Commercial and Industrial CHP Technology Cost and ...capabilities.itron.com/efg/2011/EIA2010ComIndCHPTechCostandPerformance0831.pdfCHP Technology Cost and Performance Data Analysis

Commercial and Industrial

CHP Technology

Cost and Performance Data

Analysis for EIA

Submitted to:

Thomas D. Devlin

SAIC, Inc.

Submitted to:

Erin Boedecker

Elizabeth Sendich

Energy Information Administration

Submitted by:

SENTECH, Incorporated

7475 Wisconsin Avenue

Suite 900

Bethesda, MD 20814

June 2010

Table of Contents

TABLE OF CONTENTS ................................................................................................................................ 2

TECHNICAL APPROACH ..................................................................................................................................... 1 REPORT ORGANIZATION ................................................................................................................................... 2

COMMERCIAL CHP MARKET ..................................................................................................................... 3

COMMERCIAL CHP APPLICATIONS ..................................................................................................................... 7 COMMERCIAL DISTRIBUTED GENERATION TECHNOLOGIES ...................................................................................... 8 DECLINE IN NEW CHP INSTALLATIONS ................................................................................................................ 9

CURRENT EIA COMMERCIAL CHP TECHNOLOGY CHARACTERIZATION .................................................... 12

RECOMMENDED PROTOTYPE CHP TECHNOLOGIES FOR THE COMMERCIAL SECTOR .............................. 16

FUEL CELLS .................................................................................................................................................. 18 Technology Specifications ................................................................................................................... 18

RECIPROCATING ENGINES ............................................................................................................................... 19 Digester Gas CHP ................................................................................................................................ 19 Technology Specifications ................................................................................................................... 20

GAS TURBINES ............................................................................................................................................. 22 Technology Specifications ................................................................................................................... 22

MICROTURBINES .......................................................................................................................................... 23 Technology Specifications ................................................................................................................... 24

COMMERCIAL CHP TECHNOLOGY COSTS ................................................................................................ 25

CAPITAL INSTALLED COSTS .............................................................................................................................. 25 OPERATING AND MAINTENANCE COSTS ............................................................................................................ 29

COMMERCIAL CHP TECHNOLOGY ADVANCEMENTS TO 2035 ................................................................. 31

INDUSTRIAL CHP MARKET ...................................................................................................................... 42

INDUSTRIAL CHP TECHNOLOGIES ..................................................................................................................... 49

CURRENT EIA INDUSTRIAL CHP TECHNOLOGY CHARACTERIZATION ....................................................... 49

RECOMMENDED PROTOTYPE CHP TECHNOLOGIES FOR THE INDUSTRIAL SECTOR ................................. 50

RECIPROCATING ENGINES ............................................................................................................................... 52 Technology Specifications ................................................................................................................... 52

GAS TURBINES ............................................................................................................................................. 53 Technology Specifications ................................................................................................................... 53

COMBINED CYCLES AND STEAM TURBINES ......................................................................................................... 55 Technology Specifications ................................................................................................................... 56

INDUSTRIAL CHP TECHNOLOGY COSTS ................................................................................................... 60

CAPITAL INSTALLED COSTS .............................................................................................................................. 60 OPERATING AND MAINTENANCE COSTS ............................................................................................................ 62

INDUSTRIAL CHP TECHNOLOGY ADVANCEMENTS TO 2035 .................................................................... 63

REFERENCES ........................................................................................................................................... 69

APPENDIX A: SUMMARY OF CHP INSTALLATION DATA .......................................................................... 71

APPENDIX B: EFFICIENCY CALCULATIONS ............................................................................................... 75

1

Introduction

Distributed generation (DG) is the strategic placement of electric power generating units

at or near customer facilities to supply on-site energy needs. A primary subset of the

greater DG market is combined heat and power (CHP). CHP is the sequential or

simultaneous generation of two different forms of useful energy – mechanical and

thermal - from a single primary energy source in a single, integrated system. CHP

systems usually consist of a prime mover, a generator, a heat recovery system, and

electrical interconnections configured into an integrated whole. The prime mover is any

engine used to convert fuel to shaft power or mechanical energy. The generator converts

the mechanical energy into electricity. The heat recovery system captures and converts

the energy in the prime mover’s exhaust into useful thermal energy. The mechanical

energy from the prime mover is most often used to drive a generator for producing

electricity, but may also drive rotating equipment such as compressors, pumps and fans.

The thermal energy from the heat recovery system can be used indirectly to produce

steam, hot water, chilled water for process cooling or provide input to thermally activated

cooling and dehumidification systems.

It is critical that the U.S. Department of Energy’s Energy Information Administration

(EIA) have up-to-date and accurate information on CHP technology cost and

performance. Sentech, Inc. was tasked to assist EIA characterize and update CHP

technology assumptions used in their commercial and industrial market forecast models.

Technical Approach

The approach used in this project consisted of a review of recent CHP and distributed

generation technology characterizations, a review of recent commercial CHP market

activity through the use of public and proprietary databases of CHP installations, a review

of industry publications and product literature of commercially available CHP

alternatives, a review of costs from CHP systems funded through state programs, and

telephone interviews with CHP equipment providers, industry associations, CHP R&D

stakeholders at manufacturers and government and private funding organizations, actual

end-users, and turn-key CHP system providers.

The results of the literature review, market activity assessment, and telephone interviews

were used as the basis to define a set of representative prototype CHP systems that reflect

the predominant commercial and industrial configurations used given current market

conditions. Assessment of technology trends (breakthroughs and incremental

development), review of production and packaging methods, and interviews with

technology developers and the R&D community provided the basis of out-year

projections of cost and performance of the representative systems to the year 2035.

2

Report Organization

This report provides documentation of the efforts to characterize current and projected

commercial and industrial CHP technology performance and costs. It is presented in six

topical sections within the two primary market applications (i.e. commercial and

industrial):

CHP Market Background

Current EIA Technology Assumptions

Recommended Technology Systems

Technology Performance

Technology Costs

Projected Technology Improvements to 2035

3

Commercial CHP Market

Existing U.S. commercial CHP installations and recent CHP market activity were

assessed using CHP installation database maintained by ICF International1 (ICF) with

funding from the U.S. Department of Energy (DOE) and Oak Ridge National Laboratory

(ORNL). Many commercial sector CHP systems are smaller than 1 MW and this report

includes extensive data from the ICF CHP database because of its coverage of systems as

small as 10 kW.2 The ICF CHP database contains basic facility information including

facility name, prime mover, capacity, location, fuel, and utility, as well as information on

system ownership, thermal use, and contact information. This report also incorporates

information from EIA’s Form 860, press releases, industrial periodicals and other

sources. EIA Form 860 does not make a point of including installations below 1 MW in

its survey frame. Summary CHP market data is shown in Appendix A.

Commercial applications comprise approximately 40% of the new U.S. CHP capacity

between 2006 and 2008 while industrial comprised 57% of new CHP capacity as seen in

Table 1-1. From Table 1-2 it can be seen that over the past 100 years commercial CHP

has only represented 13% of total CHP capacity.

Table 1-1: New U.S. CHP Capacity 2006-2008

Sector Class Number of Sites Capacity (MW)

Commercial 190 347.4

Industrial 53 495.6

Other 38 25.6

Total 281 868.6 Source: ICF Combined Heat and Power Installation Database

Table 1-2: Total U.S. CHP Capacity 1900- 2008


Commercial 1727 11044

Industrial 1235 65850

Other 194 5043

Total 3156 81937 Source: ICF Combined Heat and Power Installation Database

Commercial CHP sites include both commercial buildings and institutional facilities

1 ICF International acquired Energy and Environmental Analysis, Inc. (EEA) in January 2007.

2 The CHP installation database is available at www.eea-inc.com/chpdata/index.html. It contains basic

facility information including facility name, prime mover, capacity, location, fuel, and application.

The database was originally derived from the Hagler Bailly “Independent Power” database that tracked

CHP installations with initial funding by GRI. With support from US DOE and Oak Ridge National

Laboratory the database is updated annually. The data presented in the main body of this report was last

updated on January 2009 according to the website.

4

(e.g., district energy plants and colleges/universities). Commercial market summary

information is presented in Tables 2 and 3 and Figure 1.

Table 2-1: New Commercial CHP Market by Size Class 2006-2008

<1 MW 1-5 MW 5-20 MW 20-50 MW 50-100 MW >100 MW Total

Number of Sites 133 40 13 3 1 0 190

Capacity (MW) 32.2 92.1 88.2 72.0 62.9 0.0 347.4

Source: ICF Combined Heat and Power Installation Database

Table 2-2: Total Commercial CHP Market by Size Class 1900-2008

<1 MW 1-5 MW 5-20 MW 20-50 MW >50 MW Total

Number of Sites 1110 334 161 71 51 1727

Capacity (MW) 202.1 768.6 1501.1 2283.0 6290.1 11044.9


Table 3-1: New Commercial CHP Market Facility Size Summary Data 2006-2008

Minimum Site Capacity (MW) 0.03

Maximum Site Capacity (MW) 62.90

Mean Site Capacity (MW) 1.83

Median Site Capacity (MW) 0.32 Source: ICF Combined Heat and Power Installation Database

Table 3-2: Total Commercial CHP Market Facility Size Summary Data 1900-2008

Minimum Site Capacity (MW) 0.003

Maximum Site Capacity (MW) 510.00

Mean Site Capacity (MW) 6.40

Median Site Capacity (MW) 0.26 Source: ICF Combined Heat and Power Installation Database

More than half of all new and existing commercial CHP installations have a capacity of

less than 1 MW; however these systems comprise only a small share of the installed

capacity. As shown in Table 2-1, most of the new commercial CHP capacity is in units

between 1 and 20 MW. Table 2-2 illustrates the distribution of total installed CHP

capacity with slightly more than half of commercial CHP capacity at units larger than 50

MW.

5

Commercial Applications

0

20

40

60

80

100

120

140

<1 MW 1-5 MW 5-20 MW 20-50 MW 50-100 MW >100 MW

Nu

mb

er

of

Sit

es

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

Cap

ac

ity

(M

W)

Number of Sites

Capacity (MW)


Figure 1: New Distribution of Commercial CHP Market by Facility Size 2006-2008

Tables 4 and 5 present the primary fuel and prime mover distribution of the installed

commercial CHP.

Table 4-1: New Commercial CHP Installations by Fuel 2006-2008

Natrual Gas Oil Waste Fuels Biomass Total

Number of Sites 150 10 8 22 190

Capacity (MW) 100.8 2.8 22.4 39.6 165.6

Minimum Site Capacity (MW) 0.03 0.06 0.06 0.025

Maximum Site Capacity (MW) 6.00 0.72 5.50 6.20

Mean Site Capacity (MW) 0.67 0.28 2.80 1.80

Median Site Capacity (MW) 0.26 0.25 2.87 1.06 Source: ICF Combined Heat and Power Installation Database

Table 4-2: Total Commercial CHP Installations by Fuel 1900-2008

Natrual Gas Oil Waste Fuels Biomass Other Coal Wood Total

Number of Sites 1332 132 46 107 51 52 7 1727

Capacity (MW) 7434.381 653.698 876.434 423.009 37.899 1554.073 65.375 11044.9

Minimum Site Capacity (MW) 0.005 0.005 0.030 76.000 0.005 0.300 0.600

Maximum Site Capacity (MW) 510.00 210.20 100.00 3.95 13.50 175.00 25.00

Mean Site Capacity (MW) 5.58 4.95 19.05 0.003 743.120 29.886 9.339

Median Site Capacity (MW) 0.15 0.89 6.00 1.60 90.00 22.00 4.00


6

Table 5-1: New Commercial CHP Installations by Technology 2006-2008

Boiler/Steam

Turbine

Combustion

Turbine Fuel Cell

Reciprocating

Engine Microtubine

Other or

Unknown Total

Number of Sites 8 12 11 130 25 4 190

Capacity (MW) 77.7 140.4 5.4 94.7 7.1 22.0 347.4

Minimum Site Capacity (MW) 0.39 4.00 0.20 0.025 0.030 5.500

Maximum Site Capacity (MW) 25.00 62.90 1.00 6.00 0.96 5.50

Mean Site Capacity (MW) 9.72 11.70 0.49 0.73 0.29 5.50

Median Site Capacity (MW) 4.25 5.30 0.40 0.26 0.24 5.50 Source: ICF Combined Heat and Power Installation Database

Table 5-2: Total Commercial CHP Installations by Technology 1900-2008

Boiler/Steam

Turbine

Combined

Cycle

Combustion

Turbine Fuel Cell

Reciprocating

Engine Microtubine

Other or

Unknown Total

Number of Sites 153 55 153 57 1205 89 15 1727

Capacity (MW) 3847.2 3319.9 2713.9 18.7 1073.7 18.5 52.9 11044.9






Based on tables 4 and 5, the CHP market can be summarized as follows:

On average, commercial sites are much smaller than industrial sites. Technologies

for smaller applications have been more expensive and less efficient than larger

CHP.

Commercial establishments generally operate fewer hours per year and have

lower load factors, providing fewer hours of operation per year in which to

payback their higher first costs.

Unlike the majority of industrial projects that can absorb the entire thermal output

of a CHP system on-site, many commercial sites have either an inadequate

thermal load or a highly seasonal load such as space heating. The best overall

efficiency and economics come from a steady thermal load. These loads are

concentrated in relatively few types of commercial applications.

The average site size for each commercial CHP prime mover technology indicates

that most microturbine facilities and many reciprocating engine sites contain

multiple units. This is likely due to several factors. The need for redundancy in

order to enhance reliability is still an issue. Use of multiple prime movers also

facilitates higher operating efficiencies; the relatively low electric load factors and

seasonal thermal loads of commercial sites would likely require frequent part load

operation for a single unit system sized to average electric or peak thermal load.

To optimize efficiency, a well controlled configuration consisting of multiple

units which are optimally dispatched is often utilized. Nearly all generation

7

systems operate most efficiently at full load. The commercial market for

microturbines has historically focused on units with 30-70 kW of generating

capacity. The current development of larger microturbines is evidence that there

is some perceived market pull for larger systems, which is reflected by the

inclusion of a 200 kW microturbine in the list of prototypes.

Commercial CHP Applications

Commercial CHP applications typically are based on energy use in buildings. Unlike the

industrial sector that, on balance, reflects an electric load limited environment for CHP,

the commercial sector is predominantly thermal load limited. This limitation can occur

due to an inadequate or highly seasonal thermal load that is not coincident with the

electric load – as in the thermal needs for space heating. Another limitation of

commercial applications is the more limited hours of operation compared to an industrial

process operation. For example, an office building may operate 3,000 hours per year

compared to a refinery that is operated continuously, or 8,760 hours per year. High and

fairly constant thermal loads and a high number of operating hours per year characterize

the commercial applications that are favorable to CHP. CHP systems are also typically

sized to operate on a base-load basis and utilize the electric grid for supplementary and

backup power.

The simplest integration of CHP into the commercial building sectors is in applications

that meet the following criteria:

relatively coincident electric and thermal loads

thermal energy loads in the form of hot water

electric demand to thermal demand ratios in the 0.5 to 2.5 range

moderate to high operating hours (>3000 hours per year)

Thermal loads most amenable to CHP systems in commercial/institutional buildings are

space heating and hot water requirements. Needless to say, the complexity of installation

and associated costs are very site specific. The simplest thermal load to supply is hot

water. Retrofits to the existing hot water supply are relatively straightforward, and the hot

water load tends to be less seasonally dependent than space heating, and therefore, more

coincident to the electric load in the building.

Meeting space heating and cooling needs with CHP can certainly be done but is slightly

more complicated. Space heating and cooling loads are seasonal by nature and require

carefully designed and optimized control systems in combination with custom installation

engineering. Space conditioning loads are supplied by various methods in the

commercial/institutional sector, centralized hot water or steam for space heating being

only one. Absorption cooling, which relies on a chemical process to absorb and evaporate

refrigerant rather than on mechanical vapor compression cycle used by electric air

conditioning, matches well with commercial CHP applications. Indirect fired absorption

machines use hot water, steam or exhaust gases as the heat source and fit nicely with both

commercial CHP generation technologies and applications. Single effect absorption

8

machines require only a low temperature heat source. A typical small packaged

absorption chiller uses 190oF water. Water at this temperature is available from the jacket

water of reciprocating engine systems or can easily be derived from the exhaust of a

microturbine using an air-to-water heat exchanger.3

A double effect absorption machine

can provide COP of up to 1.2, but requires a higher temperature heat source, e.g., direct

firing or steam. Double effect systems consequently match well with gas turbines

equipped with a heat recovery steam generator (HRSG).4

Considering the electric and thermal load profiles and the diversity of building types and

legacy space conditioning equipment, it is clear why a single or small set of “silver

bullet” commercial CHP systems have become prominent. Explicit assessments and

characterizations by space conditioning technology of incremental design, installation

and operating costs for hot water, space heating and cooling provisions are beyond the

scope and budget of this project which is focused primarily on CHP generation

technology. This issue is probably best addressed in a follow-on project using an

exhaustive case study approach segmented by targeted commercial building type, age,

and climate and existing heating and/or cooling technology. CHP equipment developers

and system packagers have embarked on the difficult process of developing solutions to

this. Integrated energy systems (IES) are packaged combined cooling heating and power

systems (CCHP) consisting of generator sets, heat exchangers, thermal energy recovery

and utilization equipment (thermally activated heating, cooling and dehumidification),

and control systems that are being designed for targeted commercial market sectors with

federal and state R&D support. The intended value proposition of IES packages is to

simply and cost-effectively address this key application issue of the diverse commercial

market. IES packages are at different stages of development with most still yet to be

demonstrated on a full commercial scale.

Historically primary targets for CHP in the commercial sectors are those building types

with electric to hot water demand ratios consistent with the capability of current DG and

heat recovery equipment: Education, Health Care, Lodging, and District Energy

applications.

Technology development efforts targeted at heat activated cooling/refrigeration and

thermally regenerated desiccants could expand the application of commercial CHP by

increasing the base 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 in CHP markets such as restaurants, supermarkets,

refrigerated warehouses, and office buildings.

Commercial Distributed Generation Technologies

There are a variety of technologies that can be used for distributed generation in

commercial applications. Table 6 summarizes size ranges and applications for primary

3 According to Capstone, 60 kW microturbines can provide 0.32 tons of cooling per kW or just under 20

tons of cooling. 4 A 5 MW gas turbine with an HRSG can provide 0.48 tons of cooling per kW or 2,400 tons of waste-fired

9

DG technologies. In most cases, commercial CHP systems consist of a heat engine, or

prime mover that creates shaft power that in turn drives an electric generator. Diesel

fueled reciprocating engines are used extensively in commercial facilities primarily as

backup emergency generators. They are best suited for that application due to rapid

startup, on-site fuel storage capability, low capital cost per power output and very high

emissions profile. They have been employed as CHP systems. Photovoltaic utilize

renewable fuel sources to produce power. High costs currently limit these systems to

niche non-CHP applications. In CHP mode, waste heat from the prime mover is

recovered to provide steam or hot water to meet on-site needs. Prime movers for

commercial CHP systems include reciprocating engines, combustion or gas turbines,

microturbines, and fuel cells. In this analysis only fossil fueled CHP systems and one

biogas CHP system were considered.

Table 6: Commercial Distributed Technologies

Type Size Market

Power Generation Only

Diesel Compression Ignited

Reciprocating Engine 50 kW - 3 MW

Standby, remote, and peaking power for commercial and

industrial; T&D support

Photovoltaics 1 kW - 100 kW Primary power, remote power, green power

Combined Heat and Power

Natural Gas Spark Ignited

Reciprocating Engine 60 kW - 2 MW

Peaking and primary power; commercial and industrial

combined heat and power

Diesel Compression Ignited

Reciprocating Engine 50 kW - 3 MW Village power, micro-grid, renewable (wind) hybrid

Natural Gas Combustion

Turbine 3000 kW - 30 MW Industrial combined heat and power; T&D support

Microturbine 30 kW - 250 kW

Primary power, commercial and light industrial combined

heat and power

Fuel Cell 200 kW - 3 MW

Premium power, primary power, residential/commercial


Decline in New CHP Installations

Figure 2 shows CHP capacity additions for small/medium (<20 MW) and large (>=20

MW).5 This figure includes both commercial and industrial CHP systems. The quantity of

new capacity has dropped considerably in recent years. An average of 2,644 MW was

added per year from 2001 through 2004 before dropping to an average of 284 MW added

per year from 2005 through 2008; a decline of 81 percent. The decline has been

particularly pronounced in large (usually industrial) systems with generating capacities of

20 MW or more. Installations of large CHP systems declined by 94 percent between the

two periods, while installations of small/medium CHP systems declined by 22%.

There are several factors contributing to the decline of new installations:

Decline of economic activity in the manufacturing sector

Natural gas price volatility

Changes in rules regarding sales of excess electricity to the grid

5 Source: ICF Combined Heat and Power Installation Database. www.eea-inc.com/chpdata/index.html

http://www.eea-inc.com/chpdata/index.html

10

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1970

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

2006

2008

Ca

pa

cit

y A

dd

ed

(M

W)

Large Traditional CHP (>20 MW)

Small/Medium CHP (<=20 MW)

Figure 2 CHP Capacity Additions by Year

The current recession has had a major negative impact upon the manufacturing sector. In

addition to a general reduction in economic activity, several CHP-specific factors have

become less favorable. Capital is more expensive and less available than previous to

2004 and prices for the sale of excess power have become less favorable.

Natural gas price volatility has increased concerns for companies deciding whether to

consider natural gas-fired CHP projects. Although today's natural gas prices are low,

several price spikes (and the prospect that high prices may become permanent) over the

past 10 years have discouraged investments.

The Energy Policy Act of 2005 altered the landscape for CHP – especially for large

systems that represent the majority of CHP capacity. Section 1253 removes the

requirement for utilities to purchase power from large CHP units that operate in areas

with competitive electricity markets. In addition, entities developing CHP projects are

required to pay for upgrades to the electricity grid resulting from the CHP project. Some

potential developers have reported on the difficulty of negotiating these sophisticated

interconnection issues with utilities.

Despite the adverse market for CHP, recent federal legislation creates a new incentive for

CHP projects. The Emergency Economic Stabilization Act of 2008, enacted in October

2008, created a 10% investment tax credit (ITC) under 48(a)(3)(A)(v) of the Internal

11

Revenue Code. The CHP ITC is a 10 percent tax credit for the first 15MW of a system

and is limited to systems with a total capacity of 50MW or less and an efficiency of 60%

or higher. Systems up to 15 MW are eligible for the full credit and systems between 15

and 50 MW receive a prorated credit equal to the allowed capacity (15 MW) divided by

the actual system capacity. Systems larger than 50 MW are not eligible for the credit.

Systems must enter service prior to January 1, 2017.

12

Current EIA Commercial CHP Technology Characterization

The National Energy Modeling System (NEMS) is a computer-based, energy-economy

modeling system of U.S. energy markets for the long-term period through 2035. It is the

primary analysis tool for the development of long-term projections of the domestic

energy market published each year for the Annual Energy Outlook (AEO). NEMS was

designed and implemented by the U.S. Energy Information Administration (EIA) of the

U.S. Department of Energy (DOE). NEMS projects the production, imports, conversion,

consumption, and prices of energy, subject to assumptions of macroeconomic and

financial factors, world energy markets, resource availability and costs, behavioral and

technological choice criteria, cost and performance characteristics of energy

technologies, and demographics.

A key feature of NEMS is the representation of current technology and technology

improvement over time. Five of the sectors--residential, commercial, transportation,

electricity generation, and refining--include explicit treatment of individual technologies

and their characteristics, such as initial cost, operating cost, date of availability,

efficiency, and other characteristics specific to the sector.

EIA commercial CHP technology assumptions for the Annual Energy Outlook 2010 are

shown in Table 76. The analysis was completed in a series of reports by other

organizations that have been published to characterize CHP and distributed generation

costs and performance. That includes work by Discovery Insights7.

6 EIA Assumptions to the Annual Energy Outlook 2010 available through

http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/commercial_tbls.pdf 7 Discovery Insights, Commercial and Industrial CHP Technology Cost and Performance Data Analysis for

EIA’s NEMS, February 2006.

http://www.eia.doe.gov/oiaf/aeo/assumption/pdf/commercial_tbls.pdf

13

Table 7: Cost and Performance of EIA NEMS Commercial DG Technologies

Year

Average

Generating

Capacity (kW)

Electrical

Efficiency

Combined

Efficiency (Electrical +

Thermal Efficiency)

Installed Capital

Cost ($2005 per

kW of Capacity)

Service

Life

(Years)

2008 30 0.16 N/A $6,362 30

2010 32 0.18 N/A $5,717 30

2015 35 0.20 N/A $4,135 30

2020 40 0.22 N/A $3,830 30

2025 40 0.22 N/A $3,790 30

2030 45 0.25 N/A $3,200 30

Year

Average

Generating

Capacity (kW)

Electrical

Efficiency

Combined


Thermal Efficiency)

Installed Capital

Cost ($2005 per

kW of Capacity)

Service

Life

(Years)

2008 200 0.41 0.68 $6,121 20

2010 200 0.44 0.66 $5,989 20

2015 200 0.45 0.67 $5,203 20

2020 200 0.47 0.69 $4,187 20

2025 200 0.48 0.70 $3,647 20

2030 200 0.49 0.72 $3,108 20

Year

Average

Generating

Capacity (kW)

Electrical

Efficiency

Combined


Thermal Efficiency)

Installed Capital

Cost ($2005 per

kW of Capacity)

Service

Life

(Years)

2008 300 0.31 0.78 $1,980 20

2010 300 0.32 0.78 $1,878 20

2015 300 0.32 0.78 $1,714 20

2020 300 0.32 0.78 $1,551 20

2025 300 0.33 0.79 $1,343 20

2030 300 0.33 0.79 $1,134 20

Year

Average

Generating

Capacity (kW)

Electrical

Efficiency

Combined


Thermal Efficiency)

Installed Capital

Cost ($2005 per

kW of Capacity)

Service

Life

(Years)

2008 300 0.34 0.74 $2,391 20

2010 300 0.34 0.74 $2,268 20

2015 300 0.35 0.74 $2,071 20

2020 300 0.35 0.74 $1,873 20

2025 300 0.36 0.78 $1,622 20

2030 300 0.36 0.82 $1,370 20

Year

Average

Generating

Capacity (kW)

Electrical

Efficiency

Combined


Thermal Efficiency)

Installed Capital

Cost ($2005 per

kW of Capacity)

Service

Life

(Years)

2008 1000 0.23 0.68 $1,865 20

2010 1000 0.23 0.68 $1,775 20

2015 1000 0.24 0.68 $1,684 20

2020 1000 0.24 0.69 $1,593 20

2025 1000 0.25 0.69 $1,511 20

2030 1000 0.26 0.70 $1,429 20

Year

Average

Generating

Capacity (kW)

Electrical

Efficiency

Combined


Thermal Efficiency)

Installed Capital

Cost ($2005 per

kW of Capacity)

Service

Life

(Years)

2008 250 0.29 0.60 $2,540 20

2010 250 0.29 0.60 $2,328 20

2015 250 0.31 0.60 $1,981 20

2020 250 0.33 0.61 $1,634 20

2025 250 0.34 0.62 $1,343 20

2030 250 0.36 0.63 $1,052 20

Natural Gas Turbine

Natural Gas Micro-Turbine

Solar Photovoltaic

Fuel Cell

Natural Gas Engine

Oil-Fired Engine

14

The current NEMS set of DG systems includes all commercial CHP technology types

currently used in the commercial sector. As previously mentioned, photovoltaic systems

are used primarily in power generation only applications. Diesel fueled compression

ignited engines are the most prominent DG technology in the commercial sector. They

are used predominantly as backup emergency generators, but are also used as CHP prime

movers. While CHP technologies have been improving continuously over the last twenty

years, they have done so at a much less aggressive pace than projected in the primary

sources for technology characterization.

Some additional representative systems are recommended reflecting minor distinctions

between size classes within technology types and their respective performance and

capacity ratings. A recommended new set of prototype CHP systems is comprised of the

following technologies:

Phosphoric Acid Fuel Cell

Mid-Sized High Temperature Molten Carbonate Fuel Cell

Large High Temperature Molten Carbonate Fuel Cell

Natural Gas Fueled Rich Burn Reciprocating Engine with After-treatment for emissions

control

High Efficiency Natural Gas Lean Burn Reciprocating Engine

Diesel Fueled Compression-Ignited Reciprocating Engine with After-treatment for

emissions control

Industrial Gas Turbines with Low Emissions Combustion Systems

High Efficiency Recuperated Industrial-Sized Gas Turbine

Microturbine Systems

Fuel cell systems currently available and with installation and operating experience

include both phosphoric acid (PAFC) and molten carbonate fuel cells (MCFC). There are

significant differences between the low temperature PAFC and high temperature (MCFC)

in performance, current cost, and potential for cost reduction.

Reciprocating engines currently offer popular small and mid-sized rich-burn, mid-sized

lean-burn engines and a recent class of multi-megawatt systems that have been the

beneficiary of major government/private sector cost-shared technology development

efforts. The larger reciprocating engines now offer unprecedented performance for gas-

fired spark-ignited engines.

The cost and performance of commercially available gas turbine systems improves

notably between 1 MW and 3 MW and again from 3 MW and 5 MW. The smaller gas

turbines have a favorable emissions profile relative to competing reciprocating engine

options but lag in both capital cost and efficiency in that size range.

A new larger size class of microturbine driven by economies of scale and perceived

market needs is being developed and commercialized. It incorporates innovative

aeroderivative technology used in the small microturbines (e.g., materials and power

15

conditioning technology used in aircraft and transportation auxiliary power units8) with

proven industrial technology from conventional small gas turbines (e.g., hot section

materials and cooling methods).

8 Auxiliary Power Unit (APU) is a relatively small self-contained generator used in aircraft to start the main

engines and to provide electrical power and air conditioning while the aircraft is on the ground. In many

aircraft, the APU can also provide electrical power in the air. In most cases the APU is powered by a small

gas turbine engine. In addition several decades ago, there was a major development push for gas turbines as

a power source for vehicles. Gas turbines used as APU’s and incorporating advanced ceramic materials

were the basis for the automotive gas turbines. The current class of microturbines has many technical

features derived from these APU’s.

16

Recommended Prototype CHP Technologies for the Commercial Sector

The following is a recommended set of prototype CHP technologies that covers the range

of commercial applications found in the market today.

5 kW Fuel Cell

300 kW Fuel Cell

400 kW Fuel Cell

2800 kW Fuel Cell

100 kW Digester Gas

334 kW Natural Gas Reciprocating Engine


2000 kW Natural Gas Reciprocating Engines

3000 kW Gas Turbine

5000 kW Gas Turbine

65 kW Microturbine

200 kW Microturbine

Table 8 shows the list of recommended representative CHP technology prototype systems

with information about typically recovered thermal energy.

The average site size for each commercial CHP prime mover technology indicates that

most microturbine facilities and many reciprocating engine sites contain multiple units.

The median commercial CHP system size is over 1 MW. This is likely due to several

factors. The need for redundancy in order to enhance reliability is an emerging issue. The

relative low electric load factors and seasonal thermal loads of commercial sites would

likely require frequent part load operation for a single unit system sized to average

electric or peak thermal load. To optimize efficiency, a well controlled configuration

consisting of multiple units which are optimally dispatched is often utilized. Nearly all

generation systems operate most efficiently at full load. The current development of

larger microturbines is evidence that there is some perceived market pull for larger

systems.

With regard to opportunities for “small” as opposed to “large” commercial CHP systems,

the future is uncertain. Indeed, there are many more small commercial facilities than

larger ones. However, many commercial buildings have thermal load profiles that are

very low compared to their electric load profile. The optimally designed CHP systems

run continually. That typically means sizing the system to the base thermal load. For

those small facilities with poor thermal load profiles, it is not possible to economically

size a CHP system based on meeting the low base thermal load alone. Here is where

thermally activated space conditioning technologies such as absorption cooling may

improve commercial CHP opportunities. Converting building air conditioning to

absorption systems offers some advantages. The most expensive electric load, air

conditioning during peak hours, is eliminated. The remaining electric load profile has a

better load factor. Finally, the overall thermal load of the building increases; making it

17

economically feasible to size a larger CHP system that can contribute to not only summer

cooling but winter heating. This is the basis of the previously mentioned IES packages.

A later section of this report addresses the current interest in alternatively fueled

commercial CHP systems that currently comprise a very small percentage of installations.

However, due to high and volatile natural gas prices, CHP systems fueled with landfill

gas, anaerobic digester methane and other biomass are becoming of increasing interest.

Table 8: Commercial CHP Prototype Technologies

Technology Size (kW)

Typical Recovered

Thermal Energy Comments

Fuel Cell 5

Hot water for hot water or space

heating. High temperature PEM fuel cell.

Fuel Cell 300

Hot water and low perssure

steam for space conditioning

and water heating.

High temperature molten carbonate

fuel cell with internal reformation of

natural gas and anaerobic digester

gas.

Fuel Cell 400



and water heating.

Low temperature phosphoric acid

fuel cell.

Fuel Cell 2800



and water heating. Molten carbonate fuel cell.

Manure System 130 Hot Water

Microturbine 65

Domestic hot water, space

heating, pool heating, industrial

process hot water.

Microturbine 200

Domestic hot water, space

heating, pool heating, industrial

process hot water.

Gas Reciprocating

Engine 334

Space heating, absorbstion

chiller, hot water.

Gas Reciprocating

Engine 1000


chiller, hot water. New product at this capacity.

Gas Reciprocating

Engine 2000


chiller, hot water.

Gas Turbine 3000

High pressure steam for process

heating and drying and indirect

fired absorption chiller.

Gas Turbine 5000

High pressure steam for

process heating and drying and

indirect fired absorption chiller.

18

The following sections describe current (2010) cost and performance estimates for CHP

systems using the above technologies.

Fuel Cells

Fuel cells produce power electrochemically from hydrogen delivered to the negative pole

(cathode) of the cell and oxygen delivered to the positive pole (anode). The hydrogen can

come from a variety of sources, but the most economic is reforming of natural gas. There

are several different liquid and solid media that support these electrochemical reactions –

phosphoric acid (PAFC), molten carbonate (MCFC), solid oxide (SOFC), and proton

exchange membrane (PEM). Each of these media comprises a distinct fuel cell

technology with its own performance characteristics and development schedule. PAFC

technology is considered one of the more mature types of modern day fuel cells and the

first to be utilized commercially. MCFC technology is being developed for a range of

applications as low as the 250 kW range to several MW for electrical utility, industrial,

and military applications. SOFC are still in development and are undergoing further

testing. PEM Fuel Cells are in development and testing and have recently become

commercially available. Typical applications are for transportation and some stationary

uses. Direct electrochemical reactions are generally more efficient than using fuel to

drive a heat engine to produce electricity. Fuel cell efficiencies range from 37-42% for

the PAFC to upwards of 60% for MCFC and SOFC systems while PEMFSs are generally

in the range of 40-60% efficient. Fuel cells are inherently quiet and have extremely low

emissions levels as only a small part of the fuel is combusted. Like a battery, fuel cells

produce direct current (DC) that must be run through an inverter to get 60 Hz AC. The

efficiency of the power conditioning process is typically 92-96% and depends on the

system capacity and input voltage-current characteristics. These power electronics

components can be integrated with other power quality components as part of a power

quality control strategy for sensitive customers. Because of current high costs, fuel cells

are best suited to environmentally sensitive areas and customers with power quality

concerns.

Technology Specifications

Table 9 summarizes the cost and performance specifications for fuel cell systems in CHP

duty. The 5 kW system is modeled after the PEM fuel cell that has recently become

available in the state of California. Cost information was limited for this system so cost

data of the 5kW system is based off an electric only version of the fuel cell. Performance

data is still based on the CHP version of the 5kW fuel cell system. The 300 kW system is

modeled after the MCFC. The 400 kW system is based on the PAFC. The 2800 kW

system is based on the large MCFC. Installed costs shown in Table 9 reflect estimates

for a full scale demonstration of the large MCFC system.

19

Table 9: Fuel Cell Performance Summary9,10

,11

,12

Technology Fuel Cell PEMFC Fuel Cell MCFC Fuel Cell PAFC Fuel Cell MCFC

Electric Capacity (kW) 5 300 400 2800

Electric Heat Rate, HHV (Btu/kWh) 9383 8100 9500 8100

Electric Efficiency, HHV (%) 36.36% 42% 35% 42%

Fuel Input (MMBtu/hr) 0.047 2.34 3.79 21.72

Thermal Energy Output (MMBtu/hr) 0.0213 0.480 0.785 4.433

Total CHP Efficiency (%) 81.82% 61.88% 56.57% 61.67%

Power to Thermal Output Ratio 0.800 2.133 1.739 2.156

Net Heat Rate (Btu/kWh) 4052 5800 7022 5778

Variable O&M Costs ($/kWh) 0.02 0.02 0.02 0.02

Fixed O&M Costs (Restacking) ($/kW-year) 150 200 300 300

Total Installed Costs ($/kW) 15000 7485 6460 5600

Equipment ($/kW) 10000 5685 4540 3800

Installation/Labor/Materials ($/kW) 4800 1650 1760 1650Contingency ($/kW) 200 150 160 150

Reciprocating Engines

Reciprocating internal combustion engines have a long history of use in power

generation. Spark ignited natural gas engines are available in a wide range of sizes and

are used for peaking, primary power and CHP applications. Reciprocating engines offer

low first cost, easy start-up, proven reliability when properly maintained, and good load-

following characteristics.

Natural gas engines have dramatically improved their performance and emissions profile

in recent years. Rugged, accurate real time sensors and solid state electronic controls

allow greater control of the combustion process, increasing power and efficiency and

reducing emissions in state of the art gas engines.

A diesel fueled reciprocating engine is included in both power-only, its most prevalent

application, and in CHP configuration. According to the EEA CHP installation database,

only 10 oil-fired reciprocating engines were installed between 2006 and 2008 for CHP

applications. Further more based on calls with manufactures; diesel CHP installations are

rare to non-existent recently.

Digester Gas CHP

9 The performance data of the 5kW system is based on the ClearEdge Power ClearEdge5, cost data is based

on installations from Sandia report on Navy Fuel Cell Demonstration Project. The 300 kW system is based

on the Fuel Cell Energy DFC 300 model with a 300 kW rating. The 400 kW system is based on the UTC

Model 400 PureCell System. The 2800 kW system is based on the FuelCell Energy DFC3000. 10

Electrical efficiency takes into account parasitic and power conversion losses. Heat rates are provided on

a higher heating value (HHV) basis. For natural gas the average HHV is 1030 Btu/scf; average LHV is 930

Btu/scf. 11

Installed costs are intended to represent estimates for packaged system cost plus hot water

interconnections, grid interconnection, site labor and materials, construction management, engineering,

permitting, fees, contingency, and interest during construction. 12

Calculated system efficiency and performance measures are based on equations shown in Appendix B.

20

Energy production through digester gas utilizes the gas released from anaerobic digestion

to power an engine. Anaerobic digestion is the process by which biodegradable material

is consumed by microorganisms. While often used in waste management settings, the

biogas produced through anaerobic digestion is rich in both methane and carbon dioxide

and can easily be utilized as a renewable energy source. The multi-step process begins

by breaking down insoluble organic polymers in the input material (most commonly live

stock waste) using bacterial hydrolysis. The next step is to breakdown sugars and amino

acids into carbon dioxide, hydrogen, ammonia, and organic acids using acidogenic

bacteria. The organic acids are further broken down into acetic acids by acetogenic

bacteria. Finally, the acids are treated with methogen bacteria which convert it into

methane. Coupled with the carbon dioxide released during the process, the methane

produces a biogas. The biogas is then transported to and used to fire a generator

(reciprocating engine) while excess biogas is burned off by a flame. Heat from the

generator can, in turn, be used in a CHP system.

This type of system is most commonly used to meet the energy demands of large

livestock farms, but can equally be applied to wastewater treatment facilities in

municipalities. Because of high transportation costs and the need for large amounts of

organic matter, digester gas has been and is likely to remain largely decentralized. Still,

the technology represents a feasible means of producing renewable energy and heat while

reducing odor emissions, reserving nutrients in manure for fertilizer, and reducing the

risk of nutrient seepage due to leeching. The amount of energy and heat output is

dependent entirely on the amount of biogas which can be produced, which is dependent

on the amount of organic matter available for decomposition. While digester gas systems

are increasing in number large initial costs have limited much of the production to

government funded projects.


Reciprocating engine cost and performance summaries are shown in Table 10. Engine

systems can provide higher electrical efficiencies than combustion turbines in the small

sizes. The thermal heat evaluation calculations are based on the use of both the jacket

water and the exhaust heat to produce hot water.

The digester gas reciprocating engine example comes from studies of infield installations

at dairy farms in New York. Also note that for the data for installation and engineering

costs for the digester gas systems was considered inconsistent and was therefore assumed

to be double that of 334 kW reciprocating engine installation and engineering costs.

The distribution of commercial engine-based CHP systems is shown in Tables 11-1 and

11-2.

http://en.wikipedia.org/wiki/Hydrogen

http://en.wikipedia.org/wiki/Ammonia

http://en.wikipedia.org/wiki/Organic_acid

21

Table 10: Reciprocating Engine Performance Summary13

,14

,15

,16

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine

Electric Capacity (kW) 334 1,000 2,000 300 300

Electric Heat Rate, HHV (Btu/kWh) 11,494 9,097 9,394 9,618 10,124

Electric Efficency, HHV (%) 29.69% 37.51% 36.32% 35.48% 33.70%

Fuel Input (MMBtu/hr) 3.839 9.097 18.788 2.885 3.037

Thermal Energy Output (MMBtu/hr) 2.020 3.920 8.800 0.000 1.199

Total CHP Efficiency (%) 82.30% 80.60% 83.16% 35.48% 73.16%

Power to Thermal Output Ratio 0.564 0.871 0.776 - 0.854

Net Heat Rate (Btu/kWh) 3,934 4,197 3,894 9,618 5,130

Variable O&M Costs ($/kWh) 0.020 0.015 0.012 0.014 0.020

Fixed O&M Costs ($/kW-year) 75 40 25 6 9

Total Installed Costs ($/kW) 1800 1600 1400 850 1804

Equipment ($/kW) 930 910 885 517 1224

Installation Labor/Materials ($/kW) 420 390 340 201 356

Engineering/Construction Management,

Permitting, Fees & Contingency ($/kW) 450 300 175 132 224

Table 11-1: Installed Reciprocating Engine CHP Commercial Systems by Fuel

(2006-2008)

Natrual Gas Oil Biomass Total

Number of Sites 103 10 17 130

Capacity (MW) 53.3 11.4 30.0 95

Minimum Site Capacity (MW) 0.05 0.37 0.025 0

Maximum Site Capacity (MW) 6.00 4.00 4.80 15

Mean Site Capacity (MW) 0.52 1.14 1.77 3

Median Site Capacity (MW) 0.15 0.40 1.06 2

13

The 130 kW digester gas system is based on a Waukesha engine. The 334 kW system is based on the

Cummins QSK19G engine. The midsize (1000 kW) gas engine system was based on the Cummins QSK60

engine. The 2000 kW system is based on The Cummins QSV91 engine. The 300 kW diesel system is

based on the Caterpillar 3046 engine. The Diesel CHP unit is equipped with an SCR for NOx control and

diesel particulate filter (DPF) for PM control resulting in a 5% heat rate penalty. Heat is only recovered

from exhaust heat and jacket water heat. 14



Btu/scf for a 10.7% difference. The comparable difference for diesel fuel is 6.7%. 15


interconnections, grid interconnection, emissions control requirements and permitting, site labor and

materials, construction management, engineering, permitting, fees, contingency, and interest during

construction. 16


22

Table 11-2: Installed Reciprocating Engine CHP Commercial System by Fuel

(1900-2008)

Natural Gas Biomass Oil Waste Other Total

Number of Sites 981 80 110 4 30 1205

Capacity (MW) 724.994 167.136 176.162 0.195 5.237 1073.724

Minimum Site Capacity (MW) 0.005 0.025 0.005 0.030 0.010

Maximum Site Capacity (MW) 34.400 13.000 13.100 0.075 1.500

Mean Site Capacity (MW) 0.739 2.089 1.601 0.049 0.175

Median Site Capacity (MW) 0.090 1.525 0.785 0.045 0.065

Gas Turbines

Gas turbines are an established technology available in sizes ranging from several

hundred kilowatts to over one hundred megawatts. Gas turbines produce high quality heat

that can be used for industrial or district heating steam requirements. Alternatively, this

high temperature heat can be recuperated to improve the efficiency of power generation

or used to generate steam and drive a steam turbine in a combined-cycle plant.

Recuperators are heat exchangers that use the hot turbine exhaust temperature to preheat

compressed air prior to combustion. This reduces the fuel needed to heat the working gas

up to the desired turbine inlet temperature. It should be noted that while recuperation can

increase electrical efficiency, it does result in a lower turbine exhaust temperature. This is

an important consideration for CHP. Gas turbine emissions can be controlled to very low

levels using dry combustion techniques, water or steam injection, or exhaust treatment.

Maintenance costs per unit of power output are about a third to a half of reciprocating

engine generators. Low maintenance and high quality waste heat make combustion

turbines a preferred choice for many industrial or large commercial CHP applications

larger than 3 MW. Low capital cost and short construction lead-time make combustion

turbines a common choice for utility peaking capacity.


Table 12 summarizes the turbine performance parameters for the recommended

representative systems. The performance parameters for current gas turbines are taken

from manufacture specifications. The estimates are based on an unfired heat recovery

steam generator (HRSG) producing dry, saturated steam at 150 psig. Two 5 MW systems

– one recuperated and one simple cycle – are shown. The recuperated systems use

exhaust heat to preheat combustion air. This results in a significant increase in electrical

efficiency. However, in the case of CHP this reduces exhaust temperature and

consequently the amount of thermal energy that could be recovered. Recuperated systems

will have lower total CHP efficiency. The table shows electrical efficiency increases as

with gas turbine size. As one would expect, when electrical efficiency increases, the

absolute quantity of steam produced decreases. This changing ratio of power to heat may

affect the decisions that customers make in terms of CHP acceptance, sizing, and the

need to sell power.

23

Recent market shifts have resulted in lower capacity gas turbines to not sell in numbers

previously seen in the past. The 1 MW Saturn 20 has seen a lack of demand due to

multiple micro turbine installations and reciprocating engines. It is expected that the

lower capacity gas systems will be phased out in future CHP installations.

Table 12: Gas Turbine Performance Summary17

,18

,19

,20

Technology Gas Turbine

Gas Turbine

Recuperated Gas Turbine

Electric Capacity (kW) 3,510 4,600 5,670

Electric Heat Rate, HHV (Btu/kWh) 13,893 10,054 12,254

Electric Efficiency, HHV (%) 24.56% 33.94% 27.84%

Fuel Input (MMBtu/hr) 48.764 46.248 69.480

Thermal Energy Output (MMBtu/hr) 25.102 14.012 34.298

Total CHP Efficiency (%) 76.04% 64.23% 77.21%

Power to Thermal Output Ratio 0.477 1.120 0.564

Net Heat Rate (Btu/kWh) 4,953 6,246 4,693

Variable O&M Costs ($/kWh) 0.007 0.006 0.005

Fixed O&M Costs ($/kW-year) 22 14 12

Total Installed Costs ($/kW) 1,910 1,369 1,280

Equipment ($/kW) 1,130 832 826

Installation/Labor/Materials ($/kW) 507 341 271Engineering/Construction Management,

Permitting, Fees & Contingency ($/kW) 274 196 182

Microturbines

Microturbines are very small combustion turbines with outputs of 30 kW to 200 kW.

Designed to combine the reliability of auxiliary power systems used on board commercial

aircraft with the design and manufacturing economies of turbochargers, the units are

targeted at CHP and prime power applications in commercial buildings and light

industrial applications. In most configurations, a high speed turbine (100,000 rpm) drives

a high speed generator. This AC high frequency high speed out is rectified to direct

current (DC) power that is then electronically inverted to 60 Hz (or 50 Hz) AC for

general use. Microturbine systems are capable of producing power at around 25-33

percent efficiency by employing a recuperator that transfers exhaust heat back into the

incoming air stream. The systems are air cooled and some designs use air bearings,

17

The 3.5 MW system is based on the Solar Turbine Solar Centaur 40. The recuperated 5 MW system is

based on the Solar Turbine Solar Mercury 50; the simple cycle 5 MW system is based on the Solar Turbine

Solar Taurus 60. Gas turbine CHP systems are based on providing 150 psig steam with an unfired HRSG. 18



Btu/scf. 19

Installed costs are intended to represent estimates for packaged system cost plus hot water/process steam


permitting, fees, contingency, and interest during construction. 20


24

thereby eliminating both water and oil systems used by reciprocating engines. Low

emission combustion systems are being demonstrated that provide emissions

performance comparable to larger combustion turbines. The potential for reduced

maintenance and high reliability and durability remains to be demonstrated in a

commercial environment.


A summary of the technology specifications is shown in Table 13. Microturbine

developers and manufacturers quote an electrical efficiency at the high-frequency

generator terminals of 30-33% on a lower heating value (LHV) basis. However, the

energy content of fuels is typically measured on a higher heating value basis (HHV). The

difference between HHV and LHV is the energy content of the water vapor in the

combustion exhaust. Since, heat engines never capture this heat of vaporization, nor do

heat recovery steam generators, design engineers prefer to quote efficiencies in LHV. For

natural gas, the average heat content is 1030 Btu/cu ft on an HHV basis and 930 Btu/cu ft

on an LHV basis – approximately a 10% difference. Fuel is purchased on a HHV basis.

The power electronics component then introduces about 5% in additional losses in the

conversion step from high frequency to 60 Hz power. Additional parasitic loads of up to

10% of the capacity are often required for a fuel compressor necessary to compress

natural gas from typical delivery pressures of 2 psig or less to 75 psig. These adjustments

bring the electrical efficiency down into the 26-32% range.

25

Table 13: Microturbine Performance Summary21

,22

,23

,24

Technology Microturbine Microturbine

Electric Capacity (kW) 65 200

Electric Heat Rate, HHV (Btu/kWh) 12,943 10,670

Electric Efficiency, HHV (%) 26.36% 31.98%

Fuel Input HHV (MMBtu/hr) 0.842 2.280

Thermal Energy Output (MMBtu/hr) 0.375 0.744

Total CHP Efficiency (%) 70.98% 66.84%

Power to Thermal Output Ratio 0.591 0.917

Net Heat Rate (Btu/kWh) 5,735 6,750

Variable O&M Costs ($/kWh) 0.005 0.006

Fixed O&M Costs ($/kW-year) 62 25

Total Installed Costs ($/kW) 2,490 2,440

Equipment ($/kW) 1,257 1,359

Installation/Labor/Materials ($/kW) 798 741Engineering/Construction Management,

Permitting, Fees & Contingency ($/kW) 436 340

Commercial CHP Technology Costs

There are three main cost elements that are of primary concern in assessing CHP systems.

They include capital/installed costs, fuel costs (usually expressed as heat rate), and

nonfuel operating and maintenance costs.

Capital Installed Costs

The first costs of CHP projects represent a significant economic factor in the purchase

decision process. First costs include factory on board (FOB) costs of equipment,

installation costs, and integration soft costs (e.g., permitting, utility negotiations,

engineering, commissioning, etc.). There is typically a large variation in installation costs

due primarily to the non-equipment costs of installation that varies from site to site.

Notable observations and clear trends in components of installed costs across CHP

technology classes in the technologies surveyed indicate the following:

21

The microturbines are based on published specifications. The 65 kW size is based on the Capstone C65

system. The 200 kW system is based on the C200 kW Capstone system. 22



Btu/scf. 23



permitting, fees, contingency, and interest during construction. These representative systems are providing

hot water that can be used for space heating or single effect indirect fired absorption chillers. 24


26

In all technology classes the largest component of installed costs is equipment.

In all technology classes installation materials and labor was by far the largest

non-equipment cost component.

In reciprocating engines the proportion of total installed costs attributable to non-

equipment components decreases with size.

In fuel cells the percentage of installed costs attributable to equipment is

significantly higher than similarly sized traditional equipment (e.g., reciprocating

engines).

Installation materials and labor as a percentage of total installed costs is largest in

microturbine projects at approximately 30%.

Engineering (and feasibility study) costs as a percentage of total installed costs is

largest in reciprocating engine projects; as high as 25% in mid-sized lean burn

engines.

In Figures 3 thru 6 the capital cost breakdowns of the recommended commercial CHP

representative systems are shown. They were developed through assessment of recent

review of recent CHP and distributed generation assessments, and input from CHP

equipment providers and packagers.

27

5685

45403800

1650

1760

1650

150

160

150

0

1000

2000

3000

4000

5000

6000

7000

8000

300 kW MCFC 400 kW PAFC 2800 kW MCFC

$/k

W

Fuel Cell Installed Cost Breakdown

Contingency ($/kW)

Installation/Labor/Materials ($/kW)

Equipment ($/kW)

Figure 3: Fuel Cell Installed Cost Breakdown

930 910 885

420 390 340

450300

175

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

334 kW GasReciprocating

Engine


Engine


Engine

$/k

W

Reciprocating Engine Installed Cost Breakdown

Engineering/ConstructionManagement,

Permitting, Fees & Contingency($/kW)


Equipment ($/kW)

Figure 4: Reciprocating Engine Installed Costs Breakdown

28

1,130832 826

507

341 271

274

196182

0

500

1,000

1,500

2,000

2,500

3510 kW GasTurbine

4600 kW GasTurbine

5670 kW GasTurbine

$/k

W

Gas Turbine Installed Costs Breakdown

Engineering/ConstructionManagement,Permitting, Fees & Contingency($/kW)


Equipment ($/kW)

Figure 5: Gas Turbine Installed Costs Breakdown

1,257 1,359

798 741

436 340

0

500

1,000

1,500

2,000

2,500

3,000

65 kW Microturbine 200 kW Microturbine

$/k

W

Microturbine Installed Cost Breakdown



Equipment ($/kW)

Figure 6: Microturbine Installed Costs Breakdown

29

Operating and Maintenance Costs

The operating and maintenance costs presented in Table 14 include total non-fuel

operating costs and maintenance costs including routine inspections and procedures and

major overhauls. Actual costs and maintenance schedules can vary widely depending on

duty cycle, fuel, ambient conditions, site conditions, ancillary equipment (e.g. emissions

control equipment (SCR) and water treatment).

Included in the estimates are operating labor, maintenance labor, non-fuel operating

consumables, maintenance materials, spare parts and overhauls. For example, typical

reciprocating engine maintenance require some equipment inspections, repairs and

replacement on daily, monthly (check spark plug gap and timing; check controls; check

belts and hoses; conduct oil analysis), 4,000 hour (change oil and filter; change spark

plugs; change air filter; check coolant pump, alternator and starter; check carburetor and

turbocharger), 18,000 hour (clean oil cooler; replace coolant and thermostats; rebuild

heads and valve train; rebuild carburetor and turbocharger)and 36,000 hour (rebuild head

and valve train; replace crankshaft bearings/seals and piston rings/cylinder liners)

intervals. Gas turbine systems require less maintenance than reciprocating engines due to

rotating equipment and less oil contamination but a diligent maintenance program

typically includes daily visual inspection of parts, boroscope inspection of hot gas path

every 4,000 hours, hot gas section overhaul every 25,000 hours, and overhaul at 50,000

hours. Microturbine systems also have required maintenance at 8,000 hours (replace air

and fuel filters), 16,000 hrs (replace thermocouples, igniter and fuel injectors), and

40,000 hours (major overhaul - replace rotor). Microturbine fuel compressors require

service at 3,000 to 16,000 hours depending on inlet pressure. In the case of fuel cells,

electrochemical conversion and few moving parts should result in reduced operating and

maintenance requirements. Fuel cell maintenance requirements and costs are a function

of ancillary equipment, catalyst life, and stack life. A five year stack replacement is

assumed in the non-fuel operating and maintenance costs shown.

Many commercial installations prefer maintenance contracts with turnkey system

providers. Operating requirements that result in additional personnel or labor-hours on

the part of the end-user are undesirable. O&M costs presented in Table 14 are based on

8,000 operating hours expressed in terms of annual electricity generation.

30

Table 14: O&M Cost Estimates25


Variable Cost

($/kWhr)

Fixed Costs

($/kW-year)

Total O&M

($/kWhr)

Fuel Cell 300 0.02 200 0.043

Fuel Cell 400 0.02 300 0.054

Fuel Cell 2800 0.02 300 0.054

Reciprocating Engine 334 0.02 75 0.029



Diesel Recip Engine 300 0.014 6 0.015

Diesel Recip Engine 300 0.02 9 0.021

Gas Turbine 3510 0.007 22 0.010

Gas Turbine 4600 0.006 14 0.008

Gas Turbine 5670 0.005 12 0.006

Microturbine 65 0.005 62 0.012

Microturbine 200 0.006 25 0.009

25

Total non-fuel operating and maintenance costs based on 8,000 hours of operation per year

31

Commercial CHP Technology Advancements to 2035

The technical approach in estimating rate of technology advancement consisted of

literature review, market activity assessment, and telephone interviews were used to

define a set of representative prototype CHP systems that reflect the predominant

commercial and industrial configurations used given current market conditions.

Assessment of technology trends (breakthroughs and incremental development), review

of production and packaging methods, and interviews with technology developers and the

R&D community provided the basis of out-year projections of cost and performance of

the representative systems to the year 2035. With regard to technology advancement, two

scenarios are presented, a reference case and a rapid technology improvement case. The

conservative reference case assumes evolutionary technology improvement in the

conventional technologies of reciprocating engines and gas turbines, and slightly more

rapid improvement in both equipment and non-equipment installation costs of emerging

technologies such as microturbines and fuel cells. The rapid technology improvement

case assumes successful completion of key technology development programs and

technology transfer of results to commercial products on a schedule consistent with the

representative program goals. Key development programs include the DOE Solid State

Energy Conversion Alliance (SECA) program for high temperature fuel cells, DOE

Advanced Reciprocating Engine Systems (ARES) program for high efficiency gas

engines, DOE Advanced Microturbine program for the next generation microturbine

systems, DOE Thermally Activated Technologies (TAT) program for heat based cooling

and dehumidification, and DOE Integrated Energy System (IES) program for packaged

commercial combined cooling, heating and power system.

In both the reference and rapid technology improvement cases drivers for performance

improvements are based on enabling materials, controls, and in the case of reciprocating

engines, gas turbines and microturbines (i.e. combustion based CHP systems) continued

evolution of low emissions combustion systems. The reference case assumes a typically

conservative introduction of these components into commercial products until

commercially acceptable levels of durability can be proven. With regard to capital and

installed costs, the rapid technology set of assumptions assumes not only that the goals of

the referenced development programs are met, but that a robust CHP market exists to

enable rapid recovery of research and development costs.

Gas turbine projections include two 5 MW systems – one recuperated and one simple

cycle. The recuperated systems use exhaust heat to preheat combustion air. This results in

a significant increase in electrical efficiency. However, in the case of CHP this reduces

exhaust temperature and consequently the amount of thermal energy that could

recovered. Recuperated systems will have lower total CHP efficiency. This should not be

interpreted as degradation in performance. On the contrary, the recuperated system is a

quantum leap in performance improvement over the simple cycle. It will however be best

applied in CHP configurations in applications with higher power to thermal ratios.

32

Table 15 presents the reference case assumptions and Table 16 presents the rapid

technology improvement case. Capital costs shown are in 2010$.

33

Table 15: Technology Advancement Reference Case

2010

Technology Fuel Cell Fuel Cell Fuel Cell Fuel Cell



Electric Efficency, HHV (%) 36.36% 42.00% 35.00% 42.00%







Fixed O&M Costs ($/kW-year) 150 200 300 300


Equipment ($/kW) 10000 5685 4540 3800

Installation Labor/Materials ($/kW) 4800 1650 1760 1650


Permitting, Fees & Contingency ($/kW) 200 150 160 150

2015













Equipment ($/kW) 10000 3854 2846 2164




2030













Equipment ($/kW) 10000 2699 1777 1132




2035













Equipment ($/kW) 10000 2442 1539 903




34

Table 15 Continued: Technology Advancement Reference Case

2010

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine












Equipment ($/kW) 930 910 885 517 1224




2015

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine












Equipment ($/kW) 852 824 789 496 1203




2030

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine












Equipment ($/kW) 554 496 425 435 1142




2035

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine












Equipment ($/kW) 434 364 278 414 1121




35


2010

TechnologyGas Turbine

Gas Turbine

RecuperatedGas Turbine



Electric Efficency, HHV (%) 24.56% 33.94% 27.84%





Net Heat Rate (Btu/kWh) 4,953 6,246 4,693


Fixed O&M Costs ($/kW-year) 21.730 13.640 12.240

Total Installed Costs ($/kW) 1633 1483 1185

Equipment ($/kW) 1130 832 826

Installation Labor/Materials ($/kW) 507 341 271



2015


Gas Turbine



Electric Heat Rate, HHV (Btu/kWh) 13,893.000 10,054.000 12,254.000






Net Heat Rate (Btu/kWh) 4734 6045 4491




Equipment ($/kW) 1,129.780 832.410 826.400

Installation Labor/Materials ($/kW) 506.950 313.320 307.200


Permitting, Fees & Contingency ($/kW) 273.750 195.590 182.420

2030


Gas Turbine













Equipment ($/kW) 1,129.780 832.410 826.400




2035


Gas Turbine













Equipment ($/kW) 1,129.780 832.410 826.400




36


2010



Electric Heat Rate, HHV (Btu/kWh) 12943 10670

Electric Efficency, HHV (%) 26.36% 31.98%

Fuel Input (MMBtu/hr) 0.842 2.280




Net Heat Rate (Btu/kWh) 5735 6750


Fixed O&M Costs ($/kW-year) 62.134 24.709

Total Installed Costs ($/kW) 2490 2440

Equipment ($/kW) 1257 1359

Installation Labor/Materials ($/kW) 798 741



2015













Equipment ($/kW) 1,096 1,181




2030

















2035

















37

Table 16: Technology Advancement Rapid Technology Development Case

2010













Equipment ($/kW) 10000 4295 4077 3353




2015













Equipment ($/kW) 10000 2469 2303 1752




2030













Equipment ($/kW) 10000 1317 1184 741




2035













Equipment ($/kW) 10000 1061 936 517




38

Table 16 Continued: Technology Advancement Rapid Technology Development Case

2010

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine








Net Heat Rate (Btu/kWh) 3,934.120 3,846 3,792 9,137 4,923


Fixed O&M Costs ($/kW-year) 75.000 38 25 6 9

Total Installed Costs ($/kW) 1800 1,554 1,353 765 1445

Equipment ($/kW) 930 863 854 465 979




2015

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine


Electric Heat Rate, HHV (Btu/kWh) 11186 8,415 8,949 9,009 9,490






Net Heat Rate (Btu/kWh) 3634 3,568 3,532 9,009 4,795




Equipment ($/kW) 852 779 759 445 958




2030

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine












Equipment ($/kW) 554 459 395 383 897




2035

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Diesel

Reciprocating

Engine

Diesel

Reciprocating

Engine












Equipment ($/kW) 434 330 248 363 876




39


2010


Gas Turbine









Net Heat Rate (Btu/kWh) 6,652.483 4,885.802 5,762.961




Equipment ($/kW) 1098 773 808




2015


Gas Turbine













Equipment ($/kW) 1,079 756 789




2030


Gas Turbine













Equipment ($/kW) 991 704 734




2035


Gas Turbine













Equipment ($/kW) 951 686 716




40


2010

















2015

















2030

















2035

















41

Opportunity Fuels and Resource Recovery in Commercial Markets

As natural gas prices have become higher and volatile, a valuable attribute of some

commercial CHP technologies is their ability to be fueled by various fuel sources with

minimal modifications to the combustion and control systems. The use of fuels such as

waste gases from landfills, methane from anaerobic digesters, biomass, and waste

byproducts in upstream oil and gas markets, is also commonly referred to as the resource

recovery market. Units installed in these applications capture fuel that would otherwise

be flared or directly released into the environment. In most of these applications the fuel

is basically free or very cheap and the projects benefit from the additional economic

value streams. For example, most states have attractive mandatory purchase rates for

renewable and waste-to-energy plants. In fact, biomass and wood already combine for

about 40 MW of new commercial CHP capacity. Table 17 presents the distribution by

fuel of new commercial CHP.

Table 17: New Commercial CHP by Primary Fuel Source

Natrual Gas Oil Waste Fuels Biomass Total

Number of Sites 150 10 8 22 190

Capacity (MW) 242.5 11.4 53.9 39.6 347.4

Minimum Site Capacity (MW) 0.03 0.37 0.39 0.025

Maximum Site Capacity (MW) 62.90 4.00 23.00 6.20

Mean Site Capacity (MW) 1.62 1.14 6.74 1.80

Median Site Capacity (MW) 0.23 0.40 5.50 1.06

There are significant challenges to increased use of opportunity fuels for CHP.

1. Facilities need to be within a close proximity to the fuel source or have access to

economically delivered fuel. These sites typically have low thermal and electric demand.

2. Fuel conditioning and handling systems are needed in order to burn these fuels in

conventional CHP technologies. Contaminants to be removed include sulfur, H2S,

siloxanes, and moisture. Significant damage to generating equipment can be done if fuel

is not conditioned properly. In most cases modifications to equipment are needed in order

to use the fuel.

3. The source of fuel is often inconsistent in flow and heating value. Fuel handling

systems are needed to ensure acceptable heating value and flow rate of fuel.

4. Fuel processing can be labor-intensive.

As noted repeatedly throughout this report, natural gas has been the dominant fuel for

CHP. In recent years natural gas has become more expensive and volatile. Most

projections estimate that the price of natural gas will remain high. This has created in the

potential increased use of non-traditional opportunity fuels. There are market, research

and development, design, and application engineering issues to be addressed before this

market can fully be developed. CHP opportunities in industrial markets may be greater

than the commercial sector.

42

Industrial CHP Market

A review of the industrial CHP market was conducted by reviewing the best available

databases on CHP and electric generator installations. Existing U.S. industrial CHP

installations and recent CHP market activity were assessed using CHP installation

database maintained by ICF International26

(ICF) with funding from the U.S. Department

of Energy (DOE) and Oak Ridge National Laboratory (ORNL). This report also

incorporates information from EIA’s Form 860, press releases, industrial periodicals and

other sources. A summary of industrial CHP installations in the ICF database is shown in

Tables 18 and 19 and Figure 7.

Table 18-1: Industrial CHP Market by Size Class 2006-2008


Number of Sites 19 19 10 4 0 1 53

Capacity (MW) 8.8 44.4 89.0 129.4 0.0 224.0 495.6 Source: ICF Combined Heat and Power Installation Database

Table 18-2: Industrial CHP Market by Size Class 1900-2008


Number of Sites 203 256 259 202 147 168 1235

Capacity (MW) 80.7 660.7 2474.0 6637.9 10357.8 45638.2 65849.3 Source: ICF Combined Heat and Power Installation Database

Table 19-1: Industrial Market Facility Size Summary Data 2006-2008

Minimum Site Capacity 0.06

Maximum Site Capacity 224.00

Mean Site Capacity 9.35

Median Site Capacity 2.00 Source: ICF Combined Heat and Power Installation Database

Table 19-2: Industrial Market Facility Size Summary Data 1900-2008




Median Site Capacity 10.00 Source: ICF Combined Heat and Power Installation Database

26

ICF International acquired Energy and Environmental Analysis, Inc. (EEA) in January 2007.

43

Industrial Applications

0

2

4

6

8

10

12

14

16

18

20

<1 MW 1-5 MW 5-20 MW 20-50 MW 50-100 MW >100 MW

Nu

mb

er

of

Sit

es

0.0

50.0

100.0

150.0

200.0

250.0

Cap

ac

ity

(M

W)

Number of Sites

Capacity (MW)

Figure 7: Distribution of Industrial CHP Market by Facility Size

Tables 20 and 21 present the primary fuel and prime mover distribution of the installed

industrial CHP.

Table 20-1: Industrial CHP Installations by Fuel 2006-200827

Natrual Gas Coal Oil Biomass Wood Other Total

Number of Sites 36 1 2 5 8 1 53

Capacity (MW) 350.7 6.5 2.3 42.3 57.3 36.1 495.2





Table 20-2: Industrial CHP Installations by Fuel 1900-2008

Natrual Gas Coal Oil Biomass Wood Other Total

Number of Sites 661 163 69 33 135 174 1235

Capacity (MW) 47048.0 8942.8 842.8 333.1 1729.8 6952.9 65849.4





27

ICF Combined Heat and Power Installation Database defines the following terms: Biomass – Biomass,

LFG, Digester Gas, Bagasse. Coal – Coal. Natural gas – Natural Gas, Propane. Oil – Oil, Distillate Fuel

Oil, Jet Fuel, Kerosene, RFO. Waste – Waste, MSW, Black Furnace Gas, Petroleum Coke, Process Gas.

Wood – Wood, Wood Waste. Other – Other.

44

Table 21-1: Industrial CHP Installations by Technology 2006-2008

Boiler/Steam

Turbine

Combined

Cycle Gas Turbine

Reciprocating

Engine Microturbine Total

Number of Sites 21 1 11 14 6 53

Capacity (MW) 171.6 224.0 80.1 18.8 1.1 495.6




Median Site Capacity (MW) 4.00 224.00 2.92 0.80 0.10 Source: ICF Combined Heat and Power Installation Database

Table 21-2: Industrial CHP Installations by Technology 1900-2008

Boiler/Steam

Turbine

Combined

Cycle Gas Turbine

Reciprocating

Engine Microturbine Other Total

Number of Sites 597 182 197 225 17 17 1235

Capacity (MW) 21723.7 36660.5 6837.2 455.3 3.3 169.4 65849.4




Median Site Capacity (MW) 13.00 111.75 11.90 0.71 0.12 4.34


The preceding discussion focuses on ICF industrial CHP data. To complement the review

of the CHP installation database, a first-order review of the 2009 EIA Form 860 data on

generators was conducted to further assess the industrial CHP market. For NEMS and

EIA purposes, the IPP-based cogeneration is reported separately. These plants tend to be

much larger than standard industrial plants and are built to sell power to others. The

ICF data set identifies industrial cogeneration capacity as 65.8 GW, while the EIA data

shows 26.8 GW of non-IPP industrial cogeneration for 200728

. The larger IPP-based

cogeneration is given as 37.3. While there are differences between the sets of data, it is

not within the scope of this project to reconcile these differing data sets and definitions.

The data sets have been reviewed in an effort to identify representation technology

systems for characterizations.

The Form 860 database contains data on grid-connected generators larger than 1 MW,

although it includes many units below this threshold. Table 22 provides a summary of all

generators designated as “cogeneration”. The database includes 2,766 units categorized

as cogenerators, although 527 generators are identified as “out of service and not

expected to return to service” or “retired.” These 527 generators are included in this

report, although treatment of these generators in the future must be given consideration.

Table 22 lists the total number of cogenerating generators as well as the subset of 2,239

28

AER 2008. Standard industrial cogeneration capacity is shown on p. 266 and IPP cogeneration capacity

is shown on p. 265.

45

units that are operating, standby/backup or out of service but expected to be returned to

service.

Table 22: Summary of EIA Form 860 Generator Data

Operating

Standby/Backup -

available for

service

Out of Service -

will be returned to

service

Out of Service - not

expected to be

returned to service

Retired - not expected

to be returned to

service.

T ota l All

Genera tors

Total Number of Cogeneration Generators 2,046 187 6 89 438 2,766

Total Cogeneration Capacity (MW) 76,897 1,554 97 1,044 4,632 84,224

Average Cogeneration Capacity (MW) 37.6 8.3 16.2 11.7 10.6 30.4

Median Cogeneration Capacity (MW) 15.0 2.1 9.2 5.0 4.0 9.9

Operating

Standby/Backup -

available for

service

Out of Service -

will be returned to

service

T ota l All Active

Genera tors

Total Number of Cogeneration Generators 2,046 187 6 2,239

Total Cogeneration Capacity (MW) 76,897 1,554 97 78,549

Average Cogeneration Capacity (MW) 38 8 16 35.1

Median Cogeneration Capacity (MW) 15 2 9 12.5

Genera tor Sta tus

Genera tor Sta tus

Table 23 presents Form 860 data by prime mover technology for generators designated as

“cogeneration.” Steam turbines are the largest technology class yet not included in the

current technology assumptions. Key steam turbine characteristics are shown in Figures 8

and 9. Coal fueled generators is the largest group of steam turbine generators on both a

number of generators and capacity basis.

Table 23: Summary of EIA Form 860 Generator by Prime Mover Technology

Total Number of

Cogeneration

Generators

Total

Cogeneration

Capacity (MW)

Average

Cogeneration

Capacity (MW)

Median

Cogeneration

Capacity (MW)

CA (Combined Cycle Steam part) 245 13,104 53.5 24.5

CS (Combined Cycle Single Shaft) 13 562 43.2 10.4

CT (Combined Cycle Combustion Turbine) 373 30,192 80.9 65.5

GT (Gas Turbine) 467 10,380 22.2 7.2

IC (Internal Combustion Engine) 472 649 1.4 0.9

OT (Other) 4 18 4.6 5.9

ST (Steam Turbine) 1,192 29,319 24.6 10.0

T ota l 2,766 84,224 30.4 12.5

46

Figure 8: Distribution of Form 860 “Cogenerator” Steam Turbines by Fuel

29

29

Energy source definitions and nomenclature used is form EIA-860 instructions and can be found at

http://www.eia.doe.gov/cneaf/electricity/page/forms.html

47

Figure 9: Distribution of Form 860 “Cogenerator” Steam Turbine Capacity by Fuel

30

Industrial CHP facilities are concentrated in six industrial markets – chemicals, paper,

food, petroleum refining, and primary metals. Theses sectors account for over 80% of

the industrial CHP installations and approximately 90% of the industrial CHP capacity.

Figure 10 illustrates the distribution of CHP by industrial subsector.

Fuel use in industrial CHP is more diverse than the commercial sector. Natural gas is

the primary fuel used for CHP but coal, wood and process wastes are used extensively

by many industries. Power and thermal demands dictate the technology selections. Low

power to thermal ratio applications rely primarily on steam turbine systems. These

sectors include chemicals, paper, and primary metals. Those applications with high

power to thermal ratios use combustion turbine and combined cycle configurations.

As indicated in Figure 10, the large CHP systems (>50 MW) account for most

industrial CHP capacity (85%).

30

Energy source definitions and nomenclature used is form EIA-860 instructions and can be found at



48

Industrial CHP Distribution By Sector

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Installations Capacity (MW)

Other

Wood Products

Pulp and Paper

Food Processing

Electronics

Chemicals


Figure 10: Distribution of Industrial CHP Capacity by Sector

49

Industrial CHP Technologies

A review of the prominent CHP databases clearly indicates that the primary CHP

technologies that are used in industrial applications are gas turbines, reciprocating

engines, and steam turbines. Table 24 summarizes size ranges and applications. In this

analysis only fossil fueled CHP systems were considered. A section on opportunity fuels

is included later in the report.

Table 24: Industrial CHP Technologies

Type Size Market

Combined Heat and Power

Natural Gas Spark Ignited

Reciprocating Engine 1 - 6 MW

Commercial and industrial prime mover and


Natural Gas Combustion

Turbine 800 kW - 40 MW

Industrial combined heat and power;

T&D support

Combined Cycle 200 MW

Very large industrial CHP and electricity

export to wholesale market

Steam Turbine 500 kW - 40 MW

Custom designed to match various design

pressure and temperature requirements

Current EIA Industrial CHP Technology Characterization

The current NEMS set of CHP systems include most industrial CHP technology types

currently used in manufacturing sectors. There is an absence of steam turbine systems,

the most prominent industrial CHP technology. This is not intended to imply that is a

major omission. It is due to several factors:

There have been no new industrial boiler/steam turbine capacity additions over the

1990-2010 period.

New coal-based CHP has been stagnant due to emissions regulations.

NEMS does not evaluate the economics of steam turbines because their assessment is

very site-specific, including the type of fuel available and its cost. Such factors preclude

a generalized economic evaluation in the context of a sub-industry level model.

The steam turbine characterizations presented in this report represent steam turbines

retrofitted to existing boilers.

Large system cost estimates are very reasonable. A set of technology development

assumptions for the combined cycle system over time is not apparent. However, as noted

in the commercial sections that for smaller industrial systems (<10 MW) installed capital

costs in the year 2010 and the rate of improvement in installed capital cost tend to be

optimistic. While CHP technologies have been improving continuously over the last

twenty years and they have done so at a much less aggressive pace than projected in the

primary sources for technology characterization.

On the very large end of the size range of these technologies is the combined cycle

configuration, which incorporates a steam turbine in a bottoming cycle with a gas turbine.

50

Steam generated from hot gas turbine exhaust in a heat recovery steam generator (HRSG)

is used to drive a steam turbine to yield additional electricity and improve cycle

efficiency. Combined cycle systems can also be used in CHP applications. In these cases,

steam is extracted from the steam turbine to meet process or building thermal needs.

Industrial steam turbines used for CHP can be classified into two primary types -

condensing and extraction. The non-condensing turbine (also referred to as a

backpressure turbine) exhausts its entire flow of steam to the industrial process or facility

steam mains at conditions close to the process heat requirements. The term

“backpressure” refers to turbines that exhaust steam at atmospheric pressures and above.

The discharge pressure is established by the specific site requirements. 50, 150 and 250

psig are the most typical pressure levels for steam distribution systems. The lower

pressures are most often used in district heating systems, and the higher pressures 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.

The extraction turbine has opening(s) in its casing for extraction of a portion of the steam

at some intermediate pressure. The extracted steam may be use for process purposes in a

CHP facility, or for feed water heating as is the case in most utility power plants. The rest

of the steam is condensed. The facility’s specific needs 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.

Retrofit applications of steam turbines into existing boiler/steam systems can be

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

involves only 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.

Recommended Prototype CHP Technologies for the Industrial Sector

A recommended set of prototype CHP technologies that covers the range of industrial

applications found in the market today was developed. They include natural gas engines,

gas turbines, and steam turbines.



1000 kW Gas Turbine

3000 kW Gas Turbine

5000 kW Gas Turbine

10000 kW Gas Turbine

51



3000 kW Steam Turbine

15000 kW Steam Turbine

Table 25 shows the list of recommended representative CHP technology prototype

systems. The reciprocating engine and gas turbine-based systems are all natural gas

fueled. Steam turbine-based CHP systems are primarily used in industrial processes and

large institutional campuses where low-cost solid or waste fuels are readily available for

boiler use.

A section of this report addresses the current interest in alternatively fueled CHP systems

that currently comprise a very small percentage of installations. However, due to high

and volatile natural gas prices, CHP systems fueled with landfill gas, anaerobic digester

methane and other biomass are becoming of increasing interest.

Table 25: Cost and Performance of EIA NEMS Industrial CHP Technologies


Typical Recovered

Thermal Energy

Reciprocating

Engine 1000


chiller, hot water.

Reciprocating

Engine 2000


chiller, hot water.

Gas Turbine 3000

High pressure steam for process heating

and drying and indirect fired absorption

chiller.

Gas Turbine 5000




Gas Turbine

Recuperated 5000




Gas Turbine 10000 High pressure steam for process heating.



Steam Turbine 3000


and drying.

Steam Turbine 15000


and dyring.

52

The following sections describe current (2010) cost and performance estimates for CHP

systems using the above technologies.

Reciprocating Engines

Reciprocating internal combustion engines have a long history of use in power

generation. Diesel compression ignition engines are available in a wide range of sizes and

are used for emergency standby, remote and peaking power applications. Diesel engines

can be set up in a dual-fuel configuration that can burn primarily natural gas with a small

amount of diesel pilot fuel or be switched to 100 percent diesel. Spark ignited natural gas

engines are available in a wide range of sizes and are used for peaking, primary power

and CHP applications. Reciprocating engines offer low first cost, easy start-up, proven

reliability when properly maintained, and good load-following characteristics.

Natural gas engines have dramatically improved their performance and emissions profile

in recent years. Rugged, accurate real time sensors and solid state electronic controls

allow greater control of the combustion process, increasing power and efficiency and

reducing emissions in state of the art gas engines.

Reciprocating engines in the industrial sector also play a role in digester gas systems. As

mentioned in the commercial section under reciprocating engines, reciprocating engines

are utilized in many agricultural/industrial applications.


Reciprocating engine cost and performance summaries are shown in Table 26. The

systems shown make up a subset of the larger reciprocating engine systems described in

the preceding commercial sections of this report. Engine systems can provide higher

electrical efficiencies than combustion turbines in the small sizes. The thermal heat

evaluation calculations are based on the use of both the jacket water and the exhaust heat

to produce hot water.

53

Table 26: Reciprocating Engine Performance Summary31

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine

Electric Capacity (kW) 1,000 2,000


Electric Efficiency, HHV (%) 37.51% 36.32%












Gas Turbines

Gas turbines are an established technology available in sizes ranging from several

hundred kilowatts to over one hundred megawatts. Gas turbines produce high quality heat

that can be used for industrial or district heating steam requirements. Alternatively, this

high temperature heat can be recuperated to improve the efficiency of power generation

or used to generate steam and drive a steam turbine in a combined-cycle plant. Gas

turbine emissions can be controlled to very low levels using dry combustion techniques,

water or steam injection, or exhaust treatment. Maintenance costs per unit of power

output are about a third to a half of reciprocating engine generators. Low maintenance

and high quality waste heat make combustion turbines a preferred choice for many

industrial or large commercial CHP applications larger than 3 MW. Low capital cost and

short construction lead-time make combustion turbines a common choice for utility

peaking capacity.


Table 27 summarizes the turbine performance parameters for the recommended

representative systems. The performance parameters for current gas turbines are taken

from manufacture specifications. Thermal energy was calculated from published turbine

data on steam available from selected systems. The estimates are based on an unfired heat

recovery steam generator (HRSG) producing dry, saturated steam at 150 psig. The table

shows electrical efficiency increases with gas turbine size. As one would expect, when

electrical efficiency increases, the absolute quantity of steam produced decreases. This

31

The 1000 kW gas engine system was based on the Cummins QSK60 engine. The 3000 kW system is

based on the Cummins QSK91 engine.

54

changing ratio of power to heat may affect the decisions that customers make in terms of

CHP acceptance, sizing, and the need to sell power.

One major difference between this characterization and the current EIA assumptions is

the inclusion of two 5 MW systems– one recuperated and one simple cycle. The

recuperated systems use exhaust heat to preheat combustion air. This results in a

significant increase in electrical efficiency. However, in the case of CHP this reduces

exhaust temperature and consequently the amount of thermal energy that could

recovered. Recuperated systems will have lower total CHP efficiency. This should not be

interpreted as degradation in performance. On the contrary, the recuperated system is a

quantum leap in performance improvement over the simple cycle. It will however be best

applied in CHP configurations in applications with higher power to thermal ratios.

Figures 11 and 12 illustrate the notable differences in performance trends represented by

the recuperated gas turbine system.

The characterizations of technology improvement shown later in the report (Tables 31

and 32) include both recuperated and simple cycle 5 MW gas turbine systems.

Table 27: Gas Turbine Performance Summary32

Technology Gas Turbine

Gas Turbine

Recuperated Gas Turbine Gas Turbine Gas Turbine Gas Turbine

Electric Capacity (kW) 3,510 4,600 5,670 14,990 25,000 40,000

Electric Heat Rate, HHV (Btu/kWh) 13,893 10,054 12,254 10,945 9,945 9,220

Electric Efficiency, HHV (%) 24.56% 33.94% 27.84% 31.17% 34.30% 37.00%

Fuel Input (MMBtu/hr) 48.764 46.248 69.480 164.066 248.625 368.800

Thermal Energy Output (MMBtu/hr) 25.102 14.012 34.298 74.933 90.770 128.791

Total CHP Efficiency (%) 76.04% 64.23% 77.21% 76.85% 70.70% 72.10%

Power to Thermal Output Ratio 0.477 1.120 0.564 0.683 0.940 1.060

Net Heat Rate (Btu/kWh) 4,953 6,246 4,693 4,696 5,427 5,180

Variable O&M Costs ($/kWh) 0.007 0.006 0.005 0.006 0.006 0.005

Fixed O&M Costs (Restacking) ($/kW-year) 21.730 13.640 12.240 9.470 10.170 6.943

Total Installed Costs ($/kW) 1,910 1,369 1,280 1,091 1,097 972

Equipment ($/kW) 1,130 832 826 751 701 640

Installation/Labor/Materials ($/kW) 507 341 271 181 252 204Engineering/Construction Management,

Permitting, Fees & Contingency ($/kW) 274 196 182 159 144 128

32

The 3.5 MW system is based on the Solar Turbine Solar Centaur 40. The recuperated 4.6 MW system is

based on the Solar Turbine Solar Mercury 50; the simple cycle 5.6 MW system is based on the Solar

Turbine Solar Taurus 60. Gas turbine CHP systems are based on providing 150 psig steam with an unfired

HRSG. The 15 MW system is based on the Solar Turbine Titan 130. The 25 MW system is bases on the 28

MW GE LM2500. The 40 MW system is based on the 43 MW GE LM6000.

55

Gas Turbine Electric Heat Rate by Size

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

System Capacity (kW)

Ele

ctr

ic H

ea

t R

ate

, H

HV

(B

tu/k

Wh

)

Figure 11: Gas Turbine Electric Heat Rate Performance Trends

Gas Turbine Total CHP Efficiency by Size

0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

70.00%

80.00%

90.00%

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

System Capacity (kW)

To

tal

CH

P E

ffic

ien

cy

(%

)

Figure 12: Gas Turbine Total CHP Efficiency Performance Trends

Combined Cycles and Steam Turbines

Steam turbines are one of the most versatile and oldest prime mover technologies still in

general production. Steam turbines have been generating power for over 100 years, when

they first 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

56

conventional steam turbine power plants. The capacity of commercially available steam

turbines ranges from 50 kW to several hundred MW. The range of steam turbines

described in this report is below 20 MW, representing the steam turbine systems most

likely to be employed for on-site power generation by industrial and institutional users.

Unlike gas turbine and reciprocating engine CHP systems in which heat is a byproduct of

power generation, steam turbines 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. Energy is transferred from the boiler, in which

fuel is burned to provide heat for steam generation, to the turbine in the form of high

pressure steam that in turn powers the turbine and generator33

. This separation of energy

conversion functions enables steam turbines to operate with an enormous variety of fuels,

varying from 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. 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 complex for reliability and cost reasons. CHP can

be adapted to both utility and industrial steam turbine designs.


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 optimized for steam production. Hence, while steam turbine

CHP system cycle electrical efficiency34

may seem very low, it is because the primary

objective of a boiler/steam turbine CHP system is to produce large amounts of steam.

The effective electrical efficiency35

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 efficiencies36

are generally very high and approach the boiler efficiency

level. Steam boiler efficiencies range from 70 to 85% HHV depending on boiler type and

age, fuel, duty cycle, application, and steam conditions.

In combined cycle systems, a gas turbine is coupled with a steam turbine. The hot

exhaust air of a simple cycle CT is guided into a heat recovery steam generator (HRSG)

33

Steam can also be generated with the waste heat of a gas turbine as in the case of combined cycle power

plants 34

Net power output / total fuel input into the system. 35

(Steam turbine electric power output)/(Total fuel into boiler – (steam to process/boiler efficiency)). 36

Net power and steam generated divided by total fuel input.

57

to produce steam. This steam is utilized to drive a steam turbine generator. Combined

cycle increases the efficiency from 28-42%, enabling overall power generation

efficiencies as high as 60%. This is the standard configuration for new central power

station designs and is commonly used in large commercial CHP installations.

In CHP installations, gas turbine exhaust gas is directed into an HRSG. As the name

implies, HRSGs convert thermal energy into steam, which is then used to generate

additional power in a steam turbine generator. Most HRSGs have an option for duct

burners that allow for supplemental firing of the exhaust gas to increase the steam or hot

water output. The high air flow-through of gas turbines provide a plentiful supply of

oxygen for supplemental firing to provide substantial amounts of additional steam or hot

water. There are several different types of steam turbines, but the two most often used in

CHP applications are backpressure and condensing designs. Backpressure systems

function by using high pressure steam to drive a turbine, leaving lower pressure steam or

hot water that can be used for other processes. Condensing systems also use high pressure

steam to drive a turbine, but then use a condenser or series of condensers to recover

nearly all of the heat energy from the steam, leaving only low or zero pressure discharge.

Because of the choice of steam turbines alone, the capital cost of CHP facilities varies

widely, with typical installed costs ranging from $700 to $1200 per KW.

Combined cycle plants are the most common central station plant being installed

worldwide due to their high efficiency, low cost, and rapid lead time for installation.

Utility style, heavy-duty frame turbines are ideal for combined cycle plants. Although the

cost of adding a steam turbine increases the specific ($/kW) capital cost of a plant, the

operating cost is lower than any other technology on the market if the plant is operated

for 8,000 hours or more per year. Table 28 Summarizes performance and cost parameters

for the recommended 100 MW combined cycle system.

58

Table 28: Combined Cycle Performance Summary37

Technology Combined Cycle

Electric Capacity (kW) 100,000

Electric Heat Rate, HHV (Btu/kWh) 6,736

Electric Efficiency, HHV (%) 50.66%

Fuel Input (MMBtu/hr) 673.554

Thermal Energy Output (MMBtu/hr) 132.861

Total CHP Efficiency (%) 70.38%

Power to Thermal Output Ratio 2.569

Net Heat Rate (Btu/kWh) 5,075

Variable O&M Costs ($/kWh) 0.003

Fixed O&M Costs ($/kW-year) 11

Total Installed Costs ($/kW) 723

Equipment ($/kW) 488

Installation/Labor/Materials ($/kW) 147


Permitting, Fees & Contingency ($/kW) 88

Table 29 presents examples of steam turbine costs and expected performance. It should

be noted that this table differs notably from the other performance tables shown in this

report. Equipment and installed cost estimates in Table 29 are based on retrofit

applications of steam turbines into existing boiler/steam systems and not new generator

packages which is the case with the performance assumptions presented for fuel cells,

engines, microturbines and gas turbines. Only the capital and installation costs of the

steam turbine, its generator, controls and electrical interconnection is considered, with the

balance of plant already in place.

There are several notable numbers in Table 29. Although CHP electrical efficiency is

low, the effective electrical efficiency of steam turbine systems is very high because

almost all the energy difference between the high pressure boiler/HRSG output and the

lower pressure turbine output is converted to electricity. This means that total steam

turbine CHP system efficiency approaches the boiler efficiency.

37

Characteristics for “typical” commercially available generator system. The 100 MW Combined Cycle

system is based a configuration consisting of one 67 MW Frame 6EA and one 40 MW three pressure steam

turbine with re-heat.

59

Table 29: Steam Turbine Example Performance38

Technology

Steam Turbine (retrofit

back pressure example)

Steam Turbine (retrofit

back pressure example)


Boiler Efficiency, HHV (%) 80% 80%

Electric Heat Rate, HHV (Btu/kWh) 49449.28 36688.17

Turbine Isentropic Efficiency (%) 70 80



Effective Electric Efficiency, HHV (%) 75.100 77.800Electric Efficiency (Electricity to Fuel Input),

HHV (%) 6.900 9.300

Total CHP Efficiency (%) 79.500 79.700







38

System performance based off TurboSteam Inc. assessments. Capital and total installed costs assume an

existing boiler. Costs do not include boiler, fuel handling

system and emissions control.

60

Industrial CHP Technology Costs

There three main cost elements that are of primary concern in assessing CHP systems.

They include capital/installed costs, fuel costs (usually expressed as heat rate), and

nonfuel operating and maintenance costs.

Capital Installed Costs

The first costs of CHP projects represent a significant economic factor in the purchase

decision process. First costs include factory on board (FOB) costs of equipment,

installation costs, and integration soft costs (e.g., permitting, utility negotiations,

engineering, commissioning, etc.). There is typically a large variation in installation costs

due primarily to the non-equipment costs of installation that varies from site to site.

Notable observations and clear trends in components of installed costs across CHP

technology classes in the survey sample indicate the following:

The site specific conditions and process needs are the most prominent drivers of

heat recovery costs. Costs of heat recovery equipment as a percentage of

equipment costs vary widely among sites survey and published cost estimates.

The greatest variation was in the engineering and miscellaneous costs. This is

likely due to differences in interpretation of the categories and differences in cost

allocation practices.

While there is a wide scatter in published data on combined cycle installed costs a

correlation between cost and size exists. Plant costs are dependent on type of gas

turbine technology, steam turbine and process steam considerations, and the

extent to which existing facility infrastructure can be utilized.

There is a pessimistic outlook on new boiler based CHP systems as long standing

trends indicate a move away from steam toward electricity. In addition, recent

fuel price increases have made the risks of increased dependency on natural gas

unattractive.

Steam Turbine prices vary depending on size, steam conditions, speed, required

customization and competition. Price quotes typically include an assembled steam

turbine and electrical generator.

Industry cost estimates for a new complete steam turbine CHP systems typically

breakdown installed costs as follows – 25% boiler, 25% fuel handling, 15% steam

turbine, and engineering/construction 15%. Telephone interviews with

engineering firms indicated a reluctance to provide generalities with regard to

retrofit systems. Process integration and site specific issues tend to drive up

engineering and installation labor/materials costs.

Figures 13 thru 14 illustrate the capital cost breakdowns of the recommended industrial

CHP representative systems. They were developed through assessment of recent CHP

installations, review of recent CHP and distributed generation assessments, and input

from CHP equipment providers and packagers.

61

Gas Turbine Installed Costs Breakdown

751 701640

181 252

204

159 144

128

0

200

400

600

800

1,000

1,200

14,990 kW Gas

Turbine

25,000 kW Gas

Turbine

40,000 kW Gas

Turbine

$/k

W

Engineering/Construction

Management,

Permitting, Fees & Contingency

($/kW)


Equipment ($/kW)

Figure 13: Gas Turbine Installed Cost Breakdown

Steam Turbine Installed Costs Breakdown

278252

65

59

132

119

0

50

100

150

200

250

300

350

400

450

500

3,000 kW Steam Turbine 15,000 kW Steam Turbine



Equipment ($/kW)

Figure 14: Steam Turbine Installed Costs Breakdown

62

Operating and Maintenance Costs

The operating and maintenance costs presented in Table 30 include routine inspections,

procedures and major overhauls. O&M costs presented in Table 30 are based on 8,000

operating hours expressed in terms of annual electricity generation.

Included in the estimates are operating labor, maintenance labor, non-fuel operating

consumables, maintenance materials, spare parts and overhauls. Typical reciprocating

engine maintenance was described in the preceding commercial CHP sections. That

includes equipment inspections, repairs and replacement on daily, monthly (check spark

plug gap and timing; check controls; check belts and hoses; conduct oil analysis), 4,000

hour (change oil and filter; change spark plugs; change air filter; check coolant pump,

alternator and starter; check carburetor and turbocharger), 18,000 hour (clean oil cooler;

replace coolant and thermostats; rebuild heads and valve train; rebuild carburetor and

turbocharger)and 36,000 hour (rebuild heads and valve train; replace crankshaft

bearings/seals and piston rings/cylinder liners) intervals.

Gas turbine systems (i.e. simple cycle and combined cycle CHP) are the predominant

industrial CHP technologies characterized in this report. They require less maintenance

than reciprocating engines due to rotating equipment and less oil contamination but a

diligent maintenance program typically includes daily visual inspection of parts,

boroscope inspection of hot gas path every 4,000 hours, hot gas section overhaul every

25,000 hours, and overhaul at 50,000 hours.

Steam turbines, the bottoming cycle of combined cycle systems, require continual

monitoring of all fluids (primarily steam and bearing lubrication) and the inspection of all

auxiliary equipment (e.g., pumps, coolers, and safety devices). Solid fuel boilers require

additional maintenance related to fuel processing/handling, ash removal and emissions

control. Additional maintenance for solid fuel boilers also include inspection and removal

of any solids that may deposit on turbine parts and degrade performance.

Table 30: O&M Cost Estimates


Variable Cost

($/kWhr)

Fixed Costs

($/kW-year)

Total O&M

($/kWhr)



Gas Turbine 3000 0.007 21.73 0.009

Gas Turbine 5000 0.005 12.24 0.006

Gas Turbine 14990 0.006 7.47 0.007

Gas Turbine 25000 0.006 10.17 0.007

Gas Turbine 40000 0.005 6.943 0.006

Combined Cycle 100000 0.0028 10.7 0.004

63

Industrial CHP Technology Advancements to 2035

As with the commercial technologies, two scenarios are presented, a reference case and a

rapid technology improvement case. The cost and performance of CHP technologies have

been continually improving. The conservative reference case assumes evolutionary

technology improvement. The rapid technology improvement case assumes successful

completion of key technology development programs and technology transfer of results

to commercial.

The technical approach in estimating rate of technology advancement consisted of

literature review, market activity assessment, and telephone interviews were used as the

basis to define a set of representative prototype CHP systems that reflect the predominant

commercial and industrial configurations used given current market conditions.

Assessment of technology trends (breakthroughs and incremental development), review

of production and packaging methods, and interviews with technology developers and the

R&D community provided the basis of out-year projections of cost and performance of

the representative systems to the year 2030.

Gas turbine-based systems, both simple and combined cycle configurations, are the

predominant industrial CHP technology. Gas turbine performance improvement is

enabled by several key technologies:

High temperature materials including ceramics, special metal alloys, and thermal

barrier coatings that enable higher turbine inlet temperatures.

Computer processing and computational methods that allow for improved turbine

blade and vane design. This results in higher compressor and turbine efficiency

and higher pressure ratios.

Manufacturing processes that result in components incorporating both advanced

materials and more complex internal blade cooling approaches while still

maintaining acceptable levels of quality control and durability.

Continued advancement of digital control systems that ensure a wide window of

optimal performance.

Emissions control development, both combustion based and exhaust treatment,

that allows for lower emissions of key pollutants even while turbine inlet

temperatures increase.

Advancements in heat exchanger performance that improve heat transfer and limit

losses in recuperators and heat recovery steam generators.

The eventual transfer of technology from larger land based gas turbines and

aircraft engines.

Cost reduction occurs as the result of more effective packaging and integration of

subsystems and control systems. A movement toward standardization is being led

by CHP turnkey project developers and equipment suppliers. This includes less

site assembly and increased factory-assembled systems. Non-equipment costs are

reduced through expected streamlined siting, permitting, and interconnection

processes. The rapid technology improvement case assumes an accelerated

implementation of policies to enable rapid and simple CHP project development.

64

The technology advancement reference case implies a more conservative approach by gas

turbine manufacturers on the introduction of advanced components and subsystems. The

development timetable includes historical degree of durability testing before integrating

advancements in commercial products. In addition to accelerated commercial

introduction of technology advancements, the rapid technology development case also

assumes the development of a more robust CHP market that allows for more rapid

recovery of research and development investment.

Table 31 presents the reference case assumptions and Table 32 presents the rapid

technology improvement case. Capital costs shown are in constant 2010 $.

65

Table 31: Technology Advancement Reference Case

2010

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















2015

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















2030

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















2035

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















66


2010


Gas Turbine

RecuperatedGas Turbine Gas Turbine Gas Turbine Gas Turbine



Electric Efficency, HHV (%) 24.56% 33.94% 27.84% 31.17% 34.30% 37.00%





Net Heat Rate (Btu/kWh) 4,953 6,246 4,693 4,696 5,427 5,180


Fixed O&M Costs ($/kW-year) 22 14 12 9 10 7

Total Installed Costs ($/kW) 1,910 1,369 1,280 1,091 1,097 972

Equipment ($/kW) 1,130 832 826 751 701 640

Installation Labor/Materials ($/kW) 507 341 271 181 252 204



2015


Gas Turbine









Net Heat Rate (Btu/kWh) 4734 6045 4491 4526 5216 5036


Fixed O&M Costs ($/kW-year) 21.730 13.640 12.240 9.470 10.170 6.943

Total Installed Costs ($/kW) 1879 1340 1251 1066 1036 962

Equipment ($/kW) 1,111 815 808 734 662 634




2030


Gas Turbine













Equipment ($/kW) 1,023 763 752 664 585 607




2035


Gas Turbine













Equipment ($/kW) 983 745 734 664 610 607




67

Table 32: Technology Advancement Rapid Technology Development Case

2010

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















2015

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















2030

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















2035

Technology

Gas

Reciprocating

Engine

Gas

Reciprocating

Engine
















68


2010


Gas Turbine









Net Heat Rate (Btu/kWh) 6,652.483 4,885.802 5,762.961 9,493.697 5,394.552 5,107.042




Equipment ($/kW) 1098 773 808 751 701 640




2015


Gas Turbine













Equipment ($/kW) 1,079 756 789 734 662 634




2030


Gas Turbine













Equipment ($/kW) 991 704 734 664 585 607




2035


Gas Turbine













Equipment ($/kW) 951 686 716 664 610 607




69

References

California Energy Commission, Assessment of California CHP Market and Policy

Options for Increased Penetration, CEC-500-2005-060-D, April 2005.

Gas Research Institute, GRI-88/0053, Cost Reduction in Manufacture and Installation of

Gas-Fired Prepackaged Cogeneration Systems, 1988.

Bautista, P.J., “The U.S. Stationary Fuel Cell Market: What Does the Future Hold?”

POWER-GEN International, December 2004.

Oland, C.B., Guide to Combined Heat and Power Systems for Boiler Owners and

Operators, Oak Ridge National Laboratory Report ORNL/TM-2004-144, 2004

Cordova, C.J., Bautista, P.J., Darrow, K.G., Market Potential for Thermally Activated

Building Combined Heat and Power in Five National Account Sectors, Oak Ridge

National Laboratory, May 2003.

Cordova, C.J., Bautista, P.J., Darrow, K.G., National Account Energy Sector Profiles,

Oak Ridge National Laboratory,” April 2003.

Bautista, P.J., Fay, J.M., “The Drive to DG Project Implementation Efficiency – Benefits

and Best Practices,” Electric Power, March 2003.

Cogeneration Ready Reckoner – Cogeneration evaluation and viability software

CHP Database maintained by ICF International, www.eea-inc.com/chpdata/index.html

Annual Energy Review 2008, DOE Energy Information Administration, DOE/EIA-

0384(2008), June 2009.

Installation, Operation, and Maintenance Costs for Distributed Generation

Technologies, EPRI, Palo Alto, CA, 2002.

Onsite Energy, Bautista, P.J., Freedman, S.I., “Small Gas Turbines for Distributed

Generation Markets – Technology, Products, and Business Issues,” EPRI/GTI, GTI-

00/0219, December 2000.

Parsons Power Group, Market Based Advanced Coal-Powered Systems, 2000

National Renewable Energy Laboratory, Gas-Fired Distributed Energy Resource

Technology Characterizations, October 2003.

Boston Consulting Group, Perspectives No. 125: The Experience Curve Reviewed, 1973.


70

Margolis, R.M., Photovoltaic Technology Experience Curves and Markets, NCPV and

Solar Program Review Meeting, March 2003.

Reicher, Curtis, McNamara, Energy User News, Risk and Cost in Small-Scale DG

Projects, July 2003.

Cooling, Heating, and Power of Buildings Website, www.bchp.org.

Mid-Atlantic CHP Application Center Website, www.chpcenterma.org

UTC Power Website, www.utcpower.com

Fuel Cell Energy Website, www.fuelcellenergy.com

Cummins Website, www.cummins.com

Caterpillar Website, www.catepillar.com

Solar Turbines Website, www.solarturbines.com

Capstone Website, www.capstoneturbine.com

Ingersoll-Rand Website, www.ingersollrand.com

GE Website, http://www.gepower.com/home/index.htm

California Energy Commission, MTG Field Test Program Interim Result, CEC-P500-02-

053F, November 2002

California Energy Commission, Distributed Generation Case Studies for Permit

Streamlining and Impact Upon Transmission and Distribution Services, CEC-700-02-

001F, January 2002

Binder, M.J., Taylor, W.R., Holcomb, F.H., Experience with the DOD Fleet of 30 Fuel

Cell Generators, Proceedings from International Gas Research, November 2001.

Energy Solutions Center Website, www.energysolutionscenter.org

San Diego Regional Energy Office Website, www.sdreo.org.

Lemar, P., Opportunity Fuels for CHP: An Alternative to High Gas Prices, presented at

5th Annual CHP Workshop, September, 2004

Akhil, Black, Navy Fuel Cell Demonstration, Sandia National Labs, August 2008

Cornell Manure Management Website, http://www.manuremanagement.cornell.edu/

http://www.manuremanagement.cornell.edu/

71

Appendix A: Summary of CHP Installation Data39

CHP Database Summary of Installations from 2006 to 2008 (updated as of 01/09

according to the website):


281 Sites

869 MW

Primary Fuel Used = Natural Gas

Reciprocating Engines account for the most sites (176)

Average System Size = 3.091 MW

Median System Size = .4 MW

Average Industrial System Size = 9.351 MW

Average Commercial System Size = 1.828 MW

Largest States by Capacity are California (654 MW), Alabama (50 MW) New

York (40 MW), and Connecticut (26 MW)

Table A-1: Summary of New CHP Sites and Capacity by Application Class (2006-2008)


Commercial 190 347.4

Industrial 53 495.6

Other 38 25.6

Total 281 868.6

39

The source for all the installation


72

Table A-2: Summary of New CHP by Application

Commercial Summary


Number of Sites 133 40 13 3 1 0 190

Capacity (MW) 32.2 92.1 88.2 72.0 62.9 0.0 347.4




Median Site Capacity 0.32

Commercial Prime Mover Summary Boiler/Steam

Turbine

Combustion

Turbine Fuel Cell

Reciprocating

Engine Microtubine

Other or

Unknown Total

Number of Sites 8 12 11 130 25 4 190

Capacity (MW) 77.7 140.4 5.4 94.7 7.1 22.0 347.4




Median Site Capacity (MW) 4.25 5.30 0.40 0.26 0.24 5.50

Industrial Summary <1 MW 1-5 MW 5-20 MW 20-50 MW 50-100 MW >100 MW Total

Number of Sites 19 19 10 4 0 1 53

Capacity (MW) 8.8 44.4 89.0 129.4 0.0 224.0 495.6




Median Site Capacity 2.00

Industrial Prime Mover Summary

Boiler/Steam

Turbine

Combined

Cycle Gas Turbine

Reciprocating

Engine Microturbine Total

Number of Sites 21 1 11 14 6 53

Capacity (MW) 171.6 224.0 80.1 18.8 1.1 495.6




Median Site Capacity (MW) 4.00 224.00 2.92 0.80 0.10

73

Table A-3: Summary of New CHP by Generation Prime Mover Technology

Prime Mover Summary Boiler/Steam

Turbine

Combined Cycle Combustion

TurbineFuel Cell Reciprocating

Engine

Microtubine Other or

Unknown

Total

Number of Sites 30 1 25 12 176 33 4 281

Capacity (MW) 252.0 224.0 228.8 6.0 127.3 8.4 22.0 868.6





Commercial Applications

0

20

40

60

80

100

120

140

<1 MW 1-5 MW 5-20 MW 20-50 MW 50-100 MW >100 MW

Nu

mb

er

of

Sit

es

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

Cap

ac

ity

(M

W)

Number of Sites

Capacity (MW)

Figure A-1: Distribution of New Commercial CHP by Size Range

74

Figure A-2: Distribution of New Industrial CHP by Size Range

Industrial Applications

0

2

4

6

8

10

12

14

16

18

20

<1 MW 1-5 MW 5-20 MW 20-50 MW 50-100 MW >100 MW

Nu

mb

er

of

Sit

es

0.0

50.0

100.0

150.0

200.0

250.0

Cap

ac

ity

(M

W)

Number of Sites

Capacity (MW)

75

Appendix B: Efficiency Calculations

Total Efficiency = (net electric generated + net heat produced for thermal needs)/total

system fuel input

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

Net Heat Rate = (total fuel energy input – fuel that would normally be used to generate

the equivalent thermal output as the CHP system thermal output)40

/ CHP electric output

Effective Electrical Efficiency = Electric power output / (total fuel input – Steam to

process/boiler efficiency)

FERC Efficiency = (Electric power output + 0.5 Thermal output) / Fuel input

Boiler Efficiency = Heat captured by boiler or HRSG and transferred to water / fuel heat

input

Steam Turbine Isentropic Efficiency = Actual work output of machine / ideal output

40

In this analysis, displaced boilers are assumed to be 80% efficient.

Documents

Commercial and Industrial CHP Technology Cost and ...capabilities.itron.com/efg/2011/EIA2010ComIndCHPTechCostandPerformance0831.pdfCHP Technology Cost and Performance Data Analysis