HomeMy WebLinkAbout20153307.tiff A caPHE ' COLORADO
Co ' Department of Public
Health&Environment
Dedicated to protecting and improving the health and environment of the people of Colorado
Weld County - Clerk to the Board
11500 St
PO Box 758
Greeley, CO 80632 RECEIVED
October 7, 2015 OCT 1 3 2015
WELD COUNTY
COMMISSIONERS
Dear Sir or Madam:
On October 14, 2015, the Air Pollution Control Division will begin a 30-day public notice period for
Noble Energy Inc. - Lilli 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 8 Environment
APCD-SS-B1
4300 Cherry Creek Drive South
Denver, Colorado 80246-1530
Attention: Clara Gonzales
Regards,
Clara Gonzales
Public Notice Coordinator
Stationary Sources Program
Air Pollution Control Division
Enclosure
/9 - t5 CC 2L..- ttAY I-k- �0�
2015-3307
4300 Cherry Creek Drive S., Denver, CO 80246-1530 P 303 692-2000 www.colorado.gov/cdphe u.
John W. Hickenlooper, Governor ! Larry Wolk,MD,MSPH, Executive Director and Chief Medical Officer �;
A CDPHE Air Pollution Control Division
Notice of a Proposed Project or Activity Warranting Public
Comment
Website Title: Noble Energy Inc. - Lilli Gas Plant - Weld County
Notice Period Begins: October 14, 2015
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: Noble Energy Inc.
Facility: Lilli Gas Plant
Natural Gas Processing Plant
SWSW Section 4, T8N-R58W
Weld County
The proposed project or activity is as follows: This modification will establish enforceable permit limits
based on the addition of a control device (flare) to the amine unit. Permit limits have been modified for
VOC and added for hydrogen sulfide, SO2, NOX, CO, and facility-wide synthetic minor limits for HAPs.
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 09WE0848 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:
Joshua Jones
Colorado Department of Public Health and Environment
4300 Cherry Creek Drive South, APCD-SS-B1
Denver, Colorado 80246-1530
cdphe.commentsapcd@state.co.us
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COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT �f'= '�`�
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AIR POLLUTION CONTROL DIVISION *" �*.
TELEPHONE: (303)692-3150 ; ;
*1876*
CONSTRUCTION PERMIT
PERMIT NO: 09WE0848
Issuance 3
DATE ISSUED:
ISSUED TO: Noble Energy Inc.
THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS:
Natural gas processing facility, known as the Lilli Gas Processing Plant, located at SWSW
corner of Section 4, Township 8N, Range 58W, in Weld County, Colorado.
THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING:
Facility AIRS
Equipment Point Description
ID
One (1) Methyldiethanolamine (MDEA) natural gas sweetening
system for acid gas removal with a design capacity of 15.0 MMSCF
per day(Toromont: no model or serial number associated with this
unit). This emissions unit is equipped with one (1) amine
recirculation pump (Weatherford, T105, SN: 20081143/4) with a
AMN 014 total design capacity of 100 gallons per minute. This system
includes a natural gas/amine contactor, a flash tank, and a natural
gas fired amine reboiler (rated at 4.8 MMBtu/hr). Flash tank
emissions are routed to the plant inlet or to the emergency flare
when this is not possible. Emissions from the regenerator still vent
are routed to a dedicated flare with supplemental fuel provided at
approximately 7.45 MMBtu/hr.
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 demonstrate
compliance within 180 days may result in revocation of the permit. (Reference: Regulation
No. 3, Part B, III.G.2).
AIRS ID: 123/0468/014 Page 1 of 10
Amine Version 2009-1
Noble Energy Inc. Co A •o a • rtme of Public Health and Environment
Permit No. 09WE0848 Air Pollution Control Division
Issuance 3
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 Emission
Equipment ID Point NO. VOC CO SO2 H2S Type
Amine Unit 014 3.5 10.2 24.3 10.0 0.25 Point
and Flare
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 by recording the facility's annual
criteria pollutant emissions, (including all HAPs above the de-minimis reporting level)from
each emission unit, on a rolling twelve (12) month total. By the end of each month a new
twelve-month total shall be 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. This rolling twelve-month
total shall apply to all permitted emission units, requiring an APEN, at this facility.
6. Compliance with the emission limits in this permit shall be demonstrated by running the
ProMax model, version 3.2 or higher, on a monthly basis using the most recent amine unit
inlet extended gas analysis(including H2S concentration as required by Condition 17)and
recorded operational values (including gas throughput, lean amine recirculation rate, inlet
gas temperature and pressure, concentration of amine in the lean amine stream,and flare
downtime). Recorded operational values,except for gas throughput,shall be averaged on a
monthly basis for input into ProMax.
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.)
AIRS ID: 123/0468/014 Page 2 of 10
Noble Energy Inc. Co" r -do .ra rtme of Public Health and Environment
Permit No. 09WE0848 l= Air Pollution Control Division
Issuance 3 a
Facility AIRS Pollutants
Equipment Point Control Device Controlled
ID
Dedicated flare for regenerator still vent emissions and VOC, HAP,
AMN 014 closed-loop system or emergency flare for flash tank HZS
emissions
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 AIRS Process Parameter Annual Limit
Equipment ID Point
Amine Unit 014 Natural Gas Throughput 5,475 MMscf/yr
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 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
10. The permit number and AIRS ID number 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. (Reference: Regulation No. 1, Section II.A.1. &4.)
12. 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. (Reference: Regulation No. 1, Section II.A.5.)
13. This source is subject to the odor requirements of Regulation No.2.(State only enforceable)
14. 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
AIRS ID: 123/0468/014 Page 3 of 10
Noble Energy Inc. C. •o rtme of Public Health and Environment
Permit No. 09WE0848 Air Pollution Control Division
Issuance 3
• §60.640—Applicability and Designation of Affected Facilities
o §60.640(b)-Facilities that have a design capacity less than 2 long tons per day
(LT/D) of hydrogen sulfide (H2S) in the acid gas (expressed as sulfur) are
required to comply with§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.
OPERATING & MAINTENANCE REQUIREMENTS
15. 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.)
COMPLIANCE TESTING AND SAMPLING
Initial Testing Requirements
16. Within one hundred and eighty(180)days of permit issuance, a source initial compliance
test shall be conducted on the amine unit to measure the uncontrolled emission rate for the
pollutants listed below in order to demonstrate compliance with the emissions limits
contained in Condition 5. Uncontrolled emissions from both the regenerator still vent and
the amine unit flash tank shall be tested. Uncontrolled emissions from the regenerator still
vent shall include any supplemental fuel provided to assist combustion. For compliance
demonstration purposes,the controlled emission rate shall be calculated as 5%of the tested
uncontrolled emission rate, since the flare is given a 95%control efficiency. The following
amine unit operational parameters shall be recorded during the test: lean amine solution
circulation rate, natural gas throughput rate, concentration of amine in the lean amine
solution (MDEA, MEA and piperazine), inlet gas temperature and pressure. 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)
Volatile Organic Compounds using EPA approved methods.
Periodic Testing Requirements
17. The operator shall sample the inlet gas to the amine unit on an annual basis to determine
the concentration of hydrogen sulfide(H2S)in the gas stream.The sample results shall be
monitored to demonstrate that this amine unit qualifies for the exemption from the Standards
AIRS ID: 123/0468/014 Page 4 of 10
Noble Energy Inc. Ca. ;do lk rtme of Public Health and Environment
Permit No. 09W E0848 \ Air Pollution Control Division
Issuance 3 == -
of Performance for Onshore Natural Gas Processing: SO2 Emissions (§60.640(b)). The
sample results shall also be used to calculate emissions of H2S and SO2 per the Emissions
Limitations and Records section of this permit. The testing required by Condition 18 maybe
used for this demonstration.
18. The owner or operator shall complete an extended sour gas analysis prior to the inlet of the
amine unit on an annual basis. Results of the sour gas analysis shall be used to calculate
emissions of criteria pollutants and hazardous air pollutants per the Emissions Limitations
and Records section of this permit.
19. The owner or operator shall sample the lean amine stream on a weekly basis to determine
the concentration of amine (MDEA, MEA and piperazine) in the stream using a wet
chemistry titration method or other standard industry method. Results of the amine
concentration sampling shall be used to monitor compliance with Condition 6.
20. A qualitative visual emissions observation shall be conducted daily during normal operation
of the source, for at least six minutes, to monitor compliance with Conditions 11 and 12.
When visible emissions persist for more than six(6)minutes,an EPA Method 9 observation
shall be performed to measure opacity from the flare. Records of the results of the
qualitative visual emissions observations and any Method 9 observations performed shall be
kept in a log and made available to the Division upon request. (Colorado Regulation No. 1,
Section II.A.1 and 4 and Colorado Regulation No. 3, Part B, Section III.E)
ADDITIONAL REQUIREMENTS
21. All previous versions of this permit are cancelled upon issuance of this permit.
22. A revised Air Pollutant Emission Notice(APEN)shall be filed:(Reference: Regulation No.3,
Part A, I I.C)
a. Annually whenever a significant increase in emissions occurs as follows:
For any criteria pollutant:
For sources emitting less than 100 tons per year, a change in actual emissions of
five (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 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.
AIRS ID: 123/0468/014 Page 5 of 10
Noble Energy Inc. I C. + so 9 s rtme of Public Health and Environment
Permit No. 09WE0848 Air Pollution Control Division
Issuance 3
23. Federal regulatory program requirements (i.e. PSD, NANSR or Title V Operating Permit)
shall apply to this source at any such time that this source becomes major solely by virtue of
a relaxation in any permit condition. Any relaxation that increases the potential to emit
above the applicable Federal program threshold will require a full review of the source as
though construction had not yet commenced on the source. The source shall not exceed
the Federal program threshold until a permit is granted. (Regulation No.3 Parts C and D).
GENERAL TERMS AND CONDITIONS:
24. 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.
25. 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.
26. 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.
27. 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.
28. 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.
29. 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.
AIRS ID: 123/0468/014 Page 6 of 10
Noble Energy Inc. 2 L7 '' C o L rtme � of Public Health and Environment
Permit No. 09WE0848 Air Pollution Control Division
Issuance 3
30. 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:
Joshua Jones
Permit Engineer
Permit History
Issuance Date Description
Issuance 3 This Issuance Modification for revision of emission estimation
method, addition of a flare to control emissions
from the still vent and flash tank, addition of
hydrogen sulfide (H2S), SO2, NOx and CO
emissions, and addition of facility-wide HAP
limits.
Issuance 2 July 14, 2011 Transfer of Ownership from Petro-Canada
Resources (USA) Inc. to Noble Energy Inc.
Issuance 1 March 12, 2010 Issued to Petro-Canada Resources (USA) Inc.
AIRS ID: 123/0468/014 Page 7 of 10
DNoble Energy Inc. c. . so • • rtme of Public •Health and Environment
Permit No. 09WE0848 Air Pollution Control Division
Issuance 3
Notes to Permit Holder:
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 permittee providing there is no exceedance of any specific emission control regulation or any ambient
air quality standard. A revised air pollution emission notice (APEN) and application form must be
submitted with a request for a permit revision.
3) This source is subject to the Common Provisions Regulation Part II, Subpart E, Affirmative Defense
Provision for Excess Emissions During Malfunctions. The permittee shall notify the Division of any
malfunction condition which causes a violation of any emission limit or limits stated in this permit as soon
as possible, but no later than noon of the next working day, followed by written notice to the Division
addressing all of the criteria set forth in Part II.E.1. of the Common Provisions Regulation. See:
https://www.colorado.gov/pacific/cdphe/agcc-reps
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
Emission Are the Controlled
AIRS Rate emissions Emission
Point Pollutant CAS# BIN (Ib/yr) reportable? Rate(Ib/yr)
Benzene 71432 NA 20,152 YES 1008
Toluene 108883 NA 16,138 YES 807
Ethylbenzene 100414 NA 2784 YES 139
014
Xylene 1330207 NA 6203 YES 310
n-Hexane 110543 NA 542 YES 27
Hydrogen Sulfide 7783064 NA 10000 YES 500
5) The VOC emission level contained in this permit is based on the amine unit emissions predicted by the
ProMax simulation model,Version 3.2,and the supplemental fuel provided to the still vent flare for proper
combustion of the waste gases. ProMax inputs included an extended sour gas analysis,representative of
the natural gas processed by this unit,sampled on 2/5/2015.
The amount of supplemental fuel required for proper combustion of the still vent waste gas stream(6555
scf/hr)was calculated using the waste gas heat content and flow(18 Btu/scf and 19007 scf/hr)predicted
by the ProMax model,the heat content of the residue gas (1136 Btu/scf)and a desired heat content of
300 Btu/scf for the total combined flow to the flare. The mass flow rate of supplemental fuel sent to the
flare was calculated using the required volumetric flow,the average molecular weight of the gas(from
residue gas sampled on 6/21/2012) and the ideal gas equation. VOC emissions associated with the
supplemental fuel(15.95 lb/hr)were estimated using the calculated mass flow rate and the constituent
weight percents from the residue gas analysis.
The VOC emission level in this permit was calculated by applying a control efficiency of 95%for the flares
and applying a safety factor of 20%to the calculated controlled emissions. Flash tank emissions are
conservatively estimated as being completely flared,though normal operation is recycling to the inlet.
AIRS ID: 123/0468/014 Page 8 of 10
Noble Energy Inc. Cacbi'' do `;, , rtme of Public Health and Environment
Permit No. 09WE0848 Air Pollution Control Division
Issuance 3
NON, CO and SO2 emission levels contained in this permit are based on the following emission factors:
Pollutant Process Emission Factors Source
NOx Still Vent 0.0641 lb/MMBtu TCEQ
Flash Tank 0.1380 lb/MMBtu TCEQ
CO Still Vent 0.5496 lb/MMBtu TCEQ
Flash Tank 0.2755 lb/MMBtu TCEQ
SO2 Still Vent and 1.88 lb SO2/lb H2S Engineering
Flash Tank flared Estimate
The heat flow rate for the flash tank waste gas stream (1.205 MMBtu/hr) was calculated using
properties from the flash stream ProMax output(1288 Btu/scf and 936 scf/hr).
The heat flow rate for the still vent waste gas stream (7.797 MMBtu/hr) was calculated as an
aggregate of the heat flow rate from the still vent(using properties from the ProMax output, Btu/scf
and scf/hr, as described above),the heat flow rate for the supplemental fuel (1136 Btu/scf)and an
estimated supplemental fuel volume of 6555 scf/hr sent to the flare.
A 20%safety factor was applied to the estimated NON and CO emissions to establish permit limits. A
10 tpy SO2 emission rate was requested in order to provide operational flexibility as gas composition
fluctuates.
6) The following equipment is currently exempt from construction permitting requirements and/or APEN
reporting requirements based on information provided by the operator for the Division's analysis:
AIRS ID Facility ID Description Notes
This unit is exempt from APEN reporting
requirements because the design rate is
Amine unit reboiler, less than 5 MMBtu/hr (Regulation No. 3,
NA NA rated at 4.8 MMBtu/hr Part A, II.D.1.k), and is therefore also
exempt from construction permitting
requirements (Regulation no. 3, Part B,
II.D.1.a).
Criteria pollutant emission levels for this unit are based on factors from AP-42,Chapter 1.4,Small Boilers
< 100 MMBtu/hr(7/1998).
7) 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.
8) This facility is classified as follows:
Applicable Status
Requirement
Operating Permit Synthetic Minor Source for VOC, CO, HAPs(individual and total)
NANSR Synthetic Minor Source for VOC
AIRS ID: 123/0468/014 Page 9 of 10
•Noble Energy Inc. I C•- so I a rtme of Public Health and Environment
Permit No. 09WE0848 Air Pollution Control Division
Issuance 3
NSPS LLL Applicable
9) 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 Z777—Subpart MMMMM
MACT 63.8980-End Subpart NNNNN—Subpart XXXXXX
10) 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: 123/0468/014 Page 10 of 10
Construction Permit Application
Preliminary Analysis Summary
Section 1 —Applicant Information
Company Name: Noble Energy Inc.
Permit Number: 09WE0848
Source Location: SWSW Sec. 4, T8N, R58W
Equipment Description: Amine Sweetening Unit
AIRS ID: 123-0468-014
Date: 01/12/2012
Review Engineer: Joshua Jones
Control Engineer: Stefanie Rucker
Section 2—Action Completed
Grandfathered X Modification APEN Required/Permit Exempt
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
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 A modification to add a control device to this
Information Request letter to the source? permit was submitted in Dec 2013.(see
application notes below)
On what date was this application complete? Original application
September 19, 2011
Section 4—Source Description
AIRS Point Equipment Description
One(1) Methyldiethanolamine (MDEA)natural gas sweetening system for acid gas
removal with a design capacity of 15.0 MMSCF per day(Toromont, no model or serial
number associated with this unit). This emissions unit is equipped with one (1)
Weatherford, model T105(SN: 20081143/4) amine recirculation pump with a total design
014 capacity of 100 gallons per minute. This system includes a natural gas/amine contactor, a
flash tank, and a natural gas fired amine regeneration reboiler(rated at 4.8 MMBtu/hr).
Flash tank emissions are routed to the plant inlet or to the emergency flare when this is
not possible. Emissions from the regenerator still vent are routed to a dedicated flare with
supplemental fuel provided at approximately 7.45 MMBtu/hr.
Is this a portable source? Yes X No
Is this location in a non-attainment area for any criteria X Yes No
pollutant?
If"yes", for what pollutant? PM10 CO X Ozone
Is this location in an attainment maintenance area for Yes X No
any criteria pollutant?
Page 1
If"yes",for what pollutant?
(Note: These pollutants are subject to minor source PM10 CO Ozone
RACT per Regulation 3, Part B,Section III.D.2)
Is this source located in the 8-hour ozone non-
attainment region?(Note: If"yes"the provisions of X Yes No
Regulation 7,Sections XII and XVII.C may apply)
Section 5—Emission Estimate Information
AIRS Point Emission Factor Source
014 Site-specific using ProMax version 3.2
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
014 15.0 MMscf per day(5475 MMscf/yr) natural gas throughput, 100 gallons per minute
lean amine circulation rate
Basis for Actual Emissions Reported During this APEN Filing(Reported to Inventory)
AIRS Point Process Consumption/Throughput/Production Data Year
014 15.0 MMscf per day(5475 MMscf/yr) natural gas throughput, 100 2013
gallons per minute lean amine circulation rate
Basis for Permitted Emissions(Permit Limits)
AIRS Point Process Consumption/Throughput/Production
014 15.0 MMscf per day(5475 MMscf/yr) natural gas throughput, 100 gallons per minute
lean amine circulation rate
Does this source use a control device? X Yes No
AIRS Point Process Control Device Description % Reduction
Granted
Flare(dedicated flare for still vent and plant emergency
014 01 flare for flash tank) 95
Section 6—Emission Summary(tons per year)
Point NO. VOC CO H2S SO2 Single HAP Total
HAP
10.08
PTE: 014 - 169.21 - 5.0 (Benzene) 22.91
Uncontrolled point
source emission 014 -- 169.21 -- 5.0 --- 10.08 22.91
rate: (Benzene)
Controlled point 0.50
source emission 014 2.92 8.46 20.22 0.25 10.0 (Benzene)
1.15
rate:
Total Permitted
emissions 014 3.50 10.15 24.27 0.25 10.0 0.60 1.37
(includes 20% (Benzene)
safety factor):
Section 7—Non-Criteria/Hazardous Air Pollutants
Uncontrolled Are the Controlled Emission
Pollutant CAS# BIN Emission Rate emissions
(Ib/yr) reportable? Rate(Ib/yr)
Benzene 71432 NA 20,152 Yes 1008
Toulene 110543 NA 16,138 Yes 807
Ethylbenzene 100414 NA 2784 Yes 139
Page 2
Xylenes 1330207 NA 6203 Yes 310
n-Hexane 110543 NA 542 Yes 27
Note: Regulation 3, Part A, Section II.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 X Yes No
standard? (see notes section 14)
If"yes", complete the information listed below
AIRS Point Process Pollutant Regulatory Basis Test Method
01 VOC Regulation No. 3, Part B.,Section III.G.3 Stack Test
014 VOC,
01 HAPs, State Only Requirement Site-specific gas
H2S analysis
Section 9-Source Classification
Is this a new previously un-permitted source? Yes X No
What is this point classification? True X Synthetic Major
Minor Minor
What is this facility classification? True X Synthetic Major
Minor Minor
Classification relates to what programs? X Title V PSD X NA NSR X MACT
Is this a modification to an existing permit? X Yes No
If"yes"what kind of modification? X Minor Synthetic Major
Minor
Section 10—Public Comment
Does this permit require public comment per CAQCC Regulation 3? X Yes No
If"yes", for which pollutants?Why? VOC, HAPs-for synthetic minor limits
For Reg. 3, Part B, III.C.1.a (emissions increase>25/50 tpy)? Yes No
For Reg. 3, Part B, III.C.1.c.iii (subject to MACT)? X Yes 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 Yes X No
Air Quality Standards (NAAQS)?
If"yes", for which pollutants?Why?
AIRS Point Section 12—Regulatory Review
Regulation 1 - Particulate, Smoke, Carbon Monoxide and Sulfur Dioxide
Page 3
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,
014 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
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
014 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.
Regulation 3-APENs, Construction Permits,Operating Permits,PSD
Part A-APEN Requirements
Criteria Pollutants: For criteria pollutants,Air Pollutant Emission Notices are required for:
014 each individual emission point in a nonattainment area with uncontrolled actual emissions
of one ton per year or more of any individual criteria pollutant(pollutants are not summed)
for which the area is nonattainment.
(Applicant is required to file an APEN since emissions exceed 1 ton per year VOC)
Part B—Construction Permit Exemptions
014 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 ll.D.2.a)
Regulation 6- New Source Performance Standards
NSPS LLL: Each sweetening(amine)unit and each sweetening unit followed by a
sulfur recovery unit; manufacturer date after January 24, 1984.
014 Applicant is not subject to NSPS LLL because this source will have a design capacity
less than 2 long tons/day H2S 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 H2S
expressed as sulfur. No other requirements apply.
NSPS OOOO: Each sweetening(amine) unit and each sweetening unit followed by a
sulfur recovery unit; construction commenced date after August 23,2011.
014
Applicant is not subject to NSPS OOOO because construction commenced on this unit
before August 23, 2011. This unit began operation on October 5, 2010.
_Regulation 7—Volatile Organic Compounds
014 None
Regulation 8—Hazardous Air Pollutants
014 None
Page 4
Section 13—Aerometric Information Retrieval System Coding Information
Emission Pollutant/ Fugitive Emission Factor Control
Point Process Process Description Factor CAS# (Y/N) Source (°/0)
ProMax
61.81 Process
lbs/mmscf VOC No Simulator/ 95
Engineering
Estimate
1.83 H2S/ ProMax
lbs/mmscf 7783064 No Process 95
Simulator
3.65 SO2No Engineering 0
lbs/mmscf Estimate
3.68 Benzene/ ProMax
lbs/mmscf 71432 No Process 95
01 Amine Unit Simulator
014 ProMax
2.95 Toluene/ No Process 95
lbs/mmscf 108883 Simulator
0.51 Ethylbenzene/ ProMax
lbs/mmscf 100414 No Process 95
Simulator
1.13 Xylenes/ ProMax
lbs/mmscf 1330207 No Process 95
Simulator
0.10 n-Hexane/ ProMax
lbs/mmscf 110543 No Process 95
Simulator
SCC 31000305—Gas Sweetening; Amine process
Emission factors include emissions from the flash tank and still vent as well as emissions from
the flare burner used to supply supplemental fuel to the still vent waste gas stream. Factors are
based on natural gas processing of 5475 MMScf/yr.
Page 5
Section 14-Miscellaneous Application Notes
AIRS Point 014 Amine Unit
The table below summarizes the inputs to the process simulation used to calculate the PTE for this
equipment.
Parameter Value
Inlet Gas Temperature 86°F
Inlet Pressure 800 psig
An APEN and modification to the original application was submitted for the amine unit on December 19,
2012. This modification was to add a flare as a control device for the amine unit still vent and flash tank.
This application also requested a 10 tpy SO2 limit and a facility-wide HAP limit of 8/20 tpy for
individual/total HAP. No estimate of NOx or CO emissions associated with the flare was provided in the
12/9/2012 application. Additional information was submitted on June 3, 2015 which included an estimate
of NOx and CO emissions associated with the flare and a revision to VOC and HAP emission estimations
using the ProMax simulation model. Emissions were previously estimated using the HYSIS model.
Uncontrolled emission factor calculations were performed using ProMax output for the still vent and flash
tank. Still vent emissions are routed to a dedicated flare given a control efficiency of 95%. Flash tank
emissions are normally routed to plant inlet, or when this is not possible,to the plant emergency flare,
also given a 95%control efficiency. Flash tank emissions have been conservatively estimated as always
being routed to the plant emergency flare for permitting purposes.
Emissions of VOC, NON, and CO include a 20%safety factor for permitting purposes and include the
emissions from supplemental fuel provided to the still vent flare to enable proper combustion of the waste
stream.
Initial testing and self certification have been submitted to the Division, however FA was denied because
the source failed to meet the requirements of Condition 9 of previous issuance(Condition 6 of this
issuance)since they did not have the current version of the model used to establish emission limits to run
for compliance purposes.
This amine unit has a reboiler rated at 4.8 MMbtu/hr. Since this source has a design rate of less than 5
MMbtu/hr it is APEN-exempt(Regulation No. 3, Part A, II.D.1.k), and is therefore also exempt from
construction permitting requirements(Regulation no. 3, Part B, II.D.1.a). Criteria pollutant emission levels
for this unit are based on factors from AP-42, Table 1.4-1, Small Boilers< 100 MMBtu/hr(7/1998).
The source stated, in notes included in the December modification package,that the 1.78 MMBtu/hr
molecular sieve regenerator was not a part of the amine unit and should be removed from the permit.
A stack test was done for the previous permit issuance on February 24, 2011, however the plant was not
operating at design capacity of 15.0 MMscf/day. The plant was operating at about 7 MMscf/day at the
time and VOC emissions were tested at 13.1 tons/yr. Field Services had required that a new stack test
be done to demonstrate compliance once the plant was operating at 10.0 MMscf/day, since the unit was
approaching its emission limits at 7 MMscf/day. An additional compliance test was performed on June
27, 2013 at a gas processing throughput rate of 11.9 MMscf/day that revealed an uncontrolled VOC
emission rate(NMOC)of 77.7 tons/yr. However, no notice of testing or test protocol was submitted prior
to the test being performed,therefore the test report submitted was not reviewed for compliance
demonstration. A compliance test will be required within 180 days of permit issuance to determine
compliance with the revised permit limits since the initial test was done at approximately half the
permitted throughput.
This required compliance test will be for uncontrolled emissions, since testing controlled emissions from
an open flare is not possible, and a control efficiency of 95%will be applied to identify controlled
emissions for test compliance purposes.
(notes continued below)
Page 6
Section 14—Miscellaneous Application Notes(continued)
AIRS Point 014 Amine Unit
H2S emissions for the original application (2.5 tpy)were based on 10 ppm molar in feed gas (per email
with Chris Martinez on Jan 27, 2012). The revised application received on December 19, 2012
conservatively estimated uncontrolled H2S emissions at 5 tpy, and requested a permit limit of 10 tpy for
SO2 in order to provide operational flexibility as gas composition fluctuates. The ProMax model
simulation submitted for this permitting action did not include H2S emissions because the inlet gas
analysis used in the ProMax model did not show H2S at detectable levels.
The amount of supplemental fuel required for proper combustion of the still vent waste gas stream (6555
scf/hr)was calculated using the waste gas heat content and flow(18 Btu/scf and 19007 scf/hr) predicted
by the ProMax model, the heat content of the residue gas (1136 Btu/scf)and a desired heat content of
300 Btu/scf for the total combined flow to the flare. The mass flow rate of supplemental fuel sent to the
flare was calculated using the required volumetric flow, the average molecular weight of the gas (19.18
Ib/Ib-mol,from residue gas sampled on 6/21/2012)and the ideal gas equation. VOC emissions
associated with the supplemental fuel (15.95 lb/hr)were estimated using the calculated mass flow rate
and the constituent weight percents from the residue gas analysis.
Using the above calculations,the supplemental fuel burner was given a heat input rating of 7.45
MMBtu/hr. This burner is therefore subject to APEN reporting requirements but exempt from permitting
requirements per Reg. 3, Part B, Section II.D.1.e (fuel burning equipment with design rate less than 10
MMBtu/hr). Therefore emissions from supplemental fuel combustion have been included with the amine
unit point but no limit has been placed on combustion of supplemental fuel by the flare burner.
ProMax output emissions factors(uncontrolled, sum of still vent,flash tank, and supplemental
fuel, not including 20%safety factor for permitted limits)
VOC =(38.6315 lb/hr)*(8760 hr/yr)/(5475 MMscf/yr) =61.81 lb/MMscf(169.21 TPY)
Benzene= (2.3005 lb/hr)*(8760 hr/yr)/(5475 MMscf/yr)= 3.6808 lb/MMscf(10.08 TPY)
Toluene=(1.8422 lb/hr)*(8760 hr/yr)/(5475 MMscf/yr)=2.9475 lb/MMscf(8.07 TPY)
Ethylbenzene= (0.3178 lb/hr)*(8760 hr/yr)/(5475 MMscf/yr)=0.5085 lb/MMscf(1.39 TPY)
Xylenes = (0.7081 lb/hr)*(8760 hr/yr)/(5475 MMscf/yr)= 1.1330 lb/MMscf(3.10 TPY)
n-hexane= (0.0618 lb/hr)*(8760 hr/yr)/(5475 MMscf/yr) =0.0989 lb/MMscf(0.27 TPY)
Emissions of NOx and CO were estimated using emission factors (in lb/MMBtu)from the Texas
Commission on Environmental Quality(TCEQ)for non-assisted or air assisted flares (TCEQ publication
RG-360N11, Feb 2012, pg A-54). Separate EFs were used for streams with high energy(Btu)content
(flash tank waste gas)and low energy content(still vent waste gas). Heat flow rate of the flash tank
waste gas stream was calculated using properties given in the ProMax simulation (1288 Btu/scf and 936
scf/hr). Heat flow rate of the still vent waste gas stream was calculated as an aggregate of the heat flow
for the still vent waste stream (using properties from the ProMax output, 18.3 Btu/scf and 19007 scf/hr)
and the heat flow for the supplemental fuel (1136 Btu/scf and estimated supplemental fuel volume of
6555 scf/hr sent to the flare).
Controlled Emission Factors(not including 20% safety factor for permitted limits)
Flash Tank
NOx= (0.1380 Ib/MMBtu)*(1288 Btu/scf)*(936 scf/hr)*(8760 hr/yr)/(5475 MMscf/yr)=0.266 lb/MMscf
CO= (0.2755 lb/MMBtu)*(1288 Btu/scf)*(936 scf/hr)*(8760 hr/yr)/(5475 MMscf/yr)=0.531 lb/MMscf
Still Vent
NOx= (0.0641 lb/MMBtu)*((18.3 Btu/scf*19007 scf/hr)+(1136 Btu/scf)*(6555 scf/hr))/5475 MMscf/yr=
0.80 lb/MMscf
CO = (0.5496 lb/MMBtu)*((18.3 Btu/scf*19007 scf/hr)+(1136 Btu/scf)*(6555 scf/hr))/5475 MMscf/yr=
6.854 lb/MMscf
The SO2 emission factor is based on 95% conversion of H2S and a molecular weight ratio of
64.066/34.0809 (SO2 to H2S).
Page 7
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