CITY OF PH ILADELPHIA Department of Public Health
Environmental Protection Division Air Management Services



### InterOffice Memo

To: File

From: Kassahun Sellassie

Date: January 9, 2015
Subject: 1997 8-Hour RACT Analysis for Grays Ferry Cogeneration Partnership

Introduction:

The Clean Air Act (CAA) requires that moderate (or worse) ozone nonattainment areas implement reasonably available control technology (RACT) controls on all major sources of Volatile Organic Compounds (VOC) and Nitrogen Oxides (NOx). Philadelphia County is part of the Philadelphia-Wilmington-Atlantic City moderate ozone nonattainment area for the 1997 8-hour ozone NAAQS. This document presents the findings of a RACT evaluation for the 1997 8-hour ozone standard for this facility.

Company Description:

Grays Ferry Cogeneration Partnership owns and operates an electric generating unit facility at 2600 Christian Street, Philadelphia, PA 19146. Equipment used at the facility includes one (1) front wall fired boiler, and one (1) combined cycle combustion turbine (CT).

Applicability for NOx and VOC RACT :

Grays Ferry Cogeneration Partnership has been determined a single source with Veolia Schuylkill and Veolia Energy efficiency. Veolia – Schuylkill Station, GFCP, an d Veolia Energy Efficiency are a major source of NOx due to having potential NOx emissions greater than 100 tons per year, the major source threshold in Philadelphia County that is applicable to NOx RACT for the 1997 8-hour ozone NAAQS. They are not a major source of VOC, due to having potential VOC emissions not greater than 50 tons per year, the major source threshold in Philadelphia County that is applicable to NOx RACT for the 1997 8-hour ozone.

In addition to the above, the station also includes Veolia Schuylkill’s three boilers, Boiler #23, #24, and 26, are subject to 1-hour RACT, per the 1-hour RACT determination, issued by AMS as RACT plan approval with PA Permit Number 51-04942 on December 1, 1999, and approved into the SIP by EPA on December 15, 2000 (65 FR 78418). Sources under Veolia Energy Efficiency (PA) LLC that include the two new 297.92 MMBTU/hr boilers.

The facility is not subject to 1-hour ozone RACT.

Process Descriptions:

Grays Ferry Cogeneration Partnership currently has one (1) front wall fired boilers (Boiler # 25) rated 1119 MMBTU/hr and one (1) combined cycle combustion turbine (CT) rated 1515 MMBTU/hr (135 MW). The CT can run with a Heat Recovery Steam Generator (HRSG) The bo iler and the CT both burn Natural Gas (NG) and/or #2
oil.

Boiler #25 is equipped with low NOx burner and flue gas recirculation (LNB + FGR). Per Plan Approval 97019, Boiler #25 has NOx emission limits of 0.10 pounds per MMBTU when firing gas and 0.15 pounds per MMBTU when firing oil. The potential to emit (PTE) for boiler #25 based on capacity and lbs/MMBTU NOx emission limits is 490 tons per year when burning gas (1119 MMBTU/hr * 0.1 lb/MMBTU *8760 hr/yr * 1 ton/2000 lb= 490 tpy) and 735 tons per year when burning #2 oil (1119 MMBTU/hr * 0.15 lb/MMBTU *8760 hr/yr * 1 ton/2000 lb= 735 tpy). Boiler #25 and the CT, with and without HRSG, have a combined NOx limit of 540 tons per year in Plan Approval # 97019, dated on 3/8/2001, making the actual PTE for Boiler #25 540 tons per year.The CT is equipped with Selective Catalytic Reduction (SCR) and Dry Low NOx (DLN) when firing gas; SCR and water injection (WI) when firing oil. Per Plan Approval # 97019, dated on 3/8/2001, the CT has NOx emission limits of 0.0344 pounds per MMBTU (9 ppm) when firing gas and 0.1683 pounds per MMBTU (42 ppm) when firing #2 oil; the CT with HRSG has emission limit of 0.09 pounds per MMBTU when firing gas and 0.1683 pounds per MMBTU when firing oil; these limits don’t apply during startup and shutdown. These limits were determined to be Best Available Technology (BAT) for the plan approval, but could not be guaranteed during startup and shutdown, and therefore alternative limits were determined during these periods of ti me. The CT alone (without HRSG) has a NOx limit of 255 pounds per hour at all times, including startup and shutdown. The CT with HRSG has a NOx limit of 298.8 pounds per hour at all times, including startup and shutdown. The pounds per hour limit is based on the rated capacity and the pounds per MMBTU limit fo r #2 oil for the CT, and is slightly lower than this
calculation for the CT/HRSG. The theo retical PTE based on the pounds per hour NOx limits is 1,116.9 tons per year for the CT and 1,309.2 tons per year for the CT with HRSG. As mention above, Boiler #25 and the CT, with and without HRSG, have a combined NOx limit of 540 tons per year in Plan Approval # 97019, dated on 3/8/2001, making the actual PTE of the CT, with and without HRSG, 540 tons per year.

NOx RACT Evaluation:

Boiler #25: The following were considered possible additional NOx controls as RACT for Boiler #25: (1) Selective CatalyticReduction (SCR), (2) Ultra Low-NOx Burners (ULNB) and Overfire Air (ULNB with OFA), (3) Selective NonCatalytic Reduction (SNCR), and (4 ) Ultra Low NOx Burners (ULNB),

ULNB are burners designed to create a larger, lower te mperature flame. They wo uld reduce NOx emissions by
around 25% for Boiler #25

ULNB with OFA reduce NOx emissions by around 35% for Boiler #25

SCR injects ammonia upstream of a catalyst. NOx, ammonia (NH 3 ), and oxygen (O 2 ) react on the surface of the catalyst to form nitrogen (N 2 ) and water (H 2 O). NOx emissions are reduced by around 80%.

SNCR reduce NOx emissions by around 25% for Boiler #25

The NOx emissions for Boiler No. 25 were determined based on the combined limit of 540 tons per year for Boiler
No. 25 and the CT/HRSG. This is lower than the PTE based on capacity and lbs/MMBTU NOx emission limits, as
detailed above.

The following NOx controls were determined technologically feasible for Boiler No.25.

Source Control Technology Baseline NOx
Emissions (tpy) NOx
Reduction (%) NOx
Reduction (tpy) Total
Annualized Cost ($/year) Cost
Effectiveness ($/Ton) Schuylkill
Boiler #25 SCR 540 80 432 3,125,445 7,235 ULNB + OFA 540 35 189 788,409 4,171 SNCR 540 25 135 1,195,847 8,858 ULNB 540 25 135 498,135 3,690

All of these control options have been determined econo mically unreasonable. Thus, the existing control for Boiler #25 (LNB + FGR) represents NOx RACT for the 1997 8-hour ozone standard

Combustion Turbine: The Combustion Turbine (CT) with and without the HRSG already have the most stringent NOx control option for this unit, SCR + WI, which AMS has determined to be RACT. SCR + WI have an efficiency of 90-98% emission reduction. AMS has determined only the lbs/hr emission limits to be RACT for the CT, as these are the lowest achievable emissions rates resulting from existing technologies, and are applicable at all times.

Conclusions and Recommendations: AMS has determined that the existing control for CT (SCR + WI) and the existing control for Boiler #25 (LNB + FGR) represent NOx RACT for the 1997 8-hour ozone standard for Grays Ferry Cogeneration, LLC.AMS requests these requirements to be approved as RACT in the SIP. Thus, AMS determines the following as RACT:

- Boiler #25- NOx emissions shall not exceed 0.10 pounds per MMBTU when firing gas and 0.15 pounds per MMBTU when firing oil. The emission for boiler #25 is 490 tons per year when burning gas and 735 tons per year when burning #2 oil.

- The Combustion Turbine NOx emissions shall not 255 pounds per hour.

- The Combustion Turbine with HRSG NOx emissions shall not exceed 298.9 pounds per hour.

- The facility shall monitor and record compliance based on NOX CEMs for Boiler #25 and CT.

1 / 9 / 1 5

Edward Wiener, Chief of Source Registration Date

References:

1 Manufacturers of Emission Controls Association (MECA) states SCR Control 90% NOX and the most

effective emission control www.meca.org

2 Minnesota Power vendor and 

### EPA’s Clean Air Markets (CAM) data : SCR is expected to achieve a

NO X emission rate of 0.05 lb/mmBtu guarantees offered by SCR system suppliers

3 Northeast States for Coordinated Air Use Management (NESCAUM). Status Report on NOx Control Technologies and Cost Effec tiveness for Utility Boilers. June 1998 and 2008

4 EPA Air Pollution Control Cost Manual (EPA 452/B-02-001)

http://epa.gov/ttn/catc/ products.html#cccinfo

5 http://www.4cleanair.org/Documents/ ATTACHMENTNOXFIN ALASFILED.pdf

6 EPA Air Pollution Control Technology Fact Sheet, SCR Achievable emission limits

7 ACT document, NOx Emission from ICI Boilers, March 1994, USEP

## GRAYS FERRY COGENERATION PARTNERSHIP BOILER #25

Table 1 Detail Calculations for BOILER # 25- SCR

Total capital Cost
Total Capital
Investment Cost (TCI) $9,956,557 Based EPA Cost Control Manual of $6000/MMBTU/Hr. Escalate 1997 $ using the Marshall and swift Index 1

Capital Recovery $1,082,033 0.1598 20 yrs @15% -OAQPS 1 A/ p =0.1598

Annual Operating
Costs
Direct Annual
Cost Electricity
Cost2 $70,080 100kw @ $0.08/kwh, 8760 hrs/yr

Maintenance3 $101,567.56 1.5% * TCI
Ammonia3 $277,920 17/30 * 2moles of NH 3 /2 moles of NO *1.05 * NOx emission (tpy) *$410/ton*1.55 Catalyst Cost3 190,000 0.1638 Sinking Fund Factor n=5 years, i=10%
Annual Catalyst Replacement
Cost 31,122

Total Direct
Annual Cost $480,690

Indirect
Annual Cost $1,082,033 Capital Recovery

Total Annual
Cost $1,562,723

Total Annual Operating
Costs $3,125,445

NOx Emission
Reduction (TPY) 432 Based on the combined limit with the CT/HRSG of 540 tons/yr NOx, which is lower than the P TE based on rated capacity and
lbs/MMBTU NOx emission limits.
Cost
Effectiveness ($/ton NOx removed) $7,235

### Table 2 Detail Calculations for Boiler # 25- ULNB + OFA

Total capital Cost

Total Capital Investment Cost (TCI) $3,251,339 TCI includes equipment cost estimates from NESCAUM 2002 Status Report on NOx
Control for Boilers 3

Capital Recovery $519,564 0.1598 20 yrs @15% -OAQPS 1 A/ p =0.1598

Annual Operating Costs

Direct Annual Cost
Electricity Cost $70,080 100kw @ $0.08/kwh, 8760 hrs/yr

Operator $16,425 0.5hr/shift, 3 shift/day, $30/hr

Supervisor $2,463.75 15% of Operator
Maintenance $19,162.50 0.5hr/shift, 3 shift/day, $35/hr
Material $19,162.50 100% of Maintenance
Total Direct Annual Cost $127,294

Indirect Annual Cost

Overhead 1 $11,498 60% of maintenance

Administrative Charge 1 $65,027 2% of TCI

Property Taxes 1 $32,513 1% of TCI

Insurance 1 $32,513 1% of TCI

Total Indirect Annual Cost $141,551

Total Annual Operating
Costs $788,409

NOx Baseline Emissions (TPY) 540 Based on the combined limit with the CT/HRSG of 540 tons/yr NOx, which is lower than the PTE based on rated capacity
and lbs/MMBTU NOx emission limits.
NOx Emission Reduction (TPY) 135 Based on 35 % of NOx removed.

Cost Effectiveness ($/ton NOx removed) $4,171

### Table 3 Detail Calculations for Boiler # 25 ULNB

Total capital Cost
Total Capital Investment Cost (TCI) $1,798,514 TCI includes equipment cost estimates from NESCAUM 2002 Status Report on NOx
Control for Boilers 3

Capital Recovery $287,403 0.1598 20 yrs @15% -OAQPS 1 A/ p =0.1598

Annual Operating Costs

Direct Annual Cost
Electricity Cost $70,080 100kw @ $0.08/kwh, 8760 hrs/yr

Operator $16,425 0.5hr/shift, 3 shift/day, $30/hr
Supervisor $2,463.75 15% of Operator
Maintenance $19,162.50 0.5hr/shift, 3 shift/day, $35/hr

Material $19,162.50 100% of Maintenance
Total Direct Annual Cost $127,294

Indirect Annual Cost

Overhead 1 $11,498 60% of maintenanceAdministrative Charge 1 $35,970 2% of TCI

Property Taxes 1 $17,985 1% of TCI

Insurance 1 $17,985 1% of TCI
Total Indirect Annual Cost $83,438

Total Annual Operating
Costs $498,135

NOx Baseline Emissions (TPY) 540 Based on the rated capacity of 1119 MMBTU/hr, 8,760 hours per year, and a
0.15 lbs/MMBTU NOx emission limit.
NOx Emission Reduction (TPY) 135 Based on 25% of NOx removed.

Cost Effectiveness ($/ton NOx removed) $3,690

### Table 4 Detail Calculations for Boiler # 25 SNCR

Total Capital Cost

Direct Capital Cost $2,111,593 Based EPA’s Cost Control Manual of (($950/MMBTU)* Qb(MMMBTU/hr)(2375 mmbtu/hr/Qb)*(0.66+0.85 n NOx ) Qb= boiler size(mmbtu/hr); n
nox = nox removal efficiency; 1 Indirect Capital Cost $422,319 Based EPA’s Cost Manual

Total Capital Investment Cost (TCI) $2,533,912

Capital Recovery $404,919 0.1598 20 yrs @15% -OAQPS 1 A/ p =0.1598

Annual Operating Costs

Direct Annual Cost
Electricity Cost $70,080 100kw @ $0.08/kwh, 8760 hrs/yr

Maintenance $38,009 1.5% x TCI

Ammonia 1 $277,920 17/30 * 2 moles of NH 3 /2 moles of NO *1.05 * NOx emission (tpy) x 735 tpy *$410/ton*1.55(cost from 1999 to 2014) Total Direct Annual Cost $386,009

Total Indirect Annual Cost $404,919 CFR x TCI

Total Annual Operating
Costs $1,195,847

NOx Baseline Emissions (TPY) 540 Based on the rated capacity of 1119 MMBTU/hr, 8,760 hours per year, and a
0.15 lbs/MMBTU NOx emission limit.
NOx Emission Reduction (TPY) 135 Based on 25 % of NOx removed.

Cost Effectiveness ($/ton NOx removed) $8,858

## References

1. Office of Air Quality Planning and sta ndards (OAQPS), Environmental Protection Agency (EPA) Air Pollution Control Manual, Sixth Edit ion, EPA/452/B-02-001, January
2002.
2. Electricity cost: EPA cost manual, Appendix A-NOx Control Analysis
3. North East States for Coordinated Air Use Management (NESCAUM) 2002 Status Report on NOx Control for Boilers
4. Capital Recovery = Convert from P (present ) to A(Annual amount), A=P(A/P,i%,n),

1 ) 1 ( ) 1 (

  


n n



### i i i CR 

### 15% interest and 20 yrs = A/P=0.1598; Annual Cost = TCI x CFR

5. Catalyst Cost of SCR: The catalyst life is 5 years. The annual cost is given by the sinking fund factor (SFF). The SFF is the amount of money the facility will need to set aside each year to be able to replace the ca talyst at the end of its life, based on the lifespan of the catalyst a nd the interest rate.

6. SFF = Convert from F (Future) to A( Annual amount), A=F(A/F,i%,n),



### 1 ) 1 (



 

n 

### i i SFF 10% interest and 5 yrs = A/F=0.1638

Where i= Annual interest Rate (10%); n= catalyst system life (5 years);

Catalyst Annual Cost = SFF x Catalyst Cost

7. Ammonia Cost:
2NH 3 

### + 2NO + 1/2O 2 

### 2N 2 

### + 3H 2 

### O

Annual Ammonia Cost = (17/30 * 2moles of NH 3 

### /2 moles of NO *1.05 * NOx emission (tpy) *$410/ton yrs x 1.55 from 1999 to 2014 price)

NH 3 

### = Ammonia, NO = Nitric oxide; O 2 

### = Oxygen; H 2 

### O = Water; 1.05= Ammonia slip
and excess ammonia