P.1 

OAR Box 1787 

Prepped by Ollie Stewart 

Document Number: 

83) ll-C-41 

Docket Number: 

A-90-37 

Printed 11/4/200810:22:20 AM Sheet 83 of 147 
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f.%-3*t4i X 

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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY " j j •" C ~ / ' 

\ REGION I 

? 841 Chestnut Building 

tf Philadelphia. Pennsylvania 19107 

OEC 19 19S0 

Mr. Wallace N. Davis 

Executive Director xy_ y 

Virginia Department of Air Pollution Control --"'Jx ''\l* ' 

P.O. Box 10089 < 

Richmond, Virginia 23240 ifm p & 

Ret Old Dominion Electric Cooperative (ODEC) ' __.__-_ (. 

Clever, VA Plant's Proposed Permit ,,

J , i 

Dear Mr. Davis: 

Thank you for the opportunity to review the application and 

preliminary determination for the proposed ODEC electric 

generation plant at Clover. Enclosed are in-depth comments 

concerning the best available control technology (BACT) 

determination, prepared by the Air Enforcement Branch, and 

comments on the modeling, prepared by the Air Programs Branch. 

: As a preliminary matter, because of the widespread interest 

in the proposed Clover permit, it is important to clarify, for 

the record, the roles of both the Department of Air Pollution 

Control (DAPC) and EPA in the permitting process. The DAPC is 

the primary permitting authority and has the responsibility for 

establishing emission limitations that: 

n are allowed by the Virginia SIP; 

B are demonstrated to maintain attainment of the national 

ambient air quality standards (NAAQS); 

n are demonstrated to protect other air quality related 

values, including the PSD increments; and 

n consider maximum degree of reduction taking into account 

the site-specific environmental, economic and energy factors 

(the BACT determination). 

The role of EPA is to review the record to ensure that the 

proper procedures are followed by the DAPC and to point to those 

factors which, in our judgement, have not been fully considered 

in setting specific permit terms and conditions. Furthermore, 

EPA will comment on those, site-specific, factors with shortterm and long-term environmental, economic and energy 

Implications which we recommend that the DAPC evaluate in making 

the final permit decision. 
While we will look at the total record that supports the 

DAPC's final decision with respect to BACT, we have compiled 

additional documentation to support a position that tighter 

emission standards are both desirable and achievable. A summary 

of potential alternative add-on emission control technologies is 

contained in the enclosed BACT review. In addition, as part of 

your deliberation, we encourage you to consider the total impact 

of the proposed ODEC facility on the environment and its 

potentially restrictive effects on the opportunities for 

additional economic development. 

Although the proposed emission limits do not contribute to 

violations of any NAAQS or, contingent upon reevaluation of the 

modeling demonstration, PSD increments, the consumption of a 

substantial fraction of the increment by this source makes it 

increasingly difficult to accommodate additional sources in the 

future. There is, apparently, a need for these sources and a 

desire to have them locate in Virginia. While we recognize that 

increment consumption is not necessarily linear, it is prudent to 

allow additional increment to be available in the interest of 

state-wide economic development. In addition, the enactment of 

the Clean Air Act Amendments, on November 15, 1990, imposes, 

among other things, a requirement for new utility plants, 

such as ODEC, to obtain allowances for their sulfur dioxide (S02) 

emissions beginning in the year 2000. This should be viewed as 

an inducement to ODEC to minimize their S02 emissions. 

While we consider that the proposed permit limits, of 1.7% 

sulfur and 94% reduction, represent a good level of control, we 

encourage the DAPC to explore a more advanced level of control. 

The use of the regenerable MgO/weft, i ^ e system is a reliable, 

economical and efficient technology for reducing S02 emissions. 

The addition of a forced oxidation stage generates an 

environmentally acceptable gypsum waste product. S02 emission 

reductions utilizing the regenerable MgO/wet lime technology 

designed for 96% SO, removal will eliminate an additional 1490 

TPY from the emission limit cited in the proposed permit. 

Although there is no similar allowance inducement with 

respect to nitrogen oxides (NOz) emissions, it may be even more 

Important to consider additional NOx controls. There is cause 

for concern about the long term effects of N0X on the local and 

regional ecology. Nitrogen dioxide (N02), one of the nitrogen 

oxides, is a criteria air pollutant which has documented health 

effects related to the NAAQS and PSD increments, which may not be 

exceeded. For the reasons cited above with respect to S02, we 

believe it is prudent to allow a margin for additional sources. 

-7 
P.4 

NO, is also acknowledged to be a precursor to the nitrous 

and nitric acids which are a significant component of acid 

deposition. Apart from the concerns about acid rain, addressed 

in the Clean Air Act Amendments, there is a vital interest in the 

ecology of the Chesapeake Bay. One of the recognized deleterious 

phenomena impacting the Bay is nitrogen deposition. Although the 

studies to date are incomplete, the information indicates that 

the two largest sources of NO, deposition on the Bay are 

automobiles and power plants. Approximately one-third of the 

nitrogen to Chesapeake Bay is provided by the atmosphere.1 The 

problem is sufficiently well documented that the Governors of 

several Region III states, including Virginia, have agreed to 

reduce the N0X loading to the Bay by 40 % by the year 2000. 

Clearly, all additional emissions of N0X which are now permitted 

to occur will need to be, at least partially, offset by emissions 

from existing sources in order to meet this commitment. 

In addition, NO, plays an important role in the 

photochemical formation of ozone. Virginia is part of the 

northeast corridor transport region for ozone. Furthermore, it 

is possible that additional reductions of NO,, in addition to 

volatile organic compounds (VOC's), will be required to attain 

the NAAQS for ozone in Virginia. 

: Given the ecological concerns outlined above, the potential 

for significant further reduction, beyond the proposed permit 

level of control should be considered. Advances in the state-ofthe-art of Selective Catalytic Reduction (SCR) of NO, emissions 

from coal-fired plants make this control technology reliable and 

economical. A permit requiring SCR technology was recently 

proposed, and will be issued, for the Chambers Work Cogeneration 

Facility in the State of New Jersey. NO, reductions of 80% are 

achievable with the use of SCR thereby reducing NO, emissions by 

8590 TPY from the emission limit cited in the proposed permit. 

We strongly encourage the DAPC to consider the advantages of 

requiring SCR at the proposed Clover plant. 

With regard to the modeling analysis performed by the 

applicant, our principal comment concerns the alteration of the 

meteorological database to exclude low wind, stable conditions in 

order to demonstrate protection of the Class I increment at James 

River Face. Although we agree with the applicant's contention 

that persistence of stable conditions for greater than twelve 

hours is unrealistic; we do not agree that artificially adjusting 

the meteorological database to counter that fact is appropriate 

from either a technical or policy perspective. We expect the 

DAPC to secure additional technical justification from the 

\jaworski, Dr. Norbert A., et al., A Plan for Research and 

Monitoring of Atmospheric Nitrogen and Toxic Pollutants in 

Coastal Waters. EPA/600/9-89/061 (June 1, 1989) 
P.5 

1 

, 4) 

applicant to demonstrate that the approach taken is conservative 

or to perform additional analyses to demonstrate protection of 

the Class I increment. 

As a final comment, we request that the DAPC review and 

reconsider the waste management practices proposed for the Clover 

plant. We believe they could be Improved by following the 

example of the Netherlands where fly ash, bottom ash and flue gas 

desulfurization gypsum are utilized in building materials. 

Tour agency requested assistance from EPA in evaluating the 

findings of adverse impact made by the Federal Land Managers for 

the Shenandoah National Park (the National Park Service) and the 

James River Face (the Forest Service) Class I areas. We have 

sent your staff the results of the analysis performed by EPA, and 

a letter will be sent to you shortly regarding our position, at 

this time, on the issues of visibility and acid deposition. You 

should also be aware that the National Park Sezrvice has requested 

the Rural Electrification Administration (REA) to have a 

supplemental Environmental Impact Statement (EIS) performed on 

the ODEC project. If such a request is granted, no federal 

permit (such as a PSD permit) may be issued while the EIS is 

pending. 

Enclosed are the comments, prepared by the Air Enforcement 

Branch on the BACT determination, and by the Air Programs Branch, 

on the submitted air quality impact assessment. Please enter all 

of EPA's comments into the public record. If you have any 

questions or wish to discuss our comments in general please 

contact me at (215) 597-9390. If you have specific questions 

about the BACT review please contact William Browne at (215) 597-

6551. If you have specific comments about the impact assessment 

please contact Tom Casey at (215) 597-4553. 

Sincerely, 

Thomas J. Mailany. Director 

Air, Radiation & Toxics/Division 

Enclosures 

cc: w/enclosures 

K.N. Kappatos 

ODEC Vice President 

Engineering and Operations 

4201 Dominion Boulevard 

Glen Allen, VA 23060 
P.6 

MODELING COMMENTS TO THE COMMONWEALTH OF VIRGINIA 

FOR THE PUBLIC RECORD 

CONCERNING THE PROPOSED OLD DOMINION ELECTRIC COOPERATIVE 

ELECTRICAL GENERATING FACILITY 

HEAR CLOVER, VIRGINIA 

COMMENT #1 — Report Format 

The modeling demonstration was accompanied by many 

undocumented addenda and correspondence. The air quality 

analysis should have been submitted as one cohesive document 

(w/diskettes) as background for the summarizing narrative of 

the State reviewer. 

COMMENT #2 — Altering of Meteorological Database 

In its analysis of impacts on the James River Face 

Class I area, the applicant deleted from the meteorological 

database the stable (Pasquill-Gifford E and F stability), 

low-windspeed conditions that would require a transport time 

of greater than 12 hours to reach the Class I area. The 

applicant's rationale is that E and F stabilities can occur 

only at night, and therefore, a transport time of greater 

than 12 hours is unrealistic. Hours of data meeting these 

criteria were removed from the database and replaced with 

"calms." Regulatory models generally assign to calm hours 

the average concentration predicted during the averaging 

period's non-calm hours. 

While EPA agrees that a persistence of stable 

conditions for greater than twelve hours is unrealistic 

(and, further, that the persistence of many other conditions 

for greater than 12 hours is unrealistic), the applicant's 

approach is flawed and must be abandoned in favor of a 

gaussian or "puff" model from the Guideline on Air Quality 

Modeling (EPA 450/2-78-027R). The transformation of lowwindspeed events is non-conservative because these events, 

as the applicant notes, produce high concentrations (higher 

than the average of the non-calm hours). "The inherent, 

assumed conservative nature of Gaussian models" described by 

the applicant (S3.5.2) does not exist. Gaussian models are 

only conservative if applied in a consistently conservative 

manner. By artificially adjusting the meteorological 

database, this conservatism is made uncertain. 

COMMENT #3 — Six-month Meteorological Database 

Section 3.5.2 refers to a six-month meteorological 

database. It is unclear to what database this refers. One 

year of on-site meteorological data must be employed in the 

air quality analysis. Although it appears that one year of 

meteorological data was employed in the modeling analyses, 

the reference to a six-month data-set is puzzling. 
2P21^ 

COMMENT #4 — Simultaneous Start-up 

The permit must include a condition prohibiting bath 

units from starting-up simultaneously, or, alternatively, 

the applicant must demonstrate that such an event would not 

jeopardize NAAQS or PSD increment. 

COMMENT #5 — Start-up Contribution to Annual Average Impact 

The applicant claims that start-up, as an event of 

short duration, does not contribute to annual impacts. This 

assertion is incorrect. While the contribution of startups to annual Impacts may be minor, their contribution to 

annual impacts should be accounted for. 

COMMENT #6 — Infrequent Load Analysis 

In an attempt to identify controlling loading 

conditions (e.g. 100 percent load, start-up, 50 percent 

load) for short-term impacts, the applicant relied on 

comparisons of high, second-high concentrations. Because a 

violation can be caused by multi-source interactions, one 

should examine all (or a representative group) of cases when 

the proposed sources impacts significantly to establish a 

controlling load condition. 

COMMENT #7 — Total Suspended Particulate vs. PM^ 

EPA is currently developing regulations establishing 

PM10 increment. Depending on the baseline date finally 

promulgated for this increment, the proposed major source's 

emissions may consume PM10 increment. Protection of this 

PM10 increment is not a criterion for permit issuance or 

denial at this time. However, the comment is offered to 

make parties aware that the source's Impact on the PM10 

increment, once promulgated may have to be assessed. 
P.8 

•RACTV qpMMKHTS TO THE COMMnwWRAT.TB QF VIRGINIA 

FOR THE PUBLIC RECORD • --

CONCERNING THE PROPOSED OLD DOMINION ELgrTRTP COOPERATIVE 

KT.BfrTRTrAL GENERATING FACILITY 

HB&B r7TnvRPr VIRGINIA 

EMISSION SUMMARY 

1. Nitrogen Oxides (NO^: A combination of Pollution Minimum 

NO, burners, advanced overfire air plus Selective Catalytic 

Reduction controls designed for 80% NO, removal efficiency 

resulting in a maximum emission rate of 0.064 lbs NO,/MMBtu is 

achievable as BACT for NO, control. 

2. Sulfur Dioxide (SO.^: A combination of fuel sulfur 

limitation (< 1.7 wt * S coal) and the regenerable MgO/wet lime 

FGD system designed for 96% S02 removal efficiency resulting in a 

maximum emission rate 0.107 lbs S02/MMBtu on a thirty-day rolling 

average is achievable as BACT for S02 control. 

Compliance with the above emission limitations using the 

specified control technologies will eliminate 10,000 tons per 

year of air pollution. 

DETAILED DISCUSSIONS: 

1.: Nitrogen Oxides (NOT): Pollution Minimum burners in 

conjunction with an advanced overfire air system resulting in an 

emission limit of 0.32 lbs/MMBtu on a thirty-day rolling average 

has been proposed as BACT. SCR was considered the most stringent 

control technique. 

"SCR has been installed on several units in Europe and Japan 

where reported removal efficiencies range between 80 to 90 

percent. Assuming inlet NO, concentration of 0.55 lb/MM Btu and 

90 percent removal, estimated incremental costs over new source 

performance standards from $2,470 to $4,940 per ton of pollutant 

removed render SCR infeasible for Old Dominion. Because of the 

difficulties of adopting this foreign technology from the 

"learning curve" needed for this new technology, the cost would 

probably tend toward the high end of the range. This technology 

is not commercially available in the U.S." 

Rapid advances in the state-of-the art for selective 

catalytic reduction (SCR) of NO emissions have altered the above 

analysis drastically. The West German experience in applying 

SCR to coal-fired boilers burning German hard coal has been 

presented at the 1989 joint EPA/EPRI Symposium on Stationary 

Combustion NO, Control. Table 1 shows the properties of German 

hard coal.2 The sulfur content varies from 0.8-1.5 wt%; the ash 

content varies from 5-12 wt% with a maximum of 30%. The 

ODEC/draft permit restricts the annual average coal sulfur 

content to 1.3% and the maximum sulfur content per coal shipment 

to 1.7%. The properties of Old Dominion Electric Cooperative 
P.9 

(ODEC) coal from Eastern Kentucky are also shown3 in Table 2. 

ODEC has presented the most detailed analysis of coal properties 

that we have seen in a BACT determination. The Radian report* on 

W. German experience with SCR on coal-fired service cites the 

Federal Republic of Germany (FRG) coal as containing ~ 1.0% 

sulfur. 

Mori and Shimuzu5 had reported on the installation of SCR at 

Matsuura coal fired No 1 Unit (1,000 MW) which was commissioned 

in July 1990. Tables 3 to 7 show the provisions for air heater 

clogging, the SCR specification of Matsuura #1, the premises for 

economic evaluation, SCR costs and R&D considerations on the SCR 

catalyst. The SCR on Matsuura #1 is designed for 80% NO, 

reduction on a coal which contain 1.2%S, 15% ash and a heat of 

combustion of 11,160 Btu/pound. A levelized busbar cost of 3.5 

mills/KWhr was evaluated (in 1989 dollars). A catalyst life of 4 

years is projected. 

Contrary to the assertion that SCR has been installed on 

several units in Europe and Japan, Schonbucher2 cites that "at 

present 28 hard coal-fired power plants with an electric capacity 

of more than 6400 MW are retrofitted with a DENO, plant using the 

SCR process". Mitsubishi6 has supplied 18 SCR units on coalfired service in Japan. Hence, there are many coal-fired units 

fitted with SCR technology in existence. 

It is cheaper to have a new source fitted with SCR NO, 

control than to retrofit the SCR control later. Babcock and 

Wilcox7 cite that "a catalyst for a typical 500 MW boiler can be 

installed in less than one week." Hence, catalyst choice can be 

delayed till the end of the construction period and thereby 

benefit from additional SCR experience on coal-fired service. 

W. R. Grace and Company have addressed SCR issues in a 

recent paper8 entitled "Catalyst Control of Power Plant NO, 

Emissions: Technology, Economics, Prospects." "Levelized busbar 

cost" is a term used in the power industry to describe the cost 

of generating electricity; its units are cents or mills per KWH 

(1 mill »0.1 cents). The levelized busbar cost includes both 

operating costs and capital charges. As shown in Figure 1, the 

levelized busbar cost of SCR decreased in Japan over a six-year 

period, 1979-1985, by over a factor of three because of increases 

in catalyst life and reductions in catalyst volume requirements 

as a result of improved catalytic geometry and composition. In 

Germany, the learning continued, again largely due to technical 

developments; reduced catalyst installation costs, mechanized and 

automated catalyst manufacture, further improvements in catalyst 

performance, and new catalyst replacement strategies which 

allowed the extension of average catalyst lifetime guarantees to 

four years. 
P.10 

Grace's calculations show that levelized busbar cost will 

drop to 2-3 mills/KWh using the SYNOX catalyst. The cost 

effectiveness for a 500 MW plant with a NO, uncontrolled level of 

0.60 lbs NO2/106 Btu operating at 80% NO, removal using SYNOX will 

drop to $870 per ton of N02 removed. The cost effectiveness (CE) 

is computed as follows: 

CE= costs 

Tons N02 removed 

The ODEC proposed permit has a NO, emission limit of 0.32 

lbs NO2/106 Btu. Reducing the ODEC NO, emissions by 80% using 

SYNOX would conservatively yield 

CE= $870 x 0.60 lbs/106 Btu x 80% 

0.32 lbs/10° Btu x 80% 

= $1631. 

EPA guidelines suggest uncertainties in cost effectiveness 

calculations of ~ 20 to 30%. $1631 x 1.30 - $2120. Cost 

effectiveness in the range $1600-2200 might be more likely. We 

feel that these values are acceptable as an additional cost of 

conducting business. Achieving maximum emission reduction by the 

use: of add-on controls will defray the potential long-term 

environmental cost of global loading and ecological impacts. The 

record does not support any reasons for citing special economic 

harm to the project. 

The issue of unreacted ammonia (ammonia slip) being emitted 

from the power plant with SCR controls has been reported by 

Schonbucher.9 Unreacted ammonia at the Heilbronn 700 MW power 

station unit 7 varied from 0.4 to 0.6 vppm over the 8500 hour 

operational period as shown in Table 8. In addition, 

experience10 gained at Neckarwerke from operation of SCR deNO, 

units on German hard coal has resulted in a design NH3 slip of 2 

vppm. Ammonia slip is kept under control via the use of a good 

catalyst, good process control instrumentation, and proper 

ammonia distributor grid design. It is usually limited to less 

than 5 ppm in commercial practice, a level where it is not an 

issue. 

The issue of the interaction of sulfur in the flue gas with 

ammonia to form corrosive ammonium bisulfate, NH4 HSOt, deposits 

on air pre-heater surfaces has been reported by Necker.11 "After 

approximately 16,800 operating hours, the air pre-heater in Unit 

5 had to be washed for the first time. The deposits could be 

easily removed with water. The first washing water batches had a 

high NH3 content. " 
p.11 

« - • • 

The environmental impact of dispensing of spent catalyst has 

been met by the willingness of catalyst manufacturers to accept 

spent catalyst for recycling and recovery.12 

Advances in the state-of-the-art of Selective Catalytic 

Reduction (SCR) of NO, emissions from coal-fired plants make this 

control technology reliable and economically acceptable. The 

close similarity in sulfur and ash content between ODEC coal, 

German hard coal and Japanese coal at Matsuura makes the 

technology transfer of German/Japanese SCR experience on coalfired service straightforward. 

NO, emissions from the ODEC main boilers of 10,735 TPY can 

be reduced by 80% using SCR to 2147 TPY, based on 100% capacity 

factor and an annual average NO, emission rate of 0.30 lbs/MM 

Btu. The emission of 8590 TPY of N02 can be avoided by using SCR 

on coal-fired service with a NO, reduction efficiency of 80%. 

II SO. EMISSIONS 

Sulfur dioxide emissions from each main coal boiler are 

to be reduced by a wet limestone flue gas desulfurization 

system at 94% S02 reduction permitted at 0.16 lbs S02/MMBtu 

on a thirty-day rolling average where the annual average 

coal sulfur content is 1.3 wt %. 

A wet limestone flue gas desulfurization system permitted at 

94% S02 reduction is close to the maximum achievable performance 

for this particular chemical system. Meij" has reported in a 

wet limestone FGD system on a power plant burning eastern 

bituminous coal (approx. 1% S, 12,000 BTU/#, 12% ash) at 

Gelderland. Between 3 to 5% of the S02 was retained in the ash, 

about 1% was washed out in the prescrubber, and about 93% was 

washed out in the main scrubber (excluding a 2% leakage of the 

gas reheater). The total S02 removal was 95—97% for the plant. 

A recent German paper14 reports a desulfurization of flue 

gas from brown coal combustion at the Bauchhaus and Offleben 

power plants at Helmstedt. Pure sulfur is produced as the endproduct using highly concentrated sodium sulfite to remove S02 

from the flue gas. The sulfur production in 1989 was 

approximately 70,000 tons and the sodium sulfate production was 

17,000 tons. About 97% of the S02 in the flue gases from both 

plants was removed using the Wellman-Lord FGD technology. 

High S02 reduction can also be achieved with regenerable 

magnesium oxide systems. Philadelphia Electric (PECO) utilizes 

regenerable MgO technology which produced sulfuric acid as a byproduct at Eddystone and Cromby plants. 
P.12 

ODEC had considered the use of Magnesium promoted lime FGD 

systems. "The addition of soluble magnesium to a calcium-based 

system increases the alkalinity of the slurry, thus enhancing 

sulfur dioxide removal. This enhancement, however, is more 

pronounced with higher sulfur coal and available alkalinity and 

generally is not the limiting factor to absorber performance with 

limestone systems in lower (less than 2 percent) sulfur coal 

applications. High calcium content limestone is required as the 

primary reagent. Currently, all of the units in the U.S. using a 

magnesium promoted lime system purchase thiosorbic lime (a 

patented lime product) from Dravo in Maysville, Kentucky. The 

thiosorbic lime is transported by barge to all of these 

facilities. Dravo is the only producer of a lime with a suitable 

magnesium oxide content for use in these systems. The fact that 

there are no capabilities for barge delivery to the Clover 

station and that there is only one supplier of suitable lime 

greatly Impacts the availability and cost of the reagent. Other 

factors considered in evaluating this system are: (1) the 

increase in energy consumed in lime production, and (2) the 

increase in waste water discharges of soluble magnesium 

compounds. Because of the technical, energy and environmental 

considerations, magnesium promoted lime FGD systems were rejected 

as BACT." 

The Bechtel process for the magnesium oxide-promoted wet 

lime reduction of S02, at the Colstrip Station in eastern Montana 

units 3 and 4 are permitted at 0.10 lbs SO2/106 Btu at full load 

(776 MW each). When firing with the average-sulfur coal, the FGD 

system must collect 94% in the S02 in the gas. Since sulfur in 

the coal can vary from an average of 0.88% up to 1.00% the system 

must be able to remove approximately 96% of the S02 for prolonged 

periods in order to meet the permit requirements. The design 

basis for units 3 and 4 of 96% S02 removal was exceeded by 

typical unit 3 operation at 98% of S02 efficiency." The Montana 

Power Company states that no exceedances of the S02 standards 

have occurred since start-up of Unit 3 in 1983 and Unit 4 in 

1985." Regeneration of Mg(OH)2 was practiced at Colstrip for 

about two years and the complete system worked satisfactorily 

according to Jack Abrams, Bechtel National. The regeneration of 

Mg(OH)2 was later terminated. According to Colstrip's plant 

operations personnel the regeneration of Mg(OH)2 phase of the 

process was a "headache." What constitutes a headache situation 

in Montana where environmental practices allow dumping of a 

magnesium-contaminated sludge in an isolated area may be only 

inconvenient in Virginia where dumping contaminated sludge is 

unacceptable. Many improvements have been achieved since the 

Colstrip plant was constructed which could markedly improve the 

cost effectiveness in a new site. The design of Colstrip units 3 

and 4 is about ten years old. 
P.13 

The Bechtel S02 removal process17 is revealed in U.S. Patent 

4, 246,245 issued 1/20/81. Recently, European Patent EP0339683A2 

has been issued18 to Dravo Lime Company of Pittsburgh, PA for a 

process for desulfurization of a sulphur dioxide-containing 

stream (89/11/02). The example cited involves a 350 MW boiler in 

which 99% of the S02 is removed from the flue gases from 

combustion of ~ 3.9%S coal. Regeneration of Mg(OH)2 is practiced 

and a gypsum product is formed which contains 2% MgS04. The 

process can utilize magnesium-containing lime (about 3 wt% MgO) 

so-called thiosorbic lime. Bechtel has provided a design19 for 

the dolomitic lime FGD process for a 350 MW plant using 2.5%S 

eastern bituminous coal. This paper incorporates circuits for 

handling the buildup of trace materials, e.g., chlorides and 

fluorides with the design of a 97.4% S02 reduction system. 

Forced oxidation of the calcium sulfate product provides a 

commercial quality wallboard which contains only 200 ppm of 

magnesium salt. Henry Bove20 has commented on permitted levels 

for the regenerable MgO/waste acid process at Philadelphia 

Electric Company (PECO) plants. For fuels containing 1-4%S the 

source can be permitted at 96% S02 reduction and will operate at 

97-99% S02 reduction. A margin or buffer range of several 

percent allows the plant operations personnel to avoid shutdown 

when irregularities appear in the course of plant operation. 

; In the MgO/wet lime process S02 is absorbed by the following 

reaction which occurs in solution: 

S03" + H20 « 2HS03. 

We have searched Chemical Abstracts using the DIALOG program 

for information on magnesium bisulfite, Mg(HS03)2. We have 

concluded from this review of the chemical database of ~ 10 

million items that Mg(HS03)2 does not exist in the solid phase. 

The absorber contains 6% of calcium sulfate particles and the 

magnesium species are very soluble in sulfurous acid solution. 

There is no propensity for clogging, choking or solids 

precipitation. Hence, there is no need for a spare absorber 

module in the regenerable MgO/wet lime process. This analysis 

supports the Bechtel conclusion: 

"Scale formation potential within the scrubber is reduced to 

zero. All the precipitating reactions are carried out in tankage 

separate from the scrubber vessel and under readily controllable 

conditions." 
P.14 

In order to operate the regenerable MgO/ wet lime FGD system 

a source of magnesium hydroxide (milk of magnesia) is needed for 

startup, a source of calcitic lime is needed for alkalinity and a 

makeup magnesium oxide source is needed to replace MgSO( occluded 

in the gypsum product. Seawater21 is used as a source of raw 

material for processing magnesium salts and magnesium metal. The 

concentration of magnesium ion in seawater22 is shown in Table 9. 

In view of approx. 12,000,000,000 lbs. Mg per cubic mile of 

ocean, the sea provides an inexhaustible supply of magnesium 

salts. The addition of hydrated lime to seawater precipitates 

magnesium hydroxide, 

MgCl2 + Ca(0H)2 > Mg(0H)2 + CaCl2 (1) 

MgS04 + Ca(0H)2 > Mg(0H)2 + CaS04 (2) 

Reaction 2 in the regeneration step in both the Bechtel and 

Dravo Lime processes. MgO/Mg(OH)2 in dry or slurry form is 

commercially available from Dow Chemical and Premier 

Refractories, and Chemicals, Inc.23 A representative chemical 

analysis24 of Virginia high-calcium limestone shows a MgO content 

of 0.46 wt%. This concentration is sufficient to provide makeup 

MgO along with the required alkalinity from the CaO for the 

Bechtel process using hydrated lime derived from Virginia 

limestone. 

The regenerable MgO/wet lime process avoids generating a 

magnesium-contaminated sludge, utilizes cheap calcitic lime (not 

thiosorbic lime) for replacement alkalinity and avoids plugging 

in the absorber by eliminating the formation of solid calcium 

compounds. 

S02 emissions from the ODEC main boilers of 4473 TPY can be 

reduced to 2982 TPY by using the regenerable MgO/wet lime FGD 

system permitted at 96% S02. These emissions are based on 100% 

capacity factor and 1.3% sulphur in coal on an annual average. 

The use of a regenerable FGD scrubber, such as the MgO/wet 

lime process, would allow a significant reduction in the volume 

of waste to be disposed; 120,000 cu yds vs 500,000 cu yds per 

year if the gypsum product can be sold or given away. 
P.15 

8 

<* - • * 

The economic evaluation for the Clover Station BACT cites 

cost effectiveness for limestone scrubbing at 90% and 92% S02 

reduction of $923 and $972 respectively. By extrapolation 94% 

S02 reduction would be approximately $1020 per ton of S02 

removed. The cost effectiveness for the regenerable MgO/acid 

(PECO) process at 95% S02 reduction of $1,281; the MgO promoted 

wet lime system (throw-away process) at 95% S02 reduction has a 

cost effectiveness of $1,023. EPA guidelines suggest 

uncertainties in cost effectiveness calculations of ~ 20 to 30%. 

The cost effectiveness for the regenerable MgO/wet lime process 

at 96% S02 reduction would appear to be reasonable in light of 

these calculations on related variations of the basic process. 

Ill WASTE MANAGEMENT PRACTICES 

With regard to ash and flue gas desulfurization sludge 

disposal it is noteworthy that in the Netherlands25 almost all of 

the fly ash (800,000 tons) ashes (90,000 tons) and flue gas 

desulfurization-gypsum (180,000 tons), annually produced by coalfired power plants are used for the manufacture of building 

materials. The fly ash is primarily used in the manufacture of 

cement, as light-weight aggregate, and as filler in asphalt. The 

gypsum is used in the manufacture of gypsum boards and the ashes 

are used in the construction of roads and in the manufacture of 

concrete blocks. Carbon-rich fly ashes are presently being used 

for the manufacture of lime-sandstone and the gypsum is now also 

used for the manufacture of waste paper-containing gypsum 

fiberboard. 
P.16 

References 

1. Proceedings: 1989 Joint Symposium on Stationary Combustion NO, 

Control. San Francisco, CA. March 6-9, 1989 EPA-600/9-89-062b 2 

Volumes. 

2. Schonbucher, Dr. B. "Reduction of nitrogen Oxides from coalfired Power Plants by using the SCR Process. Experience in the 

Federal Republic of Germany with Pilot and Commercial Scale DeNO, 

Plants", Proceedings: 1989 Joint Symposium on Stationary 

Combustion NO, Control EPA-6—/9-89-062b Volume 2 p. 6A-1-17. 

3. Old Dominion Electric Cooperative (ODEC) BACT Determination, 

submitted to VDAPC, March 1990. 

4. Emmel, T.E., Mailbodi, M. and Martinez, J.A. "Comparison of West 

German and U.S. Flue Gas Desulfurization and Selective Catalytic 

Reduction Costs. Radian Corporation RTP, NC 27709. EPA-600/7-

90-009 April 1990. 

5. Mori, T. and Shimuzu, N. "Operating Experience of SCR Systems at 

EPOC's Coal Fired Power Station", Proceedings: 1989 Joint 

Symposium on Stationary Combustion NO, Control EPA-600/9-89-062b 

Volume 2 p. 6A-85. 

6. Cormetech, Inc. Corning, N.Y. "Supply List of Mitsubishi SCR 

System. 

7. Campobenedetto, E.J. and Murataka, T. "Application of Selective 

Catalytic Reduction Systems for NO, Control" American Power 

Conference, April 1990. 

8. Boer, F.P., Hegedus, L.L., Gouker, T.R. and Zak, K.P. "Catalytic 

Control of Power Plant NO, Emissions: Technology, Economics, 

Prospects" September 1989, submitted to CHEMTECH for publication 

(May 1990). 

9. Schonbucher, op. cit. p. 6A-17. 

10. Necker, P. "Experience Gained by Neckarwerke from Operation of 

SCR DENO, Units", Joint Symposium on Stationary Combustion NO, 

Control 1989 EPA-600/9-89-062b p. 1A-19. 

11. Necker, op. cit. p. 6A-29. 

12. Corbett, R.A. "Refiner, Petrochem Plants Focus on New Waste 

Challenges", Oil and Gas Journal March 5, 1990 pp 33-38. 
P.17 

10 

13. Meij, R. "Tracking trace elements at a coal-fired power plant 

equipped with a wet flue-gas desulfurization facility", Kema 

Scientific and Technical Reports 7(5): 267-355 (1989). N.V. 

KEMA, R and D Division, Department of Environmental Research P.O. 

Box 9035 6800 ET ARNHEM, The Netherlands 

14. Wahl, D.J. "Desulfurization of flue gas from brown coalBuschhaus and Offleben C", Umwelt, 20(3), L4-L10 (German) 

15. Berube, D.T., Monahan, W.J., Abrams, J.Z. and King, A.M. 

"Application of Dolomitic Lime Process for Flue Gas Cleaning at 

Colstrip 3 and 4", American Power Conference, Chicago, Illinois 

April 1984. 

16. Grim, CD., Montana Power Company letter to J.Z. Abrams on 

Colstrip Units 3 and 4 scrubbers, March 3, 1990. 

17. Abrams, J.Z. and Sherwin, R.M. U.S. Patent 4,246, 245 (to Bechtel 

International Corporation) "S02 Removal" January 20, 1981. 

18. Stowe, Jr. D.H. European Patent 0339683A2 (to Dravo Lime Company) 

"Process for desulfurization of a sulphur dioxide-containing gas 

stream." 

19. Abrams J.Z. and Zaczek, S.J., "Dolomitic Lime Process for 

Retrofit FGD Application", Journal of the Air Pollution Control 

Association 35, 1224-1230, 1985. 

20. Bove, Henry J., Manager of Projects, United Engineers & 

Constructors Memorandum on McrO Flue Gas Desulfurization Svstem 

December 8, 1989 to Steve Joyce, Duke-Fluor Daniel-Charlotte, 2 

NC. This two page letter is labelled Attachment 2 in the 

Mecklenburg Cogeneration Limited Partnership PSD/BACT 

Application, May 1990. 

21. Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition 

Volume 12 pp. 667-8 1967. 

22. Dow Chemical USA. 2020 Wil lard H. Dow Center, Midland, MI 

48674. 

23. Premier Refractories and Chemicals, Inc. 7887 Hub Parkway, 

Cleveland OH 44125. 

24. Kirk-Othmer op. cit. p.423. 

25. Chemical Abstract 113: 1576112 Coal Residues, uses and 

developments. Bolt N.; Stibbe, F. (KEMA, Netherlands) Energie -

spectrum 1990, 14(6), 156-162 (Netherlands) 
P.18 

TABLE 1 

From Dr. B. Schonbucher, Proceedings: 1989 Joint 

Symposium on Stationary Combustion NO, Control 

EPA-600/9-89-062b 

Properties of German Hard Coal 

Heating Value (net) MJ/kg 18 - 30 [7,760-12,900 

Btu/lb] 

Humidity 

Ash 

Volatile 

Sulphur 

Nitrogen 

Chlorine 

Hard Coal-Fired Boilers 

• 

Temperature 

Water 

C^ 

CC-2 

S02 

so3 

N0X 

% 

% 

% 

% 

% 

% 

Tabl 

Flue Gas 

C 

% 

* 

% 

mg/m3 

mg/m3 

mg/m3 

e la 

5-1 2 

5-1 2 (30) 

17 - 30 (40) 

0.8 - 1.5 

1.2 - 2.0 

0.1 - 0.3 

Composition (Behind Economizer) 

300 - 400 (420) 

7 - 9 

2 - 4 

15 - 17 

• 1500 - 3500 

10-3 0 

650 - 800*) 

or 

1200 - 2000**) 

Dust g/m3 5-1 2 (40) 

* Dry Bottom Firing System 

** Wet Bottom Firing System 
P.19 

Table 2 

Eastern Bituminous Coal from Old Dominion Electric 

Cooperative (ODEC) BACT Determination March 1990 

Coal Quality Analysis 

Ultimate Analysis -

Weight $ 

Carbon 

Hydrogen 

Sulfur 

Moisture 

Nitrogen 

Chlorine 

Oxygen (Difference) 

Ash 

Higher Keating Value 

Averaqe 

74.76 percent 

5.02 percent 

1.15 percent 

5.1 percent 

1.5 percent 

0.07 percent 

3.9 percent 

8.5 percent 

13,000 Btu/lb 

ftance 

72.0 - 80.0 

4.8 - 6.0 

0.5 - 2.0 

2.5 - 8.0 

1.0 - 2.0 

0.01 - 0.14 

5.5 - 13.C 

12,000 - 14,000 

Trace Elements - ppm 

Beryllium 

Fluoride 

Lead 

Mercury 

1.9 ppm 

101 ppm 

7.4 ppm 

0.14 ppm 

0.39 - 5.4 

10 - 560 

1.3 - 22 

0.01 - 0.5 
P.20 

From Mori and Snimuzu, Proceedings: 1989 joint Symposium 

on Stationary Combustion NOx Controls Volume 2 

Table 3 Basic Consideration for AH Clogging • 

• AH Element NF type layer in ptastaie deposit areas 

> Soot Blower Reinforced fctawer sucn as retracaole. twin cr muni nozzle types 

> Blowing Schedule Increased Mowing frequency, ex. 6 times-day 

Table 4 SCR Specification of Matsuura #1 

Design SU M Mu. Oil Vol. / Mai, trtti NC* 

GuVelufM 11,000 frr* MTi 3.100/3.029 

Gas Tantpaanir* «c 370 

Z.1: ii3 

SO 

75/E0 

203 • 1.000 

3 j max. 

0.5 max. 

100 

W.5 

Catalyst Type — P*a:t (10 mm casM 

Catalyst VoKim* m° 1.341 

Space Velocity im 2.010 

Ana Veioaty mm 10 

Linear Velocity mrs 5.3 

Reader Oirrvtreori m 12.1W 1 1S.50 1 M.SH 

Cataiyst Staoe — 3 

Tram — 2 

Table 5 Premises fcr Economic Evaluation 

P!am Generating Cacacr/ 250 MV/ x:. -ew vm 

Plant Efficiency 23.3 % irev. 

Plant Use Facer 3.5 % 

Annual Caoacry racrr 70 % 

Beerieity Transmitted i.SS* GV/f-year 

Coat Calorific Value 6.2C0 <&: '*<; .'IS ac 

Sulfur Content MV. 

Nitrogen Content 1J % 

Ash Cement 15 % 

SCfl Tyse <-?•- Ous: Svs:e--i 

NOx in/Out 25150 zz-r. .SC". CeNCx Efficiency) 

Catalyst Life - /ears 

Train 2 

Ammonia Cos: Icz".: 

Currency E-tcrar-s ?a:a '•.'• '2..1 

Ciscsunt Rate '. "-

Escalation 3a:e 2 ~'» zz 

Plant Life 20 /ears 

t-Oiin 

NOxOu 

OeNCx Efficiency 

SOxm 

so, m 

SO3 Ccmramcn 

Ousm 

SS&NHj 

ppm (6 -. OJ / 

ppm(6%0j) 

% 

ppm 

ppm 

r. 

rnymV* 

ppm 
P.21 

Table 6 SCRCo« 

CONSTHUCTJON CCST 

Reaecr and Ducting 

Cautyst 

Ammonia Facilities 

Others (Electrical Eauipment. 

C&L Civil Works) 

O/i'Site Engineering 1 

Suspofl Facilities 

Interest dunng Ccnstrucaon 

Home Cities Fee 

TOTAL CAPITAL RECUiREMENT 

H 3S0 Mw x 1, new unit, 

l l 529 value. IS - 130 Yen 

J23/V.V 

23 

5 

3 

6 

-

2 

S71 1 WV 

•] 

LEVERIZED 8US-3AR COST 

Capital 

Ooeration and Maintenance 

Catalyst Excrtar'se 

Ammonia 

Other Utilities 

Tax 

TOTAL SUS-8AR CCST 

'..5 mrils.V//h 

0.4 

3.3 

0.5 

0.1 

3.1 

3.S mills/kWh 

Table 7 R & D on SCR Catalyst 

Sample Catalyst Activity Test 

Catalyst Life Forecast 

Study on Factors in Catalyst Deactivation 

• Specie surface area N , adsorption <BE"P 

• Pore size distriuticn Mercury methcd 

• Adherent material analysis . Atomic absorption analysis 

• Surface state SEM 

• Crystal structure Xr ay Analysis 
P.22 

Table 8 

From Dr. B. Schonbucher, Proceedings: 1989 Joint 

Symposium on Stationary Combustion N0X Controls Volume 2 

Heilbronn Power Station Unit 7. DENOX Plant 

Change Of Catalyst Characteristics (700MW) 

Hours of 

Operation 

h 

0 

2500 

4600 

6300 

8500 

Nft 5liP 

vppm 

0.4 

0.6 

0.5 

0.5 

0.6 

SO2/SO2 

Conversion 

% 

1.3 

1.5 

0.5 

1.4 

1.4 

Pressure Loss 

(Reactor) 

5.7 

6.9 

5.6 

6.3 

6.5 
P.23 

11 

Table 9* 

MarrngBi"TM in Seawater 

1272 ppm Mg in ocean water 

Approximately 10.9 lbs Mg/1,000 gal. 

Approximately 12,000,000,000 lbs Mg/cubic mile 

•Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition 

volume 12, 668, 1967 
P.24 

11 

Table 9* 

Magnesium in Seawater 

1272 ppm Mg in ocean water 

Approximately 10.9 lbs Mg/1,000 gal. 

Approximately 12,000,000,000 lbs Mg/cubic mile 

*Kirk-Othmer Encyclopedia of Chemical Technology, Second Edition 

volume 12, 668, 1967 
3 

levelized Husbtir Cost 

mills/KWh 

ft •* 

O 

SB 

5 

H 

W 

O 

SB 

tu • 

O 

4 > - 1 

vo >* 

vo n 

O «» 

rn a 

r> o 

o »i 

a r» 

2 * 

B t-4 

r*«-«t 

n rt 

w H-

• o 

•t» n 

<-t o 

o a 

w rt 

-a M 

o o 

n •-• 

rt 

to o 

1978 1982 1986 1990 

Year 

o 

Oil C 

O • r» 

B TJ H 

•tJ • 

fu TJ 

a ta M 

- » a 

i r» 

t/> • 

r» tS 

•o t- o 

r» • X 

rt tB • M 

cr a 

•1 A Ul 

00 Ut 

vo a. o 

oo c a 

tO l/l M 

»-n H 

0 - H 

1 -99 f» 

• n 

•i a* 

c o a tr o o act- 4 

K- *- o 

u n m 

w <-t s: 

o 

a 

Figure 1 

SCH process operating costs: Japan, 11)79-1985; West Germany, 1985 and bcyortd 

Con 1-fired service, U.S.-equivalent costing, 1988 Hollars.