Estimate of Air Emissions from Shale Gas Development and Production in North Carolina May 15, 2015 Presented to the Mining and Energy Commission Environmental Standards Committee D EPARTMENT OF E NVIRONMENT A ND N ATURAL RESOURCES D IVISION OF A IR Q UALITY S USHMA M ASEMORE, P.E.

Call for Shale Gas Air Quality Analysis Session Law , Section 2(c) as amended by SL , Section 6  DAQ required to estimate: 1) emissions from oil and gas exploration, development, 2) emissions from associated truck traffic  Determine impact to ozone levels 2

Overview of Air Quality Assessment Process 1. Build Emissions Inventory a.Quantify emissions discharged into the atmosphere 2. Photochemical Modeling a.Emission data input into model along with meteorology b.Quantify formation and transport of ozone and pollutants 3. Assess Air Quality Impacts a.Quantifies increase/decrease in concentration of pollutants b.Impacts to receptors 3 Emissions Inventory Photochemical Model Air Quality Impact +

Development of Emission Estimates 4 The general form of the equation for emissions estimation is: E = EF × A × P Where: E= emissions EF= emission factor A = activity rate for a specific source P = additional parameter(s) affecting source emissions Examples of activity data Horsepower hours Vehicle miles traveled Cubic feet of raw gas throughput Examples of additional parameters Engine load factor Flare emissions control efficiency Silt content of unpaved road

5 Pollutants Inventoried * Nitrogen oxides (NO X ) Volatile Organic Compounds (VOC) Carbon monoxide (CO)Sulfur dioxide (SO 2 ) Particulate Matter - PM 10 & PM 2.5 Methane (CH 4 ) Benzene (C 6 H 6 )Methanol (CH 4 O) Toluene (C 7 H 8 ) Hexane (C 6 H 14 ) Ethylbenzene (C 8 H 10 CH 2 CH 3 ) Styrene (C 8 H 8 ) Xylene (C 8 H 10 ) Acrolein (C 3 H 4 O) Formaldehyde (CH 2 O) Acetaldehyde (C 2 H 4 O) Ozone (O 3 ) – formed from NO X and VOC in the presence of sunlight *where emission factors are available for a given activity

Primary Resources Used to Develop North Carolina’s Emissions Estimates DENR Shale Gas Report to the Legislature US EPA Oil and Gas Tool (updated 2014) Oil and Gas Emission Inventory Enhancement Project for Central States Air Resource Agencies 4.US EPA AP 42, Fifth Edition, Compilation of Air Pollutant Emission Factors 5.Emission inventories for various states 6

Phases of North Carolina Shale Gas Operations What Shale Gas Operations Did the NC DAQ Evaluate? Development Production Processing Gathering & Transmission 7 What Types of Sources Were Included? Point - processing plant, compressor station Mobile – equipment and supply trucks Area – drilling/compressor engines, liquid storage tanks Fugitive – completion, equipment leaks

Gathering* Compressor Engines Well Pad Roadway ProductionProcessing Gathering*, Transmission, and Distribution Development Gas Processing Plant Transmission Compressor Station To Market Shale Gas Phases 8 Well Pad

Shale Gas Activity Descriptions 9 PhaseActivity or EquipmentReference Section 1Development Site Preparation (land clearing, unpaved roads, truck trips, truck idling), Well drilling and completion (drilling, drilling mud degassing, hydraulic fracturing, green well completion) Appendix A 2Production Compressor engines, Blowdown, Glycol dehydrator, Reboiler, Pneumatic controllers, Heaters, Equipment leaks, Produced water tanks Appendix B 3Processing Acid gas removal (sweetening), Compressor engines, Glycol dehydrator, Reboiler, Liquid removal Appendix C 4 Gathering, Transmission and Distribution Compressor engines (gathering, booster and high pressure), Pipeline leaks Appendix D

Key Assumptions: Well Drilling Schedule 1.Gas recovery occurs in the Sanford sub‐basin (59,000 acres) 2.Cumulative gas produced by the field is 773 Bcf 3.Well spacing of 160 acres, total of 368 wells drilled 4.4 wells drilled per pad, total of 92 pads 5.Year of maximum activity is Year 6 per Dr. Ken Taylor 121 new wells drilled and 247 producing wells Total produced gas is 151,605 MMcf Each well recovers 2,115 MMcf of raw gas over a 20 year life 6.Water and waste water is trucked within the Sub-Basin 1,000 heavy duty truck trips per well, 100 miles each required Additional light duty truck traffic also estimated assuming 500 trips per well, 50 miles each 10 Bcf = billion cubic feet MMcf = million cubic feet

Key Assumptions: Development Phase 1.Four wells per well pad 2.40 CFR Part 60 New Source Performance Standards and 40 CFR Part 63 and National Emission Standards for Hazardous Air Pollutants regulatory requirements apply 3.Horizontal drilling and hydraulic fracturing are employed. 4.Average drilling time is 200 hours per well. 5.Non-road engines used for drilling and pumping are subject to Federal engine standards (40 CFR 89) 6.Non-road engine emission factors are based on EPA model for No electrification of drilling pads. 11

Well Drilling Schedule and Gas Recovery Assumptions This table was prepared by DENR’s Dr. Ken Taylor Estimate of Year 6 Activity: – 121 wells drilled – 247 producing wells – 151,605 MMcf gas produced Total annual emissions for Year 6 was assumed to be distributed evenly throughout the year to arrive at a daily emissions rate 12

Key Assumptions: Other Phases Production 1.One dehydrator/reboiler and wellhead compressor engine per well pad 2.No recoverable condensate is present in the raw gas CFR Part 60 and Part 63 regulations apply depending on equipment type, size, age, etc. Processing 1.Regulated as a permitted stationary source 2.All applicable state and federal rules apply 3.Acid gas removal is required Gathering/Transmission 1.40 CFR Part 60 and Part 63 regulations apply 2.One gas transmission compressor station is regulated as a stationary source 13

Key Assumptions: Raw Gas Composition EPA’s National Average Gas Composition (% Volume) 14 Assumption: No recoverable condensates

Summary of Results Estimated Annual Emissions of Criteria Air Pollutants Criteria Air Pollutants (ton per year) PhaseNO X VOCCOSO 2 PM 10 PM 2.5 Development Mobile Contribution* Production Processing E-02 Gathering & Transmission YR 6 Total Shale Gas Emissions (tpy) 1,344 1, *Shown for illustration purposes; mobile sources emissions are incorporated into Development emissions

Potential Emissions Changes Criteria Air Pollutants (ton per year) NO X VOCCOSO 2 PM 10 PM 2.5 YR 6 Total Shale Gas Emissions 1,3441, Annual Emissions without Shale Gas Development 1,944 1,274 12, % Increase in Emissions69%84%5%35%330%55% YR 6 Total Emissions with Shale Gas Development (tpy)3,2882,34913,

Daily Emissions of Criteria Air Pollutant by Activity Used for Modeling Criteria Air Pollutants (ton per day) PhaseNO X VOCCOSO 2 PM 10 PM 2.5 Development E Production E-041.1E-02 Processing E-021.4E-04 Gathering / Transmission E-045.5E-03 YR 6 Total Daily Emissions (tpd) E

Annual Emissions of Key Hazardous Air Pollutants by Activity Hazardous Air Pollutants (ton per year) Phase FormaldehydeAcetaldehydeBenzeneTolueneXylene Development Production Processing Gathering / Transmission Increase in Emissions

Relative Contribution of NO X Emissions by Activity 19 NOTE: Less than 1 tpy or Zero NO X Emissions from the following phases/activities: Development - Land Clearing, Unpaved Roads, Drilling Mud Degassing, and Green Well Completion Production - Produced Water tanks, Glycol dehydrator and associated reboiler, Pneumatic Controllers, Fugitive leaks Processing - Glycol dehydrator and associated reboiler, Vents, Fugitive Leaks & Venting, Acid Gas Waste Sweetening Units Gathering Stations (all) - Glycol dehydrator and associated reboiler, Vents Transmission - Glycol dehydrator and associated reboiler, Vents, Fugitive Leaks & Venting

Relative Contribution of VOC Emissions by Activity 20 NOTE: Less than 1 tpy or Zero VOC Emissions from the following phases/activities: Development - Land Clearing, Unpaved Roads, Drilling Mud Degassing, and Green Well Completion Processing - Glycol dehydrator and associated reboiler, Fugitive Leaks & Venting, Acid Gas Waste Sweetening Units Gathering Stations (all) - Glycol dehydrator and associated reboiler, Still Vents Transmission - Glycol dehydrator and associated reboiler, Fugitive Leaks & Venting

Uncertainty Emissions inventory methods for the Oil and Gas Sector are relatively new and constantly changing – Quality of emission factors – Quality of activity data reported in EPA Oil & Gas Tool There is uncertainty in key parameters – Number of wells drilled, Number of wells on a pad – Vertical and lateral length of wells – Gas throughput and composition – Transportation distances Other unknowns – Variability in type and age of equipment used – Engine type, size, and operating hours 21

Peer Reviewers Mark Gibbs Air Quality Division Oklahoma Dept. of Environmental Quality Ona Papageorgiou, P.E. Bureau of Ari Quality Planning, Division of Air Resources New York State Dept. of Environmental Conservation Allen Robinson, Ph.D. Dept. Head Mechanical Engineering Carnegie Mellon University Mark Gibbs Air Quality Division Oklahoma Dept. of Environmental Quality Ona Papageorgiou, P.E. Bureau of Ari Quality Planning, Division of Air Resources New York State Dept. of Environmental Conservation Allen Robinson, Ph.D. Dept. Head Mechanical Engineering Carnegie Mellon University 22

Next Steps Revise the methodology (if needed) based on – Public input – Recommendations from the EPA Oil & Gas Emissions Committee Re-run air quality models 23