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IECM Technical Documentation:
Wastewater and Solid Waste Management
January 2019
IECM Technical Documentation:
Wastewater and Solid Waste Management
Prepared by:
The Integrated Environmental Control Model Team
Department of Engineering and Public Policy
Carnegie Mellon University
Pittsburgh, PA 15213
www.iecm-online.com
For
U.S. Department of Energy
National Energy Technology Laboratory
P.O. Box 880
Compiled in January 2019
Integrated Environmental Control Model - Technical Documentation Table of Contents • iii
Table of Contents
Table of Contents iii
List of Figures iv
List of Tables v
Acknowledgements vi
Wastewater and Solid Waste Management 1
Wastewater Management ...................................................................................1
Waste and Wastewater Streams .............................................................1 Wastewater Treatment Technologies .....................................................5 References ............................................................................................10
Appendix ..............................................................................................11 Fly Ash Disposal ..............................................................................................11
Fly Ash Management ...........................................................................11
Reference .............................................................................................12 Slag Disposal at IGCC Power Plants ...............................................................12
Sulfur Disposal at IGCC Power Plants ............................................................12 Process Description ..............................................................................12 Performance Model ..............................................................................14
Sulfur Recovery Cost Model ...............................................................18
References ............................................................................................22 Nomenclature .......................................................................................22
Integrated Environmental Control Model - Technical Documentation List of Figures • iv
List of Figures
Figure 1. Chemical Precipitation Process Scheme (EPRI, 1992) ......................................................... 6
Figure 2. Vapor Compression Evaporator System Scheme (EPRI, 1992) ........................................... 9
Figure 3. Options of Fly Ash Disposal in IECM ................................................................................ 11
Figure 4. Option of Slag Disposal in IECM ....................................................................................... 12
Figure 5. Initial Catalyst Requirement for Two-Stage Claus Plant .................................................... 14
Figure 6. Annual Makeup Catalyst Requirement for Two-Stage Claus Plant .................................... 15
Figure 7. Initial Catalyst Requirement for the Beavon-Stretford Process .......................................... 15
Figure 8. Annual Catalyst Requirement for the Beavon-Stretford Process ........................................ 16
Figure 9. Power Requirement for Two-Stage Claus Plants ................................................................ 17
Figure 10. Power Requirement for the Beavon-Stretford Process ...................................................... 17
Figure 11. Predicted vs. Actual Costs for Two-Stage Claus Plants .................................................... 18
Figure 12. Predicted vs. Actual Cost of the Beavon-Stretford Section .............................................. 20
Figure 13. Initial Stretford Chemical Cost for the Beavon-Stretford Process .................................... 21
Figure 14. Annual Chemical Cost for the Beavon-Stretford Process ................................................. 22
Integrated Environmental Control Model - Technical Documentation List of Tables • v
List of Tables
Table 1. Chemical Precipitation Typical Design Parameters ............................................................... 6
Table 2. Typical Chemical Dosage Range for Chemical Precipitation ................................................ 7
Table 3. Concentration of Sludge Solids from Chemical Precipitation (% solids by weight).............. 8
Integrated Environmental Control Model - Technical Documentation Acknowledgements • vi
Acknowledgements
This documentation is a compilation of one working report and some contents of other reports:
• Berkenpas, M.B.; Kietzke, K.; Rubin, E.S. PISCES- Power Plant Chemical Assessment Model (3.03):
User Documentation. Prepared by Carnegie Mellon University for the Electric Power Research Institute,
March 1999.
• Rubin, E.S.; Berkenpas, M. B.; Frey, H. C.; Chen, C.; McCoy, S.; Zaremsky, C. J. Technical
Documentation: Integrated Gasification Combined Cycle Systems (IGCC) with Carbon Capture and
Storage (CCS). Prepared by Carnegie Mellon University for the National Energy Technology Laboratory,
May 2007.
• Zhai, H.; Rubin, E.S. Wastewater System and Treatment for Coal-fired Power Plants. Working Report
Prepared by Carnegie Mellon University. Pittsburgh, PA 15213, 2009.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 1
Wastewater and Solid Waste Management
Wastewater Management
There are a variety of waste and wastewater streams produced at coal-based power plants. This
report is to present the approaches that empirically quantify waste and wastewater streams and
provide preliminary estimates of the performance and cost of wastewater treatment processes.
Waste and Wastewater Streams Combustion of fossil fuels generates by-products and wastes. These are generally categorized into
two groups: high-volume wastes and low-volume wastes. In addition, there is an amount of
blowdown produced when a wet cooling tower is used. The amount of waste and wastewater streams
is empirically estimated as illustrated later.
High-Volume Waste Streams
Bottom ash and fly ash are two types of ash residues produced from coal combustion. At coal-fired
power plants, high-volume waste streams include fly ash wastes, bottom ash wastes, and flue gas
desulfurization (FGD) sludge.
Fly ash is the portion that is entrained in the flue gas and removed by an air pollution control system.
An electrostatic precipitator (ESP) is often installed to reduce particle emissions to acceptable levels.
The solid waste management in a power plant may consist of two separate systems: a pond for
bottom ash solids with the optional addition of fly ash and a pond or landfill for flue gas treatment
solids that may include fly ash and/or FGD solids (Bedillion et al., 1997; Berkenpas et al., 1999).
Thus, there are several ways to deal with fly ash: mixed with bottom ash, mixed with FGD wastes,
and no mixing.
Bottom ash pond is a basic facility dealing with high-volume ash wastes. In a wet sluicing system,
bottom ash is sluiced with water and transported to an ash pond where bottom ash settles in the
pond. The flows into the bottom ash pond often include bottom ash slurry, cooling tower basin
sludge, and others. When comanaged with the bottom ash, the fly ash slurry is also added to the
influent streams. The flows out of the pond include leachate, overflow, and sluicing evaporation loss.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 2
The overflow of the ash pond may be recirculated to sluice bottom and/or fly ash. The detailed ash
pond performance model is available elsewhere (Bedillion et al., 1997).
FGD is widely used to remove sulfur dioxide (SO2) from the flue gas at coal-based power plants. A
major environmental flow stream emanating from the wet FGD system is the stream of wet solids.
There are two types of FGD: forced oxidation and natural oxidation. A forced oxidation FGD system
produces a gypsum waste, whereas a natural oxidation FGD system produces a wet sludge. The
difference in the composition and mass flow rate of FGD wastes depends on the extent of oxidation
of calcium sulfite to sulfate and the extent of dewatering of the final product (Bedillion et al, 1997).
Low-Volume Waste Streams
Low-volume wastes considered include fireside cleaning wastes, air preheater cleaning wastes, floor
and yard drains, coal pile runoff, boiler blowdown, and demineralizer regenerant wastes. In addition,
slip stream and makeup water treatment wastes may be produced when a wet cooling tower is used.
Fireside Cleaning Wastes A small amount of fuel combustion by-products deposits on the furnace surfaces, such as
precipitators, economizers, superheater tubes, and boiler water tubes (EPRI, 1997). The fireside is
washed on a periodic basis. In general, fireside cleaning generates an average volume rate of 2.9
gallons per day per megawatt (gpd/MW) (EPRI, 1987; EPRI, 1997). The flow rate of fireside
cleaning is:
24/2000/= MWgrm firesidefireside (1)
Where firesidem is the amount of fireside cleaning waste (tons/hr); firesider is the fireside washing
water volume rate (2.9 MWgpd / ); MWg is the gross electricity output ( MW ); is the water
density (8.33 lb/gal); 2,000 is the unit conversion factor (lb/ton); and 24 is the unit conversion factor
(hr/day).
Air Preheater Cleaning Wastes A small amount of fuel combustion by-products adheres to the air heater surfaces. The air heaters are
cleaned with low- or high-pressure water spray at a frequency generally ranging from once per
month to once per year (EPRI, 1997). The average volume of air heater washing water at a coal-fired
plant is 14.5 gpd/MW (EPRI, 1987; EPRI, 1997). The flow rate of air heater cleaning wastes is:
24/2000/= MWgrm preheaterpreheater (2)
Where preheaterm is the amount of air heater cleaning waste (tons/hr); MWg is the gross electricity
output ( MW ); preheaterr is the air heater washing water volume rate (14.5 gpd/MW); is the water
density (8.33 lb/gal); 2,000 is the unit conversion factor (lb/ton); and 24 is the unit conversion factor
(hr/day). Air heater and fireside washing water is often routed to ash ponds due to their similarity to
ash sluice water (EPRI, 1997).
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 3
Floor and Yard Drains Numerous locations within a power plant generate wastewater that is collected in drainage systems.
Pump seals, tank leakage, wash water, and temporary supply lines contribute to floor and yard drain
flows. The volume rate of wastewater collected from floor and yard drains is estimated to be 30
gpd/MW, with an additional 10 gpd/MW contributed from laboratory sample lines used to analyze
boiler operation (EPRI, 1987; EPRI 1997). The flow rate of floor and yard cleaning wastes is:
24/2000/= MWgrm draindrain (3)
Where drainm is the amount of the floor and yard cleaning wastes (tons/hr); MWg is the gross
electricity output ( MW ); drainr is the floor and yard drain wastewater volume rate (40 MWgpd / );
is the water density (8.33 lb/gal); 24 is the unit conversion factor (hrs/day); and 2,000 is the unit
conversion factor (lbs/ton).
Coal Pile Runoff Coal pile runoff is an intermittent waste stream produced during periods of rainfall and snowmelt.
The chemical character of coal pile runoff varies with the chemical characteristics of the coal, while
the quantity of coal pipe runoff depends on precipitation and coal pile configuration. The flow rate
of coal pile runoff is (Bedillion et al., 1997):
( ) ( )20001224365/0082.0855.0 rainfal += pilecoallrunoff Ahm (4)
The area of coal pile is empirically estimated based on the coal density, a 30-day supply, and a 10-
foot high pile under a rectangular cross-section as:
pilecoalfuelpilecaol hmA /3024/2000 = (5)
Where runoffm is the flow rate of coal pile runoff (tons/hr); fuelm is the fuel consumption (tons/hr);
pilecoalA is the coal pile area ( 2ft ); lhrainfal is the average yearly rainfall (in/yr, default 40); pilecoalh is
the high pile (ft, default 10); is the water density (64 lbs / ft3); is the coal density (84 lbs/ft3);
365 is the unit conversion factor (days/yr); 24 is the unit conversion factor (hrs/day); 12 is the unit
conversion factor (inch/ft); and 2,000 is the unit conversion factor (lbs/ton). In practice, the coal pipe
runoff may be pumped to a wastewater treatment basin or directly to an ash basin, or recycled for
use as makeup water (EPRI, 1997).
Boiler Blowdown To maintain boiler operation, blowdown is necessary to remove dissolved salts and suspended solids
from the boiler. Without the blowdown, the concentrations of dissolved components within the
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 4
boiler water can increase and lead to boiler damage. See the plant water usage report for the
approach to quantify the boiler blowdown (Zhai et al., 2009).
Demineralizer Regenerant Waste Boiler requires high-purity water for efficient steam production. The wastes are produced when fresh
water making up for the boiler is treated. Ion exchange beds are often used to treat boiler makeup
water. The demineralizer regenerant wastes that accumulate on the exchange resins during the
regeneration cycle of makeup water must be periodically removed to regenerate the beds for further
use. The demineralizer wastes flow rate is:
−
−= 1
%100
%100
min
min
dewst
boilerde MkwWst
(6)
Where boilerMkw is the amount of makeup water required by the boiler;
mindeWst is the amount of
demineralizer wastes (tons/hr); and mindewst is the percentage of the water entering the demineralizer
which exits in the waste stream (%).
Slip Stream Treatment Waste This is the waste produced from the recirculating cooling water by a slip stream treatment plant. The
waste from the slip stream treatment is:
slipwstslipcwslip mWst = (7)
Where slipWst is the waste from the slip stream treatment (tons/hr); cwm is the amount of
recirculating cooling water (tons/hr); slip is the percentage of recirculating water that is processed
by the slip stream treatment facility (%); and slipwst is the amount of waste produced by slip treatment
expressed as a percentage of water entering the slip stream treatment facility (%).
Makeup Water Treatment Waste from Wet Cooling System Depending on the quality of source water, a treatment facility may be needed to treat makeup water
for a wet tower. The waste from the makeup water treatment is:
−
−= 1
%100
%100
mwwst
cscs MkwWst
(8)
Where csMkw is the amount of makeup water required by the cooling tower system (tons/hr); csWst
is the amount of waste created by cooling makeup water treatment (tons/hr); and mwwst is the amount
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 5
of waste produced by cooling tower treatment expressed as a percentage of the water entering the
cooling tower treatment facility.
Cooling Tower Blowdown
Cooling tower evaporation leads to an increase in the concentration of salts or other impurities
dissolved in the recirculating cooling water. To avoid a high concentration and subsequent scaling
within a wet cooling system, it is necessary to blow down a portion of the cooling water and replace
it with fresh water. The tower blowdown can also be reused to sluice bottom ash or fly ash
(Berkenpas et al., 1999).
Wastewater Treatment Technologies Wastewater treatment technologies considered include chemical precipitation and vapor
compression evaporator (VCE). The performance and cost models of selected treatment technologies
are briefly presented. Detailed analysis and discussion about individual treatment technologies are
available from a technical manual provided by the Electric Power Research Institute (EPRI) (EPRI,
1992).
Chemical Precipitation
Chemical precipitation is a common treatment process to alter the chemical equilibrium of a solution
for reducing the solubility of the constituents of concern, especially heavy metals (EPRI, 1992). It is
effective for the removal of compounds, including arsenic, boron, fluoride, and selenium. The design
presented here preliminarily evaluates the equipment size and chemicals. Actual design and
performance have to be determined by testing on actual wastewater.
Treatment Process
The precipitation process is a combination of coagulation, flocculation, and sedimentation. Figure 1
presents a typical chemical precipitation process scheme. Treatment process components typically
include rapid-mix tank, flocculation tank, clarifier, and chemical storage and feed systems for lime,
polymer, and coagulant (EPRI, 1992). Chemicals are often added to form particles that settle and
remove contaminants. Lime is popularly used for chemical precipitation. To make effective removal
of the insoluble compounds, coagulants, such as aluminium and iron salts, are usually added in a
rapid-mix tank in order to neutralize charges and promote the formation of settleable precipitations.
After rapid mixing, interparticle bridging and formation of an agglomerate solid take place during
the flocculation process. The clarifier is often used to remove solid wastes.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 6
Figure 1. Chemical Precipitation Process Scheme (EPRI, 1992)
Treatment Unit Sizing The major design parameters for sizing a chemical treatment process include rapid-mix time,
flocculator time, and clarifier overflow rate. Typical values or ranges for these performance
parameters are given in Table 1.
Table 1. Chemical Precipitation Typical Design Parameters
Process Unit Parameter Typical Value*
PH adjustment Reaction time 10-30 min
Coagulation Rapid-mix detention time 1-2 min
Flocculation Detention time 20-30 min
Clarification Overflow rate 500-1,000 gal/day-ft2
Clarifier depth 7-15 ft
* Source of data: EPRI, 1992.
Once process design parameters are given, the rapid-mix volume is:
RMQRMV = (9)
The flocculation volume is:
FTQFLV = (10)
The clarifier diameter is:
=
OR
QCD
14404 (11)
Where Q is the flow rate (gpm); RM is the rapid-mix time (min); FT is the flocculator time (min);
OR is the clarifier overflow rate (gpd/ft2); RMV is the rapid-mix volume (gal); FLV is the
Sludge
EffluentInfluent
Rapid-Mix Flocculator Clarifier
Lime Feed Coagulant Feed Polymer Feed
Sludge
EffluentInfluent
Rapid-Mix Flocculator Clarifier
Lime Feed Coagulant Feed Polymer Feed
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 7
flocculation volume (gal); CD is the clarifier diameter (ft); and 1,440 is the unit conversion factor
(min/day).
Chemicals Usage The amount of chemicals required is highly variable and is empirically estimated as the product of
chemical dosage and wastewater flow rate:
CFQDosM cheche = 0022.0 (12)
Where CF is the plant capacity factor (%); cheDos is the chemical dosage (mg/l);
chemM is the
required chemicals (tons/yr); Q is the influent flow rate (gpm); and 0.0022 is the complex unit
conversion factor (see the Appendix). The typical chemical dosage is summarized in Table 2.
Table 2. Typical Chemical Dosage Range for Chemical Precipitation
Chemicals Dosage Range (mg/l)
Precipitation lime 150-500
Co-precipitation ferric chloride 20-100
Co-precipitation alum. 5-20
Polymer 0.1-5
Sludge Production Sludge production is highly dependent on chemical dosage, wastewater quality, and removal
objectives and is estimated in terms of influent flow rate and sludge production rate:
012.0= QSP (13)
Where Q is the influent flow rate (gpm); SP is the sludge production per day (lb/day); is the
settleable solids produced by precipitation (mg/l); and 0.012 is the complex unit conversion factor
(see the Appendix).
On a volume basis, the sludge produced is:
12=
SPSQ (14)
Where SQ is the sludge production (gpd); is the sludge solids concentration (% solids by weight);
and 12 is the complex unit conversion factor (see the Appendix). As given in Table 3, the sludge
solid concentration is related to the removal objective.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 8
Table 3. Concentration of Sludge Solids from Chemical Precipitation (% solids by weight)
Removal Objective Range Typical value
Heavy metal removal 0.5-1 0.7
Softening 3-5 4
Electricity Requirement The electricity required for influent and influent pumping is:
CFPQ
E pump
= 8760746.0
1714 (15)
Where CF is the plant capacity factor (%); pumpE is the electricity required by pumping (kWhr/yr);
P is the pumping pressure (psi); Q is the wastewater flow rate (gpm); is the pump efficiency
(default 70%); 0.746 is the conversion factor (kW/hp); 8,760 is the unit conversion factor (hr/yr);
and 1,714 is the complex unit conversion factor (see the Appendix).
The electricity required for mixing process is:
CFRMV
Emix =−
8760746.01048.7
3 (16)
Where mixE is the electricity required by mixing process (kWhr/yr); RM is the rapid-mix time
(min); CF is the plant capacity factor (%); 7.48 is the water density (gal/ft3); 0.746 is the conversion
factor (kW/hp); 8,760 is the unit conversion factor (hr/yr); and 310
− is the conversion factor (hp/ft3).
Chemical Treatment Cost Estimate The total plant cost (TPC) of wastewater treatment is estimated based on EPRI’s Technical
Assessment Guide (EPRI, 1993), which consists of process facility cost (PFC); general facilities
capital (GFC); engineering and home office overhead, including fees; and project and process
contingencies. The capital cost includes the elements for tanks, piping, chemical feed system, valves,
clarifier, sludge pump, electrical and instrumentation, and local control. Based on EPRI’s studies
(1992), the direct PFC is estimated as a function of influent flow rate:
4947.061195.0)1992,10($ QPFC = ( 0.1
2=R ) (17)
Where Q is the wastewater flow rate (gpm). The indirect capital costs are empirically estimated as a
percentage of PFC. Total maintenance cost of chemical precipitation is estimated to be 5% of TPC.
Vapor Compression Evaporator
VCE can be used to treat wastewater at zero-discharge power plants.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 9
Treatment Process As shown in Figure 2, the vapor produced from evaporating the wastewater is compressed to elevate
its temperature and then used as the heat source in the same evaporator (EPRI, 1992). Acid or alkali
may be added for pH adjustment, depending on acidity and alkalinity of the wastewater. Wastewater
reduction reaches up to 97 percent. Recovered water from the VCE system can be recycled as
makeup water or other process water. Brine produced in the system typically has a total solid
concentration in the range of 200,000 mg/l to 300,000 mg/l. In general, the VCE system has energy
requirements of 0.07 to 0.09 kWhr per gallon of influent wastewater.
Figure 2. Vapor Compression Evaporator System Scheme (EPRI, 1992)
Process Sizing A key process design parameter is concentration factor. The concentration factor is:
in
it
VCETS
TScf lim= (18)
Where VCEcf is the concentration factor; itTS lim is the concentration limit of total solids (mg/l); and
inTS is the total solid concentration of the influent.
The blowdown brine flow rate is:
VCEcf
QBD = (19)
The distillate flow rate is:
BDQDIS −= (20)
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 10
Where Q is the flow rate (gpm); BD is the blowdown brine rate (gpm); and DIS is the distillate
flow rate (gpm).
Electricity Requirement The typical power consumption rate is 0.08 kWhr per gallon, which includes pumps, compressors,
etc. (EPRI, 1992). The electricity required for the VCE operation is:
525600= CFQEVCE (21)
Where CF is the plant capacity factor (%); VCEE is the total required electricity (kWhr/yr); Q is the
flow rate (gpm); is the power consumption rate (0.08 kWhr/gallon); and 525,600 is the unit
conversion factor (min/yr).
VCE Treatment Cost Estimate The capital cost components include tanks, evaporator body, heat exchangers, de-aerator, pumps and
compressor, electrical and instrumentation, and control. Based on EPRI’s studies, the direct PFC is
estimated as a function of influent flow rate:
4639.062818.0)1992,10($ QPFC = ( 0.1
2=R ) (22)
Where Q is the wastewater flow rate (gpm). The indirect capital costs are also empirically estimated
as a percentage of PFC. The total maintenance cost is estimated to be 6% of TPC.
References Berkenpas, M.B.; Kietzke, K.; Rubin, E.S. PISCES- Power Plant Chemical Assessment Model
(3.03): User Documentation. Prepared by Carnegie Mellon University for the Electric Power
Research Institute, March 1999.
Bedillion, M.; Berkenpas, M.B.; Kietzke, K.; and Rubin, E.S. PISCES Power Plant Chemical
Assessment Model Technical Documentation. Prepared by Carnegie Mellon University for
the Electric Power Research Institute, July 1997.
Electric Power Research Institute. Manual for Management of Low-Volume Wastes from Fossil-
Fuel-Fired Power Plants: Final Report. Report No. EPRI-CS-5281, EPRI, Palo Alto, CA,
July 1987.
Electric Power Research Institute. Wastewater Treatment Manual for Coal Gasification- Combined-
Cycle Power Plants, Volume 2: Process Design and Cost Guide. Report No. TR-101788,
EPRI, Palo Alto, CA, December 1992.
Electric Power Research Institute. TAGTM Technical Assessment Guide: Electricity Supply - 1993,
Volume 1, Rev. 7, Report No. TR-102276-VIR7, EPRI, Palo Alto, CA, June 1993.
Electric Power Research Institute. Coal Combustion By-Products and Low-Volume Wastes
Comanagement Survey. Report No. TR-108369, EPRI, Palo Alto, CA, December 1997.
Zhai, H.; Berkenpas, M.B.; Rubin, E.S. IECM Model Documentation: Plant Water Usage. Prepared
by Carnegie Mellon University for U.S. DOE National Energy Technology Laboratory,
Pittsburgh, PA, May 2009.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 11
Appendix
Complex Unit Conversion Factors
( )( )( )( )( )( )tonlbkgmg
kglbgallyrdaysday
/2000/10
/21.2/8.3/365min/14400022.0
6=
( )( ) ( )psiftgallb
hplbft
/31.2/34.8
min/000,331714
−−=
( )( )lmg
gallbday
/10
/34.8min/1440012.0
6=
gallb /34.8
%10012 =
Fly Ash Disposal
Fly Ash Management There are three options available for fly ash disposal in the Integrated Environmental Control Model
(IECM): “No Mixing,” “Mixed w/ FGD Wastes,” and “Mixed w/ Bottom Ash,” as shown in Figure 3.
The default option shown for an ESP only is to allow “No Mixing.” When a wet FGD is chosen for
SO2 removal, fly ash may be mixed with either FGD waste (“Mix w/ FGD Solids”) or bottom ash
(“Mix w/ Bottom Ash”). The “Mix w/ Bottom Ash” option indicates that the fly ash is sluiced and
combined with the bottom ash.
Figure 3. Options of Fly Ash Disposal in IECM
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 12
Reference Berkenpas, M.B.; Kietzke, K.; Rubin, E.S. PISCES- Power Plant Chemical Assessment Model
(3.03): User Documentation. Prepared by Carnegie Mellon University for the Electric Power
Research Institute, March 1999.
Slag Disposal at IGCC Power Plants
The default option for slag disposal at an integrated gasification combined-cycle (IGCC) power plant
is landfill, as shown in Figure 4. The slag collected is disposed in a landfill.
Figure 4. Option of Slag Disposal in IECM
Sulfur Disposal at IGCC Power Plants
Process Description
Claus Plant Sulfur Recovery
In most IGCC cost studies, sulfur recovery is assumed to be achieved using a Claus plant to produce
elemental sulfur. This section presents an overview of the design features of a Claus plant in the
IGCC process environment. For additional detail, see (Fluor, 1985) or any of the other detailed
design studies of IGCC or coal-to-synthetic natural gas (SNG) systems used to develop this process
area cost model.
The inlet stream to the Claus plant is the acid gas from the sulfur removal section. In this study, only
data for Claus plants that process the acid gas from a Selexol unit are considered. The acid gas
typically contains primarily carbon dioxide (CO2) and hydrogen sulfide (H2S). In order to produce
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 13
elemental sulfur, a 2:1 ratio of H2S and SO2 is required. Therefore, a portion of the incoming acid
gas is combusted in a two-stage sulfur furnace. The furnace temperature is high enough in the first
stage (typically 2,500°F) to destroy any ammonia in the acid gas. Intermediate pressure steam (e.g.,
350 pounds per square inch absolute [psia]) is generated from the waste heat produced in the sulfur
furnace, cooling the feed gas to the Claus converters to approximately 600°F. Further cooling to
350°F occurs in a sulfur condenser, generating low-pressure steam (e.g., 55 psia). Sulfur flows to a
gravity sump and is kept molten by condensing low-pressure steam that flows through coils in the
bottom of the sump.
Some of the furnace gas is used to heat the feed gas from the first condenser to approximately 450°F
prior to entering the sulfur converter, where H2S and SO2 react in the presence of a catalyst (e.g.,
Kaiser S-501) to produce elemental sulfur and water. This reaction is exothermic, and the outlet
temperature of the gas is approximately 630°F. The conversion rate is limited by thermal
equilibrium. Gaseous sulfur is recovered in a second condenser. The cooling may be accomplished
by heating water for fuel gas saturation. The feed gas is then mixed with the remaining combustion
gases and enters the second converter. A third condenser, in which water for fuel gas saturation may
be heated, is used for final sulfur recovery. The effluent gas from the Claus plant then passes through
a coalescer and then on to tail gas treatment.
Beavon-Stretford Tail Gas Treatment
In this section, an overview of the performance and design of the Beavon-Stretford process is
presented as background information for the development of a regression cost model. See (Fluor,
1983a) or (Fluor, 1983b) for a more detailed discussion of this process.
The Beavon-Stretford process is a modification of the Stretford process, which is designed to
remove H2S from atmospheric pressure gas streams and convert it to elemental sulfur. However, the
Stretford process is not appropriate for handling effluent gases containing SO2, carbonyl sulfide
(COS), or elemental sulfur. Therefore, a Beavon unit is used to catalytically reduce or hydrolyze
these species to H2S in the presence of a cobalt molybdate catalyst.
Because hydrogen is required for the reactions occurring in the Beavon unit, flash gas from the acid
gas removal section is used as a feed stream. The flash gas is partially combusted in a reducing gas
generator, mixed with the Claus plant tail gas, and the total gas stream then enters the Beavon
hydrogenation reactor. The hot gas from the reactor is cooled in a waste heat boiler where
intermediate pressure (e.g., 100 psia) steam is generated. The gas stream is further cooled in the
desuperheater section of a thermally integrated desuperheater/absorber vessel. The cooling of the gas
stream is accomplished by heat transfer with cooling water, which is recirculated through an air-
cooled heat exchanger. The gas stream then enters the absorber portion of the vessel, where more
than 99 percent of the H2S is removed by contact with a Stretford solution containing sodium
carbonate (Na2CO3). The treated gas is vented to the atmosphere.
The Stretford solution flows to a soaker/oxidizer, where anthraquinone disulfonic acid (ADA) is
used to oxidize the reduced vanadate in the Stretford solution. The ADA is regenerated by air
sparging, which also provides a medium for sulfur flotation. The sulfur overflows into a froth tank,
and the underflow from the oxidizer/soaker is pumped to a Stretford solution cooling tower and then
to a filtrate tank.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 14
The sulfur from the froth tank is pumped to a primary centrifuge, where the wet sulfur cake product
is reslurried and sent to a second centrifuge, after which the sulfur is again reslurried. The slurry is
then pumped through an ejector mixer, where the sulfur is melted and separated in a separator vessel.
The sulfur goes to a sump.
Performance Model
Claus Plant Catalyst Use
Initial Catalyst The initial catalyst requirement for two-stage Claus plants was found to depend on the recovered
sulfur mass flow rate. The initial catalyst requirement, in tons, is given by:
oCsCi mCAT ,,3
, 1003.5−
= R2 = .959
n = 12 (23)
Where:
1,000 ms,C,o 30,800 lb/hr
The regression model is shown graphically in Figure 5.
Figure 5. Initial Catalyst Requirement for Two-Stage Claus Plant
Makeup Catalyst The makeup Claus plant catalyst requirement is expressed in units of tons per year. This is the
amount of catalyst that must be replaced in an average year. It is based on a regression done by
(Frey, 1990).
oCsfiCcat mcm ,,,, 000961.0 = R2 = 0.843
n = 13 (24)
Where:
1,000 < < ms,C,,o <,26,000 lb/hr
The regression model is shown graphically in Figure 6.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 15
Figure 6. Annual Makeup Catalyst Requirement for Two-Stage Claus Plant
Beavon-Stretford Catalyst Use
Initial Catalyst The Beavon-Stretford process requires a catalyst for the Beavon unit and a special chemical for the
Stretford unit. The initial catalyst and chemical requirements for the Beavon-Stretford process were
estimated from the values reported in (Fluor, 1983a), which includes data for a range of plant sizes.
From these data, a simple linear relationship of catalyst and chemical requirements as a function of
the sulfur recovered in the Beavon-Stretford unit was identified.
In the case of the Beavon catalyst, the mass requirement as a function of sulfur flow rate can be
estimated. In the case of the Stretford chemicals, the mass requirement is not given. However, the
cost of the initial Stretford chemicals as a function of the recovered sulfur flow rate was developed.
The resulting regression models for the initial catalyst requirement (CATi,BS), in cubic feet, is:
oBSsBSi mCAT ,,, 641.03.1 +−= R2 = 1.00
n = 5 (25)
Figure 7. Initial Catalyst Requirement for the Beavon-Stretford Process
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 16
Makeup Catalyst This is the amount of catalyst that must be replaced in an average year. It is based on a regression
done by (Frey, 1990). The makeup catalyst requirement is expressed in units of cubic feet per year.
The data and regression are shown in Figure 8. Two outlier data points were excluded from the
analysis, as indicated in the figure. These points, both from the same study (Fluor, 1983b), appear
inconsistent with the more extensive set of data from the other study (Fluor, 1983a).
oBSsfiBScat mcm ,,,, 0856.0 = R2 = 1.00
n = 5 (26)
Where:
100 < ms,BS,o <,2,000 lb/hr
Figure 8. Annual Catalyst Requirement for the Beavon-Stretford Process
Energy Use
Claus Plant The auxiliary power consumption model for Claus plant in MW was developed by (Frey, 1990)
using 20 data points is given by:
oCsCe mW ,,, 000021.0 = R2=0.87 (27)
Where:
1,000 ms,C,o 30,800 (lb/hr)
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 17
Figure 9. Power Requirement for Two-Stage Claus Plants
Beavon-Stretford Unit
The auxiliary power consumption model for Beavon-Stretford plant in MW was developed by (Frey,
1990) and is given by:
oBSsBSe mW ,,, 00112.00445.0 += R2=0.990
n = 7 (28)
Where:
100 ms,BS,o 2,000 (lb/hr)
The regression model is shown graphically in Figure 10.
Figure 10. Power Requirement for the Beavon-Stretford Process
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 18
Sulfur Recovery Cost Model
Direct Capital Cost
Sulfur Recovery (Claus Plant) A direct cost correlation was developed for two-stage Claus plants based on data from a number of
gasification plant studies. A number of data points are not included in this correlation because they
represent either three-stage Claus plants or two-stage Claus plants with tail gas incineration and no
tail gas treatment, with the incinerator costs included in the direct cost.
The cost of a Claus plant is known to scale primarily with the recovered sulfur mass flow rate
capacity using the standard exponential scaling model with an exponent of approximately 0.6 (EPA,
1983). It appears that this scaling rule may have been the basis for developing the cost estimates of
Claus plants used in the design studies, because an excellent goodness-of-fit was found for a single
variable regression based on sulfur recovered. The scaling exponent that was obtained in the single
variate analysis was 0.668.
The regression model was further developed to represent the number of operating and spare trains
for each data point in the database. The Claus plant contains a two-stage sulfur furnace, sulfur
condensers, and catalysts. The cost model is the same as the one developed by (Frey, 1990). The
number of trains is estimated based on the recovered sulfur mass flow rate and the allowable range
of recovered sulfur mass flow rate per train used to develop the regression model. The number of
total trains is the number of operating trains and one spare train. Typically, one or two operating
trains are used. The direct capital cost model as developed by (Frey, 1990) and scaled to 2000
dollars is:
668.0
,
,,,96.6
=
CO
oCsCTC
N
MNDC
R2=0.994
n=21 (29)
Where:
)/(100,18695,
,,hrlbmole
N
M
CO
oCs
The regression model is shown graphically in Figure 11.
Figure 11. Predicted vs. Actual Costs for Two-Stage Claus Plants
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 19
As indicated above, the capacity of a single train varies by a factor of more than 20. Typically, one
or two operating trains and one spare train are used, each with equal capacity. Because there was a
prior expectation that the cost of the Claus plant should be modeled using an exponential scaling
relationship based on recovered sulfur capacity, with a coefficient near 0.6, this model can be
extrapolated at the high end of the range. However, as with all other models, it is recommended that
the number of trains be selected so that extrapolation is not required.
Tail Gas Treatment (Beavon-Stretford) The process is considered commercially available. The capital cost of a Beavon-Stretford unit is
expected to vary with the volume flow rate of the input gas streams and with the mass flow rate of
the sulfur produced. Data from two EPRI-sponsored studies were used to develop a regression cost
model (Fluor, 1983a; 1983b). An additional two studies were reviewed for inclusion in the database,
but information regarding key process parameters (e.g., recovered sulfur flow rate) was not reported.
The two EPRI studies report limited performance and cost data for nine different Beavon-Stretford
unit sizes. For example, there is incomplete information about inlet gas streams flow rates. Because
of the limited availability of performance data, a regression analysis based only on the sulfur
produced by the Beavon Stretford process was developed. However, this regression yielded an
excellent fit to the data. The direct capital cost model as developed by (Frey, 1990) and scaled to
2000 dollars is:
645.0
,
,,,1.7376.63
+=
BSO
oBSsBSTBS
N
mNDC
R2=0.998
n=7 (30)
Where:
200,175 ,, oBSsm lb/hr
The high coefficient of determination indicated for this model implies either that an exponential cost
model is an excellent predictor of the costs of Beavon-Stretford units, or that the costs developed in
the EPRI studies were based on a simple scaling model as an approximation. Therefore, it is not
immediately clear if this model merely represents an accepted industry practice for developing
preliminary cost estimates, or if it accurately reflects the cost of Beavon-Stretford units.
Typically, two operating and one spare train are assumed. Although the regression model is an
excellent fit to the data, it is recommended that the number of trains be adjusted so that the recovered
sulfur flow rate per train does not exceed the limits given above. As a default, the number of
operating and total trains for this process area is assumed to be the same as for the Claus plant
process area. The regression model is shown graphically in Figure 12.
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 20
Figure 12. Predicted vs. Actual Cost of the Beavon-Stretford Section
Operations and Maintenance (O&M) Cost
Makeup chemicals or catalysts are required for the sulfur removal and recovery systems in all IGCC
designs. For cold gas cleanup systems, the makeup requirements include Claus plant catalyst. For the
hot gas cleanup system with off-gas recycle, the only requirement is for makeup zinc ferrite sorbent.
For a hot gas cleanup system with sulfuric acid recovery, makeup sulfuric acid catalyst is also
required. The operating material requirements for these systems are summarized below.
To estimate the total variable operating cost, the annual material requirements appropriate to the
given system must be multiplied by their respective unit costs. The total variable cost is then:
== iisconsumable UCmOCVOC (31)
Claus Makeup Catalyst Cost The makeup solvent cost in units of M$/yr in 2000 dollars is calculated as follows:
08.478, =CcatUC $/ton catalyst
=
−
$
$0.1m
$ 6iC,cat,,,
Me
yr
ton
tonUCVOM CcatCcat (32)
Beavon-Stretford Makeup Catalyst Costs The makeup solvent cost in units of M$/yr in 2000 dollars is calculated as follows:
71.184, =BScatUC $/ton catalyst
=
−
$
$0.1m
$ 6iBS,cat,,,
Me
yr
ton
tonUCVOM BScatBScat (33)
Beavon-Stretford Makeup Chemical Costs The Beavon-Stretford process requires a catalyst for the Beavon unit and a special chemical for the
Stretford unit. The chemical requirements for the Beavon-Stretford process were estimated from the
values reported in (Fluor, 1983a), which includes data for a range of plant sizes. From these data, a
simple linear relationship of chemical requirements as a function of the sulfur recovered in the
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 21
Beavon-Stretford unit was identified, as shown in Figure 13. In the case of the Stretford chemicals,
the mass requirement is not given. However, the cost of the initial Stretford chemicals as a function
of the recovered sulfur flow rate was developed. The resulting regression models for the chemical
requirement, in 2000 dollars, is:
oBSsChemBSi mC ,,,, 8.85 = R2 = 1.00
n = 5 (34)
Where:
100 ≤ ms,BS,o ≤ 2,100 (lb/hr)
Figure 13. Initial Stretford Chemical Cost for the Beavon-Stretford Process
Beavon-Stretford Makeup Chemical Costs The regression shown below is the cost of the Stretford chemicals, in 2000 dollars, as a function of
the sulfur recovered in the Beavon-Stretford process. The model is shown graphically in Figure 14.
oBSsfChemBSi mcC ,,,, 170 = R2 = 1.00
n = 5 (35)
Where:
100 ≤ ms,BS,o ≤ 2,000 (lb/hr)
Integrated Environmental Control Model - Technical Documentation Wastewater and Solid Waste Mgmt • 22
Figure 14. Annual Chemical Cost for the Beavon-Stretford Process
References Fluor (1983a). Economic Assessment of the Impact of Plant Size on Coal Gasification Combined
Cycle Plants. Prepared by Fluor Engineers, Inc. for Electric Power Research Institute. Palo
Alto, CA. EPRI AP-3084. May.
Fluor(1983b). Shell-Based Gasification-Combined-Cycle Power Plant Evaluations. Prepared by
Fluor Engineers, Inc. for Electric Power Research Institute, Palo Alto, CA. EPRI AP-3129.
June 1983.
Fluor (1985). Cost and Performance of Kellogg Rust Westinghouse-based Gasification-Combined-
Cycle Plants. Prepared by Fluor Engineers, Inc. for Electric Power Research Institute, Palo
Alto, CA. EPRI AP-4018. June 1985.
Frey, H.C. and E.S. Rubin (1990), Stochastic Modeling of Coal Gasification Combined Cycle
Systems: Cost Models for Selected IGCC Systems, Report No. DOE/MC/24248-2901 (NTIS
No. DE90015345). June. Prepared by Carnegie Mellon University for U.S. Department of
Energy, Morgantown, WV.
Nomenclature
cf = Capacity Factor (fraction)
M,S,C,o = Molar flow rate of sulfur exiting Claus process (lbmole/hr)
ms,C,o = Mass flow of sulfur from Claus plant (lb/hr)
ms,BS,o = Mass flow of sulfur from Beavon-Stretford plant (lb/hr)
fHS = Fraction of hydrogen sulfide (by volume)
NT,C = Total number of Claus trains (integer)
NO,C = Number of operating Claus trains (integer)
NT,BS = Total number of Beavon-Stretford trains (integer)
NO,BS = Number of operating Beavon-Stretford trains (integer)
HS = Removal efficiency of hydrogen sulfide from Selexol system (fraction)
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