“TURNING INFORMATION INTO ENERGY SOLUTIONS FOR INDUSTR Y” 

INDUSTRIAL TECHNOLOGIES PROGRAM 

Presenting an Energy Efficiency Project to Management 

Winter 2003 

ISSUE FOCUS: 

Selling Efficiency Pr

to Management 

ojects 

IN THIS ISSUE 

Presenting an Energy Efficiency


Project to Management . . . . . . . . . . . . . . 1


Texas Technology Showcase


Coming in March . . . . . . . . . . . . . . . . . . . 3


$36 Million in Savings Identified


in AMCAST Assessment . . . . . . . . . . . . . 4


Boiler Blowdown Energy Recovery . . . 5


Compressed Air System Improvement


Enhances Foundry Production . . . . . . . 5


Compressed Air System 


Upgrade Results in 


Substantial Energy Savings . . . . . . . . . 6


DOE and Flying J Refinery Cooperate


to Determine Energy Savings . . . . . . . . .7


Retrofit Project Helps Mobil Refinery


Avoid a Major Capital Investment . . . . . 9


Letters to the Editor . . . . . . . . . . . . . . . 10


Coming Events . . . . . . . . . . . . . . . . . . . . 12


The lowdown on boiler blowdown. 

See page 5. 

Special to Energy Matters from the 

Compressed Air Challenge 

Often, the resistance by chief financial officers and other upper management executives can be a critical barrier to 

implementing compressed air or other 

energy efficiency system improvement 

projects. The following outline illustrates the 

kind of information that needs to be presented to management to successfully gain 

approval for such a project. 

Under most circumstances, it would be 

appropriate to seek approval by making a 

formal presentation to key management 

staff. It would be to the presenter’s advantage to have in attendance during the 

presentation the principal managers of all 

potentially affected activities. In deciding 

who should be invited, consideration 

should be given to impact on budgets as 

well as on operations. It is most important 

that all interested parties be fully informed 

before the meeting, so they can be prepared to participate. If your project gets 

approved, funding may have to come from 

other activities; those managers must be 

fully involved before your presentation, if 

you are to avoid having them oppose your 

project. 

Besides gaining the cooperation of internal management, it might be wise to gain 

the support of outside parties, who might 

lend additional credibility to your proposal. 

For example, you might want to use a 

report from an independent professional, or 

recommendations from your utility or 

energy services company. For compressed 

air projects, it would certainly be helpful to 

make reference to materials produced or 

endorsed by the Compressed Air Challenge. 

Your presentation to management must 

be tailored to the scope of the project, and 

the management style of your leadership, 

and must be keyed to achieving a decision. 

The best idea is to make the individual in 

your management scheme who can ultimately approve the project the focus of 

your presentation. 

Your presentation should present all of 

the necessary information as concisely as 

possible. Do not waste valuable time with 

unimportant details. The more irrelevant 

details you furnish, the greater the likelihood that someone will start to nit-pick. This 

may well divert the decision-maker’s attention from the true issues at hand. 

The following outline suggests a format 

for presenting your compressed air or 

energy efficiency project to management. 

Selling the Project to Management 

A. State the purpose of the presentation. 

You want everyone attending your presentation to focus on the problem you 

will present, knowing that a decision 

will have to be made. If attendees think 

they are there for an information briefing, they may easily miss some of the 

points that will critically affect the decision. 

B. State the problem to be corrected. 

What are the existing conditions that 

make it important that the project be 

considered? What costs are involved 

that can be reduced? How do existing 

conditions affect production, staffing, 

maintenance, and the bottom line? 

C. Describe the scope of the project being 

proposed. As briefly as possible, and 

using a minimum of detail, describe 

what the project will consist of in terms 

of equipment, labor, time, and cost to 

implement. This part of the presentation 

will help the decision-maker and other 

key players get a fast understanding of 

what you want to accomplish and how. 

D. State the benefits to be achieved by 

implementing the project. Using simple 

T OF ENERGY

DEPARTMEN U 

E 

NITED STAT S OFA

ERICA 

M 

(continued on page 2)  

U.S. DEPA RTMENT OF ENERGY 

www.oit.doe.gov 

www.oit.doe.gov/bestpractices 
ENERGY MATTERS 

is published quarterly by the 

U.S. Department of Energy’s 

(DOE) Industrial Technologies 

Program. 

Information contained in the 

newsletter can be reproduced 

without permission provided due 

acknowledgement is given (the 

U.S. Department of Energy’s 

Energy Matters newsletter) and 

a copy of the publication is 

supplied to the editor. 

■ 

EDITORIAL BOARD 

Rob Boteler, representing 

National Electrical Manufacturers 

Association 

Lynda Butek, representing 

Electrical Apparatus Service 

Association 

Eric T. Fletty, Business 

Development Manager, TAPPI 

Gary L. Goehring, Alcoa 

North American Extrusions 

Glenn Hahn, Spirax Sarco 

J. Bruce Medaris, Facilities 

Consulting Services and 

Executive Director, Compressed 

Air Challenge® 

Michael R. Muller, Center for 

Advanced Energy Systems, 

Rutgers University 

Arvind Thekdi, E3M, Inc. 

Chuck Whelan, DuPont 

■ 

DOE STAFF 

Chris Cockrill, BestPractices, 

Motors 

Fred Hart, Technology Manager 

Grace Ordaz, Plant-wide 

Assessment 

Peter Salmon-Cox, Lead 

Technology Manager, Technology 

Delivery and BestPractices 

■ 

COMMENTS? 

Contact: 

David Wagman, Energy Matters 

Editor, at 303-275-3602, 

e-mail david_wagman@nrel.gov 

or Karen Atkison, Associate 

Editor at 303-275-3730, e-mail 

karen_atkison@nrel.gov 

1617 Cole Blvd., MS 1609 

Golden, CO 80401 

For new subscriptions, go to 

www.oit.doe.gov/ 

bestpractices/explore_library/ 

energy_matters.shtml 

For address/subscription changes, 

please contact the editor. 

2 Energy Matters, Winter 2003 

Presenting an Energy Efficiency Project 

continued from page 1 

data summaries and graphical displays, 

explain how the project will cure the 

problems you earlier laid out in discussing existing conditions and 

improvements to the bottom line. 

Emphasize reducing operating and production costs realizing that one of the 

most important parameters is the cost 

per unit of production. In addition to 

the benefits derived from energy 

conservation, you should illustrate other 

benefits, such as: pressure stabilization, 

improving moisture control and air 

quality, the side benefit of turning off 

machines that creates additional backup capacity, and reductions in downtime and reduction of product waste. 

E.	 Clearly state the cost of implementation. Accurately state what it will cost to 

perform the project. You must examine 

all of the direct costs involved, but also 

the indirect costs. Will there be additional costs for down time and start-up? 

Will you need temporary compressed 

air capability? Will there be any interruption in production? You must be 

ready to answer all of these questions. 

F.	 Explain any effect the project will have 

on operations. While this project is 

going on, will there be any adverse 

effect on production or other operations? If so, how will it be accommodated? Has the resultant cost of any 

such impact been included in the estimate of the cost of implementation? 

G. Present the effect on the budget. Any 

significant new project will affect the 

budgeting process. If the project is 

being sought for the current budget 

year, the effect is likely to be both large 

and widespread, having an effect on 

more than just one part of the business. 

If the project is for a future budget year, 

the planning may be simplified, but the 

effect will always be felt at various 

activities in the business. Unless a 

windfall of new revenue exists to fund 

the project, funding will have to come 

from existing budget items that will 

have to be reduced. Advance coordination with the likely targets of these budget transfers can help in getting 

approval. It may be necessary to clearly 

demonstrate a long-term benefit to be 

derived for the overall business to convince a senior manager that he or she 

can accept a short-term loss of funds to 

support the project. 

Much care should go into analyzing 

the Return on Investment (ROI), that is, 

the time over which the savings to be 

realized by the project equal the cost of 

implementing it. The shorter the ROI, 

the more likely the project will be 

approved. This part of the presentation 

may be a good time to compare graphically costs against time and present the 

expected returns to clearly illustrate the 

ROI. It is also a good time to restate any 

reduction in cost per unit of production 

to be realized under the project. 

A major barrier to project approval is 

often a lack of management awareness 

of real operational costs. Collection or 

estimation of these costs, and simple 

graphical displays in your presentation 

can help highlight the need for the 

project. 

H. Provide a coordinated implementing 

plan. The best plan, implemented 

poorly, can be a total failure. Coordination between and among departments, 

realistic work schedules, accommodation for the unexpected, clearly stated, 

achievable milestones, and the assignment of a fully accountable project 

manager are essential to making the 

project a success. “What if” brainstorming should always be included in the 

planning. Under the best conditions all 

of the affected activities should be in 

agreement on the plan before the decision briefing is presented. If such agreement is not possible in advance, the 

plan should include an early milestone 

related to achieving that level of agreedto coordination. The timing for the project and each of the milestones are 

critical to the decision process. The latest date a decision can be useful must 

be made clear. Normally, this time estimate should allow management some 

time to consider options and alternatives. 

I.	 Summarize the project and ask for the 

decision. Close the sale. Summarize the 

need for the project and timing, review 

the cost/benefit analysis, lead the 

(continues)  
thought process to conclude the need 

for a decision, and ask that the decision 

be made. 

Provide a minimum of complicated 

details in the briefing itself. It is a good 

idea to have handy as much hard data 

detail as possible, in case it is requested. 

Spread sheets and reports, process studies, 

cost data and analysis are all valuable 

back-up to your presentation. However, 

avoid using these materials in the presentation itself to avoid confusion. Any data that 

you provide should be in a prepared format, and it should not be cluttered with 

ancillary, irrelevant data that may mislead 

or divert thinking. You should always 

remember that the two most critical parameters in play during your presentation are 

time and focus. Time is critical because the 

longer it takes to “make your case”, the 

less likely you are to get the decision you 

want. Focus is important because you do 

not want the decision maker to be distracted from the very specific goal of 

implementing your project. 

The most important factor in gaining the 

approval you seek, is coordinating in 

advance with all of the affected managers 

and key players within your organization. 

If you can get them to approve the concept 

informally in advance of your presentation 

to senior management, a favorable decision will be much more easily achieved. In 

most cases, it will be very difficult to get 

unanimous coordinated approval from all 

the players. And remember that because of 

the competition for funding, one or more 

of the key players will suffer some form of 

budget impact. ● 

HOW TO PRESENT AN ENERGY EFFICIENCY PROJECT TO MANAGEMENT 

In preparing to seek a decision by management, it will be necessary to follow a logical course of 

preparation. The following 10-step process, developed by the Compressed Air Challenge, is 

typical of the preparation needed. 

1 

2 

3 

4 

Identify the decision-making 

environment 

Who is the ultimate decision-maker? 

[Someone with authority to actually 

approve the project.] 

How is that person influenced? [What 

are the ‘Hot Buttons’?] 

Who are the key players who may 

influence the decision-maker? 

What is the current decision-making 

atmosphere? [Pro-active or reactive?] 

Assess the presenter skills 

Are you the best presenter in this case? 

What is your relationship with the decision-maker? 

What attitudes and loyalties are there 

that may affect the outcome? 

Is there someone else who could make 

this presentation who would be better 

received by the decision-maker? 

Identify potential allies and roadblocks 

Who are the key players? [Both internal 

and external] 

How will their individual circumstances 

impact your quest for a decision? 

What roadblocks are possible? [Who 

will be adversely affected if you get the 

decision to go ahead?] 

What policies and/or current objectives 

will either support or counter your 

proposal? 

Develop a preliminary scope of work for 

the project 

Prepare an accurate description of the 

over-all project. 

Include any supporting activities to be 

required of others, such as engineering 

support, budget and administration, 

purchasing, and operations [shut-downs, 

overtime, etc.]. 

What coordination is required with 

other activities? 

5	 Collect and assemble data to support the 

decision-making process 

Budget and finance. [What alternatives 

exist for funding?] 

How can impact on production be 

quantified? 

How will maintenance operations and 

cost be affected? 

How can the cost/benefit be quantified 

and displayed? 

What are the projected costs over time? 

What are the projected savings over 

time? 

6 Develop the preliminary presentation 

Outline the flow of the presentation. 

Create a proposed list of exhibits or 

hand-outs. 

Identify all of the potential counter 

arguments, and briefly defend against each. 

Review the alternatives. 

Prepare the closing argument to 

ask for the decision. 

7 Shop the presentation around 

Coordinate with all affected parties. 

Get comments from supporters and 

detractors, alike. 

Give credit to all who participate. 

Try to reach consensus. 

Evaluate credibility and value of 

opposition. 

8 Evaluate the presentation 

Revise as needed. 

Repeat steps 4 through 7, if necessary. 

9 Make the presentation; GET A DECISION 

10 ACT on the decision 

If approved, implement the project. 

If disapproved, analyze the rationale 

and if necessary and appropriate, repeat 

the process. 

Texas Technology Showcase Coming in March 

Chemical manufacturers and refiners from 

across the country will converge on Houston this March for the 2003 Texas Technology Showcase. The Showcase will give 

chemical and petroleum refining professionals an opportunity to see energyefficient process technologies and best 

practices in energy management that are 

now emerging in their industries. 

The Office of Energy Efficiency and 

Renewable Energy’s Industrial Technologies 

Program, and the Texas Industries 

of the Future, are teaming to present 

the Texas Technology Showcase, scheduled 

for March 17th through 19th at 

Houston’s Radisson Astrodome Hotel. 

The Texas Technology Showcase is 

designed to promote: 

■	 Increased adoption of technologies and 

best practices that enhance energy 

efficiency, improve environmental performance and reduce costs in chemical 

and refinery facilities 

■ Greater industry and government awareness of the benefits and need for integration of industrial energy efficiency and 

environmental technology and practice 

improvements 

■ Strengthened partnerships among Texas 

industries, universities, associations, 

government, and non-government organizations to focus research and projects 

into high-priority areas. 

The 3-day event will give refining and 

chemical plant managers, utility and environmental engineers, technology experts, 

laboratory researchers, educators, equipment suppliers, environmental agency staff 

(continued on page 4)  

Energy Matters, Winter 2003 3 
Texas Technology Showcase ■ Network with industry and government plant-wide energy reduction practices. 

continued from page 3 leaders One presentation is expected to cover 

members, local, state and federal ■ Visit the Exposition Hall and meet with Rohm and Haas Texas Inc.’s energy mangovernment leaders the opportunity to: more than 65 experts exhibiting tech- agement program, in place at a plant in 

■ Learn how leading companies in energy nologies and services for manufacturers Deer Park, Texas, about 20 miles east of 

efficiency and environmental perfor- and refiners. downtown Houston. The Deer Park plant is 

mance are achieving results Houston has long been considered the the largest Rohm and Haas plant and man-

■ Find out how to incorporate energy country’s energy capital. Many of the ufactures monomers used in key Rohm and 

management best practices to reduce world’s largest petrochemical companies Haas products. The plant accounts for 

costs operate facilities within the greater Hous- approximately one-third of Rohm and 

■ See the latest technologies in action ton area. Participating companies slated for Haas’ global energy consumption. To date, 

during plant tours and meet with tech- profiling during the 2003 Texas Technology the plant-wide energy management program 

nology operators and vendors Showcase include: Calpine, Chevron has resulted in a 24% reduction in energy 

■ Learn how to build support for energy Phillips Chemical Company, Dow Chemi- use on a per-pound-of-product basis. 

efficiency within an organization, cal, ExxonMobil, Merisol, Rohm and Haas The Industrial Technologies Program 

whether large or small Texas Inc., and Valero Energy Corporation. and Texas Industries of the Future expect 

■ Discover new resources for plant Presentations from participating compa- more than 700 attendees at the showcase. 

upgrades and technology development nies range from new technologies, such as For more information or to register for the 

■ See what is being done to meet emis- low-nitrous oxide process heaters, to new Texas Technology Showcase, visit 

sion reduction requirements strategies such as by-product synergies, to www.showcasetexas.org or call toll-free 

877-648-7967. ● 

$36 Million in Savings Identified in AMCAST Assessment 

AMCAST and its partners applied a 

systematic plant-wide assessment (PWA) 

approach to identify energy and cost saving opportunities at the corporation’s facility in Wapakoneta, Ohio. The team initially 

identified $3.6 million in savings opportunities resulting from increased energy and 

productivity efficiencies with paybacks 

ranging from 0 to 29 months. Additional 

savings opportunities surfaced as plant personnel were implementing the initial recommendations, and the total saving 

opportunities have grown to nearly 

$6 million. 

Encouraged by these savings, AMCAST 

has replicated the PWA methodology at 

five plants throughout the corporation and 

introduced projects from the assessment 

into its other plants. AMCAST’s strategy is 

succeeding; company-wide savings will 

reach nearly $36 million over the next 

several years. 

AMCAST SAVINGS ASSESSMENT 

Savings Identified Annual Savings 

Corporate-wide savings $36 million 

Wapakoneta plant savings realized $6 million 

Wapakoneta electrical energy savings 671,907 kWh 

Wapakoneta natural gas savings 9,146 MMBtu 

The Wapakoneta facility spends millions 

of dollars and uses energy-intensive 

processes in its production of low-pressure 

aluminum castings for automotive suspensions. The assessment team focused on all 

energy-intensive plant systems, including 

furnaces, boilers, electrical equipment, 

compressed air, fans and pumps. Scrap 

reduction also resulted in increased productivity. 

DOE funded the assessment at $75,000 

and required at least a matching amount 

from AMCAST. The accompanying table 

highlights the overall savings opportunities 

identified. 

For plant-wide assessment program 

information, contact Graze Ordaz of the 

DOE’s Industrial Technologies Program by 

phone at 202-586-8350 or by e-mail at 

grace.ordaz @ee.doe.gov. For technical 

details about the assessments, visit 

www.oit.doe.gov/bestpractices/factsheets/amcast.pdf, or contact Bob Leach of 

the Oak Ridge National Laboratory by 

phone at 865-946-1352 or by e-mail at 

leachre@ornl.gov. ● 

Clarification 

A table in the Autumn 2002 issue of Energy Matters included an incomplete statement. The table, “Comparison of Motor Rewind v. Replacement Costs and Efficiencies” accompanied the article “Making Good Motor Decisions—The Ellensburg Wastewater Treatment Plant.” The 

table included a row with an option labeled “Replace with NEMA Premium motor.” This option did not clearly state that the $12,673 cost 

reflected the cost of replacing the entire aerator, not just the motor component. Steve Dunnivant, field consultant who worked on the Ellensburg study, said his records from the February 2001 analysis contained no cost for just the NEMA premium efficiency motor. Consequently, 

the simple payback in years for using a NEMA Premium efficient motor cannot be calculated, and this information is incorrect. Companies 

should carefully review estimates for the cost of rewinds before making a repair/replace decision. In addition, the article was contributed to 

Energy Matters by the Northwest Energy Efficiency Alliance and its Electric Motor Management program. 

4 Energy Matters, Winter 2003 
Boiler Blowdown Energy Recovery 

By Greg Harrell, Ph.D., P.E.,


The University of Tennessee Energy, Environment and Resources Center


Boiler blowdown is essential for the continued operation of any boiler. Without blowdown 

chemical concentrations within the boiler water can increase above acceptable limits, leading to boiler damage. Typical problems associated with insufficient blowdown are tube scale, 

corrosion, and liquid carryover. 

Mathematically, boiler blowdown is expressed as a fraction of boiler feedwater flow as 

described by, 

 ̇ ß = Blowdown amount = Quantity of blowdown water m blowdown = Quantity of feedwater m  ̇ feedwater

• The equation is a ratio of mass flow rates, mblowdown —blowdown mass flow rate (and 

feedwater flow rate). Boiler blowdown can range from less than 1% when high quality boiler 

feedwater is used to more than 20% when poor quality water is available. Boiler feedwater 

enters the boiler with a relatively low energy content from the deaerator—deaerator pressuresaturated liquid and feed pump energy. Blowdown exits the boiler with a relatively high 

energy content—saturated liquid at boiler pressure. Fuel energy was required to achieve this 

energy increase. As a result, the activity of blowdown, although necessary, represents an 

energy loss to the boiler. Therefore, blowdown management is essential for proper boiler 

energy management. 

Blowdown is done typically for two primary purposes, both of which involve boiler 

water quality control. One function is to 

remove any solid materials precipitated in the 

boiler. Generally this takes the form of intermittently removing water from the boiler’s 

lower portions where these solids tend to 

accumulate. Target areas for this activity 

include the lower boiler drum, intermediate 

headers, and other places where loose solids 

can accumulate. Intermediate header blowdown is often done only when the boiler is 

taken out of service due to the possibility of 

upsetting internal boiler water circulation 

patterns. 

Boiler blowdown’s other primary function is to control the concentration of dissolved minerals in the boiler water. Typically the vapor-liquid interface is the primary target area for this 

activity, which involves removing liquid boiler water from just below the interface. This 

blowdown either can be continuous or intermittent. 

Reducing the loss associated with boiler blowdown is achieved through two primary 

avenues. First, blowdown rates are reduced through improved feedwater quality with the 

main focus on make-up water treatment, recycled condensate quality, and proper chemical 

treatment in the boiler. The second avenue centers on recovering the resident energy in the 

blowdown. A boiler operating with the best quality boiler feedwater will require some 

amount of blowdown to maintain water chemistry. Therefore, it is beneficial to investigate any 

benefits associated with recovering thermal energy resident in the blowdown stream. 

Measuring the amount of boiler blowdown is essential to determining the magnitude of 

the loss and the savings potential associated with recovering the energy resident in the blowdown stream. The boiler blowdown amount is typically measured and controlled by chemically analyzing the boiler water itself. Blowdown flow is typically not measured directly 

because of flow meter difficulties—even though traditional flow meters can be effectively 

applied. However, accurate estimates of the blowdown amount are found by chemically 

analyzing chloride, silica, or other chemical components when continuous blowdown is 

employed. 

Water treatment personnel can generally provide the chemical analysis needed to provide 

an accurate calculation of the blowdown. Probably the most common blowdown control 

(continued on page 6)  

Compressed Air System 

Improvement Enhances 

Foundry Production 

International Truck and Engine Corporation 

implemented an optimization project on the 

compressed air system that serves its Indianapolis Casting Corporation (ICC) foundry 

in Indianapolis, Indiana. The project 

included a leak repair campaign along with 

measures to stabilize pressure and improve 

air quality. Because of the project, the system’s efficiency was greatly improved. The 

project’s implementation also resulted in 

significant maintenance savings and production that is more reliable. The project’s 

total cost was $800,000. The annual compressed air energy and maintenance savings 

were $395,000 and more than 7.2 million 

kilowatt-hours (kWh), yielding a simple payback of just over 2 years. 

Configuring and maintaining a welldesigned compressed air system that generates a stable, uncontaminated supply of air 

is important for reliable production and 

leads to energy savings and long equipment 

life. In the case of ICC, severe fluctuations in 

air demand patterns and inadequate air 

treatment prior to the project led to excessive use of compressor capacity and resulted 

in energy waste. Furthermore, the system’s 

data acquisition and control strategy forced 

compressor operators to wait until the system pressure fell to an unacceptably low 

level before they brought additional units 

online. This caused production downtime. 

By implementing a project that stabilized 

and lowered system pressure, eliminated 

moisture and lubricant carryover, and 

reduced system demand by repairing leaks 

and correcting misapplied end uses, plant 

personnel caused their compressed air system to perform more effectively and efficiently. This resulted in substantial 

compressed air energy and maintenance 

savings, and increased foundry production. 

The BestPractices team participates in 

plant assessments and demonstration projects. Take a look at what others in your 

industry have done to increase their energy 

savings by reading their case studies. 

You can view these documents at http://www. 

oit.doe.gov/bestpractices/case_studies. 

shtml. Or, order a document from the Industrial 

Technologies Program Clearinghouse. You can 

e-mail the Clearinghouse at Clearinghouse 

@ee.doe.gov, or call 800-862-2086. ● 

Energy Matters, Winter 2003 5 
Boiler Blowdown Energy Recovery continued from page 5 

mechanism measures boiler water conductivity, which is a gross indication of boiler water 

chemical concentrations. This measurement is repeatable and reliable making it an excellent 

control measurement. This measurement is also effective in providing a general indication of 

the blowdown flow rate. Often a conductivity value is maintained in the boiler water by continuously modulating the amount of blowdown water removed from the boiler. In general, 

conductivity measurements should be supported by periodic boiler water chemical analysis. 

Evaluating the boiler blowdown rate based on chemical analysis is based on a mass balance of a chemical component entering the boiler with the feedwater. A chemical component 

must be chosen with minimal solubility in the steam that exits the boiler. As a result, the 

amount of the chemical entering the boiler with feedwater must equal the amount exiting the 

boiler in the blowdown stream—under steady-state, steady-flow conditions inflow must equal 

outflow. Therefore, the ratio of the concentration of the chemical entering in the feedwater 

flow divided by the concentration of the chemical exiting the boiler in the blowdown stream 

is a measure of the blowdown rate, or fraction of feedwater flow. This is expressed in the 

equation,  ̇ ß = Blowdown amount = C feedwater = m blowdown 

C blowdown m  ̇ feedwater 

Where, Cfeedwater and Cblowdown are the measured concentrations of the selected chemical in 

the feedwater and the blowdown, respectively. The accuracy and precision of the measurement must be taken into account when conducting this evaluation. 

Care must be given to evaluating boilers using only intermittent blowdown. Intermittent 

blowdown can be effective for controlling and managing the boiler water chemistry of relatively small-capacity, low-pressure boilers. Intermittent blowdown is done many times each 

day and consists of releasing a significant stream of boiler water for several seconds. This type 

of blowdown control allows the chemical constituents in the boiler water to concentrate until 

the blowdown occurs. The blowdown significantly reduces chemical concentrations in the 

boiler water and allows continued boiler operation. This control method releases more blowdown water than continuous control for the same maximum chemical concentrations. Therefore, in larger capacity boilers continuous blowdown will generally be more economically 

attractive. 

Blowdown amounts are generally less than 10% of the total feedwater flow, however, a 

blowdown rate of 2.0% may be excessive for a given system. The correct blowdown amount 

for a given boiler is a function of steam pressure, feedwater purity, and chemical treatment 

program. The main factors to be controlled by blowdown are the chemical concentrations in 

the boiler. Typical chemical concentration limits for boiler water are provided in the accompanying table displaying boiler water chemical limits. 

TABLE 1. BOILER WATER CHEMICAL LIMITS 

Boiler Pressure (psig) 

150 300 600 900 1,200 1,500 

Parameter Chemical Concentration (mg/liter) 

TDS (maximum) 4,000 3,500 3,000 2,000 500 300 

Phosphate (as PO4) 0-60 30-60 20-40 15-20 10-15 5-10 

Hydroxide (as CaCO3) 300-400 250-300 150-200 120-150 100-120 80-100 

Sulfite 30-60 30-40 20-30 15-20 10-15 5-10 

Silica (as SiO2) 100 50 30 10 5 3 

Total Iron (as Fe) 10 5 3 2 2 1 

Organics 70-100 70-100 70-100 50-70 50-70 50-70 

3

Each plant or manufacturing facility should work with its site water treatment expert to 

develop the most appropriate water treatment plan. 

Once the blowdown amount is known, the loss associated with the blowdown can be 

estimated. The blowdown loss equation can be written as, 

λ blowdown = Energy in the blowdown stream 

Total energy added to the boiler with fuel 

λ blowdown = m  ̇ blowdown (hblowdown – hmake-up) (100) 

m ̇ fuelHHV 

(continued on page 10)  

6 Energy Matters, Winter 2003 

Compressed Air System 

Upgrade Results in 

Substantial Energy Savings 

BWX Technologies completed a retrofit project on the compressed air system at their 

Lynchburg, Virginia, manufacturing plant. 

An internal review of the system’s performance allowed plant personnel to determine that certain components needed to be 

retrofitted with more optimal devices. The 

project included replacing antiquated compressors and over-sized dryers, implementing a more sophisticated control strategy, 

and constructing a special room to capture 

heat generated by the new compressors. 

The total cost of the project’s implementation was $487,000. The total annual savings 

were $264,000, or 4.2 million kilowatt 

hours (kWh), leading to a simple payback of 

less than 2 years. 

The replacement of a compressed air system’s components is most appropriate when 

done within the context of a system-level 

strategy to improve the overall 

system’s performance. Because the compressors at the BWX plant were worn, plant 

personnel decided to replace them with 

more cost-effective compressors that better 

served the plant’s needs. Applying the 

proper size of compressed air components 

to meet the plant’s needs also guided the 

decision to purchase new dryers. If plant 

personnel had purchased a dryer similar in 

size to the existing one, they would have 

had a dryer oversized for 70% of the plant’s 

normal needs. By using a systems approach 

towards equipment replacement and selecting the size and type of equipment that best 

suited the plant’s requirements, BWX was 

able to optimally match its air supply to its 

air demand, increasing the efficiency of 

its compressed air system. Configuring the 

system this way has yielded energy savings 

and greater plant efficiency. 

The BestPractices team participates in 

plant assessments and demonstration projects. Take a look at what others in your 

industry have done to increase their energy 

savings by reading their case studies. You 

can view these documents at http://www. 

oit.doe.gov/bestpractices/case_studies 

.shtml. Or, order a document from the 

Industrial Technologies Program Clearinghouse. You can e-mail the Clearinghouse at 

Clearinghouse@ee.doe.gov, or call 800-

862-2086. ● 
DOE and Flying J Refinery Cooperate to Determine Energy Savings 

By Sabine Molden Brueske, Energetics; 

Stuart Smith, Flying J; Robert Brasier, UOP 

Flying J, based in Ogden, Utah, operates a 

25,000 bpsd refinery in North Salt Lake. The 

refinery, with a staff of 130, processes a 

combination of crude oils from Utah, 

Wyoming, and Canada. Refinery products 

include gasoline, diesel, propane, and wax 

intermediates. The refinery supplies fuel 

products to many of the company’s highway 

travel plazas and fuel stops. 

As part of the Utah 2001 Showcase held 

in August 2001, DOE and Flying J refinery 

cost-shared a broad-based study to recommend energy efficiency improvements at 

the North Salt Lake plant. 

The DOE showcase provided a setting 

for Flying J to combine input from a range 

of energy experts and university personnel, 

resulting in a comprehensive evaluation of 

plant-wide energy use. Implementing the 

■	 To benchmark the energy consumption 

to industry standards 

■	 To install a computer-based program 

that allows for continual energy monitoring 

■	 To generate a preliminary list of projects 

to help improve energy efficiency. 

To prepare for the analysis phase of the 

study, the project team conducted process 

unit walk-throughs, held brainstorming 

sessions, and collected operating data for 

each of the units being studied. Also, early 

in the evaluation process experts in industrial energy management best practices 

provided in-plant technical assistance to 

help Flying J identify opportunities for 

increased savings and productivity in 

industrial energy use systems. The experts 

worked with Flying J to evaluate energy 

savings opportunities in process heating, 

pumps, steam, insulation, and compressed 

air systems. 

Energy consumption was calculated for 

each of the process units included in the 

study. Consumption values were benchmarked against industry-wide standards as 

well as against consultant designs. In addition to industry benchmarks, a customized 

“refinery target” was generated for each 

unit. These more refined and adjustable 

refinery targets were based on the best 

actual performances recorded during the 

test period. The intent of the customized 

benchmarks was to create obtainable 

energy targets for each unit, and to identify 

transient energy losses associated with 

short-term upsets or control problems. The 

graphs below show actual energy performance for each process unit compared to 

the benchmarks and refinery target. 

(continues)  

recommendations benefited Flying J by 

reducing electrical consumption by 5% to 

6% and by reducing purchased natural gas 

use by 35% to 40%, resulting in cost savings 

of approximately $900,000 in the first year. 

The study included three elements. First, 

a study was done involving utility plant 

systems, including process heating, pumps, 

compressed air, steam, and insulation. Second, a team of engineering faculty and students from Texas A&M University analyzed 

plant operations. This included a 2-day 

assessment of Flying J plant operations to 

identify, evaluate, and recommend opportunities to conserve energy, increase productivity, and prevent pollution. Texas 

A&M is one of 26 DOE-sponsored, university-based Industrial Assessment Centers. 

Third, Flying J chose to work with UOP 

Refinery Profitability Services Group to 

conduct a 4-month refinery-wide study of 

energy use in the process unit. 

An energy systems audit was performed 

beginning in April 2001. Findings from the 

utility plant systems and the plant operations assessment teams were made available to the consultants for use in their 

energy study. 

UOP began a 4-month, refinery-wide 

study of energy use in 10 process units in 

April 2001. This study had four primary 

objectives: 

■ To summarize the energy consumed in 

the refinery on a per-unit basis 

Snapshot of daily energy use compared to benchmarks. 

Actual 

Industry 

UOP 

80 

70 

60 

50 

40 

30 

20 

10 

0 

Energy Consumed, MMBtu/h 

Crude 

Vacuum 

Butane 

Isomerization1 

Naptha Hydrotreater 

Reformer2 

Alkylation3 

Diesel Desulf 

and Dewax 

Sat Gas 

Sulfur 

1. Butane Isomerization – Flying J reactor is integrated into the Reformer circuit. Benchmarks based on standard 

isomerization configuration. 

2. Reformer – High-pressure unit. Benchmarks based on latest technology using low pressure, high conversion 

configuration. 3. Alkylation – Excessive fluctuations in data; actual energy varied from 75% to 130% of UOP benchmarks. 

Snapshot of daily energy use compared to refinery target. 

80 

70 

60 

50 

40 

30 

20 

10 

Energy Consumed, MMBtu/h 

0 

Crude 

Vacuum 

Butane 

Isomerization1 

Naptha Hydrotreater 

Reformer2 

Alkylation3 

Diesel Desulf 

and Dewax 

Sat Gas 

Actual 

Target 

1. Butane Isomerization – Flying J reactor is integrated into the Reformer circuit. Benchmarks based on standard 

isomerization configuration. 2. Reformer – High-pressure unit. Benchmarks based on latest technology using low pressure, high conversion configuration. 

3. Alkylation – Excessive fluctuations in data; actual energy varied from 75% to 130% of UOP benchmarks. 

Energy Matters, Winter 2003 7 
DOE and Flying J Cooperate continued from page 7 

TABLE 1. RECOMMENDATIONS FOR POTENTIAL ENERGY SAVINGS $22,000/day. The target energy consumpSystem Study Area Potential Savings 

Process Heating Employ oxygen control for flue gases $100,000/yr 

Recover waste heat $1,1000,000/yr 

Pumps Minimize throttle losses on two $39,000/yr 

200 hp charge pumps 

Shut down 250 hp pump during low flow $28,000/yr 

operation and minimize throttle losses 

during high flow 

Reduce or eliminate 75 hp wax crude $10,000/yr 

recirculation flow 

Steam Improve Boiler Efficiency (2 boilers) $120,000/yr 

Replace cracking unit off-gas compresssor $500,000/yr 

steam turbine with electric motor 

Insulation Main steam line, 8” at 365°F $139/yr per LF 

97 LF of ducting, 30” at 320°F $37,000/yr 

Top of 80,000-barrel storage tank at 225°F $148,000/yr 

Reactor head, 44” $8,600/yr 

Crude Unit exchanger, 24” $4,000/yr 

Condensate receiver at 210°F $1,800/yr 

Flanged valve, 10” at 600°F $1,900/yr 

Compressed Air Modify control valves $8,600/yr 

Repair leaks $5,900/yr 

Excessive operating pressure $2,400/yr 

Implement central drying $3.700/yr 

tion was found to be 219 MMBtu/ hr, or 

$21,000/day, representing a potential refinery-wide cost savings of $1,000/day for 

normal operating periods. 

The summation of energy consumed in 

each process unit was compared to the 

summation of refinery target energy consumption for each unit. The graphs on page 

9 show the energy and cost variance 

between the two. 

A key characteristic identified was that 

as energy rates varied, several process units 

showed little change in total energy consumption. This effect was quantified to 

demonstrate the increase in per-barrel 

energy costs resulting from underutilizing 

the equipment. The consultant’s findings 

suggested where improved controls and 

instrumentation would help minimize efficiency loss at low throughputs. 

Flying J Implementation 

Flying J has implemented a majority of 

the savings opportunities suggested by the 

To establish a connection between unit 

operating conditions and energy consumption, the process unit consultant tracked a 

selection of key energy indicators. Some of 

these included heater efficiencies, reflux to 

feed ratios, and steam stripping rates. These 

indicators were used to help identify why a 

unit’s energy consumption changes within a 

specified timeframe. 

Findings 

Efforts by the utility systems, plant operations and process unit assessment teams 

resulted in a number of recommendations 

for Flying J to consider. First, the technical 

experts who analyzed utility systems made 

a number of recommendations, which are 

summarized in the table above. 

Plant Operations Assessment 

Second, the plant operations assessment 

team from Texas A&M identified potential 

annual savings of $261,000 based on eight 

recommendations. These are summarized 

in the table below. 

Process Energy Usage Study 

Third, the process unit analysis spearheaded by UOP identified 33 energy 

improvement projects with a combined 

potential savings of over $1.22 million. 

During the 4-month evaluation period, 

the total energy consumed by the process 

units at Flying J’s Salt Lake City refinery 

averaged 230 MMBtu/hr. This included 

steam, fuel, and electricity consumption, 

and had an equivalent energy cost of 

utility plant system experts. In the area of 

process heating, oxygen control for flue 

gases has been implemented. All of the 

pump system recommendations were seen 

as favorable and have been implemented, 

with the exception of a recommendation 

for a 250 hp pump, which was still under 

evaluation. Boiler efficiency is being 

improved as recommended by the steam 

expert. All of the insulation recommendations have been implemented with the 

exception of the 80,000-barrel storage tank. 

This project was scheduled to take place 

during the next tank inspection. Flying J has 

repaired compressed air leaks and partially 

implemented a central compressed air drying system. 

Of the eight recommendations that 

came from the Texas A&M plant operations 

assessment, Flying J implemented four. The 

remaining projects are still under consideration for future implementation. Flying J has 

proceeded with repairing leaking steam 

traps, insulating reformer unit piping and 

heat exchanger, rescheduling butane isomerization unit regeneration, and repairing 

steam leaks. 

In the year following receipt of the UOP 

energy analysis, Flying J implemented eight 

of the 33 recommended projects and 

TABLE 2. POTENTIAL SAVINGS FROM RECOMMENDATIONS 

Recommendation Potential Savings 

Repair leaking steam traps $147,000/yr 

Install/repair insulation on piping and heat exchanger $47,000/yr 

in Reformer Unit 

Use premium efficient motors $27,000/yr 

Install fixed capacitance to increase power factor $13,000/yr 

Reschedule operation of Butane Isomerization Unit $12,000/yr 

drier regenerations to avoid high demand times 

Use synthetic lubricants on all electric motors $10,000/yr 

Repair steam leaks $3,400/yr 

Retrofit exit sign lamps $1,200/yr (continues)  

8 Energy Matters, Winter 2003 
■ Optimized crude unit stripping steam 

rates 

■ Bypassed heavy diesel run-down coolers. 

■ Produced nitrogen on-site 

■ Insulated hydrotreater reactor piping 

■ Reduced reformer unit reactor circuit 

pressure drop 

■ Reduced carryover of water to the sulfur 

recovery unit 

■ Checked for leaking relief. 

Implementing the recommendations 

benefited Flying J by reducing electrical 

consumption by 5% to 6% and by reducing 

purchased natural gas use by 35% to 40%, 

resulting in cost savings of approximately 

$900,000 in the first year. 

Learn more about energy efficiency projects by attending the Texas Technology 

Showcase in Houston, March 17-19. The 

showcase will offer the latest in processing 

and combustion technologies, and best 

energy management practices that can 

result in improved environmental performance, increased energy efficiency and 

DOE and Flying J Cooperate continued from page 8 

Refinery-wide energy performance graph comparing actual to target energy use. 

250 

230 

210 

190 

170 

150 

10-Mar 30-Mar 

19-Apr 

09-May 29-May 

18-Jun 

08-July 

28-Jul 

17-Aug 

Total Energy, MMBtu/h 

Actual Energy Consumed 

Target Energy Consumed 

5000 

3000 

2000 

1000 

0 

-1000 

10-Mar 30-Mar 

19-Apr 

09-May 29-May 

18-Jun 

08-July 

28-Jul 

17-Aug 

Operating Cost Gap, $/day 4000 Actual Energy Consumed 

Potential refinery-wide cost savings graph based on the cost gap between actual and target 

energy use. 

eliminated another 10 for process reasons that Flying J has currently implemented


unique to Flying J. The remaining projects are :


were still under consideration. ■ Optimized crude unit pre-flash 


The eight process unit recommendations operation 

reduced costs at refineries and chemical 

plants. For more information on the Texas 

Showcase, including registration details, 

visit www.showcasetexas.org, or call tollfree 877-648-7967. ● 

Retrofit Project Helps Mobil Refinery Avoid a Major Capital Investment 

In 1998, the Mobil petroleum distribution 

facility in Vernon, California, was retooled 

from a blending plant into a less energy 

intensive distribution facility. Because the 

plant was being converted, a compressed 

air system review was performed by DOE 

Allied Partner, Scales Air Compressor Corporation. This review led to an improvement project on the plant’s compressed air 

system. The project’s implementation substantially reduced the plant’s energy and 

maintenance costs by substituting a new 

50 hp rotary screw compressor with 

load/unload controls for two 200 hp compressors and two aging 50 hp compressors. 

After the compressor replacement was 

complete, a leak repair campaign was performed, reducing the plant’s load and making its production process more reliable. 

The total project cost was $23,000 and the 

annual savings were $20,700, leading to a 

simple payback of approximately 1 year. 

The plant also avoided $52,000 in capital 

equipment costs by implementing a less 

capital-intensive project. 

Compressed air system optimization 

projects need to include both the demand 

and supply sides of the system because a 

change made in one area will affect the 

rest of the system. If only one side is 

improved, the whole system may not operate as expected, and any anticipated 

energy savings or production improvements may not be realized at all. In the 

case of the Vernon plant, the absence of a 

leak repair campaign as part of the initial 

project caused a new 50 hp compressor to 

run loaded more often than necessary and 

the 200 hp compressor to be operated 

solely to support the leaks. Once the leaks 

were fixed, the compressed air system was 

able to operate using only the new 50 hp 

compressor. 

The BestPractices team participates in 

plant assessments and demonstration projects. Take a look at what others in your 

industry have done to increase their energy 

savings by reading their case studies. You 

can view these documents at 

http://www.oit.doe.gov/bestpractices/case 

_studies.shtml. Or, order a document from 

the Industrial Technologies Program’s 

Clearinghouse. You can e-mail the Clearinghouse at Clearinghouse@ee.doe.gov, or 

call 800-862-2086. ● 

Energy Matters, Winter 2003 9 
Boiler Blowdown Energy Recovery continued from page 6 

Where • • mblowdown is the mass flow rate of blowdown and mfuel is the mass flow rate of fuel 

input to the boiler. The fuel higher heating value (HHV) is required to establish the energy 

input to the boiler. The energy resident in the blowdown stream is characterized by the 

enthalpy difference between the blowdown stream and makeup water, (hblowdown – hmakeup). 

Makeup water enthalpy is used rather than feedwater enthalpy because the blowdown must 

be “replaced” to the system by makeup water. This equation provides the loss associated with 

boiler blowdown as a percent of total energy input with the fuel supplied to the boiler. 

Here’s how it works. Assume a boiler operates with a blowdown rate determined by boiler 

water analysis to be 5.0% of feedwater flow. The boiler in this example produces 400 psig, 

700°F superheated steam. This blowdown rate is considered typical. Steam production from 

the boiler is 100,000 lb/hr resulting in a feedwater flow of 105,260 lb/hr. The blowdown 

flow—5.0% of the feedwater flow—is 5,260 lb/hr. Blowdown and makeup water properties 

are found in the accompanying table. 

TABLE 2. STEAM PROPERTIES 

Letters to the Editor 

Energy Matters welcomes 

your typewritten letters and 

e-mails. Please include your 

full name, address, organization, and 

phone number, and limit comments to 200 

words. Address correspondence to: 

David Wagman, Letters to the Editor


NREL, MS 1609


1617 Cole Blvd.


Golden, CO 80401


E-mail: David_Wagman@nrel.gov


We publish letters of interest to readers 

on related topics, comments, or criticisms/ 

corrections of a technical nature. PreferTemp- Specific Internal 

erature Pressure Volume Energy Enthalpy Entropy Quality 

Location (°F) (psia) (ft3/lbm) (Btu/lbm) (Btu/lbm) (Btu/lbm°R) (%) 

Boiler outlet 700 414.7 1.58945 1,239.90 1,361.88 1.63527 — 

Low pressure 277 24.7 17.46640 1,099.38 1,179.21 1.74124 — 

Boiler blowdown 448 414.7 0.01939 426.55 428.04 0.62561 0.0 

Make-up water 60 14.7 0.01600 28.02 28.07 0.05552 — 

Condensate return 200 14.7 0.01663 167.95 168.00 0.29381 — 

Deaerator outlet 239 24.7 0.01692 207.67 207.75 0.35234 0.0 

Feedpump exit 242 622.1 0.01692 208.47 210.42 0.35615 — 

Assume that natural gas is the boiler fuel, supplied at a cost of $3.75/106

Btu. The boiler 

operates with a combustion efficiency of 85% and a fuel flow rate of 5,896 lb/hr, this equals a 

fuel expense of $4,515,000 a year. The higher heating value of natural gas equals 23,311 

Btu/lbm. A blowdown loss calculation then can be figured as, 

lb Btu Btu 

5,260 hr(428.04 lb – 28.07 lb ) λ blowdown = (100)

lb Btu 

5,896 hr(23,311 lb ) 

Btu 

2,105,100 hr λ blowdown = (100) = 1.5% Btu 

137,450,000 hr 

Another way to say this is to note that more than 2.1 106

Btu/hr (in other words, the numerator of this equation) of input fuel energy is being lost as blowdown. The calculation below 

approximates the economic loss associated with boiler blowdown for this particular boiler, 

λ blowdown = total fuel cost (λ blowdown) 

$ $ λ blowdown = 4,515,000 yr ( 1.5%

) = 67,700 100 yr

Economically attractive projects can stem from thermal energy recovery related to boiler 

blowdown. There are typically two primary energy recovery activities employed in industry, 

and both often are incorporated in one system. 

As a first energy recovery stage, the saturated liquid high-pressure blowdown is discharged 

into a relatively low-pressure receiver. As the pressure falls a portion of the liquid flashes to 

steam. This steam is typically free from impurities carried by the liquid blowdown provided 

no droplets are carried into the steam exit. As a result this steam is available for use in the 

steam system. 

Properly designed flash vessels reduce the possibility of droplet carryover. (Several references are listed at the end of this article that offer straightforward design strategies for flash 

ence is given to articles that appeared in 

the previous two issues. Letters may be 

edited for length, clarity, and style. ● 

To the Editor: 

I just received the Fall 2002 issue of Energy 

Matters and I feel I have to comment on 

the comparison of motor rewind vs. new 

motors in the Ellensburg Wastewater Treatment Plant article. 

Based on the most recent Motor Master + 

data base I see that this example was for a 

900 RPM TEFC motor. This should have 

been indicated because 900 RPM motors 

usually do cost more. You have also used 

list prices for both the standard efficient 

motor and the premium motor. I know of 

no cases where people pay full list price. 

Quite often the prices are reduced as much 

as 30 to 40% or more. This has a great 

effect in reducing the incremental cost 

between the standard and premium 

motors. Furthermore, the data base itself 

showed a similar motor (based on efficiency) with a list price far below the 

$12,673 that you quoted. Maybe this 

motor wasn’t exactly the right fit but I’m 

sure something could have been found for 

less than the $6,000 differential price you 

showed. 

Richard A. Schondelmeier 

Senior Program Administrator 

Northeast Utilities 

To the Editor: 

I read the article on compressed air with 

great interest (“Compressed Air’s Role in 

(continues on page 11)  (continues)  

10 Energy Matters, Winter 2003 
Productivity,” Fall 2002). Overall, the article 

is good but I do have two points to make. 

First, I do not agree with the recommendation to install supply-side pressure regulators. These devices do not solve the real 

problems: inadequate compressor controls 

and leaks. The pressure regulator does not 

provide a stored air volume, the large tank 

you have to install to make it work provides the volume. This tank is required 

because the already inadequate compressor controls will not work well when the 

compressors are isolated from the process. 

The volume is needed to stabilize the compressors and minimize cycling. Proper 

compressor controls allow the header 

pressure, and the compressor discharge 

pressure, to be reduced and will respond 

to process demands without needing large 

volumes. Proper controls will save more 

energy and cost less than a supply side 

pressure regulator and volume tank. 

Second, the article does not address the 

extraordinary inefficiency of compressed 

air systems and the recommendation to 

eliminate the use of compressed air whenever possible. When calculating the cost of 

production, facilities should consider the 

cost of compressed air versus other solutions such as electric actuators, solenoids, 

low pressure blowers, and hand tools. 

Kendall W. White, P.E., CEM


Environmental Engineer


Pollution Prevention Services


Energy and Waste Management Bureau


Iowa Department of Natural Resources


EXTRA 

This month on the Energy Matters Extra 

Web site, we’ve provided supplementary 

information on selling energy-saving projects to management. We also show you 

how to access and order the new CDs: the 

Chemical Industry of the Future CD and 

the Motor Market Assessment CD. And 

there’s more! Log on to Energy Matters 

Extra at www.oit.doe.gov/bestpractices/ 

energymatters/emextra. ● 

Boiler Blowdown Energy Recovery continued from page 10 

vessel design.) The amount of flash steam produced increases as the difference between the 

boiler pressure and the flash pressure increase. The flash vessel allows the remaining liquid 

blowdown to separate from the flash steam. The flash steam then is either piped into the lowpressure steam system or into the deaerator. 

A second energy recovery stage may also be applied. Here, a heat exchanger transfers the 

remaining liquid blowdown energy to makeup water. A significant temperature difference 

typically exists between the saturated liquid leaving the flash tank and the makeup water 

supplied to the system, or the water supplied to the deaerator. 

Care should be taken in choosing a heat exchanger because the blowdown stream has a 

significant fouling potential. The heat exchanger must be capable of being mechanically 

cleaned periodically, especially those surfaces that come into contact with the blowdown. 

The heat exchanger should also be equipped with temperature-indicating devices on the inlet 

and outlet blowdown liquid streams as well as on the inlet and outlet makeup water streams. 

These temperature indications allow the heat exchanger’s effectiveness to be determined. 

Both the flash tank and the heat exchanger can be used in combination to provide lowpressure steam and to preheat makeup water. In the combined arrangement, blowdown water 

leaving the flash tank passes through the heat exchanger. A steam system specialist should be 

contacted to analyze the opportunity associated with these projects, as it often is difficult to 

implement this type of energy recovery strategy in systems that use intermittent blowdown. A 

schematic of the blowdown energy recovery system is provided below. 

Saturated 

Liquid

Blowdown 

Blowdown 

Control 

Valve 

Low Pressure 

Flash Vessel 

Saturated 

Vapor 

Saturated 

Liquid 

Saturated 

Liquid

Discharge 

Level 

Controller

Heat Exchanger 

Heated 

Makeup 

Water 

Discharge 

Discharge 

to Sewer 

T1 

T3 

T4 

T2 

Saturated 

Vapor 

Supply 

Blowdown energy recovery system. 

The type of system discussed in this article can help your plant or facility recover more than 

80% of the thermal energy resident in the blowdown stream. The required equipment can 

generally be bought and installed in such a way that it yields an economically attractive project. Further economic benefit can be attained in systems requiring reduced temperature 

wastewater discharges. Often cold water is required to be mixed with blowdown entering the 

sewer system to avoid an elevated temperature within the sewer system. This cold water can 

result in significant expense. 

Resource List 

1. The Nalco Water Handbook, Second Edition, Frank Kemmer, McGraw Hill, 1988. 

2.	 Fundamentals of Engineering Thermodynamics, Second Edition, Michael J. Moran and 

Howard N. Shapiro, John Wiley and Sons, 1992. 

3.	 National Board Rules and Recommendations for the Design and Construction of Boiler 

Blowoff Systems, 1991. ● 

Energy Matters, Winter 2003 11 
Coming Events 

CHEMICAL AND PETROLEUM SHOWCASE, HOUSTON, TX 

■ Mar 17 - Mar 19, 2003 

For more information, contact David Salem, Chemical and Petroleum Team, 202-586-8710 

MINING SHOWCASE, ELKO, NV 

■ Aug 25 - Aug 28, 2003 

For more information, contact: Mike Canty, Mining Team Lead, 202-586-8119 

BestPractices 

The Industrial Technologies Program’s BestPractices initiative and its Energy Matters 

newsletter introduce industrial end users to 

emerging technologies and well-proven, 

cost-saving opportunities in motor, steam, 

compressed air, and other plant-wide systems. 

NORTH AMERICAN DIE CASTING ASSOCIATION (NADCA) 

■ Sep 15 - Sep 18, 2003 

For more information, contact Harvey Wong Metal Casting Team Lead, 202-586-9235 

To keep up-to-date on Industrial Technologies Program’s training and other events, 

check the calendar regularly on Energy Matters Extra at www.oit.doe.gov/bestpractices/ 

energymatters/emextra. 

INFORMATION 

CLEARINGHOUSE 

Do you have questions about 

using energy-efficient process 

and utility systems in your industrial 

facility? Call the Industrial Technologies 

Program’s Information Clearinghouse 

for answers, Monday through Friday 

9:00 a.m. to 8:00 p.m. (EST). 

Fax: 360-586-8303, or access our 

homepage at www.oit.doe.gov/ 

clearinghouse. 

HOTLINE: 800-862-2086 

DOE Regional Office Representatives 

■ David Godfrey, Atlanta, GA, 

404-562-0568 

■ Scott Hutchins, Boston, MA, 

617-565-9765 

■ Brian Olsen, Chicago, IL, 

312-886-8479 

■ Jack Jenkins, Denver, CO, 

303-275-4824 

■ Chris Cockrill, Seattle, WA, 

816-873-3299 

■ Joseph Barrett, Philadelphia, PA, 

215-656-6957 

T OF ENERGY

DEPARTMEN U 

E 

NITED STAT S OFA ERICA 

M 

This document was produced for the Office 


of Energy Efficiency and Renewable Energy at


the U.S. Department of Energy (DOE) by the 


National Renewable Energy Laboratory, a DOE


national laboratory.


DOE/GO-102003-1693 • Winter 2003


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