HomeMy WebLinkAbout20131137.tiffSTATE OF COLORADO
John W. Hickenlooper, Governor
Christopher E. Urbina, MD, MPH
Executive Director and Chief Medical Officer
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
Located in Glendale, Colorado
http://www.cdphe.state.co.us
April 29, 2013
Laboratory Services Division
8100 Lowry Blvd.
Denver, Colorado 80230-6928
(303) 692-3090
Weld County Clerk & Recorder
1402 N 17th Ave
Greeley, CO 80631
Dear Sir or Madam:
WELD C uN Y
COMMISSIONERS
Colorado Department
of Public Health
and Environment
On May 2, 2013, the Air Pollution Control Division will publish a public notice for Kerr-McGee Gathering LLC
— Platte Valley Gas Plant, in the The Greeley Tribune. 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 date the public notice is published.
Please send any comment regarding this public notice to the address below.
Colorado Dept. of Public Health & Environment
APCD-SS-B 1
4300 Cherry Creek Drive South
Denver, Colorado 80246-1530
Attention: Ellen Evans
Regards,
Ellen Evans
Public Notice Coordinator
Stationary Sources Program
Air Pollution Control Division
Enclosure
WO, ti2tvao 5143
2O13-1137
STATE OF COLORADO
John W. Hickenlooper, Governor
Christopher E. Urbina, MD, MPH
Executive Director and Chief Medical Officer
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
Located in Glendale, Colorado
http://www. cd phe.state.co. us
Laboratory Services Division
8100 Lowry Blvd.
Denver, Colorado 80230-6928
(303) 692-3090
Website Title: Kerr-McGee Gathering LLC — Natural gas plant — Weld County
Released To: The Greeley Tribune
On: April 29, 2013
Published: May 2, 2013
PUBLIC NOTICE OF A PROPOSED PROJECT
OR ACTIVITY WARRANTING PUBLIC COMMENT
Colorado Department
of Public Health
and Environment
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: Platte Valley Gas Plant
Natural gas plant
16157 Weld County Road 22, Fort Lupton, CO 80621
Weld County
The proposed project or activity is as follows: Operator requesting to install a thermal oxidizer to control amine
unit still vent and amine flash tank emissions.
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):
• 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, including supplemental information, the Division's analysis, and a draft of
Construction Permit 12WE1277 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 www.colorado.gov/cdphe/AirPublicNotices
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:
Stephanie Chaousy
Colorado Department of Public Health and Environment
4300 Cherry Creek Drive South, APCD-SS-B1
Denver, Colorado 80246-1530
cdphe.commentsapcd@state.co.us
STATE OF COLORADO
COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT
AIR POLLUTION CONTROL DIVISION
TELEPHONE: (303) 692-3150
CONSTRUCTION PERMIT
PERMIT NO:
12WE1277
Issuance 1
DATE ISSUED:
ISSUED TO: Kerr-McGee Gathering, LLC
THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS:
Oil and gas facility, known as the Platte Valley Gas Plant, located at 16157 Weld County
Road 22, Fort Lupton, Colorado in Weld County, Colorado.
THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING:
Facility
Equipment
ID
AIRS
Point
Description
S009
043
One (1) amine natural gas liquids (NGL) sweetening system for
CO2 and H2S removal with a design capacity of 15,000 BBL NGL
per day (Perry Gas Processors, Horizontal Amine Still Reboiler,
serial number: 2885-C). The amine solution is a specific
formulated amine consisting of any combination of MEA, DEA,
TEA, MDEA and DGA. This emissions unit is equipped with two
(2) electric amine recirculation pumps (one is for backup only)
with a total design capacity of 100 gallons per minute. This
system includes a natural gas liquids/amine contactor, a flash
tank, and a natural gas fired amine regeneration reboiler. The
reboiler is rated at 10.7 MMBtu/hr and is covered by AIRS Point
045. Still vent emissions are routed to a Zeeco thermal oxidizer
(SN: 15838) rated 5.0 MMBtu/hr. Flash tank emissions are re-
routed back to the thermal oxidizer as fuel. Flash gas emissions
are sent to the process flare during thermal oxidizer downtime.
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 THOSE GENERAL TERMS AND CONDITIONS
INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS:
REQUIREMENTS TO SELF -CERTIFY FOR FINAL AUTHORIZATION
1. Within one hundred and eighty days (180) after 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
AIRS ID: 123/0057
Page 1 of 10
Amine SM/M Version 2012-1
YFI
CokAri\,do Df pgrtmec�t or Public Health and Environment
Air Pollution Control Division
demonstrate compliance within 180 days may result in revocation of the permit.
(Reference: Regulation No. 3, Part B, II.G.2).
2. The operator shall complete all initial compliance testing and sampling as required in this
permit and submit the results to the Division as part of the self -certification process.
(Reference: Regulation No. 3, Part B, Section III.E.)
3. 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
4. Emissions of air pollutants shall not exceed the following limitations (as calculated in the
Division's preliminary analysis). (Reference: Regulation No. 3, Part B, Section II.A.4)
Monthly Limits:
limits.
Facility
Equipment ID
AIRS
Point
Pounds per Month
Emission Type
SO2
NOx
VOC
CO
S009
043
--- .
---
187
---
Point
ATO-3
---
1111
---
934
Point
(Note: 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
SO2
NOx
VOC
CO
S009
043
---
1.1
---
Point
ATO-3
---
6.5
---
5.5
Point
l
See "Notes to Permit Holder" for information on emission factors and methods used to caculate
During the first twelve (12) months of operation after the issuance of this permit,
compliance with both the monthly and annual emission limitations is required. After the
first twelve (12) months of operation after issuance of this permit, compliance with only
the annual limitation is required.
Compliance with the annual 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 emissions each month
and keep a compliance record on site or at a local field office with site responsibility for
Division review.
5. Compliance with the emission limits in this permit shall be demonstrated by running the
Promax model on a monthly basis using the most recent amine unit inlet extended gas
analysis and recorded operational values (including gas throughput, lean amine
recirculation rate, and other operational values specified in the O&M Plan). Recorded
AIRS ID: 123/0057 Page 2 of 10
?? gAitado
t o Public Health and Environment
Air Pollution Control Division
operational values, except for gas throughput, shall be averaged on a monthly basis for
input into Promax.
6. The emission points in the table below shall be operated and maintained with the control
equipment as listed in order to reduce emissions to less than or equal to the limits
established in this permit (Reference: Regulation No.3, Part B, Section III.E.)
Facility
Equipment
ID
AIRS
Point
Control Device
Pollutants
Controlled
S009
043
Recuperative thermal oxidizer
VOC, HZS and
HAP
7. 100% of emissions that result from the flash tank associated with this amine unit shall be
recycled to the thermal oxidizer as fuel.
PROCESS LIMITATIONS AND RECORDS
8. This source shall be limited to the following maximum processing rates as listed below.
Monthly records of the actual natural gas processing rates shall be maintained by the
owner or operator and made available to the Division for inspection upon request.
(Reference: Regulation 3, Part B, II.A.4)
Process/Consumption Limits
Facility
Equipment
ID
AIRS
Point
Process Parameter
Annual
Limit
Monthly Limit
(31 days)
S009
043
Natural gas liquids throughput
5,475,000
BBL/yr
465,000
BBL/month
Combustion of waste gas and
supplemental fuel
301.4
MMscf/yr
25.6
MMscf/month
The owner or operator shall calculate monthly process rates based on the calendar
month.
During the first twelve (12) months of operation after issuance of this permit, compliance
with both the monthly and annual throughput limitations is required. After the first twelve
(12) months of operation after issuance of this permit, 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.
9. This unit shall be limited to the maximum lean amine recirculation pump rate of 100
gallons per minute. The lean amine recirculation rate shall be monitored and recorded
daily in a log maintained on site and made available to the Division for inspection upon
request. (Reference: Regulation No. 3, Part B, II.A.4)
STATE AND FEDERAL REGULATORY REQUIREMENTS
AIRS ID: 123/0057 Page 3 of 10
fYie of Public Health and Environment
Air Pollution Control Division
10. The permit number and AIRS ID point number (e.g. 123/4567/890) shall be marked on
the subject equipment for ease of identification. (Reference: Regulation Number 3, Part
B, III.E.) (State only enforceable)
11. 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. Emission control devices subject to Regulation 7,
Sections XII.C.1.d or XVII.B.1.c shall have no visible emissions. (Reference: Regulation
No. 1, Section II.A.1. & 4.)
12. This source is subject to the odor requirements of Regulation No. 2. (State only
enforceable)
13. This amine unit is subject to the New Source Performance Standards requirements of
Regulation No. 6, Part A, Subpart LLL, Standards of Performance for Onshore Natural
Gas Processing: SO2 Emissions, including, but not limited to, the following:
• 40 CFR, Part 60, Subpart A — General Provisions
• §60.640 — Applicability and Designation of Affected Facilities
o §60.640(b) - Facilities that have a design capacity less than 2 longtons per
day (LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are
required to comply with §60.647(c) but are not required to comply with
§§60.642 through 60.646.
• §60.647 — Record keeping and reporting Requirements
o §60.647(c) - To certify that a facility is exempt from the control requirements
of these standards, each owner or operator of a facility with a design capacity
less that 2 LT/D of H2S in the acid gas (expressed as sulfur) shall keep, for
the life of the facility, an analysis demonstrating that the facility's design
capacity is less than 2 LT/D of H2S expressed as sulfur.
14. The operator shall continuously monitor with a flow meter the following amine unit
emission streams:
• total acid gas volume routed to the thermal oxidizer,
• total acid gas supplemental fuel volume routed to the thermal oxidizer, and
• total flash tank off gas volume from each amine unit flash tank.
By the end of each month, the total flow for the previous months' data shall be
calculated, and a new twelve-month total shall be calculated and recorded based on the
previous twelve months' data.
15. The concentration of amine (MEA, DEA, TEA,MDEA and/or DGA plus piperazine) in the
lean amine stream shall not exceed 45 weight percent on a monthly average basis.
Records of the concentration of amine in the lean amine stream shall be kept according
to the operating and maintenance plan for this point and shall be made available to the
Division for inspection upon request (Colorado Regulation No. 3, Part A, II).
16. The permit holder shall measure and record the following amine unit operating
parameters. Records of these operating parameters shall be made available to the
Division for inspection upon request. (Colorado Regulation No. 3, Part A, II):
AIRS ID: 123/0057 Page 4 of 10
of Public Health and Environment
Air Pollution Control Division
The concentration of amine in the lean amine stream shall be measured and
recorded on a weekly basis. The concentration of amine is defined as the
combined weight percent of all amine solutions and piperazine in the lean amine
stream.
OPERATING & MAINTENANCE REQUIREMENTS
17. Upon startup of these points, the owner or operator shall follow the most recent
operating and maintenance (O&M) 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 your O&M plan are subject to Division approval prior to
implementation. (Reference: Regulation No. 3, Part B, Section III.G.7.)
18. The operating temperature of the thermal oxidizer used to control emissions from this
dehydration unit 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, at all times
that any dehydration unit still vent emissions are routed to the thermal oxidizer in order
to meet the emission limits in this permit.
COMPLIANCE TESTING AND SAMPLING
Initial Testing Requirements
19. The owner or operator shall complete the initial inlet natural gas liquids 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.)
20. A source initial compliance test shall be conducted on emissions point 043 to measure
the emission rate(s) for the pollutants listed below in order to demonstrate compliance
with the emissions limits specified in Condition 4 in this permit. The operator shall also
demonstrate the thermal oxidizer achieves a minimum destruction efficiency of 99.0% for
VOC. The operator shall measure and record, using EPA approved methods, VOC
mass emission rates from the thermal oxidizer inlet and outlet to determine the
destruction efficiency of the thermal oxidizer (ProMax/Amine Calc/GlyCalc models shall
not be used to determine the flow rate or composition of the waste gas sent to the
thermal oxidizer for the purposes of this test). The natural gas throughput, lean amine
circulation rate, 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
combustion temperature during the initial compliance test to establish the minimum
combustion temperature.
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 lit and 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
AIRS ID: 123/0057 Page 5 of 10
ofPublic Health and Environment
Air Pollution Control Division
Hazardous Air Pollutants (BTEX and n -hexane) using EPA approved
methods.
Periodic Testing Requirements
21. The operator shall measure the emission rate(s) for the pollutants listed below at least
once every six months in order to demonstrate compliance with the emissions limits
contained in this permit. Periodic testing shall be conducted at a minimum of at least
thirty (30) days apart. The operator shall also demonstrate the thermal oxidizer achieves
a minimum destruction and removal efficiency of 99.0% for VOC. The operator shall
measure and record, using EPA approved methods, VOC mass emission rates at the
thermal oxidizer inlet and outlet to determine the destruction and removal efficiency of
the thermal oxidizer (process models shall not be used to determine the flow rate or
composition of the waste gas sent to the thermal oxidizer for the purposes of this test).
The natural gas throughput, lean amine circulation rate, all amine concentrations, 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 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
Volatile Organic Compounds using EPA approved methods
Carbon Monoxide using EPA approved methods
Hazardous Air Pollutants (BTEX and n -hexane) using EPA approved
methods.
22. The operator shall sample the inlet natural gas liquids to the amine unit on an annual
basis to determine the concentration of hydrogen sulfide (H2S) in the liquids stream. The
sample results shall be monitored to demonstrate that this amine unitqualifies for the
exemption from the Standards of Performance for Onshore Natural Gas Processing:
SO2 Emissions (§60.640(b)). The testing required by Condition 23 may be used for this
demonstration.
23. The owner or operator shall complete an extended liquids analysis prior to the inlet of
the amine unit on an annual basis. Results of the sour liquids analysis shall be used to
calculate emissions of criteria pollutants and hazardous air pollutants per this permit.
ADDITIONAL REQUIREMENTS
24. This permit replaces the following permits, which are cancelled upon issuance of this
permit.
Existing
Permit No.
Existing
Emission Point
New Emission Point
95WE409.XP
123/0057/043
123/0057/043 (exemption is cancelled upon
issuance of this permit)
AIRS ID: 123/0057
Page 6 of 10
do D �p rtrhe ogPublic Health and Environment
1 Air Pollution Control Division
25. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation
No. 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 (NOx) in
ozone nonattainment areas emitting less than 100 tons of VOC or NO per
year, a change in annual actual emissions of one (1) ton per year or more or five
percent, whichever is greater, above the level reported on the last APEN; 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.
• 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.
26. 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 provisions of this
construction permit must be incorporated into the Operating Permit. The application for
the modification to the Operating Permit is due within one year of the issuance of this
permit.
GENERAL TERMS AND CONDITIONS:
27. 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 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.
28. 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 No. 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
AIRS ID: 123/0057 Page 7 of 10
t o" Public Health and Environment
Air Pollution Control Division
obtaining final authorization to operate are located in the Requirements to Self -
Certify for Final Authorization section of this permit.
29. 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.
30. 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.
31. 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 the permit. If the Division denies a
permit, conditions imposed upon a permit are contested by the owner or operator, or the
Division revokes a permit, the owner or operator or owner or operator of a source may
request a hearing before the AQCC for review of the Division's action.
32. 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.
33. 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:
Stephanie Chaousy, P.E.
Permit Engineer
Permit Histo
Issuance
Date
Description
Issuance 1
This Issuance
Issued to Kerr-McGee Gathering, LLC. Newly
permitted amine unit at a major facility.
AIRS ID: 123/0057
Page 8 of 10
7171 a oil Public Health and Environment
Air Pollution Control Division
Notes to Permit Holder at the time of this permit issuance:
1) 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.
2) 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:
http://www.cdphe. state. co. us/regulations/a i rreas/100102acicccommonprovisionsreg. pdf.
3) 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.
AIRS
Point
Pollutant
CAS #
BIN
Uncontrolled
Emission
Rate
(Ib/yr)
Are the
emissions
reportable?
Controlled
Emission
Rate
(lb/yr)
043
Benzene
71432
A
8976
Yes
90
n -Hexane
110543
C
593
No
6
4) The emission levels contained in this permit are based on the Promax model using the extended sour
gas analysis submitted with the permit application. The emissions levels in this permit were buffered
by multiplying the model results by a factor of 1.12.
5) The emission levels contained in this permit are based on the following emission factors:
Point 043:
CAS #
Pollutant
Emission Factors
Uncontrolled
Emission Factors
Controlled
Source
NOx
100 lb/MMScf
100 lb/MMScf
AP -42, Table 1.4-1
CO
84 lb/MMScf
84 lb/MMScf
AP-42,Table 1.4-1
VOC
0.04 lb/bbl
0.0004 lb/bbl
Promax
110543
n -Hexane
0.00016 lb/bbl
0.000002 lb/bbl
Promax
71432
Benzene
0.0016 lb/bbl
0.00002 lb/bbl
Promax
Note: The controlled emissions factors for point 043 are based on the thermal oxidizer control
efficiency of 99%. Emission factors are based on a fuel heat value of 1020 Btu/scf.
6) In accordance with C.R.S. 25-7-114.1, each Air Pollutant Emission 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) This facility is classified as follows:
AIRS ID: 123/0057
Page 9 of 10
et:t or Public Health and Environment
Air Pollution Control Division
Applicable
Requirement
Status
Operating Permit
Major Source of: NOx, CO, VOC, formaldehyde and Total HAPS
NANSR
Major Source of: NOx and VOC
PSD
Major Source of: CO
NSPS LLL
Applicable
8) 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
9) An Oil and Gas Industry Construction Permit Self -Certification Form is included with this permit
packet. Please use this form to complete the self -certification requirements as specified in the permit
conditions. Further guidance on self -certification can be found on our website at:
htto://www.cdphe.state.co.us/ap/oilgasoermitting.html
AIRS ID: 123/0057 Page 10 of 10
Construction Permit Application
Preliminary Analysis Summary
Section 1 — Applicant Information
Company Name:
Kerr-McGee Gathering, LLC
Permit Number:
12WE1277
Source Name:
Platte Valley Gas Plant
Source Location:
16157 Weld County Road 22, Ft. Lupton
Equipment Description:
One (1) 15,000 BBL/d NGL amine treating unit
AIRS ID:
123/0057/043
Date:
(April 25, 2012) October 5, 2012
Review Engineer:
(Jacob Sebesta) Stephanie Chaousy, P.E.
Control Engineer:
Chris Laplante
NOTE: This emission unit was previously part of 123/0319 which was located across the street from the
Ft. Lupton Gas Plant (123/0057) and was purchased by Western Gas Partners/Kerr-McGee Gathering
from Encana in 2011. These sources were aggregated as one facility at that time.
Section 2 — Action Completed
Grandfathered
Modification
APEN Required/Permit Exempt
X
CP1
Transfer of Ownership
APEN Exempt/Permit Exempt
Section 3 — Applicant Completeness Review
Was the correct APEN submitted for this source type?
X
Yes
No
i Is the APEN signed with an original signature?
X
Yes
No
Was the APEN filled out completely?
X
Yes
No
Did the applicant submit all required paperwork?
X
Yes
No
Did the applicant provide ample information to determine emission rates?
X
Yes
No
If you answered "no" to any of the above, when did you mail an
Information Request letter to the source?
Please see Section 14
On what date was this application complete?
February 8, 2012
Section 4 — Source Description
AIRS Point Equipment Description
043
One (1) amine natural gas liquids (NGL) sweetening system for CO2 and H2S removal
with a design capacity of 15,000 BBL NGL per day (Perry Gas Processors, Horizontal
Amine Still Reboiler. serial number: 2885-C). The amine solution is a specific formulated
amine consisting of any combination of MEA, DEA, TEA, MDEA and DGA. This
emissions unit is equipped with two (2) electric amine recirculation pumps (one is for
backup only) with a total design capacity of 100 gallons per minute. This system includes
a natural gas liquids/amine contactor, a flash tank, and a natural gas fired amine
regeneration reboiler. The reboiler is rated at 10.7 MMBtu/hr and is covered by AIRS
Point 045. Still vent emissions are routed to a Zeeco thermal oxidizer (SN: 15838) rated
at 5.0 MMBtu/hr. Flash tank emissions are re-routed back to the thermal oxidizer as fuel.
Flash as emissions are sent to the rocess flare during thermal oxidizer downtime.
Is this a portable source?
Yes
X
No
is this location in a non -attainment area for any criteria
pollutant?
X
Yes
No
I
Page 1
If "yes", for what pollutant?
PM,()
CO
X
Ozone
Is this location in an attainment maintenance area for
any criteria pollutant?
Yes
X
No
If "yes", for what pollutant?
(Note: These pollutants are subject to minor source
RACT per Regulation 3, Part B, Section III.D.2)
PKo
CO
Ozone
Is this source located in the 8 -hour ozone non -
attainment region? (Note: If "yes" the provisions of
Regulation 7, Sections XII and XVII.C may apply)
X
Yes
No
Section 5 — Emission Estimate Information
AIRS Point
Emission Factor Source
043
Promax Simulation Model. See Section 14 for calculations.
Did the applicant provide actual process data for the emission inventory?
X
Yes
No
Basis for Potential to Emit (PTE)
AIRS Point
Process Consumption/Throughput/Production
043
Natural gas liquids throughput: 5,475,000 BBL per year natural gas liquids
throughput, 100 gallons per minute lean amine circulation rate
Combustion of waste gas and supplemental fuel: 300.4 MMSCF/year
Basis for Actual Emissions Reported During this APEN Filing (Reported to Inventory)
AIRS Point
Process Consumption/Throughput/Production
Data Year
043
Natural gas liquids throughput: 5,475,000 BBL per year natural gas
liquids throughput, 100 gallons per minute lean amine circulation rate
Combustion of waste gas and supplemental fuel: 300.4 MMSCF/year
Basis for Permitted Emissions (Permit Limits)
AIRS Point
Process Consumption/hroughput/Production
043
Natural gas liquids throughput: 5,475,000 BBL per year natural gas liquids
throughput, 100 gallons per minute lean amine circulation rate
Combustion of waste gas and supplemental fuel: 300.4 MMSCF/year
Does this source use a control device?
X
Yes
No
AIRS Point
Process
Control Device Description
% Reduction
Granted
043
01
Zeeco (recuperative) thermal oxidizer
99
Section 6 — Emission Summary (tons per year)
Point
NO.
VOC
CO
Single HAP
Total HAP
PTE:
043
6.5
105.8
5.5
4.0 (benzene)
4.9
Uncontrolled point
source emission rate:
043
6.5
105.8
5.5
4.0 (benzene)
4.9
Controlled point
source emission rate:
043
6.5
1.1
5.5
0.04 (benzene)
0.05
Section 7 — Non -Criteria / Hazardous Air Pollutants
Pollutant
CAS #
BIN
Uncontrolled
Emission Rate
(Ib/yr)
Are the
emissions
reportable?
Controlled Emission
IE/ r
Rate ( Y )
Benzene
71432
A
8976
Yes
90
n -Hexane
110543
C
593
No
6
Page 2
Note: Regulation 3, Part A, Section ll.B.3.b APEN emission reporting requirements for non -criteria air
pollutants are based on potential emissions.without credit for reductions achieved by control
devices used by the operator.
Section 8 —Testing Requirements
Will testing be required to show compliance with any emission rate or regulatory
standard?
X
Yes
No
If "yes", complete the information listed below
AIRS Point
Process
Pollutant
Regulatory Basis
Test Method
043
01
VOC,
HAPS
Regulation No. 3, Part B., Section III.G.3
Stack Test
Section 9 —Source Classification
Is this a new previously un-permitted source?
X
Yes
No
What is this facility classification?
True
Minor
Synthetic _
Minor
X
Major
Classification relates to what programs?
X
Title V
X
PSD
X
NA NSR
X
MACT
Is this a modification to an existing permit?
Yes
X
No
If "yes" what kind of modification?
Minor
Synthetic
Minor
Major
Section 10 — Public Comment
Does this permit require public comment per CAQCC Regulation 3?
X
Yes
No
If "yes", for which pollutants? Why?
Point never went to PC during ownership under Encana.
For Reg. 3, Part B, III.C.1.a (emissions increase > 25/50 tpy)?
(controlled)
Yes
X
No
For Reg. 3, Part B, III.C.1.c.iii (subject to MACT)?
Yes
X
No
For Reg. 3, Part B, III.C.1.d (synthetic minor emission limits)?
X
Yes
No
Section 11 —Modeling
Is modeling required to demonstrate compliance with National Ambient
Air Quality Standards (NAAQS)?
If "yes", for which pollutants? Why?
Yes
X
No
AIRS Point
Section 12 — Regulatory Review
Regulation 1 - Particulate, Smoke, Carbon Monoxide and Sulfur Dioxide
043
Section II.A.1 - Except as provided in paragraphs 2 through 6 below, no owner or operator
of a source shall allow or cause the emission into the atmosphere of any air pollutant which
is in excess of 20% opacity. This standard is based on 24 consecutive opacity readings
taken at 15 -second intervals for six minutes. The approved reference test method for
visible emissions measurement is EPA Method 9 (40 CFR, Part 60, Appendix A (July,
1992)) in all subsections of Section II. A and B of this regulation.
Section II.A.5 - Smokeless Flare or Flares for the Combustion of Waste Gases No owner
or operator of a smokeless flare or other flare for the combustion of waste gases shall
allow or cause emissions into the atmosphere of any air pollutant which is in excess of
30% opacity for a period or periods aggregating more than six minutes in any sixty
consecutive minutes.
Regulation 2 — Odor
043
Section I.A - No person, wherever located, shall cause or allow the emission of odorous air
contaminants from any single source such as to result in detectable odors which are
measured in excess of the following limits: For areas used predominantly for residential or
commercial purposes it is a violation if odors are detected after the odorous air has been
diluted with seven (7) or more volumes of odor free air.
Page 3
Regulation 3 - APENs, Construction Permits, Operating Permits, PSD
043
Part A — APEN Requirements
Applicant is required to file an APEN since emissions exceed 1 ton per year VOC.
043
Part B — Construction Permit Exemptions
Applicant is required to obtain a permit since uncontrolled VOC emissions from this facility
are greater than the 2.0 TPY threshold (Reg. 3, Part B, Section II.D.2.a).
Regulation 6 - New Source Performance Standards
043
NSPS LLL: Each sweetening (amine) unit and each sweetening unit followed by a
sulfur recovery unit; manufacturer date after January 24, 1984.
Since source started operating after August 23, 2011, it will be subject to NSPS 0000,
not NSPS LLL. However, NSPS 0000 also has the long tons exemption:
This source will have a design capacity less than 2 long tons/day HZS in the acid gas based
on the information submitted in,the application. This source will be required by 60.647(c) to
keep for the life of the equipment an analysis demonstrating that the facility's design
capacity is less than 2 LT/D of HZS expressed as sulfur. No other requirements apply.
043
NSPS Dc: For boilers/reboilers/heaters construction date after June 9, 1989 and a
design capacity between 10-100 mmbtu/hr.
This amine unit has a reboiler rated 10.7 MMBtu/hr. It does not meet APEN-
exemption/permit-exemption and is subject to NSPS Dc.
Regulation 7 - Volatile Organic Compounds
043
None
Re. ulation 8 — Hazardous Air Pollutants
043
MACT DDDDD: You are subject to this subpart if you own or operate an industrial,
commercial, or institutional boiler or process heater as defined in §63.7575 that is
located at, or is part of, a major source of HAP as defined in §63.2 or §63.761 (40 CFR
part 63, subpart HH, National Emission Standards for Hazardous Air Pollutants from
Oil and Natural Gas Production Facilities), except as specified in §63.7491.Major for
MACT HH for gas processing plants is based on ALL HAPs at the facility. Is this source
considered Major for HAPS? Yes
A boiler is defined as an enclosed device using controlled flame combustion and having the
primary purpose of recovering thermal energy in the form of steam or hot water. Waste
heat boilers are excluded from this definition.
This reboiler is subject to MACT DDDDD. However, the reboiler is permitted at Point
123-0057-043, so it will not be included in this permit action.
043
MACT JJJJJJ: You are subject to this subpart if you own or operate an industrial,
commercial, or institutional boiler as defined in §63.11237 that is located at, or is part of, an
area source of hazardous air pollutants (HAP), as defined in §63.2, except as specified in
§63.11195.
Section 13—Aerometric Information Retrieval System Coding Information
Point
Process
Process Description
Emission
Factor
Pollutant /
CAS #
Fugitive
(Y/N)
Emission Factor
Source
Control
- (%)
043
01
Amine Unit
100 lb/MMscf
NOX
No
AP-42,Table 1.4-1
0
84 lb/MMscf
CO
No
AP-42,Table 1.4-1
0
0.9202
lb/1000 gal
VOC
No
Process Simulator
(Promax)
99
-0.0348
lb/1000 gal
Benzene /
71432
No
Process Simulator
(Promax)
99
0.0017
lb/1000 gal
n -Hexane
/ 110543
No
Process Simulator
(Promax)
99
SCC
31000305 — Gas Sweetening; Amine process
Emission factors include flash tank and still vent and that factors are based on natural gas liquids
processing of 5,475,000 BBL per year.
Page 4
Section 14 — Miscellaneous Application Notes
AIRS Point
043
Amine Unit
Some history
said that it was
controlled under
test the amine
this facility, therefore,
this modification
Cycrogenic Plant
because this
The table below
Jake was wo
Promax model.
Requests 99%
Promax Model:
and HAPS).
VOC = (105.8
Benzene=(4*2000)/5475000
Toluene=(0.7*2000)/5475000
N-hexane=(0.2*2000)/5475000
NOx and CO
NOx =
about this point: Encana originally owned Platte Valley. Source was onsite for 10 years+
an insignificant source (so no APEN/permit was submitted for this amine unit). It was also
Encana s ownership. When KM purchased the facility and did a self -audit, they required
unit. The test results showed that the amine unit was a significant source of emissions.
required control. Jen Mattox is the inspector for this facility and COC. It was determined
to Platte Valley would not be included in PSD determination with the addition of the Lancaster
(S. Chaousy working on this application as of 10/5/12). I am going to request monthly
source has never been permitted before and is a synthetic minor source.
summarizes the inputs to the process simulation used to calculate the PTE for this equipment.
and Operator
never
Encana to
The COC for
that
emissions
with the
(VOC
APEN)
Parameter
Value
Inlet NGL Temperature
80 °F
Inlet Pressure
500 psig
NGL Throughput
425.076 gpm
Lean amine circulation rate
100 gpm
Lean amine concentration
9.4068 mol% JEFFTREAT M-510
Flash Tank Temperature
98.5 °F
Flash Tank Pressure
90 psia
NGL Composition
1/26/2012 sample "North Platte Plant
NGL @ Inlet Stream to Amine Contactor"
king on
I have
@ 1400degF
since
Emission
TPY*2000)/5475000
emissions
this application prior
done a few things
for TO which
Jake approved
factors using Promax
bbl/yr=0.0386
bbl/yr=0.0015
bbl/yr=0.000261b/bbl*1000/42=0.0061
bbl/yr=0.0001
from the amine
0.068 lb
to his resignation.
in PA and permit
we denied for 11WE1965."
the Promax model,
Model:
lb/bbl*1000/42=0.9202
lb/bbl*1000/42=0.0348
Ib/bbl*1000/42=0.0017
unit are from AP -42,
10.7 MMBtu
He left a note saying
but all red and green
I will not take too much
Ib/1000
lb/1000 gal
lb/1000 gal
lb/1000
Table 13.5-1.
8760 hr
that he is "comfortable
text needs to be
time with the
gal (lb/bbl EF
(lb/bbl EF matches
(lb/bbl EF matches
gal
1 T
addressed.
model review
matches
APEN)
APEN)
= 3.2 TPY
CO =
MMbtu .
0.37 lb
hr
10.7 MMBtu
1 yr
8760 hr
2000 lb
1 T
+ 10% = 3.5 TPY
= 17.3 TPY
The thermal oxidizer:
agreed on 9/17/12 that
one is) at 1400degF.
NOx and CO emissions
NOx =
MMbtu
KM and the Division
a 99% destruction
Compliance testing
from the amine
0.068 lb
hr
have had several
efficiency would
will be required in
unit are from AP -42,
1.78 MMBtu
1 yr
meetings regarding
be granted for recuperative
the permit.
Table 13.5-1.
8760 hr
2000 lb
TO destruction
thermal
1 T
+ 10% = 19A TPY
efficiency. It was
oxidizers (as is this
= 0.5 TPY
CO =
MMbtu
0.37 lb
hr
1.78 MMBtu
1 yr
8760 hr
2000 lb
1 T
+10% = 0.6 TPY
= 2.9 TPY
I emailed Jen Shea
on 10/10/12 saying
and now permitted
separate to avoid confusion.
the TO will be in the
regarding 99% thermal
though the Division
compliant with emission
An updated history
agreed that changes
MMbtu
on 10/05/12 asking
that the reboiler is separately
at Ft. Lupton under
Therefore,
permit. As far as the
oxidizers at 1400degF.
is still concerned with
limit and chamber
file will not be included
for Lancaster would
hr
about the reboiler
permitted
Point 123-0057-043).
the reboiler (and
99% control is concerned,
It was determined
the compliance.
temperature.
with this application
not effect this application.
1 yr
emissions as well as
at the Ft. Lupton site
Operator requested
Dc) will not be included
the Division
for Lancaster
The permit willrequire
because it has
2000 lb
the TO emissions.
(was originally
for the two sources
in the permit.
has had several
to grant the 99%
testing to make
been modified for
+10% = 3.2 TPY
She wrote back
part of Platte Valley
to be kept
Only emissions for
meetings with KM
at 1400degF even
sure the permit is
Lancaster and it was
Page 5
AIRS Point
Jen Shea sent me an updated APEN with flash tank gases re-routed to the TO to be used as fuel, and with that, new
emission limits without the flash gas. After talking with Chris and Carissa, the re-routing should not be reviewed as a
process but a control action. Therefore, the emissions are the original APEN, and not the updated APEN received
via email 10/29/12. I talked to Jen Shea about "processes" versus "control." She agreed with my interpretation of
"process" versus "control" and agreed that the source requires public comment since it is a synthetic minor source on
its own.
043
Amine Unit (continued)
I also sent the Operator a 30+hour letter on 10/30/12. A copy is included with the application.
I emailed the operator on 01/23/13 and the operator responded on 1/29/13. Her responses are in italics:
1. When I reviewed our database, Point 043 is listed as an amine unit (15,000 BBLJDAY AMINE TREATING
UNIT, S009, AMINE TYPE: DEA) and not the reboiler. KM must submit an APEN to get a permit for the
reboiler if KM does not want to include it in this permit. The reboiler is in 99OPWE207 as source 5013. The
amine unit is listed as S009. Since it is already in the Title V as a separate source, I think we should just
leave it as is. The new AIRS ID for the Fort Lupton Complex is 123-0057-045. The amine unit AIRS is 123-
0057-043.
2. For the amine recirculation rate, could KM please confirm for me if it is 80 gpm or 100 gpm? Looking at the
APEN, the rich amine feed is 100 gpm and the lean amine stream is 80 gpm. Amine circulation was
simulated at 100 gpm.
3. The combustion emissions are not totally clear. How did KM calculate 1.78 MMBtu/hr? This value should
include the flash vent (as supplemental fuel) and the still vent but I cannot figure if it includes both. Could
you please provide a detailed explanation of this calculation? The 1.78 MMBtu/hr came from the flash and
acid gas as calculated by the manufacturer. I apologize because I did not complete this application, so I
also cannot figure out exactly how it was done. So, I went ahead and calculated everything the way I did at
Lancaster and came up with some different numbers. The emission factors used in the application are for a
flare, and I don't feel that is appropriate for a thermal oxidizer, so l switched them to utilize AP -42 external
combustion source EF's. The TO burner rating was also not included in the previous calculation so I added
that in plus the required auxiliary fuel required to meet 300 8tu/scf. SO2 emissions are unchanged, but I
added the NCR APEN form for H2S and then included combustion emissions plus conversion of H2S to
SO2 (0.04 tpy + 0.80 tpy = a 84 tpy SO2 controlled). I updated the APEN, 102 Form and calculation
sheets. All are attached for your files.
4. Could you please confirm the %a MDEA used in the model? We are using JEFFTREAT M-510 which is a
MDEA based solvent and it looks to be 9.4%.
April 11, 2013: operator provided comments during the DRAFT review process. All comments seemed self-
explanatory except for a few comments:
1. In the equipment description box, Point #: This unit already had an AIRS ID assigned to it as 123/0057/043
(see 2005 99OPWE207 Draft Permit as AIRS Point 009 for Encana). Then in 2012, Paul Rusher assigned it
123-0057-043 after the transfer of ownership.
Response: The point number has been changed to reflect the existing amine unit (S009) of Point 043. All
locations where this is have been changed. It appears that this point did receive a permit exemption a long
time ago (permit 95WE409) but since we have been processing this as permit 12WE1277, I added the
condition that says that the original permit will be cancelled upon issuance of this new permit
This permit replaces the following permits, which are cancelled upon issuance of this permit.
Existing Permit
No.
Existing Emission
Point
New Emission Point
95WE409.XP
123/0057/043
123/0057/043 (exemption is cancelled upon issuance of
this permit)
However, it was my understanding that the reboiler (10.7 MMBtu/hr) was under Point 043 only. After an
email conversation with KMG on 4/18/13, it was noted that the reboiler is Point 045 at the facility. I checked
the Division's database system to verify that Point 045 is the reboiler and it is. It is better to keep the points
separate since they have been already permitted separately.
Page 6
AIRS Point
043
Amine Unit (continued)
2. Condition 8: for the combustion limit, I do not come up with the same number;
Supp Fuel = 7385.2 scf/hr * 8760 hrs/yr = 65.58 MMSCF/yr
Waste Gas = 0.528 MMscf/day * 365 days/yr = 192.87 MMSCF/yr
Burner Fuel Use = 5 MMBtu/hr / 1020 Btu/scf * 8760 = 42.9 MMSCF/yr
Total TO fuel use = 300.4 MMSCF/yr
Total TO fuel use = 25.6 MMSCF/month
Response: 1 am not sure where I got the 15,593 mmbtu/hr, but I agree with KMG's calculations (but total
added up to 301.4 MMSCF/yr). However, when I use this throughput of 301.4 mmscf/yr and calculate NOx
(using 1001b/MMSCF from AP -42) I calculate 15.1 TPY and CO (using 84 lb/mmscf from AP -42) 12.7 TPY.
That is not what is showing on the APEN. It might be better to increase the NOx and CO to incorporate all
the parts totaling the combustion. Thoughts?
Note: I could not find any work or reference to how I calculated 15,593 MMBtu/yr as the process throughput
limit. I reviewed what KMG provided and agreed with their calculations but it did not match the NOx and CO
emissions when I did a back calculation.
KMG replied on 4/19/13: You are correct, the total "fuel" will be 301.4 MMscf/yr (I must have just miss -
calculated the total volume) For the emissions calculation, since the waste gas btu/scf is different from the
supplemental fuel gas and burner fuel gas we need to take the Ib/mmscf emission factor from AP -42 (see
footnote a of Table 1.4-1) and convert to Ib/mmbtu and then use the MMBtu/hr of all three streams to
calculate emissions. If you just use the total MMscf/yr and lb/MMscf emission factors, you are assuming all
streams have a btu of 1020, which is not the case. If you agree, I believe the emissions I calculated are
correct. I also think I gave you my calculation sheet, so you should be able to see my logic.
3. Condition 14 (NSPS LLL condition): We commenced construction after August 23, 2011, therefore this
NSPS would not apply.
Response: This source has been onsite since 1997. I emailed KMG for some clarification. KMG
respohded on 4/18/13 saying to just remove that comment prior to sending after review of Regulation. The
amine unit is subject but only required to keep documentation that it's design capacity is less than 2 LT/day.
The standard condition states in the first section that it is only subject to the H2S exemption and the second
section talks about recordkeeping to show compliance with the first section. This is the standard condition
so I believe it should be left as -is.
4. Condition 21 (initial testing requirement): The amine unit was permitted at a maximum throughput of 15,000
bbls/day and a circulation rate of 100 gpm due to the design capacity of the equipment. Currently, the plant
processes anywhere from 8,000-10,500 bbls/day with an occasional 13,000 bbls/day. We have absolutely
no control over the volumes we process, it just depends on volumes that are coming into the facility. So,
achieving the +/- 10% (13,500 bbls/day) is most likely not going to be possible based on recently processed
liquid volumes. KMG is requesting to remove this requirement from the testing condition.
This condition also requires us to operate the amine system at +/- 10% of 100 gpm. Again, our equipment
was designed to operate at 100 gpm but typically operates around 40 gpm. This circulation rate is
dependent on the volume and the composition of the inlet stream. This is something we are unable to
control, and given the recent circulation rate we are most likely not going to be able to test at the +/- 10%
required. KMG is requesting to remove this requirement from this testing condition.
Given the operational fluctuations in inlet volumes and composition, KMG needs to keep the flexibility in the
permit to allow for the amine unit to operate up to design capacity. While we are not operating at full design
capacity today, we did request that and it is reflected in our emissions limits seen in the permit.
Response: The Division is willing to remove this sentence; however, KMG will need to agree to periodic
testing. The condition would be similar to Lancaster. Please let me know if KMG will agree to this. If so, I
will remove the +/- 10% and add the periodic testing condition.
KMG replied on 4/19/13: KMG agrees to periodic testing.
I also had a phone call with KMG on 4/19/13 regarding amine concentrations. When KMG was talking to their amine
supplier, they said that the amine solution is really a combination of all the concentrations (MEA, DEA, TEA, MDEA
and DGA) and so when tested, traces of all these solutions will be present in the results. To accommodate this, I
modified the equipment description box and any condition that referenced the amine type with all the different types
of concentrations.
Page 7
AIR POLLUTANT EMISSION NOTICE (APEN) & Application for Construction Permit —
G O V C � C5
p w
Emission Source
rff
[Leave blank unless APCD has already assigned a permit t! &
12WE1277
[Provide Facility Equipment ID to identify how this equipment is referenced within your organization.
S
G
CD O ti
r0 H ti
Ei •.5 Z Z
7 col *y >, a a
nested Action. (Check applicable request boxes)
Section 02 — Re
W permit or newly reported emission source
.. d
adz
Po '= it w
° • O ct Q
N O A
O O. N Q .,y
72 U w3
a • o
=
• a m p • y 5 �O_
0 p O 0. 0 0 ai
u0. O �' ❑. h G. E E
y O 0 W .E 4° 0 0
O " O.5 v ., Co
I1 O • 0 Y L a. O .I-.
2 5 ® 3 w o u'° .
E U H ` m°. a 9 a bu.0
p C O F C
❑❑ o 0F a
A L
y Ti. > O O
d .Yi V P c' d
•O P. N b ..� tOtl
-i.a O �i ° W
Cn O' Y ^ 4�O (FL4 ` y .
O O :- •� d O N 0 0
"U'" o a o 0° o �i
5 d O h F a
3: �� OOpO OMC 0 W y N t ti-, ▪ t
G N N a E 9 O d O
y. N w N O. 0. .G N
-�" 'L 0 a+ �r rte- F F^ W
`z 0 U U d m
❑ ❑ o a
P P 0
a4 ❑.® ad' a El ID
PJ os▪ ,
❑ ❑ d4
County: Weld
O'
Kerr-McGee Gathering LLC
Platte Valley Gas Plant
16157 Weld County Road 22
Se
0
N
0
t-
00
0 0
o
U
W N
Fort Lupton, CO 80621
P. O. Box 173779
Mailing Addre
Jennifer L. Shea
Person To Ceuta
(720) 929-7028
Fax Number:
nadarko.com
Section 03 — General Information
en
'C
0.
8
m
N
b
N
0 0
O
OO d
O
Q
❑ ❑
restate.co.us/
F: g
V) Y
•. d
0 Z
�0
O -O .2 8
R J❑
JMo aI o0
TO
O m E OO
d 0. O d
P. W U d C
• 0 O
J w O .0. _
O 0 .c g. w
cn
5 x v ra n
ti d
obi `d Q
G
w Z W AA
ment Information
0
Section 04 — Amine Sweetenin
O
0 ..• Ji
O O
0 O O
00
t.
p. P.
O O
O. O.
A
P Q
O O
O O
0 O
F .O
0 0
U U
0
O
2
d
O.
J b
7?;}
N
N
O Y
e5
au
z�
m Jp
W N
W N
o a �
I- 0 't H
O J Q
y C
E t '
U V
q T
yOy C
Q L N
'd S a 2
bC
O o
O O
0, 0 N
6 O
O • 'w-" a i
O, O w
m0
U U U UDEM
,9 F d
Q -
e with TO3.doc
2013-04-10 PLV AP
N
0
0
O
0
a
FORM APCD-206
O
Permit Number:
atum & either Lat/Long or UTM)
e, if no combustion
s
In
CF)
0
(Indicate if a control device controls the flash tank and/or regenerator emissions)
Section 07 — Contr
Section 08 Emissions Inventory Information & Emission Control Information
FstimatioaMethod
"`fiussion Factor e
AP -42 Chpt 1 1
o
N
0
.4g
E
AP -42 Chpt 1
Simulation+lL2%.
Simulation+11.2%
e
N
0
O
tg
g
e
N
Pi
O
.:a�y9C'
Simulation+112°/J
Please use the APCD Non -Criteria Reportable Air Pollutant Addendum form to report pollutants not listed above.
•y
a . „A.
o
zO O
=
.E
°
E
i
E
E
°
in
vi
,n
43
0
0
below
0
• :-..
;9O
rS
C
:
1_
Identify in Section 07
Is
Z
›-
V
8
o
O
o
PS
x
241)
•
N
O.0
a
z
w
O
LU
z
U5
c
LLIG
{-
Z
< 0
1— o
= m
J O
C
J a
® rn
▪ C)
U.1 s
▪ ai
• m
O
w
Ea
N
1
Z
O .
Z
m
0
N-
0
0
N
r
Permit Number:
O.
U
a
N
County: Weld
Kerr-McGee Gathering LLC
Company Name:
Ct
m
a
0)
CD
CD
m
cts
a
Plant Location:
720-929-6028
Phone Number:
Jennifer L. Shea
Person to Contact:
Jennifer.Shea@Anada
0)
N
2
-o
W
Controlled Actual
Emissions (lbs/year)
8.1 (with TO)
/Sc
�
'
it
Uncontrolled Actual
Emissions (lbs/year)
813.9 (no TO)
Emission
Factor Source
Simulation
Emission Factor
(Include Units)
.00015 lb/bbl
uncontrolled
0.0000015
lb/bbl
controlled
Control Equipment/
Reduction (%)
99%
For Thermal
Oxidizer (TO)
(H2S to SO2)
O
L
f z
n m
x
Chemical Name
Hydrogen Sulfide
Chemical
Abstract Service
(CAS) Number
7783064
Calendar Year for which Actual Data Applies:
Reporting Scenario (1, 2 or 3):
ally Authorized to Supply Da
nature of Person L
Jennifer L. Shea
as
as
CO
0
a
a
O
N
I-
O
-C
Q
O
4)
C
O
N
a
0
0
N
Name of Person Legally Authorized to Supply Data (Please print)
Hello