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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 of aviation
gasoline fueling emissions for 2017.
5. Gravel Pits
Description of Sources
Twenty-one sand and gravel pits operated within the exterior boundaries of the
Reservation during calendar year 2017. Data was collected from the Colorado Division of
Reclamation Mining and Safety (DRMS) database 26. The emissions from pits on the
Reservation were estimated by scaling down the emissions estimates reported to the
2014 EPA NEI for La Plata and Archuleta counties for calendar year 2014.
Data Collection
The AQP identified active gravel pits located within the exterior boundaries of the
Reservation through the DRMS ArcGIS data set. AQP identified the gravel, sand, and
combined sand and gravel permits located within the exterior boundaries of the
Reservation in La Plata and Archuleta counties. Permits with an active status for 2017
U.S. EPA. (2008, October). Lead Emissions from the use of Leaded Aviation Gasoline in the United States.
Retrieved from: https://nepis.epa.gov/Exe/ZyPURL.cgi?Dockey=P1004MXJ.TXT.
25
Colorado Division of Reclamation Mining and Safety. (2018). Active Hardrock Permits. Department of Natural
Resources. Retrieved from http://mining.state.co.us/Reports/Pages/GISData.aspx.
26
68
were then cross-referenced with the DRMS Imaged Document data to determine if there
was production in 2017. This methodology determined nineteen active gravel pits in La
Plata County and two active gravel pits in Archuleta County during 2017.
Emissions
Gravel pit emissions for La Plata County were obtained from the EPA’s calendar year
2014 Nonpoint Emission Inventory for gravel pits. Emission totals were reported to NEI
for La Plata and Archuleta counties and not for individual gravel pits. To derive emission
estimates for the Reservation, the reported emission totals for La Plata County were
downscaled by the percentage of the affected acreage of active gravel pits that are
located within the exterior boundaries of the Reservation. For example, 24.02% of the
affected acreage of active gravel pits in La Plata County are within the Reservation
boundaries, therefore, gravel pits on the Reservation account for 24.02% percent of
emissions in La Plata County. Emission totals for 2017 are displayed below in Table 36.
Table 36: Emissions of PM10 and PM2.5 from active gravel pits
County
Pollutant
County emissions
[tpy]
La Plata
La Plata
Archuleta
Archuleta
PM10
PM2.5
PM10
PM2.5
175.30
21.91
29.22
3.65
Percent of active
permitted pits within
SUIR
24%
24%
57%
57%
Reservation
Emissions
[tpy]
42.11
5.26
16.62
2.08
6. Residential Heating
A. Description of Sources: Fireplaces and Wood Burning Stoves
Fireplaces and wood burning stoves are a significant source of residential heating within
the exterior boundaries of the Reservation. The predominant types of solid fuel available
are pinyon-juniper, pine, and aspen.
Data Collection
The U.S. Census 2012-2016 American Community Survey 5-Year Estimate (survey) was
used to determine the number of households on the Reservation that use fireplaces or
wood burning stoves for residential heating. 27 The survey estimates the total number of
U.S. Census Bureau. (2018). 2012-2016 American Community Survey 5-Year Estimates. Retrieved from
https://factfinder.census.gov/faces/nav/jsf/pages/index.xhtml.
27
69
households on the Reservation that used wood as a heating source during the five-year
survey period.
The U.S. Energy Information Administration, Office of Energy Consumption and Efficiency
Statistics’ 2005 Residential Energy Consumption Survey (EIA) was used to obtain the
average number of cords used within a year at an average household. 28 Table US8 of the
EIA lists that an average household uses an average of 1.6 cords per year. The U.S.
Census reported 925 households on the Reservation use fireplaces or woodstoves as the
primary heating source.
Fireplace and wood burning residential heating data for the Southern Ute Indian
Reservation in 2017 is displayed below in Table 37.
Table 37: Fireplace and wood burning residential heating data
Homes heated
with wood
Average fuel use per
household/year
Unit of
measurement
Total number of cords
used in 2017
925
1.6
Cords
1,480
Emission Calculation Methodology
Emissions for residential fireplace and wood burning stoves were calculated using the
Tribal Emissions Inventory Software Solutions (TEISS) emission calculator. The calculator
employed emission factors from EPA AP-42 Section 1.10.2, which may be adjusted based
on the units of data input.
Example Calculation
925 households x 1.6 cord = 1,480 cords (input into TEISS)
household
Assumptions
The U.S. Census surveyed 5,156 households. 925 households with an estimated
uncertainty of ± 78 use fireplaces or woodstoves for home heating. The TEISS variables
chosen were conventional pre-phase I wood stove, Rocky Mountain and Pacific Coast
region with Ponderosa Pine Hardwood Forest.
Emissions
U.S. Energy Information Administration. (2005) Table US8 Average Consumption by Fuels Used, 2005 Physical
Units per Household. Retrieved from:
http://www.eia.gov/consumption/residential/data/2005/c&e/summary/pdf/tableus8.pdf.
28
70
Total criteria pollutant and GHG emissions from residential fireplace and wood-burning
stoves on the Reservation in 2017 are displayed below in Table 38.
Table 38: Criteria pollutant and GHG emissions from fireplaces and wood burning stoves
[tons]*
Pollutant
NOx
SO2
PM10
CO
VOC
GHG (CO2e)
Total
2.13
0.30
23.26
175.40
40.28
6,393.54
*GHG reported in metric tonnes.
B. Description of Sources: Propane Heating
Liquid propane (LP) is the dominant source of residential heating on the Reservation and
in Southwest Colorado.
Data Collection
The U.S. Census 2012 -2016 American Community Survey 5-Year Estimate was used to
determine the number of households on the Reservation that use LP gas as a source of
heating.
The U.S. Energy Information Administration, Office of Energy Consumption and Efficiency
Statistics’ 2015 Residential Energy Consumption Survey (EIA) was used to obtain the
average of LP used per household. The survey estimated the average number of gallons
of LP used within a year for an average household. 29 The U.S. Census reported 2,444 or
47.4% of households on the Reservation use LP gas as the primary heat source and the
EIA estimated 278 gallons of LP gas are burned per year in households in Colorado.
Liquid Propane residential heating data for the Southern Ute Indian Reservation in 2017
is displayed below in Table 39.
Table 39: Liquid propane residential heating data
Homes Heated with
Liquid Propane
Average Fuel Use per
Household/Year
Unit of
Measurement
Total Gallons
used in 2017
2,444
278
Gallons
679,432
Emission Calculation Methodology
U.S. Energy Information Administration. (2015). Table CE2.5 Household Site Fuel Consumption in the West
Region, Totals and Average, 2015 Physical Units. Retrieved from https://www.eia.gov/consumption/.
29
71
Emissions for residential LP gas heating were calculated using the TEISS emission
calculator. The calculator employed emission factors from EPA AP-42 Section 1.5.
Example Calculation
2,444 households x 278 gallons = 679,432 gallons *(input into TEISS)
household
Assumptions
The U.S. Census surveyed 5,156 households with an estimated uncertainty of ± 147
households that use LP gas for home heating. The actual sulfur content of LP gas on the
Reservation is unknown and the default sulfur content of 0.54 grains/100 ft3 was used in
the TEISS emission calculator.
Emissions
Total criteria pollutant and GHG emissions from residential LP gas usage on the
Reservation in 2017 is displayed below in Table 40.
Table 40: Criteria pollutant and GHG emissions from liquid propane gas heating at
residential sources [tons]*
Pollutant
*
NOx
SO2
PM10
CO
VOC
GHG (CO2e)
Total
4.55
0.02
GHG reported in metric tonnes.
0.01
1.29
0.18
3,902.84
C. Description of Sources: Natural Gas Heating
Natural gas is a prevalent residential heating fuel on the Reservation.
Data Collection
The U.S. Census 2012-2016 American Community Survey 5-Year Estimate (survey) was
used to determine the number of households on the Reservation that use natural gas for
residential heating. The survey estimates the total number of households on the
Reservation that used natural gas as a heating source during the five-year survey period.
The U.S. Energy Information Administration, Office of Energy Consumption and Efficiency
Statistics’ 2015 Residential Energy Consumption Survey (EIA) was used to obtain the
average of natural gas used per household. The survey estimated the average cubic feet
of natural gas used within a year for an average household. The U.S. Census reported 976
or 20% of households on the Reservation use natural gas as the primary heat source and
the EIA estimated 48.3 thousand cubic feet (48.3 Mcf) of natural gas are burned per year
in households in Colorado.
72
Natural Gas residential heating data for the Southern Ute Indian Reservation in 2017 is
displayed below in Table 41.
Table 41: Natural gas residential heating data
Homes Heated with
Natural Gas
Average Fuel Use per
Household/Year
Unit of
Measurement
Total MMcf
used in 2017
976
0.0483
MMcf
47.14
Emission Calculation Methodology
Emissions for residential natural gas heating were calculated using the TEISS emission
calculator. The calculator employed emission factors from EPA AP-42.
Example Calculation
976 household x 0.0483 MMcf gas = 47.14 MMcf gas (input into TEISS)
household
Assumptions
The U.S. Census surveyed 5,156 households with an estimated uncertainty of ± 88
households that use natural gas for home heating. TEISS input variables were the EPA AP42 default heating value of 1020 Btu/ft3 and sulfur content of 2000 grains/ MMft3.
Emissions
Total criteria pollutant and GHG emissions from residential natural gas heating sources
on the Reservation in 2017 are displayed below in Table 42.
Table 42: Criteria pollutant and GHG emissions from natural gas heating at residential
sources [tons]*
*
Pollutant
NOx
SO2
PM10
CO
VOC
GHG (CO2e)
Total
2.27
0.01
0.18
0.97
0.13
2,568.97
GHG reported in metric tonnes.
7. Agricultural Burning
Description of Activity
Agricultural burning is performed on the Reservation to clear irrigation ditches of
vegetation and to clear pastures of weeds and vegetation prior to crop cultivation.
73
Data Collection
Emissions from agricultural burning on the Reservation were obtained from the 2014 NEI
for La Plata County and Archuleta County. EPA reported two types of agricultural
burning: Agricultural Burning Grasses, and Agricultural Burning Unspecified Crop Type.
EPA did not report emissions for Agricultural Burning Unspecified Crop Type for
Archuleta County. Emissions were not included in this emissions inventory for
Montezuma County due to only 0.2% of the county falling within the Reservation
boundaries.
Emission Calculation Methodology
Emissions obtained from the NEI for La Plata and Archuleta County were scaled down
proportionally to the percentage of land in La Plata and Archuleta counties that fall
within the exterior boundaries of the Reservation. 38.9% and 29.5 % respectively.
Assumptions
AQP assumes the methods and calculations used to develop emissions from agricultural
burning are valid and acknowledges that the process used to reduce emissions for the
Reservation could result in a slight under or overestimation of emissions. It is also
assumed that emissions from agricultural burning from the 2014 NEI are realistic
estimations that occurred in 2017.
Emissions
Criteria pollutants, NH3, and HAP emission estimates from agricultural burning that
occurred within the exterior boundaries of the Reservation in 2017 are displayed below
in Table 43.
Table 43: Criteria pollutant, NH3, and HAP emissions from agricultural burning
[tons]*
Pollutant
PM10
PM2.5
CO
NOx
NH3
SO2
VOC
TOTAL
2.19
1.61
12.61
0.30
0.87
0.09
0.74
*
Emissions for agricultural burning were estimated from data retrieved from the 2014 EPA National
Emission Inventory Database and are assumed to be realistic estimations of agricultural burning
emissions that occurred in 2017.
VI.
Mobile Sources
Description of Sources
74
Mobile source emissions are generated from on-road vehicles and non-road engines
including lawn equipment, recreational vehicles, agricultural equipment, construction
equipment, etc.
1. On-Road Mobile Sources
AQP estimated emissions from gasoline, diesel, compressed natural gas (CNG), and
ethanol fueled on-road mobile sources, such as motorcycles, passenger cars, passenger
trucks, light commercial trucks, transit buses, school buses, refuse trucks, single unit land
and short-haul trucks, motorhomes, and combination short-haul trucks.
Data Collection
Hourly humidity and temperature data were obtained from the two SUIT Ambient Air
Monitoring stations, Ute 1 and Ute 3. The humidity and temperature data were used to
calculate hourly averages for each month of the year. The hourly average values for each
month were then used as meteorology data inputs into the EPA MOVES2014a (MOVES)
emission modeling software. 30
Vehicle miles traveled (VMT) data (by vehicle type) were obtained from the 2014 NEI
County Database (CDB). Fuel type data for on-road vehicles was obtained from the 2014
NEI National Database (NDB) and no adjustments to the data set were necessary, since
fuel type usage was assumed to be the same across the Reservation.
Emission Calculation Methodology
Data values were input into the MOVES model to calculate mobile source emissions
individually for both La Plata and Archuleta counties. Data adjustments were made to the
emission totals for each county based on the percentage of road miles in La Plata and
Archuleta County that fall within the exterior boundaries of the Reservation, as
determined from GIS shapefiles obtained from the La Plata and Archuleta County GIS
departments. 31,32 The data adjustment resulted in a reduction of the emissions to
34.65% and 17.24% for La Plata and Archuleta Counties, respectively. No significant roads
on the Reservation are located in Montezuma County, and therefore AQP assumed onroad emissions for Montezuma County to be negligible. The AQP determined that 947.3
U.S. EPA Moves 2014a. (2018). Retrieved from https://www.epa.gov/catc/clean-air-technology-centerproducts#software.
30
31
La Plata County. (2018). Roads. GIS/Mapping. Retrieved from ftp://ftp.laplata.co.us/shapefiles/.
Archuleta County. (2018). Roads - Archuleta County. GIS. Retrieved from
http://www.archuletacounty.org/504/Download-GIS-Data.
32
75
miles of roads are within the Reservation boundaries. The AQP later combined the two
model output data sets to obtain Reservation emission totals. MOVES calculated
emissions for running exhaust, engine start exhaust, brake wear and tire wear from
mobile sources fueled by gasoline, diesel, CNG and ethanol. Data outputs were organized
by road type and pollutant.
Assumptions
AQP assumed data from the 2014 NEI to be the best available data for 2017 and the
emissions estimations from MOVES to be correctly calculated and realistic.
Emissions
Criteria pollutant emissions from on-road mobile sources on the Reservation in 2017 are
displayed below in Table 44.
Table 44: Criteria pollutant emissions from on-road mobile sources [tons]
Pollutant
CO
NOx
VOC
PM10
PM2.5
Emissions
2,627.19
394.23
277.89
20.38
18.24
2. Non-Road Mobile Sources
Non-road mobile sources contribute a significant portion of the NOx and CO emissions
from mobile sources. Non-road mobile sources on the Reservation include agricultural
equipment, construction and mining equipment, lawn and garden equipment, and
recreational equipment.
Data Collection
Hourly humidity and temperature data were obtained from the two SUIT Ambient Air
Monitoring stations, Ute 1 and Ute 3. The humidity and temperature data were used to
calculate hourly averages for each month of the year. The hourly average values for each
month were then used as data inputs into MOVES emission modeling software.
Fuel type data for non-road sources were obtained from the 2014 NEI NDB and used as
the fuel data inputs in MOVES.
Assumptions
AQP assumed data from the 2014 NEI to be the best available data and the emissions
estimations from MOVES to be correctly calculated and realistic.
Emission Calculation Methodology
76
AQP performed one MOVES model run for non-road sources for La Plata and Archuleta
County each. MOVES outputs emissions for weekdays and weekend days for each month.
Emissions were multiplied by the amount of weekday and weekend days per month. AQP
reduced emissions totals for La Plata and Archuleta County to 38.9 % and 29.5%
respectively, based on the portion of the counties that are within the exterior boundaries
of the Reservation.
Emissions
Criteria pollutant emissions from non-road mobile sources on the Reservation in 2017
are displayed below in Table 45.
Table 45: Criteria pollutant emissions from non-road mobile sources [tons]
VII.
Pollutant
CO
NOx
VOC
PM10
PM2.5
Emissions
1,215.65
145.03
206.79
16.46
15.62
Events
1. Wildland Fires and Prescribed Burns
Description of Activity
The forest on the Reservation is predominantly comprised of pinyon-juniper woodlands
with ponderosa, gambel oak, aspen and sub-alpine forest at higher elevation areas. The
forest is prone to wildfire and prescribed burns are utilized as a forest management
strategy to help prevent catastrophic fires, improve wildlife habitat, and improve overall
forest health. Wildfires and prescribed burns can be significant sources of air pollution on
the Reservation and the Four Corners area.
Data Collection
Wildland and prescribed burn fire (forest fire) data for calendar year 2017 were obtained
from the Bureau of Indian Affairs (BIA) and the Southern Ute Agency Fire Management
Division. 33 The initial data identified 35 fires (31 wildfires and 4 prescribed fires). Data
sets included type of fire, latitude and longitude of fire perimeter, and acres burned.
Emission Calculation Methodology
33
Bureau of Indian Affairs Fire Management. (2017). Southern Ute 2017 Fire Occurrence
77
Forest fire emission estimates were calculated using the USFS BlueSky Playground web
tool (BlueSky). 34 BlueSky is comprised of several internal USFS datasets and modeling
programs, including the Fuels Characteristic Classification System fuel information
dataset (FCCS), the CONSUME3 fuel consumption model, and the FEPS emission factors
model.
Forest fire data including latitude and longitude and acres burned are input into BlueSky
and BlueSky selects the correct default model input values based on the fire location.
Input values include available fuel load, fuel consumed, emission factors, and
meteorological forecast data. “Dry” was selected for the fuel moisture value. Forest fire
event by FCCS fuel bed type are displayed below in Table 46.
Table 46: Forest fire occurrence by fuels characteristic classification system, fuel bed type,
and acres burned
FCCS Fuel Bed Description
Number of Fires
Acres Burned
Ponderosa Pine Savanna
5
200.1
Interior Douglas-Fir-Interior Ponderosa Pine/Gamble Oak Forest
1
0.3
Pinyon-Utah Juniper Woodland
28
19.7
Sagebrush Shrubland
1
0.1
Totals
35
220.2
Emission Equations
Emissions = (Area burned) x (Fuel Load Available) x (Fuel Consumed (Burn Efficiency)) x
(Emission Factors)
Mass of Emissions =
Area burned (input from AQP datasets)
Fuel Load Available (updated FCCS map)
Fuel Consumed (CONSUME3)
Emission Factors (FEPS plus HAPs)
Assumptions
Bluesky Playground Framework
Collected and reported fire related data is assumed to be accurate and to be the best
data available. BlueSky is assumed to function as intended and to select the proper fuel
characteristics from the USFS FCCS map when latitude and longitude coordinates are
input into the model.
U.S. Forest Service AirFire Research Team. (2016). BlueSky Playground (Version 2.0 beta). Retrieved from
http://playground.airfire.org/home.php.
34
78
Emissions
Total criteria pollutant, NH3 and GHG from prescribed burns and wildland fires that
occurred within the exterior boundaries of Reservation boundaries in 2017 are displayed
below in Table 47.
Table 47: Criteria pollutant, NH3, and GHG emissions from prescribed burns and wildland
fires [tons]*
*
Pollutant
PM10
PM2.5
CO
NOx
NH3
SO2
VOC
Total
13.86
13.01
50.99
0.30
0.60
0.14
17.25
GHG
(CO2e)
728.76
GHG reported in metric tonnes.
VIII.
Biogenic
Biogenic processes of trees, vegetation, soil, and microbial activities generate VOC, NOx,
CO, and HAP emissions. EPA estimates biogenic emissions for triennial inventory years,
with the last estimation performed for calendar year 2014.
Assumptions
The AQP assumed the emission estimations prepared by EPA to be performed correctly
and to be the best available emissions estimates for 2017.
Emission Calculation Methodology
Biogenic emissions estimated for La Plata and Archuleta County were prepared by EPA
using the EPA’s Biogenic Emission Inventory System and Biogenic Emissions Landuse
Database. 35 AQP obtained the 2014 emission estimates for La Plata and Archuleta
counties from the 2014 NEI. Emissions estimates for Montezuma County were not
included in this emissions inventory due to only 0.2% of the county falling within the
Reservation boundaries.
County wide emissions were reduced for La Plata and Archuleta County to 38.9% and
29.5% respectively, based on the area of each county that is located within the exterior
boundaries of the Reservation.
Emissions
U.S. Environmental Protection Agency. (2009). Biogenic Emission Inventory System. Retrieved from
https://www.epa.gov/air-emissions-modeling/biogenic-emission-inventory-system-beis.
35
79
Criteria pollutant and HAP emissions from biogenic sources on the Reservation in 2017
are displayed below in Table 48.
Table 48: Criteria pollutant and HAP emissions from biogenic sources [tons]*
Pollutant
CO
NOx
VOC
HAP
Emissions
2,018.41
146.05
11,932.16
1,532.26
Emissions for biogenic sources were estimated from data retrieved from the 2014 EPA
National Emission Inventory data and are assumed to be realistic estimations of biogenic
source emissions for 2017.
*
IX.
Summary
1. Emissions Sources
Reservation emissions presented in this inventory are distributed between point, nonpoint, mobile, and biogenic sources.
A. Point Sources
There are four categories of point sources including:
1) Title V permitted oil and gas sources,
2) TMNSR permitted and true minor oil and gas sources,
3) Municipal solid waste landfills, and
4) Airports.
B. Non-Point Sources
There are eight categories of non-point sources including:
1) Small oil and natural gas sources,
2) Fruitland Formation Outcrop natural gas seeps
3) Gasoline stations,
4) Aviation gasoline dispensing,
5) Gravel pits,
6) Residential heating,
7) Fire events (wildland fires and prescribed burns), and
8) Agricultural burning.
C. Mobile Sources
Mobile sources are divided into two categories:
1) On-road, and
80
2) Non-road.
D. Biogenic Emissions
Biogenic emissions encompass all non-man-made emission sources.
2. Emission Inventory Findings
Oil and natural gas production and mid-stream transmission are the predominant
industries on the Reservation. Of all the quantified emission categories, oil and gas
contributed the most significant quantities of NOx, CO, SO2 and PM10 to the airshed
during 2017. Oil and gas related activities accounted for 18,695.68 tons, or 96% of the
total NOx emissions quantified in the emission inventory, 15,464.33 tons, or 71% of the
total quantified CO emissions, 63.98 tons, or 60% of the total quantified SO2 emissions,
and 229.68 tons, or 60% of the total quantified PM10 emissions. GHG emissions from the
oil and gas sector were calculated to be 4,139,484.44 metric tons, or 66% of total
Reservation emissions. A summary of 2017 criteria pollutant, HAP, and GHG emissions by
source category is displayed below in Table 49.
81
Table 49: Criteria pollutant, HAP, and GHG emissions on the Southern Ute Indian
Reservation [tons]*
Source
Category
Title V oil and
gas
Synthetic
minor oil and
gas
True minor oil
and gas
Municipal
Solid Waste
Landfills
Airports
Permitted
Point Sources
Total Point
Source
Emissions
Small oil and
gas sources
Fruitland
Formation
Outcrop
Natural Gas
Seeps
Gas Stations
Aviation
Gasoline
Gravel Pits
Residential
Heating
Fire Events
Agricultural
Burning
Total NonPoint Source
Emissions
NOx
VOC
SO2
PM10
CO
Total
HAP
PM2.5
GHG (CO2e)
Point Sources
2,381.89
947.55
28.62
75.97
2,388.07
298.40
-
1,453,124.10
315.97
165.94
5.84
3.78
206.10
35.61
-
98,310.54
4,609.43
897.09
25.56
52.36
3,507.64
298.65
-
1,365,890.40
-
6.46
-
2.30
0.21
2.49
1.38
14,379.88
34.87
17.50
4.28
4.51
198.43
5.02
3.82
-
23.79
0.81
37.17
13.03
6.97
0.05
1.94
29.21
7,365.96
2,035.36
101.48
151.95
6,307.43
640.22
7.13
2,931,734.13
Non- Point Sources
11,388.39
1,091.58
3.95
97.57
9,362.51
256.12
78.80
1,222,159.41
-
-
-
-
-
-
-
2,127,393.90
-
21.34
-
-
-
-
-
-
-
13.66
-
-
-
-
-
-
-
-
-
58.73
-
-
7.34
-
8.95
40.59
0.34
23.45
177.66
-
23.26
12,865.35
0.30
17.25
0.14
13.86
50.99
-
13.01
728.76
0.30
0.74
0.09
2.19
12.61
-
1.61
-
11,397.94
1,185.17
4.52
195.80
9,603.77
256.12
124.02
3,363,147.42
3,842.84
-
33.86
-
1,532.26
-
-
2,428.60
165.02
6,294,881.55
Mobile Sources
Mobile
Sources
539.26
Biogenic
146.06
484.68
-
36.84
Biogenic
11,932.16
2,018.41
Reservation-Wide Emissions Totals
Total:
19,449.22 15,637.36 106.00 384.58 21,772.45
*
GHG gas emissions reported in metric tonnes.
82
NOx, CO, and VOC emissions by source category on the Reservation in 2017 are displayed
below in Figures 30 and 31.
Figure 30: NOx and CO emissions by source category [tons]
Figure 31: VOC emissions by source category [tons]*
*
Airport emissions include the point airport emissions as well as the non-point aviation gasoline emissions.
83
Biogenic sources are the most significant source of VOCs and HAPs emissions to the
airshed. VOC emissions from this category account for 76% of the total VOC emissions to
the airshed at 11,932.16 tons. HAP emissions were 63% of emissions to the airshed at
1,532.26 tons.
Due to the lack of accurate emission factors and reliable data, GHG emissions were not
estimated for every category presented in this inventory. Several categories that were
not evaluated or quantified, such as mobile sources and biogenic sources, would be
expected to contribute significant emissions of GHG. However, of the total GHG
quantified, oil and natural gas activities account for 66% of the total GHG at 4,139,484.44
metric tons in CO2e. Natural gas seeps from the Fruitland Formation Outcrop account for
34% of the total GHG at 2,127,393.90 metric tons in CO2e.
3. Oil and Gas Emissions Summary
The bulk of the emission sources within the point source category are larger emission
sources such as natural gas compressor stations, central delivery points, treating plants,
and processing plants. Combined, the Title V, permitted TMNSR, and true minor sources
represent the bulk of non-biogenic VOC and HAP emissions. VOC emissions from oil and
gas point sources account for 54% of the total airshed, non-biogenic VOC emissions at
2,010.58 tons and 71% of the total non-biogenic HAP at 632.66 tons. These source
categories also contribute 57% of the total SO2 emissions to the airshed at 60.03 tons.
Within the oil and gas sector, non-point source, small oil and gas sources such as
production well sites, contribute the most NOx, CO, and PM10 emissions to the airshed in
contrast to the larger Title V, permitted TMNSR, and true minor sources. This is due to
the large number of non-registered oil and gas sources, 2,760 sites, operating within the
exterior boundaries of the Reservation. This category alone accounts for 59% of the total
airshed NOx emissions at 11,388.39 tons and 43% of the total CO emissions at 9,362.51
tons. Emissions of particulate matter 10 micrometers or less in diameter were 97.57
tons, or about 25% of the total airshed emissions. Emissions totals from oil and gas
sector sources are displayed below in Table 50 and Figures 32 through Figures 34.
Table 50: Emissions from oil and gas sector sources [tons]*
Category
NOx
VOC
SO2
Title V
2,381.89
947.55
28.62
Synthetic minor
315.97
165.94
5.84
True Minor
4,609.43
897.09
25.56
Small oil and
11,388.39 1,091.58 3.95
gas sources
Total
18,695.68 3,102.17 63.98
*
GHG emissions reported in metric tonnes.
84
PM10
75.97
3.78
52.36
CO
2,388.07
206.10
3,507.64
HAP
298.40
35.61
298.65
PM2.5
-
GHG (CO2e)
1,453,124.10
98,310.54
1,365,890.40
97.57
9,362.51
256.12
78.80
1,222,159.41
229.68
15,464.33
888.78
78.80
4,139,484.44
Figure 32: NOx and CO emissions from oil and gas sources [tons]
Figure 33: VOC and HAP emissions from oil and gas sources [tons]
85
Figure 34: GHG (CO2e) emissions from oil and gas sources [tonnes]
Within the small oil and gas sources, the emission unit type that contributed the most
NOx emissions were natural gas-fired reciprocating internal combustion engines (RICE).
Two-stroke lean burn (2SLB) RICE between 301-400 hp and four-stroke rich burn (4SRB)
engines between 0-50 hp were the largest emitting subcategories. The largest
contributor of CO emissions from small oil and gas sources were 4SRB engines between
0-50 hp and 4SRB engines between 51-100 hp.
4. Comparison of the 2017 SUIT EI, the CY2015 SUIT EI, and the WRAP CY2014 EI
To evaluate the representativeness of oil and gas emission estimations from this 2017 SUIT
emissions inventory, the AQP has compared the results with oil and gas emission estimates
for the Reservation from the 2015 Southern Ute Indian Reservation Emission Inventory (2015
SUIT EI) and the Western Regional Air Partnership (WRAP) emissions inventory titled
Development of Baseline 2014 Emissions from Oil and Gas Activity in Greater San Juan Basin
and Permian Basin (2014 WRAP EI). 36 The AQP considers the 2014 WRAP EI and 2015 SUIT EI
emissions inventories to be the most accurate and representative oil and gas emission
inventories previously prepared for the Reservation.
The WRAP EI obtained data for point sources on the Reservation from data submitted by the
Tribe to the EPA National Emission Inventory database for 2014. To quantify emissions from
Bar-Ilan A., J. G. (2009, September 1). Development of Baseline 2014 Emisions from Oil and Gas Activity in the
Greater San Juan Basin and Permian Basin. Prepared by Ramboll Environ for Western Regional Air Partnership.
Retrieved from http://www.wrapair2.org/pdf/2014_SanJuan_Permian_Baseyear_EI_Final_Report_10Nov2017.pdf
36
86
non-point oil and gas sources located on the Reservation, the WRAP EI used data from the
2015 SUIT EI. The State of Colorado, in cooperation with the Tribe’s AQP, scaled this data
back to 2014 values by developing a “growth factor” based on reported production on the
Reservation in 2015 versus 2014. In addition to SUIT EI data, the 2014 WRAP EI included San
Juan Basin emissions data provided by the State of Colorado for sources outside of the
Reservation boundaries in La Plata and Archuleta counties. The 2017 SUIT EI does not include
emissions from non-Reservation sources and therefore does not provide a direct comparison
of all emission sources included in the 2014 WRAP EI. A comparison of NOx, CO, and VOC
emissions from this 2017 SUIT EI and the La Plata and Archuleta counties section of the 2014
WRAP EI are displayed in Figure 35 below.
Figure 35: Comparison of NOx, CO, and VOC emissions from the 2014 WRAP EI with 2017
SUIT EI [tons]
A comparison of the 2015 SUIT EI and 2017 SUIT EI shows a 900.57 ton increase in NOx
emissions, a 199.84 ton increase in CO emissions and a 92.72 ton decrease in VOC emissions
between 2015 and 2017 at oil and gas point sources and non-point sources. AQP attributes
the increased NOx and CO emissions to 113 more engines being reported in 2017 than in
2015 at the non-point oil and gas sources.
Between the 2015 and 2017 SUIT EIs, emissions decrease trends were observed at oil and
gas point sources. True minor sources and Title V sources showed a decrease in NOx, CO, and
VOC emissions. Synthetic minor sources also showed a decrease of NOx and VOC emissions
but show a slight increase in CO emissions. AQP attributes the decreases in NOx and VOC
emissions to decreased oil and gas production on the Reservation between 2015 and 2017.
87
A comparison of NOx, CO and VOC emissions at oil and gas sources on the Reservation from
the 2017 SUIT EI and the 2015 SUIT EI is displayed below in Figure 36.
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
X.
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