~~· s== ) State of Utah .~ DEPARTMENT OF ENVIRONMENTAL QUALITY 

DIVISION OF AIR QUALITY 

M 150 NOM 1950 West ....l o. "",,;.1 P.O. Box 144820 

Dianne R. Nielson~ I Salt Lake City, Utah 8411~820

(801) 5364000 

Russell E.u<:utive A. Roberts Dire<:lor I (801) 536-4099 Fax
 

Dire<:lor . (801) 538-4414 T.D.D.
 

DAQE-403-95 

May 8, 1995 

W. Robert James
 

OO-ALC/EM
 

7274 Wardleigh Road
 

Hill Air Force Base, Utah 84056-5137
 

Re:	 Approval Order for Construction of Two Boilers Each in Buildings 1590 and 1703
 

Davis County CDS B NA l\'SPS
 

Dear Mr. James: 

The attached document is an Approval Order for the above referenced project. 

Future correspondence on this Approval Order should include the engineer's name as well as the 

DAQE number as shown on the upper right-hand corner of this letter. Please direct any technical 

questions you may have on this project to Mr. Arjun Ram. He may be reached at (801) 536-4066. 

Sincerely, --j;,,~, ;:1
 -~/I/I) ./;~Y-- _Russell A. Roberts; Executive Secretary
 

Utah Air Quality Board
 

RAR:AR:dn 

cc:	 Davis County Health Depanment 

4.2.4-174
 
STATE OF UTAH 

Department of Environmental Quality 

Division of Air Quality 

APPROVAL ORDER FOR .<~'" CONSTRUCTION OF TWO BOILERS EACH IN 

BUILDINGS 1590 & 1703 

PREPARED BY: Arjun Ram, Engineer 

APPROVAL ORDER NUl\ffiER
 

DAQE-403-95
 

Date: .May 8, 1995
 

Source
 

HILL AIR FORCE BASE 

Russell A. Roberts
 

Executive Secretary
 

Utah Air Quality Board
 

4.2.4-175
 
DAQE-403-95 

Page 2 

Abstracr 

This Review/Approval Order is for the installation ofrwo narural gasfired. 10w-NOx• watenube. 

steam boilers rared ar 27.6 MMBTU/HR in Building 1590 and the installarion of TWO natural gas 

fired. low NOx• firetube steam boilers. rared at 11.25 MMBTU/HR in Building 1703. These boilers 

would replace existing boilers in the buildings. which do not have low-NOx burners. This project 

does not result in an increase in acrual emissions from the boilers; therefore. a 30-day public 

commenr period is not required for this project. All the four boilers are capable of using #2 fuel oil 

as backup fuel. Emissions from the four boilers with a maximum of 720 hours of burning fuel oil per 

12-month period are 4.48 tons per year PMJo• 15.96 tons per year SOx. 18.98 tons per year NOx• 

20.05 tons per year CO. and 1.86 tons per year VOc. Low-NOx technology in conjuncrion with a 

10% opacity limitation and the use of natural gas as primary fuel are considered BeS[ A \/ailable 

QJnrrol Technology (BACT) for this project. 

The Notice of Intent for the above-referenced project has been evaluated and has heen found to be 

consistent with the requirements of the Utah Air Conservation Rules (UACR) and th~ Utah Air 

Conservation Act. However, air pollution producing sources and/or their air control fa.:i1 ities may 

not be constructed, installed, established. or modified prior to the issuance of an Arrroval Order 

(AO) by the Executive Secretary of the Utah Air Quality Board. 

Unless you have comments which would require changes, the AO for this proje.:t will he hased upon 

the following conditions: -, 

General Conditions: 

1.	 This AO applies to the following company: 

Department Of The Air Force
 

OO-ALC/EM
 

7274 Wardleigh Road
 

Hill Air Force Base, Utah 84056-5137
 

Phone Number: (801) 777-D359
 

Fax Number: (801) 777-4306
 

The equipment listed below in this AO shall be operated at the following location: 

LOCATION 

UTM COORDINATES: 

Building 1590: 4,553,750 m. Northing; 415.290 m. Easting 

Building 1703: 4,554,870 m. Northing; 414,210 m. Easting 

2.	 Definitions of terms, abbreviations, and references used in this AO conform to those 

used in the UACR, Utah Administrative Codes (UAC), and Series 40 of the Code of 

Federal Regulations (40 CFR). These definitions take precedence unless specifically 

defined otherwise herein. - 4.2.4-176
 
DAQE-403-95 

Page 3 

3.	 HilI Air Force Base shall install and operate the natural gas fired boiler according to 

the information submitted in the Notice of Intent dated December 22, 1994. 

4.	 A copy of this AO shall be posted on site. The AO shall be available to the 

employees who operate the air emission producing equipment. These employees shall 

receive instruction as to their responsibilities in operating the equipment according to 

all of the relevant conditions Iisted below. 

5.	 The approved installations shall consist of the following equipment (MMBTU/HR 

stands for million BTUs per hour): 

A.	 Two boilers (rated at 27.60 MMBTU/HR) and associated equipment in 

Building 1590 

B.	 Two boilers (ra[ed at 11.25 MMBTU/HR) and associated equipment in 

Building 1703 

Hill Air Force Base shall submit to the Division of Air Quality (DAQ), the 

Manufacturer's name. Boiler's ~10del and Serial Number (or equivalent information 

that will enable proper identifi.cation of the boilers), for each of the boilers approved 

by this condition before commencing the operation of the boilers. 

6.	 Hill Air Force Base shall permanently shut down the operation of two boilers in 

Building 1590 and two boilers in Building 1703 before commencing the operation of 

the boilers approved in Condition #5. 

7.	 The Executive Secretary shall be notitied in writing upon stan-up of the installation as 

an initial compliance inspection is required. Eighteen months from the date of this 

AO the Executive Secretary shall be notitied in writing of the status of installation if 

construction/installation is not completed. At that time the Executive Secretary shall 

require documentation or the continuous installation of the operation and may revoke 

the AO in accordance with R307-l-3.1.5. UAC. 

Limitations and Tests Procedures 

8.	 Emissions to the atmosphere from the stacks of the boilers approved in Condition #5 

shall not exceed the following rates and concentrations (the lbslhr and ppmdv values 

are equivalent and the source has the option of demonstrating compliance with values 

in either of the units): 

Source: Stacks of Boilers in Building 1590 

Pollutant lbs/hr ppmdv (3 % 0", dry) 

NO x 1.33 40 

CO 1.21 60 

4.2.4-177
 
DAQE-403-95 

Page 4 

Source: Stacks of Boilers in Building 1703 

Pollutant lbslhr I ppmdv (3 % 02' dry) 

NOx 0.54 40 

CO 0.49 60 

9.	 Stack testing to show compliance with the emission limitations stated in the above 

condition shall be performed as specified below lor each of the boilers specified in 

Condition #5: 

A.	 Emission Point Pollutant Testing Test 

Status Frequency 

Boiler Stack	 NO, '" @ 

CO '" @ 

B.	 Testing Status (To be applied above) 

*	 No initial testing is required. However. the Executive Secretary may 

require testing at any time in accordance with R307-1-3.4.1, UAC. 

The source shall be tested if directed by the Executive Secretary. 

**	 Initial compliance testing is required. The initial test date shall be 

within 180 days after the start up of a new emission source, or the 

granting of the AO for an existing emission source. 

@	 Test if directed by the Executive Secretary. Tests may he required if 

the source is suspected to be in violation with other conditions of this 

AO. 

C.	 Notification 

The applicant shall provide a notification of the test date at least 45 days 

before the test. A pretest conference shall be held if directed by the Executive 

Secretary. It shall be held at least 30 days before the test between the 

owner/operator, the tester, and the Executive Secretary. The emission point 

shall be designed to conform to the requirements of 40 CFR 60, Appendix A. 

Method 1, and Occupational Safety and Health Administration (OSHA) or 

Mine Safety and Health Administration (MSHA) approvable access shall be 

provided to the test location. 

D.	 Sample Location 

40 CFR 60. Appendix A, Method 1 

4.2.4-178 
DAQE-403-9S 

Page 5 

E.	 Volumetric Flow Rate
 

40 CFR 60, Appendix A. Method 2
 

F.	 Nitrogen Oxides (NO.1 

40 CFR 60, Appendix A, Method 7, 7A, 7B, 7e, 7D or 7E or an alternative 

method to be approved by the Executive Secretary. The test protocol shall be 

submitted for review at the time of notification of the test. 

G.	 Carbon Monoxide (CO)
 

40 CFR 60, Appendix A, Method 10
 

H.	 Calculations 

To determine mass emission rates (lbs/hr, etc.), the pollutant concentration as 

determined by the appropriate methods above shall he multiplied by the 

volumetric flow rate and any ., necessary conversion factors determined by. the 

Executive Secretary to give the results in the specified units of the emission 

limitation. 

I.	 Source Operation 

The heat (gas) input rate during all compliance testing shall be no less than 

90% of the rates listed in MMBTU/HR in Condition #5 of this AO. 

10.	 Visible emissions from any point or fu/::-:tive emission source associated with the 

installation or control facilities shall not exceed 10% opacity. Opacity observations of 

emissions from stationary sources shall be conducted in accordance with 40 CFR 60. 

Appendix A, Method 9. Visible emissions from mobile sources and intermittent 

sources shall use procedures similar to Method 9, but the requirement for observations 

to be made at IS-second interVals over a six-minute period shall not apply. Any time' 

interval with no visible emissions shall not be included. 

11.	 The following consumption limits shall not be exceeded without prior approval in 

accordance with R307-1-3.1, UAC; 

For each boiler in building 1590(rated at 27.6 MMBTUlhr): 

A.	 242,000 decatherms (242 million cubic feet) of mltural gas per 12-month 

period (l decatherm = 1,000.000 BTU) 

B.	 141,000 gallons of fuel oil to be burned per 12-month period 

C.	 720 hours of operation burning fuel oil per l2-momh period 

4.24-179 
DAQE-403-95 

Page 6 

For each boiler in building 1703 (rated at 11.25 ?vl~1BTU!hr):

A.	 98,550 decatherms (99 million cubic feet) of natural gas per 12-month period 

B. 57,500 gallons of fuel oil to be burned per 12-month period 

C.	 720 hours of operation burning fuel oil per 12-month period 

Compliance with the annual limitations shall be determined on a rolling 12-month 

total. Before the fifteenth day of each month, a new 12-month total shall be 

calculated using data from the previous 12 calendar months. Records of oil 

consumption shall be kept for all periods when the plant is in operation. Records of 

oil consumption shall be made available to the Executive Secretary or his 

representative upon request and shall include a period of two years ending with the 

date of the request. Consumption shall be determined by operating logs or vendor 

receipts. The records shall be kept on a dail v hasis. Hours of operation shall be 

determined by supervisor monitoring and maintaining of an operations log. 

12.	 The owner/operator shall use only natural gas or liquid petroleum gas as a primary 

fuel and #2 fuel oil or light grade as a backup fuel in the boiler. If any other fuel is 

to be used, an AO shall be required in accordanl.:e with R307-1-3.1, UAC. Number 

two (#2) fuel oil may be used only when natural gas supply has been interrupted. 

13.	 The sulfur content of any fuel oil burned shall not exceed 0.5 percent by weight. 

Sulfur content shall be decided by ASTM Method D-4294-89, or approved equivalent. 

The sulfur content shall be tested if directed by the Executive Secretary. 

Federal Limitations and Requirements 

14.	 In addition to the requirements of this AO, all provisions of 40 CFR 60. NSPS 

Subparts A and Dc, 40 CFR 60.40c to 60.48c (Standards of Performance for Small 

Industrial - Commercial - Institutional Steam Generating Units) apply to this 

installation. 

The owner or operator shall record and maintain records of the amount of fuel 

combusted during each day. Each boiler must have an individual fuel use meter 

which cannot be reset. to determine how much fuel that boiler used each day. 

Records & Miscellaneous 

15.	 All records referenced in this AO or in an applicable new source performance 

standard (NSPS), which are required to be kept by the owner/operator. shall be made 

available to the Executive SecreTary or his representative upon request. 

.­

4.2.4-180
 
DAQE-403-95 

Page 7 

Examples of records to be kept at this source shall include the following as applicable: 

A.	 Fuel consumption 

B.	 Test results 

16.	 All instaJlations and facilities authorized by this AO shall be adequately and properly 

maintained. All pollution control vendor recommended equipment shall be installed. 

maintained. and operated. Instructions from the vendor or established maintenance 

practices that maximize pollution control shall be used. All necessary equipment 

control and operating devices. such as pressure gauges. amp meters, volt meters. flow 

rate indicators. temperature gauges, continuous emission monitors (CEMs), etc.• shall 

be installed and operated properly and easily accessible to compliance inspectors. 

11.	 The owner/operator shaJl comply with R307-1-3.5, UAC. This rule addresses 

emission inventory reporting requirements. 

18.	 The owner/operator shall comply with R307-1-4.7. UAC. This rule addresses 

unavoidable breakdown reporting requirements. The owner/operator shall 

calculate/estimate the excess emissions whenever a breakdown occurs. The total of 

excess emissions shall be reported to the Executive Secretary as directed for each 

calendar vear. 

19.	 This source is required to pay an annual emission fee upon start-up. The fee wiJl be 

based on calculated annual emissions listed at the end of this AO. This fee is valid 

until inventory data for one year are available for the source. The owner or operator 

of this source will be billed upon start-up for all emissions that are considered 

"chargeable" as of that date. 

Any future modifications to the equipment approved by this order must also be approved in 

accordance with R307-l-3.1.1. UAC. 

This AO in no way releases the owner or operator from any liability for compliance with all other 

applicable federal. state. and local regulations Including the UACR. 

Annual emissions for this source (four boilers in Condition #5) are currently calculated at the 

following values: 

Pollutant	 Tons/vr 

A.	 PM:o 4.48 

B.	 SO.. . . . . 15.96 

C.	 NOx . . . . . . ... 18.98 

D.	 CO. . . . . .. . .. 20.05 

E.	 VOC 1.86 

4.2.4-181 
DAQE-403-95 

Page 8 

These calculations are for the purposes of determining the applicability of prevention of significant 

deterioration (PSD) and nonanainment area major source requirements of the UACR. They are not to 

be used for purposes of determining comp] iance. 

In accordance with the requirements of Title V of the 1990 Clean Air Act, the following pollutants 

may be subject to an operating permit fee. Both the fees rate and the class of pollutants are subject to 

change by State, the Federal agencies. or both. 

Pollutant	 Tons/vr 

A. Particulate	 4.48 

B. 502 . • • . • • • • • . • . . . . . . . . . . . • •• 15.96
 

C. NOx	 18.98 

D. VOC	 1.86 

Approved By); , ,i. / /~fj/f' ,--,\	 "j /!~ /
 . .' I I.
 ," .;/ /I/~• 

"--- ..v f, """ /j :. " 

Russell A. Roberts. Ex.ecutive 'Secretarv 

\ -Utah Air Quality Board . 

4.2.4-182
 
.~ , ~~ .., ... ".,	 ..... . .. , 'j ..J •• . .::-s	 • ,	 

DEPARTMENT OF ,; '-* ENVIRONMENTAL QUALm' .: :. 

. 

.. ". 

DMSION OF AIR QUALITY
 

Michael O. Luvia 150 NOM 1950 Wellt 

o.-r­ P.O. Box 144820 

Dianne R. NieiIOD. Ph.D. Salt I...akt City, Utab 84114-4820 

E.=cuaYe Dinlclar (801) 536-4000 

Ruueil A. Rabens (801) 536-4099 Fax 

ov­ (80l) 538-4414 T.D.D. 

DAQE-I04-95 

February 8, 1995 

W. Roben James 

OO-ALCIEM 

i274 Wardleigh Road 

Hill Air Force Base. Utah 84056-5137 

Re:	 Intent to Approve Construction of Two Boilers Each in Buildings 1590 and 1703 

Davis County CDS B NA NSPS 

Dear Mr. James: 

The attached document is an Intent to Approve with Fee Statement for the above referenced project. 

Future correspondence on this Approval Order should include the engineer's name as well as the 

DAQE number as snown on the upper right-hand corner of this letter. Please direct any technical 

questions you may have on this project to Mr. Arjun Ram. He may be reached at (801) 536-4066. 

Sincerely, 

/7 . (,.., ~., /1

.-/7~ I .', .".... V""//~~ ,I, -, //~

L~R. MeDlove', Manager 

New Source Review Section 

LRM:AR:dn 

cc:	 Davis County Health Depanrnent 

4.2.4-183 

?rinteo on recvc:ea DaDer 
STATE OF UTAH
 

Department of Environmental Quality 

Division of Air Quality 

INTENT TO APPROVE CONSTRUCTION OF TWO
 

BOILERS IN BUILDING 1590 AND TWO BOILERS
 

IN BUILDING 1703
 

PREPARED BY: Arjuo Ram 

INTENT TO APPROVE NUMBER 

DAQE-I04-95 

Date: February 8, 1995 

Source 

HILL AIR FORCE BASE
 

Russell A. Roberts
 

Executive Secretary
 

Utah Air Quality Board
 

4.2.4-184 
DAQE-104-95 

February 8. 1995 

Page 2 

AbsTracr 

This ReviewiApproval Order is for rhe insrallarion of lWO natural gas fired, 10w-NOx. warenube. 

sream boilers rared ar 27.6 MMBTUIHR in Building 1590 and rhe insrallarion ofrwo narural gas 

fired, low NOx•firerube sream boilers. rared ar 11.25 MMBTUIHR in Building 1703. These boilers 

would replace existing boilers in rhe buildings, which do nor have 10w-NOx burners. This projecr 

does nor resulr in an increase in actual emissions from rhe boilers: rherefore, a 3D-day public 

comment period is nor required for rhis projecr. All rhe four boilers are capable of using #2 fuel oil 

as backup fuel. Emissionsfrom rhe four boilers with a maximum of 720 hours ofburning fuel oil per 

12-month period are 4.48 rons per year PMJo, 15.96 rons per year SOx, 18.98 rons per year NOx. 

20.05 rons per year CO. anti 1.86 rons per year VOc. Low-NOx rechnology in conjuncrion wirh a 

10% opaciry limiration anti rhe use of narural gas as primary fuel are considered Besr Available 

Control Technology (BACT) for rhis projecr. 

The Notice of Intent for the above-referenced project has been evaluated and has been found to be 

consistent with the requirements of the Utah Air Conservation Rules (UACR) and the Utah Air 

Conservation Act. However, air pollution producing sources and/or their air control facilities may 

not be constructed, installed. established, or modified prior to the issuance of an Approval Order 

(AO) by the Executive Secretary of the Utah Air Quality Board. 

Unless you have comments which would require changes, the AO for this project will be based upon 

the following conditions: 

RECOMMENDED APPROVAL ORDER CONDITIONS 

General Conditions: 

1.	 This AO applies to the following company: 

Depanmem Of The Air Force
 

OO-ALCIEM
 

7274 Wardleigh Road
 

Hill Air Force Base, Utah 84056-5137
 

Phone Number: (801) 777-Q359
 

Fax Number: (801) 777-4306
 

The equipment listed below in this AO shall be operated at the following location: 

LOCATION 

UTM COORDINATES; 

Building 1590: 4.553.750 m. Northing; 415.290 m. Easting 

Building 1703: 4,554,870 m. Northing; 414.210 m. Easting 

2.	 Definitions of terms. abbreviations, and references used in this AO conform to those 

used in the UACR, Utah Administrative Codes (UAC), and Series 40 of the Code of 

4.2.4-185 
DAQE-104-95 

February 8, 1995 

Page 3 

Federal Regulations (40 CFR). These definitions take precedence unless specifically 

defined otherwise herein. 

3.	 Hill Air Force Base shall install and operate the natural gas fired boiler according to 

the infonnation submined in the Notice of Intent dated December 22, 1994. 

4.	 A copy of this AO shall be posted on site. The AO shall be available to the 

employees who operate the air emission producing equipment. These employees shall 

receive instruction as to their responsibilities in operating the equipment according to 

all of the relevant conditions listed below. 

5.	 The approved installations shall consist of the following equipment (MMBTUIHR 

stands for million BTUs per hour): 

A.	 Two boilers (rated at 27.60 MMBTUfHR) and associated equipment in 

Building 1590 

B.	 Two boilers (rated at 11.25 MMBTU/HR) and associated equipment in 

Building 1703 

Hill Air Force Base shall submit to the Division of Air Quality (DAQ), the
 

Manufacturer's name. Boiler's Model and Serial Number (or equivalent infonnation -.,
 

that will enable proper identification of the boilers), for each of the boilers approved
 

by this Condition, before commencing the operation of the boilers.
 

6.	 Hill Air Force Base shall pennanentiy shut down the operation of two boilers in 

Building 1590 and two boilers in Building 1703 before commencing the operation of 

the boilers approved in Condition #5. . 

7.	 The Executive Secretary shall be notified in writing upon stan-up of the installation as 

an initial compliance inspection is required. Eighteen months from the date of this 

AO the Executive Secretary shall be notified in writing of the status of installation if 

construction/installation is not completed. At that time the Executive Secretary shall 

require documentation of the continuous installation of the operation and may revoke 

the AO in accordance with R307-1-3.1.5, UAC. 

4.2.4-186
 
DAQE-104-95 

February 8, 1995 

Page 4 

Limitations and Tests Procedures 

8.	 Emissions to the atmosphere from the stacks of the boilers approved in Condition #5 

shall not exceed the following rates and concentrations (the lbslhr and ppmdv values 

are equivalent and the source has the option of demonstrating compliance with values 

in either of the units): 

Source: Stacks of Boilers in Building 1590 

Pollutant lbslhr ppmdv (3 % O:!, dry) 

NOx I 1.33 

CO I 1.21 60 

Source: Stacks of Boilers in Building 1703 

Pollutant lbslhr ppmdv (3% O:!, dry) 

NOx 0.54 

CO 0.49 60 

9.	 Stack testing to show compliance with the emission limitations stated in the above 

condition shall be performed as specified below for each of the boilers specified in 

Condition #5: 

A.	 Emission Point Pollutant Testin2 :rm 

Frequency 

Boiler Stack	 NO~ * @ 

CO * @ 

B.	 Testing Status (To be applied above) 

*	 No initial testing is required. However, the Executive Secretary may 

require testing at any time in accordance with R307-1-3 A.l, UAC. 

The source shall be tested if directed by the Executive Secretary. 

**	 Initial compliance testing is required. The initial test date shall be 

within 180 days after the stan up of a new emission source, or the 

granting of the AO for an existing emission source. 

@	 Test if directed by the Executive Secretary. Tests may be required if 

the source is suspected to be in violation with other conditions of this 

AO. 

4.2.4-187 
DAQE-104-95 

February 8, 1995 

Page 5 

C.	 Notification 

The applicant shaH provide a notification of the test date at least 45 days 

before the test. A pretest conference shall be held if directed by the Executive 

Secretary. It shall be held at least 30 days before the test between the 

owner/operator. the tester, and the Executive Secretary. The emission point 

shall be designed to conform to the requirements of 40 CFR 60, Appendix A, 

Method	 1, and Occupational Safety and Health Administration (OSHA) or 

Mine Safety and Health Administration (MSHA) approvable access shall be 

provided to the test location. 

D.	 Sample Location 

40 CFR 60. Appendix A, Method 1 

E.	 Volumetric Flow Rate 

40 CFR 60, Appendix A, Method 2 

F.	 Nitrogen Oxides (NO.} 

40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D or 7E or an alternative 

method to be approved by the Executive Secretary. The test protocol shall be 

submitted for review at the time of notification of the test. 

G,	 Carbon Monoxide (CQ) 

40 CFR 60, Appendix A, Method 10 

H.	 Calculations 

To determine mass emission rates (lbslhr, etc.), the pollutant concentration as 

determined by the appropriate methods above shall be multiplied by the 

volumetric flow rate and any necessary conversion factors determined by the 

Executive Secretary to give the results in the specified units of the emission 

limitation. 

I.	 Source Operation 

The heat (gas) input rate during all compliance testing shall be no less than 

90% of the rates listed in MMBTUIHR in Condition #5 of this AO. 

10.	 Visible emissions from any point or fugitive emission source associated with the 

installation or control facilities shall not exceed 10% opacity. Opacity observations of 

emissions from stationary sources shall be conducted in accordance with 40 CFR 60, 

Appendix A, Method 9. Visible emissions from mobile sources and intermittent 

4.2.4-188 
DAQE-104-95 

February 8, 1995 

Page 6 

sources shall use procedures similar to Method 9. but the requirement for observations 

to be made at 15-second intervals over a six-minute period shall not apply. Any time 

interval with no visible emissions shall not be included. 

11.	 The following consumption limits shall not be exceeded without prior approval in 

accordance with R307-1-3.1, UAC: 

For each boiler in building 1590 (rated at 27.6 MMBTUlhr): 

A.	 242.000 decatherms (242 million cubic feet) of natural gas per 12-month 

period (1 decatherm = 1,000,000 BTU) 

B.	 141,000 gallons of fuel oil to be burned per 12-month period 

C.	 720 hours of operation burning fuel oil per 12-month period 

For each boiler in building 1703 (rated at 11.25 MMBTUlhr): 

A.	 98,550 decatherms (99 million cubic feet) of natural gas per l2-monm period 

B. 57.500 gallons of fuel oil to be burned per 12-month period 

C.	 720 hours of operation burning fuel oil per 12-month period 

Compliance with me annual limitations shall be determined on a rolling 12-month 

total. Before the fifteenth day of each month, a new 12-month total shall be 

calculated using data from the previous 12 calendar months. Records of oil 

consumption shall be kept for all periods when the plant is in operation. Records of 

oil consumption shall be made available to the Executive Secretary or his 

representative upon request. and shall include a period of two years ending with the 

date of the request. Consumption shall be determined by operating logs or vendor 

receipts. The records shall be kept on a daily basis. Hours of operation shall be 

determined by supervisor monitoring and maintaining of an operations log. 

12.	 The owner/operator shall use only natural gas or liquid petroleum gas as a primary 

fuel and #2 fuel oil or light grade as a backup fuel in the boiler. If any other fuel is 

to be used, an AD shall be required in accordance with R307-1-3.1. UAC. Number 

two (#2) fuel oil may be used only when natural gas supply has been interrupted. 

13.	 The sulfur content of any fuel oil burned shall not exceed 0.5 percent by weight. 

Sulfur content shall be decided by ASTM Method D-4294-89. or approved equivalent. 

The sulfur content shall be tested if directed by the Executive Secretary. 

4.2.4-189 
DAQE-104-95 

February 8, 1995 

Page 7 

Federal Limitations and Requirements 

14.	 In addition to the requirements of this AD. all provisions of 40 CFR 60, NSPS 

SubpartS A and Dc. 4{) CFR 60.4{)c to 6O.48c (Standards of Perfonnance for Small 

Industrial - Commercial - Institutional Steam Generating Units) apply to this 

installation. 

The owner or operator shall record and maintain records of the amount of fuel 

combusted during each day. Each boiler must have an individual fuel use meter 

wbich cannot be reset, to detennine how much fuel that boiler used each day. 

Records & Miscellaneous 

15.	 All records referenced in this AD or in an applicable new source perfonnance 

standard (NSPS), which are required to be kept by the owner/operator. shall be made 

available to the Executive Secretary or his representative upon r~uest. Examples of 

records to be kept at this source shall include the following as applicable: 

A.	 Fuel consumption 

B.	 Test results 

16.	 All installations and facilities authorized by this AD shall be ad~uately and properly 

maintained. All pollution control vendor recommended equipment shall be installed, 

maintained, and operated. Instructions from the vendor or established maintenance 

practices that maximize pollution control shall be used. All necessary equipment 

control and operating devices, such as pressure gauges, amp meters, volt meters, flow 

rate indicators, temperature gauges, continuous emission monitors (CEMs), etc., shall 

be installed and operated properly and easily accessible to compliance inspectors. 

17.	 The owner/operator shall comply with R307-1-3.5, UAC. This rule addresses 

emission inventory reponing requirements. 

18.	 The owner/operator shall comply with R307-1-4.7, UAC. This rule addresses 

unavoidable breakdown reponing r~uirements. The owner/operator shall 

calculate/estimate the excess emissions whenever a breakdown occurs. The total of 

excess emissions shall be reponed to the Executive Secretary as directed for each 

calendar year. 

19.	 This source is required to pay an annual emission fee upon start-up. The fee will be 

based on calculated annual emissions listed at the end of this AD. This fee is valid 

until inventory data for one year are available for the source. The owner or operator 

of this source will be billed upon stan-up for all emissions that are considered 

"chargeable" as of that date. 

4.2.4-190 
DAQE-104-95
 

February 8, 1995
 

Page 8
 

Any future modifications to the equipment approved by this order must also be approved in
 

accordance with R307-1-301.1, UACo
 

This AO in no way releases the owner or operator from any liability for compliance with all other
 

applicable federal, state, and local regulations including the UACRo
 

Annual emissions for this source (four boilers in Condition #5) are currently calculated at the 

following values: 

Pollutant Tons/yr 

A. PMIO ' •••• 0 0 0 4.48 

B. SO~ 0 0 0 . o. 15.96 

C. NOx ' . 0 . 0 . 0 0 18.98 

D. CO 0 ••••• 0 •••••••• 20.05

E. VOC ..... 0 ••••••• 0 • 1.86

These calculations are for the purposes of determining the applicability of prevention of significant 

d~terioration (PSD) and nonattainrnent area major source requirements of the UACR. They are not to 

be used for purposes of determining compliance. 

In accordance with the requirements of Title V of the 1990 Clean Air Act, the following pollutants 

may be subject to an operating permit fee. Both the fees rate and the class of pollutants are subject to 

change by State, the Federal agencies, or both. 

Pollutant Tons/yr 

A. Particulate .. 0 0 . 0 0 . 0 0 0 . 0 .. 4.48 

B. S02 0 0 . 0 o. 15.96 

C. NOx 0" 0 0 0 . 0 0 . o. 18.98 

D. VOC , .. 0 0 0 . 0 0 0 . 1.86 

Sincerely, 

/r? ~" /. .....me= I", ./ -' 1 . .A.,< :...... -'E5'n:R: Merilove, Manager 

New Source Review Section 

4.2.4-191
 
DAQE-I04-95 

February 8, 1995 

Page 9 

Hill Air Force Base 

Construction of Two Boilers In Bldg 1590 an Two Boilers in Bldg. 1703) 

P'iling Fee 

Review EngiIiBazrs @ S50.00/hr 

Modeler hours @ $50.00/hr 

Coaputer Fee 

Hotice To Paper 

Travel miles @ SO.23/mile 

S 

S 

$ 

$ 

$ 

S 

1000.00 

0.00* 

0.00* 

0.00* 

0.00* 

0.00 

Total Charges . . . 

Aaount paid to Date 

S 

S 

1000.00 

0.00 

-... 

Balance Due . . • . . S 1000.00 

* These costs are included in the Filing P'ee. Pl.... reait a copy of this iJlYOice with your pa~t.

Please send payment to: 

Utah Division of Air Quality 

150 North 1950 We.t 

Salt Lake City, utah 84114-8420 

(801) 536-4000 

4.2.4-192
 
UTAH DIVISION OF AIR QUALITY
 

NEW/MODIFIED SOURCE PLAN REVIEW
 

W/Rdben.James 

OO..ALClEM 

727AWardleigb.R6ad 

Hil~Air .• F(JrcellaSe;p~ .••.~4P??~5.137

RE: N4tice.cflritentto.ConstructTwo BOilersill Building 1.590 and.Two Boiiers in BOOdingJ763 .. . .. . . . . ... .. . . . 

Da~is County, CDS B; NA; NSPS 

ENGINEER: A.i.ffiri~am

DATE: 

NOTICE OF INTENT DATED: D~mber·22,...1994 

PLANT CONTACT: Mr. Andreas Zekorn 

PHONE NUMBER: (8(l1)777-4)359 

FAX NUMBER (~PJ)7774306

PLANT LOCATION: Bui1<iing 1596 (2boilers) andBuildingJ70~(2b<>il~rs),HillAirForceBase

UTM COORDINATES: lluildingJ590: 4;553;750 m; •.Noithi~g;A15,2901ll;&StiDg

JJMY8mg •.!!q~:1,?5*,~(}..··m~~~~~tl~;.·114-~~1(}.~.~~Dg FEES: 

Basic Approval Order Fee $1000.00 

Review Engineer - XXX)( total hours at $50.00lhour $000.00 

Modeler - XXXX hours at $50.00/hour $000.00 

Notice To Paper .. . . . . . . . . . . . . . . . . . . . . . . . . . . .. $000.00 

Travel - 00 miles at $0.23/mile . . . . . . . . . . . . . . . . . . . .. $000.00 

TOTAL .,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1000.00
 

APPROVALS:
 

Review Engineer &Q ?/z /9 r
 ---::(S::-ig-na-I-tL-""re:....&7"'::D~a-te-)-----"1~-;7H-.-J+------------

F:\AQ\ENGINEER\if.Rtti\t\WP\AO\HAFJ!;.li()I;a.p 

4.2.4-193
 
TYPE OF IMPACT AREA 

Attainment or Non-Attainment Non-Attainment 

Non-Attainment Pollutants . . . . . . . PMlO SOx Ozone CO 

NSPS Applies yes 

NSPS Subpans A and Dc apply to this source 

NESHAP Applies no 

Toxic Pollutants no 

Toxic Major Source . . . . . . . . . . . . . . . .. no 

[> lO tpy of anyone Hazardous Air Pollutant(HAP) of > 25 tpy of any combination of 

HAPs] 

New Major Source no 

Major Modification no 

PSD Permit . , . . . . . . . . . . . . . no 

PSD Increment . . . . . . . . . . . . . . . . no 

(modeling) 

Send to EPA no 

Operating Permits Program . yes (NSPS applies) 

Title V Major Source . . . . . . . . . . . . . . . . no 

Process Path . Regular AO Processing 

EMISSIONS SUMMARY 

Total Emissions for 2 Boilers to be Installed in Building 1590. Each Rated at 27.6 

:MMBTUfHR 

Pollutant rateCt,py) 

PMIO ••••••••• 3.18 

S02 . . . . . . . .. 11.34 

NOx 13.49 

CO 14.24 

VOC , 1.32 

4.2.4-194
 
Total Emissions for 2 Boilers to be Installed in Building 1590. Each Rated at 11.25 

MMBTU/HR 

Pollutant rateCtpv)
 

PMIO ••••••••• 1.30
 

502 ..•.••.••• 4.62
 

NOx 5.50
 

CO 5.80
 

VOC 0.54
 

Total Emissions from this Project for the 4 Boilers Summarized in the Above Tables to be 

Installed in Buildings 1590 and 1703 

Pollutant rateftpy)
 

PMIO ••••••••• 4.48
 

S02 . . . . . . . .. 15.96
 

NOx 18.98
 

CO 20.05
 

VOC 1.86
 

.­

4.2.4-195
 
Abstract 

This Review/Approval Order is for the installation oftwo naJural gas fired, 10w-NOx, 

watertube, steam boilers rated at 27.6 MMBTU/HR in Building 1590 and the installation of 

two natural gas fired, low NOx, firetube steam boilers, rated at 11.25 MMBTU/HR in 

Building 1703. These boilers would replace existing boilers in the buildings, which do not 

have 10w-NOx burners. This projectdoes not result in an increase in actual emissions from 

the boilers and therefore, a 30-day public comment period is not required for this project. 

All the four boilers are capable of using #2 fuel oil as backup fuel. Emissions from the 

four boilers with a maximum of 720 hours of burning fuel oil per 12-month period are 

4.48 tons per year PM,07 15.96 tons per year SOx, 18.98 tons per year NOx, 20.05 tons 

per year CO, and 1.86 tons per year VOc. Low-NOx technology in conjunction with a 

10% opacity limitation and the use of natural gas as primary fuel are considered Be~t

Available Control Technology for this project. 

1. DESCRIPTION 

A. This ReviewIApproval Order is for the installation of two natural gas-fired, low-NOx,
 

watertube, steam boilers rated at 27.6 :M:MBTU/HR in Building 1590 and the installation of
 

two natural gas-fired, low NOx, frretube stearn boilers, rated at 11.25 :M:MBTU/HR in
 

Building 1703. These boilers would replace existing boilers in the buildings, which do not
 

have low-NOx burners. Provisions are included for the use of fuel oil as a backup fuel. ..-.,
 

This will be limited in the Approval Order (AD) to less than 200 hours per year.
 

B. The primary pollutants of concern are nitrogen oxides (NOx) and carbon monoxide
 

(CO). Nitrogen oxides are fonned at high temperatures when atmospheric nitrogen combines
 

with atmQspheric oxygen. CO is a product of incomplete combustion due to a lack oxygen,
 

low residence time, or poor mixing.
 

II. BEST AVAILABLE CONTROL TECHNOLOGY (BACD ANALYSIS 

BACT for the boilers covered under this review (from previously established BACT 

guidelines, stated in the generic permit review for boilers) is determined to be: 

1. An opacity limitation of 10% shall apply to the boiler stack. 

4.2.4-196
 
2. The NOI states that the boilers can meet NOx emission limit (concentration) of 

less than 40 ppm. which is as stringent as is required of a 100 M:MBTU/HR boiler 

according to the following equation: 

NO:< ppm $( 82. 105 -0. 4211 x( Boiler Rating )) 

where:
 

NOx ppm = NOx limitation corrected to 3 % Oxygen
 

Boiler Rating = Rating in 106 BTUIHR
 

3. Natural gas or Liquid Petroleum Gas (LPG) shall be used as the primary fuel. 

Number 2 fuel oil or cleaner fuel shall be used as a backup fuel. 

ill.	 APPLICABILITY OF FEDERAL REGULAnONS A.l\ID ITTAH 

AHMINISTRATIVE CODES WAC) 

This review is for a new minor source or minor modification. It is not a new major source 

or a major modification. The following federal regulations and state rules have been 

examined to detennine their applicability to this source category: 

1.	 R307-l-3.l, UAC - Notice of Intent required for a new source, modified 

source, or a new piece of control equipment. This rule applies. 

2.	 R307-l-3.1.7 (A), UAC - A Notice of Intent is not required for natural gas 

fuel burning equipment with a rated capacity of less than 5 x 106 BTU per 

hour. TIris rule does not apply because the boilers are rated at more than 5 

I \fMBTU/HR. 

3.	 R307-l-3.1.8 (A), UAC - Application of best available control technology 

(BACT) required at all emission points. TIris rule applies. 

4.	 R307-l-3.1.8 (C), UAC - Approval of the UAQB is required before the 

Executive Secretary. can approve a source under Section 3.6.5 that consumes 

more than 50 % of a PSD increment. This rule does not apply because a PSD 

pennit is not being issued. 

5.	 R307-1-3.1.8 (0), UAC - Enforceable offset of 1.2:1 required for new sources 

or modifications that would produce an emission increase greater than or equal 

to 50.00 tons per year of any combination of PMIQ, S02, and NO ' This is x 

required in Salt Lake, Davis, and Utah Counties and in any area that affects 

these three counties as defmed in the rule. The effective date is November 15, 

1990. Offsets are not required because the four new boilers are going to 

replace four existing boilers which have actually been emitting pollutants to the 

airshed. The new boilers would have 10w-NOx technology, and therefore, they 

would emit less pollutants than the existing boilers. 

4.2.4-197 
6.	 R307-1-3.1.8 (D), UAC - Enforceable offset of 1:1 required for new sources 

or modifications that would produce an emission increase greater than or equal 

to 25.00 tons per year but less than 50 tons per year of any combination of 

PM10' SO:!, and NO,. This is required in Salt Lake. Davis. and Utah Counties 

and in any area that affects these three counties as defmed in the rule. The 

effective date is November 15, 1990, Offsets are not required because the 

four new boilers are going to replace four existing boilers which have actually 

been emitting pollutants to the airshed. The new boilers would have low-NO, 

technology, and therefore, they would emit less pollutants than the existing 

boilers. 

7.	 R307-1-3.1.9, UAC - Rules for relocation of temporary sources. This source 

is a permanent source, Therefore, this rule does not apply. 

8.	 R307-1-3 .1.12, UAC - Requirement for installation of low-NO, burners on all 

. existing sources whenever existing fuel combustion burners are replaced, 

unless the replacement is not physically practical or cost effective. The 

effective date is November 15, 1990. 

If a Notice ofIntent is received for a replacement, the definition ofLow-NOx 

is: 

limit[ppm] = 82.1 - ( boiler rating[MMBnJ/HR] * 0.421 ) 

where the limit is given in ppm corrected to 3 % O2 and applies to natural gas 

fired external combusn'on equipment rated at or below 100 MMBTU/HR heat 

input. 

,Th1S NOI meets the requirements of this rule. The boilers would emit less 

40 ppm NOr 

9.	 R307-1-3.2. L UAC - Particulate emission limitations for existing sources that 

are located in a nonattainment area. This rule has been superseded by the 

PM\o SIP, except for Weber County. The effective date is November 15, 

1990. This source is not in a non-attainment area for PMIO and PMIO is not a 

pollutant of concern for emissions from natural gas fired boilers. 

10.	 R307-1-3.3.2, UAC - Review requirements for new major sources or major
 

modifications that are located in a nonattainment area or which impact a
 

nonattainment area. This Notice of Intent does not represent a new major
 

source or a major modification. Therefore, this rule will not apply.
 

11.	 R307-1-3.5, UAC - Emission inventory reporting requirements. This rule 

requires any source that emits 25 tons or more per year of any pollutant to 

submit an emission inventory to the Division of Air Quality at least every third 

year or as determined necessary by the Executive Secretary. 

4.2.4-198 
This rule applies to Hill Air Force Base as a pan of their annual emission 

inventory reponing requirements for major sources. The emissions from these 

boilers will be included as a pan of the base-wide emissions inventory. 

12.	 R307-l-3.6.3, UAC - PSD Increment Consumption - This rule lists the 

allowable PSD increment consumption. Under the PSD rules. the entire state 

has been triggered for TSP, SO~, and NO~. The allowable increments are as 

follows: 

TSP 

Three Hour 24 Hour Annual 

Class I Area 10 ~g/mJ 5 ~g/mJ

Class II Area 37 ~g/mJ 19 ~g/mJ

SO~

Class I Area 25 ~gimJ 5 ~glmJ 2 ~gimJ

Class II Area 5U ~g/mJ 91 ~g/mJ 20 ~g/mJ

NOx 

Class I Area 2.5 ~glmJ

Class II Area 25 ~g/mJ

There are also Class III increments, which do not apply in Utah. The above 

increments apply at all locations, unless the area is already nonattainment. 

The entire increment may not be available at all locations due to previously 

permitted sources consuming increment. Modeling analysis is not routinely 

performed for air pollution sources with emissions below the following levels: 

4.2.4-199
 
Criteria for Screen Modeling 

(Tons per Year) 

Nonattainment Areas Attainment Areas 

TSP 10 10 

PM10 5 5 

SO:! 10 20 

NOx 20 20 

CO 25 50 

VOC 10 20 

0 3 5 5 

Generic scenarios were modelled for the largest size (100 M}.1]3TU/HR) using 

worst case assumptions for stack gas temperature, stack dimensions, and 

meteorology. No increment violations were shown to occur as a result of the 

addition of a boiler using Low NOx technology. 

13.	 R307-l-3.6.5 (b), UAC - Prevention of significant deterioration (PSD) review 

requirements for new major sources or major modifications. This Notice of 

Intent does not represent a new major source or a major modification under 

P5D rules. Therefore, this rule does not apply. 

14.	 R307-l-3.6.6, UAC - Increment violations. This rule requires the UAQB to 

promu:gate a plan and implement rules to eliminate any PSD increment 

violations that occur in ·the state. No known violation has yet occurred. A 

typical 100 MMBTU/HR boiler was modelled for increment consumption. 

Any boiler rated at or less than 100 M:MBTU/HR would not consume more 

than the following increment at the points of maximum impact: 

A.	 TSP annual . 0.09 j-Lg/m3 

B.	 TSP 24 hr . 0.37 j-Lg/m3 

C.	 502 3 hr . 0.04 j-Lg/m3 

D.	 502 24 hr . 0.02 j-Lg/m3 

E.	 S02 annual 0.00 j-Lg/m3 

F.	 NOx annual 0.54 j-Lg/m3 

15.	 R307-l-3.8, UAC - Stack height rule. This rule limits the creditable height of 

stacks to that height determined to be good engineering practice. The 

formulas used to determine good engineering practice are found in 40 CFR 

51.100. A deminimus height of 65 meters (213.2 feet) is allowed. 

4.2.4-200 
16.	 R307-l-3.11, UAC - Visibility screening analysis requirements. This rule 

requires all new major sources or major modifications to undergo a visibility 

screening analysis to determine visibility impact on any mandatory Class I 

area. This review does not represent a new major source or a major 

modification under UACR rules. Therefore, this rule does not apply. 

17.	 R307-1-4.1.2, UAC - 20% opacity limitation at all emission points. Unless a 

more stringent limitation is required by New Source Performance Standards 

(NSPS) or BACT or National Emission Standards for Hazardous Air Pollutants 

(NESHAPS). In this case, an opacity limitation of 10% is recommended as . 

BACT. 

18.	 R307-l-4.1.9, UAC - EPA Method 9 shall be used for visible emission 

observations. This rule applies. 

19.	 R307-1-4.2.1. UAC - Sulfur content limitations in oil and coal used for 

combustion. This source will be permined to bum #2 fuel oil or lighter bener 

as a backup fuel. The limitation in the rule is 0.85 pounds of sulfur per 106 

BTU heat input. 

20.	 R307-l-4.6, UAC - Continuous Emission Monitoring Systems Program ­

Reporting and technical requirements for continuous emission monitoring 

systems. It covers breakdowns and quart~rly reports for continuous 

monitoring systems. Section 4.6.5 states that this regulation applies to the .­

following: 

A.	 Sources required to install CEMS as required by the following 

documents: 

1) NSPS 

2) State Implementation Plan 

3) Approval Order 

4) Consent Decree 

5) Administrative Orders and Agreements 

B.	 Any source that constructs after the promulgation of this rule, two or 

more emission points that may interfere with VEO's, shall install an 

opacity monitor on each stack. 

This source is not required to install CEMs. 

21.	 R307-l-4.7, UAC - Unavoidable breakdown reporting requirements. This rule 

applies. Section 4.7.1 discusses reporting requirements. A breakdown for any 

period longer than two hours must be reported to the Executive Secretary 

within three hours' of the beginning of the breakdown, if reasonabie, but in no 

case longer than 18 hours after the beginning of the breakdown. A wrinen 

4.2.4-201 
report is required within seven calendar days. The report shall include the 

estimated quantity of pollutants (total and excess). Section 4.7.2 discusses 

penalties. 

-

22. R307-1-4.9. UAC - Review requirements for volatile organic compound 

(VOC) sources located in a nonattainment area for ozone constructed in 1980 

or earlier. TIlls rule covers specific processes. Boilers are not covered in this 

rule. 

23. R307-1-5, UAC - Emergency episode requirements. TIlls rule requires the 

Executive Secretary to determine the stage and extent of an air pollution 

episode based on pollution levels and meteorological conditions. Under 

section 40 of the Code of Federal Regulations. part 51, subparts 150 and 151, 

it is required that sources plan emergency measures based upon the severity of 

the Non-Attainment area in which they operate. In Utah, these rules require 

that CO sources in CO Non-Attainment areas and sources of Ozone precursors 

in Ozone Non-Attainment ares. who emit 25 tons per year or more, submit an 

Emergency Episode Plan which provides for additional pollution reductions in 

the event of an Air Pollution Alert, Warning or Emergency Episode. These 

plans can include total shut-down of the process. (Some sources are required 

to submit an emergency episode plan in the PMIO SIP). 

HAFB is not located in a CO non-attainment area. For Ozone precursors, a 

basewide plan should be available/submitted. 

24. New Source Performance Standards (NSPS) - 40 CPR 60.40c to 60.48c, 

NSPS, Subpart Dc, Standards of Performance for Small IndustrialCommercial-Institutional Steam Generating Units - The effective date is June 

9, 1989. i\n affected facility is each steam generating unit for which 

construction, modification, or reconstruction commenced after June 9, 1989 

and that has a maximum design heat input capacity of 100 million BTU/hr or 

less, but greater than 10 million BTU/hr. The standards are as follows: 

Sulfur Dioxide 

If coal is the only fuel, no owner/operator shall cause to be discharged into the 

atmosphere any gases which: 

A. Contain SO: in excess of 10% of the potential SO: emission rate (90% 

reduction) 

B. Contain S02 in excess of 1. 20 lb per million BTU heat input 

If oil is the only fuel, no owner/operator shall cause to be discharged into the 

atmosphere any gases which: 

4.2.4-202 
A.	 Contain S02 in excess of 0.50 lb per million BTU heat input 

B.	 As an alternative - No owner/operator shall combust oil that contains 

greater than 0.50% sulfur by weight. Percent reduction requirements 

are not applicable. This requirement applies. 

The S02 emission limits. fuel oil sulfur limits. and percent reduction 

requirements apply at all times. including periods of start-up, shutdown. and 

malfunction. 

There is no limit for natural gas fIred boilers. 

Particulate 

If coal is the only fuel (or coal with other fuels) and the heat input is 30 

million BTU/hr or greater. no owner/operator shall cause to be discharged into 

the atmosphere any gases which: 

A.	 Contain TSP in excess of 0.05 lb per million BTU heat input (coal only 

or coal with other fuels) and has an annual capacity factor for the other 

fuels of 10 % or less 

B.	 Contain TSP in excess of 0.10 Ib per million BTU heat input (coal only 

or coal with other fuels) and has an annual capacity factor for the other 

fuels of greater than 10% and is subject to a federally enforceable 

requirement limiting operation to an annual capacity factor greater than 

10% for fuels other than coal 

If wood is the only fuel (or wood with other fuels except coal) and the heat 

input is 30 million BTU/hr or greater. no owner/operator shall cause to be 

discharged into the atmosphere any gases which: 

A.	 Contain TSP in excess of 0.10 lb per million BTU heat input (wood 

only or wood with other fuels except coal) and has an annual capacity 

factor for wood greater than 30 % 

B.	 Contain TSP in excess of 0.30 Ib per million BTU heat input (wood 

only or wood with other fuels except coal) and· has an annual capacity 

factor for wood of 30 % or less and is subject to a federally enforceable 

requirement limiting operation to an annual capacity factor for wood of 

30% or less 

There	 is no limitation for natural gas fIred equipment. 

Opacity 

4.2.4-203 
No owner/operator that combusts coaL wood, or oil and has a heat input 

capacity of 30 million BTIJ/hr or greater shall cause to be discharged into the 

atmosphere any gases that exhibit 20 % opacity or greater. except for one six 

minute period per hour of not more than 27 % opacity. 

The TSP and opacity standards apply at all times. except during periods of 

start-up, shutdown, and malfunction. 

There is no limitation for natural gas fired equipment. 

Testing (Methods are found in 40 CFR, Part 60, Appendix A ) 

If only coaL only oil. or a mixture of coal and oil is combusted, the 

procedures in Method 19 are used to determine the hourly SO: emission rate. 

For TSP, the following methods shall be used: 

Method 1 shall be used to select the sampling site and the number of sampling 

points. The sampling time for each run shall be at least 120 minutes and the 

minimum sampling volume shall be 60 dscf. 

Method 3 shall be used for gas analysis when applying Method 5, 5B, or 17. 

Method 5, 5B, or 17 shall be used as follows: - A.	 Method 5 may be used only at facilities without wet scrubber systems. 

B.	 Method 17 may be used at facilities with or without wet scrubbers, 

provided the stack gas temperature does not exceed 320°F. 

C.	 Method 5B may be used in conjunction with a wet scrubber system. 

D.	 Method 9 shall be used for determining opacities. 

Monitoring 

The owner/operator of an affected facility subject to the S02 limits in 60.42c
 

shall install and operate a CEM for measuring 502 concentrations and either
 

O2 or CO2 at the outlet of the S02 control device or at the stack outlet. The
 

owner/operator of an affected facility subject to the percent reduction
 

requirements shall install and operate a CEM for measuring SO; concentrations
 

and either O2 or CO2 at both the inlet and outlet of the 502 control device.
 

The owner/operator of an affected facility combusting coal, residual oil, or
 

wood that is subject to the opacity standards shall install and operate a CEM
 

for measuring the opacity.
 

4.2.4-204
 
",,-.. Record keeping requirements 

Natural gas-fIred boilers rated at or less than 100 :MMBTIJ/HR but more than 

10 :MMBTIJ/HR have only one requirement under this NSPS. Subsection 

60.48c contains the reporting and record keeping requirements for affected 

facilities. Paragraph g of this Subsection requires: 

"(g) The owner or operator of each affected facility shall record and 

maintain records of the amount of fuel combusted during each day". 

Under this requirement "each boiler" must have an individual "fuel use meter" 

to determine how much fuel that boiler used each day to be in compliance with 

Paragraph (g). This requirement applies. 

25. National Emission Standards for Hazardous Air Pollutants (NESHAPS) ­

There is no NESHAPS for this industrial process. 

26. National Ambient Air Quality Standards (NAAQS) - TIlis permit can be used 

throughout the state of Utah. Within the state, we have the following nonattainment areas: 

Salt Lake Countv, which is a nonattainrnent area for PMIO, S02, ozone, and 

CO (Salt Lake City only). 

Utah County, which is a nonanainment area for PMIO and CO (Provo City 

only). 

Davis County, which is a nonattainment area for PM10 and ozone. 

Tooele County, which is a nonattainment area for S02 in the eastern mountains 

above 5600 feet. 

Weber County, which is a nonattainment area for CO (Ogden only). 

All other areas are in attainment for all pollutants. 

4.2.4-205
 
This source has been modeled as a 100 M:MBTUIHR source for TSP. PM\o, -
 S02, NOx, ozone, CO. The scenario included 200 hours per year of #2 fuel oil 

combustion. The increases are listed below. Backgrounds are in addition to 

these values. The results are as follows: 

I 

Pollutant Flow 

Rate 

(g/s) 

Averaging 

Time 

Maximum 

Concentrati 

on 

(ug/m3

) 

NAAQS 

(y.g/m3

) 

Percent 

of 

NAAQS 

PM10 0.288 24-HR 0.37 150 0.24 

ANNUAL 0.09 50 0.18 

NO~ 1.701 ANNUAL 0.54 100 0.54 

SO~ 0.0126 3-HR 0.04 1300 0.00 

24-HR 0.02 365 0.00 

ANNUAL 0.00 80 0.01 

CO 1.281 1-HR 4.07 40000 0.01 

8-HR 2.85 10000 0.03 

VOC as 0 3 0.0585 1-HR 0.19 235 0.08 

For VOC emissions, there is no model that can predict an ozone impact 

directly from V0C emissions. However, since VOC are precursors to ozone 

fonnation, this new source will contribute to the existing exceedances of the 

ozone standard in Davis County. The amount of that contribution has not been 

decided. The ozone nonattainment area of Davis and Salt Lake Counties must 

show reasonable funher progress toward attainment of the standard. This 

source, along with all other VOC sources having emissions above ten tons per 

year, may have to apply more controls to lower the VOC emissions. This 

would be a SIP change action. 

27.	 40 CPR 60.14, DefInition of ModifIcation - Any physical or operational 

change to an existing facility that results in an increase in the emission rate to 

the atmosphere of any pollutant to which an NSPS standard applies. The 

following are not by themselves considered modifIcations: 

1)	 Maintenance, repair, and replacement 

2)	 An increase in production rate of an existing facility, if that increase 

can be accomplished without a capital expenditure on that facility - 4.2.4-206 
3)	 An increase in the hours of operation 

4)	 Use of an alternate fuel or raw material if. before the date any standard 

under this pan becomes applicable to that source type, as provided by 

60.1, the existing facility was designed to accommodate that alternative 

use 

5)	 The addition or use of any system or device whose primary function is 

the reduction of air pollutants 

6)	 Relocation or change in ownership 

Also see Section 1.92, which is the State's definition. It is a planned increase 

in emissions. This review might be used for modifications. 

The NOI does not represent a modification. 

28.	 40 CPR 60.15, Definition of Reconstruction - the replacement of components 

of an existing facility to such an extent that: 

1)	 The fixed capital cost of the new components exceeds 50 % of the fixed 

capital cost that would be required to construct a comparable entirely 

new facility and 

2)	 It is technologically and economically feasible to meet the applicable 

standards set forth in this pan 

This review will gen~ral1y not be used for a reconstruction, however, R307-l3.1.12, UAC, requires the installation of Low NOx burners whenever burners 

are replaced. The NOI does not represent a reconstruction. However, the 

boilers will have Low NOx burners installed. 

29,	 R307-1-1, Defmition of Major Modification - It means any physical change in 

or changes in the method of operation of a major source that would result in a 

significant net emission increase of any pollutant. A net emissions increase 

that is' significant for VOC shall be considered significant for ozone. A 

physical change or change in the method of operation shall not include: 

A.	 Routine maintenance, repair, or replacement 

B.	 Use of an alternative fuel or raw material by reason of an order under 

Section 2a and b of the ESECA of 1974 or by reason of a natural gas 

curtailment plan pursuant to the Federal Power Act 

C.	 Use of alternative fuel by reason of an order under Section 125 of 

the CAA 

4.2.4-207
 
D.	 Use of an alternative fuel at a steam generating unit to the extent that -


the fuel is generated from municipal solid waste 

E.	 Use of an alternative fuel or raw material by a source: 

1)	 which the source was capable of accommodating before January 

6, 1975, unless such change would be prohibited under any 

enforceable permit condition 

2)	 which the source is otherwise approved to use 

F.	 An increase in the hours of operation or the production rate unless such 

change would be prohibited under any enforceable permit condition 

G. Any change in ownership at a source 

This rule does not apply. 

4.2.4-208
 
RECOMMENDED APPROVAL ORDER CONDmONS 

General Conditions: 

1.	 This Approval Order (AD) applies to the following company: 

The equipment listed below in this AO shall be operated at the following. 

location: 

LOCATION
 

UTM COORDINATES:
 

Buj.ldiI).gJ590;. 4,553)750 mjN&rthirig;i415~290m.EiStillg

~~~14ingl,'79~:4,55~,87g111.• :No~J.lg;41~~7.P}I1ljli#StP.1g

2.	 DefInitions of tenns, abbreviations, and references used in this AO confonn to 

those used in the Utah Air Conservation Rules (UACR), Utah Administrative 

Codes (UAC), and Series 40 of the Code of Federal Regulations (40 CFR). 

These defInitions take precedence unless specifically defmed otherwise herein. 

3.	 Hill Air Force Base shall install and operate the natural gas fIred boiler 

according to the infonnat.on submitted in the Notice of Intent dated December 

22, 1994. 

4.	 A copy of this Approval Order (AD) shall be posted on site. The AO shall be 

available to the employees who operate the air emission producing equipment. 

These employees shall receive instruction as to their responsibilities in 

operating the equipment according to all of the relevant conditions listed 

below. 

5.	 The approved installations shall consist of the following equipment 

(MMBTU/HR stands for million BTUs per hour): 

A.	 Two boilers (rated at 27.60 M1vffiTUIHR) and associated -equipment in 

BU,ilding ~590;

B.	 Two boilers (rated at 11.25 M:MBTU/HR) and associated equipment in 

Building 1703. 

Hill Air Force Base shall submit to DAQ, the Manufacturer's Name, Boiler's 

Model and Serial Number (or equivalent information that will enable proper 

4.2.4-209 
identification of the boilers), for each of the boilers approved by this -


Condition, before commencing the operation of the boilers. 

6.	 Hill Air Force Base shall pennanently shut down the operation of two boilers 

in Building 1590 and two boilers in Building 1703 before commencing the 

operation of the boilers approved in Condition #5. 

7.	 The Executive Secretary shall be notified in writing upon start-up of the 

installation, as an initial compliance inspection is required. Eighteen months 

from the date of this Approval Order the Executive Secretary shall be notified 

in writing of the status of installation if constnlctioniinstallation is not 

completed. At that time the Executive Secretary shall require documentation 

of the continuous installation of the operation and rnay revoke the Approval 

Order in accordance with R307-1-3.1.5, UAC. 

Limitations and tests procedures 

8.	 Emissions to the atmosphere from the stacks of the boilers approved in 

Condition #5 shall not exceed the following rates and concentrations (The 

lbs/hr and ppmdv values are equivalent and the source has the option of 

demonstrating compliance with values in either of the units): 

I Source: Stacks of Boilers in Building 1590 I - Pollutant lbs/hr ppmdv (3 % O:!, dry) 

NOx 1.33 40 

CO 1.21 60 

I Source: Stacks of Boilers in Building 1703 I 

Pollutant lbs/hr ppmdv (3 % 0c, dry) 

NOx 0.54 40 

CO 0.49 60 

4.2.4-210
 
9.	 Stack testing to show compliance with the emission limitations stated in the 

above condition shall be perfonned as specified below for each of the boilers 

specified in Condition #5: 

A.	 Emission Point Pollutant Testing Test 

Status Frequencv 

Boiler Stack	 NOx * @ 

CO * @ 

B.	 Testing Status (To be applied above) 

* No initial testing is required. However, the Executive Secretary 

may require testing at any time in accordance with R307-1­

3.4.1, UAC. The source shall be tested if directed by the 

Executive Secretary. 

**	 Initial compliance testing is required. The initial test date shall 

be within 180 days after the start up of a new emission source, 

or the granting of the Approval Order for an existing emission 

source. 

@	 Test if directed by the ~ecutive Secretary. Tests may be 

required if the source is suspected to be in violation with other 

conditions of this AO. 

C.	 Notification 

The applicant shall provide a notification of the test date at least 45 days 

before the test. A pretest conference shall be held if directed by the Executive 

Secretary. It shall be held at least JO days before the test between the 

owner/operator, the tester, and the Executive Secretary. The emission point 

shall be designed to confonn to the requirements of 40 CPR. 60, Appendix A, 

Method 1, and Occupational Safety and Health Administration (OSHA) or 

Mine Safety and Health Administration (MSHA) approvable access shall be 

provided to the test location.. 

D. Sample Location
 

40 CFR 60. Appendix A, Method 1
 

E. Volumetric flow rate
 

40 CFR 60,-Appendix A, Method 2
 

F.	 Nitrogen oxides (NO.1 

4.2.4-21 I 
40 CPR 60, Appendix A, Method 7, 7A, 7B. 7C, 7D or 7E or an alternative -


method	 to be approved by the Executive Secretary. The test protocol shall be 

submitted for review at the time of notification of the test. 

G.	 Carbon monoxide (CO) 

40 CFR 60, Appendix A, Method 10 

H.	 Calculations 

To determine mass emission rates (lbs/hr, etc.), the pollutant concentration as 

determined by the appropriate methods above shall be multiplied by the 

volumetric flow rate and any necessary conversion factors determined by the 

Executive Secretary to give the results in the specified units of the emission 

limitation. 

1.	 Source Operation 

The heat (gas) input rate during all compliance testing shall be no less than 

90 % of the rates listed in MMBTU/HR in Condition #5 of this AG. 

10.	 Visible emissions from any point or fugitive emission source associated with 

the installation or control facilities shall not exceed 10% opacity. Opacity 

observations of emissions from stationary sources shall be conducted in 

accordance with 40 CFR 60, Appendix A, Method 9. Visible emissions from 

mobile sources and intennittent sources shall use procedures similar to Method 

9, but the requirement for observations to be made at l5-second intervals over 

a six-minute period shall not app~y. Any time interval with no visible 

emissions shall not be included. 

11.	 The following consumption limits shall not be exceeded without prior approval 

in accordance with R307-1-3.1, UAC: 

For each boiler in building 1590 (rated at 27.6 MMBTU/hr): 

A.	 242,000 decathenns (242 million cubic feet) of natural gas per 12­

month period (1 decathenn = 1,000,000 BTU) 

B.	 141,000 gallons of fuel oil to be burned per l2-month period 

C.	 720 hours of operation burning fuel oil per l2-month period 

For each boiler in building 1703 (rated at 11.25 MMBTU/hr): 

A.	 98,550 decatherms (99 million cubic feet) of natural gas per 12-month 

period 

B. 57,500 gallons of fuel oil to be burned per 12-month period 

C.	 720 hours of operation burning fuel oil per l2-month period 

4.2.4-21
 
Compliance with the annual limitations shall be detennined on a rolling 12­

month total. Before the flfteenth day of each month, a new 12-month total 

shall be calculated using data from the previous 12 calender months. Records 

of oil consumption shall be kept for all periods when the plant is in operation. 

Records of oil consumption shall be made available to the Executive Secretary 

or his	 representative upon request and shall include a period of two years 

ending with the date of the request. Consumption shall be determined by 

operating logs or vendor receipts. The records shall be kept on a dailv basis. 

Hours of operation shall be detennined by supervisor monitoring and 

maintaining of an operations log. 

12.	 The owner/operator shall use only natural gas or liquid petroleum gas as a 

primary fuel and #2 fuel oil or light grade as a backup fuel in the boiler. If 

any other fuel is to be used, an Approval Order shall be required in 

accordance with R307-1-3. L UAC. Number two (#2) fuel oil may be used 

only when natural gas supply has been interrupted. 

13.	 The sulfur content of any fuel oil burned shall not exceed 0.5 percent by 

weight. Sulfur content shall be decided by ASTM Method D-4294-89, or 

approved equivalent. The sulfur content shall be tested if directed by the 

Executive Secretary. 

- Federal Limitations and Reguirements 

14.	 In addition to the requirements of this Approval Order, all provisions of 40 

CFR 60, NSPS Subpans A and Dc, 40 CFR 60.40c to 60.48c (Standards of 

Performance for Small Industrial - Commercial - Institutional Steam 

Generating Units) apply to this"installation. 

The owner or operator shall record and maintain records of the amount of fuel 

combusted during each day. Each boiler must have an individual fuel use 

meter which cannot be reset, to determine how much fuel that boiler used each 

day. 

Recor~ &~cellaneous

15.	 All records referenced in this Approval Order or in an applicable NSPS, which 

are required to be kept by the owner/operator, shall be made available to the .	 . * ExecutIve Secretary or his representative upon request. Examples of records 

to be kept at this source shall include the following as applicable: 

A.	 Fuel consumption 

4.2.4-213 
B.	 Test results 

16.	 All installations and facilities authorized by this Approval Order shall be 

adequately and properly maintained. All pollution control vendor 

recommended equipment shall be installed, maintained, and operated. 

Instructions from the vendor or established maintenance practices that 

maximize pollution control shall be used. All necessary equipment control and 

operating devices, such as; pressure gauges, amp meters, volt meters, flow 

rate indicators, temperature gauges, CEMs, etc., shall be installed and 

operated properly and easily accessible to compliance inspectors. 

17.	 The owner/operator shall comply with R307-1-3.5, UAC. This rule addresses 

emission inventory reporting requirements. 

18.	 The owner/ operator shall comply with R307-1-4.7, UAC. This rule addresses 

unavoidable breakdown reporting requirements. The owner/operator shall 

calculate/estimate the excess emissions whenever a breakdown occurs. The 

total of excess emissions shall be reported to the Executive Secretary as 

directed for each calendar year. 

19.	 This source is required to pay an annual emission fee upon stan-up. The fee 

will be based on calculated annual emissions listed at the end of this Approval 

Order. This fee is valid until inventory data for one year are available for the 

source. The owner or operator of this source will be billed upon stan-up for 

all emissions that are considered "chargeable" as of that date. 

Any future modifications to the equipment approved by this order must also be appro" . in 

accordance with R307-1-3.1.1, UAC. 

This Approval Order in no way releases the owner or operator from any liability for 

compliance with all other applicable federal, state, and local regulations including the ~·tah

Air Conservation Rules. 

Annual emissions for this source (four boilers in Condition #5) are currently calculated at the 

following values: 

Pollutant	 tons/vr 

A.	 PMIO • • • • • • • • • • •• 4.48 

B.	 SOz. . . . . . . 15.96 

C.	 NOx 18.98 

D.	 CO.. . . . . .20.05 

E.	 VOC·. . . . . . . . . . .. 1.86
 

-


4.2.4-214
 
These calculations are for the purposes of detennining the applicability of PSD and 

nonattainrnent area major source requirements of the UACR. They are not to be used for 

purposes of detennining compliance. 

In accordance with the requirements of Title V of the 1990 Clean Air Act, the following 

pollutants may be subject to an operating pennit fee. Both the fees rate and the class of 

pollutants are subject to change by State, the Federal agencies. or both. 

Pollutant tons/yr 

F. Particulate. . . . . . . . . . . . . . . . .. 4.48
 

G. S02' , 15.96 

H. NOx . . . . . . . . 18.98
 

1. VOC. . . . . . . . . . . . . . . . . . . .. 1.86
 

" 4.2.4-215
 
""_0. _.,.... ''''_I'li'"-I'lr...... 11~.,~~"1 ,u :i5364e99 P.lal 

} CF~ COYfR SHE~ECEIVED JAN 3 1 1995 /~
 

(Date:31 Jan 95 ) 

(Message:)
 

From: Air Quality
 

Andreas Zekom 

EnTironmental Management Directorate 

Oo-ALCIEME 

1274 Wardleigh Road 

H1Il AFB,UT 84056.5137 

Tel: Cormnercial801.777-o3S9 

DSN 458-0359 

Fax:Commerci:dS01·777-4306 

To: 

Name: Arjun Ram 

Organization: 

Division of Air Quality 

Fax No.: (801) 536-4099 

Hi Arjun 

I 

Here are the calculation for the boilers in BUilding 1590 and BUilding 1703. We have an decrease 

in emissions for the boilers in Building 1703 and almost the same emissions in Building 1590 

so that we have over all a decrease in emissions for this NOr. 

/' 

~~-I" : 

ANDREAS ZEKO I 

Total number of pages including cover sheet: S ! 4.2.4-216
.., ... , ..,...,. .__ • 1 ... _1' _.'..... 1 ..._;'\0._10 •••_ '''''''' ''1 

I
 

I
 

I

,
 

:
 

i


, 

~·IB"!l1~.· I 

I 

I 

Heatinput 27.600.000.00 BTlTlhr 

Operating Hours 8760 hrJyr 

Emission Factors 

I 

AP-42 Table 1.4-1 - 1.4-3iLow NOx Burner 

i 

Natural Gas I 

PM I SOx NOx CO HC

Industrial 13.7 0.6 81.0 61.0 2.8 

I 

I 

Emission faetors in IbsllO"ls cu ft 

! 

I 

Calc:ulatioD 

, 

Coasumption/hr i 27600 SCFIhr 

Consumptionlyr 241,776.000 SCFlyr I 

i 

I 

Emjssigg.4l I 

i 

NahlJ]l em Industrial Boiler 

PM SOx NOx co HC 

Iblyr 3312.3 145.1 19583.9 14748.3 673.1 

tonslyr 166" 0.07 9.79 737 034 

No,; EmbsigDs ! 

Limit 40 ppm Operation 8760 hr 

Conversion ppm-IbIMMB1U 0.048 IblMMBTU 

Caleulaticm Ibt1:ar :1 1.065 Iblbr 

Caleulation IbIyr 9332.7 lblyr 

Calculation tonslyr I 4~6~ .tonsIyr.. 

I 

Iota! emissions from both boilers 

i 

PM I 6624.71blyr I 3.31 tonslyr +-1 ·~4 • 

SOlt I 290.1 Ib/yr 0.15 tonslyr 

NOx 118665.5 lWYT 9.33 toDsIyr - ·l7 

CO i 29496.7 Ib1yr 14.75 toIWyr -+- 5'.5 6 

He I 1346.2 Iblyr 0.67 toosIyr 

-t J- 53+- <:;-::>? '-:"-V'N ; : •Nj" : -<. .~~L.:

i . . . ., I ~. 2 J .•,:; '.J .•I V..L ,"') '1" '-./~;..-L.A. .... J,' '

I
 

i
 

4.2.4-2 I 7
 
,_" _ ........ -_...._. " •._ ... "" '__' ._. '\ I
 

-


Heatinpu[ 

Operating Hours 

I 

16,45<4000.00 BnJlhr 

I 8760 hrJyr 

Emission Facton 

AP42 Table 1.4-1 - 1.4-3 Low NOx Burner 

Namral Gas 

Industrial 

p¥ 

13.7 

SOx 

0.6 

NOx 

.140.0 

CO 

61.0 

He 

2.8 

Emission factors in Ibs/l0"6 cu ft 

CalmJptioo 

Consumptionlbr 

Consumptionlyr 

, 16450 SCFIhr , 

144,102.000 SCF/yr 

Natunl em Industrial BgUer 

p~ SOX NOx CO He 

( .·lblyr 1974.2 86.S 20J74.3 8790.2 401.2 

toD5Jyr O.~ 0.04 1.0.09 4.40 0.20 I 

NO; Emjuions 

Limit 40 ppm Operation 8760 br 

Conversion ppm-IblMMBnJ 0.0481bIMMBTIJ 

Cal~on JbIbr 0.635 Iblbr 

CalcaJation IbIyr 5562.4 Ibtyr 

Calculation toasIyr J 2.78 tonslyr 

" 

Total emiMjon, from both bgUm 

3948.4 Ib1yr 1.97 torJSIyr
 

SOx
 

PM 

172.91b/yr 0.09 tODSI)T
 

NOx
 11124.9 Ib1yr $.56 toDSlyr 

CO ; 17S80.4 Ib1yr 8.79~

He 802.4IbIyr 0.40~

4.2.4-218 
oJ"" -'-''''; (.,I~...... , I"'~ I ~,'W" .1 ......... ", ~'l n ..... I I""n~ ~I'" I 'u
 

Hearinpul 11.250l5OO.oo BnJlbr 

Openbng Hours I

I 8760 hr/yr 

I . 

I
 

I
 

I
 

I 

EmissioaFacton 

AP-42 Table 1.4-1 - 1.4-3 Low NOx Burner I 

I 

NAtUral Gas I 

PM SOx NOx CO He 

Industrial. d.7 0.6 81.0 61.0 2.8 

I 

Emission factors in Ibs/l0"-6 en ft 

I 

CalculatioD 

Consumptiontbr i11250.5 SCFJhr 

Consumptionlyr 98,.554,380 SCF/yr 

I ' 

r 

Emissions I 

Namral Gas Industrial BOilL 

PM I SOX NOx co HC

Iblyr 13'0.2 59.1 7982.9 , 6011.8 274.4 I 

lOnslyr O'r 0.03 3.99 3.01 0.14 

NOX [mls:siODs I 

1 

I Limit 40 ppm 8760 hr I 

r
 

r
 

Conversion ppm-lblMMBTU 0.048 IbIMM:BTU 

Calculation JbIbr I 0.4341blhr 

Ca1culation lbIyr I 3804.3 Iblyr 

Calculation tonslyr f 1.90 tons/yr

I 

Total emig;ions fmm both 

PM 2700.4 Ib/yr 1.3S tonslyr 

SOx 118.3 Iblyr 0.06 IOnslyr 

NOx 7608.5 Iblyr 3.80 tonsI)T 

CO 12023.6 Iblyr 6.01 tenWyr 

He 548.81blyr 0.27 lODSIyr 

4.2.4-219
 
----"""""""-­

, 

, 

:B,M~ IBmmI¢mg J1'~l(o)llil;~ , 

Heatinput 

Operating Hours 

Emission Factors 

10.251.000 BnJlbr 

! 8760 br/yr 

I

, 

AP-42 Table 1.4-1 - 1.4-3 Low NOx Burner 

Natural Gas I 

SOx NOx CO He 

Industrial 13L1 

I 

I 

Emission factors in Ibsll0"6 cu ft 

0.6 .~40.0 (@:"~./-' 

2.8 

I 

i 

Consumption/br 

Consumptionlyr 

I 

I 

,

I 10257 SCFJhr 

89,851.320 SCPIyr 

,

, 

I 

E.mjWgns i 

I 

I 

Hamra! GM Indu!tttia! BoHCt 

-

lblyr 

tDDSIyr 

mn Emissions 

P¥ 

l~l.O

0.62 I 

I 

I 

SOX 

53.9 

0.03 

NOx 

12579.2 

;6.29 

CO 

5430.9 

r - , .. 

HC 

250.1 

0.13 

Limit I 40 ppm

I 

i 

Conversion ppm-lblMMB'TIJ 

Calculation lbIhr , 

i c.Iculalion Ib1yr I 

! Calculation tonsIyr I 

I 

I 

I 

Igr.aI emissions frnm bptb bpilers 

! 

. Operation 

0.0481blMMBnJ 

0.3961blhr 

3468.3 Iblyr 

1.73 tcnYyr 

8760 hr 

PM 

SOX 

NOx 

CO 

He 

2-161.9 Ib1yr 

107.81b/yr 

6936.7 lbIyr 

! 10961.9 Iblyr 

SOO.3 Ibiyr 

1.23 tonslyr 

O.OS tons!yr 

3.47 toDSiyr 

5.48 tonslyr 

0.25 toDsIyr 

4.2.4-220
 
RECEIVED 

DEPARTMENT OF THE AIR FORCE DEC 2 7 1994 HEADQUARTERS OGDEN AIR LOGISTICS CENTER (AFMC)
 

HILL AIR FORCE BASE. UTAH
 Air Quality 

22 Dec 1994 

QO-ALCIEM 

7274 Wardleigh Road
 

Hill AFB UT 84056-5137
 

Mr. Russell A. Robens
 

State of Utah
 

Division of Air Quality
 

P.O. Box 144820
 

Salt Lake City Ut 84114-4820
 

Re: Notice of Intent to construct two replacement boilers in Building 1590 and two 

replacement boilers in Building1703 

Dear Mr. Robens 

We submit this Notice of Intent to receive approval to begin construction of two 

replacement boilers in Building 1590 and two replacement boilers in Building 1703. 

- Description 

Building 1590 

Two of the four existing boilers in Building 1590 with AQillS numbers 3524 and 3525 are 

to be replaced by two Low NOx Watenube Steam Boilers with a maximum steam capacity 

of 23,000 lbs/hr each. This convens to 27.6 MMBTU boiler heat input. 

Conversion Ib steamlhr to BTU/hr
 

23000 lb/hr x 1.2 x 103 = 27,600,000 BTU/hr •
 

• conversion factor according to AP 42 Appendix A 

Both boilers run primarily with natural gas with #2 fuel oil as a backup fuel. Each boiler is 

connected to a stack as shown in Atch. 1. 

Building 1703 

Two existing boilers in Building 1703 are to be replaced with two Low NOx Wetback Fire 

Tube Boilers with a steam capacity of 8625 Ibs/hr or a capacity of 250 hp. • 

Conversion hp to BTU/hr
 

250 hp x 45000 BTUI hp hr = 11,250,500 BTU/hr·
 

• conversion factor according to AP 42 Appendix A 

Both boilers run primarily with natural gas with #2 fuel oil as a backup fuel. Each boiler is 

connected to a stack as shown in Atch. 2. 

4.2.4-221 
Emissions 

AP 42 Emission factors for natural gas combustion (Table 1.4-1 to 1.4-3) 

(TTN Bulletinboard AP 42) 

Emission factors (Low NOx Burner) - __ .:~
 

Filterable PM 6.2 1b/106 fe -


Condensible PM 7.5 Ib/l06 fe "
 

Sulfur dioxide 0.6 1b/l06 ft 3
 

Nitrogen oxides 811b/106 ft3 ,
 

Carbon monoxide 61 Ib/ 106 ft3 
 

Total Organic Compounds 5.8 Ib/106 ft3 /'
 

Total Particulate is the sum of the filterable PM and condensible PM. All PM emissions can 

be assumed to be less than 10 microns. Methane comprises 52 percent of organic 

compounds. The Non Methane VOC emission factor is: 2.784 

Emissions for the boilers are calculated as follows: 

Heat input	 IDIV thennal operating emission emissions 

natural gas effiency hours factors 

BTU/hr x	 111000 SCFIBTU x 0.80 x 8760 hrs/yr x Ib/SCF = lb/yr 

Air emissions from two replacement boilers in Building 1590 are each: 

Particulate 3312.31b/yr v
 

Sulfur dioxide 145.1 Ib/yr ­


Carbon monoxide 14748.3 lb/yr ­


VOC Nonmethane 673.1 Ib/yr ­ - As a Low NOx Burner is to be installed. the emission limit is 40 ppm NOx (corrected to 

3% Oxygen). The calculations for NOx are as follows: 

• Conversion ppm to 1bIMMBTU 

40 ppm / 829 = 0.048 IblMMBTU I 

Calculation of hourlv emissions:	 - ­

0.048 IblMMBTU 

*27.6 MMBTUIhr * 0.80 3) = 1.065 Ib/hr
 

3'rhennal effiency is 80 %
 

Potential to emit for NOx is: /L..' ,r_' 

1.0651blhr * 8760 hr/yr =9332.7 Ib/yr " --<	 "c 

- = 4.67 tons/yr .' t • , J 

Total emissions from both boilers in Building 1590 are: 

Particulate 6624.71b/yr - 3.31 tons/yr ,"
 

Sulfur dioxide 290.1lb/yr 0.15 tons/yr
 

Carbon monoxide 29496.71b/yr- 14.75 tons/yr'
 

VOC Nonmethane 1346.2 1b/yr ' 0.67 tons/yr--


NOx 18665.4 Ib/yr 9-:33_tons/yr
 ,:..;' :.,-:t . ~"";,...,;)J"

With installatiOD...of two Low NOx burners in Building 1590 we will reduce NOx 

emissions by 53%. 

Building 1703 

Emission factors and calculation methods are the same as for Building 1590. 

42.4-222 
0.048 lblMMBTU * 11.3 MMBTU/hr * 0.80 =0.434 lb/hr 

Both boilers in Building 1703 will run 8760 hr/yr. 

0.434lb/hr * 8760 hr/yr	 =3801.1 lb/yr
 

= 1.90 tons/yr
 

Total emissions from both boilers in Building 1703 are: 

Particulate 2700.4 lb/yr./ 1.35 tons/yr /
 

Sulfur dioxide 118.3 lb/vr " 0.06 tons/yr
 

Carbon monoxide 12023.6 ib/yr / 6.01 tons/yr.·
 

VOC Nonmethane 548.8 lb/yr­ 0.27 tons/yr /
 

NOx 16O&5lb/yr 3~tons/yr
 .:0-,.1. -r -:..I ~_ -' I _

With installation of two Low NOx burners in Building 1703 we will reduce NOx 

emissions by 70%. 

Air cleaning devices
 

No additional air cleaning devices will be installed.
 

Location 

UTM coordinates are not available for Building 1590 and 1703.
 

Longitude and latitude for the Buildings are:
 

Building 1590 Building 1703
 

Longitude 112:00:32.38 112:01:19.66
 

Latitude 41:07:55.70 41:08:31.87


.'-/ . .... ..:,~:.:.~/ ..~5'fJ ~IS-,Z.:.!:.: 4$':" .. :. l..') . N .1 ).'~ . ­ ,.",,-,. 

Operating Schedule 

Both boilers in Building 1703 will run 8760 hours per year. The two boilers in Building 

1590 will be shut down in summer. 

Construction Schedule 

The construction is scheduled for all boilers as follows: 

Start construction: February 1995
 

End construction: October 1995
 

Start up boiler: . October 1995
 

If you have any questions, please call Mr. Andreas Zekorn at 777-0359. 

Sincerely 

,14j)~

~:B;iT JAMES 

Acting Director ofEnvironmental Management 

Attachments: 

1. Plan of boiler in Bldg 1590 

2. Plan of boilers in Bldg 1703 

4.2.4-223 
w , I' L~ .;>

. \ FEED PIPING . o o 0 I { I I r-(El CHEMICAL ( Illc~ 2 

,(E I BOILER FEED PUMPS IN BASEMENT---1 

FEEDER I. 

r=t==t=f HIX TANK I POT 1°

O.C. TO IE 1--.......... I 1f or T "IT II V
 , FOS & ............ - r"
 I IrfG ' .. " FOR -u" u ..........;)..... I NEil CONDENSATE SURGE TANK VI RECONNEC
 '\ l'oo.. G " _., " \ 12"¢ x 11'-0" I (1000 GAV' J lA' TANK LEV 

~~ Ul SAFETY --oF ~BOILERFEErfVALVING I I:> r,,1--r1 .- I ~,-' .-,:>\ (EJPIPI 

II 1/1 VALVE Ii). I TYP RnTH BQl.LERS I - Ig 'I I P-2" -. : 1 1 ) II TVP -...... (~~ )...-, 1 1 1 1 _1_ _ _ f- _~ L - L - CONNECT TO 

Ul '\ 11 17\ I ~f ITE I -.., I CONDENSATE 

"0 250H,P.150PSI\..!.; CLASS 

3/1-- __ STEAM BOILER ~~ I CONNECT NE 

6" CONNECTION............ 1" ~~ (8625 LB/HR J 17 lo- TUBE REHOVAL LINE TO, (e: 

(E J 6" STEAM I'--- I l - __ ,., f- - -- - -- - (~ - f-f- - I- REA I lP-1.1/2" .--- LINE UN 

N ""l 'r!-./ IL ,- .... TANK (Pl.",.' P '-r'L.J ,) VTR DEAERATOR 

I I .... t I,..... IL ," 1 I 

13 "t-' r '1" /~ 1 3 ~E>V1R NEW DEAERA U- ,1./ /.;' _ I-- _ DRAINER. P 

1 = --FO~ f"OR- _OS_ I OE"AE~ bF1E> J IN BASEMEN 

3" ~/1" VTR, I BRINE '" 

:8 PLANT 1 :::c=J ~E

A I It- i-<: 0) G_ THill ( E) HOTOR

- 17---.: -l.... I " I' . '-.....-./'GE) CONTROL CE

'l.ll' I IL ~F CFr r AIR COMPRESSOR t~ ~ \I '\ I

l 

E-ALK. 

I-- -, I t l

, ,(TYP. BOTH BOIL Sl\" ~3/1" \ I I ~-~)-,I n I 1 \ -t------­

20" STA~K ~~~ CONNECT 3/"" . (E) EXISTING Ii / I ~II 

TYP. (2 I t- 1_ CHEMICAL FEED LINE HE)

~- TO BOILER FEEDIIATER ~1 f\ I 

6" CONNECTION ~I ---..~ CONNECTION (BOTH BOILERS I l~ TUBE REMOVAL I 1 

(E) 6" STEAM l~ ., - ---0-0-- - - - -- - (...- - -~ - I- REA I I N "" Yj:J 17\ 250 H. P. 150 PSI 17 r-.:@E) 

,a: I .... tlJ , \..!.; STEAM BOILER I 1 I OFT.

..,,... (8625 LB/HR I +- I' 

/1" 

I l _ ~OS D as - - - - - I @ '<:t ,L: __ - - -TO~ - - - ~' 0 IE> , N I J/""/ 3" OFT. N 

P.O. C. TO (E I - G 0 G- '<:t 

I 

3" GAS LINE T "', ,-< NATURAL GAS = '~6' ~OCATEO J.) I N 

GA FUEL TRAIN (TY . OIL PUMP A~D I '<:t 

S FLOW METER I" BOTH BOILERS J . ...... HEATERS. I YP. @ I 

BOTH BOlLE S l. B~~~E 1 • 1'-( E I FLOOR DRAINI \ TANK I mu: C) \ • 1 ( TVP. -2 I Ic---- 'II { II ,II I 
-/7'" '1(/ I 

: 

CSl 

I 

. 

!Xl 

"'" PIPE MANlfO:"O 

l"TO 

3/"'" FROM \,lATER 

LEVEL SENSOR FOR 

FEEOVATER 

REGULATOR 

~-------AUXILIARY LOV 

\,lATER CUTOFF
 

...--------\,IATER LEVEL
 

GAUGE GLASS 

I:
\,IATER COLUMN
 

\,lITH PROBES 

FORCED DRAFT 

fAN------, 

STEAM DRUM 

STEAM PRESSURE _ - _ _ _ _ _ _ _
 

GAUGE
 I 

(0-300 I 

PSIG) 

• \ 

I
 

L
 

t> t>. ~t> . . \;> .. t> . II' .. II' to \;>.• t>.. . \>' 

'7' II' .t> 

4.2.4-225 

BOILER ELEVATION