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IECM Technical Documentation:

Wastewater and Solid Waste Management

January 2019

IECM Technical Documentation:


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 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.


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).


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


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


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.


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


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.


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.


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)


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.


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


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


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.


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



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


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)


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)


Figure 10. Power Requirement for the Beavon-Stretford Process


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


Figure 11. Predicted vs. Actual Costs for Two-Stage Claus Plants


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.


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


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)


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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