appendix avibe.cira.colostate.edu/ogec/docs/north carolina... · web viewin addition, large volumes...

NC Division of air Quality

Appendix A

Development Phase

September 2015

Appendix A, Revised September 2015

Table of Contents

1 Overall Assumptions for Development Phase.....................................................................................4

2 Process Description.............................................................................................................................4

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

4 Emissions Activities and Key Assumptions...........................................................................................8

4.1 Site Preparation: Land Clearing....................................................................................................8

4.1.1 Potential Emission Sources..................................................................................................8

4.1.2 Estimate of Emissions..........................................................................................................8

4.2 Transportation...........................................................................................................................10

4.2.1 Potential Emissions Sources...............................................................................................10

4.3 Unpaved Roads..........................................................................................................................15

4.3.1 Potential Emission Sources................................................................................................15

4.4 Drilling.......................................................................................................................................17


4.4.2 Estimate of Emissions........................................................................................................19

4.5 Drilling Mud Storage..................................................................................................................20



4.6 Hydraulic Fracturing...................................................................................................................21



4.7 Well Completion........................................................................................................................23


4.7.2 stimate of Emissions..........................................................................................................24

5 References.........................................................................................................................................26

List of Tables

Table A-1. Criteria Pollutants and Greenhouse Gas Emissions from Well Development.............................6

Table A-2. Hazardous Air Pollutant Emissions from Well Development......................................................7

Table A-3. Estimate of Emissions from Land Clearing................................................................................10

Appendix A, Revised September 2015

PUBLIC COMMENT DRAFT

Table A-4. US EPA Definitions of Light Duty and Heavy-Duty Truck Gross Vehicle Weight Class...............11

Table A- 5. US Truck Fleet by Fuel Type…………………………….…………………………………………………………….………11

Table A-6. Summary of Average Number of Truck Trips and Miles Traveled during Well Development...12

Table A-7. Estimated Vehicle Miles Travelled for Development of One Well............................................13

Table A-8. Average Engine Emission Rates by Pollutant and Vehicle Type6,7...........................................13

Table A-9. Average Truck Idle Time per Well Development......................................................................13

Table A-10. Average Idle Emission Rates by Pollutant for All Vehicle Types..............................................14

Table A-11. Total Emissions from Truck Trips and Idling per Well Development......................................15

Table A-12. Vehicle Miles of Unpaved Road Traveled per Vehicle Type....................................................16

Table A-13. Emission Factor Parameters for PM10 Emissions from Travel on Unpaved Roads..................16

Table A-14. Fugitive Dust Emissions from Travel on Unpaved Roads........................................................17

Table A-15. Shale Formation Comparison between NC and other states in US………………………………………18

Table A-16. Drilling Equipment..................................................................................................................20

Table A-17. Emission Factors for Criteria Air Pollutants, Drilling Activity..................................................20

Table A-18. Emission Factors for Hazardous Air Pollutants, Drilling Activity.............................................20

Table A-19. Emission Factors and Molar Percentages Used to Estimate Emissions...................................21

Table A-20. Hydraulic Fracturing Pump Specifications..............................................................................23

Table A-21. Emission Factors for Criteria Air Pollutants, Hydraulic Fracturing Activity.............................23

Table A-22. Emission Factors for Hazardous Air Pollutants, Hydraulic Fracturing Activity........................23

Table A-23. Volume Percent by Pollutant..................................................................................................25

Table A-24. VOC to BTEX Ratios for Dehydrator Emissions........................................................................25

Table A-25. Reboiler Activity Data………………………………………………………………………………………………………..…25

Table A-26 Reboiler Emission Factors……………………………………………………………………………………………………..25

Appendix A, page 3


1 Overall Assumptions for Development Phase

Wells will meet emissions requirements in 40 CFR Parts 60 and 63, Oil and Natural Gas Sector; New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants.

Horizontal drilling techniques are employed (i.e., vertical drilling occurs until the well bore is near the shale formation, then horizontal drilling occurs through the shale formation.

Each pad contains 4 wells Non-road engines are used for drilling and pumping activities Hydraulic fracturing techniques are employed Reduced Emissions Completions (Green Completions) will be employed to control flowback

emissions per 40 CFR 60 Subpart OOOO. No electrification of drilling pads.

2 Process Description

Development of natural gas wells involves the various activities to construct and operate the well. Activities in natural gas development include the following:

Exploration, Leasing, and Permitting Site Preparation Transportation of Equipment, Supplies,

and Waste

Well Drilling and Casing Well Perforation and Hydraulic Fracturing Well Completion

This Appendix discusses estimating emissions from site preparation, transportation, and well drilling, fracturing, and completion. Emissions from exploration and its associated activities are not addressed. Well development activities in the Sanford Sub-basin will be performed by many different companies and crews of workers, including construction crews, drilling crews, transporters, and pipeline companies. The companies may choose a variety of approaches to complete their work. Therefore, significant changes to the emissions estimates presented in this section may occur as plans to develop the shale gas field become more definite. Currently North Carolina does not have any natural gas production wells. Any well development activity will be subject to both 40 CFR Parts 60 and 63, Oil and Natural Gas Sector; New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews and any existing applicable state regulations.

Development activities are generally conducted sequentially; therefore the emissions from each activity, such as pad development, drilling, and fracturing, do not occur at the same time. The total emissions impact to Sanford, Moore and Lee Counties is a function of the number of wells drilled simultaneously.

There is a possibility that both vertical wells (drilling only vertically) and horizontal wells (drilling first vertically then horizontally) could be drilled within the basin. For this study, the DAQ assumed all wells were drilled horizontally since this was the assumption used by Dr. Ken Taylor to derive Table 2 Annual

Appendix A, page 4


Gas Production Estimate of the Narrative. As discussed previously, under this scenario, 121 new wells are developed in the Sanford Sub-Basin during Year 6 which is the maximum production year. Each of the activities associated with well development will be discussed in greater detail in the following sections.

Appendix A, page 5


3 Summary of Emissions

Table A-1. Criteria Pollutants and Greenhouse Gas Emissions from Well Development

Activity Source

Criteria Pollutants Greenhouse GasesNOX VOC CO SO2 PM10 PM2.5 CH4 CO2

ton/well ton/well ton/well ton/well ton/well ton/well ton/well ton/wellNot Permitted

Land clearing 0.13 0.13Unpaved Roads 1.3 1.3

Truck trips 0.92 0.08 0.56 N/A** 0.02 0.02Truck idling 0.84 0.15 1.05 0.002 0.02 0.02

PermittedDrilling Horizontal wells 2.51 0.15 0.59 4.57E-03 0.10 0.10

Drilling Mud Storage 0.07 5.82Hydraulic Fracturing 1.8 0.11 0.41 3.09E-03 0.07 0.07

Green Well Completion 2.3E-03 5.15E-02Total Emissions (ton/well) 6.08 0.57 2.61 0.01 1.65 1.64 5.88 N/A**

*Assigned based on PM10**No published EF identified

Appendix A, page 6


Table A-2. Hazardous Air Pollutant Emissions from Well Development

Activity SourceHAPS

Formaldehyde Acetaldehyde Acrolein Methanol Benzene Ethylbenzene Toluene Xylene Hexane Styreneton/well ton/well ton/well ton/well ton/well ton/well ton/well ton/well ton/well ton/well

Not PermittedƗ

Land clearingUnpaved Roads

Truck tripsTruck idling

PermittedDrilling Horizontal wells 0.010 0.011 1.62E-03 2.77E-04 2.35E-03 1.87E-03 3.10E-04 9.30E-05Drilling Mud StorageHydraulic Fracturing 9.6E-03 1.19E-03 2.04E-04 1.73E-03 1.37E-03 2.28E-04 6.83E-05

Green Well Completion 3.10E-06 6.19E-08 1.86E-06 6.19E-07 9.60-05Total Emissions (tpy) 0.020 0.011 2.81E-03 4.81E-04 4.08E-03 3.24E-03 6.34E-04 1.61E-04

Ɨ HAP emission factors were not available for Not Permitted activities

Appendix A, page 7


4 Emissions Activities and Key Assumptions

4.1 Site Preparation: Land Clearing

A shale gas well requires a prepared area on the surface or a paved pad that provides a stable base for a drill rig and its support equipment, engines to power the rig, fuel storage, retention ponds for drilling fluids, water storage tanks, truck loading areas, and associated piping. The size of the pad depends on the depth of the well, the number of wells drilled on the site, the size of retention ponds and/or storage tanks, and the area required for storing equipment. In addition, access roads are constructed to support transportation of equipment and supplies to the well. These roads are usually unpaved since they are temporary and the land will be reclaimed after the well has been abandoned. Lastly, pipelines are constructed to transport the raw gas from the well to a processing plant, distribution system, or end user.

4.1.1 Potential Emission Sources As stated previously, site preparation includes all activities associated with constructing roads, well pads, pipelines, and other infrastructure. Potential sources of emissions include;

1) fugitive dust from clearing land, 2) engine emissions from construction equipment3) emissions from burning of vegetation4) transportation of site workers

Construction operations are significant source of dust emissions that may have a substantial short-term impact on local air quality. Dust emissions during the construction of well pads or roads are associated with land clearing, and earth moving operations (cut and fill). Dust emissions can vary substantially from day to day, depending on the level of activity, the type operation, and the meteorological conditions.

The DAQ estimated particulate material with a diameter less than 10 microns (PM10) fugitive dust emissions from land clearing for this report. This included assessing the impact of land clearing for constructing well pads, utility pipeline and roads.

The clearing of land for the construction of new roads often results in debris consisting of trees, shrubs, and brush. This debris is often collected in piles and burned. North Carolina open burning rules would apply. The DAQ did not estimate particulate matter emissions from the burning of cleared vegetation since estimates of the activity data, and its duration were not readily available.

Engine emissions from construction equipment were not estimated since it is difficult to estimate the actual number and type of equipment that would be employed at a given time for this activity. Transportation of site workers was also not evaluated since there are many unknowns associated with this activity such as how far the average site worker would commute and the average number of workers required for a given activity.

Assumptions and Activity DataFugitive dust emissions from land clearing are a function of the acreage cleared. In a shale gas fracturing report, the U.S. Department of Energy (US DOE) estimated that a typical horizontal well pad with only one well would be approximately 3 to 4 acres in size1. If multiple horizontal wells are completed from a

Appendix A, page 8


single well pad, the pad size would increase to 5 to 7 acres1. However, under the latter scenario, fewer well pads are constructed. It takes several days to several weeks to construct a well pad depending on the size and design requirements.

The area cleared for access roads depends on the well pad’s proximity to public roads. The U.S. Department of the Interior (US DOI) estimated that for the Fayetteville shale basin, located in Arkansas, approximately 0.10 miles of road and 0.55 miles of utility corridor would be required to support a well which is approximately 3.4 acres in total area1.

The DAQ assumed that 4 wells were constructed per pad for a total of 92 pads. For each well pad, the DAQ assumed an average of 6 acres of land is cleared for the well pad and 3.4 acres of land is cleared for road and utility corridor construction. This study also assumes the duration of the activity is 2 weeks.

State and Federal Regulations

There are no federal rules associated with fugitive dust emissions from land clearing and construction.

North Carolina allows burning of vegetation from land clearing. However, a permit is required and there are other restrictions and conditions related to air quality which may apply to a given activity. North Carolina Administrative Code Title 15A Environment and Natural Resources, Subchapter 2D-Air Pollution Control Requirements, Section 0.190026 contains the rules for open burning26. Note there have been changes to this rule in recent years.

Emission Factors and Estimates

A general emission factor for all types of construction activity is 0.11 tons PM10/acre-month. This factor is based on a 1996 study conducted by Midwest Research Institute (MRI) for the California South Coast Air Quality Management District (SCAQMD)2. The composite factor of 0.11 tons PM10/acre-month assumes that all construction activity produces the same amount of dust on a per acre basis. In other words, the amount of dust produced is not dependent on the type of construction but merely on the area of land being disturbed by the construction activity.

Table A-3 given below presents activity data, emission factors and fugitive dust emissions of PM10 from land clearing for one well. This estimate will increase substantially as emissions from laying pipelines are added once that activity becomes more defined. Emissions data is given as tons per day averaged over a 14-day period.

Appendix A, page 9


Table A-3. Estimate of PM Emissions from Land Clearing Per Pad and Per Well

Activity Emission Factor ton/acre-month

Area Cleared

acresDurationmonths

PM10 Emissions

ton/pad ton/wellwell pad 0.11 6 0.5 0.33 0.08road 0.11 3.4 0.5 0.19 0.05Total 0.52 0.13

4.2 Transportation

Development of shale gas wells creates episodic truck traffic, or significant short-term increases in traffic volume on local roads. Large amounts of drilling, hydraulic fracturing, and production equipment must be transported to the well pad. In addition, large volumes of materials will need to be delivered to the well pad, such as diesel fuel for running drills and pumps, water for fracturing, and sand or other proppants1 for fracturing. Lastly, waste materials (both solid and liquid) must be transported away from the site for disposal. The amount of truck traffic is proportional to the depth of the well being drilled.

The drilling and fracturing equipment is only needed for a short time period and must be removed from the site once the activity is completed. Some of the equipment may be moved from well pad to well pad as development occurs. This would reduce the transportation emissions per well as the basin is developed.

There are many unknowns in the sources of equipment, water, and other materials and how far they would need to be transported. The DAQ chose to estimate the amount of truck traffic for the total well development activity using estimates from other shale gas well development sites. These data are also being used by the NC Department of Transportation to estimate local infrastructure impacts19.

4.2.1 Potential Emissions Sources

The primary sources of emissions for transportation include the following sources:

Large trucks to haul equipment Tanker trucks for water and wastewater Trucks and cargo vans for materials Truck idling emissions Railroad engine emissions Site worker traffic

In the 2012 DENR report, it was assumed that water would be transported from the water source to the well pad by truck for the first several years3. During the middle to late stages of well field development,

1 A solid material, typically treated sand or man-made ceramic materials

Appendix A, page 10

The DAQ assumed water required for fracturing is transported to the well site via truck.


the water may be delivered by pipeline, if economically feasible. For this study, the DAQ assumed that all the water is delivered by truck.

In addition to vehicle travel on roads, the trucks are assumed to idle at the well pad for significant periods of time. Idling of large diesel engines used for transportation of supplies, in addition to the engines required for drilling and fracturing, results in emissions of criteria and hazardous air pollutants and can impact site workers.

Much of the equipment and materials will be transported from manufacturing facilities by rail to local rail depots and from rail depots by trucks to the well pads. The DAQ did not estimate the increase in emissions due to diesel railroad engines since this data was not readily available.

Site worker commuting was also not estimated for this study. The number of site workers and the average distance they would travel for a given development activity is not documented in the reports reviewed for this study. In addition, site worker commuting is not expected to have a significant impact compared to the average emissions estimated for trucks.

Assumptions – Vehicle Types

The types of vehicles and machinery most commonly used during well development by class are:

Light Duty Vehicle employee vehicles Light Duty Vehicle delivery vehicles and trucksHeavy Duty Vehicle specialized cement equipment and vehicles Heavy Duty Vehicle flatbed tractor trailers Heavy Duty Vehicle trucks to transport water, sand and chemicals

Some of these trucks can weigh as much as 80,000 to 100,000 pounds when fully loaded3. Only the light duty truck and heavy duty truck trips to transport equipment and materials were estimated.

The US EPA classes vehicles by gross vehicle weight rating (GVWR). There are two basic classes of vehicles based on GVWR. Light duty trucks are up to 10,000 pounds in GVWR. Heavy duty trucks range from over 10,000 pound GVWR to upwards of 80,000 pounds GVWR. Table A- 4 shows the US EPA truck classification system. These definitions are used to assign emission factors to the truck trips. The US EPA further breaks down the heavy duty vehicle class into 8 categories. These more detailed heavy duty truck classifications were not used since information on the weight of trucks was not available for this study.

Table A-4. US EPA Definitions of Light Duty and Heavy-Duty Truck Gross Vehicle Weight Class

GVWR Class Truck Weight and Definition

LDGT Light-duty gasoline trucks, up to 8,500 lb GVWR (pick-up trucks, vans, sport-utility vehicles)

LDDT Light-duty diesel trucks up to 10,000 lb GVWT (full-size pick-up trucks, large vans)

HDGV Heavy-duty gasoline vehicles, over 8,500 lb GVWR

HDDV Heavy-duty diesel vehicles, over 10,000 lb GVWR

Appendix A, page 11


The number of light duty and heavy duty vehicles using either diesel or using gasoline is based on data contained in the 2012 Annual Energy Outlook (AEO), Reference Case published by the Energy Information Administration (EIA)23. The AEO data tables indicate that 38% of all light duty trucks are use diesel fuel and 92% of all heavy duty vehicles use diesel fuel. The remaining heavy duty truck traffic was assumed to use gasoline. The percent of gasoline and diesel light duty and heavy duty trucks is given in Table A-5.

Table A-5. US Truck Fleet by Fuel Type

Fuel Type Light Duty Trucks

Heavy Duty Trucks

Gasoline 62% 8%

Diesel 38% 92%

Activity Data – Vehicle Miles Traveled

Engine emissions from vehicle traffic on roads are calculated using the number of miles travelled, for each vehicle type. There are a number of sources for total truck trips required to support horizontal drilling and hydraulic fracturing. The DAQ examined data collected by Pennsylvania, New York and Texas. This information is summarized in Table A-63,4,5.

Table A-6. Summary of Average Number of Truck Trips and Miles Traveled during Well Development

Source Average Number of Trips

Average Miles

Chesapeake 482 n/aTexas 1186 50New York - Heavy Duty 1148 n/aNew York - Light Duty 831 n/aPennsylvania (equipment) 195-315 0-20Pennsylvania (water) 100-1000 0-20Pennsylvania (Wastewater) 100-1000 0-300RANGE 100 – 1000 0 – 300

For this study, the DAQ assumed 1,000 heavy duty truck trips are required to deliver equipment, materials and water to the well pad. The length of the average truck trip for water and wastewater hauling is assumed to be 100 miles. In addition, 500 light duty truck trips of 50 miles in length were assumed. These truck trips were split into fuel types using the percentage by fuel type given in Table A- 5.

The total vehicle miles traveled (VMT) for the development of a single well was calculated as follows for both light duty and heavy duty diesel trucks:

Total Truck VMT = Number of truck trips × Average trip length

Appendix A, page 12


Table A-7. Estimated Vehicle Miles Travelled for Development of One Well by Vehicle Type

Truck Type Activity

Percent by Fuel

TypeTrips Miles Total VMT

LDGT equipment & materials hauling 62% 310 50 15,500

LDDT equipment & materials hauling 38% 190 50 9,500

HDGV water and wastewater hauling 8% 80 100 8,000

HDDV water and wastewater hauling 92% 920 100 92,000

Emission Factors – Vehicle On Road

Emission factors for vehicles are a function of vehicle age, vehicle type, fuel type, and engine size. Light duty emissions are calculated simply as a function of vehicle miles travelled. Heavy duty truck engine emissions are more complicated and are expressed as a function of the engine brake horsepower per hour. Emissions for vehicles are generally determined in computer-based models that account for various engine emission factors, loads and duty cycles for each vehicle/engine type, and the average miles travelled on each road type. The DAQ generally uses the US EPA’s Motor Vehicle Emission Simulator (MOVES) model to determine vehicle emissions. However, this would require more resources and time than available for this study.

This study employs emission factors by vehicle class (light duty/heavy duty) and fuel type developed by the US EPA6,7. The emissions factors represent a national average of the in-use fleet as of July 2008 traveling on all road types. HAP emission factors for the average in-use fleet were not available.

Table A- 8 presents these emission factors.6,7 These emission factors reflect a partial implementation of the EPA’s Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements Rule which was promulgated in 2001 and fully implemented in 201025. Note that there will be further improvement to diesel truck emissions of NOX and PM for the 2015 in-use fleet, but readily available fleet emission factors were not available.

Table A-8. Average Engine Emission Rates by Pollutant and Vehicle Type

Pollutant LDGT LDDT HDGV HDDVgram per mile

VOC 1.224 0.189 1.586 0.447CO 11.84 0.839 13.13 2.311NOX 0.95 0.839 2.914 8.613

PM2.5 0.0045 0.091 0.044 0.202PM10 0.0049 0.099 0.051 0.219

Activity Data – Idling Times

The Texas oil and gas industry mobile survey estimated the average idle time at the well pad during well development was approximately 6 hours4. North Carolina has an anti-idling rule which limits idling of truck engines to 5 minutes in a 60-minute period (See 15A NCAC 02D .1010). However, actual idling

Appendix A, page 13


times were not adjusted to reflect this rule since implementation is up to the site operator. The total idling time and average idling per day were calculated. Table A-9 gives the average idling time per day for the development of one well.

Table A-9. Average Truck Idle Time per Well Development

Truck Type Trips

Idling Time per

Trip

Total Idling Hours

LDGT 310 6 hours 1,860

LDDT 190 6 hours 1,140HDGV 80 6 hours 480

HDDV 920 6 hours 5,520

Emission Factors – Vehicle Idling

The average idling emissions for the in-use fleet of trucks published by the US EPA in 2008 was reviewed by the DAQ8. It uses the same methodology described above. In addition, emission factors used by Texas for its shale gas well development and production fleet were reviewed4. Texas used the idling emission factors published by the US EPA in 2004 for heavy duty diesel trucks rather than those published in 2008 because the 2008 emission factor for NOX was significantly lower8,9. The DAQ also used the more conservative 2004 emission factors because fleet turnover of heavy duty vehicles is generally lower than the turnover of lighter duty vehicles. For SO2 emissions from idling, the DAQ used an emission factor of 0.27 g/hr obtained from a study using US EPA’s MOBILE 6.2 model to develop average idling emission factors 10. Table A-10 summarizes the idle emission factors used for this study.

Table A-10. Average Idle Emission Rates by Pollutant for All Vehicle Types

Pollutant LDGT LDDT HDGV HDDV*gram per hour

VOC 4.043 2.72 6.495 21.58CO 72.725 5.853 151.9 134.37NOX 4.065 3.705 5.33 135.00PM N/A N/A N/A 3.68SO2 N/A N/A N/A 0.270

Emissions - Vehicle On Road Travel and Idling

Using the total miles traveled for each vehicle type given in Table A-7, the total idle times for each vehicle type given in Table A-9, and the emission rates in Table A-8 and Table A-10 for on road travel and idling, the DAQ calculated the total emissions from truck traffic for the development of a single well. Note these are not the emissions per day but represent the transportation emissions for the entire well development period in ton per well developed.

Appendix A, page 14


The equations for calculating emissions due to vehicle travel and vehicle idling are given below.

EmissionsVehicle Travel ( ton )=EF ( gmile )×VMT ×1.1102×10−6 tong

EmissionsVehicle Idle ( ton )=EF ( ghour )×hoursidling×1.1102×10−6 ton

g

Table A-11 presents the emissions estimates for truck travel and idle times in both gram per well (g/well) and ton per well (ton/well) for each pollutant.

Table A-11. Total Emissions from Truck Trips and Idling per Well Development

PollutantTruck Travel Truck Idling

TotalTransportation

Emissions

g/well ton/well g/well ton/well g/well ton/well

VOC 74,580 0.08 132,870 0.146 207,450 0.229THC 76,579 0.08 15,539 0.017 92,117 0.102CO 509,143 0.56 956,577 1.054 1,465,720 1.616

NOx 838,404 0.92 759,543 0.837 1,597,947 1.761PM2.5 19,870 0.02 N/A N/A 19,870 0.022PM10 21,572 0.02 N/A N/A 21,572 0.024PM N/A N/A 20,314 0.022 20,314 0.022SO2 N/A N/A 1,490 0.002 1,490 0.002

4.3 Unpaved Roads

4.3.1 Potential Emission Sources

When a vehicle travels on an unpaved road, the force of the wheel on the road pulverizes the surface material. Particles are lifted and dropped from the rolling wheels, and the road surface is exposed to strong air currents. The turbulent wake behind the vehicle acts on the road surface after the vehicle has passed. This action causes emissions of fugitive dust from the road surface.

The quantity of dust emissions from a given segment of unpaved road is dependent on the volume of traffic, the silt content of the road material, and the moisture content of the road material11. Watering the road during dry periods can significantly reduce the amount of fugitive dust. Unpaved roads which are located at industrial facilities are estimated differently than public unpaved roads due to the specific use of the road.

Appendix A, page 15


Assumptions and Activity Data

As discussed in the previous section, the weight of the light duty trucks is assumed to be 8,000 pounds while the weight of the heavy duty gas trucks is assumed to be 20,000 pounds and the weight for heavy duty diesel engines is assumed to be 80,000 pounds for diesel engines. Using the average VMT calculated in the previous section gives the following activity data.

The DOE reports the average shale gas access road is 0.5 miles in length1. Therefore, the DAQ assumed a total of 1.0 miles of unpaved roads are used by trucks for access to the well pad. Table A-12 gives the total vehicle miles traveled on unpaved roads for development of one well.

Table A-12. Vehicle Miles of Unpaved Road Traveled per Vehicle Type

Truck TypeWeight (tons) Trips Miles

Total VMT

Light Duty Gas 4 310 1 310Light Duty Diesel 5 190 1 190Heavy Duty Gas 10 80 1 60Heavy Duty Diesel 40 920 1 940

Emission Factors

The US EPA estimates industrial unpaved road dust using the following equation given in AP-42 Section 13.2.2 Unpaved Roads11. In the equation, s is the percent silt content of the road and W is the vehicle weight in tons and k, a, and b are constants. VMT is the average vehicle miles of unpaved road traveled.

E=k ( s12 )a

(W3 )b

×VMT

For the 2011 National Emissions Inventory, the DAQ assumed the average silt content for the State of North Carolina as 5.1% based on local sampling data. This is the silt content used for this study. The US EPA default national silt content is 3.9%. For PM10 the constants k, a, and b in the equation given above are obtained from AP-4211. The data is summarized in the flowing table.

Table A-13. Emission Factor Parameters for PM10 Emissions from Travel on Unpaved Roads

Constant

Industrial RoadsEmission Factor

Parameters for PM10

k 1.5a 0.9b 0.45

Emissions

Using the above equation, constants and activity data, NC DAQ calculated an estimate of PM10 emissions from unpaved road dust. These estimates are given in Table A-13 on the following page.

Appendix A, page 16


Table A-14. Fugitive Dust Emissions from Travel on Unpaved Roads

Truck TypeWeight (tons) VMT/day

Silt Content

(%) k a b

PM10

Emissions(lb/well)

PM10

Emissions(ton/well)

Light Duty Gas 4 310 5.1 1.5 0.9 0.45 245 0.12

Light Duty Diesel 5 190 5.1 1.5 0.9 0.45 166 0.08

Heavy Duty Gas 25 80 5.1 1.5 0.9 0.45 144 0.07

Heavy Duty Diesel 40 920 5.1 1.5 0.9 0.45 2,050 1.02

Total Emissions 1.31

4.4 Drilling

Drilling for natural gas is accomplished two ways; by drilling only in the vertical direction (noted in this report as vertical wells) and by drilling vertically until the shale formation is reached then drilling horizontally through the shale formation (horizontal wells). The overall length of the wellbore, regardless of whether it is drilled as a vertical or horizontal well, is the primary driver of the well development activity.

As stated in Section 3.1 (North Carolina Shale Gas Formation Data and Assumptions) of the main document, the Sanford Sub-basin shale gas formation is approximately 2,100 and 6,000 feet below the surface. Table A-15 presents the vertical depth and formation thickness for several developed shale gas formations in the U.S. Based on the analysis of shale formations in the Sanford Sub-basin and well information about shale gas plays in other states; the Arkoma basin (i.e. Fayetteville) located in Arkansas (AR) has the most similar shale depths to that estimated for the Sanford Sub-basin. The Marcellus, Barnett and Haynesville shale formations were deeper than the Sanford Sub-basin as noted in Table A-15. Therefore, equipment size and activity data for drilling in the Sanford Sub-basin was obtained using estimates for the Arkoma basin from EPA’s Nonpoint Oil and Gas Emission Estimation Tool (the Tool)12.

There are two common types of drilling rigs; mechanical and diesel-electric. A mechanical drill rig employs three diesel-fired engine types to power separate processes on the drill rig and a diesel-electric drill rig employs two to three large diesel–fired generator sets to supply electricity to a control house which then powers all the engines on the rig. The drilling industry is trending toward the use of more diesel-electric drilling rigs. However, equipment data for diesel-electric drilling rigs is not readily available, so for this report, the drilling rigs were assumed to be mechanical.

Appendix A, page 17


Table A-15. Shale Formation Comparison between NC and other states in US

State(s)Shale Formation

Vertical depth, (ft)

Horizontal drilling, (ft)

Net thickness of Formation, (ft)

Total Porosity,

(%)NC Sanford

Sub-basin, Deep River basin

2100-60004

Basement ~7100

Unknown until drilling begins

Max=8004 <0.1-2.27

AR Fayetteville Shale, Arkoma basin

1,000-7,0005 3000+1 20-2005 2-85

AL, GA, KY, MD, NY, OH, PA, TN, VA, WV

Marcellus Shale, Appalachian Basin

4,000-8,5005 2000+1 50-2005 105

TX Barnett Shale

6500-85005 2500-30001 100-603 4-55

TX, LA Haynesville Shale

10,500-13,5005 200-3003 8-95

1US Shale Gas, Halliburton, 20082USGS Fact Sheet 2011-3092, August 2011.3Draft report, Development of emissions inventories for natural gas exploration and production activity in the Haynesville Shale, Environ, August 31, 20094DENR Oil and Gas Study, April 20125Modern Shale Gas, Development in the United States: A Primer, April 20096USGS Fact Sheet2012-3075, June 2012.7Hydrocarbon Source Rocks in the Deep River and Dan River Triassic Basins, North Carolina, USGS Open-File Report 2008-1108.

Mechanical drilling rigs use three types of engines: draw works, mud pumps and generators. Draw-works engines supply the power to hoisting and rotating equipment. Mud pumps circulate drilling fluids or “mud” down the drill string and back. The generators are required to power auxiliary equipment. All these engines are diesel compression ignition (CI) engines. The number and size of each type of engine and period of time required for drilling will vary with the type of formation and the required length of the well.

The emissions associated with drilling rigs in this study were calculated using emissions factors contained in the Tool for nonroad CI engines under the Source Classification Code 227010010. The Tool extracted emission factors from the EPA NONROAD2008 model. This model uses ‘the latest 2003 Power System Research sales estimates through year 2000 (15) were used in conjunction with the latest input values for load factor, activity, median life and the default scrappage curve to calculate the 2000 base year populations for CI equipment’. 26 The NONROAD2008 model was run with the engine standards in

Appendix A, page 18


effect through 2011. The resulting weighted average emission factor was extracted for the engine size ranges for inclusion in the Tool.

It should also be noted that a in addition to the drill rig, a crane will be required to raise the well pipes into place, and cement pumps will be needed to set the well casing. The DAQ was not able to obtain equipment size, activity data or emission factors for cranes or cement pumps, therefore these activities were not included in this study.


Each drill rig uses multiple (estimates range from 4 to 8) stationary diesel-fired internal combustion engines to either directly or indirectly power the drill bit. Mud pumps are required to pump the drilling mud which aids in the creation of the well bore hole. Higher horsepower mud pumps have enabled drilling crews to complete the drilling process faster by more efficiently removing the drilling solids. Engine sizes shown in the Tool are considerably lower horsepower than the equipment reported in the April 4, 2014 Oil and Gas Emission Inventory, Eagle Ford Shale report21. These differences may be due to drilling depths and geology.

Two drilling scenarios were calculated; one scenario where all wells are drilled vertically (noted as Vertical wells) and the other scenario where all wells are drilled first vertically then horizontally (noted as Horizontal wells). Emissions from the drill rig engines are dependent on the amount of time required to drill to the target length, vertically then possibly horizontally. The number of engines, average horsepower per engine and time of use were unchanged from the EPA report, ‘Estimating Nonpoint Emission from the Oil and Gas Production Sector’ which includes data and a calculator tool to EPA’s current Tool. The equipment and activity data used to calculate engine emissions are included in Tables A-16 through A-18 given on the following pages.

To estimate emissions from drilling a single gas well, the following equation from the Tool was used:

Emissions = (EF × Avg Capacity × Load Factor × Hours × Number of engines)/907,185

Where:EF = Emission factorAvg Capacity = Average capacity of the engine in hpLoad Factor = of engine at specific hp, in %Hours = of engine operation907,185 = conversion factor from grams to tons

Table A-16. Drilling Equipment

Equipment Capacity (hp)

Number of engines

Hours of operation

Load Factor, (%)

Horizontal well equipmentDraw works drilling

engines 557.5 2 200 40Mud pumps 900 2 130 60

Appendix A, page 19


Diesel generators 772 2 200 60

Table A-17. Emission Factors for Criteria Air Pollutants, Drilling Activity

Engine capacity range

NOx (g/hp-hr)

VOC (g/hp-hr)

PM10

(g/hp-hr)PM2.5 (g/hp-hr)

CO (g/hp-hr)

SO2 (g/hp-hr)

300-600 hp 4.258 0.232 0.176 0.171 1.144 0.01750-3,000 hp 5.831 0.368 0.227 0.221 1.318 0.01

Table A-18. Emission Factors for Hazardous Air Pollutants, Drilling Activity

Engine capacity range

Benzene, (g/hp-hr)

Ethylbenzene, (g/hp-hr)

Hexane, (g/hp-hr)

Toluene, (g/hp-hr)

Xylenes, (g/hp-hr)

300-600 hp 0.00242 0.000415 0.000464 0.00352 0.00279750-3,000 hp 0.00385 0.000659 0.000736 0.00559 0.00444

Assumptions The equipment list and operating times from the Tool based on a basin specific study (see

Drilling Depth Assumptions listed in Section 4.424 for Arkansas’ Arkoma Basin were used to estimate drilling emissions for NC’s Sanford Sub-basin due to similarities in depth. Geology comparisons were not made.

All engines used in this activity are assumed to use diesel fuel.

Pollutant emission estimates (for Criteria and HAPs) were made using equations in the Tool and emission factors from NONROAD2008 model13.

4.5 Drilling Mud Storage


Drilling mud is a chemical mixture (water-based, oil-based or synthetic) that is used to cool the drill bit and help hold the gas in the ground. It is circulated down the drill pipe around the bit then back up to the surface. Additionally, the drilling mud provides pressure during the boring process, which keeps the well from collapsing. The drilling mud can be removed from the site or stored at the well site in open pits. The pits are either storage tanks (open or closed) or plastic lined ground pits. While the drilling mud can be reused, any gas contained within the drilling mud must first be removed to increase the density of the mud and increase its effectiveness. Drilling solids are also removed prior to reuse to increase effectiveness.

The primary pollutants from this activity are methane and VOCs. Drilling mud data, average number of drilling days and mud type, was obtained from the Tool12 for the Arkoma basin. The Tool reported the average number of drilling days per well for Arkoma as 20 days, and the mud type was reported to be water-based. The Climate Registry Oil and Gas Protocol contains a mud degassing emission factor for

Appendix A, page 20


water-based mud of 0.26 metric tons methane (CH4) per drilling day14. This emission factor was converted from metric tons to tons then multiplied by the average number of drilling days.

Methane Emissions=[0.26metric tonsdrilling day× 1ton0.907metric tons

×averagedrilling days]The Tool also reports the molar percentage and volume of methane (CH4) for the Arkoma basin. Since this data is available, VOC emissions can be estimated for this source using its molar percentage. The DAQ estimated these emissions by taking the ratio of the molar percentage of CH4 in the Arkoma basin over the molar percentage of CH4 in the Climate Registry Oil and Gas protocol sample data. The total CH4

volume divided by the CH4 molar percentage calculates the total volume of gas then multiplying the total volume by the VOC molar percentage estimates the VOC emissions.

VOC Emissions=CH 4emissions

tonswell

CH 4mol%×VOCmol%

Table A-19. Emission Factors and Molar Percentages Used to Estimate Emissions

No. of Drilling days/well

CH4, in metric tons/drilling day

CH4, in molar %, for Arkoma basin

VOC, in molar %, for Arkoma basin

20 0.26 0.94 0.01

Assumptions

Storage of the drilling mud was assumed to be in an open pit or tank at the well site. Arkoma Basin data can be used to estimate emissions for the Sanford Sub-basin wells given

the similarities in depth to the formation.

4.6 Hydraulic Fracturing


There are two methods of fracturing being utilized by the oil and gas industry; hydraulic fracturing and nitrogen gas or foam fracturing. However, nitrogen gas/foam fracturing is only effective for very specific types of shale formations such as those found in Virginia. The more common type of fracturing is high volume hydraulic fracturing which is the act of pumping large volumes of water, a ‘proppant’ (usually sand) and any added chemicals into a well bore hole under high pressure. For the purposes of this report, it is assumed that high volume hydraulic fracturing (hydraulic fracturing) will be used in North Carolina.

Hydraulic fracturing can be utilized in vertical as well as horizontal wells. As stated previously in the drilling section above, this report assumes only horizontal wells are installed, since Dr. Taylor’s gas

Appendix A, page 21


recovery estimates are based on only horizontal wells. Emissions estimates for vertical wells are not included in this report.

The number of hydraulic fracturing stages in a horizontal well depends on the horizontal length of the well bore and pressure required for fracturing. Each stage in a horizontal well is usually 300 feet. More recent data on fracturing duration per stage from the Tool indicates the operating hours of the hydraulic fracturing pumps per stage has increased slightly. The majority of hydraulic fracturing emissions originates from the operation of diesel-fired fracturing pumps and is directly proportional to the number fracturing stages and the operating hours of the pumps.

Emissions from hydraulic fracturing pumps are due to the combustion of diesel fuel to provide power to the pumps. Emission factors for all pollutants were acquired from the Tool which used nonroad diesel engines with the Source Classification Code (SCC) of 227010010 extracted from the NONROAD2008 model. This model uses ‘the latest 2003 update of the PSR (Power System Research) sales estimates through year 2000 (15) were used in conjunction with the latest input values for load factor, activity, median life and the default scrappage curve to calculate the 2000 base year populations for CI equipment’.26 The NONROAD2008 model was run with the engine standards included through 2011 and then an average emission factor was extracted for the engine size ranges for inclusion in the Tool.

The assumptions for this section are the same as those listed in Section 4.4 of this appendix. The equipment and activity data used to estimate emissions are presented in Tables A-20 through A-22 given on the following pages.

The equation from the Tool that was used to estimate pump engine emissions is given below:

Emissions=n×EF× No.of stages×TotalCapacity×Load factor ×Hours907,185

Where:

n = Number of pump enginesEF = Emission Factor

No. of stages = Number of hydraulic fracturingTotal Capacity = Engine capacity in horsepower (hp)

Load factor = Percent loading of the of engine at a specific hp (%)Hours = Engine operating time in hours

907,185 = Conversion factor from grams to tons

Table A-20. Hydraulic Fracturing Pump Specifications

Equipment Capacity (hp) No. of engines

No. of stages Hours Load factor (%)

Fracturing Pumps, Horizontal well

2033.33 8.5 10.50 2.25 68.75

Appendix A, page 22


Table A-21. Emission Factors for Criteria Air Pollutants, Hydraulic Fracturing Activity

NOx (g/hp-hr)

VOC (g/hp-hr)

CO (g/hp-hr)

PM10 (g/hp-hr)

PM2.5 (g/hp-hr)

SO2 (g/hp-hr)

5.83 0.37 1.32 0.23 0.22 0.01

Table A-22. Emission Factors for Hazardous Air Pollutants, Hydraulic Fracturing Activity

Benzene, (g/hp-hr)

Ethylbenzene, (g/hp-hr)

Hexane, (g/hp-hr)

Toluene, (g/hp-hr)

Xylenes, (g/hp-hr)

4.0E-03 6.6E-04 7.4E-04 5.6E-03 4.4 E-03

4.7 Well Completion


The well completion phase refers to the beginning of the fracturing liquid flowback period until the well is shut in or until the gas from the well flows continuously to a gathering line or storage container. Large amounts of gas are released during this process. Historically, this gas was vented or flared. Gas release rates from hydraulically fractured wells varies based on the formation geology, fracturing technology and operating conditions.

Under 40 CFR 60 Subpart OOOO Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution, natural gas wells, including hydraulically fractured wells, will be required to perform Reduced Emissions Completions (REC) starting in 2015. There are exemptions for specific wells, such as low pressure wells which are required to flare emissions18. For this study, the DAQ assumed that all wells are completed using REC methods.

REC, or ‘green’ completion, occurs after fracturing is complete and before production begins. This period can occur after a fracturing treatment, either in preparation for a subsequent phase of treatment, or for cleanup to return the well to production. The completion phase can last from 3 to 10 days.

The REC method captures fracturing fluid and associated gas that normally would be discharged onto the ground (liquid) and vented to the atmosphere or burned in a flare (gas). The captured fluid is first processed through a separator which separates the gas from water, and the water is either stored for disposal or reused as well injection or fuel for various needs4. Then the gas is dried further by a glycol dehydrator/reboiler system (described in detail in Appendix B, Section 4.4). Dehydrated gas is returned to the gas line for use on-site as a fuel or added to the pipeline. Emissions of VOC, benzene, toluene, ethylbenzene and xylene (BTEX) and other HAPs occur from this activity. Additional emissions can also occur from equipment leaks during this phase. Figure A-1 presents a diagram of a REC system.

Appendix A, page 23


Figure A-1. Reduced Emissions Completions for Hydraulically Fractured Natural Gas Wells17

For well completion, the DAQ estimated flowback emissions from REC and emissions from operation of the reboiler used by the dehydrator. Note that the DAQ did not estimate emissions from the separator tank. Fugitive emissions from storage tanks could not be estimated due to the unknown tank configuration and absence of throughput data for the tank liquids.

Reduced Emission Completion

The REC method controls approximately 90% of the flowback emissions. Approximately 10% of the gas still escapes. Some of the well completion emissions may be captured and controlled with a flare. In this study, the DAQ assumed fugitive emissions were vented to the atmosphere.

The US EPA Background Supplemental Technical Support Document for 40 CFR 60 Subpart OOOO estimates the average flowback emissions per completion is 9,000 MMcf15. Assuming a 90% control of these emissions from employing REC, the amount of gas collected during completion is estimated at 8,100 MMcf of gas. The remaining gas, 900 MMcf, is assumed to be vented to the atmosphere.

The DAQ estimated the mass of methane and select HAP emissions from the total raw gas vented during completion. The equation below provides the equation used to estimate the mass of a specific pollutant emitted per well completion:

Gas Emitted(lb)=Fugitive gas volume(cf )×volumeof pollutant(%)×[ 0.053 pounds385 cf ]The percent volume of selected HAPs in the raw gas are required to estimate HAP emissions. Average percent volumes of specific pollutants were obtained from Table 8 of an EPA memo titled “Composition of Natural Gas for use in the Oil and Natural Gas Sector Rulemaking” 16.

Appendix A, page 24


Table A-23. Percent Volume by Pollutant

VOC Volume

%

Benzene Volume

%

Ethylbenzene Volume

%

n-Hexane Volume

%

Toluene Volume

%

Xylene Volume

%

Methane Volume

%3.66 0.005 0.00 0.155 0.003 0.001 83.1

Vented emissions for each pollutant are presented at the beginning of the Appendix in Tables A-1 and A-2.

Dehydrator/Reboiler

A dehydrator is used to remove water in the raw gas obtained during completion. Based on the Tool documentation, the two main sources of emissions found in a dehydrator device are; 1) hydrocarbon emissions including VOC and HAPs from the dehydrator still vent, and 2) combustion emissions generated by the dehydrator reboiler.

Based on equipment data contained in the Tool, the DAQ assumed one dehydrator/reboiler system per well pad. As stated previously, the total volume of raw gas collected during REC is 8,100 MMcf. This is the volume of gas processed through the dehydrator/reboiler system.

The DAQ estimated the mass of VOC and select HAP emitted from the dehydrator still vents. The VOC emission factor for the dehydrator at standard conditions was obtained from the Tool. The DAQ converted the volume of gas processed by the dehydrator at actual conditions to a volume at standard conditions (MMscf). This volume is then multiplied by the VOC emission factor for dehydrators to obtain the emissions. The VOC emission factor is given in Table A-24.

Emissions for benzene, toluene, ethylbenzene and xylene (BTEX) from the dehydrator were then calculated using ratios of the BTEX pollutants to VOC emissions. These ratios are also taken from the Tool. Table A-24 also presents the ratios for VOC to benzene, toluene, ethylbenzene and xylene. The pounds of VOC emitted are multiplied by this ratio to obtain emission of these pollutants vented to the atmosphere.

Table A-24. VOC to BTEX Ratios for Dehydrator Emissions

VOC, lb/MMscf Benzene : VOC Ethylbenzene : VOC Toluene : VOC Xylene : VOC0.528442 0.23 0.01 0.12 0.46

To calculate the reboiler combustion emissions, the reboiler operating parameters and emissions factors in in lb/MMcf were obtained from the Tool. Tables A-25 and A-26 contain the activity data and emissions factors, respectively.

Appendix A, page 25


Table A-25. Reboiler Activity Data

Reboiler rating

(MMBtu/hr)

Lower Heating Value(LHV)

(Btu/scf)

Operating hours(hr)

0.987 1035 8672

Table A-26 Reboiler Emission Factors in lb/MMcf

NOX VOC PM10 PM2.5 CO SO2 Benzene HexaneToluen

e Xylenes CH4 Formaldehyde100 5.5 7.6 7.6 84 0.6 0.22 1.8 0.11 0 2.3 0.44

Emissions for each pollutant from the dehydrator still vent and reboiler are presented at the beginning of the Appendix in Tables A-1 and A-2.

5 References

1. Modern Shale Gas Development in the United States: A Primer, Prepared for U.S. Department of Energy Office of Fossil Energy and National Energy Technology Laboratory, Prepared by Ground Water Protection Council, Oklahoma City, OK and and ALL Consulting, Tulsa, OK, April 2009.

2. Muleski, G., Improvement of Specific Emission Factors (BACM Project No. 1), Final Report. Midwest Research Institute, March 1996.

3. 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.

4. Development of Oil and Gas Mobile Source Inventory in the Barnett Shale in the 12-County Dallas-Fort Worth Area, Prepared for Texas Commission on Environmental Quality by North Central Texas Council of Governments, Grant Number: 582-11-13174, August 2012.

5. “An Emissions Inventory for the Development and Production of Marcellus Shale: Draft Report”, Anirban A. Roy, Peter J. Adams and Allen L. Robinson, Carnegie Mellon University, 2013.

6. Emission Facts: Average In-Use Emissions from Heavy-Duty Trucks, US EPA, Office of Transportation and Air Quality, EPA420-F-08-027, October 2008.

7. Emission Facts: Average Annual Emissions and Fuel Consumption for Gasoline-Fueled Passenger Cars and Light Trucks, US EPA, Office of Transportation and Air Quality, EPA420-F-08-024, October 2008.

8. Emission Facts: Idling Vehicle Emissions for Passenger Cars, Light-Duty Trucks, and Heavy-Duty Trucks, US EPA, Office of Transportation and Air Quality, EPA420-F-08-025, October 2008.

Appendix A, page 26


9. Guidance for Quantifying and Using Long Duration Truck Idling Emission Reductions in State Implementation Plans and Transportation Conformity, US EPA, Office of Transportation and Air Quality, EPA420-B-04-001, January 2004.

10. Technical Guidance on the Use of MOBILE6.2 for Emission Inventory Preparation, prepared for the United States Environmental Protection Agency. August, 2004.

11. AP-42: Compilation of Emission Factors, Chapter 13.2.2 Unpaved Roads, US EPA

12. 2011 Nonpoint Oil and Gas Emission Estimation Tool, EPA Contract No. EP-D-11-006, Work Assignment 3-03, November 21, 2014.

13. Exhaust and Crankcase Emission Factors for Nonroad Engine Modeling—Compression-Ignition, US EPA Office of Transportation and Air Quality, Assessment and Standards Division, Report No. NR-009d, July 2010.

14. The Climate Registry Oil and Gas Production Annex II to the General Reporting Protocol

15. 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, page number 1-14.

16. Supporting and Related Material Memorandum dated July 28, 2011 from Heather P. Brown, P.E. with the subject, ‘Composition of Natural Gas for use in the Oil and Natural Gas Sector Rulemaking’.

17. US EPA Natural Gas Star Program Document, ‘Reduced Emissions Completions for Hydraulically Fractured Natural Gas Wells’

18. U.S. Environmental Protection Agency. Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New Source Performance Standards; Final Rule. September 23, 2013. Docket ID No. EPA–HQ–OAR–2010–0505.

19. NC Mining and Energy Commission. Local Government Regulations Study Group Report: http://portal.ncdenr.org/web/mining-and-energy-commission/local-government-regulation-agendas Accessed November 2014.

20. “Natural Gas Potential of the Sanford Sub-basin, Deep River Basin, North Carolina”, Jeffery C. Reid, Kenneth B. Taylor, Paul E. Olsen, and O. F. Patterson, III, Search and Discovery Article #10366 (2011), posted October 24, 2011.

21. “Oil and Gas Emission Inventory, Eagle Ford Shale”, prepared by Alamo Area Council of Governments in cooperation with the Texas Commission on Environmental Quality (TCEQ), 582-11-11219 Amendment Number 5, accepted as final by TCEQ on April 4, 2014.

22. NC Mining and Energy Commission. Local Government Regulations Study Group Report: http://portal.ncdenr.org/web/mining-and-energy-commission/local-government-regulation-agendas Accessed November 2014.

23. 2012 Annual Energy Outlook (AEO) Data, Reference Case, Table 37. Transportation Sector Energy Use by Fuel Type Within a Mode, Energy Information Administration, http://www.eia.gov/forecasts/aeo/data.cfm?filter=transportation#transportation

Appendix A, page 27

http://www.eia.gov/forecasts/aeo/data.cfm?filter=transportation#transportation

http://portal.ncdenr.org/web/mining-and-energy-commission/local-government-regulation-agendas%20Accessed%20November%202014





24. Control of Air Pollution from New Motor Vehicles: Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements, Federal Register: January 18, 2001 (Volume 66, Number 12)] [Rules and Regulations] [Page 5001-5050]

25. Nonroad Engine Population Estimates, EPA-420-R-10-017, July 2010.

26. North Carolina Administrative Code Title 15A Environment and Natural Resources, Subchapter 2d-Air Pollution Control Requirements, Section .1900 - Open Burning, http://daq.state.nc.us/rules/rules/D1900.pdf

Appendix A, page 28

http://daq.state.nc.us/rules/rules/D1900.pdf

appendix avibe.cira.colostate.edu/ogec/docs/north carolina... · web viewin addition, large volumes...

Documents