PUBLIC NOTICE
Draft Air Quality Permits 7214-R1 through 7217-R1, Georgetown University, Modification and operation of four existing boilers at the Central Utility Plant of Georgetown University, 3700 O Street NW, with proposal to incorporate certain permit requirements into the District's State Implementation Plan (SIP)
Notice is hereby given that, pursuant to 20 DCMR § 210, the Air Quality Division (AQD) of the Department of Energy and Environment (DOEE), located at 1200 First Street NE, 5th Floor, Washington DC, intends to issue air quality permits to Georgetown University as follows:
- Permit No. 7215-R1 Install a New Stack on and Operate a 127.0 MMBTU/hr Dual Fuel Boiler (Boiler 1),
- Permit No. 7216-R1 to Operate a 127.0 MMBTU/hr Dual Fuel Boiler (Boiler 2),
- Permit No. 7217-R1 to Install a New Stack and Low NOx Burners in and Operate a 120.6 MMBTU/hr Dual fuel Boiler (Boiler 3), and
- Permit No. 7214-R1 to Operate a 119.8 MMBTU/hr Dual Fuel Boiler (Boiler 4).
These boilers are located at the Georgetown University Central Utilities Plant, located at 3700 O Street NW, Washington DC, 20057. The contact person for the facility is Charles Weidner, Environmental Compliance Specialist, at (202) 687-7409 or [email protected].
In addition to standard permit issuance, with this action, DOEE is proposing to submit, to the U.S. Environmental Protection Agency (EPA), the requirements contained in certain conditions of the draft permits for inclusion in the District’s State Implementation Plan (SIP), found at 40 CFR § 52, Subpart J, and specifically 40 CFR §§ 52.470(d) and 52.479. The permit conditions whose requirements are proposed for inclusion in the SIP are Conditions II(e)(3), III(b)(1) (as it applies to Boiler 1 only), and III(d). DOEE is proposing to include the requirements of these permit conditions in the SIP in order to ensure federal enforceability of an Alternative NOx RACT Plan submitted by Georgetown University pursuant to 20 DCMR 805.2. Comments on this plan were previously taken pursuant to a public notice posted in the D.C. Register (Vol. 70 – No. 25, 008868 – 008869) and on the Department’s website (https://doee.dc.gov/node/1665741) on June 23, 2023.
Emissions Estimates:
These permits are revisions or previously issued permits to construct where the construction of Boiler 4 has been completed, the installation of low NOx burners and a new stack has been completed for Boiler 2, installation of low NOx burners and a new stack is still ongoing for Boiler 3, and plans to retrofit Boiler 1 have been replaced with operational limitations. Based on these planned and previously completed activities, the potential to emit of each boiler is estimated below.
The Potential to Emit (PTE) of Boiler 1 is estimated as follows:
|
Boiler 1 Potential to Emit (PTE) Estimates |
Estimated PTE Under Previous Retrofit Plan[1] |
Estimated PTE with Proposed Operational Limits |
Change in Estimated PTE |
|
Pollutant |
(tons/yr) |
(tons/yr) |
(tons/yr) |
|
Total Particulate Matter (PM Total) |
2.9 |
0.7 |
-2.2 |
|
Sulfur Oxides (SOx) |
0.3 |
0.1 |
-0.2 |
|
Nitrogen Oxides (NOx) |
8.5 |
8.0 |
-0.5 |
|
Volatile Organic Compounds (VOC) |
2.2 |
0.5 |
-1.7 |
|
Carbon Monoxide (CO) |
20.9 |
7.2 |
-13.7 |
The PTE of Boiler 2, whose retrofits were completed prior to this permitting action is estimated as follows. Because the retrofits were previously completed, no reduction in emissions is expected to result from this permitting action.
|
Boiler 2 Potential to Emit (PTE) Estimates |
Maximum Annual Emissions |
|
Pollutant |
(tons/yr) |
|
Total Particulate Matter (PM Total) |
2.5 |
|
Sulfur Oxides (SOx) |
0.3 |
|
Nitrogen Oxides (NOx) |
7.4 |
|
Volatile Organic Compounds (VOC) |
1.9 |
|
Carbon Monoxide (CO) |
18.0 |
The PTE of Boiler 3, whose retrofits are ongoing, is estimated as follows. No new reduction in PTE is expected as a result of this permitting action, as compared to that envisioned in the prior permit to construct (Permit 7217, issued May 7, 2019), though there are slight differences in calculation methodology that have resulted in minor differences in the estimates for NOx and CO compared to the 2019 estimates.
|
Boiler 3 Potential to Emit (PTE) Estimates |
Maximum Annual Emissions |
|
Pollutant |
(tons/yr) |
|
Particulate Matter (PM Total) |
2.7 |
|
Sulfur Oxides (SOx) |
0.3 |
|
Nitrogen Oxides (NOx) |
8.2 |
|
Volatile Organic Compounds (VOC) |
2.1 |
|
Carbon Monoxide (CO) |
20.0 |
The PTE of Boiler 4, which was constructed under the authority of the previously issued permit to construct (Permit 7214, issued May 7, 2019), is estimated as follows. No new reduction in PTE is expected as a result of this permitting action, as compared to that envisioned in the prior permit to construct, though there are slight differences in calculation methodology that have resulted in minor differences in the estimates for NOx and CO compared to the 2019 estimates.
|
Boiler 4 Potential to Emit (PTE) Estimates |
Maximum Annual Emissions |
|
Pollutant |
(tons/yr) |
|
Total Particulate Matter (PM Total) |
2.7 |
|
Sulfur Oxides (SOx) |
0.3 |
|
Nitrogen Oxides (NOx) |
8.1 |
|
Volatile Organic Compounds (VOC) |
2.1 |
|
Carbon Monoxide (CO) |
19.9 |
Proposed Emission Limitations:
a. Emissions from Boiler 1 shall not exceed the following emission rates [20 DCMR 201]:
|
Pollutant |
Emissions Burning Natural Gas (lb/hr) |
Emissions Burning No. 2 Fuel Oil (lb/hr) |
|
Oxides of Nitrogen (NOx) |
11.4 |
11.4 |
|
Carbon Monoxide (CO) |
10.7 |
4.6 |
|
Volatile Organic Compounds (VOC) |
0.7 |
0.6 |
|
Sulfur Dioxide (SO2) |
0.1 |
0.2 |
|
Total Particulate Matter [PM(total)]† |
1.0 |
1.8 |
† PM Total includes both filterable and condensable fractions.
b. Emissions from Boiler 2 shall not exceed the following emission rates [20 DCMR 201]:
|
Pollutant |
Emissions Burning Natural Gas (lb/hr) |
Emissions Burning No. 2 Fuel Oil (lb/hr) |
|
Oxides of Nitrogen (NOx) |
1.8 |
12.3 |
|
Carbon Monoxide (CO) |
4.7 |
11.3 |
|
Volatile Organic Compounds (VOC) |
0.5 |
0.6 |
|
Sulfur Dioxide (SO2) |
0.1 |
0.2 |
|
Total Particulate Matter [PM(total)] † |
0.6 |
2.3 |
† PM Total includes both filterable and condensable fractions.
c. Emission from Boiler 3 shall not exceed the following emission rates [20 DCMR 201]:
|
Pollutant |
Emissions Burning Natural Gas (lb/hr) |
Emissions Burning No. 2 Fuel Oil (lb/hr) |
|
Oxides of Nitrogen (NOx) |
1.7 |
11.7 |
|
Carbon Monoxide (CO) |
4.5 |
10.7 |
|
Volatile Organic Compounds (VOC) |
0.5 |
0.6 |
|
Sulfur Dioxide (SO2) |
0.1 |
0.2 |
|
Total Particulate Matter [PM(total)] † |
0.6 |
2.2 |
† PM Total includes both filterable and condensable fractions.
d. Emissions from Boiler 4 shall not exceed the following emission rates [20 DCMR 201]:
|
Pollutant |
Emissions Burning Natural Gas (lb/hr) |
Emissions Burning No. 2 Fuel Oil (lb/hr) |
|
Oxides of Nitrogen (NOx) |
1.7 |
11.1 |
|
Carbon Monoxide (CO) |
4.4 |
10.2 |
|
Volatile Organic Compounds (VOC) |
0.5 |
0.5 |
|
Sulfur Dioxide (SO2) |
0.1 |
0.2 |
|
Total Particulate Matter [PM(total)]† |
0.6 |
2.1 |
† PM Total includes both filterable and condensable fractions.
e. NOx emissions (expressed as NO2) from each of Boilers 1, 2, 3, and 4 shall not be greater than the following:
1. For Boiler Nos. 1, 2, 3, and 4 [20 DCMR 804.1 and 20 DCMR Chapter 8, Appendix 8-1]:
i. 0.2 pound per million BTU (lb/MMBTU) heat input, maximum two-hour average, when natural gas is burned; and
ii. 0.3 lb/MMBTU, maximum two-hour average, when No. 2 fuel oil is burned;
2. For Boiler Nos. 3 and 4: 0.20 lb/MMBTU on a 30-day average of one-hour averages basis when burning natural gas or No. 2 fuel oil. [40 CFR 60.44b(l)(1)];
3. For Boiler No. 1, 0.09 lb/MMBTU, based on a calendar day average, for all types and combinations of fuel [20 DCMR 805.2]; and
4. For Boiler Nos. 2, 3, and 4 [20 DCMR 805.5(e)(2)]:
i. 0.12 lb/MMBTU, based on a calendar day average, on days when the equipment is powered by fuel oil or a combination of fuel oil and natural gas; and
ii. 0.05 lb/MMBTU, based on a calendar day average, when the equipment is powered exclusively by natural gas.
-
- Total suspended particulate matter (TSP) (also known as total filterable PM) emissions shall not exceed the following:
1. 0.06 lb/MMBTU heat input from each of Boiler Nos. 1, 2, 3, and 4, as measured by 40 CFR 60, Appendix A, Method 5 and in accordance with 20 DCMR 600.2 and 600.4. This standard applies at all times. [20 DCMR 600.1]; and
2. 0.030 lb/MMBTU heat input from Boiler No. 4, as measured by 40 CFR 60, Appendix A, Method 5. [20 DCMR 1410.1, 40 CFR 60.43b(h)(1), 40 CFR 60.46b(d)(2)(i), 40 CFR 63.11201(a), and 40 CFR 63, Subpart JJJJJJ, Table 1] This standard does not apply during startup or shutdown. [40 CFR 60.46b(a) and 40 CFR 63.11201(d)]. Note that this is a streamlined requirement. 40 CFR 60.46b(a) also exempts times of malfunction, but because this is not exempted in 40 CFR 63.11201(d), it is not exempted here, otherwise the standards are identical.
g. Visible emissions from Boiler Nos. 3 and 4 shall not exceed a five percent (5%) variability factor, above or below zero percent (0%) opacity, as monitored by Continuous Opacity Monitoring Systems (COMS) installed on the boiler outlets, except that discharges shall be permitted for two (2) minutes during any startup, cleaning, adjustment of combustion or operational controls, or regeneration of emission control equipment; provided, that such discharges shall not exceed the following opacities (unaveraged) [20 DCMR 606.1 and 606.2 and 40 CFR 60.43b(f) and 40 CFR 60.43b(g)[2]]:
1. When burning exclusively natural gas, twenty percent (20%); and
2. When burning fuel oil or a combination of fuel oil and natural gas, twenty-seven percent (27%).
h. Visible emissions from Boiler Nos. 1 and 2, as monitored by a COMS installed on the boiler outlets, shall not exceed ten percent (10%) opacity (unaveraged) at any time except that discharges shall be permitted for two (2) minutes during any startup, cleaning, adjustment of combustion or operational controls, or regeneration of emission control equipment; provided, that such discharges shall not exceed the following opacities (unaveraged) [20 DCMR 606.1 and 606.2]:
1. When burning exclusively natural gas, twenty percent (20%); and
2. When burning fuel oil or a combination of fuel oil and natural gas, twenty-seven percent (27%).
i. An emission into the atmosphere of odorous or other air pollutants from any source in any quantity and of any characteristic, and duration which is, or is likely to be injurious to the public health or welfare, or which interferes with the reasonable enjoyment of life or property is prohibited. [20 DCMR 903.1]
Violation of the requirements of this condition that occur as a result of unavoidable malfunction, despite the conscientious employment of control practices, shall be an affirmative defense for which the owner or operator shall bear the burden of proof. A malfunction shall not be considered unavoidable if the owner or operator could have taken, but did not take, appropriate steps to eliminate the malfunction within a reasonable time, as determined by the Department. [20 DCMR 903.13(b)]
j. NOx and CO emissions from each of Boilers 1, 2, 3, and 4, shall not exceed those achieved with the performance of annual combustion adjustments on the boiler, performed per Conditions III(g) and (h) of the permit. [20 DCMR 805.5(b) and 20 DCMR 805.9]
The permit application and supporting documentation, along with the draft permit are available for public inspection at AQD and copies may be made available between the hours of 8:15 A.M. and 4:45 P.M. Monday through Friday. Interested parties wishing to view these documents should provide their names, addresses, telephone numbers and affiliation, if any, to Stephen S. Ours at (202) 535-1747. Copies of the draft permit and related technical support memorandum are also available at https://doee.dc.gov/service/public-notices-hearings.
Interested persons may submit written comments or may request a hearing on this subject within 30 days of publication of this notice. The written comments must also include the person’s name, telephone number, affiliation, if any, mailing address and a statement outlining the air quality issues in dispute and any facts underscoring those air quality issues. All relevant comments will be considered both in issuing the final permit and submitting the requirements of the aforementioned permit conditions as part of the District’s SIP.
Comments on the proposed permit or SIP amendment and any request for a public hearing should be addressed to:
Stephen S. Ours
Chief, Permitting Branch - Air Quality Division
Department of Energy and Environment
1200 First Street NE, 5th Floor
Washington DC 20002
No comments or hearing requests submitted after January 2, 2024 will be accepted.
For more information, please contact Stephen S. Ours at (202) 535-1747.
