REQUIREMENTS FOR SO2 REMOVAL, 469

United States Regulations, 470 Japanese Regulations, 472 European Regulations, 473 Canadian Regulations, 474 Regulatory Benefits, 474

FORMATION OF SULFUR DIOXIDE AND SULFUR TRIOXIDE FROM COMBUSTION OF FUEL, 474

Sulfur Dioxide, 474 Sulfur Trioxide, 475

PROCESS CATEGORIES AND ECONOMICS, 476

SELECTION CRITERIA, 491

ALKALINE EARTH PROCESSES, 496 Limestone/Lime Process, 496 Magnesium Oxide Process, 539

ALKALI METAL PROCESSES, 544 Non-Regenerable, Alkali Metal-Based Processes, 544 Double Alkali Process, 546 Alkali Metal Sulfite-Bisulfite (Wellman-Lord) Process, 554 ELSORB Process, 559 Electrodialysis Regeneration (SOUL) Process, 560 Electrolytic Regeneration (Stone & Webster/lonics) Process, 561 Zinc Oxide Process, 562 Citrate Process, 563

466

CHAPTER 7

Sulfur Dioxide Removal

Sulfur Dioxide Removal 467

AMMONIA PROCESSES, 564

Basic Data, 565 Heat-Regenerative Ammonia Process, 568 Cominco Sulfur Dioxide-Recovery Process, 569 Ammonia-Ammonium Bisulfate (ABS) Process, 573 Catalytic/lFP/CEC Ammonia Process, 573 Walther Process, 575 ATS TechnologyTM Process, 578 General Electric Ammonium Sulfate Process, 579 Ammonia-Lime Double Alkali Process, 581 Ammonia-Calcium Pyrophosphate, 582

AQUEOUS ALUMINUM SULFATE PROCESS, 582

Dowa Dual Alkali Process, 582

FERROUS SULFIDE WITH THERMAL REGENERATION, 585

Sulf-X Process, 585

SULFURIC ACID PROCESSES, 585

Chiyoda Thoroughbred 101 Process, 585 ISPRA Bromine-Based Process, 588 Noell-KRC Peroxide-Based Process, 589

AMINE PROCESSES WITH THERMAL REGENERATION, 589

Basic Data, 590 Sulphidine Process, 591 ASARCO Process, 593 CANSOLV Process, 595 Dow Process, 596

SEAWATER PROCESSES, 597

Flakt-Hydro Seawater Process, 599 Bechtel Seawater Process, 600 Bischoff Seawater Process, 601

PHYSICAL SOLVENT PROCESSES, 601

Solinox Process, 602

468 Gas Purification

MOLTEN SALT PROCESS, 603

SPRAYDRYERPROCESSES,604 Aqueous Carbonate Process, 606 Lime Slurry Spray Dryer Processes, 607 Duct Spray Dryer Process, 614 Gas Suspension Spray Dryer Process, 61 4 Spray Dryer Byproduct Disposal and Use, 61 5

DRY SORPTION PROCESSES, 61 6

Injection of Dry Alkaline Solids, 617 Dry Lime/Limestone Processes, 61 8 Dry Soda Processes, 624 Dry Sorption Byproduct Disposal and Use, 626 Dry Metal Oxide Processes (Regenerative), 627 Alkalized Alumina Processes. 631

ADSORPTION PROCESSES, 634 Basic Data, 634 Carbon Adsorption Process with Water Wash Regeneration, 634 Carbon Adsorption Process with Thermal Regeneration, 637 Other Activated Coke Processes, 640

CATALYTIC OXIDATION PROCESSES, 641

SNOX Process, 642 Cat-Ox Process, 643 Catalytic Oxidation/Electrochemical Process, 645

GAS PHASE RADIATION-INDUCED CHEMICAL REACTION PROCESSES, 645

Ebara E-Beam Process, 645

ELECTROCHEMICAL CONVERSION TO SULFUR, 646

GAS PHASE REDUCTION, 646

Parsons Flue Gas Cleanup (FGC) Process, 646

REFERENCES, 647

Sulfur Dioxide Removal 469

Sulfur dioxide removal from flue gases has probably been the subject of more research than any other gas purification operation. This research had very little commercial impact until air pollution control regulations sparked explosive growth in the number of installed Flue Gas Desulfurization (FGD) systems. Since the vast majority of SO2 emissions are from fossil fuel-fired boilers at power stations, these sources have been widely controlled. Exten- sive application of wet FGD occurred in the United States and Japan in the 1970s and in Germany and the rest of Europe in the 1980s. Partly due to a lack of understanding of funda- mental chemical reactions and their impacts on process and equipment design, early U.S. wet FGD systems earned a reputation for being troublesome and expensive to operate. As a result, the simpler and less expensive spray dryer FGD processes were rapidly adopted for the low sulfur coal applications that dominated the U S . utility FGD market in the 1980s. Dry injection processes also emerged as a viable option for applications where removal requirements were modest. But, at the same time, the wet limestonellime FGD technology matured. Many of the problems experienced with the early wet scrubbers were solved, and U.S. and overseas designs incorporated numerous advances. Present designs have close to 100% reliability and high SO2 removal efficiency (90 to 98%) (Saleem, 1991B). Recent installations incorporate many improvements, such as standardized designs, in situ oxidation, reduced or no outlet flue gas reheat, and single train absorber systems, resulting in lower cost and improved reliability.

FGD process selection is usually based on securing the lowest life-cycle cost consistent with the least risk of failure to meet reliability and performance requirements. Processes that make marketable byproducts have been selected for those locations where byproduct dispos- al costs are high, where the law offers virtually no alternative (e.g., in Germany where gyp- sum is produced), or where there is a market for gypsum (e.g., in Japan, where there is no natural gypsum). The requirement for low risk has dictated the selection of simple processes that have undergone exhaustive development and that have progressed to commercial opera- tion through successively larger demonstrations and multiple full-size systems. This extreme conservatism, which is forced upon the power industry by its regulated nature, creates a tremendous obstacle to the introduction of new FGD technology. Nonetheless, the large potential market continues to lure process developers. The most successful of these have been the Japanese and German variations of the conventional wet limestone/lime technology. This chapter provides information to help in the selection and application of suitable FGD processes from the large number of possible alternatives. Consistent with this large number of alternatives is an enormous volume of published information, some of which is reviewed in this chapter.

REQUIREMENTS FOR SO2 REMOVAL

One of the first precedents for establishing limits on sulfur dioxide discharge in terms of ground level concentration was set in connection with the operation of smelters in the Salt Lake district of Utah in 1920. This resulted in the imposition of a regime which limited the sulfur dioxide concentration to 1 ppm (for an hourly average) at the level of vegetation dur- ing the growing season (Katz and Cole, 1950; Swain, 1921).

The Trail, Canada smelter of the Consolidated Smelting and Mining Company of Canada, Ltd., was the subject of a prolonged international investigation which resulted in the estab- lishment of an operating regime setting the maximum permissible discharge in terms of tons per hour under certain weather conditions and restricting sulfur dioxide emissions in terms of ground level concentration and duration (Dean and Swain, 1944). The first known instance

470 Gas Purification

where sulfur dioxide removal was a legal requirement for the operation of a large power plant was at the Battersea Station of the London Power Company, which was constructed in 1929 (Hewson et al., 1933). More recently, blanket restrictions in many areas have limited the quantities and concentrations of SO2 that can be emitted.

Environmental regulations are the driving force behind the need for and selection of FGD systems and dictate many design criteria. For example, they limit the amounts of the pollu- tants which can be discharged to the atmosphere and to any waterway. They also place limits on the concentration of toxic metals and other chemicals in landfilled byproduct, which can significantly affect the FGD process selection. Landfill material characteristics, such as leachate composition, permeability, and compressive strength and the availability of a suit- able landfill site can also be important. Expected future regulations on traces of toxic sub- stances and fine particulate may also affect the selection of a sulfur dioxide removal process.

Regulations are often written in terms of thermal megawatts consumed, MW,, because of the variations in plant efficiency. In a typical coal-fired power plant, the efficiency of con- verting heat to electricity is 33 to 35.5%, making the net electric megawatts produced, MW,, approximately one-third of the thermal megawatts consumed. In co-generation plants, part of the steam produced can be used for purposes other than generating electricity, or electricity is generated by a gas turbine as well as a steam turbine with consequent higher heat utiliza- tion, causing the relationship between MW, and MW, to vary significantly. For comparative purposes, in a typical coal-fired power plant one MW, produces about 2,400 scfm (standard cubic feet per minute) of flue gas under normal operating conditions for many coals. Howev- er, the MW, equivalent volume can be 10% higher for some coals, such as those from the Powder River Basin. Actual gas volumes are affected by the boiler exit gas temperature, which typically ranges between 220°F and 350°F for many coal-fired plants, and the gas pressure, which varies due to the altitude of the plant and the fans in the gas system.

IEA Coal Research’s FGD Handbook: Flue Gas Desulphurization Systems tabulates SO2 emission standards, guidelines, and proposed regulations in 21 countries (Klingspor and Cope, 1987). Ellison (1993) also gives ranges of national emission standards for many coun- tries and SO2 emission ceilings/targets in the European Community for large existing com- bustion plants.

United States Regulations

In the United States, the Air Quality Act of 1967 required the establishment of air quality criteria for pollutants such as SO2, the monitoring of the pollution levels of all metropolitan areas, and the selection of air quality regions. It also required a report on the technology that could be used to control these pollutants. The Clean Air Act of 1970 dictated a revised strate gy with emphasis on attainment of the clean air standards by 1975 (Engdahl, 1973). The fail- ure of the Act to achieve its goals prompted its replacement by the Clean Air Act of 1977. Because of this law, some power plants that were both high SO2 emitters and located in areas that failed to attain the air quality criteria for SO2 were retrofitted with FGD systems. All new power plants were required to reduce SO2 emissions, which in this era meant FGD systems.

The Clean Air Act Amendments of 1990 built upon the SO2 control requirements of 1977 by expanding the clean air provisions in the revised Title I, adding acid rain provisions, and capping SO2 emissions at 8.9 million tons of SO2 in the new Title IV.

Both Titles I and IV affect new SO2-emitting facilities, but Title I is the primary regula- tion. It continues the requirement that new facilities meet a criterion called New Source Per-

Sulfur Dioxide Removal 471

formance Standards (NSPS). Refer to Table 7-1. With today’s emission controls, this stan- dard is considered to be relatively straightforward to meet, but even with low sulfur coal, uncontrolled emission of SO2 is not permitted. In SOz attainment areas (areas where the ambient air quality standards are being met), new facilities must continue to go through the process called Prevention of Significant Deterioration (PSD). PSD does not involve a set level of emission or a set degree of reduction, but requires use of the Best Available Control Technology (BACT). A “Top Down” BACT analysis, in which the applicant must use the top (most effective) emission control system that cannot be shown to be technically, eco- nomically, or environmentally infeasible, is required. BACT is often more stringent than NSPS. In SOz non-attainment areas, new facilities are allowed, but they must satisfy a requirement called Emission Offset Policy. This policy requires reducing emissions from one

Table 7-1 Federal New Source Performance Standards

Affected Source Category Facilities Maximum Emissions

Fossil-Fueled Steam Generators

Sulfuric Acid Plants

Petroleum Refiners

Primary Copper Smelters

Primary Zinc Smelters Primary Lead Smelters

Petroleum-Refinery Sulfur Recovery Plants

Coal- and Oil-Fired Boilers Solid Fuel:

Liquid Fuel:

2 kg S02/metric ton (mton) (4 Ib S02/ton H2S04) and 0.075 kg acid mist/mton H2S04 (0.15 lb acid mist/ton H2S04)

230 mg/dry std m3 (0.10 graiddry std ft3)

1.2 lb S02/106 Btu*

0.8 g S02/106 Btu Process Equipment

Refinery Process Equipment including waste-heat boilers and fuel gas combustors

Copper Converter

Fuel gas max H2S:

Roaster, Smelting Furnace 0.065% SO2 by VOI

Roaster, Sintering Machine Sintering Machine, Dross

0.065% SO2 by VOI 0.065% SO2 by V O ~

Reverberatory Furnace, Electric Smelting Furnace, and Converter

oxidation or reduction with incineration excess air reduction without incineration

Clam Plant 0.025% SO2 by vol dry at 0%

0.030% by vol reduced sulfur compounds dry at 0% excess air and 0.0010% by vol H2S dry at 0% excess air

*Maximum emissions allowed vary with the sulfur content of the fuel and other factors, but in no event exceed

Source: CFR (1990) 1.2 lb/106 Btu.

472 Gas Purification

or more existing facilities to offset all the new SO2 emissions, and using Lowest Achievable Emission Rate (LAER) technology to minimize the new emissions. Unlike BACT, LAER does not accept high cost as an argument against the use of a technology.

Title IV’s SO2 emissions cap means that all new S02-emitting facilities must purchase SOp emission allowances freed up by reduction of SO2 emissions at existing facilities. Thus, construction of a new facility may require SO2 emission controls at existing facilities that would not require them for any other reason. No matter how tightly emissions are controlled, an emission allowance must be obtained for every ton of SO2 emitted over the life of the facility. These allowances can be obtained from within the company, or from other sources. However, ultimately they are obtained only through emissions reductions at existing facili- ties. Market conditions in 1996 indicate that other provisions are forcing such rapid emission reductions that allowances are currently inexpensive. However, when developing a new SO2- emitting facility, allowances may create a financial incentive to reduce emissions even lower than Title IV would require.

For existing facilities, the Title I PSD provision is not new, so it would be unusual for new measures to be required at a facility simply because it is located in a sulfur dioxide non- attainment area. Acid rain is an issue apart from breathable air quality, so it affects facilities although the air around them attains the clean air standard. Title IV requires Phase I units (a specific group of 261 units) to reduce SO2 emissions in two steps, with first step compliance by the Phase I date (January 1, 1995), and second step compliance by the Phase I1 date (Jan- uary 1, 2000). The structure of the law is such that the utilities can decide which units to con- trol, when, and by how much. The utilities can choose interim solutions of modest control such as coal switching or dry sorbent injection for all their units to meet the Phase I date, with more costly measures reserved to meet the Phase I1 date, or they can implement highly effective (and costly) measures on a few units in Phase I, and on the rest by the Phase I1 date. There are incentives for early compliance. A larger group than the Phase I group, all other units 75 MW, and larger, called Phase I1 units, must also comply by the Phase I1 date. Howev- er, these units should be able to comply with relatively low-cost methods.

In general, the US. federal regulations do not require any particular technology, and it is very difficult to generalize about allowable emission levels or required percent reduction from uncontrolled emission levels. While state and local regulations generally reiterate the federal requirements, these agencies do have the regulatory option to impose more stringent emission limits. Few areas, however, actually implement tighter requirements.

Japanese Regulations

Japan began regulation of SO2 emissions with the Air Pollution Control Law in 1968. Japanese law began differently than U S . law, setting emission limits for each plant, rather than air quality objectives for every area. This was amended in 1970, but it failed to deal with heavily industrialized areas. In 1974, a further amendment initiated the concept of regu- lation to achieve air quality in each area, similar to the U S . approach in Title I.

Japanese limits vary with the region and the stack height and are in terms of cubic meters of SO2 per hour. The permissible SO2 emissions vary between about the equivalent of 8 ppmv and 190 ppmv. Early FGD systems were usually installed on units that burned high- sulfur oil, but in the 1980s many new coal-fired units were equipped with FGD systems.

Sulfur Dioxide Removal 473

Units 100 to 300 MW, (Approx. 35 to 105 MW,)

European Regulations

FGD in Europe began as local authorities in some German states required the retrofit of SO2 scrubbers to handle a portion of the flue gas from certain boilers that were particularly problematic. By 1983, some 14 units had been installed. The environmental movement built rapidly in Germany, and a law known as GFAVO passed in June 1983. It established the fed- eral limits shown in Table 7-2, and required compliance by June 1988. In spite of the feverish activity this schedule required, the industry responded and nearly all of the some 150 affected units complied on schedule. However, the cost and disruption it caused probably influenced the framers of the flexible, two-phase acid rain law enacted in the U S . in November 1990.

In Germany, state and local authorities continue to enforce stricter SO2 limits (200 mg/Nm3 is common) where special problems exist.

The European Community (EC) has enacted legislation that asks its members to adopt limits similar to the German GFAVO. FGD systems were installed rapidly in Austria, Den- mark, Holland, and Turkey. Italy and the U.K. followed shortly thereafter. Even before the

Units 50 to 100 MWt

(Approx. 17 to 35 MW,)

Table 7-2 German Federal SO2 Emission Regulations for Coal-Fired Units

New Units

Existing Units

*Ifvery higi

Fluidized Bed Combustion

Pulverized Coal Firing or Stoker Firing

Remaining Service Life over 30,000 hours (approximately 4 years base-loaded) Remaining Service Life 10,000 hours to 30,000 hours ( 1 H to 4 years base- loaded) Remaining Service Life less than 10.000 hours

Units Larger Than 300 MWt (Approx. 105

MWe)

400 mg/Nm3 (between 0.3 and 0.8 lb/106 Btu) and 85% removal*

400 mg/Nm3 (between 0.3 and 0.8 lb/106 Btu) and 75% removal

2,000 mg/Nm3 2,000 mg/ (between 1.5 and Nm3 (between 3.9 lb/106 Btu) 1.5 and 3.9 lb/ and 60% removal lo6 Btu) and use

low-sulfur coal

2,500 mg/Nm3 (between 1.9 and 4.8 lb/106 Btu)

~~

Existing Limits

32 content or widely variable SO] content indicates 400 rng/Nm’ is unattainable with BACT, 650 mg/Nm’ (0.5 to 1 . 3 lb/106 Btu) applies.

Source: Siegfriedt and Ludwig (1984)

474 Gas Purification

dissolution of the Eastern Bloc and the Soviet Union, activity had begun there. The EC now sees scrubbing in Eastern Europe as much more cost-effective than further measures within member nations, so FGD systems are being installed in the Czech Republic, Slovenia, Poland, and Russia, generally with funds from Western governments and without any regula- tory requirements. A number of the Eastern European countries have enacted regulations with compliance scheduled in the late 1990s.

Canadian Regulations

In Canada, the Federal Ministry of the Environment has no specific SO2 removal require- ments, but encourages the provinces to regulate SO2 emissions. Each province has applied its own approach, depending on the mix of emissions found there. For example, most of Ontario’s emissions are from power plants that belong to provincially-owned Ontario Hydro, so the province prepared a plan specific to that utility. British Columbia has very lit- tle pollution from power plants, so it targets industrial sources. The differences in approach even extend to the means of measurement, where some provinces choose the European method (mg/Nm3) while others choose the U.S. method (lb/106 Btu). The Canadian attitude is also unusual, evidenced by a greater spirit of cooperation between the regulatory agencies and industry and by industry’s seeming willingness to comply early and/or beyond the letter of the regulations.

Regulatory Benefits

Sulfur dioxide emissions in the United States in 1975 were officially estimated at 33 mil- lion tons per year. The goal of the Clean Air Act Amendments of 1977 was to reduce that to 28 million tons per year by 1990 (Bauman and Crenshaw, 1977). However, low growth in electrical demand, coupled with aggressive state programs and significant reductions in industrial emissions, brought the total to 18.9 million tons by 1990. The goal of the Clean Air Act Amendments of 1990 is to achieve 8.9 million tons per year total emissions by 2001 (Public Law 101-549, 1990).

FORMATION OF SULFUR DIOXIDE AND SULFUR TRIOXIDE FROM COMBUSTION OF FUEL

Sulfur Dioxide

Flue gases from combustion processes normally contain less than 0.5 vol 5% sulfur diox- ide. The relationship between the sulfur content of the fuel and the sulfur dioxide content of the resulting flue gas is shown in Table 7-3. This table gives the sulfur dioxide content of combustion gases from several typical fuels.

Stack gas from smelters handling sulfur ores, on the other hand, can have very high sulfur dioxide concentrations. Therefore, the economics of recovering sulfur values from such gases can be much more favorable. Of course, the problems of discharging such gases with- out sulfur dioxide removal are also much more acute.

Sulfur Dioxide Removal 475

I

Table 7-3 Sulfur Dioxide Concentrations in Typical Combustion Flue Gases’

Fuel

Sulfur in

Fuel, wt Yo

Coal: Missouri Beever

Coal: Illinois No. 6 Coal: Pennsylvania Coal: New Mexican Coal: Powder River

Oil: California No. 2 Oil: Low Sulfur No. 6

(Raw)

Basin

5.9 3.5 1.7 0.5

0.35 0.27 0.21

With Excess Air HzOin SOzin S 0 2 i n

Flue Flue Flue Gas, Gas, Gas,

vol% ppmw ppmv

9.5 10,972 5,059 9.5 6,507 2,997 8.0 2,671 1,236 8.4 830 383

13.3 818 371 12.2 307 138 11.9 234 105

With Air Heater Leakage HzOin SOzin SOzin

Flue Flue Flue Gas, Gas, Gas,

vol% ppmw ppmv

8.5 9,541 4,381 8.5 5,658 2,596 7.2 2,323 1,070 7.5 722 332

11.8 711 322 10.8 267 120 10.6 203 91

Notes: I . These SOz concentrations assume no sulfur in the ash and no conversion of SOz to SO3. In the U.S., credit for

coal cleaning is allowed, but seldom practiced. 2. Gas concentrations are based on 20% excess airfor coal and on I S and 18% excess air, respectively, for No. 2

and No. 6 oil. Air heater leakage is 15% for all cases. Air heater leakage (7%) = (lb wet air leakage X 100%)/(lb wetflue gas) per American Sociery of Mechanical Engineers (ASME) Power Test Code (PTC) 4.1.

removal of the sulfur bearing compounds from the gas prior to sale and are not included in this table for that reason.

3. SO2 concentrations influe gases from the combustion of natural gas are typically extremely low due to the

4. Gas concentrations are usually expressed in terms of ppmv by convention.

Many large smelting operations that produce very high concentrations of sulfur dioxide feed the gas stream directly into a sulfuric acid plant. The design and operation of acid plants of this type are not discussed in this text, as they are considered to represent a separation and chemical manufacturing operation, not a gas purification process. On the other hand, the removal of sulfur dioxide from dilute smelter off-gas streams and the recovery of unconverted sulfur dioxide from the acid plant tail gas constitutes gas purification problems and are reviewed in this chapter.

Sulfur Trioxide

Most combustion gases that contain sulfur dioxide also contain a small, but significant amount of sulfur trioxide (or its reaction product with water, sulfuric acid). This component is of considerable importance because of its highly corrosive nature, its effect on the chem- istry of many sulfur dioxide recovery processes, and its suspected critical role in air pollution problems. The amount of sulfur trioxide emitted to the atmosphere is a function of combus- tion aidfuel ratio, fuel composition, combustion temperature, time at temperature, the pres- ence or absence of a catalyst, electrostatic precipitator conditioning with ammonia, and the

476 Gas Purification

type of flue gas desulfurization system. The equilibrium concentrations of the principal sul- fur species in the combustion gas from a typical fuel oil at several aidfuel ratios have been calculated by Pebler (1974). The results show that in excess air mixtures at equilibrium, SO2 is the most stable compound above 1,000"K; SO3 is the predominant sulfur compound between 900 and 600°K; while, on further cooling, H2S04 gains dominance over SO3.

Sulfuric acid condenses below 400°K. Fortunately, equilibrium conditions are not attained in conventional combustion processes. However, the presence of catalytically active materi- al, such as vanadium in oil and iron pyrites in coal, can increase SO3 formation. In the absence of actual analytical data for specific cases, a rough estimate of the SO3 concentration expected in combustion gases from coal and oil may be obtained from Table 7-4, which pre- sents data compiled by Pierce (1977).

The sulfuric acid dew point of combustion gases, which is the key parameter with regard to stack corrosion, has been studied by a number of investigators. The available data have been reviewed and correlated by Pierce (1977), who presented the results in graphical form. Selected points from his correlations are given in Table 7-5. Tables 7-4 and 7-5 can be used to estimate the sulfuric acid dew point of typical combustion gases in the absence of any other data. Flue gases should be kept above the estimated dew point to prevent corrosion of metals (e.g., carbon steel) by sulfuric acid. Mixtures of acids with higher dew point tempera- tures may condense; however, only limited information is available on the phenomena. Berg- er et al. (1984) review the corrosivity of various flue gas condensates. For the cases studied, sulfate was the predominant anion contributor to the acidity of the condensate, while chlo- rides and fluorides contributed to a lesser extent.

PROCESS CATEGORIES AND ECONOMICS

A great many processes have been proposed for removing sulfur dioxide from gas streams. Relatively few processes have attained commercial status; and, of those that have, many have not found a significant place in the U.S. market. In the U.S., only the 1imestoneAime wet FGD systems, predominantly with spray, tray, or packed tower absorbers; and the lime spray dryer systems are widely accepted today. Users have opted for low cost, proven systems that oper- ate with high availability (Schwieger and Haynes, 1985). Today, the FGD impact on utility system equivalent forced outage rates is usually less than 1% (NERC, 1991). The reliance of utility companies on extremely mature technologies makes it difficult for suppliers of new technologies to bid on scrubber contracts (McGraw-Hill, 1991).

Although the primary emphasis of this text is on commercial processes, other processes can provide valuable background data pertaining to the development of new improved processes. For this reason, some developing processes that appear to have the potential for future commercialization are presented. Also, some processes that are no longer considered viable, but once represented major developmental efforts or commercial operations, are reviewed. With the new legislation mandating control of NO, from many sources, there is a renewed interest in combined SO,/NO, technologies by both developers and users due to the potential cost savings. The NO, control aspects of a number of these processes are covered briefly in this chapter. More information on some of these processes and NO, only control processes is provided in Chapter 10.

To organize the many FGD processes that have been developed, the authors have departed from the categorization as either regenerable or non-regenerable commonly used by many.

Sulfur Dioxide Removal 477

Excess Oxygen H 2 0 Air in Gas, in Gas,

Fuel wt % vol % vol %

Sulfur Trioxide Expected in Gas, ppmv, with Fuel Sulfur Content of:

0.5 1.0 2.0 3.0 4.0 5.0 wt % wt % wt % wt % wt % wt %

Coal 25 4 8-13 Oil 25 4 11 Oil 17 3 12 Oil 11 2 13 Oil 5 1 13

I Source: Pierce (1977) except for H 2 0 in gas, which are calculated values for typical fuel compositions

3-7 7-14 14-28 2 0 4 0 27-54 33-66 12 15 18 22 26 30 10 13 15 19 22 25 6 7 8 10 12 14 2 3 3 4 5 6

~

Table 7-5 Sulfuric Acid Dew Point of Typical Combustion Gases

I

Water Vapor Acid Dew Point "C (OF) for Sulfur Trioxide Concentrations of:

5 in:

1 0.5 1 10 25 100 500 vol% ppmv ppmv ppmv ppmv ppmv ppmv ppmv

104 (219) 110 (230) 125 (258) 132 (270) 142 (288) 157 (315) 177 (350) 10 110 (229) 116 (240) 131 (267) 137 (279) 147 (296) 162 (323) 180 (357) 14 114 (236) 120 (247) 134 (274) 141 (286) 150 (302) 165 (328) 183 (361)

I Source: Pierce (1977)

e.g., by IEA Coal Research in FGD Handbook: Flue Gas Desulphurization Systems (Klingspor and Cope, 1987). Here, FGD processes are categorized based on the initial SO2 removal step, which reveals the greatest commonality among the processes. A detailed cate- gorization of FGD processes following this procedure is given in Figures 7-la and 7-lb. Specific sulfur dioxide removal processes are described in the subsequent sections of this chapter, which generally follows the sequence of Figures 7- la and 7-lb.

Table 7-6 provides a comprehensive list of FGD processes identified by name (or develop er) and categorized in accordance with the methodology of Figures 7-la and 7-lb. The table includes commercially important processes as well as processes that have been abandoned or not yet fully developed. Data are also given on the U.S. supplier and status of maturity of each process. Table 7-7 provides similar information on FGD byproduct treatment processes.

Not all process types indicated in Figures 7-la and 7-lb are represented by commercial processes. In fact, a list of US. power plant FGD systems operational, under construction, or planned as of December 1987, includes only 11 different processes (See Table 7-8). Between 1977 and 1983, the number of operating plants increased from 29 to 114, while the number of processes employed increased by only one (Pedco, 1977; Laseke et al., 1983).

478 Gas Purification

1. LimestonelLime Slurry ’

I. Absorptio in Liquids

b. lnhltitad Oxidation SuIfile

c. Natural oxidation > W ~ u m S u l f i l d

General Categories

A. Alkaline Metals >

Removal Agent

Sulhta

, > Sludge 2. Alkaline Fly Ash Slurry ~ None

3. Magnesia Slurry ~ a. Thermal Regeneration

Intermediate Steps Final Product

1 , Sodium or Potassium CarbonatelHydroxIdel 8. Alkali Metals . c SuHite/Citrate/Phosphate ’

d. Thermal Regeneration > Sulfur Dinxidm Crystallization

e’ > Sulfur Dioxide Electrolysis Sulfuric Acid

Sulfur Dioxidm f. Zlnc Oxide Regeneration

> Sulfur I g. Reduction

Sulfur Dloxidm

Calcium Sulfite or SulIat*

C. Ammonia

Dlammoniurn - > PhOrPhsld 2. Ammonia/

Calcium Pyrophosphate Calclum Sulfate

D. Aluminum Compounds . 1. Basic Aluminum Sulfate ~ a. Double Alkali Calcium Sulfite

. I . Ferrous Sulflde ~ a. Thermal Regeneration Sulfur E. Iron compounds r r

r r orsunate

1. Sulfuric Acid b. Acid Comenlratla

a Oxidatlon/PreciDitatlon, ~ ~ l c i ~ , , , Sulfite

% Sulfuric Acid F SuifuncAcid J 2 SuIfuric~cid/ . a OxidatlorJ Sulfuric Acid

Sulfuric Acid a. “21 3. Hydroaen Peroxide1 . HBrlBr2

Sulfuric Acid . 1. Amine . a. Thermal Regeneration, Sulfur DloxMa

. 1. WaterlSeawaler In Saawatmr

0. Oraanic Bases r r

a. None/Oxiation > Sulfile.ISulfa1e Ions H. Water

c Sulfur

a. Thermal Regeneration Sulfur Dioxide I. Physical Solvems . 1. Polyglycol Ether - r

r > Hydrogen Sulfide/ J. MoitenSahs . 1. Alkali Metal . a. Reduction

r Sulfur Carbonate

Figure 7-1 a. Categorization of wet sulfur dioxide removal processes.

Sulfur Dioxide Removal 479

. A. SprayDry II. Absorption by

Moist Particles r

General Categories Removal Agent Intermediate Steps Final Product

b. Reductiord Carbonate

Regeneration > Sulfur

I 2. Lime None > mlcium sulfite/ Sulfate

I T > CaldumSl(tr 1. LimelLimestone . None

r > Sodium Salts

r > Sulfur Dloxld.

2. SodiumCahnatd . None

3. Metal Oxides a. Reduction Bicarbonate

4. Alkalized Alumina . a. Reduction r > H2 S (or Sulfur)

Sulfur Dioxide a. Oxidation-

Sulfuric Add

2. Non-Readive . a. Thermal Sulfur Dloxids

Adsorbents Regeneration ’

> SulfurlcAcld

> Ammonium Sulfate

a. Absorption

b. Reaction A. Oxidation .

r

IV. GasPhase Conversion

Sulfur

> Sulfur

1. Electrochemical . a. Sulfur Reduction to S Vaporization

Reduction to H 2s Conversion

Figure 7-1 b. Categorization of dry sulfur dioxide removal processes.

Between 1983 and 1987, the number of operating plants increased from 114 to 149, and the number of processes increased by two (PEI Associates, 1989B). In mid-1977, Japan had almost 1,000 operational FGD plants utilizing about 15 basically different types of processes (Ando, 1977). However, the growth of FGD capacity in Japan was slow after 1977 (37 plants were built in the 1978-83 time period), and virtually no plants involving processes other than lirnestone/lime were built (Ando, 1983). A comprehensive evaluation and status report covering 189 flue gas desulfurization processes and 24 subsystems with regard to their applicability to power plants has been published by the Electric Power Research Institute (EPRI) (Behrens et al., 1984).

(text continued on page 489)

480 Gas Pur8cation

Table 7-6 FGD Process Suppliers

The process categories and process category numbers in this table correspond to those of Figures 7- la and 7-lb.

This list has been prepared as a preliminary guide to the reader. The large number of developers and suppliers makes it impossible to be completely accurate, and the constant flux in the market- place will assure that the list is promptly out of date. The reader is advised to use registers and regu- larly published lists of pollution control equipment suppliers (such as published by some trade mag- azines) and to consult suppliers for more accurate information.

The ownership/license status of the processes listed varies widely. Some of the processes are not considered proprietary in which case the listed suppliers have the expertise, experience, and/or will- ingness to offer the process commercially. Before proceeding with a project, the reader should ascer- tain the ownership status of the desired process. U.S. suppliers have been identified where known.

Key to Status

D Developmental S Development Apparently Stopped C Commercial U Unknown I Commercialized, but Apparently Inactive

Process Categories and Processes U.S. Supplier Status

ABSORPTION IN LIQUIDS

IAla LimestoneLime with Forced Oxidation ABB Environmental Systems

AirPol AirPol Babcock & Wilcox Bechtel (Pressure Hydrated Dolomite) Bechtel

Chiyoda CT-121 Chiyoda International Chuba-MKK Clean Gas Systems Deutsche Babcock Riley Environmental GEESI (Chemico based) GEESI Kawasaki (Limestone to Gypsum) Kawasaki (Mg enhanced) Kobe Steel Kobelco (CaCI) (also part of

Mitsubishi Pure Air Mitsui (Chemico based) Nippon Kokan (NKK) Nippon Steel (slag sorbent) NoelVKRC Research-Cottrell Procedair Procedair RileyBaarberg-Holter (S-H-U)

(limeklear solution) NaTec

(C-E, Peabody) ABB Envir. Systems

Babcock & Wilcox

Bischoff JOY

Clean Gas Systems

Mayemick & Associates

Cal-NO,)

C C C C C C S C C C C C

I C C C U C C

I

Sulfur Dioxide Removal 481

Table 7-6 (Continued) FGD Process Suppliers

Process Categories and Processes U.S. Supplier Status ~~

ABSORPTION IN LIQUIDS (Continued) Saarberg-Holter (S-H-U) (limestone/

Showa-Denko Steinmuller (Chemico based) Sumitomo-Fujikasui (Moretana)

Thioclear [to gypsum & Mg(OH)21 Thyssen Ube

formic acid) NaTec

(CIOz for NO,) Dravo

IAlb LimestoneMme with Inhibited Oxidation' ABB Environmental Systems (C-E, Peabody) ABB Envir. Systems Babcock & Wilcox Babcock & Wilcox RileyDeutsche Bahcock Riley Environmental GEESI GEESI Research-Cottrell Research-Cottrell Thiosorbic Dravo UOP Wheelabrator

IAlc LimestoneLime with Natural Oxidation' ABB Environmental Systems (C-E, Peabody) AirPol AirPol American Air Filter Anderson 2000 Anderson 2000

Babcock & Wilcox RileyDeutsche Babcock Riley Environmental GEESI (Chemico) GEESI Lewis Rotary Drum Dravo Mitsubishi Pure Air Nippon Kokan (NKK) Procedair Procedair Research-Cottrell Research-Cottrell Thiosorbic Dravo Thioclear [Gypsum & Mg(OH)21 Dravo Thyssen (CEA) UOP Wheelabrator Weir (Magnesium-enhanced) Kellogg

ABB Envir. Systems

Bischoff JOY Babcock & Wilcox

IA2 Alkaline Fly Ash Slurry ABB Environmental Systems (Peabody) Bechtel Bechtel CENADL Simmering-Graz-Pauker AG (Vienna)

ABB Environmental

C I C

D D C C

C C C C C C C

C C I C C C I C I C U C C C D I C I

C C I C

'Produces sludge that may require treatment f o r disposal.

482 Gas Purification

Table 7-6 (Continued) FGD Process Suppliers

Process Categories and Processes U.S. Supplier Status ~~ ~

ABSORPTION IN LIQUIDS (Continued)

IA3a Magnesium Oxide2 Bischoff (Acid Stripping and Thermal

Regeneration) Clean Gas Systems GEESI (Chemico) (Thermal Regeneration) GEESI Grillo (Thermal Regeneration) Kawasaki Magnesium Hydroxide to

Magnesium Hydroxide Process (MHP)

Mitsui Mining (Thermal Regeneration) Onahama-Tsukishima (Thermal Regeneration) Raytheon (formerly United Engineers and

Ube Magnesium Hydroxide to MgS04

Clean Gas Systems

MgS04 Discharge

to MgS04 IHI

Constructors) (Thermal Regeneration) Raytheon

Discharge

IBla Sodium Carbonate/Sodium Hydroxide ABB Environmental ABB Environmental Arthur D. Little (ex-CEA/ADL) Arthur D. Little AirPol Airpol Anderson 2000 Anderson 2000 Clean Gas Systems IHI-TCA Kawasaki Kurabo Kureha Oj i Ontario Hydro (FMC)' Ontario Hydro Procedair Procedair Showa Denko Tsukishima-Bachco UOP Wheelabrator

Clean Gas Systems

IBlb Sodiudk'otassium Salt with Oxidation Passamaquoddy Recovery Scrubber Passamaquoddy Sumitomo-Fujikasui (Moretana) (C102 for NO,)

IBlc Sodium Salt with Lime or Limestone Double Alkali Arthur D. Little (ex-CENADL) (lime) Arthur D. Little Arthur D. Little (ex-CENADL) (limestone) Arthur D. Little AirPol AirPol Anderson 2000 (lime) Anderson 2000 Asahi (limestone/oxidation; chelate for NO,) Buell (lime) GEESI

C C I I

C

C U U

C

C

C C C C C U C 1 U U 1 C U 1 1

C C

C S C C D 1

'Licensed fo r industrial applications to Advanced Air Technology. 2Separate process converts SO2 to sulfur or acid.

Sulfur Dioxide Removal 483

Table 7-6 (Continued) FGD Process Suppliers

Process Categories and Processes

ABSORPTION IN LIQUIDS (Continued)

U.S. Supplier

Kawasaki Kureha (sodium acetate/lime) Kureha-Kawasaki (limestone/oxidation) Ontario Hydro (FMC) (lime)' Ontario Hydro (FMC) (limestone)' Showa Denko-Ebara (limestone/oxidation) Tsukishima (limestone/oxidation) Zurn (lime) Zum

Ontario Hydro Ontario Hydro

IBld Sodium Salt with Thermal Regeneration* Aquaclaus Phosphate (sodium phosphate) Stauffer ELSORB (sodium phosphate) Elsorb Tung (organic extraction) Wellman-Lord (sodium carbonate)

Raycon R & D John Brown (Davy)

IBle Sodium Salt with Electrolytic/Electrodialysis Regeneration' IONICS Ionics SOXAL (Allied/Aquatech) Allied

IBlf Sodium Salt with Zinc Oxide Regeneration' Zinc Oxide (soddzinc oxide)

IBlg Citrate with Reduction Flakt-Boliden (sodium citrate) ABBFlakt U.S. Bureau of Mines (sodium citrate) U.S. Bureau of Mines (potassium citrate)

Stauffer Pfizer

ICla Ammonia with Thermal Regeneration' Cominco Exorption Cominco IFP/Stackpol 150 Simon-Carves

IClb Ammonia with Acid Stripping' ABS TVA Cominco Olin

IClc AmmonidAmmonium Sulfate, Sulfite & Thiosulfate ATS Technology Coastal Chem, Inc. GEESI GEESI Nippon Kokan (NKK) NONOX (multiple byproducts) Intelligent Resources Tampella (sulfite liquor) Ube Walther

ICld Ammonia, Lime Double Alkali Kurabo Nippon Kokan (NKK) SCRA

Status

U I C I S U U

I D D C

S D

D

I I S

I S S

S C

C D C D C I C

S D S

'Separate process converts SO2 to sulfur or acid.

484 Gas Purification

Table 7-6 (Continued) FGD Process Suppliers

I Process Categories and Processes U S . Supplier Status

ABSORPTION IN LIQUIDS (Continued)

IC2 Ammonia, Calcium Pyrophosphate r

Pircon-Peck (UT)

IDla Aluminum SulfateLime or Limestone Double Alkali Dowa IC1 Steam Stripping

IE la Ferrous Sulfide with Thermal Regeneration Sulf-x PENSYS

IF la Sulfuric Acid with Gypsum Byproduct Chiyoda CT-101 (CT-102 uses same

Showa Denko SO2 section)

IF2a Bromine with Sulfuric Acid & Hydrogen Byproducts ISPRA Ferlini/General Atomics

IF3a Hydrogen Peroxide to Sulfuric Acid Noell KRC Noell

IGla Amine with Thermal Regeneration' Asarco Asarco Cansolv (Union Carbide Canada) Dow Dow Lurgi Sulphidine NOSOX (Ethanolamine Glutarate) Monsanto TVA (melamine) UCAP UOP

Union Carbide

IHla Seawater Flakt-Hydro ABB Bechtel Bechtel Bischoff JOY

IIla Physical Solvent Linde Lotepro

IJ la Molten Salts Rockwell ABB Flakt

SPRAY DRYER (Spray Dryer and Duct Spray Dryer)

IIAla Soda to Sodium SulfitelSulfate Aqueous Carbonate Open-Loop (rotary

Babcock & Wilcox (nozzle) or nozzle) ABB

Babcock & Wilcox

'Separate process converts SO2 to sulfur or acid

D

I I

U

I U

D

D

C D I C S D D

C D D

C

S

I D

Suljiur Dioxide Removal 485

~~

Table 7-6 (Continued) FGD Process Suppliers

Process Categories and Processes U.S. Supplier Status

SPRAY DRYER (Spray Dryer and Duct Spray Dryer) (Continued)

Koch

Teller (nozzle) Research-Cottrell

Soda with Molten Carbonate Reduction to H2S1

Niro Atomizer (rotary) JOY

IIAlb Aqueous Carbonate Closed-Loop

IIA2 Lime to Calcium SulfrtelSulfate Spray Dryer

ABB (Flakt, Rockwell, Carborundum, C-E)

Babcock & Wilcox (nozzle) BuelVAnhydro (rotary) JoyEcolaire (rotary or nozzle) Lodge-Cottrell (low-speed rotary) Procedair Niro Atomizer (rotary) Research-CottrelVKomline-Sanderson (rotary) Wheelabrator (rotary or nozzle)

Duct Spray Dryer CZD

HALT (Hydrate Add'n @ Low Temp) HYPAS In-Duct

Air Pol GSA

(rotary)

E-SO,

Gas Suspension Absorption

ABB

ABB Babcock & Wilcox GEESI JOY Lodge-Cottrell Procedair JOY Research-Cottrell Wheelabrator

Bechtel Babcock & Wilcox/EPA Dravo Lime, U.S. DOE EPRI GEESI

Airpol

C I C

I

C C I C C C C C

D D D U D

C

DRY SORPTION

IIIAl Dry LimeLimestone

Furnace Sorbent Injection (FSI), LimeLimestone Injection with Multiple Burners (LIMB), Lime Injection and Hydrated Lime Injection in Upper Furnace (LI)

ABB C-E ABB C ARA (with ash reactivation for precipitator) D Babcock & Wilcox Babcock & Wilcox C Babcock-Hitachi Babcock & Wilcox D DISCUS (Inland Steel) Research-Cottrell C Fossil Energy Research Corp. (lime and urea) D R-SO, (LI) Electric Power Services D

'Separate process converts H2S to sulfur or acid.

486 Gas Purification

Table /-6 (Continued) FGD Process Suppliers

Process Categories and Processes U.S. Supplier Status

DRY SORPTION (Continued)

LIFAC (Tampella) Ontario Hydro Osterreichische Draukraftwerke PromiSoxflntevep Rileymesearch-Cottrell (lime and sodium

bicarbonate) Sonox (Ontario Hydro R&D) Steinmuller (with polisher) TAV Trocken (LIMB & LI)

Economizer Injection E1 (Economizer Injection)

Kaiser Ontario Hydro

Energy & Envir Rsch

Research Cottrell

Research-Cottrell D

Duct Injection ADVACATE (silicate enhanced) ABB Flakt D Babcock & Wilcox

(also part of SOX-NOx-Rox-Box) Babcock & Wilcox D Babcock-Hitachi Babcock & Wilcox D Coolside Consol/Babcock & Wilcox D LILAC MHI D Synergistic Reactor Aerological Resources D

Fluidized Bed Babcock-Hitachi Lin (catalytic SO3) Lurgi CFB Procedair Wulff

Babcock & Wilcox

Environmental Elements Procedair

IIIAZ Dry Soda (Duct Injection)

Sodium bicarbonate/nahcolite, Le., natural sodium bicarbonate ABB Environmental (Flakt) ABB EPRI (Arm & Hammer/Church & Dwight,

Kerr-McGee, Multi Mineral, Natrona Resources)

NaTec NaTec Solvay Wheelabrator Wheelabrator

Sodium sesquicarbonate (Na2C03 NaHC03 H20)/trona, i.e., natural sodium sesquicarbonate)

EPRI (FMC) FMC EPRI (Cominco) Cominco

IIIA3a Dry Metal Oxide' Dept. of Energy Solid Oxide (copper oxide) Exxon (comer oxide)

D D

D S _.

Houdry (Air Products) (copper & silica oxides) S

'Separate process converts SO2 to su(fur or acid.

Sulfur Dioxide Removal 487 Table 7-6 (Continued) FGD Process Suppliers

Process Categories and Processes U S . Supplier Status

DRY SORPTION (Continued)

Sorbtech (formerly Sanitech)

Shell (copper oxide) Showa-Denko (activated magnesia)

(magnesium oxide)

IIIA4a Alkalized Alumina' NOXSO U.S. Bureau of Mines

IIIBl Carbon Adsorption' Babcock-Hitachi Chemibau-Reinluft EPDC Activated Char Hugo Peterson (Steinmiiller) MitsuiBergbau-Forschung (Carbo Tech) Steag Sulfacid Sulfocarbon Sumitomo Takeda Unitika Westvaco

Sorbtech UOP

NOXSO

Babcock & Wilcox Gilbert

GEES1 Conradus Assoc., Ltd Lurgi

Westvaco

IIIB2a Non-Reactive Adsorbent with Thermal Regeneration

GAS PHASE CONVERSION

IVAla Catalytic Oxidation Bayer Double Contact (Farbenfabriken) Cat-Ox Monsanto Enviro-Chem DESONOX Degussa Electrochemical Membrane U of GA SNPA Topsoe WSA-SNOX (Haldor Tops0e) ABB Environmental

IVAlb Ammonia to Ammonium Sulfate, Nitrate E-Beam (radiation-induced chemical reaction) Ebara ENEL Pulse-Energization Karlsruhe Electron Streaming Treatment

IVBla Electrochemical Conversion to Sulfur IGR/Helipump Electrochemical Cell IGR Enterprises

IVB2a Catalytic Reduction Parsons FGC Ralph M. Parsons Chevron Chevron Ontario Research Foundation RutheniudAlumina

D S S

D S

I S D C C C C D C D S S

U

D D D

D

D S D D

'Separate process converts SO2 to sulfur or acid. Source: Siegfriedt et al. (1993)

488 Gas Purification

Table 7-7 FGD Byproduct Treatment Process Suppliers

Process Categories and Processes U.S. Supplier Status

Allied I CIL C Monsanto Monsanto C Nitrosyl-Sulfuric Acid C

SULFUR DIOXIDE TO SULFURIC ACID

SULFUR DIOXIDE REDUCTION TO SULFUR Allied Chemical (natural gas) Allied Chemical ASARCO (natural gas) ASARCO RESOX (coal) Foster-Wheeler Texas Gulf Sulfur (methane) Topsere Haldor Topsgie

CALCIUM SULFITE TO GYPSUM Sulfuric Acid Digestion (Japan) (Double Alkali) Kawasaki

CALCIUM SULFITE TO SULFUR Process Calx (converts sludge to Cas or FeS)

CALCIUM SULFITE TO HYDROGEN AND GYPSUM Hark (electrolysis) Ecolomics

U C

D

D

CALCIUM BYPRODUCT TREATMENT Amax Resource Recovery Systems, Inc. Calcilox Cefill Chemfix Controls Environmental Technology Corp. Marston Associates Ontario Liquid Waste Disposal Limited Poz-0-Tec Stabilisat TERRA CRETE Werner Pfleiderer Corporation

~ Wirtschaftsgut

D Dravo Lime I Cementa (Sweden) U Nat'l Environmental C

D D D

Conversion Systems C Steinmuller (Germany) U Sludge Fixation Tech. D

Knauf (Germany) U U

SODIUM BYPRODUCT TREATMENT Fersona (with ash to form briquettes) Sinterna Industrial Resources U

U

(Na2S04 with acidic femc solution to form very insoluble double salt)

Source: Siegfriedt et al. (1993)

Sulfur Dioxide Removal 489

Table 7-8 U.S. Power Plant Flue Gas Desulfurization Systems as of December 1987

Type System

Limestone, Wet (Non-Regenerative) Lime, Wet (Non-Regenerative) Lime/Alkaline Fly Ash, Wet Lime, Spray Dryer Lime, Hydrated-Duct Injection Magnesium Oxide (Regenerable) Sodium Carbonate, Wet (Non-Regenerable) SodiumLime Double Alkali (Non-Regenerable) Sodium Sulfite (Wellman-Lord, Regenerative) Sodium Carbonate Spray Dryer Trona Duct Injection Undecided

Total Number of Plants

Number of Systems Under

Operational Construction Planned

67 30 13 14 1 3 7 6 7 1 - - - 149

~

Source: PEI Associates (1989B)

(text continued from page 479)

Present trends in selecting FGD processes are indicated by the data in Table 7-9. This table shows the recent FGD technology selections (as well as some key design data for the systems) resulting from implementation of Phase I of the Clean Air Act Amendments of 1990. None of these systems are included in Table 7-8, which predates the 1990 Clean Air Act Amendments.

IEA Coal Research’s FGD Installations on Coal-Fired Plants (Vernon and Soud, 1990) compiles data gathered from around the world on over 500 FGD installations. The report shows that wet scrubbers using calcium-based sorbents are the most widely used. Increasing- ly, processes that produce gypsum are favored. Use of spray dryers and sorbent injection is growing in the U.S. and Europe, especially on small units, although their non-usable byprod- uct may hinder further expansion. Despite their potentially high-value byproducts, regenera- ble processes have achieved only limited use. New processes, especially those combining SO2 and NO, removal, are continually being developed. However, experience indicates that only a small portion of these technologies will achieve widespread commercial use. IEA Coal Research’s FGD Handbook (Klingspor and Cope, 1987) also provides information on the major types of FGD systems in use and planned.

The economics of FGD systems are site-specific and should be evaluated on a case-by- case basis. Nevertheless, some idea of the overall economics of flue gas desulfurization can be gained from Table 7-10 which provides data on 34 different FGD processes compiled from two reports issued by the Electric Power Research Institute. This organization has emerged as the major compiler of cost data for FGD systems. Care should be taken in using these data since costs are strongly affected by the assumed bases, including scope of items

Table 7-9 FGD Technology Selections for Phase I of the 1990 Clean Air Act Amendments (As of June 1992)

No. of Stations @ Design SO2 Number of Units with Removal Absorber Module Size

Number of Efficiency, % in % of Unit Size and Absorber Material StationdUnits (Refer to note 1) Total MW,, in MW,, per Module

Wet Limestone 1 1/20 With O.A. 10,94 I 8 wl one 100% module each Refer to note 2. with Forced I @ 98% 2 wl two 67% modules each Oxidation I @ 97% 3 wl two 50% modules each

1 @>95% 2 wl five 50% modules total 6 0 95% 1 wl three 50% modules total 2 @ 93% 2 wl three 40% modules each

2 wl three 33% modules each Without O.A. ( 1 00 to 650 MW, each)

7 0 95% 2 @ 93% 1 0 9 2 % 1 0 90%

I wl two 67% modules total Ferralium 225 Wet Limestonc I l l 91 650 with Inhibited (436 MW,each) Duplex Oxidation Stainless

Wet Lime, 3 wl one 100% module each 317L&317LM Magnesium- 215 95 & 98 4,520 (640 MW, each) Stainless Enhanced Steels (Thiosorbic Time) (217 MW, each)

Steel

2 wl six 20% modules each

Notes: 1. O.A. stund.sfor orgunic acid. Organic acids are specified for four stations and increase the removal elficiency by up to 6%. 2. Various materials are specified,for ilhe ubsorbers ($these wet limestone systems:four stations propose to use unclad alloys (thrce SI 7L, LM or LMN stainless steels and

one Hastelloy C27b), two clad steel (one with Hasilelloy C276 and one unspecified), two <.arbon steel wallpapered wiilh Hastelluy C276, one (I combination of solid and wallpapered Hastelloy C276, and two rubber lined carbon steel.

3. While the above Title IV/Phase I units accuunt for much of the FGD business for U S . suppliers during this period, there were a significant number ofawards,for new and retrofiil FGD systems in Cunadu and overseas no1 included in the above list.

Source: FGD & DeNO, Newsletter (1992)

Sulfur Dioxide Removal 491

included in capital costs, unit costs (and credits) assumed for calculating operating costs, assumed on-stream time, and the time frame of the estimate. Many recent U S . awards for limestone systems have been considerably below the EPRI database values due to the use of single 100% absorber modules, high velocity absorbers, no reheat, and no bypass, and sim- plified byproduct disposal in addition to very low profit margin, all of which differ from the EPRI database. It is also difficult to draw conclusions about new processes by comparing costs with those of proven systems because of the large uncertainties in cost estimates for processes still in the developmental stage.

A wealth of information is available for the prediction of the costs of large FGD systems. This information has been mostly developedfunded by EPRI and the EPA. The following references provide capital and operating cost information:

EPRI (3-3342 (Keeth et al., 1983) and EPRI GS-7193 (Keeth et al., 1991B, 1992) provide the cost data that are summarized in Table 7-10. Costs from the earlier report are higher than the more recently reported data, and costs from both reports are high based on market- place activity in the late 1990s. EPRI CS-3696 (Shattuck et al., 1984) provides a manual procedure for calculating retrofit FGD system costs. EPRI CS-5408-CCM (Stearns, 1987) covers a computerized version of the procedure out- lined by Shattuck et al. (1984). EPRI GS-7525-CCML (Keeth et al., 1991A) describes the computer model used in prepar- ing the data in EPRI GS-7193 (Keeth et al., 1991B, 1992). Sopocy et al. (1991) assembles a number of EPRI computer programs into a single package that can evaluate the applicability of various SO2 control technology options for a given application, determine costs of the technologies (fifteen in 1991), and evaluate proposals. It can also simulate wet limestone/lime processes. EPA/600/S7-90/022 (Maibodi et al., 1991) presents a computer model developed by the U.S. Environmental Protection Agency to estimate costs and performance of coal-fired util- ity boiler emission control systems. The model, which is based on user supplied data, gen- erates a material balance and an equipment list from which capital investment and revenue requirements are estimated. The model covers a number of conventional and emerging technologies. EPA/600/S7-90-91 (Emmel and Maibodi, 1991), PB91-133322 (Emmel and Maibodi, 1990), and EPA/600/7-88/014 (Radian, 1988) provide EPA cost estimates for specific coal- fired electric generating plants. Czahar et al. (1991) provide a handbook to aid in least-cost planning of emission control and acid rain compliance measures required by utilities.

SELECTION CRITERIA

Factors considered in the selection of sulfur dioxide removal systems vary with the type of system, but some important parameters are

gas flow rate (size) inlet and outlet sulfur dioxide concentrations installed cost types, quantities, qualities, and availabilities of sorbents, water, steam, and power

(text continued on page 494)

Table 7-1 0 Comparative Economics of Processes for Desulfurizing Power Plant Flue Gas

Capital Costs, $/kW A B C D

Dec 1982 Dec 1982 Jan 1990 Jan 1990 2 @ 500 MW, 2 @ 500 MW, 300 MW, 300 MW,

4.0% S 0.48% S 2.6% S 2.6% S Ref. Data Base 90% Rem 70%Rem 90%Rem 90%Rem

Process New New New Retrofit

Limestone-F.O. 177 - 166.2 216.2

Limestone-F.O. .- 183.7 243.4

- 169.2 234.6 Limestone-1.0. -

- 163.5 211.8 Limestone-DBA -

Limestone-Formic I30 145.5 189.2

Limestone-N.O. 1 I5 I 10 Limestone-N.O. 162 - 152.8 198.8

Limestone-Dowa 173 -

Chiyoda 139 __ 146.4 190.2

- 146.6 195.9 Pure Air Cocurrenc -

- 176.5 229.4 Limestone-F.O. -

Limestone-F.O. - 182.0 236.6

- 176.7 229.7 Limestone F.O. -

Lime-Magnesium- - 145.8 189.8

Lime-Dual Alkali 147 - 149.7 203.0 Lime-Conventional 163 -

111 129.8 166.3 Lime Spray Dryer -

- 221.2 Tampella LlFAC - -

__ 137.1 Lurgi CFB -

UON

(Disposal Grade)

(Wallboard Grade) -

-

Acid (S-H-U) - __

Dual Alkali - -

Thoroughbred 12 1

Bischoff

Noell-KRCRC

NSP Bubbler

Enhanced

-

~

- -

980% Rem -

Levelized Busbar Costs, mills/kWh (Current Dollars)' A B C D

Dec 1982 Dec 1982 Jan 1990 Jan 1990 2 @ 500 MW, 2 @ 500 MW, 300 MW, 300 MW,

4.0% S 0.48% S 2.6% S 2.6% S 70% Rem 90% Rem 90% Rem 90% Rem

UON

New New New Retrofit

1.5.8 - 11.5 13.0

- 11.5 -

- - 11.2 -

11.3 15.7 10.3

17.9 8 15.6 - 10.5

- - -

- -

- - -

- - - 14 9.6 13.5 __ -

(ruble continued on nex/ puge)

Table 7-10 (Continued) Comparative Economics of Processes for Desulfurizing Power Plant Flue Gas

A B C D Dee 1982 Dee 1982 Jan 1990 Jan 1990

2 @ 500 MW, 2 @ 500 MW, 300 MW, 300 MW, 4.0% S 0.48% s 2.6% S 2.6% S

Ref. Data Base 90% Rem 70% Rem 90% Rem 90% Rem UON

I Process New New New Retrofit

- 84.4

- 85.9

- 88.0

- 91.0

Advacate Moist Duct - -

Furnace Sorbent - -

Economizer Injection - -

Duct Sorbent - -

Injection

Injection @SO% Rem

050% Rem

Injection @SO% Rem

f Capital Costs, $/kW

HYPAS Dry Injection

Duct Spray Dryer

Nahcolite Injection Trona Injection Wellman-Lord Magnesium Oxide Sulf-x Fliikt-Boliden Aqueous Carbonate Conosox Passamaquoddy

Potassium

-

-

-

-

274 269 295 391 40 1 43 1 -

-

-

- -

217.0 217.8 - - - -

370.3

128.7 1.5% s

060% Rem 74.4

@SO% Rem

- 278.3 283.1

- -

48 1.4

Levelized Busbar Costs, m i M W h (Current Dollars)' A B C D

Dec 1982 Dec 1982 Jan 1990 Jan 1990 2 @ 500 MW, 2 @ 500 MW, 300 MW, 300 MW,

4.0% S 0.48% s 2.6% S 2.6% S 90% Rem 70%Rem 90%Rern 90%Rem

UON

New New New Retrofit

7.0

8.3 @ 50% Rem

8.3 0 50% Rem

- 8.5 @ 50% Rem

- - -

- - -

- - -

- -

- 8.8 - - 1 .5% s

0 60% Rem 6.8

@ 50% Rem - - -

- - 8.3 7

25.5 - 19.4 - 20

28.7 29.5 44.8

- - - -

- 13.3 - 13.7

- - - - - - - - - - - -

- - 19.2 -

Notes: I . Operating costs include normal operatinx expenses, capital churges, and creditsfor byproducts where applicable. Costs aretbr 65% capacity factor, 30-year (new) and IS-year (retro-

2. Abbreviations: Rem stands for Removal (of sulfur dimxide). UON stand.Y for Unless Otherwise Noted, F. 0. s tuds for Forced Oxidation, 1.0. for Inhibited Oxidation, N.O. for Natural

3. Data sources: A & B-EPRI Report CS-3342 (Keeth et a/., 1983). C & D-EPRIReport GS-7193 (Keeth et 01.. 1991%. 1992)

f i t ) levelized basis. The cost basis is per the study date. Note that the levelized cosfs are on a current basis; that is, they include the effect of interest and inflation.

Oxidation, and DBA for dibasic mid.

494 Gus Purification

(text continued from page 491)

types, quantities. characteristics, and disposal options for solid and liquid byproducts/

gas side pressure drop operating and maintenance labor and material space and sparing requirements ease and time of installation new vs. retrofit materials of construction

wastes

For salable byproduct processes, byproduct charactenstics and purity are significant con- siderations. For disposable byproduct processes, the availability of disposal sites, byproduct structural properties, and the landfill leachate properties are important factors. The need, or the potential need, to remove NO, and other pollutants should also be considered in the selection process. Some processes have the capability to remove NO, or other pollutants or can be modified to remove them. Failure to define the characteristics and availabilities of potential sorbents and wastes early in the project can lead to higher cost or poorer perfor- mance than expected. The use of a single, large module versus multiple modules or the inclusion of a spare module are also important considerations. In view of the steady improvement in scrubber reliability, there has been a growing trend toward the use of larger modules with no spares. The need for a quenchedpre-scrubber for temperature reduction, the requirement to handle failure of such a system, and/or the need to remove chlorides or partic- ulate matter are other early considerations.

For disposable byproduct processes, an early decision must often be made regarding the use of wet limestoneflime vs. spray dryer systems. Inlet and outlet SO2 concentrations are usually important in making such a decision. Many spray dryer FGD systems now operate or have been proposed to operate in the range of 90-95% SO2 removal, while wet limestone/ lime scrubbers are capable of removing about 98% SO2. If the regulatory requirements esca- late to 97% or 98% SO2 removal, the FGD selection could change from a spray dryer to a wet scrubber type.

Frank and Hirano (1990) survey the potential for the production and consumption of alter- native, usable, commercial byproducts in conjunction with a major reduction in national emissions of SO2 and NO,. They conclude that the potential byproduct yields from the U.S. acid rain control program greatly exceed available markets for the chemical products. Byproducts evaluated in the study include gypsum, sulfuric acid, ammonium sulfate, ammo- nium sulfatehitrate, and nitrogen/phosphorous fertilizer. Henzel and Ellison (1990) present a review of past, present, and potential future disposal practices and commercial FGD byprod- uct utilization. They indicate that the only discernable trend is the production of usable gyp- sum by wet FGD systems. The 1990 Clean Air Act Amendments may create a need for dis- posal sites, which tend to be expensive and scarce and which could in themselves be environmental problems. Systems that produce usable byproducts are expected to become more important in the future as the disposal option becomes less viable.

The SOz gas produced by many regenerable processes can be converted in an auxiliary plant into any of several byproducts, including liquid SO2, H2S04, and elemental sulfur. The marketability of these products depends on local demand and economic factors. Transporta-

SuEfur Dioxide Removal 495

tion distances and transportation methods, Le., pipeline, rail or road, are important factors in an economic analysis (Giovanetti, 1992A). Usually sulfuric acid is much more marketable than elemental sulfur, and elemental sulfur is more marketable than liquid sulfur dioxide. However, elemental sulfur is the least costly to store and transport. EPRI Report CS-3696 provides a decision logic approach for selecting a process for retrofit situations that takes many of the above factors into account (Shattuck et al., 1984). Table 7-11 gives typical quantities of sorbents required and byproducts produced on a pound of SO2 removed basis for several FGD processes.

It should be noted that FGD systems are not the only method of controlling flue gas SO2 emissions. Other potential methods are fuel cleaning, switching, and blending; unit retire- ment; purchase of SO2 emission allowances (in the US.); and the use of other technologies such as atmospheric fluidized bed combustion, pressurized fluidized bed combustion, gasifi- cation with fuel gas clean-up, etc. Only FGD systems are discussed in this chapter.

Table 7-1 1 Typical Quantities of Sorbents and Byproducts for Various FGD Processes’

(Pounds per pound of SO2 removed)

1 Quantities of Sorbent Required Quantities of Byproduct Produced

Limestone (Wet Process)’ 1.83 Gypsum Byproducts 3.15 Lime (Wet ~ r o c e s s ) ~ 1.02 Inhibited Oxidation Byproduct9 2.88 Hydrated Lime (Wet P roce~s )~ 1.35 Natural Oxidation Byproductlo 4-7+ Mg-Enhanced Lime (Wet P roce~s )~ 1.08 Lime Spray Dryer Byproduct” 3.24-3.69 Lime (Spray Dryer P roce~s )~ 1.20-1.47 Sulfuric Acid, 98S% 1.55 Soda Ash (Wet Process)6 1.66 Elemental Sulfur 0.50 Sodium Hydroxide (Wet Process)’ 2.50 Sodium Sulfite/Sulfate’’ 2.03 Ammonia OS3 Ammonium Sulfate 2.03 Notes:

1. Quantities of sorbent and byproduct are calculated based on stoichiometric equations and assumptions given below. Most sorbents contain some water that has not been included. Quantifies will vary with the quality of the sorbent, the presence of other acid species such as HCl and HFl in the flue gas, and other factors.

2. Dry limestone with 6% inerts and 1.10 C d S ratio. 3. Dry lime with 10% inerts and 1.05 CdS ratio. 4. Dry magnesium-enhanced lime with 10% inerts, 5% magnesium oxide, and 1.05 C d S ratio. 5. Dry lime with 5% inerts and 1.3-1.6 CdS ratio. 6. Dry 99.8% pure soda ash with aqueous sodium salts as the byproduct. 7. 50% concentration sodium hydroxide (water included) with aqueous sodium salls as the byproduct. 8. With 6% inerts in limestone and 10% moisture, (nofly ash or lime). 9. With 6% inerts in limestone and 20% moisture, withoutfly ash and lime added.

10. Naturally oxidized, wet, from limestone, withoutfly ash and lime added. 11. With 5% inerts and 20% moisture, 1.3-1.6 C d S ratio, f l y ash omitted. 12. Dry salts only. Typical byproductfrom the wet soda processes is a dilute solution, about 10-15% salt.

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