of

James E. McGreevey Department of Environmental Protection Bradley M. Campbe

Governor Commissioner

MEMO

TO: William O'Sullivan, Director

Division of Air Quality

THROUGH: Iclal Atay, Acting Assistant DirectorA^^ j^J^~J^-p><\ Air Quality Permitting Element

FROM: Serpil Guran, Rule Manager^, f^-

Air Quality Management •** *°

DATE: May 8, 2003

SUBJECT: Analysis for Coal Burning Boilers Mercury Emissions Levels and Control

Options. (N.J.A.C. 7:27-27. 8)

A. Introduction

The December 17, 2002 Mercury Rulemaking Launch Memo states that it will be useful for New

Jersey to propose mercury emissions limits for coal burning boilers prior to the USEPA and in

conjunction with efforts by other states in the northeast. The USEPA rule is expected to be

proposed in December, 2003.

This memo is prepared by the coal burning boilers subgroup of mercury rulemaking team to

determine the mercury standard to be proposed for coal burning boilers, to analyze the impact of

the proposed standard on the affected facilities, and the compliance options of these sources. For

each of the different compliance options a cost analysis is also included, to outline the cost of

compliance with the proposed standard. This is followed by the recommendations of the coal

burning boilers subgroup.

New Jersey is an Equal Opportunity Employer

Recycled Paper
B. Mercury Standard

Based on the information available to date to the Utility MACT Working Group, the Mercury

Study Report to Congress, and the pilot tests conducted at coal burning boilers for control of

mercury emissions, the mercury standard should be mg/ MW-hr or 90 percent control

efficiency, both annual average. Compliance with this standard should be determined by

conducting at least three tests per quarter, each quarter in calendar year, and then averaging all

test results.

The Basis of this recommended standard is explained in Attachment I. As can be seen from the

statistical analysis of the data, the recommended standard provide sufficient margin of safety for

compliance purposes to New Jersey facilities.

C. Impact of the Standard On Affected Coal Burning Boilers

There are seven facilities, between four companies, with total often coal burning boilers that

will be affected with this standard. They are listed in Table of the Attachment II.

i. US. Generating Co.

Carney's Point and Logan boilers are equipped with SCRs, dry scrubbers and

baghouses. Their current mercury emissions are less than 10 mg/MW-hr. These

units would meet the recommended standard with powdered activated carbon

(PAC) injection.

ii. PSEG

PSEG Boilers are currently equipped with selective non- catalytic reduction

(SNCR) and electro-static precipitators (ESP). There is also Consent Decree

that requires the installation of Selective Catalytic Reduction (SCR) and Flue-Gas

Desulfurization (FGD) as follows.

Mercer SCR by May 1,2004

FGD by December 31,2010.

Mercer SCR by May 1,2005

FGD by December 31, 2012
Hudson SCR by May 1,2007

FGD by December 31,2006

Polishing Baghouse by December 31,2006

Mercer and Mercer 2 mercury emissions are less than 20 mg/MW-hr. These

units could comply with very high carbon injection rates, or preferably by

installing polishing baghouse following the existing ESP. If the polishing

baghouse option is selected, activated carbon would be injected following the

ESP. Therefore, the impact on the fly-ash quality would be minimal Most of the

fly-ash would be collected in the ESP, and would be salable. The amount of flyash that would need to be landfilled would be minimized and the amount of

activated carbon used would be less.

Hudson mercury emissions are less than 10 mg/ MW-hr. Hudson would

comply by injecting powdered activated carbon following the existing ESP, prior

to the polishing baghouse. Fly-ash related discussions are the same as Mercer

and above.

iii. Conectiv

Atlantic Electric B.L. England Unit is equipped with Selective Non-Catalytic

Reduction (SNCR)/ESP. The mercury emissions from this boiler are around 60-

80 mg/MW-hr. This boiler has pending low-sulfur coal authorization and

Prevention of Significant Deterioration (PSD) non-compliance issues. To resolve

these issues Conectiv may decide to either install scrubber on this boiler or

permanently shut it down. If scrubber is installed, compliance with the mercury

standard could be achieved with chemical additive into the scrubbing solution

such as sodium hypochlorite.

Atlantic Electric B.L. England Unit is equipped with SNCR, scrubber and ESP.

The mercury emissions are around 27-32 mg/MW-hr. It appears that there is

some reduction of mercury emissions by the scrubber, because the boilers burn

the same coal. Unit boiler could achieve compliance with the proposed standard

with a chemical additive into the scrubbing solution such as sodium hypochlorite.

Alternately, Conectiv may install polishing baghouse following the ESP on both
Atlantic Electric B.L. England Unit and 2.

Atlantic Electric Deepwater Boiler is equipped with baghouse and currently

the mercury emissions are less than 10 mg/MW-hr, similar to US Generating

Company's boilers. Therefore, this boiler could achieve compliance with

powdered activated carbon (PAC) injection.

iv. City of Vineland

Boiler 10 is currently equipped with an ESP. City of Vineland's current mercury

emissions are less than 15 mg/MW-hr. City of Vineland could either inject PAC

into existing ESP, or alternately install polishing baghouse and inject PAC

following the ESP.

D. Cost of Compliance With the Proposed Standard

1. Compliance with PAC injection to existing air pollution controls:

i. ESP system with high PAC injection rate

Facilities with existing ESP, could retrofit their systems by installing the

activated carbon injection (PAC) system. Currently, in New Jersey none

of the facilities have PAC storage and injection system installed and

installation of storage and injection of PAC would cost 3,000/MW. For

250 MW plant, the carbon storage and injection equipment would cost

approximately 750,000.*

In addition to PAC installation cost, the PAC usage would cost to facilities

around $0.50/lb. Facilities, such as PSEG Mercer #1, #2 Conectiv

Atlantic Electric/BL England #1,#2 and City of Vineland Boiler #2 may

need to inject high amounts of PAC to achieve mg/MW-hr or 90 percent

control efficiency (annual average). However PSEG Hudson #2 would

inject lower amounts of PAC to achieve the requirements because it will

have polishing baghouse as required by the consent decree.
Facilities may also experience revenue loss if they inject high amounts of

PAC into ESP since this would create carbon-contaminated fly-ash which

is non-salable to cement industry. Currently, fly-ash price from coal

burning boilers is approximately $30/ton.2 If facility can not sell its

carbon contaminated fly- ash, it would need to dispose it with the cost of

$10 /ton. If there is no available landfill this cost may increase to

$15/ton.3 The revenue loss to facility with 400 MW coal burning

boiler, burning eastern bituminous coal with six percent ash (85 percent of

this ash is fly-ash) which generates 35,700 tons fly-ash per year4, would be

$1,428,000 including disposal costs. The revenue loss to PSEG Hudson

#2 would be none, because PAC would be injected after the ESP, prior to

the polishing baghouse. However, there would be the disposal cost of flyash and PAC collected in the baghouse. The cost of fly-ash is assumed as

$30/ton and disposal is assumed as 10/ton.5 The cost estimates are

summarized in Attachment II, Table 3.

ii. Baghouse system with low PAC injection rate

In New Jersey, US Generating (Carney's point) #1, #2 and Logan #1 and

Conectiv Atlantic Electric Deepwater Boiler #8 are currently employing

baghouses. PSEG Hudson #2 is required by the consent decree to install

polishing baghouse by 2006. These facilities would need to retrofit with

PAC injection system to achieve mg/MW-hr or 90 percent control

efficiency (annual average). The cost of installation of PAC storage and

injection cost would be similar to the cost mentioned in paragraph (i).

PSEG Hudson #2 would only contaminate approximately five percent of

its fly-ash with PAC since the amount of fly-ash collected by the ESP and

eventually sold would not be impacted, there would be no revenue loss for

Hudson #2. However, there would be the disposal cost of the amount of

fly-ash and PAC collected in the polishing baghouse. US Gen. Boilers

fly-ash, and Deepwater #8 fly-ash would be totally contaminated with

PAC. The revenue loss issue would be similar to paragraph (i) above.

The cost estimates for these facilities are summarized in Attachment II,

Table 4.

Table shows cost estimates of retrofitting the existing baghouses with

polishing baghouses. This would allow injection of PAC after primary
baghouse therefore the fly-ash would not be contaminated. There would

be no revenue loss due non-salable fly-ash, and the disposal costs would

be much lower. The overall cost of this option is lower.

2. Compliance achievement with retrofitting the existing ESP by installing

polishing baghouse following an ESP system:

Facilities with existing ESP, may retrofit the system by installing polishing

baghouse. The cost of polishing baghouse would be approximately $24,000/14^

including installation. This estimate does not include additional fan and electrical

wiring. However, the polishing baghouse system allows PAC injection after the

ESP and this eliminates revenue loss resulting from PAC contaminated, nonsalable fly-ash generation and large amounts of fly-ash disposal cost. Retrofitting

existing ESP with polishing baghouse results in lesser amount of PAC usage cost

compared to that with ESP. The cost estimates of retrofitting existing ESP with

polishing baghouse for the facilities with an ESP are summarized in Attachment

II, Table 6.

3. Units with wet scrubbers may achieve compliance with Sodium hypochlorite

additive in the scrubbing solution:

Facilities with existing wet scrubbers, may utilize then* system to reduce mercury

emissions. They may add chemical additives into the scrubbing solution such as

sodium hypochlorite. If facility does not have an existing scrubber, the capital

cost would be approximately $14 per standard cubic meter of flue gas flow rate

per hour. The operating costs would be approximately $1.4 per standard cubic

meter of flue gas flow rate per hour. This cost does not include salaries.7 The

cost estimates are summarized in Attachment II, Table 7.
G. Recommendations

The technical and the cost analysis indicates retrofitting the coal fired boilers with ESP's or

baghouses with polishing baghouses would be the best option. Therefore, the subgroup is

recommending the following standard.

mg/MW-hr or 90 percent control efficiency, annual average.

Compliance to be determined by conducting at least three tests per quarter, each

quarter in calendar year, and by averaging all tests performed during the

calendar year.

Standard to be in effect beginning calendar year 2008. The affected units should

begin testing the first quarter of 2008.

The estimated mercury emissions reduction as result of implementing the above

recommendation would be 422 pounds per year (see Attachment II, Table 2).

C: Alyssa Wolfe, DAG

Janis Hoagland, OLA

Michael Aucott

Leo Korn

Sunila Agrawal

Hironmoy Sikdar

Deirdre Garrity
ATTACHMENT

Basis of mercury emissions level for coal combustion

Data obtained from the USEPA were used to determine that the proposed mercury emissions

level could be as low as 0.25 pounds per trillion Btu heat input, which corresponds to 1.3 mg per

MW-hr.

The USEPA data was developed through the program associated with Electric Utility Steam

Generating Units Section 112 Rule Making. As part of this program, the USEPA required

electric utilities to analyze mercury content of combusted coal. It also required subset of these

utilities to perform stack tests to provide speciated mercury emissions data.

The speciated mercury emissions data were downloaded on 9/11/02 from the web site

www.epa.gov/ttn/atw/combust/utiltox/utoxpg.htmL These data include number of factors

relevant to coal combustion, such as chlorine content, coal type, and other factors including both

inlet and outlet concentrations in units of ng/dscm of particle-bound mercury, oxidized mercury,

and elemental mercury for 79 coal-burning units. Outlet concentrations that were below the

detection limit were adjusted according to convention established with the cooperation of the

USEPA by assuming these non-detect values were one-half the detection limit. Then, the total

outlet concentrations (the sum of the corrected particle-bound mercury, oxidized mercury, and

elemental mercury values) were expressed in terms of pounds per trillion Btu heat input using an

"F-factor" calculation approved by the USEPA. This calculation multiplies the [ig/dscm value

by (0.0283168/453.65) 9840 (20.9/20.9-A), where is the oxygen value for each outlet

value.

Then, also in accordance with procedures used by the USEPA and established by the Clean Air

Act Section 112, an analysis was carried out of the best performing 12% or five units, whichever

is greater, of the relevant units. Only those units burning bituminous coal were chosen in this

case, reflecting the fuel burned in New Jersey. Since there are 27 units burning bituminous coal

the best-performing five (5) units were selected.

The mean of the total mercury emission in pounds per trillion Btu for these units was determined

with the permutation distribution method.. With the permutation method, since each unit has

three measurements, sample from this distribution could be obtained by taking one of the

samples from each of the 27 units considered. This could be done in 327 different ways. This

number is too large to do all of them, but sufficiently large number of samples, 5000, was

randomly selected. For each of the obtained sets of 27 samples, the best-performing five were

used to calculate the mean. The mean emission determined in this way is 0.125 pounds mercury

per trillion Btu, with 95% confidence interval of 0.108 to 0.184 pounds mercury per trillion

Btu.
more conventional statistical method could have been used, which requires the assumption of

normality for estimation of confidence intervals. This method is based on some known properties

of the mean of several random independent variables. Specifically, given the mean and variance

of independent random variables, Xj, X2, Xn9 the variance of the mean of these random

variables is [Var(Xi) Var(X2) Var (X^ln2. Each of them's are taken to be the mean of

three within-unit mercury output measurements. The variance of the mean of each unit is

estimated as the squared sample standard error of the three within unit measurements. The

lowest average outputs are selected, i.e. 5. With this method, the mean is calculated as

0.165 pounds mercury per trillion Btu, with 95% confidence interval of 0.123 to 0.207 pounds

per trillion Btu.

Then, in order to accommodate the variability likely within stack tests, the method described in

an October, 2002 memo from Roy Oommen, Eastern Research Group, to Jim Eddinger, USEPA

OAQPS, (MACT Floor Analysis for the Industrial, Commercial, and Institutional Boilers and

Process Heaters National Emission Standards for Hazardous Air Pollutants) was used. With this

method, the ratio of high and low of the multiple stack tests (in this case normally three runs per

unit) was determined, and then the mean ratio for the group of units under consideration was

calculated. To accommodate broad range of possible interpretations, mean was taken in this

way from both the best-performing five bituminous coal burners and from all the bituminous

burners. The mean ratio of the top five is 2.0. The mean ratio of all the bituminous coal burners

is 1.7. Multiplying the higher of these values by the mean emissions as indicated above yields

0.125 or 0.25 pounds per million Btu as the limit. This is equivalent to an emission limit of

1.3mg/MW-hr.

(As noted above, mean of 0.165 pounds mercury per trillion Btu can also be arrived at with

less sophisticated statistical method. If this value is chosen, 0.165 would be multiplied by 2.0, as

above. This translates to 0.33 lbs. per trillion Btu, or 1.7 mg/MW-hr.)
ATTACHMENT II

Table 1: New Jersey Coal Burning Boilers

Facility Name

PSEG

Mercer #1

PSEG

Mercer #2

PSEG

Hudson #2

City of Vineland

Boiler #10

US Generating

(Carney's Point)

Boiler #1

US Generating

(Carney's Point)

Boiler

U.S. Generating

(Logan)

Boiler #1

Atlantic Electric

BL England-1

Concctiv

Atlantic Electric

BLEngland-2

Conectiv

II Atlantic Electric

|| Deepwater

Boiler #8

II Conectiv

Boiler Type

Nominal Size

inMW

Wall/Wet PC

300

Wall/Wet PC

300

Wall/Dry PC

640

Wall/Dry PC

23

Wall/Dry PC

112

Wall/Dry PC

112

Wall/Dry PC

200

Cyclone/Wet

135

Cyclone/Wet

160

Face Fired/Dry

82

APC

ESP/SNCR/

AEFLG

ESP/SNCR/

AEFLG

ESP

ESP

SCR/Scrubber/

Baghouse

SCR/Scrubber/

Baghouse

SCR/Scrubber/

Baghouse

SNCR/ESP

SNCR/Scrubber/

ESP

BH

Stack Test

Date

10/94

10/95

09/98

10/94

10/95

08/98

07/01

7/95

3/02

2/94

2/94

11/94

9/95

2/97

9/95

6/97

5/94

MW at the time

of stack test

326

330

327

331

330

325

327

620

25.25

122

115

211

129

125

156

165

77.2

Hg Emissions

Ib/MW-hr

0.00003

0.00004

0.00003

0.00002

0.00004

0.000007

0.000007

0.00002

0.00003

0.00002

0.00002

0.00001

0.00014

0.00017

0.00007

0.00006

0.00002

Hg Emissions

mg/MW-hr

13.61

18.14

13.61

9.07

18.14

3.17

3.17

9.07

1336

9.07

9.07

4.54

633

77.11

31.75

27.22

9.072

10
ATTACHMENT II

Table 2: New Jersey Coal Burning Boilers Actual Mercury Emissions

Facility Name

PSEG

Mercer #1

PSEG

Mercer #2

PSEG

Hudson #2

CityofVineland

Boiler #10

US Generating

(Carney's Point)

Boiler #1

US Generating

(Carney's Point)

Boiler HI

VS. Generating

(Logan)

Boiler #1

Atlantic Electric

BL England-1

Conectiv

Atlantic Electric

BL England-2

Conectiv

Atlantic Electric

Deepwater

Boiler #8

Conectiv

Total

Capacity

(MW)

300

300

640

23

112

112

200

135

160

82

Hourly

Hg Emissions

(Ib/hr)

0.0087

0.0023

0.012

0.0019

0.0055

0.001

0.002

0.014

0.0048

0.00133

Annual

Hg Emissions

(Ib/yr)

76.21

20.15

105.12

16.64

48.18

8.76

17.52

122.64

42.05

11.65

469

Projected

90 Hg reduction

(Ib/yr)

68.59

18.14

94.61

14.98

43.36

7.8

15.77

110.38

37.85

10.49

422

Most recent stack test data

11
ATTACHMENT II

Table 3: Cost Retrofitting Existing ESP with PAC Injection

PSEG

Mercer #1 300 68.59 4,441,320 900,000 45,000 829,829 276,610 81,539 18,643 3.27

PSEG

Mercer #2 300 18.14 4,441,320 900,000 45,000 740,685 246,895 301,759 18,246 3.20

City of

Vineland

Boiler #10

23 14.98 453,015 69,000 3,450 32,132 10,711 33,332 21,709 3.81

Atlantic

Electric

BL

England

Conectiv

135 110.38 1,605,708 405,000 20,250 343,237 114,412 18,877 15,434 2.71

Atlantic

Electric

BL

England

Conectiv

160 37.85 1,605,708 480,000 24,000 423,163 141,054 57,964 13,712 2.41

Basis:

-Fly-Ash price: $30/ton

-Fly-Ash disposal cost: $10/ton

-PAC Injection Rate: 201b/Macfm

-Generator Capacity Factor: 65

-Cost of PAC injection: $l,000/ton

-Cost of PAC installation: $3,000/MW

12
ATTACHMENT II

Table 4: Cost Estimates of Baghouse System with Activated Carbon

US Gen

Carney's

Point #1

112 4336 336,000 16,800 236,284

518,880 172,960 21,793

8,437

1.48

US Gen

Carney's

Point U2

112 7.80 336,000 16,800 236,284 526,200 175,400 122395 8,524 1.50

US Gen

Logan 200 15.80 600,000 30,000 336,453 807,900 269300 91370 7,218 1.27

Atlantic

Electric

Deepwate

r#8

82 10.50 246,000 12300 143,489 273,270 91,090 49,538 6,343 1.11

PSEG

Hudson

#2

640 94.61 1,920,000 96,000 1,229,904 89,253 29,751 15,272 2,258 0.40

Basis:

-5% of Fly-Ash is collected in the and baghouse is non-salable for Hudson Unit #2

-100% of fly-ash is collected in the Baghouse and non-salable for US Gen. Units and

Deepwater.

-Fly-Ash price: $30/ton

-Fly-Ash disposal cost: $10/ton

-PAC Injection Rate: 31b/Macfm 10

-Generator Capacity Factor: 65

-Cost of PAC injection: $l,000/ton

-Cost of PAC installation: $3,000/MW

13


ATTACHMENT II

Table 7: Cost Estimates of Sodium Hypochlorite Additive to Scrubber

Conectiv BL

England #1 135 110.38 633,874 633,707 6,882 8,417 0.79

Conectiv BL

England #2 160 37.85 583,030 610,470 5,341 22,578 0.61

Basis:

Cost of sodium hypochlorite additive: $1.4 NCM/hr 17

Dr. Michael Durham, President, ADA Environmental Solutions, personal communication.

David Goss, Vice President, American Coal Ash Association, personal communication.

Jim Roewer, Edison Electric Institute, personal communication

Jim LeCates, PSEG, Mercer Generating Station, personal communication.

Opcit (reference #3)

Estimate From Vendor By Phone. Vendor: Hamon-Research Cottrell

Estimate from Miltec Int.

National Energy Technology Laboratory personal Communication

Opcit(reference #1)

10 Opcit (reference #8)

11 Opcit(reference #1)

12 Opcit (reference #8)

13Opcit(reference#l)

14 Opcit (reference 8)

l5Opcit(reference#l)

16 Opcit (reference #6)

17 Opcit (reference #7)

16