v>EPA
United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 2771 1
EPA-600/7-79-199d
August 1979
Survey of Flue Gas
Desulfurization Systems:
Sherburne County
Generating Plant,
Northern States Power Co.
Interagency
Energy/Environment
R&D Program Report
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EPA-600/7-79-199d
August 1979
Survey of Flue Gas
Desulfurization Systems:
Sherburne County Generating Plant,
Northern States Power Co.
by
Bernard A. Laseke, Jr.
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
Contract No. 68-02-2603
Task No. 24
Program Element No. EHE624
EPA Project Officer: Norman Kaplan
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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CONTENTS
Page
Figures iii
Tables iv
Acknowledgements vi
Summary vii
1. Introduction 1
2. Facility Description 2
3. Flue Gas Desulfurization (FGD) System 13
Background Information 13
Process Description 18
Process Design 24
Waste Disposal 36
Process Chemistry 38
Process Control 43
4. FGD System Performance 47
Background Information 47
Operating History and Performance 48
Problems and Solutions 52
5. FGD Economics 62
Introduction 62
Approach 62
Description of Cost Elements 64
Results 64
Appendices
A. Plant Survey Form A-l
B. Plant Photographs 3-1
C-l. Operational FGD System Cost Data C-l
C-2. Cost Adjustments C-14
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FIGURES
Number Page
1 Map Showing Power Plants and Population Centers in
the Sherburne County Vicinity 3
2 Site Plan of the Sherburne County Generating Plant 4
3 Side Elevation View of the Sherburne Steam Generator 6
4 Plan View of the Sherburne Power Generating Complex 9
5 Side View of the Sherburne Power Generating Complex 10
6 Simplified Process Flow Diagram of the Sherburne
Scrubbing System 11
7 Simplified Process Flow Diagram of the Sherburne
Prototype Scrubber 16
8 Simplified Diagram of a Sherburne Scrubber Module 21
9 Close-up View of the Sherburne Scrubber Module
Holding Tank and Reaction Tank Configuration 23
10 Diagram of Sherburne's First Scrubbing Stage 28
11 Simplified Flow Diagram and Typical Flow Rates of
Sherburne Scrubbing System Water Network 39
12 Original Arrangement of Sherburne Scrubber Module
Featuring the Duplex Strainer, Perforated Plate,
and Comminuter 53
13 Redesigned In-tank Strainer and Wash-lance
Arrangement 55
iii
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TABLES
Number Paqe
1 Data Summary: Sherburne 1 and 2 xi
2 Characteristics of Coal Fired at Sherburne 5
3 Design, Operation, and Emission Data: Sherburne 12
1 and 2
4 Specifications and Consumption Rate of Performance 24
Coal
5 Ash Composition and Concentration Data 25
6 First Scrubbing Stage Design Parameters and 27
Operating Conditions
7 Marble-bed Scrubbing Stage Design Parameters and 30
Operating Conditions
8 Mist Eliminator Design Parameters and Operating 31
Conditions
9 Reheater Design Parameters and Operating Conditions 32
10 Induced-draft Fan Design Parameters and Operating 34
Conditions
11 Sherburne Scrubbing System Draft Losses 34
12 Pump Design Parameters and Operating Conditions 35
13 Thickener Design Parameters and Operating Conditions 35
14 Limestone Storage and Preparation Design Parameters 37
and Operating Conditions
15 Sherburne 1 Performance Summary: May 1976 to 50
September 1978
(continued)
IV
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TABLES (Continued)
Number Page
16 Sherburne 2 Performance Summary: April 1977 to
September 1978 51
17 Summary of Sherburne 3 Emission Control System 61
18 Sherburne 1 and 2 Reported Capital Costs 65
19 Sherburne 1 and 2 Reported Annual Costs 65
20 Sherburne 1 and 2 Adjusted Capital Costs 66
v
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ACKNOWLEDGMENTS
This report was prepared under the direction of Mr. Timothy
Devitt. The principal author was Mr. Bernard Laseke.
Mr. Norman Kaplan, EPA Project Officer, had primary responsi-
bility within EPA for this project report. Information on plant
design and operation was provided by the following members of the
Northern States Power Company: Mr. B. Catron, Assistant Production
Engineer; R.J. Kruger, Environmental and Chemical Systems Super-
visor; and J.A. Noer, Project Engineer. Mr. A.J. Snider, Manager,
Environmental Control, of Combustion Engineering, also provided
information on plant design and operation.
VI
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SUMMARY
The Sherburne County generating plant is a new coal-fired,
steam-powered, electric generating station located in Sherburne
County near Becker, Minnesota. It is designed as a four-unit
station, with the two units now in service generating 1440 MW
(gross); and a projected four-unit generating capacity of 3200 MW
(gross). The station is wholly owned and operated by the Northern
States Power Company (NSP), which serves the energy needs of the
Minnesota, Wisconsin, North Dakota, and South Dakota areas.
Sherburne 1 and 2 are currently operational. Sherburne 1
was first placed in service on March 16, 1976, and was placed in
full commercial operation on May 1, 1976. Sherburne 2 was placed
in service on January 25, 1977, and in full commercial operation
on April 1, 1977. Sherburne 3 is in the planning stage and is
scheduled to begin operation in May 1984.
Sherburne 1 and 2 are each rated at 720 MW (gross), and fire
a low-sulfur, western, subbituminuous coal from the Colstrip and
Sarpy Creek regions of southern Montana. The coal typically
contains 0.8 percent sulfur, 9 percent ash, 25 percent moisture,
and has a heating value of 19,800 kJ/kg (8,500 Btu/lb). To meet
emission regulations promulgated by the Minnesota Pollution
Control Agency, each unit is equipped with a two-stage wet
scrubbing system, using alkaline fly ash/limestone for the
control of particulate and sulfur dioxide.
These scrubbing systems were designed and supplied by Com-
bustion Engineering. Each consists of 12 two-stage scrubber
modules, 11 of which are required for full-load operation. The
modules are arranged in a four by three matrix. Each module
consists of a rod scrubber in series with a single-stage marble-
bed absorber; a two-stage chevron mist eliminator; and an in-line
vii
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hot water reheater. Four induced-draft fans (one for each group
of three modules) are located downstream of the modules, and are
operated in tandem with two forced-draft fans to compensate for
draft losses in the unit. The spent scrubbing slurry from each
system is concentrated in a thickener and discharged to a clay-
lined settling pond on the site. The pond supernatant is re-
turned to the scrubbing systems for reuse.
Alkalinity for sulfur dioxide removal is provided by the
calcium oxide in the collected fly ash and the calcium carbonate
in the limestone. Raw limestone rock is received at the plant
and ground in wet ball mills to a slurry containing 4 percent
solids, which is added to the internal reaction tank of each
scrubber module.
The Sherburne scrubbing systems were designed for a minimum
availability* of 90 percent while achieving particulate and
sulfur dioxide control levels defined by the following formula:
particulate in the flue gas exiting the scrubber not to exceed 1
percent of the inlet value or 0.09 g/m^ (0.04 gr/scf),"f whichever
is greater; sulfur dioxide in the flue gas exiting the scrubber
not to exceed 50 percent of the inlet value or 200 ppm, whichever
is greater.
The Sherburne 1 and 2 scrubbing systems were started up at
the same time as the power generating units, and were certified
commercial on May 1, 1976, and April 1, 1977, respectively.
Operation during and after startup has revealed a number of
chemical, mechanical, and design problems. The major ones
included failure of the in-line slurry recirculation strainers,
ultimately leading to severe nozzle plugging; erosion of the rods
and housing in the rod scrubbers; erosion of the sidewalls of the
*
Availability: The number of hours the scrubber system is
available for operation (whether operated or not), divided by
the number of hours in the period, expressed as a percentage.
Dry basis.
Vlll
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internal reaction tank associated with the rod scrubber; mist
eliminator plugging; relieater tube corrosion; premature failure
of the rubber lining in the slurry piping; premature failure of
recirculation pump impellers; premature failure of the protective
fiberglass lining in some of the scrubber modules; failure of the
comminuter system, ultimately leading to its removal; and failure
of the original bleedoff system, requiring replacement with a
separate effluent bleedoff pump system.
Nearly all these problems have been or are being resolved
through system design modifications. The modifications, coupled
with the additional operating experience gained by the utility,
have increased system availability. By October 1978, the Sher-
burne 1 and 2 scrubbing systems had achieved total system avail-
abilities of 92 and 94 percent, respectively, each of which is
above the minimum design level of 90 percent.
Several performance tests and data from continuous monitor-
ing have demonstrated compliance with emission regulations. The
systems have typically been removing approximately 99 percent of
the inlet particulate matter [6.9 g/m (3.0 gr/scf) inlet, 0.09
g/m (0.04 gr/scf) outlet];* and 55 to 60 percent of the inlet
sulfur dioxide (700 ppm inlet, 300 ppm outlet). Problems have
been encountered in complying with opacity requirements. Even
when the systems have been meeting or exceeding design particu-
late control levels, opacity has been in the range of 40 to 45
percent, or about twice the regulatory limitation.
Northern States Power has reported the total capital cost of
the Sherburne 1 and 2 emission control systeir.s, including air
quality control and waste disposal, to be $69,064,040. Based on
a gross generating capacity of 1440 MW, this amounts to 48.0/kW.
The total annual cost of the scrubbing systems, including air
quality control and waste disposal, was reported to be $15,014,800,
This figure includes $7,994,800 in variable charges and $7,020,000
Dry basis.
IX
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in fixed charges. Based on a station capacity factor of 75.7
percent for 1977, for a total net power production of 7.535 x
kWh, total annual costs amount to 1.99 mills/kWh.
Sherburne 3, which is rated at 860 MW (gross), will be
erected alongside Sherburne 1 and 2. This unit will also be
equipped with wet scrubbing systems using alkaline fly ash/lime-
stone, to be designed and supplied by Combustion Engineering.
This system will have eight two-stage scrubber modules, seven of
which will be required for full-load operation. The system will
consist of a rod scrubber, designed for particulate control, in
series with a vertical countercurrent spray tower absorber. This
system is designed to remove 99.5 percent of the inlet particulate
and 80 percent of the inlet sulfur dioxide. The utility and
system supplier are now conducting a series of tests on Module
101 of Sherburne 1 to determine the design and operating charac-
teristics of the Sherburne 3 scrubbing system.
Table 1 presents a summary of data on Sherburne 1 and 2 and
on the FGD scrubbing systems.
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TABLE 1. DATA SUMMARY: SHERBURNE 1 AND 2
Units
Gross rating, MW
Net rating, MW
Fuel
Average fuel characteristics:
Heating value, kJ/kg (Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
FGD process
FGD system supplier
Application
Status
Startup dates:
Initial
Commercial
Design removal efficiency:
Particulate, percent
Sulfur dioxide, percent
Water loop
Sludge disposal
Economics (reported):
Capital, $/kW (gross)
Annual, mills/kWh (net)
1 and 2
1440
1360
Coal
19,800 (8,500)
9
25
0.8
Alkaline fly ash/limestone
Combustion Engineering
New
Operational
March 16, 1976 (Unit 1)
January 25, 1977 (Unit 2)
May 1, 1976 (Unit 1)
April 1, 1977 (Unit 2)
99
50
Closed3
Forcibly oxidized sludge
disposed in an onsite
clay-lined settling pond
48.0
1.99
The water loop for this system is a closed loop design and
has operated as such during the pas 12 to 18 months. NSP
has a permit to discharge some water from the plant's holding
basin into the Mississippi River. This discharge is regu-
lated within limits established by permits from regulatory
agencies.
XI
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SECTION 1
INTRODUCTION
The Industrial Environmental Research Laboratory (IERL) of
the U.S. Environmental Protection Agency (EPA) has initiated a
study to evaluate the performance characteristics and reliability
of flue gas desulfurization (FGD) systems operating on coal-fired
utility boilers in the United States.
This report, one of a series on such systems, covers the
Sherburne County generating plant of the Northern States Power
Company. It includes pertinent process design and operating
data, a description of major startup and operational problems and
solutions, atmospheric emission data, and capital and annual cost
information.
This report is based on information obtained during and
after plant inspections conducted for PEDCo Environmental per-
sonnel on May 19, 1977, and April 7, 1978, by the Northern
States Power Company. The information presented in this report
is current as of November 1978.
Section 2 provides information and data on facility design
and operation; Section 3 provides background information and a
detailed description of the air quality and waste disposal
systems; Section 4 describes and analyzes the operation and
performance of the air quality and waste disposal systems; and
Section 5 provides a detailed review of capital and annual
costs, including values reported by the utility and PEDCo-adjusted
values. Appendices A, B, and C contain details of plant and
system operation, reported and adjusted capital and annual cost
data, and photos of the installation.
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SECTION 2
FACILITY DESCRIPTION
The Sherburne County generating plant is a new 3200-MW power
generating station, comprising four coal-fired units, that is
wholly owned and operated by the Northern States Power Company.
The last two units are in the planning stage. The third unit is
scheduled for completion in 1984. The station is located in
Sherburne County, near the village of Becker (population: about
500), Minnesota. It is situated in a lightly industrialized,
rural area of south-central Sherburne County, at a site 3 km (2
miles) southwest of Becker and 68 km (42 miles) northwest of
Minneapolis, Minnesota. The site is bounded on the southwest by
the Mississippi River. The water intake structure of the plant
is located on the bank of the river, but the plant itself is
about 1.5 km (1 mile) distant. The plant encompasses 6.9 km2
(1700 acres) of land.
Another major power station, Monticello, occupies a site
approximately 10 km (6 miles) downstream from Sherburne. This
station, which is also owned and operated by NSP, contains one
562-MW nuclear power generating unit. A map of the area, showing
the power stations and population centers, is provided in Figure
1. A site plan of the Sherburne County generating plant is
provided in Figure 2.
Each of the two units now in operation is equipped with its
own steam generator and turbine generator. The steam generator
is a controlled circulation, single-reheat, balanced-draft unit
supplied by Combustion Engineering. Each unit is designed to
produce 2261 Mg (4,985,000 Ib) per hour of superheat steam at
542°C (1007°F) and 18.3 MPa (2640 psig); and 2042 Mg (4,501,000
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) I
f ySS( r-MILLE LACS
WILDLIFE AREA
SHERBURNE NATIONAL
1- WILDLIFE REFUGE
VLITCHFIELD
PLANT SITE LOCATION MAP
5 o 9 10 is
SCALE MILES
INTERSTATE HIGHWAY
U.S HIGHWAY
Figure 1. Map showing power plants and population
centers in the Sherburne County vicinity.
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SLUDGE AND
FLY ASH POND
FUTURE
Figure 2. Site plan of the Sherburne County generating plant.
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Ib) per hour of reheat steam at 540°C (1005°F). Superheat inlet
feedwater temperature is 252°C (487°F), and reheat steam inlet
conditions are 335°C (636°F) and 4.2 MPa (597 psig). A side
elevation view of the Sherburne steam generator is provided in
Figure 3.
The turbine generator is a General Electric tandem compound
unit, with inlet steam conditions of 538°C/538°C (1000°F/1000°F)
and 16.7 MPa (2400 psig). At these conditions, the generator is
capable of producing 660 MW; but since it is designed for con-
tinuous operation at 5 percent overpressure, the maximum capa-
bility is 740 MW.
Two auxiliary oil-fired steam generators are provided for
both units to supply the steam for startup for main turbine
sealing, main boiler feed pump turbines, deaerators for each main
unit, and the auxiliary deaerator. Each of these auxiliary steam
generators are Riley Stoker shop-assembled units designed to fire
No. 2 fuel oil and produce 34 Mg (75,000 Ib) of steam per hour.
The Sherburne units burn a low-sulfur, western coal that
originates from the Colstrip and Sarpy Creek regions of southern
Montana. The Colstrip coal is supplied primarily from mines
owned and operated by Western Energy, and the Sarpy Creek coal
from mines owned and operated by Westmoreland Resources. Table 2
presents the average characteristics of the coal burned at the
plant.
TABLE 2. CHARACTERISTICS OF COAL FIRED AT SHERBURNE
Characteristic
Average
Heating value, kj/kg (Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
19,800 (8,500)
9
25
0.8
The coal is delivered to the plant by unit train at a
frequency of approximately ten 100-car trains each week. This
amounts to an average consumption of 90 Gg (100,000 tons) of coal
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Figure 3. Side view of Sherburne steam generator.
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per week for both units. Rail spurs are located on the plant
site to accommodate two trains simultaneously, one unloading and
one waiting. The cars are unloaded by an automatically controlled
rotary dumper and train positioner at a rate of 3175 Mg (3500
tons) per hour. The coal is then transferred either to a yard
storage area where active and dead coal piles are maintained, or
directly to the plant for firing.
The active coal pile contains approximately 82 Gg (90,000
tons) of coal available for automatic reclaim by a bucket-wheel
reclaimer. The dead coal pile contains approximately 1 Tg (1.1
million tons) of coal, or about 60 days' supply for both units.
Coal for the steam generators is conveyed to the plant by a
split-stream bypass at the stacker-reclaimer at a rate of 1800 Mg
(2000 tons) per hour. The rate of bypass or reclaim from the
active pile is controlled to maintain the desired weight in a
270-Mg (300-ton) storage hopper above the crushers. After crush-
ing, the coal is transferred via conveyor to a 90-Mg (100-ton)
transfer hopper and then to four banks of coal silos by the steam
generators.
To meet air emission regulations promulgated by the Minne-
sota Pollution Control Agency, each unit has been fitted with an
alkaline fly ash/limestone wet scrubbing system. Each system
consists of 12 two-stage scrubber modules for the control of
particulate and sulfur dioxide. These systems were supplied by
Combustion Engineering as an integral part of the power generating
facilities, and the duct work is arranged so that flue gas cannot
bypass the scrubber modules.
The emission control systems are designed to control partic-
ulate and sulfur dioxide levels according to the following
formula: particulate in the flue gas exiting the scrubber not to
exceed 1 percent of the inlet value or 0.09 g/m (0.04 gr/scf) on
a dry basis, whichever is greater; sulfur dioxide in the flue gas
exiting the scrubber not to exceed 50 percent of the inlet
value, or 200 ppm, whichever is greater. These control levels
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are incompliance" with"air emission requirements of the Minnesota
Pollution Control Agency. The limits for the Sherburne 1 and 2
stack for particulate are 37 ng/J (0.097 lb/106 Btu) of heat
input to the boiler, and for sulfur dioxide are 413 ng/J (0.96
lb/106 Btu) of heat input to the boiler. The results of several
performance tests and of data from continuous monitoring have
demonstrated compliance with these regulations. The systems have
typically been removing 99 percent of the inlet particulate
having inlet and outlet levels of 6.9 g/m3 (3.0 gr/scf) and 0.09
g/m3 (0.04 gr/scf), dry basis, respectively; and 55 to 60 percent
of the inlet sulfur dioxide, having inlet and outlet values of
700 ppm and 300 ppm, respectively.
Figures 4 and 5 provide an overview and a side view of the
power generating complex, including the emission control systems.
Figure 6 provides a simplified process flow diagram of the
Sherburne scrubbing system. Table 3 presents data on plant
design, operation, and atmospheric emissions.
8
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UNIT 2
Figure 4. Plan view of the Sherburne power
generating complex.
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STEAM GENERATOR
TURBINE ROOM
Figure 5. Side view of the Sherburne power generating complex.
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FLUE GAS
TO STACK
FLUE GAS TO
SCRUBBER
RIVER WATER
MAKEUP
LIMESTONE
THICKENER
UNDERFLOW PUMP
BiOWDOWN
SCRUBBER
MAKEUP PUMP
Figure 6. Simplified process flow diagram of the
Sherburne scrubbing system.
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TABLE 3. DESIGN, OPERATION, AND EMISSION DATA:
SHERBURNE 1 AND 2
Total generating capacity, MW:
Gross
Net without scrubbing
Net with scrubbing
Maximum coal consumption, Mg/h
(tons/h)
Maximum heat input, GJ/h (10 Btu/h)
Maximum flue gas rate, m /s (10 acfm)
Flue gas temperature, °C (°F)
Unit heat rate, kJ/net kWh (Btu/net kWh)
Unit capacity factor, percent (1977)a
Emission controls:
Particulate
Sulfur dioxide
Nitrogen oxide
Particulate emission rate:
Allowable, ng/J (lb/106Btu)
Actual, g/m3 (gr/scf)^
Sulfur dioxide emission rate:
Allowable, ng/J (lb/106Btu)
Actual, ppmc
1,440
1,400
1,360
369
(407)
7,128 (6,756)
1,350 (2,859)
154 (310)
10,510 (9,960)
75.7
Rod scrubber
Single-stage,
marble-bed
absorber
Furnace tangential
firing system and
overfire air
37 (0.087)
0.09 (0.04)
413 (0.96)
300
Based on the Sherburne 2 commercial operating date of
April 1, 1977.
Dry basis.
Outlet value corresponds to an inlet value of 700 ppm sulfur
dioxide.
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SECTION 3
FLUE GAS DESULFURIZATION SYSTEM
BACKGROUND INFORMATION
Early in 1970, NSP began to plan for a major addition to its
power generating capacity. At that time, NSP's peak electric
demand was 3700 MW. Demand was expected to increase during the
decade at an annual rate of 8 percent, and a peak demand of 5500
MW was projected for 1977. To select an appropriate site and
develop guidelines for pollution control, NSP solicited public
participation. A group called the Citizens Advisory Task Force,
consisting primarily of representatives from environmental groups
in Minnesota, was formed to represent the public interest in the
choice of a site. The task force took under advisement four
alternative plant sites and, after considerable study, recom-
mended the Sherburne County one, even though NSP had favored a
different location as its primary site. The task force also
developed guidelines for pollution control and recommended that
emissions of all pollutants be reduced to levels in accordance
with the best available control technology. It also recommended
that NSP provide space to accommodate future additions of pollu-
tion control equipment reflecting new technology and more strin-
gent emission standards.
In 1971, NSP selected low-sulfur, western coal from southern
Montana as the primary fuel for the Sherburne steam generators.
This decision was based on the low-sulfur content of the coal and
its cost, which was about the same as was paid for Illinois coals
having more sulfur that were burned in some NSP plants. The
selection of low-sulfur coal complicated the emission control
strategy because of the difficulty of collecting fly ash with a
13
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a high ash resistivity in ordinary electrostatic precipitators.
Since the acquisition of a construction permit was contingent
upon a commitment to remove sulfur dioxide, NSP elected to develop
a wet scrubbing system to remove both particulate and sulfur
dioxide. In addition, NSP wanted to purchase a complete system
from the steam generator supplier. Combustion Engineering
offered the marble-bed scrubber, which at that time was designed
for simultaneous tail-end removal of both particulate and sulfur
dioxide. Because of the scale and novelty of the application,
the participants decided to conduct pilot and prototype tests of
the scrubbing system to confirm its concept and design.
A laboratory demonstration program, using a 34 m^/min (1200
cfm) pilot scrubber unit, was conducted from April 3 to April 10,
1972, at Combustion Engineering's Kreisinger Laboratory. Fly ash
from Montana coal was provided by NSP. The total test time was
145 hours. Calcium sulfate levels in the slurry were controlled
without liquid purge by maintaining a solids level of 7 percent
in the slurry. The alkalinity of the fly ash and a 50 percent
stoichiometric feed rate of commercial grade limestone combined
to produce a sulfur dioxide removal of more than 50 percent.
Removal efficiencies for both particulate and sulfur dioxide were
in excess of the required levels.
A test program with a prototype scrubber unit was conducted
from March 1973 to July 1974 at NSP's Black Dog generating plant
near Minneapolis. The prototype unit was designed to treat a
nominal gas flow of 370 m3/min (13,000 acfm) at 77°C (170°F).*
This rate represented approximately 5 percent of the flue gas
from Black Dog 1, the generator on which the prototype was instal-
led. The Black Dog 1 steam generator, also a Combustion Engineering
unit, burned coal typical of the Sherburne coal during the course
of the test. The vessels in the prototype unit were the same
size as those planned for Sherburne, except in cross-sectional
area. Major equipment items included a single-stage, marble-bed
*An electrical capacity of roughly 4 to 5 MW.
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scrubber, pumps, valves, a thickener, a mist eliminator, a hot-
water reheater, and a small concrete disposal pond. A simplified
process flow diagram of the Black Dog prototype scrubber is
provided in Figure 7.
The principal objectives of the Black Dog test program were
to:
0 Demonstrate the ability of alkaline fly ash alone, or
alkaline fly ash and limestone, to achieve at least a
50 percent removal of sulfur dioxide.
0 Demonstrate the guaranteed particulate outlet loading
of 0.09 g/m3 (0.04 gr/scf), dry basis.
0 Demonstrate reliable and low maintenance operation.
0 Determine optimum scrubber operating conditions,
including requirements for instrumentation, control,
and purge stream.
0 Demonstrate reliable operation without the accumulation
of solids (plugging and scaling) on scrubber internals.
0 Demonstrate acceptable continuous operation over a 30-
day period.
Soon after startup of the prototype, it became apparent that
a particulate loading of 0.09 g/m (0.04 gr/scf) in the discharge
gas stream would be difficult to attain in a single marble-bed
scrubber design. The best the prototype could achieve consis-
tently was 1.4 g/m^ (0.6 gr/scf), which was several orders of
magnitude higher than the required emission limitation. Three
methods for improving particulate removal were considered: (1)
adding a second marble bed to the scrubber; (2) adding an elec-
trostatic precipitator upstream of the scrubber, thereby also
allowing scrubber bypass; and (3) adding or incorporating a high-
energy scrubber upstream of the marble-bed scrubber. The last of
these alternatives was chosen, and a rod scrubber, comprising two
sets of adjustable rod decks in the throat area of a venturi, was
attached to the marble-bed module.
Following the incorporation of the rod scrubber, the par-
ticulate removal efficiency of the Black Dog prototype improved
15
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TO ATMOSPHERE
FLUE GAS
LIMESTONE
SLURRY
MAKEUP
Figure 7. Simplified process flow diagram of the Black Dog prototype scrubber,
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substantially and achieved the required level. The design
modification, besides increasing the slurry recirculation rate
and the solids content of the slurry, also reduced plugging and
scaling in the scrubber. These problems had been encountered
during early operation.
Performance tests were conducted during the Black Dog pro-
gram to evaluate the feasibility and reliability of the design,
and to measure removal efficiencies, reagent consumption, and
power consumption. The major findings of the program are sum-
marized as follows:
1. Incorporation of the rod scrubber increased the total
pressure drop of the system from 1.5 kPa (6 in. H2O) to 3 kPa (12
in. H20).
2. A series of tests was made in which the inlet sulfur
dioxide and supplementary limestone were varied, while the input
fly ash remained relatively constant. The sulfur dioxide was
varied from 482 ppm to 919 ppm, and the limestone from 9 to 100
percent of stoichiometric. The sulfur dioxide removal efficiency
ranged between 48 and 88 percent under these conditions. Re-
quired levels of sulfur dioxide removal were met with as little
as 5 percent stoichiometric limestone added. The calcium in the
fly ash played a major part in the removal of sulfur dioxide,
representing 70 to 80 percent of the alkali reagent.
3. Chemical analysis after forced oxidation, provided by
sparging air into the delay tank at 300 percent air stoichiom-
etry, indicated that virtually all the sulfite was converted to
sulfate. This benefited process chemistry and improved the
quality of the sludge produced.
4. The use of cooling tower blowdown as the primary source
of makeup water was shown to be feasible.
5. A 10 percent solids level in the slurry, 70 percent of
which was fly ash and the remainder calcium solids, was suffi-
cient to provide ample seed crystals and prevent scaling.
6. The level of supplementary limestone was reduced to
achieve adequate sulfur dioxide removal and minimize scale
17
-------
formation. The optimum level was found to be about 15 percent or
less of stoichiometric.
7. A mist eliminator freeboard distance of approximately
4.5 meters (14 to 15 feet) was satisfactory for optimum mist
entrainment separation.
8. Good performance was obtained with rubber-lined process
equipment and fiberglass spray headers, and the slurry nozzles
did not exhibit wear or deterioration.
Following the incorporation of the venturi scrubber plus
some of the process and design modifications discussed above, the
reliability of the Black Dog prototype improved dramatically. A
demonstration test over a continuous period of 50 days was com-
pleted with a 99 percent availability. The Black Dog program was
terminated in July 1974 when the final design configuration and
operating parameters for the Sherburne scrubber systems had been
determined.
PROCESS DESCRIPTION
The alkaline fly ash/limestone scrubbing systems installed
on Sherburne 1 and 2 were designed and supplied by Combustion
Engineering. Each system consists of 12 scrubber modules, 11 of
which are required for full-load operation, to treat the total
boiler flue gas stream of 1,350 m3/s (2,859,000 acfm) at 154°C
(310°F). The design removal efficiencies of the systems are 99
percent of the inlet particulate and 50 percent of the inlet
sulfur dioxide when the boiler fires a coal with ash and sulfur
contents of 9 percent and 0.8 percent, respectively. The scrub-
bing systems were installed as integral parts of the power
generating complex. Duct work is arranged so that flue gas
cannot bypass the scrubber modules.
The Sherburne scrubbing systems share common limestone
handling, storage, and preparation equipment, as well as disposal
facilities for flue gas cleaning wastes. The three basic operation
18
-------
areas of the Sherburne scrubbing system—limestone handling,
storage, and preparation; flue gas treatment; slurry recircula-
tion and flue gas cleaning waste disposal—are described briefly
in the following subsections.
Limestone Handling, Storage, and Preparation
The limestone for the scrubbing systems is handled by the
coal unloading and transportation system. It is delivered to the
plant as 1.9 by 0.6 cm (3/4 by 1/4 in.) rock, and contains a
minimum of 95 percent calcium carbonate. Limestone is stored at
ground level in a conical pile alongside the yard belt for recov-
ery by a front-end loader.
Before it is milled in the wet ball mills, the limestone is
stored in a 540-Mg (600-ton) surge hopper in the crusher build-
ing. The limestone is withdrawn from the surge hopper over weigh
belts into two Allis-Chalmers wet ball mills. Each mill has a
capacity of 22 Mg (24 tons) per hour. The mills are equipped
with coarse and fine grind sections with classifiers. The product
of the mill is a 60 percent solids slurry, which is transferred
to a storage tank capable of holding a 7-hour mill output. The
slurry in the storage tank is agitated by air to prevent hard
settling.
Slurry is withdrawn from the storage tank as it is needed
and is diluted with makeup water to form a 4 to 6 percent solids
slurry, which is then transferred to a slurry tank provided for
each system. It can then be transferred to the internal reaction
tank of each scrubber module.
Flue Gas Treatment
The flue gas from the steam generator leaves the air pre-
heaters at approximately 154°C (310°F) and enters the scrubbing
system. The scrubber inlet duct work is designed to distribute
the flue gas equally among the scrubber modules, and to maintain
a high enough velocity to keep the particulate in suspension.
19
-------
This is achieved by providing individual ducts with turning vanes
at the inlet of each module.
After passing the inlet damper, the flue gas enters the rod
scrubber. This is a rectangular-throat venturi section with two
parallel rows of horizontal rods in the throat. The rods are
perpendicular to the flue gas flow. A slurry spray, which is
generated in the scrubber reaction tank and pumped to the first
stage' by the spray water pump, is introduced just above the rods.
Some of the slurry is sprayed into the gas stream and the rest is
sprayed on the walls of the venturi section to prevent deposit
formation. The rods increase the velocity of the flue gas by
reducing the cross-sectional area of the duct, causing the
particulate and sulfur dioxide in the gas to be captured by the
droplets from the slurry spray nozzles.
The flue gas, still containing a significant portion of the
inlet sulfur dioxide and some particulate, then travels into the
main part of the scrubber where it contacts the ladder vanes at
the base of the marble bed. The vanes act as distributors for
the flue gas, which is wetted by both the slurry on the bed and
the slurry being sprayed to the bed by the underbed spray nozzles.
As the flue gas passes through the marble bed, it is broken up
and mixed with the slurry entering the bed.
The flue gas next passes through the mist elimination
section to have the entrained moisture removed. The temperature
of the gas at the mist eliminator exit is 55°C (131°F). To
prevent condensation of the equilibrium moisture, the gas passes
through a finned-tube reheater that increases the scrubbed gas
temperature to about 77°C (171°F). The flue gas leaves the
reheater and travels through the outlet duct work to the induced-
draft fans; from there, it passes through two outlet breeching
sections to flues in the stack (one flue per unit).
A simplified diagram of a Sherburne scrubber module is
provided in Figure 8.
20
-------
REHEATER OUTLET It a
REHEATER INLET It cm
OUTLET GAS DUCT
OUTLET DAMPER
J
REHEATER
t
AND
SPRAY PUMP
SOOT BLOWERS (3)\
'Fr*njT
WASH BLOWERS (4)
MARBLE BED
f g ? g ? gHPOTS
UNDERBED
SPRAY HEADERS (9)
NOZZLES
MIST ELIMINATOR
(2 STAGES)
I
GAS
INLET
OVERFLOW
c=^
LJ
INLET SOOT BLOWER
QSLURRY HEADER AND
' NOZZLES (28)
ROD SCRUBBER
TOP-ENTRY
AGITATOR
REACTION TANK
JIN-TANK
•STRAINER .
8-
SIDE-ENTRY
AGITATORS (2)
Figure 8. Simplified diagram of Sherburne scrubber module
21
-------
Slurry Recirculation and Disposal of Flue Gas Cleaning Wastes
Each scrubber module is equipped with an internal recircula-
tion tank that collects the scrubbing slurry sprayed into the rod
scrubber and marble-bed sections of the scrubber module. The
tank is functionally divided into two compartments: the holding
tank and the reaction tank. The holding tank is a triangular
compartment located beneath the rod scrubber and adjoined direct-
ly to the marble-bed module. It collects, via gravity feed, the
slurry sprayed into the rod scrubber venturi. The reaction tank
is a rectangular compartment located directly below the marble
bed. It has a capacity of 250,000 liters (66,000 gallons). This
tank collects the slurry sprayed into the marble-bed section via
a drainage system consisting of 48 overflow drain pots located on
top of the marble bed.
The holding tank is equipped with one vertical-entry agita-
tor, and the reaction tank with two side-entry agitators. The
agitators continually mix the slurry, which contains calcium
salts, collected fly ash, dissolved ions, and limestone. The
limestone prepared in the milling system is continuously delivered
to the reaction tank as a 4 percent solids slurry. The slurry is
recycled to the rod scrubber and marble-bed sections of the
scrubber module by a single spray water pump that delivers it to
each of these sections, where it collects the fly ash and the
sulfur dioxide from the flue gas and returns them to the reaction
tank.
A close-up view of the holding and reaction tank configura-
tion is provided in Figure 9.
The percentage of solids in the slurry is controlled by
drawing off a bleed stream from the spray water pump discharge
and sending it to the thickener. This flow is automatically
controlled to maintain the slurry solids level at 10 percent.
The bleed stream is discharged to the thickener where the solids
are concentrated and pumped to the fly ash pond. The decanted
liquid at the top of the thickener is returned to the scrubber
22
-------
[
SPRAY
PUMP
TOP ENTRY
AGITATOR
REACTION TANK
250,000 liters
(66,000 gal)
UN-TANK
ISTRAINER
i
i
j
I
HOLDING TANK
v_
SIDE ENTRY
AGITATORS (2)
OXIDIZER
Figure 9. Close-up view of the Sherburne scrubber module
holding tank and reaction tank configuration.
23
-------
recirculation-tank for use as makeup water to the modules and
mist eliminator wash water. The slurry in the fly ash pond is
allowed to settle, with the solids remaining in the pond and the
liquid being collected and returned to the scrubber recirculation
tank.
PROCESS DESIGN
Fuel
The scrubbing systems were designed to process flue gas
resulting from the combustion of pulverized coal in two con-
ventional steam generators. Table 4 presents the fuel specifica-
tions and consumption rate of the performance coal.
TABLE 4. SPECIFICATIONS AND CONSUMPTION RATE OF PERFORMANCE COAL
Heating value, kJ/kg (Btu/lb)
Ash, percent
Moisture, percent
Sulfur, percent
Maximum firing rate, Mg/h per unit
(tons/h per unit)
19,300 (8,300)
9.0
25.0
0.8
372
(410)
Ash
The collected fly ash imparts a substantial amount of
alkalinity to the scrubbing slurry, providing the major source of
reagent for sulfur dioxide removal. Calcium oxide, magnesium
oxide, and sodium oxide, which account for the bulk of this
alkalinity, constitute 21 percent of the fly ash. Ash composi-
tion and concentration data are presented in Table 5.
Rod scrubber
The first scrubbing stage of the scrubber module provides
primary control of inlet particulate and also removes a sub-
stantial amount of the inlet sulfur dioxide. This stage, which
is attached to the side of the reaction tank, consists of an
inlet gas section, a skirt section, a venturi rod section,
24
-------
TABLE 5. ASH COMPOSITION AND CONCENTRATION DATA
Component
Calcium oxide
Magnesium oxide
Sodium oxide
Silicon oxide
Aluminum oxide
Titanium oxide
Ferric oxide
Potassium oxide
Phosphorous pentoxide
Sulfur trioxide
Undetermined
Total
Weight percent
17.0
4.0
0.3
32.0
21.0
0.5
6.0
0.3
0.5
16.5
1.9
100.0
25
-------
and.a. holding tanlt. The inlet gas section connects the flue gas
duct to the first scrubbing stage. This section contains the
inlet soot blower that removes solids accumulated at the wet-dry
interface. The skirt section, which connects the inlet gas
section to the venturi, houses the first-stage spray nozzles.
Twenty-eight nozzles penetrate the top perimeter of the skirt
section and spray slurry in a cocurrent fashion into the incoming
gas stream. In the throat area, the venturi houses two rows of
rods that are used to contact the flue gas and the slurry. The
rods in each deck are staggered: an upper row is welded to bars
that are permanently fixed in the duct, and a bottom row can be
adjusted by moving the deck up or down with a manual scissor
jack. The rods are assembled in five sections, each measuring 1
m by 3 m (3 ft by 10 ft). The slurry holding tank is connected
to the reaction tank, and houses the top-entry agitator that is
included in each module. Table 6 summarizes the design parameters
and operating conditions for the major components of the first
scrubbing stage. Figure 10 shows a diagram of the first scrub-
bing stage.
Marble-bed Scrubber
The second scrubbing stage of the scrubber module provides
additional particulate and sulfur dioxide removal. This stage,
housed in the vertical scrubber module, includes a single marble
bed, underbed sprays, a drainage system, and a reaction tank.
The marble bed is a perforated plate upon which glass spheres are
packed to an average depth of 10 cm (4 in.). Slurry is applied
to the bed by spray nozzles attached to nine underbed spray
headers, which receive part of the recycled slurry from the spray
pump discharge. Slurry drainage is provided by 48 drain pots
located on the marble bed. These overflow pots are domed, weir-
type drainage devices that are evenly spaced throughout the bed.
The slurry collected by the drain pots flows down into the
reaction tank below the marble bed. The internal reaction tank
houses the two side-entry agitators provided for each module.
26
-------
TABLE 6. FIRST SCRUBBING STAGE
DESIGN PARAMETERS AND OPERATING CONDITIONS
Number
Type
Major components
Dimensions:
Gas inlet (length x width), m(ft)
Rods (outer diameter), cm(in.)
Materials of construction:
Gas inlet
Skirt
Venturi
Rods
Spray nozzles
Holding tank
Number of rod decks
Number of rod sections per scrubber
Number of spray headers
Number of spray nozzles
Flue gas volume, m /s (acfm)
Flue gas temperature, °C (°F)
Flue gas velocity, m/s (ft/s)
Liquid recirculation rate,
liters/s (gpm)
Liquid-to-gas ratio (L/G), liters/m
(gal/103 acf)
12
Rectangular, venturi
rod scrubber
Gas inlet, skirt,
venturi, rod decks,
spray nozzles, and
holding tank
0.9 x 6.5 (3.0 x 25.5)
6.4 (2.5)
Carbon steela
316L SS
316L SS
316L SSb
Ceramic
Carbon steel3
2
5
2
28
123 (259,900)
154 (310)
15 (50)
223 (3,540)
1.8 (14)
0.64 mm (0.25 in.) plate.
b Schedule 40 pipe, 91 cm (36 in.) in length.
27
-------
INLET DUCT
SOOT BLOWER-
SLURRY
HEADER
INLET SECTION
1.9 cm (0.75 in)
PRESSURE TAP
FIRST STAGE
SPRAY NOZZLES (28)
I/
SKIRT SECTION
VENTURI SECTION
1.9 cm (0.75 in)
PRESSURE TAP
HOLDING TANK
Figure 10. Diagram of Sherburne^s first scrubbing stage,
28
-------
Each tank is also equipped with an in-tank strainer, consisting
of a large, perforated, semicircular plate installed around the
suction side of the spray water pump. Each strainer is equipped
with an automatic water washer that backwashes the strainer and
prevents it from becoming plugged. Table 7 summarizes the design
parameters and operating conditions for the major components of
the marble-bed scrubbing stage. Figure 8, which provides a
simpli-fied diagram of the scrubber module, also illustrates the
general arrangement of the marble bed.
Mist Eliminator
Each module is equipped with a mist eliminator, which is
placed horizontal to the flue gas stream. Two stages of three-
pass chevron vanes are located 3.2 m (10.5 ft) above the marble
bed. Each of these stages is washed for 2 minutes every 24 hours
with a high-pressure spray of liquor. The wash liquor is a blend
of thickener overflow and cooling tower blowdown. Four retract-
able, water-blower washers are provided for each mist eliminator.
Table 8 summarizes the design parameters and operating conditions.
Figure 87 which provides a simplified diagram o± Lhe scrubber
module, also illustrates the general arrangement of the mist
eliminator.
Reheaters
Each module is equipped with a reheater, which is placed
approximately 3 m (10 ft) above the mist eliminator. The reheater
is an in-line, hot-water heat exchanger consisting of 45 circum-
ferential finned tubes, arranged in a staggered, parallel fashion,
to allow four tube passes through the gas stream. The temperature
of the scrubbed gas stream is raised from 55°C to 77°C (131°F to
171°F) by the reheaters. This heating is designed to prevent
condensation and resultant corrosion of downstream equipment
(ducts, fans, stack), suppress plume visibility, and enhance
plume rise and pollutant dispersion. Table 9 summarizes reheater
design parameters and operating conditions. Figure 8, which
29
-------
TABLE 7. MARBLE-BED SCRUBBING STAGE DESIGN
PARAMETERS AND OPERATING CONDITIONS
Number
Type
Major components
Dinensions:
Perforated plate (length x width),
m (ft)
Marble bed (depth), cm (in.)
Marbles (diameter), cm (in.)
Area per drain pot, m^ (ft^)3
Materials of construction:
Scrubber shell
Scrubber liner
Perforated plated
Marble packing
Drain pots
Spray headers
Spray nozzles
Reaction tank6
Number of marble beds
Number of spray headers
Number of spray nozzles
Flue gas volume, m /s (acfm)
Flue gas temperature, °C (°F)
Flue gas velocity, m/s (ft/s)
Liquid recirculation rate,
liters/s (gpm)
Liquid-to-gas ratio (L/G), liters/m
(gal/103 acf)
12
Vertical, rectangular,
single-stage, marble-
bed scrubber
Perforated plate,
marble-bed packing,
drain pots, spray
headers and nozzles,
and reaction tank
5.6 x 8.1 (18.4 x 26.5)
10 (4)
2.1 (0.8)
0.9 (10)
Carbon steelb
Flake fiberglassc
316L SS
Glass
FRP (pots), 316L SS (domes)
FRP
Ceramic
Carbon steel
1
9
63
94 (200,000)
54 (130)
2 (7)
120 (1900)
1.3 (9.5)
a Each pot drains approximately 0.9 m (10 ft > of marble bed area.
6.4 mm (0.25 in.) plate.
c Ceilcote flake fiberglass lining is applied to the scrubber
shell internal from the slurry level of the reaction tank
to the reheater elevation.
316L SS construction. The plate has an open area of about
40 percent provided by 9.5-mm (3/8-in.) holes located in
1.9-cm (3/4-in.) centers.
e 1.6-cm (5/8-in.) plate.
30
-------
TABLE 8. MIST ELIMINATOR DESIGN
PARAMETERS AND OPERATING CONDITIONS
Total number
Number per module
Type
Configuration (relative to gas flow)
Materials of construction
Number of stages
Number of passes per stage
Number of vane assemblies
Shape
Distance between stages, cm (in.)
Distance above bed, m (ft)
Wash system:
Water source
Washing devices (number and type)
Wash direction
Frequency
Pressure, kPa (psig)
24
1
Chevron
Horizontal
FRP
2
3
148
Z-shaped sections
10 (4)
3.2 (10.5)
Blend of thickener
overflow and cooling
tower blowdown
4 retractable, soot-
blower-type washers
Vertical, upwards rotatable
180 deg (1st stage) ,
Vertical, upwards rotatable
360 deg (2nd stage)
Intermittent - 2 minutes
every 24 h
930 - 1140 (120 - 150)
31
-------
TABLE 9. REHEATER DESIGN PARAMETERS
AND OPERATING CONDITIONS
Total number
Number per module
Type
Location
Heating medium:
Source
Inlet temperature, °C (°F)
Outlet temperature, °C (°F)
Flow rate, liters/s (gpm)
Heat exchanger:
Tube size (outer diameter),
cm (in.)
Tube type
Number of tubes
Number of passes
Tube arrangement
Materials of construction
Self cleaning:
Type
Number
Frequency
Reheater duty, MJ/h (106 Btu/h)
AT, °C (°F)
24
1
Indirect, in-line
3 m (10 ft) above
mist eliminator
Hot water from deaerator
feed tank
176 (350)
110 (230)
145 (2300)
4.5 (1.75)
Circumferential finned
tube
45
4
Staggered
Carbon steel
Soot blowers
3
Once per shift
139 (132)
22 (40)
32
-------
provides a simplified diagram of the scrubber module, also illus-
trates the general arrangement of the reheater.
Fans
Four induced-draft fans, which operate in tandem with two
half-capacity forced-draft fans to maintain furnace draft, are
located downstream of each scrubbing system. Scrubbed gas is
discharged to a plenum that serves the induced-draft fans. Each
fan is an axial flow, 30 percent capacity unit that is equipped
with a discharge shutoff and inlet control damper. Table 10
summarizes the design and operating parameters.
Draft Losses
Table 11 summarizes the draft losses that are encountered in
the inlet and discharge ducts to the scrubbing system, as well as
within the scrubbing system itself.
Pumps
Each system is equipped with 19 major pumps, performing the
following functions: reheat medium feed (2 flue gas reheat water
pumps); makeup water feed (1 scrubber makeup water pump); makeup
water transfer (2 scrubber recirculation pumps); slurry recircu-
lation (12 scrubber spray pumps); and discharge to the pond (2
scrubber sludge pumps). Table 12 summarizes pump design parameters
and operating conditions.
Separation of Solids and Liquids
Each scrubbing system is equipped with one thickener to
concentrate the solids before discharge to the fly ash pond. The
thickener overflow is returned to the scrubber recirculation tank
for further use as makeup water, flush water, and mist eliminator
wash. Table 13 summarizes thickener design parameters and oper-
ating conditions.
33
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TABLE 10. INDUCED-DRAFT
PARAMETERS AND OPERATING
FAN DESIGN
CONDITIONS
Total number
Number per unit
Manufacturer
Service
Diameter, m (ft)
Specifications :
Type
Rating, kW (hp)
Total pressure drop, kPa
(in. H20)a
Scrubber pressure drop, kPa
(in.
Gas capacity, m /s (acfm)
Gas temperature, °C (°F)
Materials of construction
Energy requirement, MWC
8
4
Green Fuel Economizer
Dry, reheated gas
3.6 (12)
Axial flow, variable
drive, inlet damper
control
4500 (6000)
11 (44)
6 (24)
331 (702,000)
77 (171)
Carbon steel
28
Maximum design pressure drop for entire unit.
Maximum design pressure drop for entire scrubbing system.
Power requirement for scrubbing system is maximum design
pressure drop.
TABLE 11. SHERBURNE SCRUBBING SYSTEM DRAFT LOSSES
Component
Rod- se rubber
Marble bed
Mist eliminator
Reheater
Ducts and dampers
Total
kPa (in. H20)
3.25 (13.0)
1.50 (6.0)
0.125 (0.5)
0.125 (0.5)
0.50 (2.0)
5.50 (22.0)
34
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TABLE 12. PUMP DESIGN PARAMETERS AND OPERATING CONDITIONS
Number
24
24
4
2
4
2
Service
Spray
Effluent
bleed
Scrubber re-
circulation
Makeup water
Reheat water
Discharge to,
fly ash pond
Manufacturer
Worthington
Worthington
Worthington
FMC
Ingersoll-Rand
War man
Type
Centrifugal,
overhead
motors,
V-belt
Centrifugal
Centrifugal
Centrifugal
Centrifugal
Horizontal
centrifugal
Capacity
Flow,
liter/s
(gpm)
353
(5600)
9.5
(150)
126
(2000)
189
(3000)
145
(2300)
35
(560)
Head,
meters
(ft)
30
(110)
24
(80)
84
(275)
38
(125)
43
(140)
100
(330)
Materials of
construction
Ni-Hard
Rubber lined
Cast iron
Ni-Hard
Ni-Hard
Ni-Hard
U)
en
-------
TABLE 13. THICKENER DESIGN PARAMETERS
AND OPERATING CONDITIONS
Total number
Number per system
Type
Manufacturer
Dimensions:
Diameter, m (ft)
Height, m (ft)
Slurry solids, percent:
Inlet
Outlet
2
1
Center rake drive
Dorr-Oliver
50 (160)
3 (10)
10
25-30
Limestone Storage and Preparation
One limestone storage and preparation facility supplies the
reagent needs for both scrubbing systems. Two wet ball mills
grind the limestone rock to an 80 percent minus 200 mesh powder,
which is ultimately diluted to a 4 percent solids slurry and
transferred to each system. Table 14 summarizes design param-
eters and operating conditions of the reagent preparation
facility.
WASTE DISPOSAL
Four impoundment areas—the bottom ash pond, fly ash pond,
recycle basin, and holding basin—function as the primary solid
and liquid waste disposal system. Bottom ash from the steam
generators is disposed of in a 620,000 m^ (500 acre-feet) diked
impoundment pond. Flue gas cleaning wastes from the scrubber
systems are disposed of in a 30,800,000 m^ (2500 acre-feet) diked
impoundment pond. Both of these ponds are about 15 m (50 ft)
deep, are clay lined at the bottom, and contain .a clay core in
the dikes to minimize seepage. Flue gas cleaning wastes are
discharged to the fly ash pond at a rate of 38 Mg (42 tons) of
36
-------
TABLE 14. LIMESTONE STORAGE AND PREPARATION
DESIGN PARAMETERS AND OPERATING CONDITIONS
Limestone:
Rock size, cm (in.)
Supplier location
Transportation method
Calcium carbonate, percent
Storage bins:
Number
Capacity, tons (Mg)
Wet ball mills:
Number
Capacity, Mg (tons)/h
Manufacturer
Product slurry, percent solids
Classifier, type
Mill effluent:
Slurry solids, percent
Point of addition
1.9 x 0.6 (3/4 x 1/4)
Davenport, Iowa
Barge/truck
95
540 (600)
22 (24)
Allis Chalmers
60
Sieve bend
Reaction tank
37
-------
solids per hour at full load. The pond has a 7- to 9-year service
life based upon current waste discharge levels. An additional
area of about 0.2 km2 (50 acres) is available for expansion.
The recycle and holding basins receive cooling tower blow-
down, overflow from the ash ponds, storm runoff water, and makeup
water from the river. The recycle basin is a clay-lined, earthen
containment that has a surge volume capacity of 34 million liters
(9 million gallons). Water collected in the basins is recycled
back to the plant for further use in the scrubbing system and is
the bottom ash and mill-rejects sluicing system. Some of the
collected water can be discharged to the Mississippi River after
a 24-hour retention in the holding basin. This discharge stream
is monitored and regulated within limits established by permits
from regulatory agencies.
The general arrangement of the impoundment areas has been
presented in Figure 2, which provides the site plan of the
Sherburne generating plant. A simplified flow diagram of the
water network for the scrubber system is provided in Figure 11.
PROCESS CHEMISTRY
Collected fly ash and slurried limestone provide the mate-
rials for the chemical reactions in the Sherburne scrubbing
process. The fly ash, which has a 17 percent composition of
calcium oxide (lime), is collected primarily in the rod scrubbing
stage. The limestone, which has a 95 percent composition of
calcium carbonate, is ground in the wet ball mills and delivered
to the reaction tank for each module as a 4 percent slurry. The
details of the complex chemical reactions are beyond the scope of
this discussion, but the principal mechanisms are described
below.
38
-------
RECYCLE BASIN MAKEUP
21 I1ters/s
(338 gpm)
LIMESTONE
3095 kg/h
(6825 Ib/h)
EVAPORATION
90
(1440. gpm)
u>
VD
FROM
MISSISSIPPI
RIVER
SLOWDOWN
118 I1ters/s
(1863 gpm)
130 liters/s
(2056 gpm)
SCRUBBER
MAKEUP
WATER
PUMPS
10 PERCENT SOLIDS
163 liters/s
(2582 gpm)
HOLDING
BASIN
38 lUers/s
(600 gpm)
MONITORING
2 PERCENT SOLIDS
108 liters/s
(1720 gpm)
50 liters/s
(793 gpm)
38 liters/s
(600 gpm)
FLY ASH POND
13.3 I1ters/s (211
ACCUMULATED
gpm)
TO
MISSISSIPPI
RIVER
108 liters/s
(1720 gpm)
25-30 PERCENT SOLIDS
63 liters/s
(1004 gpm)
Figure 11. Simplified flow diagram and typical flow rates of
Sherburne scrubbing system water network.
-------
Gas-phase Absorption
The first step in the wet-phase absorption of sulfur dioxide
from the flue gas stream is diffusion from gas to liquid. Once
absorbed into the liquid phase, the sulfur dioxide, which is an
acidic anhydride, reacts readily with water to form sulfurous
acid.
1. S02 f •« » S02(aq.)
2. SO2(aq.) + H20 * >: H2S°3
In addition, some sulfur trioxide is formed from the further
oxidation of sulfur dioxide in the flue gas stream.
3. 2SO2 + + 02 t * + 2S03 t
This species, like sulfur dioxide, is an acidic anhydride that
reacts readily with water to form sulfuric acid when absorbed in
the liquid phase.
4. S03 i * » S03(aq.)
5. S03(aq.)
The sulfurous and sulfuric acids are polyprotic species that
dissociate into a number of ionic species:
6. H2S03^=£ H+ +
7. HS0- "* > H+ +
8. H2S04^=^ H+ + HS04-
9. HS04- -5 - *. H+ + S04=
In a reaction that is analogous to the gas-phase oxidation of
sulfur dioxide to sulfur trioxide, the sulfite ions undergo a
chemical reaction promoted by the dissolved oxygen present in the
scrubbing solution.
40
-------
10. 2S03= + 02(aq>) « 2S04=
Lime Scrubbing
The fly ash collected in the rod scrubber venturi is discharged
to the holding tank where the reactive lime dissolves in the
scrubbing slurry:
11. CaO + H20 < * Ca(OH)2
12. Ca(OH)2 < * Ca++ + 20IT
The calcium cations that are formed react with the sulfite and
bisulfite ions from the sulfur dioxide absorption.
13. Ca++ + SO3= < * CaS03
14. Ca++ + 2HSO3~ < " Ca(HS03)2
The calcium sulfite formed is capable of further reacting with
sulfur dioxide ions in the following manner:
15. CaS03 + H+
The soluble calcium bisulfite formed is neutralized with hydrated
calcium oxide (reactions 11 and 12) in the reaction tank, pro-
ducing calcium sulfite, which removes additional sulfur dioxide
(reaction 15) and also accounts for some of the waste product
species purged from the slurry circuit.
16. Ca(HSO3)2 + Ca + 20H~ < 2CaS03 + 2H20
Limestone Scrubbing
The calcium carbonate that is present in the 4-percent
solids limestone slurry delivered to the reaction tank for each
scrubber partially dissolves and ionizes as follows:
17. CaC03 « * CaC03(aq.)
18. CaCO) < * Ca++ + C03=
+
19. C03= + H « HC03~
The calcium cations formed react with the sulfite and bisulfite
ions formed from sulfur dioxide absorption.
41
-------
2-0;. Ca3++ -Hr-SQ3= < *: CaSCU
21. Ca++ + 2HS03~ « * Ca(HS03)2
The calcium sulfite formed further reacts with sulfur dioxide
ions, forming additional bisulfite that is neutralized in the
reaction tank with dissolved calcium carbonate.
22. CaSO3
23. Ca(HS03)2 + Ca++ + CO3= < * 2CaSO3 + 2H+
The calcium sulfite produced in reaction 22 is capable of remov-
ing additional sulfur dioxide and also accounts for some of the
waste products purged from the slurry circuit.
Sulfate Formation
Sulfate is generated in the scrubbing process by the gas-
phase and liquid-phase oxidation reactions cited above (reactions
3 and 10) . Approximately 60 percent of all the sulfur captured
by the scrubbers is converted to sulfate. Virtually all of the
remaining sulfite produced in the scrubbing process is also con-
verted to sulfate by forced oxidation in the reaction tanks. Air
is sparged into each tank at 350 percent air stoichiometry.
24. 2S03= + 02(aq.)^ ~ 2SO4=
The sulfate reacts with the calcium cations, producing calcium
sulfate, which precipitates out as insoluble calcium sulfate
dihydrate (gypsum). The gypsum, along with the other waste
solids (fly ash, unreacted limestone, calcium sulfite), is
concentrated in the thickener and discharged to the fly ash
pond.
25. Ca++
26. CaS04
Not all of the sulfur dioxide captured in the scrubbers leaves as
gypsum. Some of the calcium sulfite precipitates out as calcium
42
-------
sulfite hemihydrate. This material is also ultimately disposed
of in the fly ash pond.
27. CaS03 + 1/2H20 ^ * CaSO3«l/2H2O I
PROCESS CONTROL
A dedicated computer monitoring and control system is used
for process control at the Sherburne scrubber plant. This system
represents a refinement over the original concept, which relied
on only enough parameters to schedule the modules in and out of
service to meet load requirements. The old system, based in a
separate control room for scrubber operations, monitored 3 analog
and 26 digital inputs with no visual display. The refined system
is based in the main control room and is interfaced with the
boiler controls. The computer now monitors 134 analog and 48
digital points, and displays on a cathode ray tube. All routine
operations are performed by the computer and logic network.
Process control is maintained by regulating reagent feed as
a function of slurry pH, regulating waste discharge as a function
of slurry solids, and regulating water feed as a function of
liquid levels in the tanks. The efficiency of particulate
removal is maintained by controlling gas-side pressure drop
across the venturi rod decks. A 3 kPa (12 in. 1^0) pressure drop
across the rod decks is maintained by raising or lowering the
lower rod deck via a manual scissor jack. By regulating the
vertical space between the rods, gas-side pressure drop is con-
trolled, which, in turn, affects the amount of particulate
removed by the scrubber.
The efficiency of sulfur dioxide removal is maintained by
controlling slurry pH levels. The scrubbing slurry pH is measured
with a Universal Interloc pH sensor, using a fiberglass flow-
through chamber that receives slurry from a slipstream tapped off
the spray pump. Based on these measurements, the rate of lime-
stone feed into the reaction tanks is manually controlled. The
43
-------
pH control range is 5.0 to 5.5. As the pH swings above or below
this range, the amount of fresh limestone slurry is manually
reduced or increased. In this way, optimum removal efficiency
can be attained while avoiding the scaling or plugging that
results from loss of chemical control. Limestone, added to the
slurry circuit to supplement the alkalinity of the fly ash
collected in the venturi, insures a minimum sulfur dioxide
removal efficiency of 50 percent while preventing the corrosion
and scaling that come from pH swings. The additive slurry feed
to each reaction tank is controlled by an Invalco valve with a
Norbide valve plug and seat (boron carbide ceramic) for abrasion
resistance.
To control the level of slurry solids circulated through the
scrubber system, a spent slurry bleed stream is removed from each
reaction tank via an effluent pumping service that takes its
suction from the reaction tank. One effluent bleed pump is pro-
vided for each reaction tank. The spent slurry is discharged at
a rate of 9.5 liters/s (150 gpm) per module and is sent to the
thickener via the slurry transfer tank. This bleed stream is
automatically controlled by a Texas nuclear density meter (stan-
dard clamp-on type) working in conjunction with a Leeds and
Northrup controller. A meter inside the reaction tank of each
module monitors the solids level of slurry circulating through
it. When the level exceeds 10 percent a control valve is acti-
vated that allows a bleed stream to flow to the thickener until
the proper level is reestablished. Two control valves are placed
in series in the bleed line, the first manually set and the
second controlled. The control is not critical, however, and may
be made manual.
The maintenance of a 10 percent solids level in the scrub-
bing slurry is vital to the process chemistry. The level of
sulfate in the slurry is controlled by selective desupersatura-
tion in the reaction tank and continual bleed from the spray pump
discharge to the thickener. Desupersaturation of sulfate re-
quires the presence of enough calcium sulfate solids in the
44
-------
slurry to act as seed crystals, promoting crystal growth of
calcium sulfate in the process. This process is aided by the use
of a forced oxidation system that sparges air into the reaction
tanks, oxidizing all the remaining sulfite* to sulfate. The
sulfate then crystallizes on the seed crystals and is removed
from the system for disposal in the fly-ash pond. As a conse-
quence, a safe sulfite level is maintained in the slurry being
returned to the scrubbers; and critical supersaturation, which
can produce uncontrolled gypsum scale formation on equipment
internals, does not occur.t The amount of calcium sulfate seed
crystals is 2 to 3 percent of the 10 percent solids level in the
slurry, which is sufficient to control sulfate saturation levels.
A water balance system controls the water returned from the
holding and recycle basins to maintain the proper liquid levels
in the recirculation and makeup tanks. Bubble-tube level con-
trollers are used in these tanks to control the flow of makeup
water to the tanks. Flow rates in all slurry lines are measured
by magnetic flowmeters (Foxboro).
*
Approximately 60 percent of the sulfite present in the scrubber
system is converted to sulfate by natural oxidation. Nearly
all the rest is converted to sulfate by forced oxidation.
The ratio of the products of the activity coefficients of
calcium and sulfate ions to the solubility product of calcium
sulfate is a measure of relative saturation. Thus, when this
ratio is less than one subsaturation occurs. ACa++ Ago :
<1
Ksp CaSO4
Saturation and supersaturation occur when this ratio equals or
exceeds one. AC ++ A Q =
Ksp CaSC>4 ~
Heterogeneous crystallization, which is the precursor of
uncontrolled gypsum scaling, becomes critical when relative
upersaturation reaches 1.4 to 1.5.
45
-------
Sulfur dioxide concentrations in the flue gas are measured
by DuPont ultraviolet analyzers (Photometric 460) . Each scrub-
bing system is equipped with four analyzers, each having a four-
stream sample train. The monitors analyze the sulfur dioxide
inlet and outlet values for each module, the overall content of
each generating unit, and the total flow to the stack.
46
-------
SECTION 4
FGD SYSTEM PERFORMANCE
BACKGROUND INFORMATION
The Sherburne scrubbing systems are the largest and among
the more sophisticated applications of limestone scrubbing
technology in the world today. They also represent a second-
generation design philosophy, in that the basic Combustion
Engineering marble-bed scrubber design was modified after exten-
sive pilot and prototype plant testing to include such features
as a venturi rod scrubber in the first stage, forced oxidation,
and the use of the alkalinity of the collected fly ash to remove
a major portion of the sulfur dioxide. These modifications
allowed the systems to achieve design guarantees of 99 percent
particulate removal, 50 percent sulfur dioxide removal, and 90
percent availability. In addition to the Black Dog prototype
program, the final design reflected Combustion Engineering's
experience in developing scrubber technology at the Lawrence
Energy Center, Kansas Power and Light.
The operation of the scrubber systems have been very suc-
cessful up to this time. All design guarantees have been met or
bettered, with system availability at a high and steadily improv-
ing level since initial operation. The success has, in part,
been due to the continual efforts by NSP and Combustion Engineer-
ing to improve scrubber performance through design and operation
modifications. In an effort to refine the process design and
operating parameters for Sherburne 3, these participants are also
conducting a module isolation program.
47
-------
This section summarizes the operating history and performance
of the scrubbing systems, including removal efficiencies and
dependability; problems encountered and their solutions; current
research and development (R&D); and the future initiatives that
are planned.
OPERATING HISTORY AND PERFORMANCE
Sherburne 1 was first fired in early 1976 and was placed in
service on March 26, 1976. Commercial operation of the unit
began on May 1, 1976. Sherburne 2 was first fired in late 1976
and was placed in service on January 25, 1977. Commercial opera-
tion began on April 1, 1977. The scrubbing systems were started
up and were certified commercial at the same time as their
respective power generating units.
For Sherburne 1, system availability averaged 85 percent
during the first 3 months of operation after commercial startup.
During the remaining months of 1976, however, availability rose
to an average of 94 percent, giving a 1976 average of 90 percent.
In 1977, the annual average availability for the Sherburne 1
scrubbing system was 93 percent. Through September of 1978 the
availability has averaged 93 percent. This record shows that the
availability of the Sherburne 1 system has steadily improved
since commercial startup.
For Sherburne 2, scrubbing system availability averaged 93
percent during the first 9 months of operation (April through
December 1977). Through September of 1978, the availability has
averaged 94 percent. As with Sherburne 1, the availability of
this system has improved since commercial startup. The slightly
better availability of the scrubbing system on Sherburne 2 in the
entire period since commercial startup (94 percent for Sherburne
2 versus 92 percent for Sherburne 1), may be attributed to the
design and operating experience gained by the utility and system
supplier with Sherburne 1.
48
-------
Another index by which to measure the performance of the
scrubber systems is the kilowatt-hour (kWh) output of the
generating units. Since the systems are integral parts of the
power generating complex and cannot be bypassed, their availa-
bility is a limiting factor in kWh output. The average capacity
factor for Sherburne 1 for its 29 months of commercial operation
(May 1976 through September 1978) was 72.7 percent. The average
capacity factor for Sherburne 2 for its 18 months of commercial
operation (April 1977 through September 1978) was 78.8 percent.
This translates into a station capacity factor of 75.8 percent,
which closely corresponds to NSP's capacity estimates of 80
percent for the 1976 to 1980 period. The monthly kWh outputs for
both units have tended to increase,* and the output of Sherburne 2
has tended to exceed that of Sherburne 1. These trends reflect
the design and operating experience that has been gained.
Several performance tests, and the data from continuous
monitoring, have demonstrated that removal efficiencies meet the
standards of emission regulations. The scrubbing systems have
typically been removing about 99 percent of the inlet particulate
matter [6.9 g/m3 (3.0 gr/scf) inlet, 0.09 g/m (0.04 gr/scf)
outlet]t and 55 to 60 percent of the inlet sulfur dioxide (700
ppm inlet, 300 ppm outlet). The only compliance problems have
been with opacity requirements. Even when the systems have been
meeting or exceeding design particulate control levels, opacity
has typically been in the range of 40 to 45 percent, or about
twice the regulatory limitation. Tables 15 and 16 summarize the
performance of the Sherburne units, including scrubbing system
availabilities, individual module operabilities, boiler hours,
unit kWh outputs, and capacity factors.
*
The monthly output of Sherburne 2 dropped off for the first
three quarters of 1978 because of outages and overhauls.
Dry basis.
49
-------
TABLE 15. SHERBURNE 1 PERFORMANCE SUMMARY: MAY 1976 TO SEPTEMBER 1978
Month/year
May 1976
Jun. 1976
Jul. 1976
Aug. 1976
Sept. 1976
Oct. 1976
Nov. 1976
Dec. 1976
Jan. 1977
Feb. 1977
Mar. 1977
Apr. 1977
May 1977
Jun. 1977
Jul. 1977
Aug. 1977
Sept. 1977
Oct. 1977
Nov. 1977
Dec. 1977
Jan. 1978
Feb. 1978
Mar. 1978
Apr. 1978
May 1978
Jun. 1978.
Jul. 1978
Aug. 1978
Sept. 1978
Unit
output,
MWh
318,050
372,450
269,700
421,110
349,470
385,610
454,010
480,920
386,060
411,900
510,650
460,100
195,790
127,290
476,490
357,380
416,430
360,850
412,360
325,050
374,290
366,200
423,220
464,520
380,010
414,670
394,510
416,930
185,740
Unit
capacity
factor
0.64
0.75
0.54
0.85
0.70
0.68
0.95
0.97
0.78
0.80
1.0
0.93
0.39
0.26
0.96
0.72
0.84
0.73
0.83
0.65
0.75
0.74
0.85
0.94
0.77
0.84
0.79
0.84
0.37
Boiler
operation,
h
657
688
512
705
566
606
720
722
607
609
743
718
312
248
736
640
686
609
705
557
648
636
676
713
635
717
694
742
357
Total
system
availability,
percent
86
84
84
94
95
93
93
95
90
91
95
95
92
92
97
95
95
88
92
93
92
92
92
95
95
93
95
91
97
Module operability, percent
101
62
80
46
87
97
83
88
94
89
47
84
96
76
93
85
86
70
77
97
83
0
71
92
61
50
82
64
89
102
83
62
93
90
84
80
84
75
99
92
65
48
77
66
89
85
81
91
90
63
93
83
87
86
84
76
65
62
103
81
71
51
93
96
87
87
99
64
95
92
92
75
92
66
88
95
42
95
88
92
64
87
85
85
71
73
77
104
59
81
84
76
96
79
80
76
96
93
95
87
75
90
55
92
97
86
94
73
89
89
44
86
85
74
63
77
105
72
80
83
76
95
92
71
96
64
93
96
95
30
92
81
88
63
79
71
84
74
90
81
89
62
75
65
58
106
90
68
76
79
30
80
97
77
99
95
62
96
87
94
90
62
35
82
92
84
85
83
85
64
78
52
80
82
107
57
81
71
85
74
93
91
70
81
88
73
81
58
91
83
83
87
87
26
92
89
62
91
62
55
75
81
68
108
69
75
84
79
76
89
95
92
62
93
91
98
44
17
79
90
99
91
67
64
88
89
86
83
83
63
73
68
109
60
79
81
85
91
69
94
81
98
95
58
96
61
94
72
86
96
89
96
91
76
97
92
82
88
62
63
80
110
75
63
76
80
81
78
8B
40
93
83
93
78
80
83
85
77
39
89
98
80
86
71
91
71
82
72
73
80
111
72
91
87
92
100
73
73
75
98
78
90
35
0
78
90
77
58
92
95
88
88
79
87
87
72
•66
64
55
112
67
69
91
96
87
93
75
95
61
72
88
87
83
83
66
82
96
52
90
&2
87
90
52
79
95
73
83
75
cn
o
-------
TABLE 16. SHERBURNE 2 PERFORMANCE SUMMARY: APRIL 1977 TO SEPTEMBER 1978
Month/year
Apr. 1977
May 1977
Jun. 1977
Jul. 1977
Aug. 1977
Sept. 1977
Oct. 1977
Nov. 1977
Dec. 1977
Jan. 1978
Feb. 1978
Mar. 1978
Apr. 1978
May 1978
Jun. 1978
Jul. 1978
Aug. 1978
Sept. 1978
Unit
output,
MWh
442,170
421,020
423,680
382,890
366,500
423,280
449,140
435,360
443,500
387,190
367,080
483,750
436,420
70,070
326,780
393,610
384,400
396,500
Unit
capacity
factor
0.89
0.85
0.85
0.77
0.74
0.85
0.90
0.88
0.89
0.78
0.74
0.97
o.sa
0.14
0.66
0.79
0.77
0.80
Boiler
operation,
h
697
644
720
602
675
717
684
715
733
682
620
744
719
120
572
697
695
720
Total
system
availability,
percent
92
91
96
97
93
94
95
91
93
92
92
97
92
91
95
95
93
96
Module operability, percent
201
0
33
92
96
88
89
98
85
53
91
83
82
70
97
77
87
88
72
202
95
100
76
87
75
61
89
93
93
75
85
92
82
94
46
89
100
82
203
93
44
78
86
67
82
87
68
94
64
55
90
90
80
41
62
48
70
204
87
95
79
97
82
90
86
80
81
72
91
83
84
90
67
93
79
61
205
83
94
89
96
84
81
62
93
89
74
89
78
91
90
62
90
81
74
206
84
100
74
88
35
82
99
73
95
67
76
85
83
89
62
64
72
64
207
94
76
67
88
81
52
98
75
93
91
71
91
84
90
72
86
64
82
208
74
98
88
95
80
88
93
66
83
88
89
62
86
92
78
67
87
72
209
91
94
88
57
56
56
96
94
62
77
85
83
78
28
60
64
54
75
210
87
92
78
93
79
87
96
77
82
72
81
78
90
91
62
81
76
78
211
85
91
45
94
71
73
70
91
90
73
97
88
67
78
76
73
80
82
212
86
98
85
87
33
86
81
65
92
84
60
89
85
14
75
71
71
68
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PROBLEMS AND SOLUTIONS
The performance of the scrubber systems has exceeded minimum
design expectations and has steadily improved over the course of
the operating period (up to September 1978). This improvement
has come from the accumulation of operating experience, the
resolution of specific problems, and design modifications under-
taken to resolve or prevent operating problems. Many problems
have been encountered, and some continue to reduce system availa-
bility. A discussion of the major problems and solutions, and
modifications that have resulted, are discussed by equipment
category in the following paragraphs.
Strainers, Comminuters, and Perforated Plates
Original scrubber equipment included slurry line strainers,
comminuters, and perforated plates that were designed to remove
large chunks and solid particles from the slurry circuit to
prevent nozzle plugging. The arrangement of this equipment for
each module is illustrated in Figure 12. The failure of the
equipment to perform its function has contributed to the most
significant problem affecting system availability, nozzle plugging,
The original strainers were Zurn duplex units, located on
the discharge of the slurry spray pumps, that were designed to
remove solid particles larger than 6.4 mm {0.25 in.) in diameter.
In operation, however, frequent episodes of strainer plugging,
mechanical failures, and inability to remove large particles
caused severe nozzle plugging and low system availability. The
duplex design also resulted in impractical operation and mainten-
ance requirements. After extensive and futile efforts to remedy
these problems, the strainers were abandoned in favor of a new
design.
The reaction tanks were originally equipped with a com-
minuter and internal perforated plate to capture and grind the
large chunks of solids that accumulated in the slurry circuit.
The equipment proved to be unnecessary because large chunks are
not normally generated within the module. The plate also tended
52
-------
DUPLEX
STRAINER
Figure 12. Original arrangement of Sherburne scrubber module
featuring the duplex strainer, perforated plate, and comminuter.
53
-------
to be a convenient site for scale formation, which eventually
plugged it. These experiences, along with the decision to design
a new strainer, led to the removal of the comminuters and the
lower portion of the perforated plate.
Combustion Engineering installed new in-tank strainers,
consisting of large, semicircular perforated plates fitted
around the suction side of the spray pumps. Each strainer is
equipped with an oscillating and retractable wash lance for
periodic backwashing. Figure 13 shows a diagram of the rede-
signed in-tank strainer and wash lance arrangement.
One strainer, constructed of carbon steel, was installed in
September 1976, and resulted in an immediate improvement. All
the modules were equipped with the new design by March 1977. The
remedy has not, however, been a complete success; nozzle plugging
persists, caused primarily by scale formation that is sheared off
and carried to the nozzles from the strainer and piping headers.
Further, the tendency of the strainers to plug activates the wash
lance; and repeated, inefficient backwashing has caused strainer
material failures (erosion of carbon steel plate) and dilution of
slurry solids, adversely affecting process chemistry. The first
problem has been corrected by using 316L stainless steel perfor-
ated plates. The second is being corrected by devising a wash
lance with a different supply pressure and capacity.
Rod Scrubbers
Erosion of the rod scrubber housing and rods has been a con-
tinual problem. The housing erosion has been traced to the
direct impingement of slurry from the spray nozzles. Sacrificial
wear plates of 316L stainless steel construction have been fastened
to the inside of the converging section of the venturi. The 316L
stainless steel rods exhibited severe wear and failure after 8600
hours of operation. As a temporary solution to this problem,
sacrificial wear plates of stainless steel angle iron were welded
to the bottom rod deck while other materials were considered to
replace the stainless steel rods. The cause of the premature rod
54
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OSCILLATING AND
REACTING WASH
LANCE MECHANISM
PERFORATED
PLATE
SOLID PLATE
SUCTION VALVE
SPRAY PUMP
SUCTION
Figure 13. Redesigned in-tank strainer and wash-lance arrangement,
55
-------
wear has been linked to the high pressure drops across the rod
scrubbing stage. This stage was originally designed to operate
at a pressure drop of 2.1 kPa (8.5 in. H2O). To meet particulate
guarantees and lessen the opacity of stack emissions, the pres-
sure drop was increased to 3.3kPa (13 in. H20) .
Pumps
The Ni-Hard impellers and wear plates of the original slurry
spray pumps [Worthington, 353 liters/s (5600 gpm) ] fail and must
be inspected and/or replaced every 4000 to 6000 hours. On
selected modules, NSP is evaluating the use of 28 percent chrome-
iron internals and rubber-lined internals for the spray pumps.
The evaluation is still in progress, as several modules on both
systems are being refitted with rubber-lined, higher flowrate
pumps for testing.
Piping
The slurry recirculation and effluent bleed-off piping is
rubber lined up to the entry into the spray headers (Hetron FRP).
Failures have been numerous: the rubber is sheared off in chunks
by the abrasive slurry and is carried to the nozzles and spray
headers. Piping design errors—too many reducers and sharp
bends—create part of the problem by causing accelerated wear and
failure at these points. The user first tried to solve the
problem by removing the lining, but this produced accelerated
wear and erosion of the unprotected carbon steel piping. The
performance of FRP, stainless steel, and rubber-lined spool
pieces are currently being evaluated.
Numerous failures have also occurred in the thickened slurry
underflow piping. The original fiberglass piping has been
replaced with Ni-Hard piping. The mist eliminator wash lances,
which are retractable, and water-blower washers are also constructed
of fiberglass; and NSP is evaluating a stainless steel construc-
tion for this application.
56
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Spray Nozzles
Material failures and modifications have affected the
arrangement and construction of the spray nozzles in the rod
scrubber. The nozzles were originally designed to extend into
the gas stream to ensure proper spray distribution and to mini-
mize the buildup of deposits on the rods. The nozzles themselves,
however, provided convenient sites for solids deposition, and had
to be replaced with a new design that did not extend into the gas
stream; but this modification resulted in improper spray distri-
bution and subsequent buildup on the rods. New nozzles, designed
to cover the rod decks adequately and yet not extend into the gas
stream, have been installed and are functioning properly.
Nozzles constructed of Nordell (a proprietary plastic) and
carbon steel orifices were originally installed in the slurry
recirculation lines of the modules. These items failed after a
short time and were replaced with ceramic nozzles and orifices.
Although initial performance after this change was encouraging,
the nozzles eventually failed due to erosion in the tangential
cone-forming chamber. Different nozzle types have been substituted
for evaluation.
Scrubber Lining
The main body of the marble-bed scrubber module is lined
with a flake fiberglass material (Ceilcote) that has been troweled
on the carbon steel shell from the slurry level to the reheat
section. Numerous failures of this coating, ranging from pinholes
to chunks falling off, have been encountered in Sherburne 2's
modules. Since this has been encountered only in Sherburne 2,
the problem is believed to stem from improper application. The
manufacturer has repaired these liners at its own expense.
The sidewalls above the slurry level in the venturi area
have been eroded by slurry cascading down from the rods and
impinging on the sloped surfaces. Failure of the flake fiber-
glass in this area led to the addition of 316L stainless steel
wear plater,.
57
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Reheater
Some minor material failures in the reheater were observed
during the early stages of operation. This was not the result of
external or internal corrosion but external erosion caused by
initial weld failures aggravated by washing after the initial
failure. A straightening bar, which had been causing weld
failures by adding undue stress, was removed. No failures have
occurred since this modification.
Thickeners and Sludge Disposal
The slurry thickening and sludge disposal system has had
several problems since startup. During the winter of 1976-1977,
for example, the rake drive on the Sherburne 1 thickener kicked
out on torque overload. Although the situation was detected
immediately, the rake could not be restarted, and the entire
thickener filled with sludge. Slurry from both units was then
temporarily piped to one thickener (Sherburne 2 was not in com-
mercial service at the time) , which was able to accommodate the
extra volume with a minimal loss in efficiency.
Solids are thickened in a ratio of 2.5:1. The thickeners
were designed for an inlet of 10 percent solids, an outlet of 25
to 30 percent solids, and zero percent solids in the overflow.
While the scrubber effluent bleed pumps discharge at 10 percent
solids, the thickener inlet is diluted to an average inlet of
less than 5 percent solids because of sluice down from the
economizer ash hoppers. The thickener bottoms are about 35 per-
cent solids, and overflow is about 1 percent. No flocculants are
required.
Other problems have included plugging in the sludge pump
suction piping and valves, plugging in the dead-leg pipes,
failures and freezing in the sludge transport lines because of
hydraulic and drainage problems, and electrical malfunctions of
valve operators. A complete design review was performed and the
following modifications have been or are being made:
58
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0 Modify and relocate thickener sludge pump discharge
piping.
0 Install slower operators on selected valves in sludge
piping to reduce water hammer.
0 Install larger pumps and redesign piping in scrubber
pump house.
0 Level the sludge lines to fly ash pond.
0 Install surge restraints (accumulators) on sludge
lines.
0 Crosstie slurry inlets to thickeners, to allow either
unit to discharge into either thickener.
Research and Development, and Future Initiatives
Northern States Power and Combustion Engineering are coop-
erating in a scrubber improvement program that encompasses two
primary objectives: optimization of the operation of the Sher-
burne 1 and 2 scrubber systems, and development of the process
design and operating parameters of scrubbing systems for Sherburne
3. Specific goals included in the first objective are:
0 Increase particulate and sulfur dioxide removal effi-
ciencies.
0 Reduce manpower and operating costs. At the present
time, 54 persons are employed to operate and maintain
the systems. The instrument technician crews (4) and
cleaning crews (21) have been unexpectedly large.
0 Develop a more efficient and durable rod scrubber
section.
0 Improve control applications. The user has already
installed and activated a dedicated computer monitoring
and control system (see Section 3).
Several specific equipment modifications are being imple-
mented to meet the goals mentioned above.
0 Installation of a separate effluent bleed-off pump for
each module, to replace the present procedure of bleed-
ing off the slurry spray discharge line.
59
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0 Modification of the rod scrubber section, including a
different "configuration (materials and design) and
larger rods [11.4 cm (4.5 in.) outer diameter],
0 Continuation of the testing of different materials for
the rods, pumps, piping, and nozzles.
Module 101 of Sherburne 1 has been modified for the research
program to develop process design and operating parameters for
Sherburne 3. Specific objectives and equipment modifications
include:
0 Removal of the marble bed and conversion to a spray
tower design.
0 Operating the rod scrubber at a pressure drop of 1.3 to
6.3 kPa (5 to 25 in. H20).
0 Modification of the rod decks to use an 18 cm (7 in.)
outer-diameter rod in a slightly different
configuration.
0 Incorporation of a bulk entrainment separator before
the mist eliminator to improve particulate removal. A
wash tray will also be added, upstream of the mist
eliminator, to test its effect on mist eliminator
cleanliness.
0 Effect of L/G on removal efficiencies. The L/G for
Module 101 will be doubled by coupling in the slurry
spray pump and piping from another module for a short
period of time to determine the effect on the removal
of sulfur dioxide and, especially, particulate.
Table 17 summarizes the Sherburne 3 emission control system
design.
60
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TABLE 17. SUMMARY OF SHERBURNE 3 EMISSION CONTROL SYSTEM
Capacity, MW (gross)
Emission controls:
Particulate
Sulfur dioxide
Process
Supplier
Number of modules
Module design
Current status
Commercial startup
Unit 3
860
Rod scrubber
Spray tower absorber
Alkaline fly ash/limestone
Combustion Engineering
8 (1 spare)
Vertical rod
scrubber and spray
tower absorber
Letter of intent signed
May 1984
-------
SECTION 5
FGD ECONOMICS
INTRODUCTION
The cost of FGD systems for the control of sulfur dioxide
emissions is .an area of intense interest and substantial con-
troversy. For this reason, reported and adjusted economic data
have been incorporated into this report.
The rationale for including adjusted, costs stems from the
difficulty of comparing the costs that are reported. Many of the
capital and operating costs reported for operational FGD systems
are site sensitive and involve different FGD battery limits and
expenditures made in different years. To accommodate these
differences, the cost data for the systems were analyzed and
adjusted to produce accurate and comparable data for the sulfur
dioxide portion of the emission control system.
APPROACH
NSP was forwarded a cost form containing all the Sherburne
cost information that was available in the PEDCo files, with the
request that the utility verify the data and fill in missing
information. A followup visit was then arranged to assist in
data acquisition and to see that the information was complete and
reliable.
The sole intent of the adjusting procedure was to establish
accurate costs of FGD systems on a common basis, not to critique
the design or reasonableness of the costs reported by the utility,
Adjustments focused primarily on the following items:
62
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Capital costs were adjusted to July 1, 1977, dollars
using the Chemical Engineering Index. Capital costs,
represented in dollars/kilowatt ($/kW), were expressed
in terms of gross megawatts (MW).
Gross unit capacity was used to express all FGD capital
expenditures because the capital requirement of an FGD
system depends on actual boiler size before derating
for auxiliary and air quality control power requirements,
Particulate control costs were deducted in an effort to
estimate the incremental cost of sulfur dioxide control.
Capital costs associated with the modification or
installation of equipment that is not part of the FGD
system but is needed for its proper functioning were
included (e.g., stack lining, modification to existing
duct work or fans).
Indirect charges were adjusted to provide adequate
funds for engineering, field expenses, legal expenses,
insurance, interest during construction, allowance for
startup, taxes, and contingencies.
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 depends on the actual amount of kilowatt-
hours (kWh) produced by the unit after derating for
auxiliary and air quality control power requirements.
Annual costs were adjusted to a common capacity factor
(65 percent).
Replacement power costs were not included.
Sludge disposal costs were adjusted to reflect the
costs of sulfur dioxide waste disposal only (i.e.,
excluding fly ash disposal).
A 30-year life was assumed for all process and economic
considerations.
63
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DESCRIPTION OF COST ELEMENTS
Capital costs consist of direct, indirect, contingency, and
other capital costs. Direct costs include the "bought-out" cost
of the equipment, of installation, and of site development.
Indirect costs include interest during construction, contractor's
fees and expenses, engineering expenses, legal expenses, taxes,
insurance expenses, allowance for startup and shakedown, and
spares. Contingency costs include those resulting from malfunc-
tions, equipment alterations, and similar unforeseen sources.
Other capital costs include the nondepreciable items of land and
working capital.
Annual costs consist of direct, fixed, and overhead costs.
Direct costs include the costs of raw materials, utilities,
operating labor and supervision, and maintenance and repair.
Fixed costs include depreciation, interim replacement expenses,
insurance costs, taxes, and interest on borrowed capital. Over-
head costs include those of plant and payroll expenses.
RESULTS
The complete results of the capital and annual cost analysis
for Sherburne 1 and 2 are presented in Appendix C of this report.
The reported and adjusted capital cost data are summarized in the
following paragraphs.
Reported and Adjusted Capital and Annual Costs
The reported capital and annual costs provided by the
utility are summarized in Tables 18 and 19. The total reported
capital cost of both scrubber systems is $69,064,040, which is
equivalent to $47.96/kW (gross). The annual cost of both systems
is $15,014,800, which is equivalent to 1.99 mills/kWh (net).
The calculated adjusted capital and annual costs are sum-
marized in Tables 20 and 21. The total adjusted capital cost of
both systems is $101,579,000, which is equivalent to $70.54/kW
(gross). The annual adjusted cost of both systems is $18,836,800,
which is equivalent to 2.77 mills/kWh.
64
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TABLE 18. SHERBURNE 1 AND 2
REPORTED CAPITAL COSTS
(dollars)
Scrubber modules and ancillary equipment 60,000,000
Induced-draft fans 302,000
Reheat 675,652
Thickening and sludge disposal 9,525,000
In-tank strainers 119,040
Total 69,064,040
TABLE 19. SHERBURNE 1 AND 2
REPORTED ANNUAL COSTS (1977)
(dollars)
Variable charges:
Maintenance 560,000
Operating 629,900
Labor (operating and maintenance) 1,870,900
Employee expenses (operating and
maintenance) 18,500
Transportation (operating and
maintenance) 18,800
Contracted expenses (operating and
maintenance) 276,600
Limestone 449,000
Replacement energy 2,109,000
Total variable 7,994,800
Fixed charges:
Interest 4,200,000
Depreciation 924,000
Insurance and taxes 1,500,000
Interim replacement 396,000
Total fixed 7,020,000
Total annual 14,964,800
65
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TABLE 20. SHERBURNE 1 AND 2 ADJUSTED CAPITAL COSTS
(1977 dollars)
Adjustments
Total reported capital
Particulate control deduction
Fan capacity deduction
Particulate control waste disposal
Additional waste disposal pond capacity
Total indirect charges
Conversion to July 1, 1977, dollars
Total adjusted capital
69,964,040
-15,000,000
-135,900
-6,667,500
+1,500,000
29,000,000
22,918,360
101,579,000
TABLE 21. SHERBURNE 1 AND 2 ADJUSTED ANNUAL COSTS (1977)
Category
Costs, $
Variable
Overhead
Fixed charges
Total annual
5,091,800
715,000
13,745,000
18,836,800
66
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APPENDIX A
PLANT SURVEY FORM
A. Company and Plant Information
1. Company name; Northern States Power Company
2. Main office: 414 Nicollet Mall, Minneapolis, Minnesota
3. Plant name: Sherburne County Generating Station
4. Plant location: Becker, Minnesota
5. Responsible officer:
6. Plant manager:
7. Plant contact: Bob Catron
8. Position; Assistant production engineer
9. Telephone number; (612)261-4100
10. Date information gathered; May 19, 1977, and April 7, 1978
Participants in meeting Affiliation
R. Kruger Northern States Power Co.
B. Catron Northern States Power Co.
B. Laseke PEDCo ENVIRONMENTAL
H. Drake PEDCo ENVIRONMENTAL
T. Ponder PEDCo ENVIRONMENTAL
R. Klier PEDCo ENVIRONMENTAL
A-l
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B. Plant and Site Data
1. UTM coordinates:
2. Sea Level elevation:
3. Plant site plot plan (Yes, No); Yes
(include drawing or aerial overviews)
4. FGD system plan (Yes, No) ; Yes
5. General description of plant environs: Lightly'industri-
alized rural area
6. Coal shipment mode(s): Unit train
C. FGD Vendor/Designer Background
1. Process; Limestone/alkaline fly ash
2. Developer/licensor; Combustion Engineering
3. Address; 1000 Prospect Hill, Windsor, Connecticut
4. Company offering process:
Company: Combustion Engineering
Address; 1000 Prospect Hill
A-2
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Location: Windsor, Connecticut
Company contact: A.J. Snider
Position; Manager, Environmental Control
Telephone number; (203)688-1911
Architectural/engineer:
Company; Black and Veatch
Address:
Location: Kansas City/ Missouri
Company contact; R.M. Butcher
Position; Project Manager
Telephone number:_
D. Boiler Data
1. Boiler: 1 and 2
2. Boiler manufacturer; Combustion Engineering
3. Boiler service (base, intermediate, cycling, peak):
Base load
4. Year placed in service; 5/1/76 (Unit 1). 4/1/77 (Unit 2)
*
5. Total hours operation (date) ;>18 .614 (Unit 1) r 11.756 (Unit 2)
6. Remaining life of unit;
7. Boiler type; single reheat, balanced draft, pulverized coal
8. Served by stack no.; i
9. Stack height; 198 m (650 ft)
10. Stack top inner diameter; 9.8 m (32 ft)
11. Unit ratings (MW):
Gross unit rating; 720
Net unit rating without FGD: 700
As of September 1978.
A-3
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Net unit rating with FGD; 680 MW
Name plate rating;740 MW at 5% turbine overpressure
12. Unit heat rate:
Heat rate without FGD:
Heat rate with FGD; 10,510 kj/net kWh (9,960 Btu/net kWh)
13. Boiler capacity factor, (1977): 75.7 (station)
14. Fuel type; Coal
15. Flue gas flow rate:
Maximum: 1350 m /s (2,859,000 acfm)
Temperature: 154°C (310°F)
16. Total excess air:
17. Boiler efficiency:
E. Coal Data
1. Coal supplier(s):
Name (s) : Western Energy and Westmoreland Resources
Location(s):
Mine location(s): Colstrip and Sarpy Creek areas
County, State; Montana
Seam:
2. Gross heating value: 19,800 kJ/Jcg (8500 Btu/lb)
3. Ash (dry basis): 12%
4. Moisture: 25%
5. Sulfur (dry basis); 1.07%
6. Chloride:
7. Ash composition (See Table Al)
A-4
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Table Al
Constituent Percent weight
Silica, SiO2 32.0
Alumina, A1203 21.0
Titania, TiO2 0.5
Ferric oxide, Fe-O^ 6.0
Calcium oxide, CaO 17.0
Magnesium oxide, MgO 4.0
Sodium oxide, Na-O 0.3
Potassium oxide, K20 0.3
Phosphorous pentoxide, P205 0.5
Sulfur trioxide, SO- 16.5
Other
Undetermined 1.9
F. Atmospheric Emission Regulations
1. Applicable particulate emission regulation
a) Current requirement; 37 ncr/J (0.097 lb/10 Btu)
Regulation and section:
b) Future requirement:
Regulation and section:
Applicable SO2 emission regulation
a) Current requirement; 413 ng/J (0.96 lb/106 Btu)
Regulation and section:
b) Future requirement:
Regulation and section:
A-5
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G. Chemical Additives^ (Includes all reagent additives -
absorbents, precipitants, flocculants, coagulants, pH
adjusters, fixatives, catalysts, etc.)
1. Trade name:Limestone
Principal ingredient; CaCO^ (95%)
Function: Scrubbing additive
Source/manufacturer:
Quantity employed; 3.5 - 4.9 Mg/h (3.9 - 5.4 tons/h)
Point of addition: Reaction tank
2. Trade name;Not applicable (N/A)
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
3. Trade name: N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
Trade name: N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
A-6
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5 . Trade name: N/A
Principal ingredient:
Function:
Source/manufacturer:
Quantity employed:
Point of addition:
H. Equipment Specifications
1. Electrostatic precipitator(s) N/A
Number:
Manufacturer:
Design removal efficiency:
Outlet temperature:
Pressure drop:
2. Mechanical collector(s) N/A
Number:
Type:
Size:
Manufacturer:
Design removal efficiency:
Pressure drop:
3. Particulate scrubber(s)
Number: 12
Type; Venturi rod scrubber
Manufacturer; Combustion Engineering
Dimensions:
Material, shell; Carbon steel inlet, 316L SS skirt and
venturi
A-7
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Material, shell lining:
Material, internals: 316L SS rods
No. of modules per train; One
No. of stages per module; One
No. of nozzles or sprays; 26
Nozzle type; Ceramic
Nozzle size:
Boiler load capacity: 9% maximum per module (109% total)
Gas flow and temperature; 123 m3/s (259,900 cfm) , 154°C (310"f
Liquid recirculation rate; 223 liters/s (3540 gpm) per module
Modulation:
L/G ratio; 1.8 liters/m3 (14 gal/103 acf)
Pressure drop; 3.25 kPa (13.0 in. H20)
Modulation:
Superficial gas velocity: 24 m/s (80 ft/s)
Particulate removal efficiency (design/actual) : see SO- absoi
2
Inlet loading; see SO- absorber
£* ' • — - ~ ^^^^M^VMMM
Outlet loading; See SO,, absorber
S02 removal efficiency (design/actual): see SO absorber
Inlet concentration; see SO- absorber
Outlet concentration; see S02 absorber
4. SO- absorber(s)
Number; 12 (integrated with scrubbers)
Type; Marble-bed absorber
Manufacturer; Combustion Engineering _^_
Dimensions:
A-8
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Material, shell: Carbon steel
Material, shell lining: Flake fiberglass
Material, internals: 316L perforated plate, FRP spray headers
No. of modules per train: one
No. of stages per module: one
Packing/tray type: Glass spheres
Packing/tray dimensions; 10 cm (4 in.)
No. of nozzles or sprays: 63
Nozzle type: Ceramic
Nozzle size:
Boiler load capacity: 9% maximum per module (109% total)
Gas flow and temperature; 94 m /s (200,000 cfm) ; 54°C (130°F)
Liquid recirculation rate;120 liters/s (1900 gpmV _
Modulation : _ __
L/G ratio; 1.3 liters/in3 (9.5 gal/103 acf) _
Pressure drop; 1.5 kPa (6.0 in. H.-.O) _
' £, r
Modulation : _
Superficial gas velocity; 9.5 m/s (31 ft/s) _
Particulate removal efficiency (design/actual) : 99% of inlet
drv basis _
Outlet loading: Q.Q9 g/m3 (0.04 gr/scf); dry basis
or 0.09 g/m-*, whichever is greater/99%
Inlet loading: 6.9 gAi (3.0 gr/scf);
SO~ removal efficiency (design/actual) : 50% or 200 ppm
at outlet, whichever is greater/55-60%
Inlet concentration: 700 ppm _
Outlet concentration; 300 ppm
Wash water tray(s) N/A
Number:
* This is overall scrubber and absorber data on dry basis.
A-9
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Type:
Materials of construction:
Liquid recirculation rate:
Source of water:
6. Mist eliminator(s)
Number; One per module
Type: Chevron
Materials of construction: FRP
Manufacturer:
Configuration (horizontal/vertical): Horizontal
Number of stages: Two
Number of passes per stage; Three
Mist eliminator depth:
Vane spacing:
Vane angles:
Type and location of wash system; High-pressure spray for
2 min every 24 hs by four soot-blower type washers _
Superficial gas velocity; 9.2 m/s (31 ft/s) _
Freeboard distance: 3.2 m (10.5 ft) _
Pressure drop; Q-125 *Pa (0.5 in. H2O)
Comments :
7 . Reheater ( s ) : One per module
Type (check appropriate category)
A-10
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X
in-line
indirect hot air
\| direct combustion
|| bypass
|| exit gas recirculation
[1 waste heat recovery
other
Gas conditions for reheat:
Flow rate; 94 m3/s (200,000 cfm)
Temperature: 54°C (130°F)
SO- concentration; 300 ppm
Heating medium; Hot water
Combustion fuel:N/A
Percent of gas bypassed for reheat; N/A
Temperature boost (AT); 22°C (40°F)
Energy required:
Comments: About 3 m (10 ft) above M.E. consisting of 45
parallel finned tubes
8. Fan(s)
Number: Four
Type; Induced-draft, axial flow
Materials of construction; Carbon steel
Manufacturer; Green Fuel Economizer
Location: Downstream of reheater
Rating: 4500 kw (6000 hp)
Pressure drop; 11 kPa (44 in.
A-ll
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9. Recirculation tank(s):
Number: One per module
Materials of construction:
Function: Recycle/reaction
Configuration/dimensions; Rectangular
Capacity; 254,000 liters (66,000 gal)
Retention time:
Covered (yes/no); Yes (internal of module)
Agitator:
10. Recirculation/slurry pump(s):
Number: One per module
Type; Centrifugal
Manufacturer: Worthington
Materials of construction; Cast iron
Head: 84 m (275 ft)
Capacity: 7700 liters/m (2000 gpm)
11. Thickener(s)/clarifier(s)
Number: one
Type; Center-driven rake mechanism
Manufacturer: Dorr-Oliver
Materials of construction:
Configuration:
Diameter: 50 m (160 ft)
Depth: 3 m (10 ft)
Rake speed:
Retention time:
12. Vacuum filter(s) N/A
A-12
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Number:
Type:
Manufacturer:
Materials of construction:
Belt cloth material:
Design capacity:
Filter area:
13. Centr ifuge(s) N/A
Number:
Type:
Manufacturer:
Materials of construction:
Size/dimensions:
Capacity:
14. Interim sludge pond(s) N/A
Number:
Description:
Area:
Depth:
Liner type:
Location:
Service Life:
Typical operating schedule:
Ground water/surface water monitors
15. Final disposal site(s)
A-13
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Number
Description: Clay-lined settling pond
Area: 251,000 m2 (62 acres)
Depth: 15.2 m (50 ft)
Location: Onsite
Transportation mode: Pipe
Service life: 7 to 9 yr
Typical operating schedule:
.6. Raw materials production
Number: Two (Serve both units)
Type: Wet ball mills
Manufacturer: Allis Chalmers
Capacity: 22 Mg/h (24 tons/h) each
Product characteristics; 60% slurry from ball mills
80% less than 200 mesh
Equipment Operation, Maintenance, and Overhaul Schedule
1. Scrubber(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
2. Absorber(s)
A-14
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Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
3. Reheater(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
4. Fan(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
5. Mist eliminator(s)
Design life:
Elapsed operation time:
A-15
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Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures:
6. Pump(s)
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures;
7. Vacuum filter(s)/centrifuge(s) N/A
Design life:
Elapsed operation time:
Cleanout method:
Cleanout frequency:
Cleanout duration:
Other preventive maintenance procedures
8. Sludge disposal pond(s)
Design life: 7 to 9 yr
Elapsed operation time:
Capacity consumed:
Remaining capacity:
A-16
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Cleanout procedures:
J. Instrumentation
A brief description of the control mechanism or method of
measurement for each of the following process parameters:
0 Reagent addition: •
Liquor solids content:
Liquor dissolved solids content;
0 Liquor ion concentrations
Chloride:
Calcium:
Magnesium:
Sodium:
Sulfite:
Sulfate:
Carbonate:
Other (specify):
A-17
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Liquor alkalinity:
Liquor pH:
Liquor flow:
0 Pollutant (SO,, particulate, NO ) concentration in
A X
flue gas:
& Gas flow:
0 Waste water
0 Waste solids:
Provide a diagram or drawing of the scrubber/absorber train
that illustrates the function and location of the components
of the scrubber/absorber control system.
Remarks: See process control section in main body of text.
K. Discussion of Major Problem Areas:
1. Corrosion; See section on problems and solutions in the
text.
A-18
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2. Erosion:
3. Scaling:
4. Plugging:
5. Design problems:
6. Waste water/solids disposal:
A-19
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7. Mechanical problems:
L. General comments:
A-20
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APPENDIX B
PLANT PHOTOGRAPHS
B-l
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Photo No. 1. View of Bruce Mansfield Station. Featured are the hyperbolic
cooling towers, boilerhouse, scrubbing trains, and stack. Both units are
still under construction at this time.
-------
Photo No. 2. View of Bruce Mansfield Station. Featured
from left to right are the barge harbor (full at top, empty
at bottom), cooling towers, boilerhouses, scrubbing trains,
and stack. Unit 1 is in service; Units 2 and 3 are under
construction.
B-3
-------
I
Photo No. 3. View of Little Blue Run sludge containment reservoir..
Featured in foreground are the containment dam and reservoir. Featured
in background, from left to right, are the Bruce Mansfield and Braver
Valley stations.
-------
APPENDIX C -1
OPERATIONAL FGD SYSTEM COST DATA
Date June 27» 1978
Name Northern States Power Company
Address 414 Nlcollet Mall, Minneapolis. Minnesota
Name of Contact - TJM» Bob Ca^on. Plant Engineer
Phone No. (612 ) 261 -4100
Station Sherburne County
Unit TdPivhifixation Nos. 1 and 2
Unit Size, WO gross MW. 2.340.000 acfm g 171 °F
Net MW w/o Fan 140°
Net MW w/FGD 136°
FGD System Size. 144Q MW
Foot- 2.340.000 acfm @ 171
note
No. COST BREAKDOWN
I. CAPITAL COSTS OF FGD SYSTEM INSTALLATION
A. Year(s) to which estimates below apply; 1971-1977
B. Year of greatest capital expenditure: 1972
G. Month and year estimates made: April 1978
D. Date FGD contract awarded: __J_97J
Date FGD construction began: August 1972
Mar. 1, 1976 (Unit 1)
Date of initial FGD system start-up; Apr. 1. 1977 fUm't_2)
May 1, 1976 (Unit 1)
Date of commercial FGD system start-up: May 1. 1977 (Unit 2)
E. Expected FGD system life: 30 years
F. Cost adjustment made by; B.A. Laseke. Jr.
G. Cost adjustment checked bv; B-A- Laseke. Jr.
C-l
-------
Foot-
note
No.
14
H.
Direct capital cost
1, Particulate collection
Equipment cost
Installation cost
Total cost
2. Facilities for
reagent handling
and preparation
Equipment cost
Installation cost
Total cost
3. SC>2 absorber and re-
lated equipment
Equipment cost
Installation cost
Total cost
4. Fans installed for FGD
Equipment cost
Installation cost
Total cost
5. Reheat
Equipment cost
Installation cost
Total cost
Included
in reported
total cost Capital
Yes No cost, $
15,000,000
45,000,000
302,000
675,652
C- 2
-------
Foot-
note
No.
Included
in reported
total cost Capital
Yes No cost, $
Solids disposal: site
Equipment cost
Installation cost
Total cost
9,525,000
On the
Location of interim and final disposal site(s).
plant site approximately 0.5 mi from the boilerhouse
When was site(s) acquired or year of expected acquisition
1969
Cost when acquired or at time of expected acquisition
N/A .
Life span 6 to 7 year service life
Required site treatment (lining, surface preparation,
etc. ) Natural clay lining where required
Composition of disposed material (flyash_£l%, bottom
ash_Q_%, S©2 /wasteJL%, unreacted reagent_P_%,
water_70%) .
Solids disposal:
transport system
Contract cost
Equipment cost
Installation cost
Total cost
X
X
X
X
Included in
i tern 6
C-3
-------
Foot-
note
No.
J10,
9 1
10
12
Solids disposal:
treatment system
Equipment cost
Installation cost
Total cost
By-product recovery:
regenerative system
Equipment cost
Installation cost
Total cost
By-product recovery
plant
Equipment cost
Installation cost
Total cost
Instrumentation and
controls
Equipment cost
Installation cost
Total cost
Utilities and services
Equipment cost
Installation cost
Total cost
Included
in reported
total cost Capital
Yes No cost, S
N/A
N/A
346,000
N/A - Not applicable
C-4
-------
Foot-'
note
No.
13,
14
15
16,
17
Stack requirements due
to FGD
Equipment cost
Installation cost
Total cost
Additional system
modifications
Equipment cost
Installation cost
Total cost
Other
Equipment cost
Installation cost
Total cost
Other
Equipment cost
Installation cost
Total cost
Other
Equipment cost
Installation cost
Total cost
Included
in reported
total cost Capital
Yes No cost, $
119,040
C-5
-------
Foot-
note
No.
18. Other
Equipment cost
Installation cost
Total cost
J19. Other
Equipment cost
Installation cost
Total cost
J20. Other
!
j Equipment cost
I
I Installation cost
Total cost
Direct cost subtotal
Equipment cost
Installation cost
•Total cost
I. Indirect Costs
1. Engineering
In-house
A-E
2. Construction expenses
In-house
Contractor
Included
in reported
total cost Capital
Yes No cost, $
69,964,040
C-6
-------
Foot-
note
No.
3.
4.
5.
6.
7.
8.
9.
10.
11.
Included
in reported
Contractor fees
Subcontractor fees
Allowance for funds
used during construc-
tion
Allowance for start-up
Contingency
Escalation
Spares, offsite, taxes,
freight, etc.
Research and develop-
ment
Other
Indirect cost subtotal
Total Direct and Indirect Costs
S/kK (gross)
II. ANNUAL OPERATING COST
Dtal
Yes
$fi
47
c
,!
rost
No
X
X
X
X
X
X
x
X
X
X
nfi4,
16
Capital
cost , v
14D
12
Included
in reported
total cost
Yes No
Cost, S
Variable Costs
1.
All variable costs are qualified and
Particulate removal Quantified in Footnote 12 on page 12
a. Operating
(1) Labor
(2) Supervision
b. Electricity
c. O'ther utilities
(1) Water
X
y
X
X
X
X
-------
Foot •
note
No.
d. Maintenance
(1) Labor
(2) Supplies
Subtotal paniculate
2. S02 absorber
a. Operating
(1) Labor
(2) Supervision
b. Electricity consumption
(1) Feed preparation
(2) Reheat
(3) Fans
(4) SC>2 absorber
(5) Other
c. Fuel
(1) Reheat
(2) Other
d. Other Utilities
(1) Water
(2) Other
e. Maintenance
(1) Labor
(2) Supplies
Included
in reported
total cost
Yes No
Cost, $
X
X
X
X
X
C-8
-------
Foot-
note
No.
Included
total cost
Yes No
Subtotal absorber
Raw materials
a. Lime
b. Limestone
c. Fuel for process needs
d. Sodium hydroxide
e. Magnesium oxide
f. Sodium carbonate
g. Flocculant
h. Other
Subtotal raw materials
Solid and liquid waste disposal
a. Operating
(1) Labor
(2) Supervision
b. Electricity consumption
c. Other utilities
(1) Water
(2) Other
d. Maintenance
(1) Labor
(2) Supplies
e. Other
f. Credit for by-product recovery
C-9
Cost, $
N/A
N/A - Not Applicable
-------
Foot-
note
No.
13
g. Wastewater treatment
Subtotal disposal
5. Overhead
a. Plant
b. Administrative
Subtotal
Total Variable Costs
B. Fixed Charges
1. Interest
2. Annual depreciation
3. Insurance
4. Taxes
5. Other, specify
Total Fixed Costs
C. Total Variable and Fixed Costs
mills/kwh(net)
Included
in reported
total cost
Yes No
Cost, $
X
X
7
X
X
X
X
X
X
X
X
X
X
7,994,800
4,200,000
924.000
1,500,000
396,000
7.o?n:finn
$14.964.800
1.986
C-10
-------
FOOTNOTES
Line Page
1 C-2 Each unit is equipped with 12 two-stage modules for wet-
phase particulate and S(>2 removal. In addition, each
unit is provided with one spare module. Only one-fourth
of the $60,000,000 in original equipment expenditures
has been assessed for particulate removal because the
rod scrubber alone removes essentially all the particu-
late (and half of the SOz).
2 C-2 One common reagent handling and preparation facility is
used for both systems. Included are two wet ball mills
(Allis Chalmers 36 tons/hour design capacity; 24 tons/
hour actual), storage sites preparation tanks,
agitators, and transfer pumps. The primary source of
reagent is supplied by the alkalinity of the captured
fly ash.
3 C-2 Removal of S02 occurs in the rod scrubber and the
marble-bed absorber. Three-fourths of the original
equipment expenditures are assessed for S02 removal.
4 C-2 Each unit is equipped with four induced-draft scrubber
booster fans (Green Fuel Economizer). The fans are
designed to handle a gas-side pressure drop of 44 in.
H£0 of which 24 in. f^O is due to the scrubber. The
fans for Sherburne 1 cost $163,000 for equipment and
installation; the fans for Sherburne 2 cost $139,000
for equipment and installation.
5 C-2 Finned-tube carbon steel heat exchangers using hot
water raise the gas temperature 40°F prior to dis-
charge through the fans and ducts to the stack. Unit
1's reheat system cost $332,064, including pumps,
($30,650), pipes and hangers ($244,301), and installa-
tion ($57,113). Unit 2's reheat system cost $343,588,
including pumps ($31,720), pipes and hangers ($252,800),
and installation ($59,068).
6 C-3 Four ponds were built for solid waste disposal. Two
of these ponds, the fly ash pond and holding basin,
were built for the scrubbing system. These ponds,
representing a total area of 65.5 acres, were
embellished with a clay lining and were originally
provided for the lifespan of both units. This has
now been revised to a 6 to 7 year lifespan. The
total cost of ponds and equipment was $8,963,000;
plus $562,000 for inclusion of the thickeners,
(continued)
C-ll
-------
FOOTNOTES (continued)
Line Page
piplines, pumps, and other waste solids trans-
portation equipment. The user plants to expand
the present area of the ponds in order to extend
pond life.
7 C-3 The thickener underflow is about 30 percent
solids, of which 70 percent is fly ash and the
remainder sulfur-bearing calcium slats (21 percent
of the underflow is fly ash and 9 percent calcium
sulfate); virtually all the sulfur-bearing calcium
salts have been converted to sulfate by forced
oxidation. All of the limestone additive is
assumed to be used in this system.
8 C-4 A forced oxidation system (350% stoichiometric air)
is bubbled through the internal recycle tank, con-
verting all the remaining sulfite to sulfate prior
to solids separation and waste disposal. The cost
of the forced oxidation system is included in the
cost of the scrubbing equipment.
9 C-4 The costs of all process and flow instrumentation and
controls are included in the total equipment cost. In
addition, $346,000 in air and water quality monitoring
has been included.
10 C-4 Process water, electrical hookup, and switchgear
costs are included in the direct capital costs.
11 C-5 Severe plugging problems with the spray nozzles
necessitated replacement of the duplex strainers
with in-tank screens on the suction side of the
spray pumps. Carbon steel screens were used
originally and failed (erosion). 316 stainless
steel screens have been or are being placed in
all the tanks at a cost of $119,040 for material
and $960 for labor per screen.
12 C-7 All variable costs associated with the Sherburne 1
and 2 scrubbing systems were reported in the
following manner:
(continued)
C-12
-------
o
o
FOOTNOTES (continued)
Line Page
0 Maintenance: $560,300
Operating: $629,900
Labor (operating and maintenance): $1,870,900
Employee expenses (operating and maintenance):
$18,500
0 Transportation (operating and maintenance):
$18,800
0 Contracted expenses (operating and maintenance)
$276,600
0 Limestone: $449,000
0 Replacement energy (13 mills/kWh): $2,109,000
13 C-10 The user reported fixed charges based on the original
capital cost of $60,000,000 using the following fixed
charge factors:
0 Interest: 7 percent
0 Annual depreciation: 1.54 percent
0 Insurance and taxes: 2.5 percent
0 Interim replacement: 0.66 percent
0 Total fixed rate: 11.7 percent
c-13
-------
APPENDIX C-2
COST ADJUSTMENTS
1. Each unit consists of 12 two-stage particulate and S02 removal scrubber-
absorber modules: 11 full load and 1 spare. Scrubbing solution is
circulated through both the scrubber and absorber. Northern States Power
estimates that half the S02 removal from the flue gas (50 to 55%) takes
place in the rod scrubber. The utility also estimates thai-$30,000,000
of the $60,000,000 originally allocated for all the scrubbing modules
and ?3cillary equipment ($2,500,000 per module) was allocated for
particulate removal equipment and the other $30,000,000 for S0£ removal.
Since half of the S02 is removed in the venturi, however, about $15,000,000
or about half of $30,000,000 (1975 dollars; $625,000 per module) is
backed out of the costs.
0 $60,000,000 - $15,000,000 for particulate removal = $45,000,000
2. A total of $9,525,000 was allocated for the fly-ash pond and holding
basin used for the scrubbing system. Thickener underflow discharge to
the settling ponds is about 21 percent fly ash, 9 percent S02 wastes,
and 70 percent 1^0. Therefore, 21/30 or 70 percent of the cost of the
ponds is used for fly ash removal and backed out of the costs.
0 $9,525,000 - $6,667,500 = $2,857,500
3. Eight ID booster fans were supplied for both units. The cost of the four
ID fans for Unit 1 was $163,000. Since 24 in. H20 of the 44 in. H20 is
for the scrubber and 24/44 = .45, 45 percent of the $163,000 is removed.
0 $163,000 - $73,350 = $89,650
The cost of the four ID fans for Unit 2 was $139,000, of which 45 percent
is removed.
0 $139,000 - $62,550 = $76,450.
4. The sludge ponds were originally designed for the lifetime of both units.
This is now changed to a 6- to 7-year lifespan. Based on a 30 percent
solids thickener underflow and an additional 23-year capacity, costs have
been computed for the following:
0 84,000 Ib/h of sludge to pond per unit (dry basis)
0 168,000 Ib/h of sludge to pond for both units (dry basis)
0 50,400 Ib/h of S02 wastes (dry basis)
C-14
-------
0 168,000 Ib/h of S02 wastes (wet basis - 30 percent solids)
0 84 tons/h of S0£ wastes (wet basis - 30 percent solids)
Based on a 23-year additional storage capacity requirement, the extra
costs for the 862 portion, which will require an additional 3200 acre-ft
of pond, amount to $1,500,000 in 1974 dollars.
5. Direct cost adjustments:
Total reported direct costs: $69,964,040
Particulate removal equipment: -$15,000,000
Particulate sludge disposal area: -$6,667,500
Additional ID booster fan capacity: -$135,900
Additional S02 wastes storage capacity: +$1,500,000
6. Conversion to July 1, 1977, dollars:
Much of the FGD plant equipment was purchased in 1971 and 1972. An
actual breakdown of the expenditures by year is not available.
Therefore, the following assumptions have been made:
0 Assume 75 percent of the original expenditures ($60,000,000)
were made in 1971 and 1972. Assume the sludge disposal area
expenditures ($9,525,000) were made in 1973 and 1974. (The
cost of additional $62 waste storage capacity is calculated in
1974 dollars.)
The following table presents the 1977 value of reported direct
costs:
Expenditures 1977 value
(dollars) (dollars)
1971 22,500,000 34,730,290
1972 22,500,000 33,480,000
1973 9,762,500 13,834,857
1974 9,762,500 12,045,274
1975 5,000,000 5,598,194
1976 320,000 340,114
1977 119,040 119,040
Total 69,964,040 . 100,147.770
7. Direct capital cost adjustments:
0 $15,000,000 for particulate removal
5,625,000 in 1971 dollars
5,625,000 in 1972 dollars
1,250,000 in 1973 dollars = $21,765,850 (1977 dollars)
1,250,000 in 1974 dollars
1,250,000 in 1975 dollars
C-15
-------
0 $6,667,500 for fly-ash sludge removal
3,333,750 in 1974 dollars = 7,447,000 (1977 dollars)
3,333,750 in 1974 dollars
0 $135,900 for additional fan horsepower
67,950 in 1971 dollars = $206,000 (1977 dollars)
67,950 in 1972 dollars
0 Additional S02 waste pond capacity
$1,500,000 in 1974 dollars = $1,850,000 (1977 dollars)
Total adjusted direct capital cost: $73,579,000
8. Indirect capital cost adjustments:
Since the reported capital costs excluded all indirect cost elements,
the following items and amounts are included in the adjusted total:
Interest during construction: $6,350,000
Engineering fees: $7,260,000
Field overheads: $7,260,000
Cost of spares, offsite, taxes, freight: $4,500,000
Allowance for startup: $3,630,000
Total adjusted indirect capital costs: $29,000,000
9. The adjusted total capital cost:
$ 72,579,000
29,000,000
$101,579,000 = 70.54/kW (gross)
10. Adjusted annual variable costs:
0 Reported 1977 cost: $7,944,800
0 Replacement energy cost: -$2,109,000
0 Particulate removal cost: -$1,459,000
0 Overhead cost: +$715,000
Adjusted variable cost: $5,091,800
65 percent capacity factor: 0.75 mills/kWh (net)
11. Adjusted fixed costs:
With a straight line annual depreciation rate of 3.33 percent
instead of a Iowa curve value of 1.54 percent, and an interim
replacement rate of 0.7 percent instead of 0.66 percent, the annual
fixed charge rate is 13.53 percent, giving the following fixed
charges based upon the total adjusted capital cost:
13.53 percent of $101,579,000 = $13,745,000
65 percent capacity factor = $2.02 mills/kWh
C-16
-------
12. Total adjusted annual cost for 1977:
Variable cost: $5,091,800 0.75 mills/kWh
Fixed cost: $13,745,000 2.02 mills/kWh
Annual cost: $18,836,800 2.77 mills/kWh
13, Summary of adjusted costs:
Total capital: $101,579,000 $71.53/kW (gross)
Total annual: $18,836,800 2.77
-------
TECHNICAL REPORT DATA
asi' rcGil hnintcl'.on* on l/:< rrursi hcjtm t
! llllgl
1. REPORT NO.
EPA-600/7-79-199d
4.Tm.EANDsuBT,TLE Survey of Fl ue Gas Desulfur 1 za11on
Systems: Sherburne County Generating Plant,
Northern States Power Co.
7. AUTHOR(S)
Bernard A. Laseke, Jr.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
PEDCo Environmental, Inc.
11499 Chester Road
Cincinnati, Ohio 45246
3 RECIPit NT'S ACCESSION NO
b REPORT DATE
August 1979
6. PERFORMING ORGANIZATION coot
B PE RFOHMING ORGANIZATION REPORT NO
PN 3470-1-C
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 COVERED
7/78 - 12/78
14 SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES
541-2556.
IERL-RTP project officer is Norman Kaplan, Mail Drop 61, 919/
16. ABSTRACT
This report gives results of a survey of operational flue gas desulfurization
(FGD) systems on coal-fired utility boilers in the United States. The FGD
systems installed on Units 1 and 2 at the Sherburne County Generating Station
of the Northern States Power Company is described in terms of design and per-
formance. Each unit is equipped with an alkaline fly ash/limestone two-stage
wet scrubbing system for the control of particulate and sulfur dioxide. Each
FGD system includes 12 modules, 11 of which are required for full-load operation.
The flue gas cleaning wastes are forcibly oxidized, concentrated in a thickener,
and discharged for final disposal in a plant-site clay-lined settling pond. The
Sherburne 1 and 2 systems were certified commercial on May 1, 1976 and April 1,
1977 respectively. Operation has been accompanied by a number of problems,
most of which have been or are being resolved through system design modifications.
Designed for a minimum availability of 90%, the modifications have increased
availabilities to the low to mid 90 percent range. The systems have demon-
strated compliance with particulate and sulfur dioxide emission regulations.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Flue Gases
Desulfurization
Fly Ash
Limestone
Slurries
Ponds
Scrubbers
Coal
Combustion
Cost Engineering
Sulfur Dioxide
Dust Control
Air Pollution Control
Stationary Sources
Wet Limestone
Particulate
13B
21B
07A,07D
11G
08H
21D
14A
07B
IB. DISTRIBUTION STATEMENT
19. SECURITY CLASS (ThisReport)
Unclassified
21. NO. OF PAGES
126
Unlimited
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
KPA Form 2220-1 (»-7J)
C-18
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