HomeMy WebLinkAbout20182056.tiffCOLORADO
Department of Public
Health El Environment
Dedicated to protecting and improving the health and environment of the people of Colorado
Weld County - Clerk to the Board
1150 0 St
PO Box 758
Greeley, CO 80632
June 27, 2018
Dear Sir or Madam:
RECEIVED
JUL 022018
WCOMMISSIONERS
On June 28, 2018, the Air Pollution Control Division will begin a 30 -day public notice period for Kerr
McGee Gathering LLC - Ft. Lupton/Platte Valley/Lancaster Complex. A copy of this public notice and
the public comment packet are enclosed.
Thank you for assisting the Division by posting a copy of this public comment packet in your office.
Public copies of these documents are required by Colorado Air Quality Control Commission
regulations. The packet must be available for public inspection for a period of thirty (30) days from
the beginning of the public notice period. Please send any comment regarding this public notice to
the address below.
Colorado Dept. of Public Health Et Environment
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, Colorado 80246-1530
Attention: Clara Gonzales
Regards,
Clara Gonzales
Public Notice Coordinator
Stationary Sources Program
Air Pollution Control Division
Enclosure
4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe
John W. Hickenlooper, Governor
?tom' O�p
07
Larry Wolk, MD, MSPH, Executive Director and Chief Medical Officer
cc; PLC Mwt.IT3), F+C-CST,
PWnrCeR/C14/JMJC.i4)
O7 -O3-18
2018-2056
Air Pollution Control Division
Notice of a Proposed Project or Activity Warranting Public
Comment
Website Title: Kerr McGee Gathering LLC - Ft. Lupton/Platte Valley/Lancaster Complex - Weld County
Notice Period Begins: June 28, 2018
Notice is hereby given that an application for a proposed project or activity has been submitted to the
Colorado Air Pollution Control Division for the following source of air pollution:
Applicant: Kerr McGee Gathering LLC
Facility: Ft. Lupton/Platte Valley/Lancaster Complex
Natural gas processing plant
16116 WCR 22, Ft. Lupton, CO
Weld County
The proposed project or activity is as follows: The applicant proposes to construct two new cryogenic gas
processing trains with a total capacity of 153 MMscfd.
The Division has determined that this permitting action is subject to public comment per Colorado
Regulation No. 3, Part B, Section III.C due to the following reason(s):
• permitted emissions exceed public notice threshold values in Regulation No. 3, Part B, Section
III.C.1.a (25 tpy in a non -attainment area and/or 50 tpy in an attainment area)
• the source is requesting a federally enforceable limit on the potential to emit in order to avoid other
requirements
The Division has made a preliminary determination of approval of the application.
A copy of the application, the Division's analysis, and a draft of Construction Permit 17WE1059 have been
filed with the Weld County Clerk's office. A copy of the draft permit and the Division's analysis are
available on the Division's website at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices
The Division hereby solicits submission of public comment from any interested person concerning the ability
of the proposed project or activity to comply with the applicable standards and regulations of the
Commission. The Division will receive and consider written public comments for thirty calendar days after
the date of this Notice. Any such comment must be submitted in writing to the following addressee:
Carissa Money
Colorado Department of Public Health and Environment
4300 Cherry Creek Drive South, APCD-SS-B1
Denver, Colorado 80246-1530
cdphe.commentsapcd@state.co.us
ADO
Colorado Air Permitting Project
PRELIMINARY ANALYSIS - PROJECT SUMMARY
Project Details
Review Engineer:
Package 9:
Received Date:
Review Start Date:
Carissa Money
367979
8/17/2017
1/3/2018
Section 01- Facility Information
Company Name: Kerr McGee Gathering LLC's.
County AIRS ID: 123
Plant AIRS ID: 0057
Facility Name: Lancaster Plant 3
Physical Address/Locatio 16116 WCR 22, Ft. Lupton, Co
Type of Facility: Natural Gas Processing Plant
What industry segment? oil & Natural Gas Production &-
Processing
Is this facility located in a NAAQS non attainment area? Yes
If yes, for what pollutant? Don Monoxide (CO)
Weld
Section 02 - Emissions Units In Permit Application
culate Matter (PM)
Quadrant
Section
Township
Range
[3ne (NOx & VOC)
AIRS Point #
Emissions Source Type
Equipment Name
Emissions
Control?
Permit #
Issuance #
Self Cert
Required?
Action
Engineering
Remarks
075
Boiler or Process Heater
Amine Regeneration
Heater
Yes
17WE1059
1
Yes
Permit Initial
Issuance
076
tioileror Process Heater
H-31711 Molecular -.
Sieve Regeneration
Heater
No
17W E1059
1
Yes
Permit Initial
Issuance
077
Roller or Process Heater -
Molecular Sieve
Regeneration Heater
-
Yes
17W E1059
1
-;
Yes -:
Permit Initial
Issuance
078
Amine Sweetening unit
Amine 3A
Yes
17WE1059
1
Yes
--
Permit Initial
Issuance
079
Process Flare -
Process Flare
Yes -
17WE1059
1
Yes
Inihai
Issuance
080
Fugitive Component Leaks
ancaster Plant 3 Fugitiv
Yes -
17WE1059
1
Yes
-
Permit In al
Issuance
Section 03 - Description of Project
Kerr McGee Gathering (KMG) is proposing to build a new cryogenic gas processing plant at the existing Ft. Lupton/ Platte Valley/Lancaster gas plant. The new train,
referred to as Lancaster Plant 3, will consist of two functionally -identical processing trains each comprised of a hydrogen sulfide treating bed, amine contactor,
molecular sieve natural gas dehydrator, molecular sieve regeneration heater, cryogenic processing equipment, process flare, emergency diesel generator and fugitive
components, This plant will be different from LancasterTrain 1 and 2 because there will be one amine regeneration system shared by both trains in Plant 3. Thus, the
amine unit (AIRS ID 078) will consist of two amine contactor towers, one amine regenerator, one flash tank and one natural gas fired amine heater, The amine
regenerator still vent will be routed to a thermal oxidizer.
In the application, KMG stated the buildout of Plant 3 was not anticipated at the time of building LancasterTrain l and 2. KMG' explained several expansions will have
to occur at the plant to accommodate the new Plant 3 including expansion of the power substation, expansion of the metering facilities and expansion of the residue
capacity out of the Ft. Lupton Complex. The points associatef with LancasterTrain I and 2 started up around April 2014 and in June 2015. The amine unit referred to as
A-,4 (AIRS ID 066) still has not commenced operation and when I asked KMG about this unit, KMG stated there are currently no plans to start the unit. The anticipated
start date for Plant 3 is December 2019. Given the timing of the projects and the additional expansion projects required to accommodate Plant 3, Lancaster Plant 3 will
be considered a separateprojectfor PSD/NANSR review.
For Lancaster Plant 3, the total project emissions including insignificant activities (5 MIVIBtu/hr condensate stabilizer, 6 MMbtu/hr H2S pretreater heater, emergency
diesel generator) are below PSD significance thresholds for all criteria pollutants. Total project NOx emissions are 38.5 tpy which is below the 40 tpy significance
threshold. Total project PM2.5 emissions are 4.8 tpy which is below the significance threshold of 10 tpy and below the modeling threshold of`5 tpy. See summary
tables for additional details.
In the application, KMG included an inlet H25 pretreater heater for LancasterTrain 1&2 (AIRS ID 074, 17WE0826.XP) with this Lancaster Plant 3 project for PSD/NANSR
review. The heater was installed October 2017 while all the other equipment associated with Plant 3 is proposed to be installed December 2019. The 10 MMbtu/hr
inlet H25 preheater for Lancaster Train 1&2 should have been included in the PSD/NANSR review and project total for the buildout of that plant. Further, KMG had
problems with PM2.5 and the H2S treatment system at the outlet of the amine regenerator still vent since the initial startup of Lancaster Train l and land KMG
proposed at that time to change the absorbent material. In the last modification of Lancaster Train I and 2, Permit 12W81492 Issuance 3 (issued August 11, 2017),
KMG also requested the operational flexibility to install an inlet H25 pretreatment system instead of the Puraspec system. Thus, the 10 MMBtu/hr should be evaluated
with the Lancaster Train 1 and 2 project. emissions, When I re-evaluated the project netting analysis for 12WE1492 Issuance 3 and include the 10 M MBtu/hr heater, the
Colorado Air Permitting Project
net''a
not exceed the sigmtican ce thresholds (see tab'
Section 04 - Public Comment Requirements
Is Public Comment Required?
If yes, why? f equesnngSyothet (vG .
details),
And greater than 25 tpy in NAA
Section 05 - Ambient Air Impact Analysis Requirement:
Was a quantitative modeling analysis required? Alta ,
If yes, for what pollutants?
If yes, attach a copy of Technical Services Unit modeling results summary.
Section 06 - Facility -Wide Stationary Source Classification
Is this stationary source a true minor?
Is this stationary source a synthetic minor?
If yes, indicate programs and which pollutants:
Prevention of Significant Deterioration (P5D)
Title V Operating Permits (OP)
Non -Attainment New Source Review (NANSR)
Is this stationary source a major source?
If yes, explain what programs and which pollutants here SO2
Prevention of Significant Deterioration (P5D)
Title V Operating Permits (OP)
Non -Attainment New Source Review (NANSR)
S02 NOx CO VOC PM2.5 PM10 TSP HAPs
❑❑
Emissions Inventory
Section 01- Administrative Information
'Facility AIRs ID:
123 -:0057 075
County Plant
Section 02 - Equipment Description Details.
Detailed Emissions Unit
Description:
Emission Control Device
Description:
Requested Overall VOC & HAP Control
Efficiency %:
One amine heat medium heater (manufacturer;: mode.! and serial number to be determined) equipped with ultra low
NOx burners used to regenetate amide for Point 078. The heater is design rated for an input capacity of 55
a late/hr: Tills heater is fueled by natural gam
Section 03- Processing Rate Information for Emissions Estimates
Heater Design Rate
Heat content of waste gas=
Hours of Operation
Fuel Consumption
554 MMBtu/hr
102O8tu/scf
76O hr/yr
MMscf/yr
Section 04- Emissions Factors & Methodologies
19..38
0.0021
0.0034
Formaldehyde
0.075
PM10
7 f
PM2.5
7.9
SO2
0.9
40.1 MMscf/31 days
Section 05 - Emissions Inventory
Criteria Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
VOC
PM10
PM2.5
SO2
NOx
CO
4.6
1.8
1.8
0.1
9.6
9.6
4.6
1.8
1.8
0.1
9.6
9.6
lb/31 day
777
305
305
24
1637
1637
Hazardous Air Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
{tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(Ibs/year) llbs/yearl
Benzene
Toluene
Ethylbenzene
Xylene
n -Hexane
Formaldehyde
0.0006
0.0006
0.0006
0.0000
0.4253
0.0174
0.0005
0.0008
0.0000
0.0000
0.4251
0.0177
2
0
0
2
850 •
35
850
35
Section 06 - Regulatory Summary Analysis
Regulation 3, Parts A, 8
Requires APEN and Permit
Regulation 6, Part A, NIPS Subpart Dc
Subject
Regulation 6, Part B, Section II.C.2
Subject
Regulation 8, Part E, MACF Subpart DDDDD
Subject
3 of 23
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Emissions Inventory
Section 07- Initial and Periodic Sampling and Testing Reanirements
This heater will be required to have an initial stack test to confirm NOx and CO emissions.
Section 00 - Technical Analysis Notes
This s a new heaterfor a new train The soerce assumed a maximum neat nput capacity of 55 MAR6tu/hr;and operating at 8,760 hr/yr Tne source stated NOz, GO anc'vOC ern sc on are bases on
manufacturer estimates but did not provide support ng documentation. Wien l asked thee. source about these emission factors, the source statedthe emissienfactc rs are based on specifications
guaranteed for the Exterrn heaters used with Lancaster train 1 and 2. The source also stated that whilethey ha•.e not yet bid on the project
and thus do not knevwthe manufactu,er, .3e r.ids .or the
heaters will specifythese emission factors which w311 then haveto he guaranteed by the heater manufacturer.
confirmed these factorse,
ate identical Yo the emission factors used for the mole s eve regee. heaters for Lancaster Tram 1 and 2 (AIRS ID 057 and 581 Since the em ssion factors have been ppreviously
rsed focsim lar heaters at this site and thoss heaters sin e stack tested to demonstrate compliance t s acceptable touse the same emission faco' m 31Also, the heater vs+ill be nwc: tested to
ai a
confirm j'Oc and CO emissions. The . source is usmgAP 42, Chapter 1.3 em scion factors`he the other pollutants and hear content of 1,029 6cu(sef.
The source requested to use AP -42 emission factors to estimate uncontrolled':itOX and then calculate control eifiuency, based no tt, o d fie: kagee th fie manufac
conf iteer.nate to cr ease a control -42eflcy using AP -42 and manufacturer emission ',estimates.. The NCz emir on fe-Tar s ill be l s�e0 uncv: o:Ied
For the other amine regen heater (AIRS ID 061 and 0621, KNIG used a PM miss on factnriroet stack testing' has s roAr lover char AP r+2 (— 6Ibfi - hnsc`)=_nd use
(5.5 lb/MMsd(. Usingthe AP 42 Factor nor Phi and
.the manufactureremissioe factor`or VOC i more copserevvc, because
Lie actors ere Ivghar.:.'.
Section 09 - Inventor/ SCC Coding and Emissions Factors
AIRS Point # Process # SCC Code
01
075
nossi.ort factor. It is not
c VOCemission
Uncontrolled
Emissions
Pollutant Factor Control % Units
PM10 7.60 0 Ib/MMsd
PM2.5 7.60 0 Ib/MMsd
5O2 0.60 0 Ib/MMsd
NO.
40.80 0 lb/MMsd
VOC 19.4 0 Ib/MMsd
CO 40.80 0 Ib/MMsd
Benzene 0.0021 0 Ib/MMsd
Toluene 0.0034 0 Ib/MMsd
Ethylbenzene 0.0000 0 Ib/MMsd
Xyiene 0.0000 0 Ib/MMsd
„Hexane
0 Ib/MMsd
Formaldehyde 0,0750 0 Ib/MMsd
4 of 23
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Emissions Inventory
Section 01- Administrative Information
Facility AIRS ID:
0057 076
Plant Point
Section 02 - Equipment Description Details
Detailed Emissions Unit
Description:
Emission Control Device
Description:
Requested Overall VOC & HAP Control
Efficiency %:
One molecular sieve regeneration ges�, hea#er Cmanufacturer, model and seriot number tube determined) equipped
with ultra low SOur burners. The heater isdesigo-rated far an input tapatity of 18.0'MMBtitlhr This: heater is fdeled':
by natural gas.
Ultra law COX burners
Section 03 - Processing Rate Information for Emissions Estimates
Heater Design Rate
Heat content of waste gas=
Hours of Operation
Fuel Consumption
Section 04- Emissions Factors & Methodologies
3,8.4;: MMBtu/hr
120' Btu/scf
7250' hr/yr
130:8; MMscf/yr
11.1 MMscf/31 days
Pollutant
EmErznmi
meramimi
Formaldehyde
lb/MMscf
Ib/MMBtu
9.38
0.0021
0.0034
0.019
e
0.075.
0,6
, 40.80
0.0400
Emission Factor Source
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
Section 05 - Emissions Inventory
Criteria Pollutants
I Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
VOC
PM10
PM2.5
502
NOx
CO
1.3
0.5
0.5
0.0
2.7
2.7
1.3
0.5
0.5
0.0
2.7
2.7
Ib/31 day
215
84
84
7
453
453
Hazardous Air Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(Ibs/year) (Ibs/year)
Benzene
Toluene
Ethylbenzene
Xylene
n -Hexane
Formaldehyde
0.0001 0.0001
0.0002 0.0002
0.0008
0.0008 0.0000
0.1171 0.1177
0.0013 0.0049
0.3
0.4
0.0
0.0
235
10
0.3
0.4
0.0
0.0
235
10
0.0000
Section 06 - Regulatory Summary Analysis
Regulation 3, Parts A, B
Requires APES and Permit
Regulation 6, Part A, NSPS Subpart Dc
Subject
Regulation 6, Part B, Section II.C.2
Subject
Regulation 8, Part E, MACl Subpart DDDDD
Subject
5 of 23
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Emissions Inventory
Section 07- Initial and Periodic Sampling and Testing Reouirements
This heater will be required to have an initial stack test to confirm NOx and CO emissions.
Section 08- Technical Analysis Notes
This isa new heater for a new train. The source assumed a design input heat capacity of 18 a NIMBtu/hr. The source is also liraitmgihe heater to 7,250 hr/yr. The source stated NOx, CO and +/Oct
emissions : are based on manufacturer estimates but did not provide supporting documentation. When l asked the source about these emission factors, the source stated the emission factors m- based
on specrtications guaranteed for the Ezterran heaters used with Lancaster Train l and 2. The source also stated fiat while they have not yet bid on the project and thus do not know the manufacturer,
the bids for the heaters will specify these emission factors which'. will thenhave to be guaranteed by 'he heater manufacturer
I confirmed these :actors are identicalto the emission factors used in the mole=_eve regen heaters for Lance ster r -r11 and -2 (AIRS 11057 and 058 aincethe err s en factors have been previously
used for similar heaters at this site and those heaters were stack rested to demonstrate compliance, if is accepcaSic toy. use the same emisson factors f of Train : 1. Tne source is i singAP 4e, Chapter 1.4
emission factors for tike c "h.., oaITucarias and heat content of 1,020 btu/sd.
The source requestedto use AP -a2 em =s on faciorsto esumate uncontrolled NOX and then c cr Io e _on.-oi cfriclency based on the dnc_ _ _ . it r the
.
appropriate to createscontrol e,.iciency using AP -,0 and manufacturer omission esurmaues. The tO emission ra;tor will he lsted as uncontrolled_
Section 09 - Inventory SCC Coding and Emissions Factors
AIRS Point 8
076
Process 8
01
SCC Code
Pollutant
PM10
PM2.5
5O2
NOx
VOC
CO
Ber¢ene
Toluene
Ethylbenzene
Xylene
n -Hexane
Formaldehyde
Uncontrolled
Emissions
Factor
7,60
7.60
0.60
40.80
19.4
40.80
0.0021
0.0034
0.0000
0.0000
1.8000
0.0750
Control % Units
O Ih/MMscf
0 Ib/MMscf
O Ib/MMscf
O Ib/MMscf
O Ib/MMscf
O lb/MMscf
O Ib/MMscf
O Ib/MMscf
O lb/MMscf
O lb/MMscf
O Ib/MMscf
0 Ib/MMscf
6 of 23
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Emissions Inventory
Section 01- Administrative Information
Facility AIRs ID:
County
0057!
Plant
077
Section 02 - Equipment Description Details
Detailed Emissions Unit
Description:
one molecular sieve regeneration gas heater (manufacturer, model and serial number to be determined) equipped
with ultra : low NOR burners. The beater is design rated for an input capaciry of 18.4 MMB u/hr. This heater is fueled
by natural-gas.
Emission Control Device Ultra lowNOR burners
Description:
Requested Overall VOC & HAP Control
Efficiency %:
Section 03 - Processing Rate Information for Emissions Estimates
Heater Design Rate
Heat content of waste gas=
Hours of Operation
Fuel Consumption
Section 04 • Emissions Factors & Methodologies
MMBtu/hr
Btu/scf
hr/yr
MMscf/yr
1.1 MMscf/31 days
Pollutant
Formaldehyde
lb/MMscf
lb/MMBtu
..:_:0.039..
-' O0021:. -
Emission Factor Source
0!075
MMEMEMEM
40.80 ,':?llii'.
40,80
/0,0400
Section 05- Emissions Inventory
Criteria Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
lb/31 day
215
84
84
7
453
453
VOC
PM10
PM2.5
502
NOx
CO
1.3
1.3
0.5
0.5
0.5
0.5
0.0
0.0
2.7
2.7
2.7
2.7
Hazardous Air Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
. (tons/y®r) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(Ibs/year) (lbs/year)
Benzene
Toluene
Ethylbenzene
Xylene
n -Hexane
Formaldehyde
0.0001
0.0001
0.3
0.3
0.0002
0.0002
0.4
0.4
0.0004
0.0000
0.0
0.0
0.0003
0.0000
0.0
0.0
0.1177
0.1177
235
235
0.0049
0.0049
10
10
Section 06 - Regulatory Summary Analysis
Regulation 3, Parts A, B
Regulation 6, Part A, N5P5 Subpart Dc
Regulation 6, Part B, Section II.C.2
Regulation 8, Part E, MACF Subpart DDDDD
Requires APES and Permit
Subject
Subject
Subject
7 of 23
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Emissions Inventory
Section 07- Initial and Periodic Sampling and Testing Requirements
This heater will be required to have an initial stack test to confirm NOx and CO emissions.
Section 08 - Technical Analysis Notes
This is a new neaterfor a new train. The source assumed a design Input heat capacity of 18.4 MMBtu/hr. The source is also limiting the heater t0 7,250 hr/yr. The source stated NOx, CO and VOC
emissionsare based on manufacturer estimates but did not provide supporting documentation. When I asked the source about these emission-:`acto•5, tie source stated the em ssron factors are based'.
on specifications guaranteed for the Exterran heaters used with. Lancaster Train 1 and 2. The source also stated that while they have not yet b d on 0 -,re project and thus do not know the manu «surer,
the bids for the heaters will specify these emissionifacmrs whichwill then have to be guaranteed by the he.ator manufacturer.
I confirmed these factors are rdenticat to the emission factors used for the males etc ream hearers r. for ; e c._r Train 1 and 2 (AIRS I0 05h and. 058)Since the em Bran factors have been previously
used for similar heaters ' at this site and those heaters were siacir tested to demonstrate compliance, ht cac_ptable to use the same srreicn factor4for s_i. a. 'tic sourceis using AP -42, Chapter 4
emission- factorsfor the other pollutants and heat content of 4,020 btu/scf.
Tne source requested to use AP-42emrson factors to estimate uncontrolled NOX and then C21C1 date con,w ercp h-se,i on the d�etence fh tie -a_ nufa,iur
appropriate to creme a. cant of efficiency using AP+aa and manufacturer omission esu mates. The NO., e r i-s o l factor viill be Iistoa as uncontrolled
AIRS Point #
077
Process # 5CC Code
y•
Section 09 - Inventory 5CC Coding and Emissions Factors
Uncontrolled
Emissions
Pollutant Factor Control % Units
PM10 7.60 0 lb/MMscf
PM2.5 7.60 0 lb/MMscf
SO2 0.60 0 lb/MMscf
NOx 40.80 0 lb/MMscf
VOC 19.4 0 lb/MMscf
CO 40.80 0 lb/MMscf
Benzene 0.0021 0 lb/MMscf
Toluene 0.0034 0 lb/MMscf
Ethylbenzene 0.0000 0 lb/MMscf
Xylene 0.0000 0 lb/MMscf
n -Hexane 1.8000 0 lb/MMscf
Formaldehyde 0.0750 0 lb/MMscf
8 of 23 K:\PA\2017\ 17WE1059.CP1.xlsm
Emissions Inventory
Section 01- Administrative Information
Facility AIRS ID:
123 .
County
Rost Q'
Plant
Point
Section 02 - Equipment Description Details
Amine Information
Amine Type:
Make:
Model:
Serial Number:
Design Capacity:
Recirculation Pump Information
Number of Pumps
Pump Type
Make:
Model:
Design/Max Recirculation Rate:
Amine Equipment
Flash Tank
Reba'ler Burner
Stripping Gas
Equipment Description
MMscf/day
gallons/minute
nd flash tank
One (1) MOFA natural gas sweetening unit (Make: TBD, Model: TOO, Serial Number: TBD) with a design capacity of 153
MMscf per day. This emissions unit is equipped with 3 (Make: TBD, Model: TOD) electric driven amine pump with a design
capacity of 600 gallons per minute. This amine unit is equipped with a still vent and flash tank.
Emissions from the still vent are routed to the Thermal Oxidizer. Emissions from the flash tank are routed directlyto the
Emission Control Device Description: closed -loop system.
Section 03 - Processing Rate Information for Emissions Estimates
Primary Emissions - Still Vent and Flash Tank (if present)
Requested Permit Limit Throughput= „: , MMscfperyear
Potential to Emit (PTO Throughput = 55,845 MMscf per year
Secondary Emissions- Combustion Devices) for Air Pollution Control
Still Vent Control
Condenser:
Condenser emission reduction claimed:
Primary control device:
Primary control device operation:
Secondary control device:
Secondary control device operation:
Still Vent Gas Heating Value:
Still Vent Waste Gas Vent Rate:
Flesh tack Control
Primary control device:
Primary control device operation:
Secondary control device:
Secondary control device operation:
Flash Tank Gas Heating Value
Flash Tank Waste Gas Vent Rate:
TO Rating
Max design heat Release from TO
hr/yr
hr/yr
5 Otu/scf
3.19E+05. scfh
27.5 MMBtu/hr
222.5 MMscf/yr auxiliary
4743
99Jo...' Control Efficiency %
::. 95Z Control Efficiency %
Wet Gas Processed:
Still Vent Primary Control: 0.0 MMscf/yr
Still Vent Secondary Control: 0.0 MMscf/yr
Waste Gas Combusted:
Still Vent Primary Control: 2,796.0 MMscf/yr
Still Vent Secondary Control: 00 MMscf/yr
36.00. MMBtu/hr
Wet Gas Processed:
Flash Tank Primary Control: AO MMscf/yr
Flash Tank Secondary Control: 0.0 MMscf/yr
Waste Gas Combusted:
Flash Tank Primary Control: 0.0 MMscf/yr
Flash Tank Secondary Control: 0.0 MMscf/yr
237.5
1.6 MMBtu/hr from waste gas (calculated from modeled still vent gas flow and heat content)
18.9 MMscf/31 day auxiliary
Emissions Inventory
Section 04- Emissions Factors & Methodologies
Amine Unit
The source used a proprietary modal, Dow. Churn ProComp Process. Siorulotoe Version 8,3 0.> Ir6, to estimate emissions from the attune unit, The
Division does not typically use this mode.. HoweverHowever, these units are subject to ong,oing testing to confirm compliance with emissions limits The model
was based on a lean aminesolution of 45 ,,v(% amine solution (refereedtoes UCARSOIJ AP -814). It's oe learthe basisof the inlet gas stream. The model
s also based on the following parameters:
Input Parameters Flash tank
Inlet Gas Pressure
Inlet Gas Temperature
Requested Amine Recirculate Rate
STILL VENT
Maximum Vent Rate I 319178.125 scf/hr
1.0
RequestedThroughput (0) 2796 MMscf/yr
319178.1 scf/hr 7.660 MMscf/d I 237.47 MMscf/mo
% Vented I 100%
MW 42.715 IbAb-mel
Component
mole %
MW
Ibxlibmol
mass fraction
E
lb/hr
lb/yr
tpy
tpy
Water
5.65
18
1.017
0.024
Water
856.5
7502724
3751.36
3751.4
CO2
94.0366
44.01
41.386
0.969
CO2
34853.2
305313707
152656.85
152656.9
N2
6.71370E-05
28.013
0.000
0.000
N2
0.0
139
0.07
0.1
methane
1.78000E-01
16.041
0.029
0,001
methane
24.0
210644
105.32
105.3
ethane
4.79040E-02
30.07
0.014
0.000
ethane
12.1
106268
53.13
53.1
propane
1.35300E-02
44.1
0.0060
0.000
propane
5.0
44018
22.01
22.0
lsobutane
2.39870E-02
58.12
0.0139
0.000
isobutane
11.7
102849
51.42
51.4
n -butane
5.61000E-03
58.12
0. 033
0.000
n -butane
2.7
24054
12.03
12.0
isopentane
7.31880E-04
7215
0.0005
0.000
Isopentane
0.4
3896
1.95
1.9
n -pentane
6.91310E-04
72.15
0.0005
0.000
n -pentane
0.4
3680
1.84
1.8
cyclopentane
8.20920E-06
70.08
0.0000
0.000
cyclopentane
0.0
42
0.02
0.0
n -Hexane
3.70680E-04
86.18
0.0003
0.000
n -Hexane
0.3
2358
1.18
1.2
cyclohexane
5.99280E-06
84.18
0.0000
0.000
cyclohexane
0.0
37
0.02
0.0
Other hexenes
2.07290E-07
86.18
0.0000
0.000
Other hexanes
0.0
1
0.00
0,0
heptanes
3.21650E-04
100.21
0.0003
0.000
heptanes
0.3
2378
1.19
1.2
methylcyclohexene
0.00000E+00
98.19
0.0000
0.000
methylcyclohexar
0.0
0
0.00
0.0
224-TMP
0.00000E+00
114.23
0.0000
0.000
224-TMP
0.0
0
0.00
0.0
Benzene
1.21510E-02
78.11
0.0095
0.000
Benzene
8.0
70019
35.01
35.0
Toluene
6.15880E-03
92.14
0.0057
0.000
Toluene
4.8
41864
20.93
20.9
Ethylbenzene
3.28530E-03
106.168
0.0035
0.000
Ethylbenzene
2.9
25732
12.87
12.9
Xylenes
9.45190E-03
106.16
0.0100
0,000
Xylenes
8.5
74025
37.01
37.0
C8+ Heavies
6.97220E-04
116.000
0.0008
0.000
C8+ Heavies
0.7
5967
2.98
3.0
99.98957249 VOC mass fraction: 0.0013 Total VOC Emissions (Uncontrolled)
200:5
200.5
Flash Tank Pressure
Flash tank
Temperature
psg
deg F
Emission Factors
H2S and SOx emissions
Pollutant
VOC
Benzene
Toluene
Ethylhenzene
Xylene
n-Hesane
224 TMP
Pollutant
VOC
PM10
Pollutant
PM10
PM2.5
NOx
Pollutant
PM10
PM2.5
NOx
CO
Pollutant
PM2.5
NOe
CO
H25 in Fuel Gas
H25 in acid gas
Other sulfurs
Acid Gas Molar Volume to Molar Mass
502
H2S
Other sulfurs
Amine Still Vent
Uncontrolled
(Ib/MMscf)
(Waste Gas
Throughput)
Controlled
(Ib/MMscf)
(Waste Gas
Throughput)
143.39 1.4339
25.043 0.2504
14.973
9.2030
26.475,
0.8433
0.1497
0.0920
0.2648
0.0084
0 0.00
Still Vent Primary Control Device
Uncontrolled Uncontrolled
(Ib/MMBtu( (Ib/MMscf(
(Waste Heat (Waste Gas
Combusted) Combusted(
5.0094 1.5000
Still Vent Secondary Control Device
Uncontrolled Uncontrolled
(Ib/MMBtu) (Ib/MMscf(
(Waste Heat (Waste Gas
Combusted) Combusted(
0.0000
Flash Tank Primary Control Device
Uncontrolled Uncontrolled
(Ib/MMBtu) (Ib/MMscf(
(Waste Heat (Waste Gas
Combusted( Combusted(
0.0000
0.0000
0.0000
0.0000
Flash Tank Secondary Control Device
Uncontrolled Uncontrolled
(Ib/MMBtu) (Ib/MMscf(
(Waste Heat (Waste Gas
Combusted) Combusted)
0.0000
0,0000
0.0000
ppm
0.01050% oral %
mol %
379 scf/Ib-mol
64.05
34.08
60.07
Emission Factor Source
Emission Factor Source
Emission Factor Source
Emission Factor Source
Emission Factor Source
AP -42 plus 20% buffer
AP -42 plus 20% buffer
Since the flash tank Is being 100% recycled to the plant
Emissions Inventory
Puraspec removal 95%
H2S in acid gas
Other sulfurs in acid gas
H2S in fuel gas
Total
IQs in acid gas
Other wlfurs in acid gas
H28 in fuel gas
Total
Section 05 - Emissions Inventory
Did operator request a buffer?
Requested Buffer (%f
Uncontrolled H25
(tPY)
13.20
0.00
13.20
5Ox(tpy)
24.81
0.00
0.07
24.88
Combusted In TO
(tPY)
0.13
0.00
0,00
0.13
Source applied a 75% buffer to the modeled acid gas waste flow rate
Criteria Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
Permit Emissio
Uncontrolled
lb/31 day lh/MMscftota.
183 0.7136
183 0.7136
22 8.7466
4226 16.4854
2006 7.8244
1685 6.5725
451 Includes VOCf
PM10
PM2.5
H2S
502
Noe
CO
VOC
1,1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
1.1
13.2
13,2
0.1
13,2
0.13
24.9
24.9
24,9
24.9
24.9
11.8
11.8
11.8
11.8
11.8
9.9
9.9
9.9
9.9
9.9
201.1
201.1
2.7
201.1
2.7
Hazardous Alr Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(Ib/yr) (lb/yr)
Benzene
Toluene
Ethylbenzene
Xylem
n -Hexane
224 TMP
3,5E+01
3.5E+01
3.5E-01
35.0
0.4
70019
700
2,1E+01
2,1E+01
2.1E-01
20.9
0.2
41864
419
1.3E+01
1.3E+01
1.3E-01
12.9
0.1
25732
257
3,7E+01
3.7E+01
3.7E-01
37.0
0.4
74025
740
1.2E+00
1,2E+00
1.2E-02
1.2
0.01
2358
24
0.0E+00
0.0E+00
0.0E+00
0.0
0.0
0
0
Section 06 - Regulatory Summary Analysis
Regulation 3, Parts A, B
BTEX
Unit requires an APES and a permit
Unit is subject to minor source RACT. The still vent will he controlled by a thermal
oxidizer and the flash tank will be recycled 100%.
Unit is exempt from controls per NSPS 0000a.
105,82
Regulation 3, Part B, Section III.D.2
NSP5 Subpart 0000a
Section 07 - Initial and Periodic Sampling and Testing Requirements
Was the extended wet gas sample used In the process model site -specific year o"yl.
p pecm<and collected within a f application
submittal?
If no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with emission limits
Does the company request a control device efficiency greater than 95%for a flare or combustion device?
If yes, the permit will contain and Initial compliance test condition to demonstrate the destruction efficiency of the combustion device hosed on inlet and outlet concentration sampling
n Factors
Controlled
gas combusted
0.7136
0.7136
0.0875
16.4854
7.8244 139.8798133
6.5725
rom combustion and VOC front amine u
Section 08- Technical Analysis Notes
The source is requesting to install a new amine unit as part of Plant 3. The amine unit will be different from Tram 1 and 2. The proposed amine unit will consist of two separate amine contactors but will ',.
have one amine regeneration system to support both contactor towers.Thesystem will consist of two overhead contactor towers, one reboiler and one flash tank (also one rehoiler heater which is
covered under AIRS 075).
The source modeled emissions using a proprietary process model DOW ProComp Process Simulator Version 83.0.546, and provided the stream reports in the application The source applied a 75%
safety factocto the model resuitsto establish permit Omits. In the model, the source assumed even gas flow and amine circulation between the two contactors. Specifically, the source is' requesting a
total gas throughput to the amine system of 153: MMscfd and assumed 76.5 MMscfd was processed through each contactor. The model also assumed a lean amine circulation rate of 300 gpm to each
contactor for a total requested amine circulation rated 600 gpm. Under this scenario, I informed the source each contactor would have process limits of 76.5 MMscfd and 300 gpm amine
recirculation. The source requested tohave a total limit for both towers to increase operational flexibility. I requested the source provide additional modeling tams to demonstrate the impact on overall
emissions, The source provided two additional runs. One run was with uneven gas flow (100 MMscfd and 53 Mmscfd) and even recirculation rate of 300gpm, The other run was uneven gas flow (100
MMscfd and 53 MMscfd) and proportional amine rote (400 and 200 gpm)- With the two different runs, the emission rates_ from the still vent and flash tank did not change. I reviewed the runs which
were spghtly differentthan what was provided in the application. The streams were labeled differently without a processflowdiagram.The scenario supposedly represeotingthe original scenario m
the application had slightly lower VOC loading (the application had 11716 bmw) VOC/hrfrom the flash tank and 0.3702 lb mot VOCfhrfrom the still vent), The additional models appear to support the
source's position. Smcethe modeling dues not show a change in emissions, the permitwillinclude a total process limit and recirculation rate- Further, the source will monitor waste gas flow and
samplethe waste gas composition from the still vent to estimate emissions. The dash tank will be 100%recycled, so KMG is assuming the VRU is part of the process and does not include the flash tank in the uncontrolled emissions. It's acceptable to use this approach especially since regulatory
applicability does not change lithe flash tank emissions are included in the uncontrolled emissions. The permit conditions also will not change.
The source isusing AP -42 emission factors from Chapter 1.4 to estimate NOx and CO combustion emissions. The sours applied a 20% buffer tithe PM emission Factors from AP -42 chapter 1,4 to estimate PM emissions
from combustton.The source used a mass balance approach to estimate 1825 and 500 emissions.The source assumed the waste gas has 0-0105-mol%825and then 100% conversion to 50x: This. mass balance approach
s acceptable-Thesourcewillhave to monitor for 02000 centratlon.
The source mill be required to perform an initial compliance test and test the units on an annual basis ongoing-
KMG still maintains the TO and l/RU do not require back up control devices. Thus, theemiision limits assume 99%af still vent emission sat an times and 100% control of flash tank emissions at ail times. The permit does
not include any allowable downtime of the primary control devices. - - -
Emissions Inventory
Section 09 - Inventory SCC Codin¢ and Emissions Factors
AIRS Point k
078
Process a SCC Code
01
Uncontrolled
Pollutant Emissions Factor Control %
PM10 0.039 0.0%
PM2.5 0.039 0.0%
H2S 0.473 0.0%
SO2 0.891 0.0%
Nox 0.423 0.0%
CO 0.355 0.0%
VOC 7.202 98.7%
Benzene 1.254 99.0%
Toluene 0.750 99.0%
Ethylbencene 0.461 99.0%
Xylene 1.326 99.0%
n -Hexane 0.042 99.0%
224 TMP 0.000 9010/01
Truck Loading Vapor Pressure and Speciation
Component
Molecular
Weight
Stable Oil
Composition(*)
Truck Loading Vapor Pressure
Composition (b)
(lb/lb-mole)
(Mole %)
(Mole %)
(Wt. %)
Water
18.00
5.65
0.0000
0.0000
O2
16.00
0
0.0000
0.0000
Carbon Dioxide
44.01
94.0366
95.3306
98.2211
Nitrogen
28.01
0.000067137
0.0000
0.0000
Methane
16.04
0.178
4.6050
1.7293
Ethane
30.06
0.047904
0.0558
0.0393
Propane
44.09
0.01353
0.0047
0.0049
Isobutane
58.12
0.023987
0.0033
0.0045
n -Butane
58.12
0.00561
0.0005
0.0007
Isopentane
72.11
0.00073188
0.0000
0.0000
n -Pentane
72.11
0.000699519
0.0000
0.0000
Other Hexanes
86.17
6.20009E-06
0.0000
0.0000
Heptanes
100.21
-. 0.00032168
0.0000
0.0000
Octanes
114.23
0.00069722
0.0000
0.0000
Nonanes
128.20
0.0000
0.0000
Decanes+
189.00
0.0000
0.0000
Benzene
78.12
0.012151
0.0000
0.0001
Toluene
92.15
0.0061588
0.0000
0.0000
Ethylbenzene
106.17
'' 0.0032853
0.0000
0.0000
Xylenes (Total)
106.17
''' 0.0094519
0.0000
0.0000
n -Hexane
86.17
;, 0.00037088
0.0000
0.0000
2,2,4-Trimethylpentane
114.23
0
0.0000
0.0000
Total
99.98957249
100.0000
100.0000
VOC %
0.077001349
0.0087
0.0103
Liquid Bulk Temperature
64.00
F
Calculated True Vapor Pressure 101
293.74
psia
Calculated Molecular Weight of Vapors 161
42.71
lb/lb-mole
MW`TVP 12547,24456,
MW*TVP`VOC% 1.290861491
Notes:
(a) Based on E&P Tanks Model Run
(b) Vapor Composition (Mole %) = (Constituent TVP, psia) • (Consituent Mole % in Stable Oil) / (Total Liquid TVP, psia)
Vapor Composition (Wt f) _ (Constituent Mole %) * (Consituent MW, Ib/Ib-mole) / (Total Vapor MW, lb/lb-mole)
(c) True Vapor Pressure of Liquid (psia) = E (Constituent TVP, psia) * (Consituent Mole Fraction in Stable Oil). True vapor pressure
of each constituent calculated using Mpbpwih v1.43.
(d) Molecular Weight of Vapors calculated based on Equation 1-22 of AP 42 Chapter 7.1
Specific
Gravity TVPi Mwi
(mm hg) Vpi*MW
0.00E+00 0
0.00E+00 0
1.54E+04 41.95497575 6.78E+05
0.00E+00 0
0.4660 3.93E+05 0.738683602 6.30E+06
0.4460 1.77E+04 0.016779995 5.32E+05
0.5040 5.28E+03 0.002073509 2.33E+05
0.5630 2.10E+03 0.001927171 1.22E+05
0.5840 1.45E+03 0.000311212 8.43E+04
0.6240 5.27E+02 1.83098E-05 3.80E+04
0.6300 3.88E+02 1.28844E-05 2.80E+04
0.6700 1.52E+02 5.34579E-08 1.31E+04
0.6840 3.17E+01 6.72618E-07 3.18E+03
0.7010 9.81E+00 5.1432E-07 1.12E+03
0.7180 3.16E+00 0 4.04E+02
0.7840 1.06E+00 0 2.00E+02
0.8760 6.09E+01 3.80545E-05
0.8650 1.57E+01 5.86551E-06
0.8670 4.84E+00 1.11131E-06
0.8800 4.32E+00 2.85377E-06
0.6590 1.09E+02 2.29314E-06
0.6920 3.08E+01 0
0.001569056 15190.97095 42.71483385
API GRAV
90050.11002
Calculation of High Heating Value with Know Gas Speciation
Component
LHV (Btu/scf)
mole %
HHV (Btu/scf)
Water
0
5.65
0
CO2
0
94.0366
0
N2
0
0.000067137
0
methane
909.4
0.178
1010
ethane
1618.7
0.047904
1769.7
propane
2314.9
0.01353
2516.2
isobutane
3000.4
0.023987
3252
n -butane
3010.8
0.00561
3262.4
isopentane
3699
0.00073188
4000.9
n -pentane
3706.9
0.000699519
4008.7
Hexanes (Avg of 2-Methylpentane 1
4396.65
6.20009E-06
4748.85
heptanes
5100
0.00032165
5502.5
Octanes+ (Avg of C8, C9 and O10)
6492.9
0.00069722
6996.1
Nonanes
6493.2
0
6996.4
Decanes+
7189.5
0
7743
Benzene
3590.9
0.012151
3741.9
Toluene
4273.7
0.0061588
4474.9
Ethylbenzene
4970.4
0.0032853
5222
Xylenes (Avg of o, m, p xylene)
4957.1
0.0094519
5208.7
n -Hexane
4403.8
0.00037088
4756
224-TMP (LHV/HHV of n -C8)
5796
0
6248.9
H2S
586.8
0
637.1
99.98957249
Lower Heating Value of Gas
5.058625502 Btu/scf
Higher Heating Value of Gas
5.484968618 Btu/scf
Source: GPSA Engineering Data Book, page 23-4, Figure 23-2
Produced Natural Gas Venting/Flaring Preliminary Analysis
Section 01- Administrative Information
Facility AIRs ID:
County Plant
;079
Point
Colorado Department of Public Health and Environment
Air Pollution Control Division
Section 02 - Equipment Description Details
Maintenance activities and purging of gas. Activities are controlled by an elevated open process flare. Purge gas prevents low
flashback problems to the flare and keeps the flame stable. The purge gas and pilot gas used is sales gas and helps the flare
maintain a minimum required positive flow through the system. Also include combustion from pilots.
Control Efficiency
Section 03 - Processing Rate
Flare Pilot Rating
Fuel Gas Heat Value
Flare Purge Gas Rate
Process Gas
Process Gase Heat Value
Hours of operation
Total Heat Input
98%
Information for Emissions Estimates
0.19584 MMBtu/hr based on manufacturer's spec of 64 scfh per pilot and assuming 3 pilots
1020 Btu/scf
290 scf/hr 0.296 MMBtu/hr 2.5404
82.5 MMscf/yr 12.243 MMBtu/hr
1300 Btu/scf
8760 hr/yr
12.7348 MMBtu/hr
86.7 MMscf/yr
Section 04 - Emissions Factors & Methodologies
PURGE GAS
Emission Calculation Method
EPA Emission Inventory Improvement Program Publication: Volume II, Chapter 10 - Displacement Equation (10.4-3)
Ex=Q*MW`Xx/C
Ex = emissions of pollutant x
Q = Volumetric flow rate/volume of gas processed
MW = Molecular weight of gas = SG of gas * MW of air
Xx = mass fraction of x in gas
C = molar volume of ideal gas (379 scf/lb-mol) at 60F and 1 atm
7.4
Maximum Vent Rate I 290 scf/hr
RequestedThroughput (Q) 3 MMscf/yr
290.0 scf/hr J 0.007 MMscf/d I 0.22 MMscf/mo
% Vented I 100%
MW 19.364 Ib/Ib-mol
Component
mole %
MW
Ibx/Ibmol
mass fraction
E
lb/hr
lb/yr
tpy
Helium
0
4.0026
0.000
0.000
Helium
0.0
0
0.00
CO2
1.852
44.01
0.815
0.042
CO2
0.6
5463
2.73
N2
1.075
28.013
0.301
0.016
N2
0.2
2019
1.01
methane
82.302
16.041
13.202
0.682
methane
10.1
- 88492
44.25
ethane
14.159
30.063
4.257
0.220
ethane
3.3
28532
14.27
propane
0.081
44.092
0.0357
0.002
propane
0.0
239
0.12
isobutane
0.005
58.118
0.0029
0.000
isobutane
0.0
19
0.01
n -butane
0.025
58.118
0.0145
0.001
n -butane
0.0
97
0.05
isopentane
0.018
72.114
0.0130
0.001
isopentane
0.0
87
0.04
n -pentane
0.029
72.114
0.0209
0.001
n -pentane
0.0
140
0.07
cyclopentane
0.004
70.13
0.0028
0.000
cyclopentane
0.0
19
0.01
n -Hexane
0.0220
86.18
0.0190
0.001
n -Hexane
0.0
127
0.06
cyclohexane
0.0300
84.16
0.0252
0.001
cyclohexane
0.0
169
0.08
Otherhexanes
0.02
86.18
0.0172
0.001
Other hexanes
0.0
116
0.06
heptanes
0.063
100.21
0.0631
0.003
heptanes
0.0
423
0.21
methylcyclohexane
0.056
98.19
0.0550
0.003
methylcyclohexane
0.0
369
0.18
224-TMP
0.001
114.23
0.0011
0.000
224-TMP
0.0
8
0.00
Benzene
0.018
78.12
0.0141
0.001
Benzene
0.0
94
0.05
Toluene
0.067
92.15
0.0617
0.003
Toluene
0.0
414
0.21
Ethylbenzene
0.013
106.17
0.0138
0.001
Ethylbenzene
0.0
93
0.05
Xylenes
0.028
106.17
0.0297
0.002
Xylenes
0.0
199
0.10
C8+ Heavies
0.126
315.000
0.3969
0.020
C8+ Heavies
0.3
2660
1.33
Notes
99.994 VOC mass fraction: 0.0406 Total VOC Emissions (Uncontrolled)
2.6
Mole %, MW, and mass fractions are based on 2016 analysis of fuel gas for Lancaster Train 2
Emissions are based on 8760 hours of operation per year.
MW of C8+ is assumed to be 315
PROCESS GAS
Maximum Vent Rate I
9417.808219 scf/hr
RequestedThroughput (O)
82.5 MMscf/yr
9417.8 scf/hr I 0.226 MMscf/d I 7.01 MMscf/mo
% Vented I
100%
MW
19.592 lb/lb-mol
Component
mole %
MW
Ibx/Ibmol
mass fraction
E
Ib/hr
lb/yr
tpy
Helium
0
4.0026
0.000
0.000
Helium
0.0
0
0.00
CO2
3.712
44.01
1.634
0.083
CO2
40.6
355610
177.81
N2
0.514
28.013
0.144
0.007
N2
3.6
31343
15.67
methane
80.291
16.041
12.879
0.657
methane
320.0
2803581
1401.79
ethane
-
14.587
30.063
4.385
0.224
ethane
109.0
954582
477.29
propane
0.662
44.092
0.2919
0.015
propane
7.3
63538
31.77
Produced Natural Gas Venting/Flaring Preliminary Analysis
Colorado Department of Public Health and Environment
Air Pollution Control Division
isobutane
0.022
58.118
0.0128
0.001
isobutane
0.3
2783
1.39
n -butane
0.048
58.118
0.0279
0.001
n -butane
0.7
60/2
3.04
isopentane
0.013
72.114
0.0094
0.000
isopentane
0.2
2041
1.02
n -pentane
0.015
72.114
0.0108
0.001
n -pentane
0.3
23b5
1.18
cyclopentane
0.001
70.13
0.0007
0.000
cyclopentane
0.0
153
0.08
n -Hexane
0.0070
86.18
0.0060
0.000
n -Hexane
0.1
1313
0.66
cyclohexane
0.0030
84.16
0.0025
0.000
cyclohexane
0.1
550
0.27
Other hexanes
0.008
86.18
0.0069
0.000
Other hexanes
0.2
1501
0.75
heptanes
0.025
100.21
0.0251
0.001
heptanes
0.6
5453
2.73
methylcyclohexane
0.019
98.19
0.0187
0.001
methylcyclohexane
0.5
4061
2.03
224-TMP
0
114.23
0.0000
0.000
224-TMP
0.0
0
0.00
Benzene
0.003
78.12
0.0023
0.000
Benzene
0.1
510
0.26
Toluene
0.02
92.15
0.0184
0.001
Toluene
0.5
4012
2.01
Ethylbenzene
0.005
106.17
0.0053
0.000
Ethylbenzene
0.1
1156
0.58
Xylenes
0.019
106.17
0.0202
0.001
Xylenes
0.5
4391
2.20
C8+ Heavies
0.029
315.000
0,0914
0.005
C8+ Heavies
2.3
19885
9.94
100.003
VOC mass fraction:
0.0281 Total VOC Emissions (Unoon trolle
Notes
Mole %, MW, and mass fractions are based on 2016 analysis of process gas at Lancaster Train 1
Emissions are based on 8760 hours of operation per year.
MW of C8+ is assumed to be 315
Total
tpy
lb/yr
VOC
62.5
Benzene
0.3022
604
Toluene
2.2128
4426
Ethylbenzene
0.6240
1248
Xylene
2.2952
4590
n -Hexane
0.7
1440
0
Uncontrolled
H2S
H2S in Process Gas 1 ppm
Acid Gas Molar Volume to Molar Mass 379
5O2 64.05
H2S 34.08
H2S in Process Gas 7 lb/yr
S02 combustion emissions 14 lb/yr
Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment
Air Pollution Control Division
Flaring Information
Pollutant Uncontrolled Emission Factors Emission Factor Source
lb/MMscf lb/MMBtu
VOC ss 2251.14 1.75
Benzene " .6.5035
Toluene
51.041
Ethylbenzene
34
Xylene
65.566
n -Hexane 15-03
Formaldehyde
PM10
PM2.5
NOx
CO
6.0 0.0058:
613 0.0058
0'€06
3100'
Section 05 - Emissions Inventory
Controlled Emission Factors
lb/MMscf lb/MMBtu
45.023 ".
B.
35
.1301
0.000001
0.00000 '..
0.00001
0.000001'
0.0000
1.0210
2668
1.3113
0.3007.:'..
0.000
Criteria Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
lb/31 day
44
44
644
2937
332 USING SOURCE'S VALUES IN PE
PM10
PM2.5
Nox
CO
VOC
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
3.8
3.8
3.8
3.8
3.8
17.3
17.3
17.3
17.3
17.3
97.6
97.6 2.0
97.6 2.0
Hazardous Air Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
Uncontrolled Controlled
(tons/year) (tons/year)
Hequestec Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
Requested Permit Limits
Uncontrolled Controlled
(Ib/yr) (Ib/yr)
Source's Values
Uncontrolled
Controlled
(lb/yr)
(Ib/yr)
Benzene
Toluene
Ethylbenzene
Xylene
n -Hexane
224 TMP
3.0E-01
3.0E-01
6.0E-03
3.0E-01
6.0E-03
604
12
564
11
2.2E+00
2.2E+00
4.4E-02
2.2E+00
4.4E-02
4426
89
4427
89
6.2E-01
6.2E-01
1.2E-02
6.2E-01
1.2E-02
1248
25
1157
23
2.3E+00
2.3E+00
4.6E-02
2.3E+00
4.6E-02
4590
92
5686
94
7.2E-01
7.2E-01
1.4E-02
7.2E-01
1.4E-02
1440
29
1304
29
0.0E+00
0.0E+00
0.0E+00
0.0E+00
0.0E+00
0 0
Section 06 - Regulatory Summary Analysis
Regulation 3, Parts A, B
Unit is required to have an APEN and a permit
Regulation 7, Section XVII.B
Unit is not used to comply with Reg 7
Regulation 7, Section XVII.B.2.e
Unit is not used as an alternative control device for Reg 7
Produced Natural Gas Venting/Flaring Preliminary Analysis
Section 07 - Initial and Periodic Sampling and Testing Requirements
Was a site -specific gas sample collected within a year of application submittal used to
estimate emissions?
If no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with emission limits
Colorado Department of Public Health and Environment
Air Pollution Control Division
Does the company request a control device efficiency greater than 95% for a flare or combustion device? Y' ,sae5BCtibn 8 for discussion
If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling
Section 08 - Technical Analysis Notes
In the original application, the source used the THC emission factor in AP 42 Table 13.5-1 and applied a 25% VOCby weight to calculate controlled VOC. The
source divided this value by the control percentage to estimate uncontrolled VOC. The Division has approved this method for another process flare at this site
because the source confirmed this approach was appropriate by comparing results to a mass balance approach using the stream composition based on gas
samples of the purge and process gas. I requested the source estimate emissions based on the amount and composition of process gas routed to the flare to
confirm for this flare. Also, the source needs to use the gas composition approach to estimate HAPS- The source provided 2016 gas analyses and assuming the
requested' process gas throughput of 82.5 IV1Mscf/yr and purge/flare gas throughput of 2.5 MMscf/yr, the uncontrolled VOC emissions are 62.ttpy (see emission
calculations above) Since emissions are lower using the mass balance approach, the source is requesting to use the AP -42 emission factor approach to establish = -1
permit limits. It's acceptable to use the AP -42 emission factors for VOC but then use the mass balance to establish HAP values. '
95% control efficiency for open flares since the The source is requesting to use 98% control policyonly p units can't
efficiency for this,�lare Division oli is to allowfor
be tested. However, a similar permit for a similar flare at this site (AIRS ID070, Permit 14WE0142 CP1) was issued and allowed for 98% control. The source has
stated a similar flare will be installed for this train. Thus, this permit will include 98%'control efficiency provided the flare meets 60.18.
Section 09 - Inventory SCC Coding and Emissions Factors
AIRS Point #
Process # SCC Code
079 01
Uncontrolled
Emissions
Pollutant Factor Control
PM10 5.963 0.0%
PM2.5 5.963 0.0%
NOx 87.473 0.0%
VOC 2251.1 98.0%
CO 398.774 0.0%
Benzene 6.5035 98.0%
Toluene 51.0480 98.0%
Ethylbenzen 13.3414 98.0%
Xylene 65.5656 98.0%
n -Hexane 15.0365 98.0%
224 TMP 0.0000 #DIV/0l
Section 01- Administrative Information
123 0057 080:.
Facility Al Rs ID:
County Plant Point
Section 02 - Equipment Description Details
Fugitive equipment leaks from Lancaster Plant 3
Section 03 - Processing Rate Information for Emissions Estimates
Operation (hrs/yr) 8760
Colorado Department of Public Health Environment
Air Pollution Control Division
Preliminary Analysis - Emissions from Fugitive Components
Section 04 - Emissions Factors & Methodologies
Emission factors are based on Table 2-4 from EPA Protocol for Equipment Leak Emission Estimates (EPA -453/R-95-017 Nov 1995)
Service
Component Type
Count
TOC EF
lb/hr-
source
TOC EF
kg/hr-source
Control
(%)
VOC
Benzene
Toluene
Ethylbenzene
Xylene
n -Hexane
Uncontrolled
(toy)
Controlled
(toy)
Uncontrolled
(Ib/yr)
Controlled
(Ib/yr)
Uncontrolled
(lb/yr)
Controlled
(Ib/yr)
Uncontrolled
(Ib/yr)
Controlled
(Ib/yr)
Uncontrolled
(Ib/yr)
Controlled
(Ib/yr)
Uncontrolled
(Ib/yr)
Controlled
(Ib/yr)
Inlet Gas
Valves
653
9.92E-03
4.50E-03
96.0%
6.24
0.2
11.3
0.5
17.0
0.7
0.0
0.0
5.7
0.2
113.5
4,5
Pump Seals
0
5.29E-03
2.40E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Others
35
1.94E-02
8.80E -D3
0.0%
0.65
0.7
1.2
1.2
1.6
1.8
0.0
0.0
0.6
0.6
11.9
11.9
Connectors
1202
4.41E-04
2.00E-04
81.0%
0.51
0.1
0.9
D.2
1.4
0.3
0.0
0.0
0.5
0.1
9.3
1.8
Flanges
566
8.60E-04
3.90E-04
0.0%
0.47
0.5
0.9
0.9
1.3
1.3
0.0
0.0
0.4
0.4
8.5
8.5
Open-ended lines
0
4.41E-03
2,00E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
C3+Gas
Valves
1211
9.92E-03
4,50E-03
96.0%
52.62
2.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Pump Seals
0
5.29E-03
2.40E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Others
32
1.94E-02
8.80E-03
0.0%
2.72
2.7
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Connectors
10604
4.41E-04
2.00E-04
81.0%
20.48
3.9
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Flanges
342
6.60E-04
3.90E-04
0.0%
1.29
1.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Open-ended lines
0
4.41E-03
2.00E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
C3+Liquid Light Oi
Valves
1038
5.51E -D3
2.50E -D3
95.0%
25.06
1.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Pump Seals
8
2.87E-02
1.30E-02
88,0%
1.00
0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Others
17
1.65E-02
7.50E-03
0.0%
1.23
1.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Connectors
1458
4.63E-04
2.10E-04
81.0%
2.96
0.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Flanges
317
2.43E-04
1.10E-04
0.0%
0.34
0.3
0.0
0.0
0.0
0.0
0.0
0,0
0.0
0.0
0.0
0.0
Open-ended lines
0
3.09E-03
1.40E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
NGL Light Oil
Valves
114
5.51E-03
2.50E-03
95.0%
2.75
0.1
11.0
0.6
0.6
0.0
0.6
0.0
13.8
0.7
110.1
5.5
Pump Seals
0
2.87E-02
1,30E-02
88.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Others
5
1.65E-02
7.50E-03
0.0%
0.36
0.4
1.4
1.4
0.1
0.1
0.1
0.1
1.8
1.8
14.5
14.5
Connectors
321
4.63E-04
2,10E-04
81,0%
0.65
0.1
2.6
0.5
0.1
0.0
0.1
0.0
3.3
0.6
26.0
4.9
Flanges
0
2.43E-04
1.10E-04
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Open-ended lines
0
3.09E-03
1.40E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Methanol Light Oil
Valves
29
5.51 E-03
2.50E-03
95.0%
0.70
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Pump Seals
3
2.87E-02
1.30E-02
88.0%
0.38
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Others
2
1.65E-02
7.50E-03
0.0%
0.14
0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Connectors
92
4.63E-04
2.10E-04
81.0%
0.19
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Flanges
0
2.43E-04
1.10E-04
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Open-ended lines
0
3.09E-03
1.40E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Iondensate Light C
Valves
231
5.51E-03
2.50E-03
95.0%
5.58
0.3
167.3
8.4
334.6
16.7
55.8
2.8
167.3
8.4
836.5
41.8
Pump Seals
0
2.87E-02
1.30E-02
88.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Others
0
1.65E-02
7,50E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Connectors
389
4.63E-04
2.10E -D4
81.0%
0.79
0.1
23.7
4.5
47.3
9.0
7.9
1.5
23.7
4.5
118.3
22.5
Flanges
0
2.43E-04
1.10E-04
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Open-ended lines
0
3.09E-03
1.40E-03
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Heavy Oil
Valves
468
1.85E-05
8.40E-06
0.0%
0.04
0.0
1.1
1.1
2.3
2.3
0.4
0.4
1.1
1.1
5.7
5.7
Pump Seals
,17, ;„
:'
c
rqv ._
r
; ,.'�
'.,
' „
Others
9
7.05E-05
3.20E-05
0.0%
0.00
0.0
0.1
0.1
0.2
0.2
0.0
0.0
0.1
0.1
0.4
0.4
Connectors
3953
4.63E-04
2,10E-04
81.0%
8.02
1.5
240.5
45.7
481.0
91.4
80.2
15.2
240.5
45.7
1202.4
228.5
Flanges
68
8.60E-07
3.90E-07
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Open-ended lines
0
3.09E-04
1.40E-04
0.0%
0.00
0.0
0.0
0.0
0.0
0.D
0.0
0.0
0.0
0.0
0.0
0.0
Water/Oil
Valves
2.16E-04
9.80E-05
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Pump Seals
5.29E-05
2.40E-05
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Others
3.09E-02
1.40E -D2
D.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Connectors
2.43E-04
1.10E-04
0.0%
0.00
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Printed 5/29/2018
Page 19 of 23
Colorado Department of Public Health Environment
Air Pollution Control Division
Flanges
6.39E-06
2.90E-06
0.0%
0.00Prelmin3hPAnalysis-Effiksions
'ram llfiitiveComOdhents
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Open-ended lines
5.51E-04
2.50E -D4
D.0%
0.00 0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
TOTALS (tpy)
135.2
17.
0.23
0.03
0.44
0.06
0.07
0.01
0.23
0.03
1.23
0.18
TOTALS lb/ r
4 2 5 12 145 2I 45 2457 351
With safety factor:
TOTALS (tpy)
TOTALS lb
Emission Factor Source:
0.23
0.03
0.44
0.06
0.07
0.01
0.23
0.03
1.23
0.18
EPA -453/R-95-017, Table 2-4
Stream VOC Fraction (wt
Inlet Gas
0.2200
C3+ Gas
1.0000
Light Oil
1.0000
Heavy Oil
1.0000
Water/Oil
1.0000
Section 05 - Emissions Inventory
omponents (wt fraction
HAP
Gas
C3+ Gas
C3+ Light Oi
NGL Light Oil
teOH Light C
Cond Light Oil
Heavy Oil
Water/Oil
Benzene
0.0002
0
0.000
0.002
0.000
0.015
0.015
0.00
Toluene
0.0003
0
0.000
0.0001
0.000
0.030
0.030
0.00
Ethylbenzene
0
0
0.000
0.0001
D.000
0.005
0.005
0.00
Xylene
0.0001
0
0.000
0.003
0.000
0.015
0.015
0.00
n -Hexane
D.002
0
0.000
0.020
0.000
0.075
0.075
0.00
THE SOURCE'S VOC VALUES ARE SLIGHTLY HIGHER THAN MY VALUES. I WILL USE THE SOURCE'S VALUES IN THE PERMIT AND PA.
Criteria Pollutant
Potential to Emit
Uncontrolled
(tons/year)
Actual Emissions
)ncontrolle' Controlled
(tons/year) (tons/year)
tequested Permit Limit
Uncontrolled :ontrolled
(tons/year) tons/yea
lb/31 day
0
0
0
0
3261
PM10
PM2.5
Nox
CO
VOC
0,0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
136.3
1'36.3
19.2
136.3 19:2
Hazardous Air
Pollutants
Potential to Emit
Uncontrolled
(tons/year)
Actual _missions
(ncontrolle Controlled
(tons/year) (tons/year)
tequested Permit Limit
Uncontrolled-ontrolle
(tons/year) tons/yea
Hequested Permit Limits
Uncontrolled Controlled
(Ib/yr) (Ib/yr)
Benzene
Toluene
Ethylbenzene
Xylene
n -Hexane
224 TMP
0.23
0,23
0.03
0.23
0.03
462
65
0.44
0.44
0.06
0.44
0.06
888
124
0.07
0.07
0.01
0.07
0.01
145
20
0.23
0.23
0.03
D.23
0.03
459
64
1.23
1.23
0.18
1.23
0.18
2457
351
0.00
0.00
0.00
0
0
Total Components
Valves
Pump Seals
Others
Connectors
Flanges
Open-ended li
By service
Gas
3744 1864 1412
28 0 11
100 67 24
18019 11806 2260
1293 908 317
D 0 0
Light liquid
Reg. 3
Is this source located in an ozone non -attainment area or attainment maintenance area? Yes
If yes, is this source subject to leak detection and repair (LDAR) requirements per Regulation 7, Section XVII.F or XII.G or 40 CFR, Part 60, Subparts KKK or OOOO? Yes
If you repond "yes" to the first question and "no" to the second, this source is subject to Regulation 3, Part B, Section III.D.2, Reasonably Available Control Technology (RACT) requirements and must implement a
leak detection and repair program. The engineer should work with the supervisor to craft an LDAR requirement that mirrors the provisions of Regulation 7, Section XVII.F.
Reg. 6
Is this source at an onshore "natural gas processing plant" as defined in 40 CFR, Part 60.631? Yes
Did this source commences construction, reconstruction, or modification after January 20, 1984, and on or before August 23, 2011? No
If you answer "yes" to both questions above, this source is subject to the provisions of 40 CFR, Part 60, Subpart KKK "Standards of Performance for Equipment Leaks of VOC From Onshore Natural Gas Processing
Plants" contained in Regulation 6, Part A.
Did this source commences construction, reconstruction, or modification after 9/18/2015? Yes
If you answer "yes" to question #1 and #3 this source is subject to the provisions of 40 CFR, Part 60, Subpart 0000a "Standards of Performance for Crude Oil and Natural Gas Production, Transmission and
Distribution".
Reg 7
Is this source located in an ozone non -attainment area or attainment maintenance area? Yes
Is this source at an onshore "natural gas processing plant" as defined in 40 CFR, Part 60.631? Yes
If you answer "yes" to both questions above, this source is subject to the provisions of Regulation 7, Section XII.G regardless of the date of construction
Reg. 8
Is this source at a "natural gas processing plant" as defined in 40 CFR, Part 63.761? Yes
Is this facility considered a "major source" of HAP as specifically defined in 40 CFR, Part 63.761 for sites that are not prodcution field facilities? Yes
If you repond "yes" to both questions above, further review if the provisions of 40 CFR, Part 63.769 "Equipment Leak Standards" apply? Yes
Per 63.769(b), MACT HH does not apply to equipment subject to NSPS OOOO. Since this site is subject to NSPS OOOOa, MACT HH requirements will be included in the permit.
Section 07 - Initial and Periodic Sampling and Testing Requirements
Was asite-specific gas sample collected within a year of
application submittal used to estimate emissions?
If no, the permit will contain an "Initial Compliance" testing requirement to demonstrate compliance with emission limits
Printed 5/29/2018
Page 20 of 23
Colorado Department of Public Health Environment
Air Pollution Control Division
Does the company request a control device efficiency greater than 95% for a flare or-iminary Analysis - Emissions from Fugitive Components
combustion device?
If yes, the permit will contain and initial compliance test condition to demonstrate the destruction efficiency of the combustion device based on inlet and outlet concentration sampling
Section 08 -Technical Analysis Notes
Section 09 - Inventory SCC Coding and Emissions Factors
AIRS Point #
080
Process # SCC Code
01 pi
Printed 5/29/2018 Page 21 of 23
Lancaster Plant 3 Project Total for Permitted Points (including fugitive)
Criteria Pollutants
Requested Permit Limits
Uncontrolled Controlled
(tons/year) (tons/year)
PM10
4.12
4.12
PM2.5
4.12
4.12
H2S
13.20
0.13
SO2
25.10
25.10
Nox
30.57
30.57
CO
42.18
42.18
VOC
442.13
30.92
Lancaster Plant 3 Project Total with Permitted and Insignificant Activities
(including APEN-exempt and permit -exempt points)1
Requested Permit Limits
Criteria Pollutants Uncontrolled
(tons/year)
Controlled
(tons/year)
PSD Significance
Threshold (tpy)
Does Project
Exceed PSD
Threshold?
PM10
4.82
4.8
40
No
PM2.5
4.82
4.8
10
No
H2S
13.20
0.1
10
No
SO2
25.71
25.7
40
No
Nox
38.51
38.5
40
No
CO
46.35
46.4
100
No
VOC
444.03
13.6
40
No
1: The insignificant activities include a 5 MMBtu/hr condensate stabilizer heater, a 6 MMBtu/hr inlet
heater, 10 MMBtu/hr inlet heater, and a 839 hp diesel emergency generator.
Lancaster Plant 3 Project Total with Permitted and Insignificant Activities
(including APEN-exempt and permit -exempt points)1
Requested Permit Limits
Does Project
Criteria Pollutants
Uncontrolled Controlled
PSD Significance Exceed PSD
(tons/year) (tons/year)
Threshold (tpy) Threshold?
PM10
4.52 4.5
40 No
PM2.5
4.52 4.5
10 No
H2S
13.20 0.1
10 No
SO2
25.71 25.7
40 No
Nox
36.21 36.2
40 No
CO
44.55 44.6
100 No
VOC
443.23 12.8
40 No
1: The insignificant activities include a 5 MMBtu/hr condensate stabilizer heater, a 6 MME
heater, and a 839 hp diesel emergency generator. The
10 MMBtu/hr is not included in thi
evaluation since it is associated with Lancaster Train 1
and 2.
to/hr inlet
Lancaster Train 1&2 Project Emissions in Tons per Year (Permitted Values)
NOX CO VOC 5O2 PM2.5
057 Heater 4.7 4.7 2.2 0.1 0.9
058 Heater 4.7 4.7 2.2 0.1 0.9
059 Heater 14.8 14.8 2 0.2 1.7
060 Heater 14.8 14.8 2 0.2 1.7
061 Heater 14.8 14.8 2 0.2 1.7
062 Heater 14.8 14.8 2 0.2 1.7
063 Amine/TO 11.8 8.4 3.2 3.6 1.2
064 Amine/TO 11.8 8.4 3.2 3.6 1.2
065 Amine/TO 11.8 8.4 3.2 3.6 1.2
066 Amine/TO 11.8 8.4 3.2 3.6 1.2
067 Process Flare 7.3 14.6 1.6 0.03 0.3
067 Process Flare 7.3 14.6 1.6 0.03 0.3
031 Emergency Genera 1.3 0.1 0.7 0.04
H2S Pre heaters 2.3 1.8 0.8 0 0.3
Total 134.0 133.3 29.2 16.2 14.3
Phase 1 for Lancaster Train 1&2
NOX CO
Project Emissions 66.5 65.8
Contemporaneous Increases 85.9 56.8
Contemporaneous Decreases -162.7 -37.7
Net Emissions Change -10.3 84.9
Signficiant Level 40 100
Are the net emissions increasE No No
Phase 2 for Lancaster Train 1&2
NOX CO
Project Emissions 134.0 133.3
Contemporaneous Increases 52.3 43
Contemporaneous Decreases -216 -82.7
Net Emissions Change -29.7 93.6
Signficiant Level 40 100
Are the net emissions increasE No No
PM2.5
7.04
4
-5.4
5.64
10
No
PM2.5
14.3
2.6
-7.5
9.44
10
No
Permit number:
Date issued:
Issued to:
Ith & Environment
CONSTRUCTION PERMIT
17WE1059
Facility Name:
Plant AIRS ID:
Physical Location:
County:
General
Description:
Issuance:
1
Kerr McGee Gathering LLC
Platte Valley/Ft. Lupton/Lancaster Complex
123/0057
16116 Weld County Rd 22, Ft. Lupton, CO
Weld County
Natural Gas Compressor Station
Equipment or activity subject to this permit:
Facility
Equipment ID
AIRS
Point
Equipment Description
Emissions Control
Description
H 80100
075
One amine heat medium heater (Make, Model,
Serial Number: To be determined) equipped
with ultra low N0x burners used to regenerate
amine for Point 078. The heater is design rated
for an input capacity of 55 MMBtu/hr. This
heater is fueled by natural gas.
Low N0x burners
H-31711
076
One molecular sieve regeneration gas heater
(Make, Model, Serial Number: To be
determined) equipped with ultra low NOx
burners. The heater is design rated for an input
capacity of 18.4 MMBtu/hr. This heater is fueled
by natural gas.
Low N0x burners
H 32711
077
One molecular sieve regeneration gas heater
(Make, Model, Serial Number: To be
determined) equipped with ultra low N0x
burners. The heater is design rated for an input
capacity of 18.4 MMBtu/hr. This heater is fueled
by natural gas.
Low N0x burners
TO -91700
078
One (1) Methyldiethanolamine (MDEA) natural
gas sweetening system (Two Amine Contactor
Towers Make, Model, Serial Number: To be
Emissions from the still
vent are routed to a
thermal oxidizer (Make,
COLORADO
Air Pollution Control Division
Page 1 of 31
E,ti
deter <'n- for a• i • s remol with a design
capac = = 53 .er da his emissions
unit i equied three (3) lectric amine
-cir ulatio "'•um Make, Mo ;-l: To be
•e ermine • , wo operate a once with one
(1) as a backup with a total limited combined
design capacity of 600 gallons per minute. This
system includes two natural gas/amine
contactors, one amine regeneration still vent
and one amine regeneration flash tank.
Model, Serial Number:
To be determined)
which has a minimum
destruction and
removal efficiency
(DRE) of 99%. The flash
tank emissions are
routed to the plant
inlet as closed loop
system for 100% recycle
of the flash tank
emissions.
FL -90100
079
Maintenance activities and purging of gas.
Activities are controlled by an elevated open air
assisted process flare (Make, Model, Serial
Number: To be determined). Purge gas prevents
low flashback problems to the flare and keeps
the flame stable. The purge gas and pilot gas
used is sales gas and helps the flare maintain a
minimum required positive flow through the
system.
Open flare (Make,
Model, Serial Number:
To be determined)
FUG -5
080
Fugitive component leak emissions for Lancaster
Train 3
LDAR
This permit is granted subject to all rules and regulations of the Colorado Air Quality Control Commission
and the Colorado Air Pollution Prevention and Control Act (C.R.S. 25-7-101 et seq), to the specific general
terms and conditions included in this document and the following specific terms and conditions.
REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION
1. Points 075 - 080: YOU MUST notify the Air Pollution Control Division (the Division) no later than
fifteen days of the latter of commencement of operation or issuance of this permit, by submitting
a Notice of Startup form to the Division for the equipment covered by this permit. The Notice of
Startup form may be downloaded online at www.colorado.gov/pacific/cdphe/other-air-
permitting-notices. Failure to notify the Division of startup of the permitted source is a violation
of Air Quality Control Commission (AQCC) Regulation Number 3, Part B, Section III.G.1. and can
result in the revocation of the permit.
2. Within one hundred and eighty days (180) of the latter of commencement of operation or issuance
of this permit, compliance with the conditions contained in this permit shall be demonstrated to
the Division. It is the owner or operator's responsibility to self -certify compliance with the
conditions. Failure to demonstrate compliance within 180 days may result in revocation of the
permit. A self certification form and guidance on how to self -certify compliance as required by
this permit may be obtained online at www.colorado.gov/pacific/cdphe/air-permit-self-
certification. (Regulation Number 3, Part B, Section III.G.2.)
3. This permit shall expire if the owner or operator of the source for which this permit was issued:
(i) does not commence construction/modification or operation of this source within 18 months
after either, the date of issuance of this construction permit or the date on which such
construction or activity was scheduled to commence as set forth in the permit application
associated with this permit; (ii) discontinues construction for a period of eighteen months or
more; (iii) does not complete construction within a reasonable time of the estimated completion
date. The Division may grant extensions of the deadline. (Regulation Number 3, Part B, Section
III. F.4. )
COLORADO
Air Pollution Control Division
t ar n. 4 l ubi, riot ?a E rotIMe.
Page 2 of 31
4.
sting and sampling as required in this permit
the self -certification process. (Regulation
5. olio n she Division within fifteen (15) days of
commencement of operation:
•
•
•
•
•
Heater manufacturer name, model and serial number
Two amine contactor towers manufacturer name, model number and serial number
Amine circulation pump manufacturer name and model number
Thermal oxidizer manufacturer name, model number and serial number
Process flare manufacturer name, model number and serial number.
This information shall be included with the Notice of Startup submitted for the equipment.
(Reference: Regulation Number 3, Part B, III.E.)
6. The operator shall retain the permit final authorization letter issued by the Division, after
completion of self -certification, with the most current construction permit. This construction
permit alone does not provide final authority for the operation of this source.
EMISSION LIMITATIONS AND RECORDS
7. Emissions of air pollutants shall not exceed the following limitations. (Regulation Number 3, Part
B, Section II.A.4.)
)
Monthly Limits:
Facility
Equipment
ID
AIRS
Point
Pounds per Month
Emission
Type
PM2.5
NO,
5O2
VOC
CO
H2S
H-80100
075
305
1,637
---
777
1,637
---
Point
H-31711
076
--
453
---
215
453
---
Point
H-32711
077
--
453
---
215
453
---
Point
TO -91700
078
183
2,006
4,226
451
1,685
22
Point
FL -90100
079
---
644
---
332
2,937
---
Point
FUG -5
080
---
---
---
3,261
---
---
Fugitive
ote: Monthly limits are based on a 31 -day month.
The owner or operator shall calculate monthly emissions based on the calendar month.
Annual Limits:
Facility
Equipment
ID
AIRS
Point
Tons per Year
Emission
Type
pM2.5
NOX
SO2
VOC
CO
H25
H-80100
075
1.8
9.6
---
4.6
9.6
---
Point
H-31711
076
---
2.7
---
1.3
2.7
---
Point
H-32711
077
---
2.7
---
1.3
2.7
---
Point
TO -91700
078
1.1
11.8
24.9
2.7
9.9
0.1
Point
COLORADO
Pollution Control Division
lr6 ?N 4a.:titc N4A01 4 r:•H.rrr:rott
Page 3 of 31
limits.
FL- ` 10
79
--
-
2.0
17.3
---
Point
F ' -5
0
-
19.2
---
---
Fugitive
Hot rmation
ission factors and methods used to calculate
During the first twelve (12) months of operation, compliance with both the monthly and annual
emission limitations is required. After the first twelve (12) months of operation, compliance with
only the annual limitation is required.
Compliance with the annual limits, for criteria air pollutants, shall be determined on a rolling
twelve (12) month total. By the end of each month a new twelve month total is calculated based
on the previous twelve months' data. The permit holder shall calculate actual emissions each
month and keep a compliance record on site or at a local field office with site responsibility for
Division review.
8. Point 078: The owner or operator shall calculate uncontrolled VOC, HAP, and H2S emissions on
a monthly basis using the most recent measured waste gas sample composition and monthly
measured waste gas flow volume as specified in this permit. A control efficiency. of 99%, based
on maintaining the minimum temperature requirements specified in specified in this permit,
shall be applied to the uncontrolled VOC, HAP and H2S emissions. Total actual VOC emissions
shall be based on the sum of VOC emissions from the waste gas stream plus VOC due to
combustion.
9. Point 080: The operator shall calculate actual emissions from this emissions point based on
representative component counts for the facility with the most recent extended gas analysis, as
required in the Compliance Testing and Sampling section of this permit. The operator shall
maintain records of the results of component counts and sampling events used to calculate actual
emissions and the dates that these counts and events were completed. These records shall be
provided to the Division upon request.
10. The owner or operator shall operate and maintain the emission points in the table below with
the emissions control equipment as listed in order to reduce emissions to less than or equal to
the limits established in this permit. (Regulation Number 3, Part B, Section III.E.)
Facility
Equipment ID
AIRS
Point
Control Device
Pollutants
Controlled
TO -91700
078
Still Vent: Thermal Oxidizer
. VOC and
HAP
FL -90100
079
Open Flare
VOC and
HAP
11. The owner or operator shall operate and maintain the emission points in the table below as a
closed loop system and shall recycle 100% of emissions as described in the table below.
(Regulation Number 3, Part B, Section III.E.)
Facility
Equipment ID
AIRS
Point
Emissions Recycling Description
Pollutants
Recovered
TO -91700
078
Flash Tank: Recycled to Plant Inlet
VOC and
HAP
COLORADO
Aix Pollution Control Division
7
Page 4 of 31
g maxi _ m processing rates as listed below. Monthly
hall be m e' tained by the owner or operator and made
on req . =„t.= (Regulation Number 3, Part B, II.A.4.)
Process Limits
Facility
Equipment
ID
AIRS
Point
Process Parameter
Annual Limit
Monthly Limit
(31 days)
H-80100
075
Consumption of Natural
Gas as a fuel
472.4 MMscf/yr
40.1 MMscf/mOnth
H-31711
076
Consumption of Natural
Gas as a fuel
130.8 MMscf/yr
11.1 MMscf/month
H-32711
077
Consumption of Natural
Gas as a fuel
130.8 MMscf/yr
11.1 MMscf/month
TO -91700
078
Natural Gas Throughput
55,845 MMscf/yr
4,743 MMscf/month
Still Vent Waste Gas
Routed to Thermal
Oxidizer
2,796.0 MMscf/yr
237.5 MMscf/month
Combustion of
supplemental fuel and
pilot fuel at Thermal
Oxidizer
222.5 MMscf/yr
18.9 MMscf/month
FL -90100
079
Natural gas combustion -
Process and Purge Gas
86.7 MMscf/yr
7.4 MMscf/month
The owner or operator shall monitor monthly process rates based on the calendar month.
During the first twelve (12) months of operation, compliance with both the monthly and annual
throughput limitations is required. After the first twelve (12) months of operation, compliance
with only the annual limitation is required.
Compliance with the annual throughput limits shall be determined on a rolling twelve (12) month
total. By the end of each month a new twelve-month total is calculated based on the previous
twelve months' data. The permit holder shall calculate throughput each month and keep a
compliance record on site or at a local field office with site responsibility, for Division review.
13. Points 075, 076 and 077: The owner or operator shall install, operate, and maintain an
operational non-resettable elapsed flow meter for each heater. The flow rate of the fuel
combusted in these natural gas -fired combustion emission units shall be measured and recorded
using an operational non-resettable elapsed flow meter at each inlet. The owner or operator
shall use monthly throughput records to demonstrate compliance with the process limits
contained in this permit and to calculate emissions as described in this permit.
14. Point 078: The volume of gas processed for each contactor tower shall be measured by gas
meter. Total actual volume of natural gas processed shall be the summed total of the individually
metered gas flows for each amine contactor tower. The owner or operator shall use monthly
throughput records to demonstrate compliance with the process limits contained in this
permit and to calculate emissions as described in this permit.
15. Point 078: This unit shall be limited to the maximum lean amine recirculation rate of 600 gallons
per minute each. The lean amine recirculation rate shall be the summed total of the individually
metered amine recirculation rates recorded for each amine contactor. The lean amine
recirculation rate for each unit shall be recorded daily in a log maintained on site and made
available to the Division for inspection upon request. Lean amine recirculation rate shall be
monitored by using amine flow meter. (Reference: Regulation No. 3, Part B, II.A.4).
COLORADO
it Pollution Control Division
Alit; n txn s Ermlompm
Page 5 of 31
16. oint I t • : � � ekly b�: $ ;he ow • opera �eQ shall monitor and record operational values
sure and inlet gas to each amine contactor
aintained for a period of five years.
17. fle wasvented from the amine unit still vent shall
be measured and recorded using an operational non-resettable elapsed flow meter. The owner
or operator shall use monthly throughput records to demonstrate compliance with the process
limits contained in this permit and to calculate emissions as described in this permit.
18. Point 078: The volumetric flow rate of the gas combusted for supplemental fuel (auxiliary) gas
and fuel to the thermal oxidizer burner shall be measured and recorded using an operational
non-resettable elapsed flow meter. The owner or operator shall use monthly throughput records
to demonstrate compliance with the process limits contained in this permit and to calculate
emissions as described in this permit.
19. Point 079: The owner or operator shall install, operate, and maintain an operational non-
resettable elapsed flow meter for the flare to monitor and record the volume of process gas and
purge gas routed to the flare. The owner or operator shall use monthly throughput records to
demonstrate compliance with the process limits contained in this permit and to calculate
emissions as described in this permit.
STATE AND FEDERAL REGULATORY REQUIREMENTS
20. The requirements of Colorado Regulation No. 3, Part D shall apply at such time that any
stationary source or modification becomes a major stationary source or major modification solely
by virtue of a relaxation in any enforceable limitation that was established after August 7, 1980,
on the capacity of the source or modification to otherwise emit a pollutant such as a restriction
on hours of operation (Colorado Regulation No. 3, Part D, Sections V.A.7.B and VI.B.4).
With respect to this Condition, Part D requirements may apply to future modifications if current
emission limits for the following emission units are modified to equal or exceed the following
threshold levels. Increases in permit limits for any of these emissions units will require
evaluation of the original project net emissions increase to ensure the significant modification
thresholds are not exceeded:
Facility
Equipment
ID
AIRS
Point
Equipment
Descri lion
p
PollutantCurrent
Emissions - tons per year
Significant
Modification
Threshold
permit limit
H-3
074
10 MMbtu/hr
heater Inlet H2S
Heater for Train
1 lt2
(17WE0826.XP)
NOx
VOC
CO
PM2.5
S02
40
40
100
10
40
38.5
13.6
46.4
4.8
25.7
H-1
NA
5 MMbtu/hr
Condensate
stabilizer heater
H-80100
075
55 MMbtu/hr
amine
regeneration
heater
H-31711
076
18.4 MMbtu/hr
molecular sieve
regeneration
heater
COLORADO
Aix Pollution Control Division
Platt_ E.rw.tegvro.wt.
Page 6 of 31
11
4MMR
ecula .ie e
r"eneraion
TO -91700
078
153 MMscfd
Amine Unit
FL -90100
079
Process Flare
H-2
081
6 MMbtu/hr
heater Inlet H2S
Heater for Train
3 (17WE1060.XP)
GEN-4
082
839 bhp Diesel
Emergency
Generator
(17WE1061.XP)
1: Values listed represent the sum of all individual limits for equipment listed in the table.
21. This facility is located in an ozone non -attainment or attainment -maintenance area and subject
to the Reasonably Available Control Technology (RACT) requirements of Regulation Number 3,
Part B, III.D.2.a.:
Facility
Equipment
ID
AIRS
Point
RACT
Pollutants
H-31711
076
H 32711
077
Natural gas as fuel, low NOx burners, good
combustion practices
NOx, VOC
TO -91700
078
Routing amine still vent gas to a thermal oxidizer
VOC
TO -91700
078
Recycling flash tank gas to plant inlet
VOC
FL 90100
079
Installing flare and operating according to 40 CFR
60.18
VOC
FUG4
071
Implementing LDAR program as specified in 40
CFR Part 60 Subpart 0000a
VOC
22. Points 075-079: The permit number and ten digit AIRS ID number assigned by the Division (e.g.
123/4567/001) shall be marked on the subject equipment for ease of identification. (Regulation
Number 3, Part B, Section III.E.) (State only enforceable)
23. Visible emissions shall not exceed twenty percent (20%) opacity during normal operation of the
source. During periods of startup, process modification, or adjustment of control equipment
visible emissions shall not exceed 30% opacity for more than six minutes in any sixty consecutive
minutes. (Reference: Regulation No. 1, Section II.A.1. £t 4.)
24. This source is subject to the odor requirements of Regulation Number 2. (State only enforceable)
25. Points 075-077: Each heater is subject to the Particulate Matter Emission Regulations of
Regulation 1 and Regulation 6, including, but not limited to, the following:
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Pollution Control Division
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Page 7 of 31
to be emitted into the atmosphere from any
in the flue gases which exceeds the following
Fo rni nt wit ned heat inputs greater than 1x106 BTU
per hour, but less than or equal to 500x106 BTU per hour, the following
equation will be used to determine the allowable particulate emission
limitation.
PE=0.5(FI)-0.26
Where:
PE = Particulate Emission in Pounds per million BTU heat input.
Fl = Fuel Input in Million BTU per hour (Regulation 1, Section III.A.1.b and
Regulation 6, Part B, Section II.C.2).
(ii) Greater than 20 percent opacity (Regulation 6, Part B, Section II.C.3).
26. Points 075-077: Each heater is subject to the requirements of Regulation No. 6, Part A,
Subpart A, General Provisions, including, but not limited to, the following:
a. At all times, including periods of start-up, shutdown, and malfunction, the facility and
control equipment shall, to the extent practicable, be maintained and operated in a
manner consistent with good air pollution control practices for minimizing emissions.
Determination of whether or not acceptable operating and maintenance procedures are
being used will be based on information available to the Division, which may include, but
is not limited to, monitoring results, opacity observations, review of operating and
maintenance procedures, and inspection of the source. (Reference: Regulation No. 6,
Part A. General Provisions from 40 CFR 60.11)
b. No article, machine, equipment or process shall be used to conceal an emission which
would otherwise constitute a violation of an applicable standard. Such concealment
includes, but is not limited to, the use of gaseous diluents to achieve compliance with
an opacity standard or with a standard which is based on the concentration of a pollutant
in the gases discharged to the atmosphere. (5 60.12)
c. Written notification of construction and initial startup dates shall be submitted to the
Division as required under S 60.7.
d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under
§ 60.7.
e. Performance tests, if required, shall be conducted as required under §60.8.
27. Points 075-077: Each heater is subject to the New Source Performance Standards requirements
of Regulation No. 6, Part A Subpart Dc, Standards of Performance for Small Industrial -
Commercial -Institutional Steam Generating Units including, but not limited to, the following:
o § 60.48c(g)(2) As an alternative to meeting the requirements of paragraph (g)(1) of
this section, the owner or operator of an affected facility that combusts only natural
gas, wood, fuels using fuel certification in §60.48c(f) to demonstrate compliance
with the S02 standard, fuels not subject to an emissions standard (excluding
opacity), or a mixture of these fuels may elect to record and maintain records of the
amount of each fuel combusted during each calendar month.
o § 60.48c(i) All records required under this section shall be maintained by the owner
or operator of the affected facility for a period of two years following the date of
such record.
28. Points 075-077: Each heater is subject to the National Emissions Standards for Hazardous Air
Pollutants requirements of Regulation No. 8, Part E, Subpart DDDDD (40 CFR Part 63, Subpart
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cial, stituti. =:l Boilers and Process Heaters including, but
have • co ly with th subpart?
(a) If you have a new or reconstructed boiler or process heater, you must comply
with this subpart by April 1, 2013, or upon startup of your boiler or process heater,
whichever is later.
o (d) You must meet the notification requirements in §63.7545 according to the
schedule in §63.7545 and in subpart A of this part. Some of the notifications must be
submitted before you are required to comply with the emission limits and work
practice standards in this subpart.
• S 63.7500 What emission limitations, work practice standards, and operating limits must
I meet?
o (e) Boilers and process heaters in the units designed to burn gas 1 fuels subcategory
with a heat input capacity of less than or equal to 5 million Btu per hour must
complete a tune-up every 5 years as specified in §63.7540. Boilers and process
heaters in the units designed to burn gas 1 fuels subcategory with a heat input
capacity greater than 5 million Btu per hour and less than 10 million Btu per hour
must complete a tune-up every 2 years as specified in §63.7540. Boilers and process
heaters in the units designed to burn gas 1 fuels subcategory are not subject to the
emission limits in Tables 1 and 2 or 11 through 13 to this subpart, or the operating
limits in Table 4 to this subpart.
This unit is a new boiler or process heater in the units designed to burn gas 1 fuels
subcategory. The work practice standards in Table 3 that apply to this unit are as
follows:
• Conduct a tune-up of the boiler or process heater annually as specified in
§617540. Units in either the Gas 1 or Metal Process Furnace subcategories will
conduct this tune-up as a work practice for all regulated emissions under this
subpart. Units in all other subcategories will conduct this tune-up as a work
practice for dioxins/furans. (Table 3 to Subpart DDDDD, Item 3).
• Must have a one-time energy assessment performed by a qualified energy
assessor. An energy assessment completed on or after January 1, 2008, that
meets or is amended to meet the energy assessment requirements in this table,
satisfies the energy assessment requirement. A facility that operated under an
energy management program developed according to the ENERGY STAR
guidelines for energy management or compatible with ISO 50001 for at least one
year between January 1, 2008 and the compliance date specified in §63.7495
that includes the affected units also satisfies the energy assessment
requirement. The energy assessment must include the following with extent of
the evaluation for items a. to e. appropriate for the on -site technical hours listed
in §63.7575 (table 3 to Subpart DDDDD, Item 4):
o A visual inspection of the boiler or process heater system (Table 3 to
Subpart DDDD, Item 4.a).
o An evaluation of operating characteristics of the boiler or process heater
systems, specifications of energy using systems, operating and
maintenance procedures, and unusual operating constraints (Table 3 to
Subpart DDDDD, Item 4.b).
o An inventory of major energy use systems consuming energy from
affected boilers and process heaters and which are under the control of
the boiler/process heater owner/operator (Table 3 to Subpart DDDDD,
Item 4.c).
COLORADO
Air Pollution Control Division
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able a" hitectural and engineering plans, facility
tenan procedures and logs, and fuel usage (Table
DDD, Item! .d).
rev facili ergy management program and provide
recommendations for improvements consistent with the definition of
energy management program, if identified (Table 3 to Subpart DDDDD,
Item 4.e).
o A list of cost-effective energy conservation measures that are within the
facility's control (Table 3 to Subpart DDDDD, Item 4.f).
o A list of the energy savings potential of the energy conservation
measures identified (Table 3 to Subpart DDDDD, Item 4.g).
o A comprehensive report detailing the ways to improve efficiency, the
cost of specific improvements, benefits, and the time frame for
recouping those investments (Table 3 to Subpart DDDDD, Item 4.h).
• S 63.7505 What are my general requirements for complying with this subpart?
o (a) You must be in compliance with the emission limits, work practice standards, and
operating limits in this subpart. These emission and operating limits apply to you at
all times the affected unit is operating except for the periods noted in 563.7500(f).
• S 63.7510 What are my initial compliance requirements and by what date must I conduct
them?
o (g) For new or reconstructed affected sources (as defined in §63.7490), you must
demonstrate initial compliance with the applicable work practice standards in Table
3 to this subpart within the applicable annual, biennial, or 5 -year schedule as
specified in 563.7515(d) following the initial compliance date specified in
§63.7495(a). Thereafter, you are required to complete the applicable annual,
biennial, or 5 -year tune-up as specified in 563.7515(d).
• § 63.7515 When must I conduct subsequent performance tests, fuel analyses, or tune-
ups?
o (d) If you are required to meet an applicable tune-up work practice standard, you
must conduct an annual, biennial, or 5 -year performance tune-up according to
§63.7540(a)(10), (11), or (12), respectively. Each annual tune-up specified in
563.7540(a)(10) must be no more than 13 months after the previous tune-up. Each
biennial tune-up specified in §63.7540(a)(11) must be conducted no more than 25
months after the previous tune-up. Each 5 -year tune-up specified in §63.7540(a)(12)
must be conducted no more than 61 months after the previous tune-up. For a new
or reconstructed affected source (as defined in §63.7490), the first annual, biennial,
or 5 -year tune-up must be no later than 13 months, 25 months, or 61 months,
respectively, after April 1, 2013 or the initial startup of the new or reconstructed
affected source, whichever is later.
• S 63.7530 How do I demonstrate initial compliance with the emission limitations, fuel
specifications and work practice standards?
o (e) You must include with the Notification of Compliance Status a signed certification
that either the energy assessment was completed according to Table 3 to this
subpart, and that the assessment is an accurate depiction of your facility at the time
of the assessment, or that the maximum number of on -site technical hours specified
in the definition of energy assessment applicable to the facility has been expended.
o (f) You must submit the Notification of Compliance Status containing the results of
the initial compliance demonstration according to the requirements in §63.7545(e).
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do I strat _ • ' tinuou-=. compliance with the emission limitations,
ions a k pra a standa s?
(a) You must demonstrate continuous compliance with the work practice standards
in Table 3 to this subpart that applies to you according to the methods specified in
Table 8 to this subpart and paragraphs (a)(1) through (19) of this section.
o (a)(10) If your boiler or process heater has a heat input capacity of 10 million Btu
per hour or greater, you must conduct an annual tune-up of the boiler or process
heater to demonstrate continuous compliance as specified in paragraphs (a)(10)(i)
through (vi) of this section. You must conduct the tune-up while burning the type of
fuel (or fuels in case of units that routinely burn a mixture) that provided the
majority of the heat input to the boiler or process heater over the 12 months prior
to the tune-up. This frequency does not apply to limited -use boilers and process
heaters, as defined in §63.7575, or units with continuous oxygen trim systems that
maintain an optimum air to fuel ratio.
• (i) As applicable, inspect the burner, and clean or replace any components
of the burner as necessary (you may perform the burner inspection any time
prior to the tune-up or delay the burner inspection until the next scheduled
unit shutdown). Units that produce electricity for sale may delay the burner
inspection until the first outage, not to exceed 36 months from the previous
inspection. At units where entry into a piece of process equipment or into a
storage vessel is required to complete the tune-up inspections, inspections
are required only during planned entries into the storage vessel or process
equipment;
• (ii) Inspect the flame pattern, as applicable, and adjust the burner as
necessary to optimize the flame pattern. The adjustment should be
consistent with the manufacturer's specifications, if available;
• (iii) Inspect the system controlling the air -to -fuel ratio, as applicable, and
ensure that it is correctly calibrated and functioning properly (you may delay
the inspection until the next scheduled unit shutdown). Units that produce
electricity for sale may delay the inspection until the first outage, not to
exceed 36 months from the previous inspection;
• (iv) Optimize total emissions of CO. This optimization should be consistent
with the manufacturer's specifications, if available, and with any
NOx requirement to which the unit is subject;
• (v) Measure the concentrations in the effluent stream of CO in parts per
million, by volume, and oxygen in volume percent, before and after the
adjustments are made (measurements may be either on a dry or wet basis,
as long as it is the same basis before and after the adjustments are made).
Measurements may be taken using a portable CO analyzer; and
• (vi) Maintain on -site and submit, if requested by the Administrator, a report
containing the information in paragraphs (a)(10)(vi)(A) through (C) of this
section,
• (A) The concentrations of CO in the effluent stream in parts per
million by volume, and oxygen in volume percent, measured at high
fire or typical operating load, before and after the tune-up of the
boiler or process heater;
• (B) A description of any corrective actions taken as a part of the
tune-up; and
COLORADO
Air Pollution Control Division
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Page 11 of 31
t of fuel used over the 12 months prior to
the unit was physically and legally capable
ype of fuel during that period. Units sharing
to the fuel used by each unit.
o (a)(13) If the unit is not operating on the required date for a tune-up, the tune-up
must be conducted within 30 calendar days of startup.
• S 63.7545 What notifications must I submit and when?
o (a) You must submit to the Administrator all of the notifications in §563.7(b) and (c),
63.8(e), (f)(4) and (6), and 63.9(b) through (h) that apply to you by the dates
specified.
o (c) As specified in §63.9(b)(4) and (5), if you startup your new or reconstructed
affected source on or after January 31, 2013, you must submit an Initial Notification
not later than 15 days after the actual date of startup of the affected source.
o (e) If you are required to conduct an initial compliance demonstration as specified
in §63.7530, you must submit a Notification of Compliance Status according to
§63.9(h)(2)(ii). For the initial compliance demonstration for each boiler or process
heater, you must submit the Notification of Compliance Status, including all
performance test results and fuel analyses, before the close of business on the 60th
day following the completion of all performance test and/or other initial compliance
demonstrations for all boiler or process heaters at the facility according to
§63.10(d)(2). The Notification of Compliance Status report must contain all the
information specified in paragraphs (e)(1) through (8) of this section, as applicable.
If you are not required to conduct an initial compliance demonstration as specified
in §63.7530(a), the Notification of Compliance Status must only contain the
information specified in paragraphs (e)(1) and (8) of this section and must be
submitted within 60 days of the compliance date specified at §63.7495(b).
o (e)(1) A description of the affected unit(s) including identification of which
subcategories the unit is in, the design heat input capacity of the unit, a description
of the add-on controls used on the unit to comply with this subpart, description of
the fuel(s) burned, including whether the fuel(s) were a secondary material
determined by you or the EPA through a petition process to be a non -waste under
§241.3 of this chapter, whether the fuel(s) were a secondary material processed from
discarded non -hazardous secondary materials within the meaning of §241.3 of this
chapter, and justification for the selection of fuel(s) burned during the compliance
demonstration.
o (e) (6) A signed certification that you have met all applicable emission limits and
work practice standards.
o (e) (7) If you had a deviation from any emission limit, work practice standard, or
operating limit, you must also submit a description of the deviation, the duration of
the deviation, and the corrective action taken in the Notification of Compliance
Status report.
o (e) (8) In addition to the information required in §63.9(h)(2), your notification of
compliance status must include the following certification(s) of compliance, as
applicable, and signed by a responsible official:
• (i) "This facility completed the required initial tune-up for all of the boilers
and process heaters covered by 40 CFR part 63 subpart DDDDD at this site
according to the procedures in §63.7540(a)(10)(i) through (vi)."
• (ii) "This facility has had an energy assessment performed according to
§63.7530(e)."
COLORADO
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ly natural gas, refinery gas, or other gas 1
statutory exemption as provided in section
clude the following: "No secondary materials
sted in any affected unit."
• 5 63.7545 What reports must I submit and when?
o (a) You must submit each report in Table 9 to this subpart that applies to you.
o (b) For units that are subject only to a requirement to conduct subsequent annual,
biennial, or 5 -year tune-up according to 563.7540(a)(10), (11), or (12), respectively,
and not subject to emission limits or Table 4 operating limits, you may submit only
an annual, biennial, or 5 -year compliance report, as applicable, as specified in
paragraphs (b)(1) through (4) of this section, instead of a semi-annual compliance
report.
o (c) A compliance report must contain the following information depending on how
the facility chooses to comply with the limits set in this rule.
o (c) (1) If the facility is subject to the requirements of a tune up you must submit a
compliance report with the information in paragraphs (c)(5)(i) through (iii) of this
section, (xiv) and (xvii) of this section, and paragraph (c)(5)(iv) of this section for
limited -use boiler or process heater.
o (h)(3) You must submit all reports required by Table 9 of this subpart electronically
to the EPA via the CEDRI. (CEDRI can be accessed through the EPA's CDX.) You must
use the appropriate electronic report in CEDRI for this subpart. Instead of using the
electronic report in CEDRI for this subpart, you may submit an alternate electronic
file consistent with the XML schema listed on the CEDRI Web site
(http://www.epa.gov/ttn/chief/cedri/index.html), once the XML schema is
available. If the reporting form specific to this subpart is not available in CEDRI at
the time that the report is due, you must submit the report to the Administrator at
the appropriate address listed in 563.13. You must begin submitting reports via CEDRI
no later than 90 days after the form becomes available in CEDRI.
• § 63.7555 What records must I keep?
o (a) You must keep records according to paragraphs (a)(1) and (2) of this section.
o (a)(1) A copy of each notification and report that you submitted to comply with this
subpart, including all documentation supporting any Initial Notification or
Notification of Compliance Status or semiannual compliance report that you
submitted, according to the requirements in 563.10(b)(2)(xiv).
o (a)(2) Records of performance tests, fuel analyses, or other compliance
demonstrations and performance evaluations as required in 563.10(b)(2)(viii).
• § 63.7560 In what form and how long must I keep my records?
o (a) Your records must be in a form suitable and readily available for expeditious
review, according to 563.10(b)(1).
o (b) As specified in 563.10(b)(1), you must keep each record for 5 years following the
date of each occurrence, measurement, maintenance, corrective action, report, or
record.
o (c) You must keep each record on site, or they must be accessible from on site (for
example, through a computer network), for at least 2 years after the date of each
occurrence, measurement, maintenance, corrective action, report, or record,
according to §63.10(b)(1). You can keep the records off site for the remaining 3
years.
COLORADO
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29. �oint • 5: rce i ect to�. lation r mber 7, Section XVI.D. The operator shall
I including but not limited to:
his Sectio I.D. applies to the following combustion
uipmissiNOx equal to or greater than five (5) tons
per year, and that are located at existing major sources of NOx, as listed in Section XIX.A.
• XVI.D.2. Combustion process adjustment
o XVI.D.2.a. When burning the fuel that provides the majority of the heat input since
the last combustion process adjustment and when operating at a firing rate typical
of normal operation, the owner or operator must conduct the following inspections
and adjustments of boilers and process heaters, as applicable:
• XVI.D.2.a.(i) Inspect the burner and combustion controls and clean or
replace components as necessary.
• XVI.D.2.a.(ii) Inspect the flame pattern and adjust the burner or combustion
controls as necessary to optimize the flame pattern.
• XVI.D.2.a.(iii) Inspect the system controlling the air -to -fuel ratio and ensure
that it is correctly calibrated and functioning properly.
• XVI.D.2.a.(iv) Measure the concentration in the effluent stream of carbon
monoxide and nitrogen oxide in ppm, by volume, before and after the
adjustments in Sections XVI.D.2.a.(i)-(iii). Measurements may be taken using
a portable analyzer.
o XVI.D.2.e. The owner or operator must operate and maintain the boiler, duct burner,
process heater, stationary combustion turbine, or stationary internal combustion
engine consistent with manufacturer's specifications, if available, or good
engineering and maintenance practices.
o XVI.D.2.f. Frequency
• XVI.D.2.f.(i) The owner or operator must conduct the initial combustion
process adjustment by April 1, 2017. An owner or operator may rely on a
combustion process adjustment conducted in accordance with applicable
requirements and schedule of a New Source Performance Standard in 40 CFR
Part 60 or National Emission. Standard for Hazardous Air Pollutants in 40 CFR
Part 63 to satisfy the requirement to conduct an initial combustion process
adjustment by April 1, 2017.
XVI.D.2.f.(ii) The owner or operator must conduct subsequent combustion
process adjustments at least once every twelve (12) months after the initial
combustion adjustment, or on the applicable schedule according to Sections
XVI.D.4.a. or XVI.D.4.b.
• XVI.D.3. Recordkeeping
o XVI.D.3.a. The owner or operator must create a report once every calendar year
identifying the combustion equipment at the facility subject to Section XVI.D. and
including for each combustion equipment:
• XVI.D.3.a.(i) The date of the adjustment;
• XVI.D.3.a.(ii) Whether the combustion process adjustment under Sections
XVI.D.2.a.-e. was followed, and what procedures were performed;
• XVI.D.3.a.(iii) Whether a combustion process adjustment under.XVI.D.4.a.-
b.. was followed, what procedures were performed, and what New Source
Performance Standard or National Emission Standard for Hazardous Air
Pollutants applied, if any; and
COLORADO
Aiz Pollution Control Division
Page 14 of 31
ny corrective action taken.
ner o ' operator conducts the combustion process
ng to the anufacturer recommended procedures and
nufact •ecifies a combustion process adjustment
on an operation time schedule, the hours of operation.
• XVI.D.3.a.(vi) If multiple fuels are used, the type of fuel burned and heat
input provided by each fuel.
o XVI.D.3.b. The owner or operator must retain manufacturer recommended
procedures, specifications, and maintenance schedule if utilized under Section
XVI.D.4.a. for the life of the equipment, and make available to the Division upon
request.
o XVI.D.3.c. The owner or operator must retain annual reports for at least 5 years,
and make available to the Division upon request.
• XVI.D.4. As an alternative to the requirements described in Sections XVI.D.2.a.-e. and
XVI.D.3.a.:
o XVI.D.4.a. The owner or operator may conduct the combustion process adjustment
according to the manufacturer recommended procedures and schedule; or
o XVI.D.4.b. The owner or operator of combustion equipment that is subject to and
required to conduct a period tune-up or combustion adjustment by the applicable
requirements of a New Source Performance Standard in 40 CFR Part 60 or National
Emission Standard for Hazardous Air Pollutants in 40 CFR Part 63 may conduct tune-
ups or adjustments according to the schedule and procedures of the applicable
requirements of 40 CFR Part 60 or 40 CFR Part 63.
o XVI.D.4.c. The owner or operator may comply with applicable recordkeeping
requirements related to combustion process adjustments conducted according to a
New Source Performance Standard in 40 CFR Part 60 or National Emission Standard
for Hazardous Air Pollutants in 40 CFR Part 63.
30. Point 079: The flare shall be air -assisted and shall be designed and operated in accordance with
40 CFR 60.18 including, but not limited to, the following:
• §60.18(b) Flares. Paragraphs (c) through (f) apply to flares.
• §60.18(c)(1) Flares shall be designed for and operated with no visible emissions as
determined by the methods specified in paragraph (f), except for periods not to exceed
a total of 5 minutes during any 2 consecutive hours.
• §60.18(c)(2) Flares shall be operated with a flame present at all times, as determined
by the methods specified in paragraph (f).
• §60.18(c)(3) An owner/operator has the choice of adhering to either the heat content
specifications in paragraph (c)(3)(ii) of this section and the maximum tip velocity
specifications in paragraph (c)(4) of this section, or adhering to the requirements in
paragraph (c)(3)(i) of this section.
o §60.18(c)(3)(i)(A) Flares shall be used that have a diameter of 3 inches or greater,
are nonassisted, have a hydrogen content of 8.0 percent (by volume), or greater,
and are designed for and operated with an exit velocity less than 37.2 m/sec (122
ft/sec) and less than the velocity, Vmax, as determined by the following equation:
Vmax = (XH2-K1)* K2
Where:
Vmax = Maximum permitted velocity, m/sec.
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Page 15 of 31
olume
/sec)
2 = vol ,,; e -percent
sing t Am can Soci
946- I ok :orate
ercent hydrogen.
olume-percent hydrogen.
f hydrogen, on a wet basis, as calculated by
for Testing and Materials (ASTM) Method
ference as specified in §60.17).
o §60.18(c)(3)(i)(B) The actual exit velocity of a flare shall be determined by the
method specified in paragraph (f)(4) of this section.
o §60.18(c)(3)(ii) Flares shall be used only with the net heating value of the gas being
combusted being 11.2 MJ/scm (300 Btu/scf) or greater if the flare is steam -assisted
or air -assisted; or with the net heating value of the gas being combusted being 7.45
MJ/scm (200 Btu/scf) or greater if the flare is nonassisted. The net heating value
of the gas being combusted shall be determined by the methods specified in
paragraph (f)(3) of this section.
• §60.18(c)(5) Air -assisted flares shall be designed and operated with an exit velocity less
than the velocity, Vmax, as determined by the method specified in paragraph (f)(6).
• §60.18(c)(6) Flares used to comply with this section shall be steam -assisted, air -assisted,
or nonassisted.
• §60.18(d) Owners or operators of flares used to comply with the provisions of this subpart
shall monitor these control devices to ensure that they are operated and maintained in
conformance with their designs. Applicable subparts will provide provisions stating how
owners or operators of flares shall monitor these control devices.
• §60.18(e) Flares used to comply with provisions of this subpart shall be operated at all
times when emissions may be vented to them.
• §60.18(f)(1) Method 22 of appendix A to this part shall be used to determine the
compliance of flares with the visible emission provisions of this subpart. The observation
period is 2 hours and shall be used according to Method 22.
• §60.18(f)(2) The presence of a flare pilot flame shall be monitored using a thermocouple
or any other equivalent device to detect the presence of a flame.
• §60.18(f)(3) The net heating value of the gas being combusted in a flare shall be
calculated using the following equation:
n.
HT K E C1
H1
f1
Where:
HT = Net heating value of the sample, MJ/scm; where the net enthalpy per mole of
offgas is based on combustion at 25 °C and 760 mm Hg, but the standard temperature
for determining the volume corresponding to one mole is 20 °C;
Constant, 1 t q mole. MJ
1.740 x f0'" (,ppm' scar, } {Eca f
where the standard temperature for lg mole} is 20*C;
scm
C; = Concentration of sample component i in ppm on a wet basis, as measured for
organics by Reference Method 18 and measured for hydrogen and carbon monoxide
by ASTM D1946-77 or 90 (Reapproved 1994) (Incorporated by reference as specified
in §60.17); and
H; = Net heat of combustion of sample component i, kcal/g mole at 25 °C and 760
mm Hg. The heats of combustion may be determined using ASTM D2382-76 or 88 or
COLORADO
Air Pollution Control Division
Lira t€ Ant.. Rthiz 1imWhhbE rOr ter.{
Page 16 of 31
rence specified in §60.17) if published values are
fated.
actu elocity of flare shall be determined by dividing the
vo „.ri _: ,F,mk e (l F:_ tandar. °# .=R perature and pressure), as determined by
Reference Methods 2, 2A, 2C, or 2D as appropriate; by the unobstructed (free) cross
sectional area of the flare tip.
• $60.18(f)(5) The maximum permitted velocity, Vmax, for flares complying with
paragraph (c)(4)(iii) shall be determined by the following equation.
Logic) (Vmax)=(HT+28.8)/31.7
Vmax = Maximum permitted velocity, M/sec
28.8=Constant
31.7=Constant
HT = The net heating value as determined in paragraph (f)(3).
• §60.18(f)(6) The maximum permitted velocity, Vmax, for air -assisted flares shall be
determined by the following equation.
Vmax = 8.706+0.7084 (HT)
Vmax = Maximum permitted velocity, m/sec
8.706=Constant
0.7084=Constant
HT = The net heating value as determined in paragraph (f)(3).
31. Point 080: This source is subject to the requirements of 40 CFR, Part 63, Subpart HH - National
Emission Standards for Hazardous Air Pollutants for Source Categories from Oil and Natural Gas
Production Facilities including, but not limited to, the following:
• 863.769 - Equipment leak standards.
o (a) This section applies to equipment subject to this subpart and specified in
paragraphs (a)(1) and (2) of this section that is located at a natural gas processing
plant and operates in VHAP service equal to or greater than 300 hours per calendar
year.
• (1) Ancillary equipment, as defined in §63.761; and
• (2) Compressors.
o (b) This section does not apply to ancillary equipment and compressors for which the
owner or operator is subject to and controlled under the requirements specified in
40 CFR part 60, subpart OOOO. Ancillary equipment and compressors subject to and
controlled under 40 CFR part 60, subpart OOOO shall submit the periodic reports
specified in §63.775(e).
o (c) For each piece of ancillary equipment and each compressor subject to this section
located at an existing or new source, the owner or operator shall meet the
requirements specified in 40 CFR part 61, subpart V, §S61.241 through 61.247, except
as specified in paragraphs (c)(1) through (8) of this section, except that for valves
subject to §61.242-7(b) or 561.243-1, a leak is detected if an instrument reading of
500 ppm or greater is measured. A leak detected from a valve at a source constructed
on or before August 23, 2011 shall be repaired in accordance with the schedule in
§61.242-7(d), or by October 15, 2013, whichever is later. A leak detected from a
.=COLORAtO
Air Pollution. Control Division
Page 17 of 31
valve at a source constructed after August 23, 2011 shall be repaired in accordance
with the schedule in §61.242-7(d), or by October 15, 2012, whichever is later.
• (1) Each pressure relief device in gas/vapor service shall be monitored
quarterly and within 5 days after each pressure release to detect leaks,
except under the following conditions.
• (i) The owner or operator has obtained permission from the
Administrator to use an alternative means of emission limitation that
achieves a reduction in emissions of VHAP at least equivalent to that
achieved by the control required in this subpart.
• (ii) The pressure relief device is located in a nonfractionating facility
that is monitored only by non -facility personnel, it may be monitored
after a pressure release the next time the monitoring personnel are
on site, instead of within 5 days. Such a pressure relief device shall
not be allowed to operate for more than 30 days after a pressure
release without monitoring.
• (2) For pressure relief devices, if an instrument reading of 10,000 parts per
million or greater is measured, a leak is detected.
• (3) For pressure relief devices, when a leak is detected, it shall be repaired
as soon as practicable, but no later than 15 calendar days after it is detected,
unless a delay in repair of equipment is granted under 40 CFR 61.242-10.
• (4) Sampling connection systems are exempt from the requirements of 40
CFR 61.242-5.
• (5) Pumps in VHAP service, valves in gas/vapor and light liquid service, and
pressure relief devices in gas/vapor service that are located at a
nonfractionating plant that does not have the design capacity to process
283,000 standard cubic meters per day or more of field gas are exempt from
the routine monitoring requirements of 40 CFR 61.242-2(a)(1) and 61.242-
7(a), and paragraphs (c)(1) through (3) of this section.
(6) Pumps in VHAP service, valves in gas/vapor and light liquid service, and
pressure relief devices in gas/vapor service located within a natural gas
processing plant that is located on the Alaskan North Slope are exempt from
the routine monitoring requirements of 40 CFR 61.242-2(a)(1) and 61.242-
7(a), and paragraphs (c)(1) through (3) of this section.
(7) Reciprocating compressors in wet gas service are exempt from the
compressor control requirements of 40 CFR 61.242-3.
(8) Flares, as defined in §63.761, used to comply with this subpart shall
comply with the requirements of §63.11(b).
• §63.772 Test methods, compliance procedures, and compliance demonstrations.
o (a) Determination of material VHAP or HAP concentration to determine the
applicability of the equipment leak standards under this subpart (§63.769). Each
piece of ancillary equipment and compressors are presumed to be in VHAP service or
in wet gas service unless an owner or operator demonstrates that the piece of
equipment is not in VHAP service or in wet gas service.
• (1) For a piece of ancillary equipment and compressors to be considered not
in VHAP service, it must be determined that the percent VHAP content can
be reasonably expected never to exceed 10.0 percent by weight. For the
purposes of determining the percent VHAP content of the process fluid that
COLORADO
Air lots₹₹Ution Control Division
Page 18 of 31
is contained in or contacts a piece of ancillary equipment or compressor, you
shall use the method in either 63.772 (a)(1)(i) or paragraph 63.772 (a)(1)(ii).
(2) For a piece of ancillary equipment and compressors to be considered in
wet gas service, it must be determined that it contains or contacts the field
gas before the extraction of natural gas liquids.
• §63.774 - Recordkeeping Requirements.
o §63.774(b) - Each owner or operator of a facility subject to this subpart shall
maintain the records specified in §63.774(b).
• §63.775 - Reporting Requirements.
o §63.775(b) - Each owner or operator of a major source subject to this subpart shall
submit the information listed in 563.775(b).
o §63.775(d) - Each owner or operator of a source subject to this subpart shall submit
a Notification of Compliance Status Report as required under §63.9(h) within 180
days after the compliance date specified in §63.760(f). In addition to the information
required under §63.9(h), the Notification of Compliance Status Report shall include
the information specified in §63.775(d).
o §63.775(e) - An owner or operator of a major source shall prepare Periodic Reports
in accordance with paragraphs §63.775(e)(1) and (2) and submit them to the
Administrator.
o §63.775(f) - Whenever a process change is made, or a change in any of the
information submitted in the Notification of Compliance Status Report, the owner or
operator shall submit a report within 180 days after the process change is made or
as a part of the next Periodic Report as required under §63.775(e), whichever is
sooner. The report shall include the information specified in §63.775(f).
32. Point 080: This source is subject to Regulation No. 7, Section XII.G.1 (State only enforceable).
For fugitive VOC emissions from leaking equipment, the leak detection and repair (LDAR) program
as provided at 40 CFR Part 60, Subpart KKK (July 1, 2016) shall apply, regardless of the date of
construction of the affected facility, unless subject to applicable LDAR program as provided at
40 CFR Part 60, Subparts 0000 or 0000a (July 1, 2016).The operator shall comply with all
applicable requirements of Section XII.
OPERATING Et MAINTENANCE REQUIREMENTS
33. Point 078 and 079: Upon startup of these points, the owner or operator shall follow the most
recent operating and maintenance (OEM) plan and record keeping format approved by the
Division, in order to demonstrate compliance on an ongoing basis with the requirements of this
permit. Revisions to the 08M plan are subject to Division approval prior to implementation.
(Regulation Number 3, Part B, Section III.G.7.)
34. Point 078: The combustion chamber temperature of the thermal oxidizer used to control
emissions from the amine unit still vent shall be greater than 1400 `F, or the temperature
established during the most recent stack test of the equipment that was approved by the Division,
on a daily average basis. The approved daily average minimum operating temperature shall be
achieved at all times that any amine unit emissions are routed to the thermal oxidizer. The
combustion chamber temperature shall be measured and recorded at least once every hour. If
the combustion chamber temperature value is measured more frequently than once per hour,
the source shall record either each measured data value or each block average value for each 1 -
hour period calculated from all measured data values during each period.
35. Point 078: Periodic maintenance shall be completed to maintain the efficiency of the thermal
oxidizer and shall be performed at a minimum of once per every twelve months or more often as
recommended by the manufacturer specifications.
COLORADO
I Air Po€€ution Co!ttro 7xvv is t
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36. ' • 75 7 thi r one h �>.,dre•` . nd eight s (180) of the latter of commencement of
operation or issuance o is permi , a source im is compliance test shall be conducted on each
heater to measure the emission rate(s) for the pollutants listed below in order to demonstrate
compliance with the emissions limits contained in this permit. The test protocol must be in
accordance with the requirements of the Air Pollution Control Division Compliance Test Manual
and shall be submitted to the Division for review and approval at least thirty (30) days prior to
testing. No compliance test shall be conducted without prior approval from the Division. Any
compliance test conducted to show compliance with a monthly or annual emission limitation
shall have the results projected up to the monthly or annual averaging time by multiplying the
test results by the allowable number of operating hours for that averaging time (Reference:
Regulation No. 3, Part B., Section III.G.3)
Oxides of Nitrogen using EPA approved methods
Carbon Monoxide using EPA approved methods.
37. Point 078: Within one hundred and eighty days (180) of the latter of commencement of
operation or issuance of this permit, the owner or operator shall complete the initial amine unit
still vent waste gas sampling required by this permit and submit the results to the Division as
part of the self -certification process to ensure compliance with emissions limits. (Reference:
Regulation No. 3, Part B, Section III.E.)
38. Point 078: Within one hundred and eighty days (180) of the latter of commencement of
operation or issuance of this permit, the owner or operator shall complete the initial annual inlet
sour gas analysis testing required by this permit and submit the results to the Division as part of
the self -certification process to ensure compliance with emissions limits. (Reference: Regulation
No. 3, Part B, Section III.E.)
39. Point 078: Within one hundred and eighty days (180) of the latter of commencement of
operation or issuance of this permit, a source initial compliance test shall be conducted on
emissions point 078 to measure the emission rate(s) for the pollutants listed below in order to
demonstrate compliance with the emissions limits specified in this permit and to demonstrate a
minimum destruction efficiency of 99% for VOCs. The test shall determine the mass emission
rates of volatile organic compounds at the inlet and outlet of the control device, which shall be
used to determine the destruction efficiency during the test. The total natural gas throughput,
total lean amine circulation rate, MDEA concentration, and sulfur content of sour gas entering
the amine units shall be monitored and recorded during this test. The operator shall also measure
and record supplemental fuel flow rate to the thermal oxidizer and combustion zone temperature
during the initial compliance test to establish the minimum combustion temperature. This test
shall be run with the thermal oxidizer operating at the minimum combustion chamber
temperature of 1,400°F as indicated in the OItM plan for this point.
The test protocol must be in accordance with the requirements of the Air Pollution Control
Division Compliance Test Manual and shall be submitted to the Division for review and approval
at least thirty (30) days prior to testing. No compliance test shall be conducted without prior
approval from the Division. Any compliance test conducted to show compliance with a monthly
or annual emission limitation shall have the results projected up to the monthly or annual
averaging time by multiplying the test results by the allowable number of operating hours for
that averaging time (Reference: Common Provisions Section II.C and Regulation No. 3, Part B.,
Section III.G.3)
Sulfur Dioxide using EPA approved methods
Oxides of Nitrogen using EPA approved methods
Volatile Organic Compounds using EPA approved methods
Carbon Monoxide using EPA approved methods.
COLORADO
it Pollution Control Division
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Page 20 of 31
40. ' oint i1iT�` -'ne hun nd ei ays (18 = of the latter of commencement of operation
perat• ` shall demonstrate compliance with opacity
9, 40 C. `>' . Part 60, Appendix A, to measure opacity
Regulati•` Number 1, Section II.A.5)
41. Points 079: The owner or operator shall complete an initial site -specific extended gas sample
and analysis within one hundred and eighty days (180) after commencement of operation or
issuance of this permit, whichever comes later, of the assist gas and purge gas routed to the
flare to verify the Hydrogen Sulfide, VOC, Benzene, Toluene, Ethylbenzene, Xylene and n -Hexane
content (weight fraction) and heat value of this emission stream. The sampled stream shall
represent the combined streams of all gas being routed to the flare at the time of sampling.
Results of the Analysis shall be used to calculate site -specific emission factors for the pollutants
referenced in this permit (in units of lb/MMSCF) using Division approved methods. Results of the
Analysis shall be submitted to the Division as part of the self -certification and must demonstrate
the emissions factors established through the Analysis are less than or equal to, the emissions
factors submitted with the permit application and established herein in the "Notes to Permit
Holder" for this emissions point. If any site specific emissions factor developed through this
Analysis is greater than the emissions factors submitted with the permit application and
established in the "Notes to Permit Holder" the operator shall submit to the Division within 60
days, or in a timeframe as agreed to by the Division, a request for permit modification to address
this/these inaccuracy(ies).
42. Point 080: Within one hundred and eighty days (180) of the latter of commencement of
operation or issuance of this permit, the owner or operator shall complete the initial extended
gas analysis of gas samples that are representative of volatile organic compound (VOC) and
hazardous air pollutants (HAP) that may be released as fugitive emissions. These extended gas
analyses shall be used in the compliance demonstration as required in the Emission Limits and
Records section of this permit. The operator shall submit the results of the gas and liquids
analyses and emission calculations to the Division as part of the self -certification process to
ensure compliance with emissions limits.
43. Point 080: Within one hundred and eighty days (180) of the latter of commencement of
operation or issuance of this permit, the owner or operator shall complete a hard count of
components at the source and establish the number of components that are operated in "heavy
liquid service", "light liquid service", "water/oil service" and "gas service". The operator shall
submit the results to the Division as part of the self -certification process to ensure compliance
with emissions limits.
Periodic Testing Requirements
44. Point 078: The owner or operator shall measure the emission rate(s) from this unit for the
pollutants listed below at least once every 12 months, unless the unit has not operated in the
last 12 months, in order to demonstrate compliance with the emissions limits contained in this
permit. Periodic testing shall be conducted within 12 months of the prior test with a minimum
period of at least one hundred and eighty (180) days apart. In the event it is not feasible to
conduct a test at a minimum of at least one hundred and eighty (180) days apart, a written
explanation shall be submitted with the test protocol describing the reasons the testing could
not be conducted one hundred and eighty (180) days apart. If a unit will be operated at any time
during a 12 -month period, except for periods of maintenance, it must be tested as required by
this condition. If a unit has not operated for more than 12 months, it must be tested within 60
days of resuming operation. The natural gas throughput, lean amine circulation rate, MDEA
concentration, sulfur content of sour gas entering the amine unit, supplemental fuel flow to the
thermal oxidizer, and combustion zone temperature shall be monitored and recorded during this
test.
The test protocol must be in accordance with the requirements of the Air Pollution Control
Division Compliance Test Manual and shall be submitted to the Division for review and approval
at least thirty (30) days prior to testing. No compliance test shall be conducted without prior
COLORADO
ix Pollution. Control Division
rtfroli2 %X M,u'Ytlt ;ytCFi £r E.z?4CTf7P,:^SE.s=$
Page 21 of 31
ducted to show compliance with a monthly
is projected up to the monthly or annual
e allowable number of operating hours for
art B., Section III.G.3)
Sulfur Dioxide using EPA approved methods
Oxides of Nitrogen using EPA approved methods
Volatile Organic Compounds using EPA approved methods
Carbon Monoxide using EPA approved methods.
45. Point 078: The owner or operator shall sample and analyze the amine unit still vent waste gas
stream at a minimum frequency of once per calendar month. The sample shall be analyzed for
total VOC, Benzene, Toluene, Ethylbenzene, Xylene, n -Hexane, 2,2,4-trimethylpentane, and
H2S. The sample shall be collected prior to the inlet of the thermal oxidizer and prior to being
combined with any other stream. The sampled data will be used to calculate VOC and H2S
emissions as specified in this permit to show compliance with the emission limits. If neither
amine contactor tower is operated during a calendar month, monthly sampling is not required.
46. Point 078: The owner or operator shall sample the inlet gas to the plant on an annual basis to
determine the concentration of hydrogen sulfide (H2S) in the gas stream. The sample results shall
be monitored to demonstrate the amine unit qualifies for the exemption from the Standards of
Performance for Crude Oil and Natural Gas Production, Transmission and Distribution
(560.5365a(g)(3)).
47. Point 079: On a quarterly basis, the owner or operator shall complete an site -specific extended
gas sample and analysis of the assist gas and purge gas routed to the flare to verify the Hydrogen
Sulfide, VOC, Benzene, Toluene, Ethylbenzene, Xylene and n -Hexane content (weight fraction)
and heat value of this emission stream. The sampled stream shall represent the combined
streams of all gas being routed to the flare at the time of sampling. Results of the Analysis shall
be used to calculate site -specific emission factors for the pollutants referenced in this permit (in
units of lb/MMSCF) using Division approved methods. Results of the Analysis must demonstrate
the emissions factors established through the Analysis are less than or equal to, the emissions
factors submitted with the permit application and established herein in the "Notes to Permit
Holder" for this emissions point. If any site specific emissions factor developed through this
Analysis is greater than the emissions factors submitted with the permit application and
established in the "Notes to Permit Holder" the operator shall submit to the Division within 60
days, or in a timeframe as agreed to by the Division, a request for permit modification to address
this/these inaccuracy(ies).
48. Point 080: On an annual basis, the owner or operator shall complete an extended gas analysis
of gas samples that are representative of volatile organic compounds (VOC) and hazardous air
pollutants (HAP) that may be released as fugitive emissions. These extended gas analyses shall
be used in the compliance demonstration as required in the Emission Limits and Records section
of this permit.
ADDITIONAL REQUIREMENTS
49. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Regulation Number 3, Part A, II.C.)
• Annually by April 30th whenever a significant increase in emissions occurs as follows:
For any criteria pollutant:
For sources emitting less than 100 tons per year, a change in actual emissions of five
(5) tons per year or more, above the level reported on the last APEN; or
For volatile organic compounds (VOC) and nitrogen oxides sources (NOr) in ozone
nonattainment areas emitting less than 100 tons of VOC or NO, per year, a change in
COLORADO
Air Pollution Control Division
Page 22 of 31
year or more or five percent, whichever is
t APEN; or
For urc - em ing 1 ��, toy •er year more, a change in actual emissions of five
pe = or � o pe y ore, whi ver is less, above the level reported on the
last APEN submitted; or
For any non -criteria reportable pollutant:
If the emissions increase by 50% or five (5) tons per year, whichever is less, above the
level reported on the last APEN submitted to the Division.
• Whenever there is a change in the owner or operator of any facility, process, or activity;
or
• Whenever new control equipment is installed, or whenever a different type of control
equipment replaces an existing type of control equipment; or
• Whenever a permit limitation must be modified; or
• No later than 30 days before the existing APEN expires.
50. This source is subject to the provisions of Regulation Number 3, Part C, Operating Permits (Title
V of the 1990 Federal Clean Air Act Amendments). The application for the Operating Permit is
due within one year of the earliest commencement of operation of any piece of equipment
covered by this permit.
GENERAL TERMS AND CONDITIONS
51. This permit and any attachments must be retained and made available for inspection upon
request. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation
Number 3, Part B, Section II.B. upon a request for transfer of ownership and the submittal of a
revised APEN and the required fee.
52. If this permit specifically states that final authorization has been granted, then the remainder
of this condition is not applicable. Otherwise, the issuance of this construction permit does not
provide "final" authority for this activity or operation of this source. Final authorization of the
permit must be secured from the APCD in writing in accordance with the provisions of 25-7-
114.5(12)(a) C.R.S. and AQCC Regulation Number 3, Part B, Section III.G. Final authorization
cannot be granted until the operation or activity commences and has been verified by the APCD
as conforming in all respects with the conditions of the permit. Once self -certification of all
points has been reviewed and approved by the Division, it will provide written documentation of
such final authorization. Details for obtaining final authorization to operate are located in the
Requirements to Self -Certify for Final Authorization section of this permit.
53. This permit is issued in reliance upon the accuracy and completeness of information supplied by
the owner or operator and is conditioned upon conduct of the activity, or construction,
installation and operation of the source, in accordance with this information and with
representations made by the owner or operator or owner or operator's agents. It is valid only for
the equipment and operations or activity specifically identified on the permit.
54. Unless specifically stated otherwise, the general and specific conditions contained in this permit
have been determined by the APCD to be necessary to assure compliance with the provisions of
Section 25-7-114.5(7)(a), C.R.S.
55. Each and every condition of this permit is a material part hereof and is not severable. Any
challenge to or appeal of a condition hereof shall constitute a rejection of the entire permit and
upon such occurrence, this permit shall be deemed denied ab initio. This permit may be revoked
at any time prior to self -certification and final authorization by the Air Pollution Control Division
(APCD) on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air
Quality Control Commission (AQCC), including failure to meet any express term or condition of
ICOLORADO
Par Potiution Control D.iv#s3t n
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Page 23 of 31
condi ".ns imposed upon a permit are contested by
kes a .`; mit, the owner or operator of a source may
eview of t' Division's action.
56. 25 .R.hat alles required to file an Air Pollution Emission
Notice (APEN) must pay an annual fee to cover the costs of inspections and administration. If a
source or activity is to be discontinued, the owner must notify the Division in writing requesting
a cancellation of the permit. Upon notification, annual fee billing will terminate.
57. Violation of the terms of a permit or of the provisions of the Colorado Air Pollution Prevention
and Control Act or the regulations of the AQCC may result in administrative, civil or criminal
enforcement actions under Sections 25-7-115 (enforcement), -121 (injunctions), -122 (civil
penalties), -122.1 (criminal penalties), C.R.S.
By:
Carissa Money
Permit Engineer
Permit Histo
Issuance
Date
Description
Issuance 1
This Issuance
Issued to Kerr McGee Gathering LLC for two new
processing trains at an existing natural gas
processing plant. The new train, referred to as
Lancaster Plant 3 includes one 55 MMBtu/hr
regeneration heater (AIRS ID 075), two 18.4
MMBtu/hr molecular sieve regeneration heaters
(AIRS ID 076 and 077), a 153 MMSCFD amine system
consisting of two amine contactor towers sharing
one amine regeneration system and controlled by a
thermal oxidizer (AIRS ID 078), one process flare
(AIRS ID 079) and fugitive emissions from
components (AIRS ID 080). The train also includes
an APEN-exempt 5 MMBtu/hr condensate stabilizer,
a permit -exempt 6 MMBtu/hr inlet H2S preheater
(17WE1060, AIRS ID 081) and a permit -exempt 839
bhp diesel emergency generator (17WE1061, AIRS
ID 082).
COLORADO
Air Pollution Control Division
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Page 24 of 31
1) Th,.ermit;.ld�, is �.uire• °.fees t proc ing time for this permit. An invoice for these
fe " will • ssu�" of , the Fermi The per t holder shall pay the invoice within 30 days
ilur > he in will result in revocation of this permit.
(Regulation Number 3, Part A, Section VI.B.)
2) The production or raw material processing limits and emission limits contained in this permit are
based on the consumption rates requested in the permit application. These limits may be revised
upon request of the owner or operator providing there is no exceedance of any specific emission
control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN)
and complete application form must be submitted with a request for a permit revision.
3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense
Provision for Excess Emissions During Malfunctions. The owner or operator shall notify the Division of
any malfunction condition which causes a violation of any emission limit or limits stated in this permit
as soon as possible, but no later than noon of the next working day, followed by written notice to
the Division addressing all of the criteria set forth in Part II.E.1 of the Common Provisions Regulation.
See: https://www.colorado.gov/pacific/cdphe/aqcc-regs
4) The following emissions of non -criteria reportable air pollutants are estimated based upon the process
limits as indicated in this permit. This information is listed to inform the operator of the Division's
analysis of the specific compounds emitted if the source(s) operate at the permitted limitations.
Facility
Equipment ID
AIRS
Point
Pollutant
CAS #
Uncontrolled
Emissions
(Ib/yr)
Controlled
Emissions
(lb/yr)
H-80100
075
n -Hexane
110543
850
850
H-31711
076
n -Hexane
110543
235
235
H-32711
077
n -Hexane
110543
235
235
TO -91700
078
Benzene
71432
70,019
700
Toluene
108883
41,864
419
Ethylbenzene
100414
25,732
257
Xylenes
1330207
74,025
740
n -Hexane
110543
2,358
24
FL -90100
079
Benzene
71432
564
11
Toluene
108883
4,427
89
Ethylbenzene
100414
1,157
23
Xylenes
1330207
5,686
94
n -Hexane
110543
1,304
29
FUG -5
080
Benzene
71432
465
69
Toluene
108883
891
129
Ethylbenzene
100414
145
20
Xylenes
1330207
461
67
n -Hexane
110543
2,496
393
COLORADO
r Pollution Control Division
Page 25 of 31
ortabl.
able
No : All n. cnt T is
pe .'ear (l• r) a rep
Era�ice:,.aN
671
110
po nts i e ble a • •.. `- with uncontrolled emission rates above 250 pounds
d ma esult`"', annual em ion fees based on the most recent Air Pollution
5) The emission levels contained in this permit are based on the following emission factors:
Points 075, 076 and 077:
CAS
Pollutant
Uncontrolled Emission Factors
(lb/MMscf Natural Gas Combusted)
Source
NOx
40.80
Manufacturer
CO
40.80
Manufacturer
VOC
19.38
Manufacturer
PM10/PM2.5
7.6
AP -42, Table 1.4-2
SOx
0.6
AP -42, Table 1.4-2
5000
Formaldehyde
0.075
AP -42, Table 1.4-3
71432
Benzene
0.0021
AP -42, Table 1.4-3
10888
Toluene
0.0034
AP -42, Table 1.4-3
110543
n -Hexane
1.8
AP -42, Table 1.4-3
Emissions for this point is based on a heat content of 1,020 Btu/scf, a heat input rating of 55
MMBtu/hr for Point 075 and a heat input rating of 18.4 MMBTU/hr each for Points 076 and 077.
Point 078:
Emissions from the amine unit result from venting of acid gas (still vent overhead) emissions to the
thermal oxidizer (flash tank emissions are 100% recycled to the plant inlet). Additionally, emissions
result from combustion of supplemental fuel required to combust the acid gas (still vent overhead)
emissions at the thermal oxidizer. Actual VOC, HAP and H2S emissions from venting of still vent acid
gas shall be calculated based on most recent waste gas sampling and most recent monthly waste gas
flow volume. Controlled emissions are based on a thermal oxidizer control efficiency of 99%. SO2
emissions resulting from the control/combustion of H2S emissions in the waste gas are based on mass
balance and assuming 99% of the H2S is converted to SO2.
Additional combustion emissions (from both supplemental fuel and waste gas) are calculated using
the following emission factors and volume of total gas combusted. Total gas combusted is the sum
of most recent waste gas flow volume plus most recent supplemental fuel volume plus burner volume.
Total actual emissions are then based on the sum of emissions calculated for controlled waste
gas plus combustion (including supplemental fuel, burner fuel and waste gas).
CAS
Pollutant
Emission Factors - Uncontrolled
lb/MMscf total gas combusted'
Source
NOx
7.8244
AP -42, Table 1.4-1
CO
6.5725
AP -42, Table 1.4-1
PM10
0.7136
AP -42, Table 1.4-2
PM2.5
0.7136
AP -42, Table 1.4-2
COLORADO
Pollution Control Division
Page 26 of 31
CAS
Pollutant
still v ante g.' volume plus supplemental fuel volume plus
is ',n Factors ncontrolled
s supplemen a gas plus fuel
to burner
Source
VOC2
5.5
AP -42, Table 1.4-2
SO23
0.6
AP -42, Table 1.4-2
2: VOC emissions from combustion (calculated using the emission factor in the table above) must
be summed with VOC emissions from the still vent to calculate total actual emissions.
3: SO2 emissions from combustion (calculated using the emission factor in the table above) plus
conversion of H2S emissions in the still vent must be summed to calculate actual SOx emissions.
Equation for Actual NOx, CO and PM2.5 Emissions Calculations:
Actual emissions ( lb ) = Emission Factor ( lb ) x [Still Vent Waste Gas (MMscf) +
month MMscj month)
Supplemental Fuel (month) + Burner Fuel (month)
*Still Vent Waste Gas and Supplemental Fuel are based on actual measured monthly flow
volumes.
Equation for Actual VOC Emissions Calculations:
lb _ )VOCTotal (month) = VOCWaste Gas + VOC Combustion
scf
VOCWaste Gas = VOC concentration (wt %) - 100 x Still Vent Waste Gas ( )
l l month
x Gas Molecular Weight (ldmol) 379 (lbmol) x (1 — 99% control)
*VOC concentration and Gas Molecular Weight are based on actual monthly sampled
values of the amine unit still vent waste gas stream.
*Still Vent Waste Gas is the actual measured monthly flow volume of the amine unit still
vent.
VOC Combustion = Emission Factor (Mlb \
Mscf) X [Supplemental Fuel (month/ +
Burner Fuel (MMscj)
month
*Supplemental Fuel is based on actual measured monthly flow volume.
Equation for Actual HAP Emissions Calculations:
HAP (lb l_ scf
month) = HAP concentration (wt %) - 100 x Still Vent Waste Gas (month)
x Gas Molecular Weight (lbmol) . 379 (lbm l) x (1 — 99% control)
*HAP concentration and Gas Molecular Weight are based on actual monthly sampled
values of the amine unit still vent waste gas stream.
*Still Vent Waste Gas is the actual measured monthly flow volume. _
COLORADO
utiort Control Division
Page 27 of 31
scf
H2Swaste Gas = H2S concentration (mol %) - 100 x Still Vent Waste Gas )
month
lb H2S scf l
x 34.08 (lbmol H2S)) 379 (lbmol) x (1 — 99% control)
*H2S concentration is based on actual monthly sampled values of the amine unit still vent
waste gas stream.
*Still Vent Waste Gas is the actual measured monthly flow volume.
lb (H2SFuel = Emission Factor (MMscf) x [Supplemental Fuel month)
MMsc f
+ Burner Fuel (month)
*Supplemental Fuel is based on actual measured monthly flow volume.
Equation for Actual SOx Emissions Calculations:
lb
SOXTotal (month) SOXwaste Gas + SOXCombustion
SOXwaste Gas = H2Swaste Gas ± 0.01 x 64.05 lb S02 ± 34.08 lb H2S
SOXcombustlon = Emission Factor (MMscf) X [Supplemental Fuel () + lb
month
MMscf
Burner Fuel (month)
*Supplemental Fuel is based on actual measured monthly flow volume.
Point 079:
CAS
Pollutant
Emission Factors -
Uncontrolled lb/MMscf
Total Gas Combusted
Emission Factors
-Controlled
lb/MMscf
Source
NOx
87.473
87.473
AP -42, Table 13.5-1
CO
398.77
398.77
AP -42, Table 13.5-1
VOC
2,251.1
45.023
Controlled EF is AP-
42 THC Emission
Factor * 25% VOC
PM2.5/PM10
6.0
6.0
AP -42, Table 1.4-2
71432
Benzene
6.5035
0.1301
Mass Balance
108883
Toluene
51.048
1.0210
Mass Balance
100414
Ethylbenzene
13.341
0.2668
Mass Balance
1330207
Xylenes
65.566
1.3113
Mass Balance
110543
n -Hexane
15.036
0.3007
Mass Balance
Total gas combusted equals process gas volume plus purge gas volume (process gas volume and purge
gas volume are metered) plus fuel volume to flare pilot. Flare combustion efficiency is 98%.
Point 080:
Equipment Type
Service
Gas
I
Gas
I
Heavy Oil I
Light Oil
I
Water/Oil
COLORADO
Air Pollution Control Division
Page 28 of 31
Inl
1
anges
Open -Ended Lines
Pump Seals
17
6
C H vy Oit
Condensate
Water/Oil
ded in
ensate
t oil
4,342
Valves
653
1,211
468
231
Other*
35
32
9
VOC Content (wt%)
Benzene (wt%)
Toluene (wt%)
Ethylbenzene (wt%)
Xylenes (wt%)
n -hexane (wt%)
22%
100%
100%
100%
100%
0.02%
1.5%
1.5%
0.03%
3.0%
3.0%
0%
0.5%
1.5%
0.5%
0.01%
1.5%
0.2%
7.5%
7.5%
Equipment Type
Service
Light Oil
Light Oil
Light Oil
C3+ Liquid
NGL
Methanol
Connectors
1,458
321
92
Flanges
317
---
---
Open-Ended Lines
---
---
---
Pump Seals
8
---
3
Valves
1,038
114
29
Other*
17
5
2
VOC Content (wt%)
100%
100%
100%
Benzene (wt%)
---
0.2%
---
Toluene (wt%)
---
0.01%
---
Ethylbenzene (wt%)
---
0.01%
---
Xylenes (wt%)
---
0.3%
---
n-hexane (wt%)
---
2.0%
---
*Other equipment type includes compressors, pressure relief valves, relief valves, diaphragms,
drains, dump arms, hatches, instrument meters, polish rods and vents
TOC Emission Factors (kg/hr-component):
Component
Gas Service
Heavy Oil
Light Oil
Water/Oil
Service
Connectors
2.0E-04
7.5E-06
2.1E-04
1.1E-04
Flanges
3.9E-04
3.9E-07
1.1E-04
2.9E-06
Open-ended Lines
2.0E-03
1.4E-04
1.4E-03
2.5E-04
Pump Seals
2.4E-03
NA
1.3E-02
2.4E-05
Valves
4.5E-03
8.4E-06
2.5E-03
9.8E-05
Other
8.8E-03
3.2E-05
7.5E-03
1.4E-02
Source: EPA -453/R95-017
COLORADO
Air Pollution Control l Division
LV.≥aatt? *nt & Putltr. *s 2C?3 b E:�tdiroF':5e �+t
Page 29 of 31
e demonstrated by using the TOC emission
component counts, multiplied by the VOC
analyses.
6) I nce • - _ : -11 er z.'r Pollu mission Notice (APEN) associated with this
permit is valid for a term of five years from the date it was received by the Division. A revised APEN
shall be submitted no later than 30 days before the five-year term expires. Please refer to the most
recent annual fee invoice to determine the APEN expiration date for each emissions point associated
with this permit. For any questions regarding a specific expiration date call the Division at (303)-692-
3150.
7) Point 078: This amine unit is subject to 40 CFR Part 60 Subpart 0000a, Standards of Performance
for Crude Oil and Natural Gas Production, Transmission and Distribution for which Construction,
Modification, or Reconstruction Commenced after September 18, 2015 (See June 3, 2016 Federal
Register posting - effective August 2, 2016.) This rule has not yet been incorporated into Colorado
Air Quality Control Commission's Regulation No. 6. A copy of the complete subpart is available at
the Office of the Federal Register website
at: https: / /www.federalregister.gov/documents/2016/06/03/2016-11971 toil -and -natural -gas -
sector -emission -standards-for-new-reconstructed-and-modified-sources. This unit is subject to
requirements including, but not limited to, the following:
• $60.5365a - Applicability and Designation of Affected Facilities
o $60.5365a(g)(3) - Facilities that have a design capacity less than 2 long tons per day
(LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are required to
comply with recordkeeping and reporting requirements specified in $60.5423a(c) but
are not required to comply with §§60.5405a through 60.5407a and §§60.5410a(g) and
60.5415a(g).
• 56O.5423a - Record keeping and reporting Requirements
o $60.5423a(c) - To certify that a facility is exempt from the control requirements of
these standards, for each facility with a design capacity less that 2 LT/D of H2 S in
the acid gas (expressed as sulfur) you must keep, for the life of the facility, an
analysis demonstrating that the facility's design capacity is less than 2 LT/D of H2 S
expressed as sulfur.
8) Point 080: This source is subject to 40 CFR, Part 60, Subpart 0000a —Standards of Performance
for Crude Oil and Natural Gas Facilities for which Construction, Modification or Reconstruction
Commenced After September 18, 2015 (See June 3, 2016 Federal Register posting - effective August
02, 2016). This rule has not yet been incorporated into Colorado Air Quality Control Commission's
Regulation No. 6. A copy of the complete subpart is available on the EPA website at:
https://www.gpo.gov/fdsys/pka/FR-2016-06-03/pdf 2016-11971.pdf
9) This facility is classified as follows:
Applicable
Requirement
Status
Operating Permit
Major Source of NOX, VOC, CO, and HAP
PSD
Major Source of CO
NANSR
Major Source of NOX and VOC
MACT ZZZZ
Major Source Requirements Apply
MACT HH
Major Source Requirements Apply
COLORADO
u Pollution Control Division
Page 30 of 31
PS Dc
A '. li ..le
PS O' 4Oa "'
=optic
10) Full text of the Title 40, Protection of Environment Electronic Code of Federal Regulations can be
found at the website listed below:
http://ecfr.gpoaccess.gov/
Part 60: Standards of Performance for New Stationary Sources
NSPS
60.1 -End
Subpart A - Subpart KKKK
NSPS
Part 60, Appendixes
Appendix A - Appendix I
Part 63: National Emission Standards for Hazardous Air Pollutants for Source Categories
MACT
63.1-63.599
Subpart A - Subpart Z
MACT
63.600-63.1199
Subpart AA - Subpart DDD
MACT
63.1200-63.1439
Subpart EEE - Subpart PPP
MACT
63.1440-63.6175
Subpart QQQ - Subpart YYYY
MACT
63.6580-63.8830
Subpart ZZZZ - Subpart MMMMM
MACT
63.8980 -End
Subpart NNNNN - Subpart XXXXXX
COLORADO
Air Pollution Control Division
£"4R'
Page 31 of 31
(242_,ziLl v edt
lact
Boiler APEN - Form APCD-220
Air Pollutant Emission Notice (APEN) and
Application for Construction Permit
All sections of this APEN and application must be completed for both new and existing facilities, including APEN
updates. An application with missing information may be determined incomplete and may be returned or result in
longer application processing times. You may be charged an additional APEN fee if the APEN is filled out
incorrectly or is missing information and requires re -submittal.
This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit
does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths,
mining operations, engines, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty
APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air
Pollution Control Division (APCD) website at: www.colorado.Rov/cdphe/apcd.
Do not complete this form for the following source categories:
Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by
natural gas or liquid petroleum gas (LPG).
Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating
buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG).
More information can be found in the APEN exempt/permit exempt checklist:
https: / /www.colorado. Roy/ pacific /cdphe / apen-or-ai r- permit -exemptions.
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Permit Number:
IA)E. I D5
AIRS ID Number: 123 /0057 / 61-5
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 1 - Administrative Information
Company Name': Kerr McGee Gathering LLC
Site Name: Lancaster 3 Plant
Site Location: 16116 WCR 22, Ft. Lupton, CO
Mailing Address:
(Include Zip Code) PO Box 173779
Denver, CO 80217
E -Mail Address2: jillian.yamartino@anadarko.com
Site Location
County: Weld
NAICS or SIC Code: 1321
Permit Contact: Jillian Yamartino
Phone Number: 720-929-4374
'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will
appear on all documents issued by the APCD. Any changes will require additional paperwork.
'Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided.
Permit Number:
AIRS ID Number: 123 /0057 / 61-5
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 2- Requested Action
✓❑ NEW permit OR newly -reported emission source
-OR-
❑ MODIFICATION to existing permit (check each box below that applies)
❑ Change fuel or equipment ❑ Change company name
O Change permit limit ❑ Transfer of ownership3
-OR-
❑ APEN submittal for update only (Please note blank APENs will not be accepted)
- ADDITIONAL PERMIT ACTIONS -
❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE)
❑ APEN submittal for permit exempt/grandfathered source
Additional Info Et Notes: amine regeneration heater
❑ Add point to existing permit
❑ Other (describe below)
3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted.
Section 3 - General Boiler Information
General description of equipment and purpose:
amine regeneration
Manufacturer: TBD Model No.: TBD
Company equipment Identification No. (optional): H-80100
For existing sources, operation began on:
Serial No.:
For new, modified, or reconstructed sources, the projected start-up date is:
12/1/2019
❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below:
Normal Hours of Source Operation: hours/day
Seasonal use percentage: Dec -Feb: 25 Mar -May: 25
days/week weeks/year
June -Aug: 25 Sept -Nov: 25
Are you reporting multiple identical boilers on this APEN? ❑Yes ❑✓ No
If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers
or separate meters for each unit):
Form APCD-220 - Boiler APEN - Revision 7/2016
ORADO
2 C0Lnom.
Permit Number:
AIRS ID Number: 123 /0057 / [G ₹5
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 4 - Stack Information
Geographical Coordinates
Latitude/Longitude or UTM)
TBD
era
optor
taclD
SSkNQ
Discharge Heigh:
Above Ground Level
(Feet)
L
�� g
Flaw Rate��leloctty:;
( cFM)
'€ t/sec
H-80100
Indicate the direction of the stack outlet: (check one)
❑ Upward
❑ Horizontal
❑ Downward
❑ Other (describe):
Indicate the stack opening and size: (check one)
❑ Circular Interior stack diameter (inches):
❑ Square/rectangle Interior stack width (inches):
❑ Other (describe):
❑ Upward with obstructing raincap
Interior stack depth (inches):
Section 5 - Fuel Consumption Information
Design Input Rate
(MMBTUIhr)
Actual Annual Fuel Use.
(Specify Units)
Requested Annual Permit Limit
(Specify Units)
55
472.4 MMscf/year
From what year is the actual annua fuel use data?
Fuel consumption values entered above are for: E Each Boiler ❑ All Boilers ❑ N/A
Indicate the type(s) of fuel used6:
❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF)
❑ Field Natural Gas Heating value: BTU/SCF
❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon)
❑ Propane (assumed fuel heating value of 2,300 BTU/SCF)
❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content:
❑ Other (describe):
Heating value (give units):
"If you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual
boiler basis, or if the values represent total fuel usage for multiple boilers.
5Requested values will become permit limitations. Requested limit(s) should consider future process growth.
61f fuel heating value is different than the listed assumed value, please provide this informaticri in the "Other" field.
LORADO
Form APCD-220 - Boiler APEN - Revision 7/2016 3
TSP (PM)
Permit Number:
AIRS ID Number: 123 /0057 / O 5
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 6- Criteria Pollutant Emissions Information
Attach all emission calculations and emission factor documentation to this APEN form.
Is any emission control equipment or practice used to reduce emissions? fYes El No
If yes, please describe the control equipment AND state the overall control efficiency (% reduction):
Control Equipment Description
Overall Control Efficiency
re action in emissions)
PM10
PM2.5
SOX
NOX
.low-Nex-d' grid'
CO
VOC
Other:
From what year is the following reported actual annual emissions data?
Use the following tables to report the criteria pollutant emissions from source:
(Use the data reported in Section 5 to calculate these emissions.)
PrimarylFuel
Type
(natural; gas,,
#2 diesel,
ltc.) .
TSP (PM)
C1-111 5/3 ill 'j-*
ear
Uncontrolled
Emission
Factor
(Specify Units)
Emission
Factor
Source
(AP -42, Mfg.
etc)
Uncontrolled
(Tons/year)
Controlled'
(Tons/year)
equested Annual Perini
fission Limits
Uncontrolled,
(Tons/year)
Controlled
(Tons/year)
natural gas
PM10
7.6 Ib/MMscf
AP -42
1.79
PM2.5
7.6 Ib/MMscf
AP -42
x-61— i
SOX
0.6 Ib/MMscf
AP -42
de. min.
NOX
0.04 Ib/MMbtu
manuf.
9.64
CO
0.04 Ib/MMbtu
manuf.
9.64
VOC
0.019 Ib/MMbtu
manuf.
4.58
Other:
7
5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. ,�1
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. P -4P -2--r /,II
Form APCD-220 - Boiler APEN - Revision 7/2016
41
COLOR*OO
Permit Number:
AIRS ID Number: 123 /0057 /
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
O Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7.
If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria
emissions table below:
Secondary
Fuel Type
(#2 diesel,
waste oif,;
etc.)
TSP (PM)
Uncontrolled
Emission •
Factor
(Specify Units)
•
Emission
Factor
Source
(AP -42, Mfg.
etc)
ual Annual Emission
Uncontrolled "
(Tons/year) " "
Uncontrolled
(Tons/year)
Controlled'
(Tons/year)
Controlled
(Tons/year)
PM 10
PM2.5
SO.
NO.
CO
VOC
Other:
If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant
emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary
fuels' emissions tables in this Section 6:
TSP (PM)
Uncontrolled
(Tons/year)
Controlled'
(Tons/year)
Uncontrolled
(Tons/year)
Controlled
(Tons/year)
PM10
PM2.5
SO.
NO.
CO
VOC
Other:
5 Requested values will become permit Limitations. Requested limit(s) should consider future process growth.
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
COLoiSs�.
Form APCD-220 - Boiler APEN - Revision 7/2016
5I
Permit Number:
AIRS ID Number: 123 /0057 / C):7-6
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 7 - Non -Criteria Pollutant Emissions Information
Does the emissions source have any uncontrolled actual emissions of non -criteria
pollutants (e.g. HAP- hazardous air pollutant) equal to or greater than 250 lbs/year?
Yes Q✓ No
If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source:
CAS Number
Chemical Name
Overall
Control .
Efficiency
Uncontrolled
Emission
— Factor
(specify units)
!
Emission Factor
Source ". -
(AP -42 Mfg etc)
Uncontrolled
Actual
Emissions
(Ms/year)
Controlled
Actual
Emissions'.:
(lbslyear)
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, eave blank.
Section 8 - Applicant Certification
I hereby certify that all information contained herein and information submitted with this application is complete,
true and correct.
Jillian Yamartino
Digitally signed by Jillian Yamartino
' Date: 2018.01.29 11:00:49 -07'00'
1/29/2018
Signature of Legally Authorized Person (not a vendor or consultant) Date
Jillian Yamartino
HSE Representative
Name (please print)
Title
Check the appropriate box if you want:
0✓ Copy of the Preliminary Analysis conducted by the Division
�✓ Draft permit prior to public notice
0✓ Draft of the permit prior to issuance
(Checking any of these boxes may result in an increased fee and/or processing time)
This notice is valid for five (5) years unless a significant change is made, such as an increased production,
new equipment, change in fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the
expiration date of this APEN form.
Send this form along with $152.90 to:
Colorado Department of Public Health and
Environment
Air Pollution Control Division
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, CO 80246-1530
Telephone: (303) 692-3150
For more information or assistance call:
Small Business Assistance Program
(303) 692-3175 or (303) 692-3148
Or visit the APCD website at:
https: //www.colorado.gov/cdphe/apcd
Form APCD-220 - Boiler APEN - Revision 7/2016 6 I e
4O LOS Al
«rte.
ice' 'ad
Boiler APEN - Form APCD-220
Air Pollutant Emission Notice (APEN) and
Application for Construction Permit
All sections of this APEN and application must be completed for both new and existing facilities, including APEN
updates. An application with missing information may be determined incomplete and may be returned or result in
longer application processing times. You maybe charged an additional APEN fee if the APEN is filled out
incorrectly or is missing information and requires re -submittal.
This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit
does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths,
mining operations, engines, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty
APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air
Pollution Control Division (APCD) website at: www.colorado.Rov/cdphe/apcd.
Do not complete this form for the following source categories:
- Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by
natural gas or liquid petroleum gas (LPG).
Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating
buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG).
More information can be found in the APEN exempt/permit exempt checklist:
https: / /www.colorado. gov/pacific/cdphe /apen-or-air-permit-exemptions.
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Permit Number:
ITk)E.IG59
AIRS ID Number: 123 /0057 / O1-6,
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 1 - Administrative Information
Company Name': Kerr McGee Gathering LLC
Site Name: Lancaster 3 Plant
Site Location: 16116 WCR 22, Ft. Lupton, CO
Mailing Address: PO Box 173779
(Include Zip Code)
Denver, CO 80217
E -Mail Address2: jillian.yamartino@anadarko.com
Site Location
County: Weld
NAICS or SIC Code: 1321
Permit Contact: Jillian Yamartino
Phone Number: 720-929-4374
'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will
appear on all documents issued by the APCD. Any changes will require additional paperwork.
'Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided.
Permit Number:
AIRS ID Number: 123 /0057 /,
[Leave blank unless APCD has already assigned a permit it and AIRS ID]
Section 2- Requested Action
❑ NEW permit OR newly -reported emission source
-OR-
❑ MODIFICATION to existing permit (check each box below that applies)
❑ Change fuel or equipment
❑ Change permit limit
❑ Change company name
❑ Transfer of ownership3
OR -
❑ Add point to existing permit
❑ Other (describe below)
❑ APEN submittal for update only (Please note blank APENs will not be accepted)
- ADDITIONAL PERMIT ACTIONS -
❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE)
❑ APEN submittal for permit exempt/grandfathered source
Additional Info Et Notes: molecular sieve regeneration heater
3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted.
Section 3 - General Boiler Information
General description of equipment and purpose:
molecular sieve regeneration
Manufacturer: TBD
Model No.: TBD
Company equipment Identification No. (optional): H-31711
For existing sources, operation began on:
Serial No.:
For new, modified, or reconstructed sources, the projected start-up date is:
12/1/2019
El Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below:
Normal Hours of Source Operation:
19.9 hours/day 7 days/week 52
Seasonal use percentage: Dec -Feb: 25 Mar -May: 25
weeks/year
June -Aug: 25 Sept -Nov: 25
Are you reporting multiple identical boilers on this APEN? ❑Yes ✓❑ No
If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers
or separate meters for each unit):
Form APCD-220 - Boiler APEN - Revision 7/2016 2
LORADO
Frcximxr.<
Permit Number:
AIRS ID Number: 123 /0057 / -i 6
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 4 - Stack Information
Geographical Coordinates
•
(Latitude/Longitude or L!TM)
TBD
Operator
.
Stack ID No
i�x�a e�Ye
f-iJL307 g.�ra„�,i" ?....'^.Tel
(Fee J.2
iron
�),,�`-
Flbw Rage
(,Pri)
�c ty
��t,1seC) �.
H-31711
Indicate the direction of the stack outlet: tcheck one)
❑ Downward
❑ Other (describe):
❑✓ Upward
❑ Horizontal
Indicate the stack opening and size: (check one)
❑✓ Circular Interior stack diameter (inches):
❑ Square/rectangle Interior stack width (inches):
❑ Other (describe):
❑ Upward with obstructing raincap
Interior stack depth (inches):
Section 5 - Fuel Consumption Information
Design Input Rate
(MMBTU/hr)
18.4
Actual Annual Fuel Use"'
(Specify Units)
Requested Annual Perini
(Specify Units)
Limit
—130.5 MMscf/year
130,
From what year is the actual annual fuel use data? '1'V 1 5/3 E' IT
Fuel consumption values entered above are for: ✓❑ Each Boiler ❑ All Boilers ❑ N/A
Indicate the type(s) of fuel used6:
❑ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF)
❑ Field Natural Gas Heating value: BTU/SCF
❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon)
❑ Propane (assumed fuel heating value of 2,300 BTU/SCF)
❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content:
❑ Other (describe): Heating value (give units):
41f you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual
boiler basis, or if the values represent total fuel usage for multiple boilers.
'5Requested values will become permit limitations. Requested limit(s) should consider future process growth.
61f fuel heating value is different than the listed assumed value, please provide this information in the "Other" field.
Form APCD-220 - Boiler APEN - Revision 7/2016 3
COLORADO
wun
TSP (PM)
Permit Number:
AIRS ID Number: 123 /0057 /
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 6- Criteria Pollutant Emissions Information
Attach all emission calculations and emission factor documentation to this APEN form.
Is any emission control equipment or practice used to reduce emissions? Q✓ Yes No
If yes, please describe the control equipment AND state the overall control efficiency (% reduction):
Control Equipment Description
Overall Control Efficiency
reduction in emissions)
PM -10
PM2.5
SOX
NOX
�Iov�RlOx desigiie-
9°/ -
CO
VOC
Other:
From what year is the following reported actual annual emissions data?
Use the following tables to report the criteria pollutant emissions from source:
(Use the data reported in Section 5 to calculate these emissions.)
Primary Fuel
Type .:
(natural gas,
#2 diesel,
etc.)
natural gas
TSP (PM)
Uncontrolled
Emission
Factor
{Specify Units)
Emission
Factor
Source
{AP -42, Mfg
etc);
Uncontrolled
(Tons/year)
Controlled'
(Tons/year)
Uncontrolled
(Tons/year)
• Controlled
(Tons/year);•
;
PM10
7.6 Ib/MMscf
AP -42
0.5
PM2.5
7.6 Ib/MMscf
AP -42
0.5
SOX
0.6 Ib/MMscf
AP -42
de. min.
NOX
0.04 Ib/MMBtu
manuf.
6.5 �?
2.66
CO
0.04 Ib/MMBtu
manuf.
2.66
VOC
0.019 lb/MMBtu
manuf.
1.26
Other:
?.:4-3y31 313 ill
5, -
'Requested values will become permit limitations. Requested limit(s) should consider future process growth.
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank. l WC"'
Form APCD-220 - Boiler APEN - Revision 7/2016 4
OLORAOO
Permit Number: AIRS ID Number: 123 /0057 /
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
0✓ Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7.
If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria
emissions table below:
Secondary
Fuel Type
(#2 diesel,'."
waste "oil,
etc.)
TSP (PM)
Uncontrolled
Emission `
Factor„
Specify Units) •
Emission
Factor
Source
(AP -42, Mfg.
etc)
ual:Annual Emission=
Uncontrolled
(Tons/year)
Controlled7"
(Tons/year)
Uncontrolled
(Tons/year)
Controlled
(Tons/year)
PMio
PM2.5
SO,,
NO,,
CO
VOC
Other:
If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant
emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary
fuels' emissions tables in this Section 6:
TSP (PM)
Uncontrolled
(Tons/year)
Controlled'
(Tons/year)
lequested Annual Pe
Emission Limit' `J
Uncontrolled
(Tons/year)
•
Controlled
(Tons/year),-_-_
PM 10
PM2.5
SO,,
NOX
CO
VOC
Other:
5 Requested values will become permit limitations. Requested limit(s) should consider future process growth.
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
L°RAD°
Form APCD-220 - Boiler APEN - Revision 7/2016 5 I
Permit Number:
AIRS ID Number: 123 /0057 / O -
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 7 - Non -Criteria Pollutant Emissions Information
Does the emissions source have any uncontrolled actual emissions of non -criteria
pollutants (e.g. HAP- hazardous air pollutant) equal to or greater than 250 lbs/year?
Yes 0✓ No
If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source:
CAS Number
Chemical Name
Overall
Control" ."
Efficiency
Uncontrolled
Emission ' '
Factor
sect u
( P fY • nrts)
Emission Factor."
Source
jAP 4Z :Mfs. etc) ..
Uncontrolled -
Actual
Emissions
(lips/year)
Controlled
Actual
Emissions'
(lbslyear)
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, eave blank.
Section 8 - Applicant Certification
I hereby certify that all information contained herein and information submitted with this application is complete,
true and correct.
Jillian Yamartino
Digitally signed by Jillian Yamartino
Dale: 2018.01.29 11:01:33 -0T00'
Signature of Legally Authorized Person (not a vendor or consultant) Date
Jillian Yamartino
HSE Representative
Name (please print)
Title
Check the appropriate box if you want:
✓❑ Copy of the Preliminary Analysis conducted by the Division
E✓ Draft permit prior to public notice
�✓ Draft of the permit prior to issuance
(Checking any of these boxes may result in an increased fee and/or processing time)
This notice is valid for five (5) years unless a significant change is made, such as an increased production,
new equipment, change in fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the
expiration date of this APEN form.
Send this form along with $152.90 to:
Colorado Department of Public Health and
Environment
Air Pollution Control Division
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, CO 80246-1530
Telephone: (303) 692-3150
For more information or assistance call:
Small Business Assistance Program
(303) 692-3175 or (303) 692-3148
Or visit the APCD website at:
https://www.colorado.Rov/cdphe/apcd
Form APCD-220 - Boiler APEN - Revision 7/2016 6
--.COLORADO
izec_e., Jzcl
i(3`{IaC.)
Boiler APEN - Form APCD-220
Air Pollutant Emission Notice (APEN) and
Application for Construction Permit
All sections of this APEN and application must be completed for both new and existing facilities, including APEN
updates. An application with missing information may be determined incomplete and may be returned or result in
longer application processing times. You may be charged an additional APEN fee if the APEN is filled out
incorrectly or is missing information and requires re -submittal.
This APEN is to be used for boilers, hot oil heaters, process heaters, and similar equipment. If your emission unit
does not fall into one of these categories, there may be a more specific APEN for your source (e.g. paint booths,
mining operations, engines, etc.). In addition, the General APEN (Form APCD-200) is available if the specialty
APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on the Air
Pollution Control Division (APCD) website at: www.colorado.Rov/cdphe/apcd.
Do not complete this form for the following source categories:
- Heaters or boilers with a design capacity less than or equal to 5 MMBtu/hour that are fueled solely by
natural gas or liquid petroleum gas (LPG).
Heaters or boilers with a design capacity less than or equal to 10 MMBtu/hour used solely for heating
buildings for personal comfort that is fueled solely by natural gas or liquid petroleum gas (LPG).
More information can be found in the APEN exempt/permit exempt checklist:
https: / /www.colorado. gov/pacific/cdphe/apen-or-air-permit-exemptions.
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Permit Number:
i b`a9 AIRS ID Number: 123 /0057 /
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 1 - Administrative Information
Company Name':
Site Name:
Site Location:
Kerr McGee Gathering LLC
Lancaster 3 Plant
Site Location
16116 WCR 22, Ft. Lupton, CO County: Weld
Mailing Address:
(Include Zip Code) PO Box 173779
Denver, CO 80217
E -Mail Address': Jillian.Yamartino@anadarko.com
NAICS or SIC Code: 1321
Permit Contact: Jillian Yamartino
Phone Number: 720-929-4374
'Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will
appear on all documents issued by the APCD. Any changes will require additional paperwork.
'Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided.
Permit Number:
AIRS ID Number: 123 /0057 / O 4.1.
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 2- Requested Action
Q NEW permit OR newly -reported emission source
-OR-
❑ MODIFICATION to existing permit (check each box below that applies)
❑ Change fuel or equipment ❑ Change company name
❑ Change permit limit ❑ Transfer of ownership3
- OR
▪ APEN submittal for update only (Please note blank APENs will not be accepted)
- ADDITIONAL PERMIT ACTIONS -
O Add point to existing permit
❑ Other (describe below)
❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE)
❑ APEN submittal for permit exempt/grandfathered source
Additional Info a Notes: molecular sieve regeneration heater
3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted.
Section 3 - General Boiler Information
General description of equipment and purpose:
molecular sieve regeneration
Manufacturer: TBD Model No.: TBD
Company equipment Identification No. (optional): H-32711
For existing sources, operation began on:
Serial No.:
For new, modified, or reconstructed sources, the projected start-up date is:
12/1/2019
❑ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below:
Normal Hours of Source Operation:
19.9 hours/day 7 days/week 52
Seasonal use percentage: Dec -Feb: 25 Mar -May: 25
weeks/year
June -Aug: 25 Sept -Nov: 25
Are you reporting multiple identical boilers on this APEN? ❑Yes ❑✓ No
If yes, please describe how the fuel usage will be measured for each boiler (i.e., one meter for all boilers
or separate meters for each unit):
Form APCD-220 - Boiler APEN - Revision 7/2016 2
OLORADO
Mw�
6 'ae14aarrta:
LI Upward
❑ Horizontal
Permit Number:
AIRS ID Number: 123 /0057 / .�
[Leave blank unless APCD has already assigned a permit ft and AIRS ID]
Section 4 - Stack Information
Geographical Coordinates
(LatitudelLongitude or UTM)
TBD
i
Ope alt r
ackDo
D Scliarge Height
Above Ground Lever
(Feet)
Te
' f �)
rovF aL4
ftk�)
1l loch
(tfsec
H-32711
Indicate the direction of the stack outlet: (check one)
❑ Downward
❑ Other (describe):
Indicate the stack opening and size: (check one)
0 Circular Interior stack diameter (inches):
❑ Square/rectangle Interior stack width 'inches):
❑ Other (describe):
❑ Upward with obstructing raincap
Interior stack depth (inches):
Section 5 - Fuel Consumption Information
Design Input Rate
:OMB TLI/hr)
Actual Annual Fuel Use4 "`
(Specify Units)[
Requested Annual Permit Limit
,;(Specify Units)_
18.4
MMscf/year
r 36. 3
From what year is the actual annual fuel use data?
Fuel consumption values entered above are for: Ill Each Boiler ❑ All Boilers ❑ N/A (n-'/ "1''-``S
Indicate the type(s) of fuel used':
El Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF)
❑ Field Natural Gas Heating value: BTU/SCF
El Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon)
❑ Propane
11] Coal
El Other (describe):
(assumed fuel heating value of 2,300 BTU/SCF)
Heating value:
5/ /
3 il
BTU/lb Ash Content: Sulfur Content:
Heating value (give units):
411 you are reporting multiple identical boilers on one APEN, be sure to clarify if the values in this section are on an individual
boiler basis, or if the values represent total fuel usage for multiple boilers.
5Requested values will become permit limitations. Requested limit(s) should consider future process growth.
61f fuel heating value is different than the listed assumed value, please provide this information in the "Other" field.
c.O€.ORAOO
Form APCD-220 - Boiler APEN - Revision 7/2016 3 I
TSP (PM)
Permit Number:
AIRS ID Number: 123 /0057 /' 1
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 6- Criteria Pollutant Emissions Information
Attach all emission calculations and emission factor documentation to this APEN form.
Is any emission control equipment or practice used to reduce emissions? Q✓ Yes ❑ No
If yes, please describe the control equipment AND state the overall control efficiency (% reduction):
•
Overall Control Efficiency
(% reduction in emissions)
PMio
PM2.5
Sax
NO),
.ioerc-Pd9�c-design-�- -
CO
VOC
Other:
From what year is the following reported actual annual emissions data?
Use the following tables to report the criteria pollutant emissions from source:
(Use the data reported in Section 5 to calculate these emissions.)
(11, '33i/III��'j'
Primary Fuel
,
Type
(natural gas,
#2 diesel,
etc.)
TSP (PM)
Uncontrolled
Emission
Factor
(Specify Units)
Emission
Factor
Source
(AP -42, Mfg.
etc)
Uncontrolled
,(Tons/year)
Controlled.
(Tons/year)
nested Annual Perm'
ssion Limits
Uncontrolled
(Tons/year)
Controlled
(Tons/year) 'J
natural gas
PM 10
7.6 Ib/MMscf
AP -42
0.5
PM2.5
7.6 lb/MMscf
AP -42
0.5
SOX
0.6 lb/MMscf
AP -42
de. min
NO),
0.04 lb/MMBtu
manuf.
G.53 4)-
2.66
CO
0.04 lb/MMBtu
manuf.
2.66
VOC
0.019 Ib/MMBtu
manuf.
1.26
Other:
I -1131 I
5 Requested values will become permit limitations. Requested limit(s) should consider future process growth. I
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
Form APCD-220 - Boiler APEN - Revision 7/2016
41
gco oRA15rs
3 - et rnun
TSP (PM)
Permit Number:
AIRS ID Number: 123 /0057 / �a
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
❑✓ Check this box if the boiler did not combust a secondary fuel during this reporting period and skip to Section 7.
If multiple fuels were fired during this reporting period, complete this secondary fuel emissions table and the total criteria
emissions table below:
Secondary
Fuel Type
(#2 diesel,
waste 01 1,
etc.)
TSP (PM)
Uncontrolled
Emission
Factor
(Specify u -its)
Emission
Factor
Source
(AP -42, Mfg'.
etc)
Uncontrolled
(Tons/year)
Controlled
(Tons/year)
Uncontrolled
(Tons/year)
Controlled`
(Tons/year)
PM10
PM2.5
SOX
NO5
CO
VOC
Other:
If multiple fuels were fired during this reporting period, use the following table to report the TOTAL criteria pollutant
emissions from the source. Values listed below should be the sum of the reported emissions from the primary and secondary
fuels' emissions tables in this Section 6:
Actual Annual Er'nssro
Uncontrolled
(Tons/year)
Uncontrolled
(Tons/year)
Controlled'
(Tons/year) ,
Controlled
(Tons/year)
PM1a
PM2.s
5O5
NO5
CO
VOC
Other:
5 Requested values will become permit limitations. Requested limit(s) should consider future process growth.
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
tdc0RA€)o
Form APCD-220 - Boiler APEN - Revision 7/2016
5 I
3„z
Permit Number:
AIRS ID Number: 123 /0057 / C) T+
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 7 - Non -Criteria Pollutant Emissions Information
Does the emissions source have any uncontrolled actual emissions of non -criteria
pollutants (e.g. HAP- hazardous air pollutant) equal to or greater than 250 lbs/year?
Yes Q No
If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source:
Overall
Control
Efficiency
Uncontrolled
Emission
Factor
(specify units)
Emission Factor
Source
(AP -42, Mfg. -etc)
Uncontrolled
Actual
Emissions,
(lbslyear)
•
;ontrolled
Actual
Emissions'
(lbs/year) ,_
'Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, eave blank.
Section 8 - Applicant Certification
I hereby certify that all information contained herein and information submitted with this application is complete,
true and correct.
Jillian Yamartino
Digitally signed by Jillian Yarnartino
Date: 2018.01.29 1 t02:43 -07'00'
1/29/2018
Signature of Legally Authorized Person (not a vendor or consultant) Date
Jillian Yamartino
HSE Representative
Name (please print)
Title
Check the appropriate box if you want:
El Copy of the Preliminary Analysis conducted by the Division
0✓ Draft permit prior to public notice
0 Draft of the permit prior to issuance
(Checking any of these boxes may result in an increased fee and/or processing time)
This notice is valid for five (5) years unless a significant change is made, such as an increased production,
new equipment, change in fuel type, etc. A revised APEN shall be filed no less than 30 days prior to the
expiration date of this APEN form.
Send this form along with $152.90 to:
Colorado Department of Public Health and
Environment
Air Pollution Control Division
APCD-SS-B 1
4300 Cherry Creek Drive South
Denver, CO 80246-1530
Telephone: (303) 692-3150
For more information or assistance call:
Small Business Assistance Program
(303) 692-3175 or (303) 692-3148
Or visit the APCD website at:
https://www.colorado.gov/cdphe/apcd
Form APCD-220 - Boiler APEN - Revision 7/2016 6 I
R. 2.C c'_1 v-ed
,j,L4.1.31
Amine Sweetening Unit - Form APCD-206
Air Pollutant Emission Notice (APEN) and
Application for Construction Permit
All sections of this APEN and application must be completed for both new and existing facilities, including APEN
updates. An application with missing information may be determined incomplete and may be returned or result in
longer application processing times. You maybe charged an additional APEN fee if the APEN is filled out
incorrectly or is missing information and requires re -submittal.
This APEN is to be used for Amine Sweetening Units only. If your emission unit does not fall into this category,
there may be a more specific APEN for your source. In addition, the General APEN (Form APCD-200) is available if
the specialty APEN options will not satisfy your reporting needs. A list of all available APEN forms can be found on
the Air Pollution Control Division (APCD) website at: www.colorado.gov/cdphe/apcd.
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Permit Number:
i l L)E ll b5C1 AIRS ID Number: 123
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Company equipment Identification: 3A
/ 0057 /
[Provide Facility Equipment ID to identify how this equipment is referenced within your organization]
Section 1 - Administrative Information
Company Name': Kerr-McGee Gathering LLC
Site Name: Lancaster 3 Plant
Site Location: 16116 WCR 22, Ft. Lupton, CO
Mailing Address: PO Box 173779
(Include Zip Code)
Denver, CO 80217
E -Mail Address2: jillian.yamartino@anadarko.com
Site Location
County: Weld
NAICS or SIC Code: 1321
Permit Contact: Jillian Yamartino
Phone Number: 720-929-4374
1Please use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will
appear on all documents issued by the APCD. Any changes will require additional paperwork.
2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided.
Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 1
CQLORbD •
neaa�muas+:�+'P��
Permit Number:
AIRS ID Number:, 123 I (114/
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 2- Requested Action
❑✓ NEW permit OR newly -reported emission source
-OR -
❑ MODIFICATION to existing permit (check each box below that applies)
❑ Change fuel or equipment ❑ Change company name ❑ Add point to existing permit
❑ Change permit limit ❑ Transfer of ownership3 ❑ Other (describe below)
OR-
❑ APEN submittal for update only (Please note blank APENs will not be accepted)
- ADDITIONAL PERMIT ACTIONS -
• Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE)
Additional Info a Notes: Neal amine unit.
3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted.
Section 3 - General Information
General description of equipment and purpose: amine unit with 2 contactors, one reboiler, and
one reboiler heater (reported on separate APEN)
Facility equipment Identification:
For existing sources, operation began on:
For new or reconstructed sources, the projected
start-up date is:
TO -91700
/ /
12 /1 /2019
❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below:
Normal Hours of Source Operation: hours/day
Will this equipment be operated in any NAAQS nonattainment
area
Does this facility have a design capacity less than 2 long
tons/day of H2S in the acid gas?
days/week
Yes
Yes
weeks/year
No
No
Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017
COLORADO
1tw iHt-4 Fnvkrt.'�mey�
Permit Number:
AIRS ID Number: 123 / 0 / On -
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 4 - Dehydration Unit Equipment Information
Manufacturer: TBD Model : TBD Serial Number: TBD
Reboiler Rating: 44.8
Amine Type:
Pump Make and Model:
❑ MEA
MMBtu/hr Absorber Column Stages: 20
❑ DEA El TEA
stages
MDEA El DGA
# of pumps: 3
Sweet Gas Throughput4:
Design Capacity: 153 MMSCF/day
Requested: 55,845 MMSCF/year Actual:
MMSCF/year
4 Requested values will become permit limitations. Requested limit(s) should consider future process growth
Inlet Gas:
Pressure: 1003 psig
Temperature: 100
°F
Rich Amine Feed:
Pressure:
Flowrate:
1000
psia
Gal/min
Temperature: 151
°F
Lean Amine
Stream:
Pressure:
1150
psia
Temperature: 123
Flowrate: 600 Gal/min Wt. % amine: 45
Mole loading H2S
Mole Loading
CO2
°F
Sour Gas Input:
Pressure: 1000 psia Temperature: 99.8 °F
Flowrate:
MMSCF/Day
NGL Input:
Pressure:
Flowrate:
psia
Gal/min
Temperature:
°F
Flash Tank:
El No Flash Tank
Pressure: 60
psia
Temperature: 152
°F
Additional Required Information:
• Attach a Process Flow Diagram
❑ Attach the simulation model inputs Et emission report
▪ Attach composition reports for the rich amine feed, sour gas feed, NGL feed, Et outlet stream (emissions)
✓❑ Attach the extended gas analysis (including BTEX Et n -Hexane, H2S, CO2, temperature, and pressure)
Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017
31
ieeLOOAOP
«-mac
Asett
❑✓ Upward
❑ Horizontal
Permit Number:
AIRS ID Number: 123 I 0g/ 4,
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 5 - Stack Information
eographtcal Coordinates
'Latitude/Longitude or UTM
......., ii e air a ,.
ack Il k o
tschar
�tf� (� h
A oT 6
VV:
pm'Z"ch'y36
height
j4�G rG
4i-Leve
�
S
�
.-�ci.4'Yf sr
-
JIt
i ".""° °xi3
i d
tcF
E£ 1J4t
f#t7 c
TO -91700
Indicate the direction of the stack outlet: (check one)
❑ Downward
❑ Other (describe):
❑ Upward with obstructing raincap
Indicate the stack opening and size: (check one)
Circular Interior stack diameter (inches):
❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches):
❑ Other (describe):
...........................................
COLORADO
Dep+nmmsmPm.thc
%c=Eih USttHSIRpmiM
Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 4
Permit Number:
AIRS ID Number: 123 I Oa/ O 7 -
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 6 - Control Device Information
❑ VRU:
Used for control of:
Size: Make/Model:
Requested Control Efficiency %
VRU Downtime or Bypassed
❑ Combustion
Device:
Used for control of: Still Vent
Rating: 27.5 MMBtu/hr
Type: Thermal Oxidizer Make/Model: TBD
Requested Control Efficiency: 99 %
Manufacturer Guaranteed Control Efficiency 99 %
Minimum Temperature: 1400 Waste Gas Heat Content 5
Btu/scf
Constant Pilot Light: ❑ Yes ❑ No Pilot burner Rating MMBtu/hr
❑ Other:
Used for control of: Flash Gas
Description:
Flash tank overhead returned to the process via
Control Efficiency
Requested
low pressure gathering during normal operation.
0
Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 5 I
ORADO
rn:itr_uc
PM
PM
Permit Number:
AIRS ID Number: 123 I Oai o - 3'
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 7 -Emissions Inventory Information
Attach all emission calculations and emission factor documentation to this APEN form.
Is any emission control equipment or practice used to reduce emissions? ® Yes ❑ No
If yes, please describe the control equipment AND state the overall control efficiency (% reduction):
verall Requested Control,
Efficielncy
(%feduction in;emrssions)
SOX
H2S
NOX
VOC
Thermal Oxidizer
99%
CO
HAPs
Thermal Oxidizer
99%
Other:
From what year is the following reported actual annual emissions data:?
Use the following table to report the criteria pollutant emissions from source:
(Use the data reported in Sections 4 and 6 to calculate these emissions.)
nteria Pollutan
missions Invents
ncontrolled
m1ss�on
Factor;
Ib/MMbtu
Emission
F actor ,,,
ourc
(AP 42
tfig.'et
Uncontrolled
(Tons/year} _:
ontrolled5
(Tons!year)
Requested Annual Permit
Emis`sion;'Limit(s)4 a'' ,
ncontrolled
(Tons/year)
Controlled
(Tons/year)'
0.01
120% x AP -42
1.1
Sox
0.118
lb/MMbtu
AP -42 + Mass Bal.
24.9
H2S
0.063
lb/MMbtu
Mass Balance
13.2
0.13
NOX
0.098
Ib/MMbtu
AP -42
11.8
VOC
1.671
lb/MMbtu
sim.x175 % +AP42
201.2
2.7
CO
0.082
Ib/MMbtu
AP -42
9.9
4 Requested values will become permit limitations. Requested limit(s) should consider future process growth.
5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017 6
eoLOSAoo
l veu-04n.b.inw;rea:mmi
Benzene
71432
Permit Number:
AIRS ID Number: 123 /OW O
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 7 (continued)
ena Rej
orta
ncontrolled
`nission
ctor
[e Pollutant Emissions Invento
lb/MMbtu
AP-42+Mass bal.
ual,Annual Emissio
Toluene
108883
0.099
Ib/MMbtu
AP-42+Mass bal.
Ethylbenzene
100414
lb/MMbtu
AP-42+Mass bal.
Xylenes
1330207
lb/MMbtu
AP-42+Mass bal.
n -Hexane
110543
Ib/MMbtu
AP-42+Mass bal.
2,2,4-
Trimethylpentane
540841
Other:
5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
Section 8 - Applicant Certification
I hereby certify that all information contained herein and information submitted with this application is complete, true
and correct.
Jillian Yamartino
Digitally signed by Jillian Yamartino
Date: 2018.01.29 11:03:09 -07'00'
1/29/2018
Signature of Legally Authorized Person (not a vendor or consultant)
Jillian Yamartino
Date
HSE Representative
Name (please print)
Title
Check the appropriate box to request a copy of the:
❑✓ Draft permit prior to issuance
❑r Draft permit prior to public notice
(Checking any of these boxes may result in an increased fee and/or processing time)
Send this form along with $152.90 to:
Colorado Department of Public Health and
Environment
Air Pollution Control Division
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, CO 80246-1530
Make check payable to:
Colorado Department of Public Health and
Environment
Telephone: (303) 692-3150
For more information or assistance call:
Small Business Assistance Program
(303) 692-3175 or (303) 692-3148
Or visit the APCD website at:
https://www.colorado.gov/cdphe/apcd
!c OL.c RADDO
Form APCD-206 - Amine Sweetening Unit APEN - Revision 04/2017
7I
General APEN - Form APCD-200
Air Pollutant Emission Notice (APEN) and
Application for Construction Permit
Alt sections of this APEN and application must be completed for both new and existing facilities, including APEN
updates. An application with missing information may be determined incomplete and may be returned or result in
longer application processing times. You may be charged an additional APEN fee if the APEN is filled out
incorrectly or is missing information and requires re -submittal.
There may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). A list of
specialty APENs is available on the Air Pollution Control Division (APCD) website at:
www. colorado.Qov/cdphe/apcd.
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Permit Number:
toe) uffi
AIRS ID Number: 123 / 0057 / ri
[Leave blank unless APCD has already assigned a permit If and AIRS ID]
Section 1 - Administrative Information
Company Name':
Site Name:
Kerr McGee Gathering
Lancaster 3 Gas Plant
Site Location: 16116 WCR 22, Ft. Lupton, CO
Mailing Address: PO
Code)
(Include ZipBox 173779
Portable Source
Home Base:
Denver, CO 80217
Site Location Weld
County:
NAICS or SIC Code: 1321
Permit Contact: Jillian Yamartino
Phone Number: 720-929-4374
E -Mail Address2: jillian.yamartino@anadarko.com
Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear
on all documents issued by the APCD. Any changes will require additional paperwork.
2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided.
Form APCD-200 - General APEN - Revision 1/2017 1 I
to .ORADO
bscuten=rof FCS4s
- %.* FNaafranm+r<
Permit Number:
AIRS ID Number: 123 /0057 / ,
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 2- Requested Action
❑✓ NEW permit OR newly -reported emission source (check one below)
❑✓ STATIONARY source ❑ PORTABLE source
-OR -
❑ MODIFICATION to existing permit (check each box below that applies)
❑ Change fuel or equipment D Change company name ❑ Add point to existing permit
❑ Change permit limit ❑ Transfer of ownership3 ❑ Other (describe below)
-OR-
❑ APEN submittal for update only (Blank APENs will not be accepted)
- ADDITIONAL PERMIT ACTIONS -
❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE)
❑ APEN submittal for permit exempt/grandfathered source
Additional Info £t Notes: Air -assisted process flare
3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted.
Section 3 - General Information
General description of equipment and purpose:
Air -assisted process flare
Manufacturer: TDB Model No.: TBD Serial No.: TBD
Company equipment Identification No. (optional): FL -90100
For existing sources, operation began on:
For new or reconstructed sources, the projected start-up date is:
12/1/2019
❑✓ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below:
Normal Hours of Source Operation: hours/day
Seasonal use percentage: Dec -Feb: 25
Mar -May: 25
days/week weeks/year
Jun -Aug: 25
Sep -Nov: 25
COLO•RAbt3
2 I egatnv cY tu5fic
VVV Nub 6?Y-�mn:!wt
Form APCD-200 - General APEN - Revision 1/2017
Permit Number:
AIRS ID Number: 123 / 0057/ G,- fei
[Leave blank unless APCD has already assigned a permit 11 and AIRS ID] •
Section 4 - Processing/Manufacturing Information r* Material Use
O Check box if this information is not applicable to source or process
From what year is the actual annual amount?
Design Process
total combusted gas
85 MMscf/yr
nested Annu
Z eery Y,n.l:. L:
'ermit i_fmt
pecify Uni
'-8& M M scf/yr
93'4".1—
Fti/) 5/3 r/!
p3.2 -r
4 Requested values will become permit limitations. Requested limit(s) should consider future process growth.
Section 5 - Stack Information
eographical Coordinates=
Latitude/Longitude or UTM)
❑ Check box if the following information is not applicable to the source because emissions will not be emitted
from a stack. If this is the case, the rest of this section may remain blank.
�Operator�
Discharge (eight
nu Le
AbGrnd ve
ave
ge
Temp
�� �Q
I )auk Rate
F Ue t t�
sec
FL -90100
-110 feet
60.18 compl.
Indicate the direction of the stack outlet: (check one)
❑✓ Upward
❑ Horizontal
❑ Downward
❑ Other (describe):
Indicate the stack opening and size: (check one)
❑✓ Circular Interior stack diameter (inches):
❑ Square/rectangle Interior stack width (inches):
❑ Other (describe):
❑ Upward with obstructing raincap
Interior stack depth (inches):
COLORADO
Form APCD-200 - General APEN - Revision 1/2017 3 I
'Apssrmc•Lti]xblic
ner.�.asxacrsmee�<
TSP (PM)
Permit Number:
AIRS ID Number: 123 /0057/ r; f el
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 6 - Combustion Equipment a Fuel Consumption Information
❑ Check box if this information is not applicable to the source (e.g. there is no fuel -burning equipment associated
with this emission source)
Design Input Rate
(MMBTUIhr)
Actual Annual Fuel Use
(Spec y Units)
Requested Annual Permit Limit
(Specify up,t4
12.5
85 MMscf/yr
From what year is the actual annual fuel use data?
Indicate the type of fuel used5:
El Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF)
❑ Field Natural Gas Heating value: BTU/SCF
❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon)
❑ Propane (assumed fuel heating value of 2,300 BTU/SCF)
❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content:
❑ Other (describe): Heating value (give units):
a Requested values will become permit limitations. Requested limit(s) should consider future process growth.
5 If fuel heating value is different than the listed assumed value, provide this information in the "Other" field.
Section 7 - Criteria Pollutant Emissions Information
Attach all emission calculations and emission factor documentation to this APEN form.
Is any emission control equipment or practice used to reduce emissions? ❑✓ Yes ❑ No
If yes, describe the control equipment AND state the overall control efficiency (% reduction):
erall Control'Efficien
reduction in emissions
•
PM10
PM2.5
SOX
NOX
CO
VOC
combustion
98%
Other:
Form APCD-200 - General APEN - Revision 1/2017
41
.O1O RA OO
,p�srr.,c�crena4it
Benzene
98%
Permit Number:
AIRS ID Number: 123 /0057 / O3_14
[Leave blank unless APCD has already assigned a permit # and AIRS ID)
Section 7 (continued)
From what year is the following reported actual annual emissions data?
Use the following table to report the criteria pollutant emissions from source:
(Use the data reported in Sections 4 and 6 to calculate these emissions.)
TSP (PM)
Uncontroll
(Tons/year,
Controlled
(Tonslyear)
ncontrolie
Tons/year)
0
PM10
0
AP -42
PM2.5
0
AP -42
0
Sox
1.6E-3 lb/hr
m, balan @ 100% H2s conver.
de. min.
NOx
0.068 Ib/MMbtu
AP -42 @ 1300BTU/scf
3.8
CO
31 Jb/M Mbtu
AP -42 @ 1300BTU/scf
20.2'
voc
21.9 lb/hr
AP -42 & mass balance
97.6
2.0
Other:
a Requested values will become permit limitations. Requested limit(s) should consider future process growth.
6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
Section 8 - Non -Criteria Pollutant Emissions Information
Does the emissions source have any uncontrolled actual emissions of non -criteria
pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than
250 lbs/year?
If yes, use the following table to report the non -criteria pollutant (HAP) emissions
Incontrolled
Emission
Fa.
specify units)
❑r Yes ❑ No
from source:
mass balance
564
11.3
0.06 lb/hr
Toluene
98%
0.51 lb/hr
mass balance
4427
88.5
Ethylbenzene
98% .
0.13 lb/hr
mass balance
1157
23.1
Xylenes
98%
0.53 lb/hr
mass balance
5686
93.7
n -Hexane
98%
0.16 lb/hr
mass balance
1304
28.6
6 Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
O
Form APCD-200 - General APEN - Revision 1/2017
5I
Leputmrra3Po•,
H+:: , 0.?, rcam
Permit Number:
AIRS ID Number: 123 /0057 / Oc�
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 9 - Applicant Certification
I hereby certify that all information contained herein and information submitted with this application is complete,
true and correct.
Jillian Yamartino
Digitally signed by Jillian Yamartino
Date: 2018.01.29 11:52:44 -07'00'
1/29/2018
Signature of Legally Authorized Person (not a vendor or consultant) Date
Jillian Yamartino HSE Representative
Name (print) Title
Check the appropriate box to request a copy of the:
E Draft permit prior to issuance
❑✓ Draft permit prior to public notice
(Checking any of these boxes may result in an increased fee and/or processing time)
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Send this form along with $152.90 to: For more information or assistance call:
Colorado Department of Public Health and
Environment
Air Pollution Control Division
APCD-SS-B 1
4300 Cherry Creek Drive South
Denver, CO 80246-1530
Make check payable to:
Colorado Department of Public Health and Environment
Telephone: (303) 692-3150
Small Business Assistance Program
(303) 692-3175 or (303) 692-3148
Or visit the APCD website at:
https: //www.colorado.gov/cdphe/apcd
..............
Form APCD-200 - General APEN - Revision 1/2017
Tr:GOLORA,DO
v'e<1
(Ptilge)i
Fugitive Component Leak
Emissions APEN - Form APCD-203
Air Pollutant Emission Notice (APEN) and
Application for Construction Permit
All sections of this APEN and application must be completed for both new and existing facilities, including APEN
updates. An application with missing information may be determined incomplete and may be returned or result in
longer application processing times. You may be charged an additional APEN fee if the APEN is filled out
incorrectly or is missing information and requires re -submittal.
This APEN is to be used for fugitive component leak emissions. If your emission source does not fall into this
category, there may be a different specialty APEN available for your operation (e.g. natural gas venting,
condensate tanks, paint booths, etc.). In addition, the General APEN (Form APCD- 200) is available if the specialty
APEN options do not meet your reporting needs. A list of specialty APENs is available on the Air Pollution Control
Division (APCD) website at www.colorado.gov/cdphe/apcd.
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Permit Number:
AIRS ID Number: 123 / 0057 / 0 sO
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 1 - Administrative Information
Company Name:
Site Name:
Kerr-McGee Gathering LLC
Lancaster 3 Plant
Site Location: 16116 WCR 22, Ft. Lupton, CO
Mailing Address: PO Box 173779
(Include Zip Code)
Denver, CO 80217
Permit Contact: Jillian Yamartino
E -Mail Address2: jillian.yamartino@anadarko.com
Site Location Weld
County:
NAICS or SIC Code: 1321
Phone Number: 720-929-4374
Use the full, legal company name registered with the Colorado Secretary of State. This is the company name that will appear
on all documents issued by the APCD. Any changes will require additional paperwork.
2 Permits, exemption letters, and any processing invoices will be issued by APCD via e-mail to the address provided.
Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision
7/2017
Agr1.O Apo
nA
1I iHr-llk b₹+Wter.DepartasectecIPziddc
mr
Permit Number:
AIRS ID Number: 123 / 0057 /
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 2- Requested Action
❑✓ NEW permit OR newly -reported emission source (check one below)
-OR -
❑ MODIFICATION to existing permit (check each box below that applies)
❑ Change process or equipment ❑ Change company name ❑ Add point to existing permit
❑ Change permit limit ❑ Transfer of ownership3 ❑ Other (describe below)
-OR -
❑ APEN submittal for update only (Blank APENs will not be accepted)
- ADDITIONAL PERMIT ACTIONS -
El APEN submittal for permit exempt/grandfathered source
❑ Limit Hazardous Air Pollutants (HAPs) with a federally -enforceable limit on Potential To Emit (PTE)
Additional Info a Notes: Fugitive emissions.
3 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted.
Section 3 - General Information
For existing sources, operation began on:
For new or reconstructed sources, the projected start-up date is:
12/1/2019
O Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below:
Normal Hours of Source hours/day days/week
Operation:
Facility Type:
0 Well Production Facility4
❑ Natural Gas Compressor Station4
❑✓ Natural Gas Processing Plant4
0 Other
(describe):
weeks/year
4 When selecting the facility type, refer to definitions in Colorado Regulation No. 7, Section XVII.
Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision
7/2017
ta�o�nao
2 nom,a e
Noann Sttwirae ,ra
Permit Number: AIRS ID Number: 123
/ 0057 / OSt%
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 4 - Regulatory Information
What is the date that the equipment commenced construction?
Will this equipment be operated in any NAAQS nonattainment area?5 El Yes ❑ No
Will this equipment be located at a stationary source that is considered a Yes ❑ No
Major Source of Hazardous Air Pollutant (HAP) emissions?
Are there wet seat centrifugal compressors or reciprocating compressors ❑ Yes 0 No
located at this facility?
Is this equipment subject to 40 CFR Part 60, Subpart KKK? ❑ Yes O No
Is this equipment subject to 40 CFR Part 60, Subpart OOOO? ❑ Yes ❑✓ No
Is this equipment subject to 40 CFR Part 60, Subpart OOOOa? ✓❑ Yes ❑ No
Is this equipment subject to 40 CFR Part 63, Subpart HH? 0 Yes ❑ No
Is this equipment subject to Colorado Regulation No. 7, Section XII.G?❑ Yes ❑ No
Is this equipment subject to Colorado Regulation No. 7, Section XVII.F? ❑ Yes No
Is this equipment subject to Colorado Regulation No. 7, Section XVII.B.3? ❑ Yes ❑� No
5 See http://www.colorado.gov/cdphe/state-implementation-plans-sips for which areas are designated as attainment/non-
attainment.
Section 5 - Stream Constituents
❑ The required representative gas and liquid extended analysis (including BTEX) to support the data below has
been attached to this APEN form.
Use the following table to report the VOC and HAP weight % content of each applicable stream.
tream
Gas
22,100
enzene
oluene
•
wt %) :..
fthylbenzene
ylene
;wt %)_..
L)• .7
Heavy Oil
(or Heavy Liquid)
100
Light Oil
(or Light Liquid)
100
3
exane
4
me nthylpentane
o.
1518.
' .5
/.5
Water/Oil
Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision
7/2017
i✓ 131�r1�'
fcler
'1a
GOLOR ADO
3 I 4.1=0,0,4
Permit Number:
AIRS ID Number: 123 / 0057 /
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 6 - Geographical Information
eographical Coordinate
Latitude/Longitude or UT'
TBD
Attach a topographic site map showing location
Section 7 - Leak Detection and Repair (LDAR) and Control Information
Check the appropriate boxes to identify the LDAR program conducted at this site:
❑ LDAR per 40 CFR Part 60, Subpart KKK
❑ Monthly Monitoring - Control: 88% gas valve, 76% light liquid valve, 68% light liquid pump
❑ Quarterly Monitoring - Control: 70% gas valve, 61% light liquid valve, 45% light liquid pump
El LDAR per 40 CFR Part 60, Subpart OOOO/OOOOa
✓❑ Monthly Monitoring - Control: 96% gas valve, 95% light liquid valve, 86% light liquid pump, 81%
connectors
❑ LDAR per Colorado Regulation No. 7, Section XVII.F
❑ Other6:
❑ No LDAR Program
6 Attach other supplemental plan to APEN form if needed.
Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision
7/2017 4
_.._. _........ .
COLORADO
nrp.rsmsae.ox ramie
14..11 fttimrrsmeM
Permit Number:
AIRS ID Number: 123 / 0057 / cj>
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 8 - Emission Factor Information
Select which emission factors were used to estimate emissions below. If none apply, use the table below to
identify the emission factors used to estimate emissions. Include the units related to the emission factor.
E Table 2-4 was used to estimate emissions7.
❑ Table 2-8 (< 10,000ppmv) was used to estimate emissions7.
Use the following table to report the component count used to calculate emissions. The component counts listed
in the following table are representative of:
Q Estimated Component Count
❑ Actual Component Count conducted on the following date:
1,864
67
Counts
11,806
908
Emission Factor
2.0E-04
3.9E-04
4.5E-03
8.8E-03
Units
kg/hr/source
kg/hr/source
kg/hr/source
kg/hr/source
0,4-0Liquid
Counts
3,953
- (O5
17
468
9
Emission Factor
3.20E-05
8.40E-06
3.20E-05
Units
kg/hr/source
kg/hr/source
kg/hr/source
Light Oil (or Light Liqui
Counts
2,260
311
L
11
1,412
24
Emission Factor
7.50E-03
1.10E-04
1.30E-02
2.50E-03
7.50E-03
Units
kg/hr/source
kg/hr/source
kg/hr/source
kg/hr/source
kg/hr/source
:Water/
Count8
Emission Factor
Units
7 Table 2-4 and Table 2-8 are found in U.S. EPA's 1995 Protocol for Equipment Leak Emission Estimates (Document EPA -453/R-
95-017).
8 The count shall be the actual or estimated number of components in each type of service that is used to calculate the "Actual
Calendar Year Emissions" below.
9 The Other equipment type should be applied for any equipment other than connectors, flanges, open-ended lines, pump seals,
or valves.
Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision
7/2017
Co RADO
Kam.,
Permit Number:
AIRS ID Number: 123 / 0057 / v 4
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 9 - Criteria and Non -Criteria Pollutant Emissions Information
Attach all emission calculations and emission factor documentation to this APEN form.
From what year is the following reported actual annual emissions data?
Use the following table to report the criteria pollutant emissions and non -criteria pollutant (HAP) emissions from source:
Use the data reported in Section 8 to calculate these emissions.
ChemicalName:
C
Actual Annual
Emissions
RequeAn stedAnnual Permit Emission Limit(s:
Number
Uncontrolled
(tonslyear} , ;
Contro(ledi°
(tonslyegr}„
Uncontrolled ',
(tons year) , ,.',
Controlleda
{tonslyear}
voC
136.3
19.2
Does the emissions source have any actual emissions of individual non -criteria
pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 ❑ Yes ® No
lbs/year?
If yes, use the following table to report the non -criteria pollutant (HAP) emissions from source:
Benzene
71432
umber
ctua
Annual Emissions'
IuestedAnnual Permit Emission
mtt
Incontrolle
(lbs/year)'?.
ontrollei
((6s/y'e'ar.
ncor trotle
([6s/year)
• 6711- i. (,5'
ontrolle
(lbs/year
446-7- t� 4
Toluene
108883
6711
446.7 ,1
Ethylbenzene
100414
6711 ly5
b
Xylene
1330207
I
1167 l,1
n -Hexane
110543
1473 3441;
2543 3q3
2,2,4
Trimethylpentane
Other:
540841
U I
.010.2 4)Q
1° Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave
blank.
Requested values will become permit limitations. Requested limit(s) should consider future process growth, component count
variability, and gas composition variability.
Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision
7/2017
......._...... .
C is L!D R-ADo
6I .. .
i iiaxsue�bZe�,rarananh
Permit Number: AIRS ID Number: 123 / 0057 /
[Leave blank unless APCD has already assigned a permit # and AIRS ID]
Section 10 - Applicant Certification
I hereby certify that all information contained herein and information submitted with this application is complete,
true and correct.
Jillian Yamartino
Digitally signed by Jillian Yamartino
Date: 2018.01.29 10:57:25 -07'00'
1/29/2018
Signature of Legally Authorized Person (not a vendor or consultant) Date
Jillian Yamartino HSE Representative
Name (print) Title
Check the appropriate box to request a copy of the:
El Draft permit prior to issuance
E✓ Draft permit prior to public notice
(Checking any of these boxes may result in an increased fee and/or processing time)
This emission notice is valid for five (5) years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc.). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
Send this form along with $152.90 to: For more information or assistance call:
Colorado Department of Public Health and
Environment
Air Pollution Control Division
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, CO 80246-1530
Make check payable to:
Colorado Department of Public Health and Environment
Telephone: (303) 692-3150
Small Business Assistance Program
(303) 692-3175 or (303) 692-3148
Or visit the APCD website at:
https://www.colorado.gov/cdphe/apcd
Form APCD-203 - Fugitive Component Leak Emissions APEN - Revision
7/2017
COLORADO
ANY
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