NC DIVISION OF AIR QUALITY
Appendix B
Production Phase
September 2015
Appendix B, Page 1
Revised September 2015
Table of Contents
List 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
5
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
References .......................................................................................................................................... 17
List of Tables
Table B-1. Criteria Pollutants, Greenhouse Gas and Hazardous Air Pollutant Emissions from Well
Production..................................................................................................................................................... 6
Table B-2. Emission factors used in emission estimation………………………………………………………………………….8
Table B-3. Venting related specifications used in emissions estimates…………………………………………………....8
Table B-4. Typical composition values and emission ratios used to estimate emissions ............................. 9
Table B-5. Engine specifications used in emissions estimates.................................................................... 10
Table B-6. Emission factors Criteria Air Pollutants used for emission estimates (g/hp-hr) ........................ 11
Table B-7. Emission factors Hazardous Air Pollutants used for emission estimates (g/hp-hr)................... 11
Table B-8. Dehydrator and reboiler specifications used in emissions estimates ....................................... 13
Table B-9. Emission ratios to VOC emissions used in emissions estimates for the dehydrator ................. 13
Table B-10. Emission factors (lbs/MMcf) for the reboiler associated with the dehydrator ....................... 13
Table B-11. Pneumatic Controller specifications used in emission estimates............................................ 14
Table B-12. Emission ratios of gas released ................................................................................................ 14
Table B-13. Heater specifications used in emission estimates ................................................................... 15
Table B-14. Emission factors used in emission estimations (lb/MMcf) ...................................................... 15
Table B-15. Fugitive specifications used in emission estimates ................................................................. 16
Table B-16. Emission ratios used in emission estimates............................................................................. 16
Appendix B, Page 2
Revised September 2015
1
Overall Assumptions for the Production Phase
1
2
3
4
5
2
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.
There are four gas producing wells per well pad.
DAQ assumed no recoverable condensate is present in the raw gas.
For emission estimates the DAQ used the peak production estimate of 151,605 MMcf/yr gas,
from 247 gas producing wells.1
All processes are uncontrolled.
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.
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
Appendix B, Page 3
Revised September 2015
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 4
Revised 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 5
Revised September 2015
3 Summary of Emissions
Table B-1. Criteria Pollutants, Greenhouse Gas and Hazardous Air Pollutant Emissions from Well Production
Criteria
Activity
Source
GHGs
NOX
VOC
CO
SO2
PM10
PM2.5
Methane
CO2
ton/well pad
ton/well pad
ton/well pad
ton/well pad
ton/well pad
ton/well pad
ton/well pad
ton/well pad
9.65
2.20
6.58
1.68
2.29E-01
3.92E-03
2.58
0.33
0.08
579.31
2.42E-04
8.02E-02
205
Production
Blowdown
Produced Water
Wellhead Compressor
Dehydrators
Pneumatic
Fugitive Leak
Total Emissions
Venting
Tanks
Engines
Reboiler
Controllers
Heater
emissions
ton/year
0.02
4.46
2.02E-07
0.17
4.65
1.96
0.48
0.62
1.63
4.65E-02
0.01
0.52
5.27
0.10
2.93
1.69E-07
3.10E-03
1.21E-09
0.05
1.53E-08
0.05
1.53E-08
0.14
1.02E-03
0.01
0.01
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
Activity
Source
Formaldehyde
Acetaldehyde
Acrolein
Methanol
Benzene
Ethylbenzene
Toluene
Xylene
Styrene
ton/well pad
ton/well pad
ton/well pad
ton/well pad
ton/well
pad
ton/well pad
ton/well
pad
ton/well
pad
ton/well
pad
8.54E-04
2.31E-04
1.03E-03
0.00E+00
1.62E-04
1.24E-04
4.21E-04
Production
Blowdown
Produced Water
Wellhead Compressor
Dehydrators
Pneumatic
Fugitive Leak
Venting
Tanks
Engines
Reboiler
Controllers
Heater
emissions
Total Emissions
ton/year
1.11E-02
1.08E-01
8.87E-10
4.40E-02
3.27E-11
2.71E-02
3.70E-11
7.50E-04
2.77E-05
3.13E-05
0.12
0.04
0.03
Appendix B, Page 6
Revised September 2015
1.32E-02
1.32E-02
2.64E-03
6.88E-04
8.32E-03
3.76E-01
5.01E-04
3.75E-04
7.92E-04
1.01E-03
1.55E-05
1.31E-04
3.76E-03
1.05E-05
3.06E-04
2.64E-03
2.78E-04
2.94E-03
4.51E-04
1.91E-04
1.88E-04
1.73E-05
0.39
3.17E-04
3.98E-04
2.59E-04
1.24E-04
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 =
1 𝑎𝑡𝑚 × 𝑉𝑜𝑙𝑢𝑚𝑒 𝑣𝑒𝑛𝑡𝑒𝑑
𝑓
×
𝑀𝑐𝑓
𝑅
907,185
𝑀𝑊 × 𝑇 × 0.000035 𝐿
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 7
Revised September 2015
Table B-2. Emission factors used in emission estimation
Activity
(events/
yr
Volume
(Mscf/
event)
VOC
Mass
fraction
Methane
Mass
fraction
CO2
Mass
fraction
Benzene
Mass
fraction
Ethylbenzene
Mass fraction
Toluene
Mass
fraction
Xylene
Mass
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/yr
)
Volume,
(Mscf/eve
nt)
Heat Content,
(Btu/scf)
22.2
6.14
1,020
NOX
(lb/MMBtu)
CO (lb/MMBtu)
Formaldehyde
(lb/MMBtu)
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 8
Revised 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 𝑡𝑜𝑛𝑠
𝐶𝐻4 𝑡𝑜𝑛𝑠
𝑀𝑊𝑉𝑂𝐶 𝑀%𝑉𝑂𝐶
=
×
×
𝑦𝑟
𝑦𝑟
𝑀𝑊𝐶𝐻4 𝑀%𝐶𝐻4
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%)
614
1,000
0.11
0.84
VOC
(molar%)
0.05
CO2
(molar%)
Benzene
(molar%)
Ethyl
benzene
(molar%)
Toluene
(molar%)
0.01
5.42E-05
8.97E-07
1.86E-05
Xylene
(molar%)
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 9
Revised 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 =
Where:
Emissions =
EF =
Capacity =
LF =
Hrs =
907,185 =
𝐸𝐹 × 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 × 𝐿𝐹 × 𝐻𝑟𝑠
× 𝑛𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑒𝑛𝑔𝑖𝑛𝑒𝑠
907,185
tpy
Emission Factor (g/hp-hr)
Engine capacity (hp)
Load factor (%)
Hours of engine operation (hr)
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 10
Revised 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)
4.4
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
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 11
Revised 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 12
Revised 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
100
5.5
7.6
7.6
84
0.6
Benzene Hexane Toluene Xylenes
0.22
1.8
0.11
0
CH4
Formaldehyde
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 13
Revised 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 14
Revised 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
Operating
Hours
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
100
5.50
7.60
7.60
84
0.60
Benzene Hexane Toluene Formaldehyde
0.22
1.80
0.11
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 15
Revised September 2015
0.44
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
Equipment
TOC emission factor,
kg/each component-hr
Number
Number of of
Connectors Flanges
Number of
Open Ended
Lines
12
35
18
6
4.5E-03
2.0E-04
3.9E-04
2.0E-03
Annual
Hours
8,760
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 16
Revised September 2015
5
1
References
“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-2012-0816/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
Appendix B, Page 17
Revised September 2015