NC DIVISION OF AIR QUALITY

Appendix BProduction Phase

September 2015

Appendix B, Page 1Revised September 2015

Table of ContentsList of Tables................................................................................................................................................2

1 Overall Assumptions for the Production Phase...................................................................................3

2 Process Description.............................................................................................................................3

3 Summary of Emissions.........................................................................................................................6

4 Emissions Activities and Key Assumptions...........................................................................................7

4.1 Blowdown Venting/Liquids Unloading.........................................................................................7

4.2 Produced Water...........................................................................................................................8

4.3 Wellhead Compressor Engines..................................................................................................10

4.4 Glycol Dehydrators and associated Reboiler.............................................................................11

4.5 Pneumatic Controllers...............................................................................................................13

4.6 Heaters......................................................................................................................................15

4.7 Fugitive Losses from Equipment Leaks......................................................................................16

5 References.........................................................................................................................................17

List of Tables Table B-1. Criteria Pollutants, Greenhouse Gas and Hazardous Air Pollutant Emissions from Well Production...................................................................................................................................................6Table B-2. Emission factors used in emission estimation………………………………………………………………………….8Table B-3. Venting related specifications used in emissions estimates…………………………………………………....8Table B-4. Typical composition values and emission ratios used to estimate emissions.............................9Table B-5. Engine specifications used in emissions estimates...................................................................10Table B-6. Emission factors Criteria Air Pollutants used for emission estimates (g/hp-hr)........................11Table B-7. Emission factors Hazardous Air Pollutants used for emission estimates (g/hp-hr)...................11Table B-8. Dehydrator and reboiler specifications used in emissions estimates.......................................13Table B-9. Emission ratios to VOC emissions used in emissions estimates for the dehydrator.................13Table B-10. Emission factors (lbs/MMcf) for the reboiler associated with the dehydrator.......................13Table B-11. Pneumatic Controller specifications used in emission estimates...........................................14Table B-12. Emission ratios of gas released...............................................................................................14Table B-13. Heater specifications used in emission estimates...................................................................15Table B-14. Emission factors used in emission estimations (lb/MMcf)......................................................15Table B-15. Fugitive specifications used in emission estimates.................................................................16Table B-16. Emission ratios used in emission estimates............................................................................16

Appendix B, Page 2Revised September 2015

1 Overall Assumptions for the Production Phase

1 40 CFR Part 60 New Source Performance Standards and 40 CFR Part 63 and National Emission Standards for Hazardous Air Pollutants regulatory criteria will be met.

2 There are four gas producing wells per well pad. 3 DAQ assumed no recoverable condensate is present in the raw gas.4 For emission estimates the DAQ used the peak production estimate of 151,605 MMcf/yr gas,

from 247 gas producing wells.1

5 All processes are uncontrolled.

2 Process Description

This document describes the methods used to estimate air emissions from natural gas well production activities at the wellhead. Natural gas production is defined in 40 CFR Parts 60 and 633,4 as the phase that occurs between the wellhead and point of custody transfer to the natural gas transmission and storage segment, and not including natural gas processing plants. This segment includes the emission sources on a single well pad or associated with a single well pad. These emission sources include:

Blowdown venting/liquids unloading, Produced water, Wellhead compressor engines, Glycol dehydrators and associated

reboilers,

Pneumatic controllers, Heaters, and Fugitive losses from equipment leaks

The US EPA has created an Access-based 2011 Nonpoint Oil and Gas Emission Estimation Tool (the Tool)9

using data from a report prepared for the Central States Air Resources Agencies (CenSARA). The Tool is used to obtain equipment estimates, activity and emission factors.

In the body of this document, each activity has been defined with essential equipment, assumptions and references. Below is a brief description of each activity included in this report.

The activity of blowdown venting/liquids unloading occurs when liquid (water and hydrocarbons) builds up in the wellhead to the point where the well pressure can no longer lift the weight of the liquids in the well. The well is manually vented to maintain efficient production. Emissions were estimated based on average volume, gas composition and number of events amassed from the Tool. Plunger lifts can be used to facilitate the movement of the liquids out of the wellhead rather than manually ‘blowing down the well’. The plunger lift often minimized the need for manually blowing down the well but may not eliminate emissions unless the produced gas pressure can be maintained at a high enough level for consistent injection into a gas pipeline rather than venting to the atmosphere. For this report, these events are assumed not to have plunger lifts installed and to be uncontrolled.

Appendix B, Page 3Revised September 2015

Produced water is one of those fluids generated by the production well and is defined in this report as any water recovered from a production well. Storage tanks are utilized at well pads to store produced water and other fluids used in or generated by the well production process. The size of storage tanks that could be utilized at a production well for produced water varies from site to site and information on this source is limited. However, the total amount of storage space required for produced water can be estimated since there is a direct correlation between hydrocarbon production and long-term produced water generation at major shale plays. The produced water estimate for the Sanford Sub-basin was based on values from moderate produced water generating shale plays.

Another type of storage tank found at a well pad is condensate tanks. This report assumes that no recoverable condensate is present so condensate tanks were not estimated for the Sanford Sub-basin. It should be noted that in North Carolina, storage tanks are permitted as insignificant source if their emissions are less than 5 tons of criteria pollutants, primarily VOC in this case, and less than 1,000 pounds of hazardous air pollutants.

Wellhead compressor engines are required to raise the pressure from the well to pipeline pressure. There is typically one small engine per well pad fueled by recovered natural gas. Based on well operation information obtained from the Pennsylvania Department of Environmental Protection and data for compressor stations located in North Carolina, this report assumes a lean-burn engine. Equipment parameters were obtained from the Tool.

Glycol dehydrators are used to remove the water vapor entrained in the natural gas recovered from the well which must be removed from the natural gas prior to entering the pipeline. Glycol dehydrators use diethylene glycol or triethylene glycol’s chemical affinity for water to remove it by bringing the gas stream in contact with the glycol solution. The gas leaves the dehydrator relatively free of water. To recover and reuse the glycol from the water/glycol solution, an associated reboiler takes advantage of the lower boiling point of the water and heats up the solution to separate water as a vapor from the glycol liquid. VOC emissions from the dehydrator are dependent on the volume of gas that passes through it and benzene, ethylbenzene, toluene, xylene and methane are estimated based on that pollutants ratio to VOC. The North Carolina Oil and Gas Study final report2 estimated that NC natural gas wells would produce 151,605 million cubic feet (MMcf) of gas and that there would be 247 wells in the Sanford Sub-basin in Year 6. Therefore, the annual gas production for any one well is estimated as 614 MMcf (151,605 MMcf/basin divided by 247 wells/basin in Year 6). Reboiler emissions are associated with the combustion of natural gas to produce the heat used to separate the glycol/water solution.

Automatic pneumatic controllers are employed In order to maintain the correct pressure in the lines at shale gas wells. This equipment releases a small amount of gas as it operates. Federal regulations3,4 set the standard for these releases as 6.0 standard cubic feet per hour (scf/hr) for each controller. Conversely, the CenSARA national average (based on the average of the surveyed basins within the CenSARA states) release rate in the Tool is 3.15 scf/hr and this rate was used to estimate emissions.

Natural gas well sites use heaters to reduce the viscosity of fluids in storage tanks to facilitate loading. Capacity and number of these heaters used in emissions estimations were obtained from the Tool.

Appendix B, Page 4Revised September 2015

Numerous valves, connectors, flanges and open-ended lines are necessary for the operation of a natural gas well and they often leak and the emissions from these leaks were estimated using data obtained from the Tool.

Appendix B, Page 5Revised September 2015

3 Summary of EmissionsTable B-1. Criteria Pollutants, Greenhouse Gas and Hazardous Air Pollutant Emissions from Well Production

Criteria GHGsNOX VOC CO SO2 PM10 PM2.5 Methane CO2

Activity Source ton/well pad ton/well pad ton/well pad ton/well pad ton/well pad ton/well padton/well

pad ton/well padProduction

Blowdown Venting 0.02 1.96 0.10 9.65 0.33Produced Water Tanks 0.48 2.20 0.08

Wellhead Compressor Engines 4.46 0.62 2.93 3.10E-03 0.05 0.05 6.58 579.31Dehydrators Reboiler 2.02E-07 1.63 1.69E-07 1.21E-09 1.53E-08 1.53E-08 1.68 2.42E-04

Pneumatic Controllers 4.65E-02 2.29E-01 8.02E-02Heater 0.17 0.01 0.14 1.02E-03 0.01 0.01 3.92E-03 205

Fugitive Leak emissions 0.52 2.58Total Emissions ton/year 4.65 5.27 3.18 0.00 0.07 0.07 22.92 784

* NOx, CO and VOC Emissions subject to EPA 40 CFR Part 60, Subpart JJJJ and NESHAP Subpart ZZZZ** SO2 Emissions subject to EPA 40 CFR Subpart LLL- min. SO2 emission efficiency 74%

HAPS

Formaldehyde Acetaldehyde Acrolein Methanol Benzene Ethylbenzene Toluene Xylene Styrene

Activity Source ton/well pad ton/well pad ton/well pad ton/well padton/well

pad ton/well padton/well

padton/well

padton/well

padProduction

Blowdown Venting 1.11E-02 2.64E-03 1.01E-03 2.64E-03 8.54E-04Produced Water Tanks 6.88E-04 1.55E-05 2.78E-04 2.31E-04

Wellhead Compressor Engines 1.08E-01 4.40E-02 2.71E-02 1.32E-02 8.32E-03 1.31E-04 2.94E-03 1.03E-03 1.24E-04Dehydrators Reboiler 8.87E-10 3.27E-11 3.70E-11 3.76E-01 3.76E-03 4.51E-04 0.00E+00

Pneumatic Controllers 5.01E-04 1.05E-05 1.91E-04 1.62E-04Heater 7.50E-04 2.77E-05 3.13E-05 3.75E-04 1.88E-04

Fugitive Leak emissions 7.92E-04 3.06E-04 1.73E-05 2.59E-04

Total Emissions ton/year 0.12 0.04 0.03 1.32E-02 0.39 3.17E-04 3.98E-04 4.21E-04 1.24E-04

Appendix B, Page 6Revised September 2015

4 Emissions Activities and Key Assumptions

For North Carolina currently, there are no gas production wells. The CenSARA national average data was used to estimate well production equipment because there were too many unknowns regarding natural gas production in North Carolina. The CenSARA national average includes data from several basins and was considered more representative than estimates from a single basin.

4.1 Blowdown Venting/Liquids Unloading

This activity is the practice of venting gas from gas wells to prevent liquid build-up in the well that could limit production.

Assumptions and Activity Data:

Emissions are based on average venting volume per event, number of events per year and the gas composition of the vented gas from the Tool.

To estimate VOC, CO2, CH4 and BTEX: From the Tool documentation, the estimated volume of gas released during a blowdown event is converted from standard to actual conditions then multiplied by the pollutant fraction to get emission estimation per event. This emission estimation per event is then multiplied by the number of events per year to get an annual emission estimation for the specific pollutant.

Emissions= 1atm×Volume ventedRMW

×T×0.000035 McfL

× f907,185

Where;

R = Universal gas constant [0.082 L-atm/mol-K]

MW = molecular weight of gas [from the Tool, 19.648 g/mol]

T = atmospheric temperature [298 K]

f = mass fraction of pollutant

907,185 = unit conversion factor for g/ton

Appendix B, Page 7Revised September 2015

Table B-2. Emission factors used in emission estimation

Activity(events/

yr

Volume(Mscf/event)

VOCMass

fraction

MethaneMass

fraction

CO2

Mass fraction

BenzeneMass

fraction

EthylbenzeneMass fraction

TolueneMass

fraction

XyleneMass

fraction

22.2 6.14 0.142 0.699 0.024 2.17 E-4 8.29 E-5 4.57 E-6 7.01 E-5

To estimate NOx, CO and formaldehyde: The emission factor for these pollutants has units of pounds per MMBTU. These emissions were estimated by multiplying the number of events per well per year, the volume of gas emitted, an average heat content and the emission factor for the pollutant.

Table B-3. Venting related specifications used in emissions estimates

Activity, (events/y

r)

Volume, (Mscf/eve

nt)

Heat Content, (Btu/scf)

NOX

(lb/MMBtu)CO (lb/MMBtu) Formaldehyde

(lb/MMBtu)

22.2 6.14 1,020 0.07 0.37 0.04

Assumptions

CenSARA average basin and emission factors from the Tool were used to estimate emissions.

Emissions are uncontrolled.

4.2 Produced Water

Produced water is stored at natural gas well sites in storage tanks. Tank losses of VOC emissions are generated by working and breathing losses. Emissions from liquid storage tanks from working losses are generated during tank filling and draining (throughput/turnovers). Breathing loss is the loss due to daily fluctuations of temperature and pressure.

In this report, produced water refers to water returned to the surface through a well borehole during gas production (after well completion) and is a mixture of naturally occurring materials and fluids used in the drilling and hydraulic fracturing process. Produced water from a shale gas well generally occurs for the lifetime of the well; however, the quantity of produced water can vary significantly from different formations.

Assumptions and Activity Data

To calculate the emissions from produced water, the amount of produced water had to be estimated. There is a direct correlation between hydrocarbon production and long term produced water generation

Appendix B, Page 8Revised September 2015

in the major shale plays.5 The amount of produced water varies drastically in active shale gas plays. In Texas, the Barnett Shale wells generate the largest volume of produced water, greater than 1,000 gallons per million cubic feet (gal/MMcf); whereas Marcellus Shale wells produce the lowest amounts of produced water, less than 200 gal/MMcf in West Virginia, and approximately 25 gal/MMcf in Northern Pennsylvania. The Eagle Ford, Haynesville, and Fayetteville Shale plays generate a moderate amount of produced water, approximately 200 to 1,000 gal/MMcf. To estimate the emissions from produced water, the upper volume of moderate produced water generating plays of 1,000 gal/MMcf was used.

In Year 6, NC shale gas wells were estimated to produce a total of 151,605 MMcf and the estimated number of contributing wells was 247; therefore, the average gas flow rate from any one well was 614 MMcf for that year. The resulting estimate of produced water from NC wells is 614,000 gallons per year (gal/yr) [(1,000 gals/mmcf x 614 mmcf/yr) x(bbl/42 gals) = bbl/yr]. Assuming that a barrel is 42 gallons, then the number of barrels of produced water would be 14,619 bbl/yr.

Emission factors were not available for pollutants emitted from this activity. However, the methane loss in pounds per barrel (lb/bbl) and the molar percentage of VOC, CO2, and methane (CH4) in produced water were available in the Tool. Molar percentages for benzene, ethylbenzene, toluene and xylene were estimated using a ratio of their molar percent to the molar percent of CH4.

For example:

VOC tonsyr

=CH 4 tonsyr

×MWVOC

MW CH 4×M%VOC

M%CH 4

Table B-4. Typical composition values and emission ratios used to estimate emissions

Estimated average

annual gas flow rate

(MMcf/yr)

Produced water

estimate (gal/MMcf)

CH4

(lb/bbl)

CH4

(molar%)VOC

(molar%)CO2

(molar%)Benzene (molar%)

Ethyl benzene (molar%)

Toluene (molar%)

Xylene (molar%)

614 1,000 0.11 0.84 0.05 0.01 5.42E-05 8.97E-07 1.86E-05 1.34E-05

Assumptions

Assumed Sanford Sub-basin would be a moderate produced water generating play and would produce 1,000 gallons of produced water per MMcf of gas.

Assumed average values from the Tool for all emitted pollutants (molar percentages) and the molecular weight of VOC from produced water which was estimated at 55.33 grams/mole.

Emissions are uncontrolled.

Appendix B, Page 9Revised September 2015

4.3 Wellhead Compressor Engines

Wellhead compressor engines are typically small natural gas-fired internal combustion engines used to boost the produced natural gas from borehole pressure to the required pressure for the pipeline and are located at the well pad. These engines are categorized into rich-burn or lean-burn. For this report, all wellhead compressors are assumed to be lean-burn.

Assumptions and Activity Data:

The DAQ assumed that all compressors at the well pads were;o lean-burn6, o use natural gas fuel and o the emissions are uncontrolled.

The DAQ also assumed that there would be one compressor engine needed for each well pad (four wells per well pad).

Emission factors and calculation equations for this activity were extracted from the Arkoma basin factors in the Tool.

Equation estimating emissions for wellhead compressor engines:

Emissions= EF×Capacity× LF×Hrs907,185

×number of engines

Where:Emissions = tpyEF = Emission Factor (g/hp-hr) Capacity = Engine capacity (hp)LF = Load factor (%)Hrs = Hours of engine operation (hr)907,185 = conversion from g to tons

Table B-5. Engine specifications used in emissions estimates

Capacity (hp)

Hours of operation (hr)

Load Factor (%)

242 8,370 65

Appendix B, Page 10Revised September 2015

Table B-6. Emission factors Criteria Air Pollutants used for emission estimates (g/hp-hr)

NOX VOC PM10 PM2.5 CO SO2

3.07 0.43 0.04 0.04 2.02 2.1E-03

Table B-7. Emission factors Hazardous Air Pollutants used for emission estimates (g/hp-hr)

Benzene Ethyl benzene Hexane Toluene Xylene Formaldehyde

5.7E-03 1.0E-04 4.0E-03 2.0E-03 7.0E-04 7.4E-02

4.4 Glycol Dehydrators and associated Reboiler

Produced natural gas is normally saturated with water. If not removed, the water can condense and/or freeze in gathering, transmission, and distribution piping causing plugging, pressure surges, and corrosion. To avoid these problems, the produced gas is typically sent through a dehydrator where it contacts a dewatering agent. Glycol dehydrators absorb water from a wet gas stream using one of two glycol compounds which have hydrophilic properties, either diethylene glycol (DEG) or triethylene glycol (TEG). Having been stripped of water vapor, the gas stream leaves the dehydrator. The absorbed water and hydrocarbons (CH4, VOC and HAPs) are then boiled off in a reboiler/regenerator and vented to the atmosphere, or controlled by a flare. With the water removed from the glycol solution, the glycol solution can be reused in the dehydration process. Regeneration of the glycol solutions used for dehydrating natural gas can release benzene, toluene, ethylbenzene, and xylene (BTEX), as well as a wide range of less toxic organics. See Figure 1 below.

Appendix B, Page 11Revised September 2015

Figure 1. Glycol Dehydrator Schematic7

Assumptions and Activity Data:

The CenSARA average vented VOC emission factor was used to estimate dehydrator emissions because there are no production wells in NC and this average value appears to be a conservative estimate from the Tool. The emission factor for VOC is reported as standard conditions and the standard temperature and pressure used in this report are the National Institute of Standards and Technology (NIST) standards (293.15 K and 101.325 kPa respectively). Based on NC Climate office data, the annual average temperature for the Sanford area is 60.3 degrees F (288.9 K). The elevation is 262 feet above sea level so the pressure is 100.9 kPa. Emission estimates were adjusted from standard conditions to actual North Carolina average conditions (see Table B-8).

Benzene, ethylbenzene, toluene, xylene and CH4 emissions for the dehydrator are reported as a ratio to VOC emissions (see Table B-9). Therefore, VOC emissions were estimated, and then the value was multiplied by the appropriate ratio to estimate the emissions of benzene, ethylbenzene, toluene, xylene and methane.

Table B-8 shows combustion related emission factors for the reboiler.

Appendix B, Page 12Revised September 2015

Table B-8. Dehydrator and reboiler specifications used in emissions estimates

Vented VOC (lb/MMscf)

Reboiler rating

(MMBtu/hr)

Lower Heating Value(LHV)

(Btu/scf)

Operating hours(hr)

8.01 0.58 1131.12 7,837

Table B-9. Emission ratios to VOC emissions used in emissions estimates for the dehydrator

Benzene Ethylbenzene Toluene Xylene CH4

0.23 0.01 0.12 0.46 1.03

Table B-10. Emission factors (lbs/MMcf) for the reboiler associated with the dehydrator

NOX VOC PM10 PM2.5 CO SO2 BenzeneHexan

e Toluene Xylenes CH4 Formaldehyde

100 5.5 7.6 7.6 84 0.6 0.22 1.8 0.11 0 2.3 0.44

Assumptions:

one dehydrator/reboiler per well pad. For this report, it is assumed that there are four wells per well pad.

Used estimated well gas volume of 614 MMcf per well2

Used lower heat values of 1,131 Btu/scf to estimate throughput for reboiler.

4.5 Pneumatic Controllers

Pneumatic controllers may release gas because they are “automated instruments used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature”3 at well sites. These controllers often are powered by high-pressure natural gas and may release gas as part of their normal operations. Under NSPS Subpart OOOO regulations, this release or bleed rate for low bleed pneumatics must be less than or equal to 6 standard cubic feet per hour (scf/hr) for each controller at the wellhead.4

Assumptions and Activity Data:

The number of controllers and bleed rates were obtained from the Tool using US GHG Inventory default values. The bleed rate was adjusted to actual conditions using the same methodology as noted for the

Appendix B, Page 13Revised September 2015

Glycol dehydrators, Section 4.4. The total emissions for pneumatic controllers is the sum of all the potential controllers at the well (low bleed, high bleed and intermediate bleed) (see Table B-11).

The molecular weight of released gas used to estimate emissions is the average value from the Tool.

Although molecular weight was calculated for gas samples in the Sanford Sub-basin, it was not used to estimate emissions due to small sample size. Molecular weight (MW) fractions of VOC, carbon dioxide and methane are the CenSARA average values used in the Tool.

Benzene, ethylbenzene, toluene, xylene and CH4 emissions for the pneumatic controllers are reported as a ratio to VOC emissions (see Table B-12).. Therefore, VOC emissions were estimated, and then the value was multiplied by the appropriate ratio to estimate the emissions of benzene, ethylbenzene, toluene, xylene and CH4.

Table B-11. Pneumatic Controller specifications used in emission estimates

Type of Controller

Number of Controllers per well

Bleed Rate (scf/hr)

Molecular Weight of gas released (g/mol)

Low Bleed 0.144 1.39 19.65

High Bleed 0.222 37.3 19.65

Intermediate Bleed

0.12 13.5 19.65

Table B-2. Emission ratios of gas released

VOC MW fraction

CO2 MW fraction

Methane MW

fraction

Benzene to VOC

ratio

Ethylbenzene to VOC

ratio

Toluene to VOC

ratio

Xylene to VOC ratio

0.142 0.0245 0.699 1.5E-03 3.2E-05 5.8E-04 4.9E-04

Assumptions

Assumed values for VOC, CO2 and CH4 MW fractions are CenSARA average basin factors from the Tool.

Assumed emission factors for benzene, ethylbenzene, toluene and xylene are taken from the Tool and are CenSARA average values.

Appendix B, Page 14Revised September 2015

4.6 Heaters

Natural gas-fired external combustion engines are used to: 1) heat the separators which separate the natural gas liquids using their different boiling points, or 2) to provide heat for tanks to decrease the viscosity of the produced water and facilitate transfer of the liquid.

Assumptions and Activity Data

The CenSARA average equipment values from the Tool were used to estimate emissions for NC wells.

Activity level was calculated by multiplying the number of heaters by heat rating and by the hours operated. Activity level in MMBtu/yr was converted to MMcf/yr using the assumed heating value of 1030 Btu/cf.

Since these heaters are uncontrolled, the activity was multiplied by the appropriate emission factor from the Tool for a pollutant to estimate those emissions.

Table B-33. Heater specifications used in emission estimates

Rating, (MMBtu/hr)

Number of heaters* per

pad

OperatingHours

0.64 0.62 8,760

*Average value derived from the Tool

Table B-44. Emission factors used in emission estimations (lb/MMcf)

NOX VOC PM10 PM2.5

CO SO2 Benzene

Hexane Toluene Formaldehyde

100 5.50 7.60 7.60 84 0.60 0.22 1.80 0.11 0.44

Assumptions

Assumed CenSARA average basin factors from the Tool for equipment values.

Assumed heaters operate at maximum capacity.

Assumed heaters are uncontrolled.

Appendix B, Page 15Revised September 2015

4.7 Fugitive Losses from Equipment Leaks

Connectors, flanges, open-ended lines, valves and compressor wet seals contribute to emissions from produced gas leaks from various equipment at the well pad.

Assumptions and Activity Data

The number of fugitive leak sources was obtained from theTool. The numbers of a specific source is multiplied by annual hours of operation and emission factor for Total Organic Carbon (TOC). Then the TOC for the individual sources are summed to get TOC total for all fugitive leak sources.

VOC, hydrogen sulfide (H2S), benzene, ethylbenzene, toluene, xylene and CH4 emissions for fugitive leaks are reported as a ratio to TOC emissions. Therefore, TOC emissions were estimated, and then the value was multiplied by the appropriate ratio to estimate the emissions of VOC, H2S, benzene, ethylbenzene, toluene, xylene and CH4.

Table B-55. Fugitive specifications used in emission estimates

Number of Valves

Number of Connectors

Number of Flanges

Number of Open Ended Lines

Annual Hours

Equipment 12 35 18 6 8,760TOC emission factor, kg/each component-hr 4.5E-03 2.0E-04 3.9E-04 2.0E-03

Table B-66. Emission ratios used in emission estimates

VOC to TOC

H2S to TOC

Methane to TOC

Benzene to TOC

Ethylbenzene to TOC

Toluene to TOC

Xylene to TOC

0.04 2.89E-06 0.91 No value No value No value No value

Assumptions

Used CenSARA average basin factors from the Tool for equipment numbers for valves, connectors, flanges and open lines.

Appendix B, Page 16Revised September 2015

5 References

Appendix B, Page 17Revised September 2015

1 “Natural Gas Potential of the Sanford Sub-basin, Deep River Basin, North Carolina”, Jeffrey C. Reid, Kenneth B. Taylor, Paul E. Olsen, and O. F. Patterson, III, Search and Discovery Article #10366 (2011) Posted October 24, 2011. http://www.searchanddiscovery.com/documents/2011/10366reid/ndx_reid.pdf

2 North Carolina Oil and Gas Study under Session Law 2011-276, Prepared by the North Carolina Department of Environment and Natural Resources and the North Carolina Department of Commerce, April 30, 2012.

3 40 CFR Parts 60 and 63: New Source Performance Standards (Subpart OOOO) and National Emission Standards for Hazardous Air Pollutants (Subparts HH and HHH); Final Rule, Federal Register Volume 77, No. 159, August 16, 2012. http://www.gpo.gov/fdsys/pkg/FR-2012-08-16/html/2012-16806.htm

4 Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution. Background Supplemental Technical Support Document for the Final New Source Performance Standards, US EPA, Office of Air and Radiation, Office of Air Quality Planning and Standards, April 2012.

5 ‘Proceedings of the Technical Workshops for the Hydraulic Fracturing Study: Water Resources Management’, EPA 600/R-11/048, US EPA, Office of Research and Development, May 2011.

6 Personal phone conversation with Michael Rudawski, Pennsylvania Department of Environmental Protection. May 2013.

7 http://images.pennwellnet.com/ogj/images/ogj3/9725jga01.gif

9 2011 Nonpoint Oil and Gas Emission Estimation Tool, U.S. EPA, November 21, 2014