Office of Air and Radiation October 2010

 

AVAILABLE AND EMERGING TECHNOLOGIES FOR 

REDUCING GREENHOUSE GAS EMISSIONS FROM 

INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL 

BOILERS 

 

 

 

 

 

 

 
2

Available and Emerging Technologies for Reducing

Greenhouse Gas Emissions from Industrial, Commercial, 

and Institutional Boilers

 

 

 

 

 

 

 

 

 

 

 

 

 

Prepared by the 

 

Sector Policies and Programs Division 

Office of Air Quality Planning and Standards 

U.S. Environmental Protection Agency 

Research Triangle Park, North Carolina 27711 

 

 

 

 

 

 

 

 

October 2010 
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Table of Contents

 

I. Introduction ....................................................................... 4

Page

II. Purpose of This Document .................................................. 4

III. Description of ICI Boilers .................................................. 4

IV. Description of ICI Boiler Design Types .................................. 6

1. Pulverized Coal ...................................................... 6

2. Fluidized Bed ......................................................... 6

3. Stoker .................................................................. 7

4. Watertube ............................................................. 7

5. Firetube ................................................................ 8

V. Summary of Measures to Reduce GHGs.................................... 8

VI. Energy Efficiency Improvements ......................................... 11

1. O&M Practices ...................................................... 11

1.1 New Burners / Upgrades ..................................... 12

1.2 Improved Combustion Measures .............................. 13

2. Air Preheat and Economizers ..................................... 15

3. Turbulators for Firetube Boilers .................................. 17

4. Boiler Insulation .................................................... 18

5. Minimization of Air Infiltration ................................... 19

6. Boiler Blowdown Heat Exchanger ............................... 19

7. Condensate Return System ......................................... 20

8. Refractory Material Selection ...................................... 21

9. Minimization of Gas-Side Heat Transfer Surface Deposits .... 21

10. Steam Line Maintenance ............................................ 22

VII. Energy Programs and Management Systems ........................... 23

1. Sector-Specific Plant Energy Performance Benchmarks ....... 25

2. Industry Energy Efficiency Initiatives .............................. 26

VIII. Carbon Capture and Storage ....................................... 26

IX. Other Measures to Reduce GHG Emissions .............................. 26

1. Alternative Fuels – Biomass ........................................ 26

2. Co-firing ............................................................... 27

3. Fuel Switching ........................................................ 29

4. Combined Heat and Power .......................................... 33

EPA Contacts ....................................................................... 37

References ........................................................................... 38
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I. Introduction

This document is one of several white papers that summarize readily available information on 

control techniques and measures to mitigate greenhouse gas (GHG) emissions from specific industrial 

sectors. These white papers are solely intended to provide basic information on GHG control 

technologies and reduction measures in order to assist States and local air pollution control agencies, 

tribal authorities, and regulated entities in implementing technologies or measures to reduce GHGs under 

the Clean Air Act, particularly in permitting under the prevention of significant deterioration (PSD)

program and the assessment of best available control technology (BACT). These white papers do not set 

policy, standards or otherwise establish any binding requirements; such requirements are contained in the 

applicable EPA regulations and approved state implementation plans.

II. Purpose of This Document

This document provides information on control techniques and measures that are available to 

mitigate greenhouse gas (GHG) emissions from industrial, commercial, and institutional (ICI) boilers 

at this time. While a large number of available technologies are discussed here, this paper does not 

necessarily represent all potentially available technologies or measures that that may be considered for 

any given source for the purposes of reducing its GHG emissions. For example, controls that are applied 

to other industrial source categories with exhaust streams similar to the cement manufacturing sector may 

be available through “technology transfer” or new technologies may be developed for use in this sector. 

The information presented in this document does not represent U.S. EPA endorsement of 

any particular control strategy. As such, it should not be construed as EPA approval of a 

particular control technology or measure, or of the emissions reductions that could be achieved 

by a particular unit or source under review.

III. Description of ICI Boilers

Industrial boilers encompass the category of boilers used in manufacturing, processing, 

mining, and refining or any other industry to provide steam, hot water, and/or electricity. 

Industrial boiler systems are used for heating with hot water or steam in industrial process 

applications. Industrial boilers are located at facilities in the food, paper, chemicals, refining, 

and primary metals industries. There is no precise regulatory definition or specific size 

requirement for an industrial boiler. An industrial boiler is typically defined by its common 

function – a boiler that provides heat in the form of hot water or steam for co-located industrial 

process applications. This industrial boiler category does not include electric utility boilers as 

these do not provide the same service. An electric utility boiler is defined as a fossil fuel-fired 

combustion unit of more than 25 megawatts that serves a generator that produces electricity for 

sale. 

Commercial boilers encompass the category of boilers used in commercial establishments 

such as hotels/motels, restaurants, stores, office buildings, apartment buildings, and laundries to 

provide steam and/or hot water. Commercial boiler systems are used for heating with hot water 

or steam in commercial buildings. Commercial boilers are generally small in size compared to 

industrial boilers. A commercial boiler is typically defined by its common function – a boiler 

that provides heat or hot water for a commercial building or facility. 
5

Institutional boilers encompass the category of boilers used in institutional establishments 

such as medical centers, universities, schools, government buildings, and military installations to 

provide steam, hot water, and/or electricity. Institutional boiler systems are used for heating with 

hot water or steam. A majority of these are located at educational facilities. 

ICI boilers can use a number of different fuels including coal (bituminous, sub 

bituminous, anthracite, lignite), fuel oil, natural gas, biomass (wood residue, bagasse), liquefied 

petroleum gas, and a variety of process gases and waste materials. Each of these fuels has 

different combustion characteristics and produces distinct GHG emissions. Coal is the highest 

CO2 producer in ICI boilers with an average emission factor of 93.98 kg CO2/million British 

thermal units (MMBtu); natural gas has the lowest emissions of CO2 from ICI boilers with an 

average emission factor of 53.06 kg CO2/MMBtu. (EPA, 2008)

Figure 1 presents a process flow diagram of a typical industrial boiler system. 

Combustion for heat generation begins in the boiler burner system and the heat is transferred to 

the water in the boiler. The boiler produces steam and hot water for industrial process 

applications. Many boilers use an economizer to preheat the process water before it is fed to the 

boiler using waste heat from the exhaust gas. This combustion operation produces CO2

emissions and is the focus of the emission reduction techniques presented in the remainder of 

this document.

Figure 1. Schematic of an Industrial Boiler System.

Source: EPA, 2008
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IV. Description of ICI Boiler Design Types

This section includes a brief description of the ICI boiler designs. The most common ICI 

boiler designs are:

1. Pulverized coal, 

2. Fluidized bed,

3. Stoker,

4. Watertube, and

5. Firetube.

Each design has unique characteristics and can be used in various applications and industries. 

Some of these designs use multiple fuels. The larger of these boiler designs can be used to 

produce electricity, steam, or both. 

1. Pulverized Coal

Pulverized-coal (PC) boilers offer a more efficient alternative to stokers for burning coal. 

PC boilers are used in large ICI units. In PC boilers, the coal is pulverized to very small particles 

in large devices called pulverizers or mills. These coal particles are then blown with air into the 

boiler through a “burner,” where they are then burned in suspension in the furnace. PC boilers 

are usually characterized by the burner configuration (tangential, wall, cyclone) and whether the 

bottom ash exits the boiler in solid or molten form (dry bottom vs. wet bottom) (EEA, 2005). 

2. Fluidized Bed

Fluidized-bed combustors (FBC) are boilers of a more recent design and were developed 

for solid fuel combustion. In FBC, combustion takes place in suspension as in a PC boiler, but 

instead of individual burners controlling the air/fuel mixing, fuel and a mixture of inert material 

(e.g., sand, silica, ash, sorbent products) are kept suspended above the bed by an upward flow of 

combustion air through the fuel bed. This fluidization improves mixing of fuel and air, as well 

as allowing for higher residence times in the furnace (the retention time of the fuel in the bed). 

FBC are inherently suited for various fuels, including low-grade fuels such as petroleum coke, 

coal refuse, municipal waste, and biomass materials.

Even though FBC boilers do not constitute a large percentage of the total ICI boiler 

population, they have gained popularity in the last few years, due primarily to their capabilities 

to burn a wide range of solid fuels and their low- nitrogen oxide (NOX)/sulfur dioxide (SO2)

emission characteristics.

There are two major types of FBC systems currently in operation in the ICI sector: 

(1) bubbling bed – operating at a fluidizing velocity that is less than the terminal velocity of 

individual bed particles, and (2) circulating bed – operating at fluidizing velocity that exceed the 

terminal velocity of individual bed particles. 
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3. Stoker

Stoker boilers have been around the longest. In stoker boilers, the fuel is combusted in 

relatively thin layers on top of a “grate.” Stoker boilers are typically characterized according to 

the way fuel is transported to the grate. There are several ways to accomplish this. The most 

common type is the spreader stoker, where the fuel is “spread” above the grate, allowing the 

fines to combust in suspension while the heavier pieces fall to the grate and combust. Another 

type, underfeed stokers, essentially “push” the fuel into the bottom of the fuel bed, where it is 

volatized and combusted by the time it reaches the top of the bed. Chain-grate, traveling-grate, 

and water-cooled vibrating-grate stokers are less common configurations, but all achieve the goal 

of maintaining a thin bed of burning fuel on the grate.

As with PC boilers, heat is transferred from the fire and combustion gases to watertubes 

on the walls of the boiler. Stokers can burn a variety of solid fuels, including coal and various 

wood and waste fuels.

4. Watertube

Large Watertube

As the name suggests, the large watertube boiler category is classified by its size. The 

sizes range generally from 10 to 10,000 million Btu per hour (MMBtu/hr). Large watertube 

boilers account for the majority of steam production and use mostly solid fuels. They comprise 

the boiler technologies described above, which include PC, FBC, and stoker boilers. Highercapacity watertube ICI boilers often use a combustion air preheat to improve overall efficiency.

.

In watertube boilers, the fuel is combusted in a central chamber (furnace, bed, or grate) 

and the combustion gas transfers heat energy, through radiation and convection, to the water 

circulating in the metal tubes. The number of tubes varies greatly depending on boiler capacity. 

The watertubes are often welded together to form the walls of the combustion chamber in a socalled “waterwall.” Water circulates through the pipes, and the flow is designed to take 

advantage of different thermal zones to achieve specific steam conditions. Watertube boilers can 

produce steam at very high temperatures and pressures, but these boilers tend to be more 

complex and expensive than firetube units.

In terms of the ICI boiler population, most watertube boilers are sized under 10 

MMBtu/hr and, hence, characterized as small. These small watertubes are mostly oil- and gasfired boilers. Watertube boilers are used in a variety of applications ranging from supplying large 

amounts of process steam to providing space heat and hot water for industrial, commercial, and 

institutional facilities. Fundamentally, these boilers operate within the same principles as their 

“large” counterparts.

Small Watertube.
8

5. Firetube 

Firetube units are typically the smallest boilers, with most units less than 10 MMBtu/hr in 

capacity. Almost all firetube boilers burn oil, gas, or both. In a firetube boiler, the “fire” and the 

water trade places. The water is stored in the main body of the boiler, while the combustion 

gases flow through one or several metal tubes within the body of the boiler. Heat is transferred 

to the water by conduction from the firetube(s) to the surrounding water. Firetube boilers are 

characterized by the number of “passes” the firetubes make through the boiler water. Increasing 

the number of passes increases overall efficiency. The advantages of firetube boilers are their 

simplicity and low cost. The mixing of the water in one large chamber makes a firetube boiler 

well suited to producing hot water or low-pressure steam. Firetube boilers are typically prefabricated and shipped to the site.

V. Summary of Measures to Reduce GHGs 

Table 1 summarizes the GHG emission reduction measures for existing ICI boilers 

presented in this document. Where available, the table includes emission reduction potential, 

energy savings, costs, and feasibility of each measure. Generally, efficiency gains are a function 

of the difference between the new and old technologies or processes and are expressed in 

percent.

Table 1. ICI Boilers – Summary of Greenhouse Gas Emission Reduction Measures

GHG 

Measure Applicability

Efficiency 

Improvement 

(percentage pt)

CO2

Reduction 

(%)

Capital 

Costs Notes/Issues

Energy Efficiency Improvements

Replace/

Upgrade Burners

All, except for 

Stoker-type 

boilers and 

fluidized bed 

boilers

Up to 4-5%. Up to ~ 6%. $2,500 – 5,100 

per MMBtu/hr

Site specific 

considerations 

(retrofit ability) and 

economic factors 

may affect the 

installation of burners

Tuning All CO from 1000-2000 

to < 200 ppm

Unburned carbon 

(UBC) from 20-

30% to 10-15%

up to ~3% Up to $3000 Manual tuning with 

parametric testing

Optimization All 0.5% – 3.0% up to ~ 4% $100,000 Neural networkbased

Instrumentation

& Controls

All, especially at

large plants

0.5% – 3.0% (in 

addition to 

optimization)

up to ~ 4% >$1million System integration, 

calibration, and 

maintenance

Economizer Units with 

capacity over 

40°F decrease in 

flue gas temperature 

Relates to 

efficiency 

$2.3 million Larger units; must 

consider pressure 
9

25,000 pounds 

of steam per 

hour; 

equals 1% 

improvement

gain in boiler (for 650 

MMBtu/hr)

loss, steam 

conditions 

Air Preheater Units with 

capacity over 

25,000 pounds 

of steam per 

hour; 

A 300°F decrease in 

gas temperature 

represents about 6% 

improvement

~ 1% per 40°F 

temperature 

decrease

$200,000 –

250,000

(for 

10MMBtu/hr) 

Used in large boiler 

applications, not 

widely used in ICIs 

due to increase in

NOX

Create turbulent 

flow within 

firetubes

Single or two 

pass firetube 

boilers 

1% efficiency gain 

for 40°F reduction 

in flue gas 

temperature

100°F -150°F 

temperature 

decrease potential

~ 1% per 40°F 

temperature 

decrease

up to ~ 4%

$10 – 15 per 

tube

Widely accepted with 

older boilers; 

Insulation All, most 

suitable for 

surface 

temperatures 

above 120o

F

Dependent on 

surface temperature

Up to 7% Radiation losses 

increase with 

decreasing load

Reduce air 

leakages

All 1.5 – 3% potential

(Effect similar to 

reducing excess air)

Up to ~ 4% Site-specific

(None to cost 

of maintenance 

program)

Requires routine 

maintenance 

procedures

Capture energy 

from boiler 

blowdown

Most suitable 

for units w/ 

continuous 

boiler 

blowdown 

exceeding 5% 

of steam rate

Site specific 

depending on steam 

conditions

Up to ~ 7%

Up to ~ 8%

See efficiency 

comment

NA Water quality issue 

important

Condensate 

return system

All; However, 

larger units 

more 

economical to 

retrofit

Site specific -

depends on 

condensate 

temperature and % 

recovery 

Same as 

efficiency 

improvement, 

ratio of Btu/hr 

saved from 

condensate to 

Btu/hr input

$75,000 Energy savings is the 

energy contained in 

the return 

condensate, 

condensate quality 

affects use

Reduce slagging 

and fouling of 

heat transfer 

surfaces

Watertube 

boilers

1% to 3%

Site specific; fuel 

quality/operating 

condition have large 

impact

Up to ~ 4% $50,000 to 

$125,000

Downtime/economic 

factors, regain lost 

capacity

Insulating 

jackets

Surfaces over 

120°F

Same as 

efficiency 

improvement

Depends on 

length/type of 

insulation 

required for 

implementation

No deployment 

barriers
10

Reduce steam 

trap leaks

All None to cost of 

maintenance 

program

No deployment 

barriers

Post-Combustion 

Carbon capture 

and storage

demonstrated at the 

slip-stream or pilotscale

Other Measures

Alternative fuels 

– biomass

All fossil fuels Less caloric content 

than fossil fuel

Co-firing Coal-fired and 

oil-fired boilers 

reduction up to 2% 

for biomass cofiring

20-30% 

reduction with 

gas co-firing

Negative impact of 

boiler efficiency

Fuel switching Coal-fired and 

oil-fired boilers

20-35% 

reduction 

switching 

from coal to 

oil; 20-35%

reduction 

switching 

from coal to 

natural gas

Change in hardware 

to accommodate 

100% fuel switch

Combined heat 

and power

All Overall efficiency 

improves from 30-

50% to 70-80%

$1,000-

2,500/kW

High capital 

investment
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VI. Energy Efficiency Improvements

This section presents the efficiency improvement measures identified for ICI boilers. 

The majority of the identified options focus on measures that are common from the perspective 

of applicability, availability, and owner/operator experience. Some options that may require 

project or site reconfiguration and process modifications, such as combined heat and power 

(CHP) and repowering, are also included in this section. Additional costs and complexities 

would need to be considered with these options. Options will vary for each unit and multiple 

options may be applied to save energy. 

Efficiency gains derived from the various techniques or measures as well as the CO2

benefit associated with such gains are summarized for each measure in the summary table. In 

many cases the impacts of these measures are highly site specific and benefits will vary. Ranges 

for potential benefits are listed when appropriate. Because boilers have different baseline 

efficiencies, it is easier to state efficiency gains in percentage points (e.g., from 78 to 83 % = 5 

percentage points) rather than the actual efficiency gain as a percent improvement (e.g. from 78 

to 83% = 1-78/83 = 6 %). Of course it is the actual percent efficiency gain that translates 

directly to CO2 reduction. For purposes of providing nominal values in the summary tables, a 

baseline efficiency of about 78 % was used to relate efficiency gains in “percentage points” to 

CO2 reduction potential as a fractional improvement as in the example above. 

1. O&M Practices

Operating and maintenance (O&M) practices have a significant impact on plant 

performance, including its efficiency, reliability, and operating costs. Each of these parameters 

change over the life of the plant, and some deterioration of equipment is unavoidable. Boiler 

efficiency will decreases over time. The rate of deterioration can be curbed by good O&M 

practices. A well operated and maintained plant will experience less deterioration of boiler 

efficiency.

Deterioration results in higher heat rate, CO2 emissions, and operating costs; in lower 

reliability; and in some cases, reduced output. After a few years of neglect, it may reach the 

point where significant investment is required to rehabilitate the plant and bring it as close as 

possible to the design performance. Such rehabilitation programs are capital intensive and

typically O&M is covered in the budget of the plant for this reason.

Rehabilitation may focus on life extension and reliability improvement of the plant or 

may include additional measures that improve plant efficiency, occasionally above the original 

design efficiency. The efficiency can be improved by retrofitting combustion control 

technologies such as: heat recovery systems, control technology, and upgraded burners. 

Additional GHG reductions can be achieved through energy improvements in the 

steam/hot water distribution system, the boiler auxiliaries, or in process efficiency 

improvements. (U.S. EPA, 2008)
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1.1 New Burners/Upgrades

Older, wrongly sized, or mechanically deteriorated burners are typically inefficient. 

Inoperable dampers, broken registers, or clogged nozzles will render an otherwise good burner 

into a poor performer. These inefficiencies result in incomplete combustion (high carbon 

monoxide (CO) emissions and unburned carbon) and the need for high excess air. Burner 

maintenance, discussed above, is important because it can improve efficiency.

Burner upgrades will often need to consider controlling conventional emissions and 

multiple burners where the ability to maintain ideal air/fuel conditions is much more challenging.

More sophisticated combustion monitoring and controls may be an integral part of an upgrade 

and are described as a separate measure in the section on tuning and optimization.

Burner replacement and retrofits can be considered on any burner. New burners for all 

types of boilers and fuels are commercially available. Burners with single and multiple fuel 

capability, low- and ultra low-NOX models, and sizes ranging from very small to very large are 

widely deployed in industry. In addition, many suppliers (original equipment manufacturer 

(OEM) and non-OEM) offer burner retrofit parts for modifying burners rather than fully 

replacing them; this often can achieve significant improvements at lower cost than a full 

replacement. Site-specific conditions and objectives may favor one model over the other.

The potential for efficiency gains from new burners is a function of the difference 

between the old and new technologies. Levels of CO/UBC (incomplete combustion) and excess 

air between the new and old will dictate the performance improvement potential. Further, the 

burner size and turndown capability (i.e., ability to operate and/or efficiency of operation at less 

than full load) will impact the losses associated with inefficient low load and on/off cycling duty.

As an example, a natural gas burner requiring 2 percent excess oxygen (or 10 percent

excess air) in the flue gas has an efficiency of about 84 percent. A less efficient burner, requiring 

5 percent oxygen (O2) (or about 25 percent excess air), has about an 83 percent efficiency for a 1 

percent net lose in efficiency. For a coal-fired unit burning 10 percent ash coal, an unburned 

carbon (UBC or loss on ignition (LOI)) level of 20 percent would represent about a 2.5 percent 

fuel loss (Cleaver-Brooks, 2008; Ganapathy, 2003).

Finally, regarding size/turndown capability, most gas burners exhibit a turndown ratio, 

which is the ratio of capacity at full fire to its lowest firing point before shutdown, of 10:1 or 

12:1 with little or no loss in combustion efficiency. However, some burners offer turndowns of 

20:1 and up to 35:1 on oil. A higher turndown ratio reduces burner startups, provides better load 

control, saves wear-and-tear on the burner, and reduces purge-air requirements, all resulting in 

better overall efficiency (CIBO, 2003). 

To illustrate potential savings, a 100 MMBtu/hr boiler, operating at an annual capacity 

factor of 45% or 400,000 MMBtu/yr, was considered with a combustion efficiency of 79%. At a 

price of $10/MMBtu, the annual fuel cost is $4 million. The savings from an energy efficient 

burner that improves combustion efficiency by 1 percent would be (EERE 2006a):
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• Fuel Savings = [1 – current combustion efficiency (79)/improved combustion efficiency(80)]

= 1.3 percent = 5,200MMBtu

• Annual Savings (at $10/MMBtu) = 5,200 × $10/MMBtu = $52,000

• For a new low NOX burner upgrade package costing $250,000, a simple payback of about 5 

years would result

• Source: NESCAUM & MANE-VU, 2005

Implementing this measure may be technically straightforward. Site-specific conditions 

and economic considerations must be addressed. As already mentioned, burner 

replacement/retrofits can be considered at all facilities. New burners for all types of boilers and 

fuels are commercially available. Replacement of burners may also be needed to comply with 

conventional emission regulations. For example, specifically for NOX reductions, new low-NOX

burners and ultra-low-NOx burners offer the opportunity to comply with conventional emissions

regulations as well as improve efficiency. 

1.2 Improved Combustion Measures

There are a number of options for improving the combustion process and the overall 

performance of an ICI boiler. Although there is not a clear separation between them, for 

practical purposes they may be separated into the following groups:

• Combustion system tuning; 

• Combustion and boiler performance optimization; and

• Instrumentation and Controls (I&C).

Combustion Tuning

One objective of the initial setting of the combustion system is to maximize the 

combustion efficiency (minimize UBC and CO emissions), and demands to minimize NOX

emissions may require further tuning. Also, the combustion system may drift over time from its 

optimum setting or certain controls (e.g., dampers) may not be operational due to wear.

Tuning of the combustion system requires a visual check by an experienced boiler or 

stationary engineer to ensure that everything is in good working condition and set according to 

the manufacturer’s recommendations or the optimum settings developed for the particular boiler. 

Simple parametric testing may be required, which may involve changes in the key control 

variables of the combustion system and observation of key parameters such as CO emissions, 

steam outlet conditions, flue gas outlet (stack) temperature, and NOX emissions.
14

Optimization

Optimization can be accomplished in a number of different ways. The most basic 

method has been described above and is based on parametric testing, analysis of the results, and 

estimating optimum operating parameters based on a given objective. The objective could be 

combustion efficiency (the measure of completeness of oxidation of the fuel), NOX emissions, 

boiler efficiency (the ratio of net energy output divided by the energy input), plant efficiency, or 

a combination of these. For most ICI boilers, periodic testing and manual tuning are adequate. 

For larger boilers, especially ones that change operating conditions (e.g., load) frequently, it may 

be economical to install an optimization system. These are software-based systems that monitor 

and optimize boiler performance based on a user-specified objective within pre-set operating 

constraints.

Instrumentation and Controls

While optimization systems can function with whatever instrumentation and controls 

(I&C) are available at a facility, digital control systems are generally necessary to achieve the 

greatest improvement in performance through tuning and optimization. If the facility does not 

already have a modern control system, whether or not such a system is justified requires a sitespecific assessment. The decision is highly dependent on the boiler size and the requirements of 

automation and monitoring, not only of the boiler, but of the overall facility.

Instrumentation requirements are subject to the same issues; there are no fixed 

requirements for instrumentation. In fact, very little instrumentation is essential to operate the 

boiler safely. However, if maximizing boiler efficiency or minimizing emissions (e.g., CO, 

NOX, and CO2) is required, certain instrumentation is justifiable, such as, temperature sensors, 

oxygen monitors. Additional instrumentation makes it possible to achieve better performance. 

For example, excess air (oxygen) is usually set based on the manufacturer’s 

recommendations/guidelines with the objective to avoid incomplete combustion and maintain a 

stable flame. Usually, the excess air is set higher than required to ensure safe operation 

throughout the operating range of the boiler. As a result, 30 percent excess air may be set, when 

15-20 percent may be adequate. If a CO monitor is installed, the boiler operator can fine-tune 

the process for uniform operation at minimum excess air without generating excess CO

emissions.

One process control measure that has been used for ICI boilers is the use of oxygen trim 

controls. These controls measure the stack oxygen concentration and automatically adjust the 

inlet air at the burner for optimum efficiency. Manufacturers estimate that a 1 percent thermal 

efficiency can be achieved using this control.

Tuning, optimization and I&C are applicable to all boilers. However, optimization and 

I&C may not be economical in all cases. Usually, the larger the boiler, the more likely 

optimization and I&C could be justified. Also, coal or biomass fired boilers may be better 

candidates for optimization and I&C systems than natural gas-fired systems because their 

operating parameters (e.g., fuel quality) may be variable and difficult to control.
15

It is not easy to estimate efficiency improvement due to tuning, optimization, and I&C, as 

each of these approaches is site-specific and is affected greatly by the operating condition of the 

boiler (prior to implementing these measures), the type of fuel it burns, the number of control 

variables (set-points), etc. Typical estimates of efficiency improvement will be provided for 

illustration purposes. Combustion system tuning could reduce significantly CO emissions and 

UBC (in the case of coal- or oil-firing), with a CO reduction from 1000-2000 ppm to less than 

200 ppm not considered unusual. In the case of coal-fired systems, UBC (in the flyash) may be 

reduced from 20-30 percent to 10-15 percent. The addition of optimization systems, modern

controls systems, and instrumentation has resulted in efficiency improvement of 0.5 to 5.0 

percentage points. 

Tuning requires 1-2 days time of an experienced engineer. Cost estimates for tuning, 

optimization and I&C vary greatly. If the facility does not have an engineer, a consultant can be 

hired at a cost of $2,000 to $3,000. An optimization system, using neural network technology, 

ranges from $100,000 to $200,000 fully installed, calibrated, and tested. Annual technical 

support may be needed and could range from $10,000 to $30,000. The costs for modern control

systems vary; for large boilers to install new I&C, the cost may exceed $1 million. 

Implementing these measures may be technically straightforward and would require 

raising the awareness of facility staff and management regarding the potential cost savings and 

importance of tuning/optimization.

2. Air Preheat and Economizers

For most fossil fuel-fired heating equipment, energy efficiency can be increased by using 

waste heat gas recovery systems to capture and use some of the heat in the flue gas. The most 

commonly used waste heat recovery methods are preheating combustion air and water heating. 

Heat recovery equipment includes various type of heat exchangers (economizers and air heaters), 

typically located after the gases have passed through the steam generating sections of the boiler. 

Air heaters transfer heat from the flue gas to the incoming combustion air. In lowpressure gas- or oil-fired boilers, air heaters function simply as gas “coolers,” as there is no need 

to preheat the oil or gas in order for it to burn. Pulverized coal-fired boilers require the use of air 

preheaters to evaporate the moisture in the coal. This heated air also serves to transport the 

pulverized fuel to the burners. Stoker-fired boilers typically do not require preheated air unless 

the moisture content of the coal exceeds 25 percent (CIBO, 2003; Clever-Brooks, 2008).

There are two general types of air preheaters (APH): recuperators and regenerators. 

Recuperators are gas-to-gas heat exchangers usually placed on the boiler stack. Internal tubes or 

plates transfer heat from the outgoing exhaust gas to the incoming combustion air while keeping 

the two streams from mixing. Regenerators include two or more separate heat storage sections, 

each referred to as a regenerator. The hot flue gas heats the heating plates; in turn, this heat is 

transferred to the incoming combustion air.

Air preheaters are widely used in large boiler applications (as in the electric utility 

sector). In the ICI sector, APH are not as widely used as they were in the past due to more recent 
16

NOX regulations (the higher temperature of the combustion promotes NOX formation). Hence, 

many gas and liquid fuel boilers do not have APH. Economizers are favored in these cases, as 

they do not adversely impact the combustion air temperature and the resulting NOX formation. 

Economizers are basically tubular heat transfer surfaces used to preheat boiler feedwater 

before it enters the steam drum or furnace surfaces. Economizers also reduce the potential of 

thermal shock and strong water temperature fluctuations as the feedwater enters the drum or 

waterwalls.

Similar to all gas/air handling equipment, economizers and APH will impose some 

pressure loss on the system. Therefore, when considering the potential for an economizer or 

APH retrofit application, an analysis of the existing fan capacities is required. Also, reducing 

flue gas temperatures close to or below acid dew point incurs condensation/corrosion concerns 

that must be addressed on a case-by-case basis.

The general benefits of lowering flue gas temperature through combustion air preheating 

include: energy improvement from recovering the wasted flue gas heat; faster boiler startups; 

and in the case of solid fuels, the evaporation of moisture prior to combustion. Typical gains are

approximately 1 percent efficiency gain per 40 °F decrease associated with flue gas temperature.

Retrofitting an APH to a natural gas-fired 10 MMBtu/hr boiler, operating at an annual 

capacity factor of 68percent and with a flue gas temperature of 600 °F, to reduce the temperature 

by 300 °F results in an efficiency improvement from about 76 percent to 82 percent. With a 

price of $10/MMBtu, the annual fuel cost is $600,000. The savings associated with this potential 

improvement would be as follows:

• Fuel Savings = (1 – 76/82.2) = 7.5 percent = 4,500 MMBtu

• Annual Savings (at $10/MMBtu) = 4,500 × $10/MMBtu = $45,000

• Based on an estimated cost for an APH system of $200,000 to $250,000, a payback of less 

than 5 years would result (CIBO, 2003)

• The economizer recovers heat from the boiler exhaust gas and is used to pre-heat the boiler 

feed water. Capturing this normally lost heat reduces the overall fuel requirements for the 

boiler. This is possible because the boiler feed-water or return water is pre-heated by the 

economizer; therefore, the boiler’s main heating circuit does not need to provide as much 

heat to produce a given output quantity of steam or hot water. Manufacturers specify the 

total thermal efficiency of the economizer system to be 5 percent (U.S. EPA 2008). For a 

large boiler (650 MMBtu/hr or about 500,000 lb steam/hr), an estimated cost for an 

economizer was $2.3 million.

Implementing this measure may be relatively technically straightforward. Site-specific 

conditions and economic considerations must be addressed. Availability of space can be a 

barrier to the retrofit of an air preheater or an economizer. Some ICI boilers may be installed in 
17

very congested areas and within existing buildings. The issue of retrofit downtime is a common 

barrier throughout this report for all measures requiring offline implementation. Also, for any 

boiler with a remaining operating life of less than 10-15 years, the economics may not be 

favorable, especially if downtime is considered (Ganapathy, 2003).

3. Turbulators for Firetube Boilers

In firetube boilers, the hot combustion gases travel across the boiler heat-exchange 

surfaces several times. Each time this occurs is commonly called a “pass” and boilers are 

typically categorized by the number of “passes.” For example, a two-pass boiler provides two 

opportunities for hot gases to transfer heat to the boiler water. Within the tubes, the combustion 

gas typically changes from a turbulent flow regime when it enters the tubes, to a laminar regime, 

with its boundary layer of cooler gas along the tube walls. This boundary layer has a well 

known, negative impact on heat transfer.

In simple terms, turbulators help to regain the heat transfer characteristics of a turbulent 

flow regime by creating “turbulence” within the tubes. Physically, turbulators are simple devices 

(baffles, blades, coiled wire) that are inserted in the gas tubes to “break-up” the laminar 

boundary layer, resulting in the increased convective heat transfer. The result is that the flue gas 

exits at a lower temperature, and boiler efficiency is improved. For firetube boilers, turbulators 

are a cheaper alternative to economizers and APHs (Ganapathy, 2003).

Current turbulator designs do not cause a significant increase in pressure drop or 

contribute to soot formation in natural gas-fired boilers. Turbulators can also help balance gas 

flow through the tubes, thereby minimizing thermal stratification within the tubes (EnerCon, 

2008).

As already stated, the use of turbulators is intended for firetube boilers. Firetube boilers 

are primarily gas- or oil-fired. Within this group, older boilers that were typically designed with 

a lesser number of passes than newer firetube boilers, are most suitable for the application of 

turbulators. This is because multi-pass boilers are inherently more efficient due to the 

significantly higher heat transfer surface area. Turbulators are usually installed on the last boiler 

pass.

Efficiency improvement from the application of turbulators derives from the increased 

heat transfer from the flue gas and resulting lower flue gas exit temperature. This efficiency 

improvement is approximately 1 percent per 40 °F of gas temperature reduction.

Turbulators are substitutes for more costly economizers or APH. They are simple, easy 

to install, and low cost. Installed cost is about $10 to $15 per boiler tube (EERE, 2006b). As an 

example, consider a 10 million Btu/hr firetube boiler, operating 100,000 MMBtu/yr, installing a 

total of 250 turbulators into its firetube boiler, resulting in a reduction in the stack gas 

temperature of 130 °F and increasing boiler efficiency from about 79 to 82 percent. 

• Fuel Savings = (1 – 79/82.3) = 4 percent or 4,000 MMBtu
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• Annual Savings (at $10/MMBtu) = 4,000 MMBtu × $10/MMBtu = $40,000

• Simple payback at $15/tube = $3,750/$40,000 ~ 0.1 years (less than 2 months)

Implementing this measure may be technically straightforward. For firetube boilers, 

especially older types, the application of turbulators is well understood and widely applicable. 

Compared to the previously discussed APH and economizer, turbulators may result in a shorter 

payback period for firetube boilers.

4. Boiler Insulation

Due to the large size of many ICI boilers, the surface area of the outer surface of the 

boiler is very high, and significant heat loss can occur through the boiler shell. Proper insulation 

is important to keep these losses to a minimum. The refractory material lining the boiler is the 

primary insulating material. 

When replacing refractory materials at existing plants, structural considerations must be 

taken into account to assure the boiler can support the weight of the new refractory material. 

New construction can account for the weight of the refractory material in the industrial boiler 

design. The quantity of heat lost in this manner is fairly constant at different boiler firing rates 

and, as a result, becomes an increasingly higher percentage of the total heat losses at the lower 

firing rates. The radiation loss at high firing rates varies from a fraction of one percent up to two 

percent, depending on the capacity of the boiler.

Insulation is any material that is employed to restrict the transfer of heat energy. It can 

generally be categorized as either mass or reflective type depending on whether it is aimed at 

reducing conductive or radiative heat transmission, respectively. Properly applied insulation can 

result in large savings in energy losses depending on type, thickness, and condition of the 

existing insulation. Bare surface temperature in boilers ranges from saturation temperature on 

exposed tube surfaces to air and gas temperatures on duct surfaces. Radiation losses tend to 

increase with decreasing load and can be as high as 7 percent for small units or larger units 

operating at reduced loads.

Implementing this measure may be technically straightforward. Procedures have been 

developed by the Thermal Insulation Manufacturers Association to determine the optimum 

insulation thickness for various applications based on:

• fuel costs;

• operating temperatures;

• insulation type;

• depreciation period of plant and insulation; and
19

• capital investment.

5. Minimization of Air Infiltration

Air infiltration is an undesirable, but unavoidable, concern in boiler systems and 

ductwork. This occurs as a result of the large temperature difference between the hot 

combustion gases and ambient air temperature, which creates a negative pressure in the furnace. 

This is often called “stack effect” or “thermal head.” This negative pressure also occurs in 

balanced draft systems where an induced draft fan is used.

The sources for air leaks can be multiple, ranging from small openings (such as warped 

doors which deteriorated and no longer provide adequate sealing) to actual cracks in boiler 

casings or ductwork requiring more significant repairs. Indicators of excessive air leakage 

include: high O2 levels measured at the outlet of the boiler, as well as fuel consumption and gas 

temperatures. Depending on the severity and source of the leaks, the solution can be as simple as 

routine maintenance (e.g., adjust door seals), or requiring more thorough fixes during planned 

outages (e.g., repair boiler casing cracks). Maintenance of boiler systems to keep air leakage 

under control is an applicable and universally applied approach. It requires a combination of 

good maintenance procedures, as well as operational monitoring that can identify air leakage 

conditions and sources. 

The resulting impact of air leakage is similar to operating the boiler with too much excess 

air; it is a source of energy loss due to the unnecessary air being heated and wasted. The amount 

of leakage is a function of many parameters, starting with the size of the openings, but also 

includes the gas temperature, pressure, and velocity. The opportunity for improvement is a 

function of the leakage reduction and associated reduction in excess air.

The efficiency impacts can be significant. For example, a 3 percent change in O2 in a 

gas-fired boiler represents a gain of almost 4 percentage points in efficiency improvement. 

Expected efficiency improvement from reducing air leakage problems in ICI boilers are in the 

range of 1 to 4 percent.

It is difficult to address the cost of reducing air leakage, as this can range from essentially 

routine maintenance procedures to more costly repairs. However, in general, the cost/benefit to 

minimizing air leakage should provide good value.

Implementing this measure may be technically straightforward. Site-specific operating 

needs and economic considerations must be addressed. Major repairs resulting in boiler 

downtime and/or capital costs can result.

6. Boiler Blowdown Heat Exchanger

Blowdown is required to maintain water quality. Depending on site-specific conditions 

and make-up water quality, blowdown rates may vary greatly. Unfortunately, the blowdown still 
20

contains energy, which could otherwise be used instead of being wasted. This waste heat can be 

recovered with a heat exchanger, a flash tank, or flash tank in combination with a heat 

exchanger. The resulting low-pressure steam is most typically used in deaerators. Cooling the 

blowdown has the additional advantage of reducing the temperature of the liquids released into 

the sewer system.

Blowdown can be either intermittent bottom blowdown or continuous blowdown. 

Intermittent bottom blowdown may be sufficient if the feedwater is exceptionally pure. 

Intermittent blowdown is performed manually and therefore may result in wide fluctuations in 

blowdown patterns. Use of continuous rather than intermittent blowdown saves treated boiler 

water and can result in significant energy savings.

The higher the blowdown rate and boiler pressures, the more attractive the option of 

recovering the blowdown becomes. Any boiler with continuous blowdown exceeding 5 percent 

of the steam rate is a good candidate for considering blowdown waste heat recovery. 

Manufacturers specified that a 1 percent thermal efficiency can be achieved by this method 

(U.S. EPA, 2008). In certain cases, significant energy savings can be accomplished by 

recovering heat from boiler blowdown. For example, an efficiency improvement of over 2 

percent can be achieved at a 10 percent blowdown rate on a 150 psig boiler.

Site-specific conditions and economic considerations must be addressed to determine 

whether this measure involving heat recovery is technically and economically viable; it is 

necessary to consider its viability on a case-by-case basis.

7. Condensate Return System

Hot condensate that is not returned to the boiler represents a corresponding loss of 

energy. Other benefits that will accrue from an efficient condensate return system are less makeup water, water related treatment costs, boiler blowdown, and disposal costs. Energy savings 

come about from the fact that most condensate is returned at relatively hot temperature (typically 

130 to 225 °F), compared to the cold makeup water (50 to 60 °F) that must be heated. A return 

condensate system must be a function of the specific boiler and water/condensate quality, but 

essentially involves a new distribution line configuration. 

Condensate line return is applicable to all boiler types that do not already include return 

of hot condensate. The larger the unit and the hotter the condensate return, the more benefit will 

accrue. This measure is commercially available and used in industry. The condensate quality or 

purity is an important consideration on a case-by-case basis and should be considered when 

determining the appropriate quantity of condensate return.

The energy savings is the energy contained in the condensate being returned. In practice, 

the total amount of steam returned must account for the “steam flash loss” - the amount of 

saturated condensate that flashes off to steam when reduced to a lower pressure. The energy 

efficiency improvement for a particular boiler is, therefore, the ratio of Btu/hr saved from the 

condensate return to the original Btu/hr heat input to the boiler. Overall cost savings accrue from 
21

the fuel savings due to the efficiency improvement, plus the value of the reduction in the cost of 

make-up water, sewage disposal, and water treatment chemicals.

Site-specific conditions and economic considerations must be addressed to determine 

whether it would be applicable, and, therefore, it is necessary to consider its viability on a caseby-case basis. A further improvement on recovering the available energy of the condensate may 

be to use a heat exchanger (vent condenser) where the flashing steam is typically vented. Sitespecific evaluation is necessary before determining the viability of this approach.

8. Refractory Material Selection

The refractory bricks lining the combustion zone of the boiler protect the outer shell from 

the high combustion temperatures, as well as chemical and mechanical stresses. Although the 

choice of refractory materials is highly dependent on fuels, raw materials, and operating 

conditions, consideration should be given to refractory materials that provide the highest 

insulating capacity and have the longest life. Although benefits may be difficult to quantify due 

to the unique conditions at each facility, some energy savings will be realized from higher 

quality refractory materials.

9. Minimization of Gas-Side Heat Transfer Surface Deposits 

Boiler heat transfer surfaces are exposed to high temperature gases and products of 

combustion, which vary in composition amongst different fuels and operating conditions. 

Formation of soot, ash products from solid and liquid fuels, and incomplete combustion of 

carbon all contribute to the potential for surface deposits. Oxides may also be formed on the 

surface of the tubes. These deposits are further related to operational issues ranging from 

malfunctioning burners, to the condition of the heat transfer surfaces, to gas flow patterns within 

the boiler combustion zone. 

To minimize deposition problems (slagging and fouling), it is important to operate the 

boiler within the parameters for which it was designed. This imposes a number of operational 

issues, such as fuel quality restrictions and firing rates, among others. However, systems firing 

ash-laden fuels also include “cleaning” systems (soot blowers that typically use compressed air 

or steam) to periodically remove the unavoidable deposition on the boiler walls and tubes. In 

addition, many units utilize “fuel treatment” to mitigate the deposition propensity of the ash and 

products of combustion. Many such products are available and typically modify the 

characteristics of the ash (e.g., the temperature–viscosity relationship) to minimize deposition. 

More advanced soot blowing systems, or Intelligent Sootblowing Systems (ISS), use 

feedback signals, such as exit gas temperature or heat transfer sensors, to trigger their operation. 

ISS determines which soot blower needs to be operated and when, depending on the local 

performance of the heating surfaces, resulting in optimization of operations and effectiveness. In 

more extreme cases and when more severe changes in fuel quality occur, it is possible that the 

existing soot blower system may not be sufficiently adequate to remove the deposits and changes 

to the ISS may be required. 
22

Keeping heat transfer surfaces clean is essential for efficient boiler operation. As would 

be expected, solid fuels are the most common application for soot blowing systems. Although 

oil and gas units occasionally have to address deposition of soot/slag, they typically do not 

employ these systems. The choice of an appropriate soot blowing system is boiler and fuel 

dependent, as discussed above. Soot blowing systems are widely used in industry. 

Advances in soot-blowing system controls have become more widespread, especially in 

large coal-fired boilers due to the direct relationship between NOX formation and combustion 

temperature. In this case, optimizing the soot blower operation minimizes gas temperatures and 

yields not only efficiency benefits but also NOX emission reductions.

The relationship between deposits and heat transfer deterioration varies with the type of 

fuel and ash characteristics. For example, similar thickness layers of ash deposits will have 

different impacts on heat transfer based on the refractory characteristics of the individual ashes.

The extent to which dirty heat transfer surfaces affect efficiency can be estimated from an 

increase in stack temperature relative to a “clean operation” or baseline condition. Efficiency is 

reduced by approximately 1 percent for every 40 °F increase in stack temperature. Changes in 

exit gas temperatures of over 120 °F due to boiler slagging and fouling would correspond to 

about a 3 percent decrease in efficiency. Efficiency gains of 1 to 3 percent may be gained within 

the ICI boiler population by minimizing boiler surface deposition. Excessive slagging also may 

affect the outlet steam conditions of the boiler, resulting in reduced steam temperature or the 

requirement for attemperation sprays.

The cost of reducing boiler deposition can range from essentially routine maintenance 

procedures to soot-blower system retrofits. However, in general, the cost/benefit to minimizing 

deposition should provide good value. Soot blower costs vary by type (i.e., wall blowers, water 

cannon, retractable lances). Typical costs are in the range of $50K to $125K for a single soot 

blower, with wall blowers being typically the least expensive and retractable lances the most 

costly. Installation costs will typically double these numbers.

Implementing this measure may be relatively straightforward where boiler deposition 

mitigation work practices already exist or can be readily incorporated as part of boiler 

maintenance. Therefore, training and enhanced operating procedures may be needed. Retrofit of 

more advanced or robust soot blowers will require down time and capital cost. Site-specific 

operating needs and economic consideration must be addressed.

10. Steam Line Maintenance

Heat loss through uninsulated lines and fittings can be significant. For example, 250 ft 

of uninsulated, 4-inch line with 300 psig steam would yield 2800 MMBtu/yr, the equivalent of 

about 0.3 to 1.2 percent heat loss for boiler sizes between 25 and 100 MMBtu/hr. Similarly, the 

penalties for leaky valves/traps can represent measurable losses. General experience suggests 

that steam systems that do not include steam trap maintenance, over a period of 3 to 5 years can 

result in 15 to 30 percent steam trap failures. In plants that have a regular steam trap inspection 
23

and maintenance program, leaking traps should account for less than 5 percent of trap 

population.

Energy audits and maintenance procedures should highlight common maintenance items 

such as uninsulated steam distribution and condensate return lines and other fittings. Ensuring 

that all steam/condensate lines are properly insulated will yield measurable efficiency gains. 

Common practice suggests that surfaces over 120 °F (steam and condensate return piping, 

fittings) should be insulated. Insulating jackets are available for valves, traps, flanges and other 

fittings. Leaky steam traps should be fixed as they represent another potentially significant 

source of wasted energy.

Implementing this measure may be technically straightforward. These insulation and 

leaks mitigation measures are universally applied and require only a dedicated awareness of line 

conditions (routine surveys). 

VII. Energy Programs and Management Systems

Industrial energy efficiency can be greatly enhanced by effective management of the 

energy use of operations and processes. Management of operations can be guided by the U.S. 

EPA’s ENERGY STAR Program or ANSI or ISO standards. 

U.S. EPA’s ENERGY STAR Program works with hundreds of U.S. manufacturers and 

has demonstrated that companies with stronger energy management programs gain greater 

improvements in energy efficiency than those without practices focused on continuous 

improvement of energy performance. 

Energy Management Systems (EnMS) provides a framework for managing energy and 

promote continuous improvement. The EnMS provides the structure for an energy program and 

its energy team. EnMS establish assessment, planning, and evaluation procedures which are 

critical for actually realizing and sustaining the potential energy efficiency gains of new 

technologies or operational changes.

Energy management systems promote continuous improvement of energy efficiency 

through:

• Organizational practices and policies, 

• Team development,

• Planning and evaluation,

• Tracking and measurement,

• Communication and employee engagement, and
24

• Evaluation and corrective measures.

For nearly 10 years, the U.S. EPA’s ENERGY STAR Program has promoted an energy 

management system approach. This approach, outlined in the graphic below, outlines the basic 

steps followed by most energy management systems approaches.

ENERGY STAR Guidelines for Energy Management

(www.energystar.gov/guidelines)

In recent years, interest in energy management system approaches has been growing. 

There are many reasons for the greater interest. These include recognition that a lack of 

management commitment is an important barrier to increasing energy efficiency. Further, lack 

of an effective energy team and program results in low implementation rates for new 

technologies or recommendations from energy assessments. Poor energy management practices 

that fail to monitor performance do not ensure that new technologies and operating procedures 

will achieve their potential to improve efficiency.

EPA’s ENERGY STAR Guidelines for Energy Management are available for public use 

on the web and provide extensive guidance (see: www.energystar.gov/guidelines). Alternatively, 

energy management standards are available for purchase from ANSI, ANSI MSE 2001:200 and 

in the future from ISO, ISO 50001.

Energy management systems can help organizations achieve greater savings through a 

focus on continuous improvement. Companies will need to combine effective plant energy 

benchmarking and appropriate plant improvements to achieve energy savings.
25

There are a variety of factors to weigh when considering certification to an Energy 

Management Standard established by a standards body such as ANSI or ISO. First, energy 

management system standards are designed to be flexible. A user of the standard is able to 

define the scope and boundaries of the energy management system so that single production 

lines, single processes, a plant or a corporation could be certified. Achieving certification for the 

first time is not based on efficiency or savings (although re-certifications at a later time could 

be). Finally, cost is an important factor to weigh when using the standards. Internal personnel 

time commitments, external auditor and registry costs should be considered. 

Overall, a systems approach to energy management is an effective strategy for 

encouraging energy efficiency in a facility or corporation. There are multiple pathways available 

with a wide range of associated costs. The effectiveness of an energy management system is 

linked directly to the system’s scope, goals, measurement and tracking. 

1. Sector-Specific Plant Energy Performance Benchmarks

Plant energy benchmarking is the process of comparing the energy performance of one 

site against itself over time or against the range of performance of the industry. Plant energy 

benchmarking is typically done at a whole-facility or site level in order to capture the synergies 

of different technologies, operating practices, and operating conditions. 

Benchmarking enables companies to set informed and competitive goals for plant energy 

improvement. Benchmarking also helps companies prioritize where to make investment to 

improve performance of poor performers while learning from the approaches used by top 

performers. 

When benchmarking is conducted across an industrial sector, a benchmark can be 

established that defines best in class energy performance. The U.S. EPA’s ENERGY STAR 

Program has developed benchmarking tools that establish best-in-class for specific industrial 

sectors. These tools, known as Plant Energy Performance Indicators (EPI) are established for 

specific industrial sectors and are available for free at 

www.energystar.gov/industrybenchmarkingtools. Using several basic plant-specific inputs, the 

EPIs calculate a plant’s energy performance providing a score from 0-100. EPA defines the 

average plant within the industry nationally at the score of 50; energy-efficient plants score 75 or 

better. ENERGY STAR offers recognition for sites that score in the top quartile of energy 

efficiency for their sector using the EPI.
26

2. Industry Energy Efficiency Initiatives

The U.S. EPA’s ENERGY STAR Program (www.energystar.gov/industry) and U.S. 

Department of Energy’s Industrial Technology Program (www.energy.gov/energyefficiency) 

have led industry specific energy efficiency initiatives over the years. These programs have 

helped to create guidebooks of energy efficient technologies, profiles of industry energy use, and 

studies of future technologies. Some States have also lead sector specific energy efficiency 

initiatives. Resources from these programs can help identify technologies that may reduce CO2

emissions.

VIII. Carbon Capture and Storage

Carbon capture and storage (CCS) involves separation and capture of CO2 from the flue 

gas, pressurization of the captured CO2, transportation of the CO2 via pipeline, and finally 

injection and long-term geologic storage of the captured CO2. Several different technologies, at 

varying stages of development, have the potential to separate and capture CO2. Some have been 

demonstrated at the slip-stream or pilot-scale, while many others are still at the bench-top or 

laboratory stage of development.

In 2010, an Interagency Task Force on Carbon Capture and Storage was established to 

develop a comprehensive and coordinated Federal strategy to speed the commercial development 

and deployment of clean coal technologies. The Task Force was specifically charged with 

proposing a plan to overcome the barriers to the widespread, cost-effective deployment of CCS 

within 10 years, with a goal of bringing 5 to 10 commercial demonstration projects online by 

2016. As part of its work, the Task Force prepared a report that summarizes the state of CCS 

and identified technical and non-technical barriers to implementation. The development status of 

CCS technologies is thoroughly discussed in the Task Force report. For additional information 

on the Task Force and its findings on CCS as a CO2 control technology, go to: 

http://www.epa.gov/climatechange/policy/ccs_task_force.html. 

IX. Other Measures to Reduce GHG Emissions

1. Alternative Fuels – Biomass

The potential on-site reduction in CO2 emissions that may be realized by switching from 

a traditional fossil fuel to a biomass fuel is based on the specific emission factor for the fuel as 

related to its caloric value. Pure biomass fuels include animal meal, waste wood products and 

sawdust, and sewage sludge. It may also be possible to use biomass materials that are 

specifically cultivated for fuel use, such as wood, grasses, green algae, and other quick growing 

species. 

There are a number of issues related to the use of biomass fuels:

• Caloric Value - Most organic materials have a caloric content less than traditional fossil 

fuels.
27

• Trace compounds - The biomass fuel, particularly waste products, may contain trace 

elements such as heavy metals or may contain compounds that are detrimental such as 

chlorine. These substances could result in other air emission issues.

• Waste regulations - The regulation of wastes that may be used for fuel, or the types of units 

that the material may be utilized in, affects the use of those wastes as fuel. For example, if 

there are no impediments to landfilling the waste, then there may be little of the waste 

available for fuel use.

• Social acceptance - The use of waste fuels in a given area may be driven by social acceptance 

of burning the fuel in the community.

• Agricultural areas - For crops grown for biomass purposes, sufficient agricultural areas in 

proximity to the industrial boiler are required.

2. Co-firing

“Co-firing” refers to the case of burning more than one fuel in one boiler. As such, gas 

(“gas co-firing”) could be burned in a boiler designed for oil or coal. Also, biomass (in solid 

form) could be co-fired in a boiler designed for coal. Finally, liquid or gas biofuels may be cofired in all types of boilers.

Biomass may include switchgrass, sawdust, wood wastes, municipal solid wastes, nonrecyclable paper, pulp mill sludge, chicken manure and other waste fuels. Typically, biomass 

has been limited to a maximum of 20 percent of the total plant input, and in most cases, between 

3 and 12 percent. However, the pulp and paper industry has decades of experience co-firing up 

to 50 percent biomass with coal (DOE, 2004). Boilers could be designed specifically to 

accommodate biomass combustion or existing boilers could be modified; the industry has 

experience with both. 

Gas co-firing involves modification of the combustion system to accommodate the 

introduction of natural gas or biomass-derived gas. The co-fired fuel is injected directly into the 

combustion zone.

In case of biomass co-firing in boilers burning coal, the techniques can be classified 

either as direct or indirect. Direct firing involves mixing of the biomass before the pulverizers 

(“co-milling” or blending) or direct injection (separate feed system for the biomass fuel). 

Indirect firing consists of separate boilers for the primary fuel and for biomass linked by a 

common connection to the steam cycle (may share the same steam generator and steam turbine).

From the five model plants identified for industrial applications, the models burning solid 

fuels (PC, circulating fluidized bed, and stoker) are clearly suitable to co-fire natural gas, 

biofuels, and (solid) biomass. The watertube and firetube boilers burning oil can accommodate 

biofuels and natural gas.
28

Co-firing of natural gas or biofuels does not present any technical issues which cannot be 

addressed through appropriate design. In most cases, the issues associated with these fuels relate 

to economic attractiveness, availability of biofuels, and availability of natural gas at the plant 

site.

In the case of biomass co-firing, retrofits face a number of issues, mainly related to the 

key characteristics of biomass compared to coal:

• Biomass has lower density; hence it is bulkier and affects the fuel handling equipment 

(pulverizers, fuel transport and fuel feed systems).

• High moisture content, above 40 percent, increases the time required for complete 

combustion and affect boiler efficiency.

• Biomass is more volatile than coal; biomass contains up to 80 percent volatile matter (on a 

dry-weight basis) compared to a maximum of 45 percent for coal; hence it is easier to selfignite.

• High alkali biomass may contribute to formation of alkali sulfates, which make it easier to 

clean the boiler heating surface through sootblowing.

• Biomass degrades over time, which means that it cannot be stored for long periods of time.

• Biomass may contain high concentration of chloride, causing corrosion, especially if sulfur is 

also present in the fuel (either in the biomass or the coal).

However, all these issues can be addressed through appropriate design and operation. The same 

issues are being faced by new plants, but in this case, it is easier to adjust the initial design to 

accommodate co-firing.

The impact on efficiency of co-firing gas in existing boilers is expected to be minor (less 

than 0.5 percentage point). Depending on the composition of the co-fired fuel vs. the fuel it is 

replacing; fuel with high concentrations of H2 and moisture would have an adverse impact on 

plant efficiency. The impact of biomass co-firing in coal-fired boilers could result in a reduction 

of up to 2 percentage points in boiler efficiency and up to 1 percentage point in plant efficiency.

With regards to CO2 emission reductions: 

• Gas co-firing has a beneficial impact in the case where it replaces coal; this is mainly because 

the carbon content of the coal is higher than gas; a 20-30 percent reduction in CO2 is typical.

• Estimating the impact of biofuels on CO2 emission requires a process-specific assessment.

Other impacts due to biomass co-firing:

• Usually there are no impacts on plant output and reliability, assuming the right precautions 

are taken in designing and operating the facility.
29

• SO2 and mercury are reduced proportionally to the biomass or gas input because these fuels 

contain less sulfur or mercury.

• NOX emission reduction is usually greater than the percentage of biomass or gas heat input. 

If the co-firing system is designed to be also a “reburning” system (introduction of fuel above 

the primary combustion zone), NOX reduction of up to 30 percent could be achieved. 

There is significant industry experience in co-firing in all types of boilers (PC, FBC, 

cyclone and stokers) ranging from 1 to 700 megawatt (MW). The pulp and paper industry has 

been co-firing for decades. In the 1990s, many power plants demonstrated this option in Europe, 

Japan, and the United States, and then proceeded to use it commercially. 

The most common issues and barriers associated with co-firing are:

• Availability of natural gas on site; if it is not available, it may be too costly to extend a gas 

pipeline to reach the site. However, this is expected to affect a very small number of 

facilities, as the natural gas distribution in the US is well-developed and reaches most 

locations.

• Price of the co-fired fuel; natural gas is highly affected by oil and gas market conditions. 

Biofuels depends on the production process, the price of the biomass feedstock and potential 

regulatory incentives (tax breaks, etc.). Finally, biomass is site-specific, may vary 

significantly, and may increase in cost after the co-firing project is implemented.

• Availability and logistics for biomass collection and transportation.

3. Fuel Switching

Fuel switching refers to a change in the plant hardware to accommodate complete (100

percent) replacement of one fuel with another fuel. Fuel switching from a coal-, fuel oil-, or 

diesel-fired boiler to a natural gas-fired boiler can result in decreased emissions (U.S. EPA 

2008). Considering that the focus of this report is to identify CO2 reducing options, the 

following fuel switching options are of interest:

• Coal could be switched to oil, natural gas or coal-derived gas; and

• Oil could be switched to natural gas or coal-derived gas.

Fuel Switching in Coal-fired Systems

Switching from coal to another fuel is feasible and has been put into practice in several 

cases. Economics and other issues are most often the reason such switching is not taking place. 

Switching from coal to oil is feasible and has occurred in the US, especially in the 1960s when 

oil was inexpensive. If such a change would be desirable, the required hardware changes 

include:
30

• Construction of oil storage; if there is existing oil storage, it may not be adequate and a larger 

storage capacity would need to be provided.

• Replacement or modification of the burners.

• If the same output of electricity or steam is required, additional hardware modifications may 

be required. While such changes are site-specific, coal-fired boilers are usually larger than 

oil-fired; the cross sectional area of a coal-fired boiler is about 20 percent larger and the 

boiler is about 33 percent taller than an oil-fired boiler (Llinares and Smith, 1980). As a 

result, burning oil in a larger furnace most likely would not produce the same amount of 

steam, or steam with the same temperatures. If the output conditions need to be maintained, 

more extensive boiler modifications would be required.

Switching from coal to natural gas presents similar issues as a switch to oil. The cross 

sectional area of a coal-fired boiler is about 50 percent larger and the boiler is about 60 percent 

taller than a gas-fired boiler (Richards, 1978). The only differences between switching to natural 

gas and to oil are:

1. The extent of the boiler modifications, which is design-specific.

2. There is no need for natural gas storage, as gas is usually provided directly from a gas 

pipeline. However, there are plants which may not have access to natural gas and may need 

to invest in bringing a gas pipeline into the plant.

Switching from coal to coal-derived fuels is also practical, but its viability requires very 

site-specific assessment. First, the potential for CO2 reduction depends on the coal-derived gas 

production process and needs to consider all the emissions released throughout the fuel chain 

(including coal mining, coal transport, conversion from coal to gas-derived fuel and utilization in 

the industrial boiler). In terms of an existing industrial boiler accommodating the coal-derived 

gas, the considerations are similar as those required for a switch to natural gas.

Switching from coal to biofuels (of either gas or liquid form) would involve similar 

considerations as the switch from coal to oil and natural gas.

Switching from coal to biomass requires:

• Replacement of the fuel storage, handling and feed system; some equipment from the coal 

system may also be usable for biomass. Space is not likely to be a constraint, because the 

space available for storage and handling of the coal is likely to be adequate for biomass.

• Depending on the boiler design, some modifications may be required to maintain plant output 

conditions. Biomass firing typically occurs in either stoker or fluidized bed boilers. This 

requires a site-specific assessment.

Fuel Switching in Oil-fired Systems
31

Switching from oil to natural gas would involve:

• Making sure that a natural gas supply is available; if a gas pipeline is not available at the 

plant site, a pipeline extension may be required.

• Replacement or modification of the burners.

• Some modifications of the boiler are likely to be required to maintain the same output of 

electricity or steam. However, the boiler modifications are generally not expected to be as 

extensive as in the case of coal to gas switching.

Switching from oil to coal-derived gas or biofuels (in gaseous form) is similar to natural 

gas. The only difference is that CO2 emissions would need to consider all CO2 emissions 

released throughout the fuel chain (including coal mining, coal transport, conversion from coal to 

gas-derived fuel, and utilization in the industrial boiler). 

Switching from oil to liquid biofuels is the easiest option in terms of required 

modifications to the plant hardware and potential impacts on plant performance. However, the 

CO2 emissions would need to consider all fuel-chain impacts. 

Switching from oil to biomass entails similar modifications as in the case of a coal to 

biomass switch. Some differences are noteworthy:

• In some sites, space to accommodate the biomass may be an issue; oil-firing facilities only 

require an oil storage tank, while biomass would require significant storage area, as well as 

space for drying and crushing prior to being fed into the boiler.

• Oil-fired boilers are compact relative to biomass-firing boilers; hence, it is likely that the 

boiler would not be able to maintain the plant output even after significant modifications.

For the purposes of this report, it is assumed that oil to biomass switch is not attractive.

Switching of PC plants to any of the fuels mentioned above is feasible and the industry 

has relevant experience (switching from coal to oil occurred in the 1960s, and from coal to gas in 

the 1980s and 1990s). Switching to coal-derived gas or biofuels has similarities with switching 

to natural gas and oil, respectively. Also, there is adequate experience in boiler modifications to 

accommodate biomass. 

Switching of FBC to oil, gas, coal-derived gas, or biofuels is not feasible, as the 

circulating fluidized bed requires solid materials to ‘build up the bed.” FBC are suitable 

candidates to switch to biomass.

It is theoretically and practically viable to switch stoker boilers to burn oil, gas, coalderived gas, or biofuels. However, the overall design of stokers results in significantly lower 

efficiency than other prime movers (e.g., gas turbines and diesel engines), which can burn these 

fuels more efficiently. Stokers can easily accommodate biomass fuels.
32

Watertube and firetube boilers that use oil and natural gas, are suitable only for clean 

liquid or gaseous fuels. As a result, an oil-fired boiler could be switched to gas or coal-derived 

gas or biofuel. In addition to the burners which would need to be replaced, some additional 

modifications may be needed depending on the design of the existing boiler and the properties of 

the fuels. Gas-fired boilers would have less of an incentive to switch to coal-derived gas or 

biofuels, unless the price differential is adequate to justify the investment in the design 

modifications.

Efficiency change due to fuel switching is the result of the composition of the fuel and 

the design of the plant (as it exists, plus potential modifications which can be made). 

Considering that each fuel has different carbon content, this results in different amount of CO2

emissions, as illustrated by the following typical emission factors (EIA, 2008).

• Natural Gas (pipeline quality): 117.080

lbs/MMBtu

• Distillate oil (No. 1, 2 and 4, as well as diesel): 161.386

• Residual Oil (No. 5 and 6): 173.906

• Bituminous coal: 205.300

• Subbituminous coal: 212.700

• Lignite: 215.400

Hence, switching from coal to oil would result in a 20 to 35 percent CO2 reduction 

(depending on the composition of the coal and the oil), and a 40 to 50 percent reduction in the 

case of switching from coal to natural gas.

Plant efficiency improvements depend greatly on the existing plant design and design

modifications implemented as part of the fuel switching project. However, the efficiency 

changes due to design modifications are expected to be much smaller than the impact of the fuel 

composition.

In addition to CO2 emission impacts, switching to another fuel may have an impact on the 

other pollutants (particulates, SO2, NOX, and mercury). Switching from coal or oil to other fuels 

reduces particulates and, in most cases (natural gas, biofuels and biomass), SO2 emissions; the 

exact percentage SO2 reduction depends on the sulfur content of the coal or oil. NOX emissions 

depend on the design of the boiler, but some NOX reduction is expected as a result of fuel 

switching.

Barriers to fuel switching include:

• Cleaner fuels are usually more expensive. Potential incentives include: tax breaks for 

investments; fuel subsidies; allowances for reduction of emissions (presently applicable to 

SO2 and NOX); and in the future, carbon credits.
33

• The design modifications require shut-down of the plant for a few weeks or months; such 

interruption is difficult for industrial facilities which are used to operating without 

interruption, and very often, 24 hours per day.

• Site-specific barriers such as a lack of space or feedstock (for biomass systems) and lack of 

natural gas on site (in those cases where a switch to gas is desirable.

4. Combined Heat and Power

CHP, or cogeneration as it is commonly called in the US, involves production of useful 

heat and electricity from a single facility. There are significant efficiency gains to be derived

from employing CHP. Thermal electric generation processes lose 50-70 percent of the input fuel 

energy in the form of waste heat. Recovering this energy for steam or hot water production onsite or at a nearby facility increases the overall efficiency of the process from 30-50 percent to 

70-80 percent. This reduction in fuel requirements translates directly to reduced GHG 

emissions. In addition, there is often an additional GHG savings that results if fuel switching

from coal to natural gas or biomass is included. 

CHP is very widely used in the industrial sector already. There are nearly 1,800 active 

manufacturing, mining, construction, and agricultural CHP installations in the U.S. These 

facilities provide over 45 percent of the total annual industrial steam requirements. In 

commercial and institutional applications there are over 2,000 active CHP systems, which

provide about 10 percent of the total boiler load used for space heating, water heating, and 

steam-driven chillers. Although many of the ICI applications with the largest thermal loads 

already have CHP systems, there is still room for additional conversions.

The most attractive ICI boiler candidates for CHP conversion are those that operate with 

a high annual operating factor, meeting a steady thermal load. Such systems maximize the 

potential efficiency benefits of CHP and provide a higher return on the required capital 

investment. For industrial applications, process industries with 2 and 3 shift operation represent 

a good target. In the commercial and institutional sector, facilities that have continuous thermal 

demand such as hospitals, college campuses, hotels, military bases, and prisons represent the best 

targets. Lower load factor applications with high thermal utilization will also show efficiency 

and GHG benefits, but the economic return on the investment needed to convert to CHP will be 

lower. In some cases, particularly in process industries, a CHP facility sized to the thermal load 

will produce more power than can be utilized on-site. This excess power can often be sold into 

the wholesale power market.

For a site with the appropriate thermal loads, there are a number of technical alternatives 

for converting to CHP: 

• In rare cases, CHP could be added to an existing ICI boiler by increasing the steam pressure, 

adding a super-heater, and utilizing a back pressure steam turbine to generate power from the 

high pressure steam and then delivering lower pressure steam to the process. Most ICI 

boilers are not designed to be operated at higher pressures than those at which they are 

currently being operated, so this option will, in most cases, not be available. 
34

• A steam turbine CHP system generally requires a complete boiler replacement to provide the 

necessary steam conditions for power generation through a back-pressure or extraction steam 

turbine generator. The electric to thermal (E/T) output ratio for this type of CHP system 

ranges from 0.05 to 0.15, that is, 5 to 15 percent of the energy output from this type of 

system is in the form of electricity and the remaining 85-95 percent is steam. This type of 

system is commonly used when there is a solid fuel source such as coal, biomass, or waste.

• For more power generation, a combustion turbine with heat recovery steam generator 

(HRSG) can be used for the CHP system with the existing boiler providing back-up steam 

when the CHP system is not operating. This type of system has an E/T ratio of 0.45-1.05 

with the higher E/T ratios coming from larger turbines with higher electric generating 

efficiencies. Additional steam can be generated from this type of system through the use of 

duct burners in the HRSG. This additional steam is generated very efficiently (87-90 percent

higher heating value) because the turbine exhaust which provides the combustion air is 

effectively preheated to a fairly high level. This type of system is typically used where 

electric and thermal demands are high (greater than 3 MW of electricity and 10-20 

MMBtu/hr of steam) and either natural gas or distillate oil is already used for the existing 

boiler or fuel switching to a gas CHP system makes economic sense.

• Systems using large gas turbines can increase the E/T ratio by increasing the pressure of the 

steam produced by the HRSG and adding a back-pressure steam turbine for additional power 

production. These combined cycle systems typically produce over 100 MW of electric 

power with an E/T ratio of around 1.0 to 2.0 or more. This configuration is often used for 

large electric generators that are sited to produce power for sale to the grid with steam sales 

to a nearby industrial plant.

• Smaller ICI boilers, less than 1-2 MMBtu/hr, can be replaced by a variety of gas-fired CHP 

systems with heat recovery producing hot water or low pressure steam for the thermal loads. 

Reciprocating engines, microturbines, and fuel cells are all used for this purpose. These 

systems are particularly well suited for the sizes and loads of commercial and institutional 

buildings. 

In addition, to the physical matching of a CHP system to the facility electric and thermal 

loads, CHP systems require a fairly substantial investment ($1,000-2,500/kW). This investment 

will have an economic return where ratio of electric to gas prices, also called the spark spread, is 

around 3 or higher. Larger industrial systems can be economic at somewhat lower spark spreads; 

very small systems often need a somewhat higher spark spread.

Another important factor that affects the technology selection is the ratio of heat to 

electricity demand at the site. The most efficient sizing approach for CHP is to size the system 

to meet the base thermal load. This can, at times, mean the CHP system will produce more 

power than can be used on-site. However, with deregulation of the electricity market in the US,

it is often possible for industrial facilities to sell the excess electricity to the grid; this provides 

more flexibility in the design of CHP facilities, even though economics would dictate the final 

design configuration.
35

The economic and technical factors that would make CHP conversion of ICI boilers 

attractive can be summarized as follows:

• High annual operating hours

• Thermal demand with high annual load factor

• Coincident high load factor electric demand on-site or an economic electricity export market 

that the CHP system can access

• Spark spread (ratio of electric to fuel prices) of around 3 or higher

• Power quality and reliability issues at the site that the CHP system can help to address

• Economies of scale – the larger the electric and thermal requirements, the more economic 

CHP will be for any given spark spread, though small systems have also been installed 

effectively in high electric cost markets.

As previously described, CHP systems have already achieved significant market 

penetration in industrial applications and somewhat more modest success in commercial and 

institutional markets. There are about 4,000 operating CHP facilities providing over 84 

GigaWatts of electric capacity and 1.7 quads of thermal energy (ICF 2010) .

GHG emissions reductions due to CHP conversion depend on the before and after energy 

configuration, but the benefits can be quite substantial. 

An industrial, commercial, or institutional facility with an E/T ratio of 0.7, separately 

purchasing electricity generated at 33 percent efficiency and producing steam in an ICI boiler at 

80 percent efficiency results in a combined efficiency of 50 percent. A gas turbine CHP system 

with an electrical generating efficiency of 30 percent and an E/T ratio of 0.7 can meet the same 

electric and thermal loads with an overall efficiency of 72 percent. This improvement represents 

a 30 percent reduction in overall fuel use. The level of overall CO2 reductions is a function of the 

CO2 intensity of the displaced central station power production and the fuels used at the site.

If the conversion also includes fuel switching (e.g., from coal or oil to natural gas), 

additional CO2 emission reduction could be achieved. A CHP Emission Calculator developed by 

the US DOE and EPA could be useful in estimating emissions from CHP plants (EEA, 2004)

Disadvantages of CHP conversation of ICI boilers include:

• The most important barrier is the required investment, which is usually substantial. The 

thermal and electric benefits, where feasible, however, show the long-term gains in installing 

CHP weigh favorably against other control options.
36

• If there is excess electricity from the CHP facility, while regulatory changes have made it 

easier to sell it to the electric utilities or industrial customers, the selling requires time to 

negotiate contracts and is often perceived as a nuisance by many industrial companies. For 

example, connecting a CHP to the electrical grid involves compliance with national codes 

and consensus standards issued by the National Fire Protection Association and include the 

National Electric Code, the Occupational Safety and Health Administration, and local and 

state regulatory authorities. Also, electric utilities have their own interconnection and safety 

requirements, which can add to the complexity of the project.

• If a facility chooses to sell excess electricity, utilities often require written agreements 

concerning rates, metering, insurance and liability, standby power, operating schedules, and 

other operational issues. 

• The design modifications require shut-down of the plant for a few weeks or months; such 

interruption is very difficult for industrial facilities to accommodate.

• Reliability may also be a barrier in accepting new technologies (e.g., fuel cells) which are 

more efficient, but may be perceived to be less reliable than the conventional proven 

technologies.

• Site permitting for CHP systems will be required to be taken into consideration. As with 

other combustion devices, construction and operating permits would need to be obtained to 

comply with applicable environmental regulations including the non-attainment New Source 

Review program requirements or the PSD permitting process, depending on the air quality 

where the facility is located. Because current air quality regulations do not recognize the 

overall energy efficiency of CHP or credit the emissions avoided from displaced grid 

electricity generation, project planning is generally required to include designs for emission 

control systems that achieve Lowest Achievable Emission Rate compliance or represent 

BACT. However, where output-based standards are available, they can be employed to show 

CHP’s dual thermal and electrical outputs. In addition, emissions testing and monitoring 

equipment for verifying compliance are required to be included as part of the design. The 

cost of emission control equipment, as well as the cost of applying for construction and 

operating permits, can be significant. This is especially so for smaller CHP systems where 

the incremental cost is often disproportionately high.

• Lack of space (e.g., for new equipment and fuel storage) and/or lack of natural gas on site (in 

those cases where gas is not already available on site) may be a site-specific barrier.
37

EPA Contacts

Jim Eddinger

U.S. EPA

OAQPS/SPPD/ESG

Mail Code D243-01

Research Triangle Park, NC 27711

Phone: 919-541-5426

Fax: 919-541-5450

eddinger.jim@epa.gov

Christian Fellner

U.S. EPA

OAQPS/SPPD/ESG

Mail Code D243-01

Research Triangle Park, NC 27711

Phone: 919-541-4003

Fax: 919-541-5450

fellner.christian@epa.gov
38

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