# __________________________________________________________________ (2017) > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/tribal%3Asouthern_ute%3Af353422deecb736d ## Record - **Collection:** Tribal code - **Document type:** Tribal code ## Text __________________________________________________________________ Final Report for 2017 Southern Ute Indian Tribe Comprehensive Emissions Inventory for Criteria Pollutants, Hazardous Air Pollutants, and Greenhouse Gases __________________________________________________________________ Prepared by: Southern Ute Indian Tribe Environmental Programs Division Air Quality Program P.O. Box 737, MS# 84 Ignacio, Colorado 81137 (970) 563-4705 Oil and gas emission calculations prepared by Oakley Hayes, Air Quality Technical Manager Non-oil and gas emission calculations prepared by Matt Wampler, Air Quality Scientist Emission Inventory report prepared by Danny Powers, Air Quality Program Manager and Oakley Hayes, Air Quality Technical Manager December 2019 Table of Contents List of Figures ................................................................................................................................. 3 List of Tables .................................................................................................................................. 3 List of Acronyms ............................................................................................................................ 5 I. Executive Summary ................................................................................................................ 8 II. Overview ................................................................................................................................. 9 1. Purpose of Inventory .................................................................................................... 9 2. Geographic Location of Southern Ute Indian Reservation .......................................... 9 3. Climate........................................................................................................................ 10 4. Geology ...................................................................................................................... 10 5. Sources........................................................................................................................ 10 III. Data Quality Objectives ..................................................................................................... 11 1. Accuracy ..................................................................................................................... 11 2. Uncertainty ................................................................................................................. 12 3. Completeness .............................................................................................................. 12 4. Comparability ............................................................................................................. 12 IV. V. Point Sources ..................................................................................................................... 12 1. Title V Permitted Oil and Gas Sources ...................................................................... 12 2. Minor Oil and Gas Point Sources ............................................................................... 15 3. Permitted Point Sources.............................................................................................. 23 4. Landfill Gas ................................................................................................................ 23 5. Airports ....................................................................................................................... 26 Non-Point Sources ................................................................................................................ 28 1. Small Oil and Gas Sources ......................................................................................... 28 2. Fruitland Formation Outcrop Natural Gas Seeps ....................................................... 64 3. Gas Stations ................................................................................................................ 66 4. Aviation Gasoline ....................................................................................................... 67 5. Gravel Pits .................................................................................................................. 68 6. Residential Heating..................................................................................................... 69 7. Agricultural Burning................................................................................................... 73 VI. VII. 1 Mobile Sources .................................................................................................................. 74 1. On-Road Mobile Sources ........................................................................................... 75 2. Non-Road Mobile Sources ......................................................................................... 76 Events................................................................................................................................. 77 1. Wildland Fires and Prescribed Burns ......................................................................... 77 VIII. Biogenic ......................................................................................................................... 79 IX. Summary ............................................................................................................................ 80 X. Bibliography ......................................................................................................................... 89 XI. Appendix – Quality Assurance Review ............................................................................. 92 2 List of Figures Figure 1: Southern Ute Indian Reservation total criteria pollutant emissions [tons] ..................................................... 9 Figure 2: Criteria pollutant and HAP emissions at Title V sources [tons] ..................................................................... 13 Figure 3: NOx and CO emissions from Title V sources by equipment type [tons] ........................................................ 14 Figure 4: VOC and HAP emissions from Title V sources by equipment type [tons] ...................................................... 14 Figure 5: Title V speciated HAP emissions [tons] ......................................................................................................... 15 Figure 6: Criteria pollutant and HAP emissions from synthetic minor sources [tons] .................................................. 17 Figure 7: NOx and CO emissions from synthetic minor sources by equipment type [tons].......................................... 18 Figure 8: VOC and HAP emissions from synthetic minor sources by equipment type [tons] ....................................... 18 Figure 9: Speciated HAP emissions from synthetic minor sources [tons]..................................................................... 19 Figure 10: Criteria pollutant and HAP emissions from true minor oil and gas sources [tons] ..................................... 21 Figure 11: NOx and CO emissions from true minor oil and gas sources by equipment type [tons] .............................21 Figure 12: VOC and HAP emissions from true minor oil and gas sources by equipment type [tons] ...........................22 Figure 13: GHG emissions from true minor oil and gas sources by equipment type [tonnes] ..................................... 22 Figure 14: Municipal solid waste landfill emissions [tons]........................................................................................... 26 Figure 15: CO and NOx emissions from airports [tons]................................................................................................ 27 Figure 16: VOC and Total HAP emissions from airports [tons] .................................................................................... 28 Figure 17: Criteria pollutant and HAP emissions from small oil and gas sources [tons] .............................................. 30 Figure 18: NOx and CO emissions from small oil and gas sources by equipment type [tons]...................................... 30 Figure 19: VOC and HAP emissions from small oil and gas sources by equipment type [tons] ................................... 31 Figure 20: GHG emissions from small oil and gas sources by equipment type [tonnes].............................................. 31 Figure 21: Speciated HAP emissions from small oil and gas sources [tons]................................................................. 32 Figure 22: Engine counts by engine configuration and horsepower at small oil and gas sources ............................... 33 Figure 23: CO and NOx emission from small oil and gas sources by engine type [tons].............................................. 36 Figure 24: VOC and Total HAP emissions from small oil and gas sources by engine type [tons] ................................. 36 Figure 25: Liquid storage tanks at small oil and gas sources by tank contents ........................................................... 44 Figure 26: VOC and HAP emissions from liquid storage tanks at small oil and gas sources [tons] .............................53 Figure 27: VOC and HAP emissions from Fugitives, Blowdowns, Completions, Recompletions, and Pneumatics [tons] ..................................................................................................................................................................................... 63 Figure 28: GHG emissions from Fugitives, Blowdowns, Completions, Recompletions, and Pneumatics [tonnes] .......63 Figure 29: Average equipment counts at small oil and gas sources by equipment type ............................................. 64 Figure 30: NOx and CO emissions by source category [tons]....................................................................................... 83 Figure 31: VOC emissions by source category [tons]* .................................................................................................. 83 Figure 32: NOx and CO emissions from oil and gas sources [tons] .............................................................................. 85 Figure 33: VOC and HAP emissions from oil and gas sources [tons] ............................................................................ 85 Figure 34: GHG (CO2e) emissions from oil and gas sources [tonnes] ........................................................................... 86 Figure 35: Comparison of NOx, CO, and VOC emissions from the 2014 WRAP EI with 2017 SUIT EI [tons] ................87 Figure 36: Comparison of oil and gas NOx, CO, and VOC emission estimations for the Southern Ute Indian Reservation from the 2015 and 2017 SUIT EIs [tons] .................................................................................................. 88 List of Tables Table 1: Title V criteria pollutant, HAP, and GHG emissions estimations [tons]* ........................................................ 13 Table 2: Title V HAP emissions [tons] ........................................................................................................................... 15 Table 3: 40 CFR Part 49 Minor New Source Review Program Emissions Thresholds ................................................... 16 Table 4: Criteria Pollutant, HAP, and GHG emissions for synthetic minor sources [tons]* .......................................... 17 Table 5: Speciated HAP emissions from synthetic minor sources [tons] ...................................................................... 19 Table 6: Criteria pollutant and HAP emissions from true minor sources [tons]*.......................................................... 20 Table 7: Criteria pollutant and HAP emissions from permitted non-oil and gas point sources [tons] .........................23 Table 8: Municipal solid waste landfill refuse in place [tons] and emissions [tons]* ................................................... 25 Table 9: Criteria pollutant and HAP emission from airports [tons]* ............................................................................ 27 Table 10: Emissions from small oil and gas sources [tons] .......................................................................................... 29 3 Table 11: Speciated HAP emissions from small oil and gas sources [tons] .................................................................. 32 Table 12: Natural gas-fired reciprocating internal combustion engine counts and criteria pollutant, HAP, and GHG emissions for small oil and gas sources [tons]*............................................................................................................ 35 Table 13: Turbine count and criteria pollutant, HAP, and GHG emissions at small oil and gas sources [tons]* ..........38 Table 14: Theoretical extended natural gas analysis - average of 34 natural gas analyses from the Southern Ute Indian Reservation ....................................................................................................................................................... 40 Table 15: GRI-GLYCalc Model input parameters for TEG Dehydration units at small oil and gas sources ..................41 Table 16: GRI-GLYCalc Model emissions output for TEG Dehydration units [tons]...................................................... 42 Table 17: HAP and VOC Emissions from 55 TEG Dehydration Units from small oil and gas sources [tons].................42 Table 18: Assumed annual average liquid throughput values for produced water, oil, and condensate tanks at small oil and gas sources* ..................................................................................................................................................... 45 Table 19: Produced water flash gas analysis from small oil and gas sources on the Southern Ute Indian Reservation [Mol %]* ....................................................................................................................................................................... 48 Table 20: Condensate flash gas analysis from small oil and gas sources on the Southern Ute Indian Reservation [Mol %]*................................................................................................................................................................................ 49 Table 21: Average gas to water and gas to condensate ratios for small oil and gas sources* .................................... 50 Table 22: VOC, HAP, and GHG Emissions from liquid storage tanks at small oil and gas sources [tons]* ...................53 Table 23: Criteria pollutant, HAP, and GHG emissions from heaters and boilers at small oil and gas sources [tons]*55 Table 24: Assumed fugitive emission component counts at single and co-located natural gas well-sites ..................56 Table 25: Emissions of VOC, HAP, and GHG from equipment leaks and fugitive emission sources at small oil and gas sources [tons]* ............................................................................................................................................................. 57 Table 26: VOC, HAP, and GHG emissions from natural gas driven pneumatic devices at small oil and gas sources [tons]* .......................................................................................................................................................................... 59 Table 27: Assumed values for annual natural gas compressor blowdown events occurring at small oil and gas sources in 2017 ............................................................................................................................................................ 60 Table 28: VOC, HAP, and GHG emissions from natural gas blowdowns at small oil and gas sources [tons]* .............61 Table 29: Assumed values for well completion and recompletion activities at small oil and gas sources* .................62 Table 30: VOC, HAP, and GHG emissions from well completion and recompletion activities at small oil and gas sources [tons]* ............................................................................................................................................................. 62 Table 31: Average equipment counts at single and co-located well-sites at small oil and gas sources ......................64 Table 32: Emissions of methane, CO2, and total GHG in CO2 Equivalent [tonnes]....................................................... 66 Table 33: Annual gasoline throughput at gasoline stations located on the Southern Ute Indian Reservation [gal/yr]* ..................................................................................................................................................................................... 66 Table 34: VOC emissions from gasoline dispensing stations [tons] ............................................................................. 67 Table 35: VOC and HAP emissions from aviation gasoline [tons]*............................................................................... 68 Table 36: Emissions of PM10 and PM2.5 from active gravel pits ................................................................................... 69 Table 37: Fireplace and wood burning residential heating data ................................................................................. 70 Table 38: Criteria pollutant and GHG emissions from fireplaces and wood burning stoves [tons]* ............................71 Table 39: Liquid propane residential heating data ...................................................................................................... 71 Table 40: Criteria pollutant and GHG emissions from liquid propane gas heating at residential sources [tons]* .......72 Table 41: Natural gas residential heating data ........................................................................................................... 73 Table 42: Criteria pollutant and GHG emissions from natural gas heating at residential sources [tons]* ..................73 Table 43: Criteria pollutant, NH3, and HAP emissions from agricultural burning [tons]* ............................................ 74 Table 44: Criteria pollutant emissions from on-road mobile sources [tons] ................................................................ 76 Table 45: Criteria pollutant emissions from non-road mobile sources [tons] .............................................................. 77 Table 46: Forest fire occurrence by fuels characteristic classification system, fuel bed type, and acres burned ........78 Table 47: Criteria pollutant, NH3, and GHG emissions from prescribed burns and wildland fires [tons]* ...................79 Table 48: Criteria pollutant and HAP emissions from biogenic sources [tons]* ........................................................... 80 Table 49: Criteria pollutant, HAP, and GHG emissions on the Southern Ute Indian Reservation [tons]*.....................82 Table 50: Emissions from oil and gas sector sources [tons]* ....................................................................................... 84 4 List of Acronyms AP-42 EPA Compilation of Air Pollutant Emission Factors API American Petroleum Institute AQP Air Quality Program BIA United States Bureau of Indian Affairs BSFC Brake Specific Fuel Consumption BTEX Benzene, Toluene Ethyl-Benzene, Xylene bbl Barrel (42 U.S. Gallons) CAA Clean Air Act CARMMS Colorado Air Resource Management Modeling Study CDPHE Colorado Department of Health and Environment CNG Compressed Natural Gas CO Carbon Monoxide CO2e Carbon Dioxide Equivalent COGCC Colorado Oil and Gas Conservation Commission CY Calendar Year CFR Code of Federal Regulations DRMS Colorado Division of Reclamation Mining and Safety EI Emissions Inventory EIA Environmental Impact Assessment EPA United States Environmental Protection Agency FAA Federal Aviation Administration GHG Greenhouse gas GSJB Greater San Juan Basin HAP Hazardous Air Pollutants hp Horse Power H2S Hydrogen Sulfide ICR Information Collection Request ITEP Institute for Tribal Environmental Professionals Kdf Cretaceous Fruitland Formation Kpcl Cretaceous Picture Cliffs Sandstone LFG Landfill Gas 5 LP Liquid Petroleum LTO Landing and Take-off Cycles MMscf Million Standard Cubic Feet MSW Municipal Solid Waste NEI National Emissions Inventory NMHC Non-methane Hydrocarbons NMOC Non-methane Organic Compounds NOx Oxides of Nitrogen NPS National Park Service O3 Ozone Pb Lead PM10 Particulate Matter 10 microns and smaller PM2.5 Particulate Matter 2.5 microns and smaller PSD Prevention of Significant Deterioration PTE Potential to Emit QA Quality Assurance RICE Reciprocating internal combustion engine scf Standard Cubic Feet SO2 Sulfur Dioxide SUIT Southern Ute Indian Tribe TEG Tri-ethylene Glycol TEISS Tribal Emissions Inventory Software Solutions THC Total Hydrocarbons TMNSR Tribal Minor New Source Review Program TOC Total Organic Compounds tpy Tons per Year USFS United States Forest Service VOC Volatile Organic Compounds WIAC Waste Industry Air Coalition WRAP Western Regional Air Partnership 4SLB Four stroke lean burn 4SRB Four stroke rich burn 6 2SLB 7 Two stroke lean burn I. Executive Summary The Southern Ute Indian Tribe (Tribe) Air Quality Program (AQP) has prepared an emissions inventory of all quantifiable point and non-point sources on the Southern Ute Indian Reservation (Reservation) for calendar year 2017 (CY2017). The emissions inventory was prepared according to the Environmental Protection Agency Class II emission inventory guidelines of using measured data when available or data and emissions factors from reputable sources when measured data were not available. Oil and natural gas production is the predominant industry on the Reservation and emissions data for these sources were collected directly from source operators through annual emission inventories, registrations from sources under the Tribal Minor New Source Review (TMNSR) program (true minor sources), and a Clean Air Act (CAA) Section 114 information collection request issued by the Tribe in June 2018. Data for other sources were collected from various reputable state, local, and federal data sources. As of January 2018, there were a total of 3,102 oil and gas production sources operating on the Reservation. These sources consisted of 35 sources operating under Title V operating permits, 6 sources operating under TMNSR permits (synthetic minor sources), 301 true minor sources, and 2,760 non-point sources with emissions below the TMNSR program thresholds, referred to in this emissions inventory as “small oil and gas sources”. Reservation emission totals for CY 2017 were 19,449.22 tons of oxides of Nitrogen (NOx), 15,637.36 tons of Volatile Organic Compounds (VOC), 106.00 tons of Sulfur Dioxide (SO2), 384.58 tons of Particulate Matter 10 micrometers or less in diameter (PM10), 165.02 tons of Particulate Matter 2.5 micrometers or less in diameter (PM2.5), 21,772.45 tons of Carbon Monoxide (CO), 2,428.60 tons of total Hazardous Air Pollutants (HAP), and 6,294,881.55 metric tonnes of Greenhouse Gas (GHG) emissions measured in Carbon Dioxide Equivalent (CO2e). Total criteria pollutant (NOx, VOC, SO2, PM10, PM2.5, CO) and HAP emissions on the Reservation for 2017 are presented below in Figure 1. 8 Figure 1: Southern Ute Indian Reservation total criteria pollutant emissions [tons] II. Overview 1. Purpose of Inventory The purpose of this Emissions Inventory (EI) was to establish baseline emissions estimates for the 2017 calendar year for all quantifiable air emission sources located within the exterior boundaries of Reservation. The emissions data for the Reservation presented in this EI has been organized by source category and pollutant. The EI will be used for future air quality planning purposes, such as development of air quality regulations targeted at ozone precursors for maintaining attainment with the National Ambient Air Quality Standards, emissions modeling, and Title V permitting fee analysis. The primary air pollutants included in this EI are NOx, CO, PM10, PM2.5, VOC, HAP and GHG. 2. Geographic Location of Southern Ute Indian Reservation The Reservation is in southwestern Colorado. The Reservation land area covers 1,066 square miles in three counties (La Plata, Archuleta, and Montezuma) and borders New Mexico to the south. The total area covered by this inventory is approximately 682,590 acres, which encompasses all land within the external boundaries of the Reservation. The Southern Ute Indian Tribe (Tribe) and/or its members own approximately 320,000 acres, while the remaining land mass is comprised of non-Indian and government land in a checkerboard fashion. The primary land use is agricultural, and the predominant industry is oil and natural gas production. 9 3. Climate The Reservation remains generally semi-arid throughout the year. Located north of northern New Mexico desert land and south of the Colorado alpines, the average temperature range during the winter months is between twenty- and forty-degrees Fahrenheit. Freezing temperatures are common throughout the winter and during the 2017 calendar year the coldest month was February with a low of -3.05 degrees Fahrenheit and a monthly average of 26.8 degrees Fahrenheit. During the summer months the temperature typically remains in the high eighties to low nineties. The warmest month of 2017 was July with a high of 93.87 degrees Fahrenheit, and a monthly average of 71.3 degrees Fahrenheit. Snow is the dominant form of precipitation on the Reservation and total precipitation for calendar year 2017 was 8.81 inches. The driest months were June and December with 0 inches of precipitation and the wettest month was July with 2.48 inches of precipitation. 1 4. Geology The Reservation is situated in the northern portion of the San Juan Basin, a geologic structural basin underlying southwestern Colorado and northwestern New Mexico. The basin is composed of Cambrian to Holocene aged sedimentary rocks and contains one of the largest coal-bed methane natural gas fields in the world within the Cretaceous aged Fruitland Formation. 2 The majority of the natural gas production on the Reservation is coalbed methane from the Fruitland Formation, but conventional natural gas is also produced from Cretaceous aged sandstone reservoirs of the Pictured Cliffs Formation, Mesa Verde Group, and the Dakota Sandstone. Tight gas reservoirs of the Cretaceous aged Mancos Shale have also been drilled, however, no significant exploration and production has occurred within the Reservation as of 2017. 5. Sources The sources included in this emissions inventory were organized according to source type and size. These sources are as follows: A. Point Sources 1) Title V permitted oil and natural gas sources 2) TMNSR minor oil and natural gas sources, including: Southern Ute Indian Tribe: Ambient Monitoring. (2017). 2017 AQS Ute 3 Humidity and Temperature Hourly Data. Retrieved from: http://www.southernute-nsn.gov/environmental-programs/air-quality/ambient-monitoring/. 1 Fasset, J. E., & Hinds, J. S. (1971). Geology and Fuel Resources of the Fruitland Formation and Kirtland Shale of the San Juan Basin, New Mexico and Colorado. Geological Survey Professional Paper 676. United States Government Printing Office. Retrieved from https://pubs.usgs.gov/pp/0676/report.pdf. 2 10 a. Permitted minor TMNSR sources, b. Registered minor TMNSR sources, 3) Municipal solid waste landfills, and 4) Airports. B. Non-point Sources 1) Small oil and gas sources, 2) Fruitland Formation Outcrop natural gas seeps, 3) Gasoline stations, 4) Aviation gasoline dispensing, 5) Gravel pits, 6) Residential heating, and 7) Agricultural burning. C. Mobile Sources 1) On-road vehicles, and 2) Non-road equipment. D. Events 1) Fire events (wildland fires and prescribed burns). E. Biogenic Sources III. Data Quality Objectives Data objectives for this inventory are as follows: 1. Accuracy • • • • 11 Data for this EI were collected according to EPA level II EI guidelines using measured data when available or data from reputable sources such as EPA, the Colorado Oil and Gas Conservation Commission (COGCC) and professional organizations when measured data were not available. Emission factors were developed using measured data or commonly accepted emissions factors and assumptions from EPA and professional organizations. All data sources, emission factors, assumptions, and emission calculation methodologies were documented. Emission calculation models were utilized when available (GRI-GLYCalc 4.0, Tanks 4.09d, etc.) and all inputs are provided in annual emission reports or 2017 CAA Section 114 Information Collection Request (ICR) worksheets. • • Results of the 2017 SUIT EI were compared with results from the 2015 SUIT EI and the CY2014 WRAP EI for the Greater San Juan Basin. Quality Assurance review of emission totals, assumptions, emission factors, and calculation methodologies was conducted by a third-party contractor. 2. Uncertainty • • • Reported emissions may be inaccurate. The number of unreported oil and gas sources is unknown and can only be estimated based on sources reported to COGCC. Emissions differences between CY2017 SUIT EI with CY2015 SUIT EI and the WRAP CY2014 EI may occur due to different preparation methodologies and assumptions. 3. Completeness • • • • Capture 100% of point source emissions reported in the annual emission fees for CY2017. Capture 95% of non-point oil and gas sources in the 2018 CAA 114 ICR. Reported information will be used to extrapolate emissions to 100% to fill data gaps. Capture 80% of area sources (gas stations, etc.). 4. Comparability • • IV. EI results will be compared with results from the 2015 SUIT EI and the CY2014 WRAP EI for the Greater San Juan Basin. Emission factors and assumptions will be compared with methodologies used in similar emission calculation applications. Point Sources 1. Title V Permitted Oil and Gas Sources Description of Sources Thirty-five oil and gas Title V sources operated on the Reservation during calendar year 2017. Sources include natural gas compressor stations, central delivery points, treating plants, and processing plants. Title V sources are defined as sources with the potential to emit (PTE) 100 tons per year (tpy) of a single criteria pollutant, 25 tpy of HAP in aggregate, or ten tpy of an individual HAP. The Tribe has full delegation of a Title V operating permit program under 40 CFR Part 70 and during calendar year 2017, 35 oil and gas sources operated under Tribally-issued Title V permits. Data Collection 12 Title V sources are required to report emissions annually and pay a per-ton emission fee for pollutants emitted. Emissions data for Title V sources were collected directly from the calendar year 2017 fee calculation worksheets submitted by each source to the Tribe. Actual emissions data were available for all 35 Title V oil and gas sources. GHG emissions, reported as carbon dioxide equivalent (CO2e) were obtained from fee calculation worksheets (if provided) or were calculated using operator data and an emission calculation tool developed by the AQP. This data collection methodology adheres to the EPA level II EI guidelines for utilizing measured data when available. Emissions Total criteria pollutant, HAP, and GHG emissions estimated from Title V sources for the 2017 calendar year are displayed below in Table 1. Table 1: Title V criteria pollutant, HAP, and GHG emissions estimations [tons]* Pollutant NOx VOC SO2 PM CO HAP GHG (CO2e) Emissions 2,381.89 947.55 28.62 75.97 2,388.07 298.40 1,453,124.10 *CO2e emissions for all Title V sources are reported values obtained from annual Title V fee forms and EPA GHG data and are reported in metric tonnes Total criteria pollutant and HAP emissions by equipment type from Title V sources for the 2017 calendar year are displayed below in Figures 2 through 4. Figure 2: Criteria pollutant and HAP emissions at Title V sources [tons] 13 Figure 3: NOx and CO emissions from Title V sources by equipment type [tons] *”Other” includes emissions from amine units, excess emission events, blowdowns, maintenance, and fugitive emission sources Figure 4: VOC and HAP emissions from Title V sources by equipment type [tons] *”Other” includes emissions from amine units, excess emission events, blowdowns, maintenance, and fugitive emission sources Speciated HAP emissions from Title V sources are displayed below in Table 2 and Figure 5. 14 Pollutant Emissions Formaldehyde 192.50 Benzene 7.99 Table 2: Title V HAP emissions [tons] Toluene 37.90 Xylenes 21.64 Ethylbenzene 1.92 Acetaldehyde 17.83 Acrolein 12.01 Methanol 6.34 n-Hexane 0.24 Figure 5: Title V speciated HAP emissions [tons] 2. Minor Oil and Gas Point Sources The Tribal Minor New Source Review (TMNSR) permitting program is found at 40 CFR Part §49.151 through §49.164. 3 The TMNSR permitting program includes new or modified source permitting, permits by rule, and a registration program. For the purposes of this inventory, two main categories of emission sources under this program were considered: a.) Permitted TMNSR oil and gas sources, and b.) Registered TMNSR Oil and Gas Sources. The emission thresholds for the TMNSR permitting program are located at 40 CFR Part §49.153. Minor sources with emissions less than the levels displayed in Table 3 below are not required to obtain a permit or register under the program. The emission thresholds from 40 CFR Part §49.153 are displayed below in Table 3. 3 40 CFR Part 49 - Indian Country: Air Quality Planning and Management. (2016). U.S. Government Publishing Office. Retrieved from http://www.ecfr.gov/cgi-bin/textidx?SID=bc4187dbf0b08beb092efe4251fe4493&mc=true&tpl=/ecfrbrowse/Title40/40cfr49_main_02.tpl 15 Table 3: 40 CFR Part 49 Minor New Source Review Program Emissions Thresholds Regulated NSR Pollutant Carbon Monoxide (CO) Nitrogen Oxides (NOx) Sulfur Dioxide (SO2) Volatile Organic Compounds (VOC) PM Total PM10 PM2.5 Lead Fluorides Sulfuric Acid Mist Hydrogen Sulfide (H2S) Total Reduced Sulfur (including H2S) Reduced Sulfur Compounds (including H2S) Municipal Waste Combustor Emissions Municipal Solid Waste Landfill Emissions (measured as non-methane organic compounds) Minor NSR Thresholds for Attainment/ Unclassifiable [tpy] 10 10 10 5 10 5 3 0.1 1 2 2 2 2 2 10 A. Synthetic minor Oil and Gas Sources Description of Sources This category reflects larger emission sources that would be subject to either the Prevention of Significant Deterioration (PSD), Title V operating permit program, or both programs absent enforceable emission limitations to reduce the source’s PTE. These types of permits are often referred to as “synthetic minor permits”. During calendar year 2017, eleven sources on the Reservation operated under TMNSR permits. Of the eleven sources in this category, nine sources are natural gas compressor stations, one source is a natural gas processing plant, and one source is a gravel pit (permitted point source). Seven sources have permits to reduce emissions below Title V permitting thresholds and four sources have permits for various other reasons. Data Collection Only the six oil and gas sources with TMNSR permitted emissions below the Title V permitting thresholds were included in this category to avoid double counting emissions. Emissions from the remaining four oil and gas sources, which hold Title V operating permits issued by the Tribe, were already accounted for under the Title V Oil and Gas Sources category of this inventory. Synthetic minor sources are required to submit annual emissions inventories to EPA Region 8 for the pollutants regulated under each permit and emissions data was collected directly from the annual emissions inventories submitted for calendar year 16 2017 4. For the pollutants that were not reported to EPA Region 8, AQP calculated emissions or utilized data that was submitted for its 2015 emission inventory. This data collection methodology adheres to the EPA level II EI guidelines for using measured data when available. Emissions Total 2017 criteria pollutant, HAP, and GHG emissions from permitted TMNSR oil and gas sources on the Southern Ute Indian Reservation are presented below in Table 4. Table 4: Criteria Pollutant, HAP, and GHG emissions for synthetic minor sources [tons]* Pollutant NOx CO VOC Emissions 315.97 206.10 165.94 *GHG emissions reported in metric tonnes. PM 3.78 SO2 5.84 Total HAP 35.61 GHG (CO2e) 98,310.54 Total criteria pollutant and HAP emissions from synthetic minor sources on the Southern Ute Indian Reservation by equipment type are presented below in Figure 6, Figure 7, and Figure 8. Figure 6: Criteria pollutant and HAP emissions from synthetic minor sources [tons] Synthetic Minor Source Criteria Pollutant and HAP Emissions (tons) 35.61 206.10 315.97 165.94 3.78 5.84 NOx 4 VOC SO2 PM CO Total HAP Emissions from Southern Ute Indian Tribe (2018). CY 2017 EPA TMNSR Fee Forms. 17 350.00 309.52 Figure 7: NOx and CO emissions from synthetic minor sources by equipment type [tons] Synthetic Minor Source NOx and CO Emissions by Equipment Type (tons) 199.31 300.00 250.00 200.00 150.00 Engine Turbine Heater Boiler NOx Tank Dehydrator 1.61 0.27 1.27 1.49 0.00 0.00 0.12 3.80 4.55 0.14 0.00 0.00 50.00 0.00 100.00 Other CO *”Other” includes emissions from insignificant emission units Figure 8: VOC and HAP emissions from synthetic minor sources by equipment type [tons] 160.00 140.00 136.02 Synthetic Minor Source VOC and Total HAP Emissions by Equipment Type (tons) 120.00 100.00 80.00 Engine Turbine Heater Boiler VOC Tank Dehydrator 0 2.11 6.16 13.18 1.08 14.38 0.00 0.01 0.01 0 0.00 0 20.00 0.25 40.00 28.36 60.00 Other Total HAP *”Other” includes emissions from insignificant emission units Total 2017 speciated HAP emissions from synthetic minor sources on the Southern Ute Indian Reservation are displayed below in Table 5 and Figure 9. 18 Table 5: Speciated HAP emissions from synthetic minor sources [tons] Pollutant Emissions Formaldehyde 17.95 Benzene 0.85 Toluene 2.32 Xylenes 4.10 Methanol 1.33 Acetaldehyde 4.72 Acrolein 2.95 n-Hexane 1.17 Figure 9: Speciated HAP emissions from synthetic minor sources [tons] Synthetic Minor Source Speciated HAP Emissions (tons) 20.00 18.00 17.95 16.00 14.00 12.00 10.00 8.00 6.00 4.10 4.00 2.00 0.00 0.85 2.32 4.72 2.95 0.00 1.33 1.17 B. Registered Tribal Minor New Source Review Oil and Gas Sources Description of Sources The TMNSR program required operators of true minor sources as defined in §49.152, to register each oil and gas source with EPA Region 8 by no later than March 1, 2013. Existing oil and gas sources constructed or modified after March 1, 2013, but before October 3, 2016 were also required to register. All oil and gas sources constructed after March 1, 2013 are required to apply for a site-specific TMSNR permit or comply with the Oil and Gas Federal Implementation Plan for Indian Country at 40 CFR Part 49, Subpart C. As of January 2018, EPA Region 8 had received 301 oil and gas source registrations for the Reservation. 5 The registrations included source locations, emission unit descriptions, and actual emissions calculations. All the registered sources are natural gas production sources, primarily well-sites. Certain non-oil and gas sources, such as hot mix asphalt plants and stone quarrying, crushing and screening operations, also required registration with the EPA under the TMNSR program, but to date, no such sources have been registered. Presumably, non-oil and gas sources that did not register 5 Southern Ute Indian Tribe. (2018). Information Collection Request. 19 with the EPA may exist on the Reservation, and this issue will be addressed below in the data collection section. Data Collection For the purposes of this emission inventory section, only emissions from true minor sources were included. Sources with Title V operating permits or synthetic minor permits were not required to register under 40 CFR Part 49; therefore, there is little risk of double counting emissions from these sources. Emissions from Title V sources and synthetic minor sources were assessed separately, as discussed in Chapter IV Section 1 and 2A of this report. Due to the potential for registration information to be stale or out of date, the AQP issued a mandatory Clean Air Act Chapter 114 ICR in June 2018 to obtain updated and reconciled registration data from each facility operator. The ICR also included data for non-registered oil and gas sources. Specifically, the ICR requested reconciliation of the operational status of each previously registered source, equipment located at each source, and the actual emissions for calendar year 2017. The ICR also requested information that was exempted from TMNSR registration including emissions estimates for engines less than or equal to 50-hp and facility-wide emissions of HAP and GHG. It was anticipated that the ICR could also result in emissions reporting by sources that had never registered with the EPA. This data collection methodology adheres to the EPA level II EI guidelines for utilizing measured data when available. Emissions Total 2017 emissions of criteria pollutants, HAP, and GHG from true minor sources on the Reservation are displayed below in Table 6. Table 6: Criteria pollutant and HAP emissions from true minor sources [tons]* Pollutant NOx CO VOC Emissions 4,609.43 3,507.64 897.09 * GHG emissions reported in metric tonnes. PM 52.36 SO2 25.56 Total HAP 298.65 CO2e 1,365,890.40 Total 2017 criteria pollutant and HAP emissions from true minor sources on the Reservation by equipment type are displayed below in Figures 10 through 12. GHG emissions from true minor sources are displayed below in Figure 13. 20 Figure 10: Criteria pollutant and HAP emissions from true minor oil and gas sources [tons] Figure 11: NOx and CO emissions from true minor oil and gas sources by equipment type [tons] *”Other” consists of combustors, flares, and undefined equipment 21 Figure 12: VOC and HAP emissions from true minor oil and gas sources by equipment type [tons] *”Other” consists of combustors, flares, and undefined equipment Figure 13: GHG emissions from true minor oil and gas sources by equipment type [tonnes] *”Other” consists of combustors, flares, and undefined equipment 22 3. Permitted Point Sources In 2017, one non-oil and gas source operated under a TMNSR permit on the Reservation. This source is a gravel pit. Emissions from the gravel pit were obtained from the 2015 Minor Source Air Permit Application as displayed in Table 7. Table 7: Criteria pollutant and HAP emissions from permitted non-oil and gas point sources [tons] Pollutant Emissions NOx 23.79 CO 6.97 VOC 0.81 PM10 13.03 PM2.5 1.94 PM 28.76 SO2 37.17 Total HAP 0.05 CO2e 29.21 4. Landfill Gas The Southern Ute Indian Tribe has two Class II municipal solid waste (MSW) landfills within the Reservation boundaries. The first one is the Bondad Recycling Center and Depository (Bondad Landfill) located in Bondad, Colorado and the second one is the Archuleta County Landfill, located south of Pagosa Springs, Colorado. Both MSW disposal sites accept nonhazardous residential, commercial, and industrial waste. The Bondad Landfill is owned and operated by Transit Waste, LLC and has been in operation since 1997. The Archuleta County Landfill is owned and operated by Archuleta County and began operation in 1985. The Bondad Landfill operates under a tribally issued Title V operating permit and the Archuleta County Landfill reports annual landfill gas emissions to the Colorado Department of Public Health and Environment (CDPHE). Data Collection Emission data for the Archuleta County Landfill were provided by the Archuleta County Solid Waste Department and included a CY 2017 greenhouse gas report and an Air Pollution Emission Notice and Application for Construction Permit and Design Capacity Report. The Archuleta County Landfill only submitted emissions in CY 2015. AQP extrapolated SW Acceptance volumes for 2016 and 2017 for input in LandGEM 3.02 with a density 0.79 Megagram/cubic yard. The density was estimated from the reported Megagrams per cubic yard for the years 2013 through 2015. All reports were previously submitted by Archuleta County to the CDPHE. Emissions data for the Bondad Landfill were directly obtained from the CY 2017 Title V emissions fee form submitted to the Tribe. Emission Calculation Methodology Emissions for both the Archuleta County and Bondad landfills were estimated using the EPA’s MSW landfill emissions model, LandGEM version 3.02 (LandGEM). 6 The LandGEM U.S. EPA - Landfill Gas Emissions Model. (2018). Retrieved from https://www.epa.gov/catc/clean-air-technologycenter-products#software. 6 23 model estimates total landfill gas, non-methane organic compounds (NMOC), and hazardous air pollutants (HAP). The LandGEM model is based on a first-order decomposition rate equation for quantifying emissions from the decomposition of landfilled waste in MSW landfills. n 1  M i  − kt ij QCH 4 = ∑ ∑ kL0  e  10  i =1 j = 0.1 Where: QCH4 = annual methane generation in the year of calculation (m3/year) i = 1 year time increment n = (year of the calculation) – (initial year of waste acceptance) j = 0.1 year time increment k = methane generation rate (year-1) Lo = potential methane generation capacity (m3/Mg) Mi = mass of waste accepted in the ith year (Mg) tij = age of the jth section of waste mass Mi accepted the ith year (decimal years, e.g., 3.2 years) LandGEM Inputs and Assumptions Complex microbial and biochemical reactions occur within the landfill’s interior after the waste has been deposited. The two primary constituents of landfill gas (LFG) are methane (CH4) and carbon dioxide (CO2). LFG also contains small amounts of non-methane organic compounds, which includes VOC, HAP, and GHG. LandGEM estimates the LFG from anaerobic decomposition of the waste with CH4 and CO2 content between 40 and 60 percent. The LandGEM default used for methane is 50 percent by volume (the model default value). The production of LFG is a continuous process until microbial reactions are limited by substrate or moisture. Other factors include climate, moisture conditions, and types of solid waste accepted (degradable vs. inert). Parameters for climatic conditions used in the LandGEM model were a k-value of 0.02 year-1 (an arid area that receives less than 25 inches of rain annually) and a Lo-value of 170 cubic meter per megagram. The VOC concentrations are assumed to be 39 percent of NMOC concentrations, consistent with the footnote C Table 2.4-2 of the EPA’s publication titled AP-42, Fifth Edition Compilation of Air Emission Factors (EPA AP-42). 7 For the Bondad Landfill, the concentrations of HAPs in the LFG were taken from the values reported in the Waste Industry Air Coalition (WIAC) report titled Comparison of Recent Landfill Gas U.S. Environmental Protection Agency. (2018). AP-42: Compilation of Air Emission Factors. Retrieved from https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors. 7 24 Analyses with Historic AP-42 Values. 8 For HAP compounds not listed in the WIAC report, emission factors from EPA AP-42 Table 2.4-1 and Section 2.4-4 were used. HAP emissions for the Archuleta County Landfill are from the LandGEM report using default emissions factors from EPA AP-42. The total estimated emissions of LFG were estimated using the flow rate and molecular weights. Emissions The estimated LandGEM emissions for Bondad Landfill were provided to the Tribe in a Title V emissions fee form package submitted by Transit Waste for calendar year 2017. Emissions estimates for Archuleta County Landfill were calculated by the Tribe using LandGEM and the waste acceptance rates and waste-in-place data values for 2017 taken from the 2017 GHG report previously submitted by Archuleta County to the CDPHE. The AQP used the same assumptions and climatic parameters used in the report for Bondad Landfill as these values have been previously reviewed and deemed acceptable when preparing the Title V permit for the Bondad Landfill. To avoid double counting emissions from the Bondad Landfill, emissions from Bondad Landfill were only included in the Landfill gas emission totals and not included in the Title V emission totals presented in Section IV.1 of this report. Total refuse in place in tons and total emissions of GHG, VOC and HAP from MSP landfills on the Reservation for 2017 are displayed below in Table 8 and Figure 14. Table 8: Municipal solid waste landfill refuse in place [tons] and emissions [tons]* Refuse in Place GHG VOC HAPs¹ Bondad Landfill 1,151,013 3,364.60 4.68 1.17 Archuleta County Landfill Totals 386,525 1,537,538 11,016.28 14,379.88 1.78 6.46 1.32 2.49 *An insignificant quantity of double counting of VOCs occurs because many reported HAPs are also considered VOCs. 8 Waste Industry Coalition. (2001, January). Comparison of Recent Landfill Gas Analysis with Historic AP-42 Values. 25 Figure 14: Municipal solid waste landfill emissions [tons] Landfill VOC and Total HAP Emissions (tons) 5 4.68 4.5 4 3.5 3 2.5 1.78 2 1.5 1.32 1.17 1 0.5 0 Bondad Archuleta VOC Total HAP 5. Airports There are three airports located within the Reservation, the Durango-La Plata County Airport, the Animas Air Park, and the Animas Air Park Helipark. Data Collection The AQP obtained CY 2015 data from EPA’s National Emissions Inventory database (NEI), which includes total landing and take-off cycles (LTOs) and piston and turbine engine emission estimates for the heliport, taxi, and general aviation at the Animas Air Park. 9 The LTOs were from the Federal Aviation Administration (FAA). The methodologies used by EPA to calculate airport emissions are detailed in the Eastern Research Group’s document titled Documentation for Aircraft Component of the National Emissions Inventory Methodology. 10 Emissions data for the Animas Air Park and Animas Air Park Heliport were submitted to the NEI by EPA. Emissions data for the Durango-La Plata airport were reported to the NEI by the CDPHE. U.S. EPA National Emission Inventory Emissions Inventory System. (2016). Retrieved from https://www.epa.gov/air-emissions-inventories/national-emissions-inventory-nei. 9 Eastern Research Group. (2001, January). Documentation for Aircraft Component of the National Emissions Inventory Methodology. (ERG No. 0245.03402.011). 10 26 Assumptions Calendar year 2016 airport emissions are assumed to be similar to emissions from the airports during CY 2017. Emissions Total criteria pollutant and HAP emissions from airports on the Reservation for 2017 are displayed in Table 9 and Figure 15 and Figure 16 below. Table 9: Criteria pollutant and HAP emission from airports [tons]* Animas Air Park Heliport Animas Air Park Durango-La Plata County NOx 0.01 0.40 34.47 VOC 0.01 0.84 16.64 SO2 0.00 0.08 4.20 PM2.5 0.01 0.51 3.30 PM10 0.01 0.66 3.84 Lead 0.00 0.03 0.1 CO 0.27 30.93 167.24 Total HAP 0.00 0.31 4.71 34.87 17.50 4.28 3.82 4.51 0.13 198.43 5.02 Total Emissions estimations for airports are from the 2016 EPA National Emission Inventory Database and assumed to be realistic estimations of airport emissions for 2017. * Figure 15: CO and NOx emissions from airports [tons] Airport NOx and CO Emissions (tons) 180.00 167.24 160.00 140.00 120.00 100.00 80.00 60.00 40.00 34.47 20.00 0.00 30.93 0.40 Durango-La Plata County Animas Air Park NOx 27 0.01 CO 0.27 Animas Air Park Heliport Figure 16: VOC and Total HAP emissions from airports [tons] Airport VOC and Total HAP Emissions (tons) 18.00 16.64 16.00 14.00 12.00 10.00 8.00 6.00 4.71 4.00 2.00 0.00 0.84 Durango-La Plata County Animas Air Park VOC V. 0.31 0.01 0.00 Animas Air Park Heliport Total HAP Non-Point Sources 1. Small Oil and Gas Sources Description of Sources For the purpose of this EI small oil and gas sources are defined as: oil and gas sources with emissions below the thresholds that require registration under the EPA Tribal Minor New Source Review (TMNSR) Program at 40 CFR Part 49. The majority of these sources are natural gas and oil well-sites, which are comprised of artificial lift engines, separators, filter coalescers, compressor engines, reciprocating compressors, lube oil tanks, tank heaters, dehydration units, and produced water, condensate, and oil tanks. Data Collection Source information for small oil and gas sources was obtained through a mandatory Clean Air Act Section 114 ICR issued by the AQP in June of 2018 to each known operator with sources operating on the Reservation. To identify the operators within the Reservation and estimate the total number of small oil and gas sources on the Reservation, the AQP compiled site and ownership data from the COGCC and Drilling Edge databases. 11,12 11 COGCC. (2018). Production Data. La Plata. Retrieved from http://cogcc.state.co.us/data2.html#/downloads. 12 Drilling Edge Database (2018). Retrieved from http://www.drillingedge.com/colorado. 28 The ICR was the basis for collecting the information necessary to calculate emissions from small oil and gas sources and required each recipient to provide actual equipment counts and production information. Data was requested for each company’s operations on the Reservation in its entirety and not specific to any single source location. Completed ICRs were submitted by 100% of the companies that reported production on the Reservation in CY 2017 to the COGCC or Drilling Edge databases. Data obtained from the ICRs accounted for the equipment and production associated with the 2,760 known non-registered oil and gas sources on the Reservation. The AQP used ground surveys to estimate equipment counts for the remaining unreported sources. Calculation Methodology The AQP calculated emissions for small oil and gas sources on an equipment basis using measured data, widely accepted emission factors and emission calculation methodologies, the equipment counts reported in the ICR, and CY 2017 production data from the COGCC and Drilling Edge databases. Descriptions of how emissions were calculated for each equipment type are included later in this section. Emissions Criteria pollutant, HAP, and GHG emission estimations from small oil and gas sources on the Reservation in 2017 are displayed below in Table 10. Table 10: Emissions from small oil and gas sources [tons] Pollutant Emissions NOx 11,388.39 VOC 1,091.58 SO2 3.95 PM 176.37 CO 9,362.51 Total HAP 256.12 GHG (CO2e) 1,222,159.41 Criteria pollutant, HAP, and GHG emissions from small oil and gas sources on the Reservation by equipment type are displayed below in Figures 17 through 20. 29 Figure 17: Criteria pollutant and HAP emissions from small oil and gas sources [tons] Small Oil and Gas Source Criteria Pollutant and Total HAP Emissions (tons) 256.12 9,362.51 11,388.39 176.37 3.95 1,091.58 NOx VOC SO2 PM CO Total HAP 12,000.00 10,000.00 11,141.43 9,155.23 Figure 18: NOx and CO emissions from small oil and gas sources by equipment type [tons] Small Oil and Gas Source NOx and CO Emissions by Equipment Type (tons) 8,000.00 6,000.00 - NOx *”Other” consists of venting wells 30 CO - - - - - - - - 53.78 45.17 192.94 162.07 2,000.00 0.24 0.04 4,000.00 Figure 19: VOC and HAP emissions from small oil and gas sources by equipment type [tons] 124.06 200.00 3.77 0.06 15.61 0.12 Completions Recompletions 13.73 2.31 0.11 Blowdowns 2.96 1.01 Boiler 11.77 10.61 3.33 Heater 24.19 12.29 0.01 0.00 50.00 Turbine 100.00 3.63 150.00 0.02 250.00 173.53 210.05 300.00 193.97 350.00 254.36 286.22 Small Oil and Gas Source VOC and Total HAP Emissions by Equipment Type (tons) VOC Other Pneumatics Fugitives Dehydrator Tank Engine - Total HAP *”Other” consists of venting wells Figure 20: GHG emissions from small oil and gas sources by equipment type [tonnes] 450,000.00 210,291.29 350,000.00 277,961.58 400,000.00 300,000.00 250,000.00 200,122.93 500,000.00 436,235.58 Small Oil and Gas Source GHG (CO 2 e) Emissions by Equipment Type (tonnes) - *”Other” consists of venting wells 31 6,311.32 10,720.29 4,667.01 2,360.28 292.01 50,000.00 14,327.04 100,000.00 255.91 150,000.00 58,614.17 200,000.00 2017 Speciated HAP emissions are displayed below in Table 11 and Figure 21. Table 11: Speciated HAP emissions from small oil and gas sources [tons] Pollutant Formaldehyde 147.01 Emissions Benzene Toluene Xylenes 25.43 11.28 7.59 Ethylbenzene 3.36 Acetaldehyde 20.75 Acrolein Methanol 19.49 11.48 nHexane 7.31 Figure 21: Speciated HAP emissions from small oil and gas sources [tons] Small Oil and Gas Source Speciated HAP Emissions (tons) 160.00 147.01 140.00 120.00 100.00 80.00 60.00 40.00 25.43 20.00 11.28 3.36 7.59 20.75 19.49 11.48 7.31 0.00 A. Natural Gas-Fired Reciprocating Internal Combustion Engines Description of Units Natural gas-fired spark-ignited reciprocating internal combustion engines (RICE) are used by the oil and gas industry to compress natural gas, pump liquids, generate electricity, and to provide artificial lift. The most prevalent pollutants emitted from natural gas-fired RICE are NOx, CO, VOC, and HAP. Data Collection The ICR required recipients to list the total number of natural gas-fired spark-ignition and compression ignition RICE operated by their company on the Reservation. Engines were reported according to horsepower range, and engine configuration. Engine configurations included two-stroke lean-burn (2SLB), four-stroke lean-burn (4SLB), fourstroke rich-burn (4SRB), and diesel. The ICR included assumed values for engine operating hours and average brake specific fuel consumption (BSFC) and provided recipients the option to provide values more representative of their operations. A 32 summary of reported engines at small oil and gas sources on the Reservation in 2017 are displayed below in Figure 22. Figure 22: Engine counts by engine configuration and horsepower at small oil and gas sources Number of Engines Located at Small Oil and Gas Sources 700 626 600 500 400 300 4SLB 101-200 hp 4SLB 201-300 hp 4SLB 401-500 hp 4SLB 601-700 hp 64 1 2 1 1 4SRB 601-700 hp 1 4SRB 401-500 hp 1 4SRB 301-400 hp 9 4SRB 201-300 hp 16 4SRB 101-200 hp 16 4SRB 51-100 hp 35 4SRB 0-50 hp 16 4SLB 51-100 hp 54 4SLB 0-50 hp 7 2SLB 501-600 hp 44 2SLB 301-400 hp 2SLB 0-50 hp 0 7 2SLB 201-300 hp 52 2SLB 101-200 hp 100 219 2SLB 51-100 hp 200 Emission Calculation Methodology Criteria Pollutant and HAP Emissions: Criteria pollutant and HAP emissions were calculated for each engine configuration and horsepower rating category reported in the ICR. Emission calculations were based on the maximum horsepower of each reported horsepower range, the appropriate emission factors for stationary internal combustion sources from Chapter 3 of EPA AP-42, an assumed BSFC of 7,500 Btu/hp-hr (if the operator did not input anything more representative of their operating conditions), an assumed 100% engine operating load, and assumed operating schedule of 8,760 hours per year (if the operator did not input a different number of annual operating hours). The assumed BSFC value was derived by averaging the BSCF from all natural gas-fired engines in the Caterpillar Gas Engine Rating Pro software. 13 All emissions were calculated for uncontrolled operation. The natural gas on the Reservation contains negligible amounts of sulfur, therefore SO2 emissions from engines are minimal. GHG Emissions: Caterpillar, Inc. (2015). Gas Engine Rating Pro Emissions Estimation Software. Retrieved from http://www.cat.com/en_US/articles/solutions/oil-gas/gas_engine_rating_pro.html. 13 33 Greenhouse gas emissions were calculated using the default values from Tables C-1 and C-2 of 40 CFR Part 98, Subpart C and the same methodology as used for criteria pollutants and HAP. 14 Example Calculation Calculation of engine heat rate (MMBtu/hr) using AQP’s assumed brake specific fuel consumption (Btu/hp-hr): HR (MMBtu/hr) = BSFC (7500 Btu/hp-hr)/10^6 x hp Where: HR = heat rating (MMBtu/hr) BSFC = brake-specific fuel consumption hp = engine horsepower Engine emission calculation: tpy = (EF) x HR x OH/2000 pounds/ton Where: tpy = tons per year EF = emission factor (lb/MMBtu) HR = heat rate OH = annual operating hours Example NOx emissions calculation for a 200 hp four-stroke rich-burn engine operating 8,760 hours per year: tpy = (2.21 lb/MMBtu) x (1.5 MMBtu/hr) x (8760 hr)/2000 lb/ton = 14.52 tpy NOx Emissions Total criteria pollutant, HAP, and GHG emissions from natural gas-fired RICE at small oil and gas sources are displayed below in Table 12 and Figures 23 and 24. 40 CFR Part 98 - Mandatory Greenhouse Gas Reporting. (2016). U.S. Government Publishing Office. Retrieved from http://www.ecfr.gov/cgi-bin/textidx?SID=32c4baa0d0aff54fa651d1cdb1cd7934&mc=true&tpl=/ecfrbrowse/Title40/40cfr98_main_02.tpl. 14 34 Table 12: Natural gas-fired reciprocating internal combustion engine counts and criteria pollutant, HAP, and GHG emissions for small oil and gas sources [tons]* Engine Number Configuration of NOx and Horsepower Engines [hp] 2SLB 0-50 hp 52 260.14 2SLB 51-100 hp 7 72.89 2SLB 101-200 hp 44 916.38 2SLB 201-300 hp 7 218.68 2SLB 301-400 hp 54 2249.31 2SLB 501-600 hp 16 999.69 4SLB 0-50 hp 35 304.62 4SLB 51-100 hp 16 214.44 4SLB 101-200 hp 16 428.89 4SLB 201-300 hp 9 361.88 4SLB 401-500 hp 1 67.01 4SLB 601-700 hp 1 93.82 4SRB 0-50 hp 626 2267.53 4SRB 51-100 hp 219 1589.91 4SRB 101-200 hp 64 929.26 4SRB 201-300 hp 1 21.78 4SRB 301-400 hp 2 58.08 4SRB 401-500 hp 1 36.30 4SRB 601-700 hp 1 50.82 Total 1,172 11,141.43 * GHG reported in metric tonnes. 35 CO SO2 PM VOC Total HAP GHG (CO2e) 31.68 8.88 111.58 26.68 273.89 121.73 151.88 16.66 33.32 28.12 5.21 7.29 3816.83 2676.22 1564.19 36.66 97.76 61.10 85.54 9,155.23 0.05 0.01 0.17 0.04 0.42 0.19 0.05 0.03 0.06 0.05 0.01 0.01 0.60 0.42 0.25 0.01 0.02 0.01 0.01 2.42 6.30 1.77 22.20 5.30 54.49 24.22 0.70 0.01 0.02 0.01 0.00 0.00 19.49 13.6 7.99 0.19 0.50 0.31 0.44 157.61 9.85 2.76 34.69 8.28 85.15 37.84 7.57 6.20 12.40 10.47 1.94 2.72 30.37 21.30 12.45 0.29 0.78 0.49 0.68 286.22 6.31 1.77 22.03 5.31 54.60 24.27 5.28 3.62 7.46 6.30 1.17 1.63 32.22 22.54 13.18 0.31 0.82 0.51 0.72 210.05 8717.25 2442.75 30708.83 7328.24 75376.21 33500.54 9690.52 5583.42 11166.84 9422.03 1744.82 2442.75 108994.75 76423.09 44667.38 1046.89 2791.71 1744.82 2442.75 436,235.58 36 VOC 2.72 1.63 4SLB 601-700 hp Total HAP 0.29 0.31 0.78 0.82 0.49 0.51 0.68 0.72 4SRB 201-300 hp 4SRB 301-400 hp 4SRB 401-500 hp 4SRB 601-700 hp 4SRB 101-200 hp 4SRB 51-100 hp 12.45 13.18 4SRB 601-700 hp 4SRB 401-500 hp 4SRB 301-400 hp 4SRB 201-300 hp 4SRB 101-200 hp 4SRB 51-100 hp 4SRB 0-50 hp 4SLB 601-700 hp 50.82 85.54 36.30 61.10 58.08 97.76 21.78 36.66 93.82 7.29 Small Oil and Gas Source Engine NOx and CO Emissions by Engine Type (tons) 3,816.83 1,589.91 2,676.22 2,267.53 2,249.31 929.26 1,564.19 361.88 28.12 4SLB 201-300 hp 67.01 5.21 428.89 33.32 4SLB 101-200 hp 4SLB 401-500 hp 214.44 16.66 4SLB 51-100 hp 999.69 121.73 2SLB 501-600 hp 304.62 151.88 273.89 2SLB 301-400 hp 4SLB 0-50 hp 218.68 26.68 2SLB 201-300 hp CO 21.30 22.54 30.37 32.22 Small Oil and Gas Source Engine VOC and Total HAP Emissions by Engine Type (tons) 85.15 916.38 111.58 72.89 8.88 260.14 31.68 2SLB 101-200 hp 2SLB 51-100 hp 2SLB 0-50 hp NOx 4SRB 0-50 hp 1.94 1.17 10.47 6.30 4SLB 401-500 hp 4SLB 201-300 hp 12.40 7.46 6.20 3.62 4SLB 51-100 hp 4SLB 101-200 hp 7.57 5.28 - 4SLB 0-50 hp 24.27 60.00 2SLB 501-600 hp 37.84 70.00 54.60 90.00 2SLB 301-400 hp 8.28 5.31 30.00 22.03 34.69 40.00 2SLB 201-300 hp 10.00 2.76 1.77 50.00 2SLB 101-200 hp 20.00 9.85 6.31 4,500.00 4,000.00 3,500.00 3,000.00 2,500.00 2,000.00 1,500.00 1,000.00 500.00 - 2SLB 51-100 hp 2SLB 0-50 hp Figure 23: CO and NOx emission from small oil and gas sources by engine type [tons] Figure 24: VOC and Total HAP emissions from small oil and gas sources by engine type [tons] 80.00 B. Stationary Natural Gas Turbines: Description of Units Natural gas-fired stationary turbines are a type of rotary internal combustion engine used by the natural gas industry for natural gas transmission and for electric generation. Turbines operate by introducing compressed air and fuel into a combustion chamber to generate hot gases, which are expanded into the power turbine to rotate the power shaft and create work. Two types of combustion processes are used in turbines, the first being lean-premix staged combustion in which a lean air and fuel mixture is introduced into the combustion chamber, and the second type being diffusion flame combustion where the air and fuel mixing occurs within the combustion chamber. The power shaft is used to run a centrifugal compressor for gas transmission, or to rotate an alternator when used for electric generation. Data Collection The ICR required recipients to list the total number of natural gas-fired turbines operated by their company on the Reservation. Turbines were reported according to horsepower or kilowatt range and, turbine configuration. Turbine configurations included uncontrolled, water-steam injection, and lean-premix. The AQP assumed turbines to operate for 8,760 hours per year. Average brake specific fuel consumption (BSFC) was assumed to be 11,000 Btu/hp-hr, as established in the document titled Stationary Combustion Turbines in the United States. 15 If an operator specific BSFC was reported in the ICR, this value was used in place of the assumed BSFC value. Only one turbine was reported at a small oil and gas source in the ICR. The turbine was a 0-50 hp, lean pre-mix unit, operated 8,760 hours per year, with a BSFC of 11,000 Btu/hphr. Emission Calculation Methodology Criteria Pollutant and HAP Emissions: Criteria pollutant and HAP emissions were calculated based on the maximum reported horsepower, emission factors for stationary gas turbines from Chapter 3.1 of EPA AP-42, 100% engine operating load, an operating schedule of 8,760 hours per year and a reported BSFC of 11,000 Btu/hp-hr. The calculation methodology for natural gas turbines is the same methodology used for reciprocating internal combustion engines and displayed in an example calculation earlier in this section. The natural gas on the 15 McGowin (1973) Stationary Combustion Turbines in the United States. 37 Reservation contains negligible amounts of sulfur, therefore SO2 emissions from turbines are minimal. GHG Emissions: Greenhouse gas emissions were calculated using the default values from Tables C-1 and C-2 of 40 CFR Part 98, Subpart C and the same methodology as used for criteria pollutants and HAP. Emissions Criteria pollutant, HAP, and GHG emissions from natural gas turbines on the Southern Ute Reservation for 2017 are displayed in Table 13. Table 13: Turbine count and criteria pollutant, HAP, and GHG emissions at small oil and gas sources [tons]* Turbine configuration and horsepower Number of turbines NOx CO PM10 VOC Total HAP GHG (CO2e) Lean-Premix 0-50 hp 1 0.24 0.04 0.02 0.01 0.002 255.91 * GHG reported in metric tonnes. C. Tri-Ethylene Glycol Dehydration Units Description of Units Tri-ethylene glycol (TEG) dehydration units are commonly used in the natural gas industry to remove entrained water from the natural gas stream to meet pipeline contract water specifications. The dehydration process begins with routing the natural gas stream through TEG in an absorber (or contactor tower) where the entrained water is absorbed by the TEG. During this step, hydrocarbons present in the natural gas stream are also absorbed in the glycol. Following the absorption step, the water saturated (rich) glycol is then distilled to drive off absorbed water before being re-circulated to the absorber. The distillation step results in emissions of VOC and HAP from the reboiler stillvent. The common still-vent HAP emissions are benzene, toluene, ethyl-benzene, and xylene. Data Collection The AQP collected dehydration unit counts from the ICR, which required operators to enter the total number of dehydration units operated by their company at small oil and gas sources on the Reservation during calendar year 2017. The ICR included assumed dehydration unit operating parameters and a theoretical extended natural gas analysis, as described later in this section, which could be accepted or overridden with values 38 more representative of the operators’ operations. The theoretical extended gas analysis is displayed below in Table 14. 55 dehydration units were reported in the ICR submittals and all submittals accepted the AQP’s assumed operation and natural gas composition values. Emissions Calculation Methodology Emissions for glycol dehydration units were calculated using the GRI-GLYCalc 4.0 model (GLYCalc), the AQP’s theoretical values for dehydration unit operating parameters and natural gas composition, and the methodology outlined in the GLYCalc user’s manual. 16 GLYCalc is the EPA’s preferred method of quantifying emissions from glycol dehydration units for the development of tribal/state/local emissions inventories. 17 Product of combustion emissions from dehydration unit reboilers were included in the emission totals for heaters and boilers presented in Section V.1.E. of this report to avoid double counting. 16 Gas Research Institute. (2000). GLYCalc Version 4.0. Retrieved from http://sales.gastechnology.org/000102.html. U.S. EPA. (1995). Glycol Dehydrator Emissions Test Report and Emissions Estimation Methodology. Retrieved from https://www3.epa.gov/ttn/chief/old/efdocs/glycoldehydratortestreport.pdf. 17 39 Table 14: Theoretical extended natural gas analysis - average of 34 natural gas analyses from the Southern Ute Indian Reservation Component Methane Ethane Propane Isobutane n-Butane Isopentane n-Pentane n-Hexane Carbon Dioxide Nitrogen Hydrogen Sulfide Helium 2,2 Dimethylbutane 2,3 Dimethylbutane Cyclopentane 2-Methylpentane 3-Methylpentane 2,2 Dimethylpentane Methylcyclopentane 2,4-Dimethylpentane 2,2,3-Trimethylbutane Benzene 3,3-Dimethylpentane Cyclohexane 2-Methylhexane 2,3-Dimethylpentane 1,1-Dimethylcyclopentane 3-Methylhexane 1,t-3-Dimethylcyclopentane 1,c-3-Dimethylcyclopentane 3-Ethylpentane 1,t-2-Dimethylcyclopentane 2,2,4 Trimethylpentane n-Heptane Methylcyclohexane Toluene n-Octane Ethylbenzene 2,3-Dimethylheptane m-Xylene p-Xylene o-Xylene n-Nonane n-Decane n-Undecane n-Dodecane n-Tridecane 40 Average 92.2564% 1.1672% 0.3324% 0.0548% 0.0811% 0.0200% 0.0132% 0.0089% 5.9084% 0.1370% 0.0000% 0.0000% 0.0002% 0.0007% 0.0000% 0.0018% 0.0010% 0.0000% 0.0000% 0.0000% 0.0000% 0.0007% 0.0000% 0.0013% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0002% 0.0032% 0.0017% 0.0012% 0.0018% 0.0001% 0.0000% 0.0003% 0.0002% 0.0001% 0.0006% 0.0005% 0.0001% 0.0000% 0.0000% Total: Total VOC: 100.00% 0.53% GRI-GLYCalc Model Input Parameters The AQP developed assumed dehydration unit operational values for natural gas temperature, pressure, and flowrate by averaging operational information from dehydration units at non-registered oil and gas sources provided by two of the largest operators on the Reservation. An assumed extended natural gas analysis was prepared by averaging 34 individual extended gas analyses from natural gas production sector compressor stations that were reported to the AQP in Title V operating permit applications between 2012 and 2014. The AQP’s assumed values were input into the GLYCalc emissions model using a pipeline water content specification of seven pounds of water per MMscf of natural gas, 1.5% H2O lean glycol, and assuming uncontrolled operation with no flash tank. The assumed GLYCalc input parameter values are provided below in Table 15. Table 15: GRI-GLYCalc Model input parameters for TEG Dehydration units at small oil and gas sources Wet Gas Temperature [°F] Wet Gas Pressure [psig] Dry Gas Flowrate/ Throughput [MMscf/day] Lean Glycol Water Content [weight % H2O] Glycol Pump Type Pipeline Water Content Specification [lb H2O/MMscf] 68.5 353.5 0.9 1.5 Electric/ Pneumatic 7.0 GRI-GLYCalc Model Emissions Output: Fifty-five dehydration units were reported for small oil and gas sources in the ICR submittals and all dehydration unit emissions were calculated using the AQP’s default GRI-GLYCalc emissions report. The GRI-GLYCalc report was applied once to each of the 55 dehydration units reported in the ICR, and then summed to derive a reservation-wide emissions estimate for glycol dehydration units located at small oil and gas sources. No operator specific GLYCalc reports or dehydration unit emission estimations were provided in the ICR submittals. Modeled GRI-GLYCalc emissions for a single TEG dehydration unit and using the AQP’s assumed model inputs are provided in Table 16. 41 Table 16: GRI-GLYCalc Model emissions output for TEG Dehydration units [tons] Pollutant Methane Ethane Propane Isobutane n-Butane Isopentane n-Pentane Cyclopentane n-Hexane Cyclohexane Other Hexanes Heptanes Methylcyclohexane 2,2,4-Trimethylpentane Benzene Toluene Ethylbenzene Xylenes C8+ Heavies Total HC Emissions Total VOC Emissions Total HAP Emissions Total BTEX Emissions Uncontrolled Emissions 0.2341 0.0226 0.0211 0.0076 0.0156 0.0057 0.0050 0.0000 0.0080 0.0048 0.0000 0.0000 0.0097 0.0002 0.0237 0.0796 0.0122 0.0998 0.1469 0.6966 0.4399 0.3849 0.2153 Example Calculation Example calculation for VOC emissions from ICR Reported dehydration units: VOC Emissions (tpy) = AQP Generated GRI-GLYCalc Emissions Output x Number of 2018 ICR Reported Dehydration Units Example: 24.2 tpy annual VOC emissions = 0.4399 tpy VOC x 55 reported dehydration units Emissions VOC and HAP emissions from 55 TEG Dehydration Units at non-registered oil and gas sources on the Reservation are provided in Table 17. Table 17: HAP and VOC Emissions from 55 TEG Dehydration Units from small oil and gas sources [tons] Totals 42 Number of Dehydration Units 55 VOC 24.19 HAP 12.29 D. Liquid Storage Tanks Description of Equipment and Emissions Categories The oil and gas industry utilize liquid storage tanks for the storage of produced water, condensate, oil, coolants, and lubricants. The primary emissions from liquid storage tanks are methane, VOC and HAPs. Emission categories include breathing and working losses, flash emissions, and tank loadout. Breathing and Working Losses: Breathing losses occur when vapor expansion generated during temperature fluctuations increases the vapor pressure within a tank and cause fugitive emissions to escape from the roof vent. Light colored tanks and tank heaters can help maintain more consistent tank temperatures and reduce breathing losses by reducing vapor pressure variations. Full tanks also produce lower breathing losses due to less space for vapors to expand and escape from roof vents. Working losses occur when liquids are pumped into and out of storage tanks. The displacement of vapors within the tank and the turbulence caused by the movement of the liquid create airborne vapors. Submerged fill tanks can be effective for reducing turbulence and the creation of airborne vapors. Flash Emissions: Flash emissions are emissions that occur when liquid dumped from the separator into the liquid storage tank goes from higher pressure to lower pressure, resulting in the entrained gas being released as a vapor from the liquid. The gas to liquid ratio, pressure and temperature of the liquids in the separator, and the temperature and pressure of the liquid storage tank influence the amount of flashing losses. Tank Loadout Emissions: Tank loadout emissions are vapor loss from transport tanks that occur during the transfer of liquids from a storage tank to a transport tank. Loadout emissions occur due to the generation of vapors in transport tanks during liquid loading, the transfer of vapors from the liquid storage tank to the transport tank, and the displacement of vapors trapped in transport tanks from previous loads during loading. Data Collection Tank Counts and Data for Calculating Breathing and Working Losses: The ICR required each operator to provide the total number of produced water, condensate, and oil tanks located at their small oil and gas sources on the Reservation. Reported tank counts were based on tank capacity and contents. 43 A summary of tanks reported in the ICR, by tank contents, is displayed below in Figure 25. Figure 25: Liquid storage tanks at small oil and gas sources by tank contents Small Oil and Gas Source Tank Count 1400 1220 1200 1000 800 600 400 200 0 90 Condensate 48 Oil Produced Water The ICR also provided operators with the opportunity to override assumed data values for annual liquid throughput, Reid Vapor Pressure, and general tank characteristics with values more representative of their operations. Tank characteristics include roof type, color, condition, and presence of a tank heater. Development of liquid throughput values is discussed later in this section. Emissions from lubricant oil and glycol storage tanks were assumed to be negligible and no data was requested for these sources. Methodology for Deriving Average Liquid Throughput Values: The AQP developed two types of annual liquid throughput values, based on the availability of data in the COGCC database for sources in La Plata County, Colorado for CY 2017. If data were available from COGCC, the AQP used operator-specific throughput values and if the data were not available, the AQP developed assumed annual average liquid throughput values. The operator-specific annual average liquid throughput values were derived by dividing their total reported produced water and condensate/oil production numbers by the total number of sources that reported production for CY 2017. Assumed average annual liquid throughput values were developed for operators that reported active sources to the COGCC in 2017 but did not report production. The assumed annual throughput value for produced water was derived by dividing the total 44 CY 2017 produced water production values reported to the COGCC database by the total number of reported sources. A combined condensate and oil assumed annual average tank throughput value was derived by dividing the total CY 2017 combined condensate and oil production value reported to the COGCC database by the number of small oil and gas sources that reported condensate or oil production. Not all companies reported condensate or oil production to COGCC, and four companies reported much larger condensate and oil production numbers than other companies producing condensate and oil. Companies that did not produce any condensate or oil and the few companies with large production numbers were dropped from the calculations to avoid skewed production numbers. Assumed annual average liquid throughput values for the produced water, oil, and condensate at non-registered oil and gas sources on the Reservation are displayed below in Table 18. Table 18: Assumed annual average liquid throughput values for produced water, oil, and condensate tanks at small oil and gas sources* Number of Sources Operating in 2017 2017 Oil/Condensate Produced [bbl] 2017 Water Produced [bbl] Average Oil/Condensate per source per year [bbl] Average Water per source per year [bbl] 2,760 15,466 13,992,494 0.15 2,186 Throughput numbers were derived from averaging production numbers from COGCC (2017). Production Data. Retrieved from http://cogcc.state.co.us/data2.html#/downloads. * Emission Calculation Methodology Liquid storage tank emissions are calculated based on three separate emission event categories that occur during normal tank operation at atmospheric pressures, as described earlier in this section. The emissions categories include: breathing and working losses, flash emissions, and loadout emissions. Discussions are provided below the methodologies used to calculate emissions for each tank emissions category. Breathing and Working Losses Data Collection and Assumptions: Emission totals for the Reservation were developed for each individual operator by running the EPA TANKS 4.09d Emissions Estimation Software (TANKS) model once for each tank size and production type category reported in the ICR and then multiplying each modeled emissions total by the number of corresponding tanks reported. 18 U.S. EPA. (2006). TANKS 4.09d Emissions Estimation Software. Retrieved from https://www3.epa.gov/ttnchie1/software/tanks. 18 45 Reported liquid throughput values were used when provided and assumed throughput values were used when data was not provided. Emission Calculations: Standing, and working losses were calculated using the TANKS model and reported or assumed input data values for liquid throughput, Reid vapor pressure, and tank characteristics. An equal distribution through all tanks was assumed by dividing the total production by the total number of tanks in a given category. Produced water was assumed to consist of a mixture of 99% water and 1% condensate. Condensate was assumed to have a Reid Vapor Pressure of 10 in the TANKS model. The default values for crude oil were used for oil tank calculations. The model was run for tanks operating at atmospheric pressure and the TANKS model meteorological conditions for Albuquerque, New Mexico. Emission estimates using this geographic location may be biased slightly higher, as average temperatures in Albuquerque are warmer than within the Reservation. All tanks were assumed to have a cone shaped roof, to be gray in color, and equipped with a tank heater. Liquid Storage Tanks Flash Emissions Data Collection and Assumptions: The ICR requested flash gas liberation data from produced water, condensate, and oil, to aid in calculating flash emissions. No ICR submittals were returned with flash liberation data, as this type of sampling is not common practice on the Reservation. In September 2016, the AQP contracted a third-party vendor to perform flash liberation sampling at well-site locations operated by two different companies on the Reservation. Sampling was performed on the separator at each well-site in order to obtain a pressurized sample. In total, seven produced water samples were obtained from coalbed methane wells of the Fruitland Coal Formation on the east and west sides of the Reservation. Two produced water samples and one condensate sample were obtained from conventional natural gas wells of the Picture Cliffs Sandstone Formation in the south central portion of the Reservation. 19 Due to the very low oil production numbers reported to the COGCC database for La Plata County Colorado in CY2017 and the absence of viable sampling locations, the AQP elected to not obtain oil flash gas samples, but to use the condensate flash sampling results to estimate oil flash emissions Two additional condensate flash samples were provided by an operator that performed sampling in August 2016 from liquid knockout locations on a well-site gathering pipeline 19 Air Pollution Testing, Inc. (2016). Southern Ute Indian Tribe Flash Liberation Analyses. 46 containing natural gas from conventional wells in the southern portion of the Reservation. All sampling reports included an extended gas analysis, gas to water ratio, gas specific gravity, separator temperature and pressure, and ambient temperature and pressure. Results from the six valid produced water samples were averaged to obtain assumed gas composition, gas to water ratio values, gas molecular weight, and gas component weight percent to be used in the development of emission factors for estimating storage tank flash emissions. The same methodology was applied for deriving average composition values from the three valid condensate samples. Averaged extended gas analysis values for produced water and condensate are displayed below in Table 19 and Table 20, respectively. Averaged gas to water and gas to condensate values are displayed below in Table 21. 47 Table 19: Produced water flash gas analysis from small oil and gas sources on the Southern Ute Indian Reservation [Mol %]* Flash Gas Component Sample 1 Sample 2 Sample 3 Sample 4 Sample 5 Sample 6 Average Hydrogen Sulfide Nitrogen Carbon Dioxide Methane Ethane 0.0000% 0.0373% 72.3236% 26.6076% 0.3200% 0.0000% 0.0000% 68.4996% 31.0289% 0.0271% 0.0000% 1.0883% 36.5680% 62.2021% 0.1155% 0.0000% 1.0464% 29.7757% 67.0612% 0.0138% 0.0000% 2.6862% 5.8668% 91.4075% 0.0119% 0.0000% 0.5921% 16.3515% 76.3697% 4.0640% 0.0000% 0.9084% 38.2309% 59.1128% 0.7587% Propane 0.0359% 0.0231% 0.0124% 0.037% 0.0079% 1.0078% 0.1874% Isobutane N-Butane 2,2 Dimethylpropane Isopentane N-Pentane 2,2 Dimethylbutane Cyclopentane 2,3 Dimethylbutane 2 Methylpentane 3 Methylpentane N-Hexane Methylcyclopentane Benzene Cyclohexane 2-Methylhexane 3-Methylhexane 2,2,4 Trimethylpentane Other C7's N-Heptane Methylcyclohexane Toluene Other C'8s N-Octane Ethylbenzene M&P Xylenes O-Xylene Other C9's N-Nonane Other C10's N-Decane Undecanes(11) 0.0036% 0.0100% 0.0000% 0.0028% 0.0039% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.4360% 0.0000% 0.0085% 0.0084% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0037% 0.0108% 0.1872% 0.0000% 0.0000% 0.0008% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0035% 0.0160% 0.0000% 0.0037% 0.0078% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.1881% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0012% 0.0015% 0.0000% 0.0003% 0.0005% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0005% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0006% 0.0000% 0.0000% 0.0091% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0049% 0.0163% 0.0000% 0.0071% 0.0117% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 1.8678% 0.0000% 0.0227% 0.0418% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0081% 0.0514% 0.0196% 0.0000% 0.0000% 0.0141% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0007% 0.0029% 0.0000% 0.0005% 0.0012% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0035% 0.0000% 0.0000% 0.0021% 0.0000% 0.0000% 0.0003% 0.0000% 0.0026% 0.0029% 0.0016% 0.0011% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.1582% 0.1689% 0.0000% 0.1027% 0.0612% 0.0000% 0.0108% 0.0000% 0.0000% 0.0000% 0.2114% 0.0000% 0.1056% 0.0481% 0.0000% 0.0000% 0.0088% 0.0000% 0.2092% 0.0865% 0.1397% 0.2745% 0.0000% 0.0049% 0.0242% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0287% 0.0359% 0.0000% 0.0195% 0.0144% 0.0000% 0.0018% 0.0000% 0.0000% 0.0000% 0.4512% 0.0000% 0.0228% 0.0167% 0.0000% 0.0000% 0.0015% 0.0000% 0.0354% 0.0169% 0.0339% 0.0819% 0.0000% 0.0008% 0.0065% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% Totals: 100% 100% 100% 100% 100% 100% 100% Total VOC: 0.7116% 0.2422% 0.0261% 2.1029% 0.0273% 2.6225% 0.9554% Total HAP: 0.4561% 0.1881% 0.0005% 1.9560% 0.0054% 0.4946% 0.5168% * Air Pollution Testing, Inc. (2016, September). Southern Ute Indian Reservation Flash Liberation Analyses. 48 Table 20: Condensate flash gas analysis from small oil and gas sources on the Southern Ute Indian Reservation [Mol %]* Sample Sample Sample Average 1 2 3 Hydrogen Sulfide 0.000% 0.000% 0.0000% 0.000% Nitrogen 6.633% 5.170% 0.5871% 4.130% Carbon Dioxide 3.053% 2.564% 2.8208% 2.813% Methane 62.466% 62.678% 50.2222% 58.455% Ethane 14.918% 16.162% 20.4293% 17.170% Propane 6.279% 7.028% 12.0540% 8.454% Isobutane 1.371% 1.353% 3.2488% 1.991% N-Butane 1.738% 1.840% 3.6206% 2.400% 2,2 Dimethylpropane 0.000% 0.000% 0.0000% 0.000% Isopentane 0.794% 0.769% 1.7594% 1.107% N-Pentane 0.551% 0.560% 1.0198% 0.710% 2,2 Dimethylbutane 0.000% 0.000% 0.0000% 0.000% Cyclopentane 0.000% 0.000% 0.1844% 0.061% 2,3 Dimethylbutane 0.000% 0.000% 0.0000% 0.000% 2 Methylpentane 0.000% 0.000% 0.0000% 0.000% 3 Methylpentane 0.000% 0.000% 0.0000% 0.000% N-Hexane 0.869% 0.748% 1.4232% 1.013% Methylcyclopentane 0.000% 0.000% 0.0000% 0.000% Benzene 0.105% 0.076% 0.1128% 0.098% Cyclohexane 0.000% 0.000% 0.0000% 0.000% 2-Methylhexane 0.000% 0.000% 0.0000% 0.000% 3-Methylhexane 0.000% 0.000% 0.0000% 0.000% 2,2,4 Trimethylpentane 0.003% 0.003% 0.0291% 0.012% Other C7's 0.000% 0.000% 0.0000% 0.000% N-Heptane 0.557% 0.461% 0.7371% 0.585% Methylcyclohexane 0.000% 0.000% 0.2793% 0.093% Toluene 0.166% 0.126% 0.1768% 0.156% Other C'8s 0.000% 0.000% 0.8700% 0.290% N-Octane 0.304% 0.247% 0.0000% 0.184% Ethylbenzene 0.008% 0.007% 0.0076% 0.008% M&P Xylenes 0.071% 0.074% 0.1086% 0.085% O-Xylene 0.000% 0.000% 0.0000% 0.000% Other C9's 0.000% 0.000% 0.0000% 0.000% N-Nonane 0.088% 0.088% 0.0000% 0.059% Other C10's 0.000% 0.000% 0.0000% 0.000% N-Decane 0.027% 0.048% 0.0000% 0.025% Undecanes(11) 0.000% 0.000% 0.0000% 0.000% Totals: 100% 100% 100% 100% Total VOC: 12.9310% 13.4280% 25.6315% 17.3302% Total HAP: 1.2220% 1.0340% 1.8581% 1.3714% * Air Pollution Testing, Inc. (2016, September). Southern Ute Indian Reservation Flash Liberation Analyses. Flash Gas Component 49 Table 21: Average gas to water and gas to condensate ratios for small oil and gas sources* Gas/Water [scf/bbl] Gas/Condensate [scf/bbl] 3.3 16.5 * Air Pollution Testing, Inc. (2016, September). Southern Ute Indian Reservation Flash Liberation Analyses. Flash Emission Calculation Methodology: Flash emission factors in pounds per barrel (lb/bbl) were developed for VOC, BTEX, methane, and carbon dioxide. The measured gas oil/gas water ratio (scf/bbl) was divided by the ideal gas law conversion factor (scf/lb-mol) and then multiplied by the molecular weight of the flash gas (lb/lb-mol) and then multiplied by the weight percent of each specific component to derive the emission factors. The total emissions were calculated by multiplying the emission factors for each component by the total reported production in barrels. Tank throughput values in barrels per day were either reported values or the assumed values developed by AQP, as described previously in this section. Flash emission totals for the Reservation were developed for each individual operator using either reported or assumed liquid throughput values. Example Emission Factor Development for Flash Emissions: Emission Factor (lb/bbl) = GOR/R*MW*Wt% Where: GOR = measured gas oil/gas water ratio (scf/bbl) R = ideal gas law conversion factor (scf/lb-mol) MW = molecular weight of flash gas (lb/lb-mol) Wt% = weight percent of desired component in flash gas Example Emission Calculation: Emissions (ton/year) = EF*P/2000 Where: EF = emission factor (lb/bbl) P = annual production (bbl/year) 2000 = conversion factor (lb/ton) Liquid Storage Tank Loadout Emissions Data Collection and Assumptions: 50 Tank loadout emissions were calculated by conservatively assuming that all liquid storage tanks are unloaded manually by truck, and not sent through pipeline. Emission factors and emission calculations were derived from Section 5.2 of EPA AP-42 for Transportation and Marketing of Petroleum Liquids. Loading was assumed to be submerged fill and the saturation emission factor for submerged dedicated normal service was selected for calculating loading losses. Truck tank capacity was assumed to be 100 bbl per loadout event and reported or assumed liquid production numbers were used for calculating the number or loadout events per year. Each loadout event was assumed to be one-hour in duration and the assumed annual hours of unloading operations for each operator were directly correlated to the reported or assumed annual liquid production. Molecular weight and true vapor pressure values were derived from TANKS model runs for produced water and condensate. Example Tank Loadout Emissions Calculation Methodology: Tank loadout emissions are calculated using two separate calculations. The first equation is used to estimate the total molecular weight of loading emissions losses and a second equation is used to estimate the total emission rate on a pollutant basis. Both calculations are displayed below: Loading Losses Calculation: L = 12.46 x (S) x (P) x ((MW)/T) x (1-eff) Where: L=Loading Losses (lb/1000 gallons) S = Saturation Factor P = True Vapor Pressure (Pva @ T) MW = Molecular Weight (lb/lb-mol) T = Temperature E = Control Efficiency of Loading Total Emission Rate Calculation: Tons Per Year = L*Annual Throughput/2000*Wt% Where: L = Loading Losses (lb/1000 gallons) Annual Throughput = annual throughput (1000 gallons) 2000 = conversion factor (lb/ton) Wt% = Component Weight Percentage from Flash Gas Analysis 51 Liquid Storage Tank GHG Emissions Tank Flash Greenhouse Gas Emissions: Flash greenhouse gas (GHG) emissions for storage tanks were calculated using the measured data from the flash liberation sampling completed in 2016 from well-sites on the Reservation. Emission factors for Methane and Carbon Dioxide were developed as cited in the Flash Emission Calculation Methodology section of this report. These emission factors were multiplied by the total production and divided by a conversion factor to provide an output in tons per year. This was then multiplied by a conversion factor to convert to metric tonnes and then multiplied by the global warming potential of each component, found in 40 CFR Part 98 Table A-1, to provide an output total in metric tonnes of carbon dioxide equivalent. Example Calculation for Tank Flash GHG Emission: Where: CH4 (CO2e) = (EF*P/CF1)*CF2*GWP EF = emission factor (lb/bbl) P = annual production (bbl/year) CF1 = conversion factor (2000lb/ton) CF2 = conversion factor (0.907185 metric tonnes/ton) GWP = global warming potential (25 for Methane) Tank Loadout GHG Emissions GHG emissions from tank loadout were calculated using the same methodology found in the Liquid Storage Tank Loadout Emissions section of this report. Once the loadout emissions, in tons per year, are determined for a GHG, it is multiplied by a conversion factor to convert it to metric tonnes. This metric tonnes number is then multiplied by the global warming potential of the individual component to provide an output in metric tonnes of carbon dioxide equivalent. Example Tank Loadout GHG Calculations: Where: CO2e = tpy*CF*GWP CO2e = carbon dioxide equivalent (metric tonnes) tpy = emissions (tons per year) CF = conversion factor (0.907185 metric tonnes/ton) GWP = global warming potential of individual pollutant 52 Total Liquid Storage Tank Emissions Total liquid storage tank emissions at small oil and gas sources from working and breathing losses, flash emissions, tank loadout, and GHG emissions on the Reservation are displayed in below in Table 22 and Figure 26. Emissions are displayed by tank contents. Table 22: VOC, HAP, and GHG Emissions from liquid storage tanks at small oil and gas sources [tons]* Tank Contents and Capacity Tank Count Condensate 90 Produced Water 1220 Oil 48 Total Tank Count and Total Emissions 1,358 *GHG emissions reported in metric tonnes VOC 76.72 74.69 22.12 173.53 HAP 0.01 3.52 0.11 3.63 GHG (CO2e) 5.12 14,249.88 72.05 14,327.04 Figure 26: VOC and HAP emissions from liquid storage tanks at small oil and gas sources [tons] Small Oil and Gas Source Tank Emissions (tons) 90 80 76.72 74.69 70 60 50 40 30 22.12 20 10 0 0.11 0.01 Condensate Oil VOC 3.52 Produced Water Total HAP E. External Combustion Sources Description of Sources Natural gas-fired external combustion sources are widely used by the natural gas industry as tank heaters, heated separators, reboilers, and boilers. 53 Data Collection The ICR required each operator to report the total number of heaters and boilers operated by their company on the Reservation. Heater and boiler counts were reported according to heat rate range in MMBTU/hr. Operators were also given the option to report average heater and boiler operating hours to override the AQP’s assumed operating hours. A description of the AQP’s assumed values is included in the emission calculation discussion. Assumptions If no hours of operation were reported in the ICR, AQP assumed heaters to operate 24 hours per day for half of the year (183 days per year) which equates to 4,392 hours per year. Boilers were assumed to operate for 24 hours per day, 365 days a year, which equates to 8,760 hours per year. Emission Calculation Methodology Criteria pollutant and HAP emissions for external combustion sources were calculated using the emission factors from EPA AP-42 Chapter 1.4 for uncontrolled natural gas-fired external combustion sources, the maximum heat rating from each heat rating category reported in the ICR, a default natural gas heating value of 1,026 Btu/scf and assumed or reported operating hours. The AQP used the default natural gas heating value of 1,026 Btu/scf from 40 CFR Part 98 to convert the EPA emission factors from lbs/MMscf to lbs/MMBtu. GHG emissions were calculated using the Tier 1 calculation methodology, the natural gas emission factors from Tables C-1 and C-2 of 40 CFR Part 98 and assumed or reported operating hours. Example Calculations Criteria and HAP Example Calculations: lb/hr = (EF/HV) x (HR) Where: EF = Emission Factor (lb/MMscf) HV = Default Heat Value of Natural Gas fuel (Btu/scf) HR = Heat Rate of Boiler/Heater (MMBtu/hr) 54 Example NOx lb/hr calculation for 0.5 MMBtu/hr natural gas-fired boiler/heater: lb/hr = (100/1,026) x 0.5 = 0.05 tpy = (lb/hr) x OH/2000 Where: (lb/hr) = Emission Rate OH = Annual Operating Hours 2000 = Pounds per ton Example NOx tpy calculation for 0.5 MMBtu/hr natural gas-fired boiler/heater operating 4392 hours per year: tpy = (0.05) x 4392/2000= 0.1098 GHG Example Calculation: GHG Calculation Methodology: Where: = EF x HR x CF x GWP EF = fuel specific default emission factor, from tables C-1 and C-2 of Part 98 (kg/MMBtu) HR = heat rate (MMBtu/hr) CF = conversion factor (lb/kg) GWP = global warming potential Emissions Criteria pollutant, HAP, and GHG emissions from external combustion sources located at non-registered oil and gas sources on the Reservation for calendar year 2017 are displayed below in Table 23. Emissions are displayed by unit count and heat rating in MMBtu/hr. Table 23: Criteria pollutant, HAP, and GHG emissions from heaters and boilers at small oil and gas sources [tons]* Equipment Type Unit and Heat Rating Count Heaters 3343 Boilers 8 Total 3351 *GHG reported in metric tonnes. 55 NOx VOC SO2 PM CO HAP 192.94 53.78 246.72 10.61 2.96 13.57 1.21 0.32 1.53 14.66 4.09 18.75 162.07 45.17 207.25 3.33 1.01 4.34 GHG (CO2e) 210,291.29 58,614.17 268,905.46 F. Equipment Leaks and Fugitive Emissions Description of Sources Natural gas leaks from components commonly used in the natural gas industry result in emissions of methane, CO2, VOC, and HAP. Components include: valves, pumps, pressure relief valves, connectors, flanges, and, open-ended lines. These components are ancillary equipment to many larger equipment source types including: headers, separators, heaters, filters, engines, compressors, dehydration units, and storage tanks. Data Collection The ICR provided operators with the option to report average fugitive component counts for single and co-located well-sites. In the absence of ICR provided component counts, the AQP relied on assumed component counts, as detailed below. Assumptions Fugitive component counts were assumed based on component counts for natural gas production contained in the Canadian Association of Petroleum Producers (CAPP) document titled Guide to Calculating Greenhouse Gas Emissions. 20 Component counts for single and co-located well-site locations are displayed below in Table 24. Table 24: Assumed fugitive emission component counts at single and co-located natural gas well-sites Valves-Gas/Vapor Component count for a Single well 16 Component count for Two co-located wells 32 Component count for Three Co-located wells 48 Component count for Four Co-located wells 64 Connectors-Gas/Vapor 60 120 180 240 Open-Ended Lines-Gas/Vapor 3 6 9 12 Component Type-Service Emission Calculation Methodology GHG, VOC, and HAP Emission Calculations: GHG, VOC, and HAP emissions from equipment leaks and fugitive emissions were calculated using the average emission factor approach and the gas/vapor total organic compound (TOC) emission factors for oil and gas production from Table 2-4 of EPA’s OAQPS document titled Protocol for Equipment Leak Emission Estimates. The TOC Canadian Association of Petroleum Producers. (2003). Guide to Calculating Greenhouse Gas Emissions. Retrieved from http://www.capp.ca/publications-and-statistics/publications/241974. 20 56 emission factor for gas/vapor was chosen as the most representative of production on the Reservation in CY2017 and is the most conservative emission factor available. TOC emissions were calculated by multiplying the gas/vapor emission factor by component counts calculated using the CAPP generic fugitive component count and the number of sources entered in the ICR. Each source was assumed to operate for 8,760 hours annually. GHG, VOC, and HAP emissions were then derived by multiplying the TOC emissions by the GHG, VOC, and HAP molecular weight fraction percentages of an assumed extended natural gas analysis for the Reservation. If component counts were provided by operators in the ICR, emissions for their company’s productions were calculated using their reported counts in place of the CAPP component counts. Example Calculations GHG, VOC, and HAP Emission Calculation Methodology: GHG, VOC, or HAP Emissions = EPA OAQPS Average Emission Factor for Gas Valves x CAPP Generic Valve Count x Annual Operating Hours x (Ton/2000lb0 x weight percent (GHG, VOC, or HAP) = tpy GHG, VOC, or HAP emissions Valves VOC Emissions (tpy) = (0.00992 lb/hr/valve) x 1000 valves x (8760 hr/yr) x (Ton/2000 lb) x (1.51%) = 0.66 tons/year Emissions Volatile organic compound, HAP, and GHG emissions from equipment leak and fugitive emission sources located at non-registered oil and gas sources on the Reservation for calendar year 2017 are displayed below in Table 25. Table 25: Emissions of VOC, HAP, and GHG from equipment leaks and fugitive emission sources at small oil and gas sources [tons]* * Pollutant Emission Totals VOC 254.36 HAP 11.77 GHG (CO2e) 277,961.58 GHG reported in metric tonnes. G. Natural Gas Driven Pneumatic Devices Description of Sources Natural gas-driven pneumatic controllers and pumps are used in the oil and natural gas industry for maintaining liquid levels, pressures, pressure differentials, and temperature. Many devices are designed to leak, or “bleed”, natural gas and in doing so emit natural gas containing methane, CO2, VOC, and HAP. Pneumatic devices are classified as high or 57 low continuous bleed controllers, intermittent bleed controllers, or zero bleed controllers. Data Collection The AQP assigned an assumed value for the average number of pneumatic devices located at a single wellsite from the 2014 Environmental Science and Technology report titled Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States. 21 The assumed pneumatic device count value was provided in the ICR and operators were provided the opportunity to override the assumed value with values more representative of their operations. Emission Calculation Methodology Pneumatic device emissions were calculated by applying the generic natural gas emission factors found in EPA’s April 2014 Report for Oil and Natural Gas Sector Pneumatic Devices to the AQP’s assumed average device count or average device counts reported in the ICR. Example Emission Calculation: lb/hr = Count x Bleed Rate x R x MW x Y Where: Count = total number of devices Bleed Rate = bleed rate from device (scf/hr/device) R = Universal gas constant (lb-mol/379.4scf) MW = molecular weight of the component (lb/lb-mol) Y = volume fraction of component in the vented gas Example for Methane: lb/hr = 2695 x 5.5 x 1/379.4 x 16.01 x 92% = 575.4 lb/hr tpy = lb/hr x OH/2000 Where: lb/hr = emission rate in pounds per hour OH = annual operating hours Allen, D. (2014). Methane Emissions from Process Equipment at Natural Gas Production Sites in the United States: Pneumatic Controllers. Environmental Science & Technology, 49, 633-640. Retrieved from http://pubs.acs.org/doi/pdf/10.1021/es5040156. 21 58 2000 = pounds per ton tpy methane = 575.4 x 8760/2000 = 2520.3 tpy Emissions VOC, HAP, and GHG emissions from natural gas driven pneumatic devices on the Reservation during 2017 are displayed below in Table 26. Table 26: VOC, HAP, and GHG emissions from natural gas driven pneumatic devices at small oil and gas sources [tons]* Pollutant VOC Emission Totals 193.97 * GHG reported in metric tonnes. HAP 13.73 GHG (CO2e) 200,122.93 H. Natural Gas Blowdowns Description of Sources Natural gas blowdowns are intentional and unintentional gas releases during maintenance, routine operations, and emergencies. Blowdowns occur from gas compressors, compressor startups, gas wellbores, vessels, pipelines, and various equipment. Data Collection The ICR requested emissions resultant from maintenance and emergency natural gas blowdowns from compressors. Due to the burden of capturing actual emissions for each blown down event at a large number of small oil and gas sources, emissions from such events are based on assumptions on the amount of gas released, the AQP’s assumed extended gas analysis, and an assumed number of events anticipated during a calendar year. The ICR provided operators with the opportunity to override the AQP’s assumed values with values more representative of their operations. Assumptions The AQP developed assumed values for the number and time duration of annual compressor blowdowns that occur per year and the volume of natural gas vented per event. Assumed values were based on the 2015 Colorado Air Resources Management 59 Modeling Study (CARMMS) 22. The values assumed for 2017 are displayed below in Table 27. Table 27: Assumed values for annual natural gas compressor blowdown events occurring at small oil and gas sources in 2017 Compressors Annual compressor blowdowns per compressor 2 Estimated amount of gas lost per blowdown [Mscf/event] 10 Emissions Calculation Methodology Emissions from natural gas blowdowns were calculated using either the AQP’s assumed extended gas analysis or reported natural gas analysis, and assumed or reported event frequencies, duration, and gas loss values. Example Calculations: Where: tpy = Totalvented x Ideal Gas Density/2000 Totalvented = total volume of gas vented (for specific component) (scf/yr) = (volume vented per blowdown (Mscf/event) x frequency (events/yr) x 1000scf/Mscf) x %vol of component Ideal Gas Density (lb/scf) = MW/(R*T) MW = molecular weight of the component R = universal gas constant (0.730235 scf.atm/°R.lb-mol) T = temperature (60 °F converted to 519.67 °R) 2000 = pounds per ton Emissions Emissions from natural gas blowdown activities occurring on the Reservation during 2017 are displayed below in Table 28. ENVIRON International Corp.; Carter Lake Consulting; Environmental Management and Planning Solutions. (2015). Colorado Air Resources Management Modeling Study. Retrieved from https://www.blm.gov/sites/blm.gov/files/documents/files/program_natural%20resources_soil%20air%20water_air co_quicklins_CARMMS2.0.pdf. 22 60 Table 28: VOC, HAP, and GHG emissions from natural gas blowdowns at small oil and gas sources [tons]* Pollutant VOC Emission Totals 2.31 * GHG reported in metric tonnes. Total HAP 0.11 GHG (CO2e) 2,360.28 I. Well Completion and Re-completion Venting Description of Sources Well completions and recompletions, when not employing closed vent system techniques, also known as “green completions”, release natural gas during the “flow back” stage of the process. Flow back is the stage in which drilling fluid and hydrocarbon reservoir fluids return to the surface prior to well production. Green completion techniques capture flow back materials, including natural gas. Data Collection The number of well completions that occurred in calendar year 2017 were obtained from the COGCC database. A total of 39 well completions occurred on the Reservation in calendar year 2017. No data were available for well recompletions in the COGCC database and an assumed recompletion value of 1% of all operating wells per year was obtained from the 2015 CARMMS. The ICR also provided the opportunity for operators to report the number of well completion and recompletion events that occurred in calendar year 2017, including natural gas lost per event, and completion by type (conventional or green completion). Assumptions Fifty percent of all well completions were assumed to utilize green completion technology with no natural gas vented to atmosphere. Conventional well completions and recompletions were assumed to vent 1,000 Mscf of natural gas per event. These assumptions were derived from the 2015 CARMMS. For well recompletions, the assumed well recompletion value of 1% of all operating wells per year was obtained from the CARMMS study and assumed to be accurate and representative of operations on the Reservation. All completion and recompletion activities were assumed to be either conventional or green completions, based on information provided by two large natural gas operators on the Reservation. Therefore, the AQP did not estimate emissions from flaring events that 61 may occur during well completion or re-completion activities. Assumed well completion and recompletion values for 2017 are displayed below in Table 29. Table 29: Assumed values for well completion and recompletion activities at small oil and gas sources* Completion Type Percent of completions by type: Estimated amount of gas vented to atmosphere per event [Mscf/event]: Estimated amount of gas controlled via closed loop system per event [Mscf/event]: * Assumed values are based on the 2015 CARMMS. Conventional 50% Green Technology 50% 1000 0 0 1000 Emission Calculation Methodology Emissions from well completion and recompletions were calculated using an assumed extended gas analysis and reported or assumed event frequencies and gas loss values. Emissions from drilling engines that are employed during well completion and recompletion activities were not calculated. Emissions Emissions from well completion and recompletion venting on the Reservation in calendar year 2017 are displayed below in Table 30. Table 30: VOC, HAP, and GHG emissions from well completion and recompletion activities at small oil and gas sources [tons]* Pollutant VOC Emission Totals 19.38 * GHG reported in metric tonnes. Total HAPs 0.18 GHG (CO2e) 15,387.30 VOC, HAP, and GHG emissions from Fugitives, Blowdowns, Completions, Recompletions, and Pneumatics are displayed below in Figure 27 and Figure 28. 62 Figure 27: VOC and HAP emissions from Fugitives, Blowdowns, Completions, Recompletions, and Pneumatics [tons] Small Oil and Gas Source VOC and Total HAP Emissions From Various Sources (tons) 300.00 254.36 250.00 193.97 200.00 150.00 100.00 50.00 11.77 - Fugitives 13.73 2.31 Pneumatics 0.11 Blowdowns VOC 3.77 0.06 Completions 15.61 0.12 Recompletions Total HAP Figure 28: GHG emissions from Fugitives, Blowdowns, Completions, Recompletions, and Pneumatics [tonnes] Small Oil and Gas Source GHG Emissions From Various Sources (tonnes) 300,000.00 277,961.58 250,000.00 200,122.93 200,000.00 150,000.00 100,000.00 50,000.00 - Fugitives Pneumatics J. Typical Well-Site Configuration Description 63 2,360.28 4,667.01 10,720.29 Blowdowns Completions Recompletions The AQP compiled equipment count information collected in the previous comprehensive emission inventory ICRs in CY 2015 to prepare average equipment type counts based on the number of natural gas wells located on a single well-pad. This information can be used to gain a better understanding of typical well-site configurations on the Reservation and to assist with estimating emissions from any proposed natural gas development schedules. Average equipment counts at small oil and gas sources on the Reservation are displayed below in Table 31 and Figure 29. Table 31: Average equipment counts at single and co-located well-sites at small oil and gas sources Number of Wells per Pad Heater Separator Dehydrators Compressors Produced Water Tanks Condensate Tanks Engine 1 2 3 4 0.5 1.3 1.6 1.0 1.0 2.4 2.5 3.0 0.2 0.2 0.2 0.0 0.1 0.2 0.1 0.0 0.8 1.4 1.9 1.5 0.1 0.0 0.0 0.0 0.4 1.2 1.5 2.5 Figure 29: Average equipment counts at small oil and gas sources by equipment type 2.5 2 Well 3 Well 2. Fruitland Formation Outcrop Natural Gas Seeps Engine Condensate Tanks 0.1 0 0 0 Produced Water Tanks 4 Well 0.4 1.4 0.8 Dehydrators Compressors 0.1 0.2 0.1 0 0 0.2 0.2 0.2 Separator Heater 1 Well 64 1.2 1.5 1.9 1.5 2.4 2.5 1 1 1.3 1.6 0.5 3.5 3 2.5 2 1.5 1 0.5 0 3 Average Equipment Counts at Single and Co-Located Natural Gas Well Sites by Equipment Type (2015) Description of Sources Naturally occurring methane and CO2 seepage from outcrops of the Cretaceous Fruitland Formation (Fruitland Outcrop) contribute a significant quantity of the GHG emissions on the Reservation. Data Collection The data used to quantify emissions from the Fruitland Outcrop were provided to the AQP from the SUIT Department of Energy (SUIT DOE). SUIT DOE has collected outcrop seepage data on an annual basis since 2007 using an independent contractor between 2007 and 2018. The goal of the study is identification, mapping, and quantification of methane seeps on the Fruitland Outcrop. A backpack mounted, hand-held gas flux meter manufactured by WEST Systems is used to measure methane and CO2 soil gas flux concentrations in moles per meters squared per day [mol/m² day] at thirty-five seep areas, totaling 53,352,338 square feet (1.9 miles) of ground. The flux concentrations were then used by the contractor to calculate volumetric methane and CO2 concentrations for 2017 in MCFD. Emission Calculation Methodology The AQP calculated ton per year emission rates for methane and CO2 by converting the volumetric methane and CO2 flux concentrations from MSCF to SCFD and then dividing the flux concentrations by the ideal gas law constant and multiplying the constants by the molecular weight of each gas. GHG emissions in CO2 equivalence (CO2e) were calculated by multiplying methane emissions by the EPA’s global warming potential factor of 25 for methane. Example Calculations Calculation to Convert Flux Rate in SCFD to lb/day lb/day = Flux/Ideal Gas Law Conversion Factor*molar mass Where: Flux = Volumetric gas flux in SCFD Ideal Gas Law Conversion Factor = 379.3 SCF/mol Molar Mass = g*Mol¯¹ (CH4 = 16.04; CO2 = 44.01) lb/day Methane = 3,097,000/379.3*16.04 = 1,053,658 lb/day Methane Calculation to convert lb/day to tpy: 65 tpy = lb/day/2000(lb/ton)*365 (days/year) Emissions Emission calculations for methane, CO2, and total GHG in CO2e are displayed below in Table 32: Table 32: Emissions of methane, CO2, and total GHG in CO2 Equivalent [tonnes] Methane CO2 Total GHG (CO2e) 2,055,414.05 71,979.85 2,127,393.90 3. Gas Stations Description of Sources There are five road and one marina gasoline service station that operated on the Reservation during calendar year 2017. Data Collection 2017 gasoline throughput values were provided to the AQP by representatives of each gas station, and the total throughput is displayed below in Table 33. Table 33: Annual gasoline throughput at gasoline stations located on the Southern Ute Indian Reservation [gal/yr]* Total Gasoline Throughput: 2,022,603.65 Reported throughput totals for one gasoline station included both diesel and gasoline and were corrected to include only gasoline. The method used for correcting this value is explained below in the Assumptions section. * Assumptions AQP assumed that gasoline throughput values reported by gas station representatives are valid. One gasoline station provided an aggregate throughput value for diesel and gasoline fuel. The AQP corrected this throughput value to only include gasoline based on gasoline to diesel fuel dispensing rates published in the Statistics Portal 23. Statista: The Statistics Portal. (2018). U.S. motor gasoline and distillate fuel oil consumption by the transportation sector from 1992 to 2017 (in 1,000 barrels per day). Retrieved from: https://www.statista.com/statistics/189410/usgasoline-and-diesel-consumption-for-highway-vehicles-since-1992/ 23 66 Due to the absence of emission factors for diesel fuel dispensing in EPA AP-42 Section 5.22, the AQP assumed emissions from diesel fuel dispensing to be negligible and did not calculate emissions for this activity. EPA AP-42 Section 5.2.2, also assumes a negligible methane content from gasoline evaporative emissions; therefore, AQP did not calculate GHG emissions for gas stations. Emission Calculation Methodology Gas station emissions were calculated using the Tribal Emissions Inventory Software Solutions (TEISS) emissions calculator for gasoline service stations. 24 The calculator employs emission factors from EPA AP-42 Section 5.2.2. Total reported fuel throughputs were input into the TEISS emissions calculator for two stages of gasoline service station emissions. Stage 1 includes underground tank filling and submerged filling. Stage 2 includes underground tank breathing and emptying, vehicle refueling displacement losses (uncontrolled), and spillage. Emissions Total VOC emissions from gas stations on the Reservation during 2017 are displayed below in Table 34. Table 34: VOC emissions from gasoline dispensing stations [tons] Pollutant Emissions VOC 21.34 4. Aviation Gasoline Description of Sources Emission estimates for aviation gasoline and the amount of lead in the leaded gasoline for counties were last developed by EPA for calendar year 2014. Lead is an additive in aviation gasoline used for piston-engine aircrafts (either general aviation or air taxi) to increase the fuel octane and prevent valve seat decline, which is a safety concern. Data Collection Institute for Tribal Environmental Professionals. (2016). Tribal Emissions Inventory Software Solution Version 3.6.26. Retrieved from http://www7.nau.edu/itep/main/air/air_aqt_teiss. 24 67 Data was obtained from the EPA NEI for calendar year 2014. EPA’s data collection methodology is described in EPA’s 2008 Technical Support Document titled Lead Emissions from the Use of Leaded Aviation Gasoline in the United States. 25 Assumptions The AQP assumed EPA’s calendar year 2014 EPA’s aviation gasoline emission estimates for La Plata County and Animas Air Parks would be the most representative emission estimates available for calendar year 2017. Emissions VOC and HAP emissions from aviation gasoline usage on the Reservation in 2017 is displayed below in Table 35. Table 35: VOC and HAP emissions from aviation gasoline [tons]* Total VOC Emissions 13.66 Total HAP Emissions 0.72 * Emissions for aviation gasoline fueling are estimated from data sourced from the 2014 EPA National Emission Inventory Database and assumed to be realistic estimations [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/tribal%3Asouthern_ute%3Af353422deecb736d. Public record. Not legal advice.