HomeMy WebLinkAbout20161193 A CDRHE COLORADO
Coor Department of Public
,„. Health Er Environment
Dedicated to protecting and improving the health and environment of the people of Colorado
Weld County - Clerk to the Board
1150O St
PO Box 758
Greeley, CO 80632
March 28, 2016
Dear Sir or Madam:
On March 30, 2016, the Air Pollution Control Division will begin a 30-day public notice period for DCP
Midstream, LP - Spindle Gas Plant. A copy of this public notice and the public comment packet are
enclosed.
Thank you for assisting the Division by posting a copy of this public comment packet in your office.
Public copies of these documents are required by Colorado Air Quality Control Commission
regulations. The packet must be available for public inspection for a period of thirty (30) days from
the beginning of the public notice period. Please send any comment regarding this public notice to
the address below.
Colorado Dept. of Public Health O. Environment
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, Colorado 80246-1530
Attention: Clara Gonzales
Regards,
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Clara Gonzales
Public Notice Coordinator
Stationary Sources Program
Air Pollution Control Division
Enclosure
2016-1193
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4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303-692-2000 www.colorado.gov/cdphe ,.ter 9+
John W. Hickentooper, Governor I Larry Wolk,MD,MSPH, Executive vector and Chief Medical Officer i,, ,*j(2401•12tA-C 4_,(71 -i() a. a)P0 i-k-- 'I-
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CDPHE Air Pollution Control Division
co Notice of a Proposed Project or Activity Warranting Public
r. Comment
Website Title: DCP Midstream, LP - Spindle Gas Plant - Weld County
Notice Period Begins: March 30, 2016
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: DCP Midstream, LP
Facility: Spindle Gas Plant
Natural Gas Processing Plant
Sec. 34, T2N, R67W
Weld County
The proposed project or activity is as follows: Natural gas processing plant modifying an existing triethylene
glycol dehydration unit and permitting a plant flare to handle maintenance and malfunction 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, the Division's analysis, and a draft of Construction Permit 15WE1132 have been
filed with the Weld County Clerk's office. A copy of the draft permit and the Division's analysis are
available on the Division's website at https://www.colorado.gov/pacific/cdphe/air-permit-public-notices
The Division hereby solicits submission of public comment from any interested person concerning the ability
of the proposed project or activity to comply with the applicable standards and regulations of the
Commission. The Division will receive and consider written public comments for thirty calendar days after
the date of this Notice. Any such comment must be submitted in writing to the following addressee:
Bradley Eades
Colorado Department of Public Health and Environment
4300 Cherry Creek Drive South, APCD-SS-B1
Denver, Colorado 80246-1530
cdphe.commentsapcd@state.co.us
COLQRA®O
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STATE OF COLORADO
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COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT 4'; Ti
AIR AIR POLLUTION CONTROL DIVISION e
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TELEPHONE: (303) 692-3150
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CONSTRUCTION PERMIT
PERMIT NO: 1 5WE1 1 32
Issuance 1
DATE ISSUED:
ISSUED TO: DCP Midstream, LP
THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS:
Oil and gas facility, known as the Spindle Gas Plant, located in the Section 34, Township
2N, Range 67W, in Weld County, Colorado.
THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING:
Facility AIRS
Equipment Point Description
ID
One (1) Triethylene glycol (TEG) natural gas dehydration unit
(Weatherford, serial number: 34418) with a limited capacity of 7
MMscf per day. This emissions unit is equipped with one (1)
primary and one (1) backup Kimray, model 9015, gas-glycol pump
with a design capacity of 1.5 gal/min. This unit is equipped with a
P178 063 flash tank, re-boiler and still vent. Emissions from the still vent are
routed to a BTEX condenser and then to the enclosed
combustor. Emissions from the flash tank are recycled to the
plant inlet or routed to a flare (point 082). During periods of
enclosed combustor downtime, emissions from the still vent are
routed to the flare (point 082).
One (1) John Zink, custom model, serial number: STF-LH-168-24,
elevated, open flare used to combust process gas during
F-1 082 maintenance and malfunction events. Flare is also used to
combust emissions from TEG dehydration (point 063) unit during
primary control device downtime. Flare has a minimum
hydrocarbon control efficiency of 95%.
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
AIRS ID: 123/0015 Page 1 of 15
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Air Pollution Control Division
1. Within one hundred and eighty days (180) of the latter of commencement of operation or
issuance of this permit, compliance with the conditions contained in this permit shall be
demonstrated to the Division. It is the owner or operator's responsibility to self-certify
compliance with the conditions. Failure to demonstrate compliance within 180 days may
result in revocation of the permit. (Reference: Regulation No. 3, Part B, III.G.2).
2. This permit shall expire if the owner or operator of the source for which this permit was
issued: (i) does not commence construction/modification or operation of this source
within 18 months after either, the date of issuance of this construction permit or the date
on which such construction or activity was scheduled to commence as set forth in the
permit application associated with this permit; (ii) discontinues construction for a period
of eighteen months or more; (iii) does not complete construction within a reasonable
time of the estimated completion date. The Division may grant extensions of the
deadline per Regulation No. 3, Part B, III.F.4.b. (Reference: Regulation No. 3, Part B,
III.F.4.)
3. 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.)
4. 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
5. 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)
Annual Limits:
Facility AIRS Tons per Year
Equipment ID Point NO. VOC CO Emission Type
P178 063 --- 1.3 --- Point
F-1 082 1.6 9.0 5.3 Point
See "Notes to Permit Holder"for information on emission factors and methods used to calculate
limits.
Facility-wide emissions of each individual hazardous air pollutant shall be less than 8.0
tpy.
Facility-wide emissions of total hazardous air pollutants shall be less than 20.0 tpy.
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.
6. Point 063: Compliance with the emission limits in this permit shall be demonstrated by
running the GRI GlyCalc model version 4.0 or higher on a monthly basis using the most
recent wet gas analysis and recorded operational values (including gas throughput, lean
glycol recirculation rate, and other operational values specified in the O&M Plan).
Recorded operational values, except for gas throughput, shall be averaged on a monthly
basis for input into GRI GlyCalc and be provided to the Division upon request.
AIRS ID: 123/0015 Page 2 of 15
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Air Pollution Control Division
7. 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 AIRS Pollutants
Equipment Point Control Device Controlled
ID
VRU (closed loop) and backup flare during VRU
P178 . 063 downtime to control flash tank emissions VOC, HAPs
Enclosed Combustor and backup flare during
Enclosed Combustor downtime to control still vent
F-1 082 Open Flare VOC, HAPs
PROCESS LIMITATIONS AND RECORDS
9. This source shall be limited to the following maximum processing rates as listed below.
Monthly records of the actual processing rate 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 AIRS
Equipment Point Process Parameter Annual Limit
ID
Natural Gas Processed 2,555.0 MMscf/yr
P178 063 Natural Gas Processed during VRU
downtime 128.0 MMscf/yr
F-1 082 Natural gas routed to open flare 24.6 MMscf/yr
The owner or operator shall calculate monthly process rates based on the calendar
month.
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, monitor, and record
the natural gas processed each month and keep a compliance record on site or at a
local field office with site responsibility, for Division review.
10. Point 063: The owner or operator shall monitor and record VRU downtime. VRU
downtime shall be defined as times when the flash tank gas is routed to the flare. The
total hours of downtime and volume of gas processed during VRU downtime shall be
recorded on a monthly basis and used to calculate actual emissions to demonstrate
compliance with the emissions limits contained in this permit.
11. Point 063: This unit shall be limited to the maximum lean glycol circulation rate of 1.5
gallons per minute. The lean glycol recirculation rate shall be 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)
12. Point 082: The owner or operator shall continuously monitor and record on a monthly
basis the total volumetric flow rate of the gas stream being routed to the flare from all
activities using a flow meter. The owner or operator shall use monthly throughput
records to demonstrate compliance with the process limits and to calculate emissions as
described in this permit.
AIRS ID: 123/0015 Page 3 of 15
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Air Pollution Control Division
STATE AND FEDERAL REGULATORY
REQUIREMENTS
13. 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)
14. This source is subject to the odor requirements of Regulation No. 2. (State only
enforceable)
15. Point 063: This equipment is subject to the control requirements for glycol natural gas
dehydrators under Regulation No. 7, Section XII.H. Beginning May 1, 2005,
uncontrolled actual emissions of volatile organic compounds from the still vent and vent
from any gas-condensate-glycol (GCG) separator (flash separator or flash tank), if
present, shall be reduced by at least 90 percent through the use of air pollution control
equipment.
This source shall comply with all applicable general provisions of Regulation 7, Section
XII.
16. Point 063 and 082: This equipment is subject to the control requirements for glycol
natural gas dehydrators under Regulation No. 7, Section XVII.D. (State only
enforceable). These requirements include, but are not limited to:
XVII.D.3. Beginning May 1, 2015, still vents and vents from any flash separator or flash
tank on a glycol natural gas dehydrator located at an oil and gas exploration and
production operation, natural gas compressor station, or gas-processing plant
subject to control requirements pursuant to Section XVII.D.4., shall reduce
uncontrolled actual emissions of hydrocarbons by at least 95 percent on a rolling
twelve-month basis through the use of a condenser or air pollution control
equipment. If a combustion device is used, it shall have a design destruction
efficiency of at least 98%for hydrocarbons.
XVII.D.4. The control requirement in Section XVII.D.3. shall apply where:
XVII.D.4.b. Uncontrolled actual emissions of VOCs from a single glycol natural gas
dehydrator constructed before May 1, 2015, are equal to or greater than six (6)
tons per year, or two (2) tons per year if the glycol natural gas dehydrator is
located within 1,320 feet of a building unit or designated outside activity area.
17. Point 063 (enclosed combustor): The combustion device covered by this permit is
subject to Regulation Number 7, Section XVIl.B.2. General Provisions (State only
enforceable). If a flare or other combustion device is used to control emissions of volatile
organic compounds to comply with Section XVII, it shall be enclosed, have no visible
emissions during normal operations, and be designed so that an observer can, by
means of visual observation from the outside of the enclosed flare or combustion device,
or by other convenient means approved by the Division, determine whether it is
operating properly. This flare must be equipped with an operational auto-igniter
according to the following schedule:
• All combustion devices installed on or after May 1, 2014, must be equipped with
an operational auto-igniter upon installation of the combustion device;
• All combustion devices installed before May 1, 2014, must be equipped with an
operational auto-igniter by or before May 1, 2016, or after the next combustion
device planned shutdown, whichever comes first.
AIRS ID: 123/0015 Page 4 of 15
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11.
Air Pollution Control Division
18. Point 063 (open flare): The open flare covered by this permit has been approved as an
alternative emissions control device under Regulation Number 7, Section
XVII.B.2.e. The open flare must have no visible emissions during normal operations and
be designed so that an observer can, by means of visual observation from the outside of
the open flare, or by other convenient means approved by the Division, determine
whether it is operating properly.
19. Point 063: This source is subject to the requirements of 40 CFR, Part 63, Subpart HH -
National Emission Standards for Hazardous Air Pollutants for Source Categories from
Oil and Natural Gas Production Facilities including, but not limited to, the following:
• §63.764 - General Standards
o §63.764 (e)(1) -The owner or operator is exempt from the requirements of
paragraph (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).
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)(1) of this subpart; or
2. §63.764 (e)(1)(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, 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).
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.
2. §63.772(b)(2) - The determination of actual average benzene
emissions from a glycol dehydration unit shall be made using the
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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-
GLYCaIc TM , Version 3.0 or higher, and the procedures
presented in the associated GRI-GLYCaIc 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 meets
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.
1. §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
2. §63.774 (d)(1)(ii) - The actual average benzene emissions (in terms
of benzene emissions per year) as determined in accordance with
§63.772(b)(2).
20. Point 082: The Division has determined this flare shall comply with the New Source
Performance Standards requirements of Subpart A Section §60.18, General Control
Device and Work Practice Requirements, including, but not limited to, the following:
a. §60.18(b) Flares. Paragraphs (c) through (f) apply to flares.
b. §60.18(c)(1) Flares shall be designed for and operated with no visible emissions
as determined by the methods specified in paragraph (f), except for periods not
to exceed a total of 5 minutes during any 2 consecutive hours.
c. §60.18(c)(2) Flares shall be operated with a flame present at all times, as
determined by the methods specified in paragraph (f).
d. §60.18(c)(3) An owner/operator has the choice of adhering to either the heat
content specifications in paragraph (c)(3)(ii) of this section and the maximum tip
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Air Pollution Control Division
velocity specifications in paragraph (c)(4) of this section, or adhering to the
requirements in paragraph (c)(3)(i) of this section.
1.a.i.1.1.1.1 §60.18(c)(3)(i)(A) Flares shall be used that have a
diameter of 3 inches or greater, are nonassisted, have a hydrogen
content of 8.0 percent (by volume), or greater, and are designed for
and operated with an exit velocity less than 37.2 m/sec (122 ft/sec)
and less than the velocity, Vmax, as determined by the following
equation:
Vmax— (XH2—K1)* K2
Where:
Vmax = Maximum permitted velocity, m/sec.
K1 = Constant, 6.0 volume-percent hydrogen.
K2 = Constant, 3.9(m/sec)/volume-percent hydrogen.
XH2 = The volume-percent of hydrogen, on a wet basis, as
calculated by using the American Society for Testing and
Materials (ASTM) Method D1946-77. (Incorporated by reference
as specified in §60.17).
(ii) §60.18(c)(3)(i)(B) The actual exit velocity of a flare shall be
determined by the method specified in paragraph (f)(4) of this section.
(iii) §60.18(c)(3)(ii) Flares shall be used only with the net heating value of
the gas being combusted being 11.2 MJ/scm (300 Btu/scf) or greater
if the flare is steam-assisted or air-assisted; or with the net heating
value of the gas being combusted being 7.45 MJ/scm (200 Btu/scf) or
greater if the flare is nonassisted. The net heating value of the gas
being combusted shall be determined by the methods specified in
paragraph (f)(3) of this section.
e. §60.18(c)(5) Air-assisted flares shall be designed and operated with an exit
velocity less than the velocity, Vmax, as determined by the method specified in
paragraph (f)(6).
f. §60.18(c)(6) Flares used to comply with this section shall be steam-assisted, air-
assisted, or nonassisted.
g. §60.18(d) Owners or operators of flares used to comply with the provisions of
this subpart shall monitor these control devices to ensure that they are operated
and maintained in conformance with their designs. Applicable subparts will
provide provisions stating how owners or operators of flares shall monitor these
control devices.
h. §60.18(e) Flares used to comply with provisions of this subpart shall be operated
at all times when emissions may be vented to them.
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i. §60.18(f)(1) Method 22 of appendix A to this part shall be used to determine the
compliance of flares with the visible emission provisions of this subpart. The
observation period is 2 hours and shall be used according to Method 22.
j. §60.18(f)(2) The presence of a flare pilot flame shall be monitored using a
thermocouple or any other equivalent device to detect the presence of a flame.
k. §60.18(f)(3)The net heating value of the gas being combusted in a flare shall be
calculated using the following equation:
n
HT • K E CfR
{=1
Where:
HT = Net heating value of the sample, MJ/scm; where the net enthalpy per
mole of offgas is based on combustion at 25 °C and 760 mm Hg, but the
standard temperature for determining the volume corresponding to one mole
is 20 °C;
K = Constant. 7
( 1 ) {q Tole) { MJ I
1.740 x IT.' ppm sot
wfier°e the standard temperature for (q mole) is 20°C;
scm
C; = Concentration of sample component i in ppm on a wet basis, as
measured for organics by Reference Method 18 and measured for hydrogen
and carbon monoxide by ASTM D1946-77 or 90 (Reapproved 1994)
(Incorporated by reference as specified in §60.17); and
H; = Net heat of combustion of sample component i, kcal/g mole at 25 °C and
760 mm Hg. The heats of combustion may be determined using ASTM
D2382-76 or 88 or D4809-95 (incorporated by reference as specified in
§60.17) if published values are not available or cannot be calculated.
I. §60.18(f)(4) The actual exit velocity of a flare shall be determined by dividing the
volumetric flowrate (in units of standard temperature and pressure), as
determined by Reference Methods 2, 2A, 2C, or 2D as appropriate; by the
unobstructed (free) cross sectional area of the flare tip.
m. §60.18(f)(5) The maximum permitted velocity, Vmax, for flares complying with
paragraph (c)(4)(iii) shall be determined by the following equation.
Login (Vmax)=(HT+28.8)/31.7
Vmax = Maximum permitted velocity, M/sec
28.8=Constant
31.7=Constant
HT =The net heating value as determined in paragraph (f)(3).
n. §60.18(f)(6) The maximum permitted velocity, Vmax, for air-assisted flares shall be
determined by the following equation.
il Vmax= 8.706+0.7084 (HT)
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Vmax = Maximum permitted velocity, m/sec
8.706=Constant
0.7084=Constant
HT = The net heating value as determined in paragraph (f)(3).
OPERATING & MAINTENANCE REQUIREMENTS
21. Point 063 and 082: Upon issuance of this permit, 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.)
COMPLIANCE TESTING AND SAMPLING
Initial Testing Requirements
22. Point 063: The owner or operator shall demonstrate compliance with opacity standards
using EPA Method 22 to determine the presence or absence of visible emissions.
"Visible Emissions" means observations of smoke for any period or periods of duration
greater than or equal to one (1) minute in any fifteen (15) minute period during normal
operation. (Reference: Regulation 7, Section XVII.A.II)
23. Point 063: The owner or operator shall complete extended wet gas analyses prior to the
inlet of the TEG dehydrator. Analyses shall include a wet gas analysis representative of
inlet gas during cooling of molecular sieve beds and a wet gas analysis representative of
inlet gas during heating of molecular sieve beds. Results of the wet gas analyses shall
be used to calculate emissions of criteria pollutants and hazardous air pollutants per this
permit and be provided to the Division upon request.
24. Point 082: The operator shall complete an initial site specific extended gas analysis
within one hundred and eighty days (180) after commencement of operation or issuance
of this permit, whichever comes later, of the natural gas routed to this emissions unit in
order to verify the VOC, benzene, toluene, ethylbenzene, xylenes, n-hexane, and 2,2,4-
trimethylpentane content (weight fraction) of this emission stream. Results of testing
shall be used to calculate site-specific emission factors for the pollutants referenced
above (in units of lb/MMSCF gas vented) using Division approved methods. Results of
site-specific sampling and emissions factor analysis shall be submitted to the Division as
part of the self-certification and demonstrate the emissions factors established through
this initial testing are less than or equal to, the emissions factors established in the
permit application and "Notes to Permit Holder" for this emissions point. If any site
specific emissions factor developed through this sampling and analysis is greater than
the emissions factors established in the permit application and "Notes to Permit Holder"
the operator shall submit to the Division within 60 days, a request for permit modification
to update emissions factors and emissions limits specified in this permit.
Periodic Testing Requirements
25. Point 063: The owner or operator shall complete extended wet gas analyses prior to the
inlet of the TEG dehydrator on an annual basis. Analyses shall include a wet gas
analysis representative of inlet gas during cooling of molecular sieve beds and a wet gas
analysis representative of inlet gas during heating of molecular sieve beds. Results of
the wet gas analyses shall be used to calculate emissions of criteria pollutants and
hazardous air pollutants per this permit and be provided to the Division upon request.
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26. Point 082: On an annual basis, the operator shall complete a site specific extended gas
analysis of the natural gas routed to this emissions unit in order to verify the VOC
content (weight fraction) of this emission stream. Results of testing shall be used to
calculate site-specific emission factors for the pollutants referenced above (in units of
lb/MMSCF gas vented) using Division approved methods. Emission factors established
through this periodic testing shall be less than or equal to, the emissions factors
established in the permit application and "Notes to Permit Holder" for this emissions
point. If the site specific emissions factor developed through this sampling and analysis
is greater than the emissions factor established in the permit application and "Notes to
Permit Holder" the operator shall submit to the Division within 60 days, a request for
permit modification to update emissions factors and emissions limits specified in this
permit. The owner or operator shall continue to use the emissions factors established in
the permit application and "Notes to Permit Holder" to calculate actual emissions and
demonstrate compliance with the emissions limits specified in this permit unless a
modification is submitted to the Division. Records of site-specific sampling and
emissions factor analysis shall be recorded and maintained by the operator and made
available to the Division for inspection upon request.
ADDITIONAL REQUIREMENTS
27. A revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Regulation
No. 3, Part A, II.C)
a. 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 (NO,) 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.
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.
28. 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
AIRS ID: 123/0015 Page 10 of 15
Co A do ' =p e o`Public Health and Environment
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F
the modification to the Operating Permit is due within one year of the issuance of this
permit.
GENERAL TERMS AND CONDITIONS
29. 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.
30. 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
obtaining final authorization to operate are located in the Requirements to Self-
Certify for Final Authorization section of this permit.
31. 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.
32. 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.
33. 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 of a source may request a hearing
before the AQCC for review of the Division's action.
34. 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.
35. 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.
AIRS ID: 123/0015 Page 11 of 15
aCo do I p e o Public Health and Environment
Air Pollution Control Division
By:
Bradley Eades
Permit Engineer
Permit History
Issuance Date Description
Issuance 1 This Issuance Issued to DCP Midstream, LP
New CP for existing equipment previously on
95OPWE039.
This modification is being made to reflect
addition of control devices to point 063, and
addition of Point 082 (newly permitted source).
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Notes to Permit Holder at the time of this permit issuance:
1) The permit holder is required to pay fees for the processing time for this permit. An invoice for these
fees will be issued after the permit is issued. The permit holder shall pay the invoice within 30 days of
receipt of the invoice. Failure to pay the invoice will result in revocation of this permit (Reference:
Regulation No. 3, Part A, Section VI.B.)
2) The production or raw material processing limits and emission limits contained in this permit are
based on the consumption rates requested in the permit application. These limits may be revised
upon request of the owner or operator providing there is no exceedance of any specific emission
control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN)
and complete application form must be submitted with a request for a permit revision.
3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense
Provision for Excess Emissions During Malfunctions. The owner or operator shall notify the Division
of any malfunction condition which causes a violation of any emission limit or limits stated in this
permit as soon as possible, but no later than noon of the next working day, followed by written notice
to the Division addressing all of the criteria set forth in Part II.E.1. of the Common Provisions
Regulation. See: https://www.colorado.gov/pacific/cdphe/aqcc-regs
4) The following emissions of non-criteria reportable air pollutants are estimated based upon the process
limits as indicated in this permit. This information is listed to inform the operator of the Division's analysis
of the specific compounds emitted if the source(s) operate at the permitted limitations.
Uncontrolled Controlled
Emission Are the Emission
AIRS Rate emissions Rate
Point Pollutant CAS# (Ib/yr) reportable? (Ib/yr)
Benzene 71432 2546 Yes 160
Toluene 108883 7845 Yes 493
063 Ethylbenzene 100414 678 Yes 43
Xylenes 1330207 5113 Yes 322
n-Hexane 110543 761 Yes 42
Benzene 71432 496 Yes 25
Toluene 108883 239 No 12
082 Ethylbenzene 100414 7 No 0
Xylenes 1330207 34 No 2
n-Hexane 110543 3308 Yes 181
5) The emission levels contained in this permit are based on the following:
Point 063:
The emission levels contained in this permit are based on information provided in the application and
GRI GlyCalc 4.0 models. Two respective GRI GlyCalc 4.0 models were run to calculate emissions
during heating and during cooling of the molecular sieve beds. Results of the simulations were
summed assuming 4380 hr/yr operation at each condition. Controlled emissions are based on
AIRS ID: 123/0015 Page 13 of 15
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11
Air Pollution Control Division
emissions from GRI GlyCalc 4.0 model with controls and 20% buffer to account for variability in gas
composition.
Point 082:
The emission levels contained in this permit are based on the following emission factors:
Emission Factors- Emission Factors-
Uncontrolled Controlled
Pollutant lb/MMscf vented lb/MMscf vented Source
NOx 125.0 125.0 AP-42
CO 431.0 431.0 AP-42
VOC 14566.6 728.3 Gas Analysis
Benzene 20.2 1.0 Gas Analysis
n-Hexane 134.6 6.7 Gas Analysis
Toluene 9.7 0.5 Gas Analysis
Xylenes 1.4 0.1 Gas Analysis
Note: The controlled emissions for this point are based on the flare control efficiency of 95%.
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:
Applicable Status
Requirement
Operating Permit Major Source of:
VOC, CO, NOx
NANSR Major Source of:
VOC, NOx
PSD Major Source of:
CO
MACT HH Major Source Requirements: Not Applicable
Area Source Requirements: 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
I 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
AIRS ID: 123/0015 Page 14 of 15
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Airblic PollutionHealth ControlEnvironment Division
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) A self certification form and guidance on how to self-certify compliance as required by this permit may
be obtained online at: http://www.colorado.gov/pacific/cdphe/air-permit-self-certification
AIRS ID: 123/0015 Page 15 of 15
Colorado Air Permitting Project
Project Details
Review Engineer: Bradley.Fades
Package B: 330738
Received Date: 5/4/2015
Review Start Date: 11/6/2015
Section 01-Facility Information
Company Name: DCP Midstream LP
County AIRS ID: 123
Plant AIRS ID: 0015
Facility Name: Spindle Gas Plant
Physical Address/Location: SESW Sec 34 T2N R67W
Type of Facility: Natural Gas Processing Plant
Is this facility located in a NAAQS non-attainment area? Yes
If yes,for what pollutant? Ozone(NOx&VOC)
Section 02-Emissions Units In Permit Application
Emissions Issuance Self Cert
AIRS Point B Emissions Source Type Permit tt Action Engineering Remarks
Control? a Required?
Permit Initial New CP for Major T5
063 TEG Dehydrator Yes 15WE1132 1 Yes Issuance source(95OPWE039)
New CP for Major T5
Permit Initial source:Previously
082 Process Flare Yes 115WE1132 1 .Yes Issuance unpermitted source
Section 03-Description of Project
Source is requesting to add an enclosed combustor(for control of still vent emissions)and vapor recovery unit(VRU)to control flash tank
emissions for a 7.0 MMscf/d TEG dehy at an existing natural gas processing plant. Flash tank emissions will be recycled foran estimated 95%of
the time and the still vent emissions will be controlled with an enclosed flare. Emissions from the flash tank will be controlled by a back up flare
during VRU downtime.This point will be added as a new point to a new construction permit(currently operating under 95OPWE039).
In addition,source is requesting to permit a process flare to control plant emissions during plant startup,shutdown,and maintenance activities.
The Process Flare is a previously unpermitted source.
Project Emissions.
VOC:10.3 tpy(<40 tpy)
NOx:1.6 tpy(<40 tpy)
CO:5.3 tpy(<100 tpy)
Although the open flare(point 082)and the TEG Dehy(point 063)are existing emissions units, this project is conservatively estimated assuming
the project only involves construction of new emissions units because the faciility was previously permitted without claiming credit for control
devices(i.e.baseline actual emissions for purposes of determining the emissions increase is equal to zero).
1W 111 •x 15(.
This is a minor modification to an existing Title V,PSD and NANSR Major Stationary Source(i.e.emission increases do not qualify as a"significant
net emissions increase"to trigger additional requirements under NANSR or PSG()Future modifications resulting in a significant increase may result
in application of NANSR review requirements or PSD review requirements.
"significant"is as defined in Regulation 3,Part D,Section II.A.44..
� 3 y
Section 04-Public Comment Requirments
Is Public Comment Required? Yes
If yes,why? Requesting Synthetic Minor permit
Section 05-Ambient Air Impact Analysis Requirements
Was a quantitative modeling analysis required? No
If yes,for what pollutants?
If yes,attach a copy of Technical Services Unit modeling resuits summary.
Section 06-Stationary Source Classification
Is this stationary source a true minor? No
Is this stationary source a synthetic minor? ;Yes,
If yes,explain what programs and which pollutants here:
Hazardous Air Pollutants MACT:Area Source
Is this stationary source a major source? Yes
If yes,explain what programs and which pollutants here:
Title V Operating Permits.(OP):CO,VOC,NOx
Non-Attainment New Source Review(NANSR):VOC,NOx
Prevention of Significant Deterioration(PSD):CO
I
DCP Midstream LP
Spindle Gas Plant
Permit# 15WE1132 Issuance 1
AIRS ID 123/0015/063
Point Description
One(1)Triethylene glycol(TEG)natural gas dehydration unit(Weatherford,serial number 34418)with a design capacity of 7 MMscf per day. This emissions unit is
equipped with one(1)Kimray,model 9015,gas-glycol pump with a design capacity of 1.5 gamin. This unit is equipped with a flash tank,reboiler and still vent.
Emissions from the still vent are muted to an air-cooled condenser and then to the enclosed combustor. Emissions from the flash tank are muted back to the inlet by
a Vapor Recovery Unit(VRU).During periods of VRU downtime,flash tank emissions are muted to a backup flare.During periods of enclosed combustor downtime,
emissions from the still vent are routed to the backup flare.
Emissions Calculation Review
The source used GRI Glycalc 4.0 to estimate emissions.Two(2)model runs were carried out using wet gas compositions based on extended wet gas analyses
collected 3/18/2015 and 3/26/2015 from Spindle Gas Plant for pre-dehy cooling and heating respectively.Wet gas pressure and temperature are based on expected
pressure and temperature for this site during each cycle(cooling or heating).The assumption is made that 50%of gas processed is during pm-dehy cooing and 50%
is during pre-dehy heating cycles(see notes section below for further explanation of this assumption).The models were based on the following parameters:
Heating Cooling
Inlet Gas Pressure 400 psig 475 psig
Inlet Gas Temperature 95 deg F 75 deg F
Glycol Recirculate Rate 1.5 gpm 1.5 gpm 'I confirmed with the Kimray pump spec sheet that 1.5 gpm is maximum rate
Buffer 20%
GRI Glvcalc 4.0 Emissions Results
Gas throughput 7 MMscfd 217 MMscf/moi 2,555 MMscf/yr 638.8 MMscf/quarter
STILL VENT
Cooling(4380 hr/vr) Uncontrolled Controlled Controlled plus Buffer
Pollutant (lb/hr) (lbtyr) (tpy) (lb/hr) (lb/yr) (tpy) (lb/hr) (Ibtyr) (ipy) %Control.
VOC 7.0993 31095 15.5 0.354965 1555 0.78 0.4 1866 0.9 95.00%
HAPs - 2.6734 11709 5.9 0.13367 585 0.3 0.2 703 0.4 95.00%
Benzene 0.3707 1624 0.8 0.018535 81 0.0 0.0 97 0.0 95.00%
Toluene 1.3315 5832 2.9 0.066575 292 0.1 0.1 350 0.2 95.00%
Ethylbenzene 0.1059 464 0.2 0.005295 23 0.0 0.0 , 28 0.0 95.00%
Xylenes 0.7501 3285 1.6 0.037505 164 0.1 0.0 197 0.1 95.00%
n-Hexane 0.1131 495 0.2 0.005655 25 0.0 0.0 30 0.0 95.00%
2,2,4-trirnethylpentane 0.0021 9 0.0 0.000105 0 0.0 0.0 1 0.0 95.00%
Heating(4380 hr/vg -
Pollutant (lb/hr) (lb/yr) (tpy) (lb/hr) (lbtyr) (tpy) (lb/hr) (lbtyr) (tpy) %Control
VOC 2.0212 8853 4.4 0.10106 443 0.22 0.1 531 0.3 95.00%
HAPs 1.1668 5111 2.6 0.05834 256 0.1 0.1 307 0.2 95.00%
Benzene 0.2084 913 0.5 0.01042 46 0.0 0.0 55 0.0 95.00%
Toluene 0.4560 1997 1.0 0.0228 100 0.0 0.0 , 120 0.1 95.00%
Ethylbenzene 0.0486 213 0.1 0.00243 11 0.0 0.0 13 0.0 95.00%
Xylenes 0.4166 1825 0.9 0.02083 91 0.0 0.0 109 0.1 95.00%
n-Hexane 0.0369 162 0.1 0.001845 8 0.0 0.0 10 0.0 95.00%
2,2,4-trimethylpentane 0.0003 1 0.0 0.000015 0 0.0 0.0 0 0.0 95.00%
*Emissions from the still vent are muted to an enclosed combustor(ECD),during ECD downtime emissions go to backup flare
FLASH TANK Controlled emissions am 0lbrhr when using VRU for control(minimum 95%of gas throughput).
Cooling(4380 hAvrl Uncontrolled Controlled Controlled plus Buffer VRU Flare Overall
Pollutant Total To VRU To Flare (Ib/r) (tpy) (Ib/hr lb r
(lb/hr) (lb/hr) (Ib/r) ) ( N) (tpy) (lb/hr) (lb/yr) (tpy) %Control %Control %Control
VOC 0.431 0.409 0.022 1887.8 0.9 0.00108 4.7 2.36E-03 1.29E-03 5.7 2.83E-03 100.00% 95.00% 99.74%
HAPs 0.0235 0.022 0.001 102.9 0.1 5.9E-05 0.3 1.29E-04 7.05E-05 0.3 1.54E-04 100.00% 95.00% 99.74%
Benzene 0.0014 0.001 0.000 6.1 0.0 3.5E-06 0.0 7.67E-06 4.20E-06 0.0 9.20E-06 100.00% 95.00% 99.74%
Toluene 0.0027 0.003 0.000 11.8 0.0 6.8E-06 0.0 1.48E-05 8.10E-06 0.0 1.77E-05 100.00% 95.00% 99.74%
Ethylbenzene 0.0001 0.000 0.000 0.4 0.0 2.5E-07 0.0 5.48E-07 3.00E-07 0.0 6.57E-07 100.00% 95.00% 99.74%
Xylenes 0.0005 0.000 0.000 2.2 0.0 1.3E-06 0.0 2.74E-06 1.50E-06 0.0 3.29E-06 100.00% 95.00% 99.74%
n-Hexane 0.0185 0.018 0.001 81.0 0.0 4.6E-05 0.2 1.01E-04 5.55E-05 0.2 1.22E-04 100.00% 95.00% 99.74%
-
2,2,4-trimethylpentane 0.0003 0.000 0.000 1.3 0.0 7.5E-07 0.0 1.64E-06 9.00E-07 0.0 1.97E-06 100.00% 95.00% 99.74%
Heating(4380 hr/vr) Uncontrolled Controlled Controlled plus Buffer VRU Flare Overall
Pollutant Total To VRU To Flare (Ib/yr) (tpy) Ob/hr) (Ibtyr) (tpy) (lb/hr) (lbtyr) (tpy) %Control %Control %Control
(IbMr) (lb/hr) (lb/hr)
VOC 0.2044 0.19418 0.01022 895.3 0.4 0.00051 2.2 0.00112 6.13E-04 2.7 0.00134 100.00% 95.00% 99.75%
HAPs 0.0070 0.0067 0.0004 30.7 0.0 - 1.8E-05 0.1 0.00004 2.10E-05 0.1 0.00005 100.00% 95.00% 99.75%
Benzene 0.0007 0.0007 0.0000 3.1 0.0 1.8E-06 0.0 0.00000 2.10E-06 0.0 0.00000 100.00% 95.00% 99.75%
Toluene 0.0008 0.0008 0.0000 3.5 0.0 2E-06 0.0 0.00000 2.40E-06 0.0 0.00001 100.00% 95.00% 99.75%
Ethylbenzene 0.0001 0.000095 0.000005 - 0.4 0.0 2.5E-07 0.0 0.00000 3.00E-07 0.0 0.00000 100.00% 95.00% 99.75%
Xylenes 0.0002 0.00019 0.00001 0.9 0.0 5E-07 0.0 0.00000 6.00E-07 0.0 0.00000 100.00% 95.00% 99.75%
n-Hexane 0.0052 0.00494 0.00026 22.8 0.0 1.3E-05 0.1 0.00003 1.56E-05 0.1 0.00003 100.00% 95.00% 99.75%
2,2,4-trimethylpentane 0.0001 0.000095 0.000005 0.4 0.0 2.5E-07 0.0 0.00000 3.00E-07 0.0 0.00000 100.00% 95.00% 99.75%
*Emissions from the flash tank are recycled by VRU for minimum of 95%of emissions.During downtime,emissions are controlled by flare(up to 0.35 MMscfd)w/95%control.
TOTAL DEHY EMISSIONS-STILL VENT PLUS FLASH TANK
Uncontrolled Controlled Controlled plus Buffer
EF
Pollutant (lb/hr) (lbtyr) (tpy) (lb/hr) (lb/yr) (tpy) (lb/hr) (Ib/yr) (tpy) %Control (lb/MMscf) lb/31 day
VOC 9.756 42730.8 21.4 0.457614 2004.3 1.00 0.5 2405.2 1.20 95% 16.7244 204
HAPs 3.871 16953.7 8.5 0.192086 841.3 0.42 0.2 1009.6 0.50 95% 86
Benzene 0.581 2546 1.3 0.02896 126.8 0.06 0.0 152 0.08 95% 0.996 13
Toluene 1.791 7845 3.9 0.089384 391.5 0.20 0.1 470 0.23 95% 3.070 40
Ethylbenzene 0.155 , 678 0.3 0.007726 33.8 0.02 0.0 41 0.02 95% 0.2652 3
Xylenes 1.167 5113 2.6 0.058337 255.5 0.13 0.1 307 0.15 95% 2.001 26
n-Hexane 0.174 761 0.4 0.007559 33.1 0.02 0.0 40 0.02 96% 0.2978 3
2,2,4-trimethylpentane 0.003 12 0.0 0.000121 0.5 0.00 0.0 1 0.00 _ 96% 0.0048 0
Controlled emissions are based on 95%recycle of flash tank(5%Flared)and still vent emissions controlled with a combustor.
Regulatory Review
Regulation 3 _
Part A APEN Requirements
APEN is required since uncontrolled actual emissions are greater than 1 tpy VOC.
Part B-Construction Permit Requirements
Permit is required since facility-wide uncontrolled actual VOC emissions for all APEN-required points are greater than 2 tpy
Regulation 7'-Volatile Organic Compounds
XII.H VOLATILE ORGANIC COMPOUND EMISSIONS FROM OIL AND GAS OPERATIONS
Applicant is subject to the emission control requirements for glycol dehydrators since it is located in the nonattainment area and uncontrolled actual VOC emissions
are greater than 15 tpy.
XVII.D STATEWIDE CONTROLS FOR OIL AND GAS OPERATIONS
Per Reg 7,Section XVII.B.5,dehydrators subject to an emission control requirement under 40 CFR Part 63 are exempt from Section XVII.However,as discussed
below in MACT HH,this dehy is not subject to a control standard under MACT because it is meeting an emission exemption.Thus,the dehy is still subject to
Regulation 7 XVII requirements.
Applicant is currently subject to XVIII.D.3 because the enclosed combustor was not authorized by permit prior to May 1,2014,and uncontrolled actual emissions
(constructed before May 2015)are equal to or greater than 6 tpy.The open flare that is used as backup to the VRU and enclosed combustor was authorized by
permit prior to 2014 and is used as a back up control device.The open flare therefore being approved as an alternative emissions control device per Section XVII.B.
Regulation 8-Control of HAPs
Part E-MACT HH
This facility is a natural gas processing plant as defined in MACT HH.This gas-processing facility is a synthetic minor source of HAPs and is then an area source of
HAPs per MACT HH.This TEG dehy is subject to MACT HH area source requirements.However,the dehy will be able to comply with the exemption by maintaining
actual benzene emissions to less than 1984 lb/yr.This source is only required to calculate and keep records demonstrating that benzene emissions stay below the
exemption threshold.
NOTES:
•2014 Actual emissions were reported on APEN received with this application(May 4,2015)with actual uncontrolled emissions of 1.34 tpy VOC.Based on"actual"emissions,this
source would not be subject to Reg 7 Section XI I or XVII.However since permit limits allow for actual uncontrolled emissions up to 21.4 tpy VOC,requirements for Reg 7,XVII.D are
included in permit.The open flare used to control the flash tank emissions is approved as an alternative emissions control device per Reg.7 since it was authorized by permit
(95OPWE039)prior to May 1,2014 and is used as a backup control device to VRU/enclosed combustor.The open flare is also used to combust process gas during startup,shutdown
and maintenance under point 082.Also,the open flare is not equipped with an auto-igniter.This plant is continuously manned,and any occurance of pilot light failure must be
investigated prior to re-ignition per safety protocol.
*Since this facility is a natural gas processing plant,ALL HAP emitting units shall be considered when determining area/major source status wrt MACT HH.This facility is an area source
of HAPs.
*Operator calculated emissions used in this permit with GRI GlyCALC 4.0.The model was based off of extended gas analyses dated March 31,2015 and March 26 2015.This
Dehydrator has a reboiler however it has a design rate less than 5 MMBtu/hr and is APEN-exempt.
•Dehydrator has two distinct operating conditions depending on whether it is receiving gas during the heating or cooling cycle required for regeneration of the molecular sieve.The
assumption is made that 50%of the gas throughput to the Dehy is during Heating and 50%of the gas throughput to the Dehy is during Cooling.After discussion with applicant,it was
determined that Dehy inlet gas is a combination from 2 mole sieves of which either can be heating or cooling except that operation does not allow for both to be in cooling cycle
simultaneously.Based on operation,applicant expects that the actual breakdown of inlet gas is roughly 69%during heating cycles and 31%during cooling cycles.Since emission
estimates during cooling cycles are based solely on the gas composition from the cooling cycle(in reality,inlet gas is some combination of heating and cooling gas)and 50%of the total
gas throughput,the emission estimates as calculated provide a conservative estimate and calculation methods will be acceptable for compliance demonstration with the limits in this '..
permit.
*Since uncontrolled emissions for the flash tank result only during periods that the VRU is unable to recycle this stream to the plant inlet,this permit contains two process limits to
'.. capture each operating scenario.The total natural gas processed by the Dehydrator is a process limit(2,555 MMSCF/yr)in addition to the amount of gas processed during VRU/recycle
'.. system downtime(emissions result from both the flash tank and the still vent during VRU downtime).Per email correspondence from Roshini Shankaran,a plant alarm alerts an
'.. operator when the VRU associated with the flash tank is down.Time elapsed from when an operator is alerted to when the VRU is back in operation is recorded on a daily basis.
Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment
Air Pollution Control Division
DCP Midstream LP
Spindle Gas Plant
Permit# 15WE1132 Issuance 1
AIRS ID 123/0015/082
Equipment Description
Plant process streams to inlcude inlet gas,and residue gas associated with startup,shutdown,and
This source flares natural gas from: maintenance.This source is also permitted to combust gas produced in TEG Dehydrator flash tank and still vent
during primary control device downtime.
Emissions from this source are: routed to an open-flame flare
Emission Calculation Method
EPA Emission Inventory Improvement Program Publication:Volume II,Chapter 10-Displacement Equation(10.4-3)
Ex=O'MW-Xx/C
Ex=emissions of pollutant x
Q=Volumetric flow rate/volume of gas processed
MW=Molecular weight of gas=SG of gas'MW of air
Xx=mass fraction of x in gas
C=molar volume of ideal gas(379 scf/lb-mol)at 6OF and 1 atm
Throughput(O) 24.59 MMscf/yr I 2806.57 sct/hr I 2.09 MMscf/mo
MW 22,137 IMb�nol 0.001 MMsct/d
mole MW Ibx/Ibmol mass fraction E IMhr Iblyr tor
Helium 0.0200 4.0026 0.001 0.000 Helium 0.0 52 0.03
CO2 2.1500 44.01 0.946 0.043 CO2 7.0 61381 30.69
N2 0.5600 28.013 0.157 0.007 N2 1.2 10176 5.09
methane 74.1933 16041 11.901 0.538 methane 88.1 772035 386.02
ethane 12.8385 30.063 3.860 0.174 ethane 28.8 250373. 125.19
Mebane 6.1979 44.092 2.7328 0.123 propane 20.2 177274 88.64
isobutane 0.9065 58.118 0.5268 0.024 isobutane 3.9 34176 17.09
n-butane 2.0028 58.118 1.1640 0.053 n-butane 8.6 75507 37.75
isopentane 0.4375 72.114 0.3155 0.014 isopentane 2.3 20468 10.23
n-pentane 0.4150 72114 0.2993 0.014 n-pentane 2.2 19414 9.71
cyclopentane 0.0154 70.13 0.0108 0.000 cyclopentane 0.1 701 0.35
n-Hexane 0.0589 86.20 0.0507 0.002 n-Hexane 0.4 3291 1.65
cyclohexane 0.0148 86.18 0.0128 0.001 cyclohexane 0.1 827 0.41
Other hexanes 0.1264 86.18 0.1089 0.005 Other hexanes 0.8 7066 3.53
heptanes 0.0268 100.21 0.0269 0.001 heptanes 02 1742 0.87
methylcydohexane 0.0078 98.19 0.0077 0.000 methylcydohexane 0.1 497 0.25
224-IMP 0.0000 114.23 0.0000 0.000 224-TMP 0.0 0 0.00
Benzene 0.0098 78.12 0.0076 0.000 Benzene 0.1 496 0.25
Toluene 0.0040 92.15 0.0037 0.000 Toluene 0.0 239 0.12
Ethylbenzene 0.0001 106.17 0.0001 0.000 Ethylbenzene 0.0 7 0.00
Xylenes 0.0005 106.17 0.0005 0.000 Xylenes 0.0 34 0.02
C8+Heavies 0.0039 114.000 0.0044 0.000 C8+Heavies 0.0 288 0.14
99.99 VOC mass fraction: 0.2382 Total VOC Emissions(Uncontrolled) 171.0
22.137 Conservative Buffer 5%
Notes Total VOC Emissions w/Buffer(uncontrolled) 179.1
Mole%,from Spindle Gas Plant Inlet gas analysis collected 11/152013.
Emissions are based on 8760 hours of operation per year.
I used a MW of C8+of 114 used in application
Flarina Information
Equipment Description
Rare to combust various plant streams during maintenance,startup and shutdown events
Manufacturer John Zink
Model Custom
Serial Number STF-LH-168-24
Waste Gas Heating Value 1288 Btu/scf
Waste Gas Throughput 31666.19252 MMBtulyr
Combustion emission factor source: AP-42:Chapter 13.5
01.00OIttov OX/MMB[u I 04.31 Ilb 1lrev CO
O MBtu
Fuel Gas Combustion
0.46 tpy Nox
0.39 toy CO
Fuel gas combustion emissions include emissions from the flare pilot,and purge gas combustion.Purge gas is used to prevent negative pressure in the flare
header that would a/low air infiltration resulting in danger of explosion or flare damage.Emissions were calculated assuming a pilot gas flow rate of 50 acf/hr and
purge gas 1000 scf/hr and FHV of 1040 Btu/scf
Produced Natural Gas Venting/Flaring Preliminary Analysis Colorado Department of Public Health and Environment
Air Pollution Control Division
Emissions Summary
1.54 tpy NOX
Uncontrolled/PTE 5.30 tpy CO
179.1 tpy VOC
Controlled 8.95 tpy VOC
Uncontrolled Scenario A Controlled Total
Total(Ibryr) Reportable? llblvr)
Benzene 496 Yes 25
Toluene 239 No 12
Ethylbenzene 7 No 0
Xylenes 34 No 2
n-hexane' 3306 Yes 181
224-TMP 0 No 0
"includes contribution from flare pilot.Other HAPs from pilot are insignificant
Regulatory Applicability
AOCC Regulation 1
This source is subject to the opacity requirements for flares in Section II.A5:'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.'
AOCC Regulation 2
Section I.A applies to all emission sources."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."
AOCC Regulation 3 •
An APEN is required for this source because uncontrolled VOC emissions exceed two tons
Part A. per year in an attainment area.
A permit is required for this source because uncontrolled VOC emissions from this facility
Part B: exceed two tons per year in a nonattainment area for ozone.
Is public comment required? Public Comment Required because point contains new synthetic minor limits
AOCC Regulation 6-New Soprce Performance Standards
New source performance standards requirements of Subpart A Section§60.18,General
NSPS Subpart A Control Device and Work Practice Requirements for air-assisted flares.
Emission Factors for Permit
Uncontrolled
NOX 125.0 b/MMscf natural gas vented
CO 431.0 bfMMscf natural gas vented
VOC 14566.6 b/MMscf natural gas vented
Benzene 20.2 b/MMscf natural gas vented
Toluene 9.7 b/MMscf natural gas vented
Ethylbenzene 0.3 b/MMscf natural gas vented
Xylenes 1.4 b/MMscf natural gas vented
n-Hexane 134.6 b/MMscf natural gas vented
224-IMP 0.0 b/MMscf natural gas vented
Controlled
NOX 125.0 b/MMsci natural gas vented
CO 431.0 b/MMscf natural gas vented
VOC 728.3 b/MMscf natural gas vented
Benzene 1.0 b/MMscf natural gas vented
Toluene 0.5 bMtMscf natural gas vented
Ethylbenzene 0.0 b/MMsof natural gas vented
Xylenes 0.1 b/MMsof natural gas vented
n-Hexane 6.7 b/MMscf natural gas vented
224-IMP 0.0 b/MMscf natural gas vented
NOTES:...
'This source is permitted primarily for combustion of process gas during startup,shutdown,and maintenance events.This flare also combusts gas produced
from the TOG Dehydrator(point 063)in the flash tank and still vent during primary control device/gathering system downtime. The flare is equipped with a
waste gas meter that accounts for the total waste gas flow routed to the flare.As a result,some volume of the gas muted t o the flare will represent gas from
•
the still vent and/or flash tank of point 063.To simplify monitoring requirements and compliance demonstration,DCP will cal culate emissions from this point
using the entire metered volume to the flare.Since the volume of waste gas routed to this point from point 063 is a very sm all fraction of the permitted
volume,the gas flared from point 063 is not expected to contribute significantly to overall composition and volume for this source.
The waste gas metered at the flare header is inclusive of the purge gas.In order to develop a conservative NOx and CO emis sion estimate,DCP has
requested to calculate emissions resulting from the pilot and purge gas separately.Permit limits will be Inclusive of the a dditional emissions attributed to the
purge and pilot,in addition the overal requested volume(24.59 MMscf/yr)includes purge gas volume.
'This flare is subject to Regulation 7,Section XVII.B requirements for combustion devices since it is authorized as a"bac kup"control device for the TOG Deity
(point 063).
'Condition referencing 60.18 general control equipment(NSPS)was included per applicant request since some equipment that su pplies gas to the flare during
upset conditions are subject to NSPS.
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A CDPHE General APEN - Form APCD-200
> , Air Pollutant Emission Notice (APEN) and
C -4." Application for Construction Permit
All sections of this APEN and application must be completed for both new and existing facilities, including APEN
updates. An application with missing information may be determined incomplete and may be returned or result in
longer application processing times. You may be charged an additional APEN fee if the APEN is filled out
incorrectly or is missing information and requires re-submittal.
There may be a more specific APEN for your source (e.g. paint booths, mining operations, engines, etc.). A list of
specialty APENs is available on the Air Pollution Control Division (APCD)website at
www.colorado.gov/cdphe/apcd.
This emission notice is valid for five (5)years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term, or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
1, 1\1.1 �z �is
Permit Number: 95OPWE039 AIRS ID Number: 123 /0015
[Leave blank unless APCD has already assigned a permit#and AIRS ID]
Section 1 - Administrative Information
Company Name': DCP Midstream, LP
Site Name: Spindle Natural Gas Processing Plant
Site Location
Site Location:
Section 34, T2N, R67W County: Weld
NAICS or SIC Code: 1321
Mailing Address:
(Include Zip Code) 370 17th St, Suite 2500
Denver, CO Permit Contact: Roshini Shankaran
Phone Number: 303-605-2039
Portable Source
E-Mail Address:Home Base: RShankaran@dcpmidstream.com
I
'Please use the full, legal company name registered with the Colorado Secretary of State.This is the company name that will
appear on all documents issued by the APCD.Any changes will require additional paperwork.
33 of 5 5-
D,0
Form APCD-2OO - General APEN - Revision 7/2015 1 I LaV ,.• "'°„,
I
Permit Number: 95OPWE039 AIRS ID Number: 123 /0015/
[Leave blank unless APCD has already assigned a permit#and AIRS ID]
Section 2- Requested Action
❑r NEW permit OR newly-reported emission source(check one below)
2 STATIONARY source ❑ PORTABLE source
-OR
• MODIFICATION to existing permit (check each box below that applies)
❑ Change fuel or equipment ❑ Change company name ❑ Add point to existing permit
❑ Change permit limit ❑ Transfer of ownership2 ❑ Other(describe below)
-OR
▪ APEN submittal for update only (Please note blank APENs will not be accepted)
- ADDITIONAL PERMIT ACTIONS -
❑ Limit Hazardous Air Pollutants (HAPs)with a federally-enforceable limit on Potential To Emit (PTE)
❑ APEN submittal for permit exempt/grandfathered source
Additional Info Et Notes: Flare with a DRE of 95% to handle maintenance and malfunction emissions.
DCP is requesting an annual limit of 24.59 MMscf/yr for the volume of emissions being routed to the flare.
2 For transfer of ownership, a completed Transfer of Ownership Certification Form (Form APCD-104) must be submitted.
Section 3 - General Information
General description of equipment and purpose: Plant Flare
Manufacturer: John Zink Model No.: Custom Serial No.: STF-LH-168-24
Company equipment Identification No. (optional): Flare
For existing sources, operation began on: 1998
For new or reconstructed sources, the projected start-up date is:
r❑ Check this box if operating hours are 8,760 hours per year; if fewer, fill out the fields below:
Normal Hours of Source Operation: hours/day days/week weeks/year
Seasonal use percentage: Dec-Feb: Mar-May: June-Aug: Sept-Nov:
E;EC?42015
C0IORLD0
Form APCD-200 - General APEN - Revision 7/2015 2 � " "'//'
Permit Number: 95OPWE039 AIRS ID Number: 123 /0015/
[Leave blank unless APCD has already assigned a permit#and AIRS ID]
Section 4 - Processing/Manufacturing Information Et Material Use
Check box if this information is not applicable to source or process
From what year is the actual annual amount?
Design Process Actual Annual Requested Annual
Description Rate Amount Permit Limit3
(Specify Units) (Specify Units) (Specify Units)
Material
Consumption:
Finished
Product(s):
3Requested values wilt become permit limitations. Requested limit(s)should consider future process growth.
Section 5 - Stack Information
Geographical Coordinates
(Latitude/Longitude or UTM)
509828.2, 4437630.69
❑ Check box if the following information is not applicable to the source because emissions will not be emitted from a
stack. If this is the case, the rest of this section may remain blank.
Operator Discharge Height Temp. Flow Rate Velocity
Stack ID No. Above Ground Level (.F) (ACFM) (ft/sec)
(Feet)
Flare 80
Indicate the direction of the stack outlet: (check one)
O Upward ❑ Downward ❑ Upward with obstructing raincap
❑ Horizontal ❑ Other (describe):
Indicate the stack opening and size: (check one)
❑ Circular Interior stack diameter (inches):
❑ Square/rectangle Interior stack width (inches): Interior stack depth (inches):
❑ Other(describe):
3E-C24 415coLo 4DO.
Form APCD-2OO - General APEN - Revision 7/2015 3 ��
Permit Number: 95OPWE039 AIRS ID Number: 1 23 /0015/
[Leave blank unless APCD has already assigned a permit#and AIRS ID]
Section 6 - Combustion Equipment Et Fuel Consumption Information
❑� Check box if this information is not applicable to the source (e.g. there is no fuel-burning equipment associated
with this emission source)
Design Input Rate Actual Annual Fuel Use Requested Annual Permit Limit3
(MMBTU/hr) (Specify Units) (Specify Units)
1.09 9.20 MMscf/yr(Fuel only),24.59 MMscf/yr(waste gas)
From what year is the actual annual fuel use data?
Indicate the type of fuel used4:
❑■ Pipeline Natural Gas (assumed fuel heating value of 1,020 BTU/SCF)
❑ Field Natural Gas Heating value: BTU/SCF
❑ Ultra Low Sulfur Diesel (assumed fuel heating value of 138,000 BTU/gallon)
❑ Propane (assumed fuel heating value of 2,300 BTU/SCF)
❑ Coal Heating value: BTU/lb Ash Content: Sulfur Content:
❑■ Other (describe): 24.59 MMscf/yr (Waste Gas) Heating value (give units): 1288 Btu/scf
3 Requested values will become permit limitations. Requested limit(s)should consider future process growth.
4 If fuel heating value is different than the listed assumed value, please provide this information in the"Other" field.
Section 7 - Criteria Pollutant Emissions Information
Attach all emission calculations and emission factor documentation to this APEN form.
Is any emission control equipment or practice used to reduce emissions? ® Yes ❑ No
If yes, please describe the control equipment AND state the overall control efficiency (% reduction):
Pollutant Control Equipment Description Overall Control Efficiency
(%reduction in emissions)
TSP (PM)
PMio
PM 2.5
SOx
NOx
CO
VOC Flare 95%
Other:
-
COLORADO
Form APCD-2OO - General APEN - Revision 7/2015 . 4 I A.7 ","
Permit Number: 95OPWE039 AIRS ID Number: 123 /0015i
[Leave blank unless APCD has already assigned a permit#and AIRS ID]
Section 7(continued)
From what year is the following reported actual annual emissions data? N/A
Use the following table to report the criteria pollutant emissions from source:
(Use the data reported in Sections 4 and 6 to calculate these emissions.)
Emission
Uncontrolled Requested Annual Permit
Factor Actual Annual Emissions
Emission Emission Limit(s)3
Pollutant SourceFactor
(AP-42,Mfg. Uncontrolled Controlled5 Uncontrolled Controlled
(Specify units)
etc) (Tons/year) (Tons/year) (Tons/year) (Tons/year)
TSP (PM)
PM10
PM2.5
SOx
NOx 0.068 lb/MMBtu AP-42 1.54 1.54
CO 0.31 Ib/MMBtu AP-42 5.29 5.29
VOC 14572 Ib/MMscf Mass Balance 179.13 8.98
Other:
3 Requested values will become permit limitations. Requested limit(s)should consider future process growth.
5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
Section 8 - Non-Criteria Pollutant Emissions Information
Does the emissions source have any uncontrolled actual emissions of non-criteria
pollutants (e.g. HAP- hazardous air pollutant) emissions equal to or greater than 250 ® Yes ❑ No
lbs/year?
If yes, use the following table to report the non-criteria pollutant(HAP)emissions from source:
Uncontrolled Uncontrolled Controlled
CAS Overall Emission Emission Factor Actual Actual
Chemical Name Control Source
Number Efficiency Factor (AP-42,Mfg.etc) Emissions Emissions5
(specify units) (lbs/year) (lbs/year)
110-54-3 n-hexane 95% 134.55 Ib/MMscf Mass Balance 3,308 181
71-43-2 Benzene 95% 20.20 Ib/MMscf Mass Balance 496 25
5Annual emission fees will be based on actual controlled emissions reported. If source has not yet started operating, leave blank.
i5
COLOR400
Form APCD-200 - General APEN - Revision 7/2015 5 „..,,
Permit Number: 95OPWE039 AIRS ID Number: 123 /0015/
[Leave blank unless APCD has already assigned a permit#and AIRS ID]
Section 9 - Applicant Certification
I hereby certify that all information contained herein and information submitted with this application is complete, true
and correct.
2 IZZ /2015
Signature of Legally Authorized Person (not a vendor or consultant) Date
Roshini Shankaran Environmental Engineer
Name (please print) Title
Check the appropriate box to request a copy of the:
Ei Engineer's Preliminary Analysis conducted
El Draft permit prior to issuance
❑r Draft permit prior to public notice
(Checking any of these boxes may result in an increased fee and/or processing time)
This emission notice is valid for five (5)years. Submission of a revised APEN is required 30 days prior to expiration
of the five-year term,or when a reportable change is made (significant emissions increase, increase production,
new equipment, change in fuel type, etc). See Regulation No. 3, Part A, II.C. for revised APEN requirements.
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Send this form along with$152.90 to: For more information or assistance call:
Colorado Department of Public Health and
Environment Small Business Assistance Program
Air Pollution Control Division (303)692-3175 or(303)692-3148
APCD-SS-B1
4300 Cherry Creek Drive South Or visit the APCD website at:
Denver, CO 80246-1530
https://www.colorado.gov/cdphe/apcd
Telephone: (303)692.3150
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Form APCD-200 - Genera( APEN - Revision 7/2015 • 6 I A.: OLOR ADOCA
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