773 San Marin Drive, Suite 2115, Novato, CA 94998 415.899.0700 

 ENVIRON International Corporation 

DEVELOPMENT OF BASELINE 2006 EMISSIONS FROM OIL AND GAS ACTIVITY 

IN THE DENVER-JULESBURG BASIN 

Prepared for 

Colorado Department of Public Health and 

Environment Air Pollution Control Division 

Prepared by 

Amnon Bar-Ilan 

John Grant 

Ron Friesen 

Alison K. Pollack 

ENVIRON International Corporation 

773 San Marin Drive, Suite 2115 

Novato, CA 94998 

Doug Henderer 

Daniel Pring 

Buys & Associates 

300 E. Mineral Ave., Suite 10 

Littleton, CO 80122 

Kathleen Sgamma 

Independent Petroleum Association of Mountain States (IPAMS) 

410 17th Street, Suite 1920 

Denver, CO 80202 

April 30, 2008 
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TABLE OF CONTENTS 

Page 

Introduction ..................................................................................................................................1 

Temporal and Geographic Scope.....................................................................................................1 

Well Count and Production Data .....................................................................................................3 

Development of Spatial Allocation Surrogates................................................................................5 

Sources Subject to APEN Reporting and Condensate 

Tanks Subject To Regulation 7........................................................................................................7 

APEN Exempt Sources....................................................................................................................8 

APEN Exempt Emission Calculation Methodologies .....................................................................9 

Well Blowdowns..............................................................................................................................9 

Well Completions and Recompletions...........................................................................................10

Drill Rigs – Drilling Operations ....................................................................................................11 

Workover Rigs...............................................................................................................................13 

APEN Exempt Engines..................................................................................................................15 

Fugitive Leaks ................................................................................................................................16 

Heater Treater, Separators, and Glycol Dehydrator Burners.........................................................17 

Pneumatic Control Devices............................................................................................................18 

Gas Actuated Pumps......................................................................................................................19 

Produced Water Tanks...................................................................................................................20 

APEN Exempt Atmospheric Storage Tanks..................................................................................21 

Well Site Land Farming.................................................................................................................22 

Truck Loading ................................................................................................................................23 

Flaring ................................................................................................................................24 

Summary Results ...........................................................................................................................25 

TABLES 

Table 1. Comparison of active well count in Denver-Julesburg Basin........................................4 

Table 2. 2006 well count and oil, gas and water production by 

 county for the D-J Basin ................................................................................................4 

Table 3. 2006 spud counts by county for the D-J Basin ..............................................................5 

Table 4. 2006 emissions of all criteria pollutants by county 

 for the D-J Basin. .........................................................................................................28 

Table 5. 2006 NOx emissions by county and by source 

 category for the D-J Basin ...........................................................................................29 

Table 6. 2006 VOC emissions by county and by source 

 category for the D-J Basin ...........................................................................................30 
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FIGURES 

Figure 1. D-J Basin boundaries overlaid with the 2006 well locations.........................................2 

Figure 2. D-J Basin gas production spatial surrogate values for the 4km domain........................6 

Figure 3. D-J Basin oil production spatial surrogate values for the 4km domain.........................6 

Figure 4. D-J Basin drilling locations spatial surrogate values for the 4km domain ....................7 

Figure 5. 2006 NOx emissions by source category and 

 by county in the D-J Basin...........................................................................................26 

Figure 6. 2006 VOC emissions by source category and 

 by county in the D-J Basin...........................................................................................26 

Figure 7. D-J Basin NOx emissions proportional contributions 

 by source category .......................................................................................................27 

Figure 8. D-J Basin VOC emissions proportional contributions 

 by source category .......................................................................................................27 
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INTRODUCTION 

The Independent Petroleum Association of Mountain States (IPAMS) is sponsoring the 

development of a Phase III regional oil and gas emission inventory for the inter-Mountain West 

jointly with the Western Regional Air Partnership (WRAP), to build on the WRAP Phase I and 

Phase II inventory projects. This effort is focused on creating a comprehensive criteria pollutant 

emissions inventory for all activities associated with oil and gas field operations in the basins 

throughout the study region for year 2006 as well as future projection years; that includes all 

point and area sources related to the oil and gas industry. 

The initial region of interest for the emission inventory is the Denver-Julesburg (D-J) Basin, 

which includes the 8-hour ozone nonattainment area under the jurisdiction of the Air Pollution 

Control Division (APCD) of the Colorado Department of Public Health and Environment 

(CDPHE). The 2006 baseline inventory consists of two primary categories: sources subject to 

Air Pollution Emission Notice (APEN) reporting requirements, and sources exempt from APEN 

reporting, which are collectively termed “unpermitted” sources in this document. This document 

describes the methodologies by which the 2006 inventory was constructed. This methodology is 

specific to the D-J Basin and will have additions and changes for other basins in the Phase III 

project. For each source category, a basic description is given of the methodology used to 

estimate emissions from a single source or from all sources belonging to companies that 

participated in the survey effort (“participating companies”), and a description of how those 

emissions were scaled up to the county and basin-wide level. 

In general, the inventory was developed using a combination of well count and production 

activity from a commercially available database of oil and gas data maintained by IHS 

Corporation (“the IHS database”), the State of Colorado’s database of permitted sources 

including APENs sources and Regulation 7 reports, and detailed survey responses of oil and gas 

activity from several major participating companies that operate in the D-J Basin. Some 

additional data sources were also used, including American Petroleum Institute (API) technical 

literature, the US Environmental Protection Agency’s (EPA) AP-42 emissions factor technical 

guidance, the US EPA’s NONROAD emissions model, and the US EPA’s Natural Gas Star 

program technical guidance. 

Temporal and Geographic Scope 

This inventory considers a base year of 2006 for purposes of estimating emissions, consistent 

with the year for which episodic air quality modeling will be conducted for the upcoming Denver 

metropolitan area 8-hour ozone SIP modeling effort. All data requested from participating 

companies were for these companies’ activities in the calendar year 2006. Similarly, all well 

count and production data for the basin obtained from the IHS database were for the calendar 

year 2006. Emissions from all source categories are assumed to be uniformly distributed 

throughout the year except for heaters and pneumatic pumps, which are assigned seasonality 

fractions as they are typically used primarily in winter. 

The geographic scope of this inventory is the D-J Basin, whose boundaries as defined by the US 

Geological Survey (USGS) were used. The USGS boundaries for the D-J Basin were intersected 

with the State of Colorado boundaries so that only the portion of the D-J Basin within Colorado 
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was considered for this inventory. The following counties were wholly contained within the 

boundaries of the D-J Basin in this inventory: 

• Adams 

• Arapahoe 

• Boulder 

• Broomfield 

• Crowley 

• Denver 

• Douglas 

• Elbert 

• El Paso 

• Fremont 

• Jefferson 

• Kit Carson 

• Larimer 

• Lincoln 

• Logan 

• Morgan 

• Phillips 

• Pueblo 

• Sedgwick 

• Teller 

• Washington 

• Weld 

• Yuma 

Figure 1 shows the boundaries of the D-J Basin, with the 2006 well locations extracted from the 

IHS database overlaid. 

Figure 1. D-J Basin boundaries overlaid and 2006 oil and gas well locations. 
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Well Count and Production Data 

Oil and gas related activity data across the entire D-J Basin were obtained from the IHS Enerdeq 

database queried via online interface. The IHS database uses data from the Colorado Oil and 

Gas Conservation Commission (COGCC) as a source of information for Colorado oil and gas 

activity. Two types of data were queried from the Enerdeq database: production data and well 

data. Production data includes information relevant to producing wells in the basin while well 

data includes information relevant to drilling activity (“spuds”) and completions in the basin. 

Production data were obtained for the counties that make up the D-J Basin in the form of 

PowerTools input files. PowerTools is an IHS application which, given PowerTools inputs 

queried from an IHS database, analyzes, integrates, and summarizes production data in an 

ACCESS database. The D-J Basin PowerTools input files were loaded into the PowerTools 

application. From ACCESS database created by PowerTools, extractions of the following data 

relevant to the emissions inventory development were made: 

1. 2006 active wells, i.e. wells that reported any oil or gas production in 2006. 

2. 2006 oil, gas, and water production by well. 

The production data are available by API number. The API number in the IHS database consists 

of 14 digits as follows: 

• Digits 1 to 2: state identifier 

• Digits 3 to 5: county identifier 

• Digits 6 to 10: borehole identifier 

• Digits 11 to 12: sidetracks 

• Digits 13 to 14: event sequence code (recompletions) 

Based on the expectation that the first 10 digits, which include geographic and borehole 

identifiers, would predict unique sets of well head equipment, the unique wells were identified 

by the first 10 digits of the API number. 

In an attempt to validate the IHS well count and production data, comparisons were made to 

summary data for 2006 provided by COGCC. It was found that while IHS Enerdeq oil, gas, and 

water production agreed to within 1% with COGCC provided summary data, active well counts 

differed considerably between IHS data and COGCC summary data. Upon further analysis of 

the COGCC database, it was discovered that the difference in well counts was due to the way in 

which unique wells were identified. If unique wells are simply identified by unique 14-digit API 

numbers, a much higher well count is estimated compared to if unique wells are identified by the 

first 10 digits of the API number. Furthermore, discussions with COGCC indicated that 

production reports were received for some wells although the well did not produce any oil or gas. 

However, since the production report was received, COGCC classified this as an active well. If 

the first 10 digits of the API number only are used, and only wells with non-zero production of 

oil or gas are counted, well counts are consistent between the COGCC and IHS databases. Table 

1 shows basin-wide well count estimates from the COGCC and IHS Enerdeq database. 
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Table 1. Comparison of active well count in Denver-Julesburg Basin. 

Database Identifier Well Count 

COGCC API # (all digits) 21,847 

COGCC API # (first 10 digits and 

only active wells) 

16,783 

IHS Enerdeq API # (first 10 digits and 

only active wells) 

16,774 

Well data were also obtained from the IHS Enerdeq database for the counties that make up the 

Denver Julesburg basin in the form of “297” well data. The “297” well data contain information 

regarding spuds and completions. The “297”well data were processed with a PERL script to 

arrive at a database of by-API-number, spud and completion dates with latitude and longitude 

information. Drilling events in 2006 were identified by indication that the spud occurred within 

2006. If the well API number indicated the well was a recompletion, it was not counted as a 

drilling event, though if the API number indicated the well was a sidetrack, it was counted as a 

drilling event. 

The well counts and oil, gas and water production by county for the basin are presented in 

Table 2, and the spuds by county are presented in Table 3. 

Table 2. 2006 well count and oil, gas and water production by county for the D-J Basin. 

County 

Well 

Count 

Oil Production 

[bbl] 

Gas Production 

[mcf] 

Water Production 

[bbl] 

Adams 889 406,823 6,738,398 628,171

Arapahoe 103 56,018 376,623 179,392

Boulder 232 132,523 2,373,186 62,787

Broomfield 58 31,798 635,433 14,664

Crowley 0 0 0 0

Denver 34 14,674 242,598 1,189

Elbert 60 38,296 196,974 155,302

El Paso 0 0 0 0

Fremont 37 50,074 0 0

Jefferson 0 0 0 0

Kit Carson 12 21,227 344,013 201,133

Larimer 135 116,755 212,406 3,854,032

Lincoln 12 78,112 27,203 729,088

Logan 112 207,829 260,466 6,081,895

Morgan 66 92,186 290,210 2,821,974

Phillips 19 0 555,029 127,347

Pueblo 0 0 0 0

Sedgwick 3 1,295 50,202 48,177

Teller 0 0 0 0

Washington 457 660,357 2,220,766 21,455,978

Weld 11,861 12,334,121 182,996,149 7,022,304

Yuma 2,684 0 37,111,123 3,375,324

TOTAL 16,774 14,242,088 234,630,779 46,758,757
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Table 3. 2006 spud counts by county for the D-J Basin. 

County 

Total Number of 

Spuds in 2006 

Adams 7

Arapahoe 3

Boulder 9

Crowley 0

Denver 7

Elbert 1

El Paso 0

Fremont 2

Jefferson 0

Kit Carson 2

Larimer 0

Lincoln 1

Logan 9

Morgan 1

Phillips 3

Pueblo 0

Sedgwick 0

Teller 0

Washington 23

Weld 877

Yuma 555

TOTAL 1500

Development of Spatial Allocation Surrogates 

Updated spatial allocation surrogates for oil and gas emissions were developed using the 2006 

IHS data. Surrogates were developed for the following Denver CAMx modeling domain: 

04 km 

Origin (-940, -292) 

NX = 119, NY = 119 

Latitude and longitude coordinates for oil and gas wells and drilling events were obtained from 

the IHS database. All data were obtained only for the portion of the D-J basin within Colorado. 

The locations of all wells in the D-J basin are shown in Figure 1. The oil and gas production 

surrogates were based on production data at known well locations, while the drilling surrogate 

was based solely on the number and location of wells drilled. 

The creation of the surrogates took place in several steps, and relied on the use of ArcView GIS 

software. 
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1. All wells and drill rigs were labeled with the appropriate grid cell IJ values. 

2. For each individual well, the oil, gas and water production values were divided by the 

total oil, gas and water production values corresponding to the county in which the well 

was located. This division resulted in determination of the fraction of a county’s total 

production taking place at each well. In the case of the drilling surrogate, the number of 

drilling events, rather than the production values, was used. 

3. For each unique grid cell/county combination with wells, each well’s production fractions 

were summed to create the surrogate value. 

Figures 2-4 depict the 4km domain spatial surrogate values. 

Figure 2. D-J Basin gas production spatial surrogate values for the 4km domain. 

Figure 3. D-J Basin oil production spatial surrogate values for the 4km domain. 
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Figure 4. D-J Basin drilling locations spatial surrogate values for the 4km domain. 

Sources Subject to APEN Reporting and Condensate Tanks Subject to Regulation 7 

On October 31, 2007 a request was made to the APCD for the 2006 Colorado APEN database for 

all oil and gas related emission sources covered by the following SCC and SIC codes: 

• All of the SCCs 202002*, 310*, 404003* (where * indicates all sub-SCCs for the SCC) 

• And only those with the following SICs: 13*, 492*, 4612. 

APEN data for the D-J basin were extracted and sorted by operator. Company specific APEN 

source data were forwarded to participating operators for a completeness review that included 

the following three issues: 

1) Source Categories that were missing from the APEN database, 

2) Specific sources missing from the database, and 

3) Sources within the database known to be no longer operating. 

Following the completeness review and the addition or deletion of sources as appropriate, 

emission rates were reviewed. Emission rates were updated to reflect 2006 actual emissions in 

cases where supporting data were available. Actual emission updates provided by operators 

followed the APCD calculation methodologies from existing permits or required Operation and 

Maintenance Plans. The APCD methodologies are used to update Annual Emission Calculations 

(Minor Sources) and 12-Month Rolling Emission Totals (Synthetic Minor and Major Sources). 

Documentation of these changes, and a QA/QC review of updated emissions for APEN sources 

accompany this document. 

A separate request was made to APCD for a copy of the 2006 Regulation 7 atmospheric storage 

tank reports for year 2006. Within the Ozone Control Area, data from the Regulation 7 reports 

was utilized in place of the APEN data to represent stock tank emissions as the Regulation 7 

reports best reflected actual emissions. The Regulation 7 reports for condensate tanks were in 
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the form of monthly reports of condensate throughput for each tank, and emissions for each tank, 

for all companies operating condensate tanks subject to Regulation 7 in the ozone non-attainment 

area. A macro was written in EXCEL to process the reports in such a way that monthly 

condensate throughput (bbl) and emissions (lb-VOC) could be extracted and summed. 

Confirmation was obtained that CDPHE’s annual Regulation 7 condensate tank emissions 

summary for 2006 was in reasonable agreement with the extracted emissions from the monthly 

Regulation 7 reports. 

GIS analysis was used to intersect the boundary of the ozone non-attainment area with the 

latitude/longitude coordinates of all APENs sources. Those sources falling within the ozone 

non-attainment area were filtered to remove any sources that were condensate tanks, based on 

SCC and SCC description. For purposes of summing all permitted oil and gas sources’ 

emissions in the D-J Basin, emissions from the remaining APENs sources (excluding condensate 

tanks in the ozone non-attainment area) were added to the summary emissions from all 

Regulation 7 condensate tank reports. 

APEN Exempt Sources 

Survey forms consisting of 11 Excel spreadsheets (attached) were forwarded to participating 

operators in the D-J basin. Each spreadsheet contained a request for specific data related to one 

of the following APEN exempt source categories: 

• Well blowdowns 

• Well completions 

• Drilling rigs 

• Exempt engines 

• Fugitive emissions 

• Heaters 

• Gas composition analysis for the basin 

• Pneumatic devices 

• Pneumatic pumps 

• Water tanks 

• Workover rigs 

The companies participating in the survey process for the D-J Basin represented 50% of well 

ownership in the basin, 63% of gas production in the basin, and 58% of oil production in the 

basin. This represented a sufficiently large percentage of oil and gas activity in the basin that it 

was felt that the responses obtained from the participating companies would be representative of 

all oil and gas operations in the basin. 

In addition to the source categories listed above, emissions from three additional APEN exempt 

source categories were estimated based on additional information requests from the participating 

companies: 

• APEN exempt atmospheric storage tanks 

• Truck loading activities 

• Flaring from condensate tanks 
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Detailed inventory methodologies for each of the source categories follow. Extrapolation of 

these data was necessary to account for emissions from all oil and gas activity in the basin. The 

extrapolation methodology to obtain county-level and basin-wide emissions for each source 

category is described below, but is largely based on scaling by the proportional representation of 

the respondents of basin-wide well count or oil or gas production, as appropriate. 

For emissions from those source categories that relied on estimates of volume of gas vented or 

leaked, such as well blowdowns, completions, and fugitive emissions, gas composition analyses 

were requested from all participating companies. These composition analyses were averaged to 

derive a single basin-wide produced gas composition analysis. The average composition 

analysis was used to determine the average VOC volume and mass fractions of the vented gas 

basin-wide. 

It should be noted that the emission estimates calculated for APEN exempt sources rely on data 

that is not as rigorously documented as permitted sources. Much of the data provided for the 

APEN exempt sources is based upon estimates and extrapolation from the survey responses. 

However the level of detail of the surveys and the extent of participation in the survey effort 

allow for emissions estimates of unpermitted sources which are an improvement on the previous 

WRAP Phase I and Phase II emissions inventory efforts for the D-J Basin. 

APEN Exempt Emission Calculation Methodologies 

Well Blowdowns 

Methodology

Emissions from well blowdowns were calculated using the estimated volume of gas vented 

during blowdown events, the frequency of the blowdowns, and the VOC content of the vented 

gas as documented by representative compositional analyses. 

The calculations applied the ideal gas law and gas characteristics defined from a laboratory 

analysis to estimate emissions according to Equations 1 and 2: 

Equation (1) vented Vvented TOTAL V f × = ,

where: 

Vvented is the volume of vented gas per blowdown [mscf/event] 

f is the frequency of blowdowns [events/year] 

Vvented,TOTAL is the total volume of vented gas from the participating companies [mscf/year] 

Equation (2) Eblowdown = Vvented ,TOTAL ×1000 × MWVOC × R ×YVOC

where: 

Eblowdown is the total VOC emissions from blowdowns conducted by the participating 

companies [lb-VOC/yr] 

MWVOC is the molecular weight of the VOC [lb/lb-mol] 

R is the universal gas constant [lb-mol/379scf] 

Y is the volume fraction of VOC in the vented gas 
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The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions

The total VOC emissions from all blowdowns reported by participating companies was scaled by 

the proportional production ownership of the participating companies according to Equation 3: 

Equation (3) P

P E E TOTAL

blowdown,TOTAL = blowdown ×

where: 

Eblowdown,TOTAL are the total emissions basin-wide from blowdowns [tons/year] 

Eblowdown are the blowdown emissions from the participating companies [tons/year] 

PTOTAL is the total gas production in the basin in 2006 [mscf] 

P is the total gas production in the basin in 2006 by the participating companies [mscf] 

County-level emissions were estimated by allocating the total basin-wide blowdown emissions 

into each county according to the fraction of total 2006 gas production occurring in that county. 

Well Completions and Recompletions 

Methodology

Emissions from well completions were estimated on the basis of the volume of gas vented during 

completion and the average VOC content of that gas, obtained from the gas composition 

analyses. The data received from the participating companies indicated that completion flaring 

does not occur in the D-J Basin, however any Best Management Practices (BMP) for initial 

completions or re-completions were incorporated into the data provided. 

The calculation methodology for completion emissions is identical to the method for blowdown 

emissions, and follows Equations 4 and 5: 

Equation (4) vented Vvented TOTAL V f × = ,

where: 

Vvented is the volume of vented gas per initial completion or re-completion [mscf/event] 

f is the frequency of completions [events/year] 

Vvented,TOTAL is the total volume of vented gas from completions for participating companies 

[mscf/year] 

Equation (5) Ecompletion = Vvented ,TOTAL ×1000 × MWVOC × R ×YVOC
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where: 

Ecompletions is the total VOC emissions from completions conducted by all participating 

companies [lb-VOC/yr] 

MWVOC is the molecular weight of the VOC [lb/lb-mol] 

R is the universal gas constant [lb-mol/379scf] 

Y is the volume fraction of VOC in the vented gas 

The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions

The total VOC emissions from all completions reported by participating companies was scaled 

by the total number of completions in the basin to the number of completions conducted by the 

participating companies according to Equation 6: 

Equation (6) C

C E E TOTAL

completion,TOTAL = completion ×

where: 

Ecompletion,TOTAL are the total emissions basin-wide from completions [tons/year] 

Ecompletion are the completion emissions from the participating companies [tons/year] 

CTOTAL is the total number of completions in the basin in 2006 

C is the total number of completions in the basin in 2006 by the participating companies. 

County-level emissions were estimated by allocating the total basin-wide completion emissions 

into each county according to the fraction of total 2006 completions that occurred in each county. 

Drill Rigs – Drilling Operations

Methodology

The participating companies were surveyed for information on drilling rigs operating in 2006 in 

the D-J Basin. Because many drill rigs are operated by contractors to the oil and gas producers, 

data were not always available to the level of detail requested in the surveys. Some of the 

companies surveyed were able to provide exact configurations for all rigs used in their 

operations, while others were able to provide information on only one or several representative 

rigs. In all cases, complete information for every parameter needed to estimate drilling rig 

emissions was not available, and in these cases engineering analysis was used to fill in missing 

information. Because the nature of the survey responses for drilling rigs varied so much by 

company, the methodology used was to first estimate each company’s total drilling rig emissions 

given the nature of the data available for that company, and then to sum the emissions and scale 

up to the basin level. 
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In general, the emissions for an individual rig engine were estimated according to Equation 7: 

Equation (7) 907,185 ,

i drilling

drilling engine

EF HP LF t

E

× × × =

where: 

Edrilling,engine is the emissions from one engine on the drilling rig for drilling one well 

[ton/engine/spud] 

EFi is the emissions factor for the engine for pollutant i [g/hp-hr] 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

tdrilling is the actual on-time of the engine for a typical drilling event in the basin [hr/spud] 

A single drilling rig may contain from 3 – 7 or more engines, including draw works, mud pump, 

and generator engines. The total emissions from drilling one well are thus the sum of emissions 

from each engine, according to Equation 8: 

Equation (8) = ∑

i

Edrilling Edrilling ,engine,i

where: 

Edrilling is the total emissions from drilling one well [tons/spud] 

Edrilling,engine,i is the total emissions from engine i from drilling one well [tons/engine/spud] 

It should be noted that SO2 emissions were estimated using the brake-specific fuel consumption 

(BSFC) of the engine, as obtained from the US EPA’s NONROAD model for a similarly sized 

drill/bore rig engine, and the 2006 sulfur content of the off-road diesel fuel as obtained from 

communication with CDPHE. The off-road diesel fuel sulfur content was assumed to be 

500ppm. The EPA NONROAD model guidance was used to determine the fraction of fuel 

sulfur that would go to forming PM emissions – for drilling rig engines this was only 2.2% of 

sulfur content. It was assumed that the remaining sulfur in the fuel would be emitted as SO2. 

Emissions factors were either provided by the survey respondent or were obtained from the US 

EPA’s NONROAD model. For emissions factors taken from the NONROAD model, in cases 

where it was not possible to ascertain the engine’s technology type, uncontrolled, undeteriorated 

drill/bore rig engines of the same size class were assumed. When a producer supplied emission 

factors for some, but not all pollutants, the technology type of the engine was estimated based on 

the supplied emission factors and emissions factors from the NONROAD model were taken for 

the estimated technology type for drill/bore rig engines of the same size class. This allowed the 

calculations to incorporate information about specific rig engines when it was available, and 

defaulted to the NONROAD model where this information was not available. Load factors were 

similarly estimated by using respondent information where such detailed information was 

available, or by using the NONROAD model or the WRAP Phase II analysis where they were 

not available. 

The resulting rig configurations included engines of several Tier models, several different counts 

of number of engines per rig, and differing load factors for the different engines on a rig. 
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Extrapolation to Basin-Wide Emissions

Due to the variability in the type of information provided by the participating companies, it was 

decided to sum the drilling emissions for each company separately using the data and 

assumptions for that company, and then to sum all participating companies’ drilling emissions 

and scale this to the basin-wide drilling emissions. Participating companies’ drilling emissions 

were estimated using the emissions from drilling one well using that company’s representative 

rig or rigs, and then multiplying by the number of spuds drilled by that company in 2006. If 

more than one representative rig was provided, all spuds drilled by that company were divided 

evenly among the representative rigs. In the case of one respondent, all of that company’s rigs 

were detailed including the total hours of usage during the year for all rigs. This was used to 

sum the company’s drilling emissions, rather than the number of spuds. 

The basin-wide drilling emissions were derived by scaling up the combined participating 

companies’ drilling emissions according to Equation 9: 

Equation (9) S

S E E TOTAL

drilling ,TOTAL = drilling ×

where: 

Edrilling,TOTAL is the total emissions in the basin from drilling activity [tons/yr] 

Edrilling is the total emissions in the basin from drilling activity conducted by the participating 

companies (summed as described above) [tons/yr] 

STOTAL is the total number of spuds that occurred in the basin in 2006 

S is the total number of spuds in the basin in 2006 drilled by the participating companies 

County-level emissions were estimated by allocating the total basin-wide drilling rig emissions 

into each county according to the fraction of total 2006 spuds that occurred in each county. 

Workover Rigs 

Methodology: 

Participating companies’ survey responses were used to derive a representative configuration of 

a workover rig, and the estimated duration of use of the workover rig for a typical well workover 

in the basin. Workover rigs are typically smaller in total horsepower than drilling rigs and 

usually consist of only one engine. For the D-J Basin, the survey responses indicated that the 

representative workover rig consisted of one Detroit Diesel Series 60 engine of approximately 

475 hp. It was assumed that this engine was a baseline, uncontrolled, undeteriorated diesel 

engine for purposes of estimating its emissions factors. This was considered a reasonably 

conservative assumption, since some workover rig engines may be newer engines (Tier 1 or 

better), but some may not be recently maintained or rebuilt. Emissions factors were taken from 

the EPA NONROAD model for baseline, undeteriorated drill/bore rig engines of the same size 

class. The average load factor for a workover rig engine was obtained from the WRAP Phase II 

survey effort, since the participating companies were not able to provide detailed information on 

the load factors. 
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G:\IPAMS\Technical_Reports\D-J_Basin\CDPHE_Submission\2006_Baseline_Emiss_D-J_Basin_043008.doc 14

The basic methodology for estimating the emissions from a workover rig follows Equation 10: 

Equation (10) 907,185 ,

i workover

workover engine

EF HP LF t

E

× × × =

where: 

Eworkover,engine is the emissions from one workover [ton/workover] 

EFi is the emissions factor of the workover rig engine of pollutant i [g/hp-hr] 

HP is the horsepower of the workover rig engine [hp] 

LF is the average load factor of the workover rig engine 

tworkover is the average duration of a workover event [hr/workover] 

It should be noted that SO2 emissions were estimated using the BSFC of the engine, as obtained 

from the US EPA’s NONROAD model for a similarly sized drill/bore rig engine, and the 2006 

sulfur content of the off-road diesel fuel as obtained from communication with CDPHE. The 

off-road diesel fuel sulfur content was assumed to be 500ppm. The EPA NONROAD model 

guidance was used to determine the fraction of fuel sulfur that would go to forming PM 

emissions – for workover rig engines this was 2.2% of sulfur content. It was assumed that the 

remaining sulfur in the fuel would be emitted as SO2. 

Extrapolation to Basin-Wide Emissions

The total workover rig emissions for the participating companies were derived by multiplying 

the per-workover emissions above for each pollutant by the total number of workovers 

conducted by the participating companies. This was then scaled up by the ratio of total well 

count in the basin to wells owned by the participating companies, following Equation 11: 

Equation (11) W

W E E TOTAL

workover,TOTAL = workover ×

where: 

Eworkover,TOTAL are the total emissions basin-wide from workovers [tons/year] 

Eworkover are the total workover rig emissions from the participating companies [tons/year] 

WTOTAL is the total number of wells in the basin 

W is the number of wells owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide workover rig emissions 

into each county according to the fraction of total 2006 well counts that are located in each 

county. 
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APEN Exempt Engines 

Methodology: 

The participating companies provided a complete inventory of all APEN exempt engines in use 

in their operations. Emission calculations for APEN exempt engines follow a similar 

methodology as for drilling rig or workover rig engines. 

The basic methodology for estimating emissions from an exempt engine is shown in Equation 

12: 

Equation (12) 907,185

i annual

engine

EF HP LF t

E

× × × =

where: 

Eengine are emissions from an exempt engine [ton/year/engine] 

EFi is the emissions factor of pollutant i [g/hp-hr] 

HP is the horsepower of the engine [hp] 

LF is the load factor of the engine 

tannual is the annual number of hours the engine is used [hr/yr] 

Note that, similar to drilling rig and workover rig engines, SO2 emissions are estimated using the 

BSFC of the engine, and the assumed sulfur content of the fuel, assuming that all sulfur 

emissions are in the form of SO2. For natural gas-fired exempt engines, gas composition 

analyses indicate no sulfur present in the natural gas; therefore SO2 emissions are negligible from 

these engines. 

Extrapolation to Basin-Wide Emissions

Emissions from all exempt engines from the participating companies were summed. The total 

emissions from all participating companies were scaled by the ratio of total well count in the 

basin to wells owned by the participating companies according to Equation 13: 

Equation (13) W

W E E TOTAL

engine,TOTAL = engine

where: 

Eengine,TOTAL is the total emissions from exempt engines in the basin [ton/yr] 

Eengine is the total emissions from exempt engines owned by the participating companies 

[ton/yr] 

WTOTAL is the total number of wells in the basin 

W is the number of wells owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide exempt engine 

emissions into each county according to the fraction of total 2006 well counts that are located in 

each county. 
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G:\IPAMS\Technical_Reports\D-J_Basin\CDPHE_Submission\2006_Baseline_Emiss_D-J_Basin_043008.doc 16

Fugitive Leaks 

Methodology

Fugitive emissions from well sites were estimated using AP-42 emissions factors and equipment 

counts provided in the survey responses. The participating companies provided total equipment 

counts for all of their operations in the basin by type of equipment and by the type of service to 

which the equipment applies – gas, light liquid, heavy liquid, or water. 

Fugitive VOC emissions for an individual component were estimated similar to blowdown or 

completion emissions, according to Equations 14 and 15: 

Equation (14) Vvented × N = Vvented ,TOTAL

where: 

Vvented is the volume of fugitive gas leaked per component, for different service types 

[mscf/component] 

N is the number of components of each service type 

Vvented,TOTAL is the total volume of vented gas from all components for all participating 

companies [mscf/year] 

Equation (15) E fugitive = Vvented ,TOTAL ×1000 × MWVOC × R ×YVOC

where: 

Efugitive is the fugitive VOC emissions for all participating companies [lb-VOC/yr] 

MWVOC is the molecular weight of the VOC [lb/lb-mol] 

R is the universal gas constant [lb-mol/379scf] 

Y is the volume fraction of VOC in the vented gas 

The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions

Basin-wide fugitive emissions are estimated by scaling the fugitive emissions from all 

participating companies by the ratio of the total number of wells in the basin to the number of 

wells owned by the participating companies, according to Equation 16: 

Equation (16) W

W E E TOTAL

fugitive,TOTAL = fugitive

where: 

Efugitive,TOTAL is the total emissions from fugitive leaks in the basin [ton/yr] 

Efugitive is the fugitive emissions for all participating companies [lb-VOC/yr] 

WTOTAL is the total number of wells in the basin 

W is the number of wells owned by the participating companies 
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County-level emissions were estimated by allocating the total basin-wide fugitive emissions into 

each county according to the fraction of total 2006 well counts that are located in each county. 

Heater Treater, Separators, and Glycol Dehydrator Burners 

Methodology

Heater (heater-treater, separator, tank heaters and glycol dehydrator burners) emissions were 

calculated on the basis of the emissions factor of the heater, and the annual flow rate of gas to the 

heater. The annual gas flow rate was calculated from the BTU rating of the heater and the local 

BTU content of the gas. The AP-42 emission factors for an uncontrolled small boiler were used 

for specific pollutants. 

The basic methodology for estimating emissions for a single heater is shown in Equation 17: 

Equation (17) t hc

HV

HV E EF Q annual

rated

local

heater = heater × heater × × ×

where: 

Eheater is the emissions from a given heater 

EFheater is the emission factor for a heater for a given pollutant [lb/MMBTU] 

Qheater is the heater MMBTU/hr rating [MMBTUrated/hr] 

HVlocal is the local natural gas heating value [MMBTUlocal/scf] 

HVrated is the heating value for natural gas used to derive heater MMBTU rating, Qheater

[MMBTU/scf] 

tannual is the annual hours of operation [hr/yr] 

hc is a heater cycling fraction to account for the fraction of operating hours that the heater is 

firing (if available)

Emissions for all heaters in the basin operated by the participating companies were estimated 

according to Equation 18: 

Equation (18) Eheater,companies = Eheater × Nheater

where: 

Eheater,companies is the total emissions from all heaters operated by participating companies 

[lb/yr] 

Eheater is the emissions from a single heater [lb/yr/heater] 

Nheater is the total number of heaters owned by the participating companies 

The participating companies were requested to provide seasonal utilization rates to account for 

changes in usage throughout the year. 
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G:\IPAMS\Technical_Reports\D-J_Basin\CDPHE_Submission\2006_Baseline_Emiss_D-J_Basin_043008.doc 18

Extrapolation to Basin-Wide Emissions

Basin-wide heater emissions were estimated according to Equation 19: 

Equation (19) W

E W E heater companies TOTAL

heater TOTAL = ×

2000

,

,

where: 

Eheater,TOTAL is the total heater emissions in the basin [ton/yr] 

Eheater,companies is the total emissions from all heaters operated by participating companies 

[lb/yr] 

WTOTAL is the total number of wells in the basin 

W is the total number of wells in the basin owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide heater emissions into 

each county according to the fraction of total 2006 well counts that are located in each county. 

Pneumatic Control Devices 

Methodology

Pneumatic device emissions were estimated by determining the numbers and types of pneumatic 

devices used at all wells in the basin owned by the participating companies. The bleed rates of 

these devices per unit of gas produced were determined by using guidance from the EPA’s 

Natural Gas Star Program. 

The methodology for estimating the emissions from all pneumatic devices owned by 

participating companies are shown in Equations 20 and 21: 

Equation (20) vented TOTAL i i annual V = V × N × t & ,

where: 

Vvented,TOTAL is the total volume of vented gas from all pneumatic devices for all participating 

companies [mscf/year] 

Vi

& is the volumetric bleed rate from device i [mscf/hr/device] 

Ni is the total number of device i owned by the participating companies 

tannual is the number of hours per year that devices were operating [hr/yr]

Equation (21) Epneumatic = Vvented,TOTAL ×1000 × MWVOC × R ×YVOC

where: 

Epneumatic is the pneumatic device VOC emissions for all participating companies 

[lb-VOC/yr] 

MWVOC is the molecular weight of the VOC [lb/lb-mol] 

R is the universal gas constant [lb-mol/379scf] 

Y is the volume fraction of VOC in the vented gas 
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The conversion from volume of gas vented to mass of VOC produced was evaluated at standard 

temperature and pressure. 

Extrapolation to Basin-Wide Emissions

Basin-wide pneumatic device emissions were estimated according to Equation 22: 

Equation (22) W

E W E pneumatic TOTAL

pneumatic TOTAL = ×

2000 ,

where: 

Epneumatic,TOTAL is the total pneumatic device emissions in the basin [ton/yr] 

Epneumatic is the pneumatic device VOC emissions for all participating companies 

[lb-VOC/yr] 

WTOTAL is the total number of wells in the basin 

W is the total number of wells in the basin owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide pneumatic device 

emissions into each county according to the fraction of total 2006 well counts that are located in 

each county. 

Gas Actuated Pumps 

Methodology

Participating companies provided data indicating either the average gas consumption rate per 

gallon of chemical or compound pumped, or the volume rate of gas consumption per day per 

pump. 

If the gas consumption rate per pump per day was specified, this was multiplied by the number 

of pumps owned by the respondent and the total annual usage to derive total gas consumption 

from gas-actuated pumps for the respondent. If the gas consumption rate per gallon of chemical 

pumped was specified, this was multiplied by the total volume of chemical pumped by the 

respondent in the basin in 2006 to derive total gas consumption from gas-actuated pumps for the 

respondent. 

VOC emissions were estimated similarly to pneumatic devices, following Equation 23: 

Equation (23) Epump = Vvented,TOTAL ×1000 × MWVOC × R ×YVOC

where: 

Epump is the gas-actuated pump VOC emissions for all participating companies 

[lb-VOC/yr] 

Vvented,TOTAL is the total volume of vented gas from all gas-actuated pumps for all 

participating companies [mscf/year] 
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MWVOC is the molecular weight of the VOC [lb/lb-mol] 

R is the universal gas constant [lb-mol/379scf] 

Y is the volume fraction of VOC in the vented gas 

The participating companies were requested to provide seasonal utilization rates to account for 

changes in usage throughout the year. 

Extrapolation to Basin-Wide Emissions

Basin-wide gas-actuated pump emissions were estimated according to Equation 24: 

Equation (24) W

E W E pump TOTAL

pump TOTAL = ×

2000 ,

where: 

Epump,TOTAL is the total pneumatic pump emissions in the basin [ton/yr] 

Epump is the gas-actuated pump VOC emissions for all participating companies 

[lb-VOC/yr] 

WTOTAL is the total number of wells in the basin 

W is the total number of wells in the basin owned by the participating companies 

County-level emissions were estimated by allocating the total basin-wide gas-actuated pump 

emissions into each county according to the fraction of total 2006 well counts that are located in 

each county. 

Produced Water Tanks 

Methodology: 

Compositional analyses were obtained for water samples collected from produced water tanks 

for input to the Tanks 4.0 program. Tanks 4.0 was used to estimate working and breathing losses 

based on the water composition analyses obtained from participating companies. 

The average water production per well was derived as the ratio of total water production in the 

basin to the number of active wells. From this a conservative volumetric throughput of 120,000 

gallons of water per wellsite was derived. This input to Tanks 4.0 produced an output emissions 

factor of 0.06 lb-VOC/year/wellsite. 

Extrapolation to Basin-Wide Emissions

Basin-wide emissions were derived by multiplying the derived emissions factor per wellsite by 

the number of active wells in the basin, following Equation 25: 
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Equation (25) 2000

tan

tan

water ks TOTAL

water ks

EF W E −

− =

where: 

Ewater-tanks,TOTAL is the total breathing and working loss emissions of water tanks in the basin 

[tons/yr] 

EFwater-tanks is the breathing and working loss emissions factor for water tanks in the basin 

[lb-VOC/year/wellsite] 

WTOTAL is the total number of wells in the basin 

County-level emissions were estimated by allocating the total basin-wide water tank emissions 

into each county according to the fraction of total 2006 well counts that are located in each 

county. 

APEN Exempt Atmospheric Storage Tanks 

Methodology

A VOC emissions factor for APEN exempt storage tanks was derived by summing all 

uncontrolled emissions from Regulation 7 condensate tanks and dividing by the total production 

from these same tanks. The resulting emissions factor is 13.86 [lb-VOC/bbl], and assumes that 

no flares or other controls are in place for APEN exempt condensate tanks. 

Extrapolation to Basin-Wide Emissions

Within the ozone non-attainment area, total production of condensate was obtained from the 

Regulation 7 reports, which were considered the most accurate estimate of condensate 

production in this area. GIS analysis was used to intersect the locations of all active wells in the 

basin with the boundaries of the ozone non-attainment area, in order to derive an estimate of the 

total condensate production in the area based on IHS data. The Regulation 7 production total 

was subtracted from the IHS total for the ozone non-attainment area to derive total condensate 

production handled by APEN exempt storage tanks, following Equation 26: 

Equation (26) Pexempt,tan ks,NAA = PIHS,NAA − PRe g 7,NAA

where: 

Pexempt,tanks,NAA is the production handled by APEN exempt storage tanks in the ozone nonattainment area [bbl] 

PIHS,NAA is the total condensate production in the ozone non-attainment area extracted from 

the IHS database [bbl] 

PReg7,NAA is the total condensate production handled by permitted tanks in the ozone nonattainment area as derived from the Regulation 7 reports [bbl] 

Outside of the ozone non-attainment area, a similar approach was used in which the total 

production handled by permitted storage tanks was estimated for the condensate tanks listed in 

the APENs database. This was subtracted from the total production in the basin outside of the 
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non-attainment area to derive total condensate production handled by APEN exempt storage 

tanks following Equation 27: 

Equation (27) Pexempt,tan ks,outside = PIHS ,outside − PAPENs,outside

where: 

Pexempt,tanks,outside is the production handled by APEN exempt storage tanks outside of the 

ozone non-attainment area [bbl] 

PIHS,outside is the total condensate production outside of the ozone non-attainment area 

extracted from the IHS database [bbl] 

PAPENs,outside is the total condensate production handled by permitted tanks outside of the 

ozone non-attainment area as derived from the APENs permits for condensate tanks [bbl] 

Total basin-wide VOC emissions from APEN exempt condensate tanks are estimated by 

Equations 28 and 29: 

Equation (28) 2000

,tan , ,tan

,tan ,

exempt ks NAA exempt ks

exempt ks NAA

P EF

E

× =

and 

Equation (29) 2000

,tan , ,tan

,tan ,

exempt ks outside exempt ks

exempt ks outside

P EF

E

× =

where: 

Eexempt,tanks,NAA is the basin-wide emissions from exempt tanks in the ozone non-attainment 

area [tons/yr] 

Eexempt,tanks,outside is the basin-wide emissions from exempt tanks outside of the ozone nonattainment area [tons/yr] 

EFexempt,tanks is the derived VOC emissions factor for exempt tanks [lb-VOC/bbl] 

County-level emissions were estimated by allocating the total basin-wide APEN exempt 

condensate tank emissions into each county according to the fraction of total 2006 condensate 

production that occurred in each county. 

Well Site Land Farming 

Methodology

Spill reports submitted to the COGCC in 2006 for any county within the boundaries of the D-J 

Basin were summarized to determine the type of material released (oil, methanol, or produced 

water), the volume of material released, and the volume of material recovered. All oil and 

methanol not recovered was conservatively assumed to completely volatilize and contribute to 

VOC emissions. Water spills were not considered in this analysis. 

The above methodology may double count larger spills that were transported to landfarms and 

thus accounted for in the APEN process. 
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Extrapolation to Basin-Wide Emissions

Basin-wide emissions from spills were estimated according to Equation 30: 

Equation (30) 2000

unre cov ered ,i i

spills

V

E

× ρ =

where: 

Espills is the total basin-wide VOC emissions from spills 

Vunrecovered,i is the total volume of spilled material of substance i that was unrecovered 

ρi is the liquid density of substance i

County-level spill emissions were estimated by summing the spill emissions for each county, as 

indicated by the spill report. Spills that occurred in 2006 were reported for only the following 

counties in the D-J Basin: 

• Logan 

• Morgan 

• Washington 

• Weld 

• Yuma 

Truck Loading 

Methodology

Truck loading emissions were estimated based on loading losses per EPA AP-42, Section 5.2 

methodology combined with condensate produced in the basin. As surveyed producers indicated 

that all condensate production in the basin was transported by truck, no correction was necessary 

to adjust condensate production to account for other modes of transport. Loading loss emissions 

were estimated based on EPA AP-42, Section 5.2 methodology, following Equation 31: 

Equation (31) ⎟

⎠

⎞ ⎜

⎝

⎛ × × = ×

T

S V M L 12 .46

where: 

L is the loading loss rate [lb/1000gal] 

S is the saturation factor taken from AP-42 default values based on operating mode 

V is the true vapor pressure of liquid loaded [psia] 

M is the molecular weight of the vapor [lb/lb-mole] 

T is the temperature of the bulk liquid [o

R] 

Truck loading emissions for participating companies were then estimated by combining the 

calculated loading loss rate with condensate production as shown in Equation 32: 
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Equation (32) 1000

42 Eloading = L × P ×

where: 

E is the truck loading emissions [lb/yr] 

L is the loading loss rate [lb/1000gal] 

P is the condensate production for the surveyed producers [bbl] 

Extrapolation to Basin-Wide Emissions

Basin-wide truck loading emissions were estimated according to Equation 33: 

Equation (33) P

E P E loading TOTAL

loading TOTAL = ×

2000 ,

where: 

Eloading,,TOTAL is the total truck loading emissions in the basin [ton/yr] 

Eloading is the truck loading pump VOC emissions for all participating companies 

[lb-VOC/yr] 

PTOTAL is the total condensate production in the basin 

P is the condensate production for the surveyed producers [bbl] 

County-level emissions were estimated by allocating the total basin-wide truck loading 

emissions into each county subject to Regulation 7 requirements according to the fraction of 

within-EAC condensate production for each county. 

Flaring 

Methodology

For this source category the AP-42 methodology was applied to estimate flare emissions 

associated with atmospheric storage tanks. Atmospheric storage tanks vent rates were combined 

with the heat content of the gas being flared and the appropriate AP-42 emission factor to 

determine the NOx and CO emissions. Per input from surveyed producers, it was assumed that 

no flaring occurred outside of the EAC, where condensate tanks are not subject to Regulation 7 

control requirements. 

Extrapolation to Basin-Wide Emissions

Surveyed producers indicated the use of only two control technologies to conform to Regulation 

7 requirements: flaring and vapor recovery units (VRUs). Producers supplied production 

controlled by VRU which allowed for the calculation of production controlled by flaring 

according to Equation 34. Here it was assumed, conservatively that non surveyed producers 

used only flare control devices to control emissions from atmospheric storage tanks. 
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Equation (34) Pflare = PRe g7,CNT − PRe g7,VRU

where: 

Pflare is the total condensate production handled by permitted tanks in the ozone nonattainment area and controlled by flares [bbl] 

PReg7,CNT is the total condensate production handled by permitted tanks in the ozone nonattainment area and controlled by any technology as estimated in regulation 7 summaries 

[bbl] 

PReg7,VRU is the total condensate production handled by permitted tanks in the ozone nonattainment area and controlled by VRUs as reported by participating companies [bbl] 

Emissions were estimated according to AP-42 methodology, following Equation 35. 

Equation (35) E flare = EFi × Pflare ×Q × HV

where: 

Eflare is the basinwide flaring emissions [lb/yr] 

EFi is the emissions factor for pollutant i [lb/MMBtu] 

Q is the condensate tank vent rate as supplied by participating companies [scf/bbl] 

HV is the heating value of the gas as estimated by participating companies [BTU/scf] 

Pflare is the total condensate production handled by permitted tanks in the ozone nonattainment area and controlled by flares [bbl] 

County-level emissions were estimated by allocating the total basin-wide truck loading 

emissions into each county subject to Regulation 7 requirements according to the fraction of 

within EAC condensate production for each county. 

Summary Results

Results from the combined permitted sources (APENs sources excluding condensate tanks in the 

ozone non-attainment area, and condensate tanks in the ozone non-attainment area from the 

Regulation 7 reports), and the combined unpermitted sources are presented below on a county 

level and as summaries for the entire D-J Basin as a series of pie charts and bar graphs. The 

quantitative emissions summaries are presented at the end of this document in table format. 

Figure 5 shows that NOx emissions are primarily concentrated in Weld and Yuma counties, as 

evidenced by the areas of large concentrations of well locations, as shown in Figure 1. Figure 6 

shows that VOC emissions are primarily concentrated in Weld county only. Production activity 

in Yuma county is mostly dry gas, and therefore a smaller proportion of total VOC emissions 

occur in Yuma county. 

Figure 7 shows that compressor engines and drilling rigs combined account for almost 80% of 

NOx emissions. Similarly, Figure 8 shows that permitted and unpermitted condensate tanks and 

pneumatic devices account for approximately 81% of VOC emissions. 
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0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Adams

Arapahoe

Boulder

Broomfld

Crowley

Denver

Elbert

Fremont

Jefferson

Kit Cars

Larimer

Lincoln

Logan

Morgan

Phillips

Pueblo

Sedgwick

Washngtn

Weld

Yuma

County

NOx Emissions (tons/year)

Other Categories

Glycol Dehydrator

Compressor Engines

Workover rigs

Venting -

recompletions

Pneumatic devices

Permitted Fugitives

Exempt engines

Drill rigs

Figure 5. 2006 NOx emissions by source category and by county in the D-J Basin. 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

Adams

Arapahoe

Boulder

Broomfld

Crowley

Denver

Elbert

Fremont

Jefferson

Kit Cars

Larimer

Lincoln

Logan

Morgan

Phillips

Pueblo

Sedgwick

Washngtn

Weld

Yuma

County

 VOC Emissions (tons/year)

Other Categories

Glycol Dehydrator

Compressor Engines

Venting - recompletions

Venting - initial completions

Venting - blowdowns

Truck loading of condensate liquid

Small condensate tanks

Pneumatic pumps

Pneumatic devices

Large condensate tanks

Permitted Fugitives

Unpermitted Fugitives

Drill rigs

Figure 6. 2006 VOC emissions by source category and by county in the D-J Basin. 
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Drill rigs

25%

Exempt engines

14%

Other Categories

1%

Workover rigs

3%

Heaters

3%

Compressor Engines

55%

Figure 7. D-J Basin NOx emissions proportional contributions by source category. 

Large condensate tanks

50%

Other Categories

1%

Pneumatic devices

14%

Permitted Fugitives

1%

Venting - recompletions

1%

Truck loading of 

condensate liquid

1%

Venting - initial 

completions

1%

Small condensate tanks

16%

Pneumatic pumps

1%

Venting - blowdowns

2%

Unpermitted Fugitives

9%

Glycol Dehydrator

1%

Compressor Engines

3%

Figure 8. D-J Basin VOC emissions proportional contributions by source category. 
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Table 4. 2006 emissions of all criteria pollutants by county for the D-J Basin. 

County 

NOx 

[tons/yr] 

VOC 

[tons/yr] 

CO 

[tons/yr] 

SOx 

[tons/yr] 

PM 

[tons/yr] 

Adams 2,286 3,005 939 13 19

Arapahoe 742 408 253 0 4

Boulder 129 803 76 1 4

Broomfield 14 193 10 0 0

Crowley 63 1 85 0 1

Denver 32 103 19 0 2

Douglas 0 0 0 0 0

Elbert 43 363 27 0 1

El Paso 0 0 0 0 0

Fremont 16 329 9 0 1

Jefferson 6 0 10 0 0

Kit Carson 10 139 6 0 1

Larimer 37 651 23 0 1

Lincoln 14 462 11 0 0

Logan 491 1,382 183 2 9

Morgan 672 883 672 132 4

Phillips 40 47 26 0 1

Pueblo 0 0 0 0 0

Sedgwick 1 11 0 0 0

Teller 0 0 0 0 0

Washington 284 4,509 207 1 9

Weld 12,310 64,111 8,393 51 421

Yuma 3,592 4,359 1,993 24 158

Totals 20,783 81,758 12,941 226 636
 April 2008 

G:\IPAMS\Technical_Reports\D-J_Basin\CDPHE_Submission\2006_Baseline_Emiss_D-J_Basin_043008.doc Table 5. 2006 NOx emissions by county and by source category for the D-J Basin. 

County Drill rigs 

Exempt 

engines Heaters 

Workover 

Rigs 

Compressor 

Engines 

Glycol 

Dehydrator 

Other 

Categories 

Adams 24 151 30 29 2,041 0 Arapahoe 10 18 4 3 707 0 Boulder 31 40 8 8 43 0 Broomfield 0 10 2 2 0 0 Crowley 0 0 0 0 63 0 Denver 24 6 1 1 0 0 Douglas 0 0 0 0 0 0 Elbert 3 10 2 2 26 0 El Paso 0 0 0 0 0 0 Fremont 7 6 1 1 0 0 Jefferson 0 0 0 0 6 0 Kit Carson 7 2 0 0 0 0 Larimer 0 23 5 5 5 0 Lincoln 3 2 0 0 8 0 Logan 31 19 4 4 44 0 Morgan 3 11 2 2 638 8 Phillips 10 3 1 1 26 0 Pueblo 0 0 0 0 0 0 Sedgwick 0 1 0 0 0 0 Teller 0 0 0 0 0 0 Washington 79 78 15 15 97 0 Weld 3,012 2,018 400 391 6,363 5 1Yuma 1,906 457 90 89 1,050 0 Totals 5,152 2,854 565 553 11,506 13 1
 April 2008 

G:\IPAMS\Technical_Reports\D-J_Basin\CDPHE_Submission\2006_Baseline_Emiss_D-J_Basin_043008.doc Table 6. 2006 VOC emissions by county and by source category for the D-J Basin. 

County 

Drill 

rigs 

Unpermitted 

Fugitives 

Permitted 

Fugitives 

Large 

condensate 

tanks 

Pneumatic 

devices 

Pneumatic 

pumps 

Small 

condensate 

tanks 

Truck 

loading of 

condensate 

liquid 

Venting – 

blowdowns 

Venting - 

initial 

completions 

Venting - 

recompletions

Compr

Eng

Adams 2 401 84 1,279 614 44 174 23 50 2 3 Arapahoe 1 46 18 176 70 5 24 3 3 1 1 Boulder 2 105 0 417 172 12 57 7 18 3 4 Broomfield 0 26 0 100 43 3 14 2 5 0 0 Crowley 0 0 0 0 0 0 0 0 0 0 0 Denver 2 15 0 46 23 2 6 1 2 2 3 Douglas 0 0 0 0 0 0 0 0 0 0 0 Elbert 0 27 0 0 41 3 214 2 2 0 0 El Paso 0 0 0 0 0 0 0 0 0 0 0 Fremont 1 17 0 0 25 2 280 3 0 1 1 Jefferson 0 0 0 0 0 0 0 0 0 0 0 Kit Carson 1 5 0 0 8 1 118 1 3 1 1 Larimer 0 61 0 269 92 7 211 7 2 0 0 Lincoln 0 5 0 0 8 1 436 4 0 0 0 Logan 2 51 0 0 77 6 1,160 12 2 3 4 Morgan 0 30 4 0 45 3 514 5 2 0 0 Phillips 1 9 0 0 13 1 0 0 4 1 1 Pueblo 0 0 0 0 0 0 0 0 0 0 0 Sedgwick 0 1.4 0 0 2 0 7 0 0 0 0 Teller 0 0 0 0 0 0 0 0 0 0 0 Washington 6 206 0 0 312 23 3,684 37 17 8 10 Weld 209 5348 354 38,349 8,164 591 5,977 693 1,360 292 394 Yuma 132 1210 0 0 1,834 134 0 0 276 185 249 Totals 357 7564 460 40,636 11,545 836 12,874 800 1,744 500 674