Demonstration of Fuel Cells to Recover Energy from Anaerobic Digester Gas


EPA-600/R-95-034
March 1995

DEMONSTRATION OF FUEL CELLS TO RECOVER
ENERGY FROM ANAEROBIC DIGESTER GAS

Phase I. A Conceptual Design, Preliminary Cost, and Evaluation Study

by

J. C. Trocciola and H. C. Healy
International Fuel Cells Corporation
P. O. Box 739
South Windsor, CT 06074

EPA Contract 68-D2-0186

EPA Project Officer: Susan A. Thorneloe
Air and Energy Engineering Research Laboratory
Research Triangle Park, NC 27711

Prepared for

U. S. Environmental Protection Agency
Office of Research and Development
Washington, DC 20460

-------
EPA REVIEW NOTICE

This report has been reviewed by the U.S. Environmental Protection Agency, and
approved for publication. Approval does not signify that the contents necessarily
reflect the views and policy of the Agency, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.

This document Is available to the public through the National Technical informa-
tion Service, Springfield, Virginia 22161.

ABSTRACT

International Fuel Cells Corporation (IFC) is conducting a United States EPA sponsored program to demon-
strate the recovery of energy from waste methane produced by anaerobic digestion of waste water treatment
sludge. The U.S. EPA is interested in the fuel cell for this application because it is potentially one of the
cleanest energy technologies available. This program is focused on utilizing a commercial Phosphoric Acid
Fuel Cell (PAFCypower plant because of its inherently high fuel efficiency, low emissions characteristics,
and higher state of development. The environmental impact of wide spread use of this concept would be a
significant reduction in global wanning and acid rain air emissions.

This project report discusses the results of Phase I, a Conceptual Design, Preliminary Cost, and Evaluation
Study. The conceptual design of the fuel cell energy system is described and its economic and environmental
feasibility is projected. Technology evaluations aimed at improving the phosphoric acid power plant opera-
tion on Anaerobic Digester Gas (ADG) are described, and the two optional programs for completing the over-
all project are described. In Option I, the technical issues of ADG contaminant removal, and improved, fuel
cell power plant performance on low-Btu fuel are addressed. In Option II, a 1 -year field performance evalua-
tion of the energy recovery concept is planned. The demonstration will document the environmental and
economic feasibility of the fuel cell energy recovery concept.

-------
TABLE OF CONTENTS

Section	Page

ABSTRACT 						 ii

1.0 INTRODUCTION					 1

2.0 GAS PRETREATMENT REQUIREMENTS 	 2

2.1	ADG Characteristics 									 2

2.2	ADG Fuel Pretreatment Requirements			 3

2.2.1	ADG Contaminants and Fuel Cell Limits 	 3

2.2.2	Pretreatment Requirements 					 3

2.3	ADG Pretreatment System Design Concept	 5

2.3.1	Selected Pretreatment System Design Concept		 5

2.3.2	Preliminary Process Design 				 7

2.3.2.1	Preliminary Process Design - Commercial Application 		 7

2.3.2.2	Preliminary Process Design - Demonstration Unit	 8

3.0 FUEL CELL POWER PLANT REQUIREMENTS 					 10

3.1	Fuel Cell Power Plant Description 	 10

3.2	Modifications For PC25 Power Plant Demonstration on ADG 	 12

3.2.1	Modifications Required to Achieve 200-kW Output	 12

3.2.2	Required Refurbishments to the Prototype 			 13

3.3	Technology Improvements 						 13

3.3.1	Fuel Processor			 14

3.3.2	Ejector/Fuel/Control							 14

3.3.3	Water Recovery/Treatment 					 14

3.3.4	Alternative Power Plant Control	 15

3.3.5	Alternative High Quality Heat Recovery 	 16

4.0 COMMERCIAL SYSTEM CONCEPTUAL DESIGN	 17

4.1	Background - Application and Market			 17

4.2	Economic Assessment						 18

4.3	Environmental Assessment 					 27

4.4	Commercial System Conceptual Design	 29

4.5	Critical Issues 					 29

4.5.1	Marketing Issues			 29

4.5.2	Technical Issues 						 30

-------
Section Page
5.0 FUEL CELL ADG-TO-ENERGY SYSTEM DEMONSTRATION	 31

5.1	Site Selection and Description 			 31

5.1.1	Description of Back River Facilities 	 31

5.1.2	Site ADG Availability and Characteristics 	 31

5.1.3	Electrical/Thermal Fluid Integration Characteristics	 32

5.1.4	Codes/Standards and Permitting Requirements	 32

5.1.5	Proposed Location of Demonstration Equipment	 32

5.2	Option 1 and Option 2 Demonstrations 					 33

5.2.1	Option 1 Demonstration 			 33

5.2.2	Option 2 Demonstration	:		 33

APPENDICES

Appendix A Analysis of Back River Anaerobic Digester Gas			 A-i

Appendix B Technology Improvements					 B-l

Appendix C City of Baltimore MD Information	 C-l

- iv —

-------
LIST OF FIGURES

Figure	Page

2-1 Recommended ADG Pretreatment Concept 	 5

2-2 Valving Arrangement for Dual Absorbent Bed Operation			 7

2-3 Process Schematic of Commercial ADG Pretreatment System			 8

2-4	ADG Demonstration Pretreatment System Process Flow Schematic ....	..... 9

3-1	Functional Schematic Fuel Cell ADG Power Unit 	 11

4-1	Integration Between WWT and Fuel Cell 			., 17

4-2 Bergen County Utilities Authority, Total Heat Requirements 		 19

4-3 Impact of Fuel Cell Heat Recovery on Break-Even Fuel Cost 	 20

4-4 Supplemental Thermal Requirements - Conventional Case 					21

4-5 Supplemental Thermal Requirements - Fuel Cell Cases			 21

4-6 Economic Results for Scenario A 				 24

4-7 Economic Results for Scenario B 	 25

4-8 Economic Results for Scenario C 			 26

4-9 Comparison of Fuel Cell to Internal Combustion Engine Energy

Conversion System					 26

4-10 MW Site Plan Concept				 •¦	 29

4-11	Overall System Schematic and Performance Estimate for Fuel Cell
ADG-to-Energy Conversion System 							 30

5-1	Fuel Cell Site Options 			 34

5-2 IFC's Proposed Demonstrator Concept	;		 35

5-3 System Schematic and Performance Estimate for Fuel Cell

ADG-to-Energy Demonstration 		 36

B-l Fixed Area Ejector Fuel/Steam Control Configuration	 B-2

B-2 Automotive Oxygen Sensor Response	 B-8

-------
LIST OF TABLES

Table	Page

2-1 Typical ADG Compositions (Dry Basis)		 2

2-2 ADG Fuel Contaminant Limits for Fuel Cell Applications 			 3

2-3 Pretreatment Requirements - Commercial ADG Fuel Ceil Application 	 4

2-4	Pretreatment Requirements - Back River Site

Demonstrator Application 								 4

2-5	Basis for Preliminary Design of Demonstration

Pretreatment System 				 9

3-1	Performance Comparison for Nominal 200-kW Output						 11

3-2 Estimated Fuel Cell Air Emissions 			 12

3-3	General Requirements for a Fuel Cell Power Plant

for ADG Application :							 13

3-4	Technology Areas for Assessment in ADG Program			 15

4-1	Typical Waste Methane and Coal Emissions (Basis for Analysis) 	 27

4-2	Breakdown of Total Emissions due to WWT Plant (Conventional vs. Fuel Cell) ... 28

4-3	National Emissions Reductions 				 28

5-1	Overall Demonstration Phase I Objectives 					 31

5-2 Required Site Characteristics	 32

5-3 Improvements to PC25 ADG Powered Unit 	 36

B-l Power Plant Requirements With Dilute Fuel Gas 					 B-3

B-2 Fuel Cell Power Plant Oxygen Sensor Requirements 	 B-7

B-3 Oxygen Sensor Summary				 B-7

B-4 Automotive Sensors and Applicability 	 B-9

B-5 Comparison of Internal Versus External Modem			 B-13

B-6 Advantages and Disadvantages of General Modem Functions			 B-l4

B-7 High Grade Heat Improvement - System Changes 			 B-l5

-------
'N,

1.0 INTRODUCTION

This report summarizes the work performed under the Base Program of the United States Environmental
Protection Agency Contract EPA68-D2-0186, "Demonstration of Fuel Cells to Recover Energy from Anaer-
obic Digester Gas." The objectives of this program, which was initiated in November 1993 are to establish
the conceptual design of a fuel cell energy recovery system for application at anaerobic digester Waste Water
Treatment Plants (WWT), and to establish the design basis for the site specific demonstration hardware to
validate the conceptual design. The Base Program study focused on addressing the problems associated with
fuel cell operation on Anaerobic Digester Gas (ADG),

The basis for the commercial fuel cell energy recovery concept is to adapt commercially available equipment
for operation on ADG. Definition of the equipment and the site for the demonstration was based on validating
the technical issues derived from the commercial conceptual design.

The existing IFC commercial 200-kW Phosphoric Acid Fuel Cell (PAFC) power plant (designated the PC25)
was used as the basis for available fuel cell equipment. This power plant is designed to operate on pipeline
natural gas. Therefore, the derivation of the commercial conceptual design and definition of the demonstra-
tion addressed the implications of operating the power plant on ADG. The two major efforts addressed are:
(1) establishing requirements for pre treatment of ADG, and (2) defining modifications to the existing fuel cell
power plant to permit demonstration on ADG.

In the first major effort, a number of ADG WWTs were surveyed to determine the characteristics of the prod-
uct gas, specifically in terms of contaminants that could compromise long-term operation of the fuel cell pow-
er plant. This provided the information needed for selecting a gas pre treatment approach and a preliminary
process design of the pre treatment system. This effort is described in Section 2.0.

The second major effort addressed modifications to the commercial 200-kW PC25 that would permit opera-
tion of the power plant on ADG at power levels approaching rated conditions for natural gas. ADG represents
a dilute fuel gas relative to natural gas, and results in higher volume flow when fed through the power plant,
than natural gas at comparable power levels. The modifications necessary to accommodate this condition are
described in Section 3.0.

The commercial conceptual design for an ADG fuel cell-to-energy system is described in Section 4.0. The
commercial concept is based on an assessment of market for ADG WWT applications. The potential eco-
nomic and environmental benefits resulting from the fuel cell application to waste treatment were identified.

IFC intends to validate the critical elements of the commercial fuel cell energy system concept by removing
the contaminant from the ADG in a gas pretreatment unit and operating a modified PC25 power plant on the
clean dilute fuel. An existing municipal site, the Back River Waste Water Treatment Plant in Baltimore, MD,
has been selected for this demonstration. Both electricity and thermal energy produced by the fuel cell plant
will be used by the facility to demonstrate high efficiency and maximum emissions savings. Plans for the
demonstration are staged over two program phases, both of which are options beyond the Base Program. In
the Option 1 Program, IFC will verify the performance of the gas pretreatment unit at the Back River Site. In
the Option 2 Program, IFC will install a PC25 power plant with the gas pretreatment unit to verify operation of
the ADG-to-energy fuel cell power plant system. The definition of the demonstration is described in Section

IFC intends to begin the Option 1 Program in March of 1994 with the approval of EPA. The Option 2 Program
will be scheduled to follow.

-1-

-------
2.0 GAS PRETREATMENT REQUIREMENTS

2.1 ADG Characteristics

This section documents the gas compositions and typical contaminant levels for'ADG at the Back River facil-
ity (proposed demonstration site) and several other large waste water treatment sites located throughout the
United States. This data is used as a basis for establishing the ADG pre treatment requirements for a commer-
cial ADG-to-energy fuel cell application as well as for the demonstration unit.

Table 2-1 presents typical digester gas compositions for various waste water treatment facilities. Included in
the table is data from the Back River facility which was obtained by Gascoyne Laboratories. The specifics of
the analysis is included in Appendix A. Data for the other sites were obtained by American Hydrotherm, Inc.,
through direct contact with personnel at these facilities. The specifics of the analyses are also included in
Appendix A.

Table 2-1. Typical ADG Compositions (Dry Basis)

Baltimore

Nassau County

NYC DEP

Philadelphia
Water Dept.

Orange County
(Calif.)

Back River

Bay Park.

Cedar Creek.

(26th Ward)

Heating Value
(HHV, kg.cal/1

N/M

5.96

N/M

5.66

N/M

Methane, percent vol

60.9

66.0

57.2

62.0

65.6

Carbon Dioxide, percent vol

37.8

32,6

38.9

36.1

34.0

33.4

Nitrogen, percent vol

1.0

0.92

3.82

0.97

N/M

1.0

Oxygen, percent vo!

0.3 (est.)

0.45

N/M

0.20

N/M

0.03

Hydrogen Sulfide, ppmv

6.0

170**

100

<500**

Haiides, ppmv

<1.0

N/M

, <4

NMOCs, percent vol

<0.0005

0.01**

N/M

<0.001

N/M - not measured

* Not detected (Level of Detection Not Specified)
** Value set for equipment specifications, not from analyses

The data shows that the major constituents in ADG are methane (57-66 volume%), carbon dioxide (33-39
volume %), nitrogen (1-4 volume %), and a small amount of oxygen (<0.5 volume %). The minor constitu-
ents include sulfur bearing compounds (principally H2S), and trace amounts of halogen compounds (chlo-
rides) and non-methane organic compounds (NMOC's). In addition, it is important to note that ADG is typi-
cally saturated with water vapor at a temperature of approx. 95°F (not shown in table).

As the data show, the sulfur (H2S) concentration in the waste gas from the Back River site is low in compari-
son to the other sites listed. This is due to the use of iron salt in the Back River digesters to control water
chemistry. Because of the recognized variability in H2S concentrations that can exist from site to site, the
design of the gas cleanup equipment, as well as the economic assessment, is based on higher levels (100
ppmv) that ensure use in a wide range of applications. A possibility to be discussed with EPA is to verify
operation of the demonstration unit at these higher H2S levels by spiking the inlet gas to the unit and monitor-
ing the exit composition.

Data on the variability of the ADG composition at a given site due to seasonal storm, and operating influences
was not available. Conversations with plant personnel at the Back River site indicated that based on their
experience, little variability was expected. At any rate, the flexibility incorporated in the design relative to
H2S levels is expected to easily accommodate this variability. It is recommended that the seasonal variability
be quantified.

The higher heating value of ADG ranges from about 5.34-6.23 kg.cal/1 (dry basis). This volumetric heat con-
tent is significantly lower than that of natural gas (8.72-9.34 kg.cal/1), due to the large amount of diluents
(chiefly CO2) in the gas.

-2-

-------
2.2 ADG Fuel Pretreatment Requirements

This section establishes the ADG fuel pretreatment requirements for the demonstration unit and commercial
ADG to energy fuel cell applications. Specifically, the contaminants which are typically present in ADG are
identified, along with their respective maximum concentration limits for a fuel cell application. The ADG
fuel pretreatment requirements are then defined by the net difference between the actual concentration and the
maximum allowable concentration for each contaminant,

2.2.1 ADG Contaminants and Fuel Cell Limits

Table 2-2 lists the ADG contaminants which are a potential concern for fuel cell applications, along with the
maximum allowable fuel contaminant limits for a commercial fuel cell power plant operating on ADG.

Based on the survey of available ADG analyses data, the contaminants of chief concern are sulfur and halogen
compounds. The data provided in Table 2-1 and Table 2-2 indicates sulfur levels (H2S) range from a low of 6
ppmv at the Back River facility up to 200 ppmv at the NYC DEP 26th Ward Facility. Halogen compounds
(halides) range from nil to 4 ppmv. The implication of the data is the need to focus the gas pretreatment system
design on removal of hydrogen sulfide. Halide removal can be accomplished in the fuel cell power plant fuel
processor with a halogen guard bed on a site-specific basis. The beds have been utilized previously in IFC's
fuel cell power plants.

Other potential contaminants which need to be eliminated are solids, liquid water and condensate, and accom-
panying bacteria which may be present in the digester gas.

Table 2-2. ADG Fuel Contaminant Limits for Fuel Cell Applications

ADG Contaminant

Fuel Cell Power Plant
Requirements^

Issue/Concern

Sulfur (H2S)

<4 ppmV

Poison to fuel processor reforming catalyst

Halogens (F, CI, Br)

<4 ppmV ®

Corrosion of fuel processor components

NMOC's

<0.5% Olefins

Poison to fuel processor shift catalysts

o2

<4%

<0.5% ^5>

Over temperature of fuel processor beds due to
excessive oxidation

NH3

<1 ppmV

Fuel cell stack performance

n2

<15%

NH3 formation in reformer - Fuel cell stack per-
formance

h20(1)

Remove moisture &
condensate

Damage to fuel control valves. Transport of bacte-
rial phosphates

Bacteria/solids

Remove all solids/bacteria

Fouling of fuel processor piping/beds

(1)	Operating on ADG Gas (nominal composition: 60% CH4, 40% CO2)

(2)	with zinc oxide sulfur guard bed

(3)	with optional halogen guard bed in fuel processor

(4)	with peak shave option

(5)	without peak shave option

2.2.2 Pretreatment Requirements

Table 2-3 defines the pretreatment requirements for an ADG commercial fuel cell application, and Table 2-4
defines the pretreatment requirements for the Back River demonstration unit. The chief difference between a
typical commercial ADG application and the Back River demonstration unit is the level of sulfur content in
the fuel; the Back River ADG has a low level of sulfur, due to the use of iron salts in the digester to control
water chemistry (II2S levels).

The issue of ADG bacteria content and the need to filter the ADG to control downstream buildup of deposits
from the bacteria was addressed with personnel at the Back River facility, A determination was made that as

5

-3-

-------
long as the following steps are taken, bacteria filtering would not be required for the demonstration unit ap-
plication, These steps are as follows:

1. Use ADG output from the new egg-shaped digesters which according to Back River personnel have
an improved and fully effective system to remove solids and moisture carry-over from the ADG. The
new digester system incorporates a downstream improved water wash system for eliminating solids
carryover from the digesters, which is the source of deposit buildup in downstream plumbing.

2, Assure that the ADG is kept flowing (non-static) and that its temperature is kept above the condensa-
tion point. Continuous flow is standard operating procedure. Depending on location of the fuel cell
power plant, line heaters can be used to keep the lines at desired temperature.

"Eable 2-3. Pretreatment Requirements - Commercial ADG Fuel Cell Application

ADG Contaminant

Contaminant Concentration
Range

Pretreatment Requirements

Sulfur (HjS)

up to 200 ppmV

Reduce sulfur content to <4 ppmV

Halogens (F, CI, Br)

up to 4 ppmV

No pretreatment requirement, providing optional
halogen guard bed is used

NMOC's
(olefins)

ppb -» low ppm range

None

<0.5%
>0.5%

None

Requires peak shave option

NH3 .

None

Up to 4.0%

None

H20 (1)

Saturated® 35-43°C

Remove condensate/droplets from gas stream.
Prevent further condensation in downstream pip-
ing

Bacteria/solids

May be present in ADG gas

Make provisions for removing solids and moisture
carryover, prevent condensation and keep ADG
flowing.

Table 2-4. Pretreatment Requirements - Back River Site Demonstrator Application

ADG Contaminant

Contaminant Concentration

Pretreatment Requirements

Sulfur (HDS)

6 ppmV

Reduce S content to <4 ppmV

Halogens (F, CI, Br)

< 1 ppmV

No pretreatment requirement, providing optional
halogen guard bed is used

NMOC's ,
(olefins)

<5 ppmV

None

0.3%'

None

NH3

None

1.0%

None

H20 (1)

Saturated at 35 °C

Remove condensate/droplets from gas stream.
Prevent further condensation in downstream pip-
ing

Phosphates

None*

Make provisions for removing solids and possible
moisture carry-over from digester. Prevent con-
densation and keep ADG flowing

Bacteria/solids

None

-4-

-------
2.3 ADG Pre treatment System Design Concept

This section describes the selected ADG concept. This concept is applicable for a 200-kW demonstration unit
at the Back River facility as well as for a commercial ADG to energy fuel cell application. Also, the prelimi-
nary process design configurations and size estimates for the pretreatment system desulfurizer beds are pro-
vided.

2.3.1 Selected Pretreatment System Design Concept

The recommended ADG pretreatment concept is depicted in Figure 2-1, and is applicable for a 200-kW dem-
onstrator unit at the Back River site as well as for a commercial ADG to energy fuel cell application. The chief
difference between specific applications would be the physical size of the desulfurizer bed, (discussed below)
which would be dictated by the H2S content in the ADG fuel.

The proposed system utilizes a non-regenerable sulfur absorption bed for hydrogen sulfide removal. This
desulfurizer bed operates at ambient temperature and pressure and reduces hydrogen sulfide to elemental sul-
fur and water via the Claus Reaction (H2S + 1/2 O2 -* H2O + S(S)). Elemental sulfur produced in the reaction
is adsorbed by the carbon bed. An air injection system is required to control tb levels within the desulfurizer
bed to about 0.3-0.5 volume percent. For ADG applications where there is low level of naturally occurring
O2 (such as the Back River demonstrator application), a simple fixed air addition system is proposed.

Air Addition

From _

Waste. c—

Water

Treatment

Plant

Digesters

Fixed
H Control

Valve

Coalescing
Filter

cbcr

Blower

Impregnated
Activated
Carbon
Bed

lb Fuel Ceil
Power Plant

Condensate

Pretreatment Bed(s)
(H2S Removal)

Figure 2-1. Recommended ADG Pretreatment Concept

A blower would be utilized to convey the ADG thru the pretreatment module and deliver it to the fuel cell at
the required pressure. In addition, a coalescing filter would be located upstream of the blower to preclude the
possibility of solids, liquid carryover and bacteria from entering the pretreatment module and fuel cell.

The absorbent material selected for this concept is a salt impregnated activated carbon absorbent which is
commercially available. This material had previously been tested at a landfill site during a 3-month period
beginning in July 1991. The data indicated high adsorbtion capacities and high efficiencies for removing
sulfur compounds while operating at ambient temperature and pressure, with essentially 100 percent H2S
removal. Short residence times corresponding to gas velocities of 15-18 mpm (meters per minute) (space
velocities of 5300 hH) through the bed were demonstrated.

-5-

-------
IFC had experience with this material from a separate EPA program for demonstration of fuel cells from land-
fill gas (EPA Contract 68-D1-0008). In that program conducted in 1994, tests were performed both by the
vendor and IFC at simulated landfill gas conditions, which provided the basis for incorporation into the gas
pretreatment unit for the landfill application.

However, since the mechanism forl^S removal is oxidation of the H2S to elemental sulfur, some level of Oj
is required on the feed gas, ADG, as previously indicated, typically contains less than 0.5% O2. Therefore,
IFC initiated testing of the potassium impregnated carbon at conditions simulating ADG compositions. The
material manufacturer was contracted to perform the tests which determined the minimum oxygen concentra-
tions and corresponding sulfur loadings associated with use of activated carbon material. The first series of
tests indicated that an oxygen concentration of only 0.1 percent is sufficient to initiate H2S removal via the
above described absorption process.

Breakthrough testing was performed at 0.3 percent oxygen using a CO2 and methane stream containing 200
ppmv H2S. A 10 ppmv H2S breakthrough was achieved after 1,322.6 hours of testing. At a gas flow rate of
1450 cc/min., the breakthrough capacity of the impregnated carbon was determined to be equivalent to 0.62
gm S/gm carbon. Following the breakthrough test, the elemental sulfur deposited on the carbon was chemi-
cally extracted and recovered. A sulfur loading at 0.51 gm S/gm carbon (or 33.8 wt. percent defined as grams
of sulfur divided by the weight of carbon plus the weight of sulfur times 100 percent) was found. These num-
bers are in good agreement with and confirm the H2S breakthrough results. These values indicate the material
should perform well for H2S removal with low oxygen concentration and high levels of methane and carbon
dioxide typical of ADG applications.

In these tests, pure components were used and it is anticipated the presence of other adsorbable compounds
may have a tendency to reduce the capacity of the material for storing sulfur in actual field applications.
Therefore, testing of the material at WWT site to quantify the capacity of the material is recommended in the
next phase of the program.

It was concluded that the use of the activated carbon media, is the preferred ADG pretreatment method. It
does require a minimum level of O2 in the gas for promoting the demonstrated sulfur formation Claus reac-
tion. An air addition control to maintain minimum O2 levels for effective H2S removal may be required. A
minimal amount of heating will also be required to prevent condensation of liquid water on the media. This is
also consistent with the general requirement to prevent condensation in the ADG supply to avoid the forma-
tion of deposits from bacteria in the gas.

The up-front H2S, absorbent removal concept provides design flexibility for ADG application. For low levels
of HoS, the bed can be nominal in size and operated as a single thread unit. For higher levels of H2S, the
activated carbon absorbent bed could be incorporated as parallel units, allowing continuous operation of the
pretreatment system on one bed while the other is being replaced with fresh absorbent. Although the carbon
can be disposed of as a solid waste, it can be regenerated off-site, eliminating waste disposal considerations.
While the power plant hydrodesulfurizer is not required its removal from the existing power plant would in-
crease cost and is not recommended.

Operating costs associated with the activated carbon are low. Cost estimates, based on H2S loadings of 35 -
50 percent by weight 100 ppm H2S in the gas stream and material costs in the range of $4.96/kg are less than
0.10/kWhr.

-------
2.3.2 Preliminary Process Design

The size of the pre treatment module desulfurizer bed is dictated by three key variables. These are the sulfur
content of the digester gas; the maximum permitted loading of the adsorbent bed; and the desired time interval
between bed change-outs. The design for the demonstration unit (discussed in the Section 2.3.2.2) is based on
a single bed approach, due to the relatively low sulfur content in the ADG fuel (6 ppmv). However, for a
commercial application the sulfur levels are much higher (100-200 ppmV), and the single bed approach is not
practical as it would require a relatively large bed and frequent change-outs.

2.3.2.1 Preliminary Process Design - Commercial Application

The recommended approach for a commercial application is to use two beds piped in series with operated
directional control valves as shown in Figure 2-2. The valving and piping would be designed to permit opera-
tion of the two beds in series with reversing capability. The design would also provide the capability to oper-
ate on a single bed while the other bed is being changed-out. This arrangement would permit use of relatively
small beds, and would allow for significantly longer time intervals between bed change-out operations. Spe-
cifically, two beds operating in series would permit high sulfur loadings to be attained in the upstream bed, as
any breakthrough H2S would be adsorbed in the downstream bed. When the upstream bed becomes fully
loaded, (inlet H2S equals the exit H2S), it would be replaced with a new or regenerated bed, and the valve
positions would be reversed so that the ADG feed gas passes through the older bed first. This would result in
the newer bed being exposed to a sulfur free gas stream allowing it to remove halogens more effectively.
Based on the results of the lab scale testing (reported in monthly reports), capacities of 30-50 percent by
weight are anticipated with this approach.

ADG Feed
Gas

Figure 2-2, Valving Arrangement for Dual Absorbent Bed Operation

The estimated size of each of the two beds for a 200-kW commercial application is a cylinder 0.6 m in diame-
ter by 1.50 m high. For a 1.2 MW commercial application, each of the two cylinders (beds) would be 1.16 m
in diameter by 2.32 m high. These size estimates are based on a typical sulfur feed content of 100 ppm, adsor-
bent bed loading of 35 percent by weight, and a change-out interval of one year. For an application with a 200
ppm H2S content in the ADG, the same bed sizes could be used with a reduced bed change-out interval of 6
months.

-7-

-------
A schematic of the commercial design process is shown in Figure 2-3.

Air Addition

XJ Fixed Control
Valve

I Coalescing
Filler

GLEAN EXHAUST
COj + HaQ
+ N2 + Oj

200 lew
UTILITY
GRADE
PO

POWER MODULE

sSife

INVERTER

- REMOVES
02

-REMOVES
RESIDUAL
SULFUR,
MAUDES

• CONVERTS
FUEL TO
HYDROGEN

- CONVERTS
AIR AND
HYDR-
OGEN TO
DC POWER
AND

THERMAL
ENERGY

- CONVERTS
DC TO AC

- PROVIDES
SAFE
ELECTR-
ICAL
INTER-
CONNECT

COOL*"

REJECTS

WASTE

HEAT

AIR

Fuel Cell Power Plant

Digesters
Waste Water Treatment Plant

Bed 1

Bed 2

Figure 2-3. Process Schematic of Commercial ADG Pretreatment System
2.3.2.2 Preliminary Process Design - Demonstration Unit

The ADG feed gas at the proposed demonstration site contains only 6 ppm sulfur by volume. This low sulfur
content is due to their use of iron salt addition to control water chemistry. The recommended approach for this
application is to use a single adsorbent bed which would not require change-out during the one year demon-
stration period.

The design parameters used for the 200-kW rated demonstration pretreatment system are listed in Table 2-5.
Figure 2-4 is a process flow schematic of the demonstration unit. A coalescing filter will remove entrenched
liquids, and particulates. The unit will include separate ADG and air blower, and ADG and air mass flow
meters for control. This absorbent is contained in a single, vertically mounted stainless steel cylindrical ves-
sel 20.3 centimeters in diameter, and 1.1 meters in height. All of this equipment is mounted on a small skid for
ease of transporting and site installation, and allow for verification testing of the unit prior to integration with
the fuel cell power plant. Provisions will be made for heat-treating the lines and for heating the vessel for
outside installations to prevent condensation. Multiple taps on the vessel will permit sampling of the gases
during the demonstration.

Integration of this process design unit into the overall demonstration conceptual design is discussed in Sec-
tion 5.0.

-------
Table 2-5. Basis for Preliminary Design of Demonstration Pretreatment System
• 200 kW flows 91.2 kg per hour -1.4 cubic meters per minute

•	Gas Composition

•	65% CH4
_____

•	6 ppm H2S

•	Gas saturated w/water carry over

•	Activated carbon scrubber

•	Capacity of 361.7 kg H2S/m3C

•	Volume of carbon required for one year - 0.0163 rr?

•	Design volume - 0.2 m diam. x 1.1 m long (0.345 m3)

Figure 2 -4. ADG Demonstration Pretreatment System Process Flow Schematic

-------
3.0 FUEL CELL POWER PLANT REQUIREMENTS

3.1 Fuel Cell Power Plant Description

Due to the wide variation in ADG production capacities among waste water treatment plants, a modular de-
sign approach is warranted for commercial ADG to energy applications. Since a fuel cell power plant effi-
ciency is virtually unaffected by unit size, a fuel cell power plant lends itself readily to a modular design ap-
proach. For small waste water treatment plant applications, the basic building block module size is 200 kW.
Several of these modules could be readily incorporated as required on a site-specific basis. For the larger
applications, a megawatt size basic building block module size could be considered. Preliminary analysis
indicates that 1.2 MW would be a reasonable building block. Similarly, one or more of these modules could
be readily incorporated at a given site. For all of these options, the fuel cell power plant design issues are
similar. Therefore, this discussion will focus on the design for a single 200-kW power module.

The ADG power module consists of a pre-packaged, truck transportable, self-contained fuel cell power plant
with a continuous electrical rating of 200 kW. It is designed for automatic, unattended operation, and can be
remotely monitored. It can supply power to electrical loads either in parallel with the utility grid or isolated
from the grid.

A simplified functional schematic of the fuel cell power unit is shown in Figure 3-1. Major sections of the
system include the fuel processing system, fuel cell electrical conversion system and the thermal management
system. In the fuel processing section, treated ADG is converted to hydrogen and CO2 for delivery to the fuel
cell stack. The fuel processing system includes a fuel preprocessor to remove the residual contaminants from
the treated gas, a fuel reformer, and a low temperature shift converter where the reformer effluent is further
processed to provide additional hydrogen and CO2.

Within the fuel cell stack, hydrogen from the process fuel stream is combined electrochemically with oxygen
from the cathode air stream to produce dc electricity and byproduct water. The product water is recovered and
used in the reformer. The heat generated in the fuel cell stack is removed to an external heat rejection system.
This energy can be either rejected to the ambient air or recovered for use by the customer. The dc power pro-
duced in the fuel cell stack is converted to ac power in a power conditioning package not shown on the process
schematic,

A preliminary design of a fuel cell power plant was established to identify the design requirements which
allow optimum operation on ADG, Three issues specific to digester gas operation were identified which re-
flect a departure from a design optimized for operation on natural gas. The primary issue is to protect the fuel
cell from sulfur and halide compounds not scrubbed from the gas in the fuel pretreatment system. A second
issue is to provide mechanical components in the reactant gas supply systems to accommodate the larger vol-
ume flow rates that result from use of dilute methane fuel. The third issue is an increase in the heat rate of the
power plant by approximately 15 percent relative to the natural gas power plant. This is a result of using the
dilute methane fuel. One consequence of the reduced efficiency is an increase in the amount of he at which is
recoverable from the power plant. Because the effective fuel cost is relatively low, this decrease in power
plant efficiency will not have a significant impact on the overall power plant economics.

In summary, a 200-kW ADG fueled power module can be designed by modifying the natural gas fueled power
plant without the need for technology developments. The design would require resizing of selected fuel sys-
tem components to accommodate the increased reactant flow rates with minimum pressure drop. To imple-
ment the design would require non-recurring expenses for system and component design, verification testing
of the new components, and system testing to verify the power plant performance and overall system integra-
tion. A thermodynamic analysis of the fuel cell power plant optimized for operation on ADG was completed.
The resulting performance for digester gas operation is compared to the performance of a power plant operat-
ing on natural gas in Table 3-1. These estimates are based on IFC's extensive power plant operating experi-
ence which provided the data base for computer modeling of fuel cell systems.

-10-

-------
FUEL

PROCESSING
SYSTEM

FUEL
PRE-
PROCESSOR

EJECTOR

REFORMER

BURNER

LOW TEMP

SHIFT
CONVERTER

STEAM

THERMAL-
MANAGEMENT
SYSTEM

Figure 3-1. Functional Schematic Fuel Cell ADG Power Unit

Table 3-1. Performance Comparison for Nominal 200 kW Output



NATURAL GAS

ADG



POWER PLANT

POWER PLANT

Fuel

Natural Gas

ADG

Electrical Efficiency (LHV) - %

40.0

38.0

Heat Rate (HHV) - kgCal/kWHr

2,395

2,495

Available Heat - kgCal/Hr

190,000

200,000

Ambient Temperature for Fuel Water Recovery - °C

35

35

Startup Fuel

Natural Gas

ADG

-11-

-------
The estimated air emissions of the fuel cell power plant are provided in Table 3-2. The air emissions are sig-
nificantly lower than other ADG energy conversion devices, giving the fuel cell power plant the potential for
being the best available control technology for digester gas methane mitigation. These emissions are based
on extensive testing of the PC25 power plant using natural gas as the fuel. Verification of these emissions
estimates will be a key element of the demonstration program.

I&ble 3-2. Estimated Fuel Cell Air Emissions

ADG FUEL CELL

Emissions - kg/kg.cal x 10"9

NO*

3.06

SOx

Not detected

Particulates

Not detected

Smoke

None

432

Non-Methane Hydrocarbons

0.068

3.2 Modifications for PC25 Power Plant Demonstration on ADG

3.2.1 Modifications Required to Achieve 200-kW Output

The PC25 power plant is designed to operate on natural gas fuel with a net electrical power output of 200 kW.
Operation of this power plant on waste methane fuel gas, such as ADG, requires that the power plant accom-
modate a reduced heating value fuel containing up to 35-40 percent diluents (CO2) by volume. This translates
to significantly higher mass and volume fuel flow rates, with corresponding changes to the power plant pro-
cess operating conditions.

The demonstration program will provide operating data of a modified PC25 power plant on ADG. The tech-
nical approach in the Base program was to (1) determine the modifications that must be done to the power
plant in order to operate on ADG with an output of up to 200 kW; (2) to define the technical issues impeding
the commercial availability and deployment of fuel cell power plants for most methane applications, and (3)
to identify and assess technology development concepts for addressing these technical issues.

Analysis was completed to determine the modifications necessary to the PC25 power plant for operation on
ADG with a composition of 65 percent methane and 35 percent CO2 by volume. The basis for these studies
were:

• The ADG pre treatment system will remove all contaminants to no more than the levels found in natu-
ral gas.

• Grid-independent operation is not required.

It was found that the performance of a number of components were affected. The PC25 power plant hardware
capabilities were determined using analytical modeling in conjunction with performance test data. These
capabilities were then compared against the requirements for this application. As a result, the following mod-
ifications are required for operation at 200-kW electrical output on ADG fuel.

• . Modified software

• Larger-sized fuel controls

• Resized process piping and orifices for pressure drop control

• Higher head rise process air blower

-12-

-------
3.2.2 Required Refurbishments to the Prototype

In one program alternative, IFC proposes to provide the PC25 Prototype Power Plant to the project as In-Kind
Share at the start of the Option 1 Program. At the present time the prototype power plant has accumulated over
12,500 operating hours on natural gas fuel. In the event this alternative is exercised in the program, and prior
to being deployed to the demonstration site, the unit would require some refurbishments in order to meet the
program objectives of a one-year, 200-kW demonstration on ADG. The refurbishments are defined as those
components which will have either approached the end of their design life or have exhibited performance
and/or operational deficiencies during operation at IFC. The scope of the refurbishments the prototype power
plant could include the following items:

• Cell Stack Assembly
« Reformer Unit

• Gas Fired Heater

• Thermal Management System Piping

• Process Air Valves

• Customer Heat Exchanger Gaskets

The prototype cell stack assembly has been subjected to a range of operating conditions as part of the present
prototype test program which have limited its performance. Replacement of the cell stack assembly would be
warranted to ensure the performance potential of the demonstrator unit.

During the test period for the prototype unit, some sulfur compounds were deposited in the reformer unit cata-
lyst bed, resulting in decreased fuel conversion performance. For this reason the reformer unit would need to
be replaced in order to verify the functionality of the ADG gas cleanup system.

Other refurbishments may be required, depending on the accumulated operating time for the prototype at IFC.
Prior to deployment of the prototype power plant to the demonstration site, IFC will determine exactly which
refurbishments need to be made.

3.3 Technology Improvements

The generic requirements of a fuel cell power plant for use in waste treatment plants were determined. These
requirements and a qualitative assessment of benefits of meeting these requirements are shown in Table 3-3.
All of these benefits result in a reduction in the amount of airborne pollutants and global warming gases
emitted.

Table 3-3. General Requirements for a Fuel Cell Power Plant
for ADG Application

REQUIREMENT

BENEFIT

Low Capital Cost

Competitive economics lead to widespread use of fuel cells at
waste water treatment plants resulting in displacement of coal
fired electricity.

High Electrical Efficiency

Improved competitive economics for use of fuel cells at waste
water treatment plants.

Low Emission Signature

Reduction of emissions that are precursors to acid rain, smog,
and greenhouse effect.

High Quality (i.e..temperature) of fuel
cell waste heat

Increase in overall energy utilization of ADG reducing the need
for supplemental natural gas. The high quality heat may be used
in the process for melting grease, or for facility HVAC to operate
absorption air conditioners.

-13-

-------
The commercial PAFC projected cost ($1500/kW) has been shown to be suitable for most waste water treat-
ment plants. However, any reduction in this cost will increase the savings to the operator of these plants and
therefore, provide additional incentives to install these fuel cells. In a similar mode, the efficiency of the fuel
cell is superior to alternative energy conversion devices. Any increase in efficiency would result in a reduc-
tion in the amount of electricity bought from the electric grid resulting in a decrease in the amount of pollut-
ants and global warming gases. An increase in the quality, i.e., temperature of the fuel cell waste heat would
have a similar benefit.

To improve the characteristics of the commercial fuel cell power plant for anaerobic digester applications,
several technology areas and power plant modifications were investigated. Several of these areas are current-
ly under development at UFC as part of the ongoing cost reduction program, while other areas are emerging in
other industries.

Table 3-4 lists the technology areas studied, their potential benefits, and resultant findings.

3.3.1 Fuel Processor

EFC is developing an advanced, more efficient fuel processor reforming unit for natural gas applications. The
start and sustaining burners have been designed for low NOx emissions, and have demonstrated very low
methane and carbon monoxide emissions in laboratory testing (NO* emissions will be verified at a later date).
This new technology appears to offer even greater benefits for waste gas applications with respect to power
plant efficiency and emissions signatures. IFC believes that the technology is readily adaptable and should be
pursued for commercial ADG to energy fuel cell applications. For additional details, refer to Appendix B of
this document.

3.3.2 Ejector/Fuel Control

IFC's 200-kW power plant (PC25) is designed for operation on natural gas fuel. An initial determination was
made that the present PC25 fuel flow configuration would not be able to achieve the full 200 kW electrical
output on ADG without system modification. This is due to the large amount of diluent (35 percent CO ?) to
present in the digester gas which would create excessive pressure drop in the fuel system. The current steam
jet ejector is not capable of achieving the fuel pressure rise which would equal the pressure loss on ADG.

Studies were conducted to identify an approach for resolving this issue. One option considered is a new con-
cept which would utilize a fixed area ejector in conjunction with a steam flow control valve (as opposed to the
current variable flow area ejector design). The results indicated that full power operation would be achiev-
able, however, the unit would not be able to operate at idle power conditions due to insufficient steam produc-
tion. A second option considered a combination of system modifications and ejector performance improve-
ments to resolve this issue.

A series of bench-scale tests were conducted to determine the ejector performance at ADG-like conditions. It
was then determined that combining the existing ejector capability with modifications to the fuel controls and
related piping to reduce the system pressure drop would provide sufficient flow capability to support 200-kW
electric load.

Since these design changes can be readily implemented, there is no need for further technology improvements
in this area. Refer to Appendix B for additional details.

3.3.3 Water Recovery/Treatment

Recovering water for the return process adds to power plant cost. The addition of further ADG diluents to the
exhaust stream compounds this issue. A study was undertaken to assess the feasibility of using an alternative
water recovery concept which would utilize a direct contact cooler to condense water from the fuel exhaust
and cathode exhaust streams. The chief objective of the study was to reduce the overall cost associated with
the water recovery process.

-14-

-------
Table 3-4, Technology Areas for Assessment in ADG Program

Potential Power Plant Benefit

Tech
Area

Re-
duced
Cost

Increased
Efficiency

Low
Emis-
sions

Increased

Quan/
Qual Heat

Issue

Results

Further
Activities
Warranted

Fuel

Processor

Operation of re-
former on dilute
burner gas.

* Cost reduced
by 30%

* Low emissions
maintained by
increasing
flame temp.

Yes

Ejector/

Fuel

Control

Operation of
ejector on dilute
fuel gas.

• Tests of modi-
fied ejector un-
der way

Yes

Water
Recovery

Shell and tube
condenser pres-
ently used.
Look to replace
with lower cost
contact cooler.

• Cost savings
offset by effi-
ciency loss.

Controls

Advanced con-
trols could re-
duce power
plant cost. Use
of O2 sensors in
exhaust could
provide more ef-
ficient reformer
operation.

• Several areas
look promising
and warrant
further effort
and monitor-
ing.

Yes

Heat
Recovery

' ^

Maximizing
waste heat quan-
tity/quality
could provide
for better inte-
gration with
waste water
plant

• System
changes identi-
fied to increase
thermal quali-
ty/quantity do
not require
technology de-
velopment.

The results indicated that a contact cooler based water recovery system would cost slightly less than the pres-
ent condenser system. However, the negative impact on the parasite power, power plant size, and heat recov-
ery capabilities were deemed to be significant enough to make this concept unattractive. Refer to Appendix B
for additional details.

3.3.4 Alternative Power Plant Control

Several technology development items related to instrumentation and control of a commercial ADG to energy
power plant were identified and investigated as part of the base program. These include use of fuzzy logic for
adjustment of process control schedules with changing conditions; development of an on-line diagnostic tool
to facilitate rapid restoration of the power plant in the event of a malfunction or component failure; a two-way

-15-

-------
communication system for on-line data retrieval; use of automotive type or zirconia based oxygen sensors for
burner air control; and use of automotive sensors for cost savings.

Preliminary investigations indicated that all of the above concepts look promising for commercial ADG to
energy power plant applications, and should be pursued as part of the development program. See Appendix B
for further details,

3.3.5 Alternative High Quality Heat Recovery

A study was conducted to evaluate options for increasing the quantity and quality of high grade heat from the
power plant to provide for better thermal integration with the waste water treatment plants.

Results of the study indicated that several system alternatives exist, but all would increase the cost of the
power plant. To increase the quantity of high-grade heat would be a relatively straight-forward addition of
heat exchangers to the existing thermal management system. To increase the quality of high-grade heat would
require a redesign of the thermal management system. No technology development was identified, and no
further activities were recommended. Refer to Appendix B for further details.

-16-

-------
4.0 COMMERCIAL SYSTEM CONCEPTUAL DESIGN

4.1 Background - Application and Market

Waste Water Treatment Plants (WWT) incorporating anaerobic digester are typically owned by municipali-
ties. They produce a biogas that is ~65% methane/35% carbon dioxide, which, with some cleanup can be
used in a fuel cell power plant. The process and facility requires significant electric and thermal energy re-
quirements. Generally, the digester gas is utilized at the site for process and facility thermal requirements, and
no net additional thermal energy is required.

A functional schematic of how the fuel cell would integrate both electrically and thermally with the waste
water treatment plant is shown as Figure 4-1. Two key observations can be made;

1. The WWT has a large electric requirement. Therefore, all fuel cell electricity can be used in the pro-
cess and would be valued at the facility electric rate.

2. Some supplemental natural gas may be required by the WWT to augment the fuel cell thermal output.
Indications are that it is appropriate to size the fuel cell to process all the ADG produced by the facil-
ity. While this approach may result in some increased costs due to supplemental fuel requirements to
meet plant thermal needs, it is counterbalanced by the societal benefits due to a maximum reduction
in emissions which result from utilizing gas which is presently flared and by displacing electricity
generated at a central station. Additionally, the magnitude of the supplemental thermal requirements
are very seasonal and site-specific in nature. In fact at certain locations there may be no need to pur-
chase supplemental gas.

Two trends are indicated from the market data that is available. (References 1,2). One, that a relatively small
number of large treatment plants (~40) represent a significant market segment (~ 100 MW total). The small-
est of these plants produce sufficient ADG to power a fuel cell of approximately 1 MW. Two, a significantly
larger number of plants exist (~500) capable of producing sufficient gas to power aPC25 sized (200 kW) fuel
cell. Indications are that it may be appropriate to carry two conceptual designs. One incorporates a 1+MW
sized fuel cell to address the large treatment plant sector and take advantage of the economics of scale. The
second incorporates a 200 kW sized fuel cell, of which one or more such modules could be integrated to ad-
dress the needs of the smaller treatment plants. It is important to note that due to the simple pretreatment
system requirements the costs of pretreatment would not be significantly affected by scale.

FUEL CELL CASE (ANNUAL BASIS)

Thermal Requirement
4.91 x 109 kg.cal-HG

Figure 4-1. Integration Between WWT and Fuel Cell

-17-

-------
4.2 Economic Assessment

Key assumptions (hat went into economic assessment studies (without credits which will be discussed below)
are as follows:

• 80 percent F/C capacity factor (based on 95 percent availability and 20 percent variability in ADG
production).

• ADG pre treatment cost estimates:

- Capital = SlOO/kW

- O&M = 0.150/kWh

• F/C O&M Costs = 1.50/kWh at entry level cost

= 0.750/kWh at mature cost

• Natural gas price = $3/million Btu ($1.2 x 10~8/cal).

• 10 percent annual carrying charge (corresponding to municipal ownership).

ADG pretreatment capital cost is an allowance for the recurring cost of fabricating skid mounted packaged
bed absorbers, based on IFC experience in fuel processing packaged equipment. The O&M cost reflects the
expense associated with periodic changeout of the absorbent material, plus an allowance for maintenance. It
was assumed that the H2S content of the gas was 100 ppm. Fuel cell O&M reflects IFC estimates for the early
and mature commercial power plants.

One consideration impacting the economics is the related thermal integration between the fuel cell and the
WWT. Data from a 1979 Gilbert/Commonwealth study for a plant sited in Bergen County, New Jersey (see
Figure 4-2) shows the need for a variety of heat qualities (i.e., heat source temperatures) in a WWT varying
significantly between summer and winter primarily due to space heating and waste water preheating require-
ments. Based on this data, the following simplified thermal requirement profile was assumed for a Northern
U.S. climate:

• Winter: -62% of ADG produced required for plant thermal use.

• Summer: -23% of ADG produced required for plant thermal use.

From the above seasonal results, it follows that for a Southern U.S. application, space heating requirements
would be greatly reduced and thermal requirements would be roughly 23 percent of the ADG produced on a
year-round basis. Both siting options were considered in the economic analysis.

Thermal integration of the fuel cell can provide for meeting some or all of the thermal needs of the WWT with
supplementary thermal energy (natural gas) being purchased to supply the difference. A fuel cell power plant
may be designed to produce thermal energy at various temperatures. If more fuel cell heat were available at
higher temperatures, a larger fraction of it could be used by the plant, thereby reducing the amount of supple-
mentary thermal energy which must be purchased.

The impact of the quality of heat recovery from the power plant was evaluated. The following three heat
recovery options were considered:

• Option 1: Low-grade heat recovery -73.9°C hot water

• Option 2: Intermediate grade heat recovery - up to 121 °C hot water

• Option 3: High-grade heat recovery - — 149°C steam plus hot water.

-------
20
18
16
14

12
10
08

06
04
02

5.0

TOTAL HEAT

SPACE
HEAT

DIGESTER HEAT

SPACE
HEAT

2.5 g

a>
©

GREASE MELT HEAT
J I I

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Figure 4-2. Bergen County Utilities Authority, Total Heal Requirements

Impact of these options on the resulting equivalent cost of supplemental thermal is shown in Figure 4-3. The
results indicate a $120/kW to $230/kW benefit for the intermediate to high-grade heat recovery system as
compared to low-grade heat recovery. These are potential benefits for the application of fuel cells and were
used for assessing technology concepts for alternative heat recovery in the PC25 power plant. As an outcome
of the advanced heat recovery technology task, the fuel cell heat recovery Option 2 was selected as the base-
line, the cost of the system changes involved with Option 3 outweighed the benefits shown above.

With the above assumptions, an example WWT was selected and a model created to economically evaluate
the example plant with and without integration of a fuel cell power plant. The annual energy flow for the 5785
kg.cal/m3 example WWT is characterized in the upper diagram of Figure 4-4. The plant produces 500,000
liters/hour of ADG, with a heating value of 5785 kg cal/m3 (this corresponds to — 1200 kW of fuel cell capac-
ity). Without the fuel cell, the plant presently burns a portion of the ADG to provide all the plant's thermal
requirements, and flares the remainder. The quantity and quality of the thermal requirements are site specific
as discussed above but are provided for by the ADG and do not enter into the plant's annual energy bill. Elec-
trical energy requirements for the plant are provided from the grid. The energy bill for the plant is the cost of
purchased electricity from the local utility based on an existing rate structure.

Alternatively, a 1200-kW fuel cell power plant can be integrated into the example WWT- The annual energy
flow for this case is shown in the lower diagram of Figure 4-4. All of the ADG produced by the plant is fed to
the cogeneration fuel cell power plant. The 1200 kW fuel cell power plant is assumed to operate at an 80
percent annual capacity factor. Thus the fuel cell produces --60 percent of the annual electrical energy re-
quirements of the WWT; the remainder is purchased from the local utility.

Also shown in Figure 4-4, thermal energy from the fuel cell power plant is provided back to the WWT. How-
ever, since the fuel cell uses all of the plant's ADG, there may be portions of the year, depending on climate,
when there is insufficient waste heat available to satisfy the plant's thermal needs, necessitating the purchase

-19-

-------
of supplemental gas. This supplemental gas purchase has been accounted for by a detailed energy evaluation
of the fuel cell case. As shown in Figure 4-5, the supplemental thermal requirements for a high heating degree
day (Northern U.S.) climate were evaluated for both winter and summer via an energy balance around the
process. The analysis indicated that in the winter a moderate supplemental thermal requirement exists,
whereas in the summer the heat recovered from the fuel cell is sufficient to met the thermal needs of the WWT.
It should be noted that for a Southern U.S. climate (low HDD) WWT thermal requirements would essentially
correspond to the "summer" column of Figure 4-5, year-round, thus leading to no supplemental thermal re-
quirement for that case.

400



263

140-

$12Q/kW BENEFIT
FOR OPTION 2

1 100

0

LOW-GRADE INTERMEDIATE GRADE
1	2

HIGH-GRADE
3

FUEL CELL HEAT RECOVERY OPTION

Figure 4-3, Impact of Fuel Cell Heat Recovery on Break-Even Fuel Cost

-20-

-------
CONVENTIONAL CASE (ANNUAL BASIS)

n

Boiler

To flare

Waste water w

Treatment

AOG 2.52 x1010 kg.cal



plant



T

Electricity
1.19 x 10'° kg.cal

FUEL CELL CASE (ANNUAL BASIS)

Thermal Requirement
4.91 x 10® kg.cal

Figure 4-4. Supplemental Thermal Requirements - Conventional Case

FUEL CELL CASES (ANNUAL BASIS)

Purchased

© 	

W Supp. Boiler

Boiler

To flare,

T-3

Waste water _

Treatment

ADG 2,52 k 1010 k



plant

1



Supp.
elec.
from
flrid

Electricity

Fuel
Cell

LG (1)
HG Q

Fuel cell
heat

Station

Summer

Winter

©

0

-1.96 x101° kg.cal

©

-2.62x IC10 kg.cal

- 2.62 x 1010 kg.cal

©

0

-1.26 x1010 kg.cal

©

1.34 x 10910 kg.cal

-1.34 x1010 kg.cal

©

4.03 x 10s kg.cal

-1.34 x 1010 kg.cal

Figure 4-5, Supplemental Thermal Requirements - Fuel Cell Cases

-21-

-------
Economic credits that could be applicable were identified for the application. These include the following;

• Biomass electric incentives

This credit was authorized by the passage of the Energy Policy Act of 1992. (EPA act). This act provides for
incentive payments for electric energy sold or generated by a "qualified" renewable energy facility. A power
plant owned by a municipal waste water treatment plant would be a qualified facility.

The magnitude of this credit is 1.50/kWHr (adjusted each year for inflation) for the first 10 years of plant
operations, and the credits will be available for a 20 year period from the enactment of the act. When levelized
over a 20-year power plant lifetime (assuming 5.5% inflation and a 10% discount rate) this amounts to
1.40/kWhr,.

• Emission Credits

To assess the possible value of emissions reductions, market values of S1000/ton (S1.1 /kg) of SO2 and \Ox
were assumed. This assumes that the conventional case (without fuel cells) gets its electricity via the combus-
tion of coal in plants meeting New Source Performance Standards. It is felt that use of these credits is most
appropriate if the plant is served by a municipal utility, since a mechanism would then exist for the utility to
take credit for the offsets in operating other utility equipment.

While the present market value for SO2 reduction may be less than S! 000/ton (S 1.1''kg), this number was
assumed in order to establish an "upper bound" in the economic assessments. In the economic assessments,
two additional cases, Scenarios "B" and "C," assumed no value for the emission reduction, (i.e., $0/ton), in
order to provide "lower bound" cases.

• Distributed Power Credits

The concept of distributed power and the associated avoidance of electricity transmission and distribution
costs have been considered as potential fuel cell benefits, and have been recommended by EPA for consider-
ation in this application. Fuel cell power plants have been identified by EPRI, various utilities including Pa-
cific Gas and Electric, and various application assessment studies by contractors such as A.D. Little, as a
power generation technology offering benefits to rate payers associated with mitigating the need to install,
replace or extend utility transmission and distribution (T&D) power systems. Based on a recent A.D. Little
study, the average cost for expanded T&D is on the order of $500/kW of expanded central station generation
capability,

• Backup Power Credits

Backup power credits could be applicable for displacing redundant diesel equipment which WWTs install for
critical loads. Taken in conjunction with the above distributed power credits, a partial credit can be taken for
backup power credits. If the conceptual design consists of six 200-kW modules each with an average avail-
ability of 95%, the probability that three or more could be operational at all time is .9999. Therefore, it is
appropriate to take credit for 1/2 of the total potential offset of the diesel cost, or $500/kW, in a scenario where
distributed power credits are also assumed.

Three economic scenarios (A-»C) were created to take advantage of all or some of these credits. The results
are presented from the perspective of the municipal owner, in terms of potential net revenues per MMSCF of
ADG produced. For each of the following three scenarios, the biomass electricity incentives described above
were included in the assessment. Use of some or all of the other credits are described below;

• In the initial Scenario A, the municipal owner is putting in a new wastewater treatment facility utilizing
fuel cell power generation. In this case, the facility is served by a municipal electric utility.

- Emission credits,

- Distributed power credits,

- Backup credits up to 1/2 the value of the backup diesel as discussed above. This is appropriate when
taken in conjunction with the distributed power credits.

Additionally, for this "best case" scenario, a low heating degree day climate (typical of the Southern
U.S.) was assumed. This negates the requirement for supplemental fuel to provide waste heat for the

-22-

-------
treatment plant. Economic results for scenario A are shown as Figure 4-6. for this scenario fuel cells
are economically competitive for plants with electricity costs of 1.0 to 3,50/kWh or higher, making
fuel cells highly competitive in most of the country.

* In an intermediate Scenario B, the municipal owner is adding a fuel cell as part of an expansion at an
existing site. In this case, the facility is served by a private utility. The site is in a high heating degree day
climate (typical of the Northern U.S.). For this case, distributed power credits are still applicable since
the expanded capacity served by the fuel cell could offset the need for expanding the transmission and
distribution network to the plant. Emission credits, however, would be difficult to obtain since this plant
would be served by a private utility. Backup credits would be difficult to quantify dependent on the de-
gree of expansion undertaken and the likelihood that sufficient backup diesel power may already be in
place. Therefore, neither of these credits were applied. Economic results for Scenario B are shown as
Figure 4-7. For this scenario, fuel cells are economically competitive with electricity costs of 1.5 to
40/kWh or higher. This still represents a highly favorable case for fuel cells.

• In the most conservative Scenario C, the municipal owner is adding fuel cells to better utilize the energy
production capacity of the plant. Total facility production of ADG is not expanding. In this case, it would
not be appropriate to apply distributed power credits, since the existing transmission and distribution sys-
tem is already in place. Climate is assumed to be typical of the Northern U.S.; i.e., high heating degree
days. Economic results for this scenario are shown as Figure 4-8. For this scenario, the fuel cell is eco-
nomic when the plant electricity costs are 2 to 5$/kWh or higher. This still represents very favorable
economics for the fuel cell, particularly at the mature ($1500/kW) cost level.

Additionally, a comparison was made with other energy conversion options.

The internal combustion engine and the gas turbine engine have been suggested as competing options for
energy production at WWTs. For the WWT size selected for this analysis, the internal combustion engine is
more effective than the gas turbine option. This is used as the basis for the comparisons in this section. The
internal combustion engine can provide both heat and electric energy while consuming the ADG at the WWT.
With the present state-of-the-art technology, however, a lean-burn internal combustion engine has higher lev-
els of NO* unless special precautions are taken to clean up the exhaust. For this analysis, two cases are consid-
ered. The first case assumes there is no cleanup of the exhaust from the clean-bum internal combustion engine
and the second assumes that the exhaust is cleaned with Selective Catalytic Reduction (SCR). To put the
emission signatures on a comparable basis, the ADG will have to be pre treated in a manner similar to the fuel
cell system. For those cases with the SCR cleanup system, a pre treatment system has also been included as
part of the total system cost

Figure 4-9 shows the results of the economic analysis for the fuel cell system and the internal combustion
engine system. Since both can provide electricity, the comparison between the systems are based on the cost
of electricity generated from the energy conversion system. For the case where the SCR is employed to clean
up the engine exhaust, the fuel cell power plant is competitive with installed prices on the order of S3000/kW.
If no exhaust cleanup is required for the internal combustion engines, then the fuel cell is competitive at the
fully mature price of $1500/kW. In this latter case .however, the operation of the internal combustion engine
at the site would be quite dirty and significant amounts of NOx would add to the ambient air. For many loca-
tions where the fuel cell would be considered, such as California or other high emissions areas, the no exhaust
cleanup option may not be available. Consequently, the fuel cell option would be fully competitive with the
internal combustion engine where low emissions are required.

The fuel cell power plant is fully competitive in all situations in the mature production situation. For initial
power plant applications with limited lot production, the fuel cell power plant is competitive in areas with
high electric rates and/or severe emissions restrictions exist.