vvEPA
United States Industrial Environmental Research EPA 600 / 79 022b
Environmental Protection Laboratory February 1979
Agency ,>arch Triangle Park NC 2771 1
EPA Utility FGD
Survey:
October-November 1978
Interagency
Energy/Environment
R&D Program Report
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields.
The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects; assessments of, and development of, control technologies for energy
systems; and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, 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.
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EPA-600/7-79-022b
February 1979
EPA Utility FGD Survey:
October-November 1978
by
M. Melia, M. Smith, T. Koger, and B. Laseke
PEDCo. Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-02-2603
Task No. 24
Program Element No. EHE624
EPA Project Officers:
N. Kaplan
J. C. Herlihy
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park. NC 27711
Division of Stationary Source Enforcement
Office of Enforcement
Washington, DC 20460
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
NOTICE
This report, (prepared by PEDCo Environmental, Inc., Cincinnati,
Ohio, tinder EPA Contract No. 68-02-2603, Task No. 24) is provided
as an information transfer document. Data in this report are
supplied voluntarily by utility representatives; flue gas desulfuri-
zation (FGD) system designers, vendors, and suppliers; regulatory
personnel; and others. Neither EPA nor the designated contractor
warrants the accuracy or completeness of information contained in
this report.
This report is the fifth of five supplementary issues to the
December 1977-January 1978 report. Supplementary issues are
cumulative, so that it is necessary to retain only the latest
issue and the December 1977-January 1978 report (EPA-600/7-78-
051a).
Initial distribution of the report (generally, one copy per
company) is limited to organizations and individuals indicating a
specific interest in the field.of FGD technology. Additional
copies of this report and succeeding issues can be purchased from
National Technical Information Service, Springfield, Virginia
22151.
-------
CONTENTS
Notice
Tables
Executive Summary and Highlights
Section 1 Summary List of FGD Systems 1
Section 2 Status of FGD Systems 4
Section 3 Performance Description of Operational FGD Systems 23
Alabama Electric
Tombigbee 2
Arizona Electric Power
Apache 2
Arizona Public Service
Cholla 1
Cholla 2
Central Illinois Light
Duck Creek 1
Columbus and Southern Ohio Electric
Conesville 5
Conesville 6
Duguesne Light
Elrama 1 through 4
Phillips 1 through 6
Gulf Power
Scholz 1 and 2
Indianapolis Power and Light
Petersburg 3
Kansas City Power and Light
Hawthorn 3
Hawthorn 4
La Cygne 1
Kansas Power and Light
Jeffrey 1
Lawrence 4
Lawrence 5
Kentucky Utilities
Green River 1, 2, and 3
23
24
25
26
27
29
31
32
34
36
37
38
39
40
41
42
43
44
iii
-------
CONTENTS (continued)
Louisville Gas and Electric
Cane Run 4
Cane Run 5
Mill Creek 3
Paddy's Run 6
Minnkota Power Cooperative
Milton R. Young 2
Montana Power
Colstrip 1
Colstrip 2
Nevada Power
Reid Gardner 1
Reid Gardner 2
Reid Gardner 3
Northern Indiana Public Service
Dean H. Mitchell 11
Northern States Power
Sherburne 1
Sherburne 2
Pennsylvania Power
Bruce Mansfield 1
Bruce Mansfield 2
Philadelphia Electric
Eddystone 1A
Public Service Company of New Mexico
San Juan 1
San Juan 2
Southern Carolina Public Service
Winyah 2
Southern Mississippi Electric
R. D. Morrow 1
Springfield City Utilities
Southwest 1
Tennessee Valley Authority
Shawnee 10A
Shawnee 10B
Widows Creek 8
Texas Utilities
Martin Lake 1
Martin Lake 2
Monticello 3
Utah Power and Light
Huntington 1
Section 4 Summary of FGD Systems by Company
Section 5 Summary of FGD Systems by Vendor
46
47
48
49
50
51
52
53
55
57
59
61
63
65
67
69
70
71
72
73
74
76
77
80
82
83
84
85
86
87
iv
-------
CONTENTS (continued)
Paqe
Section 6
Section 7
Section 8
Section 9
Section 10
Section 11
Section 13
Appendix A
Appendix B
Appendix C
Summary of New and Retrofit FGD Systems by
Process 89
Summary of Operating FGD Systems by Process
and Generating Units 90
Summary of Sludge Disposal Practices for
Operational FGD Systems 92
Summary of FGD Systems by Process and
Regulatory Class 94
Summary of FGD Systems Under Construction 96
Summary of Planned FGD Systems 98
Total of FGD Megawatt Capacity by Year 101
FGD Systems Economics A-l
FGD Process Flow Diagrams B-l
Definitions C-l
v
-------
TABLES
No. Page
I Number and Total Capacity of FGD Systems vii
II Summary of Changes, October-November, 1978 viii
III Performance of Operational Units, October-November,
1978 xi
vi
-------
EXECUTIVE SUMMARY
This report is prepared every other month by PEDCo Environmental,
Inc., under contract to the Industrial Environmental Research
Laboratory/Research Triangle Park and the Division of Stationary
Source Enforcement of the U.S. Environmental Protection Agency.
Table I summarizes the status of FGD systems in the United States
during October and November 1978. Table II lists the units that
changed status in this period, and Table III shows the perform-
ance of operating units.
TABLE I. NUMBER AND TOTAL CAPACITY OF FGD SYSTEMS
Status
Operational
Under construction
Planned:
Contract awarded
Letter of intent
Requesting/evaluating bids
Considering only FGD systems
TOTAL
No. of
units
46
43
20
3
5
27
144
Capacity,
MW
16,054
17,297
10,690
1,960
3,100
13,406
62,507
The total power generating capacity of the electric utility
industry in the United States is now approximately 564 GW.a
Coal-fired units account for approximately 265 GW" or 47% of this
total. As indicated in Table I, 46 power generating units (all
coal-fired) are now equipped with operating FGD systems. These
units represent 16,054 MW, which is 3% of total utility power
generating capacity and just over 6% of utility coal-fired capac-
ity. Projections indicate that the total power generating capac-
ity of the U.S. electric utility industry will be approximately
vii
-------
TABLE II. SUMMARY OF CHANGES,
OCTOBER-NOVEMBER 1978
H-
H-
PGD status report
9/30/78
Arizona Public Service
Four Corners 1
Arizona Public Service
Four Corners 2
Arizona Public Service
Four Corners 3
Basin Electric Power
Laramie River 3
Northern States Power
Sherburne 3
Northern States Power
Sherburne 4
Potomac Electric Power
Dickerson 4
Springfield Water, Light &
Power
Dallman 3
Tampa Electric
Big Bend 4
Tennessee Valley Authority
Johnson vi lie
Tennessee Valley Authority
Paradise 1
Tennessee Valley Authority
Paradise 2
Utah Power & Light
' Emery 2
11/30/78
Operational
No.
46
16
MW
16,054
16,054
Under
construction
No.
38
+ 1
+1
+ 1
-i-l
•4-1
43
MW
16,128
175
175
229
190
400
17,297
Contract
awarded
No.
23
+1
-]
-1
-)
-I
20
MW
12,450
550
860
860
190
400
1.0,690
Letter of
intent
No.
1
+1
+1
3
MW
240
860
860
1,960
Requesting/
evaluat no bids
No.
4
-1
+ 1
+1
5
MW
2,350
550
650
650
3,100
Considering
only FGD
No.
27
-1
-1
-1
+ 1
+ 1
+1
27
MW
12,160
175
175
229
800
425
600
13,406
Total
No.
139
+ 1
+ 1
+1
+1
+1
144
MW
59,382
800
425
600
650
650
62,507
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TABLE III.
PERFORMANCE OF OPERATIONAL UNITS,
OCTOBER-NOVEMBER 1978
Plant
Tonbigboe 2
Apache 2
Choi la 1
Cholla 2
Duck Creek 1
Conesville 5
Conesvillo 6
drama
Phillips
Scholz CT-121
Petersburg 3
Hawthorn 3
Hawthorn 4
La Cygne
Jeffrey 1
Lawrence 4
Lawrence 5
Green River I,/, 3
Cane Run 4
Cane Run 5
Mill Creek 3
Paddy's Run 6
Milton R. Young 2
Colstrip 1
Colstrip 2
Reid Gardner 1
Reid Gardner 2
Reid Gardner 3
Mitchell 11
Sherburne 1
Shorburne 2
Mansfield 1
Mansfield 2
Eddystone 1A
San Juan 1
San Juan 2
Hinyah 2
R.D. Morrow 1
Southwest 1
Shawnee IDA
Shawnee 10B
Widows Creek S
Martin Lake 1
Martin Lake 2
Montlcello 3
Huntington 1
TOTAL
PGD systen
design
capacity
225
200
115
250
400
400
400
510
410
23
530
100
100
820
680
125
400
64
178
183
425
65
450
360
360
125
125
125
115
710
710
825
825
120
314
306
280
180
200
10
10
550
793
793
750
415
16,054
PGD unit
on line
during
period
225
200
115
250
400
400
400
510
410
23
530
820
680
125
400
64
178
183
425
450
125
125
125
115
710
710
314
306
280
180
200
10
10
415
0,413
Ho information
for this
period
100
100
360
360
825
825
120
550
793
793
750
5,576
Shut down
through-
out
period
65
65
FGD nyfltcn
availability,
Oct.
16
77
68
99
97
30
100
96
100
44
92
94
Nov.
e
operab
I
Oct.
26
64 i 42
26
99
94
24
46*
89
99
98
99
92
92
51
32
94
96
84
100
95
-
iUty,
Nov.
reliability.
ut i 1 ization ,
I
O-t. 1 Nov. Oct.
34
9
52
6
100
97
94
35
53*
37
93
91
44
100
26
43
33
96
100
99
73
100
9
52
6
74
54"
87
93
91
99
44
16
41
27
30
71
91
90
92
0
44
Sov.
24
8
46
4
24
56
33
42
42"
83
36
62
98
43
a Values roportcri are annual averanco for opcr.itu.n .'.unr.a 1978.
-------
878 GW by 1988,a an increase of 56% over the present total.
(This value reflects the annual loss resulting from the retire-
ment of older units, which is considered to be 0.4% of the aver-
age generating capacity at the end of each year.) Approximately
395 GW3""0 or 45% of the 1988 total will come from coal-fired
units. Of the 144 FGD-equipped units (62,507 MW) shown in Table
I, 141 (61,267 MW) are scheduled for operation by 1988. There-
fore, approximately 7% of the projected total generating capacity
and 16% of the projected coal-fired capacity will be controlled
by FGD by the end of 1988.
HIGHLIGHTS: OCTOBER-NOVEMBER 1978
The following paragraphs highlight FGD system developments during
October and November 1978.
Arizona Public Service reported that Cholla 1 was in service
through October and November. Module A logged 434 hours of
operation the first month and 720 hours the second, whereas
Module B logged 416 and 657 hours. The boiler operated 434 hours
in October and 720 hours in November. The reliability index
values for Modules A and B at Cholla 1 were 100% in both October
and November. Also, the utility reported that construction has
begun at Four Corners 1, 2, and 3 to upgrade the existing par-
ticulate scrubbers for additional SO2 removal.
Basin Electric Power announced that a contract was awarded to
Babcock and Wilcox for the installation of a dry collection FGD
system on Laramie River 3, a new 550-MW unit designed to fire
subbituminous coal and scheduled to commence operation in April
1982. The dry collection system will use lime slurry as the
scrubbing reagent.
Kansas City Power and Light reported average availabilities of 97
and 94% for the La Cygne 1 FGD system in October and November.
No major problems were reported.
Kansas Power and Light reported 100% availability for the FGD
systems at Lawrence 4 and 5 in both October and November. The
only downtime reported was 1 week in October for the annual
inspection of the boiler turbine.
Louisville Gas and Electric reported that the Cane Run 4 boiler
was out of service during all of October and the first part of
November because of boiler tube repairs. Operations resumed
during the second week of November. Operability of the FGD
system was 97% for the remainder of the month.
Northern States Power reported that the FGD system availability
for Sherburne 1 was 92% in both October and November and that the
-------
FGD system availability for Sherburne 2 was 94% in October anu
92% in November. A letter of intent is still in effect for the
FGD systems planned for Sherburne 3 and 4, which are scheduled to
start operation in May 1984 and 1987. Each new unit will be
rated at 860 MW and equipped with a limestone slurry rod scrubber
and spray tower absorber.
Nevada Power reported high FGD system availabilities at Reid
Gardner: 100% in October and 89% in November for Reid Gardner 1,
96% in October and 98% in November for Reid Gardner 2, 100% in
October and 98% in November for Reid Gardner 3.
Northern Indiana Public Service reported that the demonstration
Wellman-Lord FGD system on D.H. Mitchell 11 was available 99% of
the time during November.
Potomac Electric Power is in the preliminary stages of planning
an FGD system for Dickerson 4, a new 800-MW coal-fired unit
scheduled to start operation in May 1985.
Springfield Water, Light & Power reported that foundation con-
struction work began on the limestone slurry FGD system at
Dallman 3, a 190-MW coal-fired unit. Research Cottrell is sup-
plying this system, which will have a design SO2 removal effi-
ciency of 90%.
Tampa Electric announced plans to install an FGD system on Big
Bend 4, a new 425-MW unit scheduled to begin operation in early
1985. An electrostatic precipitator will provide primary partic-
ulate control. Although the FGD process has not yet been
selected, the design SO2 removal efficiency will be 90%.
The Tennessee Valley Authority plans to retrofit a magnesium
oxide FGD system at the Johnsonville steam plant. This system,
which will accommodate flue gas from 600 MW of the plant's 1500
MW capacity, is scheduled to begin operation in 1982. The
utility also announced plans to install FGD systems at Paradise 1
and 2 and is requesting/evaluating bids for two limestone slurry
FGD systems. Each system will treat 100% of the flue gas from
one of the two boilers. The Paradise 1 FGD system is scheduled
to begin operation in 1982. No startup date was reported for the
Paradise 2 FGD system.
Utah Power and Light reported that construction is proceeding on
Emery 2, a new 400-MW coal-fired unit scheduled for startup in
June 1980. Chemico will supply a lime slurry FGD system for
Emery 2. FGD construction is reported to be approximately 35%
complete.
XI
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REFERENCES FOR EXECUTIVE SUMMARY
a. Sixth Biennial Survey of Power Equipment Requirements of the
U.S. Electric Utility Industry: 1977-1986. Sponsored by
the Power Equipment Division, National Electrical Manu-
facturers Association.
b. Temple, Barker, and Sloane, Inc. Policy Testing Model for
Electric utilities, Exhibit II-3.
c. Twelth Annual Power Engineering Survey, Power Engineering,
April 1978.
xxi
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COMPANY NAME
EPA UTILITY FGD SUKVEY: UCIOHtK 19/fl - NOVEfbtk 19/B
SECTION 1
SUMMARY LIST OF FGO SYSTEMS
UNIT NAME
STAKl UP UAIt STATUS
KtG
CLASS
ALABAMA ELECTRIC COOP
ALABAMA ELECTRIC COOP
ALLEGHENY POWEK SYSTEM
ALLEGHENY POWER SYSTEM
ARIZONA ELECTRIC POWER COOP
ARIZONA ELECTKIC POWER COOP
ARIZONA PUBLIC SERVICE
ARIZONA PUBLIC SERVICE
ARIZONA PUBLIC SERVICE
ARIZONA PUBLIC SERVICE
ARIZONA PUBLIC SERVICE
ARIZONA PUBLIC SERVICE
ARIZONA PUBLIC SERVICE
ARIZONA PUBLIC SERVICE
ASSOCIATED ELECTRIC COOP
BASIN ELECTRIC POWER COOP
BASIN ELECTRIC POnER COOP
BASIN ELECTRIC POWER COOP
BASIN ELECTRIC POWER COOP
BASIN ELECTRIC POWER COOP
BIG RIVERS ELECTRIC
BIG RIVERS ELECTRIC
CENTRAL ILLINOIS LIGHT
CENTRAL ILLINOIS LIGHT
CENTRAL ILLINOIS PUBLIC SERV
CENTRAL MAINE POWER
CINCINNATI GAS ft ELECTRIC
COLORADO UTE ELECTRIC ASSN.
COLORADO UTE ELECTRIC ASSN.
COLUMBUS ft SOUTHERN OHIO ELEC.
COLUMBUS & SOUTHERN OHIO ELEC.
COLUMBUS * SOUTHERN OHIO ELEC.
COLUMBUS ft SOUTHERN OHIO ELEC.
COMMONWEALTH EDISON
COOPERATIVE POWER ASSOCIATION
COOPERATIVE POWER ASSOCIATION
DELMARVA POWER ft LIGHT
DUOUESNE LIGHT
DUOUESNE LIGHT
EAST KENTUCKY POWER COOP
GENERAL PUBLIC UTILITIES
GENERAL PUBLIC UTILITIES
GULF POWER
HQ.03JER ENERGY
HOOSIER ENERGY
INDIANAPOLIS POWER & LIGH1
INDIANAPOLIS POWER ft LIGHT
KANSAS CITY POWER ft LIGHT
KANSAS CITY POWER ft LIGHT
KANSAS CITY POWER ft LIGHT
KANSAS POWER ft LIGHT
KANSAS POWER ft LIGHT
KANSAS POWER ft LIGHT
KANSAS POWER & LIGHT
KENTUCKY UTILITIES
LAKELAND UTILITIES
LOUISVILLE GAS & ELECTRIC
LOUISVILLE GAS & ELECTRIC
LOUISVILLE GAS ft ELECTRIC
LOUISVILLE GAS ft ELECTRIC
TOMBIGBEE 2
TOMBIGBEE 3
PLEASANTS 1
PLEASANTS 2
APACHE 2
APACHE 3
CHULLA 1
CHOLLA 2
CHOLLA 4
FOUR CORNERS 1
FOUR CORNERS 2
FOUR CORNERS 3
FOUR CORNERS 4
FOUR CORNERS 5
THOMAS HILL 3
ANTELOPE VALLEY 1
ANTELOPE VALLEY 2
LARAMIE RIVfcR 1
LARAMIE RIVER 2
LARAMIE KIVER 3
GREEN 1
GREEN 2
DUCK CREEK 1
DUCK CREEK 2
NEWTON 1
SEARS ISLAND 1
EAST BEND 2
CRAIG 1
CRAIG 2
CONESVILLE 5
CUNESVILLE b
POSTON 5
POSTON 6
POWERTON 51
COAL CREEK 1
COAL CREEK 2
DELWAHE CITY 1, 2 & 3
ELRAMA POWER STATION
PHILLIPS POWER STATION
SPURLOCK 2
COHO 1
SEWARD 7
SCHOLZ 1 ft 2
MEROMJ_
MEROM 2
PETERSBURG 3
PETERSBURG o
HAWTHORN 3
HAWTHORN 4
LA CYGNE 1
JEFFREY 1
JEFFREY 2
LAWRENCE 4
LAWRENCE 5
GREEN RIVER 1,2 ft 3
MCINTOSH 3
CANE RUN 4
CANE RUN 5
CANE RUN 6
HILL CREEK 1
9-7(1
b-/9
3-79
3-80
lo-M
4-7H
b-HO
0-79
0-79
0-/9
0-OtJ
0-Bt!
1-02
1 1-el
11-83
u-ec
10-00
4-0<2
12-79
12-80
/-7a
1-U«
11-79
ll-8b
1-81
3-79
3-79
I-//
fa- 78
0-83
0-85
3-/9
2-/9
11-/9
4-80
10-/b
7-73
3-80
b-86
b-85
8-7«
4-8.1
1-82
10-77
10-63
11-/2
8-72
2-73
8-78
fa-80
12-b8
11-71
9-75
10-81
B-7b
12-77
12-78
1-81
1. OPERATIONAL UNITS
3. UNITS UNDER CONSTRUCTION
3. PLANNED - CONTRACT AWARDED
4. PLANNED - LETTER OF INTENT SIGNED
5. PLANNED - REQUESTING/EVALUATING BIDS
6. CONSIDERING ONLY FGO SYSTEMS
7. CONSIDERING FGD SYSTEMS AS WELL AS ALTtHNATIVE MtTHODS
a
a
b
n
A
t)
rj
t)
U
b
A
A
A
A
A
A
A
H
B
«
a
ri
H
c
A
A
C
b
b
A
A
A
C
A
A
A
A
H
b
C
B
b
b
H
C
A
6
H
B
H
A. BOILER CONSTRUCTED SUBJECT TO FEDERAL NSPS
B. BOILER SUBJECT TO STATE STANDARD THAT IS MORE STRINGENT THAN THE FtDERAL NSPS
C. BOILER SUBJECT TO STATE STANDARD THAT IS EUUAL TO OR LESS STRINGENT THAN NSPS
0. OTHER
E. REGULATORY CLASS UNKNOWN
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
COMPANY NAME
SECTION 1
SUMMARY LIST OF FGO SYSTEMS
UNIT NAME
REb
S1AK1 UP OATt STATUS CLASS
LOUISVILLE GAS * ELECTRIC
LOUISVILLE GAS & ELECTRIC
LOUISVILLE GAS & ELECTRIC
LOUISVILLE GAS & ELECTRIC
MINNESOTA POWER & LIGHT
MINNKOTA POWER COOPERATIVE
MONTANA POWER
MONTANA POWER
MONTANA POWER
MONTANA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEVADA POWER
NEW ENGLAND ELEC SYSTEM
NIAGARA MOHAWK POWER COOP
NORTHERN INDIANA PUB SERVICE
NORTHERN INDIANA PUB SERVICE
NORTHERN INDIANA PUB SERVICE
NORTHERN STATES POWER
NORTHERN STATES POWER
NORTHERN STATES POWER
NORTHERN STATES POWER
OTTER TAIL POWER
PACIFIC GAS AND ELECTRIC
PACIFIC GAS AND ELECTRIC
PACIFIC POWER & LIGHT
PENNSYLVANIA POWER
PENNSYLVANIA POWER
PENNSYLVANIA POWER
PHILADELPHIA ELECTRIC
PHILADELPHIA ELECTRIC
PHILADELPHIA ELECTRIC
PHILADELPHIA ELECTRIC
POTOMAC ELECTRIC POWER
POWER AUTHORITY OF NEW YORK
PUBLIC SERVICE OF INDIANA
PUBLIC SERVICE OF NEW MEXICO
PUBLIC SERVICE OF NEW MEXICO
PUBLIC SERVICE OF NEW MEXICO
PUBLIC SERVICE OF NEW MEXICO
SALT RIVER PROJECT
SALT RIVER PROJECT
SALT RIVER PROJECT
SAN MIGUEL ELECTRIC COOP
SEMINOLE ELECTRIC
SIKESTON BOARD OF MUNIC. UTIL.
SOUTH CAROLINA PUBLIC SERVICE
SOUTH CAROLINA PUBLIC SERVICE
SOUTHERN ILLINOIS POWER COOP
SOUTHERN ILLINOIS POWER COOP
SOUTHERN INDIANA GAS & ELEC
SOUTHERN MISSISSIPPI ELECTRIC
SOUTHERN MISSISSIPPI ELECTRIC
1. OPERATIONAL UNITS
8. UNITS UNDER CONSTRUCTION
3. PLANNED - CONTRACT AWARDED
MILL CREEK 2
MILL CHEEK 3
MILL CREEK a
PADDYS RUN 6
CLAY BOSWELL 4
MILTON R. YOUNG 2
COLSTR1P 1
COLSTRIP i.
COLSTRIP 3
COLSTKIP 4
HAKKY ALLEN 1
HAKRY ALLEN 2
HARRY ALLEN 3
HAKKY ALLEN 4
KEIO GARDNER 1
RtID GARDNER 2
REID GARDNER 3
REID GAKDNEK 4
WARNER VALLEY 1
WARNEK VALLEY 2
BRAYTON POINT 3
CHARLES R. HUNTLEY 6
BAILLY 7
BAILLY 6
DfcAN H. MITCHELL 11
SHERBURNE 1
SHERBUKNE 2
SHERBUHME 3
SHERBURNE 4
COYOTE 1
FOSSIL 1
FOSSIL 2
JIM BRIDGER 4
BRUCE MANSFIELD 1
BKUCfc MANSFIELD 2
BRUCE MANSFIELD 3
CROMdY
EDDYSTONE 1A
EDOYSTONE IB
EDDYSTONE 2
OICKERSON 4
ARTHUR KILL PLANT
GIBSON 5
SAN JUAN 1
SAN JUAN 2
SAN JUAN 3
SAN JUAN 4
CORONADO 1
CORONAOO 2
CORONADO 3
SAN MIGUEL 1
SEMINOLE 1
SIKESTON POWER STATION
WINYAH 2
WINYAH 3
MARION 4
MARION 5
A. B. BROWN 1
R. D. MORROW 1
R. D. MORROW 2
4. PLANNED - LETTER OF INTENT SIGNED
5. PLANNED - REQUESTING/EVALUATING BIDS
fa. CONSIDERING ONLY FGD SYSTEMS
7. CONSIDERING FGD SYSTEMS AS WELL AS ALTERNATIVE METHODS
*
i-Bd
8-78
7-81
4-73
5-80
9-77
11-75
B-7b
7-80
7-el
6-85
6-86
6-87
6-08
4-74
4-74
7-76
0-83
6-04
6-85
U- 0
0-80
U- 0
0- 0
11-76
3-76
4-77
5-84
0-87
5-81
0-85
0-86
9-79
4-76
7-77
4-80
6-80
9-75
6-80
6-80
5-85
11-84
0-82
4-78
8-78
6-79
1-82
2-79
1-80
0-87
6-BO
6-83
6-81
7-77
5-80
9-78
0-84
4-79
8-78
2-79
3
1
2
1
2
1
1
1
3
3
6
6
6
6
1
1
1
6
6
6
7
3
6
6
1
1
1
4
4
2
6
6
2
1
1
2
6
1
4
6
6
7
5
1
1
3
3
2
2
6
2
6
2
1
3
2
6
2
1
2
B
B
0
C
A
b
A
A
B
B
A
A
A
A
A
C
C
C
C
C
ri
B
b
B
A
B
B
B
d
B
B
t)
B
B
d
0
B
A
B
B
b
B
B
d
B
A. BOILER CONSTRUCTED SUBJECT TO FEDERAL NSPS
B. BOILER SUBJECT TO STATE STANDARD THAT IS MORE STRINGENT THAN THE FEDERAL NSPS
C. BOILER SUBJECT TO STATE STANDARD THAT IS EQUAL TO OR LESS STRINGENT THAN NSPS
D. OTHER
E. REGULATORY CLASS UNKNOWN
-------
EPA UTILITY FGD SUKVEY: OCTOBER 1978 - NOVtMbEK 1978
SECTION 1
SUMMARY LIST OF FGO SYSTEMS
COMPANY NAME
SOUTHWESTERN ELECTRIC POWER
SPRINGFIELD CITY UTILITIES
SPRINGFIELD MATER LIGHT & PWR
ST. JOE ZINC
TAMPA ELECTRIC
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TENNESSEE VALLEY AUTHORITY
TEXAS MUNICIPAL POWER AGENCY
TEXAS POWER & LIGHT
TEXAS POWER & LIGHT
TEXAS POWER & LIGHT
TEXAS UTILITIES
TEXAS UTILITIES
TEXAS UTILITIES
TEXAS UTILITIES
TEXAS UTILITIES
TEXAS UTILITIES
UTAH POWER & LIGHT
UTAH POWER & LIGHT
UTAH POWER & LIGHT
VIRGINIA ELECTRIC * POWER
WISCONSIN POWER & LIGHT
UNIT NAME
HENRY tt. PERKEY 1
SOUTHWEST 1
OALLMAN 3
&. F. WEATUN 1
BIG bEND 4
JUHNSONVILLE
PARADISE 1
PARADISE 2
SHAWNEE 10A
SHAWNEE 10B
WIDOWS CREEK 7
WIDOWS CREEK 8
GIBBONS CREEK 1
SANDOW 4
TWIN OAKS 1
TWIN OAKS 2
FOREST GROVE 1
MARTIN LAKE 1
MARTIN LAKE 2
MARTIN LAKE 3
MARTIN LAKE 4
MONTICELLO 3
EMERY 1
EMERY 2
HUNTINGTON 1
MT. STORM
COLUMBIA 2
STAHT UP DATE
2-84
4-77
7-80
12-78
0-85
0-82
0-82
0- 0
4-72
4-72
10-80
b-77
1-82
7-BO
8-83
9-84
0-81
8-77
5-78
12-78
8-50
5-78
1-79
6-80
5-78
0- 0
1-80
STATUS
3
1
2
2
6
6
5
5
1
1
2
1
3
3
b
6
5
1
1
2
3
1
2
2
1
7
3
REG
CLASS
A
A
A
H
A
c
c
c
c
c
c
c
A
A
A
A
A
A
A
A
A
A
A
A
A
C
A
1. OPERATIONAL UNITS
a. UNITS UNDER CONSTRUCTION
3. PLANNED - CONTRACT AWARDED
4. PLANNED - LETTER OF INTENT SIGNED
5. PLANNED - REQUESTING/EVALUATING BIDS
6. CONSIDERING ONLY FGO SYSTEMS
7. CONSIDERING FGO SYSTEMS AS WELL AS ALTERNATIVE METHODS
A. BOILER CONSTRUCTED SUBJECT TO FEDERAL NSPS
B. BOILER SUBJECT TO STATE STANDARD THAT IS MORE STRINGENT THAN THE FEDERAL NSPS
C. BOILER SUBJECT TO STATE STANDARD THAT IS EQUAL TO OR LESS STRINGENT THAN NSPS
D. OTHER
E. REGULATORY CLASS UNKNOWN
-------
EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 1978
UNIT IDENTIFICATION
SECTION 2
STATUS OF FGD SYSTEMS
CURRENT STATUS
ALABAMA ELECTRIC COOP
TOMBIGBEE £
225 MM - NEN
COAL; 1.15X SULFUR
PEABODY PROCESS SYSTEMS
LIMESTONE
STARTUP 9/78
REFER TO SECTION 3 OF THIS KEPOHT FOK ADDITIONAL INFOKMATItlN. PEABUUY
PROCESS SYSTEMS WAS AWARDED A CONTRACT FOR THE IiMS IALLA1 IUiM OF A LlUt-
STONE FGD SYSTEM ON THIS UNIT. A HIGH-EFFICIENCY ESK INSTALLED UPSIKhAM UF
THE FGO SYSTEM PROVIDES PRIMARY PARTICULATE CONIROL. THE FGO SYSTEM CUR-
TAINS TWO SCRUBBING TRAINS, TREATING APPRUX1MAttLY 70X UF THE FLUE GAS FUK
REMOVAL OF S02. STACK GAS REHEAT IS NUT REOU1KED. THE UNIT IS CURRENTLY IN
THE SHAKEDOWN-DEBUGGING PHASE OF OPERATIONS.
ALABAMA ELECTRIC COOP
TOMBIGBEE 3
225 MH - NEH
COAL; i.isx SULFUR
PEABUDY PROCESS SYSTEMS
LIMESTONE
STARTUP 6/79
PEABODY PROCESS SYSTEMS HAS BEEN AWARDED A CUNTKACT FUK THE INSTALLATION
OF A LIMESTONE FGO SYSTEM ON IHIS UNIT. A HIGH-bFUC 1 ENCY ESP "ILL
BE INSTALLED UPSTREAM UF THE FGO SYSTEM TO PROVIDE PKIMAKY
PARTICULATE CONTROL. THE FGO SYSTEM CONSISTS UF FwO TWAINS, TOGETHER
TREATING APPROXIMATELY 70X OF THE FLUE GAS FOR REMOVAL UF SULFUK
DIOXIDE. STACK GAS REHEAT WILL NOT BE REUUIKED. CUNSTRUU10N ON THE UNIT
TURBINE AND BOILER IS NOW SOX COMPLETE.
ALLEGHENY POWER SYSTEM
PLEASANTS 1
625 MM - NEN
COAL; o.sx SULFUR
BABCOCK & WILCOX
LIME
STARTUP 3/79
THE THREE PRINCIPAL OPERATING UTILITY CUMPANIES OF THE ALLEGHENY PUwEK
SYSTEM ARE INSTALLING AN EMISSION CONTROL SYSTEM FOR THIS NEW CUAL-FIKEU
UNIT WHICH INCLUDES A HIGH EFFICIENCY ESP UPSTkEAM OF FUUK TRAY TUWEKS
FOR THE CONTROL OF PAHTICULATES AND SULFUK DIUXIOE. DESIGN RfcKOVAL
EFFICIENCIES FOR THIS EMISSION CONTROL SYSTEM ARE V9.5 AND 90 PERCENT
RESPECTIVELY. THE DRAVO CO. IS SUPPLYING THIOSORdIC LIME. THt CUNSULTING
ENGINEERING FIRM IS UNITED ENGINEERS AND CONSTRUCTORS. CURKENTLY, EREC-
TION OF THE SCRUBBING EUUIPMENT IS IN PROGRESS.
ALLEGHENY POWER SYSTEM
PLEASANTS 2
625 MM - NEW
COAL; 4.5X SULFUR
BABCOCK S WILCOX
LIME
STARTUP 3/80
THE THREE PRINCIPAL OPERATING UTILITY CUMPANIES OF I HE ALLEGHENY POWER
SYSTEM ARE INSTALLING AN EMISSION CONTROL SYSTEM FOR THIS NEW CUAL-F IKKI)
UNIT WHICH INCLUDES A HIGH EFFICIENCY ESP uPSTRtAM UF FUUR TKAY TUwEkS
FOR THE CONTROL OF PARTICIPATES AND SULFUR DIOXIDE. DESIGN REMOVAL
EFFICIENCIES FOR THIS EMISSION CONTROL SYSTEM ARE 99.b AND 90 PERCENT,
RESPECTIVELY. THE DRAVO CO. IS SUPPLYING TH10SOK8IC LIME. THE CONSULTING
ENGINEERING FIRM IS UNITED ENGINEERS AND CONSTRUCTORS. CURRENTLY, FOUNDA-
TION WORK ON THE SCRUBBER PLANT IS IN PROGRESS.
ARIZONA ELECTRIC POWER COOP
APACHE 2
200 MM - NEN
COAL; 0.7X SULFUR, iox ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 8/76
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION. THE FGD
SYSTEM FOR THIS NEW 200 MW UNIT WAS SUPPLIED BY RESEARCH CUTTRELL. THE
DESIGN INCLUDES A 22 ACRE SLUDGE POND AND A 64 ACKE ASH PUND, BUTH [IF
WHICH ARE UNLINED AND TEN FEET DEEP. A KEHEAT SYSTEM IS NUT INCLUDED. THE
LINERS USED IN THE STACK AND THE DUCTS THAT LEAD TO THE STACK AKE A NE*
COLE BRAND CXL2000 WHICH HAS A VERY HIGH HEAT RESISTANCE. THIS UNIT BURNS
BITUMINOUS COAL WITH SULFUR AND ASH CUNTENTS OF .7X AND IOX RESPECTIVELY.
INITIAL OPERATION OF THIS UNIT BEGAN IN AUGUST, 1970.
ARIZONA ELECTRIC POWER COOP
APACHE 3
200 MW • NEN
COAL; o.?x SULFUR, iox ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 4/79
CONSTRUCTION OF UNIT 3 IS NOW ESSENTIALLY COMPLETE. STRUCTURE
ERECTION OF THE SCRUBBER-ABSORBER TOWERS IS COMPLETE. EACH SCRUBBER CAN
HANDLE 400,000 ACFM o> 270 F AND RECIRCULATE 20,000 GPM OF SLURRY. HUILER
CONSTRUCTION HAS BEGUN. THERE ARE CURRENTLY 2 PONDS WITH A TOTAL OF 20-
YRS CAPACITY FOR THE DISPOSAL OF THE UNFIXATEO SLUDGE. 2 ADDITIONAL PONDS
ARE PLANNED PROVIDING AN ADDITIONAL 20 YRS OF DISPOSAL CAPABILITY. THERE
WILL BE NO REHEAT. BECAUSE OF THE HIGH COST OF THE UNIT 2 STACK UNEK,
UNIT 3 WILL USE A CEILCOTE LINING INSTEAD OF THE CXL2000 USED IN UNIT 2.
ARIZONA PUBLIC SERVICE
CHOLLA 1
115 MW • RETROFIT
COAL; o.ssx SULFUR, iox ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 10/73
REFER TO SECTION 3 OF THIS REPORT FUK ADDIIlUNAL INFUKMATIUN.
THIS LIMESTONE SCRUBBING SYSTEM WAS PLACED IN SERVICE IN OCTOBER 1973.
THE SCRUBBER PLANT CONSISTS OF TWO PARALLEL SCRUBBING TRAINS. PARTICU-
LATE CONTROL IS PROVIDED BY TWO FLOOOEO-DISC SCRUBBERS. S02 CONTROL IS
PROVIDED BY ONE PACKED (MUNTERS PACKING) TOWER IA-SIOE). FLUE GAS CLEAN-
ING WASTES ARE DISCHARGED TO AN EXISTING FLY ASH POND. NO WATER IS Kt-
CYCLED BACK FROM THE DISPOSAL POND. IN-LINE STEAM KEHEATERS RAISE THt
GAS TEMPERATURE 40 F.
ARIZONA PUBLIC SERVICE
CHOLLA 2
250 MW - NEW
COAL; o.ssx SULFUR, iox ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 4/78
REFER '- SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
THE CONTRACT FOR THIS WET LIMESTONE SCRUBBING SYSTEM WAS AWARDED BY THE
UTILITY TO RESEARCH-COTTRELL. THE DESIGN INCLUDES MECHANICAL COLLECTORS
FOR PRIMARY PARTICULAR REMOVAL. THE FGU SYSTEM CONSISTS OF FOUR PARALLEL
FLOODEO-OISC AND PACKED TOWER ABSORBER TRAINS. THREE ARE REQUIRED FUR FULL
LOAD CAPACITY. INITIAL OPERATIONS BEGAN IN JUNE 1978. COMPLIANCE TESTING
WAS COMPLETED OUR1NS THE SECOND WEEK UF AUGUST 1978. THE UNIT IS CURRENTLY
UNDERGOING SHAKEDOWN AND DEBUGGING OPERATIONS.
-------
EPA UTILIIT FGD SOKVEY: UCIUbtK l-»7rt -
14/ri
SECTION e
STATUS OF FGU SYSTEMS
UNIT IDENTIFICATION
CURRENT SIATlJb
ARIZONA PUBLIC SEKVICE
CHOLLA 4
350 MW - NEH
COAL; o.?x SULFUR
RESEARCH COTTRELL
LIMESTONE
STARTUP 6/80
UNI! NO. 4 IS CURRENTLY UNDER CON!) 1KUC HUN. AKb HAb AMKDtD If^ Fu.ll Cuu-
TRACT TO RESEARCH COTTHELL. THE STATE REGULAIUF.Y AGENCY hAb NUT Yt I ut-
CIUEO THE EMISSIONS REGULATIONS WHICH WILL APHLY )u Iht J-LA^l. IHt U-t
BOILER WILL FIkE THE SAME COAL AS CHOLLA ,xO. 1, *11H bliLFUK LUfjJt*! OF
0.44-1.0 PERCENT. THt A-E FIRM IS tBASCO. TMfc FbJ SYblFM IS A IHJUrtLt LUOf
LIMESTONE ABSORPTION PROCESS ANO REVENUES OF iHh. LnuTRACT lu h-C A.U
REPORTED TO BE $5 MM. FOR CONTROL OF PARTICULAlt AN tbP flli. HAMJLt H'UZ
OF THE FLUE GAS.
ARIZONA PUBLIC SERVICE
FOUR CORNERS 1
175 MM • RETROFIT
COAL; o.rx SULFUR, 23.ox ASH
CHEMICO/APS
LIME/ALKALINE FLYASH
STARTUP 0/79
APS IS UPGRADING THE OPERATIONAL PARTlCOLAIt bCRUrtHtKb AT THt FUUK
CORNERS 1, 2 ANO 3 FOR ADDITIONAL Sod REMOVAL. LOHRtMLY, FACH il«II HAS e.
CHEMICO VENTURI SCRUBBER MODULES FOK HAHTlCuLATt CONTROL. KUIK.HLY Jui. UF
THE FLUE GAS 802 CONTEM IS HEMOVtD AT THE PKEbt'Jl I IMF lu THE VH.TuxlS
WITH THE HIGH ALKALINE FLYASH. NEW MF.X1CO ARC UFFICAL5 IfiOlCAIED THAT
THE 5 FOUR CORNERS UNITS WILL BE REUUIREu To KthuVfc AT LtASI b7.bi OF 1HF
STATION SOU (ALL 5 UNITS CONSlOERtO TOGETHER). Al)i> I I IDivAL ALKALINITY rtlLL
BE IMPARTED TO THE SCROBBlNG SOLUTION Br ADOlNb
ARIZONA PUBLIC SERVICE
FOUR CORNERS 2
175 MH - RETROFIT
COAL; o.?x SULFUR, 23.ox ASH
CHEMICO/AP3
LIME/ALKALINE FLYASH
STARTUP 0/79
APS IS .JPUHADI^G THE OPERATIONAL PJftT ' CL'L ATE SChUrtdEwa «l Tilt FUu«
CORNERS UNIT .'IOS. 1. 2 ANO 3 FOR ADO" IONAL SOd REMOVAL. tACH UNIT H«i> t
CHEMICO VENTURI SCRUBBER MOOULES FOh HARFICULAlh CO^lKOL. RUUUHLY iOX ciF
THE FLOE GAS S02 CONTENT IS REMOVED AT THE PRESENl IIME IN THE VEnTUKli,
WITH THE HIGH ALKALINE FLYASH. NEW MEXICO APC OFFICALb 1NOICAIEI) 1HA1
THE 5 FOUR CORNERS UNITS MILL BE REUOIREO Fj REMOVd Al LFAS1 67.b^ (IF I MR
STATION SOi (ALL 5 UNITS, CONSIDERED TOGETHtR). AUOIFONAL *LnALInllT .tlLL
BE IMPARTED TO THE SCRUBBING SOLUHUN HY ADOINb
ARIZONA PUBLIC SEKVICE
FOUR CORNERS 3
229 MM - RETROFIT
COAL; o.7x SULFUR* 23.ox ASH
CHEMICO/APS
LIME/ALKALINE FLYASH
STARTUP 0/79
APS IS UPGRADING THE OPERAIlONAL PAHIICULAIE bCNUbrttKb Al Int FUUK
CORNERS UNIT NOS. 1, 2 ANO 3 FOR ADDITIONAL SU£ KtMOvAL. tAC" nr/ll HAb e
CHEMICO VENTURI SCRUBBER MODOLES FOK PAKTICOLATE C.OMKOL. ROUbnLY iu* UK
THE FLUE GAS S02 CONTENT IS REMOVED Al 1 ME HrfESt.xT TI.-E In 1HE vbNluwIb
WITH THE HIGH ALKALINE FLYASH. NEtt MEXICO APC UFFICALS INDICATED THAT
THE S FOUR CORNERS UNITS rtlLL BE HEOUIRED IO Rf^OVE Al LEAbl h/.bX OF fHF
STATION S02 (ALL 5 UNITS CONSIDERED TOGETHER). AOUMIUNAL ALKALINITY nRL
BE IMPARTED TO THE SCRUBBING SOLUTION BY ADDING LIME.
ARIZONA PUBLIC SERVICE
FOUR CORNERS 4
755 MN - RETROFIT
COAL; 0.7% SULFURf 23.ox ASH
UNITED EN6INEERS
PROCESS NOT SELECTED
STARTUP 0/62
THE UllLIfV IS CURRENfLY EVALUAllNG IHE !>AIA »Nl/ livf" J«f A I IU.M ACCUMuLAIEu
DURING THE HORIZONTAL PROTOTYPE SChUBH!
-------
EPA UTILITY FbO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 2
STATUS OF FGO SYSTEMS
UNIT IDENTIFICATION
CURRENT STATUS
BASIN ELECTRIC POWER COOP
ANTELOPE VALLEY 2
455 MW - NEW
LIGNITE; 0.681 SULFUK, 8X ASH
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 11/83
TMfc UTILITY IS TENTATIVELY INVESTIGATING VARIOUS FGl) PROCESSES FOR THIS
SECOND LitNITE-HKEU UNI! SCHEDULED AT IHt NEW STATION LOCATED IN MEKCtK
COUNTY, NEAR BEULAH, NORTH DAKOTA. THIS NEW FACILITY WILL BE KNOWN AS
THE ANTELOPE VALLEY STATION AND WILL BE REuUIREU 1U COMPLY WITH STATE AIK
EMISSION STANDARDS VIA THfc BtS! AVAILABLE TECHNOLOGY. STAKT-UP IS NUrt
SCHEDULED FOR NOVEMBER 1963.
BASIN ELECTRIC POWER COOP
LARAM1E RIVER 1
570 MW - NEW
COAL; o.ex SULFUR, TZ ASH
RESEARCH COTTRELL
LIMESTONE
STARTOP 4/80
RESEARCH-C01THELL IS CuRftENlLY FABKICAI1NG I HE OOAL-LuOK LIMES1UNE WE I
SCRUBBERS. ON-SITt CONSTRUCTION COMMENCED IN JANUARY 1978. SLUDGfc WILL BE
DEWATEREO TO B3X SOLIDS BEFORE LANDFILL. 1HE SCKUBBERS WILL BE MADE OK
SIAlULtSS STEtL AND WILL HANDLE c!.3 MM ACFM AT 286 F. L/G RATIO WILL HE
60. B&W HAS BEEN AWARDED A CONTRACT FOR TWO tSP'S. IHb DESIGN DOES NO!
INCLODE STACK GAS HEHEAI. COOLING TOWEK SLOWDOWN WILL BE USED FUR MAKE-UP
IN THIS CLOSED LOOP SYSTEM. CONSTRUCTION IS NOW 201 COMPLETE.
BASIN ELECTRIC POWE* COOP
LARAMIE RIVER 2
570 «« - NEW
COAL; o.ex SULFUR, 7t ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 10/80
ftt&ESKCH-COTTRELL IS CURRENTLY FABRICATING 1 ME DUAL-LUOP LlnEaTONE w£1
SCRUBBERS. ON-SITE CONSTRUCTION CUMf-ENCEl) IN JANUARY 1978. SLUDGE WILL BE
L.C«A i*EU TO 83X SOLIDS BEFORE LA.JOFILL. THE SCKUB8ERS WILL BE MADE OF
STAINLESS STEEL ANO WILL HANDLE 2.3 MM ACFM AT 286 F. L/G RATIO ttlLL HE
60. B&w HAS BEEN AWARDED A CONTKACT FOR ! WO ESP'S. THE UfcSIbN DOES NO!
INCLUDE STACK GAS RhHEAl. COOLING TOWtR SLOWDOWN WILL BE USED FUR MAKE-UP
IN THIS CLOSED LOOP SYSTEM. CONSTRUCTION IS NOW 20X COMPLETE.
BASIN ELECTRIC POWER COOP
LARAMIE RIVER 3
550 MW - NEW
COAL; 0.8X SULFUR, 7X ASH
BABCOCK S HILCOX
PROCESS NOT SELECTED
STARTUP 4/82
LARAMIE RIVER STATION WILL FIRE SUB-BITUMINUUS COAL WITH THE FOLLOWING
CHARACTERISTICS: 8100 BTU/LB, O.tt PERCENT SULFUR AND 7.0 PERCENT ASH. A
CONTRACT FOR A DRY TYPt FGD SYSTtM HAS BEEN AWARDED TO BABCOCK & WlLCUX.
BI6 RIVERS ELECIKIC
GREEN 1
250 MH - NEw
COAL; 3.75X SULFUR
AMERICAN AIR FILTER
LIME
STARTUP 12/79
THE EMISSION CONTROL SYSTEM FOR THIS NEW COAL-FIREO UMI IS BEING SUP-
PLIED BY AMERICAN AIR FILTER. THE SYSTEM WILL CONSIST OF A COLO-SIDE ESP
AND TWO SPRAY TOWERS CONTROLLING PARTICULATE ANO S02 TO 99.6 PERCENT AND
90 PERCENT, RESPECT1VLEY. THE B&W BOILER WILL FIRt HIGH SULFUR 13.5 Tu
4.5 PERCENT) WESTERN KENTUCKY COAL. CONSTRUCTION IS NUh 66X
COMPLETE ON THE BOILER ANO 3
-------
EPA UTILITY FbO SURVEY: OCTOBER IS/fi - NUV b ^r>e R
SECTION e!
STATUS OF FGD SYSTEMS
UNIT IDENTIFICATION
COKHEl.T STATUS
CENTRAL ILLINOIS PUBLIC SERV
NEWTON 1
575 MW - NEW
COAL; 4X SULFUR
BUELL/ENVIROTECH
DOUBLE ALKALI
STARTUP 11/79
A CONTRACT HAS BEEN AnAROED HY CIPSCO TU BUELL/E N V I HI) I fc;CH FOR Tue
INSTALLATION OF AN EMISSION CONTwnc SYSTEM ON UNtl 1. I HE >• t Y COM-
PONENTS UF THE EMISSION CUNIRUL SYSTEM luLLUDt: A H1GH-EFFICItNCY EbP;
FOUR PRECOULERS, FOOK PULYSPHERE ABbLKljtRb, THuEE THICK t'.tKb, T.-.o EX-
PERIMENTAL REHEAT SYSTEMS, AND THKEE HURI/U'ITAL EXTKACI ION FILTERS HIK
SLUDGE DEftATEKlfJb. MOKE THAN bO PERCEM ilF I HE CuivS t ROC T I'JN ftURK.
AT THE PLANT HAS MEEN COMPLETED. THE FI,IJ bYbit* *ILL HAVE CEILCOTE-
LINED ABSORBER MODULES.
CENTRAL MAINE POWER
SEARS ISLAND 1
600 MW - NEW
COAL; SOURCE UNDETERMINED
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 11/86
BECAUSE OF THE DISCOVERY OF A GEllLOl, I C AL FAOLI 0"J StARS ISLAND, THE
UTILITY HAS CANCELLtO PLANS FOR A HbU-r-., NUCLEAR Ki,,-,tR PLANT. A
600-Mrt COAL-FiKfcD UNIT IS NOW BE I hi, PLANNED In ITS PLACE. CO'- ME RCI AL
OPERATION IS PROJECTED FUK NOVEMBER l^db. COMPLIANCE .'.ITH SU£ NbPb ,11L L
BE ACHIEVED BY INSTALLING AN FGD SYSTEM. L1.- E ANiJ L I'-.ES TOi.. CUrtntNfLY, CMPCO HAa
FILED AN APPLICATION rtllH THE SIATE PUBLIC OIILUIcb COMMISSION. AN tu-
VIKUNMENTAL PEKMIT APPLICATION rtILL 'it FILED .'. 1 I n [ w THE Nt»l UO YtAi-'b.
CINCINNATI GAS & ELECTRIC
EAST BEND 2
600 MW - NEW
COAL
BABCOCK & WILCOX
LIME
STARTUP 1/81
A CONTRACT HAS BEEN CONO I TIONALL Y AWARDED TO r»AbCUCi\ AND AlLCUX F UK A
COMMERCIAL LIME SCKOddI'MG SYSTEM. IHE COAL bOOKCF. IS txPECTcD TU Bt A
WESTERN KENTUCKY COAL rtlTH A HIliM SULFUK CO^ftM. THE THKeE LI.'-iE SLUKHY
FGO MODULES ftlLL 8E PRECEDED BY Hit ESP FOK PAKTIUULATt COnTKOL. A COHlKACT
HAS BEEN CONDITIONALLY AWARDED TO IUCS FOR THE SLODGt FIXATION. THK A-t
FIRM IS SARGENT AND LUNDY. UfJlT FOONJAT IO.J Clli.S T ROC I I Of. HAS rt£(,UN AND
FGO SYSTEM CONSTRUCT loh «1LL BEGIN IN tAHLY IS/9.
CULUKADU UIE ELECIRIC ASSN.
CRAIG 1
450 MW - NEW
COAL; o.4sx SULFUR
PEABODV PROCESS SYSTEMS
LIMESTONE
STARTUP 3/79
COLORADO UTE ELECTRIC ASSN.
CRAIG 2
450 MW - NEW
COAL; 0.45X SULFUR
PEABOOY PROCESS SYSTEMS
LIMESTONE
STARTUP 3/79
COLUMBUS & SOUTHERN OHIO ELEC.
CONESVILLE 5
400 MM - NEW
COAL; 4.7X SULFUR, 15.IX ASH
AIR CORRECTION DIVISION, UOP
LIME (MG-PROMOTED)
STARTUP 1/77
PEABOOY PROCESS SYSIEMb HAb BEEN AWARDED A CimlxACI lu DEsIG'. Ann
SOPPLY A LIMESTONE SLURRY SPRAY TV.vtR AciSUROtH SYSTEM FUR 502 KEMOVAL
FROM LUW-SULFUH COAL-FIRED BOILER FLUE GAS FOK U'.'lTb 1 AMU
-------
EPA UTILITY F6D SURVEY: OCTOBER 1978 - NOVEMBER 1978
UNIT
SECTION 2
STATUS UF FGD SYSTEMS
IDENTIFICATION CURRENT STAlUS
COLUMBUS & SOUTHERN OHIO ELEC. THIS UNIT WILL BURN HIGH SULFUR CuAL I APPRO* IMA TEL Y !, UNE OF I .Ml
IDENTICAL BOILERS SUPPLYING STEAM TO AN HbO-MW 1UKrtlNt-Gt "*KATOK. TnK
SLUDGE HILL BE STABILIZED AND HAOLED TO A LANDFILL. HtntA! WILL Hfc
PROVIDED BY A STEAM COIL WHICH WILL HtAT THE AMBIENT AIK THAT IS HUHPtli
INTO THE SCRUBBER OUTLET BEFORE THE FLUE GAS ENTERS iHb SUCK. THfe SOrf
EMISSION S1ANDARD IS 1.8 LB. SOa/MM tjTO. CURRtMLY, EXCAVATION, 'UCKFlLL,
AND STRUCTURAL STEEL ERECTION IS IN PROGRESS.
COOPERATIVE POWER ASSOCIATION
COAL CREEK 1
545 MH - NEW
LIGNITE! 0.63X SULFUR
COMBUSTION ENGINEERING
LIME
STARTUP 2/79
THIS UNIT IS UNDER THE COMBINED OWNERSHIP OK COOP POWER AND ONIltD
A CONTRACT HAS BEEN AWARDED TO COMBUSlIUN ENGINEERING FOR THE INSIALLA-
TION OF LIME FGD SYSTEMS ON OMTS 1 AND i Al THIS STAllUlv. THE F(,0 SYSlfcM
FOR EACH BOILER WILL CONSIST UF FOUR SPRAY HlwtR AdSORStk MODOLfcS KOR S0i>
REMOVAL. ELECTROSTATIC PRECIPITATURS WILL BE INSTALLED UPSTREAK UF EACH
ABSORBER TRAIN. CONSTHOCTION bEGAN EARLY IN AUGOS! 1977. THE DMT IS hi Off
85-90X COMPLETE. BAD WINTER WEATHER SLOWED CONSTKUCUUN SLIGHTLY.
COOPERATIVE POWER ASSOCIATION THIS UNIT IS UNDER THE COMBINED OWNERSHIP OF COUP POrtER AND UMTt.D HuwER
A CONTRACT HAS BEEN AWARDED TO COMBOSIIUN ENGINEERING FUR THfc INMALLA-
OF LIME FGD SYSTEMS UN UNITS 1 AND i. AT THIS STATION. TnE F-bD SYSTEM F-uK
EACH BOILER WILL CONSIST OF FUUR SPRAY TOWER AHSOhBER MODULES FOR SUe
REMOVAL. ELECTROSTATIC PRECIP1 T A TORS WILL tit INSTALLl-.O UPSTKtAf Cit- EACH
ABSORBER TRAIN. CONSTRUCTION BEGAN IN AUGUSI 19/7 AND THE UNIT is NOW <4t>*
COMPLETE. THERE HAVE BEEN MINOR DELAYS BUI START-UP IS STILL SCHEDULED FUR
NOVEMBER 1979.
DELMARVA'S DELAWARE CITY PLAN I HAS a BOILERS, i OF wnlCH HAVE SIEAM CAPA-
CITIES OF 500K LBS/HK EACH. THE BUILEKS GENtRAU STEA* AS WELL AS ELKCTKI-
CAL POWER FOR GETTY REFINING « MARKETING. 7-8i S COKE WILL BE HORNEU IN
THE BOILERS (INSTEAD OF THE LOW-S CRUDE OIL NOW HURNED) wHtN THE COufHUL
SYSTEM GOES INTO OPERATION IN APRIL 1980. DELMARVA WILL USE VENTIJRI SCRUB-
BERS FOR PARTICULATE REMOVAL AND WELLMAN LORD FGD SYSTEMS AT EACH rtUlLER
GAS EXIT FOR S02 CONTROL. DESIGN PAkTICULATt AND SOi REMOVAL EFFICIEN-
CIES ARE 90 AND 85-90 PERCENT RESPECTIVELY. CUNSlKUCTION IS IU COMPLETE.
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
THE FGD SYSTEM ON THIS
-------
tPA UIILITr FGu buwvkY: uciuntK
NuvLi*rtLr
UNIT IDENTIFICATION
SECTION
STATUS OF FtO
SYSTEMS
CUHKENF blAlOb
GENERAL PUBLIC UTILITIES
COHO 1
800 MW - NEW
COAL; 3.5X SULFUR
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 5/88
STARTUP DATE MAS CHANGED TO b/88 FUK BOTH HulLtK 4NU HE SULF UK 1L A T Illu
SYSTEM LIME AND LlMESTurtE SCKUBdING AK£ THE Pnlr-.AKY SIxATtblES rttl'H*
CONSIDERED FOrf COMPLIANCE WITH NEw bounct PtuFUKMariut s> UIVDAKDS. riu
DECISION HAS BEEN MAOh YET, ALTHOUGH A bLUMrtY TYPt sYSTtf IS MM
CONTEMPLATED.
GENERAL PUBLIC UTILITIES
SEWARD 7
800 MM - NEW
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 5/85
STARTUP DATE WAS CHANGED TO b/85 I-ON bUtH BOlLtK AND OES'lLF UK 1/A T [ill,
SYSTEM LIME AND LIMESTONE SCRUBBING AKE THE PKIMAKY blKAttGItS Mtl-il,
CONSIDERED FOR COMPLIANCt WITH Hit, SOUKCt PkHHlNMANCt SlAiiOAKUS. HO
DECISION HAS BEEN MADE YET, ALTHOUGH SLUrtkY [YHfc ft ILL NUT ot DSEU.
GULF POWER
SCHOLZ 1 ft 2
23 MW - RETROFIT
COAL; ax SULFUR, iix ASH
CHIYODA INTERNATIONAL
THOROUGHBRED 121
STARTUP 8/78
REFER TO SECTION 3 OF THIS REPORT FOH ADDITIONAL INF UKMAl 1 Dr.. UHlYUliA h.-
TERNATIONAL SUPPLIED THIS 23 MW PMlTOlYPE uull AHlCH ritb»n oHtKATlin, IM
AUGUST 30, 1978. THE CT-121 SYSTEM INCLUDES A r,t*LY DEVELOPED JET
BUBBLING REACTOR WHICH FEATURES A LAKbE bAS-LlUUlD lulEKFACIAL AKEA AM)
PROVIDES PARTICOLATE AS WELL AS su^ KEMOVAL. »-ibT ELIMINATION ib PKUVIOLU
BY A DOUBLE PASS VERTICAL CHEVKON. GYPSUM IS PKuOUCED AIM!) bUCKED in INK
EXISTING POND. THE STACKING CAPABILITIES OF THt GYPSUM AKt UhIMG Tfcblti)
ALONG WITH THE GHUUNO WATER NEAK THE STAC^ SITE To CHECK FUK Lf.ECH I NI, .
HOOSIER ENERGY
MEROM 1
490 MW • NEW
COAL; 3.sx SULFUR
MITSUBISHI INTERNATIONAL
LIMESTONE
STARTUP 4/81
HOOSIER ENERGY
MEROM 2
490 MW - NEW
COAL; 3.sx SULFUR
MITSUBISHI INTERNATIONAL
LIMESTONE
STARTUP 1/82
INDIANAPOLIS POWER S LIGHT
PETERSBURG 3
530 MW - NEW
COAL; 3.25X SULFUR, 9.5X ASH
AIR CORRECTION DIVISION, UOP
LIMESTONE
STARTUP 10/77
HOOSIER ENERGY AWARDED A CONIKACI lu MITSUBISHI In I t«i»A I IUNAL LUKP.
FOR TWO LIMESTONE FGO SYSTEMS FUK MErtOM 1 AND •. CUAL-t-InKn
UNITS ARE PLANNED FOR LOCATION IN SULLIVAN, INDIANA. IHt FLUh (,A.S b[KK«(-S
WILL BE CLEANED OF PAKTICOLATES WITH ESP'S 194. <4i) AND OF SULHUK i)IuXti)E
WITH GRID-10WEH ABSOHBEKS 190*) . SLUDliE wILL BE SlAolLlZtu Aijij sUCK
PILED. THE GROUND WAS 8KOKEN FOH CONSTKOCTION IN NUVE^HEK 1977, HUT nut
TO THE BAD WlNf£R WEATHER, CONST HOC T IUM WAS OtLAYEO. CUNS TKUC T [Uu HAS
PROCEEDED ACCORDING TO SCHEDOLE THROUGH THE bUMMEK.
HOOSIER ENERGY AWARDED A CONTRACT TO MITSUBISHI IivTtK-iAT IUNAL CUKP.
FOR TWO LIMESTONE FGO SYSTEMS FOR MEKOM 1 AND £. 1 HE I-.E.M ^4U Mrt COAL-HIwtO
UNITS ARE PLANNED FOR LOCATION IN SULLIVAN, INDIANA. Tut FLilt GAS 3 f K t A !•< s
WILL BE CLEANED OF PARTICULATES WITH ESP'S [94.«XJ ANU Oh SULHIK UIn*lDt
WITH GRIO-TOwER ABSORBtHS (90X). SLUDGE «1LL HE STAblLUtU A,IU STuCi\
PILED. THE GROUND WAS BROKEN FOR CONSTKUCTIUN IN NOvEMHtK 1477, Hul nut
TO THE BAD WINTER rttATHER, CONSTRUCTION WAS DELAYED. InE bUILtK IS
ESSENTALLY COMPLETE. STAKTUP IS EXPECTED SHUKILY.
REFER TO SECTION 3 OF THIS REPORT FOH ADDITIONAL INFUKN- A T ION. THt at I
LIMESTONE FGD SYSTEM INSTALLED ON THIS ONIT WAS SUPPLIED BY THE AIx
CORRECTION DIVISION OF UOP. UNIT 3 FIHES BITUMINOUS COAL HAVING A SuLhUK
CONTENT OF 3.0-3.5X, AN ASH CONTENT OF 9-101 AND A ll.OUU HlU/LB MfcATIm.
VALUE. TWO ESPS PROVIDE PRIMARY PARTICOLATE CuMKUL UHSTKEAM OF A rliUK-
MOOULE TCA FGO SYSTEM. STABILIZED SLUDGE IS DISPOSED ON AN Of-,-SlTE
THE DESIGN INCLUDES AN INDIRECT STEAM TUBE KEHEAI SYSTEM.
GING OPERATIONS ARE STILL PRUCEDING.
INDIANAPOLIS PUWER ft LIGHT
PETERSBURG 4
530 MW - NEW
COAL; 3.5X SULFUR, 1UX ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 10/83
INDIANAPOLIS POWER & LIGHI AWAKDEU A CONIKACT iu KESEAKCH CUIIKELL FUK
LIMESTONE FGD SYSTEM. SOa REMOVAL EFFICIENCY rtlLL HE APPKOX IMA 1 tL Y
80 PERCENT. THIS NEW UNIT WILL FIRE Hl&H-SULFUH SUribl I UM l.MUUS COAL «IlH
A HEATING VALUE OF 11,000 8TU/LB AND ASH AND SuLFuR CUNTENTS OF lu
AND 3.5 PERCENT, RESPECTIVELY. SLUDGt WILL bt DtwAIEHtD Ar40 MIXED
FLYASH TO PRODUCE A DRY STABILIZED PROOOCI. EXCAVA T iu>v, FOUNDATION
WORK AND SOME STEEL WORK IS NOW IN PROGRESS ON THE UNIT.
KANSAS CITY POWER ft LIGHT
HAWTHORN 3
100 MW - RETROFIT
COAL; ax SULFUR, u.sx ASH
COMBUSTION ENGINEERING
LIME
STARTUP 11/72
REFER TO SECTION 3 OF THIS REPORT FUR ADOIHoNAL ImFUHMAI lOw.
THE SCRUBBER-ABSORBER SYSTEM ON THIS UNIT WAS CONVEKltO FKOM A LIMESTONE
FURNACE INJECTION AND TAIL-END SYSTEM TO A TAIL-END LIfE SLUHHY SYSTEM.
OPERATION IN THE LIME SCRUBBING MODE COMMENCED UN FEBKOAKY 7, 1977. Cun-
PLIANCE TEST RESULTS INDICATED THE UNIT MEETS THE KANSAS CITY 0.17 Lrt/
MM BTU PARTICULATE REG. FGD SYSTEM DESIGN INCLUDES A FINNtD-TUbE STtAM
REHEATER, AN ON-SITE UNLINED SLUOliE DISPOSAL POND, AND A CrtEVKON HIST
ELIMINATOR SYSTEM. THE Z FGO MOOULES CAN BE BY-PASStO IN EMERGENCIES.
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECT ION i.
STATUS OF FGO SYSTEMS
UNIT IDENTIFICATION
CURRENT STATUS
KANSAS CITY POWER & LIGHT
HAWTHORN 4
100 MM - RETROFIT
COAL; 2X SULFUR, 12.51 ASH
COMBUSTION ENGINEERING
LIME
STARTUP 8/72
REFER TO StCTIUN 3 OF THIS REPORT FOR AODIT10NAL INFORMATION.
THE SCRUBBER-ABSORBER SYSTEM ON THIS UNIT WAS CONVERTED FROM A LIMESTONE
FURNACE INJECTION AtvU TAIL-ENO SYSTEM TU A TAIL-ENO LIME SLURRY SYSTtM.
OPERATION IN THE LIME SCRUBBING MOOt COMMENCtD UN JANUARY 1, 197/. COM-
PLIANtt TEST RESULTS INUlCATbO IHE UNIT MEETS THE KANSAS CITY O.I/ LB/
MM BTU PARTICULATt KtG. FGO SYSlbM OESIGN INCLUDES A HuNEll-TUBE STEAM
kEHEATEW, AN ON-SITE UNLINED SLUObE DISPOSAL POND , ANO A CHEVRON MIST
ELIMINATOR SYSIEM. THE Z FbO MODULES CAN BE BY-PASStO IN EMERbENC IE.S .
KANSAS CITY POWER A LIGHT
LA CYGNE 1
820 MW - NEW
COAL; 5X SULFUR, 25X ASH
BABCOCK « wILCOX
LIMESTONE
STARTUP 2/73
REFER TU SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
THE EMISSION CONTROL SYSTEM FOR THIS NEW COAL-FIRED PuwER-GENERAT1NU UNll
CONSISTS OF EIGHT SCRUBBER MODULES FOR FLY ASH AND 502 REMOVAL. EACH
MODULE INCLUDES A VENTURI SCRUBBtw IN SERIES wITn A 2-STAGE IMPINGEMENT
PLATE ABSORBER. THE SCRUBBER PLANT IS AN INTEGRAL PART UF THE POrtER-
GENERATING COMPLEX, ALLOWING NO FLUE bAS BYPASS. INITIAL OPERATIONS
COMMENCED IN FEB. 1973. COMMERCIAL SERVICE IAS ATTAINED BY JUNE 19/3.
KANSAS POWER & LIGHT
JEFFREY 1
680 MM - NEW
COAL; o.3x SULFUR, 7.sx ASH
COMBUSTION ENGINEERING
LIMESTONE
STARTUP 8/78
REFER TO SECTION 3 UF THIS REPORT FOR ADDITIONAL INFORMATION. COMBUSTION
ENGINEERING SUPPLIED THE LIMESTONE EMISSIUN CONTRUL SYSIEM FOR IHIS NEW
COAL FIREO UNIT. THE SYSTEM CONSISTS UF A CULD-SIDE ESP AND SPRAY TUrttRS
FOR THE CONTROL OF S02 AND PARTICULATE EMISSIONS. 301 OF THE FLUE GAS Ib
BYPASSED FOR REHEAT. NOX EMISSIONS ARE CONTROLLED UT AN AIR OVERFIRE SYS-
TEM AT THE TANGENTIALLY FIRED PULVERISED BURNERS. THE CLEANED GASES ARE
VENTED TO A 600 FT STACK. SLUDGE IS MIXED rtlTH BOTTOM ASH AND DISPUSEO
OF IN THE EXISTING ON-SiTE BOTTOM ASH POND.
COMBUSTION ENGINEERING IS SUPPLYING THE EMISSION CONTROL SYSTEM FOR THIS
NEw COAL FIRED UNIT. THE SYSTEM KILL CONSIST OF A COLD SIDE ESP ALONG wlTH
SPRAY TOWERS FOR THE CONTROL OF S02 AND PARTICULATE EMISSIONS. 30* UF THE
FLUE GAS WILL BE BYPASSED FOR REHEAT. AN OVERFIRE AIR SYSTEM AT THE TAN-
GENTIAL FIREO PULVERIZED BURNERS WILL CONTROL NOX EMISSIONS. THE CLEANED
GASES WILL BE VENTED TO A 600 FT STACK. SLUDGE nILL BE MIXED WITH BUTTOM
ASH AND DISPOSED ON-SITE IN THE BOTTOM ASH POND. IHE SYSTEM STEEL WUKU IS
UP ANO CONSTRUCTION IS APPROXIMATELY t>OX COMPLETE.
REFER 10 SECIIOU 3 OF IHIS REPORT FOR ADD1IIUNAL INFORMAIION.
THE NEW LIMESTONE FGO SYSTEM COMMENCED OPERATIONS IN EARLY JANUARY 19/7.
THE NEW SYSTEM REPLACED MARBLE-BED TOWERS WITH SPKAY TOWERS. THERE HAVE
BEEN NO FORCED SCRUBBER OUTAGES REPORTED SINCE START-UP. CONTINOOUS S02
MONITORS HAVE RECORDED S02 REMOVAL EFFICIANCItS OF BETTER THAN
-------
tPA UTILITY FGO SURVEY: UClObEK 197B - UUVEN'-BER 1S7B
SECTION ^
STATUS UF FGO SYSTEMS
UNIT IDENTIFICATION
CURRENT SIATUb'
LOUISVILLE GAS & ELECTRIC
CANE RUN 4
178 MW - RETROFIT
COAL? 3.75X SULFUR, 15.5X ASH
AMERICAN AIR FILTER
LIME (CARBIDE)
STARTUP 8/7b
REFER 10 SECTION 3 OF THIS REPOK1 FUK ADDITIONAL INKUKVAT1UN.
THE FGO SYSTEM RETROFITTED ON THIS BUILEK AAS DESIGNED AND SUPPLIED HY
AMERICAN AIR ULTEK ANO HAS FIRST PLACED IN THt &Ab PATH UN AUGUbT /,
1976. THE SYSTEM CONSISTS UF TWO PARALLEL MODULES rtnlLH INCLUDE MOBILE
BEO CONTACTORS ANO OPERATE WITH A CAKH10E Llr/t ADUlllVt. FOLLUMM. A
NUMBER OF MAJOR SYSTEM MODIFICATIONS CCHEVKUN-TYPE MIST ELIMINATOR, U1L
FIREO REHEAT, PLASI1E DUCT LINER, HIGHER L/G) , 1Ht SYSTEM SUCCESSFULLY
PASSED COMPLIANCE TESTING (85X SU MM FOR OPERATION, RESEARCH AND OEVELUPMENT, AND KEPOK1 nkJTING FUR
A ONE-YEAR PERIOD FOLLOWING THE FIRST THREE MUNIHS UF UPtKAlIUf, IMHEMHIS
SUBSIDY WILL NOT BE APPLIED FUR ANY CAPITAL EXPENDITURES). CUNS1RUCT10'J AT
THIS UNIT IS PRESENTLY 98Z CUMPLETE. UNIT STARTUP IS tXPFCTED Tu «E IN
LATE DECEMBER 1978 OR EARLY JANUARY 1V79.
A COMPLIANCE SCHEDULE WAS SUBMITTED TO THE JEFFERSON COUNTY AIR POL-
LOTION CONTROL DISTRICT WITH
-------
EPA UTILITY FGD SURVEY: OCTOBER 197B - NOVEMBER 197H
SECTION i
STATUS OF FGU SYSTEMS
UNIT IDENTIFICATION CURRENT STATUS
MINNESOTA POWER » LIGHT MINNESOTA P & L HAb AnAROEO A CuNlKACI 10 PEABUUY pKUthSS SYSTEMS F UK A
CLAY BOSWELL 4 L IME/ALKAL 1 Nt FLYASH SCRUBBING SYSTEM. THK CUNf IMINA 1 ION MLL tth VFNIllKl
500 MW - NEW SCRUBBERS FOLLOWED BY SHRAY IUWERS. HUT S10E tSP'S rtlLL rtt UStl) F UK
COAL? o.ax SULFUR. 9X ASH PAHTKULATE CONIRUL. STACK GAS REHEAT WILL BE ACcuMruiSHtu BY HYpAssiNb
PEABODY PROCESS SYSTEMS 5* OF FLUE GAS AROUND THE SCRUBBER. THE UNIl WILL FlKt SUo-HlT UM I NUUS>
LIME/ALKALINE FLYASH COLSTR1P COAL W11H A SULFUR CUNTtNl OF U.tlX. AND AN AS>H CUNU.Nl UF 9.Ui
STARTUP 5/80 (HEATING VALUE - 8300 BTU/LB). MAKt-UH WATER SOURCE rtlLL rth lut Hlvt* AMI
THE CLAY-LINED POND. CONSTRUCTION OF THt FGO SYSTEM IS ABOUT dOl CUMHLMh.
MINNKOTA POWER COOPERATIVE REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL I(MF OKMAT IHN.
MILTON R. YOUNG Z THIS LI ME/ ALKAL INE FLYAbH SCRUBBING SYSTtM rtAS OtSlGNtD AIMU buHPLltl) UY
450 MW - NEW AUL/COMBUSTION EQUIPMENT ASSOClATtS. IT CONSISTS OF A CULO-SlOt tSP
LIGNITE* 0.7X SULFUR, 8. OX ASH FOLLOWED BY TWO SPRAY TOWERS, THfc DESIGN INCLUDES A WASH TKAY AIMI) A
AOL/COMBUST ION EQUIP ASSOCIATE CHEVRON MIST ELIMINATOR. JbX FLUE GAS BYPASS PHUVlDES STACK GAS rfEHhAI.
LIME/ALKALINE FLYASH THE UNJT FIRES A LOK-SULFUR NORTH DAKOTA LIGNITE WITH AN AVEKAGt A.Sn
STARTUP 9/77 CONTENT OF fl PERCENT, SULFUH CONTENT OF 0.7 PERCENT, AMU HKAT CUNltuI
OF 6bOO BTU/LB. THE FLY ASH ALKALINITY JS USED AS THE PRIMARY SU«J REAbKul.
MONTANA POWER REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL IiMFUKMA T 1UN .
COLSTRIP 1 THIS FGD EQUIPPED UNIT WAS DECLARED COMMERCIAL IN NOVEMBER 197b. I Hh
360 MW - NEW SCRUBBING SYSTEM PROVIDES PAKTICULA1E AND 30e! CONTKUL wllh THRtL SCKUrt-
COALJ 0.6X SULFUR, 12X ASH BER MODULES. EACH MODULE CONSISTS OF A DUwNFLUw VENlURl SCKUrtHLK CtultK-
ADL/COMBUSTION EQUIP ASSOCIATE EU WITHIN AN UPFLOw SPRAY TOwER ABSORBER. EACH KODULt CAM ThtAT 4>J* OF
LIME/ALKALINE FLYASH THE TOTAL BOILER FLUE GAS AND THE MODULES CAM01 BE UYPASSF.O. THt UN-
STARTUP 11/75 STABILIZED SLUDGE IS DISPOSED IN AN UN-SITE LINED 01SPUSAL POND. iN-LliMh
STEAM REHEAT AND CLOSED WATEK LOOP CAPABILITY ARE INCLUDED IN 1 Hh SYSItH.
MONTANA POWER REFER TO SECTION 3 OF THIS REPORT FUR ADDITIONAL INFUK^AT Inm.
COLSTRIP Z THIS FGD EUUIPPED UNIT WAS DECLARED CUMMERClAL IN AUGUST 197b. THE
360 MW - NEW SCRUBBING SYSTEM PRuVIDES PARUCULATE AND SOd CUNTRUL WITH THRtb SCRUh-
COAL? o.ax SULFUR* 12X ASH BER MODULES. EACH MODULE CONSISTS OF A DOWNFLUW VENTURI SCRUHBER C(NTER-
ADL/COMBUSTION EQUIP ASSOCIATE ED WITHIN AN UHFLUW SPRAY TOMER ABSORBER. EACH MODULE CAN TRbAT <4Ui Ut-
LIME/ALKALINE FLYASH THE TOTAL BOILER FLUE GAS AND THE MODULES CANNOT BE BYPASStU. THt UN-
STARTUP B/76 STABILIZED SLUDGE IS DISPOSED IN AN ON-SITE LINED lUSt-USAL HUNI). [u-LIi-iK
STEAM REHEAT AND CLOSED WATER LOOP CAPABILITY ARE INCLUDED IN iHt
MONTANA POWER A CONTRACT FOR THE INSTALLATION OF TWO ADDITIONAL Llwt / ALiv AL I NE FLYASH
COLSTRIP 3 SCRUBBING SYSTEMS HAS BEEN AWARDED TU A.U. LIT T LE/CUMeUST 1UN EUUlPMhNT
700 MM - NEW ASSOCIATES. THESE SYSTEMS WILL BE INSTALLED UN UNITS * ANU n UF THt
COALI o.7x SULFUR COLSIRIP POWER STATION. COLSTRIP ONUS i AND ^ ARE BOTH tuuipHtu WITH
ADL/COMBUSTION EQUIP ASSOCIATE OPERATIONAL LIME/ALKALINE FLYASH SCRUBBING SYSTEMS FOR THE REMOVAL OF
LIME/ALKALINE FLYASH PARTICULATES AND SULFUR DIOXIDE.
STARTUP 7/80
MONTANA POWER A CONTRACT FOR I HE 1NSJ I ALLA I IUN OF I WU ADDI I IUNAL LIME / ALiv ALlNt FLYASH
COLSTRIP 4 SCRUBBING SYSTEMS HAS BEEN AWARDED TO A.O. LITTLE/COMBUSTION EUU1PMEM
700 MW - NEW ASSOCIATES. THESE SYSTEMS WILL BE INSTALLED ON UNITS 3 AND 1 OF THE
CO*L> 0.7X SULFUR CULSTR1P POWER STATION. COLSTRIP ON1TS 1 AND i ARE B01H EUUJHPtO MTH
AOL/COMBUSTION EQUIP ASSOCIATE OPERATIONAL LIME/ALKALINE FLYASH SCRUBBING SYSTEMS FUR THE KhMUVAL UF
LIME/ALKALINE FLYASH PARTICULATES AND SULFUR DIOXIDE.
STARTUP 7/81
NEVADA POWER CONSIDERING HOT SIDE ESP IN CONJUNCTION WITH AM FGD SYSTtM. SPtClFICA-
MARRY ALLEN i T10NS HAVE NOT YET BEEN PREPARED.
SOO MW - NEW
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 6/85
NEVADA POWER CONSIDERING HOT SIDE ESP IN CONJUNCTION WITH AN FGO SYSTEM"~SPEC If ICA-
HARRY ALLEN Z TION8 HAVE NOT YET BEEN PREPARED.
500 MM - NEW
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 6/86
-------
EPA UTILITY FGD SUKVEY: OCTOBER 1<»78 - NOVEMBER
UNIT IDENTIFICATION
SECTION a
STATUS OF FGD SYSTEMS
CORRENT STATUS
NEVADA POWER
HARRY ALLEN 3
500 MW - NEW
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 6/87
CONSIDERING HOT SIDE ESP IN CONJUNCTION WITH AM FGO SYSTEM. SPECIFICA
TIONS HAVE NOT YET BEEN PHEPAKED.
NEVADA POKER
HARRY ALLEN 4
SOO MM - NEW
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 6/88
CONSIDERING HOT SIDE ESP IN CONJUNCTION WITH AN FGO SYSTEM. SPECIFICA-
TIONS HAVE NOT YET BEEN PREPARED.
NEVADA POWER
REIO GARDNER 1
125 MW - RETROFIT
COALf 0.5X SULFUR, 8X ASH
AOL/COMBUSTION EQUIP ASSOCIATE
SODIUM CARBONATE
STARTUP 4/74
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
THIS SODIUM CARBONATE-BASED CTRONA) SCRUBBING SYSTEM CONSISTS OF ONE
MODULE CONTAINING A THIN VARIABLE-THROAT VENTURI SCKUBbtR FOLLOWED BY A
SEPARATOR IN SERIES WITH A SINGLE-STAGE PERFOKATED-PLATE HASH TOrtEH.
PRIMARY PARTICULATE CONTROL IS PROVIDED BY UPSIKEAM MECHANICAL COLLtCTUKS.
AN INDIRECT STEAM HOT AIR REHEAT SYSTEM HAlStS THE GAS FEMPERATORE iU F
PRIOR TO DISCHARGE TO THE MAIN STACK. THE FLUE GAS CLEANING WASTES ARE
ULTIMATELY DISPOSED IN AN ON-SITE CLAY-LINtO SOLAK EVAPORATION PUNU.
NEVADA POWER
REID GARDNER 2
125 MW - RETROFIT
COAL; o.sx SULFUR, ax ASH
ADL/COMBUSTION EQUIP ASSOCIATE
SODIUM CARBONATE
STARTUP 4/74
REFER 10 SECTION 3 OF THIS REPORT FOH AODIIIONAL INFORMAIION.
THIS SODIUM CARBONATE-BASED (TRONA) SCRUBBING SYSTEM CONSISTS OF ONE
MODULE CONTAINING A THIN VARIABLE-THKOAT VENTUHI SCKUbBEK FULLOwED bY A
SEPARATOR IN SERIES WITH A SINGLE-STAGE PERFOHATED-PLATE HASH TOrtEK.
PRIMARY PARTICULATE CONTROL IS PROVIDED BY UPSTKEAM MECHANICAL COLLtCTUKS.
AN INDIRECT STEAM HOT AIR REHEAT SYSTEM RAISES THE GAS TEMPERATURE 30 F
PRIOR TO DISCHARGE TO THE MAIN STACK. THE FLUE GAS CLEANING WASTES ARE
ULTIMATELY DISPOSED IN AN ON-SITE CLAY-LINED SOLAK EVAPORATION POND.
NEVADA POWER
REID GARDNER 3
125 MW - NEW
COAL> O.SX SULFUR, 8X ASH
AOL/COMBUSTION EQUIP ASSOCIATE
SODIUM CARBONATE
STARTUP 7/76
REFER TO SECTION 3 OF THIS REPOKI FUR ADDITIONAL INFOKMAIION.
THIS UNIT IS A NEW COAL-FIRED BOILtR THAT IS EQUIPPED WITH SOOIUM
CARBONATE-BASEO(TRONA)SCRUBBING SYSTEM WHICH INCORPORATES A TnIN
VARIABLE-THROAT VENTURI SCRUBBER FOLLOWED BY A SEPAKAIOK IN SERIES «IlH
A SINGLE-STAGE PERFORATED-PLATE NASH TObEK. MECHANICAL COLLEC10KS PROVIDE
PRIMARY PARTICULATE CONTROL. REHEAT IS PROVIDED BY AN INDIRECT STEAM HUT
AIR REHEAT SYSTEM. WASTE IS DISPOSED IN AN ON-SITE CLAY-LINED FOND.
NEVADA POWER
REID GARDNER 4
250 HW - NEW
COAL? 0.75X SULFUR
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 0/83
NEVADA POWER COMPANY HAS SCRAPPED THIER ORIGINAL PLANS TO MAKE UNIT 4 A
COPY OF UNIT 3. THE NEW PLANS CALL FOH A 250-Mfc UNIt TO bt IN OPERATION
BY 1983. THE UTILITY IS PREPARING SPECIFICATIONS AT THIS TIME. CONSTRUC-
TION IS SCHEDULED TO START IN 1980.
NEVADA POWER
WARNER VALLEY 1
250 MW - NEW
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 6/84
SPECIFICATIONS ARE BEING PREPARED FOR A SCRUBBING SYSTEM. NEVADA POwER
HAS NOT YET ANNOUNCED PLANS FOR THIS UNIT'S EMISSION CONTROL STRATEGY.
NEVADA POWER
WARNER VALLEY 2
250 MW - NEW
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 6/85
SPECIFICATIONS ARE BEING PREPARED FOH A SCRUBBING SYSTEM. NEVADA POwER
HAS NOT YET ANNOUNCED PLANS FOR THIS UNIT'S EMISSION CONTROL STRATEGY.
13
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EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 2
STATUS OF FGD SYSTEMS
UNIT IDENTIFICATION
CURRENT STAIUS
NEN ENGLAND ELEC SYSTEM
BRAYTON POINT 3
650 MW - RETROFIT
FUEL OIL; l.OX SULFUR, .11
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP OX 0
ENGLAND ELECTRIC SYSTEM HAS REQUESTED PERMISSION TO BURN 1.5X SULFUR
COAL AT THIS UNIT. THIS IS ALLOWABLE UNDER STATE STANDARDS BUT SOS EMIS-
SIONS MOULD 8fc ABUVE ALLOWABLE FEDERAL LEVELS. A DECISION BY THE EPA IS
ASH STILL PENDING. MEANWHILE, THE UTILITY IS INVESTIGATING VARIOUS ADVANCED
REGENERABLE FGO SYSTEMS WHICH OFFER A BREAKTHROUGH IN OPERATING COSTS AND
PRODUCE ELEMENTAL SULFUR AS AN END PRUOUCT. THE UTILITY IS CURRENTLY IN-
VOLVED IN BENCH AND LABORATORY SCALE INVESTIGATIONS OF SULFUR KECUVERY.
THIS UNIT IS CURRENTLY OPERATIONAL FIRING LOW SULFUR FUEL OIL.
NIAGARA MOHAWK POWER COOP
CHARLES R. HUNTLEY 66
100 MW - RETROFIT
COAL; 3.sx SULFUR
ROCKWELL INTERNATIONAL
AQUEOUS CARBONATE
STARTUP 0/80
A CONTRACT HAS AWARDED TO ATOMICS INTERNATIONAL FOR THE DESIGN AND IN-
STALLATION OF AN AQUEOUS CARBONATE FGO SYSTEM. THIS DEMONSTRATION SYSIEM
WILL PRODUCE END-PRODUCT SULFUR. FUNDS ARE dEING PROVIDED BY THE USEPA
AND THE EMPIRE STATE ELECTRIC ENERGY RESEARCH CORP. THE DESIGN SU2 RE-
MOVAL EFFICIENCY WILL BE 90 PERCENT. GROUND BREAKING FOR CONSTRUCIION WILL
BE IN LATE FALL 1978.
NORTHERN INDIANA PUB SERVICE
BAILLY 7
190 MW - RETROFIT
COAL; 3x SULFUR
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP OX 0
NORTHERN INDIANA PUBLIC SERVICE IS CURRENTLY CONSIDERING A LIME OR LIME-
STONE SCRUBBING UNIT FUR BAILLY 7 AND 8. THEY AKE ALSU WAITING FUR
PERFORMANCE RESULTS OF THE wELLMAN LORDXALLIED CHEMICAL UNIT IN SERVICE
AT DEAN H. MITCHELL 11. LOW SULFUR COAL MAY BE EMPLOYED TO COMPLY WITH
S02 EMISSION REGULATIONS. APPLICABLE INDIANA S02 REGULATIONS ARE STILL NOT
FIRMLY ESTABLISHED.
NORTHERN INDIANA PUB SERVICE
BAILLY 8
400 MW - RETROFIT
COAL; 31 SULFUR
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP OX 0
NORTHERN INDIANA PUBLIC SIRVICE IS CURRENTLY CONSIDERING A LIME UK LIME-
STONE SCRUBBING UNIT FOR BAILLY 7 AND 8. THEY AKE ALSO WAITING FOR
PERFORMANCE RESULTS OF THE WELLMAN LORDXALLIED CHEMICAL UNIT IN SERVICE
AT DEAN H. MITCHELL 11. LOW SULFUR COAL MAY BE EMPLOYED Tu COMPLY WITH
S02 EMISSION REGULATIONS. APPLICABLE INDIANA S02 REGULATIONS ARE STILL NUT
FIRMLY ESTABLISHED.
NORTHERN INDIANA PUB SERVICE REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
DEAN H. MITCHELL 11
115 MW - RETROFIT
COAL; 3.sx SULFUR, IDS ASH
DAVY POWERGAS
WELLMAN LORD
STARTUP 11X76
THIS FGD SYSTEM IS AN INTEGRATION OF THE wELLMAN-LORD 802 RECOVERY PROCESS
OFFERED BY DAVY POWERGAS AND THE S02 TO SULFUR REDUCTION PROCESS DE-
VELOPED BY ALLIED CHEMICAL. DAVY POWERGAS IS THE DESIGN AND CONSTRUCTION
FIRM AND ALLIED CHEMICAL IS SYSTEM OPERATOR AND PRODUCT MARKETER.
PERFORMANCE TESTS WERE SUCCESSFULLY COMPLETED ON SEPTEMBER 14, 1977. A
DEMONSTRATION YEAR COMMENCED ON SEPTEMBER 16, 1977.
NORTHERN STATES POWER
SHERBURNE 1
710 MW - NEW
COAL; o.ex SULFUR, 9.sx SULFUR
COMBUSTION ENGINEERING
LIMESTONE/ALKALINE FLYASH
STARTUP 3/76
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
FULL COMMERCIAL OPERATION OF THE SYSTEM BEGAN ON MAY 1, 197b. THE SCRUB-
BING SYSTEM FOR THIS UNIT CONSISTS OF 12 MODULES. EACH SCRUBBING MODULE
INCORPORATES A VENTUHI-ROD SECTION AND A MARBLE BED ABSORBER FOR PAR-
TICULATE AND SULFUR DIOXIDE REMOVAL. A FORCED OXIDATION SYSTEM CONVERTS
ALL THE CALCIUM SULFITE TO SULFATE PRIOR TO DISCHARGE TO A CLAY-LINED
SETTLING POND. STACK GAS REHEAT IS PROVIDED BY IN-LINE HOT WATER TUBES.
THE COAL BURNED AT THIS UNIT CONTAINS ,6X SULFUR AND 9-1UX ASH.
NORTHERN STATES POWER
SHERBURNE 2
710 MW - NEW
COAL; o.ex SULFUR, 9.sx ASH
COMBUSTION ENGINEERING
LIMESTONE/ALKALINE FLYASH
STARTUP 4/77
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
THE SHERBURNE NO. 2 AIR QUALITY CONTROL SYSTEM IS IDENTICAL IN DESIGN TO
THE SYSTEM IN OPERATION ON THE NO. 1 UNIT AT THIS STATION. TWELVE 2-STAGE
PARTICULATE SCRUBBER (VENTURI-ROD SCRUBBER) AND SULFUR DIOXIDE A8SURBER
(MARBLE-BED ABSORBER) MODULES ARE PROVIDED FOR FLY ASH AND 302 CONTROL.
ELEVEN MODULES ARE REQUIRED FOR FULL GENERATING CAPACITY OPERATIONS.
THE CALCIUM SULFITE IS FORCIBLY OXIDIZED TO SULFATE PRIOR TO DISCHARGE TO
THE DISPOSAL POND. IN-LINE HOT WATER TUBES PROVIDE STACK GAS REHEAT.
NORTHERN STATES POWER
SHERBURNE 3
660 MW - NEW
COAL; o.ax SULFUR, 9.sx ASH
COMBUSTION ENGINEERING
LIMESTONE/ALKALINE FLYASH
STARTUP 5/60
TWO ADDITIONAL COAL-FIRED POWER-GENERATING UNITS ARE SCHEDULED TU BE IN-
STALLED AT NSP'S SHERBURNE COUNTY GENERATING STATION IN BECKER MINNESOTA.
A LETTER OF INTENT HAS BEEN SIGNED WITH C-E FOR A LIMESTONE SLURRY SPRAY
TOWER FGO SYSTEM FOR THIS NEW 860 MW UNIT. THE 2-STAGE SCRUBBING SYSTEM
WILL REMOVE PARTICULATE (99.5X) & S02 (BOX). THE BOILER CONTRACT HAS BEEN
AWARDED TO BABCOCK AND WILCOX AND THE TURBINE WILL BE SUPPLIED BY GENERAL
ELECTRIC. START-UP HAS BEEN DELAYED TO MAY 1984 AND CONSTRUCTION START-
UP HAS BEEN SUSPENDED UNTIL APRIL 1980 DUE TO ENVIRONMENTAL PROBLEMS.
14
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tPA UTILITY FGD SURVEY: UCTOBEk 197a - NUVtl"bEk 1978
SECTION 2
STATUS OF FGD SYSTEMS
UNIT IDENTIFICATION
CURRENT STATUS
NOKTHEKN STATES PUNEK
SHERBURNE 4
660 MM - NEW
COAL; o.ex SULFUR, 9.sx ASH
COMBUSTION ENGINEERING
LIMESTONE/ALKALINE FLYASH
STARTUP 0/87
TWO AUDIUUNAL COAL-FlKEl) POWER-GENERATING UNIIS ARE SCHEDULED fu BE IN-
STALLED AT NSP'S SHERBURNE CUUNTY GENERATING STATION IN BECKER MINNESOTA.
A LETTER OF INTENT HAS BEEN SIGNED WITH C-E FUR A LIMESTONE SLURRY SPKAY
TOWER FGO SYSTEM FOR THIS NEW 66U MW UNIT. THE d-STAGE SCRUBBING SYSTEM
WILL REMOVE PARTICULATE (99.5X) & S02 (SOX). THE BOILER CONTRACT HAS cJEEN
AWARDED TO BABCOCK AND WILCUX AND THE TURBINE KILL BE SUPPLIED BY GENERAL
ELECTRIC. UNIT START-UP IS NOW TENTATIVELY SCHEDULED FOR 19»7 ALTHOUGH
ALTHOUGH CONSTRUCTION HAS BEEN SUSPENDED FnK T*0 YEARS.
OTTER TAIL POWER
COYOTE 1
400 MM • NEW
LIGNITE; 0.9X SULFUR, 6.5X ASH
WHEELABRATOR-FRYE/R.I.
NA-CO, SPRAY DRYING
STARTUP 5/81
THIS f>.tw COAL-FIRED STATION IS JOINTLY UWHLI) n 1 FIVE UTILITIES. OTTER
TAIL POWER IS THE MAJOR OWNER AND CONSTRUCTOR. MONTANA-DAKOTA UTILITIES
IS THE FACILITY OPERATOR. THIS PLANNED ONIT WILL F1KE LOW SOLFUR LIGNITE
FROM THE MERCER COUNTY AREA IN A B&w CYCLONE buILEH. THE CONTRACT FUR THIS
AQUEOUS CARBONATE/FABRIC FILTER S02 SCRUBbER-ABSORBER MAS AWARDED TO
WHEELABRATOR-FRYE AND ATOMICS INTERNATIONAL. THE DRY REMOVAL SYSTEM COM-
BINES AI'S AQUEOUS CARBONATE PROCESS IN A W-F FABRIC FILTER. UNIT CON-
STRUCTION IS NOW 20X COMPLETE AND FGO SYSTEM CONSTRUCTION HAS JUST BEGUN.
PACIFIC GAS AND ELECTRIC
FOSSIL 1
BOO HW - NEW
COAL} 0.6X SULFUR* 10X ASH
VENDOR NOT SELECTED
LIMESTONE
STARTUP 0/85
PACIFIC GAS AND ELECTRIC
FOSSIL a
600 MW - NEW
COAL} O.BX SULFUR, 10X ASH
VENDOR NOT SELECTED
LIMESTONE
STARTUP 0/86
PACIFIC POWER ft LIGHT
JIM BRIDGER 4
509 MW - NEW
COAL} 0.56X SULFUR, 9X ASH
AIR CORRECTION DIVISION, UOP
SODIUM CARBONATE
STARTUP 9/79
PENNSYLVANIA POWER
BRUCE MANSFIELD t
825 MM - NEW
COAL} 4.7X SULFUR, 12r5X ASH
CHEMICO
LIME
STARTUP 4/76
PGSE ANNOUNCED PLANS TO BUILD TWO 800-MW COAL-FIRED POWER GENERATING
UNITS IN NORTHERN CALIFORNIA. THE FIRST UNIT WILL BURN COAL WITH A HEAT-
ING VALUE OF 12000 BTU/LB, 0.8X SULFUR AND 1UX ASH CONTENTS. THE SECOND
UNIT WILL BURN COAL OF EQUAL OR BETTER UUALITY. THE EMISSION CONTROL
SYSTEM WILL CONSIST OF AN ESP OR BAGHOUSE AND A LIMESTONE FGD SYSTEM.
SLUDGE WILL BE DISPOSED OF IN A LANDFILL. START-UP DATES ARE 1985 AND 198b
FOR NOS. 1 AND 2 RESPECTIVELY. CONSTRUCTION IS NOT ENVISIONED TO BEGIN
BEFORE TWO TO THREE YEARS.
PGftE ANNOUNCED PLANS TO BUILD TWO 800-MW COAL-FIRED POWER GENERATING
UNITS IN NORTHERN CALIFORNIA. THE FIRST UNIT WILL BURN COAL WITH A HEAT-
ING VALUE OF 12000 BTU/LB, 0.8X SULFUR AND 10X ASH CONTENTS. THE SECOND
UNIT WILL BURN COAL OF EQUAL OR BETTER QUALITY. THE EMISSION CONTROL
SYSTEM WILL CONSIST OF AN ESP OR BAGHOUSE AND A LIMESTONE FGD SYSTEM.
SLUDGE WILL BE DISPOSED OF IN A LANDFILL. START-UP DATES ARE 1905 AND 1986
FOR NOS. 1 AND 2 RESPECTIVELY. CONSTRUCTION IS NOT ENVISIONED TO BEGIN
BEFORE TWO TO THREE YEARS.
THE AIR CORRECTION DIVISION OF UOP WAS AWARDED A CONTRACT FOR AN FGD
SYSTEM AT THIS NEW-509 MW COAL-FIRED UNIT. THE FGO SYSTEM WILL CONSIST OF
PARALLEL TRAY TOWER ABSORBER MODULES, EACH TREATING ONE-THIHD OF THE
BOILER FLUE GAS AT FULL LOAD. AN ESP WILL PROVIDE PRIMARY PARTICULATE
CONTROL. AN ACID BRICK LINED WET STACK IS INCLUDED IN THE SYSTEM. PPL'S
PILOT STUDY INSPECTION REVEALED SCALE FORMATION PROBLEMS. TESTS ARE BEING
CONDUCTED TO RESOLVE THIS PROBLEM. THE UTILITY EXPECTS TO CONDUCT A
SYSTEM CHECKOUT IN 7/79 WITH COMMERCIAL STARTUP AT THE END OF 1979.
REFER TO SECTION 3 OF THIS REPORT FOR ADDITONAL INFORMATION.
THIS EMISSION CONTROL SYSTEM WAS DESIGNED TO REMOVE FLYASH AND S02 FROM
3.35 MM ACFM OF FLUE GAS USING THIOSORBIC LIME AS A SCRUBBING ABSORBENT.
THE INITIAL SHAKEDOWN AND DEBUGGING PHASE OF OPERATION BEGAN FOR PART OF
THE SYSTEM IN DECEMBER 1975. PARTIAL COMMERCIAL OPERATION COMMENCED IN
APRIL 1976. THE UNIT WAS CERTIFIED FULL-LOAD COMMERCIAL IN JUNE 1976.
THE FGD SYSTEM HAS EXPERIENCED OPERATIONAL PROBLEMS SINCE IT HAS BEEN IN
SERVICE REQUIRING A NUMBER OF SYSTEM REPAIRS AND DESIGN MOD IF ICATINS.
PENNSYLVANIA POWER
BRUCE MANSFIELD 2
825 MW - NEW
COAL) 4.7X SULFUR, 12.SX ASH
CHEMICO
LIME
STARTUP 7/77
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
THIS EMISSION CONTROL SYSTEM WAS DESIGNED TO REMOVE FLYASH AND 302 FROM
3.35 MM ACFM OF FLUE GAS USING THIOSORBIC LIME AS A SCRUBBING ABSORBENT.
SIX SCRUBBING TRAINS, EACH INCLUDING TWO VENTURI SCRUBBERS IN SERIES
ARRANGEMENT, ARE PROVIDED FOR FULL-LOAD OPERATION. THE INITIAL SHAKEDOWN
AND DEBUGGING PHASE OF OPERATION BEGAN FOR THREE TRAINS IN JULY, 1977.
FULL COMMERCIAL OPERATION FOR THE ENTIRE SYSTEM COMMENCED ON OCTOBER 1,
1977.
PENNSYLVANIA POWER
BRUCE MANSFIELD 3
625 MW » NEW
COAL} 4.7X SULFUR
PULLMAN KELLOGG
LIME
STARTUP 4/80
A CONTRACT WAS AWARDED TO PULLMAN KELLOGG FUR THE FGD SYSTEM AT THIS UNIT.
THE EMISSION CONTROL SYSTEM FOR THIS UNIT WILL CONSIST OF ESP'S UP-STREAM
OF FIVE WEIR HORIZONTAL CROSSFLOW WET SCRUBBING MODULES. SLUDGE WILL BE
DISPOSED OF BY THE EXISTING SYSTEM AT THE BRUCE MANSFIELD PLANT. LINER IN
THE CHIMNEY WILL BE AN INCUNEL 625 MATERIAL. THE UNIT IS CURRENTLY UNDER
CONSTRUCTION WITH ESP'S 70-80 PERCENT CU-^LEIt AND THE FGO SYSTEM 30
PERCENT COMPLETE. UNIT START-UP WILL BE IN APRIL 1980.
15
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EPA UTILITY FGD SURVEY! OCTOBER 1976 - NOVEMBER 1978
UNIT IDENTIFICATION
SECTION i
STATUS OF FGD SYSTEMS
CURRENT STATUS
PHILADELPHIA ELECTRIC
CROMBY
150 MW • RETROFIT
COAL; 2-4Z SULFUR
UNITED ENGINEERS
MAGNESIUM OXIDE
STARTUP b/80
THE UTILITY PLANS TO RETROFIT ONE OF THE TWU BOILERS AT CROMUY WITH AN
FGO SYSTEM. HOWEVER* A FINAL DECISION HAS NUT BEEN MAUE. THE SYSTEM
BEING GIVEN PRIMARY CONSIDERATION IS MAGNESIUM OXIOE. CURRf-NTLY, THE
UTILITY IS RE-NEGOTIATING CONSENT ORDERS AND THE STAHT-UP DATE OF JUNE
I960 IS TENTATIVE.
PHILADELPHIA ELECTRIC
EOOYSTONE 1A
120 MW - RETROFIT
COAL; 2.5Z SULFUR, 101 ASH
UNITED ENGINEERS
MAGNESIUM OXIDE
STARTUP 9/75
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFOKMATION.
THE EMISSION CONTROL SYSTEM FOR THIS UNIT CONSISTS OF THRtE PARALLEL
SCRUBBING TRAINS FOR THE CONTROL OF PARTICULATt AND SULFUR DIOXIDE.
THE C-SIDE SCRUBBING TRAIN INCLUDES AN Su2 ABSUKBER MUDULt IN SERIES
WITH A PARTICULATE SCRUBBER. APPROXIMATELY UNE-THIRO OF THE BUILEK FLUE
GAS IS SCRUBBED WITH MAGNESIUM OXIDE SLURKY FOR S02 REMOVAL. THE SPKNT
SLURRY IS REGENERATED AT THE ESSEX SULFURIC ACID PLANT IN NEWARK, N.J.
THE REGENERATED MAGOX IS RETURNED TO THE PLANT FOR 302 SCRUBBING SERVICE.
PHILADELPHIA ELECTRIC
EDOYSTONE IB
240 MW - RETROFIT
COAL; 2.5X SULFUR, 101 ASH
UNITED ENGINEERS
MAGNESIUM OXIDE
STARTUP 6/80
THE INSTALLATION OF AN FGD SYSTEM ON THE BALANCE OF THE FLIlt GAS FKUM
THIS UNIT WILL FOLLOW PENDING THE OUTCOME OF THE PERFORMANCE OF THE EXPER-
IMENTAL SCRUBBING UNIT WHICH HAS BEEN INSTALLED AND CURRENTLY OPERATIONAL
ON THIS UNIT. CURRENTLY, 3 PARTICULATE SCRUBBERS ARE TREATING THE FULL
GAS LOAD FROM THIS UNIT. CONSENT ORDEKS ARE PRESENTLY BEING KE-NEGUTI AT ED
AND THE START-UP DATE OF JUNE 1980 IS TENTATIVE.
PHILADELPHIA ELECTRIC
EDDYSTONE 2
336 MW - RETROFIT
COAL; 2.5Z SULFUR, 10Z ASH
UNITED ENGINEERS
MAGNESIUM OXIDE
STARTUP b/80
THE UTILITY IS AWAITING PERFORMANCE RESULTS FROM THE EXPERIMENTAL FGO
SYSTEM INSTALLED ON UNIT 1 AT THIS STATION BEFORE PROCEEDING WITH THE
DESIGN OF AN FGD SYSTEM FOR THIS COAL-FIRED BOILER. THE SYSTEM BEING
GIVEN PRIMARY CONSIDERATION IS MAGNESIUM UXIDE, DESIGNED JOINTLY BY
UNITED ENGINEERS AND PHILADELPHIA ELECTRIC. CURRENTLY, THE UTILITY IS
RE-NEGOTIATING CONSENT ORDEKS AND THE START UP DATE OF JUNE 1980 IS
TENTATIVE.
POTOMAC ELECTRIC POWER
DICKERSON 4
800 MW - NEW
COAL; 2X SULFUR
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 5/85
THERE ARE NO FIRM PLANS FOR INSTALLATION OF AN FGD SYSTEM. STARTUP DATE
OF THE BOILER IS PLANNED FOR 1985. THIS UNIT HILL BURN 2 PERCENT SULFUR
COAL WITH A HEATING VALUE OF 11,000 BTU/L8.
POWER AUTHORITY OF NEW YORK
ARTHUR KILL PLANT
700 MW - NEW
COAL; 3z SULFUR - REFUSE
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 11/84
THE UTILITY IS CONSIDERING BOTH REGENERABLE AND LIMESTONE FGD PROCESSES.
FGD TECHNOLOGY IS. BEING CONSIDERED FOR A FOSSIL FUEL BURNING UNIT WHICH
WILL EMPLOY COAL AS THE PRIMARY FUEL AND OIL AS BACKUP. REFUSE WILL BE
PROVIDED AS A SUPPLEMENTAL FUEL SUPPLY. THE PREFERRED PLANT SITE IS THE
ARTHUR KILL FACILITY LOCATED ON STATEN ISLAND. THE PROJECT DESIGN ENGI-
NEERING FIRM IS SARGENT AND LUNDY. PUBLIC SERVICE COMMISSION HEARINGS
ARE IN PROGRESS.
PUBLIC SERVICE OF INDIANA
6IBSON 5
650 MW • NEW
COAL; 3.3Z SULFUR
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 0/62
PUBLIC SERVICE CO OF INDIANA ANNOUNCED PLANS FOR THE CONSTRUCTION OF THIS
NEW 6SO-MW COAL FIRED POWER GENERATIONG UNIT AT GIBSON STATION. BIDS
HAVE BEEN RECEIVED AND ARE BEING EVALUATED. INITIAL STARTUP IS SCHEDULED
FOR 1982.
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN 1
314 MM - NEW
COAL; 0.6X SULFUR* 20Z ASH
DAVY POWERGAS
MELLMAN LORD
STARTUP 4/78
REFER 10 SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION. THIS FGD
SYSTEM IS AN INTEGRATION OF THE WELLMAN LORD 802 RECOVERY PROCESS OF DAVY
POWERGAS AND ALLIED CHEMICAL'S S02 REDUCTION TO SULFUR PROCESS. A HOT
SIDE ELECTROSTATIC PRECIPITATOR PRECEEDS THE FGD SYSTEM. OF THE FOUR
ABSORBER TOWERS INSTALLED, THREE ARE NEEDED TO CARRY THE FULL LOAD. THE
COAL BURNED AT THIS UNIT HAS SULFUR AND ASH CONTENTS OF .8Z AND 20X RE-
SPECTIVELY. THE SYSTEM OPERATES ON A CLOSED WATER LOOP WITH RIVER WATER
BEING USED AS MAKE-UP FOR LOSSES DUE TO EVAPORATION.
16
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EPA UTILITY FGO SURVEY: UCTUdER 197H - NUVtl»dKH
SECTION 2
STATUS OF FGD SYSTEMS
UNIT IDENTIFICATION
CURRENT STATUS
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN 2
306 MW • RETROFIT
COAL) O.BX SULFUR, 20X ASH
DAVY POWERGAS
WELLMAN LORD
STARTUP 8/78
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN 3
468 MM - NEW
COAL; o.ax SULFUR, 2ox ASH
DAVY POWERGAS
WELLMAN LORD
STARTUP 6/79
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN 4
473 MW - NEW
COAL; o.ax SULFUR, aox ASH
DAVY POWERGAS
NELLMAN LORD
STARTUP 1/82
REFER TO SECTION 3 (if THIS REPOHT FOR ADDITIONAL INFORMATION. THIS FGI)
SYSTEM is AN INTEGRATION OF THE WELLMAN LORD so<2 RECOVERY PKDCESS OF DAVY
POWERGAS ANU ALLIED CHEMICAL'S S02 REDUCTION TO SULFUrf PROCESS. A HUT Slot
ELECTROSTATIC PRECIPITATOR PRECEEDS THE FliD SYSTEM. THE SYSTEM INCLUDES
FOU« ABSORBER TOWERS, THREE OF WHICH ARE NECESSARY TO CARRY THE HULL LDAU.
THE WATER LOOP IS CLOSED WITH RIVER WATER HEING USED TO MAKE UP F0« LUSStb
DUE TO EVAPORATION. THE COAL BURNED AT THIS UNIT HAS SULFUR AND ASH
CONTENTS OF .8X AND aOX RESPECTIVELY.
A CONTRACT HAS BEEN AWARDED TO DAVY POWERGAS TO SUPPLY FOUR AHSURBER
TOWERS FOR REMOVAL OF S02 AT THIS NEW UNIT. ONE MODULE IS EXPECTED TO HE
OPERATIONAL BY JUNE 1979 WHICH rtILL BRING THE UNIT INTO COMPLIANCE rtllH
FEDERAL NSPS. THE REMAINING THREE MODULES SHUULD BE OPERATIONAL BY JANUARY
1982 AT WHICH TIME THE UNIT WILL BE IN COMPLIANCE OF STATE STANDARDS.
POWER PLANT CONSTRUCTION IS BEHIND SCHEDULE BUT A8SURBER CONSTRUCTION IS
PROCEEDING AS PLANNED. IT IS POSSIBLE THAT THE FINAL THREE ABSORBERS MAY
BE IN AS EARLY AS JANUARY 1961.
DAVY POWERGAS HAS BEEN AWARDED A CONTRACT TO SUPPLY THE S02 REMOVAL SYSTEM
FOR THIS UNIT. THE PLANS INCLUDE A rtELLMAN LORD SO
-------
EPA UTILITY FGD SURVEY: OCTOBER 1976 - NOVEMBER
SECTION i
STATUS OF FGD SYSTEMS
UNIT IDENTIFICATION
CURRENT STATUS
SIKESTON BOARD OF MUNIC. DTK.
SIKESTON POWER STATION
235 MW - NEw
COAL; 2.ex SULFUR, ii.ai ASH
BABCOCK & WILCOX
LIMESTONE
STARTUP 6/81
B&W WAS AWARDED A CONTRACT FOR THE BOILER AND AIR QUALITY CONTROL SYSTEM.
THE AOCS MLL CONSIST OF 2 ESP'S FOLLOWED BY 3 FGD MODULES, EACH CAPAtiLE
OF HANDLING bOX OF THE BOILER LOAD; ONE WILL BE ON STAND-BY AT ALL TIMES.
THE UNIT WILL BURN A 2.8X SULFUR COAL. THE SIKESTON STATION WILL FEATURE
AN FRP-LINED STACK, 2 PONDS (ONE FOR FLY ASH, ONE FOR SCRUBBER SLUDGE/
BOTTOM-ASH DISPOSAL), AND « AXIAL FLOW FANS. NO STACK GAS REHEAT IS
PLANNED. MAXIMUM FLUE GAS CAPACITY IS 7
-------
tPA UTILITY FGO SURVEY: OCTOBER 197tt - NUVtl"bEk 197M
SECTION 2
STATUS OF FGO SYSTEMS
UNIT IDENTIFICATION
COkKENT STATUb
SOUTHWESTERN ELECTRIC POWFR
HENRY W. PERKEY 1
730 MW - NEW
LIGNITE; 0.8X SULFUR, 20X ASH
AIR CORRECTION DIVISION, UOP
LIMESTONE
STARTUP 2/84
A CONTRACT FUR THE EMISSION CONTROL SYSHM HAS MF.t.M AftARDEI) TO THE Alk
CORRECTION DIVISION OF UOP. THE SYSTEC DESIGN INCLUDES Two CULD-SII)t bSH'b
FOR PARTICULATE REMOVAL UP-STKEAM FROf a SHkAY TUwEKS WHICH OTILUt LIHb-
STONE SLURRY FOR S03 CONTROL. SLODGE DISPOSAL WILL BE HANULEO BY Au IUCS
SYSTEM. START-UP IS EXPECTED BY FEBRUARY 19Bi|.
SPRINGFIELD CITY UTILITIES
SOUTHWEST 1
200 MW - NEW
COAL; 3.5X SULFUR, 13X ASH
AIR CORRECTION DIVISION, UOP
LIMESTONE
STARTUP 4/77
SPRINGFIELD WATER LIGHT S
DALLMAN 3
190 MW - NEW
COAL; 3.7% SULFUR
RESEARCH COTTRELL
LIMESTONE
STARTUP 7/80
REFER TO SECTION S OF THIS REPORT FOK ADDITIONAL INFORMATION.
THE EMISSION CONTROL SYSTEM FOR THIS NEW COAL-FIKtD UNIT CONSISTS OF A
FOUR-FIELD HIGH EFFICIENCY ESP (99.6X DESIGN) AND Z TURBULENT CONTACT AB-
SORBER MODULES C80X DESIGN) FOR THE CONTROL OF PAKTICULATES AMD bo2. BOlH
THE ESP AND LIMESTONE FGD SYSTEM ARE SUPPLIED BY UOP. THE SCRUBBING
WASTES ARE DEWATEHEU BY A ROTARY DRUM VACUUM FILTER AND 1HE FILTER CAKF. IS
HAULED AWAY TO A LANDFILL. INITIAL OPERATION OF THE FGD SYSTEM OCCURRED IN
APRIL 77. IN SEPT. 77, THE UNIT SUCCESSFULLY COMPLETED COMPLIANCE TtSIIuU.
PWR A CONTRACT WAS AWARDED TO RESEARCH COTTRELL FOR THE INSTALLATION UF
A LIMESTONE FGD SYSTEM. REQUIRED SULFUR DIOXIDE REMOVAL EFFICIENCY
IS 90 PERCENT. A SLUDGE DISPOSAL STRATEGY HAS NO! BEEN FINALIZEO, BUI
THE UTILITY IS CONSIDERING EITHER PONDING OR LANDFILL. CONSTRUCTION OF
THE FGD SYSTEM FOUNDATIONS HAVE BEGUN. ALL SYSTEMS ARE ON SCHEDULE. THt
BOILER OPERATION WAS SCHEDULED TO COMMENCE IN JUNE 1978.
ST. JOE ZINC
6. F. WEATON 1
60 MW - RETROFIT
COAL; 3x SULFUR
BUREAU OF MINES
CITRATE
STARTUP 12/78
CONSTRUCTION CONTINUES ON THE CITRATE PROCESS SCRUBBING SYSTEM «HICH
WILL CONTROL 502 EMISSIONS FROM A bO-f.1 COAL-FIRED POWER GENFRATINb
UNIT AT ST. JOE MINERALS. THIS UNIT PROVIDES POWER FOR THE LOCAL UTILITY
GRID. FGD SYSTEM START-UP IS SCHEDULED FOR DECEMBER 1978. THE kEGENKKABLE
FbD SYSTEM WILL PRODUCE ELEMENTAL SULFUR AS A BY-PRODUCT. ALL MAJOk
CONSTRUCTION IS COMPLETE. WIRING AND PIPING WORK IS NOW BEING COMPLETED.
TAMPA ELECTRIC
BIG BEND 4
435 MW - NEW
COAL; 0.4-4.3X SULFUR
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 0/85
TAMPA ELECTRIC HAS ANNOUNCED PLANS TO INSTALL AN FGO SYSTEM AT BIG BEND <»
WHICH IS SCHEDULED TO BEGIN OPERATIONS EARLY IN 1985. THE FGO PROCESS HAS
NOT YET BEEN SELECTED. PRIMARY PARTICULATE CONTROL WILL BE PROVIDED BY Atj
ELECTROSTATIC PRECIPITATOR OPSTHEAM UF THt FGD SYSltM. AN INDIRECT ISTEAM
COIL) HOT AIR INJECTION REHEAT SYSTEM WILL BE INCLUDED AT THE scwuBuEk
OUTLET. DESIGN SULFUR DIOXIDE REMOVAL EFFICIENCY WILL BE 90 PEP-CtNT.
TENNESSEE VALLEY AUTHORITY
JOHNSONVILLE
600 MW - RETROFIT
COAL
TVA/UNITED ENGINEERS
MAGNESIUM OXIDE
STARTUP 0/62
TVA IS PLANNING TO RETROFIT A 600-MW MAGNESIUM OXIDE FGD SYSTEM AT
THE JOHNSONVILLE STEAM PLANT, A 1500-MW COAL-FIRED STATION. ENGINEERING
ASSISTANCE WILL BE PROVIDED BY UNITED ENGINEERS. THIS PROJECT IS BUDGETED
AT $185 MILLION, INCLUDING THE COST OF A NEW 60U-FT. STACK.
TENNESSEE VALLEY AUTHORITY
PARADISE 1
650 MW - RETROFIT
COAL
VENDOR NOT SELECTED
LIMESTONE
STARTUP 0/62
TENNESSEE VALLEY AUTHORITY
PARADISE Z
650 MW - RETROFIT
COAL
VENDOR NOT SELECTED
LIMESTONE
STARTUP O/ 0
TVA IS REQUESTING/EVALUATING BID SPECIFICATIONS FOR TwO LIMESTONE SLURRY
FGD SYSTEMS WHICH WILL BE RETROFITTED ONTO TwO 65U-MW HIGH SULFUR COAL-
FIRED BOILERS AT THIS STATION. THE FGO SYSTEMS WILL TREAT 100X OF THE FLUE
GASES FROM BOTH UNITS. TVA HAS PROJECTED THE TOTAL COST OF THE PAKAOISE
FGD SYSTEMS TO BE APPROXIMATELY $820 MILLION ($170/KW). BIO REQUEST WAS
COMPLETED BY MID-NOVEMBER AND EVALUATION IS NOW IN PROGRESS. BID EVALUA-
TION IS EXPECTED TO BE COMPLETED BY JANUARY 1 AND A CONTRACT SHOOLD 8E
AWARDED SHORTLY THEREAFTER.
TVA IS REQUESTING/EVALUATING BIO SPECIFICATIONS FOR TnO LIMESTONE SLURRY
FGD SYSTEMS WHICH WILL BE RETROFITTED ONTO TWO 650-MW HIGH SULFUR CUAL-
FIRED BOILERS AT THIS STATION. THE FGD SYSTEMS WILL TREAT 1UOX OF THE FLUE
GASES FROM BOTH UNITS. TVA HAS PROJECTED THE TOTAL COST OF THE PARADISE
FGD SYSTEMS TO BE APPROXIMATELY $220 MILLION ($17U/KW). 8ID REQUEST WAS
COMPLETED BY MID-NOVEMBER AND EVALUATION IS NOW IN PROGRESS. BIO EVALUA-
TION is EXPECTED TO BE COMPLETED BY JANUARY i AND A CONTRACT SHOULD BE
AWARDED SHORTLY THEREAFTER.
19
-------
EPA UTILITY FGO SURVEY: OCTOBER 1<>78 - NOVEMBER 1978
SECTION 2
STATUS OF FGO SYSTEMS
UNIT IDENTIFICATION
CURRENT StAIUS
TENNESSEE VALLEY AUTHORITY
SHANNEE 10A
10 MW - RETROFIT
COAL; 2.9X SULFUR, 15.8X ASH
AIR CORRECTION DIVISION, UOP
LIME/LIMESTONE
STARTUP fl/72
REFER 10 THE BACKGROUND INFORMATION IN SbCUUN 3 OF THIS HEPURT. IH1S
TURBULENT CONTACT ABSORBER (TCA) LIHE/LlMESTUNfc SCRUBBING SYSTfcM HAS bEfcN
OPERATIONAL SINCE APRIL 1972. THIS TEST PROGRAM IS FUNDED BY THE tKA WITH
TVA AS THE CONSTRUCTOR AND FACILITY OPEKATUK. THt BtCHTtL CORP. OF SAN
FRANCISCO IS THE MAJOR CONTRACTOR, TEST OIRtCTOK, AND REPORT WRITER.
TESTING CHEMICAL ADDITIVES FOR IMPROVING S02 REMOVAL EFFICIENCY
CONTINUED THROUGH OCTOBER AND NOVEMBER. BOTH VtNTURl/SPRAY TUWfcK AND TCA
SYSTEMS WERE OPERATED ON LIMESTONE SLURRY WITH HIGH FLYASH LOADING.
TENNESSEE VALLEY AUTHORITY
SHAWNEE 108
10 MW - RETROFIT
COAL) 2.9X SULFUR, 15.8X ASH
CHEMICO
LIME/LIMESTONE
STARTUP 4/72
REFER TO THE BACKGROUND INFORMATION IN SECTION 3 OF THIS KF.PORT. THIS
VENTUR1/SPRAY TOWER LIME/LIMESTONE SCRUBBING SYSTEM HAS BttN OPERATIONAL
SINCE APRIL 1972. THIS TEST PROGRAM IS FUNDED BY THE EPA WITH TVA AS IHb
CONSTRUCTOR AND FACILITY OPERATOR. THE BECHTEL COKP. OF SAN FRANCISCO IS
THE MAJOR CONTRACTOR, TEST DIRECTOR, AND REPOKT WRITER. TESTING WITH
CHEMICAL ADDITIVES FOR IMPROVING 502 REMOVAL EFFICIENCY CUNTINUEO
THROUGH OCTOBER AND NOVEMBER. BOTH VENTURI/SPRAY TOWER AND TCA SYSTEMS
WERE OPERATED ON LIMESTONE SLURRY WITH HIGH FLYASH LOADING.
TENNESSEE VALLEY AUTHORITY
WIDOWS CREEK 7
575 MW - RETROFIT
COAL» 3.7X SULFUR
COMBUSTION ENGINEERING
LIMESTONE
STARTUP 10/80
TENNESSEE VALLEY AUTHORITY ANNOUNCED THAT A CONTRACT HAS BEEN AWAHllH> Tu
COMBUSTION ENGINEERING FOR A LIMESTONE SLURRY bPHAY TOWER FGO SYSTEM. THt
FGO SYSTEM WILL TREAT HIGH SULFUR COAL FLUE GAS. THE SPRAY TUwEK AUSUKbEWS
WILL BE CONSTRUCTED OF 317L STAINLESS STEEL. THt NO. 7 UNIT FIRES CUAL
WITH THE SAME CHARACTERISTICS AS THE COAL FIRED IN UNIT 8.
INITIAL OPERATIONS ARE SCHEDULED FOR OCTOBER 19BO. THE FGO SYSTEM IS
CURRENTLY UNDER CONSTRUCTION.
TENNESSEE VALLEY AUTHORITY
WIDOWS CREEK 8
550 MW - RETROFIT
COAL; 3.7x SULFUR, i7x ASH
TENNESSEE VALLEY AUTHORITY
LIMESTONE
STARTUP 5/77
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION.
THE EMISSION CONTROL SYSTEM FOR THIS bbO-Mw COAL-FIRED POwhR-GENERATING
UNIT CONSISTS OF EXISTING ELECTROSTATIC PRECIPITA10RS FOLLOWED BY FOUR
PARALLEL SCRUBBING TRAINS, EACH CAPABLE OF HANDLING 25 PERCENT OF THE
BOILER FLUE GAS FROM UNIT 8. EACH TRAIN INCLUDES A RECTANGULAR THROAT
VENTURI SCRUBBER AND A GRID-TOWER ABSORBER SUPPLIED BY PULYCON. THE GKID
TOWER CAN BE CONVERTED TO A MOBILE-BED TOWEK IF GREATER SU2 REMOVAL IS
REQUIRED.
TEXAS MUNICIPAL POWER AGENCY
GIBBONS CREEK 1
400 MW - NEW
LIGNITE; 1.06X SULFUR, 25X ASH
COMBUSTION ENGINEERING
LIMESTONE
STARTUP 1/82
COMBUSTION ENGINEERING WAS AWARDED A CONTRACT TU DESIGN ANO SUPPLY
A 400-HW LIGNITE-FIRED BOILER, ESP, AND FGD SYSTEM AT GIBBONS CREEK
STEAM ELECTRIC STATION UNIT NO. 1. THE BOILER WILL BURN l.ObX SULFUR
LIGNITE. FLUE GAS WILL BE CLEANED OF PARTICULATES BY A COLO-S10E ESP
(99.73X EFFICIENCY). SU2 WILL BE REMOVED BY 3 SPRAY TOWER MODULES UTILU-
ING A LIMESTONE SLURRY (72.5 TO 87.5X EFFICIENCY). A CONTRACT HAS BEEN
AWARDED TO IOCS FOR SLUDGE DISPOSAL. CONSTRUCTION IS TO BEGIN IN THE
SPRING OF 1979. COMMERCIAL START-UP IS SCHEDULED FOR JANUARY, 19«2.
TEXAS POWER & LIGHT
SANDOW 4
545 MW - NEW
LIGNITE
COMBUSTION ENGINEERING
LIMESTONE
STARTUP 7/80
COMBUSTION ENGINEERING HAS BEEN CHOSEN AS THE BOILER AND FGO VENDOR FUR
THIS UNIT. BOILER CONSTRUCTION BEGAN ON SEPTEMBER 9, 19/7. PARTICULAR
REMOVAL EQUIPMENT WILL BE LOCATED ON THE COLD-SIDE UF THE AIR HEATER.
SOME PORTION OF FLUE GAS WILL BYPASS THE SCRUBBER FUR REHEAT. THE SPENT
SLURRY WILL BE PONDED AND WATER RECYCLED. FGD CONSTRUCTION IS SCHEDULED
TO BEGIN NOVEMBER 1978.
TEXAS POWER & LIGHT
TWIN OAKS t
750 MW - NEW
LIGNITE
VENDOR NOT SELECTED
LIMESTONE
STARTUP 8/63
THIS UNIT WILL BE JOINTLY OWNED BY TP&L AND ALCOA. A FIRM DECISION HAS
NOT BEEN MADE WHETHER TU INSTALL FGD FACILITIES. THIS IS PRIMARILY
DUE TO THE FACT THAT SUCH A DECISION IS NOT YET REQUIRED IN THE
UTILITIES PLANNING TIMETABLE.
TEXAS POWER * LIGHT
TWIN OAKS 2
750 MW - NEW
LIGNITE
VENDOR NOT SELECTED
LIMESTONE
STARTUP 9/84
THIS UNIT WILL HE JOINTLY OWNED BY TPfcL AND ALCUA. A FIRM DECISION HAS
NOT BEEN MADE WHETHER TO INSTALL FGD FACILITIES. THIS IS PRIMARILY
DUE TO THE FACT THAT SUCH A DECISION IS NOT YET REQUIRED IN THE
UTILITIES PLANNING TIMETABLE.
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVtKBtk
UNIT IDENTIFICATION
SECTION a
STATUS OF FGO SYSTEMS
CURRENT STATUS
TEXAS UTILITIES
FOREST GROVE 1
750 MW - NEW
LIGNITE
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP 0/81
TEXAS UTILITIES IS PLANNING A NEK 7bO-Mrt UNIT Al TMt FUREM GROVt blTt.
TWO ESP'S WILL BE INSTALLED FOR PARTICULATE CUNTHOL. THE UTILITY IS
CURRENTLY REQUESTING BIOS FOR AN FGD SYSTEM. START-UP IS SCHEDULED FUR
LATE 1981. THE BOILER WILL BE SUPPLIED BY THE BABCOCK A wlLCOX COMHAMt.
THE DESIGN DOES NOT INCLUDE A STACK GAS REHEAT SYSTEM.
TEXAS UTILITIES
MARTIN LAKE 1
793 MN - NEW
COAL) 0.9X SULFUR, 8X ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 8/77
TEXAS UTILITIES
MARTIN LAKE 2
793 MW - NEW
COAL; o.9x SULFUR, az ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 5/78
TEXAS UTILITIES
MARTIN LAKE 3
793 MM - NEW
COAL; o.9z SULFUR, ax ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 12/78
TEXAS UTILITIES
MARTIN LAKE 4
793 MM - NEM
COAL; o.9z SULFUR, sx ASH
RESEARCH COTTRELL
LIMESTONE
STARTUP 8/50
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION. THIS lit* 74.5
MW UNIT FIRES TEXAS LIGNITE CONTAINING U.9X SULFUK IAVG) AMD 8X ASH
(AVG). THE UNIT IS EQUIPPED WITH AN EMISSION CONTROL SYSTEM WHICH INCLUDES
COLD-SIDE ESP'S AND A LIMESTONE FGD SYSTEM bUTH SUPPLIED BY RESEAKCH-CUT-
TRELL. THE FGD SYSTEM CONSISTS OF b PACKED/SPRAY TO«tK ABSORBERS AHICH
TREAT 75X OF THE TOTAL BOILER FLUE GAS. THE REGAINING FLUE GAS I-S HYPASStU
FOR REHEAT. TOTAL 302 REMOVAL EFFICIENCY IS 7U.bX. THE FLUE GAS CLF.AMUG
WASTES ARE STABILIZED AND DISPOSED IN AN ON-SITE, LANDFILL.
REFER TO SECTION 3 OF THTS REPORT FOR ADDITIONAL INFUKMAT ION. IH1S NE« 79.5
MW UNIT FIRES TEXAS LIGNITE CONTAINING 0.9X SULFUK (.AVG) AND SX ASH tAVU).
THE UNIT IS EQUIPPED WITH AN EMISSION CONTROL SYSTEM CONSISTING UF COLD-
SIDE ESP'S AND A LIMESTONE FGO SYSTEM, BOTH SUPPLIED BY HESEAHCH-COTTHtLL.
THE FGD SYSTEM CONSISTS OF 6 PACKED/SPRAY TOWtR ABSORBERS THAT CHEAT 7bX
OF THE BOILER FLUE GAS. THE REMAINING GAS IS BYPASSED FUR REHEAl. TUTAL
DESIGN S02 REMOVAL EFFICIENCY IS 70.5X. THE FLUE GAS CLEANING rtASTES ARE
STABILIZED AND DISPOSED IN AN ON-SITE, LANDFILL.
THIS NEW 793-MW POWER GENERATING UNIT WILL FIRE TEXAS LIGNITE CONTAINING
0.9X SULFUR (AVG.) AND HZ ASH (AVG.). TU MEET FEDERAL NSPS, THk UNIT WILL
BE EQUIPPED WITH AN EMISSION CONTROL SYSTEM CONSISTING UF COLD-SIDt ESP'b
AND A LIMESTONE FGO SYSTEM, BOTH SUPPLIED BY RESEARCH-COTTRELL. THt FtiU
SYSTEM CONSISTS OF b PACKED/SPRAY TUWER ABSORBERS WHICH HILL TREAT 7bi UF
THE TOTAL BOILER FLUE GAS. THE REMAINING GAS WILL BE BYPASSED FDR REHEAT.
TOTAL DESIGN S02 REMOVAL EFFICIENCY IS 70.SX. THE FLUt GAS CLEANING rtASIES
WILL BE STABILIZED AND DISPOSED IN AN ON-SITE, LANDFILL.
THE CONTRACT FOR THIS FGD SYSTEM HAS BEEN AWARDED Fu RESEARCH-COTTRELL.
THE BOILER IS NOW BEING ERECTED. START-UP HAS BEEN DELAYED TO EITHER 19«b
OR 1986.
TEXAS UTILITIES
MONTICELLO 3
750 MM - NEM
LIGNITE* 1.5Z SULFUR, 19X ASH
CHEMICO
LIMESTONE
STARTUP 5/78
UTAH POWER ft LIGHT
EMERY 1
400 MW - NEW
COAL; o.sx SULFUR, 9-i2z ASH
CHEMICO
LIME
STARTUP 1/79
UTAH POWER « LIGHT
EMERY 2
400 MM • NEW
COAL; o.sx SULFUR, 9-12X ASH
CHEMICO
LIME
STARTUP 6/80
REFER TO SECTION 3 OF THIS REPORT FOR ADDITIONAL INFORMATION. THE
CONTROL SYSTEM FOR THIS UNIT CONSISTS OF A HIGH EFFICIENCY ESP AMD A LIKE-
STONE FGD SYSTEM. THE ESP (POLLUTION CONTROL-WALTHER) PROVIDES PRIMARY
PARTICULATE CONTROL (99.56Z). THE FGD SYSTEM CONSISTS OF 1 LIMESTONt
SCRUBBING SPRAY TOWERS THAT PROVIDE PRIMARI S08 CONTROL (7UZ). (HE FGD
SYSTEM IS DESIGNED TO TREAT 3MM ACFM OF FLUE GAS RESULTING FROM COAL WITH
l.SZ SULFUR, 18.9Z ASH AND O.OOZ CL. THE FLUE GAS CLEANING WASTES ARE
DISPOSED IN AN ON-SITE, LINED POND.
A CONTRACT HAS BEEN AWARDED TO THE CHEMICO AIR POLLUTION DIVISION FOR
A PEBBLE LIME WET SCRUBBING SYSTEM ON THIS NEW UNIT. THE SCRUBBING
SYSTEM IS DESIGNED TO OPERATE IN AN OPEN WATER LOOP MODE WITH AN SOS
REMOVAL EFFICIENCY OF 80 PERCENT FOR LOW SULFUR UTAH COAL. PRIMARY
PARTICULATE CONTROL WILL BE PROVIDED BY AN ESP UPSTREAM OF THE SCRUBBERS.
THE SLUDGE MILL BE STABILIZED WITH FLYASH AND DISPOSED ON THE PLANT SITE.
THE A-E DESIGN FIRM FOR THIS PROJECT IS STEARNS-ROGER. CONSTRUCTION IS NU«
IN ITS FINAL STAGES. START-UP MAY BE PUSHED BACK TO FEBRUARY.
UTAH P»L AWARDED CHEMICO A CONTRACT TO SUPPLY A LIME FGD SYSTEM FOR
EMERY 2 DESIGNED TO OPERATE IN AN OPEN WATER LOOP MODE WITH AN 505 REMOVAL
EFFICIENCY OF 80 PERCENT (FIRING LOW SULFUR UTAH COAL). PRIMARY PARTIC-
ULATE CONTROL WILL BE PROVIDED BY AN ESP UP-STREAM OF THE SCRUBBERS. THE
SLUDGE WILL BE STABILIZED WITH FLYASH AND DISPOSED ON THE PLANT SITt.
INITIAL BOILER AND FGO SYSTEM START-UP IS SCHEDULED FOR JUNE 19«0. THIS
UNIT WILL BE IDENTICAL TO UNIT 1. CONSTRUCTION ON THIS UNIT IS NOW ABUUT
35X COMPLETE. THIS UNIT WILL BE IDENTICAL TU UNIT ONE.
21
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EPA UTILITY FGO SURVEY: OCTOBER 1976 - NOVEMBER 1978
SECTION 2
STATUS OF FGO SYSTEMS
UNIT IDENTIFICATION
CURRENT STATUS
UTAH POWER ft LIGHT
HUNTINGTON 1
415 MW - NEH
COAL; O.SX SULFUR, 101 ASH
CHEHICO
LIME
STARTUP 5/78
REFER TO SECTION 3 OF THIS RFPORT FOR ADDITIONAL INFORMATION. CHEMICO WAS
THE SUPPLIER OF A LIME SCRUBBING SYSTEM FOH THIS NEW UNIT. PRIMARY PAKTIC-
ULATE REMOVAL IS PROVIDED BY AN ESP INSTALLED UHSTKtAM OF THE WEI SCRUB-
BING SYSTEM. A DAMPER IS USED DURING OPERATION TO ALLOW BETWEEN 10 AND «JU
PERCENT OF THE FLUE GAS TO BY-PASS THE FGD SYSTEM. DESIGN REMOVAL EFFI-
CIENCIES FOR 302 AND PARTICULATE ARE 80 AND 99.5 PERCENT KESPECTIVELY .
SLUDGE IS DEWATERED (60X SOLIDS) AND TRUCKED TO AN UN-SITE LANDFILL.
INITIAL OPERATIONS AT THIS UNIT BEGAN ON MAY 10, 1978.
VIRGINIA ELECTRIC 8 POWER
MT. STORM
1147 MW - RETROFIT
COAL
VENDOR NOT SELECTED
PROCESS NOT SELECTED
STARTUP O/ 0
THE UTILITY IS CURRENTLY WAITING FOR AN EPA DECISION REGARDING A WEST
VIRGINIA STATE EMISSION CONTROL PROPOSAL. PLANS FOR SULFUR DIOXIDE
CONTROL ARE TEMPORARILY AT A STANDSTILL PENDING THIS DECISION. IF THE
PRESENT PROPOSAL IS ACCEPTED AN FGD SYSTEM MAY NOT BE REQUIRED.
WISCONSIN POWER * LIGHT
COLUMBIA 2
527 MW - NEW
COAL} O.BZ SULFUR
CHEMICO
LIME/ALKALINE FLYASH
STARTUP 1/80
A CONTRACT HAS BEEN AWARDED TO CHEMICO FOR A LIME/FLYASH FGD SYS-
TEM. IT WILL CONSIST OF TWO SPRAY MODULES WITH A HOT-SIDE ESP FUR PAR-
TICULATE REMOVAL. A CLOSED LOOP WATER SYSTEM IS ANTICIPATED WITH FLYASH
STABILIZATION OF THE SLUDGE. A SLUDGE DISPOSAL POND LOCATED OFF-SITE IS
BEING CONSIDERED. THE FGD SYSTEM IS BEING DESIGNED TO TREAT bOX OF THE
FLUE GAS RESULTING FROM THE COMBUSTION OF LOW SULFUR COLSTRIP COAL. THE
REMAINING 40X WILL BE BYPASSED FOR REHEAT.
22
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EPA UTILITY FGD SURVEY: OCTObEH 1978 - NOVEMHEK 1S/B
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME ALABAMA ELECTRIC COOP
UNIT NAME TOMBIGBEE Z
UNIT LOCATION JACKSON ALABAMA
UNIT RATING ZZ5 Mw
FUEL CHARACTERISTICS COAL; l.lbX SULFUR
FGD VENDOR PEABODY PROCESS SYSTEMS
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 9/78
EFFICIENCY:
PARTICIPATES (ACTUAL)
(DESIGN) 99.6 PERCENT
S03 (ACTUAL)
(DESIGN) 60.0 PERCENT
WATER MAKE UP OPEN LOOP 1.10 GPM/MW
SLUDGE DISPOSAL UNSTABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
i
AUGUST-SEPTEMBER 1978 - INITIAL OPERATION OF THIS UNIT BEGAN DURING THE AUGUST-SEPTEMBER REPUKT ,
PERIOD. THE FGO SYSTEM IS CURRENTLY IN THE SHAKEDOWN AND DEBUGGING PHASE UF UPEKATIUN. DUE TO/
-------
EPA UTILITY F60 SURVEY: OCTOBER 1<>78 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME ARIZONA ELECTRIC POWER COOP
UNIT NAME APACHE 2
UNIT LOCATION COCHISE ARIZONA
UNIT RATING 800 MW
FUEL CHARACTERISTICS COAL; 0.7X SULFUR, 10X ASH
F60 VENDOR RESEARCH COTTRELL
PROCESS LIMESTONE
NEN OR RETROFIT NEW
START UP DATE 8/76
EFFICIENCY!
PARTICIPATES (ACTUAL)
(DESIGN) 99.4 PERCENT
303 (ACTUAL)
(DESIGN) 8S.O PERCENT
MATER MAKE UP OPEN LOOP 9.2 GPM/MW
SLUDGE DISPOSAL UNSTABILIZtD/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
AUGiT-SEPTEMBER 1978 - INITIAL OPERATION OF THE FGD SYSTEM AT THIS UNIT BEGAN IN AUGUST AND II IS
CURlNTLY BEING TESTED. NO INITIAL PROBLEMS HAVE BEEN REPORTED. DUE TO THE RECENT OPERATING STATUS
HOUR OF OPERATION ARE NOT YET AVAILABLE.
PERI) BOILER FGD HOURS OPEHABIL1TY (X) UTILIZATION (X)
OPERATION (HR) A B AH AH
OCT. | 303 N/A N/A N/A N/A N/A N/A
BOiER OUTPUT = 86,379 MW-H
NOV. 7 468 121 213 25 44 17 30
OUTPUT = 116,217 MW-H
COMPLIANCE TEST WAS COMPLETED, BUT THE RESULTS ARE NOT YET AVAILABLE. AN ACCEPTANCE TEST
5 SCHEDULED FOR THE BEGINNING OF 1979. THE ONLY PROBLEM REPORTED BY THE UTILITY WAS THE
(ABILITY OF THE LIMESTONE CRUSHER TO MEET DESIGN CAPACITY.
-------
EPA UTILITY FGO SURVEY: OCTUBtk 1978 - NOVEMbtK 19/a
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
ARIZONA PUBLIC SERVICE
CHOLLA 1
JOSEPH CITY ARIZONA
115 MW
FUEL CHARACTERISTICS COAL; 0.55X SULFUR. 10X ASH
F60 VENDOR RESEARCH COTTRELL
PROCESS LIMESTONE
NEW OR RETROFIT RETROFIT
START UP DATE 10/73
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
303 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
99.7 PERCENT
99.7 PERCENT
50-60 PERCENT
58.5 PERCENT
OPEN LOOP 1.04 GPM/MW
UNSTABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
RELIABILITY (X)
MONTH MODULE A MODULE B
JAN. 78 97 91
FEB. 78 99 88
MAR.
APR.
MAY
JUNE
JULY
AUG.
SEP.
OCT.
NOV.
78
78
78
78
78
78
78
78
78
74
100
87
100
99
100
100
100
100
74
100
90
100
100
95
too
100
too
COMMENTS
THE FLOODED DISC SCRUBBER TANK HEADER FOR SLURRY LIMESTONE
REPAIRED AFTER BEING DAMAGED DURING THE OVERHAUL. THE BUILER
WAS OPERATED ONLY 135 HRS. DURING JANUARY AS THE OVERHAUL HAU
EXTENDED INTO THIS MONTH. THE A-SIDE ANU 8-SIDE SERVICE HOURS
WERE 131 AND 183 HOURS RESPECTIVELY.
SOME MINOR LEAK REPAIRS AFTER THE OVERHAUL/CLEANING TOUK PLACE
DURING FEBRUARY. SERVICE HOURS MERE: BOILER = 642, A-SIOE =
636, B-SIDE = 564.
ONE FORCED SHUTDOWN OCCURRED ON THE A-SIOE. SERVICE HOURS HERE:
BOILER = 744, A-SIOE = 744, B-SIDE = 735.
A MINOR LEAK REPAIR MAS NECESSARY AFTER AN OVERHAUL/CLEANING.
SERVICE HOURS WERE: BOILER = 780, A-SIDE = 667, B-SIDE = 7£u.
THERE WERE NO SIGNIFICANT PROBLEMS REPORTED. ONLY GENERAL
MAINTENANCE WAS PERFORMED ON THE SYSTEM.
NO PROBLEMS WERE REPORTED.
ONLY ROUTINE MAINTENANCE WAS REQUIRED.
REPAIRS WERE NECESSARY TO PLUGGED B-SIDE REHEAT COILS.
NO PROBLEMS WERE REPORTED. SERVICE HOURS WERE: BOILER = 720,
A-SIDE s 720,.B-SIDE = 704.
ONLY ROUTINE MAINTENANCE WAS REQUIRED. SERVICE HOURS WERE:
BOILER * 434, A-SIDE > 434, B-SIDE * 416.
NO PROBLEMS WERE REPORTED. SERVICE HOURS WERE: BOILER - 720
A-SIDE = 720, B-SIDE = 657.
25
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME ARIZONA PUBLIC SERVICE
UNIT NAME CHOLLA 2
UNIT LOCATION JOSEPH CITY ARIZONA
UNIT RATING 250 MM
FUEL CHARACTERISTICS COAL; 0.55Z SULFUR, 10Z ASH
FGD VENDOR RESEARCH COTTRELL
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 6/70
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 99.7 PERCENT
302 (ACTUAL)
(DESIGN) 75.0 PERCENT
MATER MAKE UP OPEN LOOP
SLUDGE DISPOSAL UNSTABILIZEO/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
APRIL-HAY 1978 - THE SCRUBBER ON UNIT 2 IS NOW WORKING MOST OF THE TIME AND IS THEREFORE CONSIDERED
TO BE OPERATIONAL. SOME PROBLEMS HAVE OCCURRED WITH VIBRATIONS THROUGH THE SYSTEM. THE EPA HAS
GRANTED THE UTILITY AN EXTENSION FOR COMPLIANCE.
JUNE-JULY 1978 - UNIT 2 IS STILL UNDERGOING SHAKEDOWN AND DEBUGGING OPERATIONS. THE SLURRY RECYCLE
PIPING HAS EXPERIENCED CONTINUAL VIBRATION. THE CONTRACTOR HAS BEEN INJECTING NITROGEN (GAS) INTO
THE LINES TO DAMPEN THE VIBRATIONS (AIR WAS NOT USED BECAUSE THE SULFITE WOULD BE OXIDIZED TO
SULFATE AND RESULT IN SCALE FORMATION IN THE SYSTEM). A PROBLEM HAS ALSO OCCURRED WITH PEELING OF
THE CORROSION RESISTANT COATING IN THE OOWNCOMER AREA IN ONE OF THE ABSORBER MODULES.
AUGUST-SEPTEMBER 1970 - SHAKEDOWN/DEBUGGING OPERATIONS CONTINUE. THE SLURKY RECYCLE PIPING IS STILL
EXPERIENCING RESONANT VIBRATIONS.
OCTOBER-NOVEMBER 1976 - THE SHAKEDOWN/DEBUGGING OPERATIONS CONTINUE. SOME SCRUBBER COMPONENTS ARE
STILL MANNED BY BECHTEL STAFF ALTHOUGH APS IS OPERATING MOST OF THE SYSTEM.
-------
EPA UTILITY F60 SUHVEY: OCTOBER 1978 - NOVEMBtK 197B
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL F6D SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
CENTRAL ILLINOIS LIGHT
DUCK CREEK 1
CANTON ILLINOIS
400 MN
FUEL CHARACTERISTICS COAL; 3.3X SULFUR, 6.3X ASH
FGO VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
302 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
RILEY STOKER / ENVIRONEERING
LIMESTONE
NEW
7/78
99.8 PERCENT
99.8 PERCENT
85.0 PERCENT
CLOSED LOOP 1.5 GPM/MW
UNSTABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
JUNE-JULY 1978 • ALL 4 MODULES BECAME OPERATIONAL ON JULY 24. THE SYSTEM HAS OPERATED INTERMIT-
TENTLY THROUGHOUT THE PERIOD. MODIFICATIONS WERE MADE TO THE SLURRY TRANSFER TANK, SINCE IT HAS
FOUND TO BE UNDER DESIGNED. A PLUGGING PROBLEM OCCURRED IN THE FGD SYSTEM DUE TO COAL FINES BEING
MIXED IN WITH THE SLURRY. THIS RESULTED FROM THE USE OF COMMON UNLOADING AND TRANSFER SYSTEMS FUR
THE COAL AND LIMESTONE.
PERIOD
TOTAL
PERIOD (HR)
AUG. 78 744
AVAILABILITY = 45X
OPERABILITY = 46X
RELIABILITY = 46X
UTILIZATION = 42X
BOILER
OPERATION (HR)
691
691
SYSTEM
AVAILABILITY (HR)
333
333
SYSTEM CALLED
TO OPERATE (HR)
685
685
HR. SYSTEM
OPERATED
315
315
SEP. 78 720
AVAILABILITY = 46X
OPERABILITY s 46X
RELIABILITY = 46X
UTILIZATION = 44X
PROBLEMS CONTINUED WITH THE COMMON COAL AN D LIMESTONE UNLOADING FACILITY THROUGH AUGUST AND
SCREEN BASKETS WERE USED TO KEEP COAL PARTICLES OUT OF THE LIMESTONE IN
MORE PERMANENT SEPARATOR SYSTEMS ARE BEING STUDIED.
DESIGN DEFICIENCIES IN THE SLURRY TRANSFER SYSTEM PREVENTED PROPER FLOW OF THE SLURRY TU THE
SCRUBBER MODULE RECYCLE TANKS. THE OLD SYSTEM MAS REMOVED AND A NEW PIPING SYSTEM MAS IN-
STALLED. NO PROBLEMS HAVE BEEN ENCOUNTERED WITH THE NEW SYSTEM. PLUGGING OF THE RECYCLE
PUMP SHUT-OFF VALVES OCCURRED AND THEY ARE BEING REPLACED WITH PINCH VALVES. THE SCRUBBER
WASTE WATER SUMP PUMPS HAVE ALSO BEEN PLUGGING AND NEW PUMPS ARE BEING INVESTIGATED.
SEPTEMBER.
ORDER TO PREVENT NOZZLE PLUGGING.
27
-------
EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 1978
TOTAL BOILER SYSTEM SYSTEM CALLED HR. SYSIEM
PERIOD PERIOD (HR) OPERATION (HR) AVAILABILITY IHR) TO OPERATE (HR) OPERATED
OCT. 78 7<1
-------
EPA UTILITY FGO SUHVEY: UCTOBEk 1978 - MOVt^rtEK
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
COLUMBUS » SOUTHERN OHIO ELEC.
CONESVILLE 5
CONESV1LLE OHIO
400 MW
FUEL CHARACTERISTICS COAL; 4.7X SULFUR, 15.U ASM
FGD VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
802 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
AIR CORRECTION DIVISION, UOP
LIME (M6-PROMOTED)
NEW
1/77
99.6 PERCENT
89.5 PERCENT
OPEN LOOP 1.25 GPM/Mh
STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
PERIOD
OPERATION TIME (HR)
BOILER A-SIDE B-SIDE
JAN. 78 00
ALL INDEX VALUES = 0 PERCENT
FEB. 78
ALL INDEX VALUES = 0 PERCENT
HAR. 78 379 72 60
AVAJUABUJTY <*) = 20 20
OPERABILITY (X) = 19 16
RELIABILITY (X) = 64 54
UTILIZATION (X) =10 8
APR. 78 716 418 425
AVAILABILITY (X) = 67 65
OPERABILITY (X) s SB 59
RELIABILITY (X) = 61 63
UTILIZATION (X) = 58 59
MAY 78 720 327 365
AVAILABILITY (X) = 52 54
OPERABILITY (X) a 45 50
RELIABILITY (X) = 45 51
UTILIZATION (X) = 44 49
JUNE 76 720 269 217
AVAILABILITY (X) = 48 30
OPERABILITY (X) * 37 30
RELIABILITY (X) * 37 30
UTILIZATION (X) s 37 30
JULY 78 727 478 240
AVAILABILITY (X) « 66 43
OPERABILITY (X) s 66 33
RELIABILITY (X) * 66 33
UTILIZATION (X) s 64 32
COMMENTS
THE UNIT WAS SHUTDOWN FUK OVERHAUL THROUGH FEBRUARY ANI
STARTED UP ON MARCH 16.
IMPURITIES IN LIME HAVE CAUSED PLUGGING PROBLEMS. PH
CONTROLS AND SU2 ANALYSERS HAVE GIVEN SOME UPEKAT ION»L
PROBLEMS.
THE SYSTEM WAS DOWN DUE TO AN EXCESS OF FLUCCULAM
IN THE THICKENER. THIS CAUSED A HIGH AMOUNT UF SOLIDS
IN THE OVERFLOW THAT RESULTED IN PLUGGING PHUHLEMS IN
THE ABSOKBER MODULES.
THE SYSTEM WAS TAKEN OUT OF SEKVICE BECAUSE UF CONTINUED
PROBLEMS WITH THE FLOCCULANT FEED SYSTEM. THE THICKENtR
WAS EMPTIED TO RESTORE PROPER FLUCCULANT BALANCE.
FLOCCULANT WAS CLEANED OUT.
AN FRP PIPING FAILURE IN THE MIST ELIMINATOR NASH
SYSTEM OCCURRED IN JUNE.
OUTAGE TIME WAS DUE TO PLUGGING IN THE MIST ELIMINATOR
AND SCRUBBER BALL REGIONS.
29
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
COLUMBUS ft SOUTHERN OHIO ELEC.
OPERATION TIME (HR)
PERIOD BOILER A-SIDE B-SIOE
»US. 76 667 134 137
AVAILABILITY (X) = 18 18
OPERABILITY (X) s 20 21
RELIABILITY (X) s 20 21
UTILIZATION (X) s 18 18
SEP. 78 707 324 300
AVAILABILITY (X) = 61 54
OPERABILITY (X) = 46 44
RELIABILITY (X) s 55 53
UTILIZATION (X) = 45 43
OCT. 78 713 268 335
AVAILABILITY (X) = 72 82
OPERABILITY = (X) 37 47
RELIABILITY = (X) 38 47
UTILIZATION = (X) 36 45
NOV. 78 642 187 475
AVAILABILITY = (X) 43 64
OPERABILITY (X) r 29 74
RELIABILITY (X) s 29 75
UTILIZATION (X) = 26 66
CONESVILLE 5
COMMENTS
FORCED OUTAGE TIME WAS REQUIRED TO REMOVE SCALE
FROM THE MIST ELIMINATOR. IT WAS ALSO NECESSAKT TO HE-
PLACE SOME OF THE PING PONG BALLS IN THE MODULES.
DURING THE AUGUST-SEPTEMBER REPORT PERIOD PROBLEMS WERE
ENCOUNTERED WITH THE BYPASS DAMPERS. UTHER PROBLEM
AREAS INCLUDED BROKEN SLUDGE LINES AND PLUGGING OF- THE
LIME SLURRY FEED LINES.
DURING THE OCTOBER-NOVEMBER KEPORT PERIOD PROBLEMS,Wl TH
THE DAMPER DRIVE WERE REPORTED. ALSO MINIMAL kUbBER
LINER FAILURE WAS OBSERVED AT THE TOP OF THE SCKUBBEH
MODULE AND JUST AFTER THE PRESATURATUR.
30
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EPA UTILITY FGU SURVEY: OCT08EK 1978 - NUVEI"BEN 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL F6D SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
COLUMBUS & SOUTHERN OHIU ELEC.
CONESVILLE 6
CONESVILLE OHIO
000 Mw
FUEL CHARACTERISTICS COALj 4.67X SULFUR, 15.IX ASH
FGO VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
302 (ACTUAL)
(DESIGN)
HATER MAKE UP
SLUDGE DISPOSAL
AIR CORRECTION DIVISION, UOP
LIME (MG-PROMOTED)
NEW
6/76
99.6 PERCENT
89.5 PERCENT
OPEN LOOP 1.25 GPM/MW
STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
PERIOD
OPERATION TIME (HR)
BOILER A-SIDE B-SIDE
JUNE 78 524 173 175
AVAILABILITY (X) = 56 44
OPERABILITY (X) = 49 33
RELIABILITY (X) = 51 34
UTILIZATION (X) = 42 30
JULY 78 502 166 96
AVAILABILITY U) = 83 70
OPERABILITY (X) a 37 19
RELIABILITY (X) = 63 33
UTILIZATION (X) - 25 13
AUG. 76 642 318 390
AVAILABILITY (X) = 47 62
OPERABILITY (X) = 50 60
RELIABILITY (X) = 66 61
UTILIZATION (X) = 43 52
SEP. 78 706 356 388
AVAILABLITY (X) c 55 69
OPERABILITY (X) = 50 55
RELIABILITY (X) r S3 57
UTILIZATION (X) = 49 54
OCT. 78 603 181 218
AVAILABILITY (X) c 98 37
OPERABILITY (X) » 29 35
RELIABILITY (X) a 30 36
UTILIZATION (X) * 24 29
NOV. 78 480 14 43
AVAILABILITY (X) s 26 26
OPERABILITY (X) = 3 9
RELIABILITY (X) « 3 6
UTILIZATION (X) * 2 8
COMMENTS
CONTROL OF THE LOUVERED DAMPER OF THE BYPASS SYSTEM
WAS LOST. THE RESULT WAS A BACK PRESSURE BUILD UP
THAT AUTOMATICALLY TRIPPED THE BOILEK OFF. SCRUBBER
CONTROLS WERE NOT OPERATING PROPERLY AND NEEDED ADJUST-
MENT.
THE LOUVERED DAMPER PROBLEM CONTINUED. 3CKUBBEH
CONTROLS WERE ADJUSTED. THE FRP TRANSFER LINE FROM
THE THICKENER TO THE IUCS SYSTEM RUPTURED AS A RESULT
OF A WATER HAMMER IN THE LINES AND HAD TU BE REPAIRED.
THE LINE BECAME PLUGGED AT A "Y" VALVE DURING DUhN TIME.
DURING AUGUST PROBLEMS WERE ENCOUNTERED WITH THE SLUDGE
LINE AS WELL AS THE BY-PASS CONTROL DAMPERS. THE
UTILITY REPORTS THAT THESE ARE TYPICALLY HIGH MAIN-
TENANCE AREAS.
THE BY-PASS DAMPER CONTROL PROBLEMS CONTINUED THROUGH
SEPTEMBER. ANOTHER PROBLEM AREA WAS THE PLUGGING OF
THE LIME SLURRY FEED LINES.
PROBLEMS WITH DAMPER SEAL AND GUIDEBARS WERE ENCOUNT-
ERED. THE UTILITY PLANS TO REPLACE THEM DURING THE
NEXT BOILER OUTAGE.
LIME TRANSFER UAGHOUSE SHAKER PROBLEMS WERE EXPERIENCED
DURING NOVEMBER. ALSO DURING NOVEMBER THE THICKENER
RAKE MOTOR BURNED OUT AND HAD TO BE REWOUND CAUSING
DOWNTIME.
-------
EPA UTIUITV F60 SURVEYS OCTOBER 1978 - NOVEMBER 197fl
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
OUOUESNE LIGHT
ELRAMA POWER STATION
ELRAMA PENNSYLVANIA
510 Mw
FUEL CHARACTERISTICS COAL; 22 SULFUR, 16.SZ ASH
FGD VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY!
PARTICIPATES (ACTUAL)
(DESIGN)
302 (ACTUAL)
(DESIGN)
HATER MAKE UP
SLUDGE DISPOSAL
CHEMICO
LIME
RETROFIT
10/75
99.0 PERCENT
99.0 PERCENT
75+ PERCENT
63.0 PERCENT
OPEN LOOP
STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE!
PERIOD
JAN. 76
OPERATING HOURS
BOILER SCRUBBER-ABSORBER VESSELS
101 201 301 401 501
700 673 36 161
26
DURING THE PERIOD A NEW WURMfcR RECYCLE PUMP IN-
STALLED IN NOVEMBER EXPERIENCED JACK SHAFT BEARING
PROBLEMS RESULTING IN THE REMOVAL UF TWAIN 501
FROM SERVICE. BOILEK NO. « WAS CONNECTED ADDING
AN ADDITIONAL 176 Mw LUAO TU THE SYSTtM. THt
IUCS SLUDGE DISPOSAL FACILITY IS NUW IN SEKVICh.
A LOW LOAD DEMAND AND THE COAL STKIKE HAVE
HAMPERED SCRUBBER OPERATIONS. THEKE IS SOME
OUTAGE TIME SCHEDULED FOR MARCH.
FEB. 78
MAR. 78
204 277 0 107 121 THE SYSTEM WAS SHUTDUWN UN FEB. 11 DUE TU A COAL
00000 SHORTAGE. THE FOLLOWING REPAIKS WERE MADt DURING
THE OUTAGE WHICH CONTINUED THROUGH MARCH:
* BOILER EXIT DAMPERS WERE LINED WITH 316 SS UN
AREAS OF HIGH EROSION CAUSED BY FLYASH IM-
PINGEMENT.
* EXPANSION JOINTS IN THE UPSTREAM DUCTWORK
WERE SHIELDED BY METAL PLATES WHICH WERE
WELDED AT ONE END.
* EXPANSION JOINTS IN THE DOWNSTREAM DUCTWORK
WERE COMPLETELY REPLACED.
* THE DOWNSTREAM DUCTWORK WAS RELINED WITH
CEILCOTE.
* MODULE 401 INTERNALS WEKE CLEANED AND SUME
HOLES IN THE UPPER CONICAL REGION WERE RE-
PAIRED.
BOILERS 1, Z AND 4 ARE NOW COMPLETELY CONNECTED
TO THE FGD SYSTEM. BOILER 3 13 UNDERGOING
AN EXTENSIVE OVERHAUL AND WILL BE CONNECTED TO
THE SYSTEM IN LATE APRIL.
32
-------
EPA UTILITY FGO SURVEY: UCTOdeR 197B - NOVEMBER 1478
DUOUESNE LIGHT ELRAMA POKEn STATION
OPERATING HOURS
BOILER SCRUBBER-ABSORBER
MONTH 1234 AVG 101 201 501 401 501 AVG
APR. 78 699 526 0 672 475
MAY 78 723 723 0 740 547
DURING THE APRIL-MAY PERIOD BOILER NUM8EK 3 WAS STILL BEING OVERHAULED. HGC SYSTtM CUNSfKilC-
TION WAS COMPLETED AND PRELIMINARY TESTING VERIFIED SYSTEM S02 REMOVAL EFFICIENCY.
JUNE 78 691 616 0 662 492
JULY 78 691 640 588 729 662
MODULE 301 WAS PULLED OFF FOR A MAJOR CLEANING OVER THE PERIOD. MIST F.LIKIN.10K PLUGGING hAS
EXPERIENCED AS A RESULT OF LOW PH. THE CHRONIC INABILITY TO CONTROL CHtMiSTRf IPH) IS
DIRECTLY RELATED TO GRIT BUILD-UP IN THE LIME HANDLING AND SLURRY PREPARATI UNSYS IEM. THE
UTILITY IS CURRENTLY STUDYING WAYS TO TIGHTEN THE WATER BALANCE BY USING THlCENER SUPERNA-
TANT INTERMITTENTLY WITH CLEAR SERVICE HATER FOR THE MIST ELIMINATORS. A CUMLlANCt TEST
SHOULD TAKE PLACE DURING THE NEXT REPORT PERIOD.
AUG. 78 735 601 686 691 678
SEP. 78 676 585 674 720 664
DURING AUGUST MODULES 301 AND 501 WERE TAKEN DOWN FOR CLEANING. THt RUBBER LMNG UN THREE
FAN HOUSINGS WAS REPAIRED. IT WAS ALSO NECESSARY TO SHUT DUWN THE LIME MIXINGJASTN tN n*i»-w
TO CLEAN OUT EXCESSIVE GRIT AND SOLIDS BUILD UP.
33
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EPA UTILITY F60 SURVEY: OCTOBER 1978 - NUVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING ,
DUOUESNE LIGHT
PHILLIPS POWER STATION
SOUTH HEIGHT PENNSYLVANIA1
•410-MW.
FUEL CHARACTERISTICS COAL; SI SULFUR, 16.SX ASH
FGD VENDOR
PROCESS
NEW OR-RETROFIT
- ' ' •'/ '
START UP DATE
EFFICIENCY:/ .
PARTICULATES (ACTUAL)
(DESIGN)
S02 (ACTUAL)
(DESIGN)
WATER MAKE; UP
SLUDGE DISPOSAL
CHEMICO
LIME
RETROFIT
7/73
99.0 PERCENT
99.0 PERCENT
75+ PERCENT
83.0 PERCENT
OPEN LOOP
STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
MONTH
JAN.
FEB.
1
BOILER
3 4
OPERATING HOURS
AVG 101
SCRUBBER-ABSORBER
201 301 401
AVG
78 627 574 0 484 421
78 209 287 18 1.52 167
AN OUTAGE OCCURRED BETWEEN JAN. 6 AND JAN. 8 WHEN THE STACK DRAIN LEAKS w£«E REPAIRED BY
SANDBLASTING THE OUTER WALL AND REPLACING THE CARBON STEEL BANDS WITH STAINLESS STEEL BANDS.
THE SYSTEM WAS SHUTDOWN ON FEB. 11 DUE TO THE COAL SHORTAGE. THE OUTAGE CONTINUED THROUGH
MARCH AND THE SYSTEM IS SCHEDULED TO BE ON LINE BY APRIL 15. DURING THE OUTAGE 1HE FOLLOWING
REPAIRS AND MODIFICATIONS WERE MADE:
• THE BOILER EXIT DAMPERS WERE LINED WITH 316SS ON AREAS OF HIGH EKOSIUN CAUSED MY
FLYASH IMPINGEMENT.
•EXPANSION JOINTS ON THE INLET DUCTWORK WERE SHIELDED BY METAL PLATES WHICH MERE
MELDED AT ONE END.
•NUMEROUS HOLES IN THE WET GAS DUCT WORK WERE REPAIRED AND THE DUCTS WERE RELINEU
WITH CEILCOTE.
•THE THROAT DAMPERS WERE CLEANED ON ALL THE SCRUBBERS.
•INTERNAL MIST ELIMINATORS WERE CLEANED. THE EXTERNAL MIST ELIMINAlORS, WHICH
ARE BADLY DETERIORATED, MAY BE REPLACED.
•THE STACK BRICKLINING WAS INSPECTED AND SOME BRICKS WERE REPLACED AT THE TUP UF THE
STACK.
CONSTRUCTION WORK ON ADDITIONAL EQUIPMENT SUCH AS THE THICKENER AND SILOS IS ALMOST COMPLETE.
IT WAS NOTED THAT THE CEILCOTE LINER COROLINE SOSAR HAS HELD UP WELL OVER THREE YEAHS ON
THE CONICAL APEX OF MODULE 401.
MAR.! 78
APR. 78
MAY 78
358 0 562 623 524 0 345
725 389 714 667 690 0 531
THE FGO SYSTEM CAME BACK ON LINE AFTER THE COAL STRIKE IN LATE MARCH. IT IS NOT OPERATING
AT FULL LOAD BECAUSE THE NO. 6 BOILER IS STILL OUT AND SHOULD BE BACK ON LINE IN MID-JULY.
COMPLIANCE TESTS WILL TAKE PLACE IN JULY, AFTER BOILER 6 IS BACK ON LINE, TO SEE IF THE
SYSTEM IS MEETING THE 83X S02 REMOVAL REQUIREMENT FOR 2* SULFUR COAL. THERE WEKE NO HOURS
REPORTED FOR THIS PERIOD BECAUSE OF PRELIMINARY TESTING BEING CONDUCTED IN PREPARATION FUR
THE COMPLIANCE TESTS. SO FAR, TESTS INDICATE THAT THE SYSTEM WILL COMPLY WITH THE REOUIKED
STANDARDS. THE AVAILABILITY FOR ALL FOUR TRAINS WAS BETWEEN 65 AND 75 PERCENT.
34
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EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEKbEK 197B
OUOUESNE LIGHT PHILLIPS POWER STATION
OPERATING HOURS
BOILER SCRUBBER-ABSORBER
MONTH 183456 AVG 101 201 301 401 AVG
JUNE 76 632 581 616 720 516 0 S12
JULY 78 476 425 566 544 566 0 434
THE INTERNAL MIST ELIMINATOR ON MODULE 201 WAS REMOVED AND CLEANED OVER IHE PERIOD. THE
FGD SYSTEM HAS ACCUMULATED APPROXIMATELY 24,000 HOURS OF OPERATION UN ALL FOUK MODULES SINCE
START-UP. WATER BALANCE PROBLEMS HAVE CONTRIBUTED TO THE OCCURRANCE OF LOW PH,
RESULTING IN MIST ELIMINATOR PLUGGING. THE MIST ELIMINATOR PLUGGING IS
ALSO RELATED TO LOW PH RESULTING FROM LIME HANDLING AND SLURKY PREPARATION SYSTEM FAILURE.
GRIT BUILD UP HAS BEEN THE MAJOR SOURCE OF THE REAGENT HANDLING SYSTEM FAILURES. THE
UTILITY IS CURRENTLY STUDYING WAYS TO TIGHTEN THE WATER BALANCE BY USING THICKENER SUPERNA-
TANT INTERMITTENTLY WITH CLEAR SERVICE WATER FOR THE MIST ELIMINATORS. THE COMPLIANCE
TEST SHOULD TAKE PLACE DURING THE NEXT REPORT PERIOD.
AUG. 76 636 663 500 627 591 623 607
SEP. 78 608 599 593 546 146 447 490
DURING THE AUGUST-SEPTEMBER PERIOD MIST ELIMINATOR CLEANING TOOK PLACE IN ORDER TO CORRECT
THE PLUGGING PROBLEM. IN AUGUST THE INTERNAL MIST ELIMINATOR ON MODULE 201 WAS REPLACED.
THE LIME MIXING BASIN HAD TO BE SHUTDOWN OVER A WEEKEND SO THAT EXCESSIVE GNIT
AND SOLID PARTICLES THAT HAD BUILT UP COULD BE CLEANED OUT. HIGH PRESSURE WATER CLEANING WAS
PERFORMED ON MODULES 101 AND 401 AND THE RUBBER LINING ON MODULE 1U1 WAS REPAIRED. A MAJOK
PROBLEM AREA DURING THE PERIOD WAS CAUSED BY INSUFFICIENT SUPPLIES OF DRY FLYASH TO MIX
WITH THE SLUDGE. AS A RESULT THE SLUDGE HAS BEEN LEAKING OUT OF THE TRANSPORT TRUCKS WHILE
IN TRANSIT TO THE FINAL DISPOSAL SITE. APPARENTLY NOT ENOUGH FLYASH IS BEING COLLECTED WITH
THE PRESENT SYSTEM.
35
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EPA UTILITY FGD SURVEY* OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME GULF POWER
UNIT NAME SCHOLZ 1 & 2
UNIT LOCATION CHATTAHOOCHEE FLORIDA
UNIT RATING 23 MW
FUEL CHARACTERISTICS COAL; 2X SULFUR, 11X ASH
FGD VENDOR CHIYODA INTERNATIONAL
PROCESS LIMESTONE
NEW OR RETROFIT RETROFIT
START UP DATE 8/78
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 99.5 PERCENT
S02 (ACTUAL)
(DESIGN) 90 PERCENT
WATER MAKE UP CLOSED LOOP
SLUDGE DISPOSAL GYPSUM/STACKED, EXISTING POND
OPERATING EXPERIENCE UPDATE:
AUGUST-SEPTEMBER 1978 - OPERATION OF THIS PROTOTYPE UNIT BEGAN ON AUGUST 30. THIS SYSTEM UTILIZES
THE NEW JET BUBBLING REACTOR DESIGN AND IS CAPABLE OF SCRUBBING 50 PERCENT OF I HE FLUE GAS FRUM
EITHER BOILER 1 OR 2. NO INITIAL OPERATIONAL PROBLEMS HAVE BEEN REPORTED AND SYSTEM AVAILABILITY
HAS BEEN GREATER THAN 99 PERCENT.
OCTOBER-NOVEMBER 1978 - HOURS OF OPERATION ARE STILL UNAVAILABLE FUR THIS NEWLY OPERATIONAL
PROTOTYPE SYSTEM. NO MAJOR OPERATIONAL PROBLEMS HAVE BEEN ENCOUNTERED AND SYSTEM AVAILABILITY
REMAINS AT GREATER THAN 99 PERCENT. TYPICAL SULFUR DIOXIDE REMOVAL EFFICIENCY IS REPORTED 1U BE
APPROXIMATELY 93 PERCENT. A 130 HOUR SCHEDULED OUTAGE OCCURRED IN OCTOBER.
36
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EPA UTILITY F6D SUkVEY: UCTUHtK 197H - IjUVt-ftiEK 1 4 7 »
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
INDIANAPOLIS POWER * LIGHT
PETERSBURG 3
PETERSBURG INDIANA
530 MW
FUEL CHARACTERISTICS COAL? 3.25X SULFUR, 9.5Z ASH
FGD VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
S02 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
AIR CORRECTION DIVISION, UOP
THOROUGHBRED 121
NEW
10/77
99.3 PERCENT
80.0 PERCENT
CLOSED LOOP; 1.66 GPM/Mrt
STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
DECEMBER-JANUARY 1978 - OPERATION OF ALL FOUR MODULES /»AS INITIATED IN DECtMbtK 1977. A SUCCESSFUL
24-HOUR RUN WA3 COMPLETED ON DEC. 16 AND 17 WITH MODULES "B", "C" ANO "0" IN UPfcKATIUN. •»" MJDULh
HAD AN INOPERATIVE RECYCLE TANK AGITATOR. REPAIR OF THE AGITATOR WAS CUMPLE1EU ON DhC. di.
AND MODULE A WAS PLACED IN INITIAL OPERATION. A 30-DAY RUN SCHEDULED TO HtGIN JA«. 11 MAS POST-
PONED UNTIL MID-MARCH PENDING RESOLUTION OF PROBLEMS ASSOCIATED WITH THE FLY ASH rttMUVAL SYSTEM.
THE COLO HEATHER NECESSITATED THE ERECTION OF TEMPORARY ENCLOSURES AROUNU SEGMENTS OF THt FGO SYSTEM
UNTIL THE INSTALLATION OF HEAT TRACING COULD BE COMPLETED.
FEBRUARY-MARCH 1976 - THE MODULES DID NOT OPERATE DURING FEBRUARY AS REPAIRS *ERE MADE Tu LINtS Am)
VALVES DAMAGED BY FREEZE-UPS DURING THE WINTER. DURING MARCH SOME SCHEDULED ktPAlKS
HERE MADE WHICH INCLUDED INSTRUMENTATION WORK, INSULATION INSTALLATION AMD REPAIR UF A URUHHu KlNlUN
SEAR ON THE THICKENER. SYSTEM START-UP IS STILL BEING DELAYED BY PHUBLtMS *ITH IHfc FLY ASM HANDLINU
SYSTEM AND IS NOW EXPECTED TO BE IN MID-APRIL.
APRIL-MAY 1978 - THE UNIT CAME BACK ON LINE IN THE MIDDLE OF APRIL AFTER PROBLEMS ftlTH Trtf FLYASH
HANDLING SYSTEM HERE CORRECTED. THE SYSTEM OPERATED UNTIL THE MAIN POWER TRANSFORMER FAULHU,
CAUSING THE SYSTEM TO GO DOWN. THE OUTAGE LASTED UNTIL JUNE 16. PROBLEMS HAVE ALSO BEEN EXPtKl-
ENCED WITH ALL CONTROL VALVES AND PIPING. THE VALVES HAD TO BE SENT BACK Tu THE FACTORY FOR MODI-
FICATIONS.
JUNE-JULY 1978 - THE UNIT IS STILL PROCEEDING WITH SHAKEDOWN AND DEBUGGING OPERATION AS FINAL DtSIUN
MODIFICATIONS ARE BEING MADE. PREPARATIONS ARE BEING COMPLETED FOR THE COMPLIANCE TEST WHICH HAS
NOT YET TAKEN PLACE.
AUGUST-SEPTEMBER 1978 - SHAKEDOWN/DEBUGGING OPERATIONS CONTINUE. THE COMPLIANCE TEST IS NUrt SET HUR
THE LAST HEEK IN OCTOBER. THE UNIT HAS EXPERIENCED PROBLEMS WITH CONTROLS, FIBERGLASS HIPING AMU
VALVES.
OCTOBER-NOVEMBER 1978 - THE 302 COMPLIANCE TEST HAS BEEN RESCHELDULEO FUR DECEMHER DUE TO THE
INVALIDITY OF THE TEST PREVIOUSLY RUN (BYPASS DAMPER PROBLEMS). HOWEVER THE PREVIOUS TtSTINU DtU
SHOH THAT THE UNIT HAS IN PARTICULATE AND NOX COMPLIANCE. THE CRACKED PIPING PROBLEM HAS 8tEN
SOLVED BY REPLACING SECTIONS WITH RUBBER LINED STEEL PIPING, NEW FRP PIPING, ANO PROVIDING
ADDITIONAL PIPE SUPPORTS. PROBLEMS REPORTED RECENTLY WERE FREEZE-UPS IN THE LIME DELIVERY SYSTEM
AND AN INSTRUMENTATION POWER TRANSFORMER FAILURE THAT CAUSED ABOUT 6 DAYS UuTAGE.
37
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EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGI) SYSTEMS
UTILITY NAME KANSAS CITY POWER & LIGHT
UNIT NAME HAWTHORN 3
UNIT LOCATION KANSAS CITY MISSOURI
UNIT RATING 100 MM
FUEL CHARACTERISTICS COAL; 2X SULFUR, 12.5X ASH
FGO VENDOR COMBUSTION ENGINEERING
PROCESS LIME
NEW OR RETROFIT RETROFIT
START UP DATE 11/78
EFFICIENCY:
PARTICULATES (ACTUAL) 99.0 PERCENT
(DESIGN) 99.0 PERCENT
so2 (ACTUAL)
(DESIGN) 70.0 PERCENT
HATER MAKE UP OPEN LOOP 7.0 GPM/MW
SLUDGE DISPOSAL UNSTABILIZED/SLUOGE PONO
OPERATING EXPERIENCE UPDATE:
FGD SYSTEM
MONTH PERIOD HRS. BOILER HRS. FGD SYSTEM HRS. UTILIZATION (X)
FEB. 78 672 167 167 25
MAR. 78 744 406 406 56
DURING FEBRUARY THE UNIT WAS DOWN FOUK TIMES WITH ECONOMIZER AND WATER WALL LEAKS (OUTAGE
TIME APROX. 504 HRS). A TWO WEEK OUTAGE WAS SCHEDULED DURING MARCH FOR SEASONAL MAINTENANCE.
WATER WALL LEAK REPAIR AS WELL AS ACID CLEANING OF THE BOILEK CAUSED ADDITIONAL OUTAGE TIME
DURING THE LAST WEEK IN MARCH.
APR. 78 720 548 220 76
MAY 78 744 403 403 42
AN AIR PREHEATER FIRE DISCOVERED ON MAY 12 CAUSED DAMAGES THAT FORCED MUOULE A TO BE OUwN THE
REST OF THE MONTH.
JUNE 78
JULY 78
NO INFORMATION WAS AVAILABLE FOR THE JUNE-JULY REPORT PERIOD DUE 10 A PLANT STRIKE.
AUG. 78
SEP. 78
THE SCRUBBING SYSTEM IS OPERATING ALTHOUGH THE UTILITY IS STILL IN IHE MIDST UF A STRIKE.
FGD PERFORMANCE FIGURES ARE NOT AVAILABLE. THE UTILITY IS NOT RECORDING FGD SYSTEM OPEKAIIuU
HOURS DURING THE STRIKE.
38
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EPA UTILITY FGD SUKVEY: UCTUbEK 1978 - NUVEMUfcK 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL F60 SYSTEMS
UTILITY NAME KANSAS CITY POWER & LIGHT
UNIT NAME HAWTHORN 4
UNIT LOCATION KANSAS CITY MISSOURI
UNIT RATING 100 MW
FUEL CHARACTERISTICS COAL; 2X SULFUR, 13.5* ASH
F60 VENDOR COMBUSTION ENGINEERING
PROCESS LIME
NEW OR RETROFIT RETROFIT
START UP DATE 8/72
EFFICIENCY:
PARTICULATES (ACTUAL) 99.0 PERCENT
(DESIGN) 99.0 PERCENT
S02 (ACTUAL)
(DESIGN) 70.0 PERCENT
WATER MAKE UP OPEN LOOP 7.0 GPM/MW
SLUDGE DISPOSAL UNSTABILI ZED/SLUDGE PUNO
OPERATING EXPERIENCE UPDATE:
FGU SYSTtM
MONTH PERIOD MRS. BOILER HRS. FGD SYSTEM MRS. UTILIZATION (X)
FEB. 76 b72 198 19B 3D
MAR. 78 7
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
KANSAS CITY POnER * LIGHT
LA CYGNE 1
LA CYGNE KANSAS
820 MH
FUEL CHARACTERISTICS COAL; 5X SULFUR, 551 ASH
FGD VENDOR BABCOCK & WILCOX
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE
EFFICIENCY!
PARTICULATES (ACTUAL)
(DESIGN)
802 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
98.2 PERCENT
98.0 PERCENT
80.1 PERCENT
76.0 PERCENT
OPEN LOOP 1.4 GPM/MW
UNSTABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
MONTH
FEB. 76
MAR. 78
BOILER HOURS
578
741
PERCENT AVAILABILITY-BY MODULE
B C 0 E F
92
95
93
95
95
90
94
95
91
94
97
95
96
89
93
93
AVERAGE
94
FGD OPERATIONS AT LA CYGNE WERE CONDUCTED DURING THE REPORT PERIOD WITH NU MAJOR PROBLEMS
ENCOUNTERED.
APR. 70
620
91
92
91
90
92
91
91
91
MAY
THE BOILER WAS DOWN A TOTAL OF 100 HOURS IN APRIL. THIS TIME INCLUDED IHKEE UUTAGtS DUE TU
BOILER LEAKS AND LACK OF LOAD REQUIREMENT. MODIFICATIONS TO THE FGD SYSTEM wEKE PERFORMED
DURING THE OUTAGES WHICH INCLUDED CHANGING THE REHEAT TUBE BUNDLES.
78 593 89 92 92 93 92 91 93 86 91
IN MAY THE BOILER «AS DOWN TWICE FOR A TOTAL OF 151 HOURS. OUTAGES WERE AGAIN CAUSED BY
BOILER LEAKS. GENERAL MAINTENANCE AND REPAIRS ON THE FGD SYSTEM WERE CONTINUED.
JUNE 78
JULY 76
15
341
97
92 94 88 93 93 95 93
THE UNIT WAS ONLY UP FOR 15 HOURS IN JUNE. IN THE FIRST PART OF JUNE THERE WERE BOILER TUttt
LEAKS. FROM JUNE 8 TO JUNE 17 A BOILER OUTAGE WAS NECESSARY FUR GENERATOR REPAIR. THE UNIT
OPERATED THROUGHOUT JULY.
AU6. 78 577 92 93 95 96 93 94 95 95 94
SEP. 78 720 96 96 96 96 96 96 95 97 96
THERE WERE TWO BOILER OUTAGES (NON-FGO-RELATED) IN AUGUST. THE FGD SYSTEM REUUIRED ONLY ROU-
TINE MAINTENANCE. THE UTILITY IS EXPERIMENTING WITH A 3-STAGE MIST ELIMINATOR AND SOME DOU-
BLE STAGE MIST ELIMINATORS. BETTER MIST ELIMINATION AT THE SCRUBBER EXIT WUULD REDUCE THE
FREQUENCY OF REHEATER CLEANING. DURING THE JULY-SEPTEMBER PERIOD TwO I.D. FAN ROTORS WERE
REPLACED.
OCT. 76
NOV. 76
255
720
96
92
96
95
98
94
97
93
97
94
98
93
97
94
96
96
THE UTILITY REPORTED THAT NO UNUSUAL OPERATING PROBLEMS WERE ENCOUNTERED.
97
94
40
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EPA UTILITY FGD SURVEY: UC1UBEH 19/8 - MJVKMHtrf
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL F60 SYSTEMS
UTILITY NAME KANSAS POWER * LIGHT
UNIT NAME JEFFREY 1
UNIT LOCATION ST MARYS KANSAS
UNIT RATING 680 MW
FUEL CHARACTERISTICS COAL; 0.3X SULFUR, 7.5Z ASH
FGO VENDOR COMBUSTION ENGINEERING
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 8/78
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 99.0 PERCENT
302 (ACTUAL)
(DESIGN) 60.0 PERCENT
HATER MAKE UP CLOSED LOOP .59 GPM/MW
SLUDGE DISPOSAL UNSTAB1LIZED/SLUOGE POND
OPERATING EXPERIENCE UPDATE:
AUGUST-SEPTEMBER 1978 - THE SYSTEM IS PRESENTLY IN THE SHAKEDOWN PHASE OF OPERATION. EACH UF THE
SIX MODULES OPERATED DURING THIS PERIOD NO MAJOR PROBLEMS WERE REPORTED. INTEGRATED OPERATION OF
THE SYSTEM IS EXPECTED TO BEGIN DURING THE FIRST HALF OF OCTOBER.
OCTOBER-NOVEMBER 1978 » INTEGRATED OPERATION FOR THIS UNIT STILL HAS NOT BEEN ACHIEVED. A
CERTIFICATION TEST WHICH HAD BEEN SCHEDULED HAD TO BE CANCELLED DUE TO A BOILER OUTAGE. HOWEVER
NOW THE COLO WEATHER HAS FORCED POSTPONEMENT OF THE TEST INDEFINITELY. MEANWHILE INTERMITTENT FGU
OPERATIONS CONTINUE.
41
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EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME KANSAS POWER R LIGHT
UNIT NAME LAWRENCE 0
UNIT LOCATION LAWRENCE KANSAS
UNIT RATING 125 MW
FUEL CHARACTERISTICS COAL; 0.51 SULFUR, 10X ASH
FGO VENDOR COMBUSTION ENGINEERING
PROCESS LIMESTONE
NEW OR RETROFIT RETROFIT
START UP DATE 12/68
EFFICIENCY:
PARTICULARS (ACTUAL) 99* PERCENT
(DESIGN) 98.9 PERCENT
302 (ACTUAL) 90+ PERCENT
(DESIGN) 73.0 PERCENT
MATER HAKE UP OPEN LOOP
SLUDGE DISPOSAL UNSTABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
FEB. 78 THE FGD SYSTEM OPERATED DURING THE REPORT PERIOD WITH NO MAJOR PROBLEMS. THE THICKENER
MAR. 78 UNDERFLOW LINE IS STILL FROZEN AND TWO 3 INCH DIAMETER FIRE HOSES ARE BEING USED TO PUMP
THE UNDERFLOW SOLIDS TU THE POND.
APR. 70 THE UTILITY REPORTED THAT THE FGO SYSTEM AND THE BOILER RAN WITHOUT ANY OUTAGES DURING
MAY 78 THIS PERIOD.
JUNE 78 THE BOILER AND FGO SYSTEM BOTH OPERATED THROUGHOUT THE PERIOD. THE UTILITY
JULY 78 REPORTED THAT THE OPERATING HOURS EQUALED THE HOURS IN THE PERIOD.
AUG. 78 HOURS OF OPERATION WERE NOT AVAILABLE BUT THE UTILITY REPORTED THAT THE SYSTEM RAN WITH NO
SEP. 78 FORCED OUTAGES DURING THE PERIOD. THE UNIT WAS DOWN THE LAST WEEK AND A HALF IN SEPTEMBER
FOR A SCHEDULED FALL TURBINE/BOILER OUTAGE. ROUTINE MAINTENANCE INCLUDED BOILER AND
TURBINE CLEANING AND REPAIR.
OCT. 78 THE SYSTEM RAN CONTINUOUSLY THROUGHOUT THE PERIOD WITH THE EXCEPTION OF A UNE WEEK OUTAGE
NOV. 78 FOR A BOILER-TURBINE INSPECTION. AN EPA SPONSORED CONTINUOUS MONITORING TEST BEGAN AT
THIS UNIT AT THE BEGINNING OF DECEMBER AND WILL CONTINUE THROUGH THE END OF JANUARY.
THE TEST INVOLVES 24 HOUR MONITORING OF S02, OPACITY AND NOX.
-------
EPA UTILITY FGD SURVEY: UCTUbEK 197tt - NOVEPBfcK 19/e
SECTION 3
PERFOHMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME KANSAS POWER & LIGHT
UNIT NAME LAWRENCE 5
UNIT LOCATION LAWRENCE KANSAS
UNIT RATING 400 MW
FUEL CHARACTERISTICS COAL; 0.5X SULFUR, 10X ASH
FGO VENDOR COMBUSTION ENGINEERING
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 11/71
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 96.9 PERCENT
302 (ACTUAL)
(DESIGN) 52.0 PERCENT
WATER MAKE UP OPEN LOOP
SLUDGE DISPOSAL UNSTABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
FEB. 78 THE ORIGINAL FGD SYSTEM WAS PULLED OFF LINE ON MARCH 20 SO THAT THE NEW SCKUBBtR-ABSOKBER
MAR. 78 SYSTEM COULD BE TIED INTO THE GAS PATH. THIS NEW SYSTEM CONSISTS OF TWO MODULES EACH WITH
A ROD SECTION FOR PARTICULATE REMOVAL AND A SPRAY TOWER FOh S02 REMOVAL. THE CAPACITY IS
210 MW EACH. INITIAL OPERATION SHOULD BEGIN BY THE FIRST OF MAY.
APR. 78 THE NEW UNIT WENT IN SERVICE ON APRIL 11 AND HAS OPERATED MTH NU OUTAGES SINCE START-UP.
MAY 78
JUNE 78 THE BOILER OPERATED ALL BUT TWO DAYS OF THE JUNE-JULY PERIOD. THE 1*0 DAYS OF OUTAGE
JULY 76 TIME IN JUNE WERE DUE TO A BOILER DRAIN LINE LEAK. THE FGD SYSTEM OPEHATED THE ENTIRE
TIME THE BOILER WAS ON-LINE, NO PROBLEMS WERE REPORTED.
AUG. 78 THE SYSTEM RAN WITH NO FORCED OUTAGES DURING THE AUGUST-SEPTEMBEK PEK10D. THE UNIT WAS
SEP. 78 TAKEN DOWN AT THE END OF SEPTEMBER FOR A SCHEDULED TWO WEEK TURBINE/bUILtR OUTAGE. KOU-
TINE MAINTENANCE IS BEING PERFORMED ON THE BOILER AND TURBINE.
OCT. 78 THE SYSTEM RAN THROUGHOUT THE ENTIRE PERIOD WITH ONLY ONE OUTAGE. THE OUTAGE "AS WEUU1HEO
NOV. 78 FOR AN ANNUAL BOILER-TURBINE INSPECTION AND LASTED FOR ONE WEEK IN OCTOBER.
-------
EP* UTILITY FGO SURVEY: OCTOBEH 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME KENTUCKY UTILITIES
UNIT NAME GREEN RIVER 1,2 « 3
UNIT LOCATION CENTRAL CITY KENTUCKY
UNIT RATING 64 MM
FUEL CHARACTERISTICS COAL; 3.7X SULFUR, 11.OX ASH
FGD VENDOR AMERICAN AIR FILTER
PROCESS LIME
NEW OR RETROFIT RETROFIT
START UP DATE 9/75
EFFICIENCY:
PARTICULATES (ACTUAL) 99.7 PERCENT
(DESIGN) 99.7 PERCENT
SOS (ACTUAL) 80-90 PERCENT
(DESIGN) 80.0 PERCENT
WATER MAKE UP CLOSED LOOP 1.20 GPM/Mh
SLUDGE DISPOSAL UNSTABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
TOTAL BOILER MODULE MODULE CALLED HK. MODULE
PERIOD PERIOD (HR) OPERATION (HR) AVAILABILITY (HR) TO OPERATE (HK) OPERATED
JAN. 78 744 537 722 537 170
AVAILABILITY = 23X
RELIABILITY = 32X
OPERABILITY = 32X
UTILIZATION = 23X
DURING THE MONTHS OF DECEMBER AND JANUARY NUMEROUS FREEZE-UPS OCCUHED. AS ONE COMPONEfU
HAS THAWED ANOTHER MOULD FREEZE. THE ABSORBER WAS AVAILABLE FOR FGD OPERATIONS BUT CUULU NOT
BE UTILIZED BECAUSE THE SLURRY LINE TO THE POND FROZE. THE UNIT WENT DUWN AFIEK ABUIJI 170
HOURS OF OPERATION IN JANUARY. BECAUSE OF EMERGENCY CONDITIONS THE UTILITY CHOSE TO CONCEN-
TRATE THEIR MAINTENANCE CREWS ON POWER GENERATION RATHER THAN FGD OPERATION. UNDER NOR-
MAL CONDITIONS THE RELATIVELY MINOR FGD SYSTEM PROBLEMS WOULD HAVE BEEN SOLVED MOKE UUICKLY.
IN LIGHT OF THIS THE SYSTEM COULD HAVE BEEN CONSIDERED AVAILABLE THKOUGHUUT MOST OF THE
PERIOD CONCERNED.
FEB. 78 672 672 672 0 0
AVAILABILITY z 100X
RELIABILITY = UNDEFINED
OPERABILITY = OX
UTILIZATION = OX
DURING THE FREEZE UP NUMEROUS GASKETS WERE TORN THROUGHOUT THE SYSTEM. THE SYSTEM WAS SHUT
DOWN COMPLETELY FOR REPAIR WORK.
MAR. 76 744 669 744 0 0
AVAILABILITY = 100X
RELIABILITY = UNDEFINED
OPERABILITY = OX
UTILIZATION » OX
REPAIR WORK HILL CONTINUE UNTIL LATE APRIL 78 WHEN THE SCRUBBER-AttSUKBtK SYSTbK IS EXPECTED
BACK ON LINE.
APR. 78 720 295 296 295 296
AVAILABILITY = 41X
RELIABILITY s 99X
OPERABILITV s 99X
UTILIZATION = 41X
44
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EPA UTILITY hGU SURVEY: UCTUbtK 19/a - NOVbfbtK 19/H
KENTUCKY UTILITIES GKEEN KIVbK l,<> t. 3
TOTAL BOILER MODULE MODULE CALLED HK. MODULE
PERIOD PERIOD (HR) OPERATION (HO) AVAILABILITY (HK) TO OPERATE (HK) UPb*ATtO
MAY 78 744 HIU 474 tli UJ a
AVAILABILITY = 64X
RELIABILITY = 100X
OPERABILITY = 100X
UTILIZATION = 64X
THE SCREENS ON THE SUCTION SIDE OF THE PUMPS THAT PUMP THE SLURRY FKOM THE PKEP «UOM TO 1 Hfc
NOZZLES EXPERIENCED PLUGGING PROBLEMS. THE SCREENS GET PLUGGED rtlTH LAKlib GKIT IN THE SLUKKr
AND ARE SUCKED OUT OF POSITION BY THE PUMPS. THE UTILITY REPORTED THAT THIS TENDS IU Ht 4
RE-OCCURRING PROBLEM.
JUNE 78 730 525 524 b2t iia
AVAILABILITY = 73%
RELIABILITY a 100X
OPERABILITY = 100X
UTILIZATION = 73X
BOILER AND FGO SYSTEM OUTAGES DURING JUNE WERE FOR ROUTINE MA INTEilANCb.
JULY 78 744 103 99 99 44
AVAILABILITY = 13X
RELIABILITY = 100X
OPERABILITY = 96X
UTILIZATION s 13X
BOILER AND FGD SYSTEM OUTAGES DURING JULY WERE FOR ROUTINE MAINTENANCE.
AUG. 78 744 207 454 207 <>Ub
AVAILABILITY = 61X
RELIABILITY = 99X
OPERABILITY = 99X
UTILIZATION = 28X
THE UNIT WAS DOWN FROM AUGUST 1 UNTIL AUGUST 12 AS A RESULT UF BLEED PUMP PxObLEM3. ROUTINE
MAINTENANCE ALSO CONTINUED THROUGH THE MIDDLE UF THE MONTH.
SEP. 78 720 303 546 298 ' £9A
AVAILABILITY = 76X
RELIABILITY = 100X
OPERABILITY = 98X
UTILIZATION = 41X
BECAUSE OF PLUGGING PROBLEMS THE FGD SYSTEM WAS OPERATED AT APPROXIMATELY ONE THIKU UF TOTAL
CAPACITY THROUGHOUT SEPTEMBER.
OCT. 78 744 236 222 232 2
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EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME LOUISVILLE GAS & ELECTRIC
UNIT NAME CANE RUN a
UNIT LOCATION LOUISVILLE KENTUCKY
UNIT RATING 178 MW
FUEL CHARACTERISTICS COAL; 3.751 SULFUR, 15.5X ASH
FGD VENDOR AMERICAN AIR FILTER
PROCESS LIMb (CARBIDE)
NEW OR RETROFIT RETROFIT
START UP DATE 8/76
EFFICIENCY:
PARTICULATES (ACTUAL) 99.0 PERCENT
(DESIGN) 99.0 PERCENT
302 (ACTUAL) 86-89 PERCENT
(DESIGN) 85.0 PERCENT
HATER MAKE UP OPEN LOOP .56 GPM/MW
SLUDGE DISPOSAL STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
PERFORMANCE FACTORS (X)
PERIOD HOURS BOILER (HR) FGO SYSTEM (HR) OPEHABILITY UTILIZATION
FEB. 78 672 0 0 N/A 0
MAR. 78 744 349 34
THE UNIT WAS DOWN THE ENTIRE MONTH OF FEBRUARY DUE TO THE COAL SHORTAGE ANO A LACK OF AVAIL-
ABLE LIME RESULTING FROM THE SEVERE WINTER WEATHER. THE UNIT CAME BACK ON LINE MARCH 21
AFTER WHICH TIME THE FGD SYSTEM WAS ON LINE DURING 95X OF THE BOILER HOURS THROUGH THE END OF
MARCH.
APR. 78 720 303 303 100 47
DURING APRIL THE BOILER WAS DOWN FOR REPAIRS. THE UTILITY REPORTED THAT THE AVAILABILITY
ANO RELIABILITY WERE BOTH 100X.
MAY 78 744 352 115 35 13
THE BOILER WAS DOWN AGAIN IN MAY FOR REPAIRS. DURING THE BOILER OUTAGE A NUMtfER OF MODIFICA-
TIONS WERE MADE TO THE DAMPERS IN THE FGD SYSTEM. THE UTILITY REPORTED THAT THE FGD SYSTEM
HAS BEEN RUNNING WELL SINCE THE MODIFICATIONS TOOK PLACE. THE AVAILABILITY ANO RELIABILITY
FOR MAY WERE 31 AND 35 PERCENT RESPECTIVELY.
JUNE 78 720 720 715 99 99
JULY 78 744 687 678 99 91
NO FGD SYSTEM RELATED OUTAGES WERE REPORTED BY THE UTILITY FOR THE JUNE-JULY PERIOD.
AUG. 78 744 744 701 94 94
SEP. 78 720 138 138 100 19
THERE WERE NO FGD FORCED OUTAGES DURING THE AUGUST-SEPTEMBER REPORT PERIOD. THE BOILER WAS
DOWN DURING SEPTEMBER FOR TUBE REPAIRS.
OCT. 78 744 0 0 N/A 0
NOV. 78 720 432 420 97 58
THE UNIT REMAINED OUT OF SERVICE THROUGHOUT OCTOBER FOR BOILER TUBE REPAIRS. RESUMPTION OF
OPERATIONS COMMENCED DURING THE SECOND WEEK OF NOVEMBER. NO PROBLEMS WERE REPORTED SINCE
STARUP.
46
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EPA UTILITY FGD SUKVEr: OCTOHEK 19/B - NUVEKbfcK 197H
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTtMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
LOUISVILLE GAS & ELECTRIC
CANE RUN 5
LOUISVILLE KENTUCKY
103 MW
FUEL CHARACTERISTICS COAL? 3.751 SULFUR, 15.5X ASH
FGO VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
302 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
COMBUSTION ENGINEERING
LIME (CARBIDE)
RETROFIT
12/77
99.0 PERCENT
85.0 PERCENT
OPEN LOOP
STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
DECEMBER-JANUARY 1970 - OPERATION OF THE FGD SYSTEM AT CANE RUN 5 BEGAN ON DECEMbER 29. INITIAL
OPERATIONS WERE NOT CONTINUOUS. DURING OPERATION SOME OF THE CONTROLS WERE NOT WORKING PROPERLY
AND MODIFICATIONS WERE NECESSARY.
FEBRUARY-MARCH 1976 - THE PLANT REMAINED OFF LINE THROUGHOUT FEBRUARY AND THEN KE-STAHTEU UN CAWC
24. THE BOILER OPERATED APPROXIMATELY 182 HOURS THROUGH THE END OF ^ARCH WITH THE F&D SYSTh'l"
OPERATING APPROXIMATELY 91 HOURS. VARIOUS INITIAL START-UP PROBLEMS WERE STILL BEING ENCUUNUREO
CAUSING FGD SYSTEM OUTAGES.
PERIOD HOURS BOILER (HR) FGD SYSTEM (HR)
PERFORMANCE FACTORS (X)
OPERABILITY UTILIZATION
APR. 76 720 669 648 97 90
MAY 78 744 432 364 84 49
FGD SYSTEM MODIFICATIONS WERE MADE DURING THIS PERIOD IN PREPARATION FOK PERFORMANCE TESTS.
TESTING TOOK PLACE BUT EPA TEST METHODS WERE NOT FOLLOWED ACCURATELY ANU THE PROCESS OF DATA
ACQUISITION WAS HANDLED POORLY BY DATA CREWS. THE UTILITY WAS CONFIDENT THAT HAD THE CHEWS
TAKEN THE DATA PROPERLY THE UNIT WOULD HAVE PASSED THE TESTS.
JUNE 78 720 685 590 86 82
JULY 78 744 632 506 60 68
THE SYSTEM EXPERIENCED REHEATER PROBLEMS OVER THE PERIOD. THE REHEAT COIL (STEAM) INSTALLA-
TION HAS BEEN A CHRONIC PROBLEM AREA. THE BANK OF TUBES AROUND THE DUCT HAS WELDS AT EACH
END, WHERE THE COR FORMS A "U". THESE WELDS HAVE BEEN FAILING EVER SINCE INITIAL OPERATIONS.
AUG. 78 744 540 464 86 62
SEP. 78 720 609 485 80 67
PROBLEMS CONTINUED THROUGH AUGUST AND SEPTEMBER WITH THE REHEAT COIL nELDS.
AFFECTED ONLY SCRUBBER MODULE "A".
THIS PROBLEM
OCT. 78 720 530 510 96 71
NOV. 78 744 253 237 94 33
REDUCED SERVICE TIME FOR THE FGD SYSTEM OCCURRED BECAUSE OF SYSTEM SHUTDOWN FOR REPAIRS
TO THE STEAM REHEATER COILS. THE OUTAGE LASTED APPROXIMATELY TWO WEEKS.
47
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EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 197B
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTtMS
UTILITY NAME LOUISVILLE GAS & ELECTRIC
UNIT NAME MILL CREEK 3
UNIT LOCATION LOUISVILLE KENTUCKY
UNIT RATING 425 MW
FUEL CHARACTERISTICS COAL; 3.751 SULFUR, 15.5X ASH
FGD VENDOR AMERICAN Alk FILTER
PROCESS LIME (CARBIDE)
NEW OR RETROFIT NEW
START UP DATE 8/78
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 99 PERCENT
S02 (ACTUAL)
(DESIGN) 85 PERCENT
WATER MAKE UP OPEN LOOP .35 GPM/MW
SLUDGE DISPOSAL STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
AUGUST 1978 - INITIAL OPERATIONS BEGAN AT THIS UNIT ON AUGUST 13. UUt TU I Ht RECENT OPERATING
STATUS OF THE SYSTEM HOURS OF OPERATION WERE NUT AVAILABLE FOK AUGUST.
PERFORMANCE FACTORS (X)
PERIOD HOURS BOILER (HR) FGD SYSTEM (HR) OPERABILITY UTILIZATION
SEP. 76 720 714 576 81 80
DURING THE MONTH PROBLEMS WERE ENCOUNTERED WITH FRP PIPING AND SOMfc OF 1Hb PUKPS.
THE PUMP PROBLEMS WERE RELATED TO BEARING AND SHAFT FAILURES.
OCT. 78 744 710 607 84 ttl
NOV. 78 720 351 299 85 42
THE UNIT WAS SHUT DOWN ON NOVEMBER 18 FOR A SCHEDULED INSPECTION UF TURhlNEr BOILER AND
THE FGD SYSTEM. THE UNIT IS NOT EXPECTED TO BE BACK ON LINE UNTILL FEBKUAKY 1, 1S79.
48
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EPA UTILITY FGU SUHVtY: OCTubtK IS/6 NoVtcnhK 14/a
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO bYSTEMS
UTILITY NAME LOUISVILLE GAS & ELECTKIC
UNIT NAME PADDYS RUN 6
UNIT LOCATION LOUISVILLE KENTUCKY
UNIT RATING 65 MM
FUEL CHARACTERISTICS COAL; 3.75X SULFUR, 15.5X ASH
FGD VENDOR COMBUSTION ENGINEERING
PROCESS LIME (CARBIDE)
NEW OR RETROFIT RETROFIT
START UP DATE «/73
EFFICIENCY:
PARTICULATES (ACTUAL) 99.0 PERCENT
(DESIGN) 99.0 PERCENT
303 (ACTUAL) 80-99 PERCENT
(DESIGN) ao.0 PERCENT
MATER MAKE UP OPEN LOOP 0.7 GPM/MW
SLUDGE DISPOSAL STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
SEPTEMBER 1977-MARCH 1978 - PADDY'S RUN DID NOT OPERATE DURING THIS PEKIUO DUt TO A LACK UF
REQUIREMENT. THIS IS A PEAK LOAD UNIT THAT IS TO BE HEUREU SOON AFTEH THE MILL CKttK 3 UNIT
BECOMES FULLY OPERATIONAL.
APRIL-MAY 1978 - PADDY'S RUN MAS ONLY ON LINE A FEW HOURS DUHING THIS PERIOD. .JU UP£HAT10NAL
PROBLEMS WERE REPORTED BY THE UTILITY.
JUNE-JULY 1978 - THIS UNIT RAN INTERMITTENTLY FOR AHOUT EIGHI TU UN DAYS OVEK THE JUNt-JULT
AUGUST-SEPTEMBER 1978 - THIS UNIT WAS OPERATED FOR TWO WEEKS IN SEPTEMBER 50 THAT TESTInb UF A ne
FLOCCULANT COULD BE CARRIED OUT. THE RESULTS OF THE TESTS WILL DETERMINE THt IrPE uF FLUCCULANT
THAT MILL BE USED IN THE FUTURE AT THE OTHER LG&E UNITS.
OCTOBER-NOVEMBER 1978 - THE BOILER WAS NOT OPERATED DURING OCTOBER OK NOVEMRtK.
49
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EPA UTILITY FGO SURVEY: OCTOBER !<»/« - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL F&O SYSTEMS
UTILITY NAME
ONIT NAME
UNIT LOCATION
UNIT RATING
MINNKOIA POWER COOPERATIVE
MILTON R. YOUNG 2
CENTER NORTH DAKOTA
Q50 Mw
FUEL CHARACTERISTICS LIGNITE; 0.7X SOLFOR, «.OX ASH
FGU VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
S02 (ACTUAL)
(DESIGN)
HATER MAKE UP
SLUDGE DISPOSAL
ADL/COMBUSTIUN EOUIP ASSOCIATE
LIME/ALKALINE FLYASH
NEW
9/77
99.6 PERCENT
75.0 PERCENT
OPEN LOOP 1.56 GPM/MW
UNSTABILIZtD/LANOF ILL
OPERATING EXPERIENCE UPDATE:
FEBRUARY-MARCH 1978 - BOTH THE 8UILEKS AND FGO SYSTEM CAME HACK ON LINE FEB. 21 AFTER COMPLETION
OF THE TURBINE REPAIRS. ONE FORCEO-DKAFT FAN (UPSTREAM OF FGO SYSTEM) HAD AN U1L LEAK AND A SHAFT
ALIGNMENT PROBLEM. IT WAS TAKEN OFF THE LINE AND SHIPPED TO BUFFALO FORGE FUR REPAIRS. THE
AFFECTED MODULE WAS DOWN FROM FEB. 23 THROUGH APRIL 10. WHEN THE REPAIRED UNIT WAS RE-INSTALLEU.
THE VACUUM FILTER ALSO MALFUNCTIONED. ALLOWING LARGER SIZE
PARTICLES TO ESCAPE THE FILTER. THIS CAUSED THE RUBBER LINING DOWNSTREAM TO PEEL WHICH, IN
TURN, CREATED A PLUGGING PROBLEM. EIMCO ENGINEERS ARE PRESENTLY STUDYING THE PROBLEM
AND HOPE TO INCORPORATE MODIFICATIONS TO IMPROVE THE PERFORMANCE OF THE FILIERS. THE COMPLIANCE
TEST HAS AGAIN BEEN RESCHEDULED WITH EPA FUR THE END OF MAY.
APRIL-MAY 1978 - COMPLIANCE TESTING TOOK PLACE DURING THE WEEK OF JUNE 5. THE REPORT SHU1ILD BE
AVAILABLE TO THE UTILITY BY THE END OF JUNE. THE UNIT WAS DOWN WITH DAMPER PROBLEMS (OUWN
ON THE 24TH OF JUNE). APPARENTLY THE CHAINS THAT PULL THE GUILLOTINE DAMPERS WERE UNDERDfcSIGNED AND
HAVE BEEN REPLACED.
JUNE-JULY 1976 - NO INFORMATION *AS REPORTED BY THE UTILITY FOR THIS REPORT PERIOD.
AUGUST-SEPTEMBER 1978 - OFFICIAL RESULTS OF THE COMPLIANCE TEST PERFORMED UN JUNE 6 ARE STILL NOT
AVAILABLE. VARIOUS PROBLEMS WERE ENCOUNTERED WITH THIS SYSTEM DURING THE PERIOD. THE THICKENER HAS
BEEN A MAJOR PROBLEM AREA. THE POLYETHYLENE LINER WAS ACCIOENTLY PIERCED DURING REPAIRS AND HAD TU
BE PATCHED. BECAUSE OF INTERMITTENT OPERATION, HOURS ARE NOT YET AVAILABLE.
OCTOBER-NOVEMBER 1978 - THE UTILITY REPORTED THAT OPERATION OF THE BOILER AND FGD SYSTEM CONTINUED
ON AN INTERMITTENT BASIS THROUGHOUT THE PERIOD. THICKENER LINING PROBLEMS WERE ENCOUNTERED AND
EROSION IN THE SPRAY TOWERS WAS SEVERE ENOUGH TO CAUSE HOLES IN THE TOWERS. ALSO F.D. FAN PROBLEMS
HAVE BEEN A MAJOR CONCERN.
THE UTILITY HAS REPORTED OPERATIONAL PARAMETERS FOR THE ENTIRE YEAR OF 1978. THE REPORTED
PARAMETERS AREJ BOILER HOURS = 6926 MW-H = 2,626,201
A-MODULE B-MODULE
1790 2110 TOTAL SYSTEM AVAILABILITY = 46X
1940 2500 TOTAL SYSTEM OPERA8ILITY = 53X
4965 4426 TOTAL SYSTEM RELIABILITY = 54*
1634 1634 TOTAL SYSTEM UTILIZATION = 42X
FGO SYSTEM:
OPERATION (HR)
AVAILABLE (HR)
FORCED OUTAGE (HR)
SCHEDULED OUTAGE (HR)
50
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EPA UTILITY FGU SURVtY: UCTUBEK 1S7B NUVfcCHtk
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTtMS
UTILITY NAME MONTANA POWER
UNIT NAME COLSTRIP 1
UNIT LOCATION COLSTRIP MONTANA
UNIT RATING 360 Mw
FUEL CHARACTERISTICS COAL; 0.8X SULFUK, 121 ASH
FGO VENDOR ADL/COMBUST1 ON EQUIP ASSOCIATE
PROCESS LIME/ALKALINE FLYASH
NEW OR RETROFIT NEW
START UP DATE 11/75
EFFICIENCY:
PARTICULATES (ACTUAL) 99.5 PERCENT
(DESIGN) 99.5 PERCENT
303 (ACTUAL) 75.0 PERCENT
(DESIGN) 60.0 PERCENT
WATER MAKE UP CLOSED LOOP
SLUDGE DISPOSAL STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
JAN. 78 TOTAL SYSTEM AVAILABILITY 96X
FEB. 78 TOTAL SYSTEM AVAILABILITY - 100X
MAR. 78 TOTAL SYSTEM AVALIABILITY - 92X
APR. 78 TOTAL SYSTEM AVAILABILITY = 100X
MAY 78 TOTAL SYSTEM AVAILABILITY = 66X*
*THIS FIGURE IS BASED UPON 9.92 HOURS OF OPERATION ON TnU SCRUBbtKS WHILE UM1 1 WAS BEING
BROUGHT BACK ON LINE AFTER COMPLETION OF ITS ANNUAL OVERHAUL. THE I.D. FAN MUTUK WAS NUT
AVAILABLE AT UNIT STARTUP ON THE 1A MODULE.
JUNE 78 TOTAL SYSTEM AVAILABILITY - 76X
JULY 78 TOTAL SYSTEM AVAILABILITY = 96X
51
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EPA UTILITY F60 SURVtY: OCTOBER 1978 - NOVEMBER 197B
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME MONTANA POWER
UNIT NAME COLSTHIP ^
UNIT LOCATION COLSTRIP MONTANA
UNIT RATING 360 MW
FUEL CHARACTERISTICS COAL? 0.8X SULFUR, 12X ASH
FGO VENDOR AOL/COMBUST ION EQUIP ASSOCIATE
PROCESS LIME/ALKALINE FLYASH
NEW OR RETROFIT NEW
START UP DATE 8/76
EFFICIENCY:
PARTICULATES (ACTUAL) 99.5 PERCENT
(DESIGN) 99.5 PERCENT
S08 (ACTUAL) 75.0 PERCENT
(DESIGN) 60.0 PERCENT
WATER MAKE UP CLOSED LOOP
SLUDGE DISPOSAL STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
JAN. 78 TOTAL SYSTEM AVAILABILITY 97X
FEB. 78 TOTAL SYSTEM AVAILABILITY - 95X
MAR. 76 TOTAL SYSTEM AVAILABILITY = 89X*
•THIS FIGURE IS BASED UPON THE 17 DAYS OF OPERATION BEFORE THE UNIT WAS SHUT UOwN FOR A
SCHEDULED ANNUAL OVERHAUL.
APR. 78 TOTAL SYSTEM AVAILABILITY = 87X*
•THIS FIGURE IS BASED UPON 8 DAYS OF OPERATION IN APRIL AFTER A UNIT OVERHAUL.
MAY 78 TOTAL SYSTEM AVAILABILITY - 99X
JUNE 78 TOTAL SYSTEM AVAILABILITY 97X
JULY 78 TOTAL SYSTEM AVAILABILITY - 96X
-------
EPA UTILITY FGD 5UKVKY: UCIUritH 147H - MOVfcf'ttE* 14/H
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME NEVADA POWER
UNIT NAME REID GARDNER 1
UNIT LOCATION MOAPA NEVADA
UNIT RATIN6 125 MW
FUEL CHARACTERISTICS COAL; 0.5X SULFUR, 6X ASH
FGD VENDOR AOL/COMBUSTION EQUIP ASSOCIATE
PROCESS SODIUM CARBONATE
NEW OR RETROFIT RETROFIT
START UP DATE 4/70
EFFICIENCY:
PARTICULATES (ACTUAL) 99+ PERCENT
(DESIGN) 99.0 PERCENT
302 (ACTUAL) 05-94 PERCENT
(DESIGN) 85.0 PERCENT
WATER MAKE UP OPEN LOOP 0.40 GPM/MM
SLUDGE DISPOSAL UNSTABILIZED/SOLAR EVAP PUND
OPERATING EXPERIENCE UPDATE:
HR.
BOILER MODULE CALLED
TOTAL OPERATION AVAILABLE UPON TO OPERATION
PERIOD (HR.) (HR.) (HR.) OPERATE (HR.)
FEB. 78 672 369 654 309 292
AVAILABILITY = 97X
RELIABILITY = 94Z
OPERABILITY = 7SX
UTILIZATION = 43X
THE SCRUBBER-ABSORBER SYSTEM WAS OFF-LINE FOR APPROXIMATELY IB HOUH5 UUKINti FtBHUAKY DDE Tu
PLUGGED SENSING LINES AND A DUCT HI-LO PRESSURE TRIP. THE BOILER WENT OUT OF SEKVICfc ON
ON FEBRUARY 17 FOR A THREE WEEK OUTAGE.
MAR. 78 744. 355 207 355 207
AVAILABILITY = 28X
RELIABILITY = 58X
OPERABILITY = S8X
UTILIZATION = 28X
THE BOILER CAME BACK ON LINE MARCH 16 BUT PROBLEMS nITH THE GUILLOTINE SNITCHES UtLAYtD
START-UP OF THE FGD SYSTEM UNTIL MARCH 22. FGD DOWNTIME WAS APPROXIMATELY 537 HOUKS.
A PROBLEM WAS ALSO ENCOUNTERED WITH THE REHEAT STEAM REGULATOR DURING MAKCH.
APR. 78 720 560 720 541 541
AVAILABILITY = 100X
RELIABILITY = 100X
OPERABILITY z 97X
UTILIZATION = 75X
THERE WERE NO FGD SYSTEM FORCED OUTAGES. ALL DOWNTIME WAS BOILER RELATLD (179 HKS.).
MAY 78 744 630 721 605 582
AVAILABILITY s 97X
RELIABILITY = 96X
OPERABILITY a 92X
UTILIZATION = 78X
THE UNIT WAS DOWN 132 HOURS FOR A PRODUCTION CONTROL OUTAGE, 7 HOURS FOK KEPAIKS 10 THE
CONDENSER, AND 23 HOURS DUE TO HIGH TEMPERATURE ON 1.0. FAN BEARING. (OUTAGES HERE BOILEK
RELATED.)
53
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EPA UTILITY FGD SURVEY! OCTOBEK 1978 - NOVEMBER 1978
NEVADA POWER REID GARDNER 1
HR.
BOILER MODULE CALLED
TOTAL OPERATION AVAILABLE UPON TO OPERATION
PERIOD (HR.) (HR.) (HR.) OPERATE (HR.)
JUNE 78 720 720 644 663 644
AVAILABILITY = 89X
RELIABILITY . 100X
OPERABILITY = 89*
UTILIZATION = 89X
THERE WAS ONE SCHEDULED FGD OUTAGE TO REPAIR A LEAK ON THE VENTUHI WATfcK BOX.
JULY 78 744 744 744 736 736
AVAILABILITY = 100X
RELIABILITY = 100X
OPERABILITV - 99X
UTILIZATION = 99X
A SCHEDULED FGD OUTAGE WAS REQUIRED TO RECTIFY A HIGH TRAY DIFFEKbNTlAL PRESSURE KHUHLtM.
THE TRAY WAS CLEANED OUT DURING THE OUTAGE.
AUG. 78 744 706 696 707 661
AVAILABILITY = 94X
RELIABILITY = 93X
OPERABILITY = 94X
UTILIZATION = 89X
THE SCRUBBER WAS FORCED OFF LINE ON AUGUST 5 BECAUSE UF A LOSS UF THE ASH PANtL CONTROL
POWER. THIS LEFT THE UNIT WITHOUT EMERGENCY SPRAY TO THE SCRUBBERS. A SfcCUND FORCED OUTAGE
OCCURRED ON AUGUST 20 WHEN THERE WAS A SCRUBBER VENTURI HIGH TEMP ALAKM. THE EXACT CAUSE WAS
NOT KNOWN BUT A BOILER TUBE LEAK WAS SUSPECTED. THERE WAS ONE SCHEDULED OUTAGE DURING THt
MONTH TO CLEAN THE TRAY.
SEP. 78 720 644 715 631 626
AVAILABILITY = 99X
RELIABILITY s 99X
OPERABILITY = 97X
UTILIZATION = 87X
DURING THE MONTH A BOILER TRIP OCCURRED WHICH WAS CAUSED BY SCRUBBER HIGH DUCT PRESSURE. AS
A RESULT, THE UNIT WAS DOWN FOR 5.3 HOURS WHILE THE SCRUBBER PRESSURE SENSING LINES WERE
CLEANED. THERE WERE THREE OTHER BOILER-RELATED OUTAGES DURING THE MONTH TOTALING 89
HOURS. A BOILER TUBE LEAK AND BOILER BURNER WERE REPAIRED.
OCT. 78 744 667 744 667 667
AVAILABILITY = 100X
RELIABILITY - 100X
OPERABILITY - 100X
UTILIZATION = 90X
THE BOILER MAS OFF LINE ABOUT 77 HOURS FOR REMOVAL OF AN ASH CLINKER.
NOV. 78 720 686 641 686 598
AVAILABILITY s B9.X
RELIABILITY = 87X
OPERABILITY = 87X
UTILIZATION = 83X
THE FGD SYSTEM WAS DOWN FOR SCRUBBER OUTLET TEMPERATURE PROBE REPAIRS AND HIGH SOLIDS CONTENT
IN THE SCRUBBER EFFLUENT. FURTHER OUTAGE TIME RESULTED WHEN BOILER PROBLEMS CAUSED THE
VENTURI OUTLET GAS TEMPERATURE TO BECOME TOO HIGH (TEMPERATURE ALARM HIGH TKIP).
54
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EPA UTILITY FGO SUHVtY: OCTUbEH 1978 - NUVtMBtK
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME NEVADA POWER
UNIT NAME KEIO GARDNER 2
UNIT LOCATION MOAPA NEVADA
UNIT RATING 125 MW
FUEL CHARACTERISTICS COAL; 0.5X SULFUR, 8X ASH
FGD VENDOR AOL/COMBUSTION EQUIP ASSOCIATE
PROCESS SODIUM CARBONATE
NEW OR RETROFIT RETROFIT
START UP DATE 4/74
EFFICIENCY:
PARTICULATES (ACTUAL) 99+ PERCENT
(DESIGN) 99.0 PERCENT
302 (ACTUAL) 85-94 PERCENT
(DESIGN) 85.0 PERCENT
WATER MAKE UP OPEN LOOP 0.40 GPM/MW
SLUDGE DISPOSAL UNSTA8ILI ZED/SOLAR EVAP POND
OPERATING EXPERIENCE UPDATE:
HR.
BOILER MODULE CALLED
TOTAL OPERATION AVAILABLE UPON TO OPERATION
PERIOD (HR.) (HR.) (HR.) OPERATE (HR.)
FEB. 78 672 636 625 632 585
AVAILABILITY = 93Z
RELIABILITY = 92X
OPERABILITY = 92X
UTILIZATION = 87X
FGD DOWNTIME DURING FEBRUARY WAS APPROXIMATELY 48 HOURS DUE TU A PLUGGED SENSING LINE AND
A DUCT HI-LO PRESSURE TRIP. THE BOILER WAS OUT OF SERVICE 34 HOURS.
MAR. 78 744 672 726 614 595
AVAILABILITY = 98X
RELIABILITY r 97X
OPERABILITY = 89X
UTILIZATION = SOX
THERE WAS ONLY ONE FORCED FGD OUTAGE DURING MARCH WHICH LASTED APPROXIMATELY 18 HOURS. A
SCHEDULED BOILER OUTAGE AT THE BEGINNING OF THE MONTH TO REMOVE ASH BUILDUP WAS CANCELLED.
APR. 78 720 320 720 317 317
AVAILABILITY = 100X
RELIABILITY - 100X
OPERABILITY = 98X
UTILIZATION = 44X
THERE WAS ONE SCHEDULED BOILER OUTAGE WHICH LASTED ABOUT 403 HOURS.
MAY 76 744 726 743 726 724
AVAILABILITY = 100X
RELIABILITY = 100X
OPERABILITY = 100X
UTILIZATION = 97X
THE BOILER WAS OFF FOR APPROXIMATELY 18 HOURS FOR REPAIRS ON THE MILL SPOKES. THE 2A SEC.
BREAKER TRIPPED AND CAUSED AN OUTAGE OF ABOUT ONE HOUR.
55
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EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 1978
NEVADA POWER REID GAkDNtK d
BOILER MODULE HR. CALLED
TOTAL OPERATION AVAILABLE UPON TO OPERATION
PERIOD (HR.) (HR.) (HR.) OPERATE (HR.)
JUNE If 720 720 718 663 661
AVAILABILITY = 100X
RELIABILITY = 100X
OPERABILITY = 92X
UTILIZATION = 92X
THERE HERE TWO SCHEDULED FGD OUTAGES TO UNPLUG THE TRAYS AND TO CHANGfc THt OIL UN THE I.I).
FAN. A FORCED FGD OUTAGE OCCURRED WHEN HIGH DUCT PRESSURE CAUSED A B01LEK 1KIP.
JULY 78 744 676 596 701 553
AVAILABILTY = 80X
RELIABILITY = 79X
OPERABILITY - 82X
UTILIZATION = 74X
THE BOILER WAS OUT OF SERVICE DUE TO A BOILER TUBE LEAK. THERE WAS ALSU A bOlLEH TklP UUt TO
A HIGH DUCT PRESSURE. THIS WAS CAUSED BY A FAULTY POSITIONER ON THE I.U. FAN CUMTKULLtk.
THE 1.0. FAN EXPANSION JOINT ON THE SCRUBBER WAS REPLACED. ANOTHER FGD OUTAGE UCCUHRfcO "HtN
A BOLT, WHICH FELL FROM THE FAN, CAUSED VIBRATIONS. A SbCONU 8UILER IMP DURING JULT vsAS
CAUSED BY AN UNDETERMINED SOURCE. THE SUCTION LINE FROM THE VENTUR1 DISCHARGE LINF TO
THE EFFLUENT PUMPS WAS CLEANED OUT, WHEN PLUGGING OCCURRED.
AUG. 78 744 733 603 643 601
AVAILABILITY = SIX
RELIABILITY = 93X
OPERABILITY = 82X
UTILIZATION = 81X
TWO SCHEDULED OUTAGES DURING THE PERIOD WERE NECESSARY TO CLEAN THE SCRUbttEk TRAY. A THIHIJ
SCHEDULED OUTAGE WAS NECESSARY TO CLEAN THE NOZZLES ON THE SCRUbBER SPRAY HACK. THE STAIN-
LESS STEEL PIPE TO THE TRAY SPRAY NOZZLES WAS ALSO REPLACED. THEKE WERE THREE FllHCEO UUTAGKS
DURING THE MONTH. ON AUGUST 1 THE SCRUBBER EXPERIENCED HIGH DUCT PRESSURE. UN AUGUST 3 II
WAS NECESSARY TO TAKE THE SCRUBBER OFF LINE TO REPACK THE VEN1URI PUMKS. THE THIKO OUTAGE
WAS CAUSED BY A LOSS OF THE ASH PANEL CONTROL POWER. THIS LEFT THE SCRUBBER WITHOUT EMERGEN-
CY SPRAY.
SEP. 78 720 693 720 675 675
AVAILABILITY = 100X
RELIABILITY = 100X
OPERABILITY = 97X
UTILIZATION = 94X
A SCHEDULED SCRUBBER OUTAGE TOOK PLACE DURING THE MONTH IN ORDER TO CLEAN THE TRAY RECYCLE
TANK AS WELL AS THE TRAY AND SOME OF THE LINES. THREE OTHER BOILER RELATED OUTAGES WERE
CAUSED BY PROBLEMS WITH A 10-KW GENERATOR. CONTROL POWER SURGES WEKE BEING CAUSED BY OVtk-
VOLTA6E MOTOR TRIPS.
OCT. 78 744 721 714 691 685
AVAILABILITY = 96X
RELIABILITY = ??X
OPERABILITY = 95X
UTILIZATION = 921
DURING OCTOBER THE SCRUBBER INSTRUMENTS WERE WORKED ON DURING A SCHEDULED OUTAGE. THE tfUILbR
WAS FORCED OUT OF SERVICE FOR ABOUT 28 HOURS BECAUSE OF BOILER DRUM PROBLEMS.
NOV. 78 720 277 702 277 258
AVAILABILITY = 98X
RELIABILITY = 93X
OPERABILITY = 93X
UTILIZATION = 36X
A FORCED FGD OUTAGE OCCURRED DUE TO HIGH DUCT PRESSURE. WORK WAS ALSU DONE ON I.D. FAN
CONTROLS. THE UNIT WAS SHUT DOWN NOVEMBER 12 FOR SCHEDULED BOILER MAINTENANCE. THE UNIT
REMAINED OUT OF SERVICE THE REMAINDER OF THE MONTH.
56
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EPA UTILITY FGD SURVEY: UCtUbEK IVtti - MJVtKrthn 1476
SECTION 5
PERFORMANCE DESCRIPTION FOR OPERATIONAL FUD SYSTEMS
UTILITY NAME NEVADA POWER
UNIT NAME REID GARDNER 3
UNIT LOCATION MOAPA NEVADA
UNIT RATING 125 MM
FUEL CHARACTERISTICS COAL? 0.5X SULFUR, 8X ASH
F60 VENDOR ADL/COMBUSTION EQUIP ASSOCIATE
PROCESS SODIUM CARBONATE
NEW OR RETROFIT N£w
START UP DATE 7/76
EFFICIENCY:
PARTICULATES (ACTUAL) 99+ PERCENT
(DESIGN) 99.0 PERCENT
902 (ACTUAL) 85-90 PERCENT
(DESIGN) 85.0 PERCENT
WATER MAKE UP OPEN LOOP 0.40 GPM/MH
SLUDGE DISPOSAL UNSTABILIZED/SOLAR EVAP POND
OPERATING EXPERIENCE UPDATE:
HR.
BOILER MODULE CALLED
TOTAL OPERATION AVAILABLE UPON TO OPERATION
PERIOD (HR.) (HR.) (HR.) OPERATE (HR.)
FEB. 78 672 619 642 618 588
AVAILABILITY = 96X
RELIABILITY = 95X
OPERABILITY = 95X
UTILIZATION s 88X
DURING FEBRUARY FAULTY WIRING CAUSED A HIGH VENTUKI TtMPEHATUKE RESULTING IN AN INITIAL Ib
HOUR FGD SYSTEM OUTAGE. THERE WAS A SECOND OUTAGE OF 13 HOURS TO CHECK THE VENTURI
TURE INDICATOR. A THIRD OUTAGE WAS CAUSED BY PLUGGING OF THE MIX TANK rtHlCh MADE IT
SIBLE TO MIX CHEMICALS.
MAR. 78 744 741 724 738 716
AVAILABILITY = 97X
RELIABILITY a 97X
OPERABILITY = 97X
UTILIZATION = 96X
THE MIX TANK PROBLEM CONTINUED INTO MARCH CAUSING THE ONLY FGU DOWNTIME FOK THE f-.UNTh
(APROX. 20 HOURS). A FURNACE HI-LO PRESSURE TRIP CAUSED A BOILER OUTAGE UF 6 HOURS.
APR. 78 720 704 699 650 629
AVAILABILITY = 97X
RELIABILITY = 97X
OPERABILITY a 89X
UTILIZATION = 87X
THE FGD SYSTEM WAS DOWN APPROXIMATELY 21 HOURS FOR REPAIRS ON THE VENTURI EMERGENCY SPRAY
SYSTEM. THE BOILER WAS DUWN APPROXIMATELY 70 HOURS DURING APRIL.
MAY 78 744 646 724 514 494
AVAILABILITY = 97X
RELIABILITY = 96X
OPERABILITY * 77X
UTILIZATION « 66X
THERE WAS A SCHEDULED OUTAGE OF 230 HOURS FOR BOILER MAINTENANCE, AND A FORCED OUTAGE UF
20 HOURS DUE TO A FAULTY TEMPERATURE PROBE AT THE VENTUKI DURING MAY.
57
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EP* UTILITY F6D SURVEY: OCTOBER 1978 - NOVEMBER 1978
NEVADA POWER REID GARDNER 3
BOILER MODULE HH. CALLED
TOTAL OPERATION AVAILABLE UPON TO OPERATION
PERIOD (HR.) (HR.) (HR.) OPERATE (HR.)
JUNE 78 720 715 730 715 686
AVAILABILITY = 100X
RELIABILITY = 961
OPERABILITY = 96X
UTILIZATION = 95X
A SCHEDULED FGD OUTAGE OCCURRED WHEN THE FIRE SPRAY SYSTEM WAS OUT UF SERVICE. THERE hAS
ALSO A BOILER TRIP (HI-LO FURNACE PRESSURE TRIP).
JULY 78 744 726 744 583 583
AVAILABILITY = 100X
RELIABILITY = 100X
OPERABILITY = 80X
UTILIZATION = 78X
LOW VENTURI FLOW CAUSED ONE OF THREE SCHEDULED FGD OUTAGES. THIS WAS CORRECTED WHEN THE
NOZZLES ON THE RACE TRACK WERE CLEANED. ANOTHER OUTAGE OCCURRED WHEN AN INSPECTION OF THE
VENTURI TANK AND RACE TRACK WAS REQUIRED. THE TANK AND RACE TRACK NOZZLES WERE CLEANED AND
THE RUBBER LINING ON THE VENTUKI SPOOL WAS REPLACED. A THIRD OUTAGE WAS REUUIRED TO CLEAN
THE VENTURI RACE TRACK. A SCHEDULED OUTAGE. WHICH WAS NOT FGD SYSTEM RELATED. TO CLEAN THE
TURBINE LUBE OIL COOLERS ALSO OCCURRED DURING JULY.
AUG. 78 744 736 730 736 721
AVAILABILITY = 98X
RELIABILITY - 98X
OPERABILITY = 98X
UTILIZATION = 97X
THERE WAS ONE FORCED BOILER OUTAGE DURING THE MONTH CAUSED BY HIGH FURNACE PRESSURE. THE
SCRUBBER WAS FORCED OFF LINE ON AUGUST 28 DUE TO HIGH SCRUBBER FAN OUTLET PRESSURE. THE
SCRUBBER PRESSURE SENSING LINE WAS CLEANED. ON AUGUST 29 THE SCRUBBER tFFLUEM SUL10S LEVEL
WAS HIGH CAUSING AN OUTAGE OF APPROXIMATELY FIVE HOURS. THE SYSTEM WAS FLUSHED TU CORRECT
THE PROBLEM.
SEP. 78 720 236 720 228 228
AVAILABILTY = 100X
RELIABILITY = 100X
OPERA6IHTY = 97X
UTILIZATION = 32X
THIS UNIT WENT DOWN ON SEPTEMBER 10 FOR A TURBINE OVERHAUL WHICH LASTEO THRUUGH THE END OF
THE MONTH. NO SCRUBBER OUTAGES WERE REPORTED FOR THE PERIOD SEPTEMBER 1-10.
OCT. 78 744 0 744 0 0
AVAILABILITY = 100Z
RELIABILITY = N/A
OPERABILITY = N/A
UTILIZATION = OX
THE UNIT WAS DOWN THE ENTIRE MONTH OF OCTOBER FOR TURBINE OVERHAUL.
NOV. 78 720 489 707 489 447
AVAILABILITY = 98X
RELIABILITY = 91X
OPERABILITY = 9U
UTILIZATION = 62X
THE UNIT MAS BROUGHT BACK ON LINE THE 10TH OF NOVEMBER. THE FGD SYSTEM WAS DOWN ABOUT 12
HOURS FOR REPAIRING VENTURI TEMPERATURE PROBES.
-------
EPA UTILITY FGU SURVEY: OCTOBER 197B - NUVEKBfcK IT/tt
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FliO SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
NORTHERN INDIANA PUB SERVICE
DEAN H. MITCHELL 11
GARY INDIANA
1 15 MM
FUEL CHARACTERISTICS COAL; 3.5Z SULFUR, 10* ASH
FGD VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
DAVY POWERGAS
WELLMAN LORD
RETROFIT
11/76
EFFICIENCY:
PARTICULATES (ACTUAL) 99.5 PERCENT
(DESIGN)
S02 (ACTUAL)
(DESIGN)
MATER MAKE UP
SLUDGE DISPOSAL
99.5 PERCENT
91.0 PERCENT
90.0 PERCENT
CLOSED LOOP
ELEMENTAL SULFUR PRODUCT
OPERATING EXPERIENCE UPDATE:
MONTH
HOURS
IN PERIOD
HOURS
AVAILABLE
HOURS
CALLED ON
TO OPERATE
HUURS
UPERATED
AVAILABILITY RELIABILITY UTILIZATION
NOV. 77 720 531 596 128 7a 72 90
THE FGU UNIT OPERATED FOR 16 CONSECUTIVE DAYS, AVERAGING 901 S02 REMOVAL WITH 285 LONG TONS OF
SULFUR RECOVERED. FGD OPERATION WAS INTERRUPTED BY A UNIT 11 BOILER TUBE LEAK AND RESUMPTION OF FGD
OPERATION WAS FURTHER DELAYED BY MAINTENANCE IN THE EVAPORATOR SECTION. MAINTENANCE WAS ALSO PER-
FORMED ON THE FLUE GAS ISOLATION DAMPER, FLUE GAS BOOSTER BLOWER, AND S02 REDUCTION SECTION.
DEC. 77 768 379 272 0 49 0 . 0
THE FGD SYSTEM WAS NOT OPERATED DURING THIS PERIOD DUE TO ABNORMAL BOILER OPERATING CONDI TUNS
RELATED TO HIGH SILICA LEVELS IN THE FEED WATER. THE HIGH SILICA LEVELS KSULTED FROM HIGH MAKE-UP
WATER REQUIREMENTS DUE IN PART TO A HIGHER THAN NORMAL FGD PLANT USAGE, AS WELL AS UNIT 11 COAL FEtn
PROBLEMS AND A PRECIPITATOR MALFUNCTION. MAINTENANCE WAS PERFORMED ON THE FG BOOSTER BLOWER AND
THE ABSORBER SOLUTION REGENERATION SECTION.
JAN. 76 720 S76 0 0 80 0
THE FGD SYSTEM REMAINED DOWN THROUGHOUT JANUARY AS HIGH SILICA LEVELS IN THE UNIT 11 BOILER FEED
WATER PERSISTED. MAINTENANCE WAS PERFORMED ON THE UNIT 11 PRECIPITATOR, THE FG BOUSIER BLOWLR AND
THE FGO SYSTEM 302 COMPRESSOR.
FEB. 78 720 336 0 0 17 0
THE FGD SYSTEM WAS NOT OPERATED DUE TO ABNORMAL BOILER OPERATING CONDITIONS RELATED TO HIGH SILICA
LEVELS IN THE BOILER FEED WATER, COUPLED WITH UNIT 11 COAL FEED PROBLEMS, STOP VALVE PROBLEMS, PRE-
CIPITATOR MALFUNCTION AND A LEAKING BOILER TUBE AND WORK ON THE FLUE GAS ISOLATION DAMPER. MAIN-
TENANCE WAS ALSO PERFORMED ON THE FG BOOSTER BLOWER, THE EVAPORATOR CIRCULATING PUMP AND THE S02
SUPERHEATER PIPING.
MAR. 78 720 618 281 215 90 77 30
THE FGD SYSTEM OPERATED FOR TEN DAYS. OPERATION WAS INTERRUPTED BY SHUTDOWN OF THE UNIT 11 BUILER
FOR REPAIR OF COAL GRINDING MILLS AND PRECIPITATORS. PROPER CONDITIONS COULD NOT BE RE-ESTABLISHEU
FOR RE-START OF FGD OPERATION BECAUSE OF COAL FEED AND GRINDING PROBLEMS CAUSED BY EXTREMELY POOR
QUALITY COAL. MAINTENANCE WAS PERFORMED ON THE BOOSTER BLOWER AND OPERATING PROBLEMS WERE
ENCOUNTERED WITH THE FLUE GAS ISOLATION DAMPER.
59
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EPA UTILITY F60 SURVEY: OCTOBER 1976 - NOVEMBER 1978
NORTHERN INDIANA PUBLIC SERVICE
MONTH
HOURS
IN PERIOD
HOURS
AVAILABLE
HOURS
CALLED ON
TO OPERATE
HOURS
OPERATED
DEAN n. MITCHELL 11
AVAILABILITY RbLIAHlLlM UtlLUAtlUH
U
APR. 76 720 0 288 0 U U
THE F6 BOOSTER BLOWEH WAS OUT OF SERVICE FOR THIS ENTIRE PERIOD FOR KEHLA01NU. IHk FbD SYSTE* WAS
INOPERABLE. A FAILURE OF THE FLUE GAS ISOLATION DAMPER ALSO OCCURRED. A NEH SUPPLY OF HIGH SULHW
COAL WAS OBTAINED AND SUCCESSFULLY TESTED ON UMI 11 BOILER. THIS COAL IS EXPECThl) TO ALLhVlAU
PAST DIFFICULTIES WITH THE COAL FEED AND GRINDING SYSTEM. MAINltNANCE WAS ALSO PERFORMED ON THE
BOILER ID FANS, COAL FEEDING AND GRINDING SYSTEM AND THE FGO AbSORHEK.
MAY 78 720 368 529 263 51 bU 4?
THE S02 RECOVERY PORTION OF THE FGD SYSTEM OPERATED FOR 26 DAYS. THE COMPLETE FGD SYSTEM OPERATED
FOR 11 DAYS. OPERATION WAS INTERRUPTED BY FAILURE OF THE FLUE GAS ISOLATION DAMPEK, PKUbLEMi * I IM
WET COAL WHICH REQUIRED THAT THE UNIT 11 BOILER OPERATE ON LOW SULFUR COAL FOK A SHUKT PERIOD AND
PLUGGING OF AN ENTRAINMENT SEPARATOR IN THE S02 REDUCTION UNIT.
JUNE 78 720 97 521 3 13 1 U
OPERATION OF THE FGD SYSTEM WAS LIMITED BY FAILURE OF THE BOOSTER BLOWER DRIVE TURHINF AMU
INABILITY OF THE ISOLATION DAMPER TO OPERATE. THE FGO PROCESS FACILITIES, CONSISTING OF THE
ABSORBERr EVAPORATOR. S02 REDUCTION AND PURGE TREATMENT UNITS, WERE AVAILABLE FUK OPERATION FOk
ESSENTIALLY THE ENTIRE PERIOD.
JULY 78 720 43 113 17 6 4 2
OPERATION OF THE FGD SYSTEM WAS LIMITED BY IMBALANCE OF THE BOOSTER BLOWEK. DUE 10 INAH1L1IY
OF THE ISOLATION DAMPER TO OPERATE, THIS CONDITION COULD NOT BE CORRECTED UNTIL PilftKR OEKANOS
PERMITTED A SHUT DOWN OF UNIT 11 BOILER. RECURRING FLUCTUATIONS IN THE PRESSORE OF I HE MAI';
STEAM SUPPLY TO THE FGD SYSTEM ALSO LIMITED OPERATION. FLUE GAS BOOSTER BLOnEK PROBLEMS INCLUDED
LOW OIL PRESSURE, LEAKING BEARING OIL SEALS AND DRIVE TURBINE GOVERNOR MALFUNCTION. THE FGO
PROCESS FACILITIES WERE AVAILABLE FOR OPERATION FOR THE ENTIRE PER100.
AUG. 78 720 707 720 707 98 9B 9H
THE UNIT 11 BOILER OPERATED CONTINUOUSLY ON HIGH SULFUR COAL THROUGHOUT THE PERIOD. THt FGO SYSTEM
ACHIEVED FULL OPERATION ON THE FIRST DAY OF THE PERIOD. AFTER PROBLEMS WITH THE HOOSTtR hLO*v£R
WERE CORRECTED, IT REMAINED IN FULL OPERATION FUR THE BALANCE OF THE PERIOD rvITH THE F.XCEMIUN UF
ONE TWO-HOUR INTERRUPTION DUE TO AN ELECTRICAL MOTOR MALFUNCTION.
SEP. 78 720 319 321 319 44 99 44
THE UNIT 11 BOILER OPERATED ON HIGH SULFUR COAL UNTIL SEPTEMBER 12 WHEN IT wAb SHUT-DOWN FOR AN
ANNUAL OVERHAUL. THE BOILER REMAINED DOWN THROUGH THE END OF THE PERIOD. THE FGD SYSTEM CONTIN-
UED IN FULL OPERATION UNTIL SEPTEMBER 12, WITH THE EXCEPTION OF ONK TWO-HOUR INTERRUPTION DUE TO A
GOVERNOR MALFUNCTION ON THE S02 COMPRESSOR DRIVE TURBINE, AND WAS THEN SHUT-DOnN CONCURRENTLY WITH
THE UNIT 11 BOILER.
OCT. 78 840 369 504 369 44 li 44
THIS PERIOD COVERS SEPTEMBER 29 THROUGH NOVEMBER 2. FOLLOWING THE ANNUAL TUKNARUIINU, THE UNIT U
BOILER RE-STARTED ON OCTOBER 6. A NEh BASELINE TEST WAS RUN ON THE HOILER OCTOBER 7 THROUGH 12.
BALANCING OF THE FLUE GAS BOOSTER BLOWER WAS THEN COMPLETED AFTER WHICH THE FGD SY6TEK MAS STARTED
ON OCTOBER 18.
NOV. 78 720 712 717 709 99 99 98
THE UNIT 11 BOILER OPERATED CONTINUOUSLY ON HIGH SULFUR COAL EXCEPT FOR ONE THKEE-HOUK OUTAGE FOR
REPAIR OF A STEAM CONTROL VALVE. VARIATIONS IN THE PRESSURE OF THE STEAM SUPPLY TO FGD OCCURRED
DUE TO HIGH SILICA IN THE MAKE-UP WATER TO UNIT 11. PROBLEMS nERE ALSO ENCOUNTERED nITH Thfc
SODIUM SULFATE PURGE DRYER WHICH NECESSITATED DISPOSING OF PART OF THE SULFATE PURGE TO THE BOTTOM
ASH POND FOR A PORTION OF THE PERIOD.
60
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EPA UTILITY FGD SUkVEY: UCTUnEK \11H - hOVtf'HFW 1^
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME NORTHERN STATES POWER
UNIT NAME SHER8URNE 1
UNIT LOCATION BECKER MINNESOTA
UNIT RATING 710 MW
FUEL CHARACTERISTICS COAL? 0.8X SULFUR, 9.5X SULFUR
FGO VENDOR COMBUSTION ENGINEERING
PROCESS LIMESTONE/ALKALINE FLYASH
NEW OR RETROFIT NEW
START UP DATE 3/76
EFFICIENCY:
PARTICULATES (ACTUAL) 99+ PERCENT
(DESIGN) 99.0 PERCENT
S02 (ACTUAL) 50-55 PERCENT
(DESIGN) 50.0 PERCENT
WATER MAKE UP OPEN LOOP 1.13 GPM/MW
SLUDGE DISPOSAL FORCIBLY OX 101ZED/SLUOGE PONU
OPERATING EXPERIENCE UPDATE:
BOILER OPERATION TIME AND MODULE OPEKABILITY (X)
BOILER
PERIOD KR. 101 102 103 104 105 106 107 108 109 110 111 112
FEB. 76 636 0 93 92 89 74 85 89 88 76 66 B« b7
TOTAL SYSTEM AVAILABILITY = 92 PERCENT
MEGAWAMT-HOURS GENERATED = 366,200
MODULE 101 WAS DOWN IN FEBRUARY FOR MODIFICATIONS TO THE SPRAT TUWtk AbSUWBEK. 4 HULK
ENTRAINMENT SEPARATOR WAS INSTALLED ALONG WITH A KOCH «ASH TRAY. SPRAY NOBLES ivtKE
REPLACED. THE 2 IN. DIA. SS RODS IN THE PRIMARY CONTACTOR WERE KEPLACtO «ITH 6(5/B)lN. U1A.
CERAMIC COATED C.S. RODS. THE CERAMIC SLEEVES ARE 9/16IN. THICK. MODULES WHICH AKF- SHIinING
AVAILABILITY OF LESS THAN 80 PERCENT, ARE THOSE IN WHICH THE STRAINER MOOIFICATlUUb nE^t
PERFORMED.
MAR. 78 676 71 83 64 89 90 83 62 89 97 71 79 90
TOTAL SYSTEM AVAILABILITY = 92 PERCENT
MEGAWATT-HOURS GENERATED = 423,220
STRAINER MODIFICATIONS CONTINUED THROUGH MARCH AFFECTING THE AVAILABILITIES UF MODULES 101,
103, 107 AND 110.
APR. 78 713 92 87 87 44 81 85 91 86 92 91 87 S2
TOTAL SYSTEM AVAILABILITY = 95 PERCENT
MEGAWATT-HOURS GENERATED - 464,520
THE REASON FOR LOW AVAILABILITY ON MODULE 104 AND 112 IN APHIL RESULTED FOKM THE OUTAGE TIME
NECESSARY FOR THE INSTALLATION OF STEEL STRAINER SCREENS.
MAY 78 635 61 86 85 86 89 64 62 83 «2 71 87 79
TOTAL SYSTEM AVAILABILITY = 95 PERCENT
MEGAWATT-HOURS GENERATED = 380,010
THERE WERE NO MAJOR FGD RELATED OUTAGES DURING MAY.
JUNE 78 717 50 84 85 85 62 78 55 83 88 82 72 95
TOTAL SYSTEM AVAILABILITY = 93 PERCENT
MEGAWATT-HOURS GENERATED = 414,670
61
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EPA UTILITY F6D SURVEY: OCTOBER 1978 - NOVEMBER 1978
NORTHERN STATES POWER SHEKbUKNE 1
BOILER OPERATION TIME AND MODULE UPERABILITY (X)
BOILER
PERIOD HR. 101 102 103 104 105 106 107 108 IU9 110 111 112
JULY 78 694 82 76 71 74 75 52 75 63 62 72 66 73
TOTAL SYSTEM AVAILABILITY = 95 PERCENT
MEGAHATT-HOURS GENERATED = 394,510
THE UTILITY IS IN THE PROCESS OF REMOVING THE ORIGINAL ZURN DUPLEX STRAINEHS AND REPLACING
THEM WITH 316 STAINLESS STEEL STRAINERS. THE UCCURANCE OF PLUGGING PROBLEMS IN THE MIST
ELIMINATOR AND REHEATER HAS BEEN MORE FREOUENT THAN NORMAL. THE UULITY IS EVALUATING NEW
RUBBER LINED PUMPS (8000 GPM) AND STAINLESS STEEL MIST ELIMINATOR WASH LANCF.S ITO REPLACE
ORIGINAL FIBERGLAS LANCES). THE FGD SYSTEM HAS HEEN EXPERIENCING PRIMAKY CUMACTOK hALL AND
MARBLE BED WEAR. THE UTILITY IS PREPARING FOR THE STATE COMPLIANCE DEADLINE ON NOV. 1.
CURRENTLY TESTING HAS BEEN PROCEEDING ON DIFFERENT MODULES IN AN EFFORT To FINE HlNE THfc
SYSTEM.
AUG. 78 742 64 65 73 63 65 80 81 73 63 73 64 83
TOTAL SYSTEM AVAILABILITY = 91 PERCENT
MEGAWATT-HOURS GENERATED = 416,930
NO MAJOR FGD RELATED OUTAGES h£RE REPORTED BY THE UTILITY FOR THE MONTH OF AUGUST.
SEP. 78 357 89 62 77 77 58 82 68 68 80 80 55 75
TOTAL SYSTEM AVAILABILITY = 97 PERCENT
MEGAWATT-HOURS GENERATED = 185,740
THE BOILER WAS TAKEN DOWN ON SEPTEMBER 15 FOR A SCHEDULED ANNUAL BUILER AND lUKHlNE INSPEC-
TION. THIS IS EXPECTED TO LAST THROUGH OCTOBER 16. THE UTILITY HAS ASKED THAI THE STATE
COMPLIANCE DEADLINE BE MOVED UP FROM NOVEMBER 1. THE DECISION IS CURRENTLY PENDING. THt
RUBBER LINED PUMPS THAT THE UTILITY WAS INVESTIGATING AS POSSIBLE SOLUTIONS TO THF MIST
ELIMINATOR AND REHEATER PLUGGING PROBLEMS HAVE BEEN ORDERED. FOUR OF THt HUMPS HAVE BEtM
RECEIVED AND ONE IS INSTALLED. THE OTHERS WILL BE INSTALLED AS THEY COME IN. OIHFF.NfcNT
MIST ELIMINATOR SPRAY PATTERNS ARE ALSO BEING TESTED.
OCT. 78 375 95 65 80 17 66 88 53 72 86 70 85 73
TOTAL SYSTEM AVAILABILITY = 92 PERCENT
MEGAWATT-HOURS GENERATED = 195,700
THE LOW OCTOBER HOUKS RESULTED FROM THE SCHEDULED ANNUAL BOILER ANU TURBINE UVEKHAUL. THE
UNIT WAS BROUGHT BACK ON LINE IN THE MIDDLE OF OCTOBER. THE NEW SPRAY PUMPS (MtlMTIUNEU IN
JULY) MERE INSTALLED ON MODULES 104, 107, AND 110.
NOV. 78 714 42 51 88 81 71 78 77 63 85 61 84 70
TOTAL SYSTEM AVAILABILITY = 92 PERCENT
MEGAWATT-HOURS GENERATED = 403,110
IN NOVEMBER MODULE 101 (THE CONVERTED ROD SCRUBBER MODULE) WAS DOWN FOR PUMP WORK ANU
INTERNAL HEADER CONVERSION. THE UTILITY IS NOW IN THE PROCESS OF PREPARING THE MODULE FOK
FURTHER TESTING.
62
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fcPA UTILITY FGO SURVtY: UCIOBtK 1978 - NuVEKBEK 197S
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME NORTHERN STATES POWER
UNIT NAME SHERBURNE 2
UNIT LOCATION BECKER MINNESOTA
UNIT RATING 710 MM
FUEL CHARACTERISTICS COAL; 0.8X SULFUR, 9.5X ASH
FGD VENDOR COMBUSTION ENGINEERING
PROCESS LIMESTONE/ALKALINE FLYASH
NEW OR RETROFIT NEW
START UP DATE 4/77
EFFICIENCY:
PARTICIPATES (ACTUAL) 50-55 PERCENT
(DESIGN) 99.0 PERCENT
802 (ACTUAL) 55.0 PERCENT
(DESIGN) 50.0 PERCENT
WATER MAKE UP OPEN LOOP 1.13 GPM/MW
SLUDGE DISPOSAL FORCIBLY OXIDIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
BOILER OPERATION TIME AND MODULE OPERA8ILITY (X)
BOILER
PERIOD HR. 201 202 203 204 205 206 207 208 209 210 211 212
FEB. 78 620 83 85 55 91 89 76 71 89 85 81 97 60
TOTAL SYSTEM AVAILABILITY = 92 PERCENT
MEGAWATT-HOURS GENERATED = 367,080
MODULES 203 AND 212 HAVE LOW AVAILABILITY DUE TCKSTRAINEK MODIFICATIONS.
MAR. 78 744 82 92 90 83 78 85 91 62 83 78 88 89
TOTAL SYSTEM AVAILABILITY = 97 PERCENT
MEGAWATT-HOURS GENERATED = 483,750
IN SPITE OF STRAINER MODIFICATIONS ON MODULES 208 AND 210, THE SYSTEM GENERATED MAXIMUM
MEGAWATT-HOURS AND TIED THE HIGHEST RECORDED AVAILABILITY OF 97 PERCENT.
APR. 78 719 70 82 90 84 91 83 84 86 78 90 67 85
TOTAL SYSTEM AVAILABILITY = 92 PERCENT
MEGAWATT-HOURS GENERATED = 436,420
DURING APRIL MODULE 201 WAS CONVERTED FUR USE WITH THE NEW SPRAY TOWER WHICH WAS INSTALLED.
MAY 78 120 97 94 80 90 90 89 90 92 28 91 78 14
TOTAL SYSTEM AVAILABILITY = 91 PERCENT
MEGAWATT-HOURS GENERATED = 70,070
THERE WERE LINER FAILURES (CE1LCOTE) IN MOST OF THE MODULES DURING MAY. THE LINERS »EKt
REPAIRED BY THE CEILCOTE COMPANY AT THEIR OWN EXPENSE. THE INLET SEAL STRIPS WEKb ALSO
REPAIRED. THE UNIT WENT DOWN ON MAY 6 FOR THE FIRST YEAR BOILER AND TURBINE INSPfcCTION AND
WAS DOWN FOR THE REMAINDER OF THE PERIOD.
JUNE 78 572 77 46 41 67 62 62 72 78 60 62 76 75
TOTAL SYSTEM AVAILABILITY = 95 PERCENT
MEGAWATT-HOURS GENERATED = 326,760
63
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EPA UTILITY FGD SURVEY: OC10BEK 1978 - NOVEMBER 1978
NORTHERN STATES POWER SHhRBUKNE 2
BOILER OPERATIUN TIME AND MODULE OPERAB1L1TY (k)
BOILER
PERIOD HR. 201 202 203 204 205 206 207 208 209 210 211 212
JULY 78 697 87 69 62 93 90 60 8b 67 61 81 73 71
TOTAL SYSTEM AVAILABILITY = 95 PERCENT
MEGAWATT-HOURS GENERATED = 393,610
THE UTILITY IS IN THE PROCESS OF REMOVING THE ORIGINAL ZURN DUPLEX S1KA1NEKS AND
THEM WITH 316 STAINLESS STEEL STRAINERS. THE OCCURANCE OF PLUGGING PRUBLEMb IN IHE MbT
ELIMINATOR AND REHEATER HAS BtEN MORE FREMUtNT THAN NORMAL. THE UIILITY Ib EVALUATING NbW
RUBBER LINED PUMPS (8000 GPM) AND STAINLESS STEEL MIST ELIMINATOR KAbH LANCEb (lU REPLACE
ORIGINAL FIBERGLAS LANCES). THF. FGD SYSTEM HAS BEEN EXPERIENCING PRIKANY CUNTACfOK rtALL AM)
MARBLE BED WEAR. THE UTILITY IS PREPARING FOR THE STATE COMPLIANCE OtADLIIvE ON HllV. 1.
CURRENTLY, TESTING HAS BEEN PROCEEDING ON DIFFERENT MODULES IN AN EFFORT TU UNE TUNE tHfc
SYSTEM.
AUG. 76 695 88 100 48 79 81 72 64 67 54 76 60 71
TOTAL SYSTEM AVAILABILITY = 93 PERCENT
MEGAWATT-HOURS GENERATED = 384,400
SEP. 78 720 72 82 70 61 74 64 62 72 75 78 82 66
TOTAL SYSTEM AVAILABILITY = 96 PERCENT
MEGAWATT-HOURS GENERATED = 396,500
NO FGD RELATED OUTAGES WERE REPORTED BY THE UTILITY FOR THE AUGUST-SEKIEMHEK KEPUKT PI-KIUD.
THE UTILITY HAS ASKED THAT THE STATE COMPLIANCE TEST BE MOVED UP FKUM NOVEMBER 1. A DECI-
SION IS STILL PENDING. THE RUBBER LINED PUMPS THAT THE UTILITY WAb INVESIIGATING AS POS-
SIBLE SOLUTIONS TO THE MIST ELIMINATOR AND REHEATER PLUGGING PkUBLEMb HAVE KEEN ORDF.KtO.
FOUR OF THE PUMPS HAVE BEEN RECEIVED AND ONE IS INSTALLED. THE OTHEKS rtILL BE INSTALLED Ab
THEY ARE RECEIVED. DIFFERENT MIST ELIMINATOR SPRAY PATTERNS ARE ALSO BEING TESTED.
OCT. 78 688 90 79 59 73 69 64 78 76 72 69 Id 62
TOTAL SYSTEM AVAILABILITY = 94X
MEGAWATT-HOURS GENERATED = 378,990
DURING OCTOBER MODULE 203 EXPERIENCED REHEATER PROBLEMS AND A PLUGGED STkAlNEk CAUSING A
0 TO 5 DAY OUTAGE.
NOV. 78 472 84 45 82 60 75 58 77 75 63 83 72 47
TOTAL SYSTEM AVAILABILITY = 92X
MEGAWATT-HOURS GENERATED = 237,860
THE LOW NOVEMBER BOILER HOURS RESULTED FROM A TURBINE INSPECTION. NUkMAL OVERHAUL
MAINTENANCE WAS PERFORMED ON THE SPRAY PUMPS OF MODULES 202 AND 21«!.
-------
EPA UTILITY F6D SURVEY: OCTOBEK 197B - NUVECBEH 1976
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
PENNSYLVANIA POWER
BRUCE MANSFIELD 1
SHIPPINGPORT PENNSYLVANIA
825 MW
FUEL CHARACTERISTICS COAL; 4.7X SULFUR, 12,5X ASH
FGD VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
S02 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
CHEMICO
LIME
NEW
1/76
99.9 PERCENT
99.8 PERCENT
95.0 PERCENT
92.1 PERCENT
OPEN LOOP
STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
MONTH
BOILER
OPERATING HOURS
FGD MODULES
BCD
NOV. 77 720 682
F60 AVAILABILITY FACTOR X 95
F60 OPERABILITY FACTOR X 95
F6D UTILIZATION FACTOR X 95
713
99
99
99
657
91
91
91
TOTAL FGD LOST GENERATION FACTOR = 52.SX
REMOVAL OF THE OLD COATING AND PRIMING OF THE FLUE LINING IN FLUE IB IS PROCEEDING
SLOWER THAN ANTICIPATED. IT IS EXPECTED THAT TOTAL WORK ON THE FLUE WILL NOT BE COMPLETED
UNTIL FEBRUARY OR MARCH.1978.
THE FLUE WILL BE RELINEO WITH
DEC. 77 626* 677 592 675 0 0
FGD AVAILABILITY FACTOR X 100 93 99 0 0
FGD OPERABILITY FACTOR X 100 94 100 0 0
FGD UTILIZATION FACTOR X 91 79 91 0 0
TOTAL FGD LOST GENERATION FACTOR = 61 X
SANDBLASTING OF UNIT 1-B FLUE IS NEARING COMPLETION.
CXL-2000.
JAN. 78 331» 433 0 432 0 00
F6D AVAILABILITY FACTOR X 100 0 100 0 00
FGD OPERABILITY FACTOR X 100 0 100 0 00
FGD UTILIZATION FACTOR 58 0 58 0 00
TOTAL F6D LOST GENERATION FACTOR = 60X
THERE WERE PROBLEMS WITH IB FAN WHICH NECCESITATED EXTENSIVE REPAIRS. LINING ABRASION AND
DISBONDMENT IN FAN CAUSED CORROSION OF UNDERLYING SUPPORT METAL. THE UNIT TRIPPED SEVEHAL
TIMES DUE TO DIFFICULTIES IN BURNING WET STOCKPILE COAL.
FEB. 78 514* 534 410 551 0 00
FGD AVAILABILITY FACTOR X 79 61 82 0 0 0
FGD OPERABILITY FACTOR X 100 80 100 0 00
F6D UTILIZATION FACTOR X 79 61 82 0 0 0
TOTAL FGO LOST GENERATION FACTOR = 54X
EXTENSIVE REPAIRS TO IB I.D. FAN AND THE EMERGENCY NEED FOR LOAD FROM THE PLANT DURING THE
COAL STRIKE TEMPORARILY OVERLOADED 1A AND 1C TRAINS. THE MIST ELIMINATOR MILL BE REPLACED
1C TRAIN AS A RESULT OF THIS. IB FLUE RELINING CONTINUES.
65
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EP* UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
PENNSYLVANIA POWER
BRUCE MANSFIELD 1
MONTH
BOILER
MAR. 78 689 324
F60 AVAILABILITY FACTOR X 43
FGD OPERABILITY FACTOR X 47
F60 UTILIZATION FACTOR X 43
B
678
91
98
91
OPERATING HOURS
FGD MODULES
C 0
670
90
97
90
485
65
70
65
376
50
54
50
449
60
65
60
REPAIRS WERE DONE ON
TOTAL FGD LOST GENERATION FACTOR = 54X
REPLACEMENT OF THE LINING IN IB CHIMNEY WITH CXL 2000 WAS COMPLETED.
A, B, AND C FAN HOUSINGS.
APR. 78 720 530 632 357 630 697 678
FGD AVAILABILITY FACTOR X 74 88 49 87 97 94
FGD OPERABILITY FACTOR X 74 88 49 87 97 94
FGD UTILIZATION FACTOR X 74 88 49 67 97 94
TOTAL FGD LOST GENERATION FACTOR = 18X
MISCELLANEOUS LEAK REPAIRS WERE DONE ON FAN HOUSINGS AND DUCTS.
MAY 70 457 442 0 443 389 394 395
FGD AVAILABILITY FACTOR X 98 0 98 91 92 92
FGD OPERABILITY FACTOR X 97 0 97 85 84 86
FGD UTILIZATION FACTOR X 59 0 59 52 52 53
TOTAL FGD LOST GENERATION FACTOR = 21X
EXTENSIVE REPAIRS WERE MADE ON THE IB FAN. ANNUAL BOILER INSPECTION OUTAGE BEGAN UN MAY 20.
JUNE 78 0 000000
FGD AVAILABILITY FACTOR X 0 0 100 100 100 100
FGD OPERABILITY FACTOR X 0 0 0 0 00
FGD UTILIZATION FACTOR X 0 0 0 0 00
TOTAL FGD LOST GENERATION FACTOR = OX
UNIT OUTAGE TIME WAS FOR BOILER INSPECTION AND GENERATOR STATOR COOLER REPAIRS.
*NOTE: AN ATTEMPT is ALWAYS MADE TO BEGIN OPERATION OF THE BOILER AND FGD SYSTEM SIMULTANEOUSLY AT
BRUCE MANSFIELD. OCCASIONALLY PROBLEMS DELAY BOILER START-UP MAKING IT POSSIBLE FOR MONTHLY
FGD MODULE HOURS TO EXCEED ACTUAL BOILER HOURS.
66
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EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 197B
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
PENNSYLVANIA POWER
BRUCE MANSFIELD 2
SHIPPINGPORT PENNSYLVANIA
825 MW
FUEL CHARACTERISTICS COAL; 4.7X SULFUR, 12.5X ASH
FGD VENDOR CHEMICO
PROCESS LIME
NEW OR RETROFIT NEW
START UP DATE 7/77
EFFICIENCY!
PARTICULATES (ACTUAL)
(DESIGN)
S02 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
99.9 PERCENT
99.8 PERCENT
95.0 PERCENT
92.1 PERCENT
OPEN LOOP
STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
MONTH
BOILER
OPERATING HOURS
FGD MODULES
BCD
NOV. 77 581* 598 584 533 331 304 246
FGD AVAILABILITY FACTOR X 100 96 86 47 55 47
FGD OPERABILITY FACTOR X 100 100 92 57 52 42
FGD UTILIZATION FACTOR X 63 81 74 46 42 34
TOTAL FGD LOST GENERATION FACTOR = 27X
PROBLEMS ASSOCIATED WITH THE STATION POWER TRANSFORMERS CAUSED LIMITATION IN LOAD ON UNIT 2.
THREE OF THE SIX STATION TRANSFORMERS FOR UNIT 2 MERE DESTROYED.
DEC. 77 607* 469 638 616 644 513 565
FGD AVAILABILITY FACTOR X 74 99 98 100 89 99
FGD OPERABILITY FACTOR X 77 100 100 100 85 93
FGD UTILIZATION FACTOR X 63 86 83 86 69 76
TOTAL FGD LOST GENERATION FACTOR = 7.4X
COLD WEATHER CREATED SOME FREEZING PROBLEMS WITH PROCESS PIPING.
JAN. 76 391* 228 564 218 521 481 375
FGD AVAILABILITY FACTOR X 95 100 96 94 99 99
FGD OPERABILITY FACTOR X 58 100 56 100 100 96
FGD UTILIZATION FACTOR X 31 76 29 70 64 50
TOTAL FGD LOST GENERATION FACTOR = 4.3X
UNIT TRIPPED SEVERAL TIMES DUE TO DIFFICULTIES IN BURNING WET STOCKPILE COAL. BOILER
CONTROL VALVE PROBLEMS ("W" VALVE) COMPOUNDED START-UP ATTEMPT DIFFICULTIES. WHEN THE UNIT
WAS ON LINE DURING THIS MONTH, THE WET COAL ALSO PREVENTED FULL LOAD OPERATION OF
COAL MILLS.
FEB. 78 672 321 460 594 460 664 525
F60 AVAILABILITY FACTOR X 84 87 89 97 99 78
FGD OPERABILITY FACTOR X 46 68 88 71 99 78
FGD UTILIZATION FACTOR X 48 66 88 71 99 76
TOTAL FGO LOST GENERATION FACTOR = 16.6 X
MANY PROBLEMS OCCURRED WITH I.D. FAN COOLERS DUE TO INCLEMENT WEATHER.
67
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EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 1978
PENNSYLVANIA POWER
MONTH
BOILER
MAR. 78 094*
FGD AVAILABILITY FACTOR X
FGD OPERABILITY FACTOR X
FGD UTILIZATION FACTOR X
502
100
100
67
B
409
93
91
60
OPERATING HOURS
FGD MODULES
C 0 E
96
13
10
13
509
95
100
68
474
95
96
64
TOTAL F6D LOST GENERATION FACTOR = 28X
A BOILER TUBE LEAK CAUSED AN OUTAGE FOR SEVERAL DAYS,
WERE PERFORMED ON THE 2C FAN.
APR. 78 713 583 583 424 108 101
FGD AVAILABILITY FACTOR X 100 100 59 15 14
FGD OPERABILITY FACTOR X 82 83 59 15 14
FGO UTILIZATION FACTOR X 81 81 59 15 14
BRUCE MANSFIELD 2
487
97
99
65
EXTENSIVE I.U. FAN HOUSING REPAIRS
96
13
13
13
TOTAL FGD LOST GENERATION FACTOR = 38X
2B CHIMNEY FLUE LINING REPAIRS BEGAN ON APRIL 5. EXTENSIVE REPAIRS WERE DONE ON THE
-------
EPA UTILITY FGO SURVEY: OCTOttEk 19/8 - NOVEM8EH 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
PHILADELPHIA ELECTRIC
EOOYSTONE 1A
EDDYSTONE PENNSYLVANIA
120 MW
FUEL CHARACTERISTICS COAL; 2.5X SULFUR, 10* ASH
FGD VENDOR
PROCESS
NEM OR RETROFIT
START UP DATE
EFFICIENCY!
PARTICULATES (ACTUAL)
(DESIGN)
302 (ACTUAL)
(DESIGN)
MATER MAKE UP
SLUDGE DISPOSAL
UNITED ENGINEERS
MAGNESIUM OXIDE
RETROFIT
9/75
99.9 PERCENT
99.9 PERCENT
95-97 PERCENT
90.0 PERCENT
OPEN LOOP 1.1 GPM/MW
ACID PLANT REGENERATION
OPERATING EXPERIENCE UPDATE:
FEB. 76
MAR. 78
APR. 78
MAY 78
JUNE 78
78
MONTH
AUG. 78
SEP. 78
THE TURBINE OVERHAUL CONTINUED DURING THE REPORT PERIOD. DURING THE SHUIDUWN PEHIOD IT
HAS FOUND THAT SOME HIGH PRESSURE STEAM TUBES HERE CRACKED, SU UNIT MAINTENANCE: HAS TAKEN
LONGER THAN EXPECTED. SOME MINOR FGD SYSTEM MODIFICATIONS HAVE BEEN INCOKPOHATEU IN THE
COURSE OF THE SHUTDOWN PERIOD. START UP IS EXPECTED IN MID-APRIL 78.
THE UNIT JUST CAME BACK ON LINE JUNE 1 AFTER AN EXTENSIVE SYSTEM MODIFICATION UUTAGE
WHICH BEGAN DECEMBER 22. THE UNIT WAS EXPECTED BACK ON LINE IN MJ.O-APKIL, BUT THEKE "AS
A PROBLEM WITH A SUPER PRESSURE STEAM TURBINE.
DURING JUNE THE FGD SYSTEM ACHIEVED A 49X OPERABILITY. OPERABILITY FOR JULY
.WAS SIX, .PROBLEMS OCCURRED THE LAST WEEK OF JUNE WITH THE MGS03 SLUKRY CIRCULATION PUMP
NHEN THE UTILITY DISCOVERED THE RUBBER LINER WAS TORN AWAY. THEKE HAVE BEEN SOME PROBLEMS
WITH THE M60 SECTION WHERE THE MGO MIXES WITH THE SYSTEM LIQUOR. FIKE BRICK WAS REMOVED
FROM THE FLUID BED REACTOR CHAMBER TO REPLACE THE ACID 8ARRIOR PLATES WHICH w£KE FAILING.
THE FIRE BRICK WAS THEN REPLACED. THE SLOW PIECE BY PIECE PROCEDURE WAS TIME CONSUMING
AND ACCOUNTED FOR MOST OF THE REGENERABLE FACILITY DOWN TIME (MOST OF JUNE AND JULY).
MAJOR PROBLEMS WERE SOLVED ON THE REGENERATIVE FACILITY OVER THE PERIOD RESULTING IN
IMPROVED AVAILABILITY OF THE FACILITY.
PERIOD
HOURS
BOILER
HOURS
HOURS
FGD SYSTEM PARAMETERS
OPERABILITY UTILIZATION
744 631 240 3BX 32X
DURING THE MONTH OF AUGUST SCRUBBER CIRCULATING PIPING PROBLEMS MERE ENCOUNTERED. A HUT-
TERFLY CONTROL VALVE WAS NOT FULLY OPEN AND A SECTION OF PIPE DOWNSTREAM AT A 9U DEGREE
BEND ERODED AWAY. TO CORRECT THE PROBLEM THE BUTTERFLY VALVE WAS TAKEN UUT AND REPLACED
WITH A RESTRICTION ORIFICE. THE CIRCULATION PUMPING RATE WAS ALSO REDUCED.
720 S16 402 78X 56X
THE UTILITY REPORTED THAT NO MAJOR PROBLEMS WERE ENCOUNTERED DURING THE MONTH OF
SEPTEMBER. CERTAIN MECHANICAL PROBLEMS WERE RESOLVED WHICH CAUSED AN IMPROVEMENT IN THE
OPERABILITY FIGURE.
69
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EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1976
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
FUEL CHARACTERISTICS COAL; 0.8X SULFUR, 30X ASH
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN 1
WATERFLOW NEW MEXICO
MW
FGO VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
302 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
DAVY POWtRGAS
wELLMAN LORD
NEW
0/78
99.a PERCENT
85.0 PERCENT
CLOSED LOOP 1.53 GPM/Mw
ELEMENTAL SULFUR PRODUCT
OPERATING EXPERIENCE UPDATE:
FEBRUARY-MARCH 1978 - INITIAL 303 ABSORPTION AT SAN JUAN NO. 1 BEGAN ON APRIL 8, 1978. FULL CUMMEK-
CIAL OPERATION IS EXPECTED BY LATE JUNE. THE FGD SYSTEM IS CURRENTLY IN SERVICE WITH two OF Tut
UNIT'S FOUR ABSORBER CELLS OPERATING CONTINUOUSLY. A THIRD CELL IS TO BE BROUGHT UN LINE LATbK.
THREE CELLS WILL BE REQUIRED FOR FULL LOAD WITH A FOURTH INCLUDED FOR SPARE FGl) CAPACITY. THE CUR-
RENT MODE IS TO KEEP 2 CELLS IN SERVICE AT ALL TIMES AND 2 OUT OF SERVICE. 2/3 OF THE FLUb GAb
IS BEING TREATED WHILE 1/3 IS BEING BYPASSED. THE UNIT IS IN COMPLIANCE AT PRESENT WITH KtSPECT TO
302 KITH ONLY 2 CELLS RUNNING BECAUSE THE BISULFITE CONCENTRATION HAS NOT YET BUILT UP IN IHE AH80K-
BENT LIOUOR. WHEN THE SYSTEM REACHES EQUILIBRIUM WITH RESPECT TO BISULFITE (1BX BISULFITE) THE UNIT
WILL BE READY TO BEGIN REGENERATING OPERATIONS. REGENERATION IS EXPECTED TO BEGIN BY APRIL 27.
APRIL-MAY 1978 - OVER THE PERIOD THE UTILITY ACCUMULATED 22 DAYS OF DATA DURING WHICH THE BOILER
WAS DOWN FOR 7 HOURS AND THE ABSORBERS WERE DOWN FOR 28 HOURS (UNSCHEDULED). THE UNIT IS STILL NOT
STABILIZED SO USEFUL FIGURES FOR WATER REQUIREMENTS ARE UNAVAILABLE. THE CHEMICAL PLANT REMAINS IN
ITS START UP STAGE.
JUNE-JULY 1978 - THE UNIT EXPERIENCED A VERY HIGH PRESSURE DROP ACROSS THE VENTURIS DURING THIS
PERIOD. AS A RESULT, THE FANS WERE NOT ABLE TO MOVE 100X OF THE FLUE GAS THROUGH THE FGD SYSTEM.
AUGUST-SEPTEMBER 1978 - DURING THIS PERIOD THE HIGH PRESSURE DROP PROBLEM WAS CORRECTED BY MODIFYING
ADJUSTABLE PLUMB BOBS WITHIN THE MODULES TO BE FARTHER AWAY FROM THE VENTURIS. THIS IMPROVED THE
GAS FLOW AND REDUCED THE PRESSURE DROP. THE UTILITY ANTICIPATES THAT THEY WILL NOW BE ABLE TO SCRUB
100X OF THE FLUE GAS. IN ORDER TO PERFORM THESE MODIFICATIONS AT LEAST TWO MODULES WERE DOWN AT ALL
TIMES THROUGHOUT THE PERIOD. MIST ELIMINATOR REPAIRS WERE ALSO MADE WHILE THE MODULES WERE DOWN.
THERE WAS A TWO WEEK BOILER OUTAGE IN SEPTEMBER CAUSED BY A FIRE IN THE START-UP TRANSFORMER DUCT
BANK. HOURS OF OPERATION FOR THIS NEWLY OPERATIONAL UNIT ARE NOT YET AVAILABLE.
OCTOBER-NOVEMBER 1978 - THE UTILITY REPORTED THAT THE UNIT IS STILL CONSIDERED IN THE START-UP PHASE
AND NO HOURS OF OPERATION ARE AVAILABLE. THE ONLY PROBLEM REPORTED WAS LINE FREEZING DUE TO HEAT
TRACING FAILURES. SOME SULFUR PRODUCT HAS BEEN PRDUCED BUT THE REGENERATION FACILITY IS ALSO IN
THE START-UP PHASE AND NO OPERATIONAL DATA IS AVAILABLE.
70
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EPA UTILITY FGD 3UKVEY: UCTOBEK 1978 - NOVEMBEK 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME PUBLIC SERVICE OF NEW MEXICO
UNIT NAME SAN JUAN 2
UNIT LOCATION WATERFLOW NEW MEXICO
UNIT RATING 306 MW
FUEL CHARACTERISTICS COAL; 0.8X SULFUR, SOX ASH
FGD VENDOR DAVY POWERGAS
PROCESS WELLMAN LORD
NEW OR RETROFIT RETROFIT
START UP DATE 8/76
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 99.5 PERCENT
302 (ACTUAL)
(DESIGN) 85.0 PERCENT
WATER MAKE UP CLOSED LOOP
SLUDGE DISPOSAL ELEMENTAL SULFUR PRODUCT
OPERATING EXPERIENCE UPDATE:
AUGUST-SEPTEMBER 1978 - INITIAL OPERATIONS BEGAN AT THIS UNIT LATE IN AUGUST. ALL THREE MODULES
RAN TOGETHER AT FULL CAPACITY FOR THE FIRST TIME IN SEPTEMBER. A TWO WEEK BOILEK OUTAGE OCCUKKED IN
SEPTEMBER AS A RESULT OF A FIRE IN THE START-UP TRANSFORMER DUCT BANK. PROBLEMS WERE ALSO ENCOUN-
TERED WITH THE BOOSTER FAN CONTROL DAMPER. DUE TO THE RECENT OPERATING STATUS (If THIS SYSTEM
HOURS OF OPERATION ARE NOT YET AVAILABLE.
OCTOBER-NOVEMBER 1978 - THE UNIT IS STILL IN THE STARTUP-DEBUGGING STAGE AND NO OPERATIONAL HOURS
ARE AVAILABLE. PROBLEMS ENCOUNTERED INCLUDED LINE FREEZING DUE TO HEAT TRACING FAILURES AND A
TEMPORARY HIGH FLYASH LOADING DUE TO AN ESP MALFUNCTION.
71
-------
EPA UTILITY FGD SURVEY: OCTOBEK 1978 - NOVEMBER 1<»78
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME SOUTH CAROLINA PUBLIC SERVICE
UNIT NAME WINYAH 2
UNIT LOCATION GEORGETOWN SOUTH CAROLINA
UNIT RATING 580 MW
FUEL CHARACTERISTICS COAL? l.OX SULFUR, 19X ASH
FGO VENDOR BABCOCK ft WILCOX
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 7/77
EFFICIENCY:
PARTICULATES (ACTUAL) 99.1 PERCENT
(DESIGN) 99.
-------
EPA UTILITY FGD SURVEY: UCTOBEK 197B - fiUVfcMBEk 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME SOUTHERN MISSISSIPPI ELECTRIC
UNIT NAME R. D. MORROW 1
UNIT LOCATION HATTIESBURG MISSISSIPPI
UNIT RATING 180 MW
FUEL CHARACTERISTICS COAL; IX SULFUR, 8X ASH
FGD VENDOR RILEY STOKER / ENVIRONEERING
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 8/78
EFFICIENCY!
PARTICULATES (ACTUAL)
(DESIGN) 99.6 PERCENT
303 (ACTUAL)
(DESIGN) 85 PERCENT GUARANTEE
WATER MAKE UP
SLUDGE DISPOSAL STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
AUGUST-SEPTEMBER 1978 - INITIAL OPERATIONS AT THIS UNIT BEGAN IN AUGUST 1978. A FORCED bOILEK OUT-
AGE OCCURRED DURING THE PERIOD AS A RESULT OF BOILER TOBE LEAKS. THE UNIT IS EXPECTtO BACK UM LI*t
BY THE FIRST OF NOVEMBER. DUE TO THE RECENT OPERATING STATUS OF THIS SYSTEM HUUHS OF OPEHATIOiM AWE
NOT YET AVAILABLE.
OCTOBER-NOVEMBER 1978 - DURING OCTOBER OPERATION OF THE UNIT WAS INTERMITTENT DUE TO CONTINUING
BOILER TUBE PROBLEMS. THE FGD SYSTEM WAS BYPASSED ENTIRELY IN OCTOBER DUE TO SERIOUS CONTROL
VALVE PLUGGING. THE UTILITY IS IN THE PROCESS OF FINDING A SOLUTION TO THE VALVE
PROBLEM. THE BOILER WAS SHUT DOWN AGAIN THE FIRST OF NOVEMBER DUE TO BOILER TUBE PROBLEMS.
RESUMPTION OF OPERATION OF THE UNIT IS SCHEDULED FOR MARCH 1979.
73
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EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
SPRINGFIELD CITY UTILITIES
SOUTHWEST 1
SPRINGFIELD MISSOURI
aoo MW
FUEL CHARACTERISTICS COALJ 3.SX SULFUR, 13X ASH
FGD VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
SOS (ACTUAL)
(DESIGN)
MATER MAKE UP
SLUDGE DISPOSAL
AIR CORRECTION DIVISION, UOP
LIMESTONE
NEW
4/77
99.8 PERCENT
99.7 PERCENT
92.0 PERCENT
80.0 PERCENT
UNSTABILIZED/LANOFILL
OPERATING EXPERIENCE UPDATE:
FEB. 78
MAR. 78
THE ABSORBERS DID NOT OPERATE DUE TO AN EXPANSION JOINT FAILURE BETWEEN THE ID FAN AND
THE ABSORBERS. CURRENTLY, THE ABSORBERS ARE BEING BY-PASSED. THE FGD SYSTEM IS EXPECTED TO
BE BACK ON LINE BY THE END OF APRIL.
APR. 78
MAY 78
JUNE 78
THE UNIT EXPERIENCED AN FRP LINER FAILURE AS WELL AS A PUMP FAILUKE DURING THE PERIOD.
CURRENTLY ONLY ONE SCRUBBER-ABSORBER MODULE IS RUNNING. THE EXPANSION JOINT FAILURE
MENTIONED PREVIOUSLY WAS DIRECTLY RELATED TO THE DAMPER FAILURE WHICH ALLOWED THE BOILER
TO CONTINUE PUMPING GAS TO THE SEALED OFF FGD SYSTEM.
THE A-MODULE RAN STEADILY FOR OVER 11 DAYS. B-MOOULE WAS STILL DOWN WITH EXPANSION JOINT
PROBLEMS. DURING THE MONTH THE MIST ELIMINATOR WASH SYSTEM WAS ALTERED FROM A SEPARATE
CLOSED LOOP FOR EACH MODULE TO A COMMON SYSTEM FOR BOTH MODULES. THE NEW SYSTEM TAKES SUPER-
NATANT FROM THE TOP OF THE THICKENER FOR MIST ELIMINATOR SPRAY. INSTRUMENTATION PROBLEMS
HERE ENCOUNTERED DURING THE MONTH. PH PROBES WERE LOST, THE MAG-FLOW METER FOR LIMESTONE
SLURRY FAILED, AND THE AUTOMATIC GAS ANALYZERS DID NOT OPERATE PROPERLY. SOME PIPES PLUGGED
DUE TO NEOPRENE PEELING FROM VALVES. THE SLUDGE SYSTEM EXPERIENCED SOME FILTER BELT PROBLEMS
BUT THESE MERE REPAIRED.
74
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SPRINGFIELD CITY UTILITIES
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER
SOUTHWEST 1
MONTH
BOILER
OPERATING HOURS
A-SIOE B-SIDE TOTAL
FORCED OUTAGE TIME
A-SIDE B-SIDE TOTAL
MEGA^ATT-HUUk
PRODUCTION
1364
101,1B8
JULY 78 744 124 0 124 620 704
AVAILABILITY = 8X
OPERABILITY = 8X
RELIABILITY - 8X
UTILIZATION = 8*
DURING THE MONTH PROBLEMS WERE ENCOUNTERED WITH THE MODULE A TRANSFER PUMPS. NK.E DAYS >-.EwE
REQUIRED TO TKACE THE ELECTRICAL PROBLEM. A 17 DAY OUTAGE WAS CAUSED BY PROBLEMS rtlTH THE
BALL MILL AIR SUPPLY WHICH RESULTED IN THE UNAVAILABILITY OF SLURHY. B-MOOULE WAS STILL DOWN
WHILE THE UTILITY WAITED FOR THE REPLACEMENT EXPANSION JOINT. WORK AAS DUNE DURING THE MONTH
TO IMPROVE THE INSTRUMENTATION. IT HAS DISCOVERED THAT MANY OF THE PROBLEMS rtEHE DUE Tu
SCALE ACCUMULATION ON THE PROBES.
AUG. 78 744 439 0 439 305 744 1049 01,622
AVAILABILITY = 30X
OPERABILITY = 30X
RELIABILITY 30X
UTILIZATION = 30X
THE B-MODULE REMAINED DOWN THROUGHOUT AUGUST BECAUSE THE REPLACEMENT EXPANSION JOINT HAD rj()T
YET ARRIVED. EXPANSION JOINT REPAIR WAS REUUIREO ON THE A-MODULE. PROBLEMS nlTH THE
THICKENER AND PLUGGED LINES CAUSED A-MODULE OUTAGES TOTALING 211 HOURS.
ULED OUTAGES.
THERE
NO SCHED-
SEP. 78 557 159 0 159 348 720 1118 68,569
AVAILABILITY - 11X
OPERABILITY = 14X
RELIABILITY = 14X
UTILIZATION = 11X
CONTINUATION OF THE EXPANSION JOINT PROBLEM RESULTED IN THE B-MODULE REMAINING DU*N THROUGH-
OUT THE MONTH. A-MODULE DOWN TIME WAS DUE TO PLUGGING OF THE THICKENER SLURRY MAKEUP LINES
AND FAILURE OF THE BALLS WITHIN THE MODULE.
RUBBER BALLS.
THE PING PONG BALLS HERE REPLACED «ITH SOLID
OCT. 78 26 0 00 0 00
THE BOILER WAS DOWN FOR A SCHEDULED OUTAGE DURING THE MONTH. CONSIDERABLE CLEANING
OF THE A-MODULE WAS DONE AS THE LOWER THO LEVELS OF THE MODULE HAD BEGUN TO PLUG WHEN THE
BALLS FAILED (SEE SEPTEMBER 1978). A THOROUGH CLEANING OF THE ENTIRE FGD SYSTEM «AS ALSO
DONE. A BEARING WAS REPLACED ON THE SLURRY DRAW OFF PUMP. THE OUTLET DUCT WAS CLEANED AND
PLASITE INSTALLED. REPAIR WAS MADE TO THE BYPASS DUCT TOGGLE DUE TU METAL DETERIORATION.
ALL DAMPERS WERE SERVICED, REPAIRED AND EXERCISED. THE RUBBER COATING ON HOLD TANK AGITATORS
AND SLURRY STORAGE TANK AGITATOR WERE REPAIRED.
161
624
32
273
605
72,697
NOV. 78 716 463
AVAILABILITY = 51%
OPERABILITY = 44X
RELIABILITY e 44X
UTILIZATION = 43X
THE BOILER OUTAGE LASTED INTO THE FIRST PART OF NOVEMBER. AN FGD OUTAGE WAS CAUSED BY A FAN
BEARING FAILURE ON MODULE B.
75
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EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL F60 SYSTEMS
UTILITY NAME TENNESSEE VALLEY AUTHORITY
UNIT NAME SHANNEE IDA
UNIT LOCATION PADUCAH KENTUCKY
UNIT RATING 10 MM
FUEL CHARACTERISTICS COAL; 2.9X SULFUR, 15.8X ASH
F60 VENDOR AIR CORRECTION DIVISION, UOP
PROCESS LIME/LIMESTONE
NEW OR RETROFIT RETROFIT
START UP DATE 4/72
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) EXPERIMENTALLY CONTROLLED
502 (ACTUAL)
(DESIGN) EXPERIMENTALLY CONTROLLED
HATER MAKE UP EXPERIMENTALLY CONTROLLED
SLUDGE DISPOSAL EXPERIMENTALLY CONTROLLED
OPERATING EXPERIENCE UPDATE:
REFER TO OPERATING EXPERIENCE UPDATE FOR SHAWNEE NO. 10B.
76
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EPA UTILITY FGD SURVEY: OCTOBE* 1978 - NOVEMBER 197B
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
TENNESSEE VALLEY AUTHORITY
SHAWNEE 10B
PADUCAH KENTUCKY
10 MW
FUEL CHARACTERISTICS COAL; 2.9X SULFUR, 15.8X ASH
F6D VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY!
PARTICULATES (ACTUAL)
(DESIGN)
302 (ACTUAL)
(DESIGN)
WATER MAKE UP
SLUDGE DISPOSAL
CHEMICO
LIME/LIMESTONE
RETROFIT
4/72
EXPERIMENTALLY CONTROLLED
EXPERIMENTALLY CONTROLLED
EXPERIMENTALLY CONTROLLED
EXPERIMENTALLY CONTROLLED
OPERATING EXPERIENCE UPDATE:
FEB. 78 MAJOR SYSTEM DOWNTIMES DURING THE PERIOD INCLUDED: JANUARY 26 THROUGH FEBRUARY a FUR THE
MAR. 78 VENTURI/SPRAY TOWER AND JANUARY 26 THROUGH FEBRUARY 2 FOR THE TCA SYSTEM DUE TO FREEZING
WEATHER, AND MARCH 6 THROUGH MARCH 17 FOR BOTH SYSTEMS DUE TO BOILER OUTAGE.
THE EFFECT OF THE SLURRY LEVEL IN THE AIR SPARGED OXIDATION TANK WAS INVESTIGATED IN THE
TWO SCRUBBER LOOP VENTURI/SPRAY TOWER SYSTEM WHICH IS OPERATING ON LIME SLURRY WITH HIGH
FLY ASH LOADING. NEAR COMPLETE SULFITE OXIDATION (98 PERCENT) WAS ACHIEVED WITH 1
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
TENNESSEE VALLEY AUTHORITY
SHAHNEE 10A AND 10B
TOWER. MGO HAS ADDED TO THE EFFLUENT HOLD TANK TO MAINTAIN AN EFFECTIVE MG + + ION CONCEN-
TRATION OF 5000 PPM. A SLURRY STREAM WAS TAKEN FROM THE SCRUBBER DOWNCOMEK ANO SENT TO
AN OXIDATION TANK INTO WHICH AIK WAS SPAKGED. A RECYCLE STREAM OF ABOUT so GPM HAS SENT
BACK FROM THE OXIDATION TANK TO THE EFFLUENT HOLD TANK TO CONTROL PH IN THE OXIDATION TANK
ANO TO PROVIDE GYPSUM SEEDS IN THE SCRUBBER SLURRY. FINAL SYSTEM BLEEU WAS WITHDRAWN FKUM
THE OXIDATION TANK. AT AN AVERAGE OXIDATION TANK PH OF 6, SULFITE OXIDATION AVERAGED 98
PERCENT. FILTER CAKE SOLIDS CONTENT WAS as PERCENT, SIMILAR TO THAT OBTAINED WITH TWO
SCRUBBER LOOP OPERATIONS. HOWEVERi THE SLURRY SOLIDS SETTLING RATE HAS ONLY ABOUT
0.4 CM/MIN, COMPARED TO ABOUT 0.8 CM/MIN FOR THE TWO LOOP OPERATION. SETTLING HATE FOR
UNOXIOIZED SLURRY CONTAINING MAGNESIUM ION NORMALLY DID NOT EXCEED 0.1 CM/MIN WITH 50 TO
60 PERCENT FILTER CAKE SOLIDS.
TCA CONTINUED TO OPERATE WITH MGO ADDITION WITH BOTH LIME AND LIMEST.ONE SCRUBBING. FLUE
GAS WITH HIGH FLY ASH LOADING WAS USED. THE INTENT OF THESE TESTS WAS TO CLARIFY SOME OF
THE INCONSISTENT RESULTS OBTAINED DURING EARLIER RUNS MADE IN APRIL-NOVEMBER 1976, DURING
WHICH SCRUBBER DOWNCOMER AIR LEAKAGE HAS SUSPECTED IN SOME OF THE TESTS. IN GENERAL,
TESTS RUNS MADE IN 1976 HAD HIGHER INLET S03 CONCENTRATION, MOSTLY GREATER THAN 3000 PPM,
WHILE THE RECENT RUNS HAD ONLY ABOUT 3500 PPM. AT THE HIGHER INLET 803 AND THE HIGHER
RESULTANT SOa MAKE-PER-PASS, THE 1976 TESTS OPERATED EITHER UNSATURATED UR SUPERSATURATED
WITH RESPECT TO GYPSUM, DEPENDING UN THE SULFITE OXIDATION LEVEL. SEVERE GYPSUM SCALING
OCCURRED WHEN THE OPERATION WAS UNDER GYPSUM-SATURATED MODE. IN THE RECENT RUNS, OPERA-
TION WAS MOSTLY UNDER GYPSUM-SATURATED MODE. HOWEVER, BECAUSE OF THE LOHEK INLET SOS AND
LOWER 803 MAKE-PER-PASi, THE GYPSUM SATURATION LEVELS WERE NOT HIGH ENOUGH TU CAUSE ANY
SIGNIFICAN1 SCALING.
JUNE 78 FORCED OXIDATION ON THE BLEED STREAM FROM THE VENTURI/SPRAY TOWER SYSTEM CONTINUED THROUGH
JULY 78 MID-JUNE. TWO TEST RUNS WERE MADE IN WHICH MGO WAS ADDED TO MAINTAIN AN EFFECTIVE MG++
CONCENTRATION OF 5000 PPM IN THE SCRUBBER SLURRY ANO NO RECYCLE STREAM WAS SENT BACK FROM
THE OXIDATION TANK (8 FT DIAMETER AND 18 FT TANK LEVEL) TO THE EFFLUENT HOLD TANK. AVER-
AGE SULFITE OXIDATION HAS 96 PERCENT OR HIGHER AT AN AIR STOICHIOMETKIC RATIO OF l.h
ATOMS OXYGEN/MOLE SO? ABSORBED. THE OXIDATION TANK PH WAS 5.4 TU 5.6, ONLY O.a UNIT
HIGHER THAN THE EFFLUENT HOLD TANK PH. THE FILTER CAKE SOLIDS WAS 85 PERCENT AND THE
THE SOLIDS SETTLING RATE WAS 0.4 TO 0.5 CM/MIN.
BOTH SCRUBBER SYSTEMS WERE SHUT DOWN FOR TWO WEEKS FROM JUNE 19 DUE TO A BOILER OUTAGE
SCHEDULED FOR RE-ROUTING THE FLUE GAS DUCT FROM THE 800-FT STACK TO THE NO. 11 SMALL
STACK.
FOLLOWING THE BOILER OUTAGE, BOTH SCRUBBER SYSTEMS STARTED ON NEW LIME AND LIMESTONE TEST
BLOCKS IN WHICH AOIPIC ACID, AN ORGANIC ACID PH BUFFER, WAS ADDED TO THE SCRUBBER SLURRY
TO IMPROVE 803 REMOVAL EFFICIENCY.
INITIAL TEST RUNS WERE CONDUCTED WITHOUT ADIPIC ACID ADDITION TO ESTABLISH THE BASE CASE
soa REMOVAL IN BOTH LIME AND LINESTONE SCRUBBING FOR BOTH SCRUBBER SYSTEMS. THE VENTUHI/
SPRAY TOWER SYSTEM WAS OPERATED WITH TWO-SCRUBBER-LOOP CONFIGURATION WITH FORCED OXIDATION
IN THE FIRST LOOPf WHILE THE TCA WAS OPERATED IN A ONE-SCRUBBER-LOOP SCHEME WITHOUT FORCED
OXIDATION.
PRELIMINARY RESULTS SHOWED THAT 96 TO 99 PERCENT S02 REMOVAL WAS CONSISTENTLY ACHIEVED IN
THE VENTURI/SPRAY TOWER SYSTEM OPERATING WITH ABOUT 1600 PPM AND 1400 PPM ADIPIC ACID IN
THE VENTURI AND SPRAY TOWER, RESPECTIVELY. THESE S02 REMOVALS COMPARE VERY FAVORABLY WITH
THE 66 PERCENT REMOVAL FOR THE BASE CASE LIME RUN WITHOUT ADIPIC ACID. ON THE TCA SYSTEM,
A LIME RUN WITH ABOUT 400 PPM ADIPIC ACID GAVE ABOUT 80 PERCENT S03 REMOVAL, COMPARED TO
67 PERCENT FOR THE BASE CASE RUN.
AUG. 78 TESTING WITH ADIPIC ACID AS ADDITIVE FOR IMPROVING 502 REMOVAL EFFICIENCY CONTINUED
SEP. 78 THROUGH AUGUST AND SEPTEMBER. BOTH VENTURI/SPRAY TOWER AND TCA SYSTEMS WERE OPERATED ON
LIMESTONE SLURRY WITH HIGH FLYASH LOADING DURING THIS PERIOD. THE TCA WAS OPERATED
WITHOUT FORCED OXIDATION AND THE VENTURI/SPRAY TOWER WITH THO-SCRUBBER-LOOP FORCED OXIDA-
TION. AS IN THE LIME TESTS WITH ADIPIC ACID ADDITION CONDUCTED IN JULY, SIGNIFICANT
IMPROVEMENT IN S02 REMOVAL EFFICIENCY WAS ALSO OBSERVED IN THE LIMESTONE TESTS.
UNDER TYPICAL OPERATION, S03 REMOVAL HIGHER THAN 90 PERCENT COULD BE ACHIEVED BY THE
VENTURI/SPRAY TOWER WITH ABOUT 3100 PPM AND 1500 PPM ADIPIC ACID IN THE VENTURI ANO SPRAY
TOWER, RESPECTIVELY. UNDER THE SAME OPERATING CONDITIONS BUT WITHOUT ADIPIC ACID, THE SOS
REMOVAL WAS ONLY 57 PERCENT. THE SULFITE OXIDATION EFFICIENCY AND WASTE SLUDGE DEWATERING
PROPERTIES DID NOT APPEAR TO BE AFFECTED BY THE PRESENCE OF ADIPIC ACID.
IN THE TCA, HIGHER THAN 90 PERCENT 303 REMOVALS WERE OBTAINED WITH 750 TO 1500 PPM ADIPIC
ACID, COMPARED TO 71 PERCENT REMOVAL FOR A BASE CASE RUN WITHOUT ADIPIC ACID.
IN BOTH SCRUBBER SYSTEMS, THE PH IN THE SCRUBBER SLURRY NEEDS TO BE HIGHER THAN ABOUT 5.0,
THE UPPER PH BUFFER POINT OF ADIPIC ACID, FOR THIS PARTICULAR ADDITIVE TO BE FULLY
EFFECTIVE.
DETERIORATION OR DECOMPOSITION OF ADIPIC ACID APPARENTLY TAKES PLACE IN THE SCRUBBER.
ACTUAL FEED RATES OF ADIPIC ACID WERE Z TO 3 TIMES HIGHER THAN COULD BE ACCOUNTED FOR IN
THE SYSTEM DISCHARGE SLUDGE.
78
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
TENNESSEE VALLEY AUTTHORITY SHANMEE IDA AND 108
OCT. 76 A ONE MONTH LONG-TERM RELIABILITY RUN WAS CONDUCTED ON BOTH THE VENTURI/SPRAY FUrtEK AND
NOV. 78 THE TCA SYSTEMS USING LIMESTONE SLURRY WITH AOIPIC ACIO AS AN ADDITIVE FOR ENHANCING SU«2
REMOVAL EFFICIENCY. STEADY-STATE 302 REMOVAL IN BOTH RUNS WAS CONSISTNTLY HIGH IN THE
RANGE OF 96 TO 99 PERCENT UNDER TYPICAL OPERATING CONDITIONS. THE VENTURI/SPRAY TOWER
SYSTEM MAS OPERATED WITH TWO-SCRUBBER-LOOP FORCED OXIDATION. AOIPIC ACID CONCENTRATIONS
WERE 1500 PPM IN THE TCA AND THE SPRAY TOWER. AND 2400 PPM IN THE VENTUHI. BOTH SCRUBBER
SYSTEMS OPERATED FREE OF SCALING AND PLUGGING.
LONG-TERM TESTS BEGAN IN MID-NOVEMBER TO COMPARE CONVENTIONAL LIME SCRUBBING WITH ADVANCED
LIMESTONE SCRUBBING USING CHEMICAL ADDITIVES AND FORCED OXIDATION. EACH TEST WILL LAST
ONE MONTH OR LONGER. THE VENTURI/SPRAY TOWER IS BEING OPERATED WITH TwO-SCRUBBER-LOUP
FORCED OXIDATION AND WITH LIMESTONE SLURRY AND ADIPIC ACID ADDITION. THE TCA SYSTEM IS
BEING OPERATED WITH LIME SLURRY (NO ADDITIVE) AND WITHOUT FORCED OX1DAUON. DUKING THESE
TESTS CONTINUOUS SOS EMISSIONS MONITORING PROCEDURES WILL BE ASSESSED.
79
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME
UNIT NAME
UNIT LOCATION
UNIT RATING
TENNESSEE VALLEY AUTHORITY
WIDOWS CREEK 8
BRIDGEPORT ALABAMA
550 MW
FUEL CHARACTERISTICS COAL; 3.7X SULFUR, 17X ASH
FGD VENDOR
PROCESS
NEW OR RETROFIT
START UP DATE
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN)
802 (ACTUAL)
(DESIGN)
HATER MAKE UP
SLUDGE DISPOSAL
TENNESSEE VALLEY AUTHORITY
LIMESTONE
RETROFIT
5/77
99.5* PERCENT
99.5 PERCENT
85-94 PERCENT
80.0 PERCENT
STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
MONTH BOILER A-SIDE
OPERATING HOUHS
B-SIDE C-SIDE D-SIDE
COMMENTS
401
370
314
THE OUTAGE TIME FOR 1RAINS A AND B WAS KEUUIR-
ED TO REPLACE THE RUBBER LINEkS IN THE UUrtN-
COMER AREA WITH STAINLESS STtEL. THIS WILL BE
DONE TO THE REMAINING TWU TRAINS AS WELL.
FEB. 78 586 171
AVAILABILITY « 55X
OPERABILITY = 54Z
RELIABILITY = 61X *
UTILIZATION = 47X
* THE UTILITY REPORTED THAT THEY COULD NOT ACCURATELY DETERMINE RELIABILITY BECAUSE OF THEIR
INABILITY TO CALCULATE UNIT LOAD DEMAND ON A DAILY BASIS. GENERALLY, IT IS ASSUMMEO THAT SYSTEM
FORCED OUTAGE HOURS PLUS THE HOURS FGD SYSTEM OPERATED WILL GIVE ROUGHLY THE HUURS THE SYSTEM WAS
CALLED UPON TO OPERATE. IN THIS WAY, RELIABILITY CAN BE CALCULATED INDIRECTLY. HOWEVER, IN THIS
CASE, TNO TRAINS AT A TIME HAVE BEEN DOWN ON A SCHEDULED OUTAGE FOR NECESSARY MODIFICATIONS. PART
OF THIS OUTAGE TIME LIMITED BUILER OPERATION SO THAT THE UNIT COULD NOT RUN AT FULL LOAD WHEN THERE
HAS A DEMAND FOR FULL LOAD. FOR THIS CALCULATION IT WAS ASSUMMED THAT THERE WAS A DEMAND FOR FULL
LOAD DURING THE ENTIRE SCHEDULED OUTAGE SO THAT ALL OF THE TRAINS WOULD HAVE BEEN CALLED THE ENTIRE
SCHEDULED OUTAGE. THE RESULT WAS A VERY CONSERVATIVE ESTIMATE OF RELIABILITY WHERE HOURS CALLED
• SYSTEM FORCED OUTAGE HOURS » SYSTEM SCHEDULED OUTAGE + HOURS THE FGD SYSTEM OPERATED.
NOTEI THIS IS A PEDCO ESTIMATE.
MAR. 76 644 585
AVAILABILITY a 60X
OPERABILITY * 66X
RELIABILITY s 59X *
UTILIZATION * 58X
344 199 583 TRAIN B WAS OUT OF SERVICE MARCH 1 - MARCH 13
TO INSTALL STAINLESS STEEL IN THE ABSORBER AND
VENTURI OOWNCOMER AREAS. STAINLESS STEEL
COVERS WERE INSTALLED ARUUND 1*0 EXPANSION
JOINTS ON TRAIN C, IN ORDER TO PREVENT FLUE
GAS LEAKAGE FROM THE EXPANSION JOINTS. A
STAINLESS STEEL PLATE WAS WELDED OVEK THE
ENTRY DOOR OPENINGS TO TRAIN C OUTLET AND
BYPASS GUILLOTINE DAMPERS FOK THE PURPOSE
OF ELIMINATING GAS LLAKAGE. TRAIN c WAS OUT
OF SERVICE MARCH 14 - MAKCH 39 TU INSTALL
STAINLESS STEEL IN THE ABSORBER AND VENTUHI
DOWNCUMER AREAS. SEVERAL LIFTER BARS ON THE
FEED AND DISCHARGE ENDS OF THE HALL MILL WEHE
FOUND TO BE BADLY wOKN. THE UTILITY HAS HAD
WEAR PROBLEMS WITH THE SLURRY SUMP PUMP
LINERS AT THE BALL MILL.
80
-------
EPA UTILITY FGD SURVEY: OCTUbEk 1978 - NUVt^BKK
TENNESSEE VALLEY AUTHORITY wlOOwS CREEK a
MONTH BOILER A-SIOE B-SIDE C-SIOE 0-SIDE COMMENTS
APR. 78 540 480 464 576 375 DURING A BRIEF INSPECTION UF THE SCKUKBEK IN
AVAILABILITY = 691 EARLY APRIL, SOLIDS DEPOSITION hAS NOTICED IN
OPERABILITY a 83X THE MIST ELIMINATOR SECTION OF ALL TWAINS HE-
RELIABILITY 3 67X * CAUSE OF PLUGGING THAT HAD OCCUKHEU IN SEVERAL
UTILAZATION a 62X OF THE MIST ELIMINATOR SPRAY NOZZLES. TKAIU 0
rtAS NOT IN OPERATION FOR 17 DAYS. DURING THIS
PERIOD THE MIST ELIMINATOR HAS D ISSASShMBLED
BY SECTIONS AND CLEANED. A STAINLESS STEEL
LINER HAS INSTALLED ON THE SLOPING AREAS OF
THE ABSORBER AND VENTURI. STAlULKSS STEEL
PLATES WERE INSTALLED OVER THE ENTRY DOOR
OPENINGS TO TRAIN D INLET, OUTLET, AND BYPASS
GUILLOTINE DAMPERS TO REDUCE GAS LEAKAGE FROM
THE ENTRY DOOR OPENINGS. STAINLESS STEEL
COVERS WERE INSTALLED AROUND THE FIVE EXPAN-
SION JOINTS ON TRAIN D, TwU tXPANSION JUINTS
ON TRAIN A, AND ONE EXPANSION JOINT ON TKA1N
8, TO REDUCE GAS LEAKAGE TO 1HE ATMUSPHEKE.
THERE CONTINUES TO BE A WEAR PROBLEM «ITH PUMP
LINERS AT THE BALL MILL. NO CAOSE OR SOLUTION
OF THE PROBLEM HAS BEEN ASCERTAINED AS YET.
81
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME TEXAS UTILITIES
UNIT NAME MARTIN LAKE 1
UNIT LOCATION TATUM TEXAS
UNIT RATING 793 MW
FUEL CHARACTERISTICS COAL; 0.9X SULFUR, 8Z ASH
FGD VENDOR RESEARCH COTTRELL
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 8/77
EFFICIENCY:
PARTICULATES (ACTUAL) 99* PERCENT
(DESIGN) 99.a PERCENT
302 (ACTUAL) 73.9 PERCENT
(DESIGN) 70.5 PERCENT
WATER MAKE UP
SLUDGE DISPOSAL BLENDED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
FEBRUARY-MARCH 1978 - CERTIFICATION WAS RECEIVED FROM THE EPA FOR THIS UNIT. THE BOILEH AND
FGD SYSTEM OPERATED THROUGHOUT THE PERIOD. THE UTILITY IS STILL HAVING SOME PROBLEMS
WITH THE SLURRY HANDLING SYSTEM, AND SOME FORCED OUTAGE TIME OCCURRED.
APRIL-MAY 1978 - THIS UNIT WAS TAKEN OFF LINE IN APRIL FOR AN ANNUAL TWO WEEK OUTAGE. GENERATOR
PROBLEMS WERE ENCOUNTERED IN MAY CAUSING THE UNIT TO BE TAKEN OFF LINE THROUGH THE END OF THE MONTH.
JUNE-JULY 1978 - THE SYSTEM IS NOW RUNNING COMMERCIALLY. THE UTILITY HAS ENCOUNTERED SOME PROBLEMS
SINCE INITIAL OPERATION. THE DAMPERS FOR EACH ABSORBER MODULE WERE NOT FUNCTIONING PROPERLY. IT
HAS BEEN IMPOSSIBLE TO ISOLATE INDIVIDUAL MODULES FOR REPAIRS (THE ENTIRE SYSTEM WOULD HAVE TO BE
SHUTDOWN IF REPAIRS WERE REQUIRED ON ONLY ONE MODULE). THERE HAS ALSO BEEN A PROBLEM WITH THE PH
METERS. THE METERS HAVE NOT OPERATED PROPERLY FOR SOME TIME NOW.
AUGUST-SEPTEMBER 1978 - ISOLATION DAMPER PROBLEMS ARE CONTINUING. THE UNIT STILL REQUIRES EXCESSIVE
MAINTENANCE. FLOW MEASUREMENT INSTRUMENTATION HAS BEEN FAILING. OPACITY HAS BEEN HIGHER THAN EX-
PECTED (20-25X) RESULTING FROM ESP PROBLEMS. FGD SYSTEM ACCEPTANCE TESTS WERE PERFORMED BY THE
UTILITY DURING AUGUST. RESULTS ARE NOT YET AVAILABLE.
-------
EPA UTILITY FGO SURVEY: OCTOUE* 1978 - NOVEMBER 197B
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME TEXAS UTILITIES
UNIT NAME MARTIN LAKE 2
UNIT LOCATION TATUM TEXAS
UNIT RATING 793 MW
FUEL CHARACTERISTICS COAL? 0.9X SULFUR, 8X ASH
FGO VENDOR RESEARCH COTTRELL
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 5/78
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 99.fl PERCENT
SOZ (ACTUAL)
(DESIGN) 70.5 PERCENT (TOTAL)
MATER MAKE UP
SLUDGE DISPOSAL STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
JUNE-JULY 1976 - THE FGD SYSTEM WAS TESTED FOR COMPLIANCE WITH ALL 6 MODULES IN THE GAS STREAM
DURING THE FIRST PART OF AUGUST. RESULTS ARE NOT YET AVAIABLE.
AUGUST-SEPTEMBER J978 - COMPLIANCE TEST RESULTS HAVE STILL NOT BEEN PUBLISHED. MO KAJUR FGD-RELATE.D
PROBLEMS WERE REPORTED.
83
-------
EP* UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGO SYSTEMS
UTILITY NAME TEXAS UTILITIES
UNIT NAME MONTICELLO 3
UNIT LOCATION MT. PLEASANT TEXAS
UNIT RATING 750 MW
FUEL CHARACTERISTICS LIGNITE; 1.5X SULFUR, 19X ASM
FGD VENDOR CHEMICO
PROCESS LIMESTONE
NEW OR RETROFIT NEW
START UP DATE 5/78
EFFICIENCY:
PARTICULATES (ACTUAL)
(DESIGN) 99.5 PERCENT
303 (ACTUAL)
(DESIGN) 74.0 PERCENT
WATER MAKE UP CLOSED LOOP
SLUDGE DISPOSAL STABILIZED/SLUDGE POND
OPERATING EXPERIENCE UPDATE:
APR. 78 THE TEXAS AIR CONTROL BOARD REPORTED THAT THE TEXAS UTILITIES 750 Mw MUNUCfcLLO UNIT 3
MAY 78 BEGAN FGD OPERATIONS DURING THE REPORT PERIOD. AS OF YET THE UNIT HAS NOT RUN AT FULL LOAD
BUT IS EXPECTED TO BY THE END OF AUGUST.
JUNE 78 THE UNIT IS NOT AT FULL LOAD YET. ONE OF THE THREE FGD MODULES IS FULLY OPERATIONAL.
JULV 78 ANOTHER ONE IS PARTIALLY OPERATIONAL, WHILE THE THIRD IS NUT OPERATING AT ALL AS YET.
AUG. 78 THE COMPLIANCE TEST HAS NOT YET TAKEN PLACE. THE FGD SYSTEM IS OPERATIONAL. INSTRUMENTA-
SEP. 78 TION INDICATES THAT THE UNIT is IN COMPLIANCE.
-------
EPA UTILITY FGD SURVEY: UCTObEK 1978 - NOVEMBEK 1978
SECTION 3
PERFORMANCE DESCRIPTION FOR OPERATIONAL FGD SYSTEMS
UTILITY NAME UTAH POWER & LIGHT
UNIT NAME HUNTINGTON 1
UNIT LOCATION PRICE UTAH
UNIT RATING 415 MW
FUEL CHARACTERISTICS COAL; 0.5X SULFUR, 10X ASH
F6D VENDOR CHEHICO
PROCESS LIME
NEW OR RETROFIT NEW
START UP DATE 5/78
EFFICIENCYJ
PARTICULATE3 (ACTUAL)
(DESIGN) 99.5 PERCENT
SOZ (ACTUAL)
(DESIGN) aO.O PERCENT
MATER MAKE UP CLOSED LOOP .72 GPM/MW
SLUDGE DISPOSAL STABILIZED/LANDFILL
OPERATING EXPERIENCE UPDATE:
APRIL-MAY 1978 - INITIAL OPERATIONS BEGAN AT THIS UNIT ON HAY 10, 1978. DUE TO THE RECENT OPERATING
STATUS OF THE SYSTEM HOURS OF OPERATION HERE NOT AVAILABLE FOR THE APRIL-MAY REPURT PEKIOD.
PERIOD BOILER FGD SYSTEM PARAMETERS
MONTH HOURS HOURS HOURS OPERABILITY UTILIZATION
JUNE 70 720 730 470 65X 65X
JULY 78 744 731 714 98X 96X
NO MAJOR PROBLEMS WERE REPORTED BY THE UTILITY FOR THIS PERIOD. 10-201 OF THE FLUfc GAS WAS
BYPASSED THROUGH THE USE OF AN ADJUSTABLE DAMPER.
AUK. 78 744 544 544 100X 73X
SEP. 78 720 496 496 100X 69X
THERE WERE NO FORCED FGD OUTAGES DURING THE AUGUST-SEPTEMBER PERIOD. MINOH PROBLEMS »EKE EX-
PERIENCED WITH INSTRUMENTATION. A THREE WEEK BOILER OUTAGE OCCURRED AS A RESULT OF AN
EXPLOSION.
85
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 4
SUMMARY OF FGD SYSTEMS BY COMPANY
UTILITY
ALABAMA ELECTRIC COOP
ALLEGHENY POHER SYSTEM
ARIZONA ELECTRIC POWER COOP
ARIZONA PUBLIC SERVICE
ASSOCIATED ELECTRIC COOP
BASIN ELECTRIC POHER COOP
BIG RIVERS ELECTRIC
CENTRAL ILLINOIS LIGHT
CENTRAL ILLINOIS PUBLIC SERV
CENTRAL MAINE POWER
CINCINNATI GAS « ELECTRIC
COLORADO UTE ELECTRIC ASSN.
COLUMBUS ft SOUTHERN OHIO ELEC.
COMMONWEALTH EDISON
COOPERATIVE POWER ASSOCIATION
DELMARVA POWER ft LIGHT
DUOUESNE LIGHT
EAST KENTUCKY POWER COOP
GENERAL PUBLIC UTILITIES
GULF POWER
HOOSIER ENERGY
INDIANAPOLIS POWER ft LIGHT
KANSAS CITY POHER ft LIGHT
KANSAS POWER ft LIGHT
KENTUCKY UTILITIES
LAKELAND UTILITIES
LOUISVILLE GAS ft ELECTRIC
MINNESOTA POWER ft LIGHT
MINNKOTA POWER COOPERATIVE
MONTANA POHER
NEVADA POHER
NIAGARA MOHAWK POHER COOP
NORTHERN INDIANA PUB SERVICE
NORTHERN STATES POHER
OTTER TAIL POWER
PACIFIC GAS AND ELECTRIC
PACIFIC POHER ft LIGHT
PENNSYLVANIA POHER
PHILADELPHIA ELECTRIC
POTOMAC ELECTRIC POWER
PUBLIC SERVICE OF INDIANA
PUBLIC SERVICE OF NEW MEXICO
SALT RIVER PROJECT
SAN MIGUEL ELECTRIC COOP
SEMINOLE ELECTRIC
SIKESTON BOARD OF MUNIC. UTIL.
SOUTH CAROLINA PUBLIC SERVICE
SOUTHERN ILLINOIS POWER COOP
SOUTHERN INDIANA GAS ft ELEC
SOUTHERN MISSISSIPPI ELECTRIC
SOUTHWESTERN ELECTRIC POWER
SPRINGFIELD CITY UTILITIES
SPRINGFIELD WATER LIGHT ft PWR
ST. JOE ZINC
TAMPA ELECTRIC
TENNESSEE VALLEY AUTHORITY
TEXAS MUNICIPAL POHER AGENCY
TEXAS POWER ft LIGHT
TEXAS UTILITIES
UTAH POWER ft LIGHT
WISCONSIN POHER ft LIGHT
TOTAL
NO MW
2
2
2
6
1
b
2
Z
1
1
1
2
4
1
2
1
2
1
2
1
2
2
3
4
1
1
8
1
1
4
10
\
3
4
1
2
1
3
4
1
1
4
3
1
1
1
2
2
1
2
1
1
1
1
1
7
1
3
b
3
1
450.
1250.
400.
2804.
670.
2600.
490.
800.
575.
600.
600.
900.
1550.
425.
1090.
180.
920.
500.
1600.
23.
980.
1060.
1020.
1885.
64.
350.
2283.
500.
450.
2120.
3125.
100.
705.
3140.
400.
1600.
509.
2475.
846.
BOO.
650.
1560.
1050.
400.
600.
235.
560.
484.
250.
360.
720.
200.
190.
60.
425.
3045.
400.
2045.
4672.
1215.
527.
... STATUS — — — — — •
OPERATIONAL CONSTRUCTION CONTRACT
AWARDED
NO MW NO MW NO MW NO
1
0
1
2
0
0
0
1
0
0
0
0
2
0
0
0
2
0
0
1
0
1
3
3
1
0
4
0
1
2
3
0
1
2
0
0
0
2
1
0
0
2
0
0
0
0
1
0
0
1
0
1
0
0
0
3
0
0
3
1
0
225.
0.
200.
365.
0.
0.
0.
400.
0.
0.
0.
0.
800.
0.
0.
0.
920.
0.
0.
23.
0.
530.
1020.
1205.
64.
0.
851.
0.
450.
720.
375.
0.
115.
1420.
0.
0.
0.
1650.
120.
0.
0.
620.
0.
0.
0.
0.
280.
0.
0.
180.
0.
200.
0.
0.
0.
570.
0.
0.
2336.
415.
0.
1
2
1
4
0
2
2
0
1
0
0
2
0
1
2
1
0
0
0
0
2
1
0
1
0
0
3
1
0
0
0
0
0
0
1
0
1
1
0
0
0
0
2
1
0
1
0
1
1
1
0
0
1
1
0
1
0
0
1
2
0
225.
1250.
200.
929.
0.
1140.
490.
0.
575.
0.
0.
900.
0.
425.
1090.
180.
0.
0.
0.
0.
980.
530.
0.
680.
0.
0.
1102.
500.
0.
0.
0.
0.
0.
0.
400.
0.
509.
825.
0.
0.
0.
0.
700.
400.
0.
235.
0.
184.
250.
180.
0.
0.
190.
60.
0.
575.
0.
0.
793.
800.
0.
0
0
0
2
1
2
0
0
0
0
1
0
0
0
0
0
0
1
0
0
0
0
0
0
0
1
1
0
0
2
0
1
0
0
0
0
0
0
0
0
0
2
0
0
0
0
1
0
0
0
1
0
0
0
0
0
1
1
1
0
1
u.
o.
u.
1510.
67U.
1005.
0.
0.
0.
0.
600.
0.
0.
0.
0.
0.
0.
500.
0.
0.
0.
0.
0.
0.
0.
350.
330.
0.
0.
1400.
0.
100.
0.
0.
0.
0.
0.
0.
0.
0.
0.
940.
0.
0.
0.
0.
300.
0.
0.
0.
720.
0.
0.
0.
0.
0.
400.
545.
793.
0.
527.
0
0
0
0
0
1
0
1
0
1
0
0
2
0
0
0
0
u
2
0
0
0
0
0
0
u
0
0
0
0
7
0
2
2
U
2
0
0
3
1
1
0
1
0
1
0
0
1
0
0
0
0
0
0
1
3
0
2
1
0
0
PLANNED
MW
u.
0.
0.
0.
0.
455.
U.
4UU.
0.
600.
0.
0.
750.
0.
0.
0.
0.
0.
16UO.
0.
0.
0.
0.
0.
U.
0.
0.
0.
0.
0.
2750.
0.
590.
1720.
0.
1600.
0.
0.
726.
800.
650.
0.
350.
0.
600.
0.
0.
300.
U.
0.
0.
0.
0.
0.
425.
1900.
0.
1500.
750.
0.
0.
TOTALS
144 62507. 46 16054. 43 17297. 20 10690. 35 18466.
NOTE • PLANNED STATUS INCLUDES LETTER OF INTENT SIGNED,
AND CONSIDERING ONLY FGD SYSTEMS
REQUESTING/EVALUTING BIDS,
66
-------
EPA UTILITY FGO SURVEY: OCTOBEH 1978 - NOVEMBfcK 1978
SECTION 5
SUMMARY OF FGD SYSTEMS BY VENDOR
TOTAL
STATUS
OPERATIONAL CONSTRUCTION CONTRACT
AWARDED
MANUFACTURER/PROCESS
AOL/COMBUSTION EQUIP ASSOCIATE
DOUBLE ALKALI
LIME
LIME/ALKALINE FLYASH
SODIUM CARBONATE
TOTAL -
AIR CORRECTION DIVISION, UOP
LIME (MG-PROMOTED)
LIME/LIMESTONE
LIMESTONE
SODIUM CARBONATE
TOTAL -
AMERICAN AIR FILTER
LIME
LIME (CARBIDE)
TOTAL -
ROCKWELL INTERNATIONAL
AQUEOUS CARBONATE
TOTAL -
BABCOCK S MILCOX
LIME
LIMESTONE
NOT SELECTED
TOTAL •
BUELL/ENVIROTECH
DOUBLE ALKALI
TOTAL -
BUREAU OF MINES
CITRATE
TOTAL -
CHEMICO
LIME
LIME/ALKALINE FLYASH
LIME/LIMESTONE
LIMESTONE
TOTAL -
CHEMICO/APS
LIME/ALKALINE FLYASH
TOTAL -
CHIYOOA INTERNATIONAL
LIMESTONE
TOTAL -
COMBUSTION ENGINEERING
LIME
LIME (CARBIDE)
LIME/LIMESTONE
LIMESTONE
LIMESTONE/ALKALINE FLYASH
TOTAL -
DAVY POWERGAS
MELLMAN LORD
TOTAL •
NO.
1
1
5
3
10
2
i
4
1
8
4
2
6
1
1
3
7
1
11
1
1
1
1
7
1
1
1
10
3
3
1
1
4
2
2
7
2
17
6
6
MW
277.
500.
2570.
375.
3722.
800.
10.
1875.
509.
3194.
1049.
603.
1652.
100.
100.
1850.
2569.
550.
4969.
575.
575.
60.
60.
3785.
527.
10.
750,
5072.
579.
579.
23.
23.
1290.
248.
660.
3405.
1420.
7023.
1855.
1855.
NO.
0
0
3
3
6
2
1
2
0
5
1
2
3
0
0
0
2
0
2
0
0
0
0
5
0
1
1
7
0
0
1
1
2
2
0
3
2
9
3
3
MW
0.
0.
1170.
375.
1545.
800.
10.
730.
0.
1510.
64.
603.
667.
0.
0.
0.
1100.
0.
1100.
0.
0.
0.
0.
2985.
0.
10.
750.
3745.
0.
0.
23.
23.
200.
248.
0.
1205.
1420.
3073.
735.
735.
NO.
1
0
0
0
1
0
0
1
1
2
3
0
3
0
0
2
3
0
5
1
1
1
1
2
0
0
0
2
3
3
0
0
2
0
1
2
0
5
1
1
MW
277.
0.
0.
0.
277.
0.
0.
425.
509.
934.
985.
0.
985.
0.
0.
1250.
819.
0.
2069.
575.
575.
60.
60.
800.
0.
0.
0.
800.
579.
579.
0.
0.
1090.
0.
330.
1255.
0.
2675.
160.
180.
NO.
U
1
2
0
1
(1
0
1
0
1
U
0
0
1
1
1
2
1
4
0
0
0
0
0
1
0
0
1
0
0
0
0
0
0
1
2
0
3
2
2
MM
U.
500.
1400.
U.
1900.
0.
0.
12(1.
U.
720.
0.
U.
0.
100.
100.
600.
650.
550.
1800.
0.
0.
0.
0.
0.
527.
0.
0.
527.
0.
0.
0.
0.
0.
0.
330.
945.
0.
1275.
940.
940.
67
-------
EPA UTILITY F60 SURVEYS OCTOBER 1978 - NOVEMBER 1978
SECTION 5
SUMMARY OF FGD SYSTEMS BY VENDOR
TOTAL
MANUFACTURER/PROCESS
FMC CORPORATION
DOUBLE ALKALI
TOTAL -
MITSUBISHI INTERNATIONAL
LIMESTONE
TOTAL -
PEABODY PROCESS SYSTEMS
LIME/ALKALINE FLYASH
LIMESTONE
TOTAL -
PULLMAN KELLOGG
LIME
LIMESTONE
TOTAL -
RESEARCH COTTRELL
LIMESTONE
TOTAL -
RILEY STOKER / ENVIRONEERING
LIMESTONE
TOTAL -
TENNESSEE VALLEY AUTHORITY
LIMESTONE
TOTAL -
UNITED ENGINEERS
MAGNESIUM OXIDE
NOT SELECTED
TOTAL -
WESTERN PRECIP./NIRO ATOM.
LIME SPRAY DRYING
TOTAL -
WHBELABRATOR-FRYE/R.I.
NA,CO. SPRAY DRYING
TOTKL -
NO.
1
1
2
2
1
a
5
1
3
a
13
13
3
3
1
1
1
2
3
1
1
1
1
MW
250.
250.
980.
980.
500.
1350.
1850.
825.
1370.
2195.
6117.
6147.
760.
760.
550.
550.
120.
1510.
1630.
455.
455.
400.
400.
OPERATIONAL
NO.
0
0
0
0
0
1
1
0
0
0
5
5
2
2
1
1
1
0
1
0
0
0
0
MW
0.
0.
0.
0.
0.
225.
225.
0.
0.
0.
2151.
2151.
580.
580.
550.
550.
120.
0.
120.
0.
0.
0.
0.
CONSTRUCTION
NO.
1
1
2
2
1
3
4
1
2
3
7
7
1
1
0
0
0
0
0
0
0
1
1
MM
250.
250.
980.
980.
500.
1125.
1625.
825.
700.
1525.
3203.
3203.
180.
180.
0.
0.
0.
0.
0.
0.
0.
400.
400.
CONTRACT
AWAkDEO
NO.
U
0
0
0
0
U
0
U
1
1
1
1
0
0
0
0
0
2
2
1
1
0
0
Mn
0.
u.
0.
U.
0.
U.
U.
U.
670.
670.
793.
793.
0.
0.
0.
U.
0.
1510.
1510.
455.
455.
U.
0.
109 44041.
46 16054.
43 17297.
20 10690.
-------
EPA UTILITY FGD SUHVEY: UCTUHEk 1970 - NOVfcfbtk 197H
SECTION b
SUMMARY OF NEW AND RETROFIT FGO SYSTEMS BY PhUCfcSb
NEW OR OPERATIONAL CONSTRUCTION CONlkACT
PROCESS RETROFIT
LIME
LIME (CARBIDE)
LIME (M6-PROMOTED)
LIME/ALKALINE FLYASH
LIME/LIMESTONE
LIMESTONE
LIMESTONE/ALKALINE FLYASH
SUBTOTAL LIME/LIMESTONE
AQUEOUS CARBONATE
CITRATE
DOUBLE ALKALI
MAGNESIUM OXIDE
NOT SELECTED
PROCESS NOT SELECTED
SODIUM CARBONATE
WELLMAN LORD
LIME SPRAY DRYING
NA,CO, SPRAY DRYING
2 3
THOROUGHBRED 121
TOTALS
LIMB/LIMESTONE Z OF TOTAL MW
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
N
R
NO.
3
5
1
3
2
0
3
0
0
2
10
3
2
0
25.
13.
0
0
0
0
0
0
0
1
0
0
0
0
1
2
1
2
0
0
0
0
0
1
MW
2065
1164
425
426
800
0
1170
0
0
20
6501
790
1420
0
12381.
2420.
0
0
0
0
0
0
0
120
0
0
0
0
125
250
314
421
0
0
0
0
0
23
27.12820.
19.
97
75
3234.
NO
10
0
0
0
0
0
1
3
0
1
19
2
0
0
30.
6.
0
0
0
1
2
1
0
0
0
0
0
0
1
0
0
1
0
0
1
0
0
0
34.
9.
. MM
4950
0
0
0
0
0
500
579
0
330
7687
1000
0
0
13137.
1909.
0
0
0
60
825
277
0
0
0
0
0
0
509
0
0
180
0
0
400
0
0
0
14871.
2426.
88
79
PLANNED
AftAKDEU
NO.
2
0
0
0
0
0
3
0
0
1
7
0
0
0
12.
1.
0
1
0
0
0
0
0
0
1
2
0
0
0
0
2
0
1
0
0
0
0
0
16.
4.
78
17
Mw
1100
U
0
0
0
U
1927
0
U
330
3776
U
U
0
6805.
330.
0
100
0
0
0
0
0
0
550
1510
0
0
0
0
940
0
455
0
0
0
0
0
8750.
1940.
NO
0
0
0
U
(1
0
0
0
0
0
6
2
2
U
8.
2.
0
0
0
0
0
0
0
4
18
2
1
0
0
0
0
0
0
0
0
0
0
0
27.
8.
. Mn
U
0
0
0
0
0
0
U
0
0
4050
1.500
1720
0
5770.
1300.
0
0
0
0
0
0
0
1326
9055
590
425
0
0
0
0
0
0
0
0
0
0
0
15250.
3216.
38
40
TU1AL NO.
UF
NU
15
5
1
3
2
0
7
i
0
<4
46
7
a
0
75.
22.
0
1
0
1
2
1
0
5
19
4
1
0
2
2
3
3
1
0
1
0
0
1
104.
40.
PLANTS
Mi'.
8115
1 1«4
42b
42b
BOO
0
3b<*/
57S
0
680
2201b
3090
3140
0
38093.
5959.
0
100
0
60
825
277
0
1446
9605
2100
425
0
634
250
1254
601
455
0
400
0
0
23
51691.
10816.
74
55
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 7
SUMMARY OF OPERATING FGD SYSTEMS BY
PROCESS AND GENERATING UNITS
PROCESS/GENERATING UNITS
FGD/MH STARTUP EXPERIENCE(MO.)
LIME
BRUCE MANSFIELD 1
BRUCE MANSFIELD 2
ELRAMA POWER STATION
GREEN RIVER 1,2 * 3
HAWTHORN 3
HAWTHORN a
HUNTINGTON 1
PHILLIPS POWER STATION
LIME (CARBIDE)
CANE RUN 4
CANE RUN 5
MILL CREEK 3
PADDYS RUN 6
LIME (MG-PROMOTED)
CONESVILLE
CONESVILLE
LIME/ALKALINE FLYASH
COLSTRIP 1
COLSTRIP 2
MILTON R. YOUNG
LIME/LIMESTONE
SHAWNEE 10A
SHAWNEE 10B
LIMESTONE
APACHE 2
CHOLLA 1
CHOLLA 2
DUCK CREEK 1
JEFFREY 1
LA CY6NE 1
LAWRENCE 4
LAWRENCE 5
MARTIN LAKE 1
MARTIN LAKE 2
MONTICELLO 3
PETERSBURG 3
R. D. MORROW 1
SOUTHWEST 1
TOMBIGBEE 2
WIDOWS CREEK 8
WINYAH 2
LIMESTONE/ALKALINE FLYASH
SHERBURNE 1
825
625
510
64
100
100
415
410
3249.
178
183
425
65
851.
400
400
800.
360
360
450
1170.
10
10
20.
200
115
250
400
680
820
125
400
793
793
750
530
180
200
225
550
280
4-76
7-77
10-75
9-75
11-72
8-72
5-78
7-73
8-76
12-77
8-78
4-73
1-77
6-78
11-75
8-76
9-77
4-72
4-72
8-78
10-73
6-78
7-78
6-78
2-73
12-68
11-71
8-77
5-78
5-78
10-77
8-78
4-77
9-78
5-77
7-77
7291
710
3-76
33
18
39
40
74
77
8
66
355
29
13
5
69
116
24
7
31
38
29
16
83
61
61
162
5
63
7
6
5
71
121
86
17
8
8
15
5
21
4
20
18
480
34
90
-------
EPA UTILITY F60 SURVEY: OCTOBER 1978 - NOVEMBER 197?
SECTION 7
SUMMARY OF OPERATING FGD SYSTEMS BY
PROCESS AND GENERATING UNITS
PROCESS/GENERATING UNITS FGD/MM STARTUP EXPERIENCE(MO.)
SHERBURNE 2 710 4-77 21
1420. 55
MAGNESIUM OXIDE
EDDYSTONE 1A 120 9-75 40
120. 40
SODIUM CARBONATE
REID GARDNER 1 125 4-74 57
REID GARDNER 2 125 4-74 57
REID GARDNER 3 125 7-76 30
375. 144
WELLMAN LORD
DEAN H. MITCHELL 11 115 11-76 26
SAN JUAN 1 314 4-78 9
SAN JUAN 2 306 8-78 6
735. 41
THOROUGHBRED 121
SCHOLZ 1 & 2
23
23.
8-78
_5
5.
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 8
SUMMARY OF SLUDGE DISPOSAL PRACTICES FOK OPERATIONAL FGD SYSTEMS
PROCESS/GENERATING UNIT
— SLUDGE--
STABILIZED
--SLUDGE —
UNSTABILIZED
--- POND—-
LINED
PUND- —
UNLINED
LIME
BRUCE MANSFIELD 1
BRUCE MANSFIELD 2
ELRAMA POWER STATION
GREEN RIVER 1,2 S3
HAWTHORN 3
HAWTHORN 4
HUNTINGTON 1
PHILLIPS POWER STATION
TOTAL
LIME (CARBIDE)
CANE RUN 4
CANE RUN 5
MILL CREEK 3
PADDYS RUN 6
TOTAL
LIME CMC-PROMOTED)
CONESVILLE 5
CONESVILLE 6
TOTAL
LIME/ALKALINE FLYASH
COLSTRIP 1
COLSTRIP 2
MILTON R. YOUNG 2
TOTAL
LIMESTONE
APACHE 2
CHOLLA 1
CHOLLA 2
PUCK. CREEK 1
JEFFREY 1
LA CYGNE 1
LAWRENCE 4
LAWRENCE 5
MARTIN LAKE 1
MONTICELLO 3
PETERSBURG 3
R. 0. MORROW 1
TOMBIGBEE 2
WIDOWS CREEK 8
WINYAH 2
TOTAL
LIMESTONE/ALKALINE FLYASH
SHERBURNE 1
SHERBURNE 2
TOTAL
SODIUM CARBONATE
REID GARDNER 1
825
825
510
415
410
2985.
178
183
425
65
851.
400
400
800.
64
100
100
264
0.
793
750
530
180
2253.
0.
0.
360
360
450
1170.
200
115
250
400
680
820
135
400
225
550
280
4045.
710
710
1420.
125 (SOLAR POND)
360
360.
680
793
750
225
2448.
710
710
1420.
510
64
100
100
41b
1 1 0
1599.
178
1H3
65
426.
400
<>UO
BOO.
360
360.
200
115
250
400
820
1,25
400
530
180
550
280
3850.
U.
92
-------
EPA UTILITY FGD SUKVEY: OCTObEK 1978 - NOVtMBEK 197B
SECTION 8
SUMMARY OF SLUDGE DISPOSAL PRACTICES FOK OPERATIONAL FGD SYSTEMS
PROCESS/GENERATING UNIT
— SLUDGE--
STABILIZED
--SLUDGE—
UNSTABILIZEO
POND
LINED
KUNU
UNLINEU
REID GARDNER 2
REID GARDNER 3
TOTAL
0.
125 (SOLAR POND)
125 (SOLAR POND)
375.
THOROUGHBRED 121
SCHOLZ 1 & 2
23
23
TOTAL
23.
23.
-------
EPA UTILITY FGD SURVEYS OCTOBER 1976 - NOVEMBER 1976
SECTION 9
SUMMARY OF FGD SYSTEMS BY PROCESS AND REGULATORY CLASS
REGULATORY
PROCESS CLASS
LIME
LIME (CARBIDE)
LIME (MG-PROMOTED)
LIME/ALKALINE FLYASH
LIME/LIMESTONE
LIMESTONE
LIMESTONE/ALKALINE FLYASH
SUBTOTAL - LJME/LIMESTONE
AQUEOUS CARBONATE
CITRATE
LIME SPRAY DRYING
A
B
C
D
E
A
B
C
0
E
A
B
C
D
E
A
B
C
D
E
A
B
C
D
E
A
B
C
D
E
A
B
C
0
E
A
B
C
D
E
A
B
C
D
E
A
B
C
0
E
A
B
C
D
E
OPERATIONAL
NO.
1
6
1
0
0
0
3
1
0
0
0
2
0
0
0
2
1
0
0
0
0
0
2
0
0
9
6
2
0
0
0
2
0
0
0
12,
20.
6.
0.
0.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Mw
415
2770
64
0
0
0
766
65
0
0
0
800
0
0
0
720
450
0
0
0
0
0
20
0
0
4151
1770
1370
0
0
0
1420
0
0
0
5286«
7996.
1519.
0.
0.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
CONSTRUCTION
NO.
8
2
0
0
0
0
0
0
0
0
0
0
0
0
0
1
3
0
0
0
0
1
0
0
0
10
9
2
0
0
0
0
0
0
0
19.
15.
2.
0.
0.
0
0
0
0
0
0
1
0
0
0
0
1
0
0
0
M*
3630
1320
0
0
0
0
0
0
0
0
0
0
0
0
0
500
579
0
0
0
0
330
0
0
0
3717
3970
1000
0
0
0
0
0
0
0
7847.
6199.
1000.
0.
0.
0
0
0
0
0
0
60
0
0
0
0
455
0
0
0
CONTRACT
AWARDED
NO.
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
2
0
0
0
0
1
0
0
0
7
0
0
0
0
0
0
0
0
0
JO.
3.
0.
0.
o.
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
MM
1100
0
0
0
0
0
u
u
0
0
0
0
0
0
0
527
1400
0
0
0
0
330
0
0
0
3778
0
0
0
0
0
0
0
0
0
5405.
1730.
0.
0.
0.
0
0
100
0
0
0
0
0
0
0
0
0
0
0
0
PLANNED
NO.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
3
2
0
0
0
2
0
0
0
3.
5.
2.
0.
0.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
MW
0
0
0
0
u
u
0
0
u
0
0
0
u
0
0
u
0
u
0
0
u
u
u
u
0
2100
1950
1300
0
0
0
1720
0
U
0
2100.
3670.
1300.
0.
0.
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
TOTAL NO.
PLANTS
NO.
11
8
1
0
0
U
3
1
U
0
U
2
0
0
U
4
6
U
0
0
0
2
2
0
0
29
16
6
U
0
0
4
0
0
0
44,
43.
10.
0.
0.
0
0
1
0
0
0
1
0
0
0
0
1
0
0
0
MW
5145
4090
64
0
0
0
766
65
0
U
,0
BOO
0
0
0
1747
2429
0
0
0
0
660
20
0
0
13746
7690
3670
0
0
0
3140
0
0
0
20638.
19595.
3819.
0.
0.
0
0
100
0
0
0
60
0
0
0
0
455
0
0
0
-------
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVfcMBEK 1978
SECTION 9
SUMMARY OF FGO SYSTEMS BY PROCESS AND REGULATORY CLASS
REGULATORY OPERATIONAL
CONSTRUCTION
PROCESS CLASS
DOUBLE ALKALI
MAGNESIUM OXIDE
NOT SELECTED
NA2C03 SPRAY DRYING
SODIUM CARBONATE
WELLMAN LORD
THOROUGHBRED 121
TOTALS
LIME/LIMESTONE Z OF TOTAL MW
A
B
C
0
E
A
B
C
0
E
A
B
C
D
E
A
B
C
D
E
A
B
C
D
E
A
B
C
D
E
A
B
C
D
E
A
B
C
D
E
A
B
C
D
E
NO
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
3
0
0
0
0
0
2
1
0
0
0
0
1
0
0
15
23
8
0
0
MW
0
0
0
0
0
0
120
0
0
0
0
0
0
0
0
0
0
0
0
0
375
0
0
0
0
0
620
115
0
0
0
0
23
0
0
. 5661.
. 8736.
. 1657.
0.
0.
93
92
92
0
0
NO.
2
1
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
1
0
0
0
0
0
1
0
0
0
0
0
0
0
22.
18.
3.
0.
0.
MM
825
277
0
0
0
0
0
0
0
0
0
0
0
0
0
AOO
0
0
0
0
0
509
0
0
0
0
0
180
0
0
0
0
0
0
0
9072.
7045.
1180.
0.
0.
86
88
85
0
0
CONTRACT
PLANNED
AWARDED
NO.
0
U
0
0
0
0
0
U
0
0
0
3
0
0
0
0
0
U
0
0
0
U
0
0
0
0
2
0
0
U
0
0
0
0
0
10.
9.
1.
0.
0.
Mh
U
U
0
0
0
U
0
U
0
U
0
2060
0
0
U
U
0
0
0
0
0
0
0
0
0
0
940
0
0
0
0
0
0
0
0
5405.
5185.
100.
0.
0.
100
33
0
0
0
NO.
0
0
0
0
0
0
3
1
0
0
15
3
2
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
18
11
5
1
0
Mrt
0
0
U
0
0
0
726
600
0
0
7475
1205
590
800
0
0
U
0
0
0
0
0
0
0
0
U
0
U
0
0
0
0
0
0
0
. 9575.
. 5601.
. 2490.
800.
0.
22
66
52
0
0
TOTAL NO.
PLANTS
NU.
2
1
U
0
0
0
a
i
0
0
15
6
2
1
0
1
0
0
0
U
3
1
0
U
0
0
4
2
0
0
0
0
1
0
0
65.
61.
17.
1.
0.
Mn
825
277
U
0
0
U
046
600
0
0
7475
3265
590
8uo
0
400
0
0
0
U
375
509
0
0
U
0
1560
295
0
0
0
0
23
0
0
29713.
26567.
5427.
800.
0.
69
74
70
0
0
A. BOILER CONSTRUCTED SUBJECT TO FEDERAL NSPS
B. BOILER SUBJECT TO STATE STANDARD THAT IS MORE STRINGENT THAN THE FEDERAL NSPS
C. BOILER SUBJECT TO STATE STANDARD THAT IS EQUAL TO OR LESS STRINGENT THAN NSPS
0. OTHER
E. REGULATORY CLASS UNKNOWN
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 10
SUMMARY OF FGD SYSTEMS UNDER CONSTRUCTION
UTILITY COMPANY
POWER STATION
ALABAMA ELECTRIC COOP
TOMBI6BEE 3
ALLEGHENY POWER SYSTEM
PLEASANTS 1
ALLEGHENY POWER SYSTEM
PLEASANTS 2
ARIZONA ELECTRIC POWER COOP
APACHE 3
ARIZONA PUBLIC SERVICE
CHOLLA 4
ARIZONA PUBLIC SERVICE
FOUR CORNERS 1
ARIZONA PUBLIC SERVICE
FOUR CORNERS 2
ARIZONA PUBLIC SERVICE
FOUR CORNERS 3
BASIN ELECTRIC POWER COOP
LARAMIE RIVER 1
BASIN ELECTRIC POWER COOP
LARAMIE RIVER 2
BIG RIVERS ELECTRIC
GREEN 1
BIG RIVERS ELECTRIC
GREEN 2
CENTRAL ILLINOIS PUBLIC SERV
NEWTON 1
COLORADO UTE ELECTRIC ASSN.
CRAIG 1
COLORADO UTE ELECTRIC ASSN.
CRAIG ^
COMMONWEALTH EOISON
POWERTON Si
COOPERATIVE POWER ASSOCIATION
COAL CREEK 1
COOPERATIVE POWER ASSOCIATION
COAL CREEK 2
OELMARVA POWER 4 LIGHT
OELWARE CITY 1, 2 * 3
H003IER ENERGY
MEROM 1
HOOSIER ENERGY
MEROM 2
INDIANAPOLIS POWER * LIGHT
PETERSBURG 4
KANSAS POWER > LIGHT
JEFFREY 2
NEW OR
RETROFIT
N
N
N
N
N
R
R
R
N
N
N
N
N
N
N
R
N
N
R
N
N
N
N
SIZE OF FGD
UNIT (MW)
225
625
625
200
350
175
175
229
570
570
250
240
575
450
450
425
545
545
160
490
490
530
680
PROCESS/VENDOR
PEABOUY PROCESS SYSTEMS
LIMESTONE
8ABCOCK S WILCOX
LIME
BABCOCK & WILCOX
LIME
RESEARCH COTTHELL
LIMESTONE
RESEARCH COTTRELL
LIMESTONE
CHEMICO/APS
LIME/ALKALINE FLYASH
CHEMICO/APS
LIME/ALKALINE FLYASH
CHEMICO/APS
LIME/ALKALINE FLYASH
RESEARCH COTTKELL
LIMESTONE
RESEARCH C01THELL
LIMESTONE
AMERICAN AIR FILTER
LIME
AMERICAN AIR FILTER
LIME
BUELL/ENVIROTECH
DOUBLE ALKALI
PEA6UDY PROCESS SYSTEMS
LIMESTONE
PEABOOY PROCESS SYSTEMS
LIMESTONE
AIR CORRECTION DIVISION, UOP
LIMESTONE
COMBUSTION ENGINEERING
LIME
COMBUSTION ENGINEERING
LIME
DAVY POWERGAS
WELLMAN LORD
MITSUBISHI INTERNATIONAL
LIMESTONE
MITSUBISHI INTERNATIONAL
LIMESTONE
RESEARCH COTTHELL
LIMESTONE
COMBUSTION ENGINEERING
START-UP
DATfc
6/79
i/79
4/80
4/79
6/BU
0/79
U/79
U/79
4/ttU
10/80
12/79
12/8U
11/79
3/79
3/79
3/79
2/79
11/79
4/00
4/81
1/82
10/83
6/80
LIMESTONE
-------
EPA UTILITY F6D SURVEY: OCT06EK 1978 - NUVfcr'BEK 197H
SECTION 10
SUMMARY OF FGO SYSTEMS UNDER CONSTRUCTION
UTILITY COMPANY
POWER STATION
LOUISVILLE GAS ft ELECTRIC
CANE RUN 6
LOUISVILLE GAS & ELECTRIC
MILL CREEK 1
LOUISVILLE GAS ft ELECTRIC
MILL CREEK 4
MINNESOTA POWER ft LIGHT
CLAY BOSWELL 4
OTTER TAIL POWER
COYOTE 1
PACIFIC POWER & LIGHT
JIM BRIDGER a
PENNSYLVANIA POWER
BRUCE MANSFIELD 3
SALT RIVER PROJECT
CORONAOO 1
SALT RIVER PROJECT
CORONAOO 2
SAN MIGUEL ELECTRIC COOP
SAN MIGUEL 1
SIKESTON BOARD OF MUNIC. UTIL.
SIKESTON POWER STATION
SOUTHERN ILLINOIS POWER COOP
MARION 4
SOUTHERN INDIANA GAS ft ELEC
A. B. BROWN 1
SOUTHERN MISSISSIPPI ELECTRIC
R. 0. MORROW 2
SPRINGFIELD WATER LIGHT ft PWR
DALLMAN 3
9Tt. JOE_ZJNC
8. F. WEATON 1
TENNESSEE VALLEY AUTHORITY
WIDOWS CREEK 7
TEXAS UTILITIES
MARTIN LAKE 3
UTAH POWER * LIGHT
EMERY 1
UTAH POWER ft LIGHT
EMERY 2
NEW OR
RETROFIT
R
R
N
N
N
N
N
N
N
N
N
N
N
N
N
R
R
N
N
N
SIZE OF FGD
UNIT (Mw)
277
330
495
500
400
509
825
350
350
400
235
184
250
180
190
60
575
793
400
400
PROCESS/VENDOR
AOL/COMBUSTION EQUIP ASSOCIA'
DOUBLE ALKALI
COMBUSTION ENGINEERING
LIME/LIMESTONE
AMERICAN AIM FILTER
LIME
PEABODY PROCESS SYSTEMS
LIME/ALKALINE FLYASM
WHEELABRATOR-FRYE/R.I.
NA2C03 SPRAY DRYING
AIR CORRECTION DIVISION, UOP
SODIUM CARBONATE
PULLMAN KELLOGG
LIME
PULLMAN KELLOGG
LIMESTONE
PULLMAN KELLOGG
LIMESTONE
BABCOCK ft WILCOX
LIMESTONE
BABCOCK ft WILCOX
LIMESTONE
BABCOCK ft WILCOX
LIMESTONE
FMC CORPORATION
DOUBLE ALKALI
RILEY STOKER / ENVIHONEERING
LIMESTONE
RESEARCH COTTKELL
LIMESTONE
BUREAU OF MINES
CITRATE
COMBUSTION ENGINEERING
LIMESTONE
RESEARCH COTTRELL
LIMESTONE
CHEMICO
LIME
CHEMICO
LIME
STAKT-UP
DATE
12/7tt
1/81
7/81
5/80
5/81
9/79
4/80
2/79
1/80
b/80
6/81
9/78
4/79
2/79
7/8U
11/16
1U/8U
12/78
1/79
6/80
97
-------
EP* UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION 11
SUMMARY OF PLANNED FGO SYSTEMS
UTILITY COMPANY
POWER STATION
CONTRACTS AWARDED
ARIZONA PUBLIC SERVICE
FOUR CORNERS 4
ARIZONA PUBLIC SERVICE
FOUR CORNERS 5
ASSOCIATED ELECTRIC COOP
THOMAS HILL 3
BASIN ELECTRIC POWER COOP
ANTELOPE VALLEY 1
BASIN ELECTRIC POWER COOP
LARAMIE RIVER 3
CINCINNATI GAS & ELECTRIC
EAST BEND 2
EAST KENTUCKY POWER COOP
SPURLOCK 2
LAKELAND UTILITIES
MCINTOSH 3
LOUISVILLE GAS & ELECTRIC
MILL CREEK 2
MONTANA POWER
3
MONTANA POWER
COLSTRIH 4
NIAGARA MOHAWK POWER COOP
CHARLES. R. HUNTLEY 6
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN 3
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN 4
SOUTH CAROLINA PUBLIC SERVICE
WINYAH 3
SOUTHWESTERN ELECTRIC POWER
HENRY W. PERKEY 1
TEXAS MUNICIPAL POWER AGENCY
GIBBONS CREEK 1
TEXAS POWER & LIGHT
SANDOW 4
TEXAS UTILITIES
MARTIN LAKE 4
WISCONSIN POWER ft LIGHT
COLUMBIA 2
NEW OR
RETROFIT
R
R
N
N
N
N
N
N
R
N
N
R
N
N
N
N
N
N
N
N
SIZE OF FGD
UNIT (MW)
755
755
670
455
550
600
500
350
330
700
700
100
466
472
300
720
400
545
793
527
VENDOR/PROCESS
UNITED ENGINEERS
NOT SELECTED
UNITED ENGINEERS
NOT SELECTED
PULLMAN KELLOGG
LIMESTONE
WESTERN PRECIP./NIRU ATOM.
LIME SPRAY DRYING
BABCOCK & WILCOX
NOT SELECTED
BABCOCK & WILCOX
LIME
ADL/COMBUSTION EQUIP ASSOCIATE
LIME
BABCOCK 8 WILCOX
LIMESTONE
COMBUSTION ENGINEERING
LIME/LIMESTONE
ADL/COMBUSTION EQUIP ASSOCIATE
LIME/ALKALINE FLYASH
ADL/COMBUSTION EQUIP ASSOCIATE
LIME/ALKALINE FLYASH
ROCKWELL INTERNATIONAL
AUUEOUS CARBONATE
DAVY POWERGAS
WELLMAN LORD
DAVY POWERGAS
WELLMAN LORD
BABCOCK ft WILCOX
LIMESTONE
AIR CORRECTION DIVISION, UOP
LIMESTONE
COMBUSTION ENGINEERING
LIMESTONE
COMBUSTION ENGINEERING
LIMESTONE
RESEARCH COTTRELL
LIMESTONE
CHEMICO
START-UP
DATE
u/e
-------
EPA UTILITY FGO SURVEY: OCTOBEK 1978 - NOVEMUEK 1978
SECTION 11
SUMMARY OF PLANNED FGD SYSTEMS
UTILITY COMPANY
POWER STATION
PHILADELPHIA ELECTRIC
EDDYSTONE IB
NEW OR
RETROFIT
SIZE OF FGD VENDOR/PROCESS
UNIT (MW)
240
UNITED ENGINEERS
MAGNESIUM OXIDE
START-UP
DATE
6/80
REQUESTING/EVALUATING BIDS
N
CENTRAL ILLINOIS LIGHT
DUCK CREEK 2
PUBLIC SERVICE OF INDIANA
GIBSON 5
TENNESSEE VALLEY AUTHORITY
PARADISE 1
TENNESSEE VALLEY AUTHORITY
PARADISE 2
TEXAS UTILITIES
FOREST GROVE 1
N
900
650
650
650
750
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
LIMESTONE
NOT SELECTED
LIMESTONE
NOT SELECTED
NOT SELECTED
1/84
0/82
U/82
u/ 0
0/81
CONSIDERING FGD SYSTEM
BASIN ELECTRIC POWER COOP
ANTELOPE VALLEY 2
CENTRAL MAINE POWER
SEARS ISLAND 1
COLUMBUS & SOUTHERN OHIO ELEC.
POSTON 5
COLUMBUS & SOUTHERN OHIO ELEC.
POSTON 6
GENERAL PUBLIC UTILITIES
COHO 1
GENERAL PUBLIC UTILITIES
SEWARD 7
NEVADA POWER
HARRY ALLEN 1
NEVADA POWER
HARRY ALLEN 2
NEVADA POWER
HARRY ALLEN 3
NEVADA POWER
HARRY ALLEN q
NEVADA POWER
REID GARDNER 4
NEVADA POWER
WARNER VALLEY 1
NEVADA POWER
WARNER VALLEY 2
NORTHERN INDIANA PUB SERVICE
BA1LLV 7
NORTHERN INDIANA PUB SERVICE
BAILLY 8
PACIFIC GAS AND ELECTRIC
FOSSIL 1
455
600
375
375
600
800
500
500
500
500
250
250
250
190
400
800
NUT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NUT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
NOT SELECTED
LIMESTONE
11/83
11/86
0/83
0/85
5/88
5/85
6/85
6/66
6/87
6/88
0/83
0/84
6/65
O/ 0
O/ 0
0/65
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 197B
UTILITY COMPANY
POWER STATION
PACIFIC 6AS AND ELECTRIC
FOSSIL 2
PHILADELPHIA ELECTRIC
CROM8Y
PHILADELPHIA ELECTRIC
EDDYSTONE 2
POTOMAC ELECTRIC POWER
DICKERSON 4
SALT RIVER PROJECT
CORONADO 3
SEMINOLE ELECTRIC
SEMINOLE 1
SOUTHERN ILLINOIS POWER COOP
MARION S
TAMPA ELECTRIC
BI6 BEND a
TENNESSEE VALLEY AUTHORITY
JOHNSONVILLE
TEXAS POKER I LIGHT
THIN OAKS 1
TEXAS POWER ft LIGHT
THIN OAKS 2
SECTION 11
SUMMARY OF PLANNED FGD SYSTEMS
NEH OR SIZE OF FGD VENDOR/PROCESS
RETROFIT UNIT (MM)
N 800 NOT SELECTED
LIMESTONE
R ISO UNITED ENGINEERS
MAGNESIUM OXIDE
R 336 UNITED ENGINEERS
MAGNESIUM OXIDE
N 800 NUT SELECTED
NOT SELECTED
N 350 NOT SELECTED
LIMESTONE
N 600 NUT SELECTED
LIMESTONE
N 300 NUT SELECTED
NOT SELECTED
N 425 VENDOR NOT SELECTED
PROCESS NOT SELECTED
R 600 TVA/UNITED ENGINEERS
MAGNESIUM OXIDE
N 750 NOT SELECTED
LIMESTONE
N 750 NOT SELECTED
LIMESTONE
STAKT-UP
DATE
U/86
6/80
6/80
5/85
0/87
6/83
U/84
0/85
0/82
8/83
9/84
100
-------
EPA UTILITY FGD SURVEY: UCTUbfcK 1978 - NUVfcMBEK 197B
SECTION 13
TOTAL FGD MEGAWATT CAPACITY BY YEAR *
YEAH NO. UNITS MEGAWATTS
1950
1968
1971
1973
1973
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
UNDEFINED
1
1
1
4
4
2
4
6
10
18
19
23
10
11
6
6
7
3
3
2
3
793
125
400
220
1410
250
1054
2313
4921
6675
7026
9853
4805
6322
2960
3200
3950
1900
1710
1300
1240
• TOTALS DISPLAYED DO NOT INCLUDE TERMINATED OR INACTIVE SYS1EMS.
101
-------
APPENDIX A
FGD SYSTEMS ECONOMICS
A-l
-------
INTRODUCTION
The cost of flue gas desulfurization (FGD) systems for the
control of sulfur dioxide emissions is an area of intense inter-
est and substantial controversy. As a result, many computer
models have recently been developed to estimate capital and
annual costs. As part of an effort by the U.S. Environmental
Protection Agency to provide meaningful economic data concerning
FGD systems, reported economic data have been incorporated into
the EPA Utility FGD Survey report. This information has appeared
as a separate appendix of the report since October 1976. Until
January 1978, this cost appendix consisted entirely of data
reported by the utilities with little or no interpretation pro-
vided by PEDCo Environmental, Inc. Beginning with the May 1978
report, the format and content of the cost appendix were revised
to include reported and adjusted costs for the operational FGD
systems.
The rationale for including adjusted as well as reported
costs stems primarily from the lack of comparability of the
reported costs. Many of the reported cost figures, both capital
and operating, are largely site-sensitive values that cannot be
accurately compared because they refer to different FGD battery
limits and different years in which the expenditures were made.
As a result, an analysis of the cost data was made for the opera-
tional units since these systems offer the potential of having
complete and accurate economic data. The adjustments were made
to provide comparable, accurate cost data for the sulfur dioxide
portion of the emission control system. This, in effect, will
eliminate much of the confusion that exists concerning the re-
ported data, and it will provide a common basis for the reported
costs.
A-2
-------
APPROACH
In March 1978, each utility having at least one operational
FGD system was given a cost form containing all available cost
information then in the PEDCo files. The utility was asked to
verify the date), and fill in any missing information called for
on the form. R. follow-up visit by the PEDCo Environmental staff
was arranged to assist in data acquisition and to insure com-
pleteness and reliability of information. Results of the cost
analysis were irorwarded to each participating utility for final
review and comment.
The cost data were treated solely to establish the accurate
costs for FGD systems, on a common basis, not to critique the
design or reasonableness of the costs reported by any utility.
Adjustments focused primarily on the following items:
0 All capital costs were adjusted to July 1, 1977, dol-
larss. using the Chemical Engineering Index. All capital
costs, represented in dollars/kilowatt ($/kW), were
expressed in terms of gross megawatts (MW). Actual
costs were reported by utilities in dollar values for
years 1970 to 1980. These values are represented in
terms of the year of greatest capital expenditures.
0 Gross unit capacity was used to express all FGD capital
expenditures because the capital requirement of an FGD
system is dependent on actual boiler size before de-
rating for auxiliary and air quality control power
requirements.
0 Par-ticulate control costs were deducted. Since the
purpose of the study was to estimate the incremental
cos't for sulfur dioxide control, particulate control
costs were deducted using either data contained in the
cost breakdowns or as a percentage of the total direct
cost (capital and annual). The percentage reduction
varied depending upon system design and operation.
A-3
-------
The capital costs associated with the modification or
installation of equipment not part of tlie FGD system
but needed for its proper functioning, were included
(e.g. - stack lining, modification to existing ductwork
or fans, etc.).
Indirect charges were adjusted to provido adequate
funds for engineering, field expenses, logal expenses,
insurance, interest during construction, allowance for
startup, taxes, and contingency.
All annual costs, represented in mills/kilowatt-hour
(mills/kWh), were expressed in terms of net megawatts
(MW) .
Net unit capacity was used to express all FGD annual
expenditures because the annual cost requirement of an
FGD system is dependent on the actual amount of kilo-
watt-hours (kWh) produced by the unit after derating
for auxiliary and air quality control power require-
ments.
All annual costs were adjusted to a common capacity
factor (65 percent).
Replacement power costs were not included since only a
few utilities reported such costs and thes e were pre-
sented using a variety of methods.
Sludge disposal costs were adjusted to ref.'Lect the
costs of sulfur dioxide waste disposal only (i.e.,
excluding fly ash disposal) and to provide for disposal
over the anticipated lifetime of the FGD system. This
latter correction was necessary since seveiral utilities
reported costs for sludge disposal capacity that would
last only a fraction of the FGD system life. The
adjustments were based on a land cost of $2000/acre
with a sludge depth of 50 ft in a clay-lin«d pond (clay
is assumed to be available at the site).
A 30-year life was assumed for all process and economic
considerations for all new systems that were installed
for the life of the unit. A 20-year life was assumed
for all process and economic considerations for retro-
A-4
-------
fit systems that were installed for the remaining por-
tion of the life of the unit.*
0 Regeneration and by-product recovery facility costs
were added for those regenerable systems not reporting
such costs.
To the extent possible, all cost adjustments were made using
the previous assumptions developed by PEDCo Environmental. When
cost data were inadequate, adjustments were made using process
design data in conjunction with the previous cost assumptions.
In some cases, no adjustments were possible because of in-
sufficient data.
* The use of a 30-year service life for new units coincides with
the conclusion of the National Power Survey of the Federal
Power Commission which recognized this value as reasonable for
steam-electric plants. A 20-year service life was assumed for
all retrofit units even if the remaining life of the units is
less than this value. Thus, two different rates are used and
should be noted when making comparisons between new and retro-
fit systems.
A-5
-------
DESCRIPTION OF COST ELEMENTS
Capital costs consist of direct costs/ indirect costs, con-
tingency costs, and other capital costs. Direct costs include
the "bought-out" cost of the equipment, the cost of installation,
and site development. Indirect costs include interest during
construction, contractor's fees and expenses, engineering, legal
expenses, taxes, insurance, allowance for start-up and shake-
down, and spares. Contingency costs include those costs result-
ing from malfunctions, equipment alterations, and similar un-
foreseen sources. Other capital costs include the nondepreciable
items of land and working capital.
Annual costs consist of direct costs, fixed costs, and over-
head costs. Direct costs include the cost of raw materials,
utilities, operating labor and supervision, and maintenance and
repairs. Fixed costs include those of depreciation, interim
replacement, insurance, taxes, and interest on borrowed capital.
Overhead costs include those of plant and payroll expenses. The
various capital and annual cost components are discussed and
defined in greater detail in the following paragraphs.
The direct capital costs include the following elements:
0 Equipment required for the FGD system. Table A-l
provides a summary of the major process equipment used
in regenerable and nonregenerable systems.
0 Installation of equipment, including foundations; steel
work for support, buildings, piping and ducting for
effluents, slurries, sludge, and make-up water, control
panels, instrumentation, insulation of ducting, buildings,
piping, and other equipment, painting and piling.
0 Site development may include clearing and grading,
construction of access roads and walkways, establish-
ment of rail, barge, and/or truck facilities, and
parking facilities.
A-6
-------
TABLE A-l. MAJOR FGD SYSTEM EQUIPMENT SUMMARY
Category
Description
Material handling-
raw materials
Feed preparation-
raw materials
Sulfur dioxide
absorption
Flue gas reheat
Gas handling
Sludge disposal
Utilities
By-product
handling
Equipment for the handling and transfer of
raw materials includes unloading facilities,
conveyors, storage areas and silos, vibrators,
atmospheric emission control associated with
these facilities, and related accessories.
Equipment for the preparation of raw material
to produce a feed slurry consists of feed
weighers, crushers, grinders, classifiers,
ball mills, mixing tanks, pumps, agitators,
and related accessories.
Equipment for treating the flue gas includes
absorbers, mist eliminators, hold tanks,
agitators, circulating pumps, pond water re-
turn pumps, and related accessories.
Equipment required includes air, steam, or
hot water heaters, condensate tanks, pumps,
soot blowers, fans, fuel storage facilities,
gas bypass equipment, and related accessories.
Equipment to handle the boiler flue gas in-
cludes booster fans, ductwork, flue gas by-
pass system, turning vanes, supports, plat-
forms, and related accessories.
Nonregenerable FGD systems require solids/
water separation equipment such as clarifiers,
vacuum filters, centrifuges, sludge fixation
equipment, and related accessories.
Equipment to supply power and water to the
FGD equipment consists of switch-gear, break-
ers, transformers, piping, and related
accessories.
Equipment for processing the by-product of
regenerable FGD systems may include a rotary
kiln, fluid bed dryer, conveyor, storage silo,
vibrator, combustion equipment and oil stor-
age tanks, waste heat boilers, hammer mills,
evaporators, crystallizers, strippers, tanks,
agitators, pumps, compressors, sulfuric acid
absorber and cooling, mist eliminator, pumps,
acid coolers, tanks, etc.
(continued)
A-7
-------
TABLE A-l. (continued)
Category
Description
Regeneration
Purge treatment
Auxiliary
Equipment for regeneration of the absorbing
medium of an FGD system may consist of re-
actor vessels, material handling system,
storage, weigh feeder, conveyor, rotary kiln,
fluid bed calciner, dust collector, storage
silo, vibrator, combustion equipment and oil
storage tanks, waste heat boiler, hammer
mill, evaporators, crystallizers, strippers,
tanks, agitators, pumps, compressors, sul-
furic acid absorber and cooling, mist elimi-
nator, pumps, acid coolers, tanks, etc.
Equipment for the removal of purge material
(e.g. sodium sulfate) includes refrigeration,
pumps, tanks, crystallizer, centrifuge,
dryer, dust collector, conveyors, storage,
and related equipment.
Equipment not directly related to the
FGD system, but which may require design or
modification to accommodate an FGD system
may include such items as existing fans,
ducts, or stack. If new fans, ducts, or
stacks are added to improve boiler perfor-
mance and accommodate the FGD system, the
costs are prorated to the boiler and FGD
system.
A-8
-------
Indirect capi-tal costs include the following elements:
Interest accrued on borrowed capital during construction,
0 Contractor's fee and expenses, including costs for
field lab*or payroll; field office supervision; person-
nel; construction offices; temporary roadways; railroad
trackage; maintenance and welding shops; parking lot;
communicat .ions; temporary piping and electrical and
sanitary facilities; safety security (fire, material,
medical, etc.); construction tools and rental equip-
ment; unlo.ading and storage of materials; travel ex-
penses; pe: emits; licenses; taxes; insurance; overhead;
legal liabilities; field testing of equipment; start-
up; and lat»or relations.
° Engineering costs, including administrative, process,
project, an»d general; design and related functions for
specifications; bid analysis; special studies; cost
analysis; accounting; reports; consultant fees; pur-
chasing; procurement; travel expenses; living expenses;
expediting; inspection; safety; communications; model-
ing; pilot p'lant studies (if required because of pro-
cess design ior application novelty); royalty payments
during construction; training of plant personnel; field
engineering; safety engineering; and consultant ser-
vices .
0 Legal expenses, including those for securing permits,
rights-of-way , etc.
0 Taxes, includi.ng sales, and excise taxes.
0 Insurance cove ring liability for equipment in transit
and at site; f.ire, casualty, injury, and death; damage
to property; dtslay; and noncompliance.
0 Allowance for at art-up and shakedown includes the cost
associated with system start-up.
° Spare parts inciluding pumps, valves, controls, special
piping and fitti.ngs, instruments, spray nozzles, and
similar items.
Other capital costs iinclude the following elements:
0 Land required foi: the FGD process, waste disposal, re-
generation facili ty, and storage.
° Working capital, .including the total amount of money
invested in raw nuiterials and supplies in stock,
finished products in stock, and unfinished products
A-9
-------
in the process of being manufactured; accounts re-
ceivable; cash kept on hand for payment of operating
expenses such as salaries, wages, anol raw materials
purchases; accounts payable; and taxfss payable.
Annual cost of an FGD system includes the: following direct,
fixed and overhead charges:
0 Direct Charges
Raw materials, including those requ ired by the FGD
process for sulfur dioxide control, absorbent regenera-
tion, sludge treatment, sludge fixation, flocculants,
etc.
Utilities, including water for slurries, cooling and
cleaning; electricity for pumps, f;ans, valves, lighting
controls, conveyors, and mixers; fuel for reheating of
flue gases; and stream for process} ing.
Operating labor, including supervisory, skilled, and
unskilled labor required to operate, monitor, and
control the FGD process.
Maintenance and repairs, consisting of both manpower
and materials to keep the unit operating efficiently.
The function of maintenance is both preventive and
corrective to keep outages to a :rninimum.
Byproduct Sales; credit from th.e sale of byproducts
regenerable FGD processes (e.g. sulfur, sulfuric acid)
is a negative charge deducted fjrom the annual direct
cost to obtain the net annual direct cost of the FGD
system.
0 Fixed Charges
• Depreciation - the annual char«;je to recover direct and
indirect costs of physical assists over the life of the
asset.
Interim, replacement - costs (.expended for temporary or
provisional replacement of equipment that has failed or
malfunctioned prematurely.
Insurance, including the cos1;s of protection from loss
by a specified contingency, j:»eril, or unforeseen event.
Required coverage could include losses due to fire,
personal injury or death, property damage, explosion,
lightning, or other natural ;phenomena.
A-10
-------
Taxes, including franchise, excise, and property taxes
levied by a city, county, state, or Federal government.
Interest on borrowed funds.
0 Overhead
Plant and administrative overhead is a business expense
that is not charged directly to a particular part of a
project, but is allocated to it. Overhead costs in-
clude administrative, safety, engineering, legal and
medical services; payroll; employee benefits; recrea-
tion; and public relations.
Table A-2 provides a summary of the means used to determine
the missing cost elements if the costs were not reported or
insufficient information prevented their actual determination.
The assumptions and cost bases for determining the capital and
annual costs of FGD systems were developed by the PEDCo staff
based upon previous economic studies conducted for the U.S. EPA
(Flue Gas Desulfurization Process Cost Assessment, May 1975;
Simplified Procedures for Estimating Flue Gas Desulfurization
System Costs, June 1976, EPA-600/2-76-150; Particulate and Sulfur
Dioxide Emission Control Costs for Large Coal-Fired Boilers,
March 1978, EPA-600/7-78-032) .
A-ll
-------
TABLE A-2. COST ELEMENT FACTORS
Category
Value
Indirect capital costs:
Interest during
construction
Field overhead
Contractor's fee and
expenses
Engineering
Taxes
Spares
Shakedown allowance
Other capital costs:
Contingency
Direct annual costs:
Raw materials:
Fixation chemicals
Lime
Limestone
Magnesium oxide
Sodium carbonate
Salt cake (credit)
Sulfur (credit)
Sulfuric acid (credit)
Utilities:
Electricity
Water
Steam
Operating labor:
Direct labor
Supervision
10% of total direct capital costs
10% of total direct capital costs
5% of total direct capital costs
10% of total direct capital costs
2% of total direct capital costs
1% of total direct capital costs
5% of total direct capital costs
20% of total direct and indirect
capital costs
$2/ton
$40/ton
$10/ton
$150/ton
$80/ton
$50/ton
$65/ton
$25/ton
25 mills/kWh
$0.20/103 gal
$0.80/106 Btu
$ 8.50/man-hour
15% of direct labor costs
Contingency costs are used only when the cost data supplied are
incomplete (such as equipment costs or direct costs only) and a
contingency cost must be factored in to give an accurate estimate
of the total capital cost.
(continued)
A-12
-------
TABLE A-2. (continued)
Category
Value
Maintenance:
Labor and materials
Supplies
Overhead:
Plant
Payroll
Fixed annual costs:
Depreciation
Interim replacement
Taxes
Insurance
Capital costs
4% of total direct capital costs
15% of labor and materials costs
50% of operation and maintenance costs
20% of operating labor costs
3.33% or 5% (new or retrofit)
0.7% or 0.35%
4%
0.3%
9%
Some system components have life spans less than the expected
service life of the system. Interim replacement is an allow-
ance factor used in estimating annual revenue requirements to
provide for the replacement of these short-lived items. An
average allowance of 0.35% of the total investment is normally
provided and used for systems with an expected service life of
20 years or less. A higher allowance of 0.70% of the total
investment is provided and used for systems with an expected
service life of 30 years or more.
A-13
-------
DEFINITION OF COST ELEMENTS
The costs displayed in Appendix A are accompanied by a
series of alphabetic characters summarizing data presented for
each FGD system. These relate to the cost elements described
earlier in this section and identify what has been included and
excluded for reported and adjusted capital and annual costs. The
•»
alphabetic characters, along with their titles, are briefly de-
scribed in Table A-3.
A-14
-------
TABLE A-3. DESCRIPTION OF COST
Code
Title
Description
B
C
B
H
L
N
N
O
articulate control (required for FGD pro-
cess) included in capital cost.
articulate control (included in PGD
process) included in capital cost.
Total direct capital costs included.
Partial direct capital costs included.
Total indirect capital costs included.
Partial indirect costs included.
Chemical fixation of sludge included in
capital cost.
Dry sludge disposal included in capital
cost.
Off-site landfill area included in
capital cost.
Sludge pond included in capital cost.
Additional sludge disposal capacity
added for life of system.
Stack included in capital cost.
Modifications to stack, ducts, and/or
fans included in capital cost.
Total regeneration facility cost included
in capital cost.
Partial regeneration facility cost in-
cluded in capital cost.
R & D costs included in capital cost.
Particulate precollection device (ESP,
fabric filter, venturi) prior to PGD
system required for proper operation of
SO. control system.
Particulate collection equipment (venturi
scrubber) is included in the FGD system.
Complete cost of all FfiD equipment, the
labor and materials required for equip-
ment installation, and interconnecting
the system is included in the total
capital cost.
One or a number of direct cost items, or
the cost associated with one or a number
of direct cost items, are excluded from
the total capital cost.
Complete cost of all the indirect cost
elements, including interest during con-
struction, contractor's fees, engineer-
ing, legal expenses, taxes, insurance,
allowance for start-up, and spares, is
included in total capital cost.
One or a number of indirect cost items,
or the cost associated with one or a
number of indirect cost items, are ex-
cluded from the total capital cost.
The cost of a chemical fixation process
which stabilizes the flue gas cleaning
wastes prior to disposal is included in
the total capital cost.
The cost of a secondary dewatering or
treatment method, such as filtration, cen-
trifugation, or forced oxidation, which
ultimately produces a dry sludge cake
for final disposal, is included in the
total capital cost.
The cost of an off-site area used as a
landfill for flue gas cleaning wastes is
included in the total capital cost.
The cost of an on-site disposal area for
ponding of treated or untreated flue gas
cleaning wastes is included in the total
capital cost.
The cost of additional SO, waste disposal
capacity required for FGD system operation
over the anticipated service life of the
unit is included in the total capital cost.
The cost of the stack is included in the
total capital cost.
Modifications to existing equipment (stack,
fans, ducts, etc.) which are required be-
cause of inclusion of an FGD system.
Complete cost of entire regeneration
facility included in total capital cost.
Part of the cost associated with the re-f
generation facility included in the total
capital cost.
Bench scale or pilot plant studies to de-
termine process and design characteristics.
(continued)
A-15
-------
TABLE A-3. (continued)
Code
Title
Description
W
X
Costs underwritten by system supplier in-
cluded in capital cost.
Excess reagent supply costs included in
capital cost.
Total direct annual costs included.
Partial direct annual costs included.
Total fixed annual costs included.
Partial fixed annual costs included.
Overhead cost included in total annual
cost.
Particulate control costs included in
direct annual cost.
Sludge disposal service costs (contract)
included in direct annual cost.
Replacement energy costs included in
total annual costs.
Capital expenditures underwritten by the
system supplier for system repairs or
modifications for optimization of perfor-
mance or R S D programs.
Capital expenditures for reagent supply
exceeds the amount required for the period
of initial operation.
Complete cost of all raw materials,
utilities, operating labor and maintenance
and repairs is included in the total
annual cost.
One or a number of direct annual cost items,
or the cost associated with one or a number
of direct annual cost items, are excluded
from the total annual cost.
Complete cost of all fixed cost elements,
including depreciation, interim replace-
ment, insurance, taxes, and interest, is
included in the total annual cost.
One or a number of fixed annual cost items,
or the cost associated with one or a
number of fixed annual cost items, are ex-
cluded from the total annual cost.
Plant and payroll overhead costs are in-
cluded in the total annual cost.
The cost of operating particulate collection
equipment included in the FGD system is in-
cluded in the total annual cost.
The treatment and disposal of flue gas
cleaning wastes that are handled by an
outside firm.
The cost of additional power-generating
capacity required to compensate for power
used by the PGD system.
A-16
-------
RESULTS OF COST ANALYSIS
The results of the operational FGD system survey are
summarized in Tables A-4 and A-5. Table A-4 summarizes the re-
ported and adjusted capital and annual costs for all the
operational FGD systems addressed in the survey. Table A-5 pro-
duces a summary of a categorical analysis of the reported and ad-
justed capital and annual costs for the operational FGD systems
addressed in the survey. Included in this categorical analysis
are the ranges, means, and standard deviation for all the various
types and categories of FGD systems examined.
A-17
-------
TABLE A-4. REPORTED AND ADJUSTED CAPITAL AND ANNUAL
COSTS FOR OPERATIONAL FGD SYSTEMS*
Cholla 1
Conesville 5
Elrama 1-4
Phillips 1-6
Petersburg 3
Hawthorn 3-4
La Cygne 1
Green River 1-3
Cane Run 4
Cane Run 5a
Paddys Run 6
M.R. Young 2a
Colstrip 1-2
Reid Gardner 1-2
Reid Garbder 3
D.H. Mitchell 11
Sherburne 1-2
B. Mansfield 1-2
Eddystone 1AC
Winyah 2
Southwest la
Widows Creek 8
Reported
Capital
SAW
52.0
55.6
113.5
107.0
99.5
29.3
53.7
70.3
66.6
62.4
52.9
86.0
77.1
42.9
113.6
156.9
47.9
120.7
156.8
47.5
77.3
98.2
Annual
mills/kWh
2.19
4.71
8.62
7.83
8.40
1.70
14.35
2.75
0.27
2.10
2.10
14.86
1.99
14.35
1.61
2.99
Adjusted
Capital
$/kW
56.0
70.8
127.2
140.6
100.6
87.3
68.0
77.6
80.6
67.5
76.5
93.1
77.3
60.9
107.9
145.5
71.9
102.9
233.3
66.5
117.7
113.2
Annual
mills/kWh
2.58
7.42
7.81
8.57
6.56
4.35
3.78
5.24
5.78
5.56
6.51
5.16
4.06
3.20
4.38
12.73
2.77
8.68
2.92
6.17
5.28
Annual costs were not reported by the utility for this system
because of the lack of meaningful data due to recent operating
status.
Annual costs were not reported by the utility for this system
because of the lack of meaningful data due to peak load status
of unit.
0 Annual cost data are being assembled by the utility.
* Newly operation units do not appear as cost data are currently
being assembled.
A-18
-------
TABLE A-5. CATEGORICAL RESULTS OF THE REPORTED AND ADJUSTED
CAPITAL AND ANNUAL COSTS FOR OPERATIONAL FGD SYSTEMS
All
New
Retrofit
erable
Regenerable
Limestone
Live
Alkaline/fly
ash/1 iaestani
Alkaline ny
ash/line
Sodiua
Magnesium
oxide
Reported Adjusted
Capital
Range, S/kH
29.3-156.9
47.5-120.7
29.3-156.9
29.3-120.7
L56.8-156.9
47.5-99.5
29.3-120.7
47.9
77.1-86.0
42.9-113.6
156.8
Avg..
SAW
78.0
78.8
77.2
71.7
156.8
71.4
75.3
47.9
81.6
78.3
156.8
0
35.7
27.8
42.9
28.7
0.1
23.7
34.6
6.3
50.0
Annual
Range
mills/la*
0.27-14.86
0.27-14.35
2.10-14.86
0.27-14.35
14.86
1.61-2.99
2.75-14.35
1.99
0.27
2.10
Avg..
mills/kWh
5.6
4.3
7.4
5.2
14.9
2.1
9.3
0.27
2.1
Capital
o
5.1
5.4
5.4
4.8
0.6
4.3
Range, SAW
56.0-233.3
66.5-117.7
56.0-233.3
56.0-140.6
145.5-233.3
56.0-117.7
67.5-140.6
71.5
77.3-93.1
60.9-107.9
233.3
Avg.,
SAW
94.2
86.8
101.0
86.5
189.4
87.0
92.8
71.5
85.2
84.4
233.3
o
36.9
17.8
48.2
22.3
62.1
26.7
23.5
11.2
33.2
Annual
Range
millsAHh
2.58-12.73
2.77-8.68
2.58-12.73
2.58-8.68
12.73
2.58-6.56
4.35-8.68
2.77
4.06-5.16
3.20-4.38
Avg..
5.5
5.2
5.8
5.2
12.73
4.5
6.6
2.77
4.6
3.8
o
2.4
2.1
2.7
1.9
1.7
1.7
0.8
0.8
M
VO
-------
EPA UTILITY F6D SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION A-l FGD SYSTEM ECONOMICS: OPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
UTILITY
STATION
UNIT(S)
FGO MW
ELEMENTS
INCLUDED IN
CAPITAL AND
ANNUAL COSTS
TOTAL ANNUAL - MILLS/KWH
CAPACITY CAPITAL ———
FACTOR S/KH TOTAL DIRECT FIXED
Z (YEAR) (YEAR)
ALABAMA ELECTRIC COOP
TOMBIGBEE
2
255 C,E,J
*************** REPORTED ***************
69.5
(1978)
*************** ADJUSTED ***************
ARIZONA ELECTRIC POWER COOP
APACHE
2
200 B,C
*************** REPORTED ***************
5.3
(1978)
*************** ADJUSTED ***************
ARIZONA PUBLIC SERVICE
CHOLLA
1
126 B,C,E,S,U,X
C,E,K,S,U,H
*************** REPORTED ***************
85 52.0 2.19
(1973) (1976)
*************** ADJUSTED ***************
65 56.0 2.56 .48 2.10
(1977) (1977)
CENTRAL ILLINOIS LIGHT
DUCK CREEK
1
400 C,E,JrM
*************** REPORTED ***************
93.3 3.31
(1978) (1976)
*************** ADJUSTED ***************
COLUMBUS & SOUTHERN OHIO ELEC.
CONESVILLE
5
411 B,C,J,M,T,X *************** REPORTED ***************
,Y 51 55.6 4.71 4.71
(1975) (1977)
C,E,J,M,S,U *************** ADJUSTED ***************
,W,Y 65 70.8 7.42 5.06 2.36
(1977) M977)
COST ELEMENTS
CAPITAL!
A - PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
D - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARTIAL INDIRECT CAPITAL COSTS INCLUDED
G • CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H - DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J - SLUDGE POND INCLUDED IN CAPITAL COST
K - ADDITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L - STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N • TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R * D COSTS INCLUDED IN CAPITAL COST
0 - COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R • EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUAL!
S • TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U • TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
H - OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
X • PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
Y • SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z • REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -
-------
UTILITY
STATION
UNIT(S)
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 197H
SECTION A-l FGD SYSTEM ECONOMICS: OPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
ELEMENTS
INCLUDED IN
CAPITAL AND
FGO MW ANNUAL COSTS
COLUMBUS & SOUTHERN OHIO ELEC. 411 B,C,J,M,T.X
CONESVILLE , Y
6
C,E,J,M,S,U
,W,Y
CAPACITY
FACTOR
Z
TOTAL
CAPITAL
S/KW
(YEAR)
ANNUAL - MILLS/KHH
TOTAL DIRECT
(YEAR)
FIXED
*************** REPORTED ***************
51 55.6
(1975)
*************** ADJUSTED ***************
65 70.8
(1977)
DUUUESNE LIGHT
ELRAMA POWER STATION
510 B,D,F,I,J,M
»T,V,X,Y
C,E,I,J,M,S
»U,Y
*************** REPORTED ***************
64 113.5 6.62 2.83 5.79
(1976) (1977)
*************** ADJUSTED ***************
65 127.3 7.81 3.36 4.U,W,Y
*************** REPORTED ***************
99.5
(1976)
*************** ADJUSTED ***************
65 100.6 6.56 3.57 2.99
(1977) (1977)
KANSAS CITY POWER * LIGHT
HAWTHORN
3
110 B,D,F,T,X
,u,w,x
*************** REPORTED ***************
14 29.3 8.40
(1972) (1977)
*************** ADJUSTED ***************
65 67.3 4.35 2.93 1.42
(1977) (1977)
COST ELEMENTS
CAPITAL:
A - PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
0 - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARTIAL INDIRECT CAPITAL COSTS INCLUDED
G - CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H - DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J • SLUDGE POND INCLUDED IN CAPITAL COST
K - ADDITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L • STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/UR FANS INCLUDED IN CAPITAL COST
N • TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R * D COSTS INCLUDED IN CAPITAL COST
0 • COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUAL:
S - TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U - TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
W - OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
X - PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
V - SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z • REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -21
-------
EPA UTILITY FGO SURVEY! OCTOBER 1978 - NOVEMBER 1978
SECTION A-l FGO SYSTEM ECONOMICS: OPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
ANNUAL - MILLS/KWH
UTILITY
STATION
UNIT(S)
FGD MM
ELEMENTS
INCLUDED IN
CAPITAL AND
ANNUAL COSTS
TOTAL
CAPACITY CAPITAL
FACTOR S/KK TOTAL DIRECT FIXED
X (YEAR) IYEAR)
KANSAS CITY POKER & LIGHT
HAHTHORN
4
110 B,D,F,T,X
B,C,E,J,K,S
,U,w,X
*************** REPORTED ***************
10 29.3 8.40
(1972) (1977)
*************** ADJUSTED ***************
65 87.3 4.35 2.93 1.42
(1977) (1977)
KANSAS CITY POWER & LIGHT
LA CYGNE
1
874 B,C,E,J,S
C,£,J,K,S,U
*************** REPORTED ***************
30 53.7 1.70 1.70
(1972) (1977)
*************** ADJUSTED ***************
65 60.0 3.76 1.70 d.06
(1977) (1977)
KENTUCKY UTILITIES
GREEN RIVER
1,2 ft 3
64 B,C,E,J,S,U *************** REPORTED ***************
,H 16 70.3 14.35 5.06 9.29
(1975) (197H
c,E,J,s,u,w *************** ADJUSTED ***************
65 77.6 5.24 2.71 2.53
(1977) (1977)
LOUISVILLE GAS
CANE RUN
4
& ELECTRIC
190 C.E,H,J,Q,T
C,E,H,J,K,Q
,S,U,W
*************** REPORTED ***************
55 66.6 2.75
(1975) (1977)
*************** ADJUSTED ***************
65 80.6 5.78 3.62 2.16
(1977) (1977)
LOUISVILLE GAS
CANE RUN
5
& ELECTRIC
200 C,E,H,J
»U,W
*************** REPORTED ***************
62.4
(1977)
*************** ADJUSTED ***************
65 67.5 5.56 3.47 2.09
(1977) (1977)
COST ELEMENTS
CAPITAL:
A - PARTICULATE CONTROL (REQUIRED FOR FGO PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C • TOTAL DIRECT CAPITAL COSTS INCLUDED
0 - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARTIAL INDIRECT CAPITAL COSTS INCLUDED
6 - CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H • DRV SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I • OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J - SLUDGE POND INCLUDED IN CAPITAL COST
K - AODITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L - STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N • TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R & D COSTS INCLUDED IN CAPITAL COST
0 - COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL CUST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUALS
S - TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U - TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
M - OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
X - PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
V - SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z - REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -22
-------
UTILITY
STATION
UNIT(S)
EPA UTILITY FGO SURVE": OCTOBER 1978 - NOVtMHtK 1976
SECTION A-l FGO SYSTEM ECONOMICS: OPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
ANNUAL - MILLS/KrtH
ELEMENTS
INCLUDED IN
CAPITAL AND
FGO MW ANNUAL COSTS
LOUISVILLE GAS & ELECTRIC
PADDYS RUN
6
70 C,E
C,E,S,U,W
TOTAL
CAPACITY CAPITAL
FACTOR S/KW TOTAL DIHtCT FIXED
X (YEAR) CYEAK)
*************** REPORTED ***************
52.9
11973)
*************** ADJUSTED ***************
65 76.5 b.51 3.9d 2.59
(1977) (1977)
MINNKOTA POWER COOPERATIVE
MILTON R. YOUNG
a
177 C,E,H,P
C,E,H,M,P,S
*************** KEPORTED ***************
86. 0
(1976)
*************** ADJUSTED ***************
65 93.1 5.16 1.85 3.M
(1977) (1977)
MONTANA POWER
COLSTRIP
1
330 B,C,E,J,P,T
C,ErJ»K,P,S
*************** KEPORTED ***************
76 77.1 .27 .27
(1975) (1977)
*************** ADJUSTED ***************
65 77.3 4.06 1.51 ci.55
(1977) (1977)
MONTANA POWER
COLSTRIP
330 B,C,E,J,P,T
C,E,J,K,P,S
»U,W
*************** REPORTED ***************
76 77.1 .27 .27
(1975) (1977)
*************** ADJUSTED ***************
65 77.3 4.06 1.51 2.55
(1977) (1977)
NEVADA POWER
REID GARDNER
1
125 B,0,E,P,S,U
fW,X
B,C,E,J,P,S
,U,W,X
*************** REPORTED ***************
67 42.9 2.10 1.30 .t>0
(1973) (1977)
*************** ADJUSTED ***************
65 60.9 3.20 1.30 1.90
(1977) (1977)
COST ELEMENTS
CAPITAL:
A - PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
D - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARTIAL INDIRECT CAPITAL COSTS INCLUDED
G - CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H - DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J - SLUDGE POND INCLUDED IN CAPITAL COST
K - ADDITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L - STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N - TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R * D COSTS INCLUDED IN CAPITAL COST
0 • COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUALS
3 - TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U • TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
M - OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
x • PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
V - SLU06E DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z - REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -83
-------
EPA UTILITY FGD SURVEY: OCTOBER 1976 - NOVEMBER 1978
SECTION A-l FGO SYSTEM ECONOMICS: OPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
UTILITY
STATION
UNIT(S)
ELEMENTS TOTAL ANNUAL - MILLS/KWH
INCLUDED IN CAPACITY CAPITAL
CAPITAL AND FACTOR S/KW TOTAL DIKECT FIXED
FGD MM ANNUAL COSTS X (YEAR) IYEAR)
NEVADA POWER
REID GARDNER
2
125 BfDfErPfS>U *************** REPORTED ***************
,W,X 67 42.9 2.10 1.30 .80
(1973) (1977)
B*C«ErJ,P,S *************** ADJUSTED ***************
,U,H,X 65 60.9 3.20 1.30 l.<*0
(1977) (1977)
NEVADA POWER
REID GARDNER
3
12S B,C,E,L,S,U
B,C,E,S,U,W
*************** REPORTED ***************
67 113.6 2.10 1.30 .00
(1975) (1977)
*************** ADJUSTED ***************
65 107.9 4.30 1.30 3.00
(1977) (1977)
NORTHERN INDIANA PUB SERVICE
DEAN H. MITCHELL
11
92 B,CrE,L,N,S
,U,W,X,Z
C,E,L,N,S,U
»H,Z
*************** REPORTED ***************
77 156.9 14.86 6.47 8.39
(1976) (1976)
*************** ADJUSTED ***************
65 145.5 12.73 7.54 5.19
(1977) (1977)
NORTHERN STATES POWER
SHERBURNE
1
720 B,C,J,S,U,X
,Z
C,E,J,K,S,U
rW
*************** REROUTED ***************
73 47.9 1.99 1.06 .93
(1972) (1977)
*************** ADJUSTED ***************
65 71.5 2.77 .75 2.02
(1977) (1977)
NORTHERN STATES POWER
SHERBURNE
2
720 B,C,J,S,U,X
,Z
C,E,J,K,S,U
iW
*************** REPORTED ***************
73 47.9 1.99 1.06 .93
(1972) (1977)
*************** ADJUSTED ***************
65 71.5 2.77 .75 2.02
(1977) (1977)
COST ELEMENTS
CAPITAL: . . .
A - PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
0 - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARTIAL INDIRECT CAPITAL COSTS INCLUDED
6 - CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H - DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J - SLUDGE POND INCLUDED IN CAPITAL COST
K - ADDITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L - STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N - TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P • R * 0 COSTS INCLUDED IN CAPITAL COST
0 - COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUALS
8 • TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U • TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
H - OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
X » PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
V - SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z • REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -24
-------
UTILITY
STATION
UNIT(S)
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBER 1978
SECTION A-l FGD SYSTEM ECONOMICS: OPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
ELEMENTS
INCLUDED IN
CAPITAL AND
FGD MW ANNUAL COSTS
PENNSYLVANIA POWER
BRUCE MANSFIELD
1
917
B,C,E,G,I,L
,S,U,W,X
p I ? M * S
fU,W
CAPACITY
FACTOR
X
TOTAL
CAPITAL
S/KW
(YEAH)
ANNUAL - MILLS/KWH
TOTAL DIRECT
(YEAH)
FIXED
*************** REPORTED ***************
40
11.34
4.08
(1977)
120.7
(1975)
*************** ADJUSTED *******
65 102.1 8.68 5.51
(1977) (1977)
10.26
3.17
PENNSYLVANIA POWER
BRUCE MANSFIELD
2
917 B,C,E,G,I,L *************** REPORTED ***************
,S,U,W,X 40 120.7 14.34 4.08 10.26
(1975) (1977)
C,E,G,I,M,S *************** ADJUSTED ***************
'U'H 65 102.1 8.68 5.51 3.17
(1977) (1977)
PHILADELPHIA ELECTRIC
EODYSTONE
1A
105 D,F,N,P
C,E,N,P
*************** REPORTED ***************
156.8
(1972)
*************** ADJUSTED ***************
233.3
(1977)
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN
i
357 A,C,E,N
*************** REPORTED ***************
127.9
(1977)
*************** ADJUSTED ***************
PUBLIC SERVICE OF NEW MEXICO
SAN JUAN
2
357 A,C,E,N
*************** REPORTED ***************
127.9
(1977)
*************** ADJUSTED ***************
COST ELEMENTS
CAPITAL:
A - PARTICULAR CONTROL (REQUIRED FUR F6D PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
D - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E • TOTAL INDIRECT CAPITAL COSTS INCLUDED
F • PARTIAL INDIRECT CAPITAL COSTS INCLUDED
6 - CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H - DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J - SLUDGE POND INCLUDED IN CAPITAL COST
K - AOOITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L - STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N - TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R S 0 COSTS INCLUDED IN CAPITAL COST
Q - COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUAL:
S - TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U - TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
N - OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
X - PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
Y - SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
2 - REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -25
-------
EPA UTILITY FGD SURVEYS OCTOBER 1978 - NOVEMBER 1976
SECTION A-l FGO SYSTEM ECONOMICS: OPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
ANNUAL - MILLS/KWH
UTILITY
STATION
UNIT(S)
FGD MW
ELEMENTS
INCLUDED IN
CAPITAL AND
ANNUAL COSTS
TOTAL
CAPACITY CAPITAL
FACTOR S/KW TOTAL DIKECT FIXED
X (YEAR) (YEAR)
SOUTH CAROLINA PUBLIC SERVICE
WINY AH
2
140 C,F,J,M,S,V
,u,w
*************** KEPOKTtD ***************
ao 47.5 i.bi .«8 .73
(1976) (1977)
*************** ADJUSTED ***************
65 66.5 2.92 1.04 l.dtt
(1977) (1977)
SOUTHERN MISSISSIPPI ELECTRIC
R. D. MORROW
1
160
CrE
*************** REROUTED ***************
37.4
(1975)
*************** ADJUSTED ***************
SPRINGFIELD CITY UTILITIES
SOUTHWEST
1
194 C,F,H,J,P
C,E,H,J,K,P
*************** REPORTED ***************
77.3
(1974)
*************** ADJUSTED ***************
65 117.7 6.17 2.87 3.30
(1977) (1977)
TENNESSEE VALLEY AUTHORITY
NIOONS CREEK
6
550 B,C,E,P,R,T
,U
C,E,J,S,U,W
*************** REPORTED ***************
60 98.2 2.99
(1976) (1977)
*************** ADJUSTED ***************
65 113.2 5.28 1.44 3.84
(1977) (1977)
TEXAS UTILITIES
MONTICELLO
3
750
*************** REPORTED ***************
25.0
(1978)
*************** ADJUSTED ***************
COST ELEMENTS
CAPITAL:
A - PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B • PARTICULATE CONTROL (INCLUDED IN FGO PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
D - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F • PARTIAL INDIRECT CAPITAL COSTS INCLUDED
G • CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H - DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J • SLUDGE POND INCLUDED IN CAPITAL COST
K • ADDITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L • STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N • TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 • PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R » D COSTS INCLUDED IN CAPITAL COST
0 • COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R • EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUAL I
8 - TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U • TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
N - OVERHEAD C08T8 INCLUDED IN TOTAL ANNUAL COSTS
X - PARTICULATE CONTROL C08T8 INCLUDED IN DIRECT ANNUAL COSTS
Y - 8LUD6E DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z • REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -26
-------
UTILITY
STATION
UNIT(S)
EPA UTILITY FGO SURVEY: OCTOBER 1978 - NOVEMBER 197«
SECTION A-a FGD SYSTEM ECONOMICS: NONOPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
ANNUAL - MILLS/KWH
FIXED
ELEMENTS
INCLUDED IN
CAPITAL AND
FGD MW ANNUAL COSTS
ALABAMA ELECTRIC COOP
TOMBIGBEE
3
ass C.E.J
TOTAL
CAPACITY CAPITAL
FACTOR S/Kn TOTAL
X (YEAR) (YEAR)
*************** KEPURTED ***************
69.5
(197tt)
ARIZONA ELECTRIC POWER COOP
APACHE
3
200 B,C
*************** KEPORTED ***************
5.3
(1978)
BASIN ELECTRIC POWER COOP
LARAHIE RIVER
1
550 C,E
*************** REPORTED ***************
68.a
(1980)
BASIN ELECTRIC POWER COOP
LARAMIE RIVER
2
550
C,E
*************** REPORTED ***************
68.a
(198U)
BIG RIVERS ELECTRIC
GREEN
i
250 B,C
*************** REPORTED ***************
43.3
(1976)
BOSTON EDISON
MYSTIC
6
155 B,C,E,N,0
*************** REPORTED ***************
63.1 3.00
(1972) (1971)
CENTRAL ILLINOIS PUBLIC SERV
NENTON
i
575 C,E,G
*************** REPORTED ***************
189. 0
(1979)
COLORADO UTE ELECTRIC ASSN.
CRAIG
1
450 B,D,E
*************** REPORTED ***************
117.0
(1979)
COST ELEMENTS
CAPITAL! . .
A • PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
D - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARITAL INDIRECT CAPITAL COSTS INCLUDED
6 • CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H • DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I • OFF-BITE LANDFILL AREA INCLUDED IN CAPITAL COST
J • SLUDGE POND INCLUDED IN CAPITAL COST
K - AOOITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L • STACK INCLUDED IN CAPITAL COST
H • MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N - TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P • R t D COSTS INCLUDED IN CAPITAL COST
0 - COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUAL!
S •
T •
U •
V •
N •
X
TOTAL DIRECT ANNUAL COSTS INCLUDED
PARTIAL DIRECT ANNUAL COSTS INCLUDED
TOTAL FIXED ANNUAL COSTS INCLUDED
PARTIAL FIXED ANNUAL COSTS INCLUDED
OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
V . SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z - REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -27
-------
EP» UTILITY F60 SURVEY: OCTOBER 1976 - NOVEMBER 1978
SECTION A-2 FGD SYSTEM ECONOMICS: NONOPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
ANNUAL - MILLS/KWH
UTILITY
STATION
UNIT(S)
ELEMENTS
INCLUDED IN
CAPITAL AND
FGD MM ANNUAL COSTS
TOTAL
CAPACITY CAPITAL — ——
FACTOR S/KW TCHAL DIHECT FIXED
X (YEAR) (YEAR)
COLORADO UTE ELECTRIC ASSN.
CRAIG
2
450
A,C
*************** REPORTED ***************
117.0
(1979)
COMMONWEALTH EDISON
POWERTON
SI
425 C,E,H,J
*************** REPORTED ***************
117.7
(1979)
COMMONWEALTH EDISON
WILL COUNTY
1
167 B,C,E,G,J,X
*************** REPORTED ***************
49 113.0 13.06
(1972) (1975)
DETROIT EDISON
ST. CLAIR
6
163 B,C,E,J,M,X
*************** REPORTED ***************
80.3 9.60
(1976) (1976)
ILLINOIS POWER
HOOD RIVER
4
110 A,CrE,M,N
*************** REPORTED ***************
82.5
(1972)
LOUISVILLE GAS
CANE RUN
6
ft ELECTRIC
277 C»E»H,M,S,V *************** REPORTED ***************
,W 57.9 3.24 1.92 1.32
(1977) (1979)
PACIFIC POWER
JIM BRIDGER
4
& LIGHT
509 C,E,J
*************** REPORTED ***************
120.0
(1979)
POTOMAC ELECTRIC POWER
OICKERSON
3
190 A,C,E,M
*************** REPORTED
68.0
(1973)
***************
COST ELEMENTS
CAPITAL:
A - PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B - PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
D • PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARITAL INDIRECT CAPITAL COSTS INCLUDED
G - CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H • DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J - SLUDGE POND INCLUDED IN CAPITAL COST
K - AODITONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L - STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N • TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R * D COSTS INCLUDED IN CAPITAL COST
Q - COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUAL:
8 - TOTAL DIRECT ANNUAL COSTS INCLUDED
T - PARTIAL DIRECT ANNUAL COSTS INCLUDED
U • TOTAL FIXED ANNUAL COSTS INCLUDED
V - PARTIAL FIXED ANNUAL COSTS INCLUDED
W • OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
X - PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
V - SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z - REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -26
-------
EPA UTILITY FGD SURVEY: OCTOBER 1978 - NOVEMBEK 197a
SECTION A-2 F60 SYSTEM ECONOMICS: NONOPERATIONAL SYSTEMS
REPORTED AND ADJUSTED COSTS
UTILITY
STATION
UNIT(S)
ELEMENTS
INCLUDED IN
CAPITAL AND
FGD MN ANNUAL COSTS
PUBLIC SERVICE OF COLORADO
VALMONT
50 B,C,E,J
TOTAL ANNUAL - MILLS/KWH
CAPACITY CAPITAL .
FACTOR S/KW TOTAL DIRECT FIXEU
X (YEAR) (YEAR)
*************** REPORTED ***************
67.0
(1974)
SALT RIVER PROJECT
CORONADO
1
350 C,E
*************** REPORTED ***************
96.0
C1978)
SALT RIVER PROJECT
CORONADO
2
350 C,E
*************** REPORTED ***************
98.0
(197B)
SOUTHERN INDIANA GAS ft ELEC
A. B. BROWN
1
250 C,E,G
*************** REPORTED ***************
43.2
(1979)
SOUTHERN MISSISSIPPI ELECTRIC
R. 0. MORROW
2
160 C,E
*************** REPORTED ***************
37.4
(1975)
WISCONSIN PONER I LIGHT
COLUMBIA
2
527
*************** REPORTED ***************
57.0
(1980)
COST ELEMENTS
CAPITAL*
A - PARTICULATE CONTROL (REQUIRED FOR FGD PROCESS) INCLUDED IN CAPITAL COST
B • PARTICULATE CONTROL (INCLUDED IN FGD PROCESS) INCLUDED IN CAPITAL COST
C - TOTAL DIRECT CAPITAL COSTS INCLUDED
0 - PARTIAL DIRECT CAPITAL COSTS INCLUDED
E - TOTAL INDIRECT CAPITAL COSTS INCLUDED
F - PARITAL INDIRECT CAPITAL COSTS INCLUDED
6 - CHEMICAL FIXATION OF SLUDGE INCLUDED IN CAPITAL COST
H - DRY SLUDGE DISPOSAL INCLUDED IN CAPITAL COST
I - OFF-SITE LANDFILL AREA INCLUDED IN CAPITAL COST
J - SLUDGE POND INCLUDED IN CAPITAL COST
K - AD01TONAL SLUDGE DISPOSAL CAPACITY ADDED FOR LIFE OF SYSTEM
L • STACK INCLUDED IN CAPITAL COST
M - MODIFICATIONS TO STACK, DUCTS, AND/OR FANS INCLUDED IN CAPITAL COST
N - TOTAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
0 - PARTIAL REGENERATION FACILITY COST INCLUDED IN CAPITAL COST
P - R & D COSTS INCLUDED IN CAPITAL COST
0 - COSTS UNDERWRITTEN BY SYSTEM SUPPLIER INCLUDED IN CAPITAL COST
R - EXCESS REAGENT SUPPLY COSTS INCLUDED IN CAPITAL COST
ANNUAL!
3
T
U
V
TOTAL DIRECT ANNUAL COSTS INCLUDED
- PARTIAL DIRECT ANNUAL COSTS INCLUDED
- TOTAL FIXED ANNUAL COSTS INCLUDED
• PARTIAL FIXED ANNUAL COSTS INCLUDED
W - OVERHEAD COSTS INCLUDED IN TOTAL ANNUAL COSTS
X • PARTICULATE CONTROL COSTS INCLUDED IN DIRECT ANNUAL COSTS
V - SLUDGE DISPOSAL SERVICE COSTS (CONTRACT) INCLUDED IN DIRECT ANNUAL COSTS
Z - REPLACEMENT ENERGY COSTS INCLUDED IN DIRECT ANNUAL COSTS
A -29
-------
APPENDIX B
FGD PROCESS FLOW DIAGRAMS
THIS APPENDIX COMPRISES BOTH ACTIVE AND INACTIVE UNITS
ARRANGED ALPHABETICALLY ACCORDING TO UTILITY
"SUPPLEMENTAL EDITION"
CHANGES/ADDITIONS
B-l
-------
run •«
ran nun
(Wit t)
STfttt
00
IM
I— HUM MTtt-
PWWS
(THttE TOTtt.)
siuwr
TO WIT 3
IIKSTOK MIMRT rum
(no TOTAI)
SCMKI WttU
STOMU row
Alabama Electric,
Simplified Process Flow Diagram for Tomblgbee 2
-------
00
I
I*)
Niovm
SI
Mil MO IMI j
KM IKMMHI '
£A SAfMVMCI '
"" pH SSBKh
1 IfMTICUlATf XXXjQ
I ISCIUMU
1 j
MWU * |[
M»TU
LMSTM tl»WT MOW |
Jj
inn
^f
L.
i
1M
>
1.1
N
•0
—
»T«a
rt
TM
s
1
1
S
(
s
*•
STUN
;>
<
1
Wiaim.
A rui
S*. MSMMI Jfci "•«*».
_ ^ Hosni toiuaiM
[ 1
, fMTiaMTtl I
.-- SCMMtl 1 1
^^" ^ ^~»^J
^r -~itT i
rSii"*
* *
I SUM! TDM 1 1 SUKI TMK 1
i
KM
Arizona Public Service, Choila 1
Simplified Process Flow Diagram
-------
I *jj cumriti
r v
net
in
an
MU
DILI
Central Illinois Light,
Simplified Process Flow Diagram of Duck Creek 1
Power Plant and Emission Control System
-------
CO
I
in
TO STACK - aUE GASES
HIST ELIMINATOR
STORAGE
SERVICE
ttVTER
SLURRY
TRANSFER
TANK
*-4
SLURRY
STORAGE
TANK
^
D
RECYCLE TANK
TO OTHER
RECYCLE TANK
SUMP
- OVERFIOM
TO ASH POND
FROM OTHER
- RECYCLE TANK
TO IOCS
Columbus and Southern Ohio Electric, Conesville 5 and 6
Simplified Process Flow Diagram for a Riven Module
-------
CD
I
O>
JET BUBBLING REACTOR
WATER
—-"""-'^V •...-—." ff-. ~^>"—
- ..--^ **s,-.-. ••' -//- --- y-
' -^ s*1"' . -^X'/
Gulf Power, Scholz 1 and 2
Prototype FGD System,
Simplified Process Flow Diagram
-------
00
-J
ABSORBER
REJCIRCULATION
ENTUR1
SCRUBBER
VENTURI
RECIRCULATION
PUMPS
RECIRCULATIO
TANKS
HYOROCLONE
CLASSIFIER
LIMESTONE
BUNKER
LIMESTONE
SLURRY .
STORAGE^
BOILER
SETTLING POND
WET BALL
MILL
Kansas City Power and Light,
LaCygne 1 FGD System: General Diagram
-------
FURNACE
DAMPERS
•3*
00
TWO PRECIPITATORS
FOUR 1.0. FANS
ONE
STACK
WATER RETURN TO
REACTION TANKS
BLEED PUMP
RANSFER TANK
FOUR,
REACTION
TANKS
SLUDGE DISPOSAL
POND
Kansas Power and Light,
Schematic of Jeffrey Steam Generator and Emission Control Equipment
-------
STACK
50
I
£>
COAL SUPPLY-
FEEDER
PULVERIZER
I.D. FAN
STACK GAS
IR HEATER
DEMISTER
TACK GAS REHEATER
RECYCLE
WATER
STACK'
GAS
SCRUBBER
Kansas Power and Light
Original Operational FGD System at Lawrence No. 4.
-------
\
V
ItMl
•tn m
B.UMTIK
4 KM.MK
f*VHM
C-lll
MOITin
TIMRrtt
(0
IMSTOtt
««n
nmm
«ulltg>
••* mn
mm
0
MoiTin noMtt
TN* M KHIOS
/
OIIUTKH WTC1
KCIKUUTIIft TM»)
MOITIM
MIUTIM
TNK
HTlfl
"III
&«MT
Mourn
no«Au
MVS
i
t>
ONE OF TWO NODULES
Vnvw*
KtUUft
NDOUIC
r-
T
f
/
ADDITIVE
(FROM NILL)
/
0 ST¥* O
\J
BVPAS
IUE GAS FROl
UR PREHEATER
1
i
1'
l*_
C^~ c
IOOITIVE
OUTLET!
1.0. FANS (Z) 1 —
, j' ' L
• ' . » j i \i i
XL 1
INLET \ i
DAMPER I
F
mm Jj.
ROD SCRUBBER kl-L
SPRAY PUNP ,! RE
O 1 °~ w
1ST
, ADDITIVE
STORAGE TANK
EFF
REHEATER
REHEATER BLOHER
ABSORBEI
_NIST ELtmNATOR
BLOMEK
STRAINER HASHER
(TYP.)
TANK
I
MMBCf*!
PUVS(Z)
STRAINER HASH
LINE (TYP.)
ABSORBER
SPRAY PUMP
BLEED
|
Kansas Power and Light,
Lawrence No. 4 Operational FGD System
Simplified Process Flow Diagram
-------
STACK
OWL SUPPLY-
FEEDER—ft*
PULVERIZER
•I.D. FAN
•STACK GAS REHEATER
RECYCLE
WATER
STACK'
GAS
SCRUBBER
Kansas Power and Light
Original FGD System Installed at Lawrence No. 5:
Simplified Process Flow Diagram.
-------
unnni
•— »|9<
iiunm MTU
oo
i
_^
INJ
n
STACK I PONO RETURN
1 (MAKE-UP)
1 HATER
HASH
PUMP
'TO STRAINER I
1 HASHERS"^
IHAKE-UP HATER
lECIftC
TANK
RECIRC4
PUMPS
EFFLUENT
BLEED
IHEIR
THICKENER rOVERFLOM
|^gl] »-5ETTL
THICKENER POHI
SETTLING
PONO
UNOCRFLOH PUMPS
Kansas Power and Light,
Lawrence No. 5 Operational FGD System
Simplified Process Flow Diagram
-------
09
CO
ELECTRICAL
GENERATING
UNIT NO. 1
ELECTRICAL
GENERATING
UNIT NO. 2
MECHANICAL
COLLECTORS
EXISTING
STACK
K>fl ™
BYPASS
SCRUBBER
BOOSTER
FAN
MAKEUP MATER
MAKEUP MATER
RECYCLE r^ MIX/HOLD TANK
SPARE
SPARE
Kentucky Utilities,
Green River FGD System: General Process Diagram
-------
QUENCHER
HIST
ELIHINATOR
(CHEVRON)
CONTACTOR
SCRUBBFR
MODULE
ELECTROSTATIC
PRECIPITATOR
BOILER
FLUE
6AS
REACTION
TANK
CONTACTOR
SCRUBBER
MODULE
ABSORBER
RECYCLE
FAN
MIST
ELIHINATOR
(CHEVRON)
I
FLOCCUIANT
ADDITION
THICKENER
T
,___Ly-l_
\ SETTLING / POND WATER RETURN
\ POND /
S.URGE '
TANK
Louisville Gas and Electric, Cane Run 4
FGD System: Simplified Process Flow Diagram
-------
REAGENT
•»TO STACK
ELECTROSTATIC
PRECIP1TATOR
DO
I
BOILER
FLUE -
GAS
-STEAM
REHEAT
SPRAY
TOWER
LIME SLURRY
FEED PUMP
\ \
REACTION
TANK
— 1
RECYCLE
PUMP
r*
i-
,
THK
/
Louisville Gas and Electric, Cane Run 5 FGD System:
Simplified Process Flow Diagram
-------
CD
i
ot
EMERGENCY WATER
PLENUM
• BLEED ^
MIST
ELIMINATORS
-MXEAN FLUE GAS
00-SEAL WATER SUPPLY
JJNpERSPRAY MAKEUP
WATER
POND
IETURN
WASH TRAY POND
FLY ASH POND
Montana Power, Col strip F6D System:
General Process Flow Diagram
-------
TO CNIMCY
MLVERIZCR
00
i
EVAPORATION ram
ON MESA
NUNMICM.
OUST
COLLECTOR
(NULTICLONES]
REHEATER AIR FAN
•OILER
1.0. FAN
*—i—ri
TRAY RECYCLE PUMP
SODA ASH
THIN
VENTURI
THROAT
SCRUBBER
VENTURI RECYCLE
PUMP
fURGC
TO ASH POND
SODA ASM
SLURRY PUMP
Nevada Power, Reid Gardner 1,2, and 3
General Process Flow Diagram for One of the FGD Systems
-------
FLUE GAS
TO
SCRUBBER
REHEATER
LIMESTONE —i
CO
i
00
MIST
ELIMINATOR
OVERFLOW POTS
AND MARBLE BED
I.I
THICKENER
UNDERFLOW
PUMP
ASH POND
RETURN PUMP
Northern States Power, Sherburne 1 and 2 FGD System:
Simplified Process Flow Diagram
-------
TMMIII NOUU I
00
I
Uttl.b*
n
mxiwuu
•mi
Pennsylvania Power, Bruce Mansfield FGD System:
Process Flow Diagram for Unit 1 or 2
-------
r\>
o
LIMESTONE
FEED UN
(OK IN USE
FOR WO
•OILERS)
MIST
I rwr
(ONE IN USE
ONE SPAKE)
I
VENTURI SOWER
SCRUMERTN
(ONE IN USE)
MSUP MATER
HIST
ELININA'
TANK (ONE
wIN USE)
,1
I
j
1.0. FAN
(WO IN UK)
NEW mm
(OK IN USE)
NET CYCLONE
CLASSIFIER
HETIALLNUL
(ONE IN USE)
HILL SLURRY
TANK IMC
(ORE IRUSE)lgii
mi
(ONE IN USE)
I
. MXER
(ONE IN USE)
FROM THICKENER
SLURRY STORA6E
g^m TMNK
(ONE IN USE)
SLURRY
PIMP
(ONE IN USE
ONE SPARE)
RECYCLE TANK
(ONE IN USE)
"*
THICKENER
SUPPLY
(ONE IN USE)
PUNP
ONE IN USE
ONE SPARE)
(TNO IN USE
ONE SPARE)
Southern Mississippi Electric R.D. Morrow 1,
Simplified Process Flow Diagram
-------
SCRUBBER INLET
TEST PORT LOCATION
•B" ABSORBER
NODULE
TOP OF STACK
ELEVATION 1645*
TEST PORT
ELEVATION 1516'
PRECIPITATOR
INLET TEST
PORT LOCATION
00
INS
I—TOP OF OUTLET BREECHING
ELEVATION 1372'-2 3/8"
L-TOP OF BYPASS BREECHING
ELEVATION 1307'- 8 1/2"
SCRUBBER INLET
TEST PORT LOCATION
Springfield City Utilities, Southwest No. 1:
Simplified Process Diagram
-------
REHEATER
CO
ro
TNJ
"_"_ ITRAINS
*~~* IB,C, AND D
ENTRAINMENT
SEPARATOR
TO TRAINS
B.C. AND D
IjH
S7]
(T^
SLURRY PUMP
SEAL HATER
. HEADER
' »J •
o
FROM B. C. AND D TRAIN
VENTURI CIRCULATION TANKSI
TO SETTLING POND _
VENTURI
CIRCULATION
TANK AND
PUMPS
ABSORBER
CIRCULATION
TANK AND
PUMPS
— RIVER HATER
^* PUMPS f
FROM POND HATER
RECYCLE PUMPS
FROH LIMESTONE SLURRY
I TRANSFER PUMPS
EFFLUENT SLURRY
SURGE TANK AND PUMPS
TO TRAINS / *
B.C. AND DK
LIMESTONE SLURRY
FEED PUMPS
LIMESTONE SLURRY
STORAGE TANK
Tennessee Valley Authority, Widows Creek 8 FGD System:
Process Flow Diagram for One of the Four Scrubber Trains
-------
FM OUTLET
FMNMIIEII
AIR PREHEATERS
ro
CO
PIMP SEAL
MATER TO
QUENCHER
euwppiM PUMPS
INF R US
PUMP SEAL IMTER.
•All Mill COOL INS
AND HOSE STATIONS
H.TA»
MAKEUP HATER TO
HMtSTONE AREA
SERVICE MUTER
(LAKE WATER)
ASH POND
RCTUM HATER
(RECTCLE MATER)
| SOLIDS |
\XTe^=^^OO
Texas Utilities,
Simplified Process Flow Diagram for One of the Two Identical
Martin Lake FGD Systems
-------
00
PRECIPITATORS
LIMESTONE STORAGE
UL
TO SPRAY TOHER 301
TP SPRAY TOHER 301
TO SPRAY TOHER 201
LIMESTONE
STORAGE
UN
LIMESTONE GRINDING
SYSTEM
TANK AGITATOR
IYPASS
TO SPRAY TOUER 301
TO SPRAY TOHER 201
BYPASS
FROM SPRAY TOUER 301
FROM SPRAY TOUER 201
ID
TANS
301 -
301 •
d
ME* Ml
NEK 201
ma
I*
LURRY
TOR
MATCH
M
m
r
— •
=7
MM
I
N
ELIH
i
ST
NA
X
TOR
1
.LIMESTONE
.S SLURRY
*~I IMWM
^ s.
iNf
" " *
^ *• ^ •
• •* •
" • ~* •*
• V W W
SWAT TOMER
n ""
J /
RHITTENT
PRAYS
j
SP
Arn
ASH
OVERFLOH
l"
RAY
UER
rATI
•i
I
i
NTST CLIHINATC
HASH HATER
TO SPRAY TO
~\
__ SEWICE HATE*
»
HER 201
FRO
4 SPRAY TOM
TO SPRAY TOUER 301 FROM SPRAY TOMER j
^.TOHER DRAIN TO
DISPOSAL
R
1 SPRAY TOHER
RECYCLE PIMP
TOTAL PUMP SI
— INSTRtWCNT PI
SO, REHOVAL
r- SUMP PUH
J
EALS AND
URGE HATER
) ASH
PONO
AREA
PS
FROM ASH m
RETENTION 1
TO ASH AREA
LIMESTONE
SLURRY
TANK
S02 REHOVAL AREA SUMP
Texas Utilities,
Simplified Process Flow Diagram for Monticello 3
-------
APPENDIX C
DEFINITIONS
01
-------
DEFINITIONS
Boiler Capacity Factor:
Boiler Utilization Parameter
Efficiency:
Particulates
SO.
FGD Viability Indexes
(KWh generation in year)/
maximum continuous generating
capacity in kW x 8760 hr/yr).
Hours boiler operated/hours in
period, expressed as a percen-
tage.
The actual percentage of
particulates removed by the
emission control system (mech-
anical collectors, ESP, or
fabric filter and FGD) from
the untreated flue gas.
The actual percentage of SO,
removed from the flue gas by
the FGD system. Design removal
efficiency values are presented
for nonoperational systems for
which actual removal data are
not available.
Several parameters have been
developed to quantify the
viability of FGD system tech-
nology. Various terms such as
"availability," "reliability,"
"operability," and "utilization
are used to accurately repre-
sent the operation of any FGD
system during a given period.
The above-mentioned parameters
are defined below and dis-
cussed briefly. The objectives
of this discussion are to make
the reader aware that several
different definitions are
being used and to select
appropriate parameters that
can be used for reporting
purposes so that reasonably
consistent comparisons can be
made.
C-2
-------
DEFINITIONS
Availability Index
Reliability Index
PGD Operability Index
Hours the PGD system is avail-
able for operation (whether
operated or not) divide*..- by
hours in period, expressed as
a percentage. This parameter
tends to overestimate th>-
viability of the FGD system
because it does not pen. lize
for election not ro operate
the system when it could have
been operated. Boiler down-
time nay tend to increase the
magnitude ot the parameter
because FGD failures generally
cannot occur during such
periods.
Hours the FGD system was
operated divided by the hour;
the FGD system was called upon
to operate, expressed ar i
percentage. This parameter
has been developed in orcer
not to penalize the FCL
system for elected outaqes,
e.q., periods when th*..- FGD
system could have been run but
was not run because of ch<-'«ui-
cal shortages, lack of manpower,
short duration boiler operations,
etc. The main problem in
using this formula is thr-
concise determination whether
or not the system was "called
upon to operate" during a
given time period. In addition,
an undefined value can result
when the FGD system is not
called upon to operate for a
given period (e.g., turbine or
boiler outage when FGD system
is available).
Hours the FGD system was opera-
ted divided by boiler operating
hours in period, expressed as
a percentage. This parameter
indicates the degree to which
the FGD system is actually
usedi relative to boiler
C-3
-------
FGD Utilization Index
FGD Status:
Category 1
Category 2
Category 3
operating time. The parameter
does not reflect the extent of
exertion on the FGD system,
that is, the magnitude of the
parameter has little or no
correlation with FGD system
operating time. Also, the
parameter is penalized when
options are exercised not to
use the FGD system in periods
when the system is operable.
In addition, an undefined
value can result when the FGD
system is not called upon to
operate for a given period
(e.g., turbine or boiler
outage when FGD system is
available).
Hours that the FGD system
operated divided by total hours
in period. This parameter is
a relative stress factor for
the FGD system. It is not a
complete measure of FGD system
viability because the para-
meter can be strongly influ-
enced by conditions that are
external to the FGD system
(e.g., infrequent boiler
operation will lower the value
of the parameter although the
FGD system may be highly
dependable in its particular
application).
Operational - FGD system is in
service removing SO2.
Under Construction - ground
has been broken for installa-
tion of FGD system, but FGD
system has not become opera-
tional.
Planned, Contract Awarded -
contract has been signed for
purchase of FGD system but
ground has not been broken for
installation.
C-4
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Category 4
Category 5
Category 6
Category 7
Category 8
FGD Vendor
Fuel Characteristics
New
Nonregenerable
Planned, Letter of Intent
Signed - letter of intent has
been signed, but legal con-
tract for purchase has not
been awarded.
Planned, Requesting/Evaluating
Bids - bid requests have been
released but no letter of
intent or contract has been
issued.
Considering only FGD Systems -
an FGD system is proposed as a
means to meet an SO- regula-
tion.
Considering an FGD system as
well as alternative methods.
Nonoperational - FGD system
has been in service in the
past but has been shut down
permanently or for an extended
indefinite period of time.
A firm which fabricates and
supplies FGD systems, most
notably the flue gas treating
and ancillary equipment.
Type of fuel, average gross
heating value in Btu/lb.
average percent ash and average
percent sulfur content for
fuel as fired.
FGD unit and boiler were
designed at the same time or
space for addition of an FGD
unit was reserved when boiler
was constructed.
The S02 removed from the flue
gas is not recovered in a
usable or marketable form and
resulting sulfur-bearing waste
products must be disposed in
an environmentally acceptable
fashion.
C-5
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Operational Experience
Process
Regulatory Class
Regenerable
Retrofit
Sludge Disposal
C-6
Summary of FGD status and
description of current month's
progress.
Company name if process is
patented. Generic name if
several companies have similar
processes.
A. New boiler constructed
subject to Federal New
Source Performance Stan-
dards.
B. Existing boiler subject
to State Standard that is
more stringent than the
Federal New Source Per-
formance Standard (NSPS).
C. Existing boiler subject
to State Standard that is
equal to or less strin-
gent than NSPS.
D. Other (unknown, undeter-
mined) .
The SO2 removed from the flue
gas is recovered in a usable
or marketable form (e.g.,
sulfur, sulfuric acid, gypsum,
ammonium sulfate, sodium
sulfate).
FGD unit must be added to an
existing boiler not specifi-
cally designed to accommodate
FGD unit.
Disposal method for nonregen-
erable systems producing
sludge including: lined
or unlined ponds, stabilized
or unstabilized sludge, and
on- or off-site disposal,
disposal type (minefill,
landfill, structural fill).
For the regenerable systems,
the form or method of sulfur
recovery is provided (e.g. -
molten elemental sulfur,
sulfuric acid plant).
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Start-up Date
Total FGD System Lost
Generation Factor
Unit Cost
Unit Location
Unit Name
Unit Rating
Date when initial SC>2 removal
began or is scheduled to
begin.
The total monthly lost genera-
tion hours due to FGD train
outages divided by the total
monthly expected generation if
the FGD trains would have been
available for operation,
expressed as a percentage.
Capital Cost in $/kW includ-
ing: SC>2 absorption and
regeneration system, S02
recovery system, solids dis-
posal, site improvements,
land, roads, tracks, substa-
tion, engineering costs,
contractors fee and interest
on capital during construc-
tion.
Annualized Cost in mills/kWh
including fixed and variable
costs. Fixed costs include:
interest on capital, deprecia-
tion, insurance, taxes, and
labor costs including over-
head. Variable costs include:
raw materials, utilities, and
maintenance.
City and State listed in
mailing address.
Unit identification as it
appears in Electrical World -
Directory of Electrical Util-
ities, McGraw-Hill - Current
Edition - or as indicated by
utility representative for
installations in planning
stages.
Operational - Maximum con-
tinuous gross generation
capacity in MW; Preopera-
tional - maximum continuous
design generation capacity in
MW.
r-i
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Utility Name Name of corporation as it
appears in Electrical World -
Directory of Electrical Util-
ities, McGraw-Hill - Current
Edition - as space permits.
Water Make-Up Gallons per minute of make-up
water required per MW of
capacity.
C-8
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TECHNICAL REPORT DATA
(riease read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-022b
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
EPA Utility FGD Survey: October-November 1978
5. REPORT DATE
February 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHOH(S)~ '
M.Melia, M.Smith, T.Koger, and B. Laseke
8. PERFORMING ORGANISATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo. Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
10. PROGRAM ELEMENT NO.
EHE624
11. CONTRACT/GRANT NO.
68-02-2603, Task 24
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COV ERED
Periodic; 10-11/78
14. SPONSORING AGENCY CODE
EPA/600/13
is. SUPPLEMENTARY NOTES EPA project officers are N.Kaplan (IERL-RTP,MD-61.919/541^
2556) and J.C.Herlihy (DSSE,202/755-8137). EPA-600/7-78-051a thru -051d are pre-
vious reports in this series.
IB. ABSTRACT The report jg ^ up(jated supplement to EPA-600/7-78-051a and should be
used in conjunction with it. It presents a survey of utility flue gas desulfurization
(FGD) systems in the U.S. , summarizing information contributed by the utility indus-
try, process suppliers, regulatory agencies, and consulting engineering firms. Sys-
tems are tabulated alphabetically, by development status (operational, under cont-
struction, in planning stages, or terminated operations), by utility company, by pro-
cess supplier, by process, by waste disposal practice, and by regulatory class. It
presents data on system design, fuel sulfur content, operating history, and actual
performance. It discusses problems and solutions associated with the boilers and
FGD systems. Process flow diagrams and FGD system economic data are appended
to the report.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COS AT I Field/Group
Pollution
Flue Gases
Desulfurization
Electric Utilities
Waste Disposal
Boilers
Maintenance
Pollution Control
Stationary Sources
Utility Boilers
13B
21B
07A,07D
15E
13A
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThuRtp,
Unclassified
175
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73) C - 9
*U.S. GOVERNMENT PRICING OFFICE:! 979 -6«K> -01* U220 REGION NO. 4
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