peak Hourly Gas Consumption (CU M/HR)

Operating Hours/YR

Average Combution Efficiency (%)

Average Plant Efficiency (%)

Operating Pressure (PSIG)

Total Enthalpy at Operating Pressure

Steam Net Added Enthalpy for Site (BTU/LB

Annual Steam Production (LB)

Average Hourly Steam Poduction (LB/HR)

Peak Hourly Steam Load (LB/HR)

Make-up Water Annual Consumption

MILLION IMP. GAL.

Electricity Annual Consumption (KWH/YR)

Average Blow-Down Rate

Blow-Down Heat Recovery

Estimated Vent Losses (BTU/HR x 1000)

1997 to 2000

Heating and Process

163,560

113,329

14.6

1,689

3,125

8,640

82.00%

77.00%

1,204

1,052

369,750,784

43,019

80,451

19.2

1,149,957

5.60%

300

1997 to 2001

Heating and Process

163,560

113,329

14.6

1,689

3,125

8,640

82.00%

77.00%

1,204

1,052

369,750,784

43,019

80,451

19.2

1,149,957

56.0%

300

FUEL COST Cost for Year 1999$0.16

Cost for Year 2000$0.30→ Per CU MPer CU M

Steam Cost Total Annual Cost Annual Average Average Total Annual Cost Annual Average Average 15 Sites Yr 1999 Cost per Site Cost/KLB 15 Sites Yr 2000 Cost Per Site Cost/KLB

FUEL $34,628,550 $2,308,570 $6.244 $64,928,531 $4,380,000 $11.846Electricity $1,184,829 $78,989 $0.214 $1,184,829 $78,989 $0.214Water $810,006 $54,000 $0.146 $810,006 $54,000 $0.146Water Treatment Chemicls $627,484 $41,832 $0.113 $627,484 $41,832 $0.113Operating Labor $4,555,827 $303,722 $0.821 $4,555,827 $303,722 $0.821

Total Operating Cost $41,806,696 $2,787,113 $7.538 $72,106,677 $4,858,543 $13.140

Maintenance CostsMtce. Lobor (internal)Mtce. Contracts incl parts and laborSubtotal Maintenance Cost $3,005,028 $214,645 $0.581 $5,634,428 $214,645 $0.58

Total Annual Operating Cost $44,811,724 $3,001,758 $8.118 $77,741,105 $5,073,188 $13.72

Steam Digest 2001A Highly Successful Holistic Approach to a Plant-Wide Energy Management System

43

A Highly SuccessfulHolistic Approach to aPlant-Wide EnergyManagement SystemFrederick P. Fendt, P.E., Rohm and Haas Company

ABSTRACT

In the course of more than twenty years as anengineer involved directly in utility relatedprojects in a number of industries, I have seen agreat variety of energy efficiency projects and pro-grams covering the entire spectrum of efficacy.The Deer Park, Texas, plant of the Rohm andHaas Company has a unique energy managementprogram that has proven to be highly successful.This program has resulted in a 17 percent reduc-tion in energy use on a per pound of productbasis, saving 3.25 trillion btus and $15 millioneach year! This article discusses this program, itshistory, successes, and the unique characteristicsthat have contributed to those successes.

THE ROHM AND HAAS COMPANY

For more than 90 years, Rohm and Haas has beena leader in specialty chemical technology. Ourchemistry is found today in paint and coatings,adhesives and sealants, household cleaning prod-ucts, personal computers and electronic compo-nents, construction materials and thousands ofeveryday products. In every corner of the world,Rohm and Haas products are “Quietly Improv-ing the Quality of Life.™”

Rohm and Haas Company is one of the world’slargest manufacturers of specialty chemicals –technologically sophisticated materials that findtheir way into applications in a variety of majormarkets. Most Rohm and Haas products are neverseen by consumers; rather, they are used by otherindustries to produce better-performing, highquality end-products and finished goods. The his-tory of Rohm and Haas has been a series of inno-vative technical contributions to science and in-dustry, usually taking place behind the scenes.

In 1999, Rohm and Haas acquired two great com-panies – LeaRonal, a maker of electronic chemi-cals, and Morton International, a global producerof specialty chemicals and salt. These acquisitionshelped grow the company into today’s Rohm andHaas, with sales of $6.5 billion and more than20,000 employees. It operates approximately 150research and manufacturing locations in 25 coun-tries.

Rohm and Haas is committed to sustainable de-velopment and has pledged to strive to ensure thatoperations and products meet the needs of thepresent global community without compromis-ing the ability of future generations to meet theirneeds. Economic growth, environmental protec-tion and social responsibility are integral consid-erations in the company’s business decisions.

ROHM AND HAAS’ DEER PARK FACILITY

The Rohm and Haas Deer Park, Texas, facility hasoperated for over 52 years and is located on theHouston Ship Channel approximately 22 mileseast of downtown Houston. The site is over 900acres and employs more than 800 people. It servesas Rohm and Haas Company’s flagship plant andis the largest monomer manufacturer for key Rohmand Haas products. The plant manufactures inexcess of 2 billion pounds of chemical productsannually including methyl methacrylate and vari-ous acrylates. Accordingly, this plant, alone, ac-counts for approximately 35 percent of all Rohm& Haas’ corporate energy consumption.

Relative Energy Use at the Twenty LargestEnergy User Facilities for Rohm and Haas

These chemical monomers form the buildingblocks for other Rohm & Haas products, so theenergy efficiency at the Deer Park plant translates


44

across the entire supply chain, from chemical feed-stock to consumer end-products.

The plant consists of eleven different productionareas that operate as individual production facili-ties or “Plants Within A Plant” (PWP). Many ofthese processes are highly exothermic, and thus,much of Deer Park’s steam production results from“waste” heat sources. There are five steam use lev-els at the Deer Park Plant - 600, 150, 75, 35, &15 psi. Out of approximately 1,000,000 lbs/hr ofthe 600 psi steam load, the boiler house only pro-duces on average approximately 200,000 lbs/hr.All of the 150 psi and lower pressure steam is pro-duced by waste heat boilers, backpressure turbines,and let down stations. Much of the energy effi-ciency gains since 1997 have been achieved bycapitalizing on the optimization of cross processand overall plant utility integration – an overallplant systems approach between PWPs. Efficiencygains here also resulted from taking advantage ofthe plant’s large amount of by-product energy pro-duction. The PWPs are each independent withrespect to production demands, and yet, have ahigh degree of utility interdependence. Thus, amajor challenge was to better integrate this highlycomplex facility to a new level of energy optimi-zation.

ENERGY EFFICIENCY - A SPOTTY HISTORY

In the first fifty years of its operation, the plantsaw a varying and inconsistent degree of empha-sis on energy efficiency. Most previous energy ef-ficiency efforts were individual specialists focus-ing on specific issues.

The current program really began in 1997, withthe formation of a plant-wide energy team. Thisenergy team sponsored an independent plant-wideenergy survey and pinch analysis. They then cre-ated a disciplined database of energy efficiency im-provement opportunities. They subsequentlyimplemented a plant-wide energy monitoring andoptimization system based on the software pack-age “Visual Mesa.”

THE CROSS-FUNCTIONAL ENERGY TEAM

Key to the Deer Park plant’s success in energy ef-ficiency was the plant’s willingness to work as a

team within the many business units in the plant.The cross-functional energy team was started withdedicated resources consisting of PWP produc-tion membership, various plant and corporateengineering functions (utility, power, project, elec-trical), the plant energy manager, and others. Theenergy team had strong support from the plantmanager. The energy team used several tactics toassure a successful program, including:

A well-defined mission and energy manage-ment strategy that aimed to deliver the lowesttotal long-term production cost.Establishment of energy program critical suc-cess factors.A willingness to reach out beyond the plant’sborders to understand the best practices in en-ergy efficiency by attending energy seminars,conferences, networking with companies, en-ergy agencies, etc. The outside knowledgeacquired was married with decades of “lessons-learned” at the Deer Park facility to develop acomprehensive inventory of potential re-sources and opportunities.A dual timeline approach to select potentialprojects for implementation. A short-termtactical plan was used to identify and imple-ment stand-alone projects to quickly deliveron reduced energy and utility costs. A mixof longer term, strategic projects were imple-mented to ensure the development of systemsand infrastructure to deliver sustainable en-ergy savings in the future.

ACTIONS TAKEN

The team’s early emphasis was to identify andchampion implementation of all justifiableprojects that would increase overall site energy andutility efficiency. Primary goals focused on earlycost reductions (1998-2000) to help the plant meetshort-term business budget requirements. Keyfeatures of the actions taken were:

Opportunities identified were at both the util-ity and process area level.Communicating metrics to track progress to-wards goals to management/operational staff.Reporting progress to energy stakeholdersto assure program deliverables are aligned withbusiness requirements and program gaps(funding, resources, etc.) are resolved.


45

Staying on track-decreasing budgeted energyusages to reflect forecasted commitments.Developing a sufficient knowledge of plantutility systems to enable proper technical andfinancial analysis of energy opportunities.Recommending a plant-wide energy manage-ment system that provides real time energycost information and optimization recom-mendations (i.e., operations staff will be moreaware of the energy cost implications whenmaking process operation changes).Shift plant utility cost system so that each busi-ness unit pays for actual usage.

To date the team has identified over 125 projectsand more than 40 percent have been implementedover the last 3 years. Roughly 20 percent are stillunder evaluation, with the remaining percentagenot currently justifiable. Examples of the actionstaken to achieve energy savings, include: internalenergy audit (1995), compressed air leak audit(1998, Petro Chem), fired heater audit (1998,Zink), motor systems assessment (1998,Planergy), plant site energy assessment (1998,Reliant Energy Services), instrument air compres-sor and dryer audit (1998), building lighting sur-vey (1998, Wholesale Electric), steam system leakand trap assessment (1999, Petro Chem), DOE-OIT “Pumping Systems Assessment Tool” assess-ment (1999, Oak Ridge National Lab), Pinch

Technology assessment (1999, internal staff ), in-frared thermography audit (1999), real time en-ergy optimizer analyses (2000), second steam sys-tem assessment (2000, Armstrong Services), andsite assessment (2000, Energy Service Co.).

THE STRATEGIC APPROACH

The Deer Park Plant “Long Term Energy StrategyDocument” defines success as being : “when en-ergy management is understood as an implicit partof operational excellence, i.e., it is:

Understood and actually managed as part ofthe business.Addressed aggressively at the design level.Enabled adequately with instrumentation anda management system.Instrumented and optimized on a continu-ous basis by operations.A key plank of the Monomers Business Mis-sion.Optimized for the whole site.

A sub-team chartered to develop a strategy for thesite-wide energy management system found thatthe needs of the plant could be represented by fourkey deliverables:

The real time presentation of strategic energy

Rolm and Haas CompanyTwo Value-Added Chains

Major Raw Material

Propylene

PRM Plastics

Acetone

End-Uses

Disposable DiapersDetergentsWater TreatmentsMining

Industrial CoatingsLatex PaintsTextilesPapersLeatherAdhesivesFloor PolishCement ModifiersEngineering ResinsVinyl BottlesVinyl SidingVinyl Film and Sheet

Signs and DisplaysGlazingAutomotive componentsLighting FixturesBuilding PanelsMotor Oils andTransmission Fluid

Key Monomer(Building Blocks)

Acrylic Acid

MethylMethacrylate

Polymer Products

Polyacrylic Acid

Acrylic Resins

Acrylic Emulsions

Plastics Additives

Acrylic SheetMolding ResinsLubricant Additives

These products represent two-thirds of the Rohm and Haas portfolio.


46

information including data acquisition, pre-sentation, and metrics.A strategic energy-based decision-making toolwith a Monte Carlo-(statistical probability)type front end.A system for site-wide continuous operationalenergy optimization.A system or tools for local continuous opera-tional optimization.

After considerable investigation, the team con-cluded that no single tool could provide all fourdeliverables completely. The team proposed toprovide each of the deliverables as follows:

1. The real-time presentation of strategic energyinformation including data acquisition,presentation, and metrics.

This deliverable includes the field instrumenta-tion, IT infrastructure, and software for data ac-quisition, data analysis, and data presentation.The data presentation includes displays for op-erators, unit managers and engineers, plant man-agers and engineers, as well as metric calculationand tracking.

This system was already partially in place. It wastheoretically possible to completely accomplishthis deliverable with in-house designed IT infra-structure and software in addition to appropriatefield instrumentation. For example, projects toautomate the control of the 150 psig and 75 psigsteam headers and to provide a tool for steam ventand let down tracking were already underway.There were also plans to provide a means for per-formance monitoring and performance predic-tion of key energy equipment. However, it wasthe opinion of the team that the benefit of per-formance monitoring, performance prediction ofkey energy equipment, and identifying all pos-sible metrics would only be realized with a plant-wide system. A plant-wide system could prob-ably be developed in-house, but the team felt thatthis would not be cost effective. The team alsofelt that the true benefits of performance moni-toring and metrics would only be realized if thesystem was owned by one person who had thecommitment of the area managers to implementthe recommendations. Whenever the term per-formance monitoring is used, it is intended toinclude both equipment performance monitor-

ing and instrumentation monitoring.

2. A strategic energy based decision making toolwith a Monte Carlo type front end.

This deliverable would provide a tool that wouldallow good business decisions to be made basedon current and projected energy usages in the plant.The Deer Park plant is made up of semi-indepen-dent production units that share utilities but whoseenergy and utility usages are strong functions oftheir own individual business conditions. A plantenergy model that accurately shows the currentconditions can be used to predict the future mini-mum usages, the future average usages, and thefuture maximum usages. Business decisions (forexample, the choice between a steam turbine andan electric motor as a driver) based on each of theminimum, average, and maximum cases, may bedifferent for each case. The actual usages in fu-ture years would probably be different than any ofthe aforementioned cases. Thus, in order to makethe decision most likely to be the best decision, aMonte Carlo-type analysis allowing for the inputof ranges of future energy uses and their probabil-ity distributions needs to be performed providingstatistical predictions of likely plant energy usages.

The resident utility process expert had developedan excellent spreadsheet model of the plant steamsystem that was very nearly complete. One solu-tion would be to continue work to finish thismodel and to incorporate a Monte Carlo-type frontend such as “@Risk” or “Crystal Ball”. However,this would require a significant amount of timeand would delay the development of other en-ergy-saving projects. Another option would be toask the supplier of the plant-wide energy manage-ment system (for example, Visual Mesa) to incor-porate an Excel-based input tool that could thenuse “Crystal Ball” or “@Risk” to drive the MonteCarlo analysis. Because “VisualMesa” was ulti-mately chosen as the means to provide the otherdeliverables, the latter option was chosen to pro-vide this deliverable.

3. A system for site-wide continuous operationalenergy optimization.

This system includes taking the data from the firstdeliverable (real-time presentation of strategic in-formation) and incorporating it into a plant-wide


47

optimizer program. The ultimate goal would beto make as much of this optimization as possibleclosed-loop, but the initial phase would probablybe advisory only. If an optimization program wasselected, it would also facilitate the first twodeliverables.After looking at many different software platformsand programs, the team chose the VisualMesa pro-gram offered by Nelson and Roseme. The site-wide system includes all steam, all fuels includ-ing waste fuels, and condensate. It provides real-time optimization, providing new energy-savingopportunities. The team is currently building aMonte-Carlo-type front-end to facilitate “what-if ” studies.

4. A system or tools for local continuous opera-tional optimization.

The VisualMesa based optimization program al-lows for some local continuous operational opti-mization. There was also an alliance announcedseparately to use AspenTech’s suite of process op-timization tools at this site. The team decided tohandle local optimization on a case-by-case ba-sis. The team still strongly believes that there ismuch benefit to be had from local continuousoperational optimization, especially if that opti-mization can be made to be closed loop.

CRITICAL SUCCESS FACTORS

The team then identified nine critical success fac-tors that they believed were imperative if the site-wide strategic energy management system wasto succeed:

An owner/champion must be designated im-mediately. This person should be responsiblefor ensuring that the instrumentation, IT in-frastructure, and model are kept up to dateand are reliably maintained. This personshould also be responsible for, and have theauthority to, ensure that the units are heldaccountable for their energy use.Businesses must be held accountable for en-ergy used per pound of product and otherenergy metrics.A cultural change is needed that will allowthe implementation of energy optimization.For example, a true paradigm shift on oper-ating philosophy for controlling 150#/75#

letdowns and vents.The Energy Management System must beused in order to obtain benefits.The instrumentation must be reliably main-tained. The readings must be believable.Resources must be made available to imple-ment identified operational improvements.Performance must be monitored and indi-cated deviations from target acted upon in atimely manner.Adequate training must be provided.The Energy Management System must showwhere operational improvements can be maderelatively quickly.

THE RESULTS

The highlights of the energy efficiency achieve-ments since 1996 at the Rohm and Haas, DeerPark, Texas, facility are:

A 17 percent energy reduction on a per poundof chemical production basis-see graph above.Since 1997, absolute energy consumption hasdecreased 10 percent even though productionwent up by 7.7 percent.The Deer Park plant’s energy savings achieve-ments have already exceeded a 2005 Rohmand Haas corporate goal to reduce energy con-sumption by 15 percent (per pound basis)from 1995 levels.Current annual energy savings (from 1996 to1999) are at least 3.25 trillion Btu per year,valued conservatively at $15 million dollarsper year (both supply and demand charges).This amount of energy savings is equivalentto the energy consumption of 32,000 typicalU.S. homes. (101 million Btu per housingunit; EIA data)

Annual emission reductions are as follows:

NOx = 800 tons per year.(assuming 0.5 lbs. NO

x emissions avoided per

million Btu saved)CO2 = 51,350 tons per year, equivalent toremoving 25,000 cars from the roads.(31.6 lbs. CO

2 emissions avoided (carbon

equivalent) per MMBtu natural gas saved, anda typical car emits 2 tons of CO

2 per year)


48

THE PATH FORWARD

The ultimate goal of the Deer Park energy pro-gram is to achieve the lowest total operating costyear in and year out. This is verified in real-timeand on a long-term basis. Future energy programenabler opportunities will include:

Increased use of energy usage and cost per-formance metrics for day-to-day operations.Increased day-to-day use of the real timeplant-wide energy management system.Utilization of Energy Service Company part-nerships for new opportunities.Continued facilitation of a plant culturewhere energy awareness is well understoodand practiced at both plant operating and en-gineering design levels.Increased use of advanced process control.Increased automation of optimization.Increased use of metrics and accountability.Extension to water and other sustainabilityresources.Extension to other plants/replication acrosscorporation.

ACKNOWLEDGMENTS

The author would like to acknowledge the invalu-able help of Mr. Jeff Hackworth, Energy Man-ager for the Deer Park Facility, and Mr. PaulScheihing, of the U.S. Dept. of Energy in provid-ing much of the information for this article and,in fact, writing much of the text. He would alsolike to acknowledge the dedication and commit-ment of the members of the energy team, withoutwhose efforts, these successes would never havehappened.


Fred FendtRohm & Haas CompanyEmail: [email protected]: (215) 785-7661

Steam Digest 2001Celanese Chemicals Clear Lake Plant Energy Projects Assessment and Implementation

49

Celanese Chemicals ClearLake Plant EnergyProjects Assessment andImplementationJoel Weber, (formerly with) Celanese Chemicals

ABSTRACT

The Clear Lake Plant of Celanese Chemicals hasimplemented a strategy to reduce energy consump-tion. The plant identified, designed, and com-pleted several projects to improve its chemicalproduction processes. These projects reducedsteam use, fuel gas use, and electricity use. Someinvolved capital changes, but most used existingassets more efficiently. Celanese now realizes costsavings while operating a more efficient and reli-able plant.

INTRODUCTION

The Clear Lake Plant pursued a strategy to re-duce energy use in two stages. The first stage wasa part of its Low Cost Producer program. Theplant conducted a series of brainstorming meet-ings to generate ideas to reduce production costs,including energy costs. Teams of engineers andspecialists reviewed the ideas to refine them intopotential projects.

The second stage of the strategy was to constructa predictive model of the plant’s steam and energytransfer systems. The purpose of this was to re-duce or avoid inefficiencies resulting from break-ing down high pressure steam over valves, vent-ing steam, and losing water. The model considersfuel gas and electrical usage and billing rates fromsuppliers. The model anticipates the effect of aproposed change in one area, on the overall en-ergy balance of the plant. From the potentialprojects proposed in the first stage, the predictivemodel helped to select the most beneficial ones topursue.

The Clear Lake Plant expects reduced energy use(adjusting for plant expansion projects), especiallyin steam and fuel gas. Preliminary data from 1999over 1998 shows improvement, most of which can

be attributed to several projects. Most projectsinvolved no capital expenditure; some took ad-vantage of existing equipment or scheduled equip-ment replacements to design a more energy-effi-cient system.

EXAMPLES OF COMPLETED PROJECTS

Heat ExchangerOne of the plant’s processes includes a byproductremoval system, consisting of an absorber towerand a stripper tower, with a process-to-process ex-changer between two of the streams. Over theyears, the interchanger performance had deterio-rated slowly, due to fouling and corrosion. Pro-cess modeling showed that about 50Mlb/hr ofsteam driving the stripper reboiler could be re-duced by replacing the old exchanger. The unitreplaced the exchanger with one similar in size,with new cleaning nozzles and redesigned baffles.The project reduced low-pressure steam used inthe stripper, amounting to 2.5 percent of the plantenergy load.

Use Excess Process Steam for HeatRecoveryAnother process generated steam containing asmall amount of process material. This could notgo directly into the plant steam system, so theexcess steam was vented. In a separate process,purchased steam heated a Flasher vessel. To im-prove this situation, the unit implemented a low-cost project to add piping. The process steamwas lined up to the Flasher reboiler, which recov-ered the heat and condensed the steam. The re-sulting condensate went to wastewater treatment.This displaced purchased steam from the reboiler,saving at least 0.5 percent of the plant steam load.

Use a Single Incinerator Instead of TwoIn one process, two incinerators were operatedfor liquid and vent wastes. The second backedup the first incinerator, burning fuel gas for warmstandby. This avoided having to trip out the pro-cess reactors in the case that the first incineratortripped out, affecting reliability and lost produc-tion time. A study found that trip-outs of theincinerator were less frequent than expected.Therefore, it was more economical to use onlyone incinerator. Eliminating the hot standby re-

Steam Digest 2001Celanese Chemicals Clear Lake Plant Energy Projects Assessment and Implementation

50

sulted in large fuel gas savings of $1 million peryear.

Run a Distillation Tower Only Part-TimeA plant process had a distillation tower to recovera byproduct from a product stream. Previously,it had run all the time, but at fairly low rates.Now the unit manages the inventory so that thetower operates only part of the time, for 10 to 15days per month. For the other 15 to 20 days permonth, the tower shuts down. This saves onreboiler steam, cooling water, and some electric-ity savings.

Redesign of ExchangersAnother process has exchangers to recover excessheat from a vapor phase reaction product stream.The exchangers consist of a large helical tube in-side a shell, with the process material on the tubeside and the boiler feed water heating to steam onthe shell side. For this project, the exchangers wereredesigned to give more heat transfer overall.Therefore, the plant recovers more byproductsteam. This is an example of a project whichstarted as a debottlenecking project, but also re-covers energy.

Optimize Tower OperationThere are several projects under way to optimizethe operation of distillation towers. Using onetower project as an example, operations decreasedreflux, changed tray temperatures and tower pres-sures, and decreased reboiler steam. Although thesavings can vary with rate changes in the process,this project alone can save 0.4 percent of the plantsteam load.

Improve Process Control of Large AirCompressorEngineers improved process control for a largeair compressor which feeds a reaction train. Toimprove efficiency, the new control strategy mini-mized the differential pressure across the flowcontrol valve downstream of the compressor. Inorder to open up the flow control valve more, theair discharge pressure of the compressor was re-duced by lowering the speed of the compressor.This resulted in saving the high-pressure steamwhich powered the compressor.

Eliminate Hot Standby for Utilities BoilersPreviously, two boilers ran and a third was onstandby. The third burned fuel gas to keep thetubes warm, in case the other boilers tripped. Latera study determined that the reliability of the otherboilers was good enough to run without a spare,so the standby was then eliminated. This savesabout $640,000 per year on fuel gas, 2 percent ofthe plant’s energy budget.

Implement a Range of Smaller ProjectsThe plant also implemented several smaller en-ergy-saving projects. Eliminating hot standby forspare turbines, shutting down outmoded processsystems, and optimizing pump impeller usage aresome examples. Other projects made better useof steam by adding lines to transfer it where it wasneeded. The plant changed tower operation touse lower-pressure steam when possible. On acontinual basis, the plant makes choices to oper-ate equipment with turbines or with motors.

CONCLUSION

The Clear Lake Plant has achieved reductions inenergy usage by selecting and implementingprojects which required little capital expenditure.These changes are expected to improve overallenergy productivity. Often energy reductions oc-cur hand-in-hand with efficiency, productivity,and reliability improvements.

Steam Digest 2001Savings in Steam Systems (A Case Study)

51

Savings in Steam Systems(A Case Study)Rich DeBat, Armstrong Service, Inc.

ABSTRACT

Armstrong Service Inc. (ASI) conducted an engi-neered evaluation at an ammonium nitrate manu-facturing facility during the fall of 1999. This plantmanufactures nitric acid and high and low den-sity ammonia nitrate. The purpose of this evalu-ation is to identify energy losses and system im-provements in the steam and condensate systems.Steam system improvements focus on lowering thecost of steam, wherever possible, with paybacksof three years or less.

Overall, this ASI evaluation identifies six (6) steamsavings proposals with an average simple paybackof 2.9 years.

This evaluation also identifies one system defi-ciency that will lead to unnecessary expendituresif allowed to continue, but would help to increaseproduction if the suggested improvement wasimplemented.

The following report details the individual find-ings and outlines the corrections needed. The sav-ings generated from these improvements will morethan pay for themselves in short order.

SITE OBSERVATIONS

Steam GenerationThe plant has the ability to generate steam from anumber of sources. Typically, the steam require-ments for the nitric acid plant and most of thehigh or low density plants are met with the steamgenerated from the waste heat boilers in the nitricacid production process. The three waste heat boil-ers are rated at 600 psig, 100 psig and 40 psig. Inaddition, an indeck gas fired boiler rated at 80,000#/hr and 400 psig is used to supply supplementalsteam. Table 1 details related costs for steam pro-duction in the 400 psig boiler.

A Kenawee Boiler rated at 14,000 #/hr and 150psig is used as an emergency standby boiler.

Steam DistributionSteam is distributed throughout the nitric acidplant to the various steam users. From the nitricacid plant two separate outdoor steam mains (150and 220 psig) run approximately 1/4 of a mile tothe high and low density production plants. Abranch line from the high density area suppliessteam to the valley area.

Steam UtilizationIn the nitric acid plant 600 psig steam is used inthe ammonia burning process and the steam su-perheater on the extraction/reheat loop of thesteam turbine. The 600 psig steam is also reducedto 220 psig through the steam-driven turbine aircompressor. This steam is used in the ammoniasuperheater and the tailgas heater. The 220 psigsteam can also be reduced to 100 psig and 25 psigthrough reducing stations, if needed. The 100 and40 psig steam is mainly used for tracing in thenitric acid area.

The excess 220 psig steam from the nitric acidplant is exported to the high density area and val-ley areas. It can also be reduced to 150 psig andexported to the low density area. The steam re-quirements in the valley, low density and highdensity areas are greater than the steam exportedfrom the nitric acid plant. Steam from the gas-fired indeck boiler is also reduced and supplied tothese areas, as required. See Figure 1 for a steamflow diagram. The main steam users in the highdensity plant are the evaporator, ammonia super-

Total steam cost $1,426,325/yr.Average steam output 40,0000 #/hr.Steam cost less sewer and electric $5.94/1000 lb.

Natural gas cost $3.25/MCFAverage boiler efficiency 54.0%Average heat cost for boilers $5.56/10^6 BTU

Water cost $1.10/1000 gals.Annual chemical cost $0.10/1000 gals.Average treated water cost $1.20/1000 gals.Make-up boiler feedwater 22,800 #/hr.

Average condensate temperature 200 deg FAverage condensate cost $0.92/1000 lbs.

Average sewage cost $0.00/1000 gals.

Average electricity cost $0.042 per kWh

Table 1. 400 psig Steam Production Costs


52

heater, and the ammonia vaporizer. Other usersare cooler heating coils and the granulator airheating coils.

The main users in the low-density area are theammonia vaporizer and ammonia superheater.Steam is also used in the air-heating coils for thedrum dryers.

Condensate ReturnIn the nitric acid plant, condensate is returned toa vented receiver/ electric pump set and pumpedback to a main storage tank. A pressure-poweredpump is used to return condensate from the val-ley area to a main return line. A vented receiverwith electric pumps is used to return condensatefrom the high density area to the same main re-turn line. The low density and west surge tankarea also return condensate to the above main re-turn although there are no condensate pumps inthese areas. The main return line from the valley,low density, high density and west surge area re-turns the condensate to the main storage tank.Condensate is pumped from the main storage tankto the deaerator, as required.

Figure 1. Steam Flow Diagram

STEAM SYSTEM SAVINGS PROPOSAL #1:REPAIR STEAM LEAKS

BackgroundIn the nitric plant area a large number of steamleaks and valves were discovered open to atmo-sphere (see Table 2 for details). The steam leakagerate will increase during the winter months as steam

tracing is turned on and more valves are openedto the atmosphere. There are also several boilerfeedwater leaks and additional steam leaks in thehigh and low density plant areas that are not notedhere.

DiscussionUnnecessary steam discharge will drive up the costof steam. Boiler fuel usage will increase, as morefuel must be used to supply the additional steamload. The steam lost to atmosphere increases themake-up water requirements, as it is not recov-ered as condensate. The additional makeup wateralso needs more added heat and water treatment/chemicals when compared to returned condensate.


53

As can be seen in Table 2, a number of “small”leaks can add up to a large annual cost, so it isimperative that all steam leaks be repaired asquickly as possible. If the leak is ignored, the steamloss will increase over time, as will the cost of re-pairs.

RecommendationsRepair steam leaks as identified in Table 2, espe-cially the high-pressure ones, and install steamtraps in lieu of partially open valves.

Estimated SavingsThe estimated annual cost savings for repair ofsteam leaks in the nitric acid plant, and installa-tion of steam traps where needed, is $53,000/year.

CostsThe expected payback period is 1.5 years.

STEAM SYSTEM SAVINGS PROPOSAL #2:CORRECT TRAPPING ON HIGH DENSITY

EVAPORATOR

BackgroundThe condensate drainage method from the evapo-rator in the high-density area has been changedfrom the original design. The evaporator originallyhad a condensate pot with a liquid level control

on its outlet to meter condensate flow. This wasin essence an expensive electronic steam trap. Theliquid level controller and control valve have beenremoved and a gate valve is now installed in placeof the control valve. The gate valve is manually setto control condensate flow. The condensate fromthe evaporator is discharged to a pressurized flashtank (100 psig) and is then piped to an atmo-spheric receiver where it is pumped into the con-densate return line to the nitric plant. The steamplume off the atmosphere receiver’s vent is sub-stantial. See Figure 2 (on page 52) for the currentpiping arrangement.

DiscussionUsing a gate valve to control condensate flow fromthe evaporator’s coil can cause a number of prob-lems. Unlike a properly functioning steam trap(electronic or mechanical), the gate valve cannotmodulate its discharge orifice size in response tocondensate load variations. If the gate valve is notopen enough, condensate will back up into theevaporator coil when the load increases. Thismeans poor equipment performance and possibledamage due to water hammer. The obvious solu-tion is to make sure the valve is always open farenough to pass even the highest condensate loads.However, when the condensate load is less thanthe peak value, the valve will allow live steam, aswell as condensate, to pass through it. While this

Table 2. Identified Steam LeaksSteam Leakage Rate to Atmosphere (Napiers)Orifice Size Inlet Pressure #/hr Location Action

0.047 400 37 Relief valve on 400 psi boiler outlet header Repair relief valve0.047 400 37 Control valve vent on 400 psi outlet header Replace control valve0.094 400 147 Flange on venting control valve Replace gaskets, repair or replace flanges0.094 400 147 Valve packing on bypass control valve Repair leak/replace packing0.047 400 37 Isolation valve on abandoned steam header Replace valve0.094 400 147 Valve packing on branch line to PRV station Repair leak/replace packing0.016 400 4 Main steam line after 400 psi boiler Repair leak0.063 220 37 Relief valve on 220 psi steam main Repair relief valve0.063 220 37 Valve packing leak on 220 main line Repair leak/replace packing0.063 150 26 150 psi reducing station Repair leak0.063 140 24 Steam supply to air tank tracing Install steam trap0.141 125 112 Relief valve on 100 psi boiler accumulator Repair/replace relief valve0.094 40 19 Tracing blow down valve Replace valve0.094 40 19 Tracing on 600 psi control valve Repair leak0.109 40 26 Tracing steam for caustic soda tank pumps Install steam trap0.094 40 19 Tracing steam Repair leak0.125 40 35 Union on drip station ahead of 40 psi PRV Replace union0.125 15 19 Valve cracked open on takeoff line ahead of caustic tank Install steam trap0.125 15 19 Valves open to atmosphere on end of branch line in water treatment area Install steam trap0.125 15 19 Tracing line leak near cooling tower Repair leak0.19 15 42 Valve packing on control valve to deaerator (inlet valve) Repair leak/replace packing0.06 11 4 Valve packing on control valve to deaerator (outlet valve) Repair leak/replace packing0.13 15 19 Tracing line leak near waste heat boiler accumulator Repair leak

Total #/Hour 1,033


54

live steam flow may not adversely affect the coil’soperation, unless it is a very high amount, it doesmake the overall steam system very inefficient.Higher steam flow leads to increased pressure drop(loss of energy), and the potential for erosion andwater hammer in the steam distribution piping isincreased. Excessive steam flow to the condensatesystem will increase the back pressure to all othersteam users that return condensate and also maylead to water hammer, as is the case here.

The evaporator drainage system was also originallydesigned to make use of the 100 psig flash steamgenerated from the 220 psig condensate. The 100psig flash tank is still in place, but the originaluser (HVAC coils in the air handler in the truckloading offices) has been removed. Excessive liveand flash steam from the evaporator will quicklyelevate the pressure in the 100 psig flash tank tothe evaporator’s steam supply pressure (220 psig).To prevent this, the bypass valve around the 100psig flash tank is open and venting this steam tothe condensate line that runs from the 100 psigtank to the atmospheric tank. As a result, a verylarge amount of steam is being vented from theatmospheric tank and water hammer and erosionis prevalent in the system.

RecommendationThe first priority is to eliminate the excessiveamount of steam being vented from the atmo-spheric tank by installing a properly sized steamtrap in place of the gate valve that is currently be-ing used to control flow. The bypass valve on the100 psig flash tank also needs to be replaced as itmore than likely has been damaged by steam flowthrough it while in the partially open position.See Figure 3 (on page 52) for the proposed pipingmodifications.

To further optimize the system, the 100 psig flashsteam from the flash tank must be utilized. Basedon the design steam load for the evaporator of13,724 #/hr, the flash steam produced from the220 to 100 psig reduction would be 769 #/hr. Ifthis steam and condensate is further reduced to 0psig, the total amount of steam being vented wouldbe 2,312 #/hr. If the 769 #/hr of 100 psig steam isreused, the amount of vented steam at 0 psig willbe reduced to 1,440 #/hr. Two possible uses forthe 100 psi flash steam are steam coils for the airheater or the cooler heating coils.

Estimated BenefitsEstimating an excessive steam usage of 2 percent,due to the use of the gate valve as a steam trap,gives an annual dollar loss of $13,700/year. In ad-dition, recovering the 100-psig flash steam for usein the air heater equates to an annual cost savingsof $38,300/year. The total annual cost savingswould be $56,000/year.

CostsThe expected payback is 2.8 years.

STEAM SYSTEM SAVINGS PROPOSAL #3:IMPROVE CONDENSATE RETURN FROM LOW

DENSITY PLANT

BackgroundThere are two main steam supply lines to the highand low density and valley areas and both linesare 6" diameter pipe. There is one main conden-sate return line to the nitric acid plant and thisline is 4" pipe. The high density and valley areasboth have condensate pumps to return conden-sate to the main return line. However, there areno condensate pumps in the low density area otherthan the small pumps for the large storage tankon the hill. The combination of pumped conden-sate from the high density and valley areas andbiphase condensate from the low density area iscausing severe water hammer in the condensatereturn line. In addition, condensate from the largestorage tank, and other steam users in the low den-sity plant, can not be returned due to high backpressure in the return line. Currently, this con-densate is drained to the ground.

DiscussionThe lack of condensate pumps in the low densityplant means that the condensate flow from thisarea is biphase. In other words, there is both flashsteam and condensate in this return line. In abiphase condensate system, the condensate typi-cally flows due to the gravity pitch of the line, andflash steam flows as a separate phase over the topof the condensate due to the steam pressure drop.This arrangement works best if there is a head pres-sure difference (gravity) in between the equipmentand the final drainage point and the final drain-age point is at zero or very little pressure. If a pip-ing elevation rise or back pressure exists in the line,the condensate must collect in the pipe to the point


55

EVAPORATOR

220 PSIG STEAM IN

CONDENSATEOUT

100 PSIGFLASH TANK

VENT TO ABANDONEDAIR HANDLER

CONTROL VALVE FORLIQUID LEVEL CONTROL

ON 100 PSIG TANKBYPASS VALVE

EVAPORATOR

ATMOSPHERIC VENT

ATMOSPHERIC TANK

REV

1998, ARMSTR ONG SERVICE, INC.

DRAWING NO.SCALEN ON E 0

125 Windsor DriveOak Brook, IL 60523

CURRENT HIGH DENSITYEVAPORATOR PIPING

Figure #2

REV

© 1999, ARMSTRONG SERVICE, INC.

DRAWING NO.SCALE

NONE 0

LEGEND

EXISTING

PROPOSED

FIELD WELDS

100 PSIGFLASH TANK

EVAPORATOR

STEAM TRAP

BYPASSVALVE

TO RETURNLINE

FIGURE #3

125 WINDSOR DRIVEOAK BROOK, IL 60523

INSTALLATION ON STEAM TRAP ONHIGH DENSITY EVAPORATOR

Figure 2. Current High Density Evaporator Piping

Figure 3. Proposed Evaporator Piping


56

where it seals the pipe off. Then the flash steamwill build until there is enough pressure to pushthe condensate. The resultant slugs of condensatewill move very fast (up to 90 MPH) and slam intoany elbows, tees or fittings. This is called “differ-ential” water hammer. Additional water hammerwill occur when the flash steam from the biphaseflow is introduced into the pumped condensateline. The flash steam will instantly condense inthe cooler condensate creating an implosion/ex-plosion reaction. This is called “thermal” waterhammer. In addition to the water hammer, backpressure in the return line will be present at thesteam traps that are not isolated from the line by areceiver/pump combination. This back pressurewill prevent proper condensate drainage on thesteam-using equipment.

RecommendationWhen condensate cannot flow by gravity to thefinal drainage point or high backpressure exists inthe return line, a pump must be used to give thecondensate the motive force it requires. In thiscase, a pump and receiver package should be placedin the low density plant to collect condensate andpump it back to the nitric acid plant.

Estimated BenefitsThe estimated cost savings available by returningcondensate that is currently being drained in thelow density area is $17,000/year. Additional ben-efits will be realized in overall system operation,safety, and equipment life.

CostsThe estimated payback is 3.8 years.

STEAM SYSTEM SAVINGS PROPOSAL #4:RECOVER WASTE HEAT IN BOILER

BLOWDOWN WATER AND FLASH STEAM

BackgroundBlowdown water from the high-pressure (600-psig) waste heat boiler in the nitric acid plant ispiped to a 20 psig flash tank. This allows a smallpercentage (22 percent) of the hot condensate to“flash” into the low pressure (20 psig) steam line.The condensate is sent to an atmospheric flashtank where additional flash steam (4 percent) isreleased into the air and the remaining conden-

sate is discharged directly to the sewer. Also, inthe nitric acid plant area, condensate from the highpressure and medium pressure (220 psig) users ispiped to a different 20 psig flash tank and, again,this flash steam is piped to the low pressure steamline. The condensate from this 20 psig flash tank,along with condensate from the low pressure steamusers and the turbine’s surface condenser, is pipedto a large atmospheric tank. The flash steam fromthis tank is vented to the air and the condensate ispumped back to the deaerator tank.

DiscussionValuable heat in the high-pressure boilerblowdown water and in the flash steam from thelarge atmospheric tank vent is being lost to thesurroundings. This heat can be recovered by us-ing it to preheat deionized makeup water to thedeaerator.

RecommendationA deionized water supply line is already in placeto the high-pressure boiler area. A stainless steelshell and tube heat exchanger, that was previouslyused to preheat ammonia, has been abandoned inplace. This heat exchanger can be relocated andused to transfer the heat in the high-pressure boilerblowdown water to the deionized water. The pre-heated makeup water can then be sprayed into thevent line on the large atmospheric tank, whichwill condense the flash steam that is currently be-ing vented. This will reclaim the heat and the wa-ter that would otherwise be lost to the air as steam.See Figure 4 for proposed arrangement.

Estimated SavingsThe estimated cost savings for this proposal is$16,445/year.

CostsThe estimated payback is 6.5 years.

STEAM SYSTEM SAVINGS PROPOSAL #5:STEAM TRAP REPAIR AND REPLACEMENT

BackgroundThere are approximately 210 steam traps at thisfacility. A steam trap survey was completed inJanuary of 1999. Of the 170 tested steam traps inservice, 62 had failed; this equates to a 36 percentfailure rate. Based on information from the plant,


57

it is assumed the failure rate of 36 percent has de-creased, through ongoing maintenance, to 14 per-cent, resulting in an adjusted annual steam loss of14 million pounds. Using a steam cost of $5.97per thousand pounds and an operational time of6800 hours/year, the annual dollar loss (monetarylosses) is estimated at $100,000.

DiscussionThe energy efficiency of a steam distribution andcondensate return system is strongly dependenton the effective usage of steam traps. The basicfunction of a steam trap is to prevent live steamfrom blowing through and to allow condensatethat is formed, due to heat being released in thesystem, to be drained. Efficient removal of con-densate is necessary to avoid backup of conden-sate in the system. Condensate backup deterio-rates the heat-transfer process efficiency, causescorrosion, and may lead to severe damage causedby water hammer in steam distribution lines, valvesand equipment. The second function of a steamtrap is to facilitate the removal of air from the steamdistribution system. Air is present in the system

during start-up, and is introduced with themakeup water and through vacuum breakers. Thepresence of air in the system deteriorates heat trans-fer efficiency by insulating the heat transfer sur-face and causing corrosion when it is absorbed bythe condensate.

To provide long-term and energy-efficient perfor-mance of steam traps, the priority aim is to estab-lish an adequate maintenance system. Once allthe changes and recommendations have beenimplemented, the following preventive mainte-nance guidelines should be used.

In general, all steam traps should be tested at leasttwice each year - once in the fall and once in themiddle of the winter. The recommended testmethod should be a combination of visual, sonic,and temperature methods. See the following tablefor more specific testing frequency guidelines.Keep a good record of the updated information.A steam trap computer database program is thebest way to store and maintain these records. Thedatabase can also be used to store piping drawings

H e a t R e c o v e r y

o f

L P

C o n d e n s a t e

T a n k

( N o r t h

o f

6 0 0 #

B o i l e r )

R E V ©

1 9 9 9 ,

A R M S T R O N G

S E R V I C E ,

I N C .

D R A W I N G N O . S C A L E N O N E 0

L E G E N D E X I S T I N G P R O P O S E D

T O S E W E R

O R I F I C E U N I O N

W A T E R S P R A Y

F L A S H T A N K V E N T D E I O N I Z E D

W A T E R S U P P L Y

R E L O C A T E D H E A T E X C H A N G E R

2 0 P S I G F L A S H T A N K

1 2 5 W I N D S O R C O U R T O A K B R O O K , I L 6 0 5 2 3

F I G U R E #4

Figure 4. Proposed Piping for Boiler Blowdown Heat Recovery


58

of each trap application and prior history orproblems with the traps. It should be used toprint out all traps by the areas that need to betested. Each trap, as it is tested, can now bechecked off. Any changes that have been madeto the tag number should be “written over” theold entry on the computer printout. This be-comes the input to the computer.

As each trap is tested, all strainers should be blowndown for a couple of minutes to ensure they areclean. Each isolation and bypass valve should beclosed and ultrasonically checked for leakage.

Every trap, valve, or strainer that has failed shouldbe tagged for replacement or repair.

A well-run steam trap management program will:

Reduce operating costs.Improve safety.Increase production or service.Reduce maintenance and other costs by elimi-nating condensate return problems, freeze-ups, water hammer and corrosion.

In summary, using failed steam traps or not usingany, leads to three ways of waste:

Waste of live steam through the failed trap.Disturbing the local condensate return sys-tem. The high back-pressure in the conden-sate return lines decreases the pressure differ-ential across the other traps, thus decreasingtheir discharging capacity.Deviation from the required outlet tempera-tures of the heated fluid could lead to prod-uct material disturbances or more heat input.

RecommendationIt is recommended to replace all the identified de-fective and misapplied steam traps. Plants shouldalso institutionalize a steam trap maintenance pro-gram by replacing steam traps with statistical pro-jected failure during the maintenance contract pe-riod in order to supply better quality of steam andto achieve better performance of steam-usingequipment.

Estimated BenefitsAn estimated annual cost savings for replacing allidentified defective steam traps and institutional-izing a steam trap maintenance program is$100,000.

CostThe estimated payback period is 2.4 years.

STEAM SYSTEM SAVINGS PROPOSAL #6:BOILER OPTIMIZATION

BackgroundDuring the plant-wide steam system site evalua-tion, ASI engineers were able to test, visually in-spect and observe the operation of both the Indeckand Kewanee boilers. As a result of this evalua-tion process, the Indeck boiler was found to havethe highest potential for significant energy sav-ings. Therefore, this steam system savings pro-posal will address the improvements with the great-est impact toward increasing energy efficiencywhich involve upgrading and replacing controls,transmitters and loops, and boiler and burnerboiler casing.

DiscussionA distributed control system (DCS) is designedto take control of the process or the plant. In thepower industry, the term distributed control sys-tem (DCS) is generally applied to the system thatimplements boiler control and data acquisitionfunctions of the power plant.

A state-of-the-art DCS is typically composed ofmodularized microprocessor-based processingunits, input modules, output modules, operator

Table 3. Trap Testing Frequency

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noitacilppA

pirD recarT lioC ssecorP

001-0 1 1 2 3

052-101 2 2 2 3

054-152 2 2 3 4

dna154evoba

3 3 4 21


59

workstations, engineering workstations, print-ers and other types of peripheral devices, all con-nected through a multiple-level communicationsnetwork. DCS manufacturers have standardmodules for different functions. They generallyfall into two categories: control modules and dataprocessing modules.

The control modules are structured to perform avariety of control and computing tasks, such asPID (proportional plus integral plus derivative)control, binary logic, and arithmetic functions.Some manufacturers have separate modules formodulating and on-off control functions and oth-ers have combined the two into one module. Forsome manufacturers, each module is available invarying sizes to suit a user’s needs.

In addition to the control functions, the DCSneeds programs to implement all operator inter-face, report generation, and data storage and re-trieval functions. The manufacturers generallydivide these functions into separate packages, eachwith a specially structured program that serves asa platform for the user to develop graphic displays,other forms of data presentations and format op-erating logs. In general, the programming func-tions are user-friendly and menu-driven, so thatthey can be a programming tool that is easily un-derstood by the user’s personnel.

Programming functions are conducted from theengineering workstation, usually with a fullcomplement of CRT screen, keyboard, auxiliarymemory, and floppy disks. The workstation isnormally connected to the DCS communicationsnetwork, and the programs developed from theworkstation can be directly downloaded to theindividual processor modules in the system.

A DCS application in a boiler house operationtypically covers the following areas:

Boiler controls, including the combustion (fir-ing rate), furnace draft, steam temperature,and feedwater control loops.Burner control.Control loops in the plant auxiliary systemthat need to be monitored and/or controlledfrom the central control room.Alarm annunciation and recording features.

Monitoring function for other separatestand-alone controllers or control systems.Remote indication and recording of plant op-erating parameters.Periodic reports and event logs.Historical data storage and retrieval functions.

In nearly all power plants and boiler house opera-tions built in recent years, the monitoring and dataprocessing tasks that the DCS is capable of han-dling have largely replaced the conventional mimicpanels, annunciator light boxes, indicators, andrecorders in the plant control rooms. It shouldalso be mentioned that DCS application in plantshas been expanding into motor controls for thebalance of plant equipment (pumps, fans, etc.),which was once predominantly an area for PLCapplications. At the present time, the choice be-tween PLC and DCS for this application is largelya matter of cost and user’s preference.

The next area to be discussed is that of burners.Burner designs continue to be developed and arecapable of meeting new industrial standards with-out the use of flue gas recirculation for certain ap-plications. By using a combination of an air-fuellean premix and staged combustion, peak flametemperatures are reduced without the need for fluegas recirculation. While the staged combustion isa unique burner design, it can be effectively usedin today’s modern boiler applications. New boil-ers, as well as older operating boilers requiring ret-rofitting, will benefit from these successful devel-opments.

Finally, during flue gas testing analysis, our engi-neers discovered higher than normal oxygen per-centages. The location and the cause were con-firmed during a later outage. In addition to thecasing leak, two locations along the rear side wallsand roof areas were found to have broken or miss-ing refractory. The rear wall casing that houses aninspection sight glass port was also found to bedeteriorated and was in need of repair.The problems discovered with regard to brokenand missing refractory and the boiler-casing leakdo result in heat loss that directly effects the lossof thermal efficiency.

There are three major recommendations proposedfor this steam system savings proposal.


60

Option 1RecommendationRepair casing and refractory leaks on existingboiler, tune existing burner system after refractoryrepair, and continue with normal operation of theexisting boiler.

BenefitsThe estimated cost savings available by repairingthe existing boiler and tuning existing burner sys-tem is $64,000. The dollar total is based on a 4.5percent (statistical industrial standard) decrease inthe steam cost.

CostsThe Option 1 estimated payback is 7.5 months.

Option 2RecommendationEvaluate, select and install a distributed controlsystem for a boiler control upgrade. A distrib-uted control system should contain the followingminimum requirements:

Highly reliable system architecture.Open architecture programming and commu-nications.High accuracy inputs with noise and inputspike protection.Capable of complete power supply, processorand/or I/O redundancy.Hot swappable I/O cards.

In addition, plants should evaluate, select and in-stall a burner package that will guarantee a highlyreliable efficient operation with excellent turn-down capabilities.

Any equipment selected to meet the terms andconditions of this recommendation should beguaranteed under manufacturers’ warranties.

BenefitsThe estimated cost savings available by replacingthe current burner controls and installing a newDCS, along with Option 1 recommendation, is$99,843. The dollar total is based on a 7 percent(statistical industrial standard) decrease in thesteam cost.

CostsThe Option 2 estimated payback is 3.3 years.

Option 3RecommendationReplace the existing boiler, burner and distribu-tive controls system with I/O loop transmitterscontrols with new equipment with similar capac-ity as the original equipment. The boiler that isselected will have a steam capacity of 75,000 lb/hr at 350 psig/600°F superheated steam. Theboiler will be equipped with a stack economizer.The burner should have a dual fuel capability(natural gas/propane with air atomization or natu-ral gas/#2 fuel oil with steam or air atomization).With either burner that is chosen, it should be ofthe low excess air style to achieve highest efficien-cies.

BenefitsThe estimated cost savings available by replacingthe existing boiler with a new boiler, new boilercontrols and a new distributive control system withI/O loop transmitters is $121,238. The dollar to-tal is based on an 8.5 percent (statistical industrialstandard) decrease in the steam cost.

CostsThe Option 3 estimated payback is 10.5 years.

STEAM SYSTEMS IMPROVEMENT PROPOSAL

#1: STEAM TRAPPING OF “FISH POND”PIPE COILS IN LOW DENSITY AREA

BackgroundThe low density plant has a pit with steam heatedpipe coils referred to as the “fish pond”. The con-densate from these pipe coils must be lifted (si-phoned) to the steam trap. The current steam traparrangement has a bypass around the trap with-out a valve. This bypass appears to be wide open,which allows “live” steam to be discharged intothe condensate return line. The water hammer inthe piping at this location is very evident.

DiscussionElevating condensate up a lift in a siphon drain-age situation will allow some of the condensate toflash back into steam. This flash steam will lead tosporadic trap operation and ineffective conden-sate drainage from the coil. In this situation, abypass has been placed around the trap to routethe flash steam around the steam trap. Currently,the amount of steam that is being routed through


61

the bypass cannot be controlled. The currentpiping arrangement prevents the steam trapfrom functioning properly and leads to exces-sive steam waste. The discharge of live steam intothe condensate system causes the water ham-mer noted above.

RecommendationThe condensate drainage on the pipe coils shouldbe reconfigured to allow the use of a differentialcontroller (DC) steam trap. The DC trap has aninternal steam bleed that can be metered to con-trol the flow rate of the bypassed steam. Conden-sate from the steam trap will be routed to a smallreceiver/pump package and then pumped back tothe condensate receiver and pump package pro-posed in Steam Systems Savings Proposal #3. Theproposed piping is shown in Figure 5.

Estimated BenefitsThe main benefits to this proposal will be im-proved coil performance and elimination of thewater hammer. There will be a decrease in theamount of steam usage, but an estimate of the

Figure 5. Proposed Steam Trap Piping for “Fish Pond.”

amount of steam being wasted cannot be ob-tained with the data available.


Rich DeBatArmstrong ServiceEmail: [email protected]: (616) 279-3360

Steam Digest 2001Steam System Diagnostics

63

Steam SystemDiagnosticsJohn Todd, Yarway/Tyco

When steam system troubles arise, the steam trapis often unfairly assumed to be the problem.

Other factors that should be reviewed includesteam trap technologies, piping design (upstreamand downstream of the trap), system needs (forefficient operations), and trap maintenance (foroptimum performance).

This article identifies some of the more commonsituations that occur along with possible solutions.

STEAM TRAP TECHNOLOGIES

Match trap technology to application needs.

The first thing to recognize is that the steam trapis one part of a sometimes complex network ofequipment. If the trap is concentrated on exclu-sively, the correction will probably just serve as aband-aid that will not last as a permanent solu-tion to the problem.

Table 1 provides key performance characteristicsthat should be considered to meet specific appli-cation needs.

Let’s start by stating the prime role of a steam trap:to remove condensate, air and other non-condensible gases, while not losing any live steam.If a trap fails, it should fail open to ensure thatcondensate will continue to be removed from thesystem.

The information in Table 1 makes it clear that ap-plication needs should be matched to the correcttrap technology. Each trap type has its strengthsand weaknesses and will give poor results if it isapplied incorrectly.

There is no perfect trap technology for every ap-plication in every plant. Most major manufactur-ers have computerized trap sizing programs avail-able to help the user optimize selection and pre-vent basic mistakes.

Ensure that the steam being supplied is as dryas possible and contains the optimum Btu perlb. of latent heat for heat transfer.

Figure 1 readily displays the latent and sensibleheat values in saturated steam at 100 psig. At thiscondition, it containes 309 Btu per lb. sensibleheat and 881 Btu per lb. latent heat, all at a satu-rated temperature of 338° F.

As latent heat is used for heat transfer, it is best tobe as close to the dry saturated point as possible,so as to use all the available Btu.

Many plants have less than ideal steam quality,often referred to as “wet steam.” This means theyare not as close to the dry saturated condition aspossible.

This steam does not contain the maximum Btuavailable for optimum heat transfer.

For example, if a plant has steam with only 440Btu per lb. of latent heat, it stands to reason thatabout twice as much of this steam will be neededto effect the same heat transfer.

This, in turn, creates a problem in that the trapmust discharge twice the amount of condensateinto what is often an undersized return line.

Ensure that the piping allows the condensateto be removed effectively (Remember, waterruns downhill.)

Figure 1. Total Heat in 100 psig Saturated Steam


64

Many plants have water hammer, and peoplebecome complacent about it, not realizing thedamage it can cause to pipe work and associatedequipment. It can also create a personnel safetyhazard by leading to pipe breakage and possibleescape of live steam.

Water hammer is caused by:

1. Slugs of water traveling down the pipeline athigh speed. Steam has an average velocity of8,800 ft per min. (100 mph).

2. Thermal shock created by mixing of cold andhot discharges.

3. Hydraulic shock (solenoid valves).

The first two are the most common causes andcan be minimized by installing the correct drippocket design/location and return line designs.

Verify that the return line sizing is correct andensure all line direction changes are taken intoaccount when designing your piping.

After reviewing upstream piping, it is impor-tant to ensure that downstream design does notcontain any restriction or introduce water ham-mer.

This is an increasing problem because more con-densate is being returned to the boiler either be-cause of EPA rules or for cost effectiveness.

How often do people take the time to check thatthe line is large enough to handle the condensateload? Correct sizing provides a return line thatoperates only partially full, creating a soft system.

Undersizing is like squeezing a quart of liquid intoa pint container. This creates a higher return pres-sure, as well as water hammer, and leads to lessefficient handling of condensate.

Also, the return line must never run uphill.

It is sometimes forgotten in piping design that rais-ing the trap discharge by, say, 20 ft. to connect topipework creates an energy drain.

Figure 2. Trap Discharge Arrangements

Figure 3. Steam Line Drains


65

Back pressure is approximately 1/2 psi for eachfoot (e.g. 20 ft. is equal to 10 psi). This alsolowers the differential pressure across the trap,thus reducing the volume of condensate it canpass.

Figure 2 demonstrates the correct positioning oftrap discharges into the main condensate returnline. They should always enter at the top, other-wise there will be mixing of hot and cold liquids,causing water hammer.

TRAP MAINTENANCE/SURVEY

Even with the correct type and size of steam trapinstalled, a maintenance program is essential tomaintain optimum performance. Here are somepointers:

Check traps at least annually.Verify trap operation by at least two of theaccepted methods: visual, sound, tempera-ture.Insulate lines but never the trap (you mightnot find an insulated trap and it could affectthe trap’s operation).Install the trap where it can be serviced easily(difficult loactions will not get checked).

If a steam trap is properly selected, sized, installedand maintained, it will provide many years of

trouble-free service. However, it is importantto remember tht the trap is only one part of thesystem, so careful attention should be paid toother equipment and conditions that could af-fect its performance.


John ToddYarway/TycoEmail: [email protected]: (610) 832-2272

Table 1. Characteristics of Various Steam Trap TechnologiescimanydomrehT c itatsomrehT lacinahceM

csiD notsiP reveL swolleB cillatemiB toliP detrevnItekcuB

&taolFcitatsomrehT

egrahcsiD cilcyc cilcyc cilcyc /cilcycgnitaludom

/cilcycgnitaludom

cilcyc /cilcycgnitaludom

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egrahcsiDerutarepmeT

toh toh toh /tohdeloocbus

/tohdeloocbus

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gnitneVriA riaf doog tnellecxe tnellecxe tnellecxe tnellecxe roop doog

gnildnaHtriD doog doog tnellecxe riaf/doog riaf doog doog doog

taehrepuS tnellecxe tnellecxe tnellecxe riaf/doog doog doog roop roop

remmaHretaW tnellecxe tnellecxe tnellecxe riaf/doog doog doog doog roop

esnopseR doog tnellecxe tnellecxe tnellecxe riaf doog doog tnellecxe

edoMliaF nepO nepo nepo esolc/nepo nepo nepo esolc/nepo desolc

gnizeerFytilibitpecsuS

on on on on on on sey sey

evitisneSnoitisoP on on sey on on on sey sey

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sey sey sey on sey on on on

c


66

STEAM TRAP CRITERIA/APPLICATIONS

While the main purpose of this article is to ad-dress the problems of steam systems, plant per-sonnel also need to be aware of some steam trapspecifics:

Sizing and selectionSteam trap sizing and selection criteria includethe following:

Technology.Operating pressure and discharge capacity.Ensuring that trap characteristics are suitablefor the application discharge temperature.Venting ability.Suitability for drainage and pipe design.Freeze resistance.Ease of trap installation, checking and main-tenance.

ApplicationsThe three main applications for steam traps arelisted below.

1. Drip. The purpose is to remove condensatefrom piping to prevent damage to the pip-ing, control valves, strainers, etc., while as-suring that production steam users receive drysteam. To achieve this, here are some checkpoints (see Figure 3).

Provide adequately sized drip pocket (28-in.minimum length) to match pipe size (e.g. onan 8-in. header, there should be an 8-in. di-ameter drain pocket).The trap connection should be on the side,about 6 in. from the bottom of the pocket toensure that clean condensate is presented tothe steam trap.Include a dirt blowdown valve at bottom ofpocket to remove dirt or scale.Provide a trap every 300-400 ft.Locate drip pockets upstream of controlvalves, at all piping direction changes and, atthe end of the line.

2. Tracing. This is the most maligned and leastconsidered application, yet it is often vital andcould be the subject of an article by itself.

A few applications include process line trac-ing, winterization, instrument protectionand steam jacketing. All of these have thecommon purpose of ensuring that efficientsteam is distributed. Some points to remem-ber are:

Match tracing loads to tube size.Limit the tube run to 100 ft.Have only one trap per system.Make sure the trap is located at low point.Adequately insulate the line, not the trap.

3. Process. Depending on the application, thesteam trap will probably have to handleheavy start-up loads, often followed bysmaller running loads. The trap’s functionis to drain the process equipment and thusensure that effective heat transfer is achieved(through latent heat). A few guidelines foroptimum results include:

Provide an adequate size process connectionfrom equipment.Locate trap below the equipment (water runsdownhill).Use good piping practice to ensure that cleancondensate is presented to the trap (samerules as drip pocket).Include air vents and vacuum breakers asnecessary for effective equipment operation.


67

Steam Digest 2001Ultrasonic Testing Tips for Steam Traps and Valves

69

Ultrasonic TestingTips for Steam Trapsand ValvesBruce Gorelick, Enercheck Systems, Inc.

ABSTRACT

Steam can exist anywhere in a system. Steam maybe escaping through external or internal leaks infittings, valves or controls, from oversized steamtraps, or traps that are blowing, leaking or pluggedwith dirt.

Steam may be lost through uninsulated valves,flanges, sections of steam pipe, or through highback pressure in condensate lines caused by blow-ing traps. A control valve unable to close becauseof "wiredrawing" or undersized steam and con-densate lines with no provision for utilizing flashsteam could all be sources of wasted energy.

Testing Tips for Common Problem AreasIt is essential to know how each steam trap or valveworks under specific conditions in order to be ableto diagnose a problem correctly. To determine leak-age or blockage, touch the ultrasonic instrumentupstream of the valve or trap and reduce the sen-sitivity of the detector until the meter reads about50. If you need to hear the specific sound qualityof the fluid, simply tune the frequency until thesound you would expect to hear becomes clear.Next, touch downstream of the valve or trap andcompare intensity levels and, for traps, sound pat-tern levels. If the sound level is louder downstream,then fluid is passing through. If the sound level islow, then the valve or trap is closed.

Check ValvesWhen check valves are placed closer than threefeet downstream of blast action traps (such as in-verted bucket or thermodynamic types) flappersmay loosen or even break free. Damaged checkvalves will usually become noisy. When controlvalves are grossly oversized they are forced to workclose to their seats. High velocity wet steam actsalmost as sandpaper, cutting the seat when a mix-ture of steam and water is forced through the tinycrevice. With an ultrasonic instrument you candistinguish between normal machine noises and

sounds that spell trouble. To verify data, use theinstrument to test nearby units and compare.

Control Valves/Pressure-ReducingValvesAir operated control valves may be leaking at oraround their diaphragms. Scan the exterior sec-tions listening for the turbulent sounds createdby a leak. Test ultrasonically for internal leakageas you would for any other valve. It will be neces-sary to momentarily close the valve to performdefinitive testing. For those valves with dia-phragms, listen for leakage at the small bleed hole.This is a dead giveaway that a rupture has takenplace.

SolenoidsListen for leakage through solenoids that are in aclosed position. You will be able to detect whichvalve is leaking even when it is part of a large bankof valves. If you are in doubt about a judgmentcall, compare with similar valves.

Relief ValveIn a steam system, relief valves that have openedby excess pressure may not reseat properly. Somewith softer seats may be chattering or may suffermicroscopic steam and water cuffing. Ultrasonictesting will detect the turbulent passage of steamor vapor as it moves through the leak site. Touchthe instrument’s stethoscope at the point on thevalve closest to the orifice and then touch thedownstream piping. Leaking and blowing valvesare easily identified. Augment your test with ahand-held infrared thermometer for temperaturedifferentials.

Condensate Return PumpsListen for the static noise indicating a vaporiza-tion bubble collapsing around the impeller. If indoubt, test similar pumps and compare. Remem-ber to test volute pump casing temperatures withan infrared thermometer.

Pressure Powered Pump Needle ValvesThe needle valves on steam or air powered con-densate movers, like any other mechanism, willdeteriorate over time. Listen for seepage of steamthrough worn valves, usually indicated by a highpitched whistling sound. When more then onepump exists, comparisons can be useful.

Steam Digest 2001Ultrasonic Testing Tips for Steam Traps and Valves

70

Valve, Piping and Gland LeakageUse the ultrasonic instrument to scan all parts ofthe steam system for the sounds of turbulence. Itwill be a reality check to find out how many areasare actually leaking.

CONCLUSION

A maintenance program is critical in using steamefficiently. Implementing these simple steps canhelp any facility realize as much as a 34 percentsaving on steam energy costs alone. Not many in-vestments pay such high dividends. To establishan effective program, determine the optimummaintenance schedule for each trap and follow it.It would be difficult to find a less time-consum-ing program that is as cost effective.

Warnings of possible steam trap failure:

An abnormally warm boiler room.A condensate receiver is venting excessivesteam.A condensate pump water seal is failing pre-maturely.The conditioned space is overheating or un-der-heating.Boiler operating pressure is difficult to main-tain.Vacuum in return lines is difficult to main-tain.Water hammer.


Bruce GorelickEnercheck SystemsEmail: [email protected]: (704) 841-9550

Steam Digest 2001Reliable Systems and Combined Heat and Power

71

Reliable Systemsand CombinedHeat and PowerDavid Jaber, (formerly with) Alliance to Save EnergyRichard Vetterick, TRC Energy

ABSTRACT

Leading industrial companies and institutions areforever seeking new and better ways to reduce theirexpenses, reduce waste, meet environmental stan-dards, and, in general, improve their bottom-line.One approach to achieving all of these goals is a100 year-old concept, cogeneration or combinedheat and power. Efficiency of cogeneration sys-tems can reach 80 to 85 percent. Benefits of thisthroughout the plant include reliability enhance-ments and cost and emission reductions. Cogen-eration schemes and systems can be modified tothe plant design. The applicability of cogenera-tion to an industrial plant depends on the varia-tions in steam and energy required for operationon both daily and yearly scales.

Cogeneration is receiving increased attention dueto newer technologies that are making cogenera-tion opportunities available to smaller-sized ther-mal plants. Combined with electric utility de-regulation opportunities, this is causing many in-dustrial decision-makers to seriously consider co-generation for their manufacturing plants. Theadvent of energy service companies has made fi-nancing of cogeneration projects attractive, help-ing to guarantee an acceptable return on invest-ment.

Whether steam is created through cogenerationor separate generation, many opportunities existto improve performance and productivity in steamgeneration, distribution, and recovery. These op-portunities are captured by the systems approachpromoted by programs such as the Departmentof Energy’s (DOE) Steam BestPractices.

INTRODUCTION

Industrial and institutional plants need thermalenergy, generally as steam, for manufacturing pro-

cesses and heating. They also need electric powerfor motors, lighting, compressed air, and air con-ditioning. Traditionally, these fundamental needsare met separately. Steam is produced with in-dustrial boilers and electricity is purchased from alocal utility company. However, these needs canbe met at the same time with cogeneration, usingthe same heat source and on a regional scale, greatlyincreasing the overall efficiency of energy genera-tion.

Cogeneration is the concurrent production of elec-trical power and thermal energy from the sameheat source. Large steam users commonly takeadvantage of cogeneration by using high pressuresteam with a back pressure turbine to generate elec-tricity, and extract lower pressure steam from theturbine exhaust for their process needs. This ap-proach provides reliable energy while reducingtheir electric utility bills and providing thermalenergy for industrial processes.

The steam turbine generators used by electric utili-ties require moderately high steam pressures andtemperatures, with levels ranging as high as 4,400psig. and 1,100° F respectively. This is expandeddown to approximately 20 to 25 in Hg vacuumand 90° F to 100° F in the condenser, where the“latent heat of vaporization” is removed and dis-charged to the atmosphere, lakes, or rivers. In-dustrial processes are typically smaller systems us-ing lower pressure and temperature levels, rang-ing down from approximately 1,000 psig. and750° F to 150 psig. and 366° F (saturation tem-perature). The lowest heat intensity level processesare steam heating systems where pressures and tem-peratures of 15 psig. and 250° F are frequentlyutilized.

THE BEST OF BOTH WORLDS:COGENERATION

The steam generation cycle alone has a typical ther-mal efficiency of approximately 80 percent, de-pending on system loads, the fuel utilized, andthe heat traps designed into the back-end of theboiler. Industrial boilers and utility boilers canachieve these efficiency levels while producingsteam for their respective applications. Note thatthis efficiency level does not take into account theefficiency of the applications using the process


72

steam or the efficiency of the steam distributionsystem.

Most utility thermo-electric steam power plantsoperate in the range from 30 to 40 percent effi-ciency depending on the throttle pressure and tem-perature, the number of reheater loops, the num-ber of feedwater heaters utilized, and the type ofheat traps utilized on the boiler. The gas turbinedriven electric generator has historically operatedin the high 20 to 30 percent range, but with today’shigh gas temperatures and compressor outlet pres-sures, the efficiency is ranging upwards of 35 per-cent. The latest utility power plant designs utiliz-ing a combined cycle (a form of cogeneration) havehigh heat intensity gas power turbines exhaustinginto heat recovery boilers. Steam from these boil-ers then feeds a moderate heat intensity steam tur-bine generator. The combined operating efficien-cies are in the 55 to 58 percent efficiency range.There are prototype designs being tested that ex-ceed 60 percent.

However, modern industrial steam-electric cogen-eration systems can boost overall thermal efficiencylevels to an enviable 80 to 85 percent by recaptur-ing enough waste heat from electricity-producinggas turbines to meet a portion of the industrialprocess requirements.[1] Typical non-industrialcogeneration users are college and university cam-puses, hospitals, municipal heating systems, andlarge commercial buildings. In addition to achiev-ing high system thermal efficiency, steam-electriccogeneration systems can, if designed properly:

Enhance the reliability of the power supplywith on-site generating capacity to supportoperations during utility and electrical distri-bution line upsets.Reduce fuel costs by 15 to 20 percent by ex-tracting more energy from the fuel when op-erating in the cogeneration format.Reduce or eliminate power purchases.Reduce overall emission levels from lower fueluse.Potentially provide additional revenuethrough sale of excess power to a district en-ergy system or the utility electric grid.Maintain the high reliability of the singleboiler process steam system by utilizingsupplemental firing.

In terms of emissions and dollar savings, the dif-ference between cogeneration and separate steamand electricity generation can be significant. Typi-cally, cogeneration cuts fuel costs (which can rangefrom 30 to 40 percent of the selling price of power)by increasing the amount of “salable product” perunit of energy.

OUTLOOK

Cogeneration represents over half of all new powerplant capacity built in North America in the last10 years. This includes utilities and independentpower producers (IPPs) as well as cogeneration byindustrial companies and institutions. As of 1994,it accounted for 6 percent of total U.S. electric-ity-generating capacity. Of the electricity actuallygenerated, 9 percent came from cogeneration.

Deregulation of the electricity market could openthe door for renewed growth in cogeneration, butlots of potential utility and permitting-barriers stillremain. Lower demand for electricity and in-creased utility resistance to industrial cogenera-tion are expected to diminish the prospects of see-ing any new incentives for installing cogenera-tion.[2] However, utility deregulation and increas-ing concern about climate change are raising ques-tions relative to the long-term availability and re-liability of conventional power. These concernsand the availability of new low-cost generatingtechnologies have piqued the interest of industrialand commercial customers with high thermalloads, high electricity rates, or both.

The deregulation opportunity is expected topresent itself in two important areas: increasedcompetition and increased marketability of lowcost cogeneration-produced electricity. Increasedcompetition in the electric market will result inlower electricity rates, which could make it moredifficult for cogeneration projects to compete withlarger utility companies. Again, this difficulty willvary across the country as electricity rates vary.Marketability of cogenerated power will increasebecause cogenerators will be able to sell excesspower to customers other than their local utility.That means industrial cogenerators will be ableto sell electricity to the public, to other industri-als, to power brokers, and to distribution compa-nies by wheeling it to them through the local


73

utility’s distribution system. Retail wheeling willbe especially attractive in areas with very high elec-tricity rates.

TYPES OF COGENERATION SYSTEMS[3]

There are three basic types of cogeneration systems,categorized by the “prime mover” of the system:engine-based, steam turbine-based, and gasturbine-based. Each is briefly characterized below.

Engine-based SystemEngine-based systems use an internal combustionengine to power a generator. Waste heat is re-claimed by sending exhaust to a steam generator,and by extracting heat from the engine and oilcooling systems. Since engine-based systems areonly capable of producing low-pressure steam, theycannot be used by industries requiring pressureover 30 psig.

Of the three major types of cogeneration, engine-based systems possess the highest power-to-steamratio.

Power-to-steam ratio: > 1.Size range: 10 kW – 16 MW; Typical size: 1MW.Usable fuels: Gasoline and oil.

Unfortunately, engine-based cogeneration systemssuffer from frequent breakdowns, thereby raisingtheir operating and management costs, and in-creasing the costs of firm power back-up from lo-cal utilities. However, they have fairly low capitalcosts, simple operating and repair procedures, andgood load-following ability. In terms of emissions,diesel engines produce substantial amounts of ni-trous oxide (NO

x) and particulates while natural

gas engines emit unburned hydrocarbons. Bothtypes, however, emit low amounts of carbon mon-oxide (CO) and sulfur dioxide (SO

2).

Steam Turbine-based SystemThe steam turbine-based system relies on a con-ventional boiler to generate high-pressure steam.The high-pressure steam is then expanded acrossa high pressure turbine and the exhaust is routedto the process steam header. The high-pressureturbine generates electricity while functioning sim-ply as a pressure reducing valve, providing the

desired steam conditions to the process or heat-ing system. The electrical power is generated atvery high levels of thermal efficiency (95 to 96percent) as there are no losses to the condenser.This is referred to as a backpressure turbine (seeFigure 1).

Power-to-steam ratios: 0.1-0.2.Usable fuels: Gas, coal, oil, natural gas, bio-mass, wood, municipal solid waste, or indus-trial waste.Size range: 10 kW – 400 MW, Typical size:10 MW.

Back-Pressure Steam Turbine-SystemsThese systems are good producers of heat, but lowpower producers. Therefore, they are particularlyuseful where large amounts of steam (a large ther-mal load) and moderate amounts of electricity (alow electric load) are needed. This system alsoallows for large electrical drive motors to be re-

Figure 1: Boiler with Backpressure Turbine

Figure 2: Gas Turbine with Heat Recovery SteamGenerator


74

placed with back-pressure turbine drives, therebyreplacing electrical consumption with steam at ap-proximately 90 percent efficiency. The steam tur-bine drives are durable, reliable, and good load-followers. Overall emissions depends on the fuelused to fire the boiler. Coal and biomass produceNO

x, SO

x, and particulates, while oil and natural

gas produce CO and NOx.

Gas Turbine-based SystemGas turbine systems use a conventional combus-tion turbine to generate electricity. After electric-ity is generated, the exhaust from the gas turbineis fed to a thermal process, such as a heat recoverysteam generator, to produce steam (Figure 2).

Power-to-steam ratios: 0.6 - 1.0.Usable fuels: natural gas and oil.Size range: .02 MW - 300 MWTypical size: 5 MW.

Gas turbines efficiently produce power, steam, andheat in concert and are, therefore, very attractivefor cogeneration uses. However they require ahigh-quality fuel, are poor load-followers, and theirtechnical complexity requires specially-trained staffto maintain them. In place of in-facility staff,smaller units can be offered with maintenancecontracts and spare units kept available for quickchangeouts.

Various elements of these systems can be combineddepending on power and steam needs. For ex-ample, a combined-cycle gas turbine system coulddivert available steam to turn a steam turbine formore electricity, which can boost the power-to-steam ratio to the 1.5 range. Thus, when the pro-cess thermal load is down, the steam can be usedfor peaking power.

IS COGENERATION RIGHT FOR YOU?

With today’s technology developments in smallgas turbines, along with the use of supplementalfiring to support thermal peak loads swings, co-generation is an economical and practical choicefor small energy users as well as the large processindustry users. As cogeneration attracts a largerbase of applications, potential for improved en-ergy efficiency and reduced environmental pollu-tion increases. The DOE recently launched the

Industrial Combined Heat and Power (CHP) Ini-tiative to further enhance the adoption of cogen-eration and related systems.

Characteristics of Facilities Well-Suited forCogenerationIndustries that use consistent, simultaneous quan-tities of both electricity and steam with relativelyhigh energy costs are the best candidates for co-generation adoption. These often include foodprocessing, chemical manufacturing, primarymetals, commercial laundries, drywall manufac-turers, and paper mills. Demand for both steamand electricity should be year-round and have anacceptable mix of loads over the course of a day.The key to success of these systems is the abilityto match the size and loads of the combined elec-tric and steam systems.

“This [cogeneration] project is an important stepin increasing the overall efficiency and cost effec-tiveness of the operation at the Hawkins PointPlant.” -John Davis, Millennium Chemical

A perfect fit is not likely to happen, and the sys-tem must be properly sized and engineered toachieve maximum efficiency, reliability, and op-erability. Numerous combined cycles have lookedquite good on paper, only to fall short of theirgoal because the load requirements of the two sys-tems didn’t match as planned. Options in propermanagement of steam facilities include:

Business as usual.Maintaining the status quo with implemen-tation of best maintenance and operation prac-tices.Upgrading to a cogeneration system.Outsourcing energy decisions to a third-partysuch as an energy services company.

Websites with more information on cogenerationinclude www.oit.doe.gov/chpchallenge andwww.nemw.org/uschpa.

SYSTEMS THINKING

When considering which option to take, “systems”thinking offers the most advantageous way to op-erate a plant. Systems thinking applied to a facil-ity involves looking at the overall plant resource


75

and energy consumption and production to de-termine the areas in greatest need of optimiza-tion. It also applies to looking at systems indi-vidually. In incorporating systems thinking, itis useful to use The Natural Step (TNS).[4] TNSguides businesses in developing for their long-term future. It has a framework based on simplethermodynamic principles and has developedseveral tools as guides. One of these tools, theCompass, entails:

1. Visualizing how you would like to be operat-ing decades into the future.

2. Assessing your current inputs, outputs, andoperating practices.

3. Formulating a path to help you achieve thisdesired level by changing practices, policies,and operations.

This provides direction to the company as a whole.The same principle applies to energy systems.First, visualize how the steam system should beoperating. Second, assess current operation. Andthird, identify the areas for improvement and theresources which allow them to be changed.

Cogeneration can be an integral part of the pathto the ideal state of operation. However, the cur-rent state of practices and operations must alreadybe conducive to making the move to cogenera-tion.

BESTPRACTICES

Systems thinking and identification of areas of im-provement can often be difficult. Fortunately, aclearinghouse of resources has been established forsteam system management. BestPractices Steamresources, offered by the DOE’s Office of Indus-trial Technology (OIT) in conjunction with thenon-profit Alliance to Save Energy, encourages asystems perspective that views individual energy-consuming components as part of a total system,focusing on the entire plant where significant sav-ings can be found. Resources include tip sheets,case studies, lists of training courses, technical ref-erences and standards, assessment tools, and op-erational handbooks. These are available on-lineor through the Industries of the Future (IOF)Clearinghouse, (800)862-2086.

What is BestPractices?BestPractices brings together the best-availableand emerging technologies, and practices to as-sist industries to improve their competitiveposition, of which steam is one component.Through the BestPractices approach, industryhas easy access to both near-term and long-termsolutions for their total manufacturing plantoperations today. Any plant can realize near-term cost-effective energy savings between 10to 30 percent in three to five years. By apply-ing the best technologies and practices available,industry can:

Prioritize energy efficiency investments for thegreatest return on investment.Receive training, tools and documents to helpimplement projects.

The Industries of the Future Clearinghouse hasmore information on how to begin implementa-tion of best practices.

Participation in BestPractices Steam efforts is opento steam system operators and managers, devel-opers and distributors of steam systems equipment,as well as steam trade and membership organiza-tions. This active participation ensures thatBestPractices provides tools and resources that arevaluable to industrial steam operators and man-agers. It also assists steam equipment and serviceproviders, such as utilities, distributors, manufac-turers, consulting engineers, and others promot-ing steam efficiency by serving as a valuable sourceof third-party, credible information.

CONCLUSION

With cogeneration achieving efficiency levels over80 percent, fuel costs and emissions are loweredand additional profits are available from the saleof excess power. Advanced design and new tech-nology has lowered generation capacity tremen-dously, to the point where even small plants canfeasibly install cogeneration facilities. Cogenera-tion combined with the energy delivery improve-ments suggested by BestPractices Steam increasesthese benefits even more. However, before install-ing a cogeneration system there are several screen-ing factors to be considered, including individualthermal profile, initial capital outlay, permittingstandards, and readiness to be in the power pro-vider business. Existing steam system componentswhich support cogeneration equipment must be


76

running as efficiently as possible. BestPracticesSteam helps prepare industry for future cogenera-tion. In addition, the same wealth of benefits ac-crues for improved environmental and economicperformance. While the future of cogenerationin states’ deregulation remains hazy, it will con-tinue to be a “power”ful generation option.


Richard VettrickTRC EnergyEmail: [email protected]: (330) 864-2549Web address: www.trc-energy.qpc.com

REFERENCES

1. Steam: Its Generation and Use, 40th Edition, Babcock& Wilcox, Chap. 2: “Thermodynamics of Steam”, 1992,Barberton, OH.

2. 1997 Industrial Cogeneration Report, Chapter 2, GasResearch Institute, Chicago, IL.

3. Ibid.4. TNS is a movement dedicated to helping understand

our social and environmental problems and moving be-yond them by redesigning our interactions with our sur-roundings as businesses, communities, and individuals.

Steam Digest 2001Business Benefits from Plant Energy Assessments and Energy Management

77

Business Benefitsfrom Plant EnergyAssessments andEnergy ManagementDavid Jaber, (formerly with)Alliance to Save Energy

Would you like to improve your process opera-tions? Could you use an extra $100,000 to oper-ate your textile mill? If so, an energy assessmentand energy improvement project may be for you.

In pursuit of higher productivity and lower oper-ating costs, M.J. Soffe, a producer of athletic cloth-ing, recently assessed its steam, motor, and com-pressed air systems for improvement opportuni-ties at their largest and most integrated manufac-turing plant. The facility reports that it increasedits throughput capacity by 37percent while reduc-ing the energy needed per pound of product by38 percent, saving $165,000 annually in fuel ex-penditures.

As with many energy projects, M.J.Soffe foundthat the benefits are not limited to utility and fuelcost savings, but also include improved produc-tivity, increased equipment life, decreased risk of

financial penalties, and increased order turn-around. A plant energy assessment identified thesavings opportunities detailed in Table 1. Envi-ronmental emissions and penalty risks are alsogenerally improved with energy efficiency projects.These projects are often low-risk investments andeasily implemented. For example, when a Geor-gia Pacific plywood plant in Georgia insulated sev-eral steam lines leading to its pulp dryers and re-placed steam traps, it lowered emissions of green-house gases and Clean Air Act pollutants by 9.5million lbs of carbon dioxide (carbon equivalent),3,500 lbs. of SOx, and 26,000 lbs of NOx on anannual basis.[2]

IMPORTANCE OF ENERGY MANAGEMENT

Because of the power of the plant audit to leadtoward impressive improvements, the U.S. Depart-ment of Energy (DOE) partners with U.S. manu-facturers to take a comprehensive, systems ap-proach to increasing energy efficiency and savingsopportunities, focusing on steam, motor, com-pressed air, combined heat and power, and pro-cess heating systems. On August 1, 2000, DOEre-opened a solicitation for industrial manufac-turing plant-wide energy assessment proposals.Under the proposal, DOE shares up to 50 per-

Table 1. Sample Energy Assessment Findings

YTINUTROPPO NOITPIRCSED

taeHretawetsaWdnamaetSyrevoceR

ybdetalfniyllaicifitraerewslacimehctnemtaertdnaleufreliobfostsoChtiwpupeektondluoctahtmetsysgnitaehretawtneiciffenina

otretawtohfosnollagfosdnasuohtnidetlusersihT.segrusnoitcudorp.etsawetasnednocmaetsdnamaetsevissecxednadepmudeb

etasnednocmaetsdesaercnihguorhtdevassawyllaunna000,041$ahtiwdelpuocretawetsawehtmorftaehfoyrevocerdnayrevocerfonoitcuderdewollayrevocertaeH.nalpecnanetniampartmaets

noitcudorprofdedeenreliobenoylnohtiwerusserpnoitarenegmaetsregnolsnaemoslaerusserpmaetsdecudeR.owtnahtrehtar

.efiltnempiuqe

redrognisaercniosla,tnecrep73ybdesaercniyticapacgnieyD.emitkcabyapraey7.2ahtiwtcejorpani,dnuoranrut

riAdesserpmoCdnarotoMsmetsyS

tnalpehtgnivorpmiybdecudersawseitlanepytilitucirtcelefoksiRdnaesahcruprotomagnitnemelpmiybenodsawsihT.rotcafrewop

.seitiliturotomtneiciffeeromdnayciloptnemecalper

owtgniniojybraeyrep000,01$ybnwodtnewoslastsocyticirtcelEehT.rosserpmocriaegralaffogninrutdnasmetsysriadesserpmoc

]1[.ecnanetniamsselseriuqermetsyselbailererom


78

cent of the plant assessment cost, up to a $100,000limit. DOE also provides technical assistance,tools, and resources as desired by the company.

The true demands of energy production are sig-nificant. Steam systems, integral to many textiledrying processes, account for approximately 35percent of fuel used by U.S. textile manufactur-ing plants.[3] Further, the Alliance to Save En-ergy estimates that a typical plant can improve theefficiency of its steam system by 20 to 30 percentthrough opportunities in steam generation, dis-tribution, end use, and recovery. Thus, the tex-tile industry can particularly benefit by keepingsteam systems in tune.

RESOURCES FOR IMPROVING PLANT

PERFORMANCE

Many manufacturers may be interested in im-proved energy management, but where do theystart? A collection of public resources is availablefor systems operations and maintenance. Al-though much commercial information focusesonly on particular system components, DOE hasestablished a library of information as a “one-stopshop” on entire plant energy systems. For example,in partnership with a public/private network oforganizations and the Alliance to Save Energy, anational non-profit organization, many steam-sys-tem specific resources have been developed. TheDOE offerings include:

Sourcebooks that give a comprehensive sys-tem overview and reference sources for spe-cific information.Best practice tip sheets with technical im-provement suggestions.Case studies that highlight what leading com-panies have accomplished in business perfor-mance improvement.Training courses and commercial trainingcourse lists in motor, compressed air, andsteam systems.Free plant audits for small and medium manu-facturers through the Industrial AssessmentCenters(IAC). The IACs are university teamscomposed of students and professionals.Software for motor management, optimizinginsulation, screening pumps, and assessingplant cogeneration feasiblity.

Deployment of state-of-the art emerging tech-nologies developed by and for the paper in-dustry and/or other manufacturing sectors.Technology research and development oppor-tunities to help create tomorrow’s technologyfor the manufacturing plant.

Additionally, a technical assistance hotline is avail-able to answer many plant energy system ques-tions through the BestPractices clearinghouse andwebsite. Together, the Clearinghouse and thewebsite allow access to the cost sharing agreementand all resources.

STEPS FOR BETTER PERFORMANCE

Step 1: AssessmentGo through your plant to look for savings oppor-tunities. To help determine which systems offerthe largest potential in savings, the DOE cost-shareproposal enhances the financial appeal of energyauditing. Many private companies specialize inspecific system auditing, and can help from there.

Step 2: Salesmanship to Financial Deci-sion-MakersPrepare an energy improvement project proposalin language compelling to upper company man-agement. Part of this process is becoming knowl-edgeable on the financial criteria your companyuses to screen projects, such as internal rate of re-turn or return on assets. Meet with your com-pany accounting and management staff. It canhelp to increase understanding of what each sideneeds and expects. It can also improve your projectfunding prospects.

It must be remembered that energy improvementprojects may bring a host of plant changes, suchas decreased downtime, a safer workplace, in-creased employee productivity, increased plantmaintenance, plant productivity improvements,and decreased waste. A proper project proposalwill attempt to quantify these savings and costs sothe project impacts are clear to the financial deci-sion-makers. The Alliance to Save Energy offerssome guidance in this area.

Step 3: ImplementationLook at the DOE BestPractices website and callthe Clearinghouse. Determine which of the re-


79

sources are most likely to help you with plant im-provements. Tip sheets are very useful in improv-ing maintenance practices and are specific enoughto offer guidance.

Step 4: DocumentationRecord the project process and results. Documen-tation allows successful projects to be replicatedthroughout the company. It is important to shareproject benefits to help institutionalize the knowl-edge and experience gained, so others may followwhere a few have led. Otherwise, success is de-pendent on a few people, who may or may not beavailable.

Step 5: NetworkingOther companies can also have valuable insightson improvement. To the extent possible, network-ing between companies is a powerful way to dis-cover what the best are doing and share successes.Networking gives access to the universe of suc-cesses which can benefit your operation. DOEwill also partner with you to discover these exter-nal successful projects and help document yourproject in a case study.

Taking advantage of peer contacts, conferences,and workshops is invaluable in making these con-nections.

CONCLUSION

Too many manufacturing facilities are not achiev-ing their full potential because of poorly-operat-ing energy systems. Energy efficiency lies at therarely visited intersection of improved economicperformance, greater process efficiency, and envi-ronmental benefit—a win-win-win situation. Bytaking advantage of public and private energy man-agement resources and following key steps in as-sessment, salesmanship to financial decision-mak-ers, implementation, documentation, and net-working, you, too, can realize success.



REFERENCES

1. U.S. Department of Energy Draft Case Study, May2000. Plant Utility Improvements Increase Profits andProductivity at a Clothing Manufacturing Comples, 4 pp.

2. U.S. Department of Energy. November 1998. TheChallenge: Increasing Process and Energy Efficiency at aPlywood Plant, 4 pp.

3. Calculated using the Energy Information Administra-tion 1994 Manufacturing Energy Consumption Sur-vey.

Steam Digest 2001Use Spread-Sheet Based CHP Models to Identify and Evaluate Energy Cost Reduction Opportunities in Industrial Plants

81

Use Spread-Sheet BasedCHP Models to Identify andEvaluate Energy CostReduction Opportunities inIndustrial PlantsJimmy Kumana, Consultant

ABSTRACT

CHP for (Combined Heat and Power) is fast be-coming the internationally accepted terminologyfor describing the energy utilities generation anddistribution systems in industrial plants. The termis all inclusive - boilers, fired heaters, steam tur-bines, gas turbines, expanders, refrigeration sys-tems, etc.

A simulation model of the CHP system is an ex-tremely useful tool to understand the interactionsbetween the various components. Applicationsinclude:

Identifying opportunities for cost reductionthrough efficiency improvement.Accurate energy cost accounting.Evaluating the energy cost impact of proposedprocess changes on the demand side.Comparison of cogeneration options.Identifying load shaping strategies (eg. switch-ing between motors and turbine drives).Negotiating fuel/power supply contracts.

This paper describes how CHP models can bedeveloped easily and at low cost using electronicspreadsheets, and illustrates their application witha detailed example.

INTRODUCTION

The “utilities” plant at an industrial manufactur-ing facility should more properly be called theCombined Heat and Power, or CHP, system. Thisis the prevailing terminology used in Europe andelsewhere in the world, and is increasingly beingadopted in the USA as well. The CHP systemincludes all the elements involved in the genera-

tion and distribution of energy to drive the pro-cess and supporting infrastructure:

Fired boilers.Waste heat boilers.Combustion air preheaters.Economizers (for BFW preheat).Blowdown flash tanks.Condensate recovery systems (steam traps,separators).Condensate mix tanks.Deaerators.BFW pumps.Back-pressure steam turbines.Pressure reducing stations.Desuperheating stations.Gas turbines, with or without heat recoverysteam generators.Condensing steam turbines.Condensers.Cooling water circuits.Refrigeration systems (both mechanical andabsorption type),etc.

The interactions between these various compo-nents can be very complex, and cannot be easilyunderstood without constructing a reasonablyaccurate mathematical model.

CONSTRUCTING THE MODEL

A model is simply a set of equations and con-straints that establishes the quantitative relation-ship between the key parameters of interest.

Consider the CHP system for a pulp/paper mill,as depicted in Figure 1, which incorporates manyof the features found in a typical industrial facil-ity.

The overall model has two distinct elements:

a) Models of individual items of equipment.b) Computational strategy for interactions be-

tween equipment, that also reflects the oper-ating policy.

It is beyond the scope of this article to describe allpossible variations of equipment models, but someselected examples will illustrate the available op-tions for the principal items.


82

Figure 1. Schematic Flowsheet of Combined Heat and Power System


83

Boiler Model One (Simple)Operating mode = base load, constant efficiency

Input parameters = max operating capacity, oper-ating pressure and temp, efficiency, blowdown rate(as percentage of steam generation), operating rate(percentage of max).

Equations:

1. Steam gen = capacity x operating rate2. Blowdown = fraction x steam gen rate3. Feedwater = stm gen + blowdown4. Hs = f(P,T), from steam properties data base5. Fuel input = Stm (Hs – h

BFW)/h

Boiler Model Two (Simple)Operating mode = swing, variable efficiency

Input parameters = max operating capacity, oper-ating pressure and temp, blowdown rate (as per-centage of steam generation)

Equations:

1. Steam gen = Total steam production required(trial value in overall computational algo-rithm) – combined steam generated in allother boilers

2. Blowdown = fraction x steam gen rate3. Feedwater = stm gen + blowdown4. Hs = f(P,T), from steam properties data base5. Operating rate (%) = Stm gen / Capacity6. Efficiency h = f(operating rate), equation to

be provided by user, from manufacturer’s data7. Fuel input = Stm (Hs – h

BFW)/h

Boiler Model Three (Rigorous)Operating mode = base load

Input parameters = max operating capacity, oper-ating pressure and temp, blowdown rate (as per-centage of steam generation), operating rate (per-centage of max), stack gas temp, combustion airsupply temp, excess air ratio, radiative and con-vective heat losses

Equations:

1. Steam gen = capacity x operating rate2. Blowdown = fraction x steam gen rate

3. Feedwater = stm gen + blowdown4. Hs = f(P,T), from steam properties data base5. Efficiency h = calculated from boiler heat and

material balance6. Fuel input = Stm (Hs – h

BFW)/h

Back-Pressure Steam Turbine (Simple)Operating mode = constant load and flow

Input parameters = Pi, Ti, Po, steam flow in (Klb/h), power output rate (kwh/Klb). The latter iscalculated by the user from inlet and outlet pres-sures, inlet temp, and isentropic efficiency.

Equations:

1. Power, kw = output rate x steam flow2. Hs,o = Hs,i – 3412/kw3. To = f(Po, Hs,o), from steam props data base

Back-Pressure Steam Turbine (Rigorous)Operating mode = load following, variable flow

Input parameters = Pi, Ti, Po, power output re-quired, linked to process model, turbine perfor-mance curve (from manufacturer’s data) that ex-presses the steam flow rate as a function of poweroutput for the given Pi, Ti, and Po.

Equations:

1. Steam flow = f(required power output)2. Hs,o = Hs,i – 3412/kw3. To = f(Po, Hs,o), from steam props data base

DeaeratorOperating mode = steady state (see Figure 2 onnext page)

Input parameters = condensate flow and tempfrom process, condensate flow and temp fromcondensing steam turbine, economizer duty, pres-sure of steam used in economizer, DA operatingpressure, temp of makeup water (after preheat-ing), vent vapor flow from DA

Equations:

1. Combined condensate flow, C = process cond+ turbine condensate + economizer conden-sate


84

2. Mixed cond temp = sum (flow x temp) /sum (flow)

3. Assume Hv = Hs (this simplifies the modelwithout significant error)

4. BFW flow, B = sum (feedwater flows to boil-ers) + sum (flows to desuperheating stations)

5. SDA = {C(hM

– hC) + B(h

B – h

M)}/(Hs – h

M) +

V6. Makeup to DA, M = B + V – C - S

DA

Other EquipmentSimilar models must be set up for the blowdownflash tank, desuperheating stations, etc.

Overall AlgorithmNow we need to tie all the various parameters to-gether in an overall computational algorithm. Itis recommended that heat losses due to radiationand leaks be excluded from the model, as they adda tremendous amount of computational complex-ity, make the model extremely difficult to debug,and do not offer compensating benefits. The typi-cal error is about 3 percent, and this can be addedon to the fuel cost.

Input parameters = operating pressure and tempof the various steam headers, process steam de-mands at the various pressure levels, steam flowrates to the back-pressure and condensing turbines,condensate return rate (flow), DI makeup water

supply temp, estimated or allowable vent lossesfrom LP header.Calculation sequence:

Assume a trial value for total steam generation inthe boilers, and then calculate the various para-metric values from the “top down” by applyingestablished principles for steady-state material andenergy balances.

1. PRV flow from HP to IP = sum (steam fromboilers) - process demand – sum (turbine out-flows)

2. Calculate BFW flow to DSH station in IPheader by simultaneous material and heat bal-ance

3. PRV flow from IP to MP = sum (steam in-flows) + DSH stm - process demand – sum(turbine outflows)

4. Calculate BFW flow to DSH station in MPheader by simultaneous material and heat bal-ance

5. PRV flow from MP to LP = sum (steam in-flows) + DSH stm - process demand – sum(turbine outflows)

6. Calculate BFW flow to DSH station in LPheader by simultaneous material and heat bal-ance

7. Calculate flash vapor and net liquidblowdown flows from the BD flash tank, byheat/mass balance.

Figure 2. Schematic of Deaerator and Auxiliary Equipment

ProcessVent condensate

Steam Steam turbine condensateBFW toeconomizer

Utility condensatefrom economizer

Deaerator

BFW pumpProcess heat recovery

Cold DI watermakeup

Deaerator Mixed condensatetank


85

8. Calculate steam and makeup water flows tothe DA from DA model

9. BFW temp = DA temp + economizer duty /B10. Vent flow from LP header to atmos = sum

(steam inflows) + DSH stm + flash vapor fromBD tank - process demand – stm to DA

11. Heat recovery required against process hotstreams = M x (DA feed temp – DI makeupwater supply temp)

12. Calculate total steam generation required inboilers = sum (process demands) + flow tocondensing path of steam turbine + steam toeconomizer + DA steam – BD flash vapor –sum (DSH flows) + LP vent to atmos

Compare the calculated steam generation require-ment with the assumed trial value, and iterate untilthe two agree within the specified tolerance limit(eg. 0.1 Klb/h).

One note of caution – the user should be carefulto ensure that the assumptions and data inputs donot result in infeasible solutions, such as reverseflows (ie from lower to higher pressure) across thePRV, and violating capacity constraints on theboilers and turbines.

APPLICATIONS

Now let us consider some of the practical uses forthis model.

First and foremost, we compare the calculatedsteam and power balance against measured (me-tered) values. If the two are not in reasonable agree-ment it means one of two things:

a) The meters need to be recalibrated.b) The model is not an accurate representation

of the plant, and needs to be corrected.

The error could be in the physical configuration,or in the assumptions about operating policy and/or leaks and heat losses.

Once the data have been reconciled, it is possibleto begin analyzing the system for opportunities toimprove efficiency. The first thing we look for isshifting flow from PRVs to steam turbine genera-tors. In Figure 1, we see that the PRV flows arealready very small, and that the opportunity to

make more power in the back-pressure STs is limited.

We next turn our attention to condensing steamturbines. These are usually “Across the Pinch,”and not cost effective for base load operation. Themodel shows however that if the condensing flowwere reduced to the minimum of 20Klb/h, theoperating cost would go up by $630K per year,which is counter to expectation. This is becausethe swing fuel being used is coal (in power boiler#10), which is extremely cheap.

If the swing fuel were gas, however, then the costsavings would be $910/yr, which is more typical,and would be accomplished by shutting downpackage boilers #5 and 6. The model shows thatnearly a million dollars a year (including mainte-nance and operating labor cost savings) could beachieved by minimizing flow through the con-densing section of the turbines, at zero capital cost.

The next idea we explore is to increase the dutyon the economizer, e.g. from 10 MMBtu/h to 30MMBtu/h. This will mean adding additional heattransfer surface. However, the model shows thatthe cost savings are non-existent, because the in-cremental power credit is almost exactly offset bythe extra cost of fuel. Thus at current fuel andpower prices, there is no incentive to spend anyengineering resources on repairing/revamping theeconomizer. In fact, the model shows that theeconomizer could be taken out of service with nopenalty at all. This insight would probably haveeluded us without a model.

Such preliminary screening allows us to focus onthe projects that are attractive, and cast aside onesthat are not. We can simultaneously evaluate thepotential benefits of common energy conserva-tion and efficiency improvement measures suchas increasing the condensate recovery rate, pre-heating BFW makeup water to the DA, and re-ducing steam consumption in the process throughheat recovery.

For example, increasing condensate recovery from56 percent to 70 percent saves 410 K/yr, whileadding an exchanger to recover 5.5 MMBtu/h ofheat from boiler blowdown saves about $110K/yr, and further preheating BFW makeup by 26MMBtu/h to 150°F (against process waste heat)saves another $190K/yr. It may appear odd that


86

Table 1. Summary of Cost Savings from Various Projects

rebmuNesaC

0 1 2 3 4 5 6 7 8

h/utBMM,ytudrezimonocE 01 01 01 03 0 01 01 01 01

%,yrevoceretasnednoC 65 65 65 65 65 07 07 07 07

F,pmetretawdeefAD 37 37 37 37 37 37 051 051 051

h/utBMM,WFDotnicertaeH 0 0 0 0 0 0 5.13 7.62 7.62

h/blK,sgnivasmaetsPLssecorP 0 0 0 0 0 0 0 002 002

h/blK,negmaetsrelioblatoT 1951 9741 7741 4941 8641 9341 0831 0721 2611

h/utBMM,demusnocleuF

laoC 706 054 545 755 835 294 904 68 8

sreliobnisaG 89 89 0 0 0 0 0 0 0

enibruTsaGsaG 0 0 0 0 0 0 0 0 842

latoT 507 845 545 755 835 294 904 68 652

swolfmaetsrotarenegobruT

PIotPH 002 002 002 002 002 002 002 002 002

PMotPH 684 684 684 505 084 684 684 684 684

PLotPH 086 646 646 346 346 806 945 033 033

gnisnednocotPH 001 02 02 02 02 02 02 02 02

latoT 6641 2531 2531 8631 3431 4131 5521 6301 6301

WM,detarenegrewoplaoT 2.67 1.66 1.66 6.66 6.56 9.36 6.06 1.84 7.16

ry/$MM,tsocgnitarepO 22.71 58.71 13.61 23.61 23.61 19.51 16.51 65.41 39.61

ry/$MM,sgnivasevitalumuC 0 36.0- 19.0 09.0 09.0 13.1 16.1 66.2 92.0

ry/$MM,sgnivaslatnemercnI 0 36.0- 45.1 10.0- 00.0 14.0 03.0 50.1 73.2-

Case Number012345678

DescriptionBase case-existing operationMinimize condensing turbine flow, cut back on coal fired boilerMinimize condensing turbine flow, cut back on gas-fired boilers (can be shut down)Increase economizer duty to 30 MMBtu/hReduce economizer duty to zeroIncrease condensate recovery from 56 percent to 70 percentRaise DA feedwater temp to 150° F by heat recovery against processReduce LP steam demand in process through heat recovery (Pinch Analysis)Add new 15 MW Gas

Note: Numbers in bold in the table are the primary changes made in each case listed.


87

the cost savings are not proportional to the heatrecovery rate. This is because the reduction insteam generation comes from different boilerswhich have different efficiencies, an effect thatwould have been difficult to predict without themodel.

In recent years, cogeneration projects involvinggas turbines have become very popular. The modelcan be used to quickly check whether such aproject would be appropriate for local site condi-tions. The key parameters (heat rate and steam/power ratio) for the machine being consideredmust be provided as input. The model shows thatenergy operating costs actually increase by $2.37MM/yr, because the power:gas cost ratio is notfavorable, and so this project can be immediatelyrejected without further waste of time.

One must keep in mind that the foregoing con-clusions are valid only for the fuel/power costsand equipment capacity/efficiency numbers thathave been used. Under a different set of technicaland economic conditions, the optimum operat-

ing policy could be quite different. The esti-mated cost savings and key parameters for all ofthe various projects discussed above are sum-marized in Table 1.

Finally, we can postulate various levels of steamsavings in the process, in steps of 50 Klb/h, anddevelop a curve showing the net cost savings andthe marginal cost of steam. Figure 3 shows themarginal cost of steam savings is constant overthe entire range of 0-250 Klb/h, which is some-what atypical. Normally, there will be several stepchanges in the marginal cost curve, reflectingchanges in fuel mix (eg. gas vs coal) and boilerefficiency as the high cost boilers are shut down,changes in steam path (eg. PRV versus ST) due tocapacity limitations, or changes in power coststructure as due to contractual constraints.

It is important to recognize that the cost savingsachieved are a function of the order in which theprojects are implemented. Generally, the earlierprojects will have proportionately larger savings,and the later ones will have smaller savings.

CHP operating costs

12

13

14

15

16

17

18

0 50 100 150 200 250 300

Process Steam Savings, Klb/h

Ope

ratin

g C

ost,

MM

$/yr

0.4

0.6

0.8

1.0

Mar

gnal

cos

t, $/

Klb

Op Cost

Marginal cost

Misc design changes, cases 1-6

Figure 3. Operating Cost Savings and Marginal Cost of Steam


88

One of the most powerful applications of suchmodels is their use for on-line real time optimiza-tion of the operating policy for the CHP system.This has been done at many of the manufactur-ing sites owned by progressive companies likeUnion Carbide, BASF, and Chevron.

CONCLUSION

CHP simulation models are a convenient and re-liable tool to evaluate ideas for efficiency improve-ment and cost reduction. They provide accurateestimates of operating costs, and can be used foronline real-time optimization.

The cost of developing a model using electronicspreadsheets is very modest (in the range of $10 –20K, depending on complexity) compared to thepotential benefits.

It is recommended that this tool be adopted byindustry for energy cost accounting and to im-prove energy efficiency, with attendant reductionin operating cost and emissions of greenhousegases to the environment.


Jimmy KumanaConsultantEmail: [email protected]: (713) 260-7235

REFERENCES

J. D. Kumana, “CHP Models for Energy Optimization”, in-vited paper presented at Pfizer Process Engineering Con-ference, Boston, MA (Oct. 26th, 2000)

J. D. Kumana, F. J. Alanis, A. L. Swad and J. V. Shah, “CHPModeling as a Tool for Electric Power Utilities to Un-derstand Major Industrial Customers”, paper 6a pre-sented at 19th Industrial Energy Technology Confer-ence, Houston, TX (Apr. 1997)

R. Nath, J. D. Kumana and J. F. Holliday, “Optimum Dis-patching of Plant Utility Systems to Minimize Cost andLocal NOx Emissions”, Proc of ASME’s Industrial PowerConference, New Orleans, LA (Mar. 1992)

NOMENCLATURE

H enthalpy of steamh enthalpy of liquidkw kilowattskwh kilowatt-hours

P pressureS steam (flow parameter)T temperatureV vapor (flow parameter)h efficiency, percentage

ABBREVIATIONS

BD blowdownBFW boiler feed waterDA deaeratorDI De-ionized (water)DSH desuperheatingHP high pressurei inlet (as subscript)IP intermediate pressureK 1000L liquid (as subscript)LP low-pressureMM millionMP medium pressureo outlet (as subscript)PRV pressure reducing valveS steam (as subscript)ST steam turbineV vapor (as subscript)

Steam Digest 2001Justifying Steam Efficiency Projects to Management

89

Justifying SteamEfficiency Projectsto ManagementChristopher Russell, Alliance to Save Energy

ABSTRACT

Industrial plant engineers often must convince topmanagement that investing in steam efficiency isan effort worth making. Communicating thismessage is often more difficult than the actual en-gineering behind the concept. A corporate audi-ence responds more readily to a dollars-and-centsimpact than to a discussion of Btus and efficiencyratios.

By adopting a financial approach, the plant engi-neer relates steam efficiency to corporate goals.Collaborating with the financial staff yields thekind of proposal that is needed to win over corpo-rate officers who have the final say-so over suchcapital investments as steam system upgrades.

Before any recommendations can be made abouthow to justify steam improvement projects, it isfirst necessary to understand the world as man-agement typically sees it.

UNDERSTANDING CORPORATE PRIORITIES

Corporate officers are accountable to a chief ex-ecutive, a board of directors, and an owner (orshareholders, if the firm is publicly held). Theseofficers create and grow the equity value of thefirm. The corporation’s industrial facilities con-tribute to this equity by generating products witha market value that exceeds the cost of owning andoperating the plant itself.

Plant equipment—including steam system com-ponents—are assets that must generate an eco-nomic return. The annual earnings attributable tothe sale of goods produced by these assets, dividedby the value of the plant assets themselves, describethe rate of return on assets. This figure is a keymeasure by which corporate decision makers areheld accountable.

Financial officers in particular are conservative de-cision makers. They shun risk and resist spendingmoney on the plant itself, if possible. When forced

to do so, they seek investments that are most cer-tain to demonstrate a favorable return on assets.When presented with multiple investment oppor-tunities, they favor those options that lead to thelargest and fastest returns.

This corporate attitude may impose sometimes-unpleasant priorities on the plant engineer or fa-cility manager. Priorities include reliability in pro-duction, avoiding unwanted surprises by prima-rily adopting familiar technology and practices,and contributing to cost control today by cuttingcorners in maintenance and repair. No wonderindustrial decision makers often conclude thatsteam efficiency is a luxury they cannot afford.

Fortunately, the story does not end here. Indus-trial steam efficiency can save money and contrib-ute to corporate goals while effectively reducingenergy use and unwanted noxious combustionemissions in a variety of ways.

MEASURING THE DOLLAR IMPACT

Steam system improvements can move to the topof the list of corporate priorities if the proposalsrespond to distinct corporate needs. The numberand variety of corporate challenges open up manyopportunities to promote steam efficiency as asolution. And steam systems offer manyopportunities for improvement. Once target areashave been selected, the proposals need to be dressedin corporate, dollars-and-cents language.

The total dollar impact of the measure must beidentified and quantified. One framework to useis life-cycle cost analysis. This analysis captures thetotal expenses and benefits associated with an in-vestment. The result—a net gain or loss on bal-ance—can be compared to other investment op-tions or, if no investment is made, to the antici-pated outcome. When used as a comprehensiveaccounting of an investment option, the life-cyclecost analysis for a steam efficiency measure in-cludes several elements:

Search and selection costs of choosing an en-gineering implementation firm.Initial capital costs, including installation andthe costs of borrowing.Maintenance costs.Supply and consumable costs.


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Energy costs over the economic life of theimplementation.Depreciation and tax impacts.Scrap value or cost of disposal at the end ofthe equipment’s economic life.Impacts on production such as quality anddowntime.

A typical boiler installation illustrates this ap-proach. The analysis assumes a 20-year life oper-ating at high rates of capacity utilization. Fuel costsmay represent as much as 96 percent of life-cyclecosts, while the initial capital outlay is only 3 per-cent and maintenance a mere 1percent. Clearly,any measure that reduces fuel consumption (whilenot negatively affecting reliability and productiv-ity) certainly yields positive financial impacts forthe company.

PRESENTING EFFICIENCY ECONOMICS

As with any corporate investment, there are manyways to measure economic impacts. Some are morecomplex than others and proposals may use sev-eral analytical methods side-by-side. The choiceof analyses depends primarily on the sophistica-tion of the presenter and the audience.

A simple (and widely used) measure of project eco-nomics is the payback period. This term is de-fined as the period of time required for a projectto break even. It is the time needed for the netbenefits of an investment to accrue to the pointwhere they equal the cost of the initial outlay.

For a project that returns benefits in consistent,annual increments, simple payback equals the ini-tial investment divided by the annual benefit.Simple payback does not consider the time valueof money. In other words, it makes no distinctionbetween a dollar earned today and one earned inthe future, making earnings figures uncertain. Still,the measure is easy to use and understand, andmany companies use it for making a quick deci-sion on a project. The following factors are im-portant to remember when calculating a simplepayback:

The figure is approximate. It is not an exactanalysis.All benefits are measured without consider-ing their timing.

All economic consequences beyond the pay-back are ignored.Payback calculations do not always find thebest solution (because all factors are not con-sidered).Payback does not consider the time value ofmoney or tax consequences.

More sophisticated analyses take into account suchfactors such as discount rates, tax impacts, andcost of capital. One approach involves calculatingthe net present value of a project, which is de-fined by the equation:

NPW = PWB - PWC

NPW (net present worth)PWB (present worth of benefits)PWC (present worth of costs)

Another commonly used calculation for determin-ing economic feasibility of a project is internal rateof return. It is defined as the discount rate thatequates future net benefits (cash) to an initial in-vestment outlay. This discount rate can be com-pared to the interest rate at which a corporationborrows capital.

Many companies set a threshold (or hurdle) ratefor projects. This rate is the minimum requiredinternal rate of return for a project to be consid-ered viable. Future benefits are discounted at thethreshold rate, and the net present worth of theproject must be positive for the project to be giventhe go-ahead.

RELATING STEAM EFFICIENCY TO CORPORATE

PRIORITIES

Saving money, in and of itself, should be a strongincentive for increasing steam efficiency. Still, thatmay not be enough for some corporate observers.The case can be strengthened by relating a posi-tive life-cycle cost analysis to specific corporateneeds. Consider the following suggestions for in-terpreting the benefits of fuel cost savings:

A new source of permanent capital. Reducedfuel expenditures—the direct benefit of steamefficiency—can be thought of as a new sourceof capital for the corporation. An investment


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that reduces fuel costs yields savings each yearover the economic life of the improved steamsystem. Regardless of how the investment isfinanced (borrowing, retained earnings, orthird-party financing), the annual savings area permanent source of funds as long as thesavings are maintained on a continuous ba-sis.

Added shareholder value. Publicly-held cor-porations usually embrace opportunities toenhance shareholder value. Steam efficiencyis an effective way to capture new value.

Shareholder value is the product of two vari-ables: annual earnings and price-to-earnings(P/E) ratio. The P/E ratio describes thecorporation’s stock value as the current stockprice divided by the most recent annual earn-ings per share.

For a steam efficiency proposal to take ad-vantage of this measure, it should first iden-tify annual savings (or rather, addition to earn-ings ) that the proposal will generate. Multi-plying that earnings increment by the P/Eratio yields the total new shareholder valuethat can be attributed to the steam efficiencyimplementation.

Reduced cost of environmental compliance.Plant engineers can promote project benefitsas a means of limiting the corporation’s expo-sure to environmental emissions compliancepenalties. Efficient steam systems lead to bet-ter monitoring and control of fuel use. Com-bustion emissions are directly related to fueluse. They rise and fall in tandem. Implement-ing steam efficiency lets the corporation en-joy two benefits: decreased fuel expendituresper unit of production and fewer emission-related penalties.

Improved worker comfort and safety. Steamsystem optimization requires ongoing moni-toring and maintenance that yields safety andcomfort benefits in addition to fuel savings.The system monitoring routine usually iden-tifies operational abnormalities before theypresent a danger to plant personnel. Contain-ing these dangers minimizes any threats to life,health, and property.

Improved reliability and capacity utilization.Another benefit of steam efficiency is moreproductive use of steam assets. The efforts re-quired to achieve and maintain energy effi-ciency largely contribute to operating effi-ciency. By ensuring the integrity of steam sys-tem assets, the plant engineer can promisemore reliable plant operations. From the cor-porate perspective, a greater rate of return onassets is achieved in the plant.

TAKING ACTION

The following steps can help make a proposal forsteam efficiency implementation attractive to cor-porate decision-makers:

Identify opportunities for achieving steamefficiency.Determine the life-cycle cost of attaining eachoption.Identify the option(s) with the greatest netbenefits.Collaborate with the financial staff to iden-tify current corporate priorities (added share-holder value, reduced compliance costs, im-proved capacity utilization, etc.).Generate a proposal that demonstrates howthe benefits of the steam efficiency project di-rectly responds to current corporate needs.



Steam Digest 2001Steam Champions in Manufacturing

93

Steam Champions inManufacturingChristopher Russell, Alliance to Save EnergyAnthony Wright, Oak Ridge National Laboratory

ABSTRACT

Traditionally, industrial steam system managementhas focused on operations and maintenance.Competitive pressures, technology evolution, andincreasingly complex regulations provide addi-tional management challenges. The practice ofoperating a steam system demands the manage-rial expertise of a “steam champion,” which willbe described in this paper. Briefly, the steam cham-pion is a facility professional who embodies theskills, leadership, and vision needed to maximizethe effectiveness of a plant’s steam system. Per-haps more importantly, the steam champion’s de-finitive role is that of liaison between themanufacturer’s boardroom and the plant floor. Assuch, the champion is able to translate the func-tional impacts of steam optimization into equiva-lent corporate rewards, such as increased profit-ability, reliability, workplace safety, and other ben-efits. The prerequisites for becoming a true steamchampion will include engineering, business, andmanagement skills.

INTRODUCTION

Steam is a significant feature of industrial power.Steam systems account for approximately twothirds of primary fuel consumption in manufac-turing. In 1995, this consumption totaled 9.34billion quads1 , costing $21 billion (Jones 1997).Steam continues to be an ideal medium for ap-plying thermal energy in ways that transform, dis-till, shape, and cure material works in process.

Usually, plant managers perceive steam to be autility that supports core process activities. Whileplant managers may attribute value of outputsolely to process applications, no such attributionis given to steam utilities. Regardless of whetherthat view is warranted, it also implies that plantmanagers do not think of steam systems as a sourceof additional value to be captured. In this sce-nario, the steam manager’s job is simply to ensurea reliable supply of steam. At worst, this suggests

that some managers are oblivious to the opportu-nities to control steam system operating costs.

However, the optimization of industrial steam sys-tems is a worthwhile pursuit that returns real valueto the asset owners. In order to achieve this, steamsystems will require management that is more so-phisticated than what was required in the past.The operations aspect of steam optimization willinclude proper system design, balancing2, main-tenance, and repair procedures. Increasingly, how-ever, business priorities enter the steam manage-ment agenda.

Competition and cost pressures demand thatmanufacturers squeeze value from plant expenseswhile still generating revenue from marketableproducts. Meanwhile, new technologies emergethat can enhance steam system productivity. Othertechnologies pose threats as substitutes to steamapplications. At the same time, steam manage-ment is made more complicated by the imposi-tion of environmental regulations and operatorcertifications. A more sophisticated manager—a“steam champion”—is the professional equippedwith the skills, leadership, and vision necessary tomanage the forces that now characterize indus-trial steam operations.

STEAM CHAMPION: MAJOR MANAGEMENT

FUNCTIONS

The qualities of a steam champion may be bestdescribed by an overview of his or her managerialfunctions and concerns. The steam champion’smajor activity groups are discussed in the sectionsthat follow. These include:

1. Performance management: the strategicevaluation of plant functions relative to in-dustry peers or benchmarks.

2. Operations management: the identificationand implementation of maintenance and op-erations processes that ensure reliable steamoutput.

1 A “Quad” is one quadrillion (or 1015) Btu.2 “Balancing” refers to the continuous process of adjusting

the volume of steam to be generated against the loads de-manded of the system. A perfectly balanced system expe-riences no excess or shortage of steam load.


94

3. Personnel management: the employ and de-velopment of human resources as needed toperform system operations.

4. Business management: the analysis and com-munication of steam system performance inrelation to business priorities and goals.

5. Planning: the anticipation of changes in thebusiness environment, including new tech-nologies, regulations, market conditions, andhuman resource issues.

PERFORMANCE MANAGEMENT

Performance management is the first step in opti-mizing a steam system relative to best-in-class stan-dards. Several key operating metrics3 allow (1)comparison among systems within the same in-dustry and (2) comparison of one system’s perfor-mance over periodic intervals. While the sharingof data with competitive firms is usually problem-atic, professional engineering societies, local utili-ties, or manufacturing assistance programs mayhelp in this regard. Operations benchmarking mayalso be accomplished if a plant is one of manybelonging to the same corporate group.

The true effectiveness of steam operations can beevaluated with a couple of fundamental metrics.The cost per thousand pounds of steam producedis one comprehensive measure of steam systemoperating expense. Steam’s contribution to plantoutput is another potential metric, and can beexpressed as pounds of steam required per unit ofproduction. The comparison of these metrics toindustry standards provides a relative measure ofa steam plant’s operating condition. Knowledgeof the steam plant’s relative performance is a pre-requisite to implementing an ongoing optimiza-

tion program. Table 1 (see below) suggests thesteam champion’s checklist of performance man-agement items.

OPERATIONS MANAGEMENT

Operations management involves the identifica-tion and implementation of improvement oppor-tunities. Some activities are remedial or reactivein nature, such as fixing leaks. Others are rou-tine, such as monitoring and recording perfor-mance data. Still others are proactive, requiringthe investment in new equipment that will en-hance productivity. Optimized steam systemsdeliver thermal resources with a minimum of lossfrom the boiler to the plant’s process applications.Best-in-class or benchmark comparisons help toidentify the features of an optimized system. Ref-erence to such comparisons should lead directlyto the formulation of an operations managementprogram, having system optimization as its goal.

The steam champion’s operations managementprogram requires diligent monitoring and main-tenance. This provides system reliability and alsoensures that potentially dangerous anomalies arediscovered and corrected before personnel areharmed. Disciplined operations preclude down-time, allowing the plant to demonstrate greaterproductivity. Proper combustion, water treatment,

Table 1. Steam Champion’s Performance Management Checklist Adapted from (Wright 2001).

3 A metric is a variable or a ratio of variables that records theperformance of a chosen feature for each of many differ-ent observations. For example, boiler efficiency comparesthe Btu content of a boiler’s steam output to the Btu con-tent of the fuel consumed to produce that steam. Boilerefficiency is a metric because it can be recorded and com-pared (1) for many boilers, or (2) repeatedly for the sameboiler at regular intervals.

Steam Costs Monitor fuel cost to produce steam in ($) per 1000 lbs. of steam.Calculate and trend fuel cost to generate steam.

Measure steam/product benchmark: lbs. steam required per unit ofproduction.Trend steam/product benchmark with periodic measurements.

Steam System CriticalParameter Measurements

Steam production rate.Fuel flow rate.Feedwater flow rate.Makeup water flow rate.Blowdown flow rate.Chemical input flow rate.Intensiveness of steam flow metering (by plant, building, processunit, etc.).

Steam/ProductBenchmarks


95

Table 2. Steam Champion’s Operations Management Checklist Adapted from (Wright 2001).

Steam System Operating Practices

Boiler Plant Operating Practices

Steam Trap MaintenanceProgram

Select proper trap for application.At least annual testing of all traps.Maintain a steam trap database.Repair/replace defective traps.

Water TreatmentProgram

Ensure that water treatment system functions properly.Measure conductivity and blowdown rates for boiler andmud drum.

Steam Insulation Ensure that boiler refractory and insulation on pipes,valves, flanges, etc. are in good condition.Ensure that steam distribution, end use, and recoveryequipment insulation is in good condition.

Steam Leaks Record frequency of leaks.Establish an order of loss magnitude for leaks.Establish system and timetable for repairing leaks.

Water Hammer Note frequency of water hammer episodes.Ability to remedy water hammer.

Periodic Inspection andMaintenance for SteamSystems

Generation: Boiler, dearator, feedwater tank, chemicaltreatment equipment, blowdown equipment, economizer,combustion air preheater, clean boiler’s fireside or water-side deposits, etc.Distribution: Piping, steam traps, air vents, valves, pres-sure reducing stations, etc.End-use: Turbines, piping, heat exchangers, coils, jack-eted kettles, steam traps, air vents, vacuum breakers, pres-sure reducing valves, etc.Recovery: Piping, valves, fittings, flash tanks, conden-sate pumps, condensate meters, etc.

Boiler Efficiency Determine ratio of Btu heat absorbed by steam to Btu en-ergy input from fuel.Measure flue gas temperature, oxygen content, and car-bon monoxide content.Select type of excess air control (non, manual, automatic).

Heat Recovery Equipment Use feedwater economizer and/or combustion air pre-heater.Perform blowdown heat recovery.

Quality of Steam Monitor boiler output to ensure “dryness” of steam.General Boiler Operation Use automatic controller for continuous blowdown.

Investigate common system faults (patterns of alarm sig-nals) to determine remedies.Reduce frequency of steam pressure fluctuations beyond+/- 10 percent of boiler operating pressure.

Steam Distribution, End Use, & Recovery Operating PracticesMinimize Steam FlowThrough PRVs

Analyze pressure reduction options: none, use boiler con-trols or PRVs, use backpressure turbines.

Recover & UtilizeAvailable Condensate

Maximize volume of condensate recovered and utilized.

Use High PressureCondensate to Make LowPressure Steam

Maximize volume of flash steam recovered and utilized.


96

condensate control, insulation and refractory, andleak repair all ensure that the thermal transfer ofsteam is maximized. If any of these functions arecompromised, the ensuing thermal loss usuallyrequires more fuel to compensate. That, of course,means additional operating costs. Finally, as fuelconsumption increases, so do combustion emis-sions and the liabilities associated with them.

More intensive operations and maintenance willcause certain steam plant O&M4 costs to rise.The steam champion understands that over theboiler’s lifetime, expenditures for fuel alone willdwarf other costs as well as the capital outlay forthe boiler itself. The rise in incidental O&M costsexpended to optimize the steam system can bemore than compensated by fuel cost savings.

System optimization is an ongoing process. Con-tinuous improvement, or judiciously maintainedoptimization, is the rule. Many plant managersmake the mistake of implementing a one-time,comprehensive system improvement, only to letthe efficiency gains erode over time through inat-tentive maintenance.

Table 2 (see previous page) offers the monitoringand maintenance duties on the steam champion’soperations management checklist.

PERSONNEL MANAGEMENT

It is immediately evident that the duties demandedby the operations management program will makeintensive use of well-trained, motivated, and dis-ciplined manpower. Plant technicians will needto apply mechanical as well as record-keepingskills. The steam champion must ensure that staffare adequately trained to understand the “big pic-ture,” i.e., the steam load’s relationship to processdemands. But equally important is the knowledgeneeded to monitor and remedy operating featuresof the steam system itself. In addition to train-ing, the steam champion will be tasked with de-signing and scheduling a monitoring and main-tenance routine. This routine will facilitate theplanning of staffing levels and man-hours to beapplied. In addition, it helps the steam cham-pion to better plan the purchase of consumablesrelated to operations needs.

Motivation is key to staff serving effectively. Whileit is critical for staff to understand the purpose

and means of achieving plant optimization, themotivation to carry out the necessary operationsroutine will be enhanced if staff also share in thesavings that optimization provides. Rewards alsocreate the incentive for staff to look for improve-ment opportunities above and beyond the sched-uled operations duties.

Training is the prerequisite to effective staffing.The steam champion seeks training resources andorganizes a training regimen that develops eachstaff member in stages. Initial training introducesbasic operational concepts and safety. Intermedi-ate training is intended for staff with some opera-tional experience who are prepared to improvetheir range of technical abilities. Advanced train-ing presents the use of industry standards andbenchmarks, introduces operating liabilities relatedto resource management and emissions control,and perhaps the fundamentals of human resourcemanagement.

The steam champion also has his or her own train-ing agenda. Business principles are important,while new technology development, energy mar-ket functions, and regulatory policies are worthyof repeat study.

Membership in a professional engineering societyis a worthwhile commitment for key staff as wellas the steam champion. These societies have ex-cellent resources for training and development.The provision of such membership and its per-quisites is also a way to reward staff.

Training culminates in the ability to fully realizethe goals of an operations program. The result—the ongoing optimization of the steam system—provides savings that accrue to the plant’s bottomline.

BUSINESS MANAGEMENT

Steam production is ultimately conducted for busi-ness purposes. The steam champion’s businessmanagement agenda is two-fold: contribute to

4 “O&M” refers to operations and maintenance costs, whichare routine or at least clearly driven by hours of operationor volume of production. O&M costs typically includelabor and consumables such as cleaning supplies, uniforms,lubricants, space heat and lighting, and communicationand documentation expenses.


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plant output while demonstrating steam’s contribu-tion in meaningful business terms. Success onboth counts will get the attention of upper man-agement, who will ultimately decide how muchfinancial and material support are available tosteam operations.

The advent of submetering technologies helps thesteam champion to track steam’s contribution todifferent process lines within a plant. That me-tering data is a primary input for demonstratingbusiness results.

Why do operations data need to be translated intobusiness terms? Unfortunately, few chief execu-tive or finance officers have an understanding orinterest in the engineering functions and measure-ments that define operations management. It isusually a waste of everyone’s time if a plant man-ager describes steam optimization impacts in termsof Btus, pounds per hour, or efficiency ratios.Meaningful communication describes impacts interms of increases in net income, return on assets,and addition to shareholder equity. The steamchampion discusses the impact of steam optimi-zation in these terms.

Central to business dialog is the improvement ofnet income, or the “bottom line.” All other fi-nancial impacts depend on this measure. The pre-ceding discussion of system operations manage-ment describes how optimization reduces fuel ex-penditures. Those expense savings translate di-rectly into new income. A thorough discussionof steam system efficiency’s financial impacts, withexamples, is already available (Russell 2000). Thefollowing is a select review of the financial im-pacts of steam optimization.

Return on assets (ROA). As a financial variable,ROA is simply the ratio of net income for an ac-counting period to the average value of plant as-sets in place for that period. A corporate deci-sion-maker uses ROA as a measure of how hardassets work. To illustrate, consider two plants, bothwith $10 million in assets. One produces an an-nual income of $1 million (a 10 percent ROA),while the other produces $2 million (20 percentROA). This is clearly a difference worthy of in-vestigation.

Production cost per unit. Competition in some

industries forces managers to focus on cost. Thisis especially true for high-volume, commodity pro-cesses such as refining, primary chemicals, andpulp and paper production. The marketplace usu-ally dictates prices; profitability will then dependon cost containment. A steam champion is pre-pared to document and communicate the resultsof optimization in terms of a reduction in costper unit of product. The corporate audience of-ten responds better to this measure than to a state-ment of aggregate costs saved. Sometimes, a fewpennies saved in the per-unit production cost havea meaningful impact on the product’s marketabil-ity. A steam champion can identify the incrementof per-unit cost savings attributable to steam op-timization.

Addition to shareholder equity. The holdingcompanies that own manufacturing concerns arekeenly interested in the performance of their stock,as well as in the opinions of that stock as issued byWall Street analysts. Accordingly, company ex-ecutives place a priority on the company’s perfor-mance in terms of the variables tracked by equityanalysts.5 The holding company’s cumulative goal,however, is to grow shareholder equity. The steamchampion can translate an improvement in netincome into incremental growth in equity. Forexample, assume that a holding company stocksells at a price of ten times earnings.6 If a steamoptimization initiative realizes $1 million in sav-ings, shareholder wealth is increased by an incre-ment of $10 million ($1 million times the P-Eratio of 10).

The steam champion serves his or her own inter-ests in contributing to the firm’s financial and cor-porate priorities. Steam managers compete withprocess and other managers for a share of the firm’scapital budget. Those managers who can demon-strate superior returns on their capital investmentproposals will get greater corporate support.

PLANNING

As implied by the previous discussion, the indus-trial steam plant manager’s agenda encompasses

5 Some examples of financial variables tracked by equity ana-lysts include inventory turnover, debt ratios, profit mar-gins on sales, and rates of retun on assets. Many othercreative variables exist.

6 Stated alternatively, the stock’s P-E ratio is 10.


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more than mechanical concerns. Regulation, hu-man resource considerations, and technology evo-lution impact steam management to varying de-grees over time. The steam champion monitorsthese forces and makes plans for accommodatingchange.

Emissions control. These regulations impact mostlarge-scale combustion processes. Current out-put restrictions limit sulfur dioxide and nitrousoxides. Emerging legislation in response to glo-bal warming concerns will focus on carbon emis-sions. Industrial steam managers must containemissions output with alternative fuel selections,proper combustion techniques, and abatementtechnologies. The acceptable thresholds for emis-sions production are subject to constant revision.Professional and industry associations have excel-lent resources for interpreting U.S. Environmen-tal Protection Agency regulations as well as thetechnologies and practices that facilitate compli-ance.7 The steam champion uses these resourcesto adjust the operations management plan accord-ingly.

Professional certifications. Safety and emissionsregulations shape the personnel certification re-quirements for steam system operations. The costof acquiring certifications, as well as the cost ofcompensation required by properly certified per-sonnel, is a challenge for human resource man-agement. Under-trained apprentices are easier onthe payroll, but a corresponding loss in produc-tivity is the trade-off. It is desirable to developthese personnel, assuming they can be retainedafter completing their training. The steam cham-pion has tough choices for sustaining acceptablelevels of certified labor. Depending on labor mar-ket conditions and the plant manager’s tolerancefor continuous hiring and staff development, thechoice is between outsourcing operations to a cer-tified energy performance contractor, or manag-ing a staff with a few key professionals and acomplement of apprentices who essentially learnon the job. In the best of circumstances, the steamchampion can plan staffing needs in response tostatutory certification requirements. But in prac-tice, this human resource challenge may defy plan-ning. The steam champion will need executive-level commitment to training and compensationas the means for attaining system optimization.

Technology evolution. New technologies are inpart relevant to the preceding discussions aboutemissions control and professional certification.But technology development is also relevant toplant and process design. Certain control, moni-toring, and automation technologies are emerg-ing that will boost the productivity of steam sys-tems. Other technologies emerge as substitutesfor steam. The steam champion monitors devel-opment on both these fronts and uses this knowl-edge to influence asset selection for the plant.

Monitoring technologies rely on data flows overtime to determine a steam system’s operatingnorms. Monitoring reports warn the operatorwhen a data snapshot captures operating resultsout of the ordinary. Boiler operations, distribu-tion elements, and end-use applications can all bemonitored in this fashion. Automation technolo-gies perform a variety of functions, from signal-ing the failure of key hardware components tocontrolling the mixture of fuels used simulta-neously for combustion. The steam championmonitors the implementation of these innovationsand employs them to the extent that such tech-nologies are compatible with available human re-sources. To elaborate, it is theoretically possibleto monitor every component of a steam system;this could be a problem if there is insufficient staffto interpret all the data that the monitors gener-ate.

New technologies also bring substitutes to steam.Infrared applications, both electric and natural gasfired, have supplanted steam in the drying of pa-per coatings in some plants. Sonic vibrators, incombination with membrane sifters, are emerg-ing as a non-thermal method for distilling liquids.Countless electric applications have been devisedto provide thermal energy with pin-point accu-racy in product fabrication processes.

The steam champion monitors technology devel-opments for those that are relevant to his or herindustry. In some instances, steam championsmay determine that a substitute technology is ul-timately superior to steam. The true criteria inmaking such a choice is the degree to which a tech-nology option will add value—either through cost

7 The American Gas Association and the American Petro-leum Institute are two good examples.


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reduction or product enhancement. Steam cham-pions in certain industries or facilities may haveto evolve professionally with the prevailing tech-nology. But in the industries featuring large scale,continuous thermal energy, steam is not unlikelyto be supplanted. The need for steam championsto support these systems will continue for the fore-seeable future.

CONCLUSION

The fundamental premise of steam system opti-mization is that some investment of resources isrequired to accomplish fuel savings. Projects tobe implemented will be those with the most at-tractive savings and return on investment. Manu-facturers that choose to pursue optimization willhave (1) a sufficient time horizon to realize ben-efits that are especially large in the long term, and(2) top level executive commitment to achievingoptimization goals. In short, the appropriate cor-porate culture is a prerequisite for allowing a steamchampion to emerge and thrive.

Steam champions already exist, serving their em-ployers and perhaps entire industries with theirexpertise. Many are senior, which is not surpris-ing given the volume of expertise they haveamassed. But by the same token, senior champi-ons eventually retire, and replacements are not al-ways available. Energy policy, as well as industryleaders at the trade association level, might wantto support the development of new steam cham-pions. The steam champion managementagenda—performance, operations, personnel,business, and planning—is one that needs ad-equate support from the training community.

Given industry’s appetite for energy, as well as theenergy supply concerns that are resurfacing in2001, the rationale for developing and retainingsteam champions is compelling. The business im-pacts of doing so should be all the incentive neededfor industry to act accordingly.


Christopher RusellAlliance to Save EnergyEmail: [email protected]: (202) 530-2225


REFERENCES

Jones, Ted. 1997. “Steam Partnership: Improving SteamSystem Efficiency Through Marketplace Partnerships.”Steam Digest 2000: 5-12.

Wright, Anthony. 2001. Steam System Scoping Tool, a self-contained spreadsheet template available at no chargefrom the Steam Clearinghouse:[email protected] or (800) 862-2086.

Russell, Christopher. 2000. “Steam Efficiency: Impacts fromBoilers to the Boardroom.” Steam Digest 2000: 23-34. Also available from:

http: //www.ase.org/programs/industrial/Boil2Bord.pdf

For additional informationon BestPractices Steam, contact:

FRED HARTOffice of Industrial TechnologiesU.S. Department of Energy202 586-1496

CHRISTOPHER RUSSELLSenior Program Manager for IndustryThe Alliance to Save Energy202 530-2225

Visit the OIT Steam Web site at:www.oit.doe.gov/bestpractices/steamwww.steamingahead.org

For information about otherOIT Programs call:

OIT ClearinghousePhone: (800) 862-2086Fax: (360) 586-8303http://www.oit.doe.gov

Office of Industrial TechnologiesEnergy Efficiency andRenewable EnergyU.S. Department of EnergyWashington, D.C. 20585

DOE/GO-102002-1516January 2002

OFFICE OF INDUSTRIAL TECHNOLOGIESENERGY EFFICIENCY AND RENEWABLE ENERGY � U.S. DEPARTMENT OF ENERGY

ALLIANCE TO SAVE ENERGYTHIRD DECADE OF LEADERSHIP

A compendium of articles

on the technical and

financial benefits of steam

efficiency, presented

by stakeholders in the

U.S. Department of Energy�s

BestPractices Steam efforts.

Documents

Steam Digest 2001 - NREL · Glenn Hahn, Spirax Sarco ... This program resulted in a 17 percent reduction in energy use on a per pound of product basis, saving 3.25 trillion Btus and