HomeMy WebLinkAbout20092935.tiffSTATE OF COLORADO
Bill Ritter, Jr., Governor
James B. Martin, Executive Director
Dedicated to protecting and improving the health and environment of the people of Colorado
4300 Cherry Creek Dr. S.
Denver, Colorado 80246-1530
Phone (303) 692-2000
TDD Line (303) 691-7700
Located in Glendale, Colorado
http://www.cdphe.state.co.us
November 6, 2009
Mr. Steve Moreno
Weld County Clerk
1402 N. 17th Ave.
Greeley, CO 80631
Dear Mr. Moreno:
Laboratory Services Division
8100 Lowry Blvd.
Denver, Colorado 80230-6928
(303) 692-3090
Colorado Department
of Public Health
and Environment
The Air Pollution Control Division will publish a public notice for the DCP Midstream, LP. This public
notice will be published in The Greeley Tribune on November 12, 2009.
Thank you for assisting the Division by making the enclosed package (includes public notice,
preliminary analysis, Air Pollutant Emission Notice(s) and draft permit(s)) available for public review
and comment. It must be available for public inspection for a period of thirty (30) days from the date
the public notice is published.
Please forward any comment regarding this public notice to the address below.
Colorado Department of Public Health and Environment
APCD-SS-B 1
4300 Cherry Creek Drive South
Denver, CO 80246-1530
Attention: Jacquie Barela
Regards,
Jacqueline N. Barela
Public Notice Coordinator
Stationary Sources Program Air Pollution Control Division
Roll' c.t G Rtti'eta
13_3/O(1
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NOTICE OF INTENTION TO MODERNIZE / EXPAND
MEWBOURN NATURAL GAS PROCESSING PLANT
BY
DCP MIDSTREAM, LP
CONTENTS
1. PUBLIC NOTICE
2. PRELIMINARY ANALYSIS
3. APPLICATION FOR CONSTRUCTION PERMIT
AND AIR POLLUTANT EMISSION NOTICES
ON COMPACT DISK
4. DRAFT PERMIT
PREPARED BY:
RAM N. SEETHARAM
COLORADO DEPARTMENT OF PUBLIC HEALTH & ENVIRONMENT
4300 CHERRY CREEK DRIVE SOUTH, APCD-SS-BI
GLENDALE CO 80246-1530
STATE OF COLORADO
Bill Ritter, Jr., Governor
James B. Martin, Executive Director
Dedicated to protecting and improving the health and environment of the people of Colorado
4300 Cherry Creek Dr. S.
Denver, Colorado 80246-1530
Phone (303) 692-2000
TDD Line (303) 691-7700
Located in Glendale, Colorado
http://www.cdphe.state.co.us
Laboratory Services Division
8100 Lowry Blvd.
Denver, Colorado 80230-6928
(303) 692-3090
Released to: The Greeley Tribune on November 6, 2009; published November 12, 2009
PUBLIC NOTICE OF A PROPOSED PROJECT
OR ACTIVITY WARRANTING PUBLIC COMMENT
Colorado Department
of Public Health
and Environment
The Colorado Air Pollution Control Division has declared that the following proposed construction activity
warrants public comment. Therefore, the Air Pollution Control Division of the Colorado Department of Public
Health and Environment hereby gives NOTICE, pursuant to Section 25-7-114.5(5), C.R.S. of the Colorado Air
Quality Control Act that an application to the Division has been received for an emission permit on the following
proposed project and activity:
DCP Midstream, LP owns and operates a natural gas processing facility, known as Mewbourn Natural Gas
Processing Plant, located in the Southeast 'A of Section 35, Township 4 North, Range 66 West, southeast of
Gilcrest, near the intersection of Weld County Roads 35 and 38, in Weld County, Colorado. This facility is
classified as a Major Stationary Source and subject to New Source Review (Non -Attainment) provisions, and also
subject to Operating Permit provisions under Title V of the Federal Clean Air Act. The company has proposed to
modernize and expand the facility to increase the facility's gas processing capacity from 75 MMSCF per day to
125 MMSCF per day.
The company has made an application to the Division for granting a Construction Permit for the above
modernization / expansion project. Modernized / expanded facility will consist of:
Operating three existing compressor engines without modification/s.
Operating four existing compressor engines with modification/s for enhanced controls and accepting limited
operations of these engines.
Operating existing stabilized natural gas condensate tanks and loadout/s with new emission controls (refrigerated
condensers).
Operation of all other existing emission sources (except insignificant activities) will be discontinued, and rendered
inoperable or removed from the facility.
Adding two natural gas fired combustion turbines powering inlet natural gas compressors. These will be
equipped with Dry Low NOx Combustion Systems.
Adding five natural gas fired engines powering residue natural gas compressors. These are low emissions engines
with oxidation catalysts for control of Carbon Monoxide (CO), Volatile Organic Compounds (VOC), and
Hazardous Air Pollutants (HAPs).
Adding two natural gas fired combustion turbines running electric power generators. Generated electric power is
used for running various gas processing equipment. These are equipped with Dry Low NOx Combustion
Systems.
Adding a natural gas sweetening (by removal of Carbon Dioxide and Hydrogen Sulfide) system. Emissions will
be controlled by a Thermal Oxidizer. This will be supported by a natural gas fired amine regeneration reboiler
equipped with Ultra Low NOx combustion system.
Adding a natural gas dehydration system using triethylene glycol. Emissions will be controlled by a condenser,
and uncondensed gases are routed to a Thermal Oxidizer.
This modification to the facility is a potential major modification of a major stationary source. With federally
enforceable operating constraints and emission control requirements, the emission changes will be less than the
major modification thresholds. With the issuance of such a permit, and compliance with the permit conditions,
the modification will be classified as a synthetic minor modification of a major stationary source.
A copy of the draft permit is available for review in the public comment package.
The Division hereby solicits and requests submission of public comment concerning the aforesaid proposed
project and activity for a period of thirty (30) days from and after the date of this publication. Any such comment
must be in writing and be submitted to the following addressee:
Roland C. Elea, P. E.
Colorado Department of Public I Iealth and Environment
4300 Cherry Creek Drive South, APCD-SS-B I
Glendale, Colorado 80246-1530
Within thirty (30) days following the said thirty (30) -day period for public comment, the Division shall consider
comments and, pursuant to Section 25-7-114.5(7)(a), either grant, deny, or grant with conditions, the emission
permit. Said public comment is solicited to enable consideration of approval of and objections to the proposed
construction of the subject project and activity by affected persons.
A copy of the application for the emission permit, the Preliminary Analysis of said application, and
accompanying data concerning the proposed project and activity are available for inspection at the office of the
Clerk and Recorder of Weld County during regular business hours and at the office of the Air Pollution Control
Division, Colorado Department of Public Ilealth and Environment. 4300 Cherry Creek Drive South, Glendale.
Colorado. Draft permit and preliminary analysis may also be reviewed on the Division's website:
http://www.cdphestate.co.us/ap/airpublicnotices.htm1
COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT
AIR POLLUTION CONTROL DIVISION
PRELIMINARY ANALYSIS
Applicant
DCP Midstream, LP
Permit No.
09WE1136
Plant Location
Mewbourn Natural Gas Processing Plant
SE 'A of Sec 35, T4N, R66W 6th PM, SE of Gilcrest near
the intersection of WCRs 35 and 38, Weld County
Source No.
123/0090/ALL
Review Engineer
Ram N. Seetharam
Date
11/06/2009
Control Engineer
R K Hancock III, P. E.
Page
1 of I
Project
Description
DCP Midstream, LP owns and operates a natural gas processing facility, known as Mewbourn
Natural Gas Processing Plant, located in the Southeast'/ of Section 35, Township 4 North, Range 66
West, southeast of Gilcrest, near the intersection of Weld County Roads 35 and 38, in Weld County,
Colorado. This facility is classified as a Major Stationary Source and subject to New Source Review
(Non -Attainment) provisions, and also subject to Operating Permit under Title V provisions of the
Federal Clean Air Act. The company has proposed to modernize and expand the facility to increase the
facility's gas processing capacity from 75 MMSCF per day to 125 MMSCF per day.
The company has made an application to the Division for granting a Construction Permit for the above
modernization / expansion project. Modernized / expanded facility will consist of:
Operating three existing compressor engines without modification/s.
Operating four existing compressor engines with modification/s for enhanced controls and accepting
limited operations of these engines.
Operating existing stabilized natural gas condensate tanks and loadout/s with new emission controls
(refrigerated condensers).
Operation of all other existing emission sources (except insignificant activities) will be discontinued,
and rendered inoperable or removed from the facility.
Adding two natural gas fired combustion turbines powering inlet natural gas compressors. These will be
equipped with Dry Low NOx Combustion Systems.
Adding five natural gas fired engines powering residue natural gas compressors. These are low
emissions engines with oxidation catalysts for control of Carbon Monoxide (CO), Volatile Organic
Compounds (VOC), and Hazardous Air Pollutants (HAPs).
Adding two natural gas fired combustion turbines running electric power generators. Generated electric
power is used for running various gas processing equipment. These are equipped with Dry Low NOx
Combustion Systems.
Adding a natural gas sweetening (by removal of Carbon Dioxide and Hydrogen Sulfide) system.
Emissions will be controlled by a Thermal Oxidizer. This will be supported by a natural gas fired amine
regeneration reboiler equipped with Ultra Low NOx combustion system.
Adding a natural gas dehydration system using triethylene glycol. Emissions will be controlled by a
condenser, and uncondensed gases are routed to a Thermal Oxidizer.
This modification to the facility is a potential major modification of a major stationary source. With
federally enforceable operating constraints and emission control requirements, the emission changes will
be less than the major modification thresholds. With the issuance of such a permit, and compliance with
the permit conditions, the modification will be classified as a synthetic minor modification of a major
stationary source.
Emission Sources
VOC / HAPs from various natural gas processes and equipment leaks. Combustion gases from:
reciprocating internal combustion engines, combustion turbines, amine reboiler, hot oil heater, and
thermal oxidizer.
Requested
Emissions
Total facility emissions after modernization (tons per year): PM/PM 10: 14.75; NOx: 151.28; VOC:
111.84; CO: 176.97; Sulfur Dioxide (SO2): 21.51; Any Single I IAP: 5.00; Total HAPs: 14.00
Regulatory Status
This modification is classified as a synthetic minor modification of a major stationary source.
Impact on
Ambient Air
Quality
Modeling was conducted for SO and NOx. Total maximum (source impact + background)
concentration in ambient air are estimated at: SO2(3-hour): 125.1; SO2 (24 -hour): 47.1 ug/m^3;
SO2 (annual): 6.8 ug/m^3; NOx (as NO2) (annual): 28.5 ug/m^3. This shows compliance with the
standards.
Public Comment
Requirement
To render the permit and permit conditions federally enforceable, and to classify the changes as a
synthetic minor modification of a major stationary source.
DRAFT
PERMIT
PERMIT NO:
DATE ISSUED:
ISSUED TO:
09WE1136
1136
DCP Midstream, LP
INITIAL APPROVAL
THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS:
Natural gas processing facility, known as Mewbourn Natural Gas Processing Plant, located in the
Southeast'' 'A of Section 35, Township 4 North, Range 66 West, southeast of Gilcrest, near the
intersection of Weld County Roads 35 and 38, in Weld County, Colorado.
THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING:
This is a facility -wide permit for a modernized / expanded natural gas processing facility consisting of emission
sources as detailed below. APEN-exempt sources are listed separately as an attachment:
AIRS Point ID
and Stack Height
Description
Make
Model
Serial No.
Existing emission sources that will continue to operate with no modifications
123/0090/101
Stk. Ht.: 16.48 ft.
Natural gas fired, 4 -stroke, rich -burn, naturally
aspirated, reciprocating internal combustion engine,
heat input rated at 2.6 MMBTU per hour, output rated
at 330 HP, running a natural gas / vapor compressor.
Emissions are controlled by AFR and a Non -Selective
Catalytic Reduction system. Identified as C-211.
Caterpillar
G379 NA
72B641
123/0090/102
Stk. Ht.: 40.00 ft.
Natural gas fired, 4 -stroke, rich -bum, turbocharged,
reciprocating internal combustion engine, heat input
rated at 12.8 MMBTU per hour, output rated at 1,680
HP, running a natural gas compressor. Emissions are
controlled by AFR-and a Non -Selective Catalytic
Reduction System. Identified as C-167.
Waukesha
L7044GSI
C13852-1
123/0090/103
Stk. Ht.: 40.00 ft.
Natural gas fired, 4 -stroke, rich -burn, turbocharged,
reciprocating internal combustion engine, heat input
rated at 11.6 MMBTU per hour, output rated at 1,478
HP, running a natural gas compressor. Emissions are
controlled by AFR and a Non -Selective Catalytic
Reduction System. Identified as C-179.
Waukesha
L7042GSI
240410
Equipment / Activities Continued...
AIRS Facility ID: 123/0090
Page I of 25
Colorado Department of uA DRAFT
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09 W E 1136
Initial Approval
PERMIT
anent
'ision
Equipment / Activities (Continuation -1) -
AIRS Point ID
and Stack Height
Description
Make
Model
Serial No.
Existing emission sources that will resume operation after modification/s for enhanced emission controls
123/0090/104
Natural gas fired, 4 -stroke, rich -bum, naturally
Waukesha
L7042 GU
286822
aspirated, reciprocating internal combustion engine,
Stk. Ht.: 23.21 ft.
heat input rated at 6.4 MMBTU per hour, output rated
at 896 HP, running a natural gas compressor.
Emissions are controlled by AFR and a Non -Selective
Catalytic Reduction system. Identified as C-129.
123/0090/105
Natural gas fired, 4 -stroke, rich -burn, naturally
Waukesha
L7042 GU
285300
aspirated, reciprocating internal combustion engine,
Stk. Ht.: 23.21 ft.
heat input rated at 6.4 MMBTU per hour, output rated
at 896 HP, running a natural gas compressor.
-
Emissions are controlled by AFR and a Non -Selective
Catal tic Reduction system. Identified as C-134.
123/0090/106
Natural gas fired, 4 -stroke, rich -burn, turbocharged,
Waukesha
L7042 GSI
339839
reciprocating internal combustion engine, heat input
Stk. Ht.: 27.98 ft.
rated at 11.2 MMBTU per hour, output rated at 1,478
HP, running a natural gas compressor. Emissions are
controlled by AFR and a Non -Selective Catalytic
Reduction system. Identified as C-130.
123/0090/107
Natural gas fired, 4 -stroke, rich -burn, turbocharged,
Waukesha
L7042 GSI
397541
reciprocating internal combustion engine, heat input
Stk. Ht.: 28.00 ft.
rated at 11.2 MMBTU per hour, output rated at 1,478
HP, running a natural gas compressor. Emissions are
controlled by AFR and a Non -Selective Catalytic
Reduction system. Identified as C-131.
Existing emission sources with additional components and augmentation / controls for modernization /
ex u ansion
123/0090/108
Facility Equipment Leaks. Emissions minimized by Leak Detection and Repair Program. F017.
Component Counts
Component
Count
Component
Count
Valves — Gas / Vapor
2522
Pump Seals — Light Liquid
38
Valves — Light Liquid
1982
Connectors — Gas / Vapor
1914
Relief Valves — Gas / Vapor
134
Connectors — Light Liquid
6066
Relief Valves — Light Liquid
36
Flange Joints — Gas / Vapor
1718
Compressors
14
Flange Joints — Light Liquid
1146
123/0090/109
Condensate loadout. Emissions controlled by a
refrigerated condenser
Custom
None
None
123/0090/110
Four (4) tanks, 400 bbl each, for storage of stabilized
Custom
None
None
natural gas condensate. Emissions controlled by a
refri crated condenser.
Equipment / Activities Continued...
Page 2 of 25
AIRS Facility ID: 123/0090
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09 WE 1136
Initial Approval
Colorado Department of Pu DRAFT
A
PERMIT
iment
'ision
Equipment / Activities (Continuation -2)
AIRS Point ID
Description
Make
Model
Serial No.
New emission sources for modernization / expansion
123/0090/111
Stk. Ht.: 35.80 ft.
Natural gas fired combustion turbine, heat input rated
at 50.1 MMBTU per hour. This is equipped with Dry
Low NOx combustion system for minimizing
emissions of Nitrogen Oxides. This powers a natural
gas compressor. Identified as Inlet 1. C0170
Solar
Taurus 60
TBP
123/0090/112
Stk. Ht.: 35.80 ft.
Natural gas fired combustion turbine, heat input rated
at 50.1 MMBTU per hour. This is equipped with Dry
Low NOx combustion system for minimizing
emissions of Nitrogen Oxides. This powers a natural
_gas compressor. Identified as Inlet 2. C0180
Solar
Taurus 60
TBP
123/0090/113
Stk. Ht.: 45.00 ft.
Natural gas fired, 4 -stroke, turbo -charged, lean -burn,
low emissions design, reciprocating internal
combustion engine, heat input rated at 17.9 MMBTU
per hour, output rated at 2,370 HP, powering a natural
gas compressor. Emissions are controlled by an
oxidation catalyst. Identified as Residue 1. C250.
Caterpillar
G36o8TALE
BEN00563
123/0090/114
Stk. Ht.: 45.00 ft.
Natural gas fired, 4 -stroke, turbo -charged, lean -burn,
low emissions design, reciprocating internal
combustion engine, heat input rated at 17.9 MMBTU
per hour, output rated at 2,370 HP, powering a natural
gas compressor. Emissions are controlled by an
oxidation catalyst. Identified as Residue 2. C251.
Caterpillar
G3608TALE
BEN00565
123/0090/115
Stk. Ht.: 45.00 ft.
Natural gas fired, 4 -stroke, turbo -charged, lean -burn,
low emissions design, reciprocating internal
combustion engine, heat input rated at 17.9 MMBTU
per hour, output rated at 2,370 HP, powering a natural
gas compressor. Emissions are controlled by an
oxidation catalyst. Identified as Residue 3. C252.
Caterpillar
G36o8TALE
BEN00567
123/0090/116
Stk. Ht.: 45.00 ft.
Natural gas fired, 4 -stroke, turbo -charged, lean -burn,
low emissions design, reciprocating internal
combustion engine, heat input rated at 17.9 MMBTU
per hour, output rated at 2,370 HP, powering a natural
gas compressor. Emissions are controlled by an
oxidation catalyst. Identified as Residue 4. C253.
Caterpillar
G36o8TALE
BEN00572
123/0090/117
Stk. Ht.: 45.00 ft.
Natural gas fired, 4 -stroke, turbo -charged, lean -burn,
low emissions design, reciprocating internal
combustion engine, heat input rated at 17.9 MMBTU
per hour, output rated at 2,370 HP, powering a natural
gas compressor. Emissions are controlled by an
oxidation catalyst. Identified as Residue 5. C254.
Caterpillar
G36o8TALE
- -
BEN00571
Equipment / Activities Continued...
Page 3 of 25
AIRS Facility ID: 123/0090
Colorado Department of Pu A DRAFT
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09 WE 1136
Initial Approval
PERMIT
iment
vision
— -- - - - —
Equipment / Activities Continuation=
AIRS Point ID
Description
Make
Model
Serial No.
123/0090/118
Stk. Ht.: 45.00 ft.
Natural gas fired combustion turbine, heat input rated at
61.6 MMBTU per hour. This is equipped with Dry Low
NOx combustion system for minimizing emissions of
Nitrogen Oxides. This runs an electric power generator.
Identified as Genset 1. G1650.
Solar
Taurus 70
TG09548
123/0090/119
Stk. Ht.: 45.00 ft.
Natural gas fired combustion turbine, heat input rated at
61.6 MMBTU per hour. This is equipped with Dry Low
NOx combustion system for minimizing emissions of
Nitrogen Oxides. This runs an electric power generator.
Identified as Genset 2. G1670.
Solar
Taurus 70
TG09549
123/0090/120
Natural gas sweetening (by removal of Carbon Dioxide
and Hydrogen Sulfide) system using a 50 % solution of
Methyldiethanolamine (MDEA), process feed gas design
rated at 125 MMSCF per day, and an amine recirculation
rate of 540 gallons per minute. This system consists of:
natural gas / amine contactor, amine flash tank, and
amine regenerator (heating unit under AIRS PT ID:
123/0090/121). Emissions are routed to a regenerative
thermal oxidizer (AIRS PT ID: 123/0090/124).
Identified as AM001.
TBP
TBP
TBP
123/0090/121
Stk. Ht.: 20.00 ft.
Natural gas fired amine regeneration reboiler, heat input
design rated at 64.9 MMBTU per hour. This is equipped
with Ultra -Low NOx combustion system for
minimization of Nitrogen Oxides emissions. This is
identified as Amine Heater H776.
Zeeco
GLSF-16
TBP
123/0090/122
',.
Natural gas dehydration system using Triethyleneglycol
(TEG), process feed design rated at 125 MMSCF per day,
and a glycol recirculation rate of 26.8 gallons per minute.
This system consists of: natural gas / glycol contactor,
glycol flash tank, glycol regenerator reboiler (heat
provided by hot gases from various combustion processes
supplemented by a hot oil heater (AIRS Point ID:
123/0090/123). Flash tank off gases are directly routed to
regenerative thermal oxidizer. Still vent emissions are
routed through a condenser, and then to regenerative
thermal oxidizer (AIRS PT ID: 123/0090/124). Identified
as Deh dration Unit D-931.
TBP
TBP
TBP
123/0090/123
Stk. Ht.: 20.00 ft.
Natural gas fired hot oil heater, heat input design rated at
26.0 MMBTU per hour. This is equipped with Ultra-
Low-NOx combustion system for minimization of
Nitrogen Oxides emissions. Hot oil is used to provide
heat to various natural gas processes at the facility
including supplemental heat for glycol regeneration
reboiler. This is identified as Hot Oil Heater. H771.
Devco
HeliFlow
TBP
123/0090/124
Stk. Ht.: 40.00 ft.
Regenerative thermal oxidizer, heat input design rated at
11.0 MMBTU per hour. Natural gas used for startup.
This is equipped with Low NOx combustion system for
minimization of Nitrogen Oxides emissions. Emissions
from various processes at this facility arc routed into this
thermal oxidizer for thermal destruction. Natural gas is
used for startup to raise the temperature to normal
operating level. This is identified as Thermal Oxidizer.
TO701.
McGill
AirClean
MTT-10
RTO
TBP
Stk. Ht.: 75.00 ft.
Emergency Flare
End of Equipment / Activities.
Page 4 of 25
AIRS Facility ID: 123/0090
Colorado Department of Pu A DRAFT
tment
+ision
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
PERMIT
THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR
QUALITY CONTROL COM-MISSION AND THE -COLORADO AIR POLLUTION PREVENTION AND
CONTROL ACT C.R.S. (25-7-101 et seq), TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN
THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS:
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 initial approval 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; or (iii) does not complete construction within a reasonable time of the estimated completion date
(See General Condition No. 6., Item 1.). Upon a showing of good cause by the permittee, the Division may grant
extensions of the permit. (Reference: Regulation No. 3, Part B, Section III.F.4.)
2. Prior to the startup of operations under this permit, operation of all equipment / activities not specifically
included under this permit shall be discontinued, disconnected and rendered inoperable. Within thirty (30) days
of such discontinuance, a communication shall be sent to the Division requesting inactivation of those emission
sources in the Division's inventory system and cancellation of related Construction Permit/s. Such discontinued
equipment shall continue to be disconnected and inoperable if left at the facility or dismantled and removed from
the facility as expeditiously as possible, but, no later than six (6) months from the date of discontinuance. A
communication shall be sent to the Division confirming that all such equipment has been removed from the
facility.
3. Within one hundred and eighty days (180) after commencement of operation, compliance with the conditions
contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self certify
compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of
the permit. (Information on how to certify compliance was mailed with the permit.)
AIRS Point ID numbers (for example, "AIRS PT ID: 123/0090/101") shall be marked on the subject equipment
(except the piping components that are identified under Regulation No. 6, Part A, Subpart KKK) for ease of
identification. (Reference: Regulation No. 3, Part B, Section III.E.) (State only enforceable)
5. This source is subject to the odor requirements of Regulation No. 2. (State only enforceable)
6. 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. Opacity shall be measured by EPA
Method 9. (Reference: Regulation No. 1, Section ILA. I. & 4.)
7. Stack heights for discharge of emissions for various emission sources shall be at least the heights specified under
Specific Equipment / Activities.
8. Prevention of Significant Deterioration (PSD) requirements shall apply to this source at any such time that this
source becomes major for PSD solely by virtue of a relaxation in any permit condition. Any relaxation that
increases the potential to emit above the applicable PSD threshold will require a full PSD review of the source as
though construction had not yet commenced on the source. The source shall not exceed the PSD threshold until
a PSD permit is granted. (Reference: Regulation No.3, Part D, Section VI.B.4.)
9. Major stationary source requirements for non -attainment areas shall apply at such time that this source becomes
major solely by virtue of a relaxation in any permit condition. Any relaxation that increases the potential to emit
above the applicable major modification threshold will result in this source being subject to Major Stationary Source
requirements of Regulation No. 3, Part D, Section V. This source shall not exceed the major modification threshold
until compliance with Regulation No. 3, Part D, Section V. has been achieved.
Page 5 of 25
AIRS Facility ID: 123/0090
Colorado Department of u DRAFT
PERMIT
iment
ision
10. Within one hundred and eighty days (180) after commencement of operation, the applicant shall submit to the -
Division for approval an operating and maintenance plan for all control equipment and control practices, and a
proposed record keeping format that will outline how the applicant will maintain compliance on an ongoing basis
with the requirements of this permit. The operating and maintenance plan shall commence at startup. (Reference:
Regulation No. 3, Part B, Section III.G.7.)
11. This facility is subject to Regulation No. 7. Various emission sources are subject to, but not limited to the
following provisions:
Natural gas -fired, rich -burn, reciprocating internal combustion engines referenced under AIRS Points ID:
123/0090/102, 123/0090/103,123/0090/104, 123/0090/105, 123/0090/106, and 123/0090/107. These are subject to
Regulation No. 7, XVI. B. 1. Emissions from each of these engines shall be controlled by an air -to -fuel ratio
controller and a non -selective catalytic reduction system.
Natural gas -fired, lean -burn, reciprocating internal combustion engines referenced under AIRS Points ID:
123/0090/113,123/0090/114, 123/0090/115, 123/0090/116, and 123/0090/117. These are subject to Regulation
No. 7, XVI. B. 2. Emissions from each of these engines shall be controlled by an oxidation catalyst.
All new, modified or relocated (into the state) natural gas -fired reciprocating internal combustion engines are
subject to Regulation No. 7, XVII. E. 2. b. For engines (including those replacements under Alternative Operating
Scenarios provisions) that are claimed to be not subject to this provision of the regulation, documents shall be kept
demonstrating that those engines are existing, unmodified, and not relocated into the state. Emissions of various
pollutants shall not exceed the rates (grams per horsepower -hour) specified in the table below:
Maximum
Engine Horsepower
Construction, Modification or
Relocation (into the state) Date
pollutants and Emission
Standards gram/hp-hr
NOx
CO
VOC
Less than 100
Any
NA
NA
NA
Greater than 100 and less than 500
On or after January 1, 2008
2.0
4.0
1.0
On or after January 1, 2011
1.0
2.0
0.7
Greater than 500
On or after July 1, 2007
2.0
4.0
1.0
On or after July 1, 2010
1.0
2.0
0.7
Natural gas -fired, rich -burn, reciprocating internal combustion engines referenced under AIRS Points ID:
123/0090/102,123/0090/103,123/0090/104, 123/0090/105, 123/0090/106, and 123/0090/107. These are subject
to Regulation No. 7, XVII. E. 3. a. By July 1, 2010, each of these engines shall be operated with an air -to -fuel
ratio controller and a non -selective catalytic reduction system.
Natural gas -fired, lean -burn, reciprocating internal combustion engines referenced under AIRS Points ID:
123/0090/113,123/0090/114, 123/0090/115, 123/0090/116, and 123/0090/117. These are not subject to
Regulation No. 7, XVII. E. 3. b., as they are subject to Regulation No. 6, Part A, Subpart JJJJ.
Natural gas dehydration system referenced under AIRS Point ID: 123/0090/122. This emission source is not
subject to Regulation No. 7, XVII. D, as it is subject to a Federal MACT. However, this emission source is
subject to Regulation No. 7, XII. H. Uncontrolled actual emissions of volatile organic compounds from glycol
regenerator reboiler still vent and glycol flash tank shall be reduced by at least 90 percent through the use of
condenser or other air pollution control equipment.
Equipment leaks referenced under AIR Point ID: 123/0090/108. This is subject to Regulation No. 7, XII. G. I.
Emissions from equipment leaks shall be minimized by implementing a leak detection and repair program
(LDAR) conforming to Federal Standards of Performance for New Stationary Sources, codified under Chapter I,
Title 40 CFR Part 60, Subpart KKK, as soon as practicable, but no later than 180 days after initial startup.
Page 6 of 25
AIRS Facility ID: 123/0090
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
Colorado Department of Pu DRAFT
A
PERMIT
12. This facility is subject to Regulation No. 6, Part A, Subpart KKK, Standards of Performance for Equipment
Leaks of VOC from Onshore Natural -Gas Processing Plants, including, but not limited to, the following:
iment
vision
§ 60.632 Standards. A Leak Detection and Repair (LDAR) program shall be implemented.
§ 60.635 Recordkeeping requirements.
§ 60.636 Reporting requirements.
13. This facility is subject to Regulation No. 6, Part A, Subpart LLL, Standards of Performance for Onshore Natural
Gas Processing : SO2 Emissions, including, but not limited to, the following:
§ 60.647 Recordkeeping and reporting requirements:
§ 60.647(c) Certify that the facility's design capacity is less than 2 long tons per day of H2S in the
acid gas (expressed as sulfur), and is exempt from the control requirements of these
standards. An analysis shall be kept at the site for the life of the facility
demonstrating that the design capacity is less than 2 long tons per day of HZS
expressed as sulfur.
14. Natural gas -fired, lean -burn, reciprocating internal combustion engines referenced under AIRS Points ID:
123/0090/113, 123/0090/114, 123/0090/115, 123/0090/116, and 123/0090/117, are subject to Regulation No. 6,
Part A, Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion Engines,
including, but not limited to, the following:
§ 60.4233(e) Emission Standards
Date of Manufacture
Pollutants and Emission Standards, rams per hp -hour
NOx
CO VOC
After 7/1/2007 and before 7/1/2010
2.0
4.0 1.0
I
On and After 7/1/2010
1.0
2.0 0.7
§ 60.4243 Compliance Requirements
§ 60.4244 Testing Requirements
§ 60.4245 Notification, Reports and Records
15. Combustion turbines referenced under AIRS Points ID: 123/0090/111, 123/0090/112, 123/0090/118, and
123/0090/119, are subject to Regulation No. 6, Part A, Subpart KKKK, Standards of Performance for Stationary
Combustion Turbines, including, but not limited to, the following:
§ 60.4320 Emission Standards for Nitrogen Oxides _.
Concentration of Nitrogen Oxides in the exhaust gases shall not be in excess of 25
parts per million, at 15 % Oxygen.
§ 60.4330 Emission Standards for Sulfur Dioxide
Emissions of Sulfur Dioxide shall not be in excess of 0.06 pound per MMBTU heat
input. Compliance with this emission standard shall be demonstrated by firing natural
gas with sulfur content of 20 grains or less per 100 standard cubic feet.
Page 7 of 25
AIRS Facility ID: 123/0090
Colorado Department of Pu A DRAFT
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
PERMIT
iment
+ision
§ 60.4340 Compliance Demonstratimrfoi NMogen-Oxides-Standards by annual performance
tests in accordance with § 60.4400. If the NOx emission result from the performance
tests is less than or equal to 75 percent of the NOx emission limit for the turbine,
frequency of performance tests may be reduced to once every 2 years (no more than
26 calendar months following the previous performance tests). If the results of any
subsequent performance test exceed 75 percent of the NOx emission limit for the
turbine, annual performance tests must be resumed.
16. Amine Regeneration Reboiler, referenced under AIRS Point ID: 123/0090/121 and Hot Oil Heater, referenced
under AIRS Point ID: 123/0090/123 are subject to 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:
§ 60.48c Reporting and recordkeeping requirements.
The emission sources combust only pipeline quality natural gas.
17. All emission sources that are subject to one or other subpart of Regulation No. 6, Part A, are also subject to the
following requirements of Regulation No. 6, Part A, Subpart A, General Provisions:
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, Pan A. General Provisions from 40 CFR 60.11
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. (§ 60.12)
c. Written notification of construction and initial startup dates shall be submitted to the Division
as required under § 60.7.
Records of startups, shutdowns, and malfunctions shall be maintained, as required under
§ 60.7.
e. Excess Emission and Monitoring System Performance Reports shall be submitted as required
under § 60.7.
f. Performance tests shall be conducted as required under § 60.8.
g. General notification and reporting requirements under § 60.19.
18. Natural gas dehydration system, referenced under AIRS Point ID: 123/0090/122, is subject to the TEG
dehydrator area source 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:
Page 8 of25
AIRS Facility ID: 123/0090
Colorado Department of uA DRAFT
iment
'ision
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
§63.764 - General Standards
PERMIT
o §63.764 (e)(l) -The owner or operator is exempt from the requirements of paragraph (c)(1) and (d) of
this section if the criteria listed in paragraph (e)(1)(i) or (ii) of this section are met, except that the
records of the determination of these criteria must be maintained as required in §63.774(d)(1).
§63.764 (e)(1)(i) — The actual annual average flowrate of natural gas to the glycol dehydration
unit is less than 85 thousand standard cubic meters per day (3.0 MMSCF/day), as determined
by the procedures specified in §63.772(b)(I) of this subpart; or
§63.764 (e)(l)(ii) — The actual average emissions of benzene from the glycol dehydration unit
process vent to the atmosphere are less than 0.90 megagram per year (1.0 ton Benzene/year),
as determined by the procedures specified in §63.772(b)(2) of this subpart.
• §63.772 - Test Methods, Compliance Procedures and Compliance Demonstration
o §63.772(b) - Determination of glycol dehydration unit flowrate or benzene emissions. The procedures
of this paragraph shall be used by an owner or operator to determine glycol dehydration unit natural gas
flowrate or benzene emissions to meet the criteria for an exemption from control requirements under
§63.764(e)(1).
§63.772(b)(1) - The determination of actual flowrate of natural gas to a glycol dehydration unit
shall be made using the procedures of either paragraph (b)(1)(i) or (b)(1)(ii) of this section.
§63.772(b)(1)(i) — The owner or operator shall install and operate a monitoring
instrument that directly measures natural gas flowrate to the glycol dehydration unit
with an accuracy of plus or minus 2 percent or better. The owner or operator shall
convert annual natural gas flowrate to a daily average by dividing the annual flowrate
by the number of days per year the glycol dehydration unit processed natural gas.
• §63.772(b)(1)(ii) - The owner or operator shall document, to the Administrator's
satisfaction, that the actual annual average natural gas flowrate to the glycol
dehydration unit is less than 85 thousand standard cubic meters per day.
§63.772(b)(2) - The determination of actual average benzene emissions from a glycol
dehydration unit shall be made using the procedures of either paragraph (b)(2)(i) or (b)(2)(ii)
of this section. Emissions shall be determined either uncontrolled, or with federally
enforceable controls in place.
• §63.772(b)(2)(i) — The owner or operator shall determine actual average benzene
emissions using the model GRI-GLYCalc TM , Version 3.0 or higher, and the
procedures presented in the associated GRI-GLYCalc TM Technical Reference
Manual. Inputs to the model shall be representative of actual operating conditions of
the glycol dehydration unit and may be determined using the procedures documented
in the Gas Research Institute (GRI) report entitled "Atmospheric Rich/Lean Method
for Determining Glycol Dehydrator Emissions" (GRI-95/0368.1); or
§63.772(b)(2)(ii) - The owner or operator shall determine an average mass rate of
benzene emissions in kilograms per hour through direct measurement using the
methods in §63.772(a)(1)(i) or (ii), or an alternative method according to §63.7(f).
Annual emissions in kilograms per year shall be determined by multiplying the mass
rate by the number of hours the unit is operated per year. This result shall be
converted to megagrams per year.
• §63.774 - Recordkeeping Requirements
o §63.774 (d)(1) - An owner or operator of a glycol dehydration unit that mccts the exemption criteria in
§63.764(e)(1)(i) or §63.764(e)( 1 )(ii) shall maintain the records specified in paragraph (d)(1)(i) or
paragraph (d)(1)(ii) of this section, as appropriate, for that glycol dehydration unit.
Page 9 of 25
AIRS Facility ID: 123/0090
Colorado Department of a DRAFT
PERMIT
invent
+ision
§63.774 (d)(1)(i)— The actual annual average natural gas throughput (in terms of natural gas
flowrate to the glycol dehydration unit per day) as determined in accordance with
§63.772(b)(1), or
§63.774 (d)(1)(ii) - The actual average benzene emissions (in terms of benzene emissions per
year) as determined in accordance with §63.772(6)(2).
19. Natural gas -fired, lean -bum, reciprocating internal combustion engines referenced under AIRS Points ID:
123/0090/113, 123/0090/114, 123/0090/115, 123/0090/116, and 123/0090/117, are subject to Federal Maximum
Achievable Control Technology Standards codified under Chapter I, Title 40 CFR part 63, Subpart ZZZZ.
These engines are located at a facility that is an area source of hazardous air pollutants. Compliance with the
Federal Standards of Performance for New Stationary Sources codified under Chapter 1, Title 40 CFR Part 60,
Subpart JJJJ, is considered compliance with Federal Maximum Achievable Control Technology Standards
codified under Chapter 1, Title 40 CFR part 63, Subpart ZZZZ.
20. Various emission sources shall be equipped and operated with emission low emissions combustion systems and /
or control devices / systems to limit the emissions and to achieve at least the emission control efficiencies as
specified in the tables below. Periods during which these control devices / systems are not operating shall be
treated as upset conditions. Operating parameters of the control equipment shall be identified in the operation
and maintenance plan to be submitted with the compliance certification within one hundred and eighty days
(180) after commencement of operation. The identified operating parameters will replace the control efficiency
requirement on the final permit. (Reference: Regulation No.3, Part B, Section III.E.)
AIRS
Point
ID
Control Devices /
Control Systems
Pollutants and Minimum Overall Control Efficiencies (Percent) To Be Achieved
NOx
CO
VOC
75-07-
0
107-
02-8
71-
43-2
50-
00-0
110-
54-3
l0S-
88-3
1330-
20-7
101
AFR and NSCR
91.37
92.47
86.00
50.00
50.00
50.00
86.00
102
AFR and NSCR
91.11
92.25
86.00
50.00
50.00
50.00
86.00
103
AFR and NSCR
86.40
88.66
66.70
50.00
50.00
50.00
76.00
104
AFR and Advanced NSCR
95.50
81.20
80.00
50.00
50.00
50.00
86.00
105
AFR and Advanced NSCR
95.50
87.50
80.00
50.00
50.00
50.00
86.00
106
AFR and Advanced NSCR
95.50
87.50
80.00
50.00
50.00
50.00
86.00
107
AFR and Advanced NSCR
95.50
87.50
80.00
50.00
50.00
50.00
86.00
108
Leak Detection and Repair
67.61
67.59
109
Refrigerated Condenser
83.13
82.45
82.45
82.45
82.45
110
Refrigerated Condenser
83.15
82.45
83.11
83.11
83.11
113
AFR and Oxidation Catalyst
93.00
70.00
50.00
50.00
50.00
90.00
114
AFR and Oxidation Catalyst
93.00
70.00
50.00
50.00
50.00
90.00
115
AFR and Oxidation Catalyst
93.00
70.00
50.00
50.00
50.00
90.00
116
AFR and Oxidation Catalyst
93.00
70.00
50.00
50.00
50.00
90.00
117
AFR and Oxidation Catalyst
93.00
70.00
50.00
50.00
50.00
90.00
120
Thermal Oxidizer
99.00
99.00
99.00
99.00
99.00
122
Condenser and Thermal Oxid.
99.36
99.52
99.27
99.76
99.92
Low emissions combustion systems to limit the emissions as specified:
AIRS Point ID
Emission Limits
III
3 -hour average concentrations (ppmvd) in exhaust gases at 15 % Oxygen: NOx: 15; CO: 25
112
3 -hour average concentrations (ppmvd) in exhaust gases at 15 % Oxygen: NOx: 15; CO: 25
118
3 -hour average concentrations (ppmvd) in exhaust gases at 15 % Oxygen: NOx: 15; CO: 25
119
3 -hour average concentrations (ppmvd) in exhaust gases at 15 % Oxygen: NOx: 15; CO: 25
121
NOx: 30 pounds per MMSCF
123
NOx: 30 pounds per MMSCF
124
NOx: 0.068 pound per MMBTIJ
21. Various emission sources shall be limited to operation / processing / fuel use rates as listed below and all other
activities, operational rates and numbers of equipment as stated in the application. Monthly records of the actual
consumption rate shall be maintained by the applicant and made available to the Division for inspection upon
request. (Reference: Regulation No. 3, Part B, Section II.A.4.)
AIRS Facility ID: 123/0090
Page 10 of 25
Colorado Department of Pu A DRAFT
iment
iision
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
PERMIT
AIRS Point ID
/ Processing Fuel Use Rate Limits
- -Operation -I
123/0090/101
Natural gas for combustion: 1.84 MMSCF per month and 21.69 MMSCF per year.
123/0090/102
Natural gas for combustion: 9.11 MMSCF per month and 107.21 MMSCF per year.
123/0090/103
Natural gas for combustion: 8.19 MMSCF per month and 96.48 MMSCF per year.
123/0090/104
Operation: 1,488 hours/year.
Natural gas for combustion: 0.77 MMSCF per month and 9.11 MMSCF per year.
123/0090/105
Operation: 1,488 hours/year.
Natural gas for combustion: 0.77 MMSCF per month and 9.11 MMSCF per year.
123/0090/106
Operation: 4,464 hours/year
Natural gas for combustion: 4.04 MMSCF per month and 47.52 MMSCF per year.
123/0090/107
Natural gas for combustion: 7.92 MMSCF per month and 93.26 MMSCF per year.
123/0090/109
Throughput of stabilized natural gas condensate: 40,444 bbl/month and 476,190 bbl/year.
123/0090/110
Throughput of stabilized natural gas condensate: 40,444 bbl/month and 476,190 bbl/year.
123/0090/111
Natural gas for combustion: 35.50 MMSCF/month and 417.93 MMSCF/year
123/0090/112
Natural gas for combustion: 35.50 MMSCF/month and 417.93 MMSCF/year
123/0090/113
123/0090/114
Total operation for all 5 compressor engines: 35,040 compressor engine -hours per year.
123/0090/115
Total natural gas for combustion: 51.17 MMSCF/month and 602.47 MMSCF/year.
123/0090/116
123/0090/117
123/0090/118
Total operation of the 2 generator turbines: 9504 generator turbine -hours per year.
123/0090/119
Total natural gas for combustion: 47.34 MMSCF / month and 557.57 MMSCF / year.
123/0090/120
Feed natural gas: 3,875 MMSCF / month and 45,625 MMSCF per year.
123/0090/121
Natural gas for combustion: 45.986 MMSCF / month and 541.45 MMSCF / year.
123/0090/122
Feed natural gas: 3,875 MMSCF / month and 45,625 MMSCF per year.
123/0090/123
Natural gas for combustion: 18.422 MMSCF / month and 216.91 MMSCF / year.
123/0090/124
Waste gas (-1,074 BTU/SCF) combusted: 7.643 MMSCF / month and 89.99 MMSCF/year.
During the first twelve (12) months of operation, compliance with both the monthly and yearly consumption
limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly
limitation shall be required. Compliance with the yearly consumption limits shall be determined on a rolling
twelve (12) month total.
22. Emissions of air pollutants shall not exceed the following limitations (as calculated in the Division's preliminary
analysis). Compliance with the annual limits shall be determined on a rolling (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 monthly emissions and keep a compliance record on site for Division review. (Reference:
Regulation No. 3, Part B, Section II.A.4)
Total -facility- emissions:
Particulate Matter:
PM10 (Particulate Matter<I0 µm):
Sulfur Dioxide:
Nitrogen Oxides:
Volatile Organic Compounds:
Carbon Monoxide:
Any Single Hazardous Air Pollutant:
Total of All Hazardous Air Pollutants:
14.75 tons per year.
14.75 tons per year.
21.51 tons per year.
14.20 tons per month and 167.16 tons per year.
10.32 tons per month and 121.41 tons per year.
15.89 tons per month and 187.03 tons per year.
0.67 ton per month and 8.0 tons per year.
1.67 tons per month and 20.00 tons per year.
Page 11 of 25
AIRS Facility ID: 123/0090
Colorado Department of u DRAFT
A
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09 WE 1136
Initial Approval
From individual (or trouped) emission sources:
PERMIT
iment
iision
AIRS
Point
ID
Monthly and Yearly
Emission Limits
Tons per month
Tons per year
NOx
VOC
CO
NOx
VOC
CO
101
0.43
0.27
0.43
5.10
3.19
5.10
102
2.07
1.03
2.07
24.33
12.17
24.33
103
1.82
1.21
1.82
21.41
14.27
21.41
104
0.07
0.04
0.13
0.73.
0.44
1.47
105
0.07
0.04
0.13
0.73
0.44
1.47
106
0.31
0.19
0.62
3.64
2.18
7.27
107
0.61
0.36
1.21
7.14
4.28
14.27
108
2.70
31.73
109
0.83
9.71
110
0.29
3.36
111
1.12
NA
1.13
13.14
NA
13.32
112
1.12
NA
1.13
13.14
NA
13.32
113
3.89
2.41
1.50
45.76
28.28
17.56
114
115
116
117
118
1.49
NA
1.51
17.49
NA
17.76
119
120
0.34
3.98
121
0.69
0.13
1.94
8.12
1.49
22.74
122
0.32
3.75
123
0.28
NA
0.78
3.25
NA
9.11
124
0.28
NA
1.52
3.29
NA
17.88
During the first twelve (12) months of operation, compliance with both the monthly and yearly emission
limitations shall be required. After the first twelve (12) months of operation, compliance with only the yearly
limitation shall be required. Compliance with the yearly emission limits shall be determined on a rolling twelve
(12) month total.
23. Source compliance tests shall be conducted to measure the emission rate(s) for the pollutants listed below in
order to show compliance with various emission standards, emission limits, and to demonstrate performance of
the emission control devices / systems. 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 stack 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.
Volatile Organic Compounds using EPA approved methods.
Carbon Monoxide using EPA approved methods.
Formaldehyde
Benzene
n-l-lexane
Toluene
Xylenes
Page 12 of 25
AIRS Facility ID: 123/0090
Colorado Department of uA DRAFT
iment
+ision
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
PERMIT
- - 24.- - - Comp res,erenginesmay-be-replacedunder Alternative Operating Scenarios (AOS) provisions of Regulation
No. 3, Part A, IV. A. Methods and Procedures specified in Attachment A shall be complied with for such
replacement/s.
25. Compressor and electric power generator combustion turbines may be replaced under Alternative Operating
Scenarios (AOS) provisions of Regulation No. 3, Part A, IV. A. Methods and Procedures specified in
Attachment B shall be complied with for such replacement/s.
26. 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.b, for
minimization and / or control of emissions of Volatile Organic Compounds and Nitrogen Oxides. For the
requested emissions, compliance with the requirements to minimize and / or control the emissions specified in
this permit are determined to be RACT for this facility. Any request/s for modification of this permit for
increased allowable emissions shall be accompanied by RACT analyses.
27. A Revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation No. 3, Part A, Section II.C.)
a. Annually 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 tons per year or
more, above the level reported on the last APEN submitted; or
For VOC sources in ozone non -attainment areas emitting less than 100 tons of VOC per year, a change
in actual emissions of one ton per year or more or five percent, whichever is greater, above the level
reported on the last APEN submitted; or
For sources emitting 100 tons per year or more, a change in actual emissions of five percent or 50 tons
per year or more, whichever 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.
b. Whenever there is a change in the owner or operator of any facility, process, or activity; or
c. Whenever new control equipment is installed, or whenever a different type of control equipment
replaces an existing type of control equipment; or
d. Whenever a permit limitation must be modified; or
e. No later than 30 days before the existing APEN expires. APEN/s expires five (5) years from the date/s
of submittal.
Ram N. Seetharam Roland C. I -lea, P.E.
Permit Review Engineer Permits Section Supervisor
Page 13 of 25
AIRS Facility ID: 123/0090
Colorado Department of Pu A DRAFT
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
Permit History:
Date
Action
Description
This issuance
IA
Initial Approval. Synthetic Minor Modification of a Major Source.
Public comment conducted to render the permit and permit conditions
federally enforceable. Issued to DCP Midstream, LP. Upon startup
under this permit, all previously issued permits for this facility will be
canceled.
PERMIT
anent
vision
APEN Submittal Logs (to be maintained further by the permittee):
AIRS Points ID: 123/0090/101 and 123/0090/102
APEN Submittal Date
APEN Expiry Date
Renewal APEN to be
submitted by
Remarks
April 30, 2008
April 30, 2013
March 31, 2013
AIRS Point ID: 123/0090/103
APEN Submittal Date
APEN Expiry Date
Renewal APEN to be
submitted by
Remarks
October 5, 2009
October 5, 2014
September 5, 2014
All other AIRS Points ID:
APEN Submittal Date
APEN Expiry Date
Renewal APEN to be
submitted by
Remarks
August 21, 2009
August 21, 2014
July 22, 2014
Notes to Permit Holder:
1) The production or raw material processing limits and emission limits contained in this permit are based on the
production/processing rates requested in the permit application. These limits may be revised upon request of
the permittee 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 application form must be submitted with
a request for a permit revision.
2) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense Provision
for Excess Emissions During Malfunctions. The permittee 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.I. of the Common Provisions Regulation. See:
http://www.cdphe.state.co. us/regulations/airregs/ 100102agcccommonprovi sionsreg. pdf.
Page 14 of 25
AIRS Facility ID: 123/0090
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
Colorado Department of Pu DRAFT
A
PERMIT
3) This facility modification is classified as a:
Synthetic Minor Modification
At a: Major Facility
iment
'ision
4) This source is subject to the provisions of Regulation No. 3, Part C, Operating Permits (Title V of the 1990
Federal Clean Air Act Amendments). The application for modification of the Operating Permit to incorporate the
changes is due within one year of commencing operation after modification.
5) The following emissions of non -criteria reportable air pollutants are established based upon the activities
indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific
compounds. This information is listed on the Division's emission inventory system.
C.A.S.# SUBSTANCE EMISSIONS [LB/YR'
106-99-0 1,3 -Butadiene
75-07-0 Acetaldehyde
107-02-8 Acrolein
71-43-2 Benzene
100-41-4 Ethylbenzene
50-00-0 Formaldehyde
110-54-3 n -Hexane
108-88-3 Toluene
1330-20-7 Xylenes (isomers and mixture)
357
3,180
2,140
2,777
31
10,151
4,901
2,944
1,301
Page 15 of 25
AIRS Facility ID: 123/0090
Colorado Department of uA DRAFT
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09WE1136
E 1136
Initial Approval
ATTACHMEN-A
ALTERNATIVE OPERATING SCENARIOS
RECIPROCATING INTERNAL COMBUSTION ENGINES
October 8, 2008
PERMIT
iment
iision
The following Alternative Operating Scenario (AOS) for the temporary and permanent replacement of natural gas fired
reciprocating internal combustion engines has been reviewed in accordance with the requirements of Regulation No. 3.,
Part A, Section IV.A, Operational Flexibility -Alternative Operating Scenarios, Regulation No, 3, Part B, Construction
Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant
Deterioration, and it has been found to meet all applicable substantive and procedural requirements. This permit
incorporates and shall be considered a Construction Permit for any engine replacement performed in accordance with this
AOS, and the permittee shall be allowed to perform such engine replacement without applying for a revision to this
permit or obtaining a new Construction Permit.
A.1 Engine Replacement
The following AOS is incorporated into this permit in order to deal with a compressor engine breakdown or periodic
routine maintenance and repair of an existing onsite engine that requires the use of either a temporary or permanent
replacement engine. "Temporary" is defined as in the same service for 90 operating days or less in any 12 month period.
"Permanent" is defined as in the same service for more than 90 operating days in any 12 month period. The 90 days is the
total number of days that the engine is in operation. If the engine operates only part of a day, that day shall count as a
single day towards the 90 -day total. The compliance demonstrations and any periodic monitoring required by this AOS
are in addition to any compliance demonstrations or periodic monitoring required by this permit.
All replacement engines are subject to all federally applicable and state -only requirements set forth in this permit
(including monitoring and record keeping).
The results of all tests and the associated calculations required by this AOS shall be submitted to the Division within 30
calendar days of the test or within 60 days of the test if such testing is required to demonstrate compliance with NSPS or
MACT requirements. Results of all tests shall be kept on site for five (5) years and made available to the Division upon
request.
The permittee shall maintain a log on -site and contemporaneously record the start and stop date of any engine
replacement, the manufacturer, date of manufacture, model number, horsepower, and serial number of the engine(s) that
are replaced during the term of this permit, and the manufacturer, model number, horsepower, and serial number of the
replacement engine. In addition to the log, the permittee shall maintain a copy of all Applicability Reports required under
section A.1.2 and make them available to the Division upon request.
A.1.1 The permittee may temporarily replace an existing compressor engine that is subject to the emission limits set
forth in this permit with an engine that is of the same manufacturer, model, and horsepower or a different manufacturer,
model, or horsepower as the existing engine without modifying this permit, so long as the emissions from the temporary
replacement engine comply with the emission limitations for the existing permitted engine as determined in section A.2.
Measurement of emissions from the temporary replacement engine shall be made as set forth in section A.2.
A.1.2 The permittee may permanently replace the existing compressor engine with an engine that is of the same
manufacturer, model, emission controls and horsepower without modifying this permit so long as the emissions from the
permanent replacement engine comply with 1) the permitted annual emission limitations for the existing engine, 2) any
permitted short-term emission limitations for the existing permitted engine, and 3) the applicable emission limitations as
set forth in the Applicability Report submitted to the Division with the Air Pollutant Emissions Notice (APEN) for the
replacement engine. Measurement of emissions from the permanent replacement engine and compliance with the
applicable emission limitations shall be made as set forth in section A.2.
Page 16 of 25
AIRS Facility ID: 123/0090
Colorado Department of Pu A DRAFT
unent
+ision
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09 WE 1136
Initial Approval
PERMIT
The AOS cannot be used for the permanent replacement of an entire engine at any source that is currently a major
stationary source, ferpurposes-olPrevention-of Significant Deterioration or Non -Attainment Area New Source Review
("PSD/NANSR") unless the existing engine has emission limits that are below the significance levels in Reg 3, Part D,
II.A.42.
An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model and serial number and
horsepower of the permanent replacement engine shall be filed with the Division for the permanent replacement engine
within 14 calendar days of commencing operation of the replacement engine. The APEN shall be accompanied by the
appropriate APEN filing fee, a cover letter explaining that the permittee is exercising an alternative operating scenario
and is installing a permanent replacement engine, and a summary of any new applicable requirements for the replacement
engine, Example Applicability Reports can be found at http://www.cdphe.state.co.us/ap/oilgaspermitting.html. This
submittal shall be accompanied by a certification from the Responsible Official indicating that "based on the information
and belief formed after reasonable inquiry, the statements and information included in the submittal are true, accurate and
complete".
This AOS cannot be used for permanent engine replacement of a grandfathered or permit exempt engine or an engine that
is not subject to emission limits.
The permittee shall agree to pay fees based on the normal permit processing rate for review of information submitted to
the Division in regard to any permanent engine replacement.
Nothing in this AOS shall preclude the Division from taking an action, based on any permanent engine replacement(s),
for circumvention of any state or federal PSD/NANSR requirement. Additionally, in the event that any permanent engine
replacement(s) constitute(s) a circumvention of applicable PSD/NANSR requirements, nothing in this AOS shall excuse
the permittee from complying with PSD/NANSR and applicable permitting requirements.
A.2 Portable Analyzer Testing
The permittee shall measure nitrogen oxide (NOx) and carbon monoxide (CO) emissions in the exhaust from the
replacement engine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the
replacement engine.
All portable analyzer testing required by this permit shall be conducted using the Division's Portable Analyzer
Monitoring Protocol (ver March 2006 or newer) as found on the Division's website at:
http://www.cdphe.state.co.us/ap/downrnortanalyzeoroto.pdf
Results of the portable analyzer tests shall be used to monitor the compliance status of this unit.
For comparison with an annual (tons/year) or short term (lbs/unit of time) emission limit, the results of the tests shall be
converted to a lb/Iv basis and multiplied by the allowable operating hours in the month or year (whichever applies) in
order to monitor compliance. If a source is not limited in its hours of operation the test results will be multiplied by the
maximum number of hours in the month or year (8760), whichever applies.
For comparison with a short-term limit that is either input based (lb/mmBtu), output based (g/hp-hr) or concentration
based (ppmvd @ 15% O2) that the existing unit is currently subject to or the replacement engine will be subject to, the
results of the test shall be converted to the appropriate units as described in the above -mentioned Portable Analyzer
Monitoring Protocol document.
If the portable analyzer results indicate compliance with both the NOx and CO emission limitations, in the absence of
credible evidence to the contrary, the source may certify that the engine is in compliance with both the NOx and CO
emission limitations for the relevant time period.
AIRS Facility ID: 123/0090
Page 17 of 25
Colorado Department of uA DRAFT
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09 WE l 136
Initial Approval
PERMIT
intent
'ision
— Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable
analyzer results fail to demonstrate compliance with either the NOx or CO emission limitations, the engine will be
considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates
compliance with both the NOx and CO emission limitations or until the engine is taken offline.
A.3 Applicable Regulations for Permanent Engine Replacements If the facility is a major stationary source for
NANSR/PSI) and this engine does not have limits below significance levels in Reg 3, part D, II.A.42 (e.g., 39 tpy NOx
limit, etc.). permanent replacements are not allowed
A.3.1 Reasonably Available Control Technology (RACT): Reg 3, Part B § II.D.2
All permanent replacement engines that are located in an area that is classified as attainment/maintenance or
nonattainment must apply Reasonably Available Control Technology (RACT) for the pollutants for which the area is
attainment/maintenance or nonattainment. Note that both VOC and NOx are precursors for ozone. RACT shall be
applied for any level of emissions of the pollutant for which the area is in attainment/maintenance or nonattainment,
except as follows:
In the Denver Metropolitan PM10 attainment/maintenance area, RACT applies to PMR, at any level of emissions and to
NOx and SO2, as precursors to PM)°, if the potential to emit of NOx or SO2 exceeds 40 tons/yr.
For purposes of this AOS, the following shall be considered RACT for natural-gas fired reciprocating internal combustion
engines
VOC: The emission limitations in NSPS JJJJ
CO: The emission limitations in NSPS JJJJ
NOx: The emission limitations in NSPS JJJJ
SO2: Use of natural gas as fuel
PM1o: Use of natural gas as fuel
As defined in 40 CFR Part 60 Subparts GG (§ 60.331) and 40 CFR Part 72 (§ 72.2), natural gas contains 20.0 grains or
less of total sulfur per 100 standard cubic feet.
A.3.2 Control Requirements and Emission Standards: Regulation No. 7, Sections XVI. and XVII.E (State -Only
conditions).
Control Requirements: Section XVI
Any permanent replacement engine located within the boundaries of an ozone nonattainment area is subject to the
applicable control requirements specified in Regulation No. 7, section XVI, as specified below:
Rich burn engines with a manufacturer's design rate greater than 500 hp shall use a non -selective catalyst and air
fuel controller to reduce emission.
Lean bum engines with a manufacturer's design rate greater than 500 hp shall use an oxidation catalyst to reduce
emissions.
The above emission control equipment shall be appropriately sized for the engine and shall be operated and maintained
according to manufacturer specifications.
The source shall submit an applicability analysis with the summary report required under Condition A.1.2
Page 18 of 25
AIRS Facility ID: 123/0090
Colorado Department of u DRAFT
A
anent
iision
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09 WE 1136
Initial Approval
PERMIT
Emission Standards: SectionXVILE— State -only requirements
Any permanent engine that is either constructed or relocated to the state of Colorado from another state, after the date
listed in the table below shall operate and maintain each engine according to the manufacturer's written instructions or
procedures to the extent practicable and consistent with technological limitations and good engineering and maintenance
practices over the entire life of the engine so that it achieves the emission standards required in the table below:
Max Engine
HP
Construction or
Relocation Date
Emission Standards in G/hp-hr
NOx
CO
VOC
100<I-Ip<500
January 1, 2008
2.0
4.0
1.0
January 1, 2011
1.0
2.0
0.7
500<Hp
July 1, 2007
2.0
4.0
1.0
July 1, 2010
1.0
2.0
0.7
The source shall submit an applicability analysis with the summary report required under Condition A.1.2
A.3.3 NSPS for spark ignition internal combustion engines: 40 CFR 60, Subpart JJJJ
A permanent replacement engine that is manufactured on or after 7/1/09 for emergency engines greater than 25 hp,
7/1/2008 for engines less than 500 hp, 7/1/2007 for engines greater than or equal to 500 hp except for lean burn engines
greater than or equal to 500 hp and less than 1,350 hp, and 1/1/2008 for lean burn engines greater than or equal to 500 hp
and less than 1,350 hp are subject 40 CFR 60, Subpart JJJJ. An analysis of applicable monitoring, recordkeeping, and
reporting requirements for the permanent engine replacement shall be included in the summary report required under
Condition A.1.2. Any testing required by the NSPS is in addition to that required by this AOS.
Note that under the provisions of Regulation No. 6. Part B, section I.B. that Relocation of a source from outside of the
State of Colorado into the State of Colorado is considered to be a new source, subject to the requirements of Regulation
No. 6 (i.e., the date that the source is first relocated to Colorado becomes equivalent to the manufacture date for purposes
of determining the applicability of NSPS JJJJ requirements). See the NSPS JJJJ section of Appendix A for additional
discussion.
A.3.4 Reciprocating internal combustion engine (RICE) MACT: 40 CFR Part 63, Subpart ZZZZ
A.3.4.1 Area Source for HAPs
A permanent replacement engine located at an area source that commenced construction or reconstruction after June 12,
2006 as defined in § 63.2, will meet the requirements of 40 CFR Part 63, Subpart ZZZZ by meeting the requirements of
40 CFR Part 60, Subpart JJJJ. An analysis of the applicable monitoring, recordkeeping, and reporting requirements for
the permanent engine replacement shall be included in the summary report required under Condition A1.2. Any testing
required by the MACT is in addition to that required by this AOS.
AIRS Facility ID: 123/0090
Page 19 of 25
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09WE E 1 136
Initial Approval
A.4.3.2 Major source for HAPs
Colorado Department of uA DRAFT
PERMIT
anent
iision
A permanent replacement engine that is located at major source is subject to the requirements in 40 CFR Part 63 Subpart
ZZZZ as follows:
Existing, new or reconstructed spark ignition 4 stroke rich burn engines with a site rating of more than 500 hp
are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ.
New or reconstructed (construction or reconstruction commenced after 12/19/02) 2 stroke and 4 stroke lean burn
engines with a site rating of more than 500 hp are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ.
New or reconstructed (construction or reconstruction commenced after 6/12/06) 4 stroke lean burn engines with
a site rating of greater than or equal to 250 but less or equal to 500 hp and were manufactured on or after 1/1/08
are subject to the requirements in 40 CFR Part 63 Subpart ZZZZ.
New or reconstructed (construction or reconstruction commenced after 6/12/06) 2 stroke lean bum or 4 stroke
rich burn engines with a site rating of 500 hp or less will meet the requirements of 40 CFR 63, Subpart ZZZZ by
meeting the requirements of 40 CFR 60, Subpart JJJJ.
New or reconstructed (construction or reconstruction commenced after 6/12/06) 4 stroke lean burn engines with
a site rating of less than 250 hp will meet the requirements of 40 CFR 63, Subpart ZZZZ by meeting the
requirements of 40 CFR 60, Subpart JJJJ.
An analysis of the applicable monitoring, recordkeeping, and reporting requirements for the permanent engine
replacement shall be included in the summary report required under Condition A.1.2. Any testing required by
the MACT is in addition to that required by this AOS.
A.3.5 Additional Sources
The replacement of an existing engine with a new engine is viewed by the Division as the installation of a new emissions
unit, not "routine replacement" of an existing unit. The AOS is therefore essentially an advanced construction permit
review. The AOS cannot be used for additional new emission points for any site; an engine that is being installed as an
entirely new emission point and not as part of an AOS-approved replacement of an existing onsite engine has to go
through the appropriate Construction/Operating permitting process prior to installation.
Page 20 of 25
AIRS Facility ID: 123/0090
Colorado Department of Pu A DRAFT
invent
tision
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09WE1136
Initial Approval
ATTACHMENT B
ALTERNATIVE OPERATING SCENARIOS
COMBUSTION TURBINES
Routine Turbine Component Replacements
PERMIT
The following physical or operational changes to the turbines in this permit are not considered a modification for
purposes of NSPS GG, NSR/PSD, or Regulation No. 3:
I) Replacement of stator blades, turbine nozzles, turbine buckets, fuel nozzles, combustion chambers, seals, and shaft
packings, provided that they are of the same design as the original.
2) Changes in the type or grade of fuel used, if the original gas turbine installation, fuel nozzles, etc. were designed for its
use.
3) An increase in the hours of operation (unless limited by a permit condition)
4) Variations in operating loads within the engine design specification.
5) Any physical change constituting routine maintenance, repair, or replacement.
Turbines undergoing any of the above changes are subject to all federally applicable and state -only requirements set forth
in this permit (including monitoring and record keeping). If replacement of any of the components listed in (1) or (5)
above results in a change in serial number for the turbine, a letter explaining the action as well as a revised APEN and
appropriate filing fee shall be submitted to the Division within 30 days of the replacement.
Note that the repair or replacement of components must be of genuinely the same design. Except in accordance with the
Alternate Operating Scenario set forth below, the Division does not consider that this allows for the entire replacement (or
reconstruction) of an existing turbine with an identical new one or one similar in design or function. Rather, the Division
considers the repair or replacements to encompass the repair or replacement of components at a turbine with the same (or
functionally similar) components.
Alternative Operating Scenarios
The following Alternative Operating Scenario (AOS) for temporary and permanent combustion turbine replacement and
turbine component replacement has been reviewed in accordance with the requirements of Regulation No. 3., Part A,
Section IV.A, Operational Flexibility -Alternative Operating Scenarios, and Regulation No. 3, Part B, Construction
Permits, and Regulation No. 3, Part D, Major Stationary Source New Source Review and Prevention of Significant
Deterioration and has been found to meet all applicable substantive and procedural requirements. This permit
incorporates and shall be considered a Construction Permit for any combustion turbine replacement performed in
accordance with this AOS, and the permittee shall be allowed to perform such turbine or turbine component replacement
without applying for a revision to this permit or obtaining a new Construction Permit.
1. Turbine Replacement
The following AOS is incorporated into this permit in order to deal with a turbine breakdown or periodic routine
maintenance and repair of an existing onsite turbine that requires the use of a temporary replacement turbine.
"Temporary" is defined as in the same service for 90 operating days or less in any 12 month period. The 90 days is the
total number of days that the turbine is in operation. If the turbine operates only part of a day, that day counts towards the
90 day total. Note that the compliance demonstrations made as part of this AOS are in addition to any compliance
demonstrations required by this permit.
Page 21 of25
AIRS Facility Ill: 123/0090
Colorado Department of u DRAFT
PERMIT
All replacement turbines are subject to all federally applicable and state -only requirements set forth in this permit
(including monitoring and record keeping)
iment
'ision
Results of all tests and the associated calculations pursuant required by this AOS shall be submitted to the Division within
30 calendar days of the test. Results of all tests shall be kept on site for five (5) years and made available to the Division
upon request.
The permittee shall maintain a log on -site to contemporaneously record the start and stop date of any turbine replacement,
the manufacturer, model number, horsepower, and serial number of the turbine(s) that are replaced during the term of this
permit, and the manufacturer, model number, horsepower, and serial number of the replacement turbine.
Any permanent turbine replacement under this AOS may result in the replacement turbine being considered a new
affected facility for purposes of NSPS and shall be subject to all applicable requirements of that Subpart including, but
not limited to, any required Performance Testing.
a. The permittee may temporarily replace an existing permitted turbine provided such replacement
turbines are [e.g. GE LM6000] combustion turbines without modifying this permit, so long as the
emissions from the temporary replacement turbine comply with the emission limitations for the existing
permitted turbine as determined in Section 2. Measurement of emissions from the temporary
replacement turbine shall be made as set forth in Section 2.
b. The permittee may permanently replace the existing permitted combustion turbine provided such
replacement turbines are [e.g. GE LM6000] combustion turbines without modifying this permit so long
as the emissions from the permanent replacement turbine comply with the emission limitations for the
existing permitted turbine as determined in Section 2.
An Air Pollutant Emissions Notice (APEN) that includes the specific manufacturer, model, and serial number of the
permanent replacement turbine shall be filed with the Division for the permanent replacement turbine within 14 calendar
days of commencing operation of the replacement turbine. The APEN shall be accompanied by the appropriate APEN
filing fee and a cover letter explaining that the permittee is exercising an alternative operating scenario and is installing a
permanent replacement turbine.
This AOS cannot be used for permanent turbine replacement of a grandfathered turbine or a turbine that is not subject to
emission limits.
The permittee shall agree to pay fees based on the normal permit processing rate for review of information submitted to
the Division in regard to any permanent turbine replacement.
2. Portable Analyzer Testing
The permittee shall measure nitrogen oxide (NO„) and carbon monoxide (CO) emissions in the exhaust from the
replacement turbine using a portable flue gas analyzer within seven (7) calendar days of commencing operation of the
replacement engine.
All portable analyzer testing required by this permit shall be conducted using the Division's Portable Analyzer
Monitoring Protocol (ver March 2006 or newer) as found on the Division's website at:
http://www.cdphe.state.co.us/ap/down/portanalyzeproto.pdf
Results of the portable analyzer tests shall be used to monitor the compliance status of this unit. For comparison with an
annual or short term emission limit, the results of the tests shall be converted to a lb/hr basis and multiplied by the
allowable operating hours in the month or year (whichever applies) in order to monitor compliance. If a source is not
limited in its hours of operation the test results will be multiplied by the maximum number of hours in the month or year
(8760), whichever applies.
Page 22 of 25
AIRS Facility ID: 123/0090
DCP Midstream, LP — Mewboum Natural Gas Processing Plant
Permit No. 09 WE 1136
Initial Approval
Colorado Department of Pu DRAFT
A
PERMIT
iment
vision
If the portable analyzer results indicate compliance with both the NOx and -CO emission limitations, -in -the -absence -of-
credible evidence to the contrary, the source may certify that the turbine is in compliance with both the NO, and CO
emission limitations for the relevant time period.
Subject to the provisions of C.R.S. 25-7-123.1 and in the absence of credible evidence to the contrary, if the portable
analyzer results fail to demonstrate compliance with either the NO, or CO emission limitations, the turbine will be
considered to be out of compliance from the date of the portable analyzer test until a portable analyzer test indicates
compliance with both the NO, and CO emission limitations or until the turbine is taken offline.
3. Additional Sources
The replacement of an existing turbine with a new turbine is viewed by the Division as the installation of a new emissions
unit, not "routine replacement" of an existing unit. The AOS is therefore essentially an advanced construction permit
review. The AOS cannot be used for additional new emission points for any site; a turbine that is being installed as an
entirely new emission point and not as part of an AOS-approved replacement of an existing onsite turbine must go
through the appropriate Construction/Operating permitting process prior to installation.
PSD
4.2.8 At its discretion, the Division may require that the permittee apply for and obtain a minor
permit modification, in accordance with the provisions of Regulation No. 3, Part C, § X, for any
permanent turbine replacement.
4.2.9 Nothing in this AOS shall preclude the Division from taking an action, based on any
permanent turbine replacement(s), for circumvention of any state or federal Prevention of Significant
Deterioration or Non -Attainment New Source Review ("PSD/NSR") requirement. Additionally, in
the event that any permanent turbine replacement(s) constitute(s) a circumvention of applicable
PSD/NSR requirements, nothing in this AOS shall excuse the permittee from complying with
PSD/NSR and applicable Title V permitting requirements.
Page 23 of 25
AIRS Facility ID: 123/0090
Colorado Department of a DRAFT
ATTACHMENT C -
INSIGNIFICANT ACTIVITIES
PERMIT
iment
'ision
Space heating furnace (office), 0.100 MMBTU/hour
Water heater (office), 0.036 MMBTU/hour
Space heating furnace (shop), 0.100 MMBTU/hour
Kerosene tank, 560 gallons capacity
Coolant tank, 2,000 gallons capacity
Lube oil tank, 6,000 gallons capacity
Coolant tank, 1,000 gallons capacity
Triethyleneglycol tank, 1,000 gallons capacity
3 Methanol tanks, two of 2,000 gallons capacity, and one of 300 gallons
Lube oil tank, 560 gallons capacity
HMO (?) tank, 988 gallons capacity
Dehydrator system water tank, 10 barrels capacity
Triethyleneglycol / oily water tank, 300 gallons capacity
Scavenger tank, 300 gallons capacity
HMO (?) overflow tank, 2,000 gallons capacity
Oil stormwater tank, 10 barrels capacity
Oil stormwater tank, 80 barrels capacity
Oil stormwater tank, 10 barrels capacity
Used oil tank, 250 gallons capacity
Pressurized storage tanks, three of 60,000 gallons each, one of 5,000 gallons, and one of 3,000 gallons
Compressor blow downs from maintenance activities
Estimated potential total emissions: VOC: 4.06 tons per year
Page 24 of 25
AIRS Facility ID: 123/0090
Colorado Department of uA DRAFT
❑rent
'ision
DCP Midstream, LP — Mewbourn Natural Gas Processing Plant
Permit No. 09 WE 1136
Initial Approval
PERMIT
GENERAL TERMS AND CONDITIONS: (IMPORTANT! READ ITEMS 5,6,7 AND 8)
--This-permit-is-issued-in reliance upon the accuracy and completeness of information supplied by -the -applicant
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 applicant or applicant's agents. It is valid
only for the equipment and operations or activity specifically identified on the permit.
2. 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.
3. 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 final approval 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 the permit.
If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division
revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for
review of the Division's action.
4. This permit and any required attachments must be retained and made available for inspection upon request at the
location set forth herein. With respect to a portable source that is moved to a new location, a copy of the
Relocation Notice (required by law to be submitted to the APCD whenever a portable source is relocated) should
be attached to this permit. The permit may be reissued to a new owner by the APCD as provided in AQCC
Regulation No. 3, Part B, Section II.B. upon a request for transfer of ownership and the submittal of a revised
APEN and the required fee.
5. Issuance (initial approval) of an emission permit does not provide "final" authority for this activity or operation
of this source. Final approval of the permit must be secured from the APCD in writing in accordance with the
provisions of 25-7-I14.5(12)(a) C.R.S. and AQCC Regulation No. 3, Part B, Section III.G. Final approval
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. If the APCD so determines, it will provide written
documentation of such final approval, which does constitute "final" authority to operate. Compliance with the
permit conditions must be demonstrated within 180 days after commencement of operation.
6. THIS PERMIT AUTOMATICALLY EXPIRES IF you (1) do not commence construction or operation
within 18 months after either the date of issuance of this permit or the date on which such construction or
activity was scheduled to commence as set forth in the permit, whichever is later; (2) discontinue construction
for a period of 18 months or more; or (3) do not complete construction within a reasonable time of the estimated
completion date. Extensions of the expiration date may be granted by the APCD upon a showing of good cause
by the permittee prior to the expiration date.
7. YOU MUST notify the APCD no later than thirty days after commencement of the permitted operation or
activity. Failure to do so is a violation of Section 25-7-114.5(12)(a), C.R.S. and AQCC Regulation No. 3, Part
B, Section 111G.I., and can result in the revocation of the permit. You must demonstrate compliance with the
permit conditions within 180 days after commencement of operation as stated in condition 5.
8. Section 25-7-114.7(2)(a), C.R.S. requires that all sources 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.
9. 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.
Page 25 of 25
AIRS Facility ID: 123/0090
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