Oil and Gas Production Facilities

Chapter 6, Section 2 Permitting Guidance

June 1997

Revised November 1998

Revised January 2000

Revised August 2001

Revised July 28, 2004 (specific guidance for Jonah/Pinedale Anticline Area)

Revised August 2007

Revised March 2010

This Guidance applies to surface oil and gas production facilities where hydrocarbon fluids are produced, 

processed and/or treated prior to custody transfer from the facility.

This Guidance does not apply to natural gas-fired engines unless the engine is used to power a pumping 

unit.

The Presumptive BACT permitting requirements under this Guidance apply to facilities with associated 

wells spud on/after August 1, 2010 and to facilities with a modification occurring on/after August 1,

2010. 

Start up or modification of a facility may occur prior to obtaining an Air Quality Permit or Waiver only 

when the Presumptive BACT permitting requirements under this Guidance are met. Otherwise, an Air 

Quality Permit or Waiver shall be obtained prior to start up or modification of a facility.

For the purposes of this Guidance CDA refers to facilities located in Concentrated Development Areas.

JPAD refers to facilities located in the Jonah and Pinedale Anticline Development Area.

STATEWIDE refers to all facilities not located in the CDA or JPAD areas.
B L A N K
Table of Contents

Applicability 1

 When is a permit needed 1

 Which pollutants are associated with O&G Production Facilities 1

Production Facility Emission Sources 2

 O&G Production Facility equipment emission sources 2

BACT & Presumptive BACT (what it is and when to use it) 3

JPAD CDA STATEWIDE Map 4

STATEWIDE P-BACT permitting requirements 5

 Flashing 5

Dehydration Units 6

Scenario 1 6

Scenario 2 7

Determining potential uncontrolled & potential emissions from dehydration units 8

Pneumatic pumps 9

Pneumatic controllers 10

Blow down & venting 10

Emission sources without P-BACT requirements 10

CDA P-BACT permitting requirements 11

Flashing 11

Dehydration units 12

Scenario 1 12

Scenario 2 13

Pneumatic pumps 14

Pneumatic controllers 15

Well completions 15

Produced water tanks 16

Blow down & venting 17

Emission sources without P-BACT requirements 17

JPAD P-BACT permitting requirements 18

Flashing 18

Dehydration units 18

Pneumatic heat trace pumps & other pneumatic pumps 19

Pneumatic controllers 19

Produced water tanks 20

Well completions 20

Blow down & venting 21

Emission sources without P-BACT requirements 21

Determining P-BACT emissions 22

Flashing 22

Dehydration units 24

Kimray glycol pump rates (Table 1) 25
Table of Contents cont’d

BACT Emission control requirements 26

Flashing emissions 26

Dehydration unit emissions 27

Sources without P-BACT emission control requirements 28

Permit Applications 29

A complete applications includes ... 29

How to obtain forms 30

When/where to file application 30

Example process diagram & description 31 - 32

Application review process, Public Notice, billing 33

Notice of Installation 34

NOI use as complete application 34

NOI use as equipment change notification 34

Examples for use of NOI 36

How to obtain NOI form 37

When/where to file NOI form 37

JPAD permit application - specific requirements 38

AQD Pinedale 1 forms 39

Explanation of 0.6 decline factor 40

Appendix A - Permit Application Forms 42

AQD-OG0 Application Identification 44

AQD-OG0 NOI Identification 45

AQD-OG00 Checklist for Complete Application 46

AQD-OG1 Application Cover Sheet 47

AQD-OG2 Equipment List 48

Equipment List Page 2 49

AQD-OG3 Storage Tanks, Pressurized Vessels & Pneumatic Pumps 50

AQD-OG4 Dehydration Units 51

AQD-OG5 Pumping Unit Engines 52

AQD-OG6 Emission Summary 53

AQD-OG7 NOI 54

AQD-OG8 Multiple Facilities 55

AQD-OG9 Change of Ownership 56

AQD-OG10 BACT Cost Analysis Worksheet 57

Appendix B – Emission Calculations 59

AP-42 emission factors 61

Storage tank emissions (flashing, working, breathing losses) 61

Pressurized vessels (separator, treater, FWKO, flash separator, gunbarrel, gas boot) 62

Dehydration units 62

Natural gas-fired heaters 63

Flares 63

Pneumatic pumps 64

Truck loading 65

Fugitives 66

IC pumping unit engines 67

Mol% to Wt% conversion 67

Appendix C – Definitions 68
Acronyms & Abbreviations

For thepurposes of this Guidance CDA refers to facilities located in Concentrated Development Areas.

JPAD refers to facilities located in the Jonah and Pinedale Anticline Development Area.

STATEWIDE refers to all facilities not located in the CDA or JPAD areas.

AQD Air Quality Division

API American Petroleum Institute

BACT Best Available Control Technology

BBL barrel

BPD barrels per day

BTEX Benzene/Toluene/

Ethyl-benzene/Xylenes

Btu British thermal unit

C6 S2 Chapter 6 Section 2 (of the 

WAQSR)

CAA Clean Air Act Amendments of 1990

CDA Concentrated Development Area

CO Carbon Monoxide

EPA Environmental Protection Agency

gpm gallons per minute

H2S Hydrogen Sulfide

HAP Hazardous Air Pollutants

HP high pressure

Hp horsepower

JPAD Jonah & Pinedale Anticline 

Development Area

lb pound

LP low pressure

MMBtu one million BTUs

MMSCF one million standard cubic feet 

(SCF × 106) 

(MMSCFD = 1,000,000 SCF per day)

MSCF one thousand standard cubic feet

(SCF×1000)

(MSCFD=1000 SCF per day)

NESHAP National Emission Standards for 

Hazardous Air Pollutants

NOI Notice of Installation

NOV Notice of Violation

NOX Nitrogen Oxides

NSPS New Source Performance 

Standards

NSR New Source Review

pph pounds per hour

PPMV parts per million by volume

PSD Prevention of Significant 

Deterioration

psig pounds per square inch gauge

psia pounds per square inch absolute

SCF standard cubic foot

SO2 Sulfur Dioxide

S/W/B Standing/Working/Breathing losses

TEG Tri-Ethylene Glycol

TPY Tons per Year

VOC Volatile Organic Compounds

WAQD Wyoming Air Quality Division

WAQSR Wyoming Air Quality Standards 

and Regulations

WDEQ Wyoming Department of 

Environmental Quality
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 1 of 71

Introduction

The Chapter 6 Section 2 Oil and Gas Production Facilities Permitting Guidance (C6 S2 Guidance)

document serves as a supplement to the Wyoming Air Quality Standards and Regulations (WAQSR) 

Chapter 6 Section 2 New Source Review (NSR) permitting program. The C6 S2 Guidance applies solely to 

the permitting of oil and gas production facilities. 

Obtain a copy of the C6 S2 Guidance by contacting the Wyoming Air Quality Division at (307) 777-7391

or (307) 473-3475 or download a PDF version from http://deq.state.wy.us/aqd/

Applicability

If ANY air pollutant will be released to the atmosphere from a new or modified facility, the facility is 

subject to WAQSR and the Wyoming Environmental Quality Act.

Owners/operators of ALL regulated air emission sources constructed or modified after May 29, 1974 

shall comply with the WAQSR Chapter 6, Section 2 permitting requirements. 

Failure to comply with Wyoming air quality regulations may result in an enforcement action in the form 

of a “Notice of Violation” and penalties of up to $10,000.00 per day.

To obtain a copy of the WAQSR contact the Wyoming Air Quality Division at (307) 777-7391 or download 

the PDF version from http://deq.state.wy.us/aqd/

 

Air pollutants associated with O&G production facilities are:

Volatile Organic Compounds (VOC): Hydrocarbon compounds excluding methane (C1) and ethane (C2). 

VOCs are also referred to as C3

+

compounds – propane, butane, pentane, hexane, + etc.

Hazardous Air Pollutants (HAP): Section 112(b) of the Clean Air Act lists 188 HAPs. HAPs commonly 

associated with O&G production are BTEX and n-hexane (benzene, toluene, ethyl-benzene, xylenes and 

n-C6).

Nitrogen Oxides (NOX): NOX emissions are the result of natural gas combustion.

Carbon Monoxide (CO): CO emissions are the result of natural gas combustion.

Hydrogen Sulfide (H2S): Sour gas and Sulfur Dioxide (SO2) created when sour gas is combusted.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 2 of 71

Production Facility Emission Sources

O&G production facilities emission sources:

Storage Tanks: Vapors containing regulated air pollutants are released from solution as oil, condensate 

and water are transferred from separation equipment to atmospheric storage tanks. These vapors are 

called flashing losses. Vapors evaporated or displaced from tanks are called working and breathing 

(also called standing) losses.

Dehydration Units: Glycol, usually tri-ethylene glycol (TEG), is used in dehydration units to absorb water 

from wet produced gas. “Lean” TEG contacts the wet gas and absorbs water. The TEG, now considered 

“rich” is routed through a flash separator and/or reboiler for regeneration. Vapors released from the 

flash separator and reboiler still vent contain regulated air pollutants.

Pressurized Process Vessels: Vapors vented from gun barrels, separators, treaters, water knockouts, 

gas boots, flash separators, drip pots, etc. contain regulated air pollutants. The discharge lines and 

vents from all of these vessels shall be considered when determining emission sources.

Natural Gas-Fired Equipment: Some of the byproducts of natural gas combustion in process heaters, 

boilers, burners, flares, engines, etc. are regulated air pollutants.

Fugitives: All production facilities contain numerous equipment components such as valves, flanges, 

threaded connections, tubing connections, open-ended lines, pump seals, etc which are manufactured 

and installed in ways intended to contain gases or liquids. Over time some of them begin to leak. 

Unintentional emissions associated with leaks are called fugitive emissions. For purposes of this 

Guidance, emissions from components that are improperly designed (e.g. enardo valves over 

pressurizing, failure of thief hatches to reseat after over pressurizing) or equipment not maintained 

properly (e.g., thief hatch left open) are not considered to be fugitive emissions. 

Pneumatic Pumps & Controllers: The discharge vapors from natural gas-operated pneumatic 

equipment contain regulated air pollutants.

Truck Loading: Vapors displaced from truck tanks during the loading of oil or condensate contains

regulated air pollutants.

Venting & Blow down: Natural gas and liquids contain regulated air pollutants.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 3 of 71

BACT & Presumptive BACT

Under C6 S2, all new or modified sources or facilities which may generate regulated air emissions shall

be permitted prior to start up or modification and Best Available Control Technology (BACT) shall be 

applied to reduce or eliminate emissions, with consideration given for technical feasibility and 

economical reasonableness. BACT is a process, not an emission limit. Regulation does not set a 

minimum emission threshold below which BACT does not need to be considered. 

At O&G facilities production rates and associated pollutant emissions are usually unknown prior to start 

up. The AQD has tailored a permitting program allowing for the start up or modification of O&G 

facilities prior to permitting provided specific emission control requirements are met.

This is the Presumptive BACT permitting process for O&G production facilities.

Presumptive BACT requirements have been established for emissions associated with:

Flashing & working/breathing losses from atmospheric storage tanks and pressurized vessels

Dehydration unit process vents

Natural gas-operated pneumatic equipment

Natural gas-fired pumping unit engines 

If emissions are known prior to construction or modification, a permit shall be obtained PRIOR TO 

CONSTRUCTION or MODIFICATION and Presumptive BACT shall be addressed in the application. 

Examples include:

Construction of a central tank battery for collecting and processing production from surrounding

existing wells with known production rates;

Consolidation of multiple existing facilities for which production rates have been established;

Installation of a dehydration unit for an existing well with an established gas production rate;

Installation of larger capacity equipment to replace undersized equipment;

Replacement of an emission control system or device with a different system or device.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 4 of 71

Presumptive BACT

Presumptive BACT requirements have been established for three areas. 

CDA Concentrated Development Areas.

JPAD Jonah and Pinedale Anticline Development Area.

STATEWIDE 

The CDA is defined by seven counties: Sublette, Lincoln, Uinta, Carbon, Sweetwater, Fremont and 

Natrona.

The JPAD area is defined as:

R109W & R110W in T34N

R109W & R110W in T33N

R108W, R109W & R110W in T32N

R108W, R109W & R110W in T31N

R107W, R108W & R109W in T30N

R107W, R108W & R109W in T29N

R108W & R109W in T28N

R107W, R108W & R109W in T27N

STATEWIDE refers to all other areas.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 5 of 71

Presumptive BACT Requirements for STATEWIDE Facilities

Flashing

For the purpose of determining flashing emissions all vapor streams containing VOC or HAP components 

from all storage tanks (e.g., oil, condensate, produced water with oil or condensate carryover) and all 

separation vessels (e.g., gun barrels, production and test separators, production and test treaters, water 

knockouts, gas boots, flash separators, drip pots, etc.) at a facility which are or may be vented to the 

atmosphere shall be considered.

New Facilities

Within 60-days of the First Date of Production (FDOP), flashing emissions containing greater 

than or equal to 10 TPY VOC shall be controlled by at least 98%.

Modified Facilities

Within 60-days of modification, new and existing flashing emissions containing greater than or 

equal to 10 TPY VOC shall be controlled by at least 98%.

New and Modified Facilities

Condensate and oil tanks that are on site for use during emergency or upset conditions, such as 

spare tanks at facilities connected to liquids gathering systems, are not subject to the 98% 

control requirements.

The removal of flashing emissions control devices may be allowed upon approval after one year 

if VOC flashing emissions have declined to less than, and are reasonably expected to remain 

below 8 TPY.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 6 of 71

Presumptive BACT Requirements for STATEWIDE Facilities cont’d

Dehydration Units

To meet the P-BACT requirements for dehydration units operators must follow 

either Scenario 1 or Scenario 2.

 

For the purpose of determining emissions from dehydration units, vapor streams containing VOC or HAP 

components released from the process vents (reboiler still vents & glycol flash separator vents) of all 

dehydration units at a facility which are or may be vented to the atmosphere shall be considered. 

Scenario 1

New Facilities

PAD Facilities

Upon FDOP, all dehydration unit VOC and HAP emissions shall be controlled by at least 98%. 

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 6 TPY and

All units are equipped with still vent condensers.

Single Well Facilities

Upon FDOP, all dehydration units shall be equipped with reboiler still vent condensers. The 

condensers may not later be removed.

Within 60-days of FDOP, if total potential uncontrolled

1

VOC emissions from all units are greater 

than or equal to 6 TPY, emissions from all units shall be controlled by at least 98%.

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 6 TPY and

All units are equipped with still vent condensers.

Modified Facilities

Requirements are the same as those for PADs and single well facilities except use the date of 

modification in place of FDOP. Control requirements apply to existing and new dehydration 

units.

 

1

See definitions on Page 8
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 7 of 71

Presumptive BACT Requirements for STATEWIDE Facilities cont’d

Dehydration Units Scenario 2

New PAD and Single Well Facilities

Upon FDOP, all dehydration units shall be equipped with glycol flash separators and reboiler still 

vent condensers. Removal of the flash separators and condensers will not be allowed.

Within 30-days of FDOP, if total potential uncontrolled1VOC emissions from all dehydration 

units are greater than or equal to 8 TPY, at least 98% control of emissions shall be installed and 

operational on all units.

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 8 TPY and

All units are equipped with flash separators and still vent condensers.

Modified Facilities

Upon modification, glycol flash separators and reboiler still vent condensers shall be installed 

and operating on all new and existing dehydration units. Removal of the flash separators and 

condensers will not be allowed.

Within 30-days of modification, if total potential uncontrolled1VOC emissions are greater than 

or equal to 8 TPY, at least 98% control of emissions shall be installed and operational on all new

and existing dehydration units.

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 8 TPY and

All units are equipped with flash separators and still vent condensers.

All Facilities

When a combustion unit is required at a facility for control of flash or dehydration unit 

emissions, all non-condensable still vent vapors shall be collected and routed to the combustion 

unit for at least 98% control of VOC and HAP emissions and all glycol flash separator vapors shall 

be collected and routed to the combustion unit for at least 98% control of VOC and HAP 

emissions and/or used as fuel for process equipment burners.

At facilities where a combustion unit is not required for control of flash or dehydration unit 

emissions, all glycol flash separator vapors shall be collected for use as fuel in process 

equipment burners. Excess flash vapors that are not used as fuel may be vented to the

atmosphere.

 

1

See definitions on Page 8 
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 8 of 71

Presumptive BACT Requirements for STATEWIDE Facilities cont’d

 

Dehydration Units

Potential Uncontrolled VOC emissions shall be determined using GRI-GLYCalc V3.0 or higher or other 

method accepted by the Division and shall be based on the projected, year one, average daily dry gas 

throughput rate, maximum circulation rate for the glycol circulation pump(s) installed, average expected 

operating parameters for wet gas temperature and pressure, maximum dry gas water content or 

number of absorber stages and extended hydrocarbon content of the wet gas from a sample of the wet 

gas taken upstream of the dehydration unit contact tower. Flash separators and still vent condensers, 

limited operating hours and limited glycol circulation rates shall not be considered when determining 

potential uncontrolled emissions.

Still vent condensers shall consist of equipment engineered and designed to achieve maximum 

condensation of the condensable components in the still vent vapors by providing adequate 

temperature differentials between the condenser outlet and still vent stream. Still vent pipes shall not 

be considered condensers.

Potential emissions for determining combustion device removal after one year shall be calculated using 

GRI-GLYCalc V3.0 or higher or other method accepted by the Division based on the most recent 30-days 

of normal gas production rates, actual average wet gas temperature and pressure, actual water content 

of the dried gas or number of absorber stages, “worst case” operating parameters of the glycol flash 

separator and still vent condenser. 

“Worst case” flash separator and condenser parameters are: 

1) maximum glycol flash separator operating pressure

2) lowest glycol flash separator operating temperature

3) maximum still vent condenser outlet temperature

4) maximum still vent condenser outlet pressure

5) all vapors from flash separator are vented 

Actual operating parameters for glycol flash separators and still vent condensers may be used upon 

approval. Limited operating hours and limited glycol circulation rates shall not be considered when 

determining potential emissions.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 9 of 71

Presumptive BACT Requirements for STATEWIDE Facilities cont’d

 

Pneumatic Pumps

New Facilities

PAD Facilities

Upon FDOP, VOC and HAP emissions associated with the discharge streams of all natural 

gas-operated pneumatic pumps shall be controlled by at least 98% or the pump 

discharge streams shall be routed into a closed loop system (e.g., sales line, collection 

line, fuel supply line). 

Single Well Facilities

Within 60-days of FDOP,

At sites with combustion units installed for the control of flash or dehydration 

unit emissions:

VOC and HAP emissions associated with the discharge streams from 

natural gas-operated pneumatic pumps shall be controlled by at least 

98% by routing the pump discharge streams into the combustion unit or 

the discharge streams shall be routed into a closed loop system.

At sites without combustion units installed for the control of flash or 

dehydration unit emissions:

Pneumatic pumps (other than those for heat trace/heat medium/hot 

glycol circulation) shall be solar, electric or air-driven pumps in lieu of 

natural gas-operated pneumatic pumps. Wherever possible, heat 

trace/heat medium/hot glycol circulation pumps shall be solaroperated, electric or air-driven. 

Modified Facilities

Requirements are the same as above except include all new and existing pneumatic pumps and 

use the date of modification in place of FDOP.

New and Modified Facilities

At sites where pneumatic pump emissions are controlled by a combustion unit used for the 

control of flash or dehydration unit emissions, control of the pneumatic pump emissions will be 

evaluated upon request for removal of the combustion unit. (see Flashing, Page 5)
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 10 of 71

Presumptive BACT Requirements for STATEWIDE Facilities cont’d

Pneumatic Controllers

New Facilities 

Upon FDOP, natural gas-operated pneumatic controllers shall be low* or no-bleed controllers or 

the controller discharge streams shall be routed into a closed loop system.

Modified Facilities

Upon modification, new natural gas-operated pneumatic controllers shall be low or no-bleed 

controllers or the controller discharge streams shall be routed into a closed loop system. 

Within 60-days of modification, existing natural gas-operated pneumatic controllers shall be 

replaced by or converted to low or no-bleed controllers or the discharge streams of the existing 

natural gas-operated controllers shall be routed into a closed loop system.

 

Blow down/Venting

Best Management Practices (BMP) and information gathering requirements will be incorporated into 

permits for new and modified facilities.

BMP: During manual and automated blow down/venting episodes associated with liquids 

unloading, wellbore depressurization in preparation for maintenance or repair, hydrate clearing, 

emergency operations, equipment depressurization, etc., associated VOC and HAP emissions 

shall be minimized to the extent practicable. During manual blow down/venting, personnel shall 

remain on site to ensure minimal gas venting occurs.

Information Gathering: Specific recordkeeping and reporting requirements will be established 

during the permitting process and will include estimates of associated regulated air pollutants, 

reasons for episodes, durations of episodes, steps taken to minimize emissions and descriptions 

of emission estimation methods. 

Emission sources without Presumptive BACT requirements

For uncontrolled sources emitting greater than or equal to 8 TPY VOC or greater than or equal to 5 TPY 

total HAPs that do not have P-BACT requirements, a BACT analysis shall be filed with the permit 

application for the associated facility. 

*low bleed devices vent less than 6 cfh
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 11 of 71

Presumptive BACT Requirements for CDA Facilities

Flashing

For the purpose of determining flashing emissions all vapor streams containing VOC or HAP components 

from all storage tanks (e.g., oil, condensate, produced water with oil or condensate carryover) and all 

separation vessels (e.g., gun barrels, production and test separators, production and test treaters, water 

knockouts, gas boots, flash separators, drip pots, etc.) at a facility which are or may be vented to the 

atmosphere shall be considered.

New Facilities

PAD Facilities

Upon FDOP, VOC and HAP flashing emissions shall be controlled by at least 98%.

Single Well Facilities

Within 60-days of FDOP, flashing emissions containing greater than or equal to 8 TPY 

VOC shall be controlled by at least 98%.

Modified Facilities

PAD Facilities

Upon modification, all new and existing VOC and HAP flash emissions shall be controlled 

by at least 98%.

Single Well Facilities

Within 60-days of modification, all new and existing flashing emissions containing 

greater than or equal to 8 TPY VOC shall be controlled by at least 98%.

New and Modified Facilities

Condensate and oil tanks that are on site for use during emergency or upset conditions, such as 

spare tanks at facilities connected to liquids gathering systems, are not subject to the 98% 

control requirements.

The removal of flashing emissions control devices may be allowed upon approval after one year 

if VOC flashing emissions have declined to less than, and are reasonably expected to remain 

below 8 TPY.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 12 of 71

Presumptive BACT Requirements for CDA Facilities cont’d

Dehydration Units

To meet the P-BACT requirements for dehydration units operators must follow 

either Scenario 1 or Scenario 2.

 

For the purpose of determining emissions from dehydration units, vapor streams containing VOC or HAP 

components released from the process vents (reboiler still vents & glycol flash separator vents) of all 

dehydration units at a facility which are or may be vented to the atmosphere shall be considered.

Scenario 1

New Facilities

PAD Facilities

Upon FDOP, all dehydration unit VOC and HAP emissions shall be controlled by at least 98%. 

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 6 TPY and

All units are equipped with still vent condensers.

Single Well Facilities

Upon FDOP, all dehydration units shall be equipped with reboiler still vent condensers. Removal 

of the condensers will not be allowed.

Within 60-days of FDOP, if total potential uncontrolled1VOC emissions from all units are greater 

than or equal to 6 TPY, emissions from all units shall be controlled by at least 98%.

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 6 TPY and

All units are equipped with still vent condensers.

Modified Facilities

Requirements are the same as those for PADs and single well facilities except use the date of 

modification in place of FDOP. Control requirements apply to existing and new dehydration 

units.

 

1

See definitions on Page 8
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 13 of 71

Presumptive BACT Requirements for CDA Facilities cont’d

Dehydration Units Scenario 2

New PAD and Single Well Facilities

Upon FDOP, all dehydration units shall be equipped with glycol flash separators and reboiler still 

vent condensers. Removal of the flash separators and condensers will not be allowed.

Within 30-days of FDOP, if total potential uncontrolled1VOC emissions from all dehydration 

units are greater than or equal to 8 TPY, at least 98% control of emissions shall be installed and 

operational on all units.

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 8 TPY and

All units are equipped with flash separators and still vent condensers.

Modified Facilities

Upon modification, glycol flash separators and reboiler still vent condensers shall be installed 

and operating on all new and existing dehydration units. Removal of the flash separators and 

still vent condensers will not be allowed.

Within 30-days of modification, if total potential uncontrolled1VOC emissions are greater than 

or equal to 8 TPY, at least 98% control of emissions shall be installed and operational on all new 

and existing dehydration units.

After one year, combustion units used to achieve the 98% control may be removed upon 

approval if

Total potential1VOC emissions from all units are less than 8 TPY and

All units are equipped with flash separators and still vent condensers.

All Facilities

When a combustion unit is required at a facility for control of flash or dehydration unit 

emissions, all non-condensable still vent vapors shall be collected and routed to the combustion 

unit for at least 98% control of VOC and HAP emissions and all glycol flash separator vapors shall 

be collected and routed to the combustion unit for at least 98% control of VOC and HAP 

emissions and/or used as fuel for process equipment burners.

At facilities where a combustion unit is not required for control of flash or dehydration unit 

emissions, all glycol flash separator vapors shall be collected for use as fuel in process 

equipment burners. Excess flash vapors that are not used as fuel may be vented to the 

atmosphere.

 

1

See definitions on Page 8
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 14 of 71

Presumptive BACT Requirements for CDA Facilities cont’d

 

Pneumatic Pumps

New Facilities

PAD Facilities

Upon FDOP, VOC and HAP emissions associated with the discharge streams of all natural 

gas-operated pneumatic pumps shall be controlled by at least 98% or the pump 

discharge streams shall be routed into a closed loop system (e.g., sales line, collection 

line, fuel supply line). 

Single Well Facilities

Within 60-days of FDOP,

At sites with combustion units installed for the control of flash or dehydration 

unit emissions:

VOC and HAP emissions associated with the discharge streams from 

natural gas-operated pneumatic pumps shall be controlled by at least 

98% by routing the pump discharge streams into the combustion unit or 

the discharge streams shall be routed into a closed loop system.

At sites without combustion units installed for the control of flash or 

dehydration unit emissions:

Pneumatic pumps (other than heat trace/heat medium/hot glycol 

circulation) shall be solar, electric or air-driven pumps in lieu of natural 

gas-operated pneumatic pumps. Wherever possible, heat trace/heat 

medium/hot glycol circulation pumps shall be solar-operated, electric or 

air-driven. 

Modified Facilities

Requirements are the same as above except include all new and existing pneumatic pumps and 

use the date of modification in place of FDOP.

New and Modified Facilities

At sites where pneumatic pump emissions are controlled by a combustion unit used for the 

control of flash or dehydration unit emissions, control of the pneumatic pump emissions will be 

evaluated upon request for removal of the combustion unit. (see Flashing, Page 11)
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 15 of 71

Presumptive BACT Requirements for CDA Facilities cont’d

Pneumatic Controllers

New Facilities

Upon FDOP, natural gas-operated pneumatic controllers shall be low* or no-bleed controllers or 

the controller discharge streams shall be routed into a closed loop system.

Modified Facilities

Upon modification, new natural gas-operated pneumatic controllers shall be low or no-bleed 

controllers or the controller discharge streams shall be routed into a closed loop system. 

Within 60-days of modification, existing natural gas-operated pneumatic controllers shall be 

replaced by or converted to low or no-bleed controllers or the discharge streams of existing 

natural gas-operated pneumatic controllers shall be routed into closed loop system.

Well Completions

Operators shall submit applications to perform well completions using Best Management Practices. One 

permit will be issued to each company that drills and completes wells within the Concentrated 

Development Areas. The permits will be modeled after those issued to companies completing wells in 

the Jonah and Pinedale Anticline Development Area. An example of a well completions or “Green 

Completions” permit is available on the AQD website, http://deq.state.wy.us/aqd or a copy may be 

obtained by contacting the Wyoming Air Quality Division at (307) 777-7391 or (307) 473-3475.

Green Completion permit applications shall be filed with the Division by November 1, 2010.

*low bleed devices vent less than 6 cfh
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 16 of 71

Presumptive BACT Requirements for CDA Facilities cont’d

Produced Water Tanks

New Facilities

PAD Facilities

Upon FDOP, VOC and HAP emissions from all active produced water tanks shall be 

controlled by at least 98%.

Single Well Facilities

Within 60-days of FDOP, at sites where flashing emissions must be controlled by at least 

98%, VOC and HAP emissions from all active produced water tanks shall be controlled by 

at least 98%.

Modified Facilities

PAD Facilities

Upon modification, VOC and HAP emissions from all new active produced water tanks 

shall be controlled by at least 98%.

Within 60-days of modification, existing open-top, active, produced water tanks shall be 

taken out of service for use as active produced water tanks. All active produced water 

tanks shall be closed top and shall have VOC and HAP emissions controlled by at least 

98%.

New and Modified Facilities

Open-top or blow down tanks shall not be used as active produced water tanks but may 

be used for blow down or for temporary storage during emergency or upset conditions, 

such as spare tanks at facilities connected to liquids gathering systems, and do not have 

to be tied into 98% control systems. 

Removal of produced water tank emissions control may be allowed upon approval. (see 

Flashing, Page 11)
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 17 of 71

Presumptive BACT Requirements for CDA Facilities cont’d

 

Blow down/Venting

Best Management Practices (BMP) and information gathering requirements will be incorporated into 

permits for new and modified facilities. 

BMP: During manual and automated blow down/venting episodes associated with liquids 

unloading, wellbore depressurization in preparation for maintenance or repair, hydrate clearing, 

emergency operations, equipment depressurization, etc., associated VOC and HAP emissions 

shall be minimized to the extent practicable. During manual blow down or venting, personnel 

shall remain on site to ensure minimal gas venting occurs.

Information Gathering: Specific recordkeeping and reporting requirements will be established 

during the permitting process and will include estimates of associated regulated air pollutants, 

reasons for episodes, durations of episodes, steps taken to minimize emissions and descriptions 

of emission estimation methods.

For companies with existing facilities as of the date of this Guidance, blow down and venting 

permit applications shall be filed by November 1, 2010. 

Emission sources without Presumptive BACT requirements

For uncontrolled sources emitting greater than or equal to 8 TPY VOC or greater than or equal to 5 TPY 

total HAPs that do not have P-BACT requirements, a BACT analysis shall be filed with the permit 

application for the associated facility. 
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 18 of 71

Presumptive BACT Requirements for JPAD Facilities 

Flashing

For the purpose of determining flashing emissions all vapor streams containing VOC or HAP components 

from all storage tanks (e.g., oil, condensate, produced water with oil or condensate carryover) and all 

separation vessels (e.g., gun barrels, production and test separators, production and test treaters, water 

knockouts, gas boots, flash separators, drip pots, etc.) at a facility which are or may be vented to the 

atmosphere shall be considered.

New Facilities

Upon FDOP, VOC and HAP flashing emissions shall be controlled by at least 98%.

Modified Facilities

Upon modification, all new and existing VOC and HAP flashing emissions shall be controlled by 

at least 98%.

New and Modified Facilities

Condensate and oil tanks that are on site for use during emergency or upset conditions, such as 

spare tanks at facilities connected to liquids gathering systems, are not subject to the 98% 

control requirements.

The removal of flashing emissions control devices may be allowed upon approval after one year 

if VOC flashing emissions have declined to less than, and are reasonably expected to remain 

below 8 TPY.

Dehydration Units

New Facilities

Upon FDOP, all VOC and HAP emissions from dehydration unit process vents shall be controlled 

by at least 98%. No control removal will be allowed.

Modified Facilities

Upon modification, all VOC and HAP emissions from new and existing dehydration unit process 

vents shall be controlled by at least 98%. No control removal will be allowed.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 19 of 71

Presumptive BACT Requirements for JPAD Facilities cont’d

Pneumatic Heat Trace Pumps & Other Pneumatic Pumps

New Facilities

Upon FDOP, VOC and HAP emissions associated with the discharge streams of all natural gasoperated pneumatic pumps shall be controlled by at least 98% or the pump discharge streams 

shall be routed into a closed loop system (e.g., sales line, collection line, fuel supply line).

Modified Facilities

Upon modification, VOC and HAP emissions associated with the discharge streams of all new 

and existing natural gas-operated pneumatic pumps shall be controlled by at least 98% or the 

pump discharge streams shall be routed into a closed loop system. 

New and Modified Facilities

For pneumatic pump emissions controlled by a combustion unit used to control flash or 

dehydration unit emissions which may be removed, the control method for pump emissions will 

be evaluated upon request for approval to remove the combustion unit. (see Flashing, Page 18)

Pneumatic Controllers

New Facilities

Upon FDOP, natural gas-operated pneumatic controllers shall be low* or no-bleed controllers or 

the controller discharge streams shall be routed into a closed loop system.

Modified Facilities

Upon modification, new natural gas-operated pneumatic controllers shall be low or no-bleed 

controllers or the controller discharge streams shall be routed into a closed loop system. 

Within 60-days of modification, existing natural gas-operated pneumatic controllers shall be 

replaced by or converted to low or no-bleed controllers or the controller discharge streams shall

be routed into a closed loop system. 

*low bleed devices vent less than 6 cfh
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 20 of 71

Presumptive BACT Requirements for JPAD Facilities cont’d

Produced Water Tanks

New Facilities

Upon FDOP, VOC and HAP emissions from all active produced water tanks shall be controlled by 

at least 98%. 

Modified Facilities

Upon modification, VOC and HAP emissions from all new active produced water tanks shall be 

controlled by at least 98%. 

Within 60-days of modification, existing open-top, active, produced water tanks shall be taken 

out of service for use as active produced water tanks. All active produced water tanks shall be 

closed top and shall have VOC and HAP emissions controlled by at least 98%.

New and Modified Facilities

Open-top or blow down tanks shall not be used as active produced water tanks but may be used 

for blow down or for temporary storage during emergency or upset conditions, such as spare 

tanks at facilities connected to liquids gathering systems, and do not have to be tied into 98% 

control systems.

Removal of water tank emissions control may be allowed upon approval. (see Flashing, Page 18)

Well Completions

Operators shall submit applications to perform well completions using Best Management Practices. One 

permit will be issued to each company that drills and completes wells within the JPAD area. The permits 

will be modeled after those issued to companies completing wells in the Jonah and Pinedale Anticline 

Development Area. An example of a well completions or “Green Completions” permit is available on the 

AQD website, http://deq.state.wy.us/aqd or a copy may be obtained by contacting the Wyoming Air 

Quality Division at (307) 777-7391 or (307) 473-3475.

Green Completion permit applications shall be filed with the Division by November 1, 2010.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 21 of 71

Presumptive BACT Requirements for JPAD Facilities cont’d

Blow down/Venting

Best Management Practices (BMP) and information gathering requirements will be incorporated into 

permits for new and modified facilities. 

BMP: During manual and automated blow down/venting episodes associated with liquids 

unloading, wellbore depressurization in preparation for maintenance or repair, hydrate clearing, 

emergency operations, equipment depressurization, etc., associated VOC and HAP emissions 

shall be minimized to the extent practicable. During manual blow down or venting, personnel 

shall remain on site to ensure minimal gas venting occurs.

Information Gathering: Specific recordkeeping and reporting requirements will be established 

during the permitting process and will include estimates of associated regulated air pollutants, 

reasons for episodes, durations of episodes, steps taken to minimize emissions and descriptions 

of emission estimation methods.

For companies with existing facilities as of the date of this Guidance, blow down and venting 

permit applications shall be filed by November 1, 2010. 

Emission sources without Presumptive BACT requirements

For uncontrolled sources emitting greater than or equal to 8 TPY VOC or greater than or equal to 5 TPY 

total HAPs that do not have P-BACT requirements, a BACT analysis shall be filed with the permit 

application for the associated facility. 
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 22 of 71

Determining Presumptive BACT Flashing Emissions

Flashing losses occur when produced liquids (crude oil or condensate) are exposed to temperature 

increases or pressure drops as they are transferred from production vessels to other vessels or to 

atmospheric storage tanks. For purposes of this guidance, the term “flash emissions” refers to VOC and 

HAP pollutants associated with entrained natural gas vapors released to the atmosphere from 

hydrocarbon liquids in surface production equipment. This production equipment may include gun 

barrels, separators, treaters, produced water tanks, gas drips, freewater knockouts, etc. In addition to 

flash emissions, vessels containing hydrocarbon liquids also have emissions associated with working and 

breathing (also called standing) losses. These are vapors displaced from oil or condensate due to 

evaporation and agitating.

Use the following steps to determine projected potential flashing and working/breathing losses:

STEP 1: 30-days after the First Date of Production calculate the average daily condensate or oil 

production.

Example: Well produced 600 BBL during the first 30-days after the First Date of Production.

average daily condensate/oil production = 600 BBL ÷ 30 days = 20 BPD

STEP 2: Calculate the projected first year annualized average daily condensate/oil production rate by 

multiplying the average 30-day rate times 0.6. This effectively results in a first year, 

annualized daily production rate which is 20% of the initial production rate. Additionally, this 

effectively accounts for an 80% decline in daily production by the end of the first year. 

(described in more detail on page 40)

Example:

projected first year, annualized average daily oil/condensate production = 20 × 0.6 = 12 BPD

If the expected decline rate is less than 80%, then the expected decline rate should be used. 

Using an expected decline rate > 80% requires pre-approval from the Division. 

STEP 3: Use an approved flash emissions model or direct measurement of tank emissions to 

determine projected first year VOC and HAP emissions associated with the projected first 

year average daily production rate.

Actual flash emissions are determined the same as projected potential emissions except that the actual 

average daily condensate or oil production rate is used rather than a projected production rate.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 23 of 71

Determining Presumptive BACT Flashing Emissions cont’d

Several methods are available to calculate or measure flash emissions with some being more accurate 

than others. Even through working/breathing/flashing losses are almost always mixed together and exit 

from a common vent at the same time, some methods only calculate working and breathing losses and 

some only calculate flashing losses. Some methods will calculate all three types of emissions 

simultaneously. Each method has specific constraints. For whichever method used, all supporting data 

used to calculate the emissions, including identification of the calculation method, description of 

sampling methods and copies of lab sampling analyses shall be provided with the emissions estimate.

Method Emissions 

Calculated

Comments

1 Direct measurement working, breathing, 

flash

Sampling and lab analysis required. Results are relatively 

accurate.

2 Process Simulator flash only i.e. PROMAX, HYSIM, HYSIS

Software is expensive but results are accurate when based 

on site-specific sampling and lab analysis.

3 API E&P TANKS Software 

V 2.0

working, breathing, 

flash

Requires site specific sampling. Not as accurate as more 

expensive process simulators and no longer supported by 

the software producer (American Petroleum Institute). 

4 Laboratory 

measurement of the 

Gas-Oil-Ratio (GOR) from 

a pressurized liquid 

sample

flash only This is a direct laboratory analysis of the flash vapors 

emitted from a pressurized oil/condensate sample.

5 EPA TANKS 4.0.9d working, breathing 

only

Program distributed by the EPA through their website at 

http://www.epa.gov/ttn/chief/efpac/efsoftware.html

Extended hydrocarbon liquids analyses used for model input shall be no older than three years. 

Composite analyses may be used as input. These are averaged extended hydrocarbon compositions 

based on samples from at least five nearby wells producing from the same formation and under similar 

conditions (± 25° psig) as the well being permitted. Analyses used as the basis for the average shall be 

no older than three years.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 24 of 71

Determining Presumptive BACT Dehydration Unit Emissions

Dehydration units use glycol (TEG, DEG or EG) to absorb water from produced gas before it is introduced 

into gas sales or collection lines. Upon contact with wet gas, “lean” glycol absorbs water and other 

liquids. It is then considered “rich”. To remove impurities, or regenerate, the rich glycol is routed 

through a glycol flash separator and/or a reboiler. During flash separation and reboiling, water and 

hydrocarbon vapors containing VOC and HAP pollutants are released from the rich glycol. These are 

then discharged to the atmosphere from the dehydration unit process vents. 

Use the following steps to determine projected potential dehydration unit emissions:

STEP 1: Once a new well has produced for 30-days after the First Date of Production, determine the 

average daily gas production rate.

Example:

Well produced 100 MMCF during the first 30-days after the First Date of Production

average daily gas production = 100 MMCF ÷ 30 days = 3.3 MMCFD

STEP 2: Calculate the projected first year, annualized average daily gas production rate by 

multiplying the initial average 30-day rate times 0.6. This effectively results in a first year, 

annualized daily production rate which is 20% of the initial production rate. Additionally, this 

effectively calculates an 80% decline in daily production by the end of the first year. 

(described in more detail on page 40.) 

Example:

projected first year, annualized average daily gas production = 3.3 × 0.6 = 2.0 MMCFD

STEP 3: Use GRI-GLYCalc V3.0 or higher or other method approved by the Division with the projected 

first year, annualized average daily production rate to determine potential, annualized

uncontrolled VOC and HAP emissions from the dehydration unit process vents. Process 

vents include reboiler still vents, glycol flash separators and still vent condensers.

Model input:

1) An extended hydrocarbon analysis of wet gas sampled upstream of the reboiler contact tower. 

Analyses used for model input shall be no older than three years. Composite analyses may be used 

as input. These are averaged extended hydrocarbon compositions based on samples of wet gas 

from at least five nearby wells producing from the same formation and under similar conditions (± 

25° psig) as the well being permitted. Analyses used as the basis for the average shall be no older 

than three years.

2) The projected first year average daily gas production rate (MMCFD).

3) Average, actual equipment operational parameters, including wet gas temperature and pressure, 

dry gas water content, glycol flash separator temperature and pressure, stripping gas source and 

rate and average operating parameters of emission control equipment. 

4) The maximum lean glycol circulation rate (gpm) for the glycol circulation pump in use. Maximum 

circulation rates for the most commonly used Kimray Model pumps are listed in TABLE 1. 
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 25 of 71

Determining Presumptive BACT Dehydration Unit Emissions cont’d

TABLE 1

KIMRAY GLYCOL PUMP RATES

Model #

Capacity (gpm) Working Pressure 

(psi)

min max min max

3154 PV 0.05 0.22 100 1500

1715 PV 0.13 0.67 300 1500

4015 PV 0.2 0.67 300 1500

9015 PV 0.45 1.5 300 1500

21015 PV 1.1 3.5 400 1500

45015 PV 2.77 7.5 400 1500

4015 LP 0.13 0.33 100 500

2015 SC 0.13 0.33 100 500

5015 SC 0.2 0.83 100 500

10015 SC 0.37 1.67 100 500

20015 SC 1 3.33 100 500

Data from Kimray O&G Equipment and Controls Catalog

Actual dehydration unit emissions are determined the same as projected potential emissions except 

that the actual average daily gas production rate is used in the GlyCalc model rather than a projected 

production rate.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 26 of 71

BACT for Flashing Emissions

The following control systems or devices are accepted by the Division as meeting BACT for flash

emissions:

1) A vapor recovery device that is designed and operated and may be demonstrated to reduce the 

mass content of VOC and total HAP emissions in the vapors vented to the device by at least 98% by 

weight.

2) An enclosed, smokeless combustion device or flare that is designed and operated and may be 

demonstrated to reduce the mass content of VOC and total HAP emissions in the vapors vented to 

the device by at least 98% by weight.

3) Any other control device or configuration that can be demonstrated to reduce the mass content of 

total HAP and VOC in the process gases vented to the device or configuration by at least 98% by 

weight.

4) Monitoring and recordkeeping which will demonstrate continuous and effective emission control 

are required upon start up of the control system. For a combustion device this may be a 

thermocouple and continuous recording device or any other equivalent device to detect and record 

the presence of the pilot flame, or a combustion chamber temperature recorder/monitor. The 

monitoring/recording requirements become enforceable permit conditions.

5) Emissions control equipment, systems or devices, all vent lines, connections, fitting, valves, relief 

valves, thief hatches or any other appurtenance employed to contain and collect vapors and 

transport them to the emission control system or device, shall be maintained and operated during 

any time a well is producing such that the emissions are controlled at all times.

CAUTION: Total emissions from any facility or source shall not exceed major source levels prior to 

emission control installation. Major source levels are 10 TPY of any single HAP, 25 TPY of any 

combination of HAP or 100 TPY of any regulated pollutant. Flash emissions prior to control installation 

will be determined using approved emission models or methods based on actual reported production 

and operating conditions. Reported production includes that sold during well completion activities 

which are reported to the WOGCC. Flash emissions are directly proportional to production rates, 

provided operational parameters remain consistent, so it is acceptable to prorate emissions based on 

production.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 27 of 71

BACT for Dehydration Unit Emissions

Other emission control systems or devices than those previously discussed may be used upon approval 

by the Division to meet BACT requirements for emissions from dehydration unit process vents (reboiler 

still vents and vents from glycol flash separators or glycol flash tanks). In order to be approved, the 

operator must provide a demonstration certifying the system or device will reduce the mass content of 

total HAP and VOC in the process gases vented to the device or configuration by at least 98% by weight.

Emissions control equipment, systems or devices, all vent lines, connections, fitting, valves, relief valves, 

hatches or any other appurtenance employed to contain and collect vapors and transport them to the 

emission control system or device, shall be maintained and operated during any time a well is producing 

such that the emissions are controlled at all times. 

Monitoring and recordkeeping which will demonstrate continuous and effective emission control are 

required upon start up of the control system. For combustion devices this may be a thermocouple and 

continuous recording device for the pilot flame or any other equivalent device to detect and record the 

presence of the pilot flame. A temperature recorder/monitor might be used to demonstrate sufficient 

heat of combustion or a continuous, wind-up chart recorder might be used to demonstrate continual 

operation by measuring and recording temperature or pressure parameters.

REMINDER: Dehydration units at oil and gas production facilities may be subject to additional NESHAP 

requirements under 40 CFR part 63, subpart HH. It is the operator’s responsibility to comply with all 

applicable requirements of the NESHAP regulations.

CAUTION: Total emissions from any facility or source shall not exceed major source levels prior to 

emission control installation. Major source levels are 10 TPY of any single HAP, 25 TPY of any 

combination of HAP or 100 TPY of any regulated pollutant. Dehydration unit emissions occurring prior 

to the installation of required controls will be determined using the GRI-GLYCalc model or other method 

approved by the Division based on the maximum lean glycol circulation rate and the actual reported gas 

production rate including any gas which was routed through the dehydration unit during well 

completion operations.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 28 of 71

BACT for Sources without P-BACT Requirements

For emission sources without PRESUMPTIVE BACT requirements, BACT shall be addressed when the 

uncontrolled source emits greater than or equal to 8 TPY VOC or greater than or equal to 5 TPY total 

HAP emissions.

For these sources EITHER the emission source will be controlled using BACT OR a BACT cost analysis will 

be performed and submitted with the application showing either: 

control is not technically feasible (i.e., due to physical constraints the emissions cannot be

controlled) 

OR 

control is not economically reasonable (i.e., based on a control cost analysis the “cost to control 

per ton of pollutant reduced” is uneconomical).

CAUTION: BACT may be required at lower levels and for other emissions and emission sources 

than those stated in this guidance, but as a minimum, BACT shall be considered when 

equal to or above these guidance emission levels. For example, operators installing 

pumping unit engines according the APP=NOI process might be asked to submit a BACT 

analysis for the engine.

Multiple pieces of the same type of equipment are considered one emission source for permitting 

purposes. For example, there are five oily rag burners at a facility. Uncontrolled emissions from the five 

burners shall be aggregated for permitting purposes. If total uncontrolled VOC emissions from the five 

burners are less than 8 TPY, BACT requirements are met with no control. If total uncontrolled emissions 

from the five burners are greater than or equal to 8 TPY VOC or greater than or equal to 5 TPY total HAP, 

emissions from all five burners shall be reduced to less than 8 TPY total VOC and less than 5 TPY total 

HAP in order to meet BACT requirements or the applicant shall demonstrate controlling the emissions is 

not economically reasonable nor technically feasible.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 29 of 71

Permit Applications

For JPAD facilities, the application submittal process is different from the process for CDA and Statewide 

facilities. See Page 38 for JPAD application instructions.

For CDA and Statewide facilities, unless a permit is issued prior to start up, a C6 S2 Oil & Gas Production 

Facilities permit application shall be filed within 90-days after the First Date of Production for a new 

facility or Date of Modification of an existing facility. The application notifies the AQD that the new or 

modified facility has begun operation. It describes the facility process, equipment and associated 

emissions/emissions controls and serves as a form of certification by the owner that the Presumptive 

BACT requirements have been met.

Whether the application is being filed after construction under the Presumptive BACT process or prior to 

construction, the appropriate application forms depend upon the facility equipment and operating 

scenario. A complete application includes the following appropriate forms: 

A cover letter stating the purpose of the application

A written process description and process diagram for the facility including each air emission 

source and the operational parameters of each source (examples on pages 31 & 32)

The appropriate application forms

AQD-OG0 Identification of application type (application or NOI = application)

AQD-OG00 Completeness checklist

AQD-OG1 Application Cover Sheet 

AQD-OG2 Equipment List

AQD-OG3 Storage Tanks, Pressurized Vessels & Pneumatic Pumps

AQD-OG4 Dehydration Units

AQD-OG5 Pumping Unit Engines 

AQD-OG6 Emission Summary

AQD-OG7 Notice of Installation

AQD-OG8 Multiple Facilities

AQD-OG10 BACT cost analysis

Explanations or demonstrations of all methods used to calculate or estimate emissions for each 

emission source, including controlled and uncontrolled sources. Emission calculation methods 

are described later.

All applicable and required attachments noted on the forms, including 

Input and output for emission models/software/process simulations

Equipment manufacturer’s emissions information

Laboratory analyses used for emission models/software/process simulations or calculations 

including a description of sampling procedures and handling, sampling locations, sampling 

location parameters (i.e., pressure and temperature at sampling port)

Any additional attachments or information necessary for complete review of the application
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 30 of 71

Permit Applications cont’d

Download application forms from the AQD website:

http://deq.state.wy.us/aqd/oilgas.asp

Contact the Wyoming Air Quality Division at (307) 777-7391 or (307) 473-3475

Make written request to: Wyoming Department of Environmental Quality

Air Quality Division

Herschler Building, 2-E

122 West 25th Street

Cheyenne, WY 82002

attn: O&G NSR Permitting

or

Wyoming Department of Environmental Quality

Air Quality Division

152 North Durbin Street, Suite 100

Casper, WY 82601

attn: O&G NSR Permitting

For facilities constructed or modified under the Presumptive BACT process submit EITHER 1 paper copy 

with original signature and 1 electronic copy OR 3 paper copies (one with original signature) of the 

complete C6 S2 application within 90-days of the First Date of Production to the address below.

For all facilities where emissions are known prior to construction submit EITHER 1 paper copy with

original signature and 1 electronic copy OR 3 paper copies (one with original signature) of the complete 

C6 S2 application prior to construction to the address below.

NSR Program Manager / attn: O&G Production Facilities

Department of Environmental Quality

Air Quality Division

Herschler Building, 2-E

122 West 25th Street

Cheyenne, WY 82002

The preferred method for filing the application is 1 paper copy with 1 electronic copy.
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 31 of 71

Permit Applications cont’d

Example Process Diagram & Description

EXAMPLE: Air emission sources in the diagram are the condensate storage tank from which vapors are vented to the 

atmosphere, the dehydration unit reboiler still vent and the three natural gas-fired process heaters. Produced fluids are 

directed to the 3-phase separator for separation of condensate/water/gas. Wet gas is directed to the TEG dehydration unit for 

drying. Separated condensate and water are routed to the appropriate tanks for storage prior to being hauled from location via 

truck. Produced gas is used as burner fuel. Reboiler vapors and flash emissions are vented to the atmosphere along with 

S/W/B losses from the condensate tank.

500-bbl 

Produced 

Water Tank

1000 BWPD

400-bbl 

Condensate

Tank

20 BPD

4.0 MMCFD 

TEG 

Dehydration

Unit

3-Phase 

Separator

500 psig

85 oF

Separated Condensate/ Water to 

Storage Tanks

Dry Gas to Sales

1.0 MMBtu/hr 

Reboiler Heater

Wet Gas to 

Dehy

Well Fluids 

to Separator

Reboiler Vapors 

to Atmosphere

Flash and S/W/B Vapors to 

Atmosphere

0.50 MMBtu/hr 

Tank Heater

Truck Loadout (20 BPD)
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

Page 32 of 71

Permit Applications cont’d

Example Process Diagram & Description

EXAMPLE: Total well fluids from four wells flow to the 2-ph HP separators. Wet gas from the HP separators flows to the four 

dehydration units. Separated fluids from the 2-ph HP separators flows to the 3-ph LP separators. Separated condensate and 

water flows from the 3-ph LP separators to the storage tanks. Gas released in the 3-ph separators is routed to the condensate 

storage tanks. Tank vapors, including tank flash, gas from the 3-ph LP separators and S/W/B vapors are collected and directed 

to a 30-foot smokeless combustor. The temperature of the combustor is continually monitored and recorded using a SCADA 

system. Reboiler still vents vapors flow through condensers. Condensed liquids are pumped to the condensate storage tanks. 

Non-condensable vapors flow to the 20-foot Mini-Combustors. The temperature of the Mini-combustors is continually 

monitored and recorded using a SCADA system. Pneumatic heat trace pumps operate 6 months per year using produced gas 

from the HP separators to operate. Vent lines from the pumps are routed into the condensate dump lines from the LP 

separators. 

The process diagram does not need to be computer generated. A simple hand sketch is sufficient as 

long as the required information is included. The diagram does not need to be drawn to scale and does 

not need to represent the exact position of production equipment at the facility as long as the process 

description and operating scenario are clearly defined.

Well 1 

HP 2-Phase Separators with 0.5 

MMBtu/hr heaters

600 psig, 80 deg F

400-bbl 

Condensate Tank

400-bbl 

Condensate Tank

Combustor

Tank Flash, LP Separator Flash, S/W/B losses

Mini 

Combustor

4.0 MMCFD 

TEG 

Dehydration 

Unit with 0.085 

MMBtu/hr 

reboiler

6.0 MMCFD 

TEG 

Dehydration 

Unit with 0.75 

MMBtu/hr 

reboiler

Mini 

Combustor

Separated Condensate

& LP Separator Flash

Pneumatic Heat Trace Pumps

Condenser

20 psig, 130 deg F

LP 3-Phase Separators

60 psig, 120 deg F 

Separated 

Water

Truck Loading

Well 2 Well 3 Well 4 

Separated Wet Gas

Dry gas to Sales 

Pipeline

400-bbl Water Tank

400-bbl Water Tank

Separated Liquids

Condenser

20 psig, 130 deg F

6.0 MMCFD 

TEG 

Dehydration 

Unit with 0.5 

MMBtu/hr 

reboiler

10.0 MMCFD 

TEG 

Dehydration 

Unit with 0.75 

MMBtu/hr 

reboiler
C6 S2 O&G Production Facilities Permitting Guidance

March 2010

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Permit Applications cont’d

Upon receiving the application, the AQD sends a receipt letter to the applicant. The application is 

logged into the AQD tracking system and assigned a reviewing engineer. The engineer has up to 30-days 

to perform a completeness review to ensure adequate and correct information has been filed. If the 

application is deemed incomplete the engineer will notify the applicant and request further information. 

Upon completeness the engineer has 60-days to complete a technical review, write an application 

analysis and make any recommendations. During this process the decision to issue a permit or waiver 

takes place. If the decision is to issue a permit, the proposed permit, including compliance 

requirements, is published for a mandatory 30-day public comment period. If no comments are 

received the permit is issued once the public comment period ends. If comments are received these are 

addressed by the AQD. It is possible comments will warrant a public hearing. When this is the case, a 

final permit may be denied or delayed.

An hourly fee will be assessed for the time it takes AQD personnel to process the application. A bill will 

be sent to the applicant when the process is complete. Billing is handled as follows:

Initial billing is assessed when a proposed permit is sent to public notice. Initial billing shall be 

paid prior to issuance of the final permit.

Final billing is assessed for waivers and permits after these are issued.

Contact the Division for the current hourly rate.

NOTE: The Presumptive BACT permitting process may not be used for sour gas (H2S) production facilities 

unless the only emissions of H2S will be those associated with fugitive losses from valves, fittings, surface 

piping and pneumatic devices, etc. If there will be H2S emissions associated with vented gas or tank 

vapors or if sour gas will be flared the applicant shall contact the Division for permitting guidance prior 

to construction. 

NOTE: NO internal combustion compressor engines or generator engines may be installed under the 

Presumptive BACT process. No pumping unit engines greater than 50-Hp or with nitrogen oxide (NOX) 

emissions greater than 5 TPY may be installed under the Presumptive BACT permitting process. 

Such engines shall be permitted prior to installation.
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Permit Applications cont’d

NOTICE of INSTALLATION (NOI)

For some O&G production facilities or equipment, associated air emissions are considered relatively 

insignificant by the AQD. In these cases the NOI form, FORM AQD-OG7, serves as a complete C6 S2 

permit application. 

The NOI can be used for facilities such as single wellsites, consisting of only a wellhead or perhaps a 

separation unit, where no produced fluids are stored or dehydrated. Instead, the produced fluids are 

routed directly from the wellhead or separation vessels into a sales line, collection system or to a 

separate facility for treatment, storage and sales. The only emissions at this type of facility would be 

fugitive emissions from equipment leaks and fittings, or NOX and CO emissions associated with small 

natural gas fired process heaters.

The NOI may be used as a complete permit application ONLY if ALL of the following apply to the facility 

owner:

There are no hydrocarbon liquids storage tanks.

There are no dehydration units.

There are no pressurized vessels from which hydrocarbon vapors are vented to the atmosphere 

other than during upset or emergency conditions.

There are no internal combustion pumping unit engines ≥ 50 HP or with ≥ 5 TPY NOX emissions.

There are no H2S emissions from the facility other than those associated with fugitive leaks from 

process components and surface piping.

There are no SO2 emissions associated with the combustion of sour gas.

REMINDER for Pumping Unit Engines: Pumping unit engines at oil and gas production facilities are 

subject to additional NESHAP requirements under 40 CFR part 63, subpart ZZZZ. Also, engines at these 

facilities may be subject to additional NSPS requirements under 40 CFR part 60, subpart JJJJ based on 

engine manufacture date. It is the operator’s responsibility to comply with all applicable requirements 

of the NSPS and NESHAP regulations.

Using the NOI as notification of equipment replacements and changes

The NOI may be used for notification of equipment change outs or replacements, provided the changes 

will not significantly increase permitted emissions, if at all. For example, use the NOI as notification of 

replacement of a TEG dehydration unit with one having a higher design rating but with the same model 

glycol pump as previously permitted, or higher rated reboiler burner. Increased emissions associated 

with the larger burner would be considered insignificant and there would be no emissions increase 

associated with the larger dehy as long as there is no change in the glycol pump model or wet gas 

throughput.
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Permit Applications cont’d

NOTICE of INSTALLATION (NOI)

Another example would be to use the NOI as notification of the installation of additional production 

tanks at a previously permitted facility provided throughput to the current and additional tanks is the 

same as or less than the previously permitted throughput and provided the vent lines of the new tanks 

are tied into emission control devices if such was required for the existing tanks.

The NOI may be used as notification of the installation of different process heater, such as replacing a 

0.5 MMBtu/hr line heater with a 0.75 MMBtu/hr line heater.

Examples are illustrated on the next page.
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Permit Applications cont’d

Examples of cases where the NOI may be used as a complete C6 S2 

permit application or as notification of equipment changes 

flowing well

separator

produced fluids to gathering 

system or separate facility

gas to sales or collection 

system

process heater

electric

pumping unit

produced oil to gathering system 

or separate facility

produced water

1

2

3

<50 Hp & <5 TPY NOx

pumping unit with natural 

gas-fired engine

SOUR fluids to treater heater

treater

sour production to gathering 

system or separate facility

4

A storage tank is added to an 

existing facility. Tank 

throughput at the facility is no 

greater than previously 

permitted throughput. If 

existing tanks are connected 

to an emission control device, 

the new tank shall also be 

connected to the control 

device.

install new tank

SWEET gas burner fuel
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Permit Applications cont’d

Notice of Installation (NOI)

How to obtain NOI Form AQD-OG7

The link to electronic forms on the AQD website is

http://deq.state.wy.us/aqd/oilgas.asp

Contact the Wyoming Air Quality Division at (307) 777-7391 or (307) 473-3475

Make written request to: Wyoming Department of Environmental Quality

Air Quality Division

Herschler Building, 2-E

122 West 25th Street

Cheyenne, WY 82002

When/where to file a NOI

Within 60-days of the First Date of Production, equipment change out, equipment replacement or 

equipment addition submit EITHER 1 paper copy with original signature and 1 electronic copy OR 3 

paper copies (one with original signature) of the NOI form to:

NSR Program Manager / attn: O&G Production Facilities

Department of Environmental Quality

Air Quality Division

Herschler Building, 2-E

122 West 25th Street

Cheyenne, WY 82002

The preferred method for filing the NOI is 1 paper copy with 1 electronic copy.
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Specific Requirements for JPAD Permit Applications

For JPAD, the Presumptive BACT permitting process varies from that for all other statewide areas.

Unlike the Presumptive BACT permitting process for CDA and Statewide facilities, the permitting 

process for JPAD facilities does not require the determination of projected, potential emissions prior to 

application filing. Instead, emissions meeting the BACT requirements shall be in place upon the First 

Date of Production at all new and modified facilities. A C6 S2 application is filed to notify the AQD of the 

start up of a new facility or the modification to an existing facility. The application describes new, 

modified and future well/equipment installations along with the associated, controlled and uncontrolled 

emissions and serves as a form of certification by the owner that Presumptive BACT requirements for 

emission controls and control device monitoring have been and will be met.

A complete C6 S2 application, including all appropriate forms, shall be filed for within sixty-days of the 

First Date of Production or modification for:

all new single well facilities

all new PAD facilities

modifications to existing single or PAD facilities

If a facility has been previously permitted and the permit contains conditions authorizing additional 

equipment and wells to be added according to the July 28, 2004 Guidance Addendum, a complete 

application may be submitted using the AQD Pinedale-1 Form.

Any additional attachments or information necessary for complete review of the application

Emissions reported in the application shall be based on projected rates for new wells and current 

average production rates at the time of application filing for existing wells. Higher production rates may 

be used if the applicant wants to permit for production/emission increases.

NOTE: At facilities with a permit authorizing the addition of future wells, the authorization becomes 

invalid if no wells are added to the facility within 24 months after receipt of the permit or if the addition 

of the planned wells is discontinued for a period of 24 months or more. The permit for the existing wells 

remains valid.

For facilities requiring a permit prior to start up of operations, emissions reported in the application 

should be based on expected production rates. Higher production rates may be used if the applicant 

wants to permit for production/emissions increases.
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Specific Requirements for JPAD Permit Applications cont’d

How to obtain C6 S2 application, AQD Pinedale-1 and NOI forms

Download electronic forms from the AQD website at:

http://deq.state.wy.us/aqd/oilgas.asp

Contact the Wyoming Air Quality Division at (307) 777-7391 or (307) 473-3475

Make written request to:

Wyoming Department of Environmental Quality 

Air Quality Division

Herschler Building, 2-E

122 West 25th Street

Cheyenne, WY 82002

attn: O&G NSR Permitting

When/where to file C6 S2 permit applications, AQD Pinedale-1 and NOI forms

For facilities where emissions are known prior to construction submit EITHER 1 paper copy with original 

signature and 1 electronic copy OR 3 paper copies (one with original signature) of the complete C6 S2 

application PRIOR to construction to the address below.

For facilities constructed or modified under the Presumptive BACT process submit EITHER 1 paper copy 

with original signature and 1 electronic copy OR 3 paper copies (one with original signature) of the 

complete C6 S2 application within 60-days of the First Date of Production to the address below.

For facilities with additions authorized under the July 28, 2004 Guidance Addendum, use the AQD 

Pinedale-1 Form. Submit EITHER one electronic and one paper copy with original signature OR three 

paper copies (one with original signature) within 60-days of the First Date of Production to:

NSR Program Manager / attn: O&G Production Facilities

Department of Environmental Quality

Air Quality Division

Herschler Building, 2-E

122 West 25th Street

Cheyenne, WY 82002

The preferred method for filing the application is 1 paper copy with 1 electronic copy.
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The 0.6 decline factor ....

The first year daily production rates are represented by the jagged line BOX 1. The area under the line 

represents the total actual production volume for the first year. It is difficult to calculate the total 

volume under the jagged line so it is smoothed out BOX 2 using statistical methods.

BOX 1 BOX 2

BOX 3 BOX 4

 

The smoothed curve is “straightened” out in BOX 3, then “leveled” out in BOX 4. Now the total production for the 

first year is represented by the area under the line in BOX 4 which is easily calculated. Production curves from a 

large sampling of Wyoming wells indicate the average well declines by 80% during the first year. That 80% decline 

is represented by the level line in BOX 4 after the first 30-day average production rate is multiplied by 0.6. For the 

first month the well makes an average 3.333 MMCFD. With 80% decline during the first year, the well will make 

0.667 MMCFD at the end of the first year (3.333 - 0.8(3.333) = 0.667). Then the average daily production rate over 

365 days is (3.333 + 0.667)/2 = 2.0 MMCFD which is the same as 3.333 × 0.6 = 2.0.

start up 365 days 

 

 MMCFD

start up 365 days

 

 2.0 MMCFD

 

start up 365 days 

 

start up 365 days 

 

 MMCFD

The “smoothed” curve in BOX 2 is 

“straightened” out using mathematical 

methods. 

EXAMPLE - actual daily gas production rate vs time

Actual production during the first year is represented by the area 

under the jagged line which ultimately turns out to be ≈ 730 

MMCF. 

The jagged line representing daily 

production is “smoothed” out using 

statistical methods. 

“leveled” out, projected daily gas production rate vs time

Total projected production for the first year is represented 

by the area under the straight line 

2 MMCFD × 365 days = 730 MMCF

First year projected emissions are based on 730 MMCF of 

produced gas. 
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B L A N K
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APPENDIX A

F O R M S
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B L A N K
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Form AQD-OG0 Application

Identifies the submittal as a C6 S2 O&G Production Facilities Permit Application
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Form AQD-OG0 NOI

Identifies the submittal as a C6 S2 O&G Production Facilities Notice of Installation = Application
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Form AQD-OG00 Completeness Checklist
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Form AQD-OG1 Application Coversheet
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Form AQD-OG2 Equipment List
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Form AQD-OG2 Equipment List, Page 2
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Form AQD-OG3 Storage Tanks, Pressurized Vessels & Pneumatic Pumps
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Form AQD-OG4 Dehydration Units
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Form AQD-OG5 Pumping Unit Engines
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Form AQD-OG6 Emission Summary
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Form AQD-OG7 Notice of Installation
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Form AQD-OG8 Multiple Facilities
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Form AQD-OG9 Change of Ownership
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Form AQD-OG10 BACT Cost Analysis

Company Name:

Facility Name:

Wyoming Air Quality Standards and Regulations - Chapter 6, Section 2(c)(v)

Best Available Control Technology Control Cost Analysis Worksheet

(Based on Office of Air Quality Planning and Standards, EPA, OAQPS Control Cost Manual, Fourth Edition, EPA 450/3-90-006, January 1990, Section 2.3.2)

Targeted Emission

Reference Site Control Controlled or Typical without with

No. Rating Manufacturer Model Method Targeted BACT Control Control

(units) Emission (units) (TPY) (TPY)

Example 1500 Waukesha L7042GSI Catalitic/AFR NOx 2 g/hp-hr 144.7 28.9

Reference Interest Control Capital Capital Annual Capital Realized

No. Rate System Life Recovery Factor Investment Maintenance Recovery Cost Economic

(i) (n) (CRF) (P) Cost (CRC) Benefit

Example 0.1 10 0.163 $14,000 $4,000 $2,278 $0

0 #DIV/0! #DIV/0!

0 #DIV/0! #DIV/0!

"n" is the control system economic life, typically thought to be 10-20 years.

"i" is the considered the annual pretax marginal rate of return on private investment (i.e., what it may cost you to borrow the money).

"P" is the capital investment required to install the controls (i.e., equipment purchase cost, installation/retrofit cost, engineering, etc.).

Annual Maintenance Cost is the yearly costs to maintain the control effectiveness (i.e., cleaning, testing, etc).

CRC = CRF * P

CRC = Capital Recovery Cost (Annualized cost of control over the life of the control)

CRF = Capital recovery Factor

P = Capital Investment

CRF = i(1+i)n/(1+i)n-1

i = Annual Interest Rate

n = Economic life of the control

Total Annual Cost (TAC) = Annual Maintenance Cost + Capital Recovery Cost - Realized Economic Benefit

Cost to Control = TAC / (Targeted Emission Volume Without Control - Targeted Emission Volumn with Control)

Reference TAC Cost to Control

Number ($) ($/Ton)

Example $6,278 $54

0 #DIV/0! #DIV/0!

0 #DIV/0! #DIV/0!

Does the control have "Economic Reasonableness" and "Technical Practicability"?
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B L A N K
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APPENDIX B

EMISSION CALCULATIONS
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B L A N K
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Emissions from processes and equipment which shall be accounted for and reported by applicants FOR 

ALL O&G PRODUCTION FACILITIES are:

Emission Unit or Process Associated Emissions

storage tanks (flashing & S/W/B losses) VOC HAP H2S

pressurized vessels (flashing losses) VOC HAP H2S

dehydration units (reboiler still vents & glycol flash tanks) VOC HAP

natural gas fired burners, heaters, flares NOX CO SO2

natural gas operated pneumatic pumps VOC HAP H2S

fugitives VOC HAP H2S

natural gas fired engines NOX CO SO2

truck load out VOC HAP H2S

AP-42 EMISSION FACTORS

Throughout this Guidance reference is made to AP-42 emission factors. The complete AP-42 

compilation may be downloaded from http://www.epa.gov/ttn/chief/ap42/index.html

STORAGE TANK EMISSIONS

Flashing and Standing/Working/Breathing (S/W/B) losses are the terms for emissions which occur 

when hydrocarbon liquids are exposed to temperature and pressure changes (i.e., from separator 

pressure and temperature to storage tank pressure and temperature) causing hydrocarbon vapors to be 

released from the liquids. The vapors may contain VOCs, HAPs and H2S. 

Software is available for modeling these emissions. Models accepted by the Air Quality Division are 

those using Peng-Robinson or S-R-K methods based on widely accepted principals of behavior for 

hydrocarbon vapors and liquids. Some common software programs for estimating these emissions are 

PROMAX, HYSIM, HYSYS, K-FLASH, PROSIM and API E&P TANKS v2.0. The models require input detailing 

chemical properties of the fluids handled and physical operating parameters of the system(s) and 

production equipment. Output from the models includes volumes, rates and chemical components of 

the individual process streams from tanks and pressurized vessels.

Emissions from storage tanks may also be physically measured. In order to do so all tank valves, 

hatches, relief devices, leaks, etc. shall be sealed. Tank vapors shall only be allowed to exit the tank 

through a metered outlet. Usually this requires a meter capable of measuring low volumes. The 

measurement period shall last long enough to capture a representative tank vapor volume. An 

extended hydrocarbon analysis of the vapors shall be obtained along with the vapor volume. 
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MEASURED TANK FLASH EMISSIONS - EXAMPLE CALCULATION

The tons per year of VOC and HAP emissions associated with tank flashing are calculated as follows:

Given: Condensate tank vapors = 1000 scf/day

 VOC weight % = 20

 HAP weight % = 5

 Condensate vapor molecular weight = 20 lb/lb-mol

TPY total flash emissions = 1000 scf/day × (1 lb-mol/379 scf) × (20 lb/lb-mol) × (ton/2000 lb) × (365 days/year) = 9.6 TPY

TPY total VOC emissions = 9.6 TPY × (20 weight % VOC / 100) = 1.9 TPY VOC

TPY total HAP emissions = 9.6 TPY × (5 weight % HAP / 100) = 0.5 TPY HAP

S/W/B losses

Not all software programs include tools for estimating S/W/B losses. There is free software available 

from the EPA named EPA TANKS. The most recent available version of EPA TANKS is ver. 4.09D. The 

software may be downloaded from the EPA website at 

http://www.epa.gov/ttn/chief/software/tanks/index.html

PRESSURIZED VESSELS

Whenever vapors from a pressurized vessel (separator, treater, FWKO, flash separator, gunbarrel, gas 

boot, etc) are released to the atmosphere, other than during times of emergency or upset conditions, 

emissions associated with those vapors shall be accounted for.

The same flash emission models mentioned above, for tank flash emissions, are often used to estimate 

emissions from pressurized vessels. Again, an extended hydrocarbon analysis of the liquids involved and 

actual operational conditions of the production equipment are necessary as input for the models.

Even when vapors from a pressurized vessel are collected for use as process burner fuel or fuel for an IC 

engine, for example, emissions associated with the total vapors shall be accounted for when considering 

potential emissions from a facility. If the volume and rate of vented vapors are known and an extended 

hydrocarbon analysis is available, associated emissions may be calculated in the same manner as 

described on Page 68 (calculation of flash emissions). If these are not available, the volumes shall be 

measured and analyzed in order to perform the calculations and determine associated emissions. 

DEHYDRATION UNIT EMISSIONS

Air pollutants, mostly VOCs and HAPs, are associated vapors released from reboiler still vents and glycol 

flash separators. To estimate these emissions the GRI-GLYCalc v3.0 or higher model or other approved 

method is used. This relatively inexpensive software was created by the Gas Research Institute (GRI) for 

determining optimal operating parameters for dehydration units and is available from the Gas 

Technology Institute (GTI) with a website address of http://www.gastechnology.org

Input for the model includes an extended hydrocarbon analysis of wet gas sampled upstream of the 

contact tower, actual operating parameters of all associated equipment (i.e., reboiler still vent temp., 

flash separator temp., dry gas flow rate, glycol recirculation rate, condenser, etc) and physical properties 

of the dry and wet gas streams. The model provides an estimate of individual emission components and 

the rates of vapor and liquid streams exiting each process vent of a dehydration unit. When submitting 

a GRI-GLYCalc model it is only necessary to submit the INPUT SUMMARY, EMISSIONS SUMMARY, 

CONDENSER VENT OUTPUT (if applicable) and FLASH TANK OUTPUT (if applicable). 
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NATURAL GAS FIRED HEATERS (external combustion equipment)

NOX, CO and VOC emissions from process unit heaters should be calculated using the emission factors 

(EF) below from EPA AP-42, Tables 1.4-1, 1.4-2 and 1.5-1. The following lists these factors:

Emission Factors for Industrial and Commercial Boilers

Pollutant Butane Gas1

Propane Gas2Natural Gas3Natural Gas3

(0.3 to 100 MMBtu/hr heat input) (0.3 to 100 MMBtu/hr heat input) <100 MMBtu/hr heat input

NOX

4

15 lb/1000 gal 13 lb/1000 gal 0.098 lb/MMBtu 100 lb/MMcf

CO48.4 lb/1000 gal 7.5 lb/1000 gal 0.082 lb/MMBtu 84 lb/MMcf

TOC4,5 1.1 lb/1000 gal 1.0 lb/1000 gal 0.010 lb/MMBtu 11 lb/MMcf

1

Based on an average heating value of 102 × 106Btu/1000 gallons of Butane. 

2

Based on an average heating value of 91.5 × 106Btu/1000 gallons of Propane.

3

Based on an average heating value of 1020 Btu/SCF of natural gas.

4

The emission factors in this table may be converted to other natural gas heating values by multiplying the given emission 

factors by the ratio of the heating value of the actual gas used to the average heating values listed 

Converted EF = (EF from table above × (actual heat value/heat value in table)). 

5

VOC emissions may be determined by multiplying the calculated TOC (total organic compounds) emission rate by the weight 

percent of VOC compounds in the actual fuel gas stream.

HEATER EMISSIONS - EXAMPLE CALCULATION

Given: Separator heater rating = 0.5 MMBtu/hr

 Gas Heating Value = 1300 Btu/scf

 VOC weight % = 20

 Annual operating hours = 8760

 NOX EF = 100 lb/MMcf

 CO EF = 84 lb/MMcf

 TOC EF = 11 lb/MMcf

NOX emissions = (0.5 MMBtu/hr) × (100 lb/MMcf) × (1300 Btu/1020 Btu) x (1 scf/1020 Btu) × (8760 hr/yr) × (ton/2000 lb) = 0.27 TPY NOX

For CO emissions, the same calculation is used except the EF is 84 lb/MMcf.

VOC emissions = 0.5 × 11 x (1300/1020) x 1/1020 × 8760/2000 x (20% VOC/100) = 0.006 VOC TPY VOC ← INSIGNIFICANT at less than 0.1 TPY

FLARES

The NOX and CO emissions for flares should be based on 0.14 lb NOX/MMBtu and 0.035 lb CO/MMBtu

and the reported fuel usage based heat input. VOC and HAP emissions from flaring should be based 

upon the guaranteed destruction efficiency of the flare. Reported flared gases shall include pilot gas 

with heat content and flared gas with average estimated heat content. The rational for using these 

factors as opposed to AP-42 factors for flares is that the flare factors are believed to be only applicable 

to chemical plant type flares engaged in burning low BTU gases. The gases typically burned in flares in 

Wyoming contain more than 900 Btu/scf and emissions are expected to be closer to the AP-42 factors 

for NOX and CO from gas fired heaters and boilers greater than 10 MMBtu/hr.
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FLARE EMISSIONS - EXAMPLE CALCULATIONS – CONDENSATE TANK FLASH

Given: Total waste gas = 125 scf/hr

 Gas heating value = 1350 Btu/scf

 H2S weight % = 5.5

 H2S mole % = 4.4

 Tank vapor MW = 28 lb/lbmol

 SO2 MW = 64 lb/lbmol

NOX emissions = (125 scf/hr) × (1350 Btu/scf) × (0.14 lb NOX /MMBtu) × (MMBtu/106Btu) × (8760 hr/yr) × (1 ton/2000 lb) = 0.1 TPY NOX

Unflared H2S emissions = (125 scf/hr) × (28 lb/lb-mol) × (1 lb-mol/379 scf) × (8760 hr/yr) × (ton/2000 lb) x (5.5/100) = 2.2 TPY H2S 

Flared H2S emissions = (2.2 TPY) × (100% - 98%/100)= 0.04 TPY H2S ← INSIGNIFICANT at less than 0.1 TPY

SO2 emissions from flaring sour gas = (125 scf/hr) × (8760 hr/yr) × (1 lb-mol/379 scf) × (64 lb SO2/lb/mol) × (ton/2000 lb) × (4.4/100)

 = 4.1 TPY SO2

FLARE PILOT EMISSIONS

Given: Flare pilot gas = 5 scf/min

 Gas heating value = 1000 Btu/scf

NOX emissions = (5 scf/min) × (1000 Btu/scf) × (0.14 lb NOX/MMBtu) × (MMBtu/106Btu) × (60 min/hr) × (8760 hr/yr) × (1 ton/2000 lb)

 = 0.18 TPY NOX

For CO emissions the same calculations are used except the EF for CO is 0.035 lb/MMBtu.

FLARE EMISSIONS EXAMPLE CALCULATION – DEHYDRATION UNITS

Given: Glycol flash separator vapors = 25 scf/min

 Reboiler still vent vapors = 5 scf/min

 Total waste gas = 30 scf/min (25 scf/min glycol flash vapors + 5 scf/min reboiler still vent vapors)

 Gas Heating Value = 1050 Btu/scf (assume at least 1000 BTU/SCF if the heat content is unknown)

 

NOX emissions = (30 scf/min) × (1050 Btu/scf) × (0.14 lb NOX/MMBtu) × (1 MMBtu/106Btu) × (60 min/hr) × (8760 hr/yr) × (1 ton/2000 lb) 

 = 1.1 TPY NOX

For CO emissions the same calculations are used except the EF for CO is 0.035 lb/MMBtu.

PNEUMATIC PUMPS

If a pneumatic pump uses natural gas as the motive gas, the pump will release VOC and HAP emissions 

each time it strokes since all motive gas is vented by the pump. To determine emissions from the pump, 

manufacturer’s information regarding gas usage shall be known as well as the hydrocarbon composition 

of the motive gas.

PNEUMATIC PUMP EMISSIONS - EXAMPLE CALCULATION

A Texsteam Series MX pump is used to circulate hot glycol in heat trace lines. The pump moves 0.15 

gallons per 40 strokes and is currently stroking at 20 strokes per minute (spm). The pump requires 24 

scf for each gallon of glycol pumped. The pump motive gas weighs 20 lb/lb-mol and contains 50 wt% 

VOCs and 30 wt% HAPs.

Pump usage/vent rate = (20 strokes/min) × (0.15 gallons/40 strokes) × (24 scf/gallon) = 1.8 scf/min

VOC emissions = (1.8 scf/min) × (20 lb/lb-mol) × (lb-mol/379 scf) × (ton/2000 lb) × (525600 min/yr) × (50 wt% VOC/100) = 12.5 TPY VOC 
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TRUCK LOADING

VOC emissions from loading oil or condensate into tank trucks should be estimated using the following 

formula with data from AP-42 tables.

LL - 12.46 × S × P × M/T

Where: LL = loading loss, pound per 1,000 gallons of liquid loaded (lb/1000 gal)

S = a saturation factor (See Table 5.2-1 below)

P = true vapor pressure of liquid loaded (psia)

M = molecular weight of tank vapors (lb/lb-mol)

T = temperature of bulk liquid loaded (oR) (oR = oF + 460)

"S" values are obtained from Table 5.2-1.

"M" and "N" values are obtained from Table 7.1-2.

Table 5.2-1 Saturation (S) Factors for Calculating Petroleum Liquid Loading Losses

Cargo Carrier Mode of Operation "S" Factor

tank trucks and rail tank cars

submerged loading of a clean cargo tank 0.50

submerged loading: dedicated normal service 0.60

submerged loading: dedicated vapor balance service 1.00

splash loading of a clean cargo tank 1.45

splash loading: dedicated normal service 1.45

splash loading: dedicated vapor balance service 1.00

Table 7.1-2 Properties of Selected Petroleum Liquids

Only crude oil properties are supplied here. The full table of values can be found in AP-42, Table 7.1-2)

petroleum 

liquid

vapor 

molecular 

weight at 60oF 

(lb/lb-mol)

condensed 

vapor 

density at 

60oF (lb/gal)

liquid density at 60oF 

(lb/gal)

true vapor pressure (psi) at various temperatures in 

oF 

40 50 60 70 80 90 100

"M" "P"

Crude Oil 

RVP 5 50 4.5 7.1 1.8 2.3 2.8 3.4 4.0 4.8 5.7

TRUCK LOADOUT - EXAMPLE CALCULATION

Given: Condensate loaded = 360 bbl crude/month

 S = 0.6

 P = 2.3 psi

 M = 50 lb/lb-mol

 T = 50

LL = (12.46) × (0.60) × (2.3 psi) × (50 lb/lb-mol) = 1.69 lb/1000 gal

(50oF + 460)

Loading losses (TPY) = (1.69 lb/1000 gal) × (annual sales of 360 bbl/mo) × (12 mo/yr) × (42 gal/bbl) × (ton/2000 lb) = 0.15 TPY
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FUGITIVE EMISSIONS

The easiest way to calculate total hydrocarbon fugitive emissions is to multiply the number of 

components at a site by the EPA Average Emissions Factors shown in the tables below. The first table 

lists the average emission rates of total hydrocarbon (THC) to be assumed for all components in 

hydrocarbon service installed at a site. The factors are current as of June 15, 1996 and given in pounds 

per component - day (lb/component-day). The second table lists speciated rates.

The only information needed for this method is a count or estimate of the number of flanges, 

connectors (other than flanges), open-ended lines, pumps, valves and "other" components at the site 

grouped by stream (gas, light oil, heavy oil, water/oil). The number of components can be determined 

by either counting them in the field or by estimating them.

EPA Average Emission Factors for Total Hydrocarbon (THC) Emissions

From O&G Production Operations

(lb/component-day)

equipment type

equipment service category

gas

heavy oil

(< 20oAPI)

light oil

(> 20oAPI) water/light oil 1

connector .011 .0004 .011 .0058

flange .021 .000021 .0058 .00015

open ended line .11 .0074 .074 .013

other 2.47 .0017 .4 .74

pump .13 not available .69 .0013

valve .24 .00044 .13 .0052

SOURCE: US EPA Bulletin Board (Leaks_OG.WP5; 8/9/1995)

1

 The water/light oil emission factors apply to water streams in light oil service with water content between 50% and 99%. For streams with 

water content > 99% the emission rate is considered negligible. 

2

 The “other” equipment type includes compressor, pressure relief valves, diaphragms, drains, dump arms, hatches, instruments, meters, 

polished rods and vents.

NOTE: The emission factors in the table above are not intended to be used to represent emissions from 

components that are improperly designed (e.g., enardo valves over pressurizing, failure of thief hatches 

to reseat after over pressurizing) or equipment not maintained properly (e.g., thief hatch left open). For 

example, emissions from an enardo valve on a condensate tank vent line, operating in the full or 

partially open position due to excessive tank vapor pressure that exceeds the pressure setting of the 

enardo valve, are not considered to be fugitive emissions. 

Speciated hydrocarbon emission rates can be estimated by multiplying the total hydrocarbon emission 

rates obtained from the table above by actual measured weight fractions or by using the values listed in 

the table below.

Speciated Fugitive Emission Factors

(Estimated weight fractions of THC emissions in each category)

Methane NMHC VOC C6+Benzene Toluene EthylBenzene Xylenes

light crude 0.613 0.387 0.292 0.02430 0.00027 0.00075 0.00017 0.00036

heavy crude 0.942 0.058 0.030 0.00752 0.00935 0.00344 0.00051 0.00372

gas production 0.92 0.080 0.035 0.00338 0.00023 0.00039 0.00002 0.00010

NOTES: 1. Emission factor = Speciated Emissions/Total Emissions

2. NMHC = Non-methane hydrocarbons

3. VOC = Propane and heavier hydrocarbons
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FUGITIVE EMISSIONS - EXAMPLE CALCULATION

Given: 25 valves in light oil service

 THC emission factor = 0.13 lb/component-day

 VOC weight fraction = 0.292

 HAP weight fractions = 0.02430 + 0.00027 + 0.00075 + 0.00017 + 0.00036 = 0.0259

VOC emissions = 25 valves × 0.13 lb THC/valves-day × 1 ton/2000 lb × 365 day/hr × 0.292 = 0.17 TPY VOC

HAP emissions = 25 valves × 0.13 lb THC/valves-day × 1 ton/2000 lb × 365 day/yr × 0.0259 = 0.015 TPY total HAPs

INTERNAL COMBUSTION PUMPING UNIT ENGINE EMISSIONS

The method for calculating engine emissions is to use emission factors provided by the engine 

manufacturer, the maximum site-rated horsepower and the annual operating hours. 

PUMPING UNIT ENGINE EMISSIONS - EXAMPLE CALCULATION

Given: Manufacturer’s NOX emission factor = 2 g/hp-hr

 Maximum site-rated horsepower = 250 hp

 Annual operating hours = 8760

NOX emissions = (2.0 g/hp-hr) × (250 hp) × (8760 hr/yr) × (ton/2000 lb) × (1 lb/453.6 g) = 4.8 TPY

For CO and VOC emissions the same calculations are used except the manufacturer’s EF for CO and VOC are used.

CONVERTING MOLE PERCENT TO WEIGHT PERCENT

Many emission estimation and calculation methods require weight percents to be used, rather than 

mole percents. Most lab analyses list gas constituents in mole percents, however you can request the 

lab provide both mole and weight percents.

You may download the Excel spreadsheet to convert mole percent to weight percent, at 

http://deq.state.wy.us/aqd/miscforms.asp
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APPENDIX C

DEFINITIONS
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Air Contaminant - shall mean dust, fumes, mist, smoke, other particulate matter, vapor, gas or any 

combination of these; but shall not include steam or water vapor.

Air pollutants - Also known as criteria pollutants, Air pollutant emissions which have ambient air 

standards associated with them. Air pollutants include such emissions as volatile organic compounds 

(VOC), nitrogen oxides (NOx), carbon monoxide (CO), sulfur dioxide (SO2), hazardous air pollutants (HAP) 

and others.

Average Daily Production - The qualified maximum total production of domestic crude petroleum and 

petroleum condensates including natural gas liquids produced from a well during a certain period of 

time (i.e. 1-month, 1-year) divided by the number of calendar days in the certain period during which 

the well produced. For example, the average 30-daily condensate production rate for well ABC is the 

qualified maximum total condensate production during the 30-day period x(BBL) ÷ 30(days) = y(BPD). If 

well ABC only produced 5 days out of the 30-day period, then the average daily condensate production 

rate for the well is x(BBL) ÷ 5(days) = y(BPD).

Closed System – A vessel (treater, separator), pipeline, sales line, gathering line, collection line, field gas 

supply or distribution line or any other vessel or line from which no vapors or liquids can exit through 

open lines, holes, vents or valves unless those lines, holes, vents or valves are connected to another 

closed system or to a source of continual and complete combustion, unless the vent or valve is a relief 

device that is designed and intended to open only during emergency situations.

Completion – An oil well shall be considered completed when the first new oil is produced through 

wellhead equipment into lease tanks from the producing interval after the production string has been 

run. A gas well shall be considered completed when the well is capable of producing gas through 

wellhead equipment from the producing zone after the production string has been run. 

Condensate - Hydrocarbon liquid separated from natural gas that condenses (becomes liquid) due to 

changes in temperature, pressure, or both, and remains liquid at standard conditions.

Custody Transfer - The transfer of produced petroleum and/or condensate, after processing and/or 

treatment in the producing operations, from storage vessels or automatic transfer facilities to pipelines 

or any other forms of transportation.

Division - The Department of Environmental Quality, Air Quality Division

First Date of Production - The date permanent production equipment is in place and product is 

consistently flowing to sales lines, gathering lines or storage tanks. Production occurring during well 

completion activities which is routed to temporary production equipment is considered to occur prior to 

the First Date of Production. If extended periods of time pass between zone completions but 

production from initially completed zones is consistently flowing to permanent production equipment, 

the First Date of Production is the date when production from the initial zones began consistently 

flowing to the permanent production equipment, even though more zones will be completed later.

Fugitive Emissions (Fugitives) - Air emissions which result from gas vapors escaping through and around 

seals, packing, gaskets, threads, and other such pressure sealing connections.

Gas – All natural gases and all hydrocarbons not defined as oil.
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Gas Well – A well, the principal production of which, at the mouth of the well, is gas, as defined by the 

Wyoming Conservation Law.

Grand fathered - A facility, installation or site which was built or in service before May 29, 1974 and that 

has not been physically or operationally changed, causing an increase in any pollutant (to which any 

state standard applies) or causing the emission of a new pollutant. (Modifications which could eliminate 

grandfather status are increasing production rate by fracturing, acidizing, recompletion of a zone, 

change in artificial lift methods, bringing new wells into a central battery or a waterflood response. Also 

such things as installing an engine, increasing horsepower, change in burner ratings. This list is not all 

inclusive and judgment should be used to determine appropriate status.)

HAP - Hazardous air pollutant, found in Section 112(b) of the Clean Air Act is a list of 188 contaminants 

with the classification “hazardous air pollutant”. Typical hazardous air pollutants include benzene, 

toluene, ethyl-benzene, xylene, n-hexane, formaldehyde, methanol and others.

Major Emitting Facility - A facility which either has the potential to emit 250 TPY or more of any one 

regulated air pollutant or is a named facility and has the potential to emit 100 TPY or more of any one 

regulated air pollutant.

Major Source - A source which emits either 100 TPY or more of a regulated air pollutant, 10 TPY or more 

of a hazardous air pollutant, or 25 TPY or more of the total hazardous air pollutants.

Modified Facility - An existing facility becomes modified once production streams or production 

equipment associated with another well or wells is added to or tied into it. The date modification occurs 

to an existing facility is the First Date of Production for the added well or the date the production 

streams associated with an additional well or wells are tied into equipment at the existing facility.

Examples of modified facilities not involving new wells or added production from other wells are:

An existing well facility is completed in additional production zones resulting in increased 

production and/or emissions at the facility greater than those previously permitted.

Existing production equipment is replaced with larger equipment, resulting in increased 

potential or actual emissions.

Oil – Crude petroleum oil and any other hydrocarbons, regardless of gravities, which are produced at 

the well in liquid form by ordinary production methods, and which are not the result of condensation of 

gas before or after it leaves the reservoir.

Oil Well – A well, the principal production of which, at the mouth of the well, is oil, as defined by the 

Wyoming Conservation Law.

PAD - A PAD facility is a location where more than one well and/or associated production equipment 

are located, where some or all production equipment is shared by more than one well or where well 

streams from more than one well are routed through individual production trains located at the same or 

contiguous and adjacent location. If the production streams or production equipment associated with 

one or more wells is added to an existing single well facility, that location is then considered to be a PAD 

facility. A single well becomes a multiple well or PAD facility upon the First Date of Production of an 

additional well at the location or on the day production streams associated with an additional well or 

wells from separate locations are routed to the single well facility.
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Potential to Emit - The maximum capacity of a stationary source to emit any air pollutant under its 

physical and operational design. Any physical or operational limitation on the capacity of a source to 

emit an air pollutant, including air pollution control equipment and restrictions on hours of operation or 

on the type or amount of material combusted, stored or processed, shall be treated as part of its design 

if the limitation is enforceable by the EPA and the Division.

Recompletion – Any downhole operation in an existing oil or gas well that is conducted to establish 

production of oil or gas from any geological interval not currently completed or producing in said 

existing oil or gas well.

Single Well Facility – A single well facility is one where production equipment is associated with only 

one well. A single well becomes a multiple well or PAD facility upon the First Date of Production of an 

additional well at the location or on the day production streams associated with an additional well or 

wells from separate locations are routed to the single well facility. 

Spud – The commencement of operations for the first boring of a hole for the drilling of an oil, gas or 

injection well. This includes setting conductor casing.

Synthetic Minor - “Synthetic Minor” sources are sources that do the following types of things to limit 

emission rates below 100 TPY: 1) limit operating hours of a source or 2) limit production rates such that 

source emissions are less than 100 TPY.

VOC - Volatile organic compound means any organic compound which participates in atmospheric 

photochemical reactions; typically considered C3

+

or Non-methane/ethane hydrocarbon vapors.

VOC Weight Percent - This is the weight of the volatile organic compounds, expressed as a percent, as 

compared to the total weight of the compounds in a gas stream. (This should not be confused with the 

volume or mole percent of a gas stream, which is usually how it is expressed in a lab analysis of a gas.)

Wildcat Well – Any oil or gas well designated as a wildcat well by the Wyoming Oil and Gas Conservation 

Commission. Wildcat wells are wells outside known fields or new wells which are determined by the 

Commission to have discovered oil or gas in a pool not previously proven productive.

Workover – Any downhole operation in an existing oil or gas well that is designed to sustain, restore or 

increase the production rate or ultimate recovery in a geologic interval currently completed or 

producing in said existing oil or gas well. Workover includes but is not limited to: acidizing, 

reperforating, fracture treating, sand/paraffin removal, casing repair, squeeze cementing or setting 

bridge plugs to isolate water productive zones from oil or gas productive zones or any combination 

thereof. Workover does not mean the routine maintenance, repair or replacement of downhole 

equipment such as rods, pumps, tubing, packers or other mechanical devices.

Worst case - A situation allowed in air permitting in the State of Wyoming where a facility, site or 

source (which is representative of all the facilities, sites or sources within a designated field area) may 

be used to represent the worst air emissions for the field area sources.

Wyoming Environmental Quality Act - Wyoming Statute, Title 35 “Public Health and Safety”, Chapter 11 

“Environmental Quality” which provides the authority for the rules and regulations of the Air Quality 

Division.