Review of WRAP Oil Gas Phase II Emissions

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Review of WRAP Oil & Gas Phase II Emissions Inventory and Controls Analysis PRESENTATION

Review of WRAP Oil & Gas Phase II Emissions Inventory and Controls Analysis PRESENTATION FOR THE WESTAR OIL AND GAS WORKSHOP Amnon Bar-Ilan Ron Friesen Alison Pollack ENVIRON Intl. Corp. September 12, 2007 Pinedale, WY

WRAP Phase II Project Overview • Project was focused on developing an improved emissions

WRAP Phase II Project Overview • Project was focused on developing an improved emissions inventory of oil and gas exploration and production area sources in the WRAP region • Area source categories included compressor engines, drilling rigs, heaters and other wellhead equipment • Previous emission inventory (EI) efforts: - WRAP Phase I analysis, 2002 and 2018 (completed 2005) - NMED EI for San Juan and Rio Arriba counties (completed 2006) • Specific objectives of the Phase II project: - Emissions inventory improvements for 2002 - Current base year updates for 2005 - 2018 growth factor projections improvements - Control technology evaluations and control strategies scenarios - 2018 point source SO 2 emissions improvements 2

Western States Oil & Gas Regions of Interest Major basins of O&G activity in

Western States Oil & Gas Regions of Interest Major basins of O&G activity in Phase II analysis: Permian Basin (NM) San Juan Basin North (CO) Denver-Julesburg Basin (CO) Green River Basin (WY) Big Horn Basin (WY and MT) San Juan Basin South (NM) Uinta-Piceance Basin (CO and UT) Paradox Basin (UT) Wind River Basin (WY) Powder River Basin (WY and MT) 3

2002 Emissions Inventory Improvements • New methodology estimated 2002 emissions on a basin-wide average

2002 Emissions Inventory Improvements • New methodology estimated 2002 emissions on a basin-wide average basis for all basins in the WRAP region, focusing on those basins where major O&G activities are occurring and detailed producer information is available • In basins where significant activity was not occurring, or producer information was unavailable, used Phase I estimates 4

Data Collection from O&G Producers • Data were collected from most major and some

Data Collection from O&G Producers • Data were collected from most major and some medium-sized and independent oil and gas companies operating in the WRAP region • Data collection was in the form of a questionnaire sent to each producer • Information was provided on: - Overall activity (i. e. number of wells, gas production, etc. ) - Equipment used and equipment counts - Emissions controls in use or planned - Projections of future activity, demand, and production in the region 5

Overview of Methods • Basin-specific emissions estimates were made using activity and equipment information

Overview of Methods • Basin-specific emissions estimates were made using activity and equipment information provided directly by the producers - Previous Phase I work used available data from limited areas and generalized to WRAP region • For Phase II EI improvements, focus was on well-head compressors and drilling rigs as area sources • Focused basin list only – these are the areas where major oil and gas activity is occurring or expected to occur • Updated baseline emissions year from 2002 to 2005 • Revised 2018 projections using most recent planning information available and producer data where available 6

2002 Emissions Inventory Drilling Rig Emissions • • • Improved estimate of actual drilling

2002 Emissions Inventory Drilling Rig Emissions • • • Improved estimate of actual drilling time by formation and basin from producer information on drilling times (rather than spud date and well completion date) Improved estimate of average drilling rig engine load by formation and basin Determined average horsepower requirements by formation and basin and identified most often used or representative makes/models of drilling rig engines Incorporated manufacturer’s rated emissions factors for makes/models identified, or producers’ emissions tests where available Incorporated SO 2 emissions factors (based on sulfur content of fuel) 7

2002 Emissions Inventory Drill Rig Emissions - TPY NOx SOx VOC 2002 877 66

2002 Emissions Inventory Drill Rig Emissions - TPY NOx SOx VOC 2002 877 66 0 0 Colorado 2, 803 118 101 Montana 1, 046 225 0 24 1 0 New Mexico 5, 476 244 68 North Dakota 1, 536 358 0 0 29 6 0 334 17 12 4, 997 150 228 17, 123 1, 185 410 Alaska Arizona Nevada Oregon South Dakota Utah Wyoming WRAP Total Note: Emissions estimates include data from previous work for the NMED in the San Juan Basin and the Southern Ute inventory in Colorado 8

2002 Emissions Inventory Compressor Engine Emissions • Determined for each basin either (a) the

2002 Emissions Inventory Compressor Engine Emissions • Determined for each basin either (a) the average percentage of wells with wellhead, lateral and central compression, or (b) percentage of total HP with wellhead, lateral or central compression • Did not include central and lateral compressors that have been counted in a point source inventory for each state • Determined for each basin a representative or most often used make/model of compressor, including HP and rated or tested emissions factors • Determined for each basin an average load factor for wellhead/lateral compressors • Basin-wide emissions estimate on the basis of total well count 9

2002 Emissions Inventory Compressor Engine Emissions - TPY NOx SOx VOC 2002 Alaska 0

2002 Emissions Inventory Compressor Engine Emissions - TPY NOx SOx VOC 2002 Alaska 0 0 0 Arizona 8 0 0 Colorado 3, 271 0 1, 204 Montana 1, 791 0 4 33 0 0 New Mexico 35, 140 1 3, 541 North Dakota 2, 920 0 0 73 0 0 South Dakota 284 0 0 Utah 843 0 53 1, 791 0 231 46, 154 1 5, 034 Nevada Oregon Wyoming WRAP Total Note: Emissions estimates include data from previous work for the NMED in the San Juan Basin and the Southern Ute inventory in Colorado. Other Colorado compressor emissions are assumed to be part of Colorado’s point source inventory and are not included here. 10

2002 Emissions Inventory Exploration & Production Previous Work included: • – Tanks - flashing,

2002 Emissions Inventory Exploration & Production Previous Work included: • – Tanks - flashing, working and breathing losses (VOC) – Glycol dehydration units (VOC) – Heaters (VOC and NOx) – Pneumatic Devices (VOC) – Completion-venting and flaring (VOC, NOx, CO) Work Plan identified potential additional work, if resources permitted, to estimate VOC from: • • – Venting (from unloading fluids) – Fugitives (using typical well diagrams) – Dehydrators (look at point source vs. area source distribution) Resources did not allow this work to be completed 11

Additional Categories CBM Engines • Emissions from CBM wells were addressed through estimating drilling

Additional Categories CBM Engines • Emissions from CBM wells were addressed through estimating drilling rig and compressor emissions • Previous estimates for CBM pump engine emissions were not updated Fugitive Dust Emissions • Resources did not allow estimating fugitive dust emissions 12

Updated 2002 → 2005 Emissions • Objective was to update base year for projections

Updated 2002 → 2005 Emissions • Objective was to update base year for projections from 2002 to 2005 using newly available state OGC data for 2005 • 2005 represents a more current base year for projections and can be used as a second “data point” to verify projections methodology • Methodology was to first update 2002 emissions using the methodology described here, then to scale up 2002 data using 2005 OGC well count or production • In areas with no production or wells in 2002, but with production or wells in 2005 emissions were scaled based on state average emissions per well (or per production unit) 13

Updated 2002 → 2005 Emissions Drill Rig Emissions - TPY NOx 2002 Alaska SOx

Updated 2002 → 2005 Emissions Drill Rig Emissions - TPY NOx 2002 Alaska SOx 2005 2002 2005 877 835 66 62 0 0 Colorado 2, 803 8, 000 118 350 Montana 1, 046 3, 007 225 640 24 37 1 1 New Mexico 5, 476 8, 640 244 362 North Dakota 1, 536 3, 055 358 688 0 0 29 203 6 43 334 2, 888 17 149 4, 997 15, 783 150 541 17, 123 42, 448 1, 185 2, 835 Arizona Nevada Oregon South Dakota Utah Wyoming WRAP Total 14

Updated 2002 → 2005 Emissions 2005 Compressor Engine Emissions - TPY NOx 2002 SOx

Updated 2002 → 2005 Emissions 2005 Compressor Engine Emissions - TPY NOx 2002 SOx 2005 2002 2005 Alaska 0 0 Arizona 8 6 0 0 Colorado 3, 271 3, 302 0 0 Montana 1, 791 2, 267 0 0 33 33 0 0 New Mexico 35, 140 35, 345 1 1 North Dakota 2, 920 2, 799 0 0 73 51 0 0 South Dakota 284 305 0 0 Utah 843 996 0 0 1, 791 3, 288 0 0 46, 154 48, 393 1 1 Nevada Oregon Wyoming WRAP Total Note: Emissions estimates include data from previous work for the NMED in the San Juan Basin and the Southern Ute inventory in Colorado. Other Colorado compressor emissions are assumed to be part of Colorado’s point source inventory and are not included here. 15

2018 Emissions • Emissions estimated for county-level emissions in WRAP region for: NOx, SO

2018 Emissions • Emissions estimated for county-level emissions in WRAP region for: NOx, SO 2, VOC, CO • Emissions included updated growth projections from Resource Management Plans, Alaska Oil & Gas Report, and National Energy Forecast released by the Energy Information Administration (EIA) • Projected emissions to 2018 using 2005 base case and growth factors • State controls evaluated: - Wyoming BACT requirements for permitted sources - Colorado controls requirements for point sources (ERG) - Utah BACT requirements for compressors • Federal controls evaluated: - Federal nonroad engine standards - EPA nonroad diesel fuel sulfur content standards 16

2018 Emissions Projections Drilling Rigs - TPY NOx 2005 Alaska SOx 2018 2005 2018

2018 Emissions Projections Drilling Rigs - TPY NOx 2005 Alaska SOx 2018 2005 2018 835 452 62 1 0 0 Colorado 8, 000 4, 413 350 11 Montana 3, 007 2, 821 640 6 37 21 1 0 New Mexico 8, 640 5, 343 362 3 North Dakota 3, 055 1, 655 688 4 0 0 203 118 43 0 2, 888 944 149 1 Wyoming 15, 783 9, 883 541 3 WRAP Total 42, 448 25, 652 2, 835 29 Arizona Nevada Oregon South Dakota Utah 17

2018 Emissions Projections Compressor Engines - TPY NOx 2005 SOx 2018 2005 2018 Alaska

2018 Emissions Projections Compressor Engines - TPY NOx 2005 SOx 2018 2005 2018 Alaska 0 0 Arizona 6 8 0 0 Colorado 3, 302 4, 006 0 0 Montana 2, 267 3, 946 0 0 33 40 0 0 New Mexico 35, 345 47, 599 1 1 North Dakota 2, 799 18, 399 0 0 51 37 0 0 South Dakota 305 368 0 0 Utah 996 164 0 0 3, 288 655 0 0 48, 393 76, 399 1 1 Nevada Oregon Wyoming WRAP Total Note: Colorado 2018 emissions projections for compressor engines are applied only to the Southern Ute inventory. All other compressor emissions are assumed to be part of Colorado’s point source inventory and are not included here. 18

2018 NOx Emissions Projections All O&G Sources States Alaska Arizona Oil Well –All Sources

2018 NOx Emissions Projections All O&G Sources States Alaska Arizona Oil Well –All Sources Drill Rigs Compressor Engines Gas Well – All Sources CBM Pump Engines All Area Sources All Point Sources 452 0 0 453 36, 382 36, 835 0 8 7 15 382 397 10109 10, 109 14, 825 48, 342 1, 734 California Colorado* 4, 413 12 4, 006 24, 687 400 33, 517 Idaho Montana TOTAL 2, 821 126 3, 946 6, 987 13, 880 2, 533 16, 413 21 2 40 0 63 47 110 New Mexico 5, 343 522 47, 599 20, 183 67 73, 714 36, 320 110, 034 North Dakota 1, 655 126 18, 399 689 20, 869 3, 928 24, 797 0 37 7 44 753 797 South Dakota 118 6 368 66 557 311 868 Utah 944 122 164 5, 066 6, 297 1, 930 8, 227 247 Nevada Oregon Washington Wyoming WRAP Total 9, 883 147 655 22, 449 1, 008 34, 142 9, 075 43, 217 25, 652 1, 063 75, 222 80, 140 1, 475 183, 551 118, 576 302, 127 *Note: Colorado 2018 emissions projections for compressor engines are applied only to the Southern Ute inventory. All other compressor emissions are assumed to be part of Colorado’s point source inventory and are not included here. 19

2018 SOx Emissions Projections All O&G Sources States Drill Rigs Oil Well - All

2018 SOx Emissions Projections All O&G Sources States Drill Rigs Oil Well - All Sources Compressor Engines Gas Well - All Sources CBM Pump Engines All Area Sources All Point Sources TOTAL Alaskaa 1 0 0 1 79 80 Arizona 0 0 0 0 997 129 140 10 10 California Coloradob 11 0 0 11 Idaho Montana 6 0 0 0 6 16 22 Nevada 0 0 0 0 0 New Mexico 3 0 1 7 0 12 12, 990 13, 002 North Dakota 4 0 0 0 4 2, 672 2, 676 Oregon 0 0 8 8 South Dakota 0 0 0 15 Utah 1 0 0 0 1 0 1 4 4 Washington Wyoming WRAP Total 3 0 0 3 9, 067 6, 423 29 0 1 7 0 38 23, 340 23, 378 *Note: Colorado 2018 emissions projections for compressor engines are applied only to the Southern Ute inventory. All other compressor emissions are assumed to be part of Colorado’s point source inventory and are not included here. 20

Discussion of Phase I vs Phase II NOx and SOx Emissions Inventory • Wyoming

Discussion of Phase I vs Phase II NOx and SOx Emissions Inventory • Wyoming NOx emissions decrease from 2005 to 2018 – due to wellhead compressor emissions reduction, implementation of the BACT controls requirement by 2018 • Oil vs. gas wells – corrected the Phase I assumption of emissions based on all gas production, no gas equipment on oil wells. • SO 2 emissions in both 2002 and 2018 have been reduced from Phase I due to improved estimates of actual drilling times based on producer feedback • General trend in both Phase I and Phase II analyses is for SOx emissions to decrease substantially by 2018 due to the phase-in of ultra-low sulfur diesel fuel 21

2018 Point Source SO 2 Emissions • Revised Pechan report on 2018 SO 2

2018 Point Source SO 2 Emissions • Revised Pechan report on 2018 SO 2 emissions projections to incorporate ENVIRON projection methodology and producers’ information on growth forecasts and emissions controls • Identified major SO 2 point source emissions sources in each state of interest • Obtained producer information on control strategy effectiveness, implementation rate, timetable and growth trends from 2002 – 2005 as well as for 2018 based on production forecasts • Conducted review of Title V Permits to determine emissions with and without control technologies • Revised estimates of 2018 emissions 22

2018 Point Source SO 2 Emissions Wyoming Plant Name Operator County Previous 2018 SO

2018 Point Source SO 2 Emissions Wyoming Plant Name Operator County Previous 2018 SO 2 Emissions [tpy] (Pechan) Updated 2018 SO 2 Emissions [tpy] Whitney Canyon Gas Plant BP Uinta 9, 172 0 Lost Cabin Gas Plant Burlington Fremont 3, 170 2, 378 Carter Creek Gas Plant Chevron Uinta 1, 184 284 Beaver Creek Gas Plant Devon Fremont Shute Creek Facility Exxon Lincoln 2, 651 52 Elk Basin Gas Plant Howell Petroleum Park 2, 136 1, 500 Oregon Basin Gas Plant Marathon Oil Park 438 350 Worland Gas Plant Highland Partners Washakie Brady Gas Plant Anadarko Sweetwater Total 42 318 210 181 18, 961 3, 666 23

2018 Point Source SO 2 Emissions New Mexico Plant Name Operator County Previous 2018

2018 Point Source SO 2 Emissions New Mexico Plant Name Operator County Previous 2018 SO 2 Emissions [tpy] (Pechan) Updated 2018 SO 2 Emissions [tpy] Maljamar Gas Plant Frontier Field Services Lea 3, 373 3, 574 Indian Basin Gas Plant Marathon Oil Eddy 2, 794 1, 100 Artesia Gas Plant Duke Energy Eddy 1, 134 19 Monument Gas Plant Targa Midstream Services Lea 1, 159 1, 432 Dagger Draw Gas Plant Agave Energy Eddy 230 243 Denton Gas Plant Davis Gas Processing Lea 399 295 Eunice Gas Plant Duke Energy Lea 953 55 Linam Ranch Gas Plant Duke Energy Lea 1, 261 26 Jal No. 3 Gas Plant Sid Richardson Lea 1, 633 1, 231 Eunice Gas Plant Targa Midstream Services Lea Saunders Gas Plant Total 25 28 12, 936 8, 027 24

Controls Evaluated • Developed a series of white papers on control technologies for drill

Controls Evaluated • Developed a series of white papers on control technologies for drill rigs and compressors and some VOC sources • White papers include only those technologies deemed technically feasible now • List of control technologies includes: − Engine modifications (e. g. , lean-burn engines, ignition timing) − Aftertreatment control devices (e. g. , catalysts, exhaust gas recirculation) − Engine replacement/repowering − VOC controls (e. g. , dehydrators, pneumatics) 25

White Papers • Control effectiveness • Capital and Operating Cost • Potential emissions reduction

White Papers • Control effectiveness • Capital and Operating Cost • Potential emissions reduction • Cost-effectiveness ($/ton) 26

Sources of Information • ENVIRON Field Tests – – – Pilot Project to Assess

Sources of Information • ENVIRON Field Tests – – – Pilot Project to Assess the Effectiveness of an Emission Control System for Gas Compressor Engines in Northeast Texas – 2006 Results from 19 emission tests on 8 different compressor engines less than 500 hp Demonstrated the control efficiency of NSCR using AFR controllers in remote applications • Selected Studies and Sources of Information – – – Technology Demonstration Report – Selective Catalytic Reduction and Bi-Fuels Implementation on Drill Rig Engines, prepared for Shell Rocky Mountain Production LLC and Ultra Petroleum Inc. , Pinedale, WY, June 2006. Manufacturers of Emissions Control Association, Stationary Engine Emission Control, May 2002 Personal Communications with Emission Control Equipment Manufacturers • 4 Corners Air Quality Task Force (AQTF) – – Draft Report of Mitigation Options, Version 5, January 10, 2007 (update this) Conference Calls with the Mitigation Options Workgroup 27

Sources of Information (continued) • U. S. EPA Control Technology Guidelines Stationary Reciprocating Internal

Sources of Information (continued) • U. S. EPA Control Technology Guidelines Stationary Reciprocating Internal Combustion Engines, Alternative Control Techniques Document, EPA-453/R-93 -032 – Final Regulatory Support Document: Control of Emissions from New Marine Compression -Ignition Engines Above 30 Liters Per Cylinder EPA-420 -R-03 -004 – • California Air Resources Board RACT/BARCT Determinations Determination of Reasonably Available Control Technology and Best Available Retrofit Control Technology for Stationary Spark-Ignited Internal Combustion Engines – 2001 – Includes more than 2, 500 test results for engines permitted in California – • NESCAUM Studies Stationary Diesel Engines in the Northeast: An Initial Assessment of the Regional Population, Control Technology Options, and Air Quality Policy Issues – 2003 – Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal Combustion Engines, Technologies and Cost Effectiveness, Northeast States for Coordinated Air Use Management, December 2000. – • EPA Natural Gas Star Program Lessons Learned from Best Management Practices – Technology Reports on Best Management Practices – 28

Summary of Control Options Under Consideration: Compressor Engines Measure No. CE-1 Category Compressor Engines-Rich

Summary of Control Options Under Consideration: Compressor Engines Measure No. CE-1 Category Compressor Engines-Rich Burn Control Measure Name 1 Pollutant Control Efficiency (%) NSCR NOx 90 to 98 HC 50 CE-2 Compressor Engines, SI and CI AFR NOx 10 to 40 CE-3 Compressor Engines, SI and CI ITR NOx 15 to 30 CE-4 Compressor Engines, SI and CI AFR + ITR NOx 10 to 40 CE-5 Compressor Engines, Rich Burn PSC NOx 80 CE-6 Compressor Engines, SI L-E NOx 80 CE-7 Compressor Engines, Lean Burn SCR NOx 80 CE-8 Compressor Engines, All Replace Engine NOx 60 to 100 CE-9 Compressor Engines, All Fuel Switching NOx 30 NSCR - Non-selectic catalytic reduction AFR - Air Fuel Ratio Control, ITR - Ignition Timing Retard, PSC - Prestratified Charge, L-E - Low Emission Engine, SCR - Selective Catalytic R, eduction, EGR - Exhaust Gas Recirculation, CEC - Crankcase Emission Control, DPF - Diesel Particulate Filter, DOC - Diesel Oxidation Catalyst, LNC - Lean NOx Catalyst, NG - Natural Gas, VRU - Vapor Recovery Unit 1 29

Summary of Control Options Under Consideration: Drilling Rigs Measure No. Category Control Measure Name

Summary of Control Options Under Consideration: Drilling Rigs Measure No. Category Control Measure Name 1 Pollutant Control Efficiency % DER-1 Drilling Rig Engines ITR NOx 15 to 30 DER-2 Drilling Rig Engines SCR NOx 80 to 95 DER-3 Drilling Rig Engines EGR NOx 40 DER-4 Drilling Rig Engines CEC PM 6 to 23 DER-5 Drilling Rig Engines DPF PM 85 HC 90 DER-6 Drilling Rig Engines DOC PM 25 HC 90 DER-7 Drilling Rig Engines LNC NOx 10 to 20 DER-8 Drilling Rig Engines Low S PM 14 NG NOx 85 to 90 PM 50 to 80 Emulsion NOx 20 PM 17 NSCR - Non-selectic catalytic reduction AFR - Air Fuel Ratio Control, ITR - Ignition Timing Retard, PSC - Prestratified Charge, L-E - Low Emission Engine, SCR - Selective Catalytic R, eduction, EGR - Exhaust Gas Recirculation, CEC - Crankcase Emission Control, DPF - Diesel Particulate Filter, DOC - Diesel Oxidation Catalyst, LNC - Lean NOx Catalyst, NG - Natural Gas, VRU - Vapor Recovery Unit 1 30

Summary of Control Options Under Consideration: Other Wellhead Sources Measure No. Category Control Measure

Summary of Control Options Under Consideration: Other Wellhead Sources Measure No. Category Control Measure Name 1 Pollutant Control Efficiency % Optimize Circulation VOC 33 to 67 EAP-1 Glycol Dehydration Electric Pump VOC 67 Flash Tank VOC 10 to 40 EAP-2 Pneumatic Controls Instrument Air VOC 98 Non-Bleed VOC 98 EAP-3 Completion Venting and Flaring VOC 62 to 84 Green Completion VOC 70 EAP-4 Tanks VRU VOC 95 Water Blanket VOC TBD NSCR - Non-selectic catalytic reduction AFR - Air Fuel Ratio Control, ITR - Ignition Timing Retard, PSC - Prestratified Charge, L-E - Low Emission Engine, SCR - Selective Catalytic R, eduction, EGR - Exhaust Gas Recirculation, CEC - Crankcase Emission Control, DPF - Diesel Particulate Filter, DOC - Diesel Oxidation Catalyst, LNC - Lean NOx Catalyst, NG - Natural Gas, VRU - Vapor Recovery Unit 1 31

Controls Analysis • Compressor Engines – Cost-effectiveness and NOx reduction potential estimated for –

Controls Analysis • Compressor Engines – Cost-effectiveness and NOx reduction potential estimated for – • Drilling – – range of compressor engines across WRAP region Engine size ranged from 50 hp – 300+ hp Rigs Cost-effectiveness and NOx reduction potential estimated for range of drilling rigs across WRAP region If multiple engines are present on a single rig, control is applied to all engines and the overall “rig” cost-effectiveness and NOx reduction potential reported Drilling rig engines sizes vary from 200 hp – 1500 hp Drilling rig engines vary widely in activity 32

Controls Analysis – Example Calculation: Drilling Rigs Varies with geographic area, average is based

Controls Analysis – Example Calculation: Drilling Rigs Varies with geographic area, average is based on available data from producers Operating Fraction (%/yr) SCR 0. 75 6, 570 $142, 645 Useful Life (years) 10. 0 NOx Emission Factor (g/bhp-hr) 8. 94 1. 12 VOC Emission Factor (g/bhp-hr) 0. 11 Engine Size (bhp) 967 Avg. Load 0. 68 NOx g/hr 5879 735 VOC g/hr 72 NOx tons/year 42. 57 5. 32 VOC tons/year 0. 52 NOx Reduction tons/year 37. 25 VOC Reduction tons/year 0. 00 Annualized Cost-Effectiveness (NOx Only) $3, 829 Annualized Cost-Effectiveness (VOC Only) N/A Annualized Capital Cost No anticipated VOC reduction for this example control measure Baseline 0. 75 Annual usage (hr/yr) Varies by basin, calculation conducted for each basin CATERPILLAR D 398 33

Summary of Emissions Reductions and Cost-Effectiveness: Drill Rigs Measure No. Control Measure Name Control

Summary of Emissions Reductions and Cost-Effectiveness: Drill Rigs Measure No. Control Measure Name Control Efficiency % NOx Reduction [tpy] Cost-Effectiveness [$/ton] DRE-1 ITR 15 to 30 6. 6 to 17. 2 1, 000 to 2, 200 DRE-2 SCR 80 to 95 25. 8 to 66. 8 3, 000 to 7, 700 DRE-3 EGR 40 11. 8 to 30. 6 800 to 2, 000 DRE-7 LNC 10 to 20 4. 4 to 11. 5 1, 400 to 3, 400 DRE-8 Low S Diesel 14 TBD DRE-8 NG 85 to 91 TBD DRE-8 Emulsified Diesel 20 5. 9 to 15. 3 4, 500 to 11, 600 DRE-9 Tier 2 to Tier 4 Replacement 43 to 93 7. 8 to 33. 6 900 to 2, 400 DRE-9 Tier 3 to Tier 4 Replacement 43 to 89 4. 7 to 20. 1 900 to 2, 000 34

Summary of Emissions Reductions and Cost-Effectiveness: Compressor Engines Measure No. Control Measure Name Control

Summary of Emissions Reductions and Cost-Effectiveness: Compressor Engines Measure No. Control Measure Name Control Efficiency % NOx Reduction [tpy] Cost. Effectiveness [$/ton] CE-1 NSCR 90 to 98 1. 0 to 45. 3 200 to 7, 900 CE-2 AFR 10 to 40 0. 3 to 12. 1 100 to 2, 500 CE-3 ITR 15 to 30 0. 3 to 10. 8 100 to 1, 200 CE-4 AFR + ITR 10 to 40 0. 3 to 12. 1 100 to 3, 600 CE-5 PSC 80 0. 9 to 38. 5 100 to 3, 000 CE-6 L-E 80 0. 9 to 38. 5 100 to 2, 600 CE-7 SCR 80 0. 9 to 38. 5 900 to 31, 000 CE-8 Replace Engine 60 to 100 0. 9 to 38. 5 100 to 4, 700 35

Control Options: Summary • For drill rigs most controls fall within the $750/ton-NOx -

Control Options: Summary • For drill rigs most controls fall within the $750/ton-NOx - $2000/ton. NOx range − Exceptions for emulsified fuel, SCR systems which have higher cost -effectiveness • For compressor engines most controls have C-E values $1000/ton-NOx or below except SCR/NSCR • Further information needed on bi-fuel engines and cost – NG cost, infrastructure, piping, etc. 36

Emissions Control Scenarios Proposed Work • For each viable control technology, estimate emissions reduction

Emissions Control Scenarios Proposed Work • For each viable control technology, estimate emissions reduction potential for O&G area sources in each state - Consider controls currently in place - Consider controls required by states and EPA in the future • Focus analysis not only on compressors and drill rigs but also exploration and development sources of VOC emissions • Develop scenarios to show emissions reductions for a range of − Growth projections − Control technology penetration rates • Estimate costs for each scenario - Consider costs already incurred - Consider incremental costs and cost-effectiveness where appropriate 37

Future Work on Oil and Gas Emissions Inventory • Independent Petroleum Association of the

Future Work on Oil and Gas Emissions Inventory • Independent Petroleum Association of the Mountain States (IPAMS) is considering funding a Phase III oil and gas inventory • Phase III would be a collaboration between IPAMS, major oil and gas companies, WRAP and/or other state agencies to develop most comprehensive oil and gas emissions inventory to date • Phase III inventory would improve estimates of all source categories from oil and gas operations and include all major criteria pollutants (NOx, SOx, VOC) • • Engines (e. g. drilling rigs, compressors, CBM pumps) • VOC sources (e. g. pneumatic devices, flares, tank condensates) Phase III to proceed in three steps: 1. Focus on Denver-Julesburg Basin in support of Colorado ozone SIP modeling as a pilot study 2. Expand to include other major basins covered by IPAMS members 3. Develop an annual reporting tool to facilitate future reporting 38