E CHP

£EPA combined heat and

POWER PARTNERSHIP

Catalog of
CHP Technologies

U.S. Environmental Protection Agency
Combined Heat and Power Partnership

^CHP

&EPA COMBINED HEAT AND
POWER PARTNERSHIP

September 2017


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Disclaimer

The information contained in this document is for information purposes only and is gathered
from published industry sources. Information about costs, maintenance, operations, or any other
performance criteria is by no means representative of EPA, ORNL, or ICF policies, definitions,
or determinations for regulatory or compliance purposes.

The September 2017 revision incorporated a new section on packaged CHP systems
(Section 7).

This Guide was prepared by Ken Darrow, Rick Tidball, James Wang and Anne Hampson at ICF
International, with funding from the U.S. Environmental Protection Agency and the U.S. Department of
Energy.

Catalog of CHP Technologies

ii

Disclaimer


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Table of Contents

Section 1. Introduction	1-1

1.1	Overview of CHP Technologies	1-2

1.2	CHP Efficiency Compared to Separate Heat and Power	1-8

1.3	Emissions	1-10

1.4	Comparison of Water Usage for CHP compared to SHP	1-12

1.5	Outlook	1-13

Section 2. Technology Characterization - Reciprocating Internal Combustion Engines.... 2-1

2.1	Introduction	2-1

2.2	Applications	2-2

2.2.1	Combined Heat and Power	2-2

2.2.2	Emergency/Standby Generators	2-3

2.2.3	Peak Shaving	2-3

2.3	Technology Description	2-3

2.3.1	Basic Processes	2-3

2.3.2	Components	2-5

2.3.2.1	Engine System	2-5

2.3.2.2	Diesel Engines	2-6

2.3.2.3	Dual Fuel Engines	2-7

2.3.2.4	Heat Recovery	2-8

2.4	Performance Characteristics	2-9

2.4.1	Part Load Performance	2-11

2.4.2	Effects of Ambient Conditions on Performance	2-12

2.4.3	Engine Speed Classifications	2-12

2.4.4	Performance and Efficiency Enhancements	2-13

2.4.4.1	Brake Mean Effective Pressure (BMEP) and Engine Speed	2-13

2.4.4.2	Turbocharging	2-14

2.4.5	Capital Costs	2-14

2.4.6	Maintenance	2-16

2.4.7	Fuels	2-17

2.4.7.1	Liquefied Petroleum Gas	2-18

2.4.7.2	Field Gas	2-18

2.4.7.3	Biogas	2-19

2.4.7.4	Industrial Waste Gases	2-19

2.4.8	System Availability	2-20

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Table of Contents (continued)

2.5	Emissions and Emissions Control Options	2-20

2.5.1	Emissions Characteristics	2-21

2.5.1.1	Nitrogen Oxides (NOx)	2-21

2.5.1.2	Carbon Monoxide (CO)	2-21

2.5.1.3	Unburned Hydrocarbons	2-22

2.5.1.4	Carbon Dioxide (CO2)	2-22

2.5.2	Emissions Control Options	2-22

2.5.2.1	Combustion Process Emissions Control	2-22

2.5.2.2	Post-Combustion Emissions Control	2-24

2.5.2.3	Oxidation Catalysts	2-24

2.5.2.4	Diesel Particulate Filter	2-24

2.5.2.5	Three-Way Catalyst (Non Specific Catalytic Reduction)	2-24

2.5.2.6	Selective Catalytic Reduction (SCR)	2-25

2.5.3	Gas Engine Emissions Treatment Comparison	2-25

2.6	Future Developments	2-26

Section 3. Technology Characterization - Combustion Turbines	3-1

3.1	Introduction	3-1

3.2	Applications	3-1

3.3	Technology Description	3-2

3.3.1	Basic Process	3-2

3.3.2	Components	3-4

3.3.2.1 Types of Gas Turbines	3-5

3.4	Performance Characteristics	3-5

3.4.1	Fuel Supply Pressure	3-7

3.4.2	Heat Recovery	3-8

3.4.3	Part-Load Performance	3-9

3.4.4	Effects of Ambient Conditions on Performance	3-10

3.4.4.1	Ambient Air Temperature	3-10

3.4.4.2	Site Altitude	3-12

3.4.5	Capital Costs	3-12

3.4.6	Maintenance	3-14

3.4.7	Fuels	3-15

3.4.8	Gas Turbine System Availability	3-16

3.5	Emissions and Emissions Control Options	3-16

3.5.1	Emissions	3-16

3.5.2	Emissions Control Options	3-17

Catalog of CHP Technologies	iv	Table of Contents


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Table of Contents (continued)

3.5.2.1	Diluent Injection	3-18

3.5.2.2	Lean Premixed Combustion	3-18

3.5.2.3	Selective Catalytic Reduction (SCR)	3-18

3.5.2.4	CO Oxidation Catalysts	3-19

3.5.2.5	Catalytic Combustion	3-19

3.5.2.6	Catalytic Absorption Systems	3-19

3.6 Future Developments	3-20

Section 4. Technology Characterization - Steam Turbines	4-1

4.1	Introduction	4-1

4.2	Applications	4-2

4.3	Technology Description	4-3

4.3.1	Basic Process	4-3

4.3.2	Components	4-3

4.3.2.1	Boiler	4-4

4.3.2.2	Steam Turbine	4-4

4.3.2.3	Condensing Turbine	4-6

4.3.2.4	Non-Condensing (Back-pressure) Turbine	4-7

4.3.2.5	Extraction Turbine	4-8

4.4	Performance Characteristics	4-9

4.4.1	Performance Losses	4-11

4.4.2	Performance Enhancements	4-12

4.4.2.1	Steam Reheat	4-12

4.4.2.2	Combustion Air Preheating	4-12

4.4.3	Capital Costs	4-12

4.4.4	Maintenance	4-14

4.4.5	Fuels	4-15

4.4.6	System Availability	4-15

4.5	Emissions and Emissions Control Options	4-15

4.5.1	Boiler Emissions Control Options - NOx	4-16

4.5.1.1	Combustion Process emissions Control	4-16

4.5.1.2	Flue Gas Recirculation (FGR)	4-17

4.5.1.3	Low Excess Air Firing (LAE)	4-17

4.5.1.4	Low Nitrogen Fuel Oil	4-17

4.5.1.5	Burner Modifications	4-17

4.5.1.6	Water/Steam Injection	4-18

4.5.2	Post-Combustion Emissions Control	4-18

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Table of Contents (continued)

4.5.2.1	Selective Non-Catalytic Reduction (SNCR)	4-18

4.5.2.2	Selective Catalytic Reduction (SCR)	4-18

4.5.2.3	Boiler Emissions Control Options - S0X	4-18

4.6 Future Developments	4-19

Section 5. Technology Characterization - Microturbines	5-1

5.1	Introduction	5-1

5.2	Applications	5-1

5.3	Technology Description	5-2

5.3.1	Basic Process	5-2

5.3.2	Components	5-3

5.3.2.1	Turbine & Compressor	5-3

5.3.2.2	Generator	5-4

5.3.2.3	Recuperator & Combustor	5-5

5.3.2.4	CHP Heat Exchanger	5-5

5.4	Performance Characteristics	5-5

5.4.1	Part-Load Performance	5-7

5.4.2	Effects of Ambient Conditions on Performance	5-8

5.4.3	Capital Cost	5-12

5.4.4	Maintenance	5-14

5.4.5	Fuels	5-16

5.4.6	System Availability	5-16

5.5	Emissions	5-16

5.6	Future Developments	5-17

Section 6. Technology Characterization - Fuel Cells	6-1

6.1	Introduction	6-1

6.2	Applications	6-3

6.2.1	Combined Heat and Power	6-4

6.2.2	Premium Power	6-4

6.2.3	Remote Power	6-5

6.2.4	Grid Support	6-5

6.2.5	Peak Shaving	6-5

6.2.6	Resiliency	6-6

6.3	Technology Description	6-6

6.3.1 Basic Processes and Components	6-6

6.3.1.1 Fuel Cell Stacks	6-9

Catalog of CHP Technologies	vi	Table of Contents


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Table of Contents (continued)

6.3.1.2	Fuel Processors	6-9

6.3.1.3	Power Conditioning Subsystem	6-10

6.3.1.4	Types of Fuel Cells	6-10

6.3.1.5	PEMFC (Proton Exchange Membrane Fuel Cell or Polymer
Electrolyte Membrane)	6-11

6.3.1.6	PAFC (Phosphoric Acid Fuel Cell)	6-11

6.3.1.7	MCFC (Molten Carbonate Fuel Cell)	6-12

6.3.1.8	SOFC (Solid Oxide Fuel Cell)	6-12

6.4	Performance Characteristics	6-13

6.4.1	Electrical Efficiency	6-14

6.4.2	Part Load Performance	6-14

6.4.3	Effects of Ambient Conditions on Performance	6-15

6.4.4	Heat Recovery	6-15

6.4.5	Performance and Efficiency Enhancements	6-16

6.4.6	Capital Cost	6-16

6.4.7	Maintenance	6-17

6.4.8	Fuels	6-17

6.4.9	System Availability	6-18

6.5	Emissions and Emissions Control Options	6-18

6.5.1	Primary Emissions Species	6-18

6.5.1.1	Nitrogen Oxides (NOx)	6-18

6.5.1.2	Carbon Monoxide (CO)	6-19

6.5.1.3	Unburned Hydrocarbons	6-19

6.5.1.4	Carbon Dioxide (CO2)	6-19

6.5.2	Fuel Cell Emission Characteristics	6-19

6.6	Future Developments	6-20

Section 7. Packaged CHP Systems	7-1

7.1	Introduction	7-1

7.2	The Evolution of Packaged CHP Systems	7-1

7.3	Significant Attributes	7-4

7.3.1	Standardization	7-4

7.3.2	Black Start/Islanding Capability	7-4

7.3.3	Acoustic Enclosure	7-5

7.3.4	Modularity	7-5

7.3.5	Third-Party Own/Operate Business Arrangements	7-6

7.3.6	Replicability	7-6

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Table of Contents (continued)

7.4	Applications	7-6

7.4.1	Installed Packaged Systems	7-7

7.4.2	Technical Potential	7-9

7.5	Technology Description	7-10

7.5.1 Heat Recovery	7-11

7.6	Cost and Performance Characteristics	7-12

7.6.1	Part-Load Operation	7-13

7.6.2	Installed Costs	7-13

7.6.3	Maintenance Costs	7-14

7.6.4	Fuels	7-15

7.7	Emissions, Emissions Control Options, and Prime Mover Certification	7-15

Appendix A: Expressing CHP Efficiency

Catalog of CHP Technologies

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Table of Contents


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List of Figures

Figure 1-1. CHP versus Separate Heat and Power (SHP) Production	1-9

Figure 1-2. Equivalent Separate Heat and Power Efficiency	1-10

Figure 2-1. 4-Stroke Reciprocating Engine Cycle	2-4

Figure 2-2. Closed-Loop Heat Recovery System	2-9

Figure 2-3. Part Load Generator Terminal Efficiency System 5	2-12

Figure 3-1. Gas Turbine Configuration with Heat Recovery	3-3

Figure 3-2. Components of Simple Cycle Gas Turbine	3-4

Figure 3-3. Heat Recovery from a Gas Turbine System	3-8

Figure 3-4. Effect of Part Load Operation on Electrical Efficiency	3-10

Figure 3-5. Effect of Ambient Temperature on Capacity and Efficiency	3-11

Figure 3-6. The Effect of Altitude on Gas Turbine Capacity	3-12

Figure 4-1. Boiler/Steam Turbine System	4-3

Figure 4-2. Comparison of Impulse and Reaction Turbine Design	4-5

Figure 4-3. Condensing Steam Turbine	4-7

Figure 4-4. Non-Condensing (Back-pressure) Steam Turbine	4-7

Figure 4-5. Extraction Steam Turbine	4-8

Figure 5-1. Microturbine-based CHP System Schematic	5-3

Figure 5-2. Compact Microturbine Design	5-5

Figure 5-3. Part Load Efficiency at ISO Conditions, Capstone C65	5-8

Figure 5-4. Temperature Effect on Power, Capstone C200-LP	5-9

Figure 5-5. Temperature Effect on Efficiency, Capstone C200-LP	5-10

Figure 5-6. Temperature Effect on Power and Efficiency, FlexEnergy MT250	5-10

Figure 5-7. Ambient Elevation vs. Temperature Derating, Capstone C65	5-12

Figure 5-8. Capstone C370 Two-shaft High Efficiency Turbine Design	5-18

Figure 6-1. Commercial Fuel Cell for CHP Application	6-4

Figure 6-2. Fuel Cell Electrochemical Process	6-7

Figure 6-3. Effect of Operating Temperature on Fuel Cell Efficiency	6-9

Figure 6-4. Comparison of Part Load Efficiency Derate	6-15

Figure 6-5. Recent Worldwide Fuel Cell Installations by Fuel Cell Type, in Megawatts	6-20

Figure 7-1. Annual U.S. Capacity Additions: Packaged CHP Systems	7-2

Figure 7-2. Aegis ThermoPower (TP-75), 75 kW	7-3

Figure 7-3. Tecogen Tecopower CM-75, 75 kW	7-3

Figure 7-4. MTU 12V400 GS, 358 kW	7-3

Figure 7-5. Capstone C65 ICHP, 65 kW	7-3

Figure 7-6. Amerigen 8150 (Using the MAN E2876 E312 Engine), 150 kW	7-3

Figure 7-7. Energy Choice EC 190 Natural Gas system, 190 kW	7-3

Catalog of CHP Technologies	ix	List of Figures


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List of Figures (Continued)

Figure 7-8. 2G Avus 800, 800 kW	7-3

Figure 7-9. Siemens SGE-36SL, 676 kW	7-3

Figure 7-10. Packaged System Installations by Market Segment	7-7

Figure 7-11. Packaged System Installations and Capacity by Size Range	7-9

Figure 7-12. Technical Potential for <500 kW Packaged CHP Applications in the Commercial
and Institutional Sectors, by Market Segment	7-10

Figure 7-13. Packaged CHP System Diagram	7-11

Catalog of CHP Technologies

x

List of Figures


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List of Tables

Table 1-1. U.S. Installed CHP Sites and Capacity by Prime Mover	1-3

Table 1-2. Summary of CHP Technology Advantages and Disadvantages	1-4

Table 1-3. Comparison of CHP Technology Sizing, Cost, and Performance Parameters	1-6

Table 1-4. Water Consumption by SHP Technology, Cooling Technology	1-12

Table 2-1. Reciprocating Engine Characteristics	2-1

Table 2-2. Gas Spark Ignition Engine CHP - Typical Performance Parameters	2-10

Table 2-3. Reciprocating Engine Types by Speed (Available MW Ratings)	2-13

Table 2-4. Estimated Capital Cost for Typical Gas Engine Generators in Grid Interconnected

CHP Applications	2-15

Table 2-5. Representative Overhaul Intervals for Natural Gas Engines in Baseload Service	2-16

Table 2-6. Typical Natural Gas Engine Maintenance Costs ($2013/kWh)	2-17

Table 2-7. Major Constituents and LHV of Gaseous Fuels	2-18

Table 2-8. Availabilities and Outage Rates for Natural Gas Engines	2-20

Table 2-9. Uncontrolled NOx Emissions versus Efficiency Tradeoffs	2-23

Table 2-10. Post-Combustion Exhaust Gas Cleanup Options	2-24

Table 2-11. Gas Engine Emissions Characteristics with Available Exhaust Control Options	2-26

Table 3-1. Gas Turbine Design Characteristics	3-4

Table 3-2. Typical Performance for Gas Turbines in CHP Operation	3-6

Table 3-3. Power Requirements for Natural Gas Fuel Compression	3-8

Table 3-4. Cost Estimation Parameters	3-13

Table 3-5. Estimated Capital Cost for Representative Gas Turbine CHP Systems	3-14

Table 3-6. Gas Turbine Non-Fuel O&M Costs	3-15

Table 3-7. Gas Turbine Availability and Outage Rates	3-16

Table 3-8. Gas Turbine Emissions Characteristics	3-17

Table 4-1. Summary of Steam Turbine Attributes	4-1

Table 4-2. Backpressure Steam Turbine Cost and Performance Characteristics*	4-10

Table 4-3. Steam Turbine Availability	4-15

Table 4-4. Typical Boiler Emissions Ranges	4-16

Table 5-1. Summary of Microturbine Attributes	5-1

Table 5-2. Microturbine Cost and Performance Characteristics	5-6

Table 5-3. Equipment and Installation Costs	5-13

Table 5-4. Example Service Schedule, Capstone C65	5-14

Table 5-5. Maintenance Costs Based on Factory Service Contracts	5-15

Table 5-6. Microturbine Emissions Characteristics	5-17

Table 6-1. Comparison of Fuel Cell Applications, Advantages, and Disadvantages	6-2

Table 6-2. Characteristics of Major Fuel Cell Types	6-11

Table 6-3. Fuel Cell CHP - Typical Performance Parameters	6-13

Catalog of CHP Technologies	xi	List of Tables


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List of Tables (Continued)

Table 6-4. Estimated Capital and O&M Costs for Typical Fuel Cell Systems in Grid
Interconnected CHP Applications (2014 $/kW)	6-17

Table 6-5. Estimated Fuel Cell Emission Characteristics without Additional Controls	6-19

Table 7-1. Packaged Systems Total Installed Capacity and Median Size by Market Segment	7-8

Table 7-2. Packaged CHP Systems - Performance Characteristics	7-12

Table 7-3. Packaged CHP Systems - Equipment Costs	7-14

Table 7-4. Packaged CHP Systems - Maintenance Costs	7-14

Catalog of CHP Technologies

xii

List of Tables


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Section 1. Introduction

Combined heat and power (CHP) is an efficient and clean approach to generating electric power and
useful thermal energy from a single fuel source. CHP places power production at or near the end-user's
site so that the heat released from power production can be used to meet the user's thermal
requirements while the power generated meets all or a portion of the site electricity needs. Applications
with steady demand for electricity and thermal energy are potentially good economic targets for CHP
deployment. Industrial applications particularly in industries with continuous processing and high steam
requirements are very economic and represent a large share of existing CHP capacity today. Commercial
applications such as hospitals, nursing homes, laundries, and hotels with large hot water needs are well
suited for CHP. Institutional applications such as colleges and schools, prisons, and residential and
recreational facilities are also excellent prospects for CHP.

The direct benefits of combined heat and power for facility operators are:

•	Reduced energy related costs - providing direct cost savings.

•	Increased reliability and decreased risk of power outages due to the addition of a separate
power supply.

•	Increased economic competitiveness due to lower cost of operations.

In addition to these direct benefits, the electric industry, electricity customers, and society, in general,
derive benefits from CHP deployment, including:

•	Increased energy efficiency - providing useful energy services to facilities with less primary
energy input.

•	Economic development value - allowing businesses to be more economically competitive on a
global market thereby maintaining local employment and economic health.

•	Reduction in emissions that contribute to global warming - increased efficiency of energy use
allows facilities to achieve the same levels of output or business activity with lower levels of
fossil fuel combustion and reduced emissions of carbon dioxide.

•	Reduced emissions of criteria air pollutants - CHP systems can reduce air emissions of carbon
monoxide (CO), nitrogen oxides (NOx), and Sulfur dioxide (S02) especially when state-of-the-art
CHP equipment replaces outdated and inefficient boilers at the site.

•	Increased reliability and grid support for the utility system and customers as a whole.

•	Resource adequacy - reduced need for regional power plant and transmission and distribution
infrastructure construction.

CHP systems consist of a number of individual components - prime mover (heat engine), generator,
heat recovery, and electrical interconnection - configured into an integrated whole. The type of
equipment that drives the overall system (i.e., the prime mover) typically identifies the CHP system. The
purpose of this guide is to provide CHP stakeholders with a description of the cost and performance of
complete systems powered by prime-mover technologies consisting of:

Catalog of CHP Technologies

1-1

Introduction


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1.	Reciprocating internal combustion engines

2.	Combustion turbines

3.	Steam turbines

4.	Microturbines

5.	Fuel cells

In 2008, the EPA CHP Partnership Program published its first catalog of CHP technologies as an online
educational resource for regulatory, policy, permitting, and other interested CHP stakeholders. This CHP
Technology Guide is an update to the 2008 report1. The Guide includes separate, detailed chapters on
each of the five prime movers listed above. These technology chapters include the following
information:

•	Description of common applications

•	Basic technology description

•	Cost and performance characteristics

•	Emissions and emissions control options

•	Future developments

Packaged CHP Systems

In September 2017, the EPA CHP Partnership added a new section (Section 7) to the Catalog that
provides information on packaged CHP systems. Specifically, the section discusses:

•	The evolution of packaged CHP systems

•	Significant attributes

•	Applications

•	Technology description

•	Cost and Performance characteristics

•	Emissions and emission control options

This introduction and overview section provides a discussion of the benefits of CHP technologies, a
summary comparison of the five main prime-mover technology systems, and a discussion of key CHP
benefits. There is also an appendix that provides the formulas for the various performance
measurements used in the Guide.

1.1 Overview of CHP Technologies

The five technologies described in the Guide make up 97 percent of the CHP projects in place today and
99 percent of the total installed CHP electric capacity. Table 1-1 shows the breakdown by each prime
mover technology.

1 Catalog of CHP Technologies, U.S. Environmental Protection Agency Combined Heat and Power Partnership Program,
December 2008.

Catalog of CHP Technologies

1-2

Introduction


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Table 1-1. U.S. Installed CHP Sites and Capacity by Prime Mover

Prime Mover

Sites

Share of
Sites

Capacity
(MW)

Share of
Capacity

Reciprocating Engine

2,194

51.9%

2,288

2.7%

Gas Turbine*

667

15.8%

53,320

64.0%

Boiler/Steam Turbine

734

17.4%

26,741

32.1%

Microturbine

355

8.4%

78

0.1%

Fuel Cell

155

3.7%

84

0.1%

Other

121

2.9%

806

1.0%

Total

4,226

100.0%

83,317

100.0%

* includes gas turbine/steam turbine combined cycle
Source: ICF CHP Installation Database, April 2014

All of the technologies described convert a chemical fuel into electric power. The energy in the fuel that
is not converted to electricity is released as heat. All of the technologies, except fuel cells, are a class of
technologies known as heat engines. Heat engines combust the fuel to produce heat, and a portion of
that heat is utilized to produce electricity while the remaining heat is exhausted from the process. Fuel
cells convert the energy in the fuel to electricity electrochemically; however, there are still inefficiencies
in the conversion process that produce heat that can be utilized for CHP. Each technology is described in
detail in the individual technology chapters, but a short introduction of each is provided here:

•	Reciprocating engines, as shown above, make up over half of the CHP systems in place, though,
because of the generally smaller system sizes, less than 3 percent of total capacity. The
technology is common place - used in automobiles, trucks, trains, emergency power systems,
portable power systems, farm and garden equipment. Reciprocating engines can range in size
from small hand-held equipment to giant marine engines standing over 5-stories tall and
producing the equivalent power to serve 18,000 homes. The technology has been around for
more than 100 years. The maturity and high production levels make reciprocating engines a low-
cost reliable option. Technology improvements over the last 30 years have allowed this
technology to keep pace with the higher efficiency and lower emissions needs of today's CHP
applications. The exhaust heat characteristics of reciprocating engines make them ideal for
producing hot water.

•	Steam turbine systems represent 32 percent of U.S. installed CHP capacity; however, the
median age of these installations is 45 years old. Today, steam turbines are mainly used for
systems matched to solid fuel boilers, industrial waste heat, or the waste heat from a gas
turbine (making it a combined cycle.) Steam turbines offer a wide array of designs and
complexity to match the desired application and/or performance specifications ranging from
single stage backpressure or condensing turbines for low power ranges to complex multi-stage
turbines for higher power ranges. Steam turbines for utility service may have several pressure
casings and elaborate design features, all designed to maximize the efficiency of the system. For
industrial applications, steam turbines are generally of simpler single casing design and less
complicated for reliability and cost reasons. CHP can be adapted to both utility and industrial
steam turbine designs.

•	Gas turbines, as shown, make up over 60 percent of CHP system capacity. It is the same
technology that is used in jet aircraft and many aeroderivative gas turbines used in stationary

Catalog of CHP Technologies

1-3

Introduction


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applications are versions of the same engines. Gas turbines can be made in a wide range of sizes
from microturbines (to be described separately) to very large frame turbines used for central
station power generation. For CHP applications, their most economic application range is in sizes
greater than 5 MW with sizes ranging into the hundreds of megawatts. The high temperature
heat from the turbine exhaust can be used to produce high pressure steam, making gas turbine
CHP systems very attractive for process industries.

•	Microturbines, as already indicated, are very small gas turbines. They were developed as
stationary and transportation power sources within the last 30 years. They were originally based
on the truck turbocharger technology that captures the energy in engine exhaust heat to
compress the engine's inlet air. Microturbines are clean-burning, mechanically simple, and very
compact. There were a large number of competing systems under development throughout the
1990s. Today, following a period of market consolidation, there are two manufacturers in the
U.S. providing commercial systems for CHP use with capacities ranging from 30-250 kW for
single turbine systems with multiple turbine packages available up to 1,000 kW.

•	Fuel cells use an electrochemical or battery-like process to convert the chemical energy of
hydrogen into water and electricity. In CHP applications, heat is generally recovered in the form
of hot water or low-pressure steam (<30 psig) and the quality of heat is dependent on the type
of fuel cell and its operating temperature. Fuel cells use hydrogen, which can be obtained from
natural gas, coal gas, methanol, and other hydrocarbon fuels. Fuel cells are characterized by the
type of electrochemical process utilized, and there are several competing types, phosphoric acid
(PAFC), proton exchange membrane (PEMFC), molten carbonate (MCFC), solid oxide (SOFC), and
alkaline (AFC). PAFC systems are commercially available in two sizes, 200 kW and 400 kW, and
two MCFC systems are commercially available, 300 kW and 1200 kW. Fuel cell capital costs
remain high due to low-volume custom production methods, but they remain in demand for
CHP applications because of their low air emissions, low-noise, and generous market subsidies.

Table 1-2 and Table 1-3 provide a summary of the key cost and performance characteristics of the CHP

technologies discussed in the CHP Technology Guide.

Table 1-2. Summary of CHP Technology Advantages and Disadvantages

CHP system

Advantages

Disadvantages

Available sizes

Spark ignition
(SI)

reciprocating
engine

•	High power efficiency with
part-load operational
flexibility.

•	Fast start-up.

•	Relatively low investment
cost.

•	Has good load following
capability.

•	Can be overhauled on site
with normal operators.

•	Operate on low-pressure
gas.

•	High maintenance costs.

•	Limited to lower
temperature cogeneration
applications.

•	Relatively high air
emissions.

•	Must be cooled even if
recovered heat is not used.

•	High levels of low frequency
noise.

1 kW to 10
MW in DG
applications

Compression
ignition (CI)
reciprocating
engine (dual
fuel pilot
ignition)

High speed
(1,200 RPM)
<4MW

< 80 MW for
Low speed (60-
275 RPM)

Catalog of CHP Technologies

1-4

Introduction


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Table 1-2. Summary of CHP Technology Advantages and Disadvantages

CHP system

Advantages

Disadvantages

Available sizes

Steam turbine

•	High overall efficiency-
steam to power.

•	Can be mated to boilers
firing a variety of gaseous,
liquid or solid fuels.

•	Ability to meet more than
one site heat grade
requirement.

•	Long working life and high
reliability.

•	Power to heat ratio can be
varied.

•	Slow start up.

•	Very low power to heat
ratio.

•	Requires a boiler or other
steam source.

50 kW to
several

hundred MWs

Gas turbine

•	High reliability.

•	Low emissions.

•	High grade heat available.

•	No cooling required.

•	Require high pressure gas or
in-house gas compressor.

•	Poor efficiency at low
loading.

•	Output falls as ambient
temperature rises.

500 kW to 300
MW

Microturbine

•	Small number of moving
parts.

•	Compact size and light
weight.

•	Low emissions.

•	No cooling required.

•	High costs.

•	Relatively low mechanical
efficiency.

•	Limited to lower
temperature cogeneration
applications.

30 kW to 250
kW with
multiple unit
packages up to
1,000 kW

Fuel cells

•	Low emissions and low
noise.

•	High efficiency over load
range.

•	Modular design.

•	High costs.

•	Fuels require processing
unless pure hydrogen is
used.

•	Sensitive to fuel impurities.

•	Low power density.

5 kW to 2 MW

Catalog of CHP Technologies

1-5

Introduction


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Table 1-3. Comparison of CHP Technology Sizin:

Cost, and Performance Parameters

Technology

Recip. Engine

Steam Turbine

Gas Turbine

Microturbine

Fuel Cell

Electric efficiency (HHV)

27-41%

5-40+%2

24-36%

22-28%

30-63%

Overall CHP efficiency (HHV)

77-80%

near 80%

66-71%

63-70%

55-80%

Effective electrical efficiency

75-80%

75-77%

50-62%

49-57%

55-80%

Typical capacity (MW.)

.005-10

0.5-several hundred
MW

0.5-300

0.03-1.0

200-2.8 commercial CHP

Typical power to heat ratio

0.5-1.2

0.07-0.1

0.6-1.1

0.5-0.7

1-2

Part-load

ok

ok

poor

ok

good

CHP Installed costs ($/kWe)

1,500-2,900

$670-1,100

1,200-3,300
(5-40 MW)

2,500-4,300

5,000-6,500

Non-fuel O&M costs ($/kWhe)

0.009-0.025

0.006 to 0.01

0.009-0.013

0.009-.013

0.032-0.038

Availability

96-98%

72-99%

93-96%

98-99%

>95%

Hours to overhauls

30,000-60,000

>50,000

25,000-50,000

40,000-80,000

32,000-64,000

Start-up time

10 sec

1hr-1 day

10 min -1 hr

60 sec

3 hrs - 2 days

Fuel pressure (psig)

1-75

n/a

100-500
(compressor)

50-140
(compressor)

0.5-45

Fuels

natural gas, biogas,

LPG, sour gas,
industrial waste gas,
manufactured gas

all

natural gas, synthetic
gas, landfill gas, and
fuel oils

natural gas, sour gas,
liquid fuels

hydrogen, natural gas,
propane, methanol

Uses for thermal output

space heating, hot
water, cooling, LP
steam

process steam, district
heating, hot water,
chilled water

heat, hot water, LP-HP
steam

hot water, chiller,
heating

hot water, LP-HP steam

Power Density (kW/m2)

35-50

>100

20-500

5-70

5-20

NOx (Ib/MMBtu)
(not including SCR)

0.013 rich burn 3-way
cat.

0.17 lean burn

Gas 0.1-.2 Wood 0.2-.5
Coal 0.3-1.2

0.036-0.05

0.015-0.036

0.0025-.0040

NOx (Ib/MWhjotaioutput)
(not including SCR)

0.06 rich burn 3-way
cat.

0.8 lean burn

Gas 0.4-0.8
Wood 0.9-1.4
Coal 1.2-5.0.

0.52-1.31

0.14-0.49

0.011-0.016

Power efficiencies at the low end are for small backpressure turbines with boiler and for large supercritical condensing steam turbines for power generation at the high end.

Catalog of CHP Technologies

1-6

Introduction


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Key comparisons shown in Table 1-3 are described in more detail below:

•	Electric efficiency varies by technology and by size with larger systems of a given technology
generally more efficient than smaller systems. There is overlap in efficiency ranges among the
five technology classes, but, in general, the highest electric efficiencies are achieved by fuel
cells, followed by large reciprocating engines, simple cycle gas turbines, microturbines, and then
steam turbines. The highest electric efficiencies are achievable by large gas turbines operating in
combined cycle with steam turbines that convert additional heat into electricity.

•	Overall CHP efficiency is more uniform across technology types. One of the key features of CHP
is that inefficiencies in electricity generation increase the amount of heat that can be utilized for
thermal processes. Therefore, the combined electric and thermal energy efficiency remains in a
range of 65-80 percent. The overall efficiency is dependent on the quality of the heat delivered.
Gas turbines that deliver high pressure steam for process use have lower overall efficiencies
than microturbines, reciprocating engines, and fuel cells that are assumed, in this comparison,
to deliver hot water.

•	Installed capital costs include the equipment (prime mover, heat recovery and cooling systems,
fuel system, controls, electrical, and interconnect) installation, project management,
engineering, and interest during construction for a simple installation with minimal need for site
preparation or additional utilities. The costs are for an average U.S. location; high cost areas
would cost more. The lowest unit capital costs are for the established mature technologies
(reciprocating engines, gas turbines, steam turbines) and the highest costs are for the two small
capacity, newer technologies (microturbines and fuel cells.) Also, larger capacity CHP systems
within a given technology class have lower installed costs than smaller capacity systems.

•	Non-fuel O&M costs include routine inspections, scheduled overhauls, preventive maintenance,
and operating labor. As with capital costs, there is a strong trend for unit O&M costs to decline
as systems get larger. Among technology classes gas turbines and microturbines have lower
O&M costs than comparably sized reciprocating engines. Fuel cells have shown high O&M costs
in practice, due in large part to the need for periodic replacement of the expensive stack
assembly.

•	Start-up times for the five CHP technologies described in this Guide can vary significantly.
Reciprocating engines have the fastest start-up capability, which allows for timely resumption of
the system following a maintenance procedure. In peaking or emergency power applications,
reciprocating engines can most quickly supply electricity on demand. Microturbines and gas
turbines have a somewhat longer start-up time to "spool-up" the turbine to operating speed.
Heat recovery considerations may constrain start-up times for these systems. Steam turbines,
on the other hand, require long warm-up periods in order to obtain reliable service and prevent
excessive thermal expansion, stress and wear. Fuel cells also have relatively long start-up times
(especially for those systems using a high temperature electrolyte.). The longer start-up times
for steam turbines and fuel cells make them less attractive for start-stop or load following
operation.

•	Availability indicates the amount of time a unit can be used for electricity and/or steam
production. Availability generally depends on the operational conditions of the unit.
Measurements of systems in the field have shown that availabilities for gas turbines, steam
turbines, and reciprocating engines are typically 95 percent and higher. Early fuel cell and

Catalog of CHP Technologies

1-7

Introduction


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microturbine installations experienced availability problems; however, commercial units put in
service today should also show availabilities over 95 percent.

1.2 CHP Efficiency Compared to Separate Heat and Power

Many of the benefits of CHP stem from the relatively high efficiency of CHP systems compared to other
systems. Because CHP systems simultaneously produce electricity and useful thermal energy, CHP
efficiency is measured and expressed in a number of different ways.3 A brief discussion of these
measures is provided below, while Appendix A provides a more detailed discussion.

The efficiency of electricity generation in power-only systems is determined by the relationship between
net electrical output and the amount of fuel used for the power generation. Heat rate, the term often
used to express efficiency in such power generation systems, is represented in terms of Btus of fuel
consumed per kWh of electricity generated. However, CHP plants produce useful heat as well as
electricity. In CHP systems, the total CHP efficiency seeks to capture the energy content of both
electricity and usable steam and is the net electrical output plus the net useful thermal output of the
CHP system divided by the fuel consumed in the production of electricity and steam. While total CHP
efficiency provides a measure for capturing the energy content of electricity and steam produced it does
not adequately reflect the fact that electricity and steam have different qualities. The quality and value
of electrical output is higher relative to heat output and is evidenced by the fact that electricity can be
transmitted over long distances and can be converted to other forms of energy. To account for these
differences in quality, the Public Utilities Regulatory Policies Act of 1978 (PURPA) discounts half of the
thermal energy in its calculation of the efficiency standard (EffFERc). The EFFferc is represented as the
ratio of net electric output plus half of the net thermal output to the total fuel used in the CHP system.

Another definition of CHP efficiency is effective electrical efficiency, also known as fuel utilization

effectiveness (FUE). This measure expresses CHP efficiency as the ratio of net electrical output to net
fuel consumption, where net fuel consumption excludes the portion of fuel that goes to producing
useful heat output. FUE captures the value of both the electrical and thermal outputs of CHP plants and
it specifically measures the efficiency of generating power through the incremental fuel consumption of
the CHP system.

EPA considers fuel savings as the appropriate term to use when discussing CHP benefits relative to
separate heat and power (SHP) operations. Fuel savings compares the fuel used by the CHP system to a
separate heat and power system (i.e. boiler and electric-only generation). Positive values represent fuel
savings while negative values indicate that the CHP system in question is using more fuel than separate
heat and power generation.

Figure 1-1 shows the efficiency advantage of CHP compared with conventional central station power
generation and onsite boilers. When considering both thermal and electrical processes together, CHP
typically requires only % the primary energy separate heat and power systems require. CHP systems

3 Measures of efficiency are denoted either as lower heating value (LHV) or higher heating value (HHV). HHV includes the heat
of condensation of the water vapor in the products. Unless otherwise noted, all efficiency measures in this section are reported
on an HHV basis.

Catalog of CHP Technologies

1-8

Introduction


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utilize less fuel than separate heat and power generation, resulting for the same level of output,
resulting in fewer emissions.

Figure 1-1. CHP versus Separate Heat and Power (SHP) Production4

Conventional
Generation

Power Station Fuel
(U.S. Fossil Mix)

91 Units Fuel



56 Units Fuel

IL

Boiler Fuel

Combined Heat and Power

5 MW Natural Gas
Combustion Turbine
and Heat Recovery Boiler

Power Plant

EFFICIENCY:

33%

EFFICIENCY:
80%



1 30 ^

Units
Electricity









/ \

Electricity

Electricity









Combined

Heat
& Power
(CHP)

Heat

45
Units

Heat





Steam



N	/



51% ...OVERALL EFFICIENCY... 75%

Another important concept related to CHP efficiency is the power-to-heat ratio. The power-to-heat
ratio indicates the proportion of power (electrical or mechanical energy) to heat energy (steam or hot
water) produced in the CHP system. Because the efficiencies of power generation and steam generation
are likely to be considerably different, the power-to-heat ratio has an important bearing on how the
total CHP system efficiency might compare to that of a separate power-and-heat system. Figure 1-2
illustrates this point. The figure shows how the overall efficiency might change under alternate power-
to-heat ratios for a separate power-and-heat system and a CHP system.

4 In this example of a typical CHP system, to produce 75 units of useful energy, the conventional generation or separate heat
and power systems use 147 units of energy—91 for electricity production and 56 to produce heat—resulting in an overall
efficiency of 51 percent. However, the CHP system needs only 100 units of energy to produce the 75 units of useful energy from
a single fuel source, resulting in a total system efficiency of 75 percent.

Catalog of CHP Technologies	1-9	Introduction


-------
Figure 1-2. Equivalent Separate Heat and Power Efficiency

Site Efficiency as a function of P/H
Ratio

SP

£
C

OJ

'u

ts

OJ

¦D
C

f0

"to

E

¦o

ai
c
la
E
o
u

95%
85%
75%
65%
55%
45%
35%
25%



0.00 0.50 1.00 1.50 2.00
Power to Heat Ratio (P/H)



•SHP

u

GT

A

MT

~

ST

•

FC

•

Recip

2.50

SHP assumes 35.7percent efficient electric and 80 percent efficient thermal generation

CHP overall thermal and electric efficiencies are higher than corresponding efficiencies for SHP across
the range of power-to-heat ratios. However, as shown the SHP efficiency varies as a function of how
much of the lower efficiency electricity is supplied versus the higher efficiency thermal energy. At very
low power-to-heat ratios, as is typical for steam turbine systems, CHP is above the SHP line, but only by
a few percentage points. As electric efficiencies of the CHP systems get higher (and corresponding p/h
ratios increase), the relative improvement of CHP compared to SHP increases dramatically.

1.3 Emissions

In addition to cost savings, CHP technologies offer significantly lower emissions rates compared to
separate heat and power systems. The primary pollutants from gas turbines are oxides of nitrogen
(NOx), carbon monoxide (CO), and volatile organic compounds (VOCs) (unburned, non-methane
hydrocarbons). Other pollutants such as oxides of sulfur (SOx) and particulate matter (PM) are primarily
dependent on the fuel used. Similarly, emissions of carbon dioxide are also dependent on the fuel used.
Many gas turbines burning gaseous fuels (mainly natural gas) feature lean premixed burners (also called
dry low-NOx burners) that produce NOx emissions ranging between 0.17 to 0.25 Ibs/MWh5 with no post-
combustion emissions control. Typically commercially available gas turbines have CO emissions rates
ranging between 0.23 Ibs/MWh and 0.28 Ibs/MWh. Selective catalytic reduction (SCR) or catalytic
combustion can further help to reduce NOx emissions by 80 percent to 90 percent from the gas turbine

5 The NOx emissions reported in this section in Ib/MWh are based on the total electric and thermal energy provided by the CHP
system in MWh.

Catalog of CHP Technologies

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Introduction


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exhaust and carbon-monoxide oxidation catalysts can help to reduce CO by approximately 90 percent.
Many gas turbines sited in locales with stringent emission regulations use SCR after-treatment to
achieve extremely low NOx emissions.

Microturbines have the potential for low emissions. All microturbines operating on gaseous fuels feature
lean premixed (dry low NOx, or DLN) combustor technology. The primary pollutants from microturbines
include NOx, CO, and unburned hydrocarbons. They also produce a negligible amount of S02.
Microturbines are designed to achieve low emissions at full load and emissions are often higher when
operating at part load. Typical NOx emissions for microturbine systems range between 4 ppmv and 9
ppmv or 0.08 Ibs/MWh and 0.20 Ibs/MWh. Additional NOx emissions removal from catalytic combustion
in microturbines is unlikely to be pursued in the near term because of the dry low NOx technology and
the low turbine inlet temperature. CO emissions rates for microturbines typically range between 0.06
Ibs/MWh and 0.54 Ibs/MWh.

Exhaust emissions are the primary environmental concern with reciprocating engines. The primary
pollutants from reciprocating engines are NOx, CO, and VOCs. Other pollutants such as SOx and PM are
primarily dependent on the fuel used. The sulfur content of the fuel determines emissions of sulfur
compounds, primarily S02. NOx emissions from small "rich burn" reciprocating engines with integral 3-
way catalyst exhaust treatment can be as low as 0.06 Ibs/MWh. Larger lean burn engines have values of
around 0.8 Ibs/MWh without any exhaust treatment; however, these engines can utilize SCR for NOx
reduction.

Emissions from steam turbines depend on the fuel used in the boiler or other steam sources, boiler
furnace combustion section design, operation, and exhaust cleanup systems. Boiler emissions include
NOx, SOx, PM, and CO. Typical boiler emissions rates for NOx range between 0.3 Ibs/MMBtu and 1.24
Ibs/MMBtu for coal, 0.2 Ibs/MMBtu and 0.5 Ibs/MMBtu for wood, and 0.1 Ibs/MMBtu and 0.2
Ibs/MMBtu for natural gas. Uncontrolled CO emissions rates range between 0.02 Ibs/MMBtu and 0.7
Ibs/MMBtu for coal, approximately 0.06 Ibs/MMBtu for wood, and 0.08 Ibs/MMBtu for natural gas. A
variety of commercially available combustion and post-combustion NOx reduction techniques exist with
selective catalytic reductions achieving reductions as high as 90 percent.

Fuel cell systems have inherently low emissions profiles because the primary power generation process
does not involve combustion. The fuel processing subsystem is the only significant source of emissions
as it converts fuel into hydrogen and a low energy hydrogen exhaust stream. The hydrogen exhaust
stream is combusted in the fuel processor to provide heat, achieving emissions signatures of less than
0.019 Ibs/MWh of CO, less than 0.016 Ibs/MWh of NOx and negligible SOx without any after-treatment
for emissions. Fuel cells are not expected to require any emissions control devices to meet current and
projected regulations.

Other pollutants such as SOx and PM are primarily dependent on the fuel used. CHP technologies that
could use fuels other than natural gas, including reciprocating engines and steam turbines, could also
incur other emissions from its fuel choice. For example, the sulfur content of the fuel determines
emissions of sulfur compounds, primarily S02.

Catalog of CHP Technologies

1-11

Introduction


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S02 emissions from steam turbines depend largely on the sulfur content of the fuel used in the
combustion process. S02 comprises about 95 percent of the emitted sulfur and the remaining 5 percent
is emitted as sulfur tri-oxide (S03). Flue gas desulphurization (FGD) is the most commonly used post-
combustion S02 removal technology and is applicable to a broad range of different uses. FGD can
provide up to 95 percent S02 removal.

C02 emissions result from the use the fossil fuel-based CHP technologies. The amount of C02 emitted in
any of the CHP technologies discussed above depends on the fuel carbon content and the system
efficiency. The fuel carbon content of natural gas is 34 lbs carbon/MMBtu; oil is 48 lbs of carbon/MMBtu
and ash-free coal is 66 lbs of carbon/MMBtu.

1.4 Comparison of Water Usage for CHP compared to SHP

Water is critical in all stages of energy production, from drilling for oil and gas to electricity production.
As water supply levels are being challenged by continuing and severe droughts, especially in the
Southeast and Western regions of the U.S., as well as increasing demand and regulations, water
requirements and usage are becoming important considerations in energy production.

According to the U.S. Geological Survey (USGS), thermoelectric power, which uses water for cooling
steam turbines, accounts for the largest share of water withdrawal in the U.S., at 49 percent in 2005
(latest year data are available). Table 1-4 shows the water consumption (gal/MWh) by SHP technology
and cooling technology.

Table 1-4. Water Consumption by SHP Technology, Cooling Technology6



Cooling Technologies - Water Consumption (gal/MWh)

Open-
LODp

Closed-Loop
Reservoir

Closed-

Loop
Cooling
Tower

Hybrid
Cooling

Air-Cooling

Fuel Technology

Thermal

Coal

300

385
(±115)

480

between

60

(±10)

Nuclear

400

625
(±225)

720

between

60
(±10)

Natural Gas Combustion
Turbine

negligible

negligible

negligible

negligible

negligible

Natural Gas Combined-
Cycle

100

130*
(±20)

180

between

60*
(±10)

Integrated Gasification
Combined-Cycle

not used

not used

350'
(+100)

between

60'
(±10)

Concentrated Solar
Power

not used

not used

840
(±80)

between

80f
(±10)

Non-
Thermal

Wind

none

none

none

none

none

Photovoltaic Solar

none

none

none

none

none

Estimated based on withdrawal and consumption ratios

6 Stillwellll, Ashlynn S., et al, Enerev-Water Nexus in Texas. The University of Texas at Austin and Environmental Defense Fund,
April 2009.

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Introduction


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The role of CHP technologies could be critical in water issues, as CHP systems, particularly reciprocating
engine, combustion turbine, microturbines, and fuel cells, use almost negligible amounts of water. A
boiler/steam turbine CHP system water consumption would be similar to the SHP technology shown in
Table 1-4.

1.5 Outlook

In the last twenty years, there has been substantial improvement in gas turbine technology with respect
to power, efficiency, durability, emissions, and time/cost to market. These improvements have been the
combined results of collaborative research efforts by private industry, universities, and the federal
government. Public-private partnerships such as the DOE Advanced Turbine Systems Program and the
Next Generation Turbine program have advanced gas turbine technology. Current collaborative research
is focusing on both large gas turbines and those applicable for distributed generation. Large gas turbine
research is focused on improving the efficiency of combined cycle plants to 65 percent (LHV), reducing
emission even further, and integrating gas turbines with clean coal gasification and carbon capture. The
focus for smaller gas turbines is on improving performance, enhancing fuel flexibility, reducing
emissions, reducing life cycle costs, and integration with improved thermal utilization technologies.
Continued development of aeroderivative gas turbines for civilian and military propulsion will provide
carryover benefits to stationary applications. Long-term research includes the development of hybrid
gas turbine fuel cell technology that is capable of 70 percent (LHV) electric efficiency.

Microturbine manufacturers are continuing to develop products with higher electrical efficiencies.
Working cooperatively with the Department of Energy, Capstone is developing a 250 kW model with a
target efficiency of 35 percent (gross output, LHV) and a 370 kW model with a projected 42 percent
efficiency. The C250 will feature an advanced aerodynamic compressor design, engine sealing
improvements, improved generator design with longer life magnet, and enhanced cooling. The project
will use a modified Capstone C200 turbocompressor assembly as the low-pressure section of a two shaft
turbine. This low-pressure section will have an electrical output of 250 kW. A new high-temperature,
high-pressure turbocompressor assembly will increase the electrical output to 370 kW. Product
development in microturbines over the years has been to achieve efficiency and cost reductions by
increasing the capacity of the products. Starting with original products in the 30-50 kW range,
microturbine manufacturers have developed and are continuing to develop increasingly larger products
that compete more directly with larger reciprocating gas engines and even small simple cycle gas
turbines.

Public-private partnerships such as the DOE Advanced Reciprocating Engine System (ARES) funded by
DOE and the Advanced Reciprocating Internal Combustion Engine (ARICE) program funded by the
California Energy Commission have focused attention on the development of the next generation
reciprocating engine. The original goals of the ARES program were to achieve 50 percent brake thermal
efficiency (LHV), NOx emissions to less than 1 g/bhp-hr (0.3 Ib/MWh), and maintenance costs of
$0.01/kWh, all while maintaining cost competitiveness. The development focus under ARES includes:

•	Combustion chamber design

•	Friction reduction

•	Combustion of dilute mixtures

Catalog of CHP Technologies

1-13

Introduction


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•	Turbocompounding

•	Modified or alternative engine cycles

•	Exhaust energy retention

•	Exhaust after-treatment - improving SCR and TWC operation and proving the operation of Lean
NOx catalyst (LNC)

•	Water injection

•	High power density

•	Multiple source ignition

The U.S. DOE funds collaborative research and development toward the development of improved ultra-
supercritical (USC) steam turbines capable of efficiencies of 55-60 percent that are based on boiler tube
materials that can withstand pressures of up to 5,000 psi and temperatures of 1,400 °F. To achieve these
goals, work is ongoing in materials, internal design and construction, steam valve development, and
design of high pressure casings. A prototype is targeted for commercial testing by 2025. Research is also
underway to restore and improve the performance of existing steam turbines in the field through such
measures as improved combustion systems for boilers, heat transfer and aerodynamics to improve
turbine blade life and performance, and improved materials to permit longer life and higher operating
temperatures for more efficient systems.

The focus on emerging markets such as waste heat recovery and biomass-fueled power and CHP plants
is stimulating the demand for small and medium steam turbines. Technology and product development
for these markets should bring about future improvements in steam turbine efficiency, longevity, and
cost. This could be particularly true for systems below 500 kW that are used in developmental small
biomass systems and in waste-heat-to-power systems designed to operate in place of pressure
reduction valves in commercial and industrial steam systems operating at multiple pressures.

Catalog of CHP Technologies

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Introduction


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Section 2. Technology Characterization - Reciprocating Internal
Combustion Engines

2.1 Introduction

Reciprocating internal combustion engines are a well-established and widely used technology.
Worldwide production for reciprocating internal combustion engines is over 200 million units per year.7
Reciprocating engines include both diesel and spark-ignition configurations. They are important for both
transportation and for stationary uses. Their sizes range from fractional horsepower engines to 5-story
tall marine propulsion systems weighing over 5 million pounds and producing over 80 megawatts (MW)
of power. The long history of technical development and high production levels have contributed to
making reciprocating engines a rugged, reliable, and economic choice as a prime mover for CHP
applications.

Reciprocating engine technology has improved dramatically over the past three decades, driven by
economic and environmental pressures for power density improvements (more output per unit of
engine displacement), increased fuel efficiency, and reduced emissions. Electronic Power Control
Modules (PCMs) have made possible more precise control and diagnostic monitoring of the engine
process. Stationary engine manufacturers and worldwide engine R&D firms continue to drive advanced
engine technology, including accelerating the diffusion of innovative technology and concepts from the
automotive market to the stationary market.

The features that have made reciprocating engines a leading prime mover for CHP and other distributed
generation applications are summarized in Table 2-1.

Table 2-1. Reciprocating Engine Characteristics

Size range

Reciprocating engines are available in sizes from 10 kW to over 18 MW.

Thermal output

Reciprocating engines can produce hot water, low pressure steam, and chilled water
(using an absorption chiller).

Fast start-up

The fast start-up capability of reciprocating engines allows timely resumption of the
system following a maintenance procedure. In peaking or emergency power applications,
reciprocating engines can quickly supply electricity on demand.

Black-start capability

In the event of an electric utility outage, reciprocating engines require minimal auxiliary
power requirements. Generally only batteries or compressed air are required.

Availability

Reciprocating engines have typically demonstrated availability in excess of 95 percent in
stationary power generation applications.

Part-load operation

The high part-load efficiency of reciprocating engines ensures economical operation in
electric load following applications.

Reliability and life

Reciprocating engines have proven to be reliable power generators given proper
maintenance.

Emissions

Diesel engines have relatively high emissions levels of NOx and particulates. However,
natural gas spark ignition engines have improved emissions profiles.

7 Power Systems Research, EnginLinkTM 2013

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2-1

Reciprocating IC Engines


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2.2 Applications

Reciprocating engines are well suited to a variety of distributed generation applications, and are used
throughout industrial, commercial, and institutional facilities for power generation and CHP.
Reciprocating engines start quickly, follow load well, have good part load efficiencies, and generally have
high reliabilities. In many cases, having multiple reciprocating engine units further increases overall
plant capacity and availability. Reciprocating engines have higher electrical efficiencies than gas turbines
of comparable size, and thus lower fuel-related operating costs. In addition, the upfront costs of
reciprocating engine gensets are generally lower than gas turbine gensets in sizes below 20 MW.
Reciprocating engine maintenance costs are generally higher than comparable gas turbines, but the
maintenance can often be handled by in-house staff or provided by local service organizations.

2.2.1 Combined Heat and Power

There are over 2,000 active reciprocating engine combined heat and power (CHP) installations in the
U.S. providing nearly 2.3 gigawatts (GW) of power capacity8. These systems are predominantly spark
ignition engines fueled by natural gas and other gaseous fuels (biogas, landfill gas). Natural gas is lower
in cost than petroleum based fuels and emissions control is generally more effective using gaseous fuels.
Reciprocating engine CHP systems are commonly used in universities, hospitals, water treatment
facilities, industrial facilities, and commercial and residential buildings. Facility capacities range from 30
kW to 30 MW, with many larger facilities comprised of multiple units. Spark ignited engines fueled by
natural gas or other gaseous fuels represent 84 percent of the installed reciprocating engine CHP
capacity.

Thermal loads most amenable to engine-driven CHP systems in commercial/institutional buildings are
space heating and hot water requirements. The simplest thermal load to supply is hot water. The
primary applications for CHP in the commercial/institutional and residential sectors are those building
types with relatively high and coincident electric and hot water demand such as colleges and
universities, hospitals and nursing homes, multifamily residential buildings, and lodging. If space heating
needs are incorporated, office buildings, and certain warehousing and mercantile/service applications
can be economical applications for CHP. Technology development efforts targeted at heat activated
cooling/refrigeration and thermally regenerated desiccants expand the application of engine-driven CHP
by increasing the thermal energy loads in certain building types. Use of CHP thermal output for
absorption cooling and/or desiccant dehumidification could increase the size and improve the
economics of CHP systems in already strong CHP markets such as schools, multifamily residential
buildings, lodging, nursing homes and hospitals. Use of these advanced technologies in other sectors
such as restaurants, supermarkets and refrigerated warehouses provides a base thermal load that opens
these sectors to CHP application.

Reciprocating engine CHP systems usually meet customer thermal and electric needs as in the two
hypothetical examples below:

• A typical commercial application for reciprocating engine CHP is a hospital or health care facility
with a 1 MW CHP system comprised of multiple 200 to 300 kW natural gas engine gensets. The

8 ICF CHP Installation Database. Maintained for Oak Ridge National Laboratory by ICF International. 2013. http://www.eea-
inc. com/chpdata/index. h tml

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system is designed to satisfy the baseload electric needs of the facility. Approximately 1.6 MW
of thermal energy (MWth), in the form of hot water, is recovered from engine exhaust and
engine cooling systems to provide space heating and domestic hot water to the facility as well as
to drive absorption chillers for space conditioning during summer months. Overall efficiency of
this type of CHP system can exceed 70 percent.

• A typical industrial application for engine CHP would be a food processing plant with a 2 MW
natural gas engine-driven CHP system comprised of multiple 500 to 800 kW engine gensets. The
system provides baseload power to the facility and approximately 2.2 MWth low pressure steam
for process heating and washdown. Overall efficiency for a CHP system of this type approaches
75 percent.

2.2.2	Emergency/Standby Generators

Reciprocating engine emergency/standby generators are used in a wide variety of settings from
residential homes to hospitals, scientific laboratories, data centers, telecommunication equipment, and
modern naval ships. Residential systems include portable gasoline fueled spark-ignition engines or
permanent installations fueled by natural gas or propane. Commercial and industrial systems more
typically use diesel engines. The advantages of diesel engines in standby applications include low
upfront cost, ability to store on-site fuel if required for emergency applications, and rapid start-up and
ramping to full load. Because of their relatively high emissions of air pollutants, such diesel systems are
generally limited in the number of hours they can operate. These systems may also be restricted by
permit from providing any other services such as peak-shaving.

2.2.3	Peak Shaving

Engine generators can supply power during utility peak load periods thereby providing benefits to both
the end user and the local utility company. The facility can save on peak power charges and the utility
can optimize operations and minimize investments in generation, transmission, and distribution that are
used only 0-200 hours/year. In a typical utility peak shaving program, a utility will ask a facility to run its
on-site generator during the utility's peak load period, and in exchange, the utility will provide the
facility with monthly payments.

2.3 Technology Description
2.3.1 Basic Processes

There are two primary reciprocating engine designs relevant to stationary power generation
applications - the spark ignition Otto-cycle engine and the compression ignition Diesel-cycle engine. The
essential mechanical components of the Otto-cycle and Diesel-cycle are the same. Both use a cylindrical
combustion chamber in which a close fitting piston travels the length of the cylinder. The piston
connects to a crankshaft that transforms the linear motion of the piston into the rotary motion of the
crankshaft. Most engines have multiple cylinders that power a single crankshaft.

The main difference between the Otto and Diesel cycles is the method of igniting the fuel. Spark ignition
engines (Otto-cycle) use a spark plug to ignite a pre-mixed air fuel mixture introduced into the cylinder.
Compression ignition engines (Diesel-cycle) compress the air introduced into the cylinder to a high

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pressure, raising its temperature to the auto-ignition temperature of the fuel that is injected at high
pressure.

Engines are further categorized by crankshaft speed in revolutions per minute (rpm), operating cycle (2-
or 4-stroke), and whether turbocharging is used. Reciprocating engines are also categorized by their
original design purpose, such as automotive, truck, industrial, locomotive and marine. Hundreds of
small-scale stationary power, CHP, irrigation, and chiller applications use automotive engine models.
These are generally low-priced engines due to the economies of scale of large production volumes.

Truck engines have the cost benefit of production volume and are designed for a reasonably long life
(e.g., one million miles). A number of truck engines are available as stationary engines. Engines intended
for industrial use are designed for durability and for a wide range of mechanical drive and electric power
applications. Their sizes range from 20 kW up to 6 MW, including industrialized truck engines in the 200
to 600 kW range and industrially applied marine and locomotive engines above 1 MW.

There are 2-cycle engines in stationary power applications, particularly in standby service. However,
most spark ignition and the diesel engines relevant to stationary power generation applications
complete a power cycle in four strokes of the piston within the cylinder as shown in Figure 2-1.

1.	Intake stroke - introduction of air (diesel) or air-fuel mixture (spark ignition) into the cylinder.

2.	Compression stroke - compression of air or an air-fuel mixture within the cylinder. In diesel engines,
the fuel is injected at or near the end of the compression stroke (top dead center or TDC), and
ignited by the elevated temperature of the compressed air in the cylinder. In spark ignition engines,
the compressed air-fuel mixture is ignited by an ignition source at or near TDC.

3.	Power stroke - acceleration of the piston by the expansion of the hot, high pressure combustion
gases.

4.	Exhaust stroke - expulsion of combustion products from the cylinder through the exhaust port.

Figure 2-1.4-Stroke Reciprocating Engine Cycle

STROKE 2
COMPRESSION

STROKE 4
EXHAUST

Source: http://www.globalspec.com/learnmore/motion_controls/engines_components/industrial_engines

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2.3.2 Components

2.3.2.1 Engine System
Natural Gas Spark Ignition Engines

Current natural gas engines for power generation offer low first cost, fast start-up, proven reliability
when properly maintained, excellent load-following characteristics, and significant heat recovery
potential. Electric efficiencies of natural gas engines range from 30 percent LHV (27 percent HHV) for
small stoichiometric engines (<100 kW) to over 46 percent LHV (42 percent HHV) for large lean burn
engines (> 3 MW).9,10 Waste heat recovered from the hot engine exhaust and from the engine cooling
systems produces either hot water or low pressure steam for CHP applications. Overall CHP system
efficiencies (electricity and useful thermal energy) of up to 80 percent (HHV) can be achieved.

Spark ignition engines use spark plugs, with a high-intensity spark of timed duration, to ignite a
compressed fuel-air mixture within the cylinder. Natural gas is the predominant spark ignition engine
fuel used in electric generation and CHP applications. Other gaseous and volatile liquid fuels, ranging
from landfill gas to propane to gasoline, can be used with the proper fuel system, engine compression
ratio, and tuning. American manufacturers began to develop large natural gas engines for the
burgeoning gas transmission industry after World War II. Smaller engines were developed (or converted
from diesel blocks) for gas gathering and other stationary applications as the natural gas infrastructure
developed. Natural gas engines for power generation applications are primarily 4-stroke engines,
available in sizes up to about 18 MW.

Depending on the engine size, one of two ignition techniques ignites the natural gas:

•	Open chamber - the spark plug tip is exposed in the combustion chamber of the cylinder,
directly igniting the compressed fuel-air mixture. Open chamber ignition is applicable to any
engine operating near the stoichiometric air/fuel ratio for up to moderately lean mixtures.11

•	Precombustion chamber - a staged combustion process where the spark plug is housed in a
small chamber mounted on the cylinder head. This cylinder is charged with a rich mixture of fuel
and air, which upon ignition shoots into the main combustion chamber in the cylinder as a high
energy torch. This technique provides sufficient ignition energy to light off very lean fuel-air
mixtures used in large bore engines.12

The simplest natural gas engines operate with a natural aspiration of air and fuel into the cylinder (via a
carburetor or other mixer) by the suction of the intake stroke. High performance natural gas engines are

9	The exact ratio of air to fuel that is required for complete combustion is called the stoichiometric ratio. If there is less or more
air than needed for complete combustion the engine is called rich burn or lean burn respectively.

10	Most efficiencies quoted in this report are based on higher heating value (HHV), which includes the heat of condensation of
the water vapor in the combustion products. In engineering and scientific literature the lower heating value (LHV-which does
not include the heat of condensation of the water vapor in the combustion products) is often used. The HHV is greater than the
LHV by approximately 10% with natural gas as the fuel (i.e., 50% LHV is equivalent to 45% HHV). Higher Heating Values are
about 6% greater for oil (liquid petroleum products) and 5% for coal.

11	Stoichiometric ratio is the chemically correct ratio of fuel to air for complete combustion, i.e., there is no unused fuel or
oxygen after combustion.

12	Lean mixture is a mixture of fuel and air in which an excess of air is supplied in relation to the amount needed for complete
combustion; similarly, a rich mixture is a mixture of fuel and air in which an excess of fuel is supplied in relation to the amount
needed for complete combustion.

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turbocharged to force more air into the cylinders. Natural gas spark ignition engines operate at modest
compression ratios (compared with diesel engines) in the range of 9:1 to 12:1 depending on engine
design and turbocharging.

Using high energy ignition technology, very lean fuel-air mixtures can be burned in natural gas engines,
lowering peak temperatures within the cylinders, and resulting in reduced NOx emissions. The lean burn
approach in reciprocating engines is analogous to dry low-NOx combustors in gas turbines. All major
natural gas engine manufacturers offer lean burn, low emission models and are engaged in R&D to
further improve their performance.

Natural gas spark ignition engine efficiencies are typically lower than diesel engines because of their
lower compression ratios. However, large, high performance lean burn engine efficiencies can exceed
those of diesel engines of the same size. Natural gas engine efficiencies range from about 28 percent
(LHV) for small engines (<50 kW) to 46 percent (LHV) for the largest high performance, lean burn
engines. Lean burn engines tuned for maximum efficiency may produce twice the NOx emissions as the
same engine tuned for minimum NOx. Tuning for low NOx typically results in a sacrifice of 1 to 1.5
percentage points in electric generating efficiency from the highest level achievable.

Many natural gas spark ignition engines are derived from diesel engines (i.e., they use the same block,
crankshaft, main bearings, camshaft, and connecting rods as the diesel engine). However, natural gas
spark ignition engines operate at lower brake mean effective pressure (BMEP) and peak pressure levels
to prevent knock.13 Due to the derating effects from lower BMEP, the spark ignition versions of smaller
diesel engines may produce only 60 to 80 percent of the power output of the parent diesel.
Manufacturers often enlarge cylinder bore by about 5 to 10 percent to increase the power to levels
which meet or exceed their diesel counterparts. The $/kW capital costs of large, high performance
natural gas spark ignition engines are typically on a similar level to the diesel engines from which they
were derived. However, by operating at lower cylinder pressure and bearing loads as well as in the
cleaner combustion environment of natural gas, spark ignition engines generally offer the benefits of
extended component life compared to their diesel parents.

2.3.2.2 Diesel Engines

Diesel engines have historically been the most common type of reciprocating engine for both small and
large power generation applications. However, in the United States and other industrialized nations,
diesel engines are increasingly restricted to emergency standby or limited duty-cycle service because of
air emission concerns and also because of the high cost of fuel. Consequently, the natural gas-fueled SI
engine is now the engine of choice for the higher duty cycle stationary power market (over 500 hr/yr)
and is the primary focus of this report.

Compression ignition diesel engines are among the most efficient simple-cycle power generation
options on the market. Efficiency levels increase with engine size and range from about 30 percent
(HHV) for small high-speed diesels up to 42 to 48 percent (HHV) for the large bore, slow speed engines.
High speed diesel engines (>=1,000 rpm) are available for up to about 4 MW in size. Low speed diesel

13 Brake mean effective pressure (BMEP) can be regarded as the "average" cylinder pressure on the piston during the power
stroke and is a measure of the effectiveness of engine power output or mechanical efficiency.

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engines (60 to 275 rpm) are available as large as 80 MW. Medium speed diesel engines (400 - 1000 rpm)
are available for up to approximately 17 MW.

Diesel engines typically require compression ratios of 12:1 to 17:1 to heat the cylinder air to a
temperature at which the injected fuel will ignite. The quality of fuel injection significantly affects diesel
engine operating characteristics, fuel efficiency, and emissions. Fine atomization and good fuel
dispersion by the injectors are essential for rapid ignition, ideal combustion and emissions control.
Manufacturers are increasingly moving toward electronically controlled, high pressure injection systems
that provide more precise calibration of fuel delivery and accurate injection timing.

Depending on the engine and fuel quality, diesel engines produce 5 to 20 times the NOx (on a ppmv
basis) of a lean burn natural gas engine. Diesel engines on marine engines often emit over 20 lbs
NOx/MWh and present on road engines emit less than 13 lbs NOx/MWh. New diesel engines will achieve
rates of approximately 0.65 lb NOx/MWh. Diesel engines also produce assorted heavy hydrocarbons and
particulate emissions. However, diesel engines produce significantly less CO than lean burn gas engines.
The NOx emissions from diesels burning heavy oil are typically 25 to 30 percent higher than diesels using
distillate oil. Common NOx control techniques include delayed fuel injection, exhaust gas recirculation,
water injection, fuel-water emulsification, inlet air cooling, intake air humidification, and compression
ratio and/or turbocharger modifications. In addition, an increasing number of larger diesel engines are
equipped with selective catalytic reduction and oxidation catalyst systems for post-combustion
emissions reduction.

High speed diesel engines generally require high quality fuel oil with good combustion properties. No. 1
and No. 2 distillate oil comprise the standard diesel fuels. Ultra-low sulfur diesel with sulfur contents of
less than 0.15 ppm is now required for the new Tier 4 diesel engines to reduce sulfur emissions. High
speed diesel engines are not suited to burning oil heavier than distillate. Heavy fuel oil requires more
time for combustion and the combination of high speed and contaminants in lower quality heavy oils
cause excessive wear in high speed diesel engines. Many medium and low speed diesel designs burn
heavier oils including low grade residual oils or Bunker C oils.

2.3.2.3 Dual Fuel Engines

Dual fuel engines are predominantly fueled by natural gas with a small percentage of diesel oil added.
There are two main configurations for introducing the gaseous fuel in a dual fuel engine. These engines
can be purpose built or conversions of diesel engines. Such engines can be switched to 100 percent
diesel operation. Dual fuel engines provide a multi-use functionality. Operation on predominantly
cheaper and cleaner burning natural gas allows the engine to be used in CHP and peak shaving
applications, while operation on 100 percent diesel allows the engine to also meet the onsite fuel
requirements of emergency generators. The dual function adds benefit in applications that have specific
emergency generator requirements such as in hospitals or in public buildings.

There are three main configurations for introducing the gaseous and pilot diesel fuel: 1) low pressure
injection with the intake air, 2) high pressure injection after the intake air has been compressed by the
piston, and 3) micropilot prechamber introduction of the diesel fuel. New dual-fuel engines are offered
in oil and gas production markets to reduce operating costs. Dual-fuel retrofits of existing diesel engines
are also offered as a means to reduce both operating costs and emissions for extending the hours of use

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for limited duty engines such as emergency and peaking applications. Dual fuel is not widely used for
CHP applications.

2.3.2.4 Heat Recovery

The economics of engines in on-site power generation applications often depend on effective use of the
thermal energy contained in the exhaust gas and cooling systems, which generally represents 60 to 70
percent of the inlet fuel energy. Most of the waste heat is available in the engine exhaust and jacket
coolant, while smaller amounts can be recovered from the lube oil cooler and the turbocharger's
intercooler and aftercooler (if so equipped). As shown in the previous table, 45 to 55 percent of the
waste heat from engine systems is recovered from jacket cooling water and lube oil cooling systems at a
temperature too low to produce steam. This feature is generally less critical in commercial/institutional
applications where it is more common to have hot water thermal loads. Steam can be produced from
the exhaust heat if required (maximum pressure of 400 psig), but if no hot water is needed, the amount
of heat recovered from the engine is reduced and total CHP system efficiency drops accordingly.

Heat in the engine jacket coolant accounts for up to 30 percent of the energy input and is capable of
producing 190 to 230 °F hot water. Some engines, such as those with high pressure or ebullient cooling
systems, can operate with water jacket temperatures of up to 265°F. Engine exhaust heat represents 30
to 50 percent of the available waste heat. Exhaust temperatures for the example systems range from
720 to 1000°F. By recovering heat in the cooling systems and exhaust, around 80 percent of the fuel's
energy can be effectively utilized to produce both power and useful thermal energy.

Closed-loop cooling systems - The most common method of recovering engine heat is the closed-loop
cooling system as shown in Figure 2-2. These systems are designed to cool the engine by forced
circulation of a coolant through engine passages and an external heat exchanger. An excess heat
exchanger transfers engine heat to a cooling tower or a radiator when there is excess heat generated.
Closed-loop water cooling systems can operate at coolant temperatures from 190 to 250°F. Depending
on the engine and CHP system's requirements, the lube oil cooling and turbocharger after-cooling may
be either separate or part of the jacket cooling system.

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Figure 2-2. Closed-Loop Heat Recovery System

Ebullient Cooling Systems - Ebullient cooling systems cool the engine by natural circulation of a boiling
coolant through the engine. This type of cooling system is typically used in conjunction with exhaust
heat recovery for production of low-pressure steam. Cooling water is introduced at the bottom of the
engine where the transferred heat begins to boil the coolant generating two-phase flow. The formation
of bubbles lowers the density of the coolant, causing a natural circulation to the top of the engine.

The coolant at the engine outlet is maintained at saturated steam conditions and is usually limited to
250°F and a maximum of 15 psig. Inlet cooling water is also near saturation conditions and is generally 2
to 3°F below the outlet temperature. The uniform temperature throughout the coolant circuit extends
engine life and contributes to improved combustion efficiencies.

Exhaust Heat Recovery - Exhaust heat is typically used to generate hot water of up to about 230°F or
steam up to 400 psig. Only a portion of the exhaust heat can be recovered since exhaust gas
temperatures are generally kept above temperature thresholds to prevent the corrosive effects of
condensation in the exhaust piping. For this reason, most heat recovery units are designed for a 250 to
350°F exhaust outlet temperature.

Exhaust heat recovery can be independent of the engine cooling system or coupled with it. For example,
hot water from the engine cooling can be used as feedwater or feedwater preheat to the exhaust
recovery unit. In a typical district heating system, jacket cooling, lube oil cooling, single stage
aftercooling, and exhaust gas heat recovery are all integrated for steam production.

2.4 Performance Characteristics

Table 2-2 summarizes performance characteristics for typical commercially available natural gas spark
ignition engine CHP systems over a 100 kW to 9 MW size range. This size range covers the majority of
the market applications for engine-driven CHP. Heat rates and efficiencies shown were taken from
manufacturers' specifications and industry publications. Available thermal energy was taken directly
from vendor specifications or, if not provided, calculated from published engine data on engine exhaust

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temperatures and engine jacket and lube system coolant flows. CHP thermal recovery estimates are
based on producing hot water for process or space heating needs.

Most reciprocating engine manufacturers typically assign three power ratings to engines depending on
the intended load service:

•	Standby - continuous full or cycling load for a relatively short duration (usually less than 100
hours) - maximum power output rating

•	Prime - continuous operation for an unlimited time (except for normal maintenance
shutdowns), but with regular variations in load - 80 to 85 percent of the standby rating

•	Baseload - continuous full-load operation for an unlimited time (except for normal maintenance
shutdowns) - 70 to 75 percent of the standby rating.

The ratings shown are for baseload operation.

Table 2-2. Gas Spark Ignition Engine CHP - Typical Performance Parameters

Cost & Performance Characteristics14

System

1

2

3

4

5

Baseload Electric Capacity (kW)

100

633

1,121

3,326

9,341

Total Installed Cost in 2013 ($/kW)15

$2,900

$2,837

$2,366

$1,801

$1,433

Electrical Heat Rate (Btu/kWh), HHV16

12,637

9,896

9,264

8,454

8,207

Electrical Efficiency (%), HHV

27.0%

34.5%

36.8%

40.4%

41.6%

Engine Speed (rpm)

2,50017

1,800

1,800

1,50018

720

Fuel Input (MMBtu/hr), HHV

1.26

6.26

10.38

28.12

76.66

Required Fuel Gas Pressure (psig)

0.4-1.0

> 1.16

> 1.74

> 1.74

75

CHP Characteristics











Exhaust Flow (1000 Ib/hr)

1.2

7.89

13.68

40.17

120

Exhaust Temperature (Fahrenheit)

1,200

941

797

721

663

Heat Recovered from Exhaust (MMBtu/hr)

0.21

1.48

2

5.03

10

Heat Recovered from Cooling Jacket (MMBtu/hr)

0.46

0.72

1.29

1.63

4.27

Heat Recovered from Lube System (MMBtu/hr)

Incl.

0.27

0.44

1.12

5.0

Heat Recovered from Intercooler (MMBtu/hr)

n/a

0.31

0.59

2.89

7.54

Total Heat Recovered (MMBtu/hr)

0.67

2.78

4.32

10.67

26.81

Total Heat Recovered (kW)

196

815

1,266

3,126

7857

14	Characteristics are for representative natural gas engine gensets commercially available in 2013. Data based on (1) Tecogen
Inverde Ultra 100, (2) GE Jenbacher (GEJ) JMS-312C65; (3) GEJ JMS-416B85, (4) GEJ JMS-620F01, and (5) Wartsila 20V34SG

15	Details on installed costs are provided later in Table 2-4.

16	All engine manufacturers quote heat rates in terms of the lower heating value (LHV) of the fuel. However the purchase price
of fuels on an energy basis is measured on a higher heating value basis (HHV). For natural gas, the average heat content is 1030
Btu/scf on an HHV basis and 930 Btu/scf on an LHV basis - a ratio of approximately 0.9 (LHV / HHV).

17	At rated load. The unit operates at variable speeds from 1,000 to 3,000 rpm, with a peak output of 125 kW while producing
60 Hz power through the inverter.

18	The unit operates through a gearbox to produce 60 Hz power.

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Table 2-2. Gas Spark Ignition Engine CHP - Typical Performance Parameters

Cost & Performance Characteristics14

System

1

2

3

4

5

Form of Recovered Heat

H20

H20

H20

H20

H20, steam

Total Efficiency [%)19

80.0%

78.9%

78.4%

78.3%

76.5%

Thermal Output / Fuel Input [%)

53.0%

44.4%

41.6%

37.9%

35.0%

Power / Heat Ratio20

0.51

0.78

0.89

1.06

1.19

Source: Compiled by ICFfrom vendor supplied data.

The data in the table show that electrical efficiency increases as engine size becomes larger. As electrical
efficiency increases, the absolute quantity of thermal energy available to produce useful thermal energy
decreases per unit of power output, and the ratio of power to heat for the CHP system generally
increases. A changing ratio of power to heat impacts project economics and may affect the decisions
that customers make in terms of CHP acceptance, sizing, and the desirability of selling power.

2.4.1 Part Load Performance

In power generation and CHP applications, reciprocating engines generally drive synchronous generators
at constant speed to produce steady alternating current (AC) power. As load is reduced, the heat rate of
spark ignition engines increases and efficiency decreases. Figure 2-3 shows the part load efficiency curve
for a typical lean burn natural gas engine. The efficiency at 50 percent load is approximately 8 to 10
percent less than full load efficiency. As the load decreases further, the curve becomes somewhat
steeper. While gas engines compare favorably to gas turbines, which typically experience efficiency
decreases of 15 to 25 percent at half load conditions, multiple engines may be preferable to a single
large unit to avoid efficiency penalties where significant load reductions are expected on a regular basis.
Diesel engines exhibit even more favorable part load characteristics than spark ignition engines. The
efficiency curve for diesel engines is comparatively flat between 50 and 100 percent load.

19	Total CHP Efficiency = (net electric generated + net thermal energy recovered)/total engine fuel input.

20	Power/Heat Ratio = (CHP electric power output (Btus))/useful thermal output (Btus)

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Figure 2-3. Part Load Generator Terminal Efficiency, System 5



Wartsila 20V34SG Generator Terminal Efficiency, LHV



E

1

' VIA

|

















































w **

¦ 1 449%

7%







42JW

















MA
MA

ilOW

















¦















si jm































26 30 40 50 60 7

lOAO(%|

0 to » 100

Source: Wartsila21

2.4.2	Effects of Ambient Conditions on Performance

Reciprocating engines are generally rated at ISO conditions of 77 °F and 0.987 atmospheres (1 bar)
pressure. (Gas turbines are rated at 59 °F.) Like gas turbines, reciprocating engine performance -
measured for both output and efficiency - degrades as ambient temperature or site elevation increases.
While the effect on gas turbines can be significant, it is less so on engines. Reciprocating engine
efficiency and power are reduced by approximately 4 percent per 1,000 feet of altitude above 1,000
feet, and about 1 percent for every 10°F above 77°F.

2.4.3	Engine Speed Classifications

Reciprocating engines are classified as high-, medium-, or low-speed. Table 2-3 presents the standard
speed ranges in each class and the types and sizes of engines available. Engine driven electric generators
typically must run at fixed (or synchronous) speeds to maintain a constant 50 or 60 Hertz (Hz) output,
setting the engine speed needed within the classifications (i.e., a 60 Hz generator driven by a high speed
engine would require engine speeds of 1200, 1800 or 3600 rprn versus a 50 Hz generator which requires
engine speeds of 1000, 1500 or 3000 rpm).

21 Wartsila gas-fired engines, http://www.wartsila.com/en/power-plants/technology/combustion-engines/gas-engines.

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Table 2-3. Reciprocating Engine Types by Speed (Available MW Ratings)

Speed
Classification

Engine Speed

Stoic/Rich Burn,
Spark Ignition22

Lean Burn, Spark
Ignition

Dual Fuel

Diesel

High Speed

1000-3600 rpm

0.01-1.5 MW

0.15-3.0 MW

1.0-3.5 MW23

0.01-3.5 MW

Medium
Speed

275-1000 rpm

None

1.0-18 MW

1.0-17 MW

0.5-18 MW

Low Speed

58-275 rpm

None

None

2.0-65 MW

2-84 MW

Source: SFA Pacific, Inc., Wartsila

Engine power output is partly proportional to engine speed, which affords high speed engines the
highest output per unit of displacement (cylinder size) and the highest power density. Consequently,
high speed engines generally have the lowest $/kW production costs of the three types. The cost
benefits of high speed engines must be weighed against other factors. Smaller high speed engines have
lower efficiencies than large bore, lower speed engines due in part to the higher surface area to volume
ratio for small cylinders resulting in slightly higher heat losses. In addition, higher speed engines tend to
have higher wear rates, resulting in shorter periods between minor and major overhauls. These factors
are often less important than capital costs for limited duty cycle applications.

Medium speed stationary power engines are largely derived from marine and locomotive engines.
Medium speed engines are higher in cost, but generally higher in efficiency than high speed engines.
Because of their massive physical size and high cost of installation, low speed engines are increasingly
being displaced by medium and high speed engines as the primary choice for stationary power
applications; with low speed engines being left to their primary market as marine propulsion engines.

Most reciprocating engine manufacturers typically assign three power ratings to engines depending on
the intended load service:

•	Standby - continuous full or cycling load for a relatively short duration (usually less than 100
hours) - maximum power output rating.

•	Prime - continuous operation for an unlimited time (except for normal maintenance
shutdowns), but with regular variations in load - 80 to 85 percent of the standby rating.

•	Baseload - continuous full-load operation for an unlimited time (except for normal maintenance
shutdowns) - 70 to 75 percent of the standby rating.

2.4.4 Performance and Efficiency Enhancements

2.4.4.1 Brake Mean Effective Pressure (BMEP) and Engine Speed

Engine power is related to engine speed and the BMEP during the power stroke. BMEP, as described
above, can be regarded as an "average" cylinder pressure on the piston during the power stroke, and is
a measure of the effectiveness of engine power output or mechanical efficiency. Engine manufacturers
often include BMEP values in their product specifications. Typical BMEP values are as high as 320 psig
for large natural gas engines and 350 psig for diesel engines. Corresponding peak combustion pressures

22	Stoichiometric or rich burn combustion is required for the use of 3-way catalytic converters for emissions control.

23	Micropilot, prechamber dual fuel engines

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are about 2,400 psig and 2,600 psig respectively. High BMEP levels increase power output, improve
efficiency, and result in lower capital costs ($/kW).

BMEP can be increased by raising combustion cylinder air pressure through increased turbocharging,
improved aftercooling, and reduced pressure losses through improved air passage design. These factors
all increase air charge density and raise peak combustion pressures, translating into higher BMEP levels.
However, higher BMEP increases thermal and pneumatic stresses within the engine, and proper design
and testing is required to ensure continued engine durability and reliability.

2.4.4.2 Turbocharging

Essentially all modern engines above 300 kW are turbocharged to achieve higher power densities. A
turbocharger is basically a turbine-driven intake air compressor. The hot, high velocity exhaust gases
leaving the engine cylinders power the turbine. Very large engines typically are equipped with two
turbochargers. On a carbureted engine, turbocharging forces more air and fuel into the cylinders, which
increases the engine output. On a fuel injected engine, the mass of fuel injected must be increased in
proportion to the increased air input. Cylinder pressure and temperature normally increase as a result of
turbocharging, increasing the tendency for detonation for both spark ignition and dual fuel engines and
requiring a careful balance between compression ratio and turbocharger boost level. Turbochargers
normally boost inlet air pressure on a 3:1 to 4:1 ratio. A wide range of turbocharger designs and models
are used. Heat exchangers (called aftercoolers or intercoolers) are normally used on the discharge air
from the turbocharger to keep the temperature of the air to the engine under a specified limit.
Intercooling on forced induction engines improves volumetric efficiency by increasing the density of
intake air to the engine (i.e. cold air charge from intercooling provides denser air for combustion thus
allowing more fuel and air to be combusted per engine stroke increasing the output of the engine).

2.4.5 Capital Costs

This section provides typical study estimates for the installed cost of natural gas spark-ignited,
reciprocating engine-driven generators in CHP applications. Capital costs (equipment and installation)
are estimated for the five typical engine genset systems ranging from 100 kW to 9 MW. These are
"typical" budgetary price levels; it should also be noted that installed costs can vary significantly
depending on the scope of the plant equipment, geographical area, competitive market conditions,
special site requirements, emissions control requirements, prevailing labor rates, and whether the
system is a new or retrofit application.

The basic generator package consists of the engine connected directly to a generator without a gearbox.
In countries where 60 Hz power is required, the genset operates at multiples of 60 - typically 1800 rpm
for smaller engines, and 900 or 720 or 514 rpm for the large engines. In areas where 50 Hz power is used
such as Europe and Japan, the engines run at speeds that are multiples of 50 - typically 1500 rpm for the
small engines. In Table 2-4, System 4 is based on a German design, and operates at 1,500 rpm and
produces 60 Hz power through a gearbox. The smaller engines are skid mounted with a basic control
system, fuel system, radiator, fan, and starting system. Some smaller packages come with an enclosure,
integrated heat recovery system, and basic electric paralleling equipment. The cost of the basic engine
genset package plus the costs for added systems needed for the particular application comprise the
total equipment cost. The total plant cost consists of total equipment cost plus installation labor and

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materials (including site work), engineering, project management (including licensing, insurance,
commissioning and startup), and financial carrying costs during the 4 to 18 month construction period.
All engines are in low NOx configuration. System 1, a stoichiometric (rich burn) engine, uses a three-way
catalyst to reduce emissions to their final level. The other systems are all lean burn engines and are
shown with a SCR, CO catalyst, and continuous emissions monitoring system (CEMS) that are required in
environmentally sensitive areas such as Southern California and the Northeastern U.S.

Table 2-4 provides cost estimates for combined heat and power applications based on a single unit
engine. The CHP system is assumed to produce hot water, although the multi-megawatt size engines are
capable of producing low-pressure steam. The heat recovery equipment consists of the exhaust
economizer that extracts heat from the exhaust system, process heat exchanger for extracting heat from
the engine jacket coolant, circulation pump, control system, and piping. These cost estimates include
interconnection and paralleling. The package costs are intended to reflect a generic representation of
popular engines in each size category. The interconnection/electrical costs reflect the costs of paralleling
a synchronous generator for the larger systems. The 100 kW system uses an inverter based generator
that has been pre-certified for interconnection in most areas. Labor/materials represent the labor cost
for the civil, mechanical, and electrical work as well as materials such as ductwork, piping, and wiring.
Project and construction management also includes general contractor markup and bonding, and
performance guarantees. Contingency is assumed to be 5 percent of the total equipment cost in all
cases. Cost estimates for multiple unit installations have lower unit costs than single unit installations.

Table 2-4. Estimated Capital Cost for Typical Gas Engine Generators in Grid

Interconnected CHP Applications

Capital Cost, $/kW

System

1

2

3

4

5

Nominal Capacity (kW)

100

633

1121

3326

9341

Equipment (Costs in 2013 ($/kW))

Gen Set Package

$1,400

$400

$375

$350

$575

Heat Recovery

$250

$500

$500

$500

$175

Interconnect/Electrical

$250

$140

$100

$60

$25

Exhaust Gas Treatment



$750

$500

$230

$150

Total Equipment

$1,900

$1,790

$1,475

$1,140

$925

Labor/Materials

$500

$448

$369

$285

$231

Total Process Capital

$2,400

$2,238

$1,844

$1,425

$1,156

Project and Construction
Management

$125

$269

$221

$171

$139

Engineering and Fees

$250

$200

$175

$70

$30

Project Contingency

$95

$90

$74

$57

$46

Project Financing

$30

$42

$52

00

r*>

$62

Total Plant Cost ($/kW)

$2,900

$2,837

$2,366

$1,801

$1,433

Source: Compiled by ICFfrom vendor-supplied data

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2.4.6 Maintenance

Maintenance costs vary with type, speed, size and number of cylinders of an engine. These costs
typically include:

•	Maintenance labor

•	Engine parts and materials such as oil filters, air filters, spark plugs, gaskets, valves, piston rings,
electronic components, etc. and consumables such as oil

•	Minor and major overhauls.

Maintenance can either be done by in-house personnel or contracted out to manufacturers,
distributors, or dealers under service contracts. Full maintenance contracts (covering all recommended
service) generally cost between 1 to 2.5 cents/kWh depending on engine size, speed and service. Many
service contracts now include remote monitoring of engine performance and conditions in addition to
allowing for predictive maintenance. Service contract rates typically are all-inclusive, including the travel
time of technicians on service calls.

Recommended service is comprised of routine short interval inspections/adjustments and periodic
replacement of engine oil and filters, coolant, and spark plugs (typically 500 to 2,000 hours). An oil
analysis is part of most preventative maintenance programs to monitor engine wear. A top-end overhaul
is generally recommended between 8,000 and 30,000 hours of operation (see Table 2-5) that entails a
cylinder head and turbocharger rebuild. A major overhaul is performed after 30,000 to 72,000 hours of
operation and involves piston/liner replacement, crankshaft inspection, bearings, and seals.

Maintenance intervals are shown in Table 2-5.

Table 2-5. Representative Overhaul Intervals for Natural Gas Engines in

Baseload Service



Time Between Overhaul (thousand operating hours)
as a Function of Engine Speed (rpm)

720 rpm

900 rpm

1200 rpm

1500 rpm

1800 rpm

Minor Overhaul

>30

15-36

24-36

10-20

8-15

Major Overhaul

>60

40-72

48-60

30-50

30-36

Source: SFA Pacific, Inc.

Maintenance costs presented in Table 2-6 are based on engine manufacturer estimates for service
contracts consisting of routine inspections and scheduled overhauls of the engine generator set. Costs
are based on 8,000 annual operating hours expressed in terms of annual electricity generation. Engine
maintenance can be broken into fixed components that need to be performed on a recurring basis
regardless of the engine run time and variable components that depend on the hours of operation. The
vendors quoted all O&M costs on a variable basis for a system in baseload operation.

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Table 2-6. Typical Natural Gas Engine Maintenance Costs ($2013/kWh)



System

1

2

3

4

5

Nominal Capacity (kW]

100

633

1121

3326

9341

Service Contract

$0,023 - $0,025

$0,020

$0,018

$0,015

$0.0075

Consumables

included

$0,001

$0,001

$0,001

.001

Total O&M Costs, 2013 $/kWh

$0,023 - $0,025

$0,021

$0,019

$0,016

.0085

Source: Compiled by ICFfrom vendor supplied data

2.4.7 Fuels

In addition to operation on natural gas, spark ignition engines operate on a variety of alternative
gaseous fuels including:

•	Liquefied petroleum gas (LPG) - propane and butane mixtures

•	Sour gas - unprocessed natural gas as it comes directly from the gas well

•	Biogas - any of the combustible gases produced from biological degradation of organic wastes,
such as landfill gas, sewage digester gas, and animal waste digester gas

•	Industrial waste gases - flare gases and process off-gases from refineries, chemical plants and
steel mill

•	Manufactured gases - typically low- and medium-Btu gas produced as products of gasification
or pyrolysis processes

Factors that impact the operation of a spark ignition engine with alternative gaseous fuels include:

•	Volumetric heating value - Since engine fuel is delivered on a volume basis, fuel volume into
the engine increases as heating value decreases, requiring engine derating on fuels with lower
Btu content. Derating is more pronounced with naturally aspirated engines, and depending on
air requirements, turbocharging partially or totally compensates.

•	Autoignition characteristics and detonation tendency for fuels with lower octane rating such
as propane - This is often characterized by a calculated value known as the Methane Number
(MN). Different manufacturers may calculate Methane Number differently. Gases with heavier
hydrocarbon components (Propane, Ethane, Butane, etc.) have a lower Methane Number as
they will tend to autoignite more easily.

•	Contaminants that may impact engine component life or engine maintenance, or result in air
pollutant emissions that require additional control measures.

•	Hydrogen-containing fuels may require special measures (generally if hydrogen content by
volume is greater than 5 percent) because of hydrogen's unique flammability and explosion
characteristics.

Table 2-7 presents representative constituents of some of the alternative gaseous fuels compared to
natural gas. Industrial waste and manufactured gases are not included in the table because their
compositions vary widely depending on their source. They typically contain significant levels of H2
and/or CO. Other common constituents are C02, water vapor, one or more light hydrocarbons, and H2S
or S02.

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Table 2-7. Major Constituents and LHV of Gaseous Fuels

Fuel Component / LHV

Natural Gas

LPG

Digester Gas

Landfill Gas

Methane, CH4, % vol.

80-97

0

35-65

40-60

Ethane, C2H6, % vol.

3-15

0-2

0

0

Propane, C3Hs, % vol.

0-3

75-97

0

0

Butane,C4Hio, % vol.

0-0.9

0-2

0

0

Higher CxH2x+2, % vol.

0-0.2

0 - 2024

0

0

C02, % vol.

0-1.8

0

30-40

40-60

N2, % vol.

0-14

0

1-2

0-13

H2, % vol.

0-0.1

0

0

0

LHV, (Btu/scf)

830 - 1075

2500

300 - 600

350 - 550

Source: SFA Pacific, Inc.; North American Combustion Handbook

Contaminants are a concern with many waste fuels, specifically acid gas components (H2S, halogen
acids, HCN; ammonia; salts and metal-containing compounds; organic halogen-, sulfur-, nitrogen-, and
silicon-containing compounds such as siloxanes); and oils. In combustion, halogen and sulfur compounds
form halogen acids, S02, some S03 and possibly H2S04emissions. The acids can also corrode
downstream equipment. A substantial fraction of any fuel nitrogen oxidizes into NOx in combustion. To
prevent corrosion and erosion of components, solid particulates must be kept to very low
concentrations. Various fuel scrubbing, droplet separation and filtration steps will be required if any fuel
contaminant levels exceed manufacturers specifications. Landfill gas in particular often contains chlorine
compounds, sulfur compounds, organic acids, and silicon compounds, which dictate pretreatment.

Once treated and acceptable for use in the engine, emissions performance profiles on alternative fuels
are similar to natural gas engine performance. Specifically, the low emissions ratings of lean burn
engines can usually be maintained on alternative fuels.

2.4.7.1	Liquefied Petroleum Gas

Liquefied petroleum gas (LPG) is composed primarily of propane and/or butane. While propane and
butane ratings are higher than gasoline, most stationary spark ignition engines are designed with higher
compression ratios that optimize operation with natural gas and its associated high methane number.
Use of fuels with lower methane numbers like LPG in natural gas engines requires retarding of ignition
timing and other appropriate adjustments to avoid detonation (knocking). LPG often serves as a back-up
fuel where there is a possibility of interruption in the natural gas supply. Off-spec LPG may require
cooling to condense out larger volumes of butane or heavier hydrocarbons that would aggravate engine
knock. High butane content LPG is recommended only for low compression, naturally aspirated engines.

2.4.7.2	Field Gas

Field gas often contains more than 5 percent by volume of heavy ends (butane and heavier), as well as
water, salts and H2S and usually requires some scrubbing before use in natural gas engines. Cooling may
be required to reduce the concentrations of butane and heavier components. Field gas usually contains

24 High levels of heavier hydrocarbons are found in LPG derived from refinery processing

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some propane and normally is used in low compression engines (both naturally aspirated and
turbocharged). Retarded ignition timing eliminates detonation.

2.4.7.3	Biogas

Biogases (landfill gas and digester gas) are predominantly mixtures of methane and C02 with HHV in the
range of 300 to 700 Btu/scf. Landfill gas also contains a variety of contaminants as discussed earlier.
Biogases are produced essentially at or somewhat below atmospheric pressure so must be compressed
for delivery to the engine. After compression, cooling and scrubbing or filtration are required to remove
compressor oil, condensate, and any particulates that may have been entrained in the original gas.
Scrubbing with a caustic solution may be required if acid gases are present. Because of the additional
requirements for raw gas treatment, biogas powered engine facilities are more costly to build and
operate than natural gas-based systems.

A key contaminant in biogas is a class of compounds called siloxanes, a subgroup of silicones containing
Si-0 bonds with organic radicals. These compounds are widely used for a variety of industrial processes
and are also commonly added to consumer products, including detergents, shampoos, cosmetics, paper
coatings, and textiles. Siloxanes in wastewater do not break down in wastewater treatment facilities or
in landfills. As sludge undergoes anaerobic digestion, it may be subjected to temperatures of up to 150
°F. At these temperatures, siloxanes volatilize and enter the gas stream. Subjected to the heat of
combustion in a reciprocating engine (turbine or microturbine), siloxanes leave behind hard deposits of
silica on pistons and valve assemblies causing abrasion and impact damage that reduce the life and
efficiency of the engine. Siloxanes need to be removed using refrigeration or sorbents such as activated
carbon, alumina, synthetic resins, or liquid sorbents.25

For engines operating on biogas, additional capital investment is required for this fuel clean-up,
compression, and sometimes derating of the engine capacity due to the lower thermal energy content
of the fuel. For a 1,000 kW reciprocating engine, the added equipment and installation cost is about
$600/kW.26 Smaller systems can require nearly the same amount of equipment, so unit costs go up
rapidly on smaller installations.

Improved engine design and hardened valve seats reduce siloxane damage on engines, thereby reducing
the need for complete removal.

2.4.7.4	Industrial Waste Gases

Industrial waste gases that are common used as reciprocating engine fuels include refinery gases and
process off-gases. Refinery gases typically contain components such as H2, CO, light hydrocarbons, H2S,
and ammonia, as well as C02 and N2. Process off-gases include a wide variety of compositions. Generally,
waste gases are medium- to low-Btu content. Medium-Btu gases generally do not require significant
engine derating; low-Btu gases usually require derating.

25	Dick McCarrick, "Siloxanes and Biogas," Environmental Leader (online edition), July 10, 2012.
http://www.environmentalleader.com/2012/07/10/siloxanes-and-biogas/

26	Opportunities for and Benefits of Combined Heat and Power at Wastewater Treatment Facilities, Eastern Research Group and
EE A, Inc. (now ICF) for the U.S. EPA, 2007.

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Depending on their origin and contaminants, industrial gases sometimes require pretreatment
comparable to that applied to raw landfill gas. Particulates (e.g., catalyst dust), oils, condensable gases,
water, C4+ hydrocarbons and acid gases may all need to be removed. Process offgases are usually
available at pressures of several atmospheres or higher, which are generally satisfactory for delivery to
an on-site or nearby reciprocating engine facility.

2.4.8 System Availability

The percentage of time that a system is either up and running or available for use is referred to as its
availability. Systems are unavailable during periods of scheduled maintenance or forced outages.
Reciprocating engines are maintenance intensive but, they can provide high levels of availability, even in
high load factor applications. While natural gas engine availabilities vary with engine type, speed and
fuel quality, Table 2-8 illustrates typical availability numbers based on a survey of natural gas engine
gensets in CHP applications.

Table 2-8. Availabilities and Outage Rates for Natural Gas Engines

Reciprocating Engines

< 100 kW

100-800 kW

800-9000 kW

Systems Surveyed

14

8

18

Availability, %

97.93%

95.99%

98.22%

Forced Outage Rate, %

1.76%

1.98%

0.85%

Scheduled Outage Rate, %

0.73%

2.47%

1.12%

Source: ICF27

Some engine manufacturers offer engine exchange programs or other maintenance options that
increase the ability to promptly deliver and install replacement units on short notice, typically increasing
facility availabilities to greater than 95 percent. The use of multiple units or back-up units at a site can
further increase the availability of the overall facility over 99 percent.

2.5 Emissions and Emissions Control Options

Emissions of criteria pollutants - oxides of nitrogen (NOx), carbon monoxide (CO), and volatile organic
compounds (VOCs - unburned, non-methane hydrocarbons) - are the primary environmental concern
with reciprocating engines operating on natural gas. Emissions of sulfur compounds (SOx) depend only
on the sulfur content of the fuel. SOx emissions are an issue only in large, slow speed diesels firing heavy
oils. SOx emissions from natural gas engines are assumed to be less than 0.0006 Ib/MMBtu.28 Particulate
matter (PM) can be an important pollutant for engines using liquid fuels. Ash and metallic additives in
the fuel contribute to PM in the exhaust. Particulate emissions from 4-stroke lean burn natural gas
engines are 4,000 times lower than for an uncontrolled diesel engine.

27	Distributed Generation Operational Reliability and Availability Database, EEA, Inc. (now part of ICF), January 2004

28	EPA AP-42, Natural Gas Fired Reciprocating Engines.

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2.5.1 Emissions Characteristics

2.5.1.1	Nitrogen Oxides (NOx)

NOx emissions are usually the primary concern with natural gas engines and are a mixture of (mostly)
NO and N02 in variable composition. In measurement, NOx is reported as parts per million by volume in
which both species count equally (e.g., ppmv at 15 percent 02, dry). Other common units for reporting
NOx in reciprocating engines are g/hp-hr and g/kWh, or as an output rate such as Ib/hr. Among natural
gas engine options, lean burn natural gas engines produce the lowest NOx emissions directly from the
engine. However, rich burn engines can more effectively make use of three way catalysts (TWC) to
produce very low emissions. If lean burn engines must meet extremely low emissions levels, as in
California CARB 2007 standards of .07 Ib/MWh then selective catalytic reduction must be added. Rich
burn engines would qualify for this standard by taking a CHP credit for avoided boiler emissions. Lean
burn engines can meet the standard using selective catalytic reduction (SCR). Both rich burn and lean
burn engines have been certified for operation in Southern California meeting the stringent California
Air Resources Board (CARB) 2007 standards.

The control of peak flame temperature through lean burn conditions has been the primary combustion
approach to limiting NOx formation in gas engines. Diesel engines produce higher combustion
temperatures and more NOx than lean burn gas engines, even though the overall diesel engine air/fuel
ratio may be very lean. There are three reasons for this: (1) heterogeneous near-stoichiometric
combustion; (2) the higher adiabatic flame temperature of distillate fuel; and (3) fuel-bound nitrogen.29
The diesel fuel is atomized as it is injected and dispersed in the combustion chamber. Combustion
largely occurs at near-stoichiometric conditions at the air-droplet and air-fuel vapor interfaces, resulting
in maximum temperatures and higher NOx. In contrast, lean-premixed homogeneous combustion used
in lean burn gas engines results in lower combustion temperatures and lower NOx production.

For any engine there are generally trade-offs between low NOx emissions and high efficiency. There are
also trade-offs between low NOx emissions and emissions of the products of incomplete combustion (CO
and unburned hydrocarbons). There are three main approaches to these trade-offs that come into play
depending on regulations and economics. One approach is to control for lowest NOx accepting a fuel
efficiency penalty and possibly higher CO and hydrocarbon emissions. A second option is finding an
optimal balance between emissions and efficiency. A third option is to design for highest efficiency and
use post-combustion exhaust treatment.

2.5.1.2	Carbon Monoxide (CO)

CO and VOCs both result from incomplete combustion. CO emissions result when there is inadequate
oxygen or insufficient residence time at high temperature. Cooling at the combustion chamber walls and
reaction quenching in the exhaust process also contribute to incomplete combustion and increased CO
emissions. Excessively lean conditions can lead to incomplete and unstable combustion and high CO
levels. Therefore, control of NOx through lean combustion can increase CO and VOC emissions out of the
engine.

29 Kirby Chapman, Cost Effective Reciprocating Engine Emissions Control and Monitoring for E&P Field and Gathering Engines,
Kansas State University, 2003.

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2.5.1.3	Unburned Hydrocarbons

Volatile hydrocarbons also called volatile organic compounds (VOCs) can encompass a wide range of
compounds, some of which are hazardous air pollutants. These compounds are discharged into the
atmosphere when some portion of the fuel remains unburned or just partially burned. Some organics
are carried over as unreacted trace constituents of the fuel, while others may be pyrolysis products of
the heavier hydrocarbons in the gas. Volatile hydrocarbon emissions from reciprocating engines are
normally reported as non-methane hydrocarbons (NMHCs).

2.5.1.4	Carbon Dioxide (CO2)

While not considered a pollutant in the ordinary sense of directly affecting health, emissions of carbon
dioxide (C02) are of concern due to its contribution to climate change. The amount of C02 emitted is a
function of both fuel carbon content and system efficiency. The fuel carbon content of natural gas is 34
lbs carbon/MMBtu; oil is 48 lbs carbon/MMBtu; and (ash-free) coal is 66 lbs carbon/MMBtu. As
converted to C02 in the exhaust, these values are 117 Ib/MMBtu for natural gas, 160 Ib/MMBtu for
diesel oil, and 205-226 Ib/MMBtu for coal.

2.5.2 Emissions Control Options

Emissions from natural gas SI engines have improved significantly in the last decade through better
design and control of the combustion process and through the use of exhaust catalysts. Advanced lean
burn natural gas engines are available that produce NOx levels as low 1.8 Ib/MWh and CO emissions of
8.1lb/MWh before any exhaust gas treatment. Adding selective catalytic reduction (SCR) and a CO
oxidation catalyst can allow lean burn reciprocating engines to meet the very stringent California South
Coast emissions standards of 0.07 Ib/MWh for NOx and 1.0 Ib/MWh for CO.

NOx control has been the primary focus of emission control research and development in natural gas
engines. The following provides a description of the most prominent emission control approaches.

2.5.2.1 Combustion Process Emissions Control

Control of combustion temperature has been the principal focus of combustion process control in gas
engines. Combustion control requires tradeoffs - high temperatures favor complete burn up of the fuel
and low residual hydrocarbons and CO, but promote NOxformation. Lean combustion dilutes the
combustion process and reduces combustion temperatures and NOxformation, and allows a higher
compression ratio or peak firing pressures resulting in higher efficiency. However, if the mixture is too
lean, misfiring and incomplete combustion occur, increasing CO and VOC emissions.

Lean burn engine technology was developed during the 1980s as a direct response to the need for
cleaner burning gas engines. As discussed earlier, thermal NOx formation is a function of both flame
temperature and residence time. The focus of lean burn developments was to lower combustion
temperature in the cylinder using lean fuel/air mixtures. Lean combustion decreases the fuel/air ratio in
the zones where NOx is produced so that peak flame temperature is less than the stoichiometric
adiabatic flame temperature, therefore suppressing thermal NOx formation. Most lean burn engines use
turbocharging to supply excess air to the engine and produce the homogeneous lean fuel-air mixtures.
Lean burn engines generally use 50 to 100 percent excess air (above stoichiometric). The typical
uncontrolled emissions rate for lean burn natural gas engines is between 1.5-6.0 Ib/MWh.

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As discussed above, an added performance advantage of lean burn operation is higher output and
higher efficiency. Optimized lean burn operation requires sophisticated engine controls to ensure that
combustion remains stable and NOx reduction is maximized while minimizing emissions of CO and VOCs.
Table 2-9 shows data for a large lean burn natural gas engine that illustrates the tradeoffs between NOx
emissions control and efficiency. At the lowest achievable NOx levels (45 to 50 ppmv), almost 1.5
percentage points are lost on full rated efficiency.

Table 2-9. Uncontrolled NOx Emissions versus Efficiency Tradeoffs

Engine Characteristics

Low NOx

High Efficiency

Capacity (MW)

9.3

9.3

Speed (rpm)

720

720

Efficiency, LHV (percent)

44.1

45.7

Emissions:

NOx (g/kWh)

0.62

1.2

(ppmv @ 15% 02)

45

90

CO (g/kWh)

1.9

1.3

(ppmv @15% 02)

226

158

NMHC (g/kWh)

1.0

0.71

(ppmv @ 15% 02)

209

153

Data Source: Based on engine manufacturer's data - Wartsila 20V34SG Prechamber Lean Burn Gas
Engine30

Combustion temperature can also be controlled to some extent in reciprocating engines by one or more
of the following techniques:

•	Delaying combustion by retarding ignition or fuel injection.

•	Diluting the fuel-air mixture with exhaust gas recirculation (EGR), which replaces some of the air
and contains water vapor that has a relatively high heat capacity and absorbs some of the heat
of combustion.

•	Introducing liquid water by direct injection or via fuel oil emulsification - evaporation of the
water cools the fuel-air mixture charge.

•	Reducing the inlet air temperature with a heat exchanger after the turbocharger or via inlet air
humidification.

•	Modifying valve timing, compression ratio, turbocharging, and the combustion chamber
configuration.

Water injection and EGR reduce diesel NOx emissions 30 to 60 percent from uncontrolled levels. The
incorporation of water injection and other techniques to lean burn gas engines is the focus of ongoing
R&D efforts for several engine manufacturers and is being pursued as part of the Department of

30 Wartsila Gas-fired Engines, http://www.wartsila.com/en/power-plants/technology/combustion-engines/gas-
engines#expandable_id

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Energy's Advanced Reciprocating Engine Systems (ARES) program. One of the goals of the program is to
develop a 45 percent efficient (HHV) medium sized natural gas engine operating at 0.3 lb NOx/MWh (0.1
g NOx/bhph).

2.5.2.2 Post-Combustion Emissions Control

There are several types of catalytic exhaust gas treatment processes that are applicable to various types
of reciprocating engines. Table 2-10 shows the methods in use today, the applicable engine types, and
the pollutant reduction achievable.

Table 2-10. Post-Combustion Exhaust Gas Cleanup Options

Emission Control Technology

Applicable Engine
Type

Typical Performance Reductions, %

CO

NMHC

NOx

PM

Diesel Oxidation Catalyst
(DOC)

Diesel

90

80

0

20

Catalyzed Diesel Particulate
Filter (DPF)

Diesel

90

90

0

90+

Non-selective Catalytic
Reduction (NSCR)

Rich Burn Natural

Gas

90

80

95

0

NG Oxidation Catalyst

Lean Burn Natural

Gas

95

95

0

0

Selective Catalytic Reduction
(SCR)

Lean Burn Diesel or
Natural Gas

0

0

95

0

Reference: Jay Warner and Gary Bremigan, System Solutions for Optimizing Exhaust Emission Control Systems,

Universal Acoustic & Emissions Control Technologies USA, 2010

2.5.2.3	Oxidation Catalysts

Oxidation catalysts generally are precious metal compounds that promote oxidation of CO and
hydrocarbons to C02 and H20 in the presence of excess 02. CO and non-methane hydrocarbon analyzer
(NMHC) conversion levels of 95 percent are achievable. Methane conversion may approach 60 to 70
percent. Oxidation catalysts are now widely used with all types of engines, including diesel engines. They
are being used increasingly with lean burn gas engines to reduce their relatively high CO and
hydrocarbon emissions.

2.5.2.4	Diesel Particulate Filter

While not an issue for spark ignition engines firing gaseous fuels, compression ignition engines fueled by
diesel or heavy oil produce particulates that must be controlled. Diesel particulate filters can reduce
over 90 percent of particulate (soot) emissions from diesel engines. There are a variety of filter materials
and regeneration strategies used. Currently, there are no commercially available particulate control
devices available for large, medium speed diesel engines.31

2.5.2.5	Three-Way Catalyst (Non Specific Catalytic Reduction)

The catalytic three-way conversion process (TWC) is the basic automotive catalytic converter process
that reduces concentrations of all three major criteria pollutants - NOx, CO, and VOCs. The TWC is also

31 Private Communication, Wartsila, January 2014.

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called non-selective catalytic reduction (NSCR). NOx and CO reductions are generally greater than 90
percent, and VOCs are reduced approximately 80 percent in a properly controlled TWC system. Because
the conversions of NOx to N2, the conversion of CO and hydrocarbons to C02 and H20 will not take place
in an atmosphere with excess oxygen (exhaust gas must contain less than 0.5 percent 02), TWCs are only
effective with stoichiometric or rich-burning engines. Typical "engine out" NOx emission rates for a rich
burn engine are 10 to 15 gm/bhp-hr. NOx emissions with TWC control are as low as 0.15 g/bhp-hr.

Stoichiometric and rich burn engines have significantly lower efficiency than lean burn engines (higher
carbon emissions) and only certain sizes (<1.5 MW) and high speeds are available. The TWC system also
increases maintenance costs by as much as 25 percent. TWCs are based on noble metal catalysts that
are vulnerable to poisoning and masking, limiting their use to engines operated with clean fuels (e.g.,
natural gas and unleaded gasoline). In addition, the engines must use lubricants that do not generate
catalyst poisoning compounds and have low concentrations of heavy and base metal additives.

Unburned fuel, unburned lube oil, and particulate matter can also foul the catalyst. TWC technology is
not applicable to lean burn gas engines or diesels.

2.5.2.6 Selective Catalytic Reduction (SCR)

This technology selectively reduces NOx to N2 in the presence of a reducing agent. NOx reductions of 80
to 90 percent are achievable with SCR. Higher reductions are possible with the use of more catalyst or
more reducing agent, or both. The two agents used commercially are ammonia (NH3 in anhydrous liquid
form or aqueous solution) and aqueous urea. Urea decomposes in the hot exhaust gas and SCR reactor,
releasing ammonia. Approximately 0.9 to 1.0 mole of ammonia is required per mole of NOx at the SCR
reactor inlet in order to achieve an 80 to 90 percent NOx reduction.

SCR systems are considered commercial today and represent the only technology that will reduce NOx
emissions to the levels required in Southern California and the Northeast U.S. Still, SCR adds significantly
to the capital and operating cost of a reciprocating engine CHP system. As shown previously in Table
2-4, SCR with oxidation catalyst and associated continuous energy monitoring system adds between
$150-$700/kW to the capital cost for a lean burn reciprocating engine CHP installation. The cost burden
is higher for smaller engines.

2.5.3 Gas Engine Emissions Treatment Comparison

Table 2-11 shows achievable emissions for each of the five representative gas engine systems. The
emissions presented assume available exhaust treatment. System 1, the 100 kW engine, is a high speed,
rich burn engine. Use of a TWC system with EGR provides NOx emissions of just under 0.07 lb NOx per
MWh after credit is taken for the thermal energy provided.32 The Lean burn engine systems use an
SCR/CO system providing emissions reduction that meets the CARB 2007 emissions limits without
consideration of the thermal energy credit.

With current commercial technology, highest efficiency and lowest NOx are not achieved
simultaneously. Therefore many manufacturers of lean burn gas engines offer different versions of an
engine - a low NOx version and a high efficiency version - based on different tuning of the engine

32 CARB 2007 emissions regulations allow CHP systems to include both the electric and thermal output in the calculation of
output based emissions.

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controls and ignition timing. With the addition of SCR after-treatment, described below, some
manufacturers tune engines for higher efficiency and allow the SCR system to remove the additional
NOx. Achieving highest efficiency operation results in conditions that generally produce twice the NOx as
low NOx versions (e.g., 3 Ib/MWh versus 1.5 Ib/MWh). Achieving the lowest NOx typically entails sacrifice
of 1 to 2 points in efficiency (e.g., 38 percent versus 36 percent). In addition, CO and VOC emissions are
higher in engines optimized for minimum NOx.

Table 2-11. Gas Engine Emissions Characteristics with Available Exhaust

Control Options

Emissions

System

1

2

3

4

5

Nominal Capacity (kW)

100

633

1121

3326

9341

Electrical Efficiency (% HHV)

27.0%

34.5%

36.8%

40.4%

41.6

Engine Combustion

Rich

Rich

Lean

Lean

Lean

Precatalyst Emissions

NOx (Ib/MWh)



1.77

1.77

1.77

2.6433

CO (Ib/MWh)



8.12

8.12

8.12

4.18

VOC (Ib/MWh)



0.97

0.97

0.97

1.39

Post Catalyst Emissions

NOx (Ib/MWh)

0.070

0.07

0.07

0.07

.07

CO (Ib/MWh)

0.200

0.20

0.20

0.20

.20

VOC, (Ib/MWh)

0.1

0.10

0.10

0.10

.10

C02 Gross (Ib/MWh)

1,479

1,158

1,084

989

988

C02 Net (Ib/MWh)

499

516

520

520

540

Source: Compiled by ICFfrom vendor supplied data

2.6 Future Developments

Reciprocating engines have improved significantly over the last two decades in terms of increased
efficiency and reduced emissions. Electronic engine control and improved combustion chamber design,
including the use of precombustion chambers, allow engines to operate on leaner fuel mixtures.
Improvements in materials and design have allowed engines to operate at higher speeds and power
densities while still maintaining long life.

These improvements have been the combined results of collaborative research efforts by private
industry, universities, and the federal government. Public private partnerships such as the DOE
Advanced Reciprocating Engine System (ARES) funded by DOE and the Advanced Reciprocating Internal
Combustion Engine (ARICE) program funded by the California Energy Commission (CEC) have focused
attention on the development of the next generation reciprocating engine.

33 The Wartsila engine shown here (System 5) when matched with SCR is tuned for best efficiency at the expense of higher
uncontrolled NOx - letting the SCR remove the NOx. This strategy results in lower overall operating costs.

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The ARES program has been active for more than 10 years. The program has produced and
commercialized Phase I and Phase II engines with current work on a Phase III engine to reach the overall
design efficiency goals of 0.1 g/bhp NOx emissions, 50 percent BTE efficiency, 80+ percent CHP
efficiency, maintenance costs of $0.01/kWh while maintaining cost competitiveness.34

For a technology originally developed in the 19th century, reciprocating internal combustion engines
have continually improved and adapted to the needs of the market more than 100 years later. Ongoing
improvements in efficiency, cost, and emissions reduction will ensure that reciprocating engines will
continue to remain viable and competitive with newer technologies such as fuel cells and microturbines
in the distributed generation market. Installations of multiple large engines have proven to be
competitive in power generation applications of more than 200 MW.

34 Industrial Distributed Energy R&D Portfolio Report: Summary, U.S. Department of Energy Advanced Manufacturing Office,
June 2011.

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Section 3. Technology Characterization - Combustion Turbines

3.1	Introduction

Gas turbines have been in use for stationary electric power generation since the late 1930s. Turbines
went on to revolutionize airplane propulsion in the 1940s, and since the 1990s through today, they have
been a popular choice for new power generation plants in the United States.

Gas turbines are available in sizes ranging from 500 kilowatts (kW) to more than 300 megawatts (MW)
for both power-only generation and combined heat and power (CHP) systems. The most efficient
commercial technology for utility-scale power plants is the gas turbine-steam turbine combined-cycle
plant that has efficiencies of more than 60 percent (measured at lower heating value [LHV]35). Simple-
cycle gas turbines used in power plants are available with efficiencies of over 40 percent (LHV). Gas
turbines have long been used by utilities for peaking capacity. However, with changes in the power
industry and advancements in the technology, the gas turbine is now being increasingly used for base-
load power.

Gas turbines produce exhaust heat at high temperatures that can be recovered in a CHP configuration to
produce steam for process use. Such CHP configurations can reach overall system efficiencies (electricity
and useful thermal energy) of 70 to 80 percent. By the early 1980s, the efficiency and reliability of
smaller gas turbines (1 to 40 MW) had progressed sufficiently to be an attractive choice for industrial
and large institutional users for CHP applications.

Gas turbines have very low emissions compared to other fossil-powered generation technologies. With
catalytic exhaust cleanup or lean pre-mixed combustion, some large gas turbines achieve emissions of
oxides of nitrogen (NOx) well below 10 parts per million (ppm).36 Because of their relatively high
efficiency and the reliance on natural gas as a primary fuel, gas turbines emit substantially less carbon
dioxide (C02) per kilowatt-hour (kWh) generated than other fossil technology in commercial use.37

3.2	Applications

Gas turbines are used in a variety of stationary applications:

• Electric utility central station power generation - Gas turbines are used widely by the electric
utility industry. Combined cycle turbine plants contribute to base-load power needs, and simple
cycle turbines are used for meeting peak-load. Today, gas turbines comprise 32 percent, or 315
gigawatts (GW), of central station power plant capacity

35	Most of the efficiencies quoted in this report are based on higher heating value (HHV), which includes the heat of
condensation of the water vapor in the combustion products. In engineering and scientific literature concerning heat engine
efficiencies the lower heating value (LHV - which does not include the heat of condensation of the water vapor in the
combustion products) is usually used. The HHV is greater than the LHV by approximately 10 percent with natural gas as the fuel
(e.g., 50 percent LHV is equivalent to 55 percent HHV). HHV efficiencies are about 8 percent greater for oil (liquid petroleum
products) and 5 percent for coal.

36	Volumetric emissions for gas turbines are measured at 15 percent oxygen in the exhaust.

37	Fuel cells, which produce electricity from hydrogen and oxygen, emit only water vapor. There are emissions associated with
producing the hydrogen supply depending on its source. However, most fuel cell technologies are still being developed, with
only one type (phosphoric acid fuel cell) commercially available in limited production.

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•	Combined heat and power - Gas turbines are used extensively for CHP applications providing
efficient, economic, and reliable service. Gas turbines comprise 63 percent, or 51.5 GW, of total
installed CHP capacity in the U.S.38 Close to 80 percent of this gas turbine CHP capacity is in large
combined cycle plants that maximize the export of power to the electrical grid.39 The remaining
GT CHP capacity is made up of simple-cycle gas turbine based CHP systems, typically less than 40
MW.

•	Mechanical drive - Oil and gas production, processing, transmission, and some process
industries use gas turbines for pumping, compression, and other mechanical drive operations. In
mechanical power applications, the turbine shaft power is used directly. There is no electrical
generator, though there can be heat recovery, and such systems can be classified as CHP.

•	Distributed power-only - Gas turbines are used for distributed power generation at remote
oilfield facilities and can be used by industry and utilities alike for portable power generation.
Large industrial facilities install simple-cycle gas turbines without heat recovery to provide
peaking power in capacity constrained areas, and utilities often place gas turbines in the 5 to 40
MW size range at substations to provide incremental capacity and grid support. A number of
turbine manufacturers and packagers offer mobile turbine generator units in the 5-40 MW size
range that can be used in one location during a period of peak demand and then transported to
another location for the following season.

Gas turbines are ideally suited for CHP applications because their high-temperature exhaust can be used
to generate process steam at conditions as high as 1,200 pounds per square inch gauge (psig) and 900 °F
or used directly in industrial processes for heating or drying. A typical industrial CHP application for gas
turbines is a chemical plant with a 25 MW simple cycle gas turbine supplying base-load power to the
plant with an unfired heat recovery steam generator (HRSG) on the exhaust. This gas turbine CHP
system will produce approximately 29 MW thermal (MWth) of steam for process use within the plant.

A typical commercial/institutional CHP application for gas turbines is a college or university campus with
a 5 MW simple-cycle gas turbine. Approximately 8 MWth of 150 psig to 400 psig steam (or hot water) is
produced in an unfired heat recovery steam generator and sent to a central thermal loop for campus
space heating during the winter, or to single-effect absorption chillers to provide cooling during the
summer.

3.3 Technology Description
3.3.1 Basic Process

Gas turbine systems operate on the Brayton thermodynamic cycle, a constant pressure open cycle heat
engine. The Brayton cycle consists of a compressor, a combustion chamber, and an expansion turbine.
The compressor heats and compresses the inlet air which is then further heated by the addition of fuel
in the combustion chamber. The hot air and combustion gas mixture drives the expansion turbine
producing enough energy to provide shaft-power to the generator or mechanical process and to drive
the compressor as well. The power produced by an expansion turbine and consumed by a compressor is

38	Electric utility sector gas turbine capacity is from EIA data (2014). CHP gas turbine total capacity based on the ICF CHP
Installations database.

39	ICF CHP Installations Database, 2014

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proportional to the absolute temperature of the gas passing through the device. Consequently, it is
advantageous to operate the expansion turbine at the highest practical temperature consistent with
economic materials and internal blade cooling technology and to operate the compressor with inlet air
flow at as low a temperature as possible. As technology advances permit higher turbine inlet
temperature, the optimum pressure ratio also increases.

There are several variations of the Brayton cycle in use today. Fuel consumption may be decreased by
preheating the compressed air with heat from the turbine exhaust using a recuperator or regenerator.
The compressor work may also be reduced and net power increased by using intercooling or precooling
techniques. In a combined cycle, the exhaust may be used to raise steam in a boiler and to generate
additional power. Figure 3-1 shows the configuration for an unrecuperated industrial gas turbine with
shaft power, driving an electric generator and the exhaust heat powering a heat recovery steam
generator (HRSG) with supplementary firing capability.

Figure 3-1. Gas Turbine Configuration with Heat Recovery

Source: University of Calgary

Gas turbine exhaust is quite hot, up to 800 to 900°F for smaller industrial turbines, and up to 1,100°F for
some new, large central station utility machines and aeroderivative turbines. Such high exhaust
temperatures permit direct use of the exhaust for applications such as combustion air preheating,
drying, or other applications requiring hot air stream. Such direct use of the exhaust is also called closely
coupled CHP. More commonly, the exhaust heat is recovered with the addition of a heat recovery steam
generator, which produces steam or hot water. A portion or all of the steam generated by the HRSG may
be used to generate additional electricity through a steam turbine in a combined cycle configuration.

A gas turbine system is considered to be a combined heat and power (CHP) configuration if the waste
heat (i.e., thermal energy) generated by the turbine is applied in an end-use. For example, a simple-cycle
gas turbine using the exhaust in a direct heating process is a CHP system. A gas turbine system that uses
the turbine exhaust in a HRSG, and then uses the steam from the HRSG to produce electricity in a steam
turbine is a combined cycle unit, and is not considered to be CHP (no end-use thermal need). This latter
configuration is a waste heat-to-power (WHP) system.

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Key gas turbine design characteristics are shown in Table 3-1.

Table 3-1. Gas Turbine Design Characteristics

Thermal output

Gas turbines produce a high quality (high temperature) thermal output suitable for
most combined heat and power applications. High-pressure steam can be generated
or the exhaust can be used directly for process drying and heating. The exhaust can
also be used to produce chilled water using an absorption chiller.

Fuel flexibility

Gas turbines operate on natural gas, synthetic gas, landfill gas, and fuel oils. Plants
typically operate on gaseous fuel with a stored liquid fuel for backup to obtain the
less expensive, interruptible rate for natural gas.

Reliability and life

Modern gas turbines have proven to be reliable power generators given proper
maintenance. Time to overhaul is typically 25,000 to 50,000 hours.

Size range

Gas turbines are available in sizes from 500 kW to over 300 MW.

Emissions

Many gas turbines burning gaseous fuels (mainly natural gas) feature lean premixed
burners (also called dry low-NOxcombustors) that produce NOx emissions below 25
ppm, with laboratory data showing emissions down to 9 ppm, and simultaneous low
CO emissions in the 10 to 50 ppm range.40 Selective catalytic reduction (SCR) or
catalytic combustion can further reduce NOx emissions. Many gas turbines sited in
locales with stringent emission regulations use SCR after-treatment to achieve single-
digit (below 9 ppm) NOx emissions.

Part-load operation

Because gas turbines reduce power output by reducing combustion temperature,
efficiency at part load can be substantially below that of full-power efficiency.

3.3.2 Components

Figure 3-2 shows the primary components of a simple cycle gas turbine.

Figure 3-2. Components of Simple Cycle Gas Turbine

Higher temperature and pressure ratios result in higher efficiency and specific power, or power-to-
weight ratio. Thus, the general trend in gas turbine advancement has been towards a combination of

40 Gas turbines have high oxygen content in their exhaust because they burn fuel with high excess air to limit combustion
temperatures to levels that the turbine blades, combustion chamber and transition section can handle without compromising
system life. Consequently, emissions from gas turbines are evaluated at a reference condition of 15 percent oxygen. For
comparison, boilers use 3 percent oxygen as the reference condition for emissions, because they can minimize excess air and
thus waste less heat in their stack exhaust. Note that due to the different amount of diluent gases in the combustion products,
the NOx measurement of 9 ppm @ 15 percent oxygen is approximately equivalent to 27 ppm @ 3 percent oxygen.

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higher temperatures and pressures. While such advancements increase the manufacturing cost of the
machine, the higher value, in terms of greater power output and higher efficiency, provides net
economic benefits.

3.3.2.1 Types of Gas Turbines

Aeroderivative Gas Turbines

Aeroderivative gas turbines for stationary power are adapted from their jet and turboshaft aircraft
engine counterparts. While these turbines are lightweight and thermally efficient, they are usually more
expensive than products designed and built exclusively for stationary applications. The largest
aeroderivative generation turbines available are 40 to 50 MW in capacity. Many aeroderivative gas
turbines for stationary use operate with compression ratios in the range of 30:1, requiring a high-
pressure external fuel gas compressor. With advanced system developments, larger aeroderivative
turbines (>40 MW) have achieved over 43 percent simple-cycle efficiency (LHV).

Industrial Gas Turbines

Industrial gas turbines, or frame gas turbines, are exclusively for stationary power generation and are
available in capacities from 1 to over 300 MW. They are generally less expensive, more rugged, can
operate longer between overhauls, and are more suited for continuous base-load operation with longer
inspection and maintenance intervals than aeroderivative turbines. However, they are less efficient and
much heavier. Industrial gas turbines generally have more modest compression ratios (up to 16:1) and
often do not require an external fuel gas compressor. Larger industrial gas turbines (>100 MW) are
approaching simple-cycle efficiencies of approximately 40 percent (LHV) and combined-cycle efficiencies
of 60 percent (LHV).

Industrial plants use gas turbines between 500 kW to 40 MW for on-site power generation and for direct
mechanical drive applications. Small gas turbines also drive compressors on long distance natural gas
pipelines. In the petroleum industry, turbines drive gas compressors to maintain well pressures and
provide compression and pumping for refineries and petrochemical plants. In the steel industry,
turbines drive air compressors used for blast furnaces. In process industries such as chemicals, refining
and paper, and in large commercial and institutional applications turbines are used in combined heat
and power mode generating both electricity and steam for use on-site.

3.4 Performance Characteristics

The efficiency of the Brayton cycle is a function of pressure ratio, ambient air temperature, turbine inlet
air temperature, the efficiency of the compressor and turbine elements, turbine blade cooling
requirements, and also any other performance enhancements (i.e., recuperation, intercooling, inlet air
cooling, reheat, steam injection, or combined cycle). All of these parameters, along with gas turbine
internal mechanical design features, continue to improve with time. Therefore newer machines are
usually more efficient than older ones of the same size and general type.

Table 3-2 summarizes performance characteristics for typical commercially available gas turbine CHP
systems over the 3 to 45 MW size range. In the table, note that:

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•	Heat rates shown are from manufacturers' specifications and are net of losses due to inlet and
outlet pressure drop and parasitic power.

•	Available thermal energy (steam output) was calculated from information provided by the
vendors or published turbine data on turbine exhaust temperatures and flows.

•	CHP steam estimates are based on an unfired HRSG producing dry, saturated steam at 150 psig.

•	Total efficiency is defined as the sum of the net electricity generated plus steam produced for
plant thermal needs divided by total fuel input to the system. Higher steam pressures can be
obtained but at slightly lower total efficiencies. Additional steam can be generated and total
efficiency further increased with duct firing in the HRSG (see heat recovery section).

•	To estimate fuel savings effective electrical efficiency is a more useful value than overall
efficiency. Effective electric efficiency is calculated assuming the useful thermal output from the
CHP system would otherwise be generated by an 80 percent efficient boiler. The theoretical
boiler fuel is subtracted from the total fuel input and the remaining fuel input used to calculate
the effective electric efficiency which can then be compared to traditional electric generation.

•	The ratings in the table are all for systems operating in baseload (continuous) duty. Peaking and
emergency power units generally have lower efficiency, lower capital cost, higher emissions,
and are limited in their run hours.

The data in the table show that electrical efficiency generally increases as combustion turbines become
larger. As electrical efficiency increases, the absolute quantity of thermal energy available to produce
steam decreases per unit of power output, and the ratio of power to heat for the CHP system increases.
A changing ratio of power to heat impacts project economics and may affect the decisions that
customers make in terms of CHP acceptance, sizing, and the desirability of selling power. It is generally
recommended to size a CHP system based on a site's thermal load demand; therefore, such power to
heat ratios are important characteristics to consider.

Table 3-2. Typical Performance for Gas Turbines in CHP Operation

Cost & Performance Characteristics41

System

1

2

3

4

5

Net Electricity Capacity (kW)

3,304

7,038

9,950

20,336

44,488

Installed Cost (2013 $/kW)42

$3,281

$2,080

$1,976

$1,518

$1,248

Electric Heat Rate (Btu/kWh), HHV43

14,247

11,807

12,482

10,265

9,488

Electrical Efficiency (%), HHV

23.95%

28.90%

27.34%

33.24%

35.96%

Fuel Input (MMBtu/hr), HHV

47.1

83.1

124.2

208.7

422.1

Required Fuel Gas Pressure (psig)

166.8

299.4

362.3

405.2

538

41	Data based on: 3 MW- Solar Turbines Centaur 40, 7 MW- Solar Taurus 70,10 MW- Solar Mars 100, 20 MW- Solar Titan
250, 45 MW-GE LM6000.

42	Installed costs based on CHP system producing 150 psig saturated steam with an unfired heat recovery steam generator, gas
compression, building, with SCR/CO/CEMS exhaust gas treatment in an uncomplicated installation at a customer site.

43	All turbine and engine manufacturers quote heat rates in terms of the lower heating value (LHV) of the fuel. Electric utilities
measure power plant heat rates in terms of HHV and fuel prices are given in terms of the HHV. The ratio of LHV to HHV is
approximately 0.9 for natural gas.

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Table 3-2. Typical Performance for Gas Turbines in CHP Operation

Cost & Performance Characteristics41

System

1

2

3

4

5

CHP Characteristics

Exhaust Flow (1,000 Ib/hr)

149.2

211.6

334

536

1047

GT Exhaust Temperature (Fahrenheit)

838

916

913

874

861

HRSG Exhaust Temperature (Fahrenheit)

336

303

322

326

300

Steam Output (MMBtu/hr)

19.66

34.44

52.36

77.82

138.72

Steam Output (1,000 Ibs/hr)

19.65

34.42

52.32

77.77

138.64

Steam Output (kW equivalent)

5,760

10,092

15,340

22,801

40,645

Total CHP Efficiency (%), HHV44

65.7%

70.4%

69.5%

70.5%

68.8%

Power/Heat Ratio45

0.57

0.70

0.65

0.89

1.09

Net Heat Rate (Btu/kWh)46

6,810

5,689

5,905

5,481

5,590

Effective Electrical Efficiency (%)47

50%

60%

58%

62%

61%

Thermal Output as Fraction of Fuel Input

0.42

0.41

0.42

0.37

0.33

Electric Output as Fraction of Fuel Input

0.24

0.29

0.27

0.33

0.36

Source: Compiled by ICFfrom vendor-supplied data
3.4.1 Fuel Supply Pressure

As shown previously in Figure 3-2, the fuel gas is mixed with the combustion air after it has been heated
and compressed. Therefore, the fuel gas must also be compressed to a pressure somewhat higher than
the combustion air. This pressure is determined by the turbine pressure ratio. The fuel gas compressor
size and energy requirements are determined not only by the required outlet conditions but also by the
delivery pressure. Depending on the supply pressure of the gas being delivered to the site, the cost and
power consumption of the fuel gas compressor can be a significant consideration. Table 3-3 shows the
power required to compress natural gas from supply pressures typical of commercial and industrial
service to the pressures required by typical industrial gas turbines. Required supply pressures generally
increase with gas turbine size.

44	Total Efficiency = (net electric generated + net steam produced for thermal needs)/total system fuel input

45	Power/Steam Ratio = CHP electrical power output (Btu)/ useful steam output (Btu)

46	Net Heat Rate = (total fuel input to the CHP system - the fuel that would be normally used to generate the same amount of
thermal output as the CHP system output assuming an efficiency of 80 percent)/CHP electric output (kW).

47	Effective Electrical Efficiency = (CHP electric power output) / (total fuel into CHP system - total heat recovered/0.8);
Equivalent to 3,412 Btu/kWh/Net Heat Rate.

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Table 3-3. Power Requirements for Natural Gas Fuel Compression48

Turbine Conditions

System

1

2

3

4

5

Turbine Electric Capacity (kW)

3,304

7,038

9,950

20,336

44,488

Turbine Pressure Ratio

10.1

17.6

17.7

24

31.9

Pressure Required, psig

167

299

362

405

538

Required Compression Power (kW)

55 psig gas supply pressure

51

162

289

538

1,370

150 psig gas supply pressure

21

63

113

211

510

250 psig gas supply pressure

NA

39

70

131

310

Source: Compiled by ICFfrom vendor supplied data
3.4.2 Heat Recovery

The economics of gas turbines as CHP in process applications are highly dependent on effective use of
the thermal energy contained in the exhaust gas. Figure 3-3 provides a schematic representation of a
gas turbine generator with exhaust heat recovery transferring energy to a heat recovery steam
generator (HRSG) that can provide steam for process use or to drive a steam turbine generator. Thermal
energy generally represents 60 to 70 percent of the inlet fuel energy. The most common use of this
energy is for steam generation in unfired or supplementary fired heat recovery steam generators.
However, the gas turbine exhaust gases can also be used as a source of direct process energy, for
unfired or fired process fluid heaters, or as preheated combustion air for power boilers. An unfired
HRSG is the simplest steam CHP configuration and can generate steam up to approximately 1,200 psig.

Figure 3-3. Heat Recovery from a Gas Turbine System

Gas Turbine

As the quality of the steam required satisfying a thermal load increases, the overall system efficiency
decreases. Even with a counter-flow heat exchanger, the HRSG stack temperature increases when the
steam quality increases. For the Solar Taurus 70, an overall efficiency of 80.5 percent is possible with a
HRSG producing 15 psig steam (LHV basis). A system producing 900 psig steam has an overall efficiency

48 Fuel gas supply pressure requirements calculated assuming delivery of natural gas at an absolute pressure 35 percent greater
than the compressor discharge in order to meet the requirements of the gas turbine flow control system and combustor mixing
nozzles. Mass flow of fuel based on the fuel flow of reference gas turbines in the size range considered, and assuming an
electric motor of 95 percent efficiency driving the booster compressor. Gas supply pressures of 50 psig, 150 psig and 250 psig
form the basis of the calculations.

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of 72.8 percent (LHV basis.) The low pressure steam can extract the exhaust energy down to a HRSG
stack temperature of 275 °F; for the high (900 psig) steam requirement, energy can only be extracted
down to a HRSG stack temperature of 380 °F.49

Overall CHP efficiency generally remains high under part load conditions because the lower efficiencies
of electric generation at part load create more heat available for recovery steam making. The same low
pressure steam system described above has an overall efficiency at 50 percent output that is virtually
unchanged from full load operation even though the generation efficiency has dropped from 32.8
percent to 24.8 percent (LHV basis.) However, at 50 percent load the power to heat ratio has dropped
from the full load value of 0.70 to 0.46 indicating that a much higher share of the total energy recovered
is in the form of heat.

Gas turbines operate with a high degree of excess air compared to the stoichiometric ratio50 required
for combustion of the input fuel. Turbine exhaust is typically about 15 percent oxygen. Since very little
of the available oxygen in the turbine air flow is used in the combustion process, the oxygen content in
the gas turbine exhaust permits supplementary fuel firing ahead of the HRSG to increase steam
production relative to an unfired unit. Supplementary firing can raise the exhaust gas temperature
entering the HRSG up to a maximum of 2,800°F and increase the amount of steam produced by the unit
by more than a factor of four. Moreover, since the turbine exhaust gas is essentially preheated
combustion air, the fuel consumed in supplementary firing is less than that required for a stand-alone
boiler providing the same increment in steam generation. The HHV efficiency of incremental steam
production from supplementary firing above that of an unfired HRSG is often 85 percent or more when
firing natural gas.

Supplementary firing also increases system flexibility. Unfired HRSGs are typically convective heat
exchangers that respond solely to exhaust conditions of the gas turbine and do not easily allow for
steam flow control. Supplementary firing capability provides the ability to control steam production,
within the capability of the burner system, independent of the normal gas turbine operating mode. Low
NOx duct burners with guaranteed emissions levels as low as 0.08 lb NOx/MMBtu can be specified to
minimize the NOx contribution of supplemental firing.

3.4.3 Part-Load Performance

When less than full power is required from a gas turbine, the output is reduced by lowering the turbine
inlet temperature. In addition to reducing power, this change in operating conditions also reduces
efficiency. Figure 3-4 shows a typical part-load derate curve. Emissions are generally increased at part
load conditions, especially at half load and below.

49	Vendor supplied performance data.

50	The stoichiometric ratio refers to the amount of one reactant necessary to completely react with other reactant, without
having any input leftover once the reaction has completed.

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*25%

c

<1

o 20%

c

UJ

™ 15%

W

'C

« 10%

UJ

5%

0%

0%	20% 40% 60% 80% 100%

Percent of Full Load

Source: Solar Turbines, Mars 10051
3.4.4 Effects of Ambient Conditions on Performance
3.4.4.1 Ambient Air Temperature

The ambient conditions under which a gas turbine operates have a noticeable effect on both the power
output and efficiency. At elevated inlet air temperatures, both the power and efficiency decrease. The
power decreases due to the decreased air flow mass rate (the density of air declines as temperature
increases), and the efficiency decreases because the compressor requires more power to compress air
of higher temperature. Conversely, the power and efficiency increase when the inlet air temperature is
reduced. Figure 3-5 shows the variation in power and efficiency for the nominal 7.5 MW Solar Taurus 70
gas turbine as a function of ambient temperature. ISO rating conditions for gas turbines are at sea level
and 59 °F. Compared to this rating point, power output drops to 80 percent at 100 °F and increases to
107 percent at 40 °F. The corresponding efficiency effects are down 8 percent and up 2 percent for 100
and 40 °F respectively. The effects of ambient temperature on output and efficiency need to be
considered in the design and evaluation of a gas turbine CHP system because in many parts of the
country, electric prices are highest in the summer when performance of the system is at its lowest.

51 "Mars 100 Gas Turbine Generator Set", Solar Turbines A Caterpillar Company.
https://mysolar.cat.eom/cda/files/126902/7/dsl00pg.pdf

Figure 3-4. Effect of Part Load Operation on Electrical Efficiency

Part Load Performance

35%

30% -I	^

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Figure 3-5. Effect of Ambient Temperature on Capacity and Efficiency

FULL LOAD PERFORMANCE

10,000

9,000

-- 34.0

Selected Operating Point

-	Power with Eva per at we Inlet Cooling

-	Nominal Thermal Efficiency: {©terminals)%

-	Efficiency with Evaporative In let Cooling

20	40	60	80

Engine Inlet Air Temperature,°F

- - 30.0

- - 26.0

- - 24.0

- - 22 .0

Source: Solar TurbinesTaurus 7052

8,000

7,000

6,000

5,000

3.000

2,000

1,000

SITE CONDITIONS:

_ Site Elevation: 0 feet
Relative Humidity: 60%
Inlet Loss: 4.0 "H20
Exhaust Loss: 4.0 "H20

Figure 3-5 also shows how inlet air cooling can help to moderate the loss of power and efficiency at
higher ambient temperatures. The figure shows that cooling the air entering the turbine by 40 to 50°F
on a hot day can increase power output by 15 to 20 percent. The decreased power and efficiency
resulting from high ambient air temperatures can be mitigated by any of several approaches to inlet-air
cooling, including refrigeration, evaporative cooling, and thermal-energy storage using off-peak cooling.

With refrigeration cooling, either a compression driven or thermally activated (absorption chiller)
refrigeration cycle cools the inlet air through a heat exchanger. The heat exchanger in the inlet air
stream causes an additional pressure drop in the air entering the compressor, thereby slightly lowering
cycle power and efficiency. However, as the inlet air is now substantially cooler than the ambient air
there is a significant net gain in power and efficiency. Electric motor compression refrigeration requires
a substantial parasitic power loss. Thermally activated absorption cooling can utilize waste heat from the
gas turbine, reducing the direct parasitic loss. However, the complexity and cost of this approach pose
potential drawbacks in many applications.

Evaporative cooling, which is widely used due to its low capital cost, uses a spray of water directly into
the inlet air stream. Evaporation of the water reduces the temperature of the air. Since cooling is limited
to the wet bulb air temperature, evaporative cooling is most effective when the wet bulb temperature is
appreciably below the dry bulb (ordinary) temperature. Evaporative cooling can consume large

52 "Taurus 70 Gas Turbine Generator Set", Solar Turbines/4 Caterpillar Company.
https://mysolar.cat.eom/cda/files/1987672/7/ds70gs.pdf

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quantities of water, making it difficult to operate in arid climates. A few large gas turbines have
evaporative cooling, which is expected to be used more frequently on smaller machines in the future.

The use of thermal-energy storage systems, such as ice, chilled water, or low-temperature fluids, to cool
inlet air can eliminate most parasitic losses from the augmented power capacity. Thermal energy
storage is a viable option if on-peak power pricing only occurs a few hours a day. In that case, the
shorter time of energy storage discharge and longer time for daily charging allow for a smaller and less
expensive thermal-energy storage system.

3.4.4.2 Site Altitude

The density of air decreases at altitudes above sea level reducing the mass of air that the compressor
section of the turbine can introduce into the combustor. The reduced mass of air flow produces a
corresponding reduction in the power (capacity) that the turbine can generate as shown in Figure 3-6.
The percentage power reduction is the same for all turbines and is not dependent on the turbine size or
the pressure ratio of the compressor. Unlike the effects of increased ambient temperature, which also
produces a reduction in the efficiency of electricity production, altitude changes have only a very slight
impact on efficiency.

Figure 3-6. The Effect of Altitude on Gas Turbine Capacity

Altitude Capacity Derate

120.0% T

£

« 100.0% --

Q.


o

« 60.0% -
a*


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turbine package plus the costs for added systems needed for the particular application comprise the
total equipment cost.

Installed capital costs can vary significantly depending on the scope of the plant equipment,
geographical area, competitive market conditions, special site requirements, emissions control
requirements, prevailing labor rates, whether the system is a new or retrofit application, and whether
the site is a greenfield, or is located at an established industrial site with existing roads, water, fuel,
electric, etc. The cost estimates presented here are meant to represent a basic installation at an
established site. The parameters for the cost estimation are shown in Table 3-4.

Table 3-4. Cost Estimation Parameters

Site Conditions

Fuel

Pipeline quality natural gas

Altitude, temp, RH

ISO rating conditions

Inlet and Outlet Pressure Drop

As operated for CHP with HRSG and SCR

Site Fuel Gas Pressure

55 psig (gas compression required)

Steam Requirements

Max unfired steam flow, 150 lbs, saturated

Condensate Conditions

60% condensate return

212° F condensate return

70° F makeup water

Emissions Requirements

Dry Low NOx combustion with SCR/CO/CEMS

Scope of Supply

Project Management

Engineer, procure, construct, manage

Civil

Buildable site with infrastructure available

Electrical

Switchgear, interconnection, control, transformer

Fuel System

Fuel gas compressor, fuel gas filter, regulator,
heater

Building

Building at $100/square foot

Steam System

Assume the CHP system is tying into an existing
steam system with existing water treatment, de-
aerator, and feed-water pumps

Table 3-5 details estimated capital costs (equipment and installation costs) for the five representative
gas turbine CHP systems. The table shows that there are definite economies of scale for larger turbine
power systems. Turbine packages themselves decline in cost only slightly between the range of 5 to 40
MW, but ancillary equipment such as the HRSG, gas compression, water treatment, and electrical
equipment are much lower in cost per unit of electrical output as the systems become larger.

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Table 3-5. Estimated Capital Cost for Representative Gas Turbine CHP Systems53

Cost Component

System

1

2

3

4

5

Nominal Turbine
Capacity (kW)

3,510

7,520

10,680

21,730

45,607

Net Power Output
(kW)

3,304

7,038

9,950

20,336

44,488

Equipment

Combustion Turbines

$2,869,400

$4,646,000

$7,084,400

$12,242,500

$23,164,910

Electrical Equipment

$1,051,600

$1,208,200

$1,304,100

$1,490,300

$1,785,000

Fuel System

$750,400

$943,000

$1,177,300

$1,708,200

$3,675,000

Heat Recovery Steam
Generators

$729,500

$860,500

$1,081,000

$1,807,100

$3,150,000

SCR, CO, and CEMS

$688,700

$943,200

$983,500

$1,516,400

$2,625,000

Building

$438,500

$395,900

$584,600

$633,400

$735,000

Total Equipment

$6,528,100

$8,996,800

$12,214,900

$19,397,900

$35,134,910

Installation

Construction

$2,204,000

$2,931,400

$3,913,700

$6,002,200

$10,248,400

Total Installed Capital

$8,732,100

$11,928,200

$16,128,600

$25,400,100

$45,383,310

Other Costs

Project/Construction
Management

$678,100

$802,700

$1,011,600

$1,350,900

$2,306,600

Shipping

$137,600

$186,900

$251,300

$394,900

$674,300

Development Fees

$652,800

$899,700

$1,221,500

$1,939,800

$3,312,100

Project Contingency

$400,700

$496,000

$618,500

$894,200

$1,526,800

Project Financing

$238,500

$322,100

$432,700

$899,400

$2,303,500

Total Installed Cost

Total Plant Cost

$10,839,800

$14,635,600

$19,664,200

$30,879,300

$55,506,610

Installed Cost, $/kW

$3,281

$2,080

$1,976

$1,518

$1,248

Source: Compiled by ICF from vendor-supplied data.

3.4.6 Maintenance

Non-fuel operation and maintenance (O&M) costs are presented in Table 3-6. These costs are based on
gas turbine manufacturer estimates for service contracts, which consist of routine inspections and
scheduled overhauls of the turbine generator set. Routine maintenance practices include on-line
running maintenance, predictive maintenance, plotting trends, performance testing, fuel consumption,
heat rate, vibration analysis, and preventive maintenance procedures. The O&M costs presented in
Table 3-6 include operating labor (distinguished between unmanned and 24 hour manned facilities) and
total maintenance costs, including routine inspections and procedures and major overhauls.

53 Combustion turbine costs are based on published specifications and package prices. Installation estimates are based on
vendor cost estimation models and developer-supplied information.

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Table 3-6. Gas Turbine Non-Fuel O&M Costs

Cost Component

System

1

2

3

4

5

Net Operating Capacity (kW)

3,304

7,038

9,950

20,336

44,488

Turbine O&M ($/kWh)

$0.0090

$0.0090

$0.0089

$0.0062

$0.0062

BOP O&M ($/kWh)

$0.0036

$0.0033

$0.0031

$0.0031

$0.0030

Total O&M ($/kWh)

$0.0126

$0.0123

$0.0120

$0.0093

$0.0092

Source: Compiled by ICFfrom vendor-supplied data

Daily maintenance includes visual inspection by site personnel of filters and general site conditions.
Typically, routine inspections are required every 4,000 hours to insure that the turbine is free of
excessive vibration due to worn bearings, rotors, and damaged blade tips. Inspections generally include
on-site hot gas path horoscope inspections and non-destructive component testing using dye penetrant
and magnetic particle techniques to ensure the integrity of components. The combustion path is
inspected for fuel nozzle cleanliness and wear, along with the integrity of other hot gas path
components.

A gas turbine overhaul is needed every 25,000 to 50,000 hours depending on service and typically
includes a complete inspection and rebuild of components to restore the gas turbine to nearly original
or current (upgraded) performance standards. A typical overhaul consists of dimensional inspections,
product upgrades and testing of the turbine and compressor, rotor removal, inspection of thrust and
journal bearings, blade inspection and clearances and setting packing seals.

Gas turbine maintenance costs can vary significantly depending on the quality and diligence of the
preventative maintenance program and operating conditions. Although gas turbines can be cycled,
cycling every hour triples maintenance costs versus a turbine that operates for intervals of 1,000 hours
or more. In addition, operating the turbine over the rated capacity for significant periods of time will
dramatically increase the number of hot path inspections and overhauls. Gas turbines that operate for
extended periods on liquid fuels will experience shorter than average overhaul intervals.

3.4.7 Fuels

All gas turbines intended for service as stationary power generators in the United States are available
with combustors equipped to handle natural gas fuel. A typical range of heating values of gaseous fuels
acceptable to gas turbines is 900 to 1,100 Btu per standard cubic foot (scf), which covers the range of
pipeline quality natural gas. Clean liquid fuels are also suitable for use in gas turbines.

Special combustors developed by some gas turbine manufacturers are capable of handling cleaned
gasified solid and liquid fuels. Burners have been developed for medium Btu fuel (in the 400 to 500
Btu/scf range), which is produced with oxygen-blown gasifiers, and for low Btu fuel (90 to 125 Btu/scf),
which is produced by air-blown gasifiers. These burners for gasified fuels exist for large gas turbines but
are not available for small gas turbines.

Contaminants in fuel such as ash, alkalis (sodium and potassium), and sulfur result in alkali sulfate
deposits, which impede flow, degrade performance, and cause corrosion in the turbine hot section.

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Fuels must have only low levels of specified contaminants in them (typically less than 10 ppm total
alkalis, and single-digit ppm of sulfur).

Liquid fuels require their own pumps, flow control, nozzles and mixing systems. Many gas turbines are
available with either gas or liquid firing capability. In general, gas turbines can convert for use with one
fuel to another quickly. Several gas turbines are equipped for dual firing and can switch fuels with
minimal or no interruption.

Lean burn/dry low NOx gas combustors generate NOx emissions levels as low as 9 ppm (at 15 percent
02). Liquid fuel combustors have NOx emissions limited to approximately 25 ppm (at 15 percent 02).
There is no substantial difference in general performance with either fuel. However, the different heats
of combustion result in slightly higher mass flows through the expansion turbine when liquid fuels are
used, and thus result in a small increase in power and efficiency performance. In addition, the fuel pump
work with liquid fuel is less than with the fuel gas booster compressor, thereby further increasing net
performance with liquid fuels.

3.4.8 Gas Turbine System Availability

Operational conditions affect the failure rate of gas turbines. Frequent starts and stops incur damage
from thermal cycling, which accelerates mechanical failure. The use of liquid fuels, especially heavy fuels
and fuels with impurities (alkalis, sulfur, and ash), radiates heat to the combustor walls significantly
more intensely than the use of clean, gaseous fuels, thereby overheating the combustor and transition
piece walls. On the other hand, steady operation on clean fuels can permit gas turbines to operate for a
year without need for shutdown. Based on a survey of 41 operating gas turbine systems shown in Table
3-7, the average availability of gas turbines operating on clean gaseous fuels, like natural gas, is around
95 percent.

Table 3-7. Gas Turbine Availability and Outage Rates

Gas Turbines

0.5 to 3 MW

3 to 20 MW

20 to 100 MW

Systems Surveyed

11

21

9

Availability, %

96.12%

94.73%

93.49%

Forced Outage Rate, %

2.89%

2.88%

1.37%

Scheduled Outage Rate, %

0.99%

2.39%

5.14%

Source: ICF

3.5 Emissions and Emissions Control Options
3.5.1 Emissions

Table 3-8 shows typical emissions for each of the five typical turbine systems. Typical emissions
presented are based on natural gas combustion showing emissions before and after exhaust treatment
using SCR and CO oxidation.

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Table 3-8. Gas Turbine Emissions Characteristics

Emissions Characteristics

System

1

2

3

4

5

Electricity Capacity (kW)

3,304

7,038

9,950

20,336

44,488

Electrical Efficiency (HHV)

24.0%

28.9%

27.3%

33.3%

36.0%

Emissions Before After-treatment

NOx (ppm)

25

15

15

15

15

NOx (Ib/MWh)

1.31

0.65

0.69

0.57

0.52

CO (ppmv)

50

25

25

25

25

CO (Ib/MWh)

1.60

0.66

0.70

0.58

0.53

NMHC (ppm)

5

5

5

5

5

NMHC (Ib/MWh)

0.09

0.08

0.08

0.07

0.06

Emissions with SCR/CO/CEMS

NOx (ppm)

2.5

1.5

1.5

1.5

1.5

NOx (Ib/MWh)

0.09

0.05

0.05

0.05

0.05

CO (ppmv)

5.0

2.5

2.5

2.5

2.5

CO (Ib/MWh)

0.11

0.05

0.05

0.05

0.05

NMHC (ppm)

4.3

4.3

4.3

4.3

2.0

NMHC (Ib/MWh)

0.08

0.06

0.07

0.06

0.02

C02 Emissions

Generation C02 (Ib/MWh)

1,667

1,381

1,460

1,201

1,110

Net COzwith CHP (Ib/MWh)

797

666

691

641

654

Source: Compiled by ICFfrom vendor supplied data, includes heat recovery

Table 3-8 also shows the net C02 emissions after credit is taken for avoided natural gas boiler fuel. The
net C02 emissions range from 641-797 Ibs/MWh. A natural gas combined cycle power plant might have
emissions in the 800-900 Ib/MWh range whereas a coal power plant's C02 emissions would be over
2000 Ib/MWh. Natural gas fired CHP from gas turbines provides savings against both alternatives.

3.5.2 Emissions Control Options

Emissions control technology for gas turbines has advanced dramatically over the last 20 years in
response to technology forcing requirements that have continually lowered the acceptable emissions
levels for nitrogen oxides (NOx), carbon monoxide (CO), and volatile organic compounds (VOCs). When
burning fuels other than natural gas, pollutants such as oxides of sulfur (SOx) and particulate matter
(PM) can be an issue. In general, SOx emissions are greater when heavy oils are fired in the turbine. SOx
control is generally addressed by the type of fuel purchased, than by the gas turbine technology.
Particulate matter is a marginally significant pollutant for gas turbines using liquid fuels. Ash and metallic
additives in the fuel may contribute to PM in the exhaust.

A number of control options can be used to control emissions. Below are descriptions of these options.

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3.5.2.1	Diluent Injection

The first technique used to reduce NOx emissions was injection of water or steam into the high
temperature flame zone. Water and steam are strong diluents and can quench hot spots in the flame
reducing NOx. However, because positioning of the injection is not precise some NOx is still created.
Depending on uncontrolled NOx levels, water or steam injection reduces NOx by 60 percent or more.
Water or steam injection enables gas turbines to operate with NOx levels as low as 25 ppm (@ 15
percent 02) on natural gas. NOx is reduced only to 42 to 75 ppm when firing with liquid distillate fuel.
Both water and steam increase the mass flow through the turbine and create a small amount of
additional power. Use of exhaust heat to raise the steam temperature also increases overall efficiency
slightly. The water used needs to be demineralized thoroughly in order to avoid forming deposits and
corrosion in the turbine expansion section. This adds cost and complexity to the operation of the
turbine. Diluent injection increases CO emissions appreciably as it lowers the temperature in the
burnout zone, as well as in the NOx formation zone.

3.5.2.2	Lean Premixed Combustion

Lean premixed combustion (DLN/DLE54) pre-mixes the gaseous fuel and compressed air so that there are
no local zones of high temperatures, or "hot spots," where high levels of NOx would form. Lean
premixed combustion requires specially designed mixing chambers and mixture inlet zones to avoid
flashback of the flame. Optimized application of DLN combustion requires an integrated approach for
combustor and turbine design. The DLN combustor becomes an intrinsic part of the turbine design, and
specific combustor designs must be developed for each turbine application. While NOx levels as low as 9
ppm have been achieved, most manufacturers typically offer a range of 15-25 ppm DLN/DLE combustion
systems when operating on natural gas.

3.5.2.3	Selective Catalytic Reduction (SCR)

The primary post-combustion NOx control method in use today is SCR. Ammonia is injected into the flue
gas and reacts with NOx in the presence of a catalyst to produce N2 and H20. The SCR system is located
in the exhaust path, typically within the HRSG where the temperature of the exhaust gas matches the
operating temperature of the catalyst. The operating temperature of conventional SCR systems ranges
from 400 to 800°F. The cost of conventional SCR has dropped significantly over time—catalyst
innovations have been a principal driver, resulting in a 20 percent reduction in catalyst volume and cost
with no change in performance. SCR reduces between 80 to 90 percent of the NOx in the gas turbine
exhaust, depending on the degree to which the chemical conditions in the exhaust are uniform. When
used in series with water/steam injection or DLN combustion, SCR can result in low single digit NOx
levels (1.5 to 5 ppm). SCR requires on-site storage of ammonia, a hazardous chemical. In addition,
ammonia can "slip" through the process unreacted, contributing to environmental and health
concerns.55

54	Dry low NOx/Dry low emissions

55	The SCR reaction, with stoichiometric ammonia (for NOx reduction) or other reagent should eliminate all NOx. However,
because of imperfect mixing in the combustor the NOx is not uniformly distributed across the turbine exhaust. Additionally, the
ammonia, or other reagent, also is not injected in a precisely uniform manner. These two non-uniformities in chemical
composition cause either excess ammonia to be used, and to consequently "slip" out of the exhaust, or for incomplete reaction
of the NOx in the turbine exhaust.

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3.5.2.4	CO Oxidation Catalysts

Oxidation catalysts control CO in gas turbine exhaust. Some SCR installations incorporate CO oxidation
modules along with NOx reduction catalysts for simultaneous control of CO and NOx. The CO catalyst
promotes the oxidation of CO and hydrocarbon compounds to C02 and water as the exhaust stream
passes through the catalyst bed. The oxidation process takes place spontaneously so no reactants are
required. The catalyst is usually made of precious metal such as platinum, palladium, or rhodium. Other
formations, such as metal oxides for emission streams containing chlorinated compounds, are also used.
CO catalysts also reduce VOCs and organic hazardous air pollutants (HAPs). CO catalysts on gas turbines
result in approximately 90 percent reduction of CO and 85 to 90 percent control of formaldehyde
(similar reductions can be expected on other HAPs).

3.5.2.5	Catalytic Combustion

Catalytic combustion systems oxidize the fuel at lean conditions in the presence of a catalyst. Catalytic
combustion is a flameless process, allowing fuel oxidation to occur at temperatures below 1,700°F,
where NOx formation is low. The catalyst is applied to combustor surfaces, which cause the fuel air
mixture to react with the oxygen and release its initial thermal energy. The combustion reaction in the
lean premixed gas then goes to completion at design temperature. Data from ongoing long term testing
indicates that catalytic combustion exhibits low vibration and acoustic noise, only one-tenth to one-
hundredth the levels measured in the same turbine equipped with DLN combustors. Catalytic
combustors capable of achieving NOx levels below 3 ppm are entering commercial production.56 Similar
to DLN combustion, optimized catalytic combustion requires an integrated approach for combustor and
turbine design. Catalytic combustors must be tailored to the specific operating characteristics and
physical layout of each turbine design.

3.5.2.6	Catalytic Absorption Systems

SCONOx™, patented by Goal Line Environmental Technologies (currently EmerChem), is a post-
combustion alternative to SCR that reduces NOx emissions to less than 2.5 ppm and almost 100 percent
removal of CO. SCONOx™ combines catalytic conversion of CO and NOx with an absorption/regeneration
process that eliminates the ammonia reagent found in SCR technology. It is based on a unique
integration of catalytic oxidation and absorption technology. CO and NO catalytically oxidize to C02 and
N02. The N02 molecules are subsequently absorbed on the treated surface of the SCONOx™ catalyst.
The system does not require the use of ammonia, eliminating the potential for ammonia slip associated
with SCR. The SCONOx™ system is generally located within the HRSG, and under special circumstances
may be located downstream of the HRSG. The system operates between 300-7002F. U.S. EPA Region 9
identified SCONOx™ as "Lowest Achievable Emission Rate (LAER)" technology for gas turbine NOx control
in 1998. The SCONOx™ technology is still in the early stages of market introduction. Issues that may
impact application of the technology include relatively high capital cost, large reactor size compared to
SCR, system complexity, high utilities cost and demand (steam, natural gas, compressed air and
electricity are required), and a gradual rise in NO emissions over time that requires a 1 to 2 day

56 For example, Kawasaki offers a version of their MIA 13X, 1.4 MW gas turbine with a catalytic combustor with less than 3 ppm
NOx guaranteed.

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shutdown every 6 to 12 months (depending on fuel quality and operation) to remove and regenerate
the absorption modules ex-situ.57

3.6 Future Developments

In the last twenty years, there have been substantial improvement in gas turbine technology with
respect to power, efficiency, durability, green operation, and time/cost to market. These improvements
have been the combined results of collaborative research efforts by private industry, universities, and
the federal government. Public private partnerships such as the DOE Advanced Turbine Systems
Program and the Next Generation Turbine program have advanced gas turbine technology by meeting
goals including:

•	Combined cycle electric efficiency of 60 percent (LHV)

•	NOx emissions of less than 10 ppm

•	10 percent reduction in the cost of electricity

•	Improvement in reliability, availability, and maintainability (RAM)

•	Development of the recuperated 4.6 MW Solar Mercury gas turbine with low emissions and
electrical efficiency of 37.5 percent (LHV) compared to an unrecuperated gas turbine of similar
size having an electric efficiency of 28.5 percent

Current collaborative research is focusing on both large gas turbines and those applicable for distributed
generation. Large gas turbine research is focused on improving the efficiency of combined cycle plants
to 65 percent (LHV), reducing emission even further, and integrating gas turbines with clean coal
gasification and carbon capture. The focus for smaller gas turbines is on improving performance,
enhancing fuel flexibility, reducing emissions, reducing life cycle costs, and integration with improved
thermal utilization technologies. Continued development of aeroderivative gas turbines for civilian and
military propulsion will provide carryover benefits to stationary applications.

Long term research includes the development of hybrid gas turbine fuel cell technology that is capable
of 70 percent (LHV) electric efficiency.58

57	Resource Catalysts, Inc.

58	DOE turbine/fuel cell hybrid program, http://www.netl.doe.gov/technologies/coalpower/fuelcells/hybrids.html

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Section 4. Technology Characterization - Steam Turbines

4.1 Introduction

Steam turbines are one of the most versatile and oldest prime mover technologies still in general
production used to drive a generator or mechanical machinery. The first steam turbine used for power
generation was invented in 1884. Following this initial introduction, steam turbines rapidly replaced
reciprocating steam engines due to their higher efficiencies and lower costs. Most of the electricity
produced in the United States today is generated by conventional steam turbine power plants. The
capacity of steam turbines can range from 50 kW to several hundred MWs for large utility power plants.
Steam turbines are widely used for combined heat and power (CHP) applications in the United States
and Europe.

Unlike gas turbine and reciprocating engine CHP systems, where heat is a byproduct of power
generation, steam turbine generators normally generate electricity as a byproduct of heat (steam)
generation. A steam turbine is captive to a separate heat source and does not directly convert fuel to
electric energy. The energy is transferred from the boiler to the turbine through high pressure steam
that powers the turbine and generator. This separation of functions enables steam turbines to operate
using a large variety of fuels, from clean natural gas to solid waste, including all types of coal, wood,
wood waste, and agricultural byproducts (sugar cane bagasse, fruit pits and rice hulls). In CHP
applications, steam at lower pressure is extracted from the steam turbine and used directly in a process
or for district heating, or it can be converted to other forms of thermal energy including hot or chilled
water.

Steam turbines offer a wide array of designs and complexity to match the desired application and/or
performance specifications ranging from single stage backpressure or condensing turbines for low
power ranges to complex multi-stage turbines for higher power ranges. Steam turbines for utility service
may have several pressure casings and elaborate design features, all designed to maximize the efficiency
of the power plant. For industrial applications, steam turbines are generally of simpler single casing
design and less complicated for reliability and cost reasons. CHP can be adapted to both utility and
industrial steam turbine designs.

Table 4-1 provides a summary of steam turbine attributes described in detail in this chapter.

Table 4-1. Summary of Steam Turbine Attributes

Size range

Steam turbines are available in sizes from under 100 kW to over 250 MW. In the
multi-megawatt size range, industrial and utility steam turbine designations
merge, with the same turbine (high pressure section) able to serve both
industrial and small utility applications.

Custom design

Steam turbines can be designed to match CHP design pressure and temperature
requirements. The steam turbine can be designed to maximize electric efficiency
while providing the desired thermal output.

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Table 4-1. Summary of Steam Turbine Attributes

Thermal output

Steam turbines are capable of operating over a very broad range of steam
pressures. Utility steam turbines operate with inlet steam pressures up to 3500
psig and exhaust at vacuum conditions as low as 2 psia. Steam turbines can be
custom designed to deliver the thermal requirements of the CHP application
through use of backpressure or extraction steam at appropriate pressures and
temperatures.

Fuel flexibility

Steam turbines offer a wide range of fuel flexibility using a variety of fuel sources
in the associated boiler or other heat source, including coal, oil, natural gas,
wood and waste products, in addition to waste exhaust heat recaptured in a heat
recovery steam generator.

Reliability and life

Steam turbine equipment life is extremely long. There are steam turbines that
have been in service for over 50 years. When properly operated and maintained
(including proper control of boiler water chemistry and ensuring dry steam),
steam turbines are extremely reliable with overhaul intervals measured in years.
Larger turbines require controlled thermal transients as the massive casing heats
up slowly and differential expansion of the parts must be minimized. Smaller
turbines generally do not have start-up restrictions.

4.2 Applications

Steam turbines are well suited to medium- and large-scale industrial and institutional applications,
where inexpensive fuels, such as coal, biomass, solid wastes and byproducts (e.g., wood chips), refinery
residual oil, and refinery off gases are available. Applications include:

•	Combined heat and power - Steam turbine-based CHP systems are primarily used in industrial
processes where solid or waste fuels are readily available for boiler use. In CHP applications,
steam may be extracted or exhausted from the steam turbine and used directly. Steam turbine
systems are very commonly found in paper mills as there is usually a variety of waste fuels from
hog fuel to black liquor. Chemical plants are the next most common industrial user of steam
turbines followed by primary metals. There are a variety of other industrial applications
including the food industry, particularly sugar and palm oil mills.

•	Mechanical drive - Instead of producing electric power, the steam turbine may drive equipment
such as boiler feedwater pumps, process pumps, air compressors and refrigeration chillers. Such
applications, usually accompanied by process use of steam are found in many of the CHP
industries described above.

•	District heating and cooling systems - There are cities and college campuses that have steam
district heating systems where adding a steam turbine between the boiler and the distribution
system or placing a steam turbine as a replacement for a pressure reducing station may be an
attractive application. Often the boiler is capable of producing moderate-pressure steam but the
distribution system needs only low pressure steam. In these cases, the steam turbine generates
electricity using the higher pressure steam, and discharges low pressure steam into the
distribution system. Such facilities can also use steam in absorption chillers to produce chilled
water for air conditioning.

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• Combined cycle power plants - The trend in power plant design is to generate power with a gas
turbine and use the exhaust heat to generate steam that provides additional power through a
steam turbine. Such combined-cycle power plants are capable of achieving electric generation
efficiencies of over 50 percent. For large industrial CHP applications, an extraction-condensing
type of steam turbine can be used in a combined cycle plant with the steam turbine extracting a
portion of the steam for process use. There are many large independent power producers (IPP)
using combined cycle power plants operating on natural gas to provide power to the electric
grid and steam to one or more industrial customers.

4.3 Technology Description

4.3.1	Basic Process

The thermodynamic cycle for the steam turbine is known as the Rankine cycle. This cycle is the basis for
conventional power generating stations and consists of a heat source (boiler) that converts water to
high pressure steam. In the steam cycle, water is first pumped to elevated pressure, which is medium to
high pressure, depending on the size of the unit and the temperature to which the steam is eventually
heated. It is then heated to the boiling temperature corresponding to the pressure, boiled (heated from
liquid to vapor), and then most frequently superheated (heated to a temperature above that of boiling).
The pressurized steam is expanded to lower pressure in a turbine, then exhausted either to a condenser
at vacuum conditions, or into an intermediate temperature steam distribution system that delivers the
steam to the industrial or commercial application. The condensate from the condenser or from the
industrial steam utilization system is returned to the feedwater pump for continuation of the cycle.

4.3.2	Components

A schematic representation of a steam turbine power system is shown in Figure 4-1.

Figure 4-1. Boiler/Steam Turbine System

Steam

Condenser

1

Heat out

In the simple schematic shown, a fuel boiler produces steam which is expanded in the steam turbine to
produce power. When the system is designed for power generation only, such as in a large utility power

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system, the steam is exhausted from the turbine at the lowest practical pressure, through the use of a
water-cooled condenser to extract the maximum amount of energy from the steam. In CHP plants or
district heating systems, the steam is exhausted from the steam turbine at a pressure high enough to be
used by the industrial process or the district heating system. In CHP configuration, there is no condenser
and the steam and condensate, after exiting the process, is returned to the boiler.

There are numerous options in the steam supply, pressure, temperature and extent, if any, for reheating
steam that has been partially expanded from high pressure. Steam systems vary from low pressure lines
used primarily for space heating and food preparation, to medium pressure and temperature used in
industrial processes and cogeneration, and to high pressure and temperature use in utility power
generation. Generally, as the system gets larger the economics favor higher pressures and
temperatures, along with their associated heavier walled boiler tubes and more expensive alloys.

4.3.2.1	Boiler

Steam turbines differ from reciprocating engines, internal combustion engines, and gas turbines in that
the fuel is burned in a piece of equipment, the boiler, which is separate from the power generation
equipment. The energy is transferred from the boiler to the steam turbine generator by an intermediate
medium, typically steam under pressure. As mentioned previously, this separation of functions enables
steam turbines to operate with an enormous variety of fuels. The topic of boiler fuels, their handling,
combustion and the cleanup of the effluents of such combustion is a separate and complex issue that is
addressed in the fuels and emissions sections of this report.

For sizes up to (approximately) 40 MW, horizontal industrial boilers are built. This enables them to be
shipped via rail car, with considerable cost savings and improved quality, as the cost and quality of
factory labor is usually both lower in cost and greater in quality than field labor. Large shop-assembled
boilers are typically capable of firing only gas or distillate oil, as there is inadequate residence time for
complete combustion of most solid and residual fuels in such designs. Large, field-erected industrial
boilers firing solid and residual fuels bear a resemblance to utility boilers except for the actual solid fuel
injection. Large boilers usually burn pulverized coal; however, intermediate and small boilers burning
coal or solid fuel employ various types of solids feeders.

4.3.2.2	Steam Turbine

In the steam turbine, the steam is expanded to a lower pressure providing shaft power to drive a
generator or run a mechanical process.

There are two distinct designs for steam turbines -impulse and reaction turbines. The difference
between these two designs is shown in Figure 4-2. On impulse turbines, the steam jets are directed at
the turbine's bucket shaped rotor blades where the pressure exerted by the jets causes the rotor to
rotate and the velocity of the steam to reduce as it imparts its kinetic energy to the blades. The next
series of fixed blades reverses the direction of the steam before it passes to the second row of moving
blades. In Reaction turbines, the rotor blades of the reaction turbine are shaped more like airfoils,
arranged such that the cross section of the chambers formed between the fixed blades diminishes from
the inlet side towards the exhaust side of the blades. The chambers between the rotor blades essentially
form nozzles so that as the steam progresses through the chambers its velocity increases while at the

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same time its pressure decreases, just as in the nozzles formed by the fixed blades. The competitive
merits of these designs are the subject of business competition, as both designs have been sold
successfully for well over 75 years.

Figure 4-2. Comparison of Impulse and Reaction Turbine Design
Impulse Turbine	Reaction Turbine

Source: Electropaedia, http://www.mpoweruk.com/steam_turbines.htm

The stationary nozzles accelerate the steam to high velocity by expanding it to lower pressure. A
rotating bladed disc changes the direction of the steam flow, thereby creating a force on the blades that,
because of the wheeled geometry, manifests itself as torque on the shaft on which the bladed wheel is
mounted. The combination of torque and speed is the output power of the turbine. A reduction gear
may be utilized to reduce the speed of the turbine to the required output speed for the generator.

The internal flow passages of a steam turbine are very similar to those of the expansion section of a gas
turbine (indeed, gas turbine engineering came directly from steam turbine design around 100 years
ago). The main differences are gas density, molecular weight, isentropic expansion coefficient, and to a
lesser extent, the viscosity of the two fluids.

Compared to reciprocating steam engines of comparable size, steam turbines rotate at much higher
rotational speeds, which contribute to their lower cost per unit of power developed. In addition, the
inlet and exhaust valves in reciprocating steam engines cause steam pressure losses that don't
contribute to power output. Such losses do not occur in steam turbines. As a result of these design

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differences, steam turbines are more efficient than reciprocating steam engines operating from the
steam at the same inlet conditions and exhausting into the same steam exhaust systems.

There are numerous mechanical design features that have been created to increase efficiency, provide
for operation over a range of conditions, simplify manufacture and repair, and achieve other practical
purposes. The long history of steam turbine use has resulted in a large inventory of steam turbine stage
designs that can be used to tailor a product for a specific application. For example, the division of steam
acceleration and change in direction of flow varies between competing turbine manufacturers under the
identification of impulse and reaction designs. Manufacturers tailor clients' design requests by varying
the flow area in the stages and the extent to which steam is extracted (removed from the flow path
between stages) to accommodate the client specifications.

When steam is expanded through a very high pressure ratio, as in utility and large industrial steam
systems, the steam can begin to condense in the turbine if the temperature of the steam drops below
the saturation temperature at that pressure. If water drops were allowed to form in the turbine, they
would impact the blades and would cause blade erosion. At this point in the expansion, the steam is
sometimes returned to the boiler and reheated to high temperature and then returned to the turbine
for further (safe) expansion. In a few very large, very high-pressure utility steam systems, double reheat
systems are installed.

With these choices the designer of the steam supply system and the steam turbine have the challenge of
creating a system design which delivers the (seasonally varying) power and steam, that also presents the
most favorable business opportunity to the plant owners.

Between the power (only) output of a condensing steam turbine and the power and steam combination
of a back pressure steam turbine, essentially any ratio of power to heat output can be supplied to a
facility. Moreover, back pressure steam turbines can be obtained with a variety of back pressures,
further increasing the variability of the power-to-heat ratio.

4.3.2.3 Condensing Turbine

The primary type of turbine used for central power generation is the condensing turbine shown
schematically in Figure 4-3. These power-only utility turbines exhaust directly to condensers that
maintain vacuum conditions at the discharge of the turbine. An array of tubes, cooled by water from a
river, lake or cooling tower, condenses the steam into (liquid) water.59 The vacuum conditions in the
condenser are caused by the near ambient cooling water causing condensation of the steam turbine
exhaust steam in the condenser. As a small amount of air is known to leak into the system when it is
below atmospheric pressure, a relatively small compressor or steam air ejector may be used to remove
non-condensable gases from the condenser. Non-condensable gases include both air and a small
amount of the corrosion byproduct of the water-iron reaction, hydrogen.

59 At 80° F, the vapor pressure of water is 0.51 psia, at 100° F it is 0.95 psia, at 120° F it is 1.69 psia and at 140° F Fahrenheit it is
2.89 psia

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The condensing turbine processes result in maximum power and electrical generation efficiency from
the steam supply and boiler fuel. The power output of condensing turbines is sensitive to ambient
conditions.60

Figure 4-3. Condensing Steam Turbine

High pressure steam

Vacuum pressure steam
to condenser

Steam turbines used for CHP can be classified into two main types: non-condensing and extraction,
which will be discussed in the following two sections.

4.3.2.4 Non-Condensing (Back-pressure) Turbine

A non-condensing turbine (also referred to as a back-pressure turbine) exhausts some or all of its steam
flow to the industrial process or facility steam mains at conditions close to the process heat
requirements, as shown in Figure 4-4.

Figure 4-4. Non-Condensing (Back-pressure) Steam Turbine

High pressure
steam

Low pressure steam

60 From a reference condition of condensation at 100° F, 6.5 percent less power is obtained from the inlet steam when the
temperature at which the steam is condensed is increased (because of higher temperature ambient conditions) to 115° F.
Similarly, the power output is increased by 9.5% when the condensing temperature is reduced to 80° F. This illustrates the
influence of steam turbine discharge pressure on power output and, consequently, net heat rate and efficiency.

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Usually, the steam sent into the mains is not much above saturation temperature.61 The term back-
pressure refers to turbines that exhaust steam at atmospheric pressures and above. The discharge
pressure is established by the specific CHP application. The most typical pressure levels for steam
distribution systems are 50, 150, and 250 psig. The lower pressures are most often used in district
heating systems, while the higher pressures are most often used in supplying steam to industrial
processes. Industrial processes often include further expansion for mechanical drives, using small steam
turbines for driving heavy equipment that is intended to run continuously for very long periods.
Significant power generation capability is sacrificed when steam is used at high pressure, rather than
being expanded to vacuum conditions in a condenser. Discharging steam into a steam distribution
system at 150 psig can sacrifice slightly more than half the power (compared to a vacuum exhaust) that
could be generated when the inlet steam conditions are 750 psig and 800° F, typical of small steam
turbine systems.

4.3.2.5 Extraction Turbine

An extraction turbine has one or more openings in its casing for extraction of a portion of the steam at
some intermediate pressure. The extracted steam may be used for process purposes in a CHP facility, or
for feedwater heating, as is the case in most utility power plants. The rest of the steam can be expanded
to below atmospheric pressure to a condenser, or delivered to a low pressure steam application as
illustrated in Figure 4-5.

Figure 4-5. Extraction Steam Turbine

High pressure

steam

Medium/low
pressure steam
To process *

Y

Condenser

or process use

The steam extraction pressure may or may not be automatically regulated depending on the turbine
design. Regulated, or controlled extraction permits more steam to flow through the turbine to generate
additional electricity during periods of low thermal demand by the CHP system. In utility type steam
turbines, there may be several extraction points, each at a different pressure corresponding to a
different temperature at which heat is needed in the thermodynamic cycle. The facility's specific needs

61 At 50 psig (65 psia) the condensation temperature is 298° F, at 150 psig (165 psia) the condensation temperature is 366° F,
and at 250 psig (265 psia) it is 406° F.

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for steam and power over time determine the extent to which steam in an extraction turbine will be
extracted for use in the process, or be expanded to vacuum conditions and condensed in a condenser.

In large, complex industrial plants, additional steam may be admitted to the steam turbine by flowing
into the casing to increase the flow in the steam path. Often this happens when multiple boilers are
used at different pressures, because of their historical existence. These steam turbines are referred to as
admission or reheat turbines. At steam extraction and admission locations, there are usually steam flow
control valves that add to the steam and control system cost.

4.4 Performance Characteristics

Boilers and steam turbines used for large, central station electric power generation can achieve
electrical efficiencies of up to 45 percent HHV62 though the average efficiency of all units in the field is
around 33 percent.63 Backpressure steam turbines used in CHP applications extract only a portion of the
steam energy to generate electricity, delivering the rest for process use. Consequently, the electric
generation efficiencies for the examples shown are all below 10 percent HHV. However, when the
energy value of the steam delivered for process use is considered, the effective electrical efficiency is
over 75 percent.

Table 4-2 summarizes performance characteristics for typical commercially available backpressure
steam turbines used in CHP applications between 500 kW to 15 MW size range.

Isentropic steam turbine efficiency refers to the ratio of power actually generated from the turbine to
what would be generated by a perfect turbine with no internal flowpath losses using steam at the same
inlet conditions and discharging to the same downstream pressure. Turbine efficiency is not to be
confused with electrical generating efficiency, which is the ratio of net power generated to total fuel
input to the cycle. Steam turbine efficiency is a measure of how efficiently the turbine extracts power
from the steam itself and is useful in identifying the conditions of the steam as it exhausts from the
turbine and in comparing the performance of various steam turbines. Multistage (moderate to high
pressure ratio) steam turbines have thermodynamic efficiencies that vary from 65 percent for very small
(under 1,000 kW) units to over 90 percent for large industrial and utility sized units. Small, single stage
steam turbines can have efficiencies as low as 40 percent.

Heat recovery methods from a steam turbine use back pressure exhaust or extraction steam. However,
the term is somewhat misleading, since in the case of steam turbines, it is the steam turbine itself that
can be defined as a heat recovery device.

Steam turbine CHP systems are generally characterized by very low power to heat ratios, typically in the
0.05 to 0.2 range. This is because electricity is a byproduct of heat generation, with the system

62	All turbine and engine manufacturers quote heat rates in terms of the lower heating value (LHV) of the fuel. However, the
usable energy content of fuels is typically measured on a higher heating value basis (HHV). In addition, electric utilities measure
power plant heat rates in terms of HHV. For natural gas, the average heat content of natural gas is 1,030 Btu/scf on an HHV
basis and 930 Btu/scf on an LHV basis - or about a 10 percent difference.

63	Technology Roadmap: High-Efficiency, Low-Emissions Coal-Fired Power Generation, International Energy Agency, December
4, 2012.

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optimized for steam production. Hence, while steam turbine CHP system electrical efficiency64 may
seem very low, it is because the primary objective is to produce large amounts of steam. The effective
electrical efficiency65 of steam turbine systems, however, is generally very high, because almost all the
energy difference between the high pressure boiler output and the lower pressure turbine output is
converted to electricity. This means that total CHP system efficiencies66 are generally very high and
approach the boiler efficiency level. Steam boiler efficiencies range from 70 to 85 percent HHV
depending on boiler type and age, fuel, duty cycle, application, and steam conditions.

Table 4-2. Backpressure Steam Turbine Cost and Performance Characteristics*

Steam Turbine Parameters67

System

1

2

3

Nominal Electricity Capacity (kW)

500

3,000

15,000

Typical Application

Industrial, PRV
application

Industrial,
universities,
hospitals

Industrial,
universities,
hospitals

Equipment Cost ($/kW)68

$668

$401

$392

Total Installed Cost ($/kW)69

$1,136

$682

$666

O&M Costs ($/kW)70

$0,010

$0,009

$0,006

Turbine Isentropic Efficiency (%)71

52.5%

61.2%

78.0%

Generator/Gearbox Efficiency (%)

94%

94%

96%

Steam Flow (Ibs/hr)

20,050

152,600

494,464

Inlet Pressure (psig)

500

600

700

Inlet Temperature (° Fahrenheit)

550

575

650

Outlet Pressure (psig)

50

150

150

Outlet Temperature (° Fahrenheit)

298

373

379.7

CHP System Parameters

1

2

3

Boiler Efficiency (%), HHV

80%

80%

80%

Electric Efficiency (%), HHV72

6.27%

4.92%

7.31%

Fuel Input (MMBtu/hr)

27.2

208.3

700.1

Steam to Process (MMBtu/hr)

19.9

155.7

506.8

Steam to Process (kW)

5,844

45,624

148,484

Total CHP Efficiency (%), HHV73

79.60%

79.68%

79.70%

64	Net power output / total fuel input into the system.

65	(Steam turbine electric power output) / (Total fuel into boiler- (steam to process/boiler efficiency)).

66	Net power and steam generated divided by total fuel input.

67	Characteristics for "typical" commercially available steam turbine generator systems provided by Elliott Group.

68	Equipment cost includes turbine, gearbox, generator, control system, couplings, oil system (if required), and packaging; boiler
and steam system costs are not included.

69	Installed costs vary greatly based on site-specific conditions; installed costs of a "typical" simple installation were estimated
to be 50-70% of the equipment costs.

70	Maintenance assumes normal service intervals over a 5 year period, excludes parts.

71	The Isentropic efficiency of a turbine is a comparison of the actual power output compared to the ideal, or isentropic, output.
It is a measure of the effectiveness of extracting work from the expansion process and is used to determine the outlet
conditions of the steam from the turbine.

72	CHP electrical efficiency = Net electricity generated/Total fuel into boiler. A measure of the amount of boiler fuel converted
into electricity.

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Table 4-2. Backpressure Steam Turbine Cost and Performance Characteristics*

Steam Turbine Parameters67

System

1

2

3

Power/Heat Ratio74

0.086

0.066

0.101

Net Heat Rate (Btu/kWh)75

4,541

4,540

4,442

Effective Electrical Efficiency (%), HHV

75.15%

75.18%

76.84%

Heat/Fuel Ratio76

0.733

0.748

0.724

* For typical systems available in 2014.

Equipment costs shown include the steam turbine, gearbox, generator, control system, couplings, oil
system (if required), and packaging. Installed costs vary greatly based on site-specific conditions.
Installed costs of a "typical" simple installation were estimated to be 50-70 percent of the equipment
costs. Boiler and steam system costs are not included in these estimates.

4.4.1 Performance Losses

Steam turbines, especially smaller units, may leak steam around blade rows and out the end seals.

When the turbine operates or exhausts at a low pressure, as is the case with condensing steam turbines,
air can also leak into the system. The leakages cause less power to be produced than expected, and the
makeup water has to be treated to avoid boiler and turbine material problems. Air that has leaked
needs to be removed, which is usually done by a steam air ejector or a fan removing non-condensable
gases from the condenser.

Because of the high pressures used in steam turbines, the casing is quite thick, and consequently steam
turbines exhibit large thermal inertia. Large steam turbines must be warmed up and cooled down slowly
to minimize the differential expansion between the rotating blades and the stationary parts. Large
steam turbines can take over ten hours to warm up. While smaller units have more rapid startup times
or can be started from cold conditions, steam turbines differ appreciably from reciprocating engines,
which start up rapidly, and from gas turbines, which can start up in a moderate amount of time and load
follow with reasonable rapidity.

Steam turbine applications usually operate continuously for extended periods of time, even though the
steam fed to the unit and the power delivered may vary (slowly) during such periods of continuous
operation. As most steam turbines are selected for applications with high duty factors, the nature of
their application often takes care of the need to have only slow temperature changes during operation,
and long startup times can be tolerated. Steam boilers similarly may have long startup times, although
rapid start-up boilers are available.

73	Total CHP efficiency = (Net electricity generated + Net steam to process)/Total fuel into boiler.

74	Power/Heat Ratio = CHP electrical power output (Btu)/useful heat output (Btu).

75	Net Heat Rate = (total fuel input to the boiler - the fuel that would be required to generate the steam to process assuming
the same boiler efficiency)/steam turbine electric output (kW).

76	Effective Electrical Efficiency = (Steam turbine electric power output) / (Total fuel into boiler - (steam to process/boiler
efficiency)). Equivalent to 3,412 Btu/kWh/Net Heat Rate.

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4.4.2	Performance Enhancements

In industrial steam turbine systems, business conditions determine the requirements and relative values
of electric power and process, or steam for heating. Plant system engineers then decide the extent of
efficiency enhancing options to incorporate in terms of their incremental effects on performance and
plant cost, and select appropriate steam turbine inlet and exhaust conditions. Often the steam turbine is
going into a system that already exists and is being modified so that a number of steam system design
parameters are already established from previous decisions, which exist as system hardware
characteristics and the turbine must be properly matched to these conditions.

As the stack temperature of the boiler exhaust combustion products still contain some heat, tradeoffs
are made regarding the extent of investment in heat reclamation equipment for the sake of efficiency
improvement. Often the stack exhaust temperature is set at a level where further heat recovery would
result in condensation of corrosive chemical species in the stack, with consequential deleterious effects
on stack life and safety.

4.4.2.1	Steam Reheat

Higher pressures and temperatures along with steam reheat are used to increase power generation
efficiency in large industrial (and utility) systems. The higher the pressure ratio (the ratio of the steam
inlet pressure to the steam exit pressure) across the steam turbine, and the higher the steam inlet
temperature, the more power it will produce per unit of mass flow, provided that the turbine can
reliably accommodate the pressure ratio and that the turbine is not compromised by excessive
condensation within the last expansion stage. To avoid condensation within the flowpath or to maximize
available steam energy, the inlet steam temperature is increased until the economic life limit of turbine
materials is reached. This limit is now generally in the range of 900° F for small industrial steam turbines
using typical materials.

Expanding steam can reach a condition of temperature and pressure where condensation to (liquid)
water begins. Small amounts of water droplets can be tolerated in the last stages of a steam turbine
provided that the droplets are not too large or numerous. Turbine flowpaths can employ features for
extracting a portion of the condensate form the flowpath in order to limit water droplet impingement
on the blading. Also, protective blade treatments such as Stellite are often employed to harden the
blading surfaces exposed to the droplet impingement and reduce blade material erosion. For turbines
using a reheat cycle, steam is extracted after it has partially expanded, heated in a heat exchanger, and
returned to the turbine flowpath for further expansion.

4.4.2.2	Combustion Air Preheating

In large industrial systems, air preheaters recover heat from the boiler exhaust gas stream, and use it to
preheat the combustion air, thereby reducing fuel consumption. Boiler combustion air preheaters are
large versions of the heat wheels used for the same purpose on industrial furnaces.

4.4.3	Capital Costs

A steam turbine-based CHP plant is a complex process with many interrelated subsystems that must
usually be custom designed. In a steam turbine CHP plant burning a solid biomass fuel, the steam
turbine generator makes up only about 10 percent of the total plant equipment costs - the solid fuel

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boiler makes up 45 percent and the prep yard, electrostatic precipitator, and other equipment each
adding about 15 percent.77 Engineering and construction add 70 percent to equipment costs.

The cost of complete solid fuel CHP plants varies with many factors—fuels handling, pollution control
equipment and boiler cost are major cost items. Because of both the size of such plants and the diverse
sources of the components, solid fuel cogeneration plants invariably involve extensive system
engineering and field labor during construction. Typical complete plant costs can be over $5,000/kW,
with little generalization except that for the same fuel and configuration, costs per kW of capacity
generally increase as size decreases. While the overall cost of plants with a given steam output would be
similar, the amount of steam extracted for process use, and thus not available for power generation, has
a significant effect on the costs quoted in $/kW of electricity out.

Steam turbine costs exhibit a modest extent of irregularity, as steam turbines are made in sizes with
finite steps between the sizes. The cost of the turbine is generally the same for the upper and lower limit
of the steam flowing through it, so step-like behavior is sometimes seen in steam turbine prices. Since
they come in specific size increments, a steam turbine that is used at the upper end of its range of
power capability costs less per kW generated than one that is used at the lower end of its capability.
Additionally, raw material cost, local labor rates, delivery times, availability of existing major
components, and similar business conditions can affect steam turbine pricing.

Often steam turbines are sold to fit into an existing plant. In some of these applications, the
specifications, mass flow, pressure, temperature and backpressure or extraction conditions are
customized and therefore do not expose themselves to large competition. These somewhat unique
machines may be more expensive per kilowatt than other machines that are more generalized, and
therefore face greater competition. This is the case for three reasons: 1) a greater amount of custom
engineering and manufacturing setup may be required; 2) there is less potential for sales of duplicate or
similar units; and 3) there are fewer competitive bidders. The truly competitive products are the "off-
the-rack" type machines, while "custom" machines are naturally more expensive.

Because of the relatively high cost of the system, high annual capacity factors are required to enable a
reasonable recovery of invested capital.

However, retrofit applications of steam turbines into existing boiler/steam systems can be cost
competitive options for a wide variety of users depending on the pressure and temperature of the
steam exiting the boiler, the thermal needs of the site, and the condition of the existing boiler and
steam system. In such situations, the decision is based only on the added capital cost of the steam
turbine, its generator, controls and electrical interconnection, with the balance of plant already in place.
Similarly, many facilities that are faced with replacement or upgrades of existing boilers and steam
systems often consider the addition of steam turbines, especially if steam requirements are relatively
large compared to power needs within the facility.

In general, steam turbine applications are driven by balancing lower cost fuel or avoided disposal costs
for the waste fuel, with the high capital cost and (preferably high) annual capacity factor for the steam

77 "Cogeneration and Small Power Production Manual," Scott Spiewak and Larry Weiss, 1997. Data for a 32.3 MW multi-fuel
fired, 1,250 psig, 900 °F, 50 psig backpressure steam turbine used in an industrial cogeneration plant.

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plant, and the combined energy plant-process plant application through CHP. For these reasons, steam
turbines are not normally direct competitors of gas turbines and reciprocating engines.

Steam turbine prices vary greatly with the extent of competition and related manufacturing volumes for
units of desired size, inlet and exit steam conditions, rotational speed and standardization of
construction. Prices are usually quoted for an assembled steam turbine-electrical generator package.
The electrical generator can account for 20 percent to 40 percent of the assembly. As the steam
turbine/electrical generator package is heavy, due in large part to the heavy walled construction of the
high pressure turbine casing, it must be mounted carefully on an appropriate pedestal or baseplate. The
installation and connection to the boiler through high pressure-high temperature steam pipes must be
performed with engineering and installation expertise. As the high pressure steam pipes typically vary in
temperature by 750° F between cold standby/repair status and full power status, care must be taken in
installing a means to accommodate the differential expansion accompanying startup and shutdown to
minimize induced stress on the turbine casing. Should the turbine have variable extraction, the cost of
the extraction valve and control system adds to the installation.

Small steam turbine generators of less than 1,000 kW are generally more expensive on a per KW basis.
However, products have been developed and are being marketed specifically for small market
applications.

As the steam for a steam turbine is generated in a boiler by combustion and heat transfer, the
temperature of the steam is limited by furnace heat transfer design and manufacturing consideration
and boiler tube bundle design. Higher heat fluxes in the boiler enable more compact boilers, with less
boiler tube material to be built, however, higher heat fluxes also result in higher boiler tube
temperature and the need for the use of a higher grade (adequate strength at higher temperature)
boiler tube material. Such engineering economic tradeoffs between temperature (with consequential
increases in efficiency) and cost appear throughout the steam plant.

4.4.4 Maintenance

Steam turbines are very rugged units, with operational life often exceeding 50 years. Maintenance is
simple, comprised mainly of making sure that all fluids (steam flowing through the turbine and the oil
for the bearing) are always clean and at the proper temperature with low levels of moisture or high
steam quality or superheat. The oil lubrication system must be clean and at the correct operating
temperature and level to maintain proper performance. Other items include inspecting auxiliaries such
as lubricating-oil pumps, coolers and oil strainers and checking safety devices such as the operation of
overspeed trips.

In order to obtain reliable service, steam turbines require long warm-up periods so that there are
minimal thermal expansion stress and wear concerns. Steam turbine maintenance costs are typically
below $0.01/kWh. Boilers and any associated solid fuel processing and handling equipment that is part
of the boiler/steam turbine plant require their own types of maintenance which can add $0.02/kWh for
maintenance and $0.015/kWh for operating labor.

One maintenance issue with steam turbines is that solids can carry over from the boiler and deposit on
turbine nozzles and other internal parts, degrading turbine efficiency and power output. Some of these

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are water soluble but others are not. Three methods are employed to remove such deposits: 1) manual
removal; 2) cracking off deposits by shutting the turbine off and allowing it to cool; and 3) for water
soluble deposits, water washing while the turbine is running.

An often-overlooked component in the steam power system is the steam (safety) stop valve, which is
immediately ahead of the steam turbine and is designed to be able to experience the full temperature
and pressure of the steam supply. This safety valve is necessary because if the generator electric load
were lost (an occasional occurrence), the turbine would rapidly overspeed and destroy itself. Other
accidents are also possible, supporting the need for the turbine stop valve, which may add significant
cost to the system.

4.4.5	Fuels

Industrial boilers operate on a wide variety of fuels, including wood, coal, natural gas, oils (including
residual oil, the leftover material when the valuable distillates have been separated for separate sale),
municipal solid waste and sludge. The fuel handling, storage and preparation equipment needed for
solid fuels considerably adds to the cost of an installation. Thus, such fuels are used only when a high
annual capacity factor is expected of the facility, or when the solid material has to be disposed of to
avoid an environmental or space occupancy problem.

4.4.6	System Availability

Steam turbines are generally considered to have 99 percent plus availability with longer than one year
between shutdowns for maintenance and inspections. This high level of availability applies only to the
steam turbine, not to the boiler or HRSG that is supplying the steam. For complete systems, the
complexity of the fuel handling, combustion, boiler, and emissions, especially for solid fuels, brings
overall availability down below that of reciprocating engines and gas turbines. As shown in Table 4-3, a
survey of 16 small steam turbine power systems showed an average availability of 90.6 percent with a
range of 72.4-99.8 percent. The best system ran for a period of two years without a forced outage.

Table 4-3. Steam Turbine Availability

Other Technologies

Steam Turbines <25MW

Number Sampled

16



Min.

Avg.

Max.

Availability (%)

72.37

90.59

99.82

Forced Outage Rate (%)

0.00

3.12

16.41

Scheduled Outage Factor (%)

0.00

6.88

27.63

Service Factor (%)

3.37

78.72

99.65

Mean Time Between Forced Outages (hrs)

120

828

16,600

Source: ICF78

4.5 Emissions and Emissions Control Options

Emissions associated with a steam turbine are dependent on the source of the boiler input fuel. Steam
turbines can be used with a boiler firing any one or a combination of a large variety of fuel sources, or

78 Distributed Generation Operational Reliability and Availability Database, EEA, Inc. (now part of ICF) for ORNL, 2003.

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they can be used with a gas turbine in a combined cycle configuration. Boiler emissions vary depending
on fuel type and environmental conditions.

Table 4-4 illustrates typical emissions of NOx, PM, and CO for boilers by size of steam turbine system and
by fuel type. SOx emissions are not based on the size of the boiler; rather, they are a function of the
sulfur content of the fuel and the fuel combustion rate. Based on using the average fuel heat content
assumptions, uncontrolled input emissions for SOx range from 0.49-1.9 Ibs/MMBtu from coal/91.16-
2.22 Ibs/MMBtu from wood,80 1.53lbs/MMBtu from fuel oils,81 and very little to insignificant levels from
natural gas combustion.

Table 4-4. Typical Boiler Emissions Ranges

Boiler Fuel

System 1
500 kW

Systems 2 and 3
3 MW / 15 MW

NOx

CO

PM

NOx

CO

PM

Coal (Ibs/MMBtu)

N/A

N/A

N/A

0.20-1.24

0.0.02-0.7



Wood

(Ibs/MMBtu)

0.22-0.49

0.6

0.33-0.56

0.22-0.49

0.06

0.33-0.56

Fuel Oil
(Ibs/MMBtu)

0.15-0.37

0.03

0.01-0.08

0.07-0.31

0.03

0.01-0.08

Natural Gas
(Ibs/MMBtu)

0.03-0.1

0.08

-

0.1-0.28

0.08

-

Note: all emissions values are without post-combustion treatment.

Source: EPA, Compilation of Air Pollutant Emission Factors, AP-42, Fifth Edition, Volume I: Stationary Point and Area
Sources

4.5.1 Boiler Emissions Control Options - NOx

NOx control has been a focus of emission control research and development in boilers. The following
provides a description of the most prominent emission control approaches.

4.5.1.1 Combustion Process emissions Control

Combustion control techniques are less costly than post-combustion control methods and are often
used on industrial boilers for NOx control. Control of combustion temperature has been the principal
focus of combustion process control in boilers. Combustion control requires tradeoffs - high
temperatures favor complete burn up of the fuel and low residual hydrocarbons and CO, but promote
NOxformation. Very lean combustion dilutes the combustion process and reduces combustion
temperatures and NOxformation, and allows a higher compression ratio or peak firing pressures
resulting in higher efficiency. However, if the mixture is too lean, misfiring and incomplete combustion
occurs, increasing CO and VOC emissions.

79 http://www.eia.gov/coal/production/quarterly/co2_article/co2.html

so

http://www20.gencat.cat/docs/dmah/Home/Ambits%20dactuacio/Medi%20natural/Gestio%20forestal/Funcions%20dels%20b

oscos/Funcions%20productores%20dei%20bosc/Biomassa%20forestai/Activitats%20realitzades/Curs%20daprofitament%20de%

20biomassa%20forestai/2_ncp.pdf

81 http://www.imo.org/OurWork/Environment/PoilutionPrevention/AirPollution/Pages/Sulphur-oxides-(SOx)-%E2%80%93-
Reguiation-14. aspx

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4.5.1.2	Flue Gas Recirculation (FGR)

FGR is the most effective technique for reducing NOx emissions from industrial boilers with inputs below
100 MMBtu/hr. With FGR, a portion of the relatively cool boiler exhaust gases re-enter the combustion
process, reducing the flame temperature and associated thermal NOx formation. It is the most popular
and effective NOx reduction method for firetube and watertube boilers, and many applications can rely
solely on FGR to meet environmental standards.

External FGR employs a fan to recirculate the flue gases into the flame, with external piping carrying the
gases from the stack to the burner. A valve responding to boiler input controls the recirculation rate.
Induced FGR relies on the combustion air fan for flue gas recirculation. A portion of the gases travel via
ductwork or internally to the air fan, where they are premixed with combustion air and introduced into
the flame through the burner. Induced FGR in newer designs utilize an integral design that is relatively
uncomplicated and reliable.

The physical limit to NOx reduction via FGR is 80 percent in natural gas-fired boilers and 25 percent for
standard fuel oils.

4.5.1.3	Low Excess Air Firing (LAE)

Boilers are fired with excess air to ensure complete combustion. However, excess air levels greater than
45 percent can result in increased NOx formation, because the excess nitrogen and oxygen in the
combustion air entering the flame combine to form thermal NOx. Firing with low excess air means
limiting the amount of excess air that enters the combustion process, thus limiting the amount of extra
nitrogen and oxygen entering the flame. This is accomplished through burner design modification and is
optimized through the use of oxygen trim controls.

LAE typically results in overall NOx reductions of 5 to 10 percent when firing with natural gas, and is
suitable for most boilers.

4.5.1.4	Low Nitrogen Fuel Oil

NOx formed by fuel-bound nitrogen can account for 20 to 50 percent of total NOx levels in oil-fired boiler
emissions. The use of low nitrogen fuels in boilers firing distillate oils is one method of reducing NOx
emissions. Such fuels can contain up to 20 times less fuel-bound nitrogen than standard No. 2 oil.

NOx reductions of up to 70 percent over NOx emissions from standard No. 2 oils have been achieved in
firetube boilers utilizing flue gas recirculation.

4.5.1.5	Burner Modifications

By modifying the design of standard burners to create a larger flame, lower flame temperatures and
lower thermal NOxformation can be achieved, resulting in lower overall NOxemissions. While most
boiler types and sizes can accommodate burner modifications, it is most effective for boilers firing
natural gas and distillate fuel oils, with little effectiveness in heavy oil-fired boilers. Also, burner
modifications must be complemented with other NOx reduction methods, such as flue gas recirculation,
to comply with the more stringent environmental regulations. Achieving low NOx levels (30 ppm)
through burner modification alone can adversely impact boiler operating parameters such as turndown,
capacity, CO levels, and efficiency.

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4.5.1.6 Water/Steam Injection

Injecting water or steam into the flame reduces flame temperature, lowering thermal NOxformation and
overall NOx emissions. However, under normal operating conditions, water/steam injection can lower
boiler efficiency by 3 to 10 percent. Also, there is a practical limit to the amount that can be injected
without causing condensation-related problems. This method is often employed in conjunction with
other NOx control techniques such as burner modifications or flue gas recirculation.

When used with natural gas-fired boilers, water/steam injection can result in NOx reduction of up to
80 percent, with lower reductions achievable in oil-fired boilers.

4.5.2 Post-Combustion Emissions Control

There are several types of exhaust gas treatment processes that are applicable to industrial boilers.

4.5.2.1	Selective Non-Catalytic Reduction (SNCR)

In a boiler with SNCR, a NOx reducing agent such as ammonia or urea is injected into the boiler exhaust
gases at a temperature in the 1,400 to 1,600° F range. The agent breaks down the NOx in the exhaust
gases into water and atmospheric nitrogen (N2). While SNCR can reduce boiler NOx emissions by up to
70 percent, it is very difficult to apply this technology to industrial boilers that modulate or cycle
frequently because the agent must be introduced at a specific flue gas temperature in order to perform
properly. Also, the location of the exhaust gases at the necessary temperature is constantly changing in
a cycling boiler.

4.5.2.2	Selective Catalytic Reduction (SCR)

This technology involves the injection of the reducing agent into the boiler exhaust gas in the presence
of a catalyst. The catalyst allows the reducing agent to operate at lower exhaust temperatures than
SNCR, in the 500 to 1,200° F depending on the type of catalyst. NOx reductions of up to 90 percent are
achievable with SCR. The two agents used commercially are ammonia (NH3 in anhydrous liquid form or
aqueous solution) and aqueous urea. Urea decomposes in the hot exhaust gas and SCR reactor,
releasing ammonia. Approximately 0.9 to 1.0 moles of ammonia is required per mole of NOx at the SCR
reactor inlet in order to achieve an 80 to 90 percent NOx reduction.

SCR is however costly to use and can only occasionally be justified on boilers with inputs of less than 100
MMBtu/hr. SCR requires on-site storage of ammonia, a hazardous chemical. In addition, ammonia can
"slip" through the process unreacted, contributing to environmental and health concerns.

4.5.2.3	Boiler Emissions Control Options - SOx

The traditional method for controlling SOx emissions is dispersion via a tall stack to limit ground level
emissions. The more stringent SOx emissions requirements in force today demand the use of reduction
methods as well. These include use of low sulfur fuel, desulfurizing fuel, and flue gas desulfurization
(FGD). Desulfurization of fuel, such as in FGD, primarily applies to coal, and is principally used for utility
boiler emissions control. Use of low sulfur fuels is the most cost effective SOx control method for
industrial boilers, as it does not require installation and maintenance of special equipment.

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FGD systems are of two types: non-regenerable and regenerable. The most common non-regenerable
results in a waste product that requires proper disposal. Regenerable FGD converts the waste product
into a product that is saleable, such as sulfur or sulfuric acid. SOx emissions reductions of up to 95
percent can be obtained with FGD.

4.6 Future Developments

While steam turbines are a mature technology, their importance in worldwide power generation makes
incremental improvements in cost and performance very beneficial. Higher efficiencies reduce fuel
consumption, emissions of air pollutants and greenhouse gases, and cooling water requirements. Since
commercial introduction, efficiencies for large condensing steam turbines have increased from the mid-
teens to up to 48 percent. The U.S. Department of Energy funds collaborative research and development
toward the development of improved ultra-supercritical (USC) steam turbines capable of efficiencies of
55-60 percent that are based on boiler tube materials that can withstand pressures of up to 5,000 psi
and temperatures of 1,400° F. To achieve these goals, work is ongoing in materials, internal design and
construction, steam valve development, and design of high pressure casings. A prototype is targeted for
commercial testing by 2025.82

Research is also underway to restore and improve the performance of existing steam turbines in the
field through such measures as improved combustion systems for boilers, heat transfer and
aerodynamics to improve turbine blade life and performance, and improved materials to permit longer
life and higher operating temperatures for more efficient systems.83

The focus on renewable markets, such as waste heat recovery, biomass fueled power, and CHP plants, is
stimulating the demand for small and medium steam turbines. Technology and product development for
these markets should bring about future improvements in steam turbine efficiency, longevity, and cost.
This could be particularly true for systems below 500 kW that are used in developmental small biomass
systems, and in waste-heat-to-power systems, as the latter is designed to operate in place of pressure
reduction valves in commercial and industrial steam systems operating at multiple pressures.

82	Advanced TurbinesTechnology Program Plan, National Energy Technology Laboratory, Clean Coal Research Program, U.S.
Department of Energy, January 2013.

83	Energy Tech, http://www.energy-tech.com/article.cfm?id=17566

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Section 5. Technology Characterization - Microturbines

5.1 Introduction

Microturbines, as the name implies, are small combustion turbines that burn gaseous or liquid fuels to
drive an electrical generator, and have been commercially available for more than a decade. Today's
microturbine technology is the result of development work in small stationary and automotive gas
turbines, auxiliary power equipment, and turbochargers, much of which took place in the automotive
industry beginning in the 1950s. The development of microturbine systems was accelerated by the
similarity of design to large engine turbochargers, and that provided the basis for the engineering and
manufacturing technology of microturbine components.

During the 1990s several companies developed competing microturbine products and entered, or
planned to enter, the market. As the market matured, the industry underwent a consolidation phase
during which companies merged, changed hands, or dropped out of the market. In the United States
today, this has led to two main manufacturers of stationary microturbine products - Capstone Turbine
Corporation and FlexEnergy.

Table 5-1 provides a summary of microturbine attributes. Microturbines range in size from 30 to 330
kilowatts (kW). Integrated packages consisting of multiple microturbine generators are available up to
1,000 kW, and such multiple units are commonly installed at sites to achieve larger power outputs.
Microturbines are able to operate on a variety of fuels, including natural gas, sour gas (high sulfur, low
Btu content), and liquid petroleum fuels (e.g., gasoline, kerosene, diesel fuel, and heating oil).

Table 5-1. Summary of Microturbine Attributes

Electrical Output

Available from 30 to 330 kW with integrated modular packages up to 1,000 kW.

Thermal Output

Exhaust temperatures in the range of 500 to 600 °F, suitable for supplying a
variety of site thermal needs, including hot water, steam, and chilled water
(using an absorption chiller).

Fuel Flexibility

Can utilize a number of different fuels, including natural gas, sour gas (high
sulfur, low Btu content), and liquid fuels (e.g., gasoline, kerosene, diesel fuel, and
heating oil).

Reliability and life

Design life is estimated to be 40,000 to 80,000 hours with overhaul.

Emissions

Low NOx combustion when operating on natural gas; capable of meeting
stringent California standards with carbon monoxide/volatile organic compound
(CO/VOC) oxidation catalyst.

Modularity

Units may be connected in parallel to serve larger loads and to provide power
reliability.

Part-load Operation

Units can be operated to follow load with some efficiency penalties.

Dimensions

Compact and light weight, 2.3-2.7 cubic feet (cf) and 40-50 pounds per kW.

5.2 Applications

Microturbines are ideally suited for distributed generation applications due to their flexibility in
connection methods, their ability to be stacked in parallel to serve larger loads, their ability to provide

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stable and reliable power, and their low emissions compared to reciprocating engines. Important
applications and functions are described below:

•	Combined heat and power (CHP) - microturbines are well suited to be used in CHP applications
because the exhaust heat can either be recovered in a heat recovery boiler, or the hot exhaust
gases can be used directly. Typical natural gas fueled CHP markets include:

c Commercial - hotels, nursing homes, health clubs
c Institutional - public buildings

c Industrial - small operations needing hot water or low pressure steam for wash water as in
the food and manufacturing sectors

•	Combined cooling heating and power (CCHP) - The temperature available for microturbine
exhaust allows effective use with absorption cooling equipment that is driven either by low
pressure steam or by the exhaust heat directly. Cooling can be added to CHP in a variety of
commercial/institutional applications to provide both cooling and heating.

•	Resource recovery-the ability of microturbines to burn a variety of fuels make it useful for
resource recovery applications including landfill gas, digester gas, oil and gas field pumping and
power applications, and coal mine methane use.

•	Peak shaving and base load power (grid parallel).

•	Thermal oxidation of very low Btu fuel or waste streams - Microturbine systems have been
designed to provide thermal oxidation for applications needing methane or volatile organic
compound destruction such as for landfill gas or other waste gases.

•	Premium power and power quality - due to the inverter based generators, power quality
functionality can be added to CHP, and power-only applications allowing the system to be part
of an overall uninterruptible power supply (UPS) system providing black start capability and
back-up power capability to provide power when the electrical grid is down. The system can also
provide voltage and other power quality support. Such functions are useful for applications with
high outage costs and sensitive power needs including small data centers, hospitals, nursing
homes, and a variety of other applications that have critical service requirements.

•	Power only applications - microturbines can be used for stand-alone power in remote
applications where grid power is either unavailable or very high cost. The systems can also run
as back-up power or in peak-shaving mode, though such use is limited.

•	Microgrid - Microturbines are inverter based generation, and are therefore well-suited for
application in utility microgrids, providing grid support and grid communication functions. This
area of use is in a development and demonstration phase by electric power companies.

5.3 Technology Description
5.3.1 Basic Process

Microturbines operate on the same thermodynamic cycle (Brayton Cycle) as larger gas turbines and
share many of the same basic components. In this cycle, atmospheric air is compressed, heated (usually

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by introducing and burning fuel), and then these hot gases drive an expansion turbine that drives both
the inlet compressor and a drive shaft capable of providing mechanical or electrical power. Other than
the size difference, microturbines differ from larger gas turbines in that they typically have lower
compression ratios and operate at lower combustion temperatures. In order to increase efficiency,
microturbines recover a portion of the exhaust heat in a heat exchanger called a recuperator, to
increase the energy of the gases entering the expansion turbine thereby boosting efficiency.
Microturbines operate at high rotational speeds of up to 60,000 revolutions per minute. Of the two
primary players in the domestic industry, Capstone couples this shaft output directly to a high speed
generator and uses power electronics to produce 60 Hz electricity. FlexEnergy uses a gearbox to reduce
the drive speed to 3600 rpm to power a synchronous electric generator.

5.3.2 Components

Figure 5-1 shows a schematic diagram of the basic microturbine components, which include the
combined compressor/turbine unit, generator, recuperator, combustor, and CHP heat exchanger. Each
of these primary components is described further below.

Figure 5-1. Microturbine-based CHP System Schematic

POWER EXHAUST

Source: FlexEnergy
5.3.2.1 Turbine & Compressor

The heart of the microturbine is the compressor-turbine package (or turbocompressor), which is
commonly mounted on a single shaft along with the electric generator. The shaft, rotating at upwards of
60,000 rpm, is supported on either air bearings or conventional lubricated bearings. The single moving
part of the one-shaft design has the potential for reducing maintenance needs and enhancing overall
reliability.

Microturbine turbomachinery is based on single-stage radial flow compressors and turbines, unlike
larger turbines that use multi-stage axial flow designs. Radial design turbomachinery handles the small
volumetric flows of air and combustion products with reasonably high component efficiency.84 Large-

1 With axial flow turbomachinery, blade height would be too small to be practical.

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size axial flow turbines and compressors are typically more efficient than radial flow components.
However, in the size range for microturbines - 0.5 to 5 lbs/second of air/gas flow - radial flow
components offer minimum surface and end wall losses thereby improving efficiency.

As mentioned earlier, microturbines operate on either oil-lubricated or air bearings, which support the
shaft. Oil-lubricated bearings are mechanical bearings and come in three main forms - high-speed metal
roller, floating sleeve, and ceramic surface. Ceramic surface bearings typically offer the most attractive
benefits in terms of life, operating temperature, and lubricant flow. While they are a well-established
technology, they require an oil pump, oil filtering system, and liquid cooling that add to microturbine
cost and maintenance. In addition, the exhaust from machines featuring oil-lubricated bearings may not
be useable for direct space heating in cogeneration configurations due to the potential for air
contamination.

Air bearings allow the turbine to spin on a thin layer of air, so friction is low and rpm is high. They have
been in service on airplane cabin cooling systems for many years. No oil or oil pump is needed. Air
bearings offer simplicity of operation without the cost, reliability concerns, maintenance requirements,
or power drain of an oil supply and filtering system.

5.3.2.2 Generator

The microturbine produces electrical power either via a high-speed generator turning on the single
turbo-compressor shaft or through a speed reduction gearbox driving a conventional 3,600 rpm
generator. The high-speed generator single-shaft design employs a permanent magnet, and an air-
cooled generator producing variable voltage and high-frequency AC power. This high frequency AC
output (about 1,600 Hz for a 30 kW machine) is converted to constant 60 Hz power output in a power
conditioning unit. Power conditioning involves rectifying the high frequency AC to DC, and then inverting
the DC to 60 Hz AC. However, power conversion comes with an efficiency penalty (approximately 5
percent). In addition to the digital power controllers converting the high frequency AC power into usable
electricity, they also filter to reduce harmonic distortion in the output. The power conditioning unit is a
critical component in the single-shaft microturbine design and represents significant design challenges,
specifically in matching turbine output to the required load. To accommodate transients and voltage
spikes, power electronic units are generally designed to handle seven times the nominal voltage. Most
microturbine power electronics generate three-phase electricity.

To start-up a single shaft design, the generator acts as a motor turning the turbo-compressor shaft until
sufficient rpm is reached to start the combustor. If the system is operating independent of the grid
(black starting), a power storage unit (typically a battery) is used to power the generator for start-up.

Electronic components also direct all of the operating and startup functions. Microturbines are generally
equipped with controls that allow the unit to be operated in parallel or independent of the grid, and
internally incorporate many of the grid and system protection features required for interconnection. The
controls also allow for remote monitoring and operation.

Figure 5-2 provides an example of the compact design of the basic microturbine components (in this
case, for the Capstone model C200 (200 kW)). The turbocompressor section, riding on air bearings,

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drives the high speed, air cooled generator. The entire assembly is surrounded by a can like structure
housing the recuperator and the combustion chamber.

Figure 5-2. Compact Microturbine Design

An
Inta

Fuel Injector

.Combustion
Chamber

Source: Capstone Turbines, C200

5.3.2.3	Recuperator & Combustor

The recuperator is a heat exchanger that uses the hot turbine exhaust gas (typically around 1,2002F) to
preheat the compressed air (typically around 3002F) going into the combustor, thereby reducing the fuel
needed to heat the compressed air to the required turbine inlet temperature. Depending on
microturbine operating parameters, recuperators can more than double machine efficiency. However,
since there is increased pressure drop on both the compressed air and turbine exhaust sides of the
recuperator, this increased efficiency comes at the expense of about a 10-15 percent drop in power
output.

5.3.2.4	CHP Heat Exchanger

In CHP operation, microturbines offer an additional heat exchanger package, integrated with the basic
system, that extracts much of the remaining energy in the turbine exhaust, which exits the recuperator
at about 500-600° F. Exhaust heat can be used for a number of different applications, including potable
water heating, space heating, thermally activated cooling and dehumidification systems (absorption
chillers, desiccant dehumidification). Because microturbine exhaust is clean and has a high percentage
(15 percent) of oxygen, it can also be used directly for process applications such as driving a double-
effect absorption chiller or providing preheat combustion air for a boiler or process heat application.

5.4 Performance Characteristics

Table 5-2 summarizes cost and performance characteristics for typical microturbine CHP systems
ranging in size from 30 kW to 1 MW. Heat rates and efficiencies are based on manufacturers'
specifications for systems operating on natural gas, the predominant fuel choice in CHP applications.
The table assumes that natural gas is delivered at typical low delivery pressures which require a booster

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compressor to raise the gas pressure to the point at which it can be introduced into the compressed
inlet air-stream. Electrical efficiencies and heat rates shown are net of power losses from the gas
booster compressor. Customers that have, or can gain access to, high pressure gas from their local gas
utility can avoid the capacity and efficiency losses due to fuel gas compression. Capital costs, described
in more detail in a later section, are based on assumptions of a basic grid connect installation.
Installation costs can vary widely depending on site conditions and regional differences in material,
labor, and site costs. Available thermal energy is calculated based on manufacturer specifications on
turbine exhaust flows and temperatures. CHP thermal recovery estimates are based on producing hot
water for process or space heating applications. All performance specifications are at full load
International Organization for Standards (ISO) conditions (59 °F, 60 percent RH, 14.7 psia).

The data in the table show that electrical efficiency generally increases as the microturbine becomes
larger. Microturbines have lower electrical efficiencies than reciprocating engines and fuel cells, but are
capable of high overall CHP efficiencies. The low power to heat ratios (P/H) of microturbines (which
implies relatively more heat production), makes it important for both overall efficiency and for
economics to be sited and sized for applications that allow full utilization of the available thermal
energy.

As shown, microturbines typically require 50 to 140 psig fuel supply pressure. Local distribution gas
pressures usually range from 30 to 130 psig in feeder lines and from 1 to 50 psig in final distribution
lines. If available, sites that install microturbines will generally opt for high pressure gas delivery rather
than adding the cost of a booster compressor with its accompanying efficiency and capacity losses.

Estimated installed capital costs range from $4,300/kW for the 30 kW system down to $2,500/kW for
the 1,000 kW system - described in more detail in Section Capital Cost.

Table 5-2. Microturbine Cost and Performance Characteristics

Microturbine Characteristics [1]

System

1

2

3

4

5

6

Nominal Electricity Capacity (kW)

30

65

200

250

333

1000

Compressor Parasitic Power (kW)

2

4

10

10

13

50

Net Electricity Capacity (kW)

28

61

190

240

320

950

Fuel Input (MMBtu/hr), HHV

0.434

0.876

2.431

3.139

3.894

12.155

Required Fuel Gas Pressure (psig)

55-60

75-80

75-80

80-140

90-140

75-80

Electric Heat Rate (Btu/kWh), LHV [2]

13,995

12,966

11,553

11,809

10,987

11,553

Electric Efficiency (%), LHV [3]

24.4%

26.3%

29.5%

28.9%

31.1%

29.5%

Electric Heat Rate (Btu/kWh), HHV

15,535

14,393

12,824

13,110

12,198

12,824

Electric Efficiency (%), HHV

21.9%

23.7%

26.6%

26.0%

28.0%

26.6%

CHP Characteristics

Exhaust Flow (lbs/sec)

0.68

1.13

2.93

4.7

5.3

14.7

Exhaust Temp (°F)

530

592

535

493

512

535

Heat Exchanger Exhaust Temp (°F)

190

190

200

190

190

200

Heat Output (MMBtu/hr)

0.21

0.41

0.88

1.28

1.54

4.43

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Table 5-2. Microturbine Cost and Performance Characteristics

Microturbine Characteristics [1]

System

1

2

3

4

5

6

Heat Output (kW equivalent)

61.0

119.8

258.9

375.6

450.2

1,299.0

Total CHP Efficiency (%), HHV [4]

70.0%

70.4%

63.0%

66.9%

67.5%

63.1%

Total CHP Efficiency (%), LHV

77.3%

77.8%

69.6%

73.9%

74.6%

69.8%

Power/Heat Ratio [5]

0.46

0.51

0.73

0.64

0.71

0.73

Net Heat Rate (Btu/kWh) [6]

6,211

5,983

6,983

6,405

6,170

6,963

Effective Electric Eff. (%), HHV [7]

54.9%

57.0%

48.9%

53.3%

55.3%

49.0%

Cost

CHP Package Cost ($/kW) [8]

$2,690

$2,120

$2,120

$1,840

$1,770

$1,710

Total Installed Cost ($/kW) [9]

$4,300

$3,220

$3,150

$2,720

$2,580

$2,500

Notes:

1.	Characteristics presented are representative of commercially available microturbine systems. Table data are based from
smallest to largest: Capstone C30,; Capstone C65 CARB, Capstone C200 CARB, FlexEnergy MT250, FlexEnergy MT330,
Capstone C1000-LE

2.	Turbine and engine manufacturers quote heat rates in terms of the lower heating value (LHV) of the fuel. Gas utilities
typically report the energy content on a higher heating value (HHV) basis. In addition, electric utilities measure power
plant heat rates in terms of HHV. For natural gas, the average heat content is near 1,030 Btu/scf on an HHV basis and
about 930 Btu/scf on an LHV basis - a ratio of approximately 0.9 (LHV / HHV).

3.	Electrical efficiencies are net of parasitic and conversion losses. Fuel gas compressor needs based on 1 psi inlet supply.

4.	Total Efficiency = (net electricity generated + net heat produced for thermal needs)/total system fuel input

5.	Power/Heat Ratio = CHP electrical power output (Btu)/ useful heat output (Btu)

6.	Net Heat Rate = (total fuel input to the CHP system - the fuel that would be normally used to generate the same amount of
thermal output as the CHP system output assuming an efficiency of 80 percent)/CHP electric output (kW).

7.	Effective Electrical Efficiency = (CHP electric power output) / (total fuel into CHP system - total heat recovered/0.8).

8.	Equipment cost only. The cost for all units, except the 30 kW size, includes integral heat recovery water heater. All units
include a fuel gas booster compressor.

9.	Installed costs based on CHP system producing hot water from exhaust heat recovery in a basic installation in grid connect
mode.

5.4.1 Part-Load Performance

Microturbines that are in applications that require electric load following must operate during some
periods at part load. Although, operationally, most installations are designed to operate at a constant
output without load-following or frequent starts and stops. Multiple unit installations can achieve load
following through sequentially turning on more units requiring less need for part load operation. When
less than full electrical power is required from a microturbine, the output is reduced by a combination of
mass flow reduction (achieved by decreasing the compressor speed) and turbine inlet temperature
reduction. In addition to reducing power, this change in operating conditions also reduces efficiency.
Figure 5-3 shows a sample part-load efficiency curve for the Capstone C65. At 50 percent power output,
the electrical efficiency drops by about 15 percent (decline from approximately 30 percent to 25
percent). However, at 50 percent power output, the thermal output of the unit only drops 41 percent
resulting in a net loss of CHP efficiency of only 5 percent.

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Figure 5-3. Part Load Efficiency at ISO Conditions, Capstone C65
C65 ISO Part Load Efficiency (Nominal Engine)

Net Power [kW]

Source: Capstone, C65 Technical Reference
5.4.2 Effects of Ambient Conditions on Performance

The ambient conditions (temperature and air pressure) under which a microturbine operates have a
noticeable effect on both the power output and efficiency. This section provides a better understanding
of the changes observed due to changes in temperature and air pressure. At elevated inlet air
temperatures, both the power and efficiency decrease. The power decreases due to the decreased mass
flow rate of air (since the density of air declines as temperature increases), and the efficiency decreases
because the compressor requires more power to compress air that is less dense. Conversely, the power
and efficiency increase with reduced inlet air temperature.

Figure 5-5 shows the variation in power and efficiency for a microturbine as a function of ambient
temperature compared to the reference International Organization for Standards (ISO) condition of sea
level and 59°F. The density of air decreases at altitudes above sea level. Consequently, power output
decreases. Figure 5-4 shows the effect of temperature on output, and Figure 5-5 shows the effect on
efficiency for the Capstone C200. The Capstone unit maintains a steady output up to 70-80 °F due to a
limit on the generator output. However, the efficiency declines more uniformly as ambient temperature
increases. Figure 5-6 shows a combined power and efficiency curve for the FlexEnergy MT250. For this
model, both power output and efficiency change more or less uniformly above and below the ISO rating
point.

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Figure 5-4. Temperature Effect on Power, Capstone C200-LP

C200 LPNG Net Power vs. Ambient Temperature at Sea Level

200
180
100
140

I. 120
s

1100
I 80

60
40

20
0

0 10 20 30 40 50 SO 70 80 SO 100 110 120

Ambient Temperature [°F]

Source: Capstone Turbines

























































































































•





























•



^^"Normnal

















num
mum









C200 Low Pressure























Natur

al bas















































































































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Figure 5-5. Temperature Effect on Efficiency, Capstone C200-LP
C200 LPNG Net Efficiency vs. Ambient Temperature at Sea Level

10 20 30 40 50 60 70 80

Ambient Temperature [CF]

90

100

110

120

Source: Capstone Turbines

Figure 5-6. Temperature Effect on Power and Efficiency, FlexEnergy MT250
-18C -7	4

1

in

+i

¦w

QJ

.
U
C

.2
"0

Source: FlexEnergy

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Inlet air cooling can mitigate the decreased power and efficiency resulting from high ambient air
temperatures. While inlet air cooling is not a feature on today's microturbines, cooling techniques now
entering the market, or being employed, on large gas turbines may work their way into next generation
microturbine products.

Evaporative cooling, a relatively low capital cost technique, is the most likely inlet air cooling technology
to be applied to microturbines. It uses a very fine spray of water directly into the inlet air stream.
Evaporation of the water reduces the temperature of the air. Since cooling is limited to the wet bulb air
temperature, evaporative cooling is most effective when the wet bulb temperature is significantly below
the dry bulb temperature. In most locales with high daytime dry bulb temperatures, the wet bulb
temperature is often 20^F lower. This temperature difference affords an opportunity for substantial
evaporative cooling. However, evaporative cooling can consume large quantities of water, making it
difficult to operate in arid climates.

Refrigeration cooling in microturbines is also technically feasible. In refrigeration cooling, a compression-
driven or thermally activated (absorption) refrigeration cycle cools the inlet air through a heat
exchanger. The heat exchanger in the inlet air stream causes an additional pressure drop in the air
entering the compressor, thereby slightly lowering cycle power and efficiency. However, as the inlet air
is now substantially cooler than the ambient air, there is a significant net gain in power and efficiency.
Electric motor driven refrigeration results in a substantial amount of parasitic power loss. Thermally
activated absorption cooling can use waste heat from the microturbine, reducing the direct parasitic
loss. The relative complexity and cost of these approaches, in comparison with evaporative cooling,
render them less likely.

Finally, it is also technically feasible to use thermal energy storage systems - typically ice, chilled water,
or low-temperature fluids - to cool inlet air. These systems eliminate most parasitic losses from the
augmented power capacity. Thermal energy storage is a viable option if on-peak power pricing only
occurs a few hours a day. In that case, the shorter time of energy storage discharge and longer time for
daily charging allow for a smaller and less expensive thermal energy storage system.

The density of air also decreases with increasing altitude. The effect of altitude derating on the Capstone
C65 is shown in Figure 5-7. An installation in the mile high city of Denver would have a capacity of only
56 kW - a 14 percent drop in capacity. Unlike the effects of temperature rise, an increase in altitude at a
given temperature does not have much impact on energy efficiency. The units operate at nearly the
same efficiency, though at a lower output.

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Figure 5-7. Ambient Elevation vs. Temperature Derating, Capstone C65

10 20 30 40 50 60 70 80

Ambient Temperature [=F]

80

too

110

120

130

Source: Capstone Turbines

Gas turbine and microturbine performance is also affected by inlet and exhaust back-pressure. ISO
ratings are at zero inlet pressure with no exhaust back-pressure. Adding the additional CHP heat
exchanger definitely produces some increase in exhaust back pressure. Pressure drops on the inlet side
from air filters also reduces the system output and efficiency. For the C65 shown in the previous figure,
every 1" pressure drop on the inlet side produces roughly a 0.6 percent drop in power and a 0.2 percent
drop in efficiency. A 1" pressure drop on the exhaust side produces about a 0.35 percent drop in power
and a 0.25 percent drop in efficiency.

It is important when evaluating microturbine performance at a given site to consider all of the derating
factors that are relevant: site altitude, average temperature and seasonal temperature swings, and
pressure loss derating resulting from filters and the CHP heat recovery system. The combination of these
factors can have a significant impact on both capacity and efficiency. Reduction in capacity also impacts
the unit costs of the equipment because the same costs are being spread over fewer kilowatts.

5.4.3 Capital Cost

This section provides study estimates of capital costs for basic microturbine CHP installations. It is
assumed that the thermal energy extracted from the microturbine exhaust is used for producing hot
water for use on-site. Equipment-only and installed costs are estimated for each representative
microturbine system. It should be emphasized that installed costs can vary significantly depending on
the scope of the plant equipment, geographical area, competitive market conditions, special site

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requirements, emissions control requirements, prevailing labor rates, and whether the system is a new
or a retrofit application.

Table 5-3 provides cost estimates for combined heat and power applications, assuming that the CHP
system produces hot water and that there is no fuel pretreatment. Thermal recovery in the form of
cooling can be accomplished with the addition of an absorption chiller - not included in this comparison.
The basic microturbine package consists of the microturbine and power electronics. All of the
commercial and near-commercial units offer basic interconnection and paralleling functionality as part
of the package cost. All but one of the systems offers an integrated heat exchanger heat recovery
system for CHP within the package.

There is little additional equipment that is required for these integrated systems. A heat recovery
system has been added where needed, and additional controls and remote monitoring equipment have
been added. The total plant cost consists of total equipment cost plus installation labor and materials
(including site work), engineering, project management (including licensing, insurance, commissioning
and startup), and financial carrying costs during a typical 3-month construction period.

The basic equipment costs represent material on the loading dock, ready to ship. It includes the cost of
the generator package, the heat recovery, the flue gas compression and interconnection equipment
cost. As shown in the table, the cost to a customer for installing a microturbine-based CHP system
includes a number of other factors that increase the total costs by 70-80 percent.

Labor/materials represent the labor cost for the civil, mechanical, and electrical work and materials such
as ductwork, piping, and wiring. A number of other costs are also incurred. These costs are often
referred to as soft costs and they vary widely by installation, by development channel and by approach
to project management. Engineering costs are required to design the system and integrate it
functionally with the application's electrical and mechanical systems. In this characterization,
environmental permitting fees are included. Project and construction management also includes general
contractor markup, and bonding and performance guarantees. Contingency is assumed to be 5 percent
of the total equipment cost in all cases. An estimated financial interest of 5 percent during a 3-month
construction period is also included.

The cost estimates shown represent a basic installation. In the California Self-Generation incentive
Program (SGIP) the average installation cost for 116 non-renewable fuel microturbine systems between
2001-2008 was $3,150/kW. For 26 renewable fueled systems over the same time period, the average
installed cost was $3,970/kW.85

Table 5-3. Equipment and Installation Costs



System

1

2

3

4

5

6

Electric Capacity

Nominal Capacity (kW)

30

65

200

250

333

1000

Net Capacity (kW)

28

61

190

240

320

950

85 CPUC Self-Generation Incentive Program: Cost Effectiveness of Distributed Generation Technologies, ITRON, Inc., 2011.

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Table 5-3. Equipment and Installation Costs



System

1

2

3

4

5

6

Equipment Costs

Gen Set Package

$53,100

$112,900

$359,300

$441,200

$566,400

$1,188,600

Heat Recovery

$13,500

$0

$0

$0

$0

$275,000

Fuel Gas Compression

$8,700

$16,400

$42,600

$0

$0

$164,000

Interconnection

$0

$0

$0

$0

$0

$0

Total Equipment ($)

$75,300

$129,300

$401,900

$441,200

$566,400

$1,627,600

($/kW)

$2,689

$2,120

$2,120

$1,840

$1,770

$1,710

Installation Costs

Labor/Materials

$22,600

$28,400

$80,400

$83,800

$101,900

$293,000

Project & Construction Mgmt

$9,000

$15,500

$48,200

$52,900

$68,000

$195,300

Engineering and Fees

$9,000

$15,500

$44,200

$48,500

$56,600

$162,800

Project Contingency

$3,800

$6,500

$20,100

$22,100

$28,300

$81,400

Financing (int. during const.)

$700

$1,200

$3,700

$4,100

$5,100

$14,800

Total Other Costs ($)

$45,100

$67,100

$196,600

$211,400

$259,900

$747,300

($/kW)

$1,611

$1,100

$1,035

$881

$812

$787

Total Installed Cost ($)

$120,400

$196,400

$598,500

$652,600

$826,300

$2,374,900

($/kW)

$4,300

$3,220

$3,150

$2,720

$2,580

$2,500

Source: Microturbine package costs and equipment from the vendors; installation costs developed by ICF.

As the table shows, there are economies of scale as sizes get larger. From 30 to 333 kW capital costs
increase as the 0.8 power factor of the capacity increase86 - a 100 percent increase in size results in an
80 percent increase in capital cost. Similar scale economies also exist for multiple unit installations such
as the 1,000 kW unit comprised of five 200-kW units. The unit cost of the larger system is only 80
percent of the cost of the single unit.

5.4.4 Maintenance

Maintenance costs vary with size, fuel type and technology (air versus oil bearings). A typical
maintenance schedule is shown in Table 5-4.

Table 5-4. Example Service Schedule, Capstone C65

Maintenance
Interval

Component

Maintenance
Action

Comments

24 months

UCB Battery

Replace

—

4,000 hours

Engine Air Filter

Inspect

Replace if application requires

Electronics Air Filter

Inspect

Clean if necessary

Fuel Filter Element (external)

Inspect

Replace if application requires (not
required for gas pack)

86 (Costi/Cost2) = (Sizei/Size2)0'8

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Table 5-4. Example Service Schedule, Capstone C65

Maintenance
Interval

Component

Maintenance
Action

Comments



Fuel System

Leak Check

—

8,000 hours

Engine Air Filter

Replace

—

Electronics Air Filter

Clean

—

Fuel Filter Element (external)

Replace

Not required for gas pack

Igniter

Replace

—

ICHP Actuator

Replace

—

20,000 hours
or 3 years

Battery Pack

Replace

—

20,000 hours

Injector Assemblies

Replace

—

TET Thermocouple

Replace

—

SPV

Replace

Replace with Woodward valve upgrade
kit

40,000 hours

Electronic Components: ECM,
LCM, & BCM Power Boards,
BCM & ECM Fan Filters, Fans,
EMI Filter, Frame PM

Replace

Kits available for each major
configuration

Engine

Replace

Remanufactured or new

Source: Adapted from Capstone C65 User's Manual.

Most manufacturers offer service contracts that cover scheduled and unscheduled events. The cost of a
full service contract covers the inspections and component replacements outlined in Table 5-5, including
replacement or rebuild of the main turbocompressor engine components. Full service costs vary
according to fuel type and service as shown.

Table 5-5. Maintenance Costs Based on Factory Service Contracts

Maintenance Costs

System

1

2

3

4

5

6

Nominal Electricity Capacity
(kW)

30

65

200

250

333

1000

Fixed ($/kW/yr)

—

—

—

$9,120

$6,847

—

Variable ($/kWh)

—

—

—

$0,010

$0,007

—

Average @ 6,000 hrs/year
operation ($/kWh)

—

$0,013

$0,016

$0,011

$0,009

$0,012

Source: Compiled by ICFfrom vendor supplied data

Maintenance requirements can be affected by fuel type and site conditions. Waste gas and liquid fuel
applications may require more frequent inspections and component replacement than natural gas
systems. Microturbines operating in dusty and/or dirty environments require more frequent inspections
and filter replacements.

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5.4.5	Fuels

Stationary microturbines have been designed to use natural gas as their primary fuel. Microturbines
designed for transportation applications typically utilize a liquid fuel such as methanol. As previously
noted, microturbines are capable of operating on a variety of fuels including:

•	Liquefied petroleum gas (LPG) - propane and butane mixtures

•	Sour gas - unprocessed natural gas as it comes directly from a gas well

•	Biogas - any of the combustible gases produced from biological degradation of organic wastes,
such as landfill gas, sewage digester gas, and animal waste digester gas

•	Industrial waste gases - flare gases and process off-gases from refineries, chemical plants and
steel mills

•	Manufactured gases - typically low- and medium-Btu gas produced as products of gasification
or pyrolysis processes

Some of the elements work as contaminants and are a concern with some waste fuels, specifically the
acid gas components (H2S, halogen acids, HCN, ammonia, salts and metal-containing compounds,
halogens, nitrogen compounds, and silicon compounds) and oils. In combustion, halogen and sulfur
compounds form halogen acids, S02, some S03, and possibly H2S04 emissions. The acids can also corrode
downstream equipment. Solid particulates must be kept to low concentrations to prevent corrosion and
erosion of components. Various fuel scrubbing, droplet separation, and filtration steps are required if
fuel contaminant levels exceed manufacturer specifications. Landfill gas in particular often contains
chlorine compounds, sulfur compounds, organic acids, and silicon compounds which dictate fuel
pretreatment. A particular concern with wastewater treatment and landfill applications is the control of
siloxane compounds. Siloxanes are a prevalent manmade organic compound used in a variety of
products, and they eventually find their way into landfills and waste water. When siloxanes are exposed
to high temperatures inside the combustion and exhaust sections of the turbine, they form hard silicon
dioxide deposits that can eventually lead to turbine failure.

5.4.6	System Availability

Microturbine systems in the field have generally shown a high level of availability.87 The basic design and
low number of moving parts is conducive to high availability; manufacturers have targeted availabilities
of 98-99 percent. The use of multiple units or backup units at a site can further increase the availability
of the overall facility.

5.5 Emissions

Microturbines are designed to meet State and federal emissions regulations including more stringent
State emissions requirements such as in California and other states (e.g., the Northeast). All
microturbines operating on gaseous fuels feature lean premixed (dry low NOx, or DLN) combustor
technology. All of the example commercial units have been certified to meet extremely stringent
standards in Southern California of less than 4-5 ppmvd of NOx (15 percent 02.) After employing a
CO/VOC oxidation catalyst, carbon monoxide (CO) and volatile organic compound (VOC) emissions are at

87 Availability refers to the percentage of time that the system is either operating or available to operate. Conversely, the
system is unavailable when it is shut down for maintenance or when there has been a forced outage.

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Microturbines


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the same level. "Non-California" versions have NOx emissions of less than 9 ppmvd. The emissions
characteristics are shown in Table 5-6.

Table 5-6. Microturbine Emissions Characteristics



System

1

2

3

4

5

6

Nominal Electric Capacity (kW)

30

65

200

240

320

1,000

Recovered Thermal Energy (kW)

61.0

119.8

258.9

376

450

1,299.0

Nominal Electrical Efficiency, HHV

23.6%

25.3%

28.1%

27.2%

29.2%

28.1%

NOx (ppm @ 15% 02, dry) [1]

9

4

4

5

9

4

NOx (Ib/MWh) [2]

0.49

0.17

0.14

0.23

0.39

0.14

NOx (Ib/MWh with CARB CHP credit)

0.16

0.06

0.06

0.09

0.16

0.06

CO (ppm @ 15% 02, dry) [1]

40

8

8

5

10

8

CO (Ib/MWh) [3]

1.8

0.24

0.2

0.14

0.26

0.2

CO (Ib/MWh with CARB CHP credit)

0.59

0.08

0.09

0.06

0.11

0.09

VOC (ppm @ 15% 02, dry) [1, 4]

9

3

3

5

9

3

VOC (Ib/MWh) [5]

0.23

0.05

0.2

0.08

0.13

0.2

VOC (Ib/MWh with CARB CHP credit)

0.08

0.02

0.09

0.03

0.06

0.09

C02 (Ib/MWh electric only) [6]

1,814

1,680

1,497

1,530

1,424

1,497

C02 (Ib/MWh with CARB CHP credit)

727

700

817

749

722

815

Notes:

1. Vendor estimates for low emission models using natural gas fuel. For systems 1, 2, 3, and 6 the vendor

provided both input- (ppmv) and output-based emissions (Ib/MWh.) For units 4 and 5, the output emissions
were calculated as described below.

2.	Output based NOx emissions (Ib/MWh) = (ppm @15% 02) X 3.413) / ((272 X (% efficiency HHV))

3.	Output based CO emissions (Ib/MWh) = (ppm @15% 02) X 3.413) / ((446 X (% efficiency HHV))

4.	Volatile organic compounds.

5.	Output based VOC emissions (Ib/MWh) = (ppm @15% 02) X 3.413) / ((782 X (% efficiency HHV))

6.	Based on 116.39 lbs COz/MMBtu.

The C02 emissions estimates with CHP show the potential of microturbines in CHP applications to
reduce the emissions of C02. Coal fired generation emits about 2,000 Ib/MWh, and even state of the art
natural gas combined cycle power plants produce C02 emissions in the 800-900 Ib/MWh range, even
before transmission line losses are considered.

5.6 Future Developments

Microturbines first entered the market in the 30-75 kW size range. Of the last several years,
microturbine manufacturers have developed larger capacity products to achieve better economics of
operation through higher efficiencies and lower capital and maintenance costs.

Manufacturers are continuing to develop products with higher electrical efficiencies. Known
developments include a model Capstone is developing, with the Department of Energy, on a 250 kW
model with a target efficiency of 35 percent (gross output, LHV) and a 370 kW model with a projected
42 percent efficiency. The C250 is intended to feature an advanced aerodynamic compressor design,

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Microturbines


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engine sealing improvements, improved generator design with longer life magnet, and enhanced
cooling.

Key technical developments of the C370 model, shown schematically in Figure 5-8, include:

•	Dual property, high-temperature turbine

•	High-pressure compressors (11:1) and recuperator

•	Dual generators - both low pressure and high-pressure spool

•	Dual spool control development

•	High-temperature, low emissions combustor

•	Inter-state compressor cooling

Figure 5-8. Capstone C370 Two-shaft High Efficiency Turbine Design

Source: DOE, Energy Efficiency and Renewable Energy Fact Sheet

The C370 model will use a modified Capstone C200 turbocompressor assembly as the low-pressure
section of a two shaft turbine. This low-pressure section will have an electrical output of 250 kW. A new
high-temperature, high-pressure turbocompressor assembly will increase the electrical output to 370
kW.

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Microturbines


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Section 6. Technology Characterization - Fuel Cells

6.1 Introduction

Fuel cell systems employ an entirely different approach to the production of electricity than traditional
combustion based prime mover technologies. Fuel cells are similar to batteries in that they both
produce a direct current (DC) through an electrochemical process without direct combustion of a fuel
source. However, whereas a battery delivers power from a finite amount of stored energy, fuel cells can
operate indefinitely, provided the availability of a continuous fuel source. Two electrodes (a cathode and
anode) pass charged ions in an electrolyte to generate electricity and heat. A catalyst enhances the
process.

Fuel cells offer the potential for clean, quiet, and efficient power generation. Because the fuel is not
combusted, but instead reacts electrochemically, there is minimal air pollution associated with its use.
Fuel cells have been under development for over 40 years as an emerging power source however, fuels
cells of many different sizes are commercially available now. Based on their environmental benefits,
high efficiency and virtually no emissions of criteria pollutants, fuel cells are supported by a number of
state and federal tax incentive programs that help to offset the overall system costs. These incentives
have been designed to promote continued fuel cell development, cost reductions, and overall market
deployment.

The inventor of fuel cell technology was Sir William Grove, who demonstrated a hydrogen fuel cell in
London in the 1830s. Grove's technology remained without a practical application for over 100 years.
Fuel cells returned to the laboratory in the 1950s when the United States space program required the
development of new power systems with low to no air emissions. Today, the topic of fuel cells
encompasses a broad range of different technologies, technical issues, and market dynamics that make
for a complex but promising outlook. Significant public and private investment are being applied to the
development of fuel cell products for both stationary and transportation applications.

There are four primary types of fuel cells that are used for stationary combined heat and power (CHP)
applications. These include: 1) phosphoric acid (PAFC), 2) molten carbonate (MCFC), 3) solid oxide
(SOFC), and 4) proton exchange membrane (PEMFC). Two additional primary fuel cell types - direct
methanol (DMFC) and alkaline (AFC) - are used primarily in transportation and non-stationary fuel cell
applications, in addition to PEMFC.

The electrolyte and operating temperatures vary for each of the fuel cell types. Operating temperatures
range from near-ambient to 1,800°F, and electrical generating efficiencies range from 30 percent to over
50 percent on a Higher Heating Value (HHV) basis. As a result, fuel cells can have different performance
characteristics, advantages, and limitations, which can be suited to distributed generation applications
in a variety of approaches. Table 6-1 provides a summary of the primary advantages and disadvantages
of the various types of fuel cells.

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Fuel Cells


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Table 6-1. Comparison of Fuel Cell Applications, Advantages, and Disadvantages



Applications

Advantages

Disadvantages

Alkaline (AFC)

•

Military

•

Cathode reaction

•

Sensitive to C02



•

Space

•

faster in alkaline
electrolyte, leads
to high
performance
Low cost
components

•

in fuel and air

Electrolyte

management

Direct Methanol (DMFC)

•

Backup power

•

No need for

•

Expensive



•

Portable power



reformer



catalysts



•

Military

•

(catalyst
separates H2
from liquid
methanol)
Low temperature

•

Low temperature
waste heat

Phosphoric Acid (PAFC)

•

Auxiliary power

•

Higher

•

Platinum catalyst



•

Electric utility



temperature

•

Startup time



•

Distributed



enables CHP

•

Low current and





generation

•

Increased
tolerance to fuel
impurities



power

Proton Exchange

•

Backup power

•

Solid electrolyte

•

Expensive

Membrane (PEMFC)

•

Portable power



reduces



catalysts



•

Distributed
generation



corrosion &
electrolyte

•

Sensitive to fuel
impurities



•
•

Transportation
Specialty vehicles

•
•

management
problems
Low temperature
Quick startup

•

Low temperature
waste heat

Molten Carbonate

•

Auxiliary power

•

High efficiency

•

High

(MCFC)

•

Electric utility

•

Fuel flexibility



temperature



•

Distributed
generation

•

Can use a variety
of catalysts



corrosion and
breakdown







•

Suitable for CHP

•
•

Long startup time
Low power
density

Solid Oxide (SOFC)

•

Auxiliary power

•

High efficiency

•

High



•

Electric utility

•

Fuel flexibility



temperature



•

Distributed

•

Can use a variety



corrosion and





generation

•

of catalysts
Solid electrolyte



breakdown of
cell components







•

Suitable for CHP
& Combined
heat, hydrogen,
and

powerHybrid/GT
cycle

•

High

temperature
operation
requires long
startup time and
limits

Catalog of CHP Technologies

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Fuel Cells


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Source: DOE Fuel Cell Technologies Program-

While there are many different types of fuel cells, there are a few important shared characteristics.
Instead of operating as Carnot cycle engines, or thermal energy-based engines, fuel cells use an
electrochemical or battery-like process to convert the chemical energy of hydrogen into water and
electricity and through this process achieve high electrical efficiencies. Second, fuel cells use hydrogen
as the input fuel, which is typically derived from a hydrocarbon fuel such as natural gas or biogas. Third,
most, but not all, fuel cell systems are composed of three primary subsystems: 1) the fuel cell stack that
generates direct current electricity; 2) the fuel processor that converts the fuel (i.e. natural gas) into a
hydrogen-rich feed stream; and 3) the power conditioner that processes the electric energy into
alternating current or regulated direct current. There are a small number of special application fuel cell
systems that are designed to operate on stored hydrogen fuel, and those fuel cells are configured to
utilize the DC power output directly.

As previously mentioned, all types of fuel cells also have low emissions profiles. This is because the only
combustion processes are the reforming of natural gas or other fuels to produce hydrogen and the
burning of a low energy hydrogen exhaust stream to provide heat to the fuel processor.

Current CHP fuel cell installations total about 83.6 MW domestically.89 California leads the nation in fuel
cell installations, with just under 45 MW, roughly split half natural gas and half biogas. Connecticut and
New York follow as the second and third-ranked states with current fuel cell installations at 25 MW and
10 MW, respectively. Those three states comprise 95 percent of the current domestic fuel cell market.

There is a significant amount of biogas fuel cells in California (representing almost a quarter of all fuel
cell installations domestically by MW). Many of these systems were developed recently (i.e. 2010) as a
result of additional incentives stemming from the California Self-Generation Incentive Program (SGIP).90
Specifically, "directed biogas" projects (i.e. projects that consume biogas fuel produced at a different
location) are eligible for higher incentives under the SGIP. Both CHP and electric-only fuel cells qualify
for the SGIP incentive.

6.2 Applications

Fuel cells are either available or being developed for a number of stationary and vehicle applications.
The power applications include commercial and industrial CHP (200-2800 kW), pure electrical
generation91 (105-210 kW), residential and commercial systems for CHP (3-10 kW), back-up and
portable power systems (0.25-5 kW). In DG markets, the primary characteristic driving early market
acceptance is the ability of fuel cell systems to provide reliable premium power. The primary interest
drivers have been their ability to achieve high efficiencies over a broad load profile and low emission
signatures without additional controls. Figure 6-1 illustrates an actual site with a fuel cell system
functioning in CHP configuration.

88	http://energy.gov/eere/fuelcells/comparison-fuel-cell-technologies

89	CHP Installation Database. Maintained by ICF International for Oak Ridge National Laboratory. 2014. http://www.eea-
inc. com/chpdata/index. h tml

90	"2012 SGIP Impact Evaluation and Program Outlook" Itron. February 2014

91	Based on Bloom Energy models ES-5700, ES-5400, and UPM-570

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Fuel Cells


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Figure 6-1. Commercial Fuel Cell for CHP Application

Source: FuelCell Energy

6.2.1	Combined Heat and Power

Due to the high installed cost of fuel cell systems, the most prevalent and economical DG application is
CHP. CHP applications are on-site power generation in combination with the recovery and use of by-
product heat. Continuous baseload operation and the effective use of the thermal energy contained in
the exhaust gas and cooling subsystems enhance the economics of on-site generation applications.

Heat is generally recovered in the form of hot water or low-pressure steam (<30 psig), but the quality of
heat is dependent on the type of fuel cell and its operating temperature. PEMFC and DMFC operate at
temperatures below 200°F, and therefore have low quality heat. Generally, the heat recovered from fuel
cell CHP systems is appropriate for low temperature process needs, space heating, and potable water
heating. In the case of SOFC and MCFC technologies, medium pressure steam (up to about 150 psig) can
be generated from the fuel cell's high temperature exhaust gas, but the primary use of this hot exhaust
gas is in recuperative heat exchange with the inlet process gases.

The simplest thermal load to supply is hot water. Primary applications for CHP in the
commercial/institutional sectors are those building types with relatively high and coincident electric and
hot water/space heating demand such as colleges and universities, hospitals, nursing homes, and
lodging. Technology developments in heat activated cooling/refrigeration and thermally regenerated
desiccants will enhance fuel cell CHP applications by increasing the thermal energy loads in certain
building types. Use of these advanced technologies in applications such as restaurants, supermarkets,
and refrigerated warehouses provides a base-thermal load that opens these applications to CHP.

6.2.2	Premium Power

Consumers who require higher levels of reliability or power quality, and are willing to pay for it, often
find some form of DG to be advantageous. These consumers are typically less concerned about the
initial prices of power generating equipment than other types of consumers. Premium power systems
generally supply base load demand. As a result, and in contrast to back-up generators, emissions and
efficiency become more significant decision criteria.

Fuel ceil systems offer a number of intrinsic features that make them suitable for the premium power
market. These market-driving features include low emissions/vibration/noise, high availability, good
power quality, and compatibility with zoning restrictions. As emissions become more relevant to a

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Fuel Cells


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business's bottom line in the form of zoning issues and emissions credits, fuel cells become a more
appealing type of DG.

Some types of fuel cell systems have already demonstrated high availability and reliability. As fuel cells
further mature in the market, they are expected to achieve the high reliability associated with fewer
moving parts.

While fuel cells require significant power conditioning equipment in the form of direct current to
alternating current conversion, power from fuel cell systems is clean, exhibiting none of the signal
disturbances observed from grid sources.

Finally, zoning for fuel cell systems is easier than other types of DG systems. Fuel cell systems can be
designed for both indoor and outdoor installation, and in close proximity to sensitive environments,
people, or animals.

6.2.3	Remote Power

In locations where power from the local grid is unavailable or extremely expensive to install, DG is a
competitive option. As with premium power, remote power applications are generally base load
operations. Consequently, emissions and efficiency become more significant criteria in much of the
remote power DG market. Coupled with their other potential advantages, fuel cell systems can provide
competitive energy into certain segments of the remote power DG market. Where fuel delivery is
problematic, the high efficiency of fuel cell systems can also be a significant advantage.

6.2.4	Grid Support

One of the first applications that drew the attention of electric utilities to fuel cell technologies was grid
support. Numerous examples of utility-owned and operated distributed generating systems exist in the
U.S. and abroad. The primary application in the U.S. has been the use of relatively large diesel or natural
gas engines for peaking or intermediate load service at municipal utilities and electric cooperatives.
These units provide incremental peaking capacity and grid support for utilities at substations. Such
installations can defer the need for T&D system expansion, can provide temporary peaking capacity
within constrained areas, or be used for system power factor correction and voltage support, thereby
reducing costs for both customers and the utility system. The unique feature of fuel cell systems is the
use of power conditioning inverters to transform direct current electricity into alternating current. These
power conditioners can be operated almost independent of the fuel cell to correct power factors and
harmonic characteristics in support of the grid if there is enough capacity.

6.2.5	Peak Shaving

In certain areas of the country, customers and utilities are using on-site power generation to reduce the
need for costly peak-load power. Peak shaving is also applicable to customers with poor load factor
and/or high demand charges. Typically, peak shaving does not involve heat recovery, but heat recovery
may be warranted where the peak period is more than 2,000 hours/year. Since low equipment cost and
high reliability are the primary requirements, equipment such as reciprocating engines are ideal for
many peak-shaving applications. Emissions may be an issue if operating hours are high. Combining peak
shaving and another function, such as standby power, enhances the economics. High capital cost and

Catalog of CHP Technologies

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Fuel Cells


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relatively long start-up times (particularly for MCFC and SOFC) will most likely prevent the widespread
use of fuel cells in peak shaving applications.

6.2.6 Resiliency

Fuel cells can be configured to operate independently of the grid, and can therefore provide emergency
power during outages. This was evident particularly during recent hurricane events, where significant
power outages occurred. For instance, during Hurricanes Irene and Superstorm Sandy, fuel cells helped
keep communication lines open for different communications service providers.92 Fuel cells are also
generally resilient based on the undergrounded natural gas supply.

6.3 Technology Description

Fuel cells produce direct current electricity through an electrochemical process, much like a standard
battery. Unlike a standard battery, a fuel supply continuously replenishes the fuel cell. The reactants,
most typically hydrogen and oxygen gas, are fed into the fuel cell reactor, and power is generated as
long as these reactants are supplied. The hydrogen (H2) is typically generated from a hydrocarbon fuel
such as natural gas or LPG, and the oxygen (02) is from ambient air.

6.3.1 Basic Processes and Components

Fuel cell systems designed for DG applications are primarily natural gas or LPG fueled systems. Each fuel
cell system consists of three primary subsystems: 1) the fuel cell stack that generates direct current
electricity; 2) the fuel processor that converts the natural gas into a hydrogen rich feed stream; and 3)
the power conditioner that processes the electric energy into alternating current or regulated direct
current.

Figure 6-2 illustrates the electrochemical process in a typical single cell, acid-type fuel cell. A fuel cell
consists of a cathode (positively charged electrode), an anode (negatively charged electrode), an
electrolyte and an external load. The anode provides an interface between the fuel and the electrolyte,
catalyzes the fuel reaction, and provides a path through which free electrons conduct to the load via the
external circuit. The cathode provides an interface between the oxygen and the electrolyte, catalyzes
the oxygen reaction, and provides a path through which free electrons conduct from the load to the
oxygen electrode via the external circuit. The electrolyte, an ionic conductive (non-electrically
conductive) medium, acts as the separator between hydrogen and oxygen to prevent mixing and the
resultant direct combustion. It completes the electrical circuit of transporting ions between the
electrodes.

92 The Business Case for Fuel Cells, Reliability, Resiliency & Savings (2013). See www.fuelcells.org.

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Fuel Cells


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Figure 6-2. Fuel Cell Electrochemical Process

f*

'.(Hi-j

C

\JU|

J	Electrolyte

/

Cathode

/ \



02

H20

H20

Source: ICF

The hydrogen and oxygen are fed to the anode and cathode, respectively. However, they do not directly
mix, and result in combustion. Instead, the hydrogen oxidizes one molecule at a time, in the presence of
a catalyst. Because the reaction is controlled at the molecular level, there is no opportunity for the
formation of NOx and other pollutants.

At the anode the hydrogen gas is electrochemically dissociated (in the presence of a catalyst) into
hydrogen ions (H+) and free electrons (e_).

Anode Reaction:

2H2 4H+ + 4e~

The electrons flow out of the anode through an external electrical circuit. The hydrogen ions flow into
the electrolyte layer and eventually to the cathode, driven by both concentration and potential forces.
At the cathode the oxygen gas is electrochemically combined (in the presence of a catalyst) with the
hydrogen ions and free electrons to generate water.

Cathode Reaction:
The overall reaction in a fuel cell is as follows:

02 + 4H+ + 4e" 2H20

Net Fuel Cell Reaction: 2H2 + 02 2H20 (vapor) + Energy

When generating power, electrons flow through the external circuit, ions flow through the electrolyte
layer and chemicals flow into and out of the electrodes. Each process has natural resistances, and
overcoming these reduces the operational cell voltage below the theoretical potential. There are also
irreversible processes93 that affect actual open circuit potentials. Therefore, some of the chemical
potential energy converts into heat. The electrical power generated by the fuel cell is the product of the

93 An irreversible process is a change in the potential energy of the chemical that is not recovered through the electrochemical
process. Typically, some of the potential energy is converted into heat even at open circuit conditions when current is not
flowing. A simple example is the resistance to ionic flow through the electrolyte while the fuel cell is operating. This potential
energy "loss" is really a conversion to heat energy, which cannot be reconverted into chemical energy directly within the fuel
cell.

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Fuel Cells


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current measured in amps and the operational voltage. Based on the application and economics, a
typical operating fuel cell will have an operating voltage of between 0.55 volts and 0.80 volts. The ratio
of the operating voltage and the theoretical maximum of 1.48 volts represents a simplified estimate of
the stack electrical efficiency on a HHV94 basis.

As described above, resistance heat is also generated along with the power. Since the electric power is
the product of the operating voltage and the current, the quantity of heat that must be removed from
the fuel cell is the product of the current and the difference between the theoretical potential and the
operating voltage. In most cases, the water produced by the fuel cell reactions exits the fuel cell as
vapor, and therefore, the 1.23-volt LHV theoretical potential is used to estimate sensible heat generated
by the fuel cell electrochemical process.

The overall electrical efficiency of the cell is the ratio of the power generated and the heating value of
the hydrogen consumed. The maximum thermodynamic efficiency of a hydrogen fuel cell is the ratio of
the Gibbs free energy and the heating value of the hydrogen. The Gibbs free energy decreases with
increasing temperatures, because the product water produced at the elevated temperature of the fuel
cell includes the sensible heat of that temperature, and this energy cannot be converted into electricity
without the addition of a thermal energy conversion cycle (such as a steam turbine). Therefore, the
maximum efficiency of a pure fuel cell system decreases with increasing temperature. Figure 6-3
illustrates this characteristic in comparison to the Carnot cycle efficiency limits through a condenser at
50 and 100°C95. This characteristic has led system developers to investigate hybrid fuel cell-turbine
combined cycle systems to achieve system electrical efficiencies in excess of 70 percent HHV.

94	Most of the efficiencies quoted in this report are based on higher heating value (HHV), which includes the heat of
condensation of the water vapor in the products.

95	Larminie, James and Andrew Dicks, Fuel Cell Systems Explained. John Wiley & Sons, Ltd., West Sussex, England, 2000.

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Fuel Cells

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Figure 6-3. Effect of Operating Temperature on Fuel Cell Efficiency

100%

>
I
I

90%

80%

| 70%
"o

i5 60%

E

TO
C
>
¦O

o
E

50%
40%

20%

| 10%

0%

—	H2 Fuel Cell

—Carnot at 21 OF Condensor

-	- Carnot at 120F Condensor
• H2 Stack Efficiency

O NG Fuel Cell Systems

200 400 600 800 1000 1200 1400
Operational Temperature, F

1600 1800 2000

Source: Larminie, James and Andrew Dicks, Fuel Cell Systems Explained. John Wiley & Sons, Ltd.,
West Sussex, England, 2000.

6.3.1.1	Fuel Cell Stacks

Practical fuel cell systems require voltages higher than 0.55 to 0.80. Combining several cells in electrical
series into a fuel cell stack achieves this. Typically, there are several hundred cells in a single cell stack.
Increasing the active area of individual cells manages current flow. Typically, cell area can range from
100 cm2 to over 1 m2 depending on the type of fuel cell and application power requirements.

6.3.1.2	Fuel Processors

In distributed generation applications, the most viable fuel cell technologies use natural gas (CH4) as the
system's fuel source. To operate on natural gas or other fuels, fuel cells require a fuel processor or
reformer, a device that converts the natural gas fuel into a hydrogen-rich gas stream. While adding fuel
flexibility to the system, the reformer also adds significant cost and complexity. There are three primary
types of reformers: steam reformers, autothermal reformers, and partial oxidation reformers. The
fundamental differences are the source of oxygen used to combine with the carbon within the fuel to
release the hydrogen gases and the thermal balance of the chemical process. Steam reformers use
steam, while partial oxidation units use oxygen gas, and autothermal reformers use both steam and
oxygen.

Steam reforming is extremely endothermic and requires a substantial amount of heat input.
Autothermal reformers typically operate at or near the thermal neutral point, and therefore, do not
generate or consume thermal energy. Partial oxidation units combust a portion of the fuel (i.e. partially
oxidize it), releasing heat in the process. When integrated into a fuel cell system that allows the use of
anode-off gas, a typical natural gas reformer can achieve conversion efficiencies in the 75 to 90 percent
LHV range, with 83 to 85 percent being an expected level of performance. These efficiencies are defined
as the LHV of hydrogen generated divided by the LHV of the natural gas consumed by the reformer.

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Fuel Cells


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Some fuel cells can function as internally steam reforming fuel cells. Since the reformer is an
endothermic catalytic converter and the fuel cell is an exothermic catalytic oxidizer, the two combine
into one with mutual thermal benefits. More complex than a pure hydrogen fuel cell, these types of fuel
cells are more difficult to design and operate. While combining two catalytic processes is difficult to
arrange and control, these internally reforming fuel cells are expected to account for a significant
market share as fuel cell based DG becomes more common.

It is also during this process, depending on the efficiency of the fuel cell, that C02 is emitted as part of
the reforming of the natural gas into usable hydrogen. C02 emissions range between 700 to 900
Ib/MWh depending on the fuel cell technology used.

6.3.1.3	Power Conditioning Subsystem

Fuel cells generate direct current electricity, which requires conditioning before serving a load.
Depending on the cell area and number of cells, this direct current electricity is approximately 200 to
400 volts per stack. If the system is large enough, stacks can operate in series to double or triple
individual stack voltages. Since the voltage of each individual cell decreases with increasing load or
power, the output is considered an unregulated voltage source. The power conditioning subsystem
boosts the output voltage to provide a regulated higher voltage input source to an electronic inverter.
The inverter then uses a pulse width modulation technique at high frequencies to generate alternating
current output. The inverter controls the frequency of the output, which can be adjusted to enhance
power factor characteristics. Because the inverter generates alternating current within itself, the output
power is generally clean and reliable. This characteristic is important to sensitive electronic equipment
in premium power applications. The efficiency of the power conditioning process is typically 92 to 96
percent, and is dependent on system capacity and input voltage-current characteristic.

6.3.1.4	Types of Fuel Cells

There are four basic types of fuel cells most suitable for stationary CHP applications. The fuel cell's
electrolyte or ion conduction material defines the basic type. Two of these fuel cell types, polymer
electrolyte membrane (PEMFC) and phosphoric acid fuel cell (PAFC), have acidic electrolytes and rely on
the transport of H+ ions. Carbonate fuel cell (MCFC) has basic electrolytes that rely on the transport of
C032ions. The fourth type, solid oxide fuel cell (SOFC), is based on a solid-state ceramic electrolyte in
which oxygen ions (02~) are the conductive transport ion.

Each fuel cell type operates at an optimum temperature, which is a balance between the ionic
conductivity and component stability. These temperatures differ significantly among the four basic
types, ranging from near ambient to as high as 1800°F. The proton conducting fuel cell type generates
water at the cathode and the anion conducting fuel cell type generates water at the anode.

Table 6-2 presents fundamental characteristics for the primary fuel cell types most suitable for
stationary CHP.

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Table 6-2. Characteristics of Major Fuel Cell Types



PEMFC

PAFC

MCFC

SOFC

Type of Electrolyte

H+ ions (with anions
bound in polymer
membrane)

H+ ions (H3PO4
solutions)

C03= ions (typically,
molten LiKaC03
eutectics)

0= ions (Stabilized
ceramic matrix with
free oxide ions)

Common Electrolyte

Solid polymer
membrane

Liquid phosphoric
acid in a lithium
aluminum oxide
matrix

Solution of lithium,
sodium, and/or
potassium
carbonates soaked
in a ceramic matrix

Solid ceramic,
Yttria stabilized
zirconia (YSZ)

Typical construction

Plastic, metal or
carbon

Carbon, porous
ceramics

High temp metals,
porous ceramic

Ceramic, high temp
metals

Internal reforming

No

No

Yes, good temp
match

Yes, good temp
match

Oxidant

Air to 02

Air to Enriched Air

Air

Air

Operational
Temperature

150- 180°F (65-85°C)

302-392°F (150-
200°C)

1112-1292°F (600-
700°C)

1202-1832°F (700-
1000°C)

DG System Level
Efficiency (% HHV)

25 to 35%

35 to 45%

40 to 50%

45 to 55%

Primary Contaminate
Sensitivities

CO, Sulfur, and NH3

CO < 1%, Sulfur

Sulfur

Sulfur

Source: DOE Fuel Cells Technology Program96

6.3.1.5	PEMFC (Proton Exchange Membrane Fuel Cell or Polymer Electrolyte
Membrane)

NASA developed this type of fuel cell in the 1960s for the first manned spacecraft. The PEMFC uses a
solid polymer electrolyte and operates at low temperatures (less than 200°F). Due to their modularity
and simple manufacturing, reformer/PEMFC systems for residential DG applications (i.e. micro CHP)
have enjoyed considerable market success, particularly in Asia. PEMFC's have high power density and
can vary their output quickly to meet demand. This type of fuel cell is highly sensitive to CO poisoning.
PEMFCs have historically been the market leader in terms of number of fuel cell units shipped. There is a
wide range of PEMFC manufacturers.

6.3.1.6	PAFC (Phosphoric Acid Fuel Cell)

PAFC uses phosphoric acid as the electrolyte and is one of the most established fuel cell technologies.
The first PAFC DG system was designed and demonstrated in the early 1970s. PAFCs are capable of fuel-
to-electricity efficiencies of 36 percent HHV or greater. The current 400 kW product has a stack lifetime
of over 40,000 hours and commercially based reliabilities in the 90 to 95 percent range. ClearEdge

96 "2012 Fuel Cell Technologies Market Report" U.S. Department of Energy, October 2013.
http://energy.gov/sites/prod/files/2014/03/fll/2012_market_report.pdf

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Power is a primary US manufacturer of PAFC systems after buying the PAFC assets from United
Technologies. Recently however ClearEdge has encountered financial problems.97

6.3.1.7	MCFC (Molten Carbonate Fuel Cell)

The MCFC uses an alkali metal carbonate (Li, Na, K) as the electrolyte and has a developmental history
that dates back to the early part of the twentieth century. Due to its operating temperature range of
1,100 to 1,400°F, the MCFC holds promise in CHP applications. This type of fuel cell can be internally
reformed, can operate at high efficiencies (50 percent HHV), and is relatively tolerant of fuel impurities.
Government/industry R&D programs during the 1980s and 1990s resulted in several individual pre-
prototype system demonstrations. Fuel Cell Energy is one of the primary manufacturers of commercially
available MCFCs, ranging from 300 kW to 2800 kW.

6.3.1.8	SOFC (Solid Oxide Fuel Cell)

SOFC uses solid, nonporous metal oxide electrolytes and is generally considered less mature in its
development than the MCFC and PAFC technologies. SOFC has several advantages (high efficiency,
stability and reliability, and high internal temperatures) that have attracted development support. The
SOFC has projected service electric efficiencies of 45 to 60 percent and higher, for larger hybrid,
combined cycle plants. Efficiencies for smaller SOFC units are typically in the 50 percent range.

Stability and reliability of the SOFC are due to an all-solid-state ceramic construction. Test units have
operated in excess of 10 years with acceptable performance. The high internal temperatures of the
SOFC are both an asset and a liability. As an asset, high temperatures make internal reforming possible.
As a liability, these high temperatures add to materials and mechanical design difficulties, which reduce
stack life and increase cost. While SOFC research has been ongoing for 30 years, costs of these stacks are
still comparatively high. Currently, two of the primary SOFC manufacturers include Bloom Energy, which
is a pure electric fuel cell (i.e. no waste heat is captured) and Ceramic Fuel Cells.

Design Characteristics

The features that have the potential to make fuel cell systems a leading prime mover for CHP and other
distributed generation applications include:

Size range

Fuel cell systems are constructed from individual cells that generate 100 W to 2 kW
per cell. This allows systems to have extreme flexibility in capacity. Multiple systems
can operate in parallel at a single site to provide incremental capacity.

Thermal output

Fuel cells can achieve overall efficiencies in the 65 to 95% range. Waste heat can be
used primarily for domestic hot water applications and space heating.

Availability

Commercially available systems have demonstrated greater than 90% availability.

Part-load operation

Fuel cell stack efficiency improves at lower loads, which results in a system electric
efficiency that is relatively steady down to one-third to one-quarter of rated capacity.
This provides systems with excellent load following characteristics.

Cycling

While part-load efficiencies of fuel cells are generally high, MCFC and SOFC fuel cells
require long heat-up and cool-down periods, restricting their ability to operate in
many cyclic applications.

97 ClearEdge Power filed for Chapter 11 bankruptcy in May of 2014.

http://www.oregonlive.com/business/index.ssf/2014/05/clearedge_power_files_for_bankruptcy_as_financial_woes_mount.ht
ml

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High-quality power

Electrical output is computer grade power, meeting critical power requirements
without interruption. This minimizes lost productivity, lost revenues, product loss, or
opportunity cost.

Reliability and life

While the systems have few moving parts, stack assemblies are complex and have had
problems with seals and electrical shorting. Recommended stack rebuilds required
every 5-10 years are expensive.

Emissions

The only combustion within a fuel cell system is the low energy content hydrogen
stream exhausted from the stack when using pure hydrogen as a fuel source. This
stream is combusted within the reformer and can achieve emissions

Signatures of < 2 ppmv CO, <1 ppmv NOx and negligible SOx (on 15% 02, dry basis).
However most fuel cells need to convert natural gas (CH4) to hydrogen (H2). During
this process C02 is emitted at varying levels based on the efficiency of the fuel cell.

Efficiency

Different types of fuel cells have varied efficiencies. Depending on the type and
design, electric efficiency ranges from 30% to close to 50% HHV.

Quiet operation

Conversational level (60dBA @ 30 ft.), acceptable for indoor installation.

Siting and size

Indoor or outdoor installation with enclosure.

Fuel use

The primary fuel source for fuel cells is hydrogen, which can be obtained from natural
gas, coal gas, methanol, and other fuels containing hydrocarbons.

6.4 Performance Characteristics

Fuel cell performance is a function of the type of fuel cell and its capacity. Since the fuel cell system is a
series of chemical, electrochemical, and electronic subsystems, the optimization of electric efficiency
and performance characteristics can be a challenging engineering task. The electric efficiency calculation
example provided in the next section illustrates this.

Table 6-3 summarizes performance characteristics for representative commercially available and
developmental natural gas fuel cell CHP systems over the 0.7 kW to 1,400 kW size range. This size range
covers the majority of the market applications. All systems included in Table 6-3 are commercially
available as of 2014.

Table 6-3. Fuel Cell CHP - Typical Performance Parameters

Performance Characteristics

System 1

System 2

System 3

System 4

System 5

Fuel Cell Type

PEMFC

SOFC

MCFC

PAFC

MCFC

Nominal Electricity Capacity (kW)

0.7

1.5

300

400

1,400

Net Electrical Efficiency (%), HHV)

35.3%

54.4%

47%

34.3%

42.5%

Fuel Input (MMBtu/hr), HHV

0.0068

0.0094

2.2

4.0

11.2

Total CHP Efficiency (%), HHV

86%

74%

82%

81%

82%

Power to Heat Ratio

0.70

2.78

1.34

0.73

1.08

Net Heat Rate (Btu/kWh), HHV

9,666

6,272

7,260

9,948

8,028

Exhaust Temperature (°F)

NA

NA

700

NA

700

Available Heat (MMBtu/hr)

NA

NA

0.78 (to 120°F)

0.88 (to 140° F)

3.73 (to 120°F)

Sound(dBA)

NA

47 (at 3 feet)

72 (at 10 feet)

65 (at 33 feet)

72 (at 10 feet)

NA = not available or not applicable

Source: ICF, specific product specification sheets

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Heat rates and efficiencies shown were taken from manufacturers' specifications and industry
publications or are based on the best available data for developing technologies. CHP thermal recovery
estimates are based on producing low quality heat for domestic hot water process or space heating
needs. This feature is generally acceptable for commercial/institutional applications where it is more
common to have hot water thermal loads.

Generally, electrical efficiency increases as the operating temperature of the fuel cell increases. SOFC
fuel cells have the highest operating temperatures (which can be advantageous as well as
disadvantageous) and they also have the highest electric efficiencies. In addition, as electrical efficiency
increases, the absolute quantity of thermal energy available to produce useful thermal energy decreases
per unit of power output, and the ratio of power to heat for the CHP system generally increases. A
changing ratio of power to heat impacts project economics and may affect the decisions that customers
make in terms of CHP acceptance, sizing, and the desirability of selling power.

6.4.1 Electrical Efficiency

As with all generation technologies, the electrical efficiency is the ratio of the power generated and the
heating value of the fuel consumed. Because fuel cells have several subsystems in series, the electrical
efficiency of the unit is the multiple of the efficiencies of each individual section. The electric efficiency
of a fuel cell system is calculated as follows:

here)

For example, the electrical efficiency of a PAFC can be calculated as follows:

Effaec = (84%FPS)*(83% util)*(0.75V/1.25V)*(95%PC)*(0.9HHV/LHV)

= 36% electric efficiency HHV

As the operating temperature range of the fuel cell system increases, the electric efficiency of the
system tends to increase. Although the maximum thermodynamic efficiency decreases as shown in
Figure 6-3, improvements in reformer subsystem integration and increases in reactant activity balance
out to provide the system level increase. Advanced high temperature MCFC and SOFC systems can
achieve simple cycle efficiencies in the range of 50 to 60 percent HHV, while hybrid combined fuel cell-
heat engine systems are calculated to achieve efficiencies above 60 percent in DG applications.

6.4.2 Part Load Performance

In CHP applications, fuel cell systems are expected to follow the thermal load of the host site to
maximize CHP energy economics. Figure 6-4 shows the part load efficiency curve for a PAFC fuel cell in
the 100 kW to 400 kW size range in comparison to a typical lean burn natural gas engine. It shows that

Effaec = (Eff fps * H2 Utilization * Effstack * Effpc)*(HHV/LHV ratio of the fuel)

Where:

H2 Utilization

Effstack

Eff pc

Eff FPS

Fuel Processing Subsystem Efficiency, LLV (LHV of H2 Generated/LHV of Fuel
Consumed)

% of H2 actually consumed in the stack
(Operating Voltage/Energy Potential ~1.23 volts)

AC power delivered/(dc power generated) (auxiliary loads are assumed dc loads

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fuel cells maintain efficient performance at partial loads better than reciprocating engines. The fuel cell
efficiency at 50 percent load is within 2 percent of its full load efficiency characteristic. As the load
decreases further, the curve becomes somewhat steeper, as inefficiencies in air blowers and the fuel
processor begin to override the stack efficiency improvement.

Figure 6-4. Comparison of Part Load Efficiency Derate

38%

36%
x 34%

& 32%


-------
applications but use the heat to boost the internal process and to improve electrical generation
efficiencies.

As an example, there are four primary potential sources of usable waste heat from a fuel cell system:
exhaust gas including water condensation, stack cooling, anode-off gas combustion, and reformer heat.
A sample PAFC system achieves 36 percent electric efficiency and 72 percent overall CHP efficiency,
which means that it has a 36 percent thermal efficiency or power to heat ratio of one. Of the available
heat, 25 to 45 percent is recovered from the stack-cooling loop that operates at approximately 400° F
and can deliver low- to medium-pressure steam. The balance of heat is derived from the exhaust gas-
cooling loop that serves two functions. The first is condensation of product water, thus rendering the
system water self-sufficient, and the second is the recovery of by-product heat. Since its primary
function is water recovery, the balance of the heat available from the PAFC fuel cell is recoverable with
120° F return and 300° F supply temperatures. This tends to limit the application of this heat to domestic
hot water applications. The other aspect to note is that all of the available anode-off gas heat and
internal reformer heat is used internally to maximize system efficiency.

In the case of SOFC and MCFC fuel cells, medium-pressure steam (up to about 150 psig) can be
generated from the fuel cell's high temperature exhaust gas, but the primary use of these hot exhaust
gases is in recuperative heat exchange with the inlet process gases. Like engine and turbine systems,
fuel cell exhaust gas can be used directly for process drying.

6.4.5	Performance and Efficiency Enhancements

Air is fed to the cathode side of the fuel cell stack to provide the oxygen needed for the power
generation process. Typically, 50 to 100 percent more air is passed through the cathode than is required
for the fuel cell reactions. The fuel cell can be operated at near-ambient pressure, or at elevated
pressures to enhance stack performance. Increasing the pressure, and therefore the partial pressure of
the reactants, increases stack performance by reducing the electrode over potentials associated with
moving the reactants into the electrodes where the catalytic reaction occurs. It also improves the
performance of the catalyst. These improvements appear to optimize at approximately three
atmospheres pressure if optimistic compressor characteristics are assumed.98 More realistic
assumptions often result in optimizations at ambient pressure where the least energy is expended on air
movement. Because of these characteristics, developers appear to be focused on both pressurized and
ambient pressure systems.

6.4.6	Capital Cost

This section provides estimates for the installed cost of fuel cell systems designed for CHP applications.
Capital costs (equipment and installation) are estimated in Table 6-4 for five representative CHP fuel cell
systems. Estimates are "typical" budgetary price levels. Installed costs can vary significantly depending
on the scope of the plant equipment, geographical area, competitive market conditions, special site
requirements, prevailing labor rates, and whether the system is a new or retrofit application.

98 Larminie, James and Andrew Dicks, Fuel Cell Systems Explained. John Wiley & Sons, Ltd., West Sussex, England, 2000., p. 90.

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Table 6-4. Estimated Capital and O&M Costs for Typical Fuel Cell Systems in
Grid Interconnected CHP Applications (2014 $/kW)

Installed Cost Components

System 1
Residential

System 2
Residential

System 3
C&l

System 4
C&l

System 5
C&l

Fuel Cell Type

PEMFC

SOFC

MCFC

PAFC

MCFC

Nominal Electricity Capacity (kW)

0.7

1.5

300

400

1400

Total Package Cost (2014 $/kW)99

$ 22,000

$ 23,000100

$10,000

$ 7,000

$ 4,600

O&M Costs (2014 $/MWh)

$ 60

$ 55

$45

$ 36

$40

Source: ICF Manufacturer Data Collection

6.4.7	Maintenance

Maintenance costs for fuel cell systems will vary with type of fuel cell, size and maturity of the
equipment. Some of the typical costs that need to be included are:

•	Maintenance labor.

•	Ancillary replacement parts and material such as air and fuel filters, reformer igniter or spark
plug, water treatment beds, flange gaskets, valves, electronic components, etc., and
consumables such as sulfur adsorbent bed catalysts and nitrogen for shutdown purging.

•	Major overhauls include shift catalyst replacement (3 to 5 years), reformer catalyst replacement
(5 years), and stack replacement (5 to 10 years).

Maintenance can either be performed by in-house personnel or contracted out to manufacturers,
distributors or dealers under service contracts. Details of full maintenance contracts (covering all
recommended service) and costing are not generally available, but are estimated at 0.7 to 2.0
cents/kWh excluding the stack replacement cost sinking fund. Maintenance for initial commercial fuel
cells has included remote monitoring of system performance and conditions and an allowance for
predictive maintenance. Recommended service is comprised of routine short interval
inspections/adjustments and periodic replacement of filters (projected at intervals of 2,000 to 4,000
hours).

6.4.8	Fuels

Since the primary fuel source for fuel cells is hydrogen produced from hydrocarbon fuels, fuel cell
systems can be designed to operate on a variety of alternative gaseous fuels including:

•	Natural Gas - methane from the pipeline.

•	Liquefied petroleum gas (LPG) - propane and butane mixtures.

•	Sour gas - unprocessed natural gas as it comes directly from the gas well.

•	Biogas - any of the combustible gases produced from biological degradation of organic wastes,
such as landfill gas, sewage digester gas, and animal waste digester gas.

•	Industrial waste gases - flare gases and process off-gases from refineries, chemical plants and
steel mill.

99	Total package cost includes all equipment (including heat recovery) as well as estimated labor and installation costs.

100	Total package costs for larger (i.e. 200 kW) SOFC systems are significantly less expensive than $23,000, however those data
were not made available to us for estimation.

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•	Manufactured gases - typically low- and medium-Btu gas produced as products of gasification
or pyrolysis processes.

Factors that impact the operation of a fuel cell system with alternative gaseous fuels include:

•	Volumetric heating value - Since fuel is initially reformed by the fuel cell's fuel processing
subsystem, the lower energy content fuels will simply result in a less concentrated hydrogen-
rich gas stream feeding the anode. This will cause some loss in stack performance, which can
affect the stack efficiency, stack capacity or both. Increased pressure drops through various flow
passages can also decrease the fine balance developed in fully integrated systems.

•	Contaminants are the major concern when operating on alternative gaseous fuels. If any
additional sulfur and other components (e.g., chlorides) can be removed prior to entering the
fuel processing catalyst, there should be no performance or life impact. If not, the compounds
can cause decreased fuel processor catalyst life and potentially impact stack life.

6.4.9 System Availability

Fuel cell systems are generally perceived as low maintenance devices. Fuel cells in North America have
been recorded achieving more than 90 percent availability. In premium power applications, 100 percent
customer power availability, and 95 percent+ fleet availability has been reported during the same time
period. Fuel cells can provide high levels of availability, especially in high load factor (i.e. baseload)
applications.

6.5 Emissions and Emissions Control Options

As the primary power generation process in fuel cell systems does not involve combustion, very few
emissions are generated. In fact, the fuel processing subsystem is the only source of emissions. The
anode-off gas that typically consists of 8 to 15 percent hydrogen is combusted in a catalytic or surface
burner element to provide heat to the reforming process. The temperature of this very lean combustion
can be maintained at less than 1,800° F, which also prevents the formation of oxides of nitrogen (NOx)
but is sufficiently high to ensure oxidation of carbon monoxide (CO) and volatile organic compounds
(VOCs - unburned, non-methane hydrocarbons). Other pollutants such as oxides of sulfur (SOx) are
eliminated because they are typically removed in an absorbed bed before the fuel is processed.

6.5.1 Primary Emissions Species
6.5.1.1 Nitrogen Oxides (NOx)

NOx is formed by three mechanisms: thermal NOx, prompt NOx, and fuel-bound NOx. Thermal NOx is the
fixation of atmospheric oxygen and nitrogen, which occurs at high combustion temperatures. Flame
temperature and residence time are the primary variables that affect thermal NOx levels. The rate of
thermal NOx formation increases rapidly with flame temperature. Prompt NOx is formed from early
reactions of nitrogen modules in the combustion air and hydrocarbon radicals from the fuel. It forms
within the flame and typically is on the order of 1 ppm at 15 percent 02, and is usually much smaller
than the thermal NOx formation. Fuel-bound NOx forms when the fuel contains nitrogen as part of the
hydrocarbon structure. Natural gas has negligible chemically bound fuel nitrogen. Fuel-bound NOx can
be at significant levels with liquid fuels.

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6.5.1.2	Carbon Monoxide (CO)

CO and VOCs both result from incomplete combustion. CO emissions result when there is inadequate
oxygen or insufficient residence time at high temperature. Cooling at the combustion chamber walls and
reaction quenching in the exhaust process also contribute to incomplete combustion and increased CO
emissions. Excessively lean conditions can lead to incomplete and unstable combustion and high CO
levels.

6.5.1.3	Unburned Hydrocarbons

Volatile hydrocarbons, also called volatile organic compounds (VOCs), can encompass a wide range of
compounds, some of which are hazardous air pollutants. These compounds are discharged into the
atmosphere when some portion of the fuel remains unburned or just partially burned. Some organics
are carried over as unreacted trace constituents of the fuel, while others may be pyrolysis products of
the heavier hydrocarbons in the gas. Volatile hydrocarbon emissions from reciprocating engines are
normally reported as non-methane hydrocarbons (NMHCs). Methane is not a significant precursor to
ozone creation and smog formation and is not currently regulated. Methane is a greenhouse gas and
may come under future regulations.

6.5.1.4	Carbon Dioxide (CO2)

Carbon dioxide (C02) emissions are of concern due to its contribution to global warming. Atmospheric
warming occurs since solar radiation readily penetrates to the surface of the planet but infrared
(thermal) radiation from the surface is absorbed by the C02 (and other polyatomic gases such as
methane, unburned hydrocarbons, refrigerants and volatile chemicals) in the atmosphere, with
resultant increase in temperature of the atmosphere. The amount of C02 emitted is a function of both
fuel carbon content and system efficiency. The fuel carbon content of natural gas is 34 lbs
carbon/MMBtu; oil is 48 lbs carbon/MMBtu; and (ash-free) coal is 66 lbs carbon/MMBtu.

6.5.2 Fuel Cell Emission Characteristics

Table 6-5 illustrates the emission characteristics of fuel cell systems. Fuel cell systems do not require any
emissions control devices to meet current and projected regulations. As previously noted, fuel cells
generally have very low emissions.

Table 6-5. Estimated Fuel Cell Emission Characteristics without Additional Controls

Emissions Characteristics

System 1

System 2

System 3

System 4

System 5

Fuel Cell Type

PEMFC

SOFC

MCFC

PAFC

MCFC

Nominal Electricity Capacity (kW)

0.7

1.5

300

400

1,400

NOx (Ib/MWh)

Negligible

Negligible

0.01

0.01

0.01

SOx (Ib/MWh)

Negligible

Negligible

0.0001

Negligible

0.0001

CO (Ib/MWh)

Negligible

Negligible

Negligible

0.02

Negligible

VOC (Ib/MWh)

Negligible

Negligible

Negligible

0.02

Negligible

C02 (Ib/MWh)

1,131

734

980

1,049

980

C02 with heat recovery (Ib/MWh)

415

555

520-680

495

520

Source: ICF Manufacturer Data Collection

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6.6 Future Developments

Over the past years fuel cell capital costs have decreased and their use in multiple applications have
increased. In 2007, SOFC were not even commercially shipping and now there are many of them being
shipped in multiple sizes globally. In the US multiple factors point towards continued levels of fuel cell
market penetration. These factors include: relatively low domestic natural gas prices, continued fuel cell
technological advancements reducing capital costs and new business models such as leasing, favorable
incentives and policies, continued desire for low emissions profiles, and general resiliency and reliability
advantages of distributed energy.

Globally, MCFC shipments by MW have been on par with that of vehicle PEMFC, as shown in Figure 6-5.
As the only commercial developer of MCFCs in the United States, Fuel Cell Energy is uniquely positioned
to continue its successes, both domestically and internationally.

Figure 6-5. Recent Worldwide Fuel Cell Installations by Fuel Cell Type, in Megawatts

Fuel Cell Installations by Type (MW)

250

200

150

100

50

I AFC
MCFC
SOFC
PAFC
DMFC
PEMFC

2009 2010 2011 2012 2013

Source: Fuel Cell Today101

Large-scale stationary fuel cells for CHP have also been successfully deployed in Asia (specifically Korea
and Japan). Europe could also be a growth opportunity as FuelCell Energy has formed joint ventures in
the European continent.102 It is likely through these international joint ventures that US-based fuel cell
manufacturers can leverage local market experience and technological expertise in international
markets. These sales opportunities will also increase demand leading to potentially more reductions in
costs as we have seen in solar photovoltaic panels and now batteries.

101	"yhe FUe| Cell Industry Review 2013", Fuel Cell Today, http://www.fuelcelltoday.com/media/1889744/fct_review_2013.pdf

102	"FuelCell Energy Announces Completion of Asset Acquisition and German Joint Venture with Fraunhofer IKTS", June 26,
2012. http://fcel.client.shareholder.com/releasedetail.cfm?releaseid=686425

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What may be the next significant growth engine for fuel cells is the development of micro-CHP fuel cells.
According to a 2013 report from Fuel Cell Today, residential micro-CHP fuel cells outsold conventional
micro-CHP boilers for the first time in 2012 in Japan. The report elaborates that this micro-CHP
application is migrating to Europe and it may become a trend in the US with both PEMFC and SOFC
technologies.

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Section 7. Packaged CHP Systems

Acknowledgements

This section of the Catalog was prepared by David Jones (ICF International), Anne Hampson (ICF
International), Charlie Goff (ERG), Gary McNeil (U.S. Environmental Protection Agency), and Neeharika
Naik-Dhungel (U.S. Environmental Protection Agency).

7.1 Introduction

The purpose of this section of the Catalog is to introduce
packaged CHP systems and their unique attributes to facility
owners and operators, real estate developers, CHP project
developers, architects, engineers, and policymakers.

Depending on the application, packaged systems can be
cheaper and easier to install and operate than conventional
CHP systems (i.e., unique site-specific systems involving the
integration of different components — prime mover,
generator, heat recovery equipment, electrical switchgear,
emissions control devices, and controls). Also, because
packaged systems are standardized, they can be good choices
for organizations with multiple facilities with similar electrical
and thermal requirements.

This section of the Catalog of CHP
Technologies is different than the
other sections of the Catalog, in that
it addresses a new CHP system
configuration, whereas the other
sections characterize specific CHP
prime mover technologies.
Accordingly, this section includes
material such as installations and
technical potential by market
segment, which are not found in the
other sections.

Packaged systems include a prime mover (i.e., reciprocating engine, microturbine, or fuel cell), a
generator, heat recovery equipment, electrical switchgear, emissions control devices, and controls,
sometimes packaged in a weather-resistant sound-attenuating enclosure. These systems can be
installed as single units or combined to form larger systems. Product offerings for packaged systems
have been focused on relatively small (£ 500 kW) sizes.

This section of the Catalog provides an overview of packaged systems, including:

•	The evolution of packaged CHP systems

•	Significant attributes

•	Applications

•	Technology description

•	Cost and performance characteristics

•	Emissions and emissions control options

7.2 The Evolution of Packaged CHP Systems

Until relatively recently, nearly all CHP installations were unique site-specific conventional CHP systems.
In the late 1990s, as the market for CHP applications boomed, many manufacturers and developers
started offering standardized factory-built, ready-to-install packaged CHP systems that simplified, and

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shortened the time required for, CHP system procurement and installation. Today there are 27 packaged
system vendors in the United States, according to a 2016 survey103 of the packaged CHP industry.

In 2016 an estimated 950 packaged systems are installed in the United States, totaling 215 MW of
capacity.104 Annual additions of packaged system capacity are increasing, as shown in Figure 7-1.105

Figure 7-1. Annual U.S. Capacity Additions: Packaged CHP Systems

20

O^HCNro^rLntDr-vcocno^HrMro^i-n
OOOOOOOOOO^—i^—i^—I*—iv-l*H

oooooooooooooooo

Source: ICF/U.S. DOE Combined Heat and Power Installation Database, February 2017,
https://doe.icfwebservices.com/chpdb/.

103	Compiled by ICF from vendor-supplied data, 2016.

104	ICF/U.S. DOE Combined Heat and Power Installation Database, February 2017, https://doe.icfwebservices.com/chpdb/.

105	Ibid.

Catalog of CHP Technologies

Packaged CHP Systems

7-2


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Examples of Packaged CHP Systems

Figure 7-2. Aegis ThermoPower Figure 7-3. Tecogen Tecopower Figure 7-4. MTU 12V400 GS, 358
(TP-75), 75 kW	CM-75, 75 kW	kW

Catalog of CHP Technologies	7-3	Packaged CHP Systems

Figure 7-5. Capstone C65 ICHP,
65 kW

Figure 7-8. 2G Avus 800,
800 kW

Figure 7-6. Amerigen 8150 (Using	Fnprpv rhnirp Fr qn

the MAN E2876 E312 Engine), F|gure 7 '¦ Energy Choice

150 kW

Natural Gas system, 190 kW

Figure 7-9. Siemens SGE-36SL, 676 kW


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7.3 Significant Attributes

Packaged systems have certain important attributes:

•	Standardization

•	Black start/islanding capability (sometimes optional)

•	Acoustic enclosure (sometimes optional)

•	Modularity

•	Third-party own/operate business arrangements (may be available)

•	Repl icabil ity

7.3.1 Standardization

Because packaged systems are built and delivered in accordance with published specifications, their
configuration and performance can be well understood before the purchase decision is made. This
facilitates many elements of the procurement process, including equipment selection, financial analysis
before purchase, site-specific engineering, permitting and site modifications, as well as system
installation. Site-specific engineering is typically limited to designing connections to the fuel supply,
water supply, thermal loads, electrical system, and building control system.

Customers can choose several options. These include:

•	Type of generator (synchronous, induction, or inverter)

•	Black start/islanding capability

•	Enhanced sound attenuation

•	Additional emissions controls

•	Specialized heat recovery options, such as an absorption chiller to produce chilled water for
cooling applications or a steam boiler to make steam from the prime mover exhaust

NYSERDA CHP Program

The standardization of CHP equipment can make it easier for programs such as the New York State
Energy Research and Development Authority's (NYSERDA's) CHP Program to pre-approve projects for
incentives. Programs like NYSERDA's provide a level of assurance that the pre-approved systems
meet the requirements of the approving organization.

Information about NYSERDA's CHP Program is available at:

h tips ://porta I. nyserda. ny. gov/CORE_Sol icitation_Detail_Page?Soli citation ld=aOrtOOOOOOOQnqyAAC

7.3.2 Black Start/Islanding Capability

Several packaged system vendors offer models with black start/islanding capability. These systems can
disconnect from the utility grid using an automatic transfer switch and run independently during power
outages (i.e., in "island mode"). While CHP systems are not typically intended to meet a facility's full
load requirements, they can provide electricity to critical loads when the electric grid is not available.

CHP systems with black start/islanding capability can supplement traditional diesel standby generators,
providing an added level of redundancy during long-term outages and natural disasters when diesel fuel

Catalog of CHP Technologies

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can become scarce (e.g., Hurricane Sandy). Also, in certain circumstances, CHP can replace diesel
standby generators.

Black start/islanding capability requires additional components, which may increase equipment cost
and/or installation cost. The extent to which black start/islanding capability adds to installation costs
depends on factors such as the existing electrical system in the host facility, the switchgear required,
and the size of the electrical loads to be served when the system is islanding.106

7.3.3	Acoustic Enclosure

Systems may include a sound attenuation enclosure—as standard equipment or as an option-
consisting of sound-absorbing material surrounded by a metal cover. Optional enhanced sound
attenuation capability may be available.

7.3.4	Modularity

Because of their modular design, packaged systems can be installed as single units, or several can be
connected to create larger multiple-unit systems. Systems using multiple modular units can have a
number of additional significant attributes:

•	Under certain circumstances, multiple-unit
systems can be more efficient than a
conventional CHP system of the same size.

Conventional systems lose efficiency when
slowed down to follow load fluctuations. In
multiple-unit systems, individual units can be
shut down to reduce system output to follow
load fluctuations, allowing remaining operational
units to function at higher efficiencies.

•	Systems using multiple modular units can also
improve reliability and system availability, since
one unit can be taken off line for maintenance
while the others continue to operate.

•	Additional units can be added over time to
increase output as electrical and/or thermal
loads increase.107

A disadvantage of using multiple modular units instead
of one large unit is that the installed cost per kW is typically higher. In addition, in full-load operation, a
conventional CHP system will typically be more efficient than a system of equal size comprising multiple
packaged system units.

CHP Project Development

Taking a CHP project from conception to
completion involves five steps:

•	Qualification/screening

•	Level 1 feasibility analysis

•	Level 2 feasibility analysis
(investment grade analysis)

•	Procurement, including installation

•	Operations and maintenance
Depending on the nature of the facility and
the performance objectives of a CHP system
being considered, each of the five steps may
be performed by the facility's manager or
agent, consultants, or vendors.

Learn more about these steps, including
goals, timeframes, typical costs, and facility
level of effort required on the EPA CHP
Partnership website.

106	Based on data collected from EPA CHP Partners that manufacture packaged CHP systems.

107	Often up to five or six units may be operated together, depending on the equipment specifications.

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7.3.5	Third-Party Own/Operate Business Arrangements

Many packaged system vendors offer "own and operate" business arrangements, which can be
structured as agreed upon by the host facility and the vendor. One model is for the vendor or a third
party to install, own, operate, and maintain the system, and provide the system outputs to the host
facility under terms established in a contract. In this way, the facility can have on-site power production
and other CHP benefits without a capital expenditure or the risks and responsibilities of ownership. The
contract may include an option for the host facility to purchase the system at specified terms.

7.3.6	Replicability

Operators of multifamily buildings, big box stores, hotels, restaurants, and supermarkets often manage
many buildings with similar electrical and thermal requirements. Because a specific packaged system
model will perform consistently when installed in facilities with comparable layouts and electric/thermal
requirements, that model can become a known quantity for the building operator. With this experience,
the building operator can confidently choose the same system for other buildings with similar
electrical/thermal requirements.

7.4 Applications

While conventional CHP applications have been concentrated in the industrial/heavy manufacturing
sector, packaged CHP applications are most often used in the commercial, multifamily, institutional, and
light manufacturing sectors. Attributes of facilities that make them good matches for packaged systems
include:

•	Electrical and thermal load and profiles that match packaged system outputs. Most packaged
systems are under 500 kW in size, which is a good match for the electrical and thermal loads of
commercial, multifamily, and institutional buildings.

•	Space constraints - Many facilities have constraints on the physical size of units that can be
installed, and packaged systems tend to have a relatively small footprint.

•	Building owners who place a high value on ease of installation and operation - The

standardization of packaged systems means an easier procurement process compared to
conventional CHP systems.

•	Need for flexible financing options - CHP projects are capital-intensive, which can be a problem
for some market sectors. Many packaged systems are available through "own and operate"
arrangements, where the vendor retains ownership and is responsible for installation,
operation, and maintenance, if the building owners do not want to perform this function.

•	A building that is one of several similar facilities in the same enterprise - If a packaged system
is a good fit for one facility, it becomes a known quantity that can be confidently deployed at
other facilities with similar load requirements and layouts.

Larger energy users, such as industrial/manufacturing facilities and some large institutional facilities
might not find as much value in a packaged system as they would in a custom-engineered conventional
CHP system that can be precisely tailored to their specific facility needs.

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7.4.1 Installed Packaged Systems

Figure 7-10 presents packaged system installations by market segment, and Table 7-1 presents total
installed packaged system capacity and the median system size by market segment.

Figure 7-10. Packaged System Installations by Market Segment

140

1

Industrial

¦ III

Commercial/lnstitutional/Multifamily



/ // /* /
/ / / s #•

J?



&



I

&



Z/////W

*c5& ^ ~ 
-------
Table 7-1. Packaged Systems Total Installed Capacity and Median Size by Market

Segment

Sector

Market Segment

Installed Capacity (MW)

Median Size (kW)



Agriculture

4.5

100



Chemicals

5.0

180

+-»

tn

Food Processing

10.9

300

~o
c

Misc. Manufacturing

8.0

390



Other Industrial

9.8

180



Amusement/Recreation

7.6

75



Colleges/Universities

14.5

180



Commercial Office Buildings

21.4

75



Government Buildings

6.4

90



Hospitals/Healthcare

15.7

220

u £ c
s_ o E

Hotels and Motels

7.8

100

U n:
£ => —

Multifamily Buildings

22.3

75

E 5 3

O J2 |

Nursing Homes

10.8

75

u S ^

Schools (K-12)

17.7

75



Supermarkets

4.2

320



Wastewater Treatment

14.1

130



Other Comm./Institutional

16.3

170



Other/Unknown

18.6

140

Source: ICF/U.S. DOE Combined Heat and Power Installation Database, February 2017
https://doe.icfwebservices.com/chpdb/.

The packaged system market has been dominated by market segments in the
commercial/institutional/multifamily sector. More than 91 percent of installations are contained in
these sectors. Multifamily buildings have the highest number of packaged system installations, followed
by schools and nursing homes. These market segments, as well as hotels, government buildings, and
amusement and recreation facilities, tend to use smaller systems, with median sizes of 100 kW or less,
than the other market segments. Industrial market segments have fewer installations but tend to have
larger capacities, with median sizes greater than 100 kW.

Figure 7-11 presents packaged system installations and capacity by size range. Almost 90 percent of the
packaged system installations are applications under 500 kW in size (although packaged system are
available in sizes up to several MW). Note that the total installed capacity of systems under 500 kW is
approximately equal to that of systems > 500 kW.

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Figure 7-11. Packaged System Installations and Capacity by Size Range

<100 kW 100-199 kW 200-499 kW 500-999 kW 1-5 MW
Packaged CHP Size Range

¦ Total Capacity (MW) I Number of Installations

Source: ICF/U.S. DOE Combined Heat and Power Installation Database, February 2017,
https://doe.icfwebservices.com/chpdb/.

7.4.2 Technical Potential

Technical potential is an estimate of market size constrained only by technological limits—the ability of
CHP technologies to fit customer energy needs without regard to economic for market factors. For this
reason, actual potential will be less than technical potential, but in some cases, it may still be a useful
indicator of relative economic potential.

Ninety percent of packaged system installations are units under 500 kW. There is currently 21.3 GW of
technical potential for systems under 500 kW in the U.S. commercial, institutional, and multifamily
sectors108, at more than 100,000 facilities. The technical potential for <500 kW packaged system
applications is greatest in the following ten market segments:

Amusement/recreation
Big box retail

Commercial office buildings
Government buildings
Hotels and motels
Multifamily buildings
Nursing homes
Restaurants
Schools
Supermarkets

108 ICF, CHP Technical Potential Database, 2016.

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Each of these market segments is estimated to contain over 1 GW of technical potential for systems
<500 kW. Figure 7-12 breaks down the technical potential for packaged systems <500 kW.

Figure 7-12. Technical Potential for <500 kW Packaged CHP Applications in the
Commercial and Institutional Sectors, by Market Segment

3,000

2,500





Source: ICF, 2016.

More information on the technical potential for CHP applications - including the industrial sector and
larger size ranges - can be found in the Department of Energy's 2016 CHP Technical Potential Report.109

7.5 Technology Description

The general design of packaged systems is relatively consistent throughout all packaged products. The
main components of packaged systems include:

•	Prime mover - the power-producing machine (or chemical process, in the case of fuel cells) that
drives the electric generator.

•	Generator - a device that converts mechanical energy into electricity.

•	Heat exchanger - a device that transfers heat from the prime mover exhaust gas and/or the
engine block to water, to produce hot water or steam.

109 U.S. Department of Energy, Combined Heat and Power (CHP) Technical Potential in the United States, March 2016,
http://energy.gov/sites/prod/files/2016/04/f30/CHP%20Technical%20Potential%20Study%203-31-2016%20Final.pdf.

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• Control panel - controls and monitoring instruments.

Figure 7-13 provides a process diagram that shows how these different components interact in a
packaged system.

Figure 7-13. Packaged CHP System Diagram

Source: EPA CHP Partnership

7.5.1 Heat Recovery

A defining characteristic of CHP systems is their ability to recover and put to beneficial use otherwise-
wasted heat. Most packaged systems use recovered heat to produce hot water, but steam and chilled
water options are also available.

To produce chilled water, packaged systems are coupled with an absorption chiller, which converts
recovered heat into chilled water that can be used for air conditioning or other cooling loads. In this
way, more of the system's thermal output can be used, which increases system efficiency. Packaged
systems with absorption chillers are well-suited for applications that consistently require chilled water,
such as supermarkets and data centers, as well as buildings with seasonal heating and cooling needs,
like multifamily buildings, hotels, health clubs and health care facilities.

Specifying Packaged CHP System Capacity Based on Thermal and Electric Requirements

Sizing decisions are best made based on an understanding of facility electrical and thermal loads (hot
water, heating cooling), and how they match with the outputs of available packaged systems.
Typically, packaged CHP capacity is selected in a way that allows facilities to utilize all of the electric
and thermal energy on site, while operating at or near full load. Building energy modeling can be used
to determine the system that best meets the facility's needs while operating efficiently and providing
an acceptable return on investment. Energy models often used include eQUEST and EnergyPlus.

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7.6 Cost and Performance Characteristics

When making a purchase decision, the cost and performance characteristics presented in this section
should be considered in conjunction with other factors, such as expected service life, guarantees, and
availability of service and support, along with performance characteristics not presented here, such as
noise and vibration.

Table 7-2 summarizes the performance characteristics for packaged systems consisting of a single
reciprocating engine or microturbine. Data were gathered from the seven EPA CHP Partner companies
that manufacture packaged systems and that responded to a data request.110

Fuel Cells: Efficient Operation and Environmental Benefits

Fuel cell CHP systems can be designed to operate with high electric efficiencies—potentially over 50
percent—and can maintain high efficiency at partial loads. Most fuel cells convert natural gas to
hydrogen using a reformer, which emits carbon at a lower rate than other prime mover technologies.
Nearly all fuel cell CHP is sold as packaged systems.

Table 7-2. Packaged CHP Systems - Performance Characteristics

Performance Characteristic

Size Range (kW)111

30-99

100-199

200-499

500-1,000

>1,000

Electrical Heat Rate (Btu/kWh), HHV

10,000 -
12,600

9,800 -
12,600

9,200 -
10,800

9,000 -
11,000

8,200 -
10,400

Electrical Efficiency (%), HHV

24-32%

27-35%

32-37%

28-38%

33-41%

Total Heat Recovered (Btu/kWh)

5,300 -
7,000

4,600 -
6,400

3,600 -
5,400

3,600 -
4,700

3,400 -
5,600

Typical form of Recovered Heat112

H20

H20

H20

H20

H20, Steam

Total CHP Efficiency113 (%), HHV

73-82%114

67-86%

76-82%

67-82%

78-87%

Power/Heat Ratio

0.49-0.64

0.52-0.73

0.64-0.95

0.72-0.96

0.61-1.01

Source: Compiled from data supplied by the seven EPA CHP Partner companies that manufacture packaged systems
and that responded to a data request.

110	These seven companies manufacture systems using reciprocating engines or microturbines, which account for 97 percent of
packaged systems in the United States (fuel cell systems account for the remaining three percent). One additional company,
which manufactures packaged systems using fuel cells, responded to the data request. However, because fuel cells have
different characteristics, and tend to be used in different applications than reciprocating engine and microturbine systems, they
are not a focus of this section. Fuel cell cost and performance characteristics can be found in the Fuel Cells section of the
Catalog.

111	Size ranges reflect the large majority of packaged systems sold. However, some vendors sell systems as small as 5 kW.

112	Although hot water is the typical form of recovered heat for most size ranges, steam may be an option for all ranges.

113	Total CHP efficiency for reciprocating engines is approximately 80 percent, while the total CHP efficiency for microturbines
tends to be close to 70 percent.

114	One vendor reports offering a 50 kW system with 92 percent efficiency. The system has unique attributes and certain
limitations compared to typical systems.

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Some key takeaways from Table 7-2 are:

•	Electric efficiencies and total CHP efficiencies tend to increase with system size.

•	As systems get larger, the power-to-heat ratio tends to increase (i.e., more electricity is
delivered relative to recovered heat).

•	Performance varies within a given size range due to different prime mover and heat recovery
technologies, and different system designs.

•	Recovered heat from packaged systems is typically in the form of hot water.

More details on the characteristics of efficiency, thermal output, and other technical information for
reciprocating engines and microturbine technologies are provided in their respective Catalog sections.

7.6.1	Part-Load Operation

In most packaged systems, reciprocating engines or microturbines drive generators at a constant speed
to produce steady alternating current (AC) power. As load is reduced, generator speed decreases, the
heat rate of the prime mover increases, and electrical efficiency decreases. Electrical efficiency at half
load is typically 10 to 25 percent less than full-load efficiency, with efficiencies falling more steeply for
loads lower than half of the unit's rated capacity.

Systems comprising multiple units can reduce part-load efficiency penalties, which is especially
important for commercial applications. Electric loads for commercial buildings tend to vary more than
they do in manufacturing facilities. Because individual units can be put in standby mode when the
building load drops, the other units can continue to operate at or near peak efficiency. In the same
circumstances, a single-unit system might need to operate at reduced electrical efficiency.

More information on part-load performance for reciprocating engines and microturbines can be found
in their respective sections of the Catalog.

7.6.2	Installed Costs

Installed costs include equipment and installation costs. Equipment costs vary depending on factors
such as:

•	Emissions controls (included as standard equipment or as options)

•	Sound attenuation performance level

•	Generator type (induction/synchronous/inverter)

•	Black start/islanding capability

•	Specialized heat recovery equipment (e.g. absorption chiller)

Table 7-3 presents typical equipment costs for packaged systems. These costs represent cost data
provided by EPA CHP Partner companies that manufacture packaged systems and reflect difference in
features provided as standard equipment.

Installation costs are not presented. Packaged system vendors report large variations in installation
costs, based on such factors as:

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7-13

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Variables based on the location of the equipment, such as ventilation routing, or rigging or
cranes that might be required for installation. Also, installation costs may be higher for retrofits
of existing buildings compared to new construction.

Insurance requirements for contractors and subcontractors.

Bonding requirements.

Restrictions on working hours and access to site.

Metering, permitting, and utility interconnection requirements.

Local labor rates or minimum rates required by the Davis-Bacon and Related Acts, where
applicable.

• Black start/islanding capability, which adds to installation costs depending on factors such as the
existing electrical system in the host facility, switchgear required, and the size of the electrical
loads to be served when the system is islanding.

Installation costs for packaged systems tend to be less than for conventional systems of similar size. For
example, for a 1,000 kW packaged system, installation costs can be as low as $150,000 compared to
$700,000 for conventional systems.

Table 7-3. Packaged CHP Systems - Equipment Costs

Packaged System Costs

Size Range (kW)

30-99

100-199

200-499

500-1,000

>1,000

Equipment Cost ($/kW)

$1,000 -
$2,850

$1,400 -
$3,100

$1,000 -
$2,000

$900-
$1,850

$650-
$1,100

Source: Compiled from data supplied by the seven EPA CHP Partner companies that manufacture packaged systems
and that responded to a data request.

7.6.3 Maintenance Costs

Unlike for conventional systems, maintenance for packaged systems is typically performed by the
system vendor or a third party. Maintenance costs vary depending on factors such as type of CHP
technology, remote monitoring, and performance guarantees. The ranges of maintenance costs for
different sizes of packaged system reciprocating engines and microturbines are shown in Table 7-4
(while costs here are presented in $/kWh, note that some vendors price maintenance in $/run hour, not
$/kWh). For more information on maintenance requirements for reciprocating engines and
microturbines, refer to their respective sections of the Catalog.

Table 7-4. Packaged CHP Systems - Maintenance Costs



Size Range (kW)

30-99

100-199

200-499

500-1,000

>1,000

Maintenance
Costs ($/kWh)

$0,013 -
$0,025

$0,018 -
$0,025

$0,017 -
$0,021

$0,010-
$0,016

$0,002-
$0,016

Source: Compiled from data supplied by the seven EPA CHP Partner companies that
manufacture packaged systems and that responded to a data request, vendors.

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7.6.4 Fuels

Packaged systems generally use natural gas as fuel. However, other fuels, such as propane and biogas,
can be used. Biogas fuels (e.g., anaerobic digester gas and landfill gas) may require pretreatment to
remove moisture, hydrogen sulfide and siloxanes. The extent of pretreatment depends on the quality of
the fuel and the prime mover technology. More details on fuels that can be used for different prime
movers can be found in their respective technology characterizations in the Catalog.

7.7 Emissions, Emissions Control Options, and Prime Mover Certification

Most CHP systems emit certain pollutants-carbon dioxide115, oxides of nitrogen (NOx), carbon monoxide
(CO), and volatile organic compounds. Emissions can vary depending on the prime mover technology,
fuel type, and the emissions controls that are applied. Many packaged systems are equipped with
emissions controls to reduce NOx, CO and VOC emissions. Additional emissions controls may be
available as options.

Packaged system vendors may offer systems with engines certified to comply with U.S. EPA regulations
for stationary engines. A certificate of conformity with the Clean Air Act is supplied with these engines.
Owners of systems with non-certified engines are responsible for having the engines individually
performance-tested using the required EPA-approved test protocol (some vendors who sell uncertified
systems perform emissions testing on systems after they are installed).

A thorough discussion of emissions and control options for each prime mover technology is provided in
its respective technology characterization sections of the Catalog.

115 While there is no currently viable technology to reduce C02 emissions from fossil fuel combustion, emissions can be reduced
by increasing the useful outputs from a given amount of fuel burned. CHP is a highly cost-effective way to achieve this
objective.

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Appendix A: Expressing CHP Efficiency

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Appendix A: Expressing CHP Efficiency

A.l Expressing CHP Efficiency

Many of the benefits of CHP stem from the relatively high efficiency of CHP systems compared to other
systems. Because CHP systems simultaneously produce electricity and useful thermal energy, CHP
efficiency is measured and expressed in a number of different ways116 Table A-l summarizes the key
elements of efficiency as applied to CHP systems.

As illustrated in Table A-l the efficiency of electricity generation in power-only systems is determined by
the relationship between net electrical output and the amount of fuel used for the power generation.
Heat rate, the term often used to express efficiency in such power generation systems, is represented in
terms of Btus of fuel consumed per kWh of electricity generated. However, CHP plants produce useable
heat as well as electricity. In CHP systems, the total CHP efficiency seeks to capture the energy content
of both electricity and usable steam and is the net electrical output plus the net useful thermal output of
the CHP system divided by the fuel consumed in the production of electricity and steam. While total CHP
efficiency provides a measure for capturing the energy content of electricity and steam produced it does
not adequately reflect the fact that electricity and steam have different qualities. The quality and value
of electrical output is higher relative to heat output and is evidenced by the fact that electricity can be
transmitted over long distances and can be converted to other forms of energy. To account for these
differences in quality, the Public Utilities Regulatory Policies Act of 1978 (PURPA) discounts half of the
thermal energy in its calculation of the efficiency standard (EffFERc). The EFFferc is represented as the
ratio of net electric output plus half of the net thermal output to the total fuel used in the CHP system.
Opinions vary as to whether the standard was arbitrarily set, but the FERC methodology does recognize
the value of different forms of energy. The following equation calculates the FERC efficiency value for
CHP applications.

P +

EFFferc = j

Another definition of CHP efficiency is effective electrical efficiency, also known as fuel utilization

effectiveness (FUE). This measure expresses CHP efficiency as the ratio of net electrical output to net
fuel consumption, where net fuel consumption excludes the portion of fuel that goes to producing
useful heat output. The fuel used to produce useful heat is calculated assuming typical boiler efficiency,
generally 80 percent. The effective electrical efficiency measure for CHP captures the value of both the
electrical and thermal outputs of CHP plants. The following equation calculates FEU.

116 Measures of efficiency are denoted either as lower heating value (LHV) or higher heating value (HHV). HHV includes the heat
of condensation of the water vapor in the products. Unless otherwise noted, all efficiency measures in this section are reported
on an HHV basis.

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FUE captures the value of both the electrical and thermal outputs of CHP plants and it specifically
measures the efficiency of generating power through the incremental fuel consumption of the CHP
system.

EPA considers fuel savings as the appropriate term to use when discussing CHP benefits relative to
separate heat and power (SHP) operations. Fuel savings compares the fuel used by the CHP system to a
separate heat and power system (i.e. boiler and electric-only generation). The following equation
determines percent fuel savings (S).

In the fuel saving equation given above, the numerator in the bracket term denotes the fuel used in the
production of electricity and steam in a CHP system. The denominator describes the sum of the fuel
used in the production of electricity (P/EffP) and thermal energy (Q/EffQ) in separate heat-and-power
operations. Positive values represent fuel savings while negative values indicate that the CHP system in
question is using more fuel than separate heat and power generation.

Table A-l. Measuring the Efficiency of CHP Systems

System

Component

Efficiency Measure

Description

Separate
heat and
power (SHP)

Thermal

Efficiency (Boiler)

Net Useful Thermal Output

Err0 =

Energy Input

Net useful thermal output for the
fuel consumed.

Electric-only
generation

Power Output

-L/-T _Tp —

Energy Input

Electricity Purchased From
Central Stations via Transmission
Grid.

Overall Efficiency
of separate heat
and power (SHP)

P + Q

EFF,„, = 				

P/EFFpo_r +0/EFFra		

Sum of net power (P) and useful
thermal energy output (Q)
divided by the sum of fuel
consumed to produce each.

Combined
heat and
power (CHP)

Total CHP System
Efficiency

effm=(p+q)/f

Sum of the net power and net
useful thermal output divided by
the total fuel (F) consumed.

FERC Efficiency
Standard

EFF -(P + Q/2)

Ljl 1 FERC r,

F

Developed for the Public Utilities
Regulatory Act of 1978, the FERC
methodology attempts to
recognize the quality of electrical
output relative to thermal
output.

Catalog of CHP Technologies

A-2

Appendix A


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Table A-l. Measuring the Efficiency of CHP Systems

System

Component

Efficiency Measure

Description



Effective
Electrical
Efficiency (or
Fuel Utilization
Efficiency, FUE):

P

FUE =

F - Q/EFEj^g^j

Ratio of net power output to net
fuel consumption, where net fuel
consumption excludes the
portion of fuel used for producing
useful heat output. Fuel used to
produce useful heat is calculated
assuming typical boiler efficiency,
usually 80 percent.



Percent Fuel
Savings

S = 1			—	

P/EFFp + Q/EFFq

Fuel savings compares the fuel
used by the CHP system to a
separate heat and power system.
Positive values represent fuel
savings while negative values
indicate that the CHP system is
using more fuel than SHP.

Key:

P = Net power output from CHP system

Q = Net useful thermal energy from CHP system
F = Total fuel input to CHP system
EFFp = Efficiency of displaced electric generation
EFFq = Efficiency of displaced thermal generation

Catalog of CHP Technologies

A-3

Appendix A


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