ATTACHMENT J 

DEVELOPMENT OF TEXAS STATEWIDE DRILLING RIGS EMISSIONS 

INVENTORIES FOR THE YEARS 1990, 1993, 1996, AND 1999 THROUGH 2040

DEVELOPMENT OF TEXAS STATEWIDE 

DRILLING RIGS EMISSION 

INVENTORIES FOR THE YEARS 1990,

1993, 1996, AND 1999 THROUGH 

2040 

FINAL REPORT

TCEQ Contract No. 582-11-99776 

Work Order No. 582-11-99776-FY11-05 

Prepared for: 

Texas Commission on Environmental Quality 

Air Quality Division 

Prepared by: 

Eastern Research Group, Inc. 

August 15, 2011 
ERG NO. 0292.00.005.002 

Development of Texas Statewide Drilling Rigs Emission 

Inventories for the years 1990, 1993, 1996, and 1999 through 

2040 

FINAL REPORT 

TCEQ Contract No. 582-11-99776 

Work Order No. 582-11-99776-FY11-05 

Prepared for: 

Kritika Thapa 

Texas Commission on Environmental Quality 

P. O. Box 13087 

Austin, TX 78711-3087 

Prepared by: 

Rick Baker 

Diane Preusse 

Eastern Research Group, Inc. 

3508 Far West Blvd., Suite 210 

Austin, TX 78731 

August 15, 2011 
i 

Table of Contents 

Section Page 

1. Executive Summary ...................................................................................................... 1-1

2. Introduction ................................................................................................................... 2-1

3. Drilling Rig Overview .................................................................................................. 3-1

3.1 Drilling Permits ................................................................................................. 3-1

3.2 Drilling Rig Overview ...................................................................................... 3-1

4. Emissions Inventory Development and Results ........................................................... 4-1

4.1 Activity Data ..................................................................................................... 4-2

4.1.1 Historical Activity ................................................................................. 4-2

4.1.2 Projected Activity .................................................................................. 4-4

4.2 Model Rig Emission Profiles ............................................................................ 4-9

4.2.1 Model Rig Engine Profiles .................................................................... 4-9

4.2.2 Model Rig Emission Factors ............................................................... 4-11

4.3 Emission Estimation Methodology ................................................................. 4-18

4.3.1 Example Emission Calculations .......................................................... 4-20

4.4 Results ............................................................................................................. 4-20

4.4.1 Emission Summary ............................................................................. 4-20

4.4.2 CERS XML Files ................................................................................ 4-40

4.5 Quality Assurance ........................................................................................... 4-40

5. Conclusions and Recommendations ............................................................................. 5-1

6. References ..................................................................................................................... 6-1

Appendix A. Annual HAP Emissions by Species (lbs/yr) ...................................................... A-1

Appendix B. Texas County Groupings Used for Growth Factor Projection Assignment ....... B-1

Appendix C. Total Drilling Depth by County by Model Rig Well Type Category ................. C-1

Appendix D. Annual and OSD County-Level Emission Estimates ........................................ D-1
ii 

List of Tables 

Section Page 

Table 1-1. Statewide Drilling Rig Estimates (Tons/Year) .......................................................... 1-2

Table 4-1. Projected Crude Oil Production 2010-2035 .............................................................. 4-7

Table 4-2. Projected Natural Gas Production 2010-2035 ............................................................ 4-8

Table 4-3. Weighted Average Projected Growth Factors 2011-2035+ ....................................... 4-9

Table 4-4. Model Rig Engine Parameters ................................................................................. 4-10

Table 4-5. PM10 Speciation Factors .......................................................................................... 4-12

Table 4-6. TOG Speciation Factors .......................................................................................... 4-12

Table 4-7. Annual Weighted Average Diesel Fuel Sulfur ........................................................ 4-13

Table 4-8. Emission Factors for Vertical Wells <= 7,000 feet (tons/1,000 feet) ...................... 4-14

Table 4-9- Emission Factors for Vertical Wells > 7,000 feet (tons/1,000 feet) ........................ 4-15

Table 4-10. Emission Factors for Directional/Horizontal Wells (tons/1,000 feet) ................... 4-16

Table 4-11. TxLED Counties .................................................................................................... 4-19

Table 4-12. Statewide Annual Emissions Totals (Tons/Year), Controlled Scenario ............... 4-21

Table 4-13. Statewide OSD Emissions Totals (Tons/Day), Controlled Scenario .................... 4-25

Table 4-14. Statewide Annual Emissions Totals (Tons/Year), Uncontrolled Scenario ........... 4-26

Table 4-15. Statewide OSD Emissions Totals (Tons/Day), Uncontrolled Scenario ................ 4-29

Table 4-16. County NOx Emissions Totals, Controlled Scenario (2010) .................................. 4-30

Table 4-17. Comparison of Statewide 2008 Annual Emissions Totals (Tons/Year), Current 

and Previous Studies, Controlled Scenario .................................................................... 4-41

Annual PM Toxics by Year (Lbs/Year) .......................................................................................... 1

Annual TOG Toxics by Year (Lbs/Year) ....................................................................................... 3

List of Figures 

Section Page 

Figure 1-1. Statewide Drilling Rig Estimates (NOx and CO Tons/Year) ................................... 1-3

Figure 1-2. Statewide Drilling Rig Estimates (VOC and SO2 Tons/Year) ................................. 1-4

Figure 1-3. Statewide Drilling Rig Estimates (PM10 and PM2.5 Tons/Year) .............................. 1-4

Figure 4-1. EIA Regions ............................................................................................................. 4-4

Figure 4-2. TRC Districts ........................................................................................................... 4-5

Figure 4-3. Statewide Drilling Rig Emissions – Controlled Scenario (NOx and CO 

Tons/Year) ..................................................................................................................... 4-22

Figure 4-4. Statewide Drilling Rig Emissions – Controlled Scenario (VOC and SO2 

Tons/Year) ..................................................................................................................... 4-23

Figure 4-5. Statewide Drilling Rig Emissions – Controlled Scenario (PM10 and PM2.5

Tons/Year) ..................................................................................................................... 4-23
iii 

Figure 4-6. Statewide Annual Drilling Rig Activity (000’s feet) ............................................. 4-24

Figure 4-7. Statewide Drilling Rig Emissions – Uncontrolled Scenario (NOx and CO 

Tons/Year) ..................................................................................................................... 4-27

Figure 4-8. Statewide Drilling Rig Emissions – Uncontrolled Scenario (VOC and SO2

Tons/Year) ..................................................................................................................... 4-28

Figure 4-9. Statewide Drilling Rig Emissions – Uncontrolled Scenario (PM10 and PM2.5

Tons/Year) ..................................................................................................................... 4-28

Figure 4-10. Annual NOx Emissions by Year – Top 10 Counties (2010 basis) ....................... 4-36

Figure 4-11. 2010 Annual NOx Emissions by County (Tons/Year) .......................................... 4-37

Figure 4-12. 2010 Annual VOC Emissions by County (Tons/Year) ......................................... 4-38

Figure 4-13. 2010 Annual PM2.5 Emissions by County (Tons/Year) ........................................ 4-39

Figure 4-14. Controlled and Uncontrolled Emissions Projections (NOx Tons/Year) .............. 4-41

Figure 4-15. Controlled and Uncontrolled Emissions Projections (CO Tons/Year) ............... 4-42

Figure 4-16. Controlled and Uncontrolled Emissions Projections (VOC Tons/Year) ............ 4-42

Figure 4-17. Controlled and Uncontrolled Emissions Projections (PM10 Tons/Year) ............ 4-43

Figure 4-18. Controlled and Uncontrolled Emissions Projections (SO2 Tons/Year) .............. 4-43

 
iv 

LIST OF ACRONYMS 

Acronym Definition

API American Petroleum Institute  

CERR Consolidated Emissions Reporting System

CO Carbon Monoxide

DOE U.S. Department of Energy

EIA Energy Information Administration

ERG Eastern Research Group  

HAP Hazardous Air Pollutant  

hp Horsepower

MMBBL Million Barrels

NIF NEI Input Format  

NOx Nitrogen Oxides

OSD Ozone Season Daily

PM10 PM with particle diameter less than 10 micrometers  

PM2.5 PM with particle diameter less than 2.5 micrometers  

QAPP Quality Assurance Project Plan

SCC Source Classification Code

SIP State Implementation Plan

SO2 Sulfur Dioxide

TCEQ Texas Commission on Environmental Quality

TexAER Texas Air Emissions Repository

TOG Total Organic Gases

TRC Texas Railroad Commission  

TxLED Texas Low Emission Diesel  

US EPA United States Environmental Protection Agency

VOC Volatile Organic Compounds

XML Extensible Markup Language
1-1 

1. Executive Summary 

The purpose of this study was to develop comprehensive statewide controlled and 

uncontrolled emissions inventories for drilling rig engines associated with onshore oil 

and gas exploration activities occurring in Texas. Oil and gas exploration and 

production facilities are considered some of the largest sources of area source emissions 

in certain geographical areas, dictating the need for continuing studies and surveys to 

more accurately depict these activities. The current inventory effort builds off of the 

previous 2009 study prepared for the TCEQ, 2009 Drilling Rig Emission Inventory for 

the State of Texas (July 15, 2009, prepared by ERG), which focused exclusively on 

drilling activities. The previous effort is expanded upon by improving the activity data 

(well counts, types, and depths) used to estimate emissions, and uses the drilling rig 

engine emission profiles developed in the 2009 study. The improved well activity data 

was obtained through acquisition of the “Drilling Permit Master and Trailer” database 

from the Texas Railroad Commission (TRC). The activity data and emissions 

characterization data were then used to develop controlled and uncontrolled drilling rig 

engine emissions inventories for the years 1990, 1993, 1996, and 1999 through 2040. 

The rig profiles developed in the 2009 study provided: 

 The average number of engines on a rig 

 Average engine model year and size (hp) 

 Average load for each engine 

 Engine function (draw works, mud pumps, power) 

 Average engine hour data for each well (total hours) 

 Average well drilling time (actual number of drilling days) 

 Average well completion time (number of days needed for well completion activities) 

 Average well depth 

Target pollutants for this study include nitrogen oxides (NOx), volatile organic 

compounds (VOC), carbon monoxide (CO), particulate matter (PM10 and PM2.5), sulfur 

dioxide (SO2), and hazardous air pollutants (HAP). Emissions were calculated for each 

county in Texas where drilling occurred and are provided in annual tons per year and by 

typical ozone season day. Emission estimates for years prior to 2011 were based on TRC 

records of oil and gas well completions during those years, and U.S Department of 

Energy (DOE), Energy Information Administration (EIA) oil and gas production growth 

estimates were used to develop the projections for the years 2011 forward. 

Emissions estimates developed from this inventory project may be used for improved 

input data to photochemical air quality dispersion modeling, emissions sensitivity 

analyses, State Implementation Plan (SIP) development, and other agency activities. 
1-2 

The final inventory estimates are provided in Consolidated Emissions Reporting System 

(CERS) Extensible Markup Language (XML) to facilitate entry of the data into the 

state’s TexAER (Texas Air Emissions Repository) database, and for the purposes of 

submittal to US EPA. For purposes of XML preparation, Source Classification Code 

(SCC) 23-10-000-220 (Industrial Processes - Oil and Gas Exploration and Production - 

All Processes - Drill Rigs) was used, consistent with the 2009 study. 

Table 1-1 summarizes the statewide annual emission estimates for 1990, 1993, 1996, and 

1999 through 2040. Figures 1-1 through 1-3 present this same information in chart 

form. Note that the PM10 and PM2.5 values are so close together that they are difficult to 

distinguish in Figure 1-3. Appendix A provides the corresponding statewide emissions 

estimates for HAPs. 

Table 1-1. Statewide Drilling Rig Estimates (Tons/Year) 

Year CO NOX PM2.5 PM10 SO2 VOC

1990 13,366 25,308 2,457 2,533 3,037 3,462

1993 15,193 29,354 2,743 2,828 3,141 3,940

1996 15,502 33,037 2,737 2,822 4,093 4,044

1999 10,568 24,159 1,707 1,760 1,647 2,769

2000 14,570 33,578 2,350 2,422 2,290 3,798

2001 16,910 38,960 2,726 2,810 2,641 4,410

2002 11,027 27,974 1,919 1,978 2,100 2,955

2003 14,234 37,220 2,471 2,548 2,825 3,803

2004 15,057 40,164 2,607 2,688 3,040 4,047

2005 17,706 47,798 3,068 3,163 3,606 4,788

2006 15,235 52,497 2,463 2,539 4,290 4,135

2007 16,071 57,197 2,320 2,392 909 4,443

2008 17,745 59,261 2,615 2,696 1,033 4,593

2009 8,464 29,231 1,244 1,282 523 2,202

2010 7,182 24,531 1,024 1,056 21 1,846

2011 6,869 23,254 1,016 1,047 21 1,725

2012 6,949 22,920 1,028 1,060 22 1,716

2013 5,893 19,878 652 672 19 1,687

2014 5,916 19,875 655 675 20 1,691

2015 5,897 19,819 653 673 20 1,693

2016 5,826 18,711 643 663 20 1,691

2017 4,375 17,954 537 553 19 1,417

2018 3,085 16,446 400 413 19 1,164

2019 3,096 16,545 402 414 19 1,170

2020 3,102 16,475 402 415 20 1,175

2021 1,712 14,182 233 240 19 832

2022 1,705 14,201 233 240 19 837

2023 1,711 14,308 234 242 19 843

2024 2,178 16,194 308 318 22 956
1-3 

Year CO NOX PM2.5 PM10 SO2 VOC

2025 2,170 16,186 307 317 22 956

2026 2,409 18,006 346 357 24 1,032

2027 1,307 11,359 221 228 19 732

2028 1,269 11,190 219 226 19 725

2029 1,254 9,817 185 190 18 787

2030 1,244 9,762 183 189 18 783

2031 1,233 8,878 172 177 17 778

2032 1,200 8,649 170 175 17 772

2033 779 8,566 143 148 17 671

2034 770 8,490 142 146 17 665

2035 761 8,410 140 145 17 660

2036 387 7,869 96 99 16 637

2037 385 7,861 96 99 16 637

2038 384 7,853 96 99 16 637

2039 382 7,316 96 99 16 637

2040 381 7,311 96 99 16 637

Figure 1-1. Statewide Drilling Rig Estimates (NOx and CO Tons/Year) 
1-4 

Figure 1-2. Statewide Drilling Rig Estimates (VOC and SO2 Tons/Year) 

Figure 1-3. Statewide Drilling Rig Estimates (PM10 and PM2.5 Tons/Year) 

The study results provide a significant improvement upon the 2009 effort, utilizing 

improved gap filling methods for the TRC dataset to obtain a more complete and 

accurate set of drill rig activity. In addition, this study utilized historical drilling data 

from the TRC to estimate past emissions, rather than relying on surrogate based backcasting from a base year, as was done in the previous study. Finally, the study greatly 

expanded the time horizon of the previous study, ranging from 1990 with projections 

through 2040. The result is a reliable, temporally resolved profile of county-level 

drilling activity emissions. The successful update of the state’s TexAER database system 
1-5 

with this data, associated with a new area source SCC, will allow for improved SIP and 

trend analysis for all regions of the state. 

Based on the projected oil and gas production levels in Texas from the EIA, drilling 

activity is estimated to remain relatively constant across the state from 2011 through 

2035. However, the continued phase-in of more stringent Non-Road diesel engine 

emission standards should cause a steady decrease in drilling-related emissions over 

time. SO2 emissions levels in particular are estimated to have fallen precipitously due to 

the introduction of the ultra-low sulfur standards for diesel fuel in 2010, and should 

remain extremely low for the foreseeable future. 

An analysis of county-level data found that the vast majority of Texas counties produced 

some level of emissions associated with drilling activities (206 of 254 counties) in the 

2010 base year. However, the county-level distribution of NOx emissions is highly 

skewed, with 14 counties being responsible for 50 percent of total statewide NOx in 

2010. In addition, the preponderance of the high NOx emitting counties were 

predominantly in West and North-Central Texas. 

While the emissions inventory results provide an excellent basis for assessing historical 

emissions levels, significant sources of uncertainty remain. Most importantly, 

projections of future activity are highly uncertain, subject to significant rises and falls 

depending upon economic factors and associated oil and gas prices. Accordingly, 

periodic refinement of the activity data used for projected years 2011 through 2040 is 

strongly recommended to account for such factors. In addition, the contribution of 

hydraulic fracturing operations to drilling activity emissions remains unknown at this 

time. 
2-1 

2. Introduction 

The purpose of this study was to develop comprehensive statewide controlled and 

uncontrolled emissions inventories for drilling rig engines associated with onshore oil 

and gas exploration activities occurring in Texas. Oil and gas exploration and 

production facilities are considered some of the largest sources of area source emissions 

in certain geographical areas, dictating the need for continuing studies and surveys to 

more accurately depict these activities. The current inventory effort builds off of the 

previous 2009 study prepared for the TCEQ, 2009 Drilling Rig Emission Inventory for 

the State of Texas (July 15, 2009, prepared by ERG), which focused exclusively on 

drilling activities. The previous effort is expanded upon by improving the activity data 

(well counts, types, and depths) used to estimate emissions, and uses the drilling rig 

engine emission profiles developed in the 2009 study. The improved well activity data 

was obtained through acquisition of the “Drilling Permit Master and Trailer” database 

from the Texas Railroad Commission (TRC). The activity data and emissions 

characterization data were then used to develop controlled and uncontrolled drilling rig 

engine emissions inventories for the years 1990, 1993, 1996, and 1999 through 2040. 

While drilling activities are generally short-term in duration, typically covering a few 

weeks to a few months, the associated diesel engines are usually very large, from several 

hundred to over a thousand horsepower (hp). As such, drilling activities can generate 

substantial amounts of NOx emissions. While previous studies have focused more 

intently on quantifying the ongoing fugitive VOC emissions associated with oil and gas 

production, significant uncertainty remains regarding the shorter term NOx emission 

levels associated with drilling activity. 

The activity and drilling rig engine emissions profiles developed under the 2009 study 

were used to develop emissions estimates of VOC, NOx, CO, PM10 and PM2.5, SO2, and 

HAP for drilling rig engines across the state. Emissions are calculated on a county-level 

basis and provided in annual tons per year and by typical ozone season day. 

Section 3.0 of this report provides an overview of the drilling process and identifies the 

types of activities and equipment that are commonly associated with drilling activity. 

Section 4.0 describes the development of the emissions inventory including how the 

activity data was compiled, how the model drilling rig emission profiles were developed, 

and how these model drilling rig emission profiles were combined with the activity data 

to develop the emission inventories, along with quality assurance measures applied. 

Section 5.0 summarizes the conclusions for this study and offers recommendations for 

future studies. 
3-1 

3. Drilling Rig Overview 

3.1 Drilling Permits 

All exploratory oil and gas drilling in Texas requires a permit. These permits are 

processed and maintained through the TRC. The drilling permits are available for 

review through the TRC website, and include well-specific data such as approval date, 

location (county), well profile (vertical, horizontal, directional), well depth, start or 

“spud-in” date, and well completion date. ERG obtained this data in electronic format 

through acquisition of the “Drilling Permit Master and Trailer” database. This database 

formed the basis of the activity data used to develop the historical emissions inventories 

(those prior to 2011). 

3.2 Drilling Rig Overview 

Air pollutant emissions from oil and gas drilling operations originate from the 

combustion of diesel fuel in the drilling rig engines. The main functions of the engines 

on an oil and gas drilling rig are to provide power for hoisting pipe, circulating drilling 

fluid, and rotating the drill pipe. Of these operations, hoisting and drilling fluid 

circulation require the most power. 

There are two common types of rigs currently in use – mechanical and electrical. In 

general, mechanical rigs have three independent sets of engines. The first set of engines 

(draw works engines) are used to provide power to the hoisting and rotating equipment, 

a second set of engines (mud pump engines) are dedicated to circulating the drilling 

fluid which is commonly referred to as “mud”, and a third set of engines (generator 

engines) are used to provide power to auxiliary equipment found on the drill site such as 

lighting equipment and heating and air conditioning for crew quarters and office space. 

There may be one, two, or more draw works engines, depending on the input power 

required. There are typically two mud pumps for land rigs, with each mud pump 

independently powered by a separate engine. The mud pump engines are typically the 

largest engines used on a mechanical rig. Finally, there are typically two electric 

generator engines per mechanical rig, with one running continuously and the second 

serving as a stand by unit. 

Electrical rigs are typically comprised of two to three large, identical diesel-fired enginegenerator sets that provide electricity to a control house called a silicon controlled 

rectifier (SCR) house. Electricity from the SCR house is then used to provide power to 

separate motors on the rig. In this configuration, there are dedicated electric motors 

used for the draw works/hoisting operations, the mud pumps, and other ancillary power 

needs (such as lighting). The generator engines are loaded as required to meet 

fluctuating power demands, with one unit typically designated for standby capacity. The 
3-2 

trend in new rig design is almost exclusively towards electric rigs, except perhaps for the 

smallest rigs. This is probably due to the relative expense of engines versus motors, both 

in terms of initial cost and maintenance. Today, electrical rigs are common, especially 

for larger rigs (Bommer, 2008). 

After drilling and casing a well, it must be “completed.” Completion is the process in 

which the well is enabled to produce oil or gas. Once the desired well depth is reached, 

the geological formation must be tested and evaluated to determine whether the well 

will be completed for production, or plugged and abandoned. To complete the well 

production, casing is installed and cemented and the main drilling rig is dismantled and 

moved to the next site. A smaller rig, called a completion rig (also known as a workover 

rig), is then moved on site to bring the well into production, to perforate the production 

casing and run production tubing to complete the well. Typically, the completion rig is a 

carrier-mounted arrangement and may be on-site for several days to a week or more 

depending on well depth and other factors. The completion rigs hoist smaller loads and 

pump at lower rates than the drilling rigs, and therefore require much smaller engine 

capacity. 

Increasingly, reservoir productivity is enhanced by the application of a stimulation 

technique called hydraulic fracturing.1 Fracturing jobs are often high rate, high volume, 

and high pressure pumping operations. They are accomplished by bringing very large 

truck- mounted diesel-powered pumps (e.g., 2,000 hp or more) to the well site to inject 

the fracturing fluids and material, and to power the support equipment such as fluid 

blenders. In this process, the reservoir rock is hydraulically overloaded to the point of 

rock fracture. The fracture is induced to propagate away from the well bore by pumping 

hydraulic fracturing fluid into the well bore under high pressure. The fracture is kept 

open after the end of the job by the introduction of a solid proppant (sand, ceramic, 

bauxite, or other material), by eroding the sides of the fracture walls and creating rubble 

by high injection rates, or for carbonate formations, by etching the walls with acid. The 

fracture thus created and held open by the proppant materials becomes a high 

conductivity pathway to the well bore for reservoir fluid. 

Fracturing generally takes place directly after removal of the completion rig in order to 

initiate gas production. Therefore it is reasonable to assume that most fracturing occurs 

within days or weeks of well completion. The frequency and timing of both fracturing as 

well as re-fracturing (wherein a well nearing exhaustion is fractured again in order to reinvigorate gas flow), is not contained in the TRC database and is unknown. 

Oil and gas wells are commonly classified as vertical, directional, or horizontal wells, 

depending on the direction of the well bore. Vertical wells are the most common, and 

 

1

 Hydraulic methods are the only type of fracturing known to occur with any frequency in the shale formations in 

Texas. 
3-3 

are wells that are drilled straight down from the location of the drill rig on the surface. 

Directional wells are wells where the well bore has not been drilled straight down, but 

has been made to deviate from the vertical. Directional wells are drilled through the use 

of special tools or techniques to ensure that the well bore path hits a particular 

subsurface target, typically located away from (as opposed to directly under) the surface 

location of the well. Horizontal wells are a subset of directional wells in that they are not 

drilled straight down, but are distinguished from directional wells in that they typically 

have well bores that deviate from vertical by 80 - 90 degrees. Horizontal wells are 

commonly drilled in shale formations. Once the desired depth has been reached (the 

well bore has penetrated the target formation), lateral legs are drilled to provide a 

greater length of well bore in the reservoir. 

In vertical wells, a single fracture job per reservoir is commonly done. In high angle or 

horizontal wells, it is common to perform multiple fracturing jobs (multi stage 

fracturing) along the path of the bore hole through a reservoir. The measure of the 

power required is based on the hydraulic horsepower necessary to fracture the well. 

Although very short in duration (typically less than a day), fracturing activities may 

result in substantial NOx emissions due to the very high horsepower requirements. 
4-1 

4. Emissions Inventory Development and Results 

The activity data from the TRC and the model rig emissions profiles developed in the 

2009 study for each model rig well type category were utilized to develop emissions 

estimates for selected target years, as described in the following sections. The 2009 

study, which serves as the basis for the current inventory development, attempted to 

characterize activity and emissions for all significant sources associated with drilling 

activities. Note that small engines – e.g., 25 hp and less – were excluded from the 

survey effort due to their anticipated low levels of emissions. In addition, the survey 

results did not find any engines powered by gasoline or natural gas, so emission 

inventory estimates were limited to diesel engines. 

EPA’s NONROAD emission factor model estimates emissions for “Other Oil Field 

Equipment” which includes fracturing rigs, mechanical drilling engines, oil field pumps, 

pump jacks, and seismograph rigs (PSR 1998). Of these subcategories, only the first 

three are involved in drilling activities. The 2009 survey results successfully profiled 

activity and population levels for drilling engines and pumps, as well as electrical 

generators used to power auxiliary equipment as described in the previous section. 

During the data collection phase of the 2009 study, information was also solicited from 

respondents regarding fracturing activities. As part of their survey response, drilling 

contractors and oil and gas exploration companies occasionally provided some 

qualitative or quantitative information regarding fracturing, but the responses were 

highly variable in content and format. In general, the indication was that fracturing was 

a short-term activity (less than one day in duration), and that pump trucks containing 

multiple, large diesel-fired engines could be used simultaneously to pump the fracturing 

fluids into the well.2

Specific information regarding the frequency of fracturing events and the total hp-hours 

required per event were not generalizable to the inventory as a whole, however. Further 

investigation regarding fracturing was made by contacting service companies that 

provide fracturing services, as well as interviewing personnel at the TRC and 

researching the availability of fracturing data on-line through the TRC website. Two of 

the three service companies contacted provided some data for the fracturing activities 

performed in 2008, which varied from the use of five 1,250 hp pump engines for a total 

duration of 1 hour, to the use of seven 2,500 hp pump engines for a total duration of 12 

hours. The third service company contacted did not provide any data. 

 

2

 Note that these pump engines are different than the pumps used to circulate drilling fluid, as profiled for this 

inventory. 
4-2 

Unlike the drilling permit records obtained through the “Drilling Permit Master and 

Trailer” database, fracturing data is not compiled by the TRC or otherwise made readily 

available in any summarized format through any on-line queries or electronic datasets. 

However, images of individual well completion records (referred to as G-1 forms for gas 

well completions and W-2 forms for oil well completions) are available on-line through 

the TRC website. Using American Petroleum Institute (API) numbers from the TRC 

data, a random on-line search was performed to review the G-1 and W-2 records for 

approximately 1,200 wells. The G-1 and W-2 forms were only found for approximately 

one-third of these wells. These forms are frequently completed by hand, with 

inconsistent data being reported by individual well operators, with much of the data 

being incomplete. However, based on a review of the records we were able to identify, it 

appears that approximately 80% of the wells in the sample had some kind of fracturing 

activity occurring prior to well completion. (Given the short duration of fracturing 

activities, it is reasonable to assume that most or all of the emissions associated with 

fracturing occur in the same year as the emissions associated with drilling.) While data 

is not currently available under this project to provide emission estimates for fracturing 

activities, due to the large engine sizes used by the pump trucks, this is a source category 

that may be considered for inclusion in future emission inventory development projects. 

4.1 Activity Data 

4.1.1 Historical Activity 

The Texas Railroad Commission (TRC) maintains oil and natural gas drilling permits for 

the state of Texas. ERG obtained a copy of the database in ASCII, position-delimited 

format from a TRC download on May 12, 2011. Using the TRC manual, ERG uploaded 

the database file into Microsoft Access. The database file contained over 650,000 

unique drilling permit and well ID records from 1948 to mid-2011. ERG was tasked 

with identifying historical drilling activities which occurred in base years 1990, 1993, 

1996, and from 1999-2010 for a total of 15 years. 3 In addition to descriptive 

information about each permit record (i.e., permit number, American Petroleum 

Institute (API) number, Well ID, etc.), the TRC data file contains information for when 

drilling began (Spud Date), when drilling was completed (Drilling Completion Date), 

wellbore profile type (vertical or horizontal), and permitted well depth. 

It is important to note that approximately 19% of the data records did not contain both 

Spud Date and Completion Date, thus it could not be determined definitively if activity 

occurred during a base year of interest. It is believed that these records were 

administrative records, and no drilling activity was associated with these entries. 

Additionally, over 51% of the data records had either a Spud Date in 2011, finished 

 

3

 Note that unlike the 2009 study, which back-cast well activity levels using surrogates, this study used actual 

historical activity levels for all years between 1990 and 2010. 
4-3 

drilling prior to 1990, or the entire drilling activity took place in a non-base year of 

interest (1991, 1992, 1994, 1995, 1997, or 1998). As such, these records were not 

included in the analysis. Finally, we identified approximately 4% of the data as having 

either a Spud Date or a Drilling Completion Date, but not both. We “flagged” these 

records as possibly occurring during a base year of interest. As a result, over 168,000 

data records (~ 26%) were initially identified as having drilling activities occurring 

during one of the 15 years of interest. 

Prior to calculating the activity data needed to calculate estimated drilling emissions, 

ERG reviewed the flagged records to potentially add to the records of interest. We used 

the TRC website (www.rrc.state.tx.us) to approximate surrogate Spud or Drilling 

Completion Dates. Specifically, if a Spud Date was missing, ERG used the TRC Permit 

Approved Date as a surrogate for Spud Date and Surface Casing Date or Well 

Completion Date as a surrogate Drilling Completion Date. However, since there were 

over 25,000 flagged records, it was not feasible to examine each one due to time and 

resource constraints. Therefore, we prioritized the flagged records by reviewing the 

deepest permitted wells first. As a result, we were able to identify nearly 15,000 more 

data records in which drilling occurred in a base year of interest. 

Additionally, we verified base year data records in which the Spud Dates, Completed 

Drilling Dates, or permitted well depths were obvious errors. For example, permit ID = 

618176 had a permitted well depth of 89,000 feet. In reviewing the TRC website, it was 

determined that the permitted well depth should have been 8,900 feet. Additional 

errors include Spud or Completed Drilling Dates that occurred prior to 1948 or after 

2011. Also, it appears as if some years were transposed (e.g., 1990 vs. 1909) and these 

were corrected accordingly. 

In some cases, drilling which occurred over multiple years was pro-rated for the base 

year of interest. In these situations, ERG calculated an “Average Drilling Rate” by 

dividing the permitted well depth by the number of drilling days, which is the number of 

days between the Completed Drilling Date and the Spud Date. The “Average Drilling 

Rate” was then used to pro-rate the total drilling days to each year. For example, permit 

ID = 486390 had a Spud Date of December 29, 2000, a Drilling Completion Date of 

January 8, 2001, and a total permitted well depth of 4,500 feet. Based on the Spud Date 

and Drilling End Date, it is assumed that drilling was continuous for 11 days. Therefore 

the “Average Drilling Rate” for this well was assumed to be 409.1 ft per day, and the 

2000 pro-rated drilling was set to 1,227 feet for 2000 and 3,273 feet for 2001 (4,500 

ft/11 days = 409.1 ft per day; 409.1 ft per day * 8 days = 3,272.8 ft; 409.1 ft per day * 3 

days = 1,227.3 feet). 

In total, ERG identified over 183,000 TRC permit records with drilling activity assigned 

to the target years. Each data record was also classified by three different wellbore 
4-4 

profile types defined during the 2009 study: “vertical well ≤ 7,000 feet”; “vertical well > 

7,000 feet”; and “horizontal/directional well”. These well type categories were selected 

to characterize three broadly different rig operation and engine type profiles, as 

discussed in detail in the 2009 report. The total amount of feet drilled was then summed 

to the county-level by wellbore profile type for each year. 

ERG’s processed drilling activity records covered the vast majority of TRC drilling 

records for the target years: of the 188,533 total wells drilled during the target years 

between 1990 and 2010 (as per the TRC database), ERG successfully characterized and 

processed 183,211 wells, or 97.2% of all recorded activity. The remaining wells could not 

be characterized adequately due to irresolvable data gaps or similar data 

inconsistencies. 

4.1.2 Projected Activity 

2011 through 2040 projected activity data were developed using 2010 as the base year 

activity data from the TRC and forecasting future activity based on US DOE Energy 

Information Administration (EIA) projections of oil and gas production for the 

Midcontinent, Southwest and Gulf Coast regions from the Annual Energy Outlook 2011, 

Reference Case. The EIA data tables (specifically Supplemental Tables 132 and 133) 

present estimated crude oil and natural gas production estimates for the years 2008-

2035. The geographic level of the projected data is by EIA Region. 

Portions of Texas fall into three EIA Regions: Gulf Coast (Region 2); Southwest (Region 

4); and Midcontinent (Region 3). The majority of the State is in the Gulf Coast and 

Southwest EIA Regions. Only a small portion (area to the west of Oklahoma) is in the 

Midcontinent Region. Figure 4-1 shows the EIA regions and their coverage in Texas. 

Figure 4-1. EIA Regions 
4-5 

Figure 4-2 provides a county-level map indicating each of the TRC Districts. 

Figure 4-2. TRC Districts4

 

 

4 http://www.rrc.state.tx.us/forms/maps/ogdivisionmap.php
4-6 

Using the above figures, ERG developed a direct correspondence between EIA regions 

and TRC regions, as follows: 

 EIA Midcontinent => TRC District 10 

 EIA Southwest => TRC Districts 7b, 7c, 8, 8a, 9 

 EIA Gulf Coast => TRC Districts 1 - 6 

Using these assignments ERG developed growth projections through 2035 for the three 

different county groupings - see Appendix B for county groups. 

Table 4-1 and Table 4-2 show projected crude oil and natural gas production for the 

three relevant EIA Regions, from 2010 through 2035. The total percentage change for 

each year from 2011 through 2035 is presented relative to the base year of 2010. 

This data was then used to calculate a projected growth factor (%) for each year from 

2011 through 2035 for each county grouping by weighting the oil and gas percentage 

growth figures relative to the number of oil and gas wells completed statewide in 2010. 

(Growth rates for 2036 – 2040 are assumed to equal the 2035 rate). For example, the 

projected growth factor for 2011 for the EIA Gulf Coast (GC) region is calculated as 

follows: 

2011 GC factor = ((% change from 2010 to 2011 in GC Crude Oil Production x number of 

oil well completions in 2010) + (% change from 2010 to 2011 in GC Natural Gas 

Production x number of gas well completions in 2010)) / (total number of oil and gas 

well completions in 2010) 

Using the data in Table 4-1 and Table 4-2, combined with the statewide well completion 

counts, the projected growth factor for the EIA GC region in 2011 is: 

2011 GC factor = ((9.8% x 5,392) + (-1.3% x 4,071)) / (5,392+ 4,071) = 5.0% 

Table 4-3 shows the growth factors that were developed for each projected county 

grouping and year combination as a result of this analysis. These factors were then 

applied to the 2010 base year well depth totals by county to determine activity data for 

2011 through 2035. These projections are based on the best data currently available, but 

should be revisited periodically given the volatile economic nature of oil and gas prices. 
4-7 

Table 4-1. Projected Crude Oil Production 2010-2035 

EIA Region

Crude Oil Production (MMBBL/day)

2010 2011 2012 2103 2014 2015 2016 2017 2018 2019 2020 

Gulf Coast 0.53 0.58 0.60 0.62 0.62 0.64 0.66 0.67 0.69 0.71 0.72 Midcontinent 0.34 0.33 0.34 0.34 0.34 0.35 0.36 0.37 0.37 0.40 0.42 Southwest 0.94 0.97 0.99 1.01 1.02 1.03 1.05 1.07 1.09 1.11 1.11 % Change from 2010Gulf Coast 9.8% 13.2% 16.7% 18.1% 21.9% 24.8% 27.8% 31.2% 34.7% 36.4% Midcontinent   ‐5.3%  ‐2.1% ‐0.7% ‐0.3% 1.7% 4.5% 6.6% 8.8% 15.3% 21.2% Southwest 3.2% 5.6% 7.0% 8.7% 9.8% 11.2% 14.0% 16.2% 17.7% 18.2% 

EIA Region

Crude Oil Production (MMBBL/day)

2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 

Gulf Coast 0.75 0.75 0.73 0.73 0.72 0.72 0.71 0.71 0.70 0.68 Midcontinent 0.60 0.62 0.64 0.65 0.65 0.65 0.66 0.65 0.64 0.64 Southwest 1.10 1.10 1.09 1.09 1.08 1.06 1.05 1.04 1.03 1.02 % Change from 2010Gulf Coast 41.5% 41.4% 39.4% 38.6% 36.9% 35.9% 35.7% 34.5% 33.5% 29.8% Midcontinent 74.1% 79.9% 85.2% 87.9% 89.7% 89.7% 91.4% 90.0% 84.9% 84.6% Southwest 17.3% 16.8% 15.9% 15.8% 14.5% 13.2% 11.9% 10.6% 9.2% 8.5% 
4-8 

Table 4-2. Projected Natural Gas Production 2010-2035 

EIA Region

Natural Gas Production (trillion cubic feet)

2010 2011 2012 2103 2014 2015 2016 2017 2018 2019 2020 202

Gulf Coast 4.25 4.19 4.21 4.28 4.28 4.26 4.16 4.09 4.03 3.99 4.00 4Midcontinent 3.17 3.16 3.17 3.18 3.15 3.12 3.05 2.98 2.91 2.85 2.74 2Southwest 4.25 4.18 4.14 4.16 4.14 4.13 4.07 4.01 3.96 3.90 3.90 3% Change from 2010Gulf Coast   ‐1.3%  ‐1.0% 0.7% 0.9% 0.3% ‐1.9% ‐3.6% ‐5.0%  ‐6.1% ‐5.9% ‐5.Midcontinent   ‐0.2% 0.0% 0.5% ‐0.6% ‐1.4% ‐3.7% ‐6.0% ‐8.0%  ‐10.1% ‐13.4% ‐13.Southwest   ‐1.7%  ‐2.5% ‐2.1% ‐2.5% ‐2.7% ‐4.3% ‐5.6% ‐6.9%  ‐8.3% ‐8.2% ‐8.

EIA Region

Natural Gas Production (trillion cubic feet)

2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 

Gulf Coast 3.95 4.00 4.01 4.04 4.06 4.03 4.00 3.98 3.99 4.0Midcontinent 2.70 2.70 2.68 2.67 2.67 2.62 2.59 2.58 2.57 2.5Southwest 3.92 3.93 3.91 3.89 3.90 3.87 3.89 3.92 3.97 4.0% Change from 2010Gulf Coast  ‐6.9%  ‐5.9%  ‐5.5% ‐4.8% ‐4.3% ‐5.0% ‐5.7%  ‐6.2% ‐6.1% ‐5.8% Midcontinent  ‐14.8%  ‐14.8%  ‐15.3% ‐15.6% ‐15.8% ‐17.3% ‐18.2%  ‐18.4% ‐18.9% ‐18.6% Southwest  ‐7.6%  ‐7.5%  ‐8.0% ‐8.4% ‐8.3% ‐8.9% ‐8.4%  ‐7.7% ‐6.5% ‐5.4% 
4-9 

Table 4-3. Weighted Average Projected Growth Factors 2011-2035+

Year Gulf Coast Midcontinent Southwest

2011 5.02% ‐3.11% 1.09%

2012 7.09% ‐1.20% 2.12%

2013 9.82% ‐0.18% 3.09%

2014 10.70% ‐0.43% 3.88%

2015 12.61% 0.37% 4.42%

2016 13.31% 0.97% 4.53%

2017 14.29% 1.18% 5.57%

2018 15.63% 1.57% 6.26%

2019 17.15% 4.37% 6.51%

2020 18.20% 6.32% 6.84%

2021 18.70% 13.64% 6.17%

2022 19.69% 22.03% 6.46%

2023 20.89% 29.30% 6.89%

2024 20.68% 35.86% 6.59%

2025 21.05% 39.16% 6.35%

2026 20.08% 41.96% 5.62%

2027 19.93% 43.37% 5.39%

2028 19.18% 44.31% 4.69%

2029 18.30% 43.67% 3.69%

2030 17.89% 44.25% 3.17%

2031 16.99% 43.37% 2.73%

2032 16.46% 40.25% 2.45%

2033 14.48% 40.20% 2.52%

2034 13.86% 38.58% 1.61%

2035+ 12.34% 35.39% 1.60%

Appendix C contains a summary of the total well depth by county and year for each 

model rig well type category. 

4.2 Model Rig Emission Profiles 

4.2.1 Model Rig Engine Profiles 

The 2009 study established rig engine profiles for three distinct model rig categories for 

the following well types and depths based on the results of the data collection survey: 

 Vertical wells less than or equal to 7,000 feet; 

 Vertical wells greater than 7,000 feet; and 

 Horizontal/Directional wells. 
4-10 

For each of these rig categories, a model rig engine profile was developed. In order for 

the model rig engine profile data to be applied consistently to the TRC activity data, the 

survey results were normalized to a 1,000 foot drilling depth. This was accomplished by 

dividing the total drilling hours for each engine included in each survey by the well 

depth for that survey to obtain the hours of operation per engine per 1,000 feet of 

drilling depth. 

As the engine profiles and functions for engines used on mechanical rigs and electrical 

rigs are distinctly different, separate engine profiles for mechanical and electrical rigs 

were developed for each model rig well type category. 

The following average engine parameters were calculated for each model rig well type 

category using a weighted average for each parameter based on the number of wells 

associated with each survey: 

 Number of engines by rig type (i.e., mechanical draw works, mud pumps, and 

generators; electrical rig engines; and completion engines) 

 Engine age 

 Engine size (hp) 

 Engine on-time (hours/1,000 feet drilled) 

 Overall average load (%) 

The weighted averaged engine parameters developed for each model rig category by rig 

type in the 2009 study are summarized in Table 4-4. 

Table 4-4. Model Rig Engine Parameters 

Model Rig

Category

Rig Type Engine

Type

# of

Engines

Average

Age (yrs)

Engine

Size (hp)

Hours/1,000 ft

drilled

Average

Load (%)

Vertical <=

7,000 ft

Mechanical Draw Works 1.60 7 442 30.8 51.8

Mud Pumps 1.69 6 428 29.4 45.9

Generator 0.97 4 330 28.3 70.4

Vertical

> 7,000 ft

Mechanical Draw Works 2.01 25 455 35.9 47.4

Mud Pumps 1.62 18 761 33.2 46.0

Generator 2.00 10 407 19.3 78.7

Electrical 2.15 2 1,381 62.6 48.5

Horizontal/

Directional

Mechanical Draw Works 2.00 15 483 50.1 41.1

Mud Pumps 2.00 6 1,075 36.4 42.6

Generator 2.00 10 390 26.8 69.0

Electrical 2.03 2 1,346 47.3 52.5

All All Completion 1.00 Default 350 10.0 43.0
4-11 

As can be seen in Table 4-4, the expected trend toward larger engine sizes and more 

hours required per 1,000 feet for the deeper vertical wells and the horizontal/directional 

wells was verified. The older engine ages for the mechanical rigs used on the deeper 

vertical wells and the horizontal/directional wells are based on several surveys received 

for these well types that covered a large number of wells drilled by rigs with older 

engines. However, as noted in the 2009 study report, the future trend for these types of 

wells is towards the use of electrical rigs, and the average age of the engines used on the 

electrical rigs for these well types is only two years. 

4.2.2 Model Rig Emission Factors 

Using the model rig engine parameters presented in Table 4-4, EPA’s NONROAD2008a 

model was modified to develop criteria pollutant emission factors for each model rig 

well type category for each year of the inventory (1990, 1993, 1996, and 1999 through 

2040). Use of the NONROAD model allowed for expected reductions in emissions over 

time due to the phasing in of EPA’s emissions standards for Non-Road diesel engines. 5

Following the same methodology used in the 2009 emission inventory study, ERG 

modified the ACTIVITY.DAT file within NONROAD to reflect the appropriate hours per 

year and load factors for the required engine types (mechanical and electrical engines 

for each of the three rig types). Modifications were made for SCC 2270010010 (Diesel 

Other Oil Field Equipment). ERG also modified the TX.POP file to reflect the 

appropriate average hp for the engine type in question, and set the equipment 

population count to 1 in order to ease post-processing calculations. In addition, default 

NONROAD OPT files (input files containing basic model run information) were 

modified to reflect the statewide diesel fuel sulfur levels (see below) for each scenario 

year of interest. Accordingly, sets of OPT, activity, and population files were developed 

to model each well type/engine type/scenario year combination for this analysis. 

Hazardous air pollutant (HAP) emission factors were developed by speciating the 

NONROAD emission factors based on HAP emissions profiles obtained from the 

California Air Resource Board’s Speciation Profile Database (ARB, 2001). The specific 

speciation profiles used were Profile #818 for TOG and Profile #425 for PM. This 

methodology is consistent with the prior 2009 emission inventory study approach, as 

well as the speciation method used within the TCEQ’s TexN emissions model. The HAP 

speciation factors used are presented in Table 4-5 and Table 4-6. 

 

5

 While the NONROAD model was used to calculate drilling activity emissions (in order to more accurately capture 

emission standard phase in impacts), these emissions are actually classified as area sources emissions and reported 

as such to the TCEQ. 
4-12 

Table 4-5. PM10 Speciation Factors 

HAP HAP CAS # Weight Fraction of PM10

Antimony 7440360 0.000036

Arsenic 7440382 0.000005

Cadmium 7440439 0.000040

Cobalt 7440484 0.000011

Chlorine 7782505 0.000344

Lead 7439921 0.000042

Manganese 7439965 0.000040

Nickel 7440020 0.000019

Mercury 7439976 0.000030

Phosphorous 7723140 0.000127

Selenium 7782492 0.000010

Table 4-6. TOG Speciation Factors 

HAP HAP CAS # Weight Fraction of TOG

1,3‐butadiene 106990 0.002

2,2,4‐trimethylpentane 540841 0.003

Acetaldehyde 75070 0.074

Benzene 71432 0.02

Cumene 98828 2E‐04

Ethylbenzene 100414 0.003

Formaldehyde 50000 0.147

Methanol 67561 3E‐04

m‐xylene 108383 0.006

Naphthalene 91203 9E‐04

n‐hexane 110543 0.002

o‐xylene 95476 0.003

Propionaldehyde 123386 0.01

p‐xylene 106423 0.001

Styrene 100425 6E‐04

Toluene 108883 0.015

SO2 emissions were based on fuel sulfur content profiles for Texas obtained from 

historical fuel sampling data performed for the TCEQ. The average diesel sulfur content 

(% weight) for a particular analysis year was developed using the county-level fuel 

parameter data contained in TCEQ’s TexN model, weighted by the number of wells in 

each county in 2008. The statewide average diesel sulfur content values calculated are 

presented in Table 4-7 reflecting the reduced sulfur requirements over time. 
4-13 

Table 4-7. Annual Weighted Average Diesel Fuel Sulfur 

Year Sulfur (% weight)

1990 0.3015

1993 0.2693

1996 0.3138

1999 0.1733

2000 0.1717

2001 0.1708

2002 0.1706

2003 0.1700

2004 0.1692

2005 0.1678

2006 0.1665

2007 0.0320

2008 0.0317

2009 0.0321

2010+ 0.0015

Mass emissions per 1,000 feet of drilling for each engine type were derived from 

NONROAD outputs. The activity levels entered into NONROAD corresponded to the 

hours required to drill 1,000 feet, so NONROAD outputs were uniformly normalized to 

these units. Total emissions for each engine type/drill rig category combination were 

calculated by dividing the NONROAD output emissions total by the fractional engine 

population for the appropriate engine model year (from NONROAD’s by-model-year 

output), and then multiplying by the average number of engines for each drill rig type. 

For example, the average age for a shallow well mechanical draw works engine is 7 

years. Therefore for a 1990 calendar year run, emissions for a 1983 engine are first 

identified in the NONROAD by-model-year output. Since the NONROAD population 

file was set to equal one unit (corresponding to all model years), NONROAD calculates 

the “population” of 7 year old engines to be 0.0386 (i.e., 3.86% of all engines operating 

in 1990). In order to calculate total emissions per 1,000 feet of drilling activity for this 

engine, the mass emissions associated with this model year are first divided by this 

population to obtain the mass emissions rate per year for one engine (e.g., 0.0015 tons 

per year CO per 0.0386 engines = 0.039 tons per year per unit). Finally, this values is 

multiplied by the average number of engines of this type for the given well type (e.g., 1.6 

mechanical draw works engines per shallow well drill rig) to obtain the emission factor 

expressed as mass emissions for each engine category/well type combination per 1,000 

feet of drilling activity. 

Total hydrocarbon (THC) exhaust emissions from the NONROAD model were converted 

to VOC and TOG using ratios of 1.053 and 1.070, respectively (U.S. EPA, 2005a). 

Crankcase THC emissions were assumed to be equivalent to both VOC and TOG (U.S. 
4-14 

EPA, 2005b). For diesel Non-Road engines, PM10 is assumed to be equivalent to PM, 

while the PM2.5 fraction of PM10 is estimated to be 0.97 (U.S. EPA, 2005a). 

Table 4-8, Table 4-9, and Table 4-10 contain the criteria pollutant emission factors 

developed for each model rig well type category for the emission inventory target years. 

Note that emission factors for uncontrolled emission inventory estimates were set equal 

to the 1990 factors below, as these pre-date the introduction of diesel engine controls. 

Table 4-8. Emission Factors for Vertical Wells 

<= 7,000 feet (tons/1,000 feet) 

Year NOx SO2 VOC CO PM10 PM2.5 TOG

1990 0.25171 0.03063 0.04040 0.15717 0.03131 0.03037 0.04104

1993 0.25444 0.02738 0.03638 0.14060 0.02670 0.02590 0.03696

1996 0.26302 0.03197 0.02351 0.08748 0.01316 0.01276 0.02389

1999 0.26260 0.01766 0.02331 0.08677 0.01185 0.01150 0.02368

2000 0.24601 0.01751 0.01968 0.07693 0.01041 0.01010 0.01999

2001 0.24580 0.01742 0.01961 0.07669 0.01036 0.01005 0.01992

2002 0.22069 0.01741 0.01411 0.06173 0.00819 0.00794 0.01433

2003 0.19156 0.01737 0.00773 0.04439 0.00567 0.00550 0.00785

2004 0.19135 0.01729 0.00767 0.04415 0.00562 0.00545 0.00779

2005 0.18171 0.01715 0.00741 0.04125 0.00559 0.00542 0.00753

2006 0.18138 0.01702 0.00735 0.04102 0.00553 0.00537 0.00747

2007 0.16568 0.00327 0.00699 0.03648 0.00444 0.00431 0.00710

2008 0.14886 0.00324 0.00662 0.03164 0.00446 0.00433 0.00672

2009 0.14675 0.00328 0.00652 0.03092 0.00443 0.00430 0.00663

2010 0.13275 0.00015 0.00642 0.03010 0.00400 0.00388 0.00652

2011 0.12988 0.00015 0.00634 0.02951 0.00394 0.00382 0.00644

2012 0.11200 0.00015 0.00628 0.02926 0.00368 0.00357 0.00638

2013 0.08760 0.00015 0.00619 0.02854 0.00337 0.00327 0.00629

2014 0.08282 0.00015 0.00611 0.02777 0.00332 0.00322 0.00621

2015 0.07454 0.00014 0.00574 0.02223 0.00266 0.00258 0.00583

2016 0.07407 0.00014 0.00570 0.02204 0.00263 0.00255 0.00579

2017 0.06190 0.00013 0.00519 0.01384 0.00166 0.00161 0.00527

2018 0.04010 0.00011 0.00459 0.00433 0.00053 0.00052 0.00467

2019 0.03966 0.00011 0.00456 0.00417 0.00051 0.00049 0.00463

2020 0.02752 0.00011 0.00452 0.00401 0.00049 0.00047 0.00460

2021 0.01353 0.00011 0.00450 0.00388 0.00047 0.00046 0.00457

2022 0.01316 0.00011 0.00448 0.00376 0.00045 0.00044 0.00455

2023 0.01281 0.00011 0.00446 0.00365 0.00044 0.00043 0.00453

2024 0.01246 0.00011 0.00444 0.00354 0.00042 0.00041 0.00451

2025 0.01207 0.00011 0.00442 0.00342 0.00041 0.00040 0.00450

2026 0.01176 0.00011 0.00441 0.00333 0.00040 0.00038 0.00448

2026 0.01148 0.00011 0.00440 0.00325 0.00038 0.00037 0.00447

2027 0.01121 0.00011 0.00439 0.00317 0.00037 0.00036 0.00446
4-15 

Year NOx SO2 VOC CO PM10 PM2.5 TOG

2027 0.01095 0.00011 0.00438 0.00310 0.00036 0.00035 0.00445

2028 0.01071 0.00011 0.00437 0.00303 0.00035 0.00034 0.00444

2028 0.01049 0.00011 0.00436 0.00296 0.00035 0.00034 0.00443

2029 0.01030 0.00011 0.00435 0.00291 0.00034 0.00033 0.00442

2029 0.01012 0.00011 0.00434 0.00285 0.00033 0.00032 0.00441

2030 0.00995 0.00011 0.00434 0.00280 0.00032 0.00031 0.00441

2030 0.00980 0.00011 0.00433 0.00275 0.00032 0.00031 0.00440

2031 0.00966 0.00011 0.00433 0.00271 0.00031 0.00030 0.00440

2031 0.00955 0.00011 0.00432 0.00269 0.00031 0.00030 0.00439

2032 0.00944 0.00011 0.00432 0.00267 0.00031 0.00030 0.00439

2033 0.00935 0.00011 0.00432 0.00265 0.00031 0.00030 0.00439

2034 0.00928 0.00011 0.00432 0.00263 0.00030 0.00029 0.00439

2035 0.25171 0.03063 0.04040 0.15717 0.03131 0.03037 0.04104

2036 0.25444 0.02738 0.03638 0.14060 0.02670 0.02590 0.03696

2036 0.26302 0.03197 0.02351 0.08748 0.01316 0.01276 0.02389

2037 0.26260 0.01766 0.02331 0.08677 0.01185 0.01150 0.02368

2037 0.24601 0.01751 0.01968 0.07693 0.01041 0.01010 0.01999

2038 0.24580 0.01742 0.01961 0.07669 0.01036 0.01005 0.01992

2038 0.22069 0.01741 0.01411 0.06173 0.00819 0.00794 0.01433

2039 0.19156 0.01737 0.00773 0.04439 0.00567 0.00550 0.00785

2040 0.19135 0.01729 0.00767 0.04415 0.00562 0.00545 0.00779

Table 4-9- Emission Factors for Vertical Wells > 7,000 feet (tons/1,000 feet) 

Year NOx SO2 VOC CO PM10 PM2.5 TOG

1990 0.49496 0.05948 0.06914 0.26759 0.05123 0.04969 0.07024

1993 0.49504 0.05313 0.06903 0.26713 0.05060 0.04908 0.07013

1996 0.49495 0.06190 0.06889 0.26660 0.05118 0.04964 0.06998

1999 0.49879 0.03421 0.06243 0.24004 0.04199 0.04073 0.06342

2000 0.49870 0.03389 0.06240 0.23995 0.04195 0.04069 0.06339

2001 0.49849 0.03372 0.06234 0.23971 0.04189 0.04063 0.06332

2002 0.46064 0.03370 0.05520 0.20664 0.03828 0.03713 0.05608

2003 0.46042 0.03358 0.05514 0.20639 0.03822 0.03707 0.05601

2004 0.46020 0.03342 0.05508 0.20616 0.03816 0.03702 0.05595

2005 0.45996 0.03315 0.05500 0.20588 0.03809 0.03695 0.05587

2006 0.43976 0.03294 0.03956 0.15015 0.02524 0.02448 0.04019

2007 0.43941 0.00633 0.03950 0.14992 0.02305 0.02236 0.04012

2008 0.41484 0.00627 0.03791 0.14969 0.02320 0.02250 0.03851

2009 0.41450 0.00635 0.03785 0.14947 0.02316 0.02247 0.03845

2010 0.41067 0.00030 0.03757 0.14922 0.02266 0.02198 0.03817

2011 0.38828 0.00030 0.03679 0.14474 0.02272 0.02204 0.03737

2012 0.38788 0.00030 0.03673 0.14449 0.02268 0.02200 0.03731

2013 0.36209 0.00027 0.03066 0.11096 0.01306 0.01267 0.03114

2014 0.36162 0.00027 0.03061 0.11076 0.01303 0.01264 0.03110
4-16 

Year NOx SO2 VOC CO PM10 PM2.5 TOG

2015 0.36110 0.00027 0.03056 0.11054 0.01299 0.01260 0.03105

2016 0.34210 0.00027 0.03052 0.11036 0.01274 0.01235 0.03101

2017 0.33770 0.00027 0.02778 0.09816 0.01199 0.01163 0.02822

2018 0.29887 0.00027 0.02054 0.06434 0.00828 0.00804 0.02086

2019 0.29843 0.00027 0.02050 0.06418 0.00826 0.00801 0.02083

2020 0.29800 0.00027 0.02047 0.06402 0.00824 0.00799 0.02079

2021 0.25188 0.00026 0.01265 0.03544 0.00431 0.00418 0.01285

2022 0.25151 0.00026 0.01263 0.03532 0.00429 0.00416 0.01283

2023 0.25116 0.00026 0.01261 0.03521 0.00428 0.00415 0.01281

2024 0.30891 0.00034 0.01574 0.04822 0.00639 0.00620 0.01599

2025 0.30851 0.00034 0.01572 0.04810 0.00637 0.00618 0.01597

2026 0.36940 0.00041 0.01828 0.05992 0.00813 0.00788 0.01857

2026 0.18307 0.00026 0.00997 0.02947 0.00456 0.00442 0.01013

2027 0.18042 0.00026 0.00991 0.02873 0.00455 0.00442 0.01007

2027 0.15075 0.00023 0.01184 0.02869 0.00363 0.00352 0.01203

2028 0.15051 0.00023 0.01183 0.02862 0.00362 0.00351 0.01202

2028 0.12694 0.00023 0.01182 0.02859 0.00332 0.00322 0.01201

2029 0.12178 0.00023 0.01177 0.02786 0.00329 0.00319 0.01195

2029 0.12160 0.00023 0.00904 0.01605 0.00256 0.00248 0.00918

2030 0.12143 0.00023 0.00903 0.01599 0.00255 0.00247 0.00918

2030 0.12128 0.00023 0.00903 0.01595 0.00254 0.00247 0.00917

2031 0.10549 0.00021 0.00838 0.00510 0.00123 0.00119 0.00852

2031 0.10538 0.00021 0.00838 0.00507 0.00122 0.00119 0.00851

2032 0.10527 0.00021 0.00837 0.00505 0.00122 0.00119 0.00851

2033 0.08953 0.00021 0.00837 0.00503 0.00122 0.00118 0.00851

2034 0.08946 0.00021 0.00837 0.00501 0.00122 0.00118 0.00850

2035 0.49496 0.05948 0.06914 0.26759 0.05123 0.04969 0.07024

2036 0.49504 0.05313 0.06903 0.26713 0.05060 0.04908 0.07013

2036 0.49495 0.06190 0.06889 0.26660 0.05118 0.04964 0.06998

2037 0.49879 0.03421 0.06243 0.24004 0.04199 0.04073 0.06342

2037 0.49870 0.03389 0.06240 0.23995 0.04195 0.04069 0.06339

2038 0.49849 0.03372 0.06234 0.23971 0.04189 0.04063 0.06332

2038 0.46064 0.03370 0.05520 0.20664 0.03828 0.03713 0.05608

2039 0.46042 0.03358 0.05514 0.20639 0.03822 0.03707 0.05601

2040 0.46020 0.03342 0.05508 0.20616 0.03816 0.03702 0.05595

Table 4-10. Emission Factors for Directional/Horizontal Wells 

(tons/1,000 feet) 

Year NOx SO2 VOC CO PM10 PM2.5 TOG

1990 0.62480 0.07390 0.06988 0.26540 0.04582 0.04444 0.07098

1993 0.62488 0.06601 0.06977 0.26494 0.04506 0.04371 0.07087

1996 0.62938 0.07696 0.06288 0.23655 0.03852 0.03736 0.06388

1999 0.63098 0.04251 0.05971 0.22359 0.03236 0.03138 0.06066
4-17 

Year NOx SO2 VOC CO PM10 PM2.5 TOG

2000 0.63089 0.04212 0.05968 0.22350 0.03231 0.03134 0.06063

2001 0.63068 0.04190 0.05962 0.22326 0.03224 0.03128 0.06056

2002 0.52031 0.04192 0.03887 0.12698 0.02177 0.02112 0.03949

2003 0.52286 0.04178 0.03473 0.10983 0.01724 0.01672 0.03528

2004 0.52264 0.04159 0.03467 0.10959 0.01718 0.01666 0.03522

2005 0.52241 0.04124 0.03459 0.10932 0.01710 0.01659 0.03514

2006 0.48263 0.04095 0.02674 0.07816 0.01340 0.01300 0.02716

2007 0.48228 0.00787 0.02668 0.07792 0.01069 0.01037 0.02710

2008 0.41103 0.00780 0.02216 0.07769 0.01122 0.01089 0.02251

2009 0.41069 0.00790 0.02210 0.07747 0.01119 0.01085 0.02245

2010 0.40019 0.00037 0.02140 0.07722 0.01062 0.01030 0.02174

2011 0.35517 0.00037 0.01617 0.06470 0.00928 0.00900 0.01643

2012 0.33742 0.00037 0.01502 0.06445 0.00937 0.00909 0.01526

2013 0.25166 0.00030 0.02051 0.06399 0.00675 0.00654 0.02084

2014 0.24871 0.00030 0.02031 0.06379 0.00674 0.00653 0.02063

2015 0.24323 0.00030 0.01995 0.06357 0.00674 0.00654 0.02027

2016 0.22416 0.00030 0.01972 0.06064 0.00664 0.00644 0.02004

2017 0.20118 0.00028 0.01322 0.02658 0.00392 0.00380 0.01343

2018 0.19951 0.00028 0.01316 0.02607 0.00390 0.00378 0.01337

2019 0.19907 0.00028 0.01313 0.02591 0.00387 0.00376 0.01334

2020 0.19864 0.00028 0.01309 0.02575 0.00385 0.00374 0.01330

2021 0.18028 0.00028 0.01092 0.01335 0.00270 0.00262 0.01109

2022 0.17734 0.00028 0.01087 0.01289 0.00267 0.00259 0.01105

2023 0.17698 0.00028 0.01085 0.01278 0.00266 0.00258 0.01103

2024 0.17076 0.00028 0.01084 0.01267 0.00264 0.00256 0.01101

2025 0.17036 0.00028 0.01082 0.01255 0.00263 0.00255 0.01099

2026 0.16196 0.00027 0.01047 0.00688 0.00194 0.00189 0.01064

2026 0.16168 0.00027 0.01046 0.00680 0.00193 0.00187 0.01063

2027 0.16141 0.00027 0.01045 0.00672 0.00192 0.00186 0.01062

2027 0.15306 0.00027 0.01044 0.00665 0.00191 0.00185 0.01061

2028 0.15281 0.00027 0.01043 0.00658 0.00190 0.00185 0.01060

2028 0.15259 0.00026 0.01042 0.00652 0.00189 0.00184 0.01059

2029 0.15240 0.00026 0.01041 0.00646 0.00189 0.00183 0.01058

2029 0.15222 0.00026 0.01041 0.00640 0.00188 0.00182 0.01057

2030 0.15206 0.00026 0.01040 0.00635 0.00187 0.00182 0.01057

2030 0.15190 0.00026 0.01039 0.00630 0.00187 0.00181 0.01056

2031 0.15177 0.00026 0.01039 0.00627 0.00186 0.00181 0.01056

2031 0.15165 0.00026 0.01039 0.00624 0.00186 0.00180 0.01055

2032 0.15154 0.00026 0.01038 0.00622 0.00186 0.00180 0.01055

2033 0.15146 0.00026 0.01038 0.00620 0.00185 0.00180 0.01055

2034 0.15138 0.00026 0.01038 0.00618 0.00185 0.00180 0.01055

2035 0.62480 0.07390 0.06988 0.26540 0.04582 0.04444 0.07098

2036 0.62488 0.06601 0.06977 0.26494 0.04506 0.04371 0.07087

2036 0.62938 0.07696 0.06288 0.23655 0.03852 0.03736 0.06388
4-18 

Year NOx SO2 VOC CO PM10 PM2.5 TOG

2037 0.63098 0.04251 0.05971 0.22359 0.03236 0.03138 0.06066

2037 0.63089 0.04212 0.05968 0.22350 0.03231 0.03134 0.06063

2038 0.63068 0.04190 0.05962 0.22326 0.03224 0.03128 0.06056

2038 0.52031 0.04192 0.03887 0.12698 0.02177 0.02112 0.03949

2039 0.52286 0.04178 0.03473 0.10983 0.01724 0.01672 0.03528

2040 0.52264 0.04159 0.03467 0.10959 0.01718 0.01666 0.03522

4.3 Emission Estimation Methodology 

Once the total depth drilled per year was aggregated by model rig well type category, 

and the emission factor profile for each model rig well type category was developed, 

county level emissions for each model rig well type category were estimated by 

multiplying the total depth drilled by county by the emission factors developed through 

use of the 2009 study survey data and the NONROAD model, as follows: 

This process is repeated for each of the well category/engine type combinations of 

interest – for example, mechanical draw works engines used for shallow vertical wells (< 

7,000 feet). 

For 2006 onward, NOx emission estimates for the 110 counties in the eastern half of 

Texas subject to the Texas Low Emission Diesel (TxLED) program were adjusted 

downward by 6.2% to account for the effect of the rule. 6 Table 4-11 identifies the 

counties where this adjustment was made. 

 

6

 The TxLED program requirements initiated in 2006, so these adjustments were not applied to the 2002 and 2005 

modeling scenarios. 
4-19 

Table 4-11. TxLED Counties 

Anderson Denton Johnson Robertson

Angelina Ellis Karnes Rockwall

Aransas Falls Kaufman Rusk

Atascosa Fannin Lamar Sabine

Austin Fayette Lavaca San Jacinto

Bastrop Franklin Lee San Patricio

Bee Freestone Leon San Augustine

Bell Fort Bend Liberty Shelby

Bexar Galveston Limestone Smith

Bosque Goliad Live Oak Somervell

Bowie Gonzales Madison Tarrant

Brazoria Grayson Marion Titus

Brazos Gregg Matagorda Travis

Burleson Grimes McLennan Trinity

Caldwell Guadalupe Milam Tyler

Calhoun Hardin Montgomery Upshur

Camp Harris Morris Van Zandt

Cass Harrison Nacogdoches Victoria

Chambers Hays Navarro Walker

Cherokee Henderson Newton Waller

Collin Hill Nueces Washington

Colorado Hood Orange Wharton

Comal Hopkins Panola Williamson

Cooke Houston Parker Wilson

Coryell Hunt Polk Wise

Dallas Jackson Rains   

De Witt Jasper Red River   

Delta Jefferson Refugio   

For counties subject to TxLED requirements, NOx emissions were estimated as follows: 

Total county level emissions were then determined by summing county level emissions 

for each of the three model rig categories for a given year. 
4-20 

4.3.1 Example Emission Calculations 

Using the data above, CO emissions in 2008 for Anderson County from vertical wells > 

7,000 feet are estimated as follows: 

ECO = (Depth (1,000 feet/yr)) x (EFpoll (tons/1,000 feet)), or 

ECO = (85 (1,000 feet/yr)) x (1.50E-01 (tons/1,000 feet)) 

ECO = 12.7 (tons/yr) 

As Anderson County is subject to the TxLED requirements, NOx emissions in 2008 for 

Anderson County from vertical wells > 7,000 feet are estimated as follows: 

ENOx = (Depth (1,000 feet/yr)) x (EFpoll (tons/1,000 feet)) x (0.938), or 

ENOx = (85 (1,000 feet/yr)) x (4.15E-01 (tons/1,000 feet)) x (0.938) 

ENOx = 33.1 (tons/yr) 

4.4 Results 

4.4.1 Emission Summary 

Tables 4-12, through 4-15, as well as Figures 4-3 through 4-9 summarize the statewide 

annual and ozone-season daily criteria emissions totals for diesel engine drill rigs, for 

both controlled and uncontrolled scenarios. An Uncontrolled scenario was developed by 

combining year-specific activity levels with the 1990 emission rates generated using the 

NONROAD2008 model. The diesel engines operating in 1990 were not subject to 

emission controls and represent “uncontrolled” conditions. The Controlled scenario 

reflects the emission controls in place for any given year, and are accounted for in the 

NONROAD2008 model emission factors output for each analysis year. Depending upon 

the analysis year in question, one or more of the following emission controls are 

reflected in the Controlled scenario: 

 Federal Emission Standards for Heavy-Duty and Non-Road Engines - “1998 HD and 

Non-Road Rule”; 

 Tier 1, 2 and Tier 3 Emission Standards: Control of Emissions of Air Pollution from 

Non-Road Diesel Engines - “Tier 1, 2 and 3 Rule”; and 

 Clean Air Non-Road Diesel - Tier 4 Final Rule – “Tier 4 Rule”, including ultra-low 

sulfur requirements for Non-Road diesel fuel. 

In addition, the impact of the state TxLED rule is also included in all Controlled scenario 

estimates after 2005, as described above. None of these rules are accounted for in the 

Uncontrolled scenario. 
4-21 

HAP emissions estimates and by-county breakouts were provided in the electronic XML 

files submitted to the TCEQ under Task 2b of this study. Appendix A also provides the 

statewide emissions estimates for HAPs, while Appendix D provides county level 

breakouts for statewide annual and ozone season day emissions. 

Table 4-12. Statewide Annual Emissions Totals (Tons/Year), 

Controlled Scenario 

Year NOx SO2 VOC CO PM10 PM2.5

1990 25,308 3,037 3,462 13,366 2,533 2,457

1993 29,354 3,141 3,940 15,193 2,828 2,743

1996 33,037 4,093 4,044 15,502 2,822 2,737

1999 24,159 1,647 2,769 10,568 1,760 1,707

2000 33,578 2,290 3,798 14,570 2,422 2,350

2001 38,960 2,641 4,410 16,910 2,810 2,726

2002 27,974 2,100 2,955 11,027 1,978 1,919

2003 37,220 2,825 3,803 14,234 2,548 2,471

2004 40,164 3,040 4,047 15,057 2,688 2,607

2005 47,798 3,606 4,788 17,706 3,163 3,068

2006 52,497 4,290 4,135 15,235 2,539 2,463

2007 57,197 909 4,443 16,071 2,392 2,320

2008 59,261 1,033 4,593 17,745 2,696 2,615

2009 29,231 523 2,202 8,464 1,282 1,244

2010 24,531 21 1,846 7,182 1,056 1,024

2011 23,254 21 1,725 6,869 1,047 1,016

2012 22,920 22 1,716 6,949 1,060 1,028

2013 19,878 19 1,687 5,893 672 652

2014 19,875 20 1,691 5,916 675 655

2015 19,819 20 1,693 5,897 673 653

2016 18,711 20 1,691 5,826 663 643

2017 17,954 19 1,417 4,375 553 537

2018 16,446 19 1,164 3,085 413 400

2019 16,545 19 1,170 3,096 414 402

2020 16,475 20 1,175 3,102 415 402

2021 14,182 19 832 1,712 240 233

2022 14,201 19 837 1,705 240 233

2023 14,308 19 843 1,711 242 234

2024 16,194 22 956 2,178 318 308

2025 16,186 22 956 2,170 317 307

2026 18,006 24 1,032 2,409 357 346

2027 11,359 19 732 1,307 228 221

2028 11,190 19 725 1,269 226 219

2029 9,817 18 787 1,254 190 185

2030 9,762 18 783 1,244 189 183

2031 8,878 17 778 1,233 177 172

2032 8,649 17 772 1,200 175 170
4-22 

Year NOx SO2 VOC CO PM10 PM2.5

2033 8,566 17 671 779 148 143

2034 8,490 17 665 770 146 142

2035 8,410 17 660 761 145 140

2036 7,869 16 637 387 99 96

2037 7,861 16 637 385 99 96

2038 7,853 16 637 384 99 96

2039 7,316 16 637 382 99 96

2040 7,311 16 637 381 99 96

Figure 4-3. Statewide Drilling Rig Emissions – Controlled Scenario 

(NOx and CO Tons/Year) 
4-23 

Figure 4-4. Statewide Drilling Rig Emissions – Controlled Scenario 

(VOC and SO2 Tons/Year) 

Figure 4-5. Statewide Drilling Rig Emissions – Controlled Scenario (PM10

and PM2.5 Tons/Year) 

Figures 4.3 through 4.5 show a general increase in most pollutants between 1990 and 

2008, after which time emissions drop off dramatically due to decreased drilling activity 

associated with the economic downturn and associated lower natural gas prices. Figure 

4-6 presents the corresponding statewide drilling activity for comparison. CO emissions 

show the least variation over time, with the large emission rate improvement associated 

with the introduction of the Tier 2 emission standards (roughly 50% compared to prior 
4-24 

standards) in the early 2000’s offsetting growth in drilling activity during this time. 

VOC and PM emissions trends are similar to CO, due to similar reductions associated 

with these same emission standards. 

Figure 4-6. Statewide Annual Drilling Rig Activity (000’s feet) 

NOx and SO2 emissions trends display a somewhat different pattern during this time, 

however. NOx emissions increase dramatically up through 2008, since the Tier 2 

emission standards had a negligible impact on this pollutant, relative to the prior 

standard. (Substantial NOx reductions are found with the introduction of the Tier 3 and 

4 diesel emission standards, taking effect in the late 2000s and thereafter, however.) 

SO2 emissions are almost solely dependent on diesel fuel sulfur levels, and as long as 

these levels are constant over time, SO2 emissions will track drilling activity in a one-toone fashion. SO2 emissions are seen to go negligible levels with the introduction of the 

Tier 4 ultra-low sulfur requirements after 2009. Other emission rates are projected to 

decrease more slowly as a result of continued penetration of cleaner Tier 3 and 4 

engines, coupled with some decline in overall projected drilling activity. 

Ozone season day (OSD) emissions were calculated by dividing annual emissions 

estimates by 365. These values are presented in the tables below. Note that trend charts 

are not presented for OSD totals, since the relative emissions over time do not change 

compared to the annual emissions cases above. 
4-25 

Table 4-13. Statewide OSD Emissions Totals (Tons/Day), 

Controlled Scenario 

Year NOx SO2 VOC CO PM10 PM2.5

1990 69.34 8.32 9.48 36.62 6.94 6.73

1993 80.42 8.61 10.79 41.62 7.75 7.52

1996 90.51 11.21 11.08 42.47 7.73 7.50

1999 66.19 4.51 7.59 28.95 4.82 4.68

2000 92.00 6.28 10.40 39.92 6.64 6.44

2001 106.74 7.24 12.08 46.33 7.70 7.47

2002 76.64 5.75 8.10 30.21 5.42 5.26

2003 101.97 7.74 10.42 39.00 6.98 6.77

2004 110.04 8.33 11.09 41.25 7.36 7.14

2005 130.95 9.88 13.12 48.51 8.67 8.41

2006 143.83 11.75 11.33 41.74 6.96 6.75

2007 156.70 2.49 12.17 44.03 6.55 6.36

2008 162.36 2.83 12.58 48.62 7.39 7.16

2009 80.09 1.43 6.03 23.19 3.51 3.41

2010 67.21 0.06 5.06 19.68 2.89 2.81

2011 63.71 0.06 4.73 18.82 2.87 2.78

2012 62.80 0.06 4.70 19.04 2.90 2.82

2013 54.46 0.05 4.62 16.15 1.84 1.79

2014 54.45 0.05 4.63 16.21 1.85 1.79

2015 54.30 0.05 4.64 16.16 1.84 1.79

2016 51.26 0.05 4.63 15.96 1.82 1.76

2017 49.19 0.05 3.88 11.99 1.52 1.47

2018 45.06 0.05 3.19 8.45 1.13 1.10

2019 45.33 0.05 3.21 8.48 1.13 1.10

2020 45.14 0.05 3.22 8.50 1.14 1.10

2021 38.86 0.05 2.28 4.69 0.66 0.64

2022 38.91 0.05 2.29 4.67 0.66 0.64

2023 39.20 0.05 2.31 4.69 0.66 0.64

2024 44.37 0.06 2.62 5.97 0.87 0.84

2025 44.34 0.06 2.62 5.95 0.87 0.84

2026 49.33 0.07 2.83 6.60 0.98 0.95

2027 31.12 0.05 2.00 3.58 0.62 0.60

2028 30.66 0.05 1.99 3.48 0.62 0.60

2029 26.90 0.05 2.16 3.44 0.52 0.51

2030 26.74 0.05 2.15 3.41 0.52 0.50

2031 24.32 0.05 2.13 3.38 0.49 0.47

2032 23.70 0.05 2.11 3.29 0.48 0.46

2033 23.47 0.05 1.84 2.14 0.41 0.39

2034 23.26 0.05 1.82 2.11 0.40 0.39

2035 23.04 0.05 1.81 2.09 0.40 0.38

2036 21.56 0.04 1.75 1.06 0.27 0.26

2037 21.54 0.04 1.75 1.06 0.27 0.26
4-26 

Year NOx SO2 VOC CO PM10 PM2.5

2038 21.51 0.04 1.74 1.05 0.27 0.26

2039 20.04 0.04 1.74 1.05 0.27 0.26

2040 20.03 0.04 1.74 1.04 0.27 0.26

Table 4-14. Statewide Annual Emissions Totals (Tons/Year), 

Uncontrolled Scenario 

Year NOx SO2 VOC CO PM10 PM2.5

1990 25,308 3,037 3,462 13,366 2,533 2,457

1993 29,293 3,516 4,029 15,560 2,955 2,866

1996 32,726 3,930 4,522 17,470 3,324 3,224

1999 23,843 2,863 3,291 12,717 2,419 2,347

2000 33,463 4,017 4,611 17,814 3,387 3,285

2001 38,820 4,658 5,311 20,509 3,889 3,772

2002 30,872 3,705 4,233 16,350 3,103 3,010

2003 41,692 5,001 5,679 21,924 4,151 4,026

2004 45,106 5,406 6,081 23,459 4,423 4,291

2005 53,975 6,465 7,230 27,879 5,243 5,086

2006 64,690 7,744 8,592 33,107 6,204 6,018

2007 71,418 8,540 9,341 35,953 6,695 6,494

2008 81,904 9,788 10,638 40,920 7,597 7,369

2009 41,030 4,899 5,271 20,256 3,742 3,630

2010 35,024 4,183 4,502 17,302 3,197 3,101

2011 35,975 4,296 4,620 17,756 3,280 3,182

2012 36,519 4,361 4,689 18,019 3,328 3,228

2013 37,146 4,435 4,767 18,321 3,383 3,282

2014 37,421 4,468 4,803 18,457 3,408 3,306

2015 37,838 4,518 4,855 18,656 3,445 3,341

2016 37,982 4,535 4,873 18,724 3,457 3,353

2017 38,321 4,576 4,916 18,893 3,488 3,384

2018 38,664 4,617 4,960 19,059 3,519 3,413

2019 39,004 4,657 5,002 19,219 3,548 3,441

2020 39,265 4,688 5,034 19,344 3,571 3,463

2021 39,360 4,699 5,044 19,380 3,577 3,469

2022 39,714 4,741 5,087 19,547 3,607 3,499

2023 40,111 4,789 5,136 19,735 3,641 3,532

2024 40,138 4,792 5,139 19,744 3,642 3,533

2025 40,216 4,801 5,148 19,778 3,648 3,539

2026 39,983 4,773 5,117 19,662 3,626 3,518

2027 39,943 4,768 5,112 19,641 3,623 3,514

2028 39,718 4,742 5,083 19,529 3,602 3,494

2029 39,395 4,703 5,041 19,368 3,572 3,465

2030 39,249 4,685 5,022 19,295 3,558 3,452

2031 39,012 4,657 4,992 19,180 3,537 3,431
4-27 

Year NOx SO2 VOC CO PM10 PM2.5

2032 38,824 4,635 4,969 19,090 3,521 3,415

2033 38,513 4,598 4,931 18,946 3,495 3,390

2034 38,229 4,564 4,894 18,805 3,469 3,365

2035 37,923 4,528 4,857 18,663 3,443 3,340

2036 37,923 4,528 4,857 18,663 3,443 3,340

2037 37,923 4,528 4,857 18,663 3,443 3,340

2038 37,923 4,528 4,857 18,663 3,443 3,340

2039 37,923 4,528 4,857 18,663 3,443 3,340

2040 37,923 4,528 4,857 18,663 3,443 3,340

Figure 4-7. Statewide Drilling Rig Emissions – Uncontrolled Scenario 

(NOx and CO Tons/Year) 
4-28 

Figure 4-8. Statewide Drilling Rig Emissions – Uncontrolled Scenario 

(VOC and SO2 Tons/Year) 

Figure 4-9. Statewide Drilling Rig Emissions – Uncontrolled Scenario 

(PM10 and PM2.5 Tons/Year) 

The emissions trends presented in Figures 4-7 through 4-9 above clearly show how 

emissions for all pollutants would be substantially higher without the benefit of the 

engine and fuel controls implemented since 1990. In addition, since emission rates are 

held constant for these estimates, the year-to-year changes shown above are exclusively 

due to changes in historical and projected drilling activity (see Figure 4-6). 
4-29 

Table 4-15. Statewide OSD Emissions Totals (Tons/Day), 

Uncontrolled Scenario 

Year NOx SO2 VOC CO PM10 PM2.5

1990 69.34 8.32 9.48 36.62 6.94 6.73

1993 80.25 9.63 11.04 42.63 8.10 7.85

1996 89.66 10.77 12.39 47.86 9.11 8.83

1999 65.32 7.84 9.02 34.84 6.63 6.43

2000 91.68 11.01 12.63 48.81 9.28 9.00

2001 106.36 12.76 14.55 56.19 10.65 10.33

2002 84.58 10.15 11.60 44.79 8.50 8.25

2003 114.22 13.70 15.56 60.07 11.37 11.03

2004 123.58 14.81 16.66 64.27 12.12 11.75

2005 147.88 17.71 19.81 76.38 14.36 13.93

2006 177.23 21.22 23.54 90.71 17.00 16.49

2007 195.67 23.40 25.59 98.50 18.34 17.79

2008 224.39 26.82 29.14 112.11 20.81 20.19

2009 112.41 13.42 14.44 55.50 10.25 9.95

2010 95.96 11.46 12.33 47.40 8.76 8.50

2011 98.56 11.77 12.66 48.65 8.99 8.72

2012 100.05 11.95 12.85 49.37 9.12 8.84

2013 101.77 12.15 13.06 50.19 9.27 8.99

2014 102.52 12.24 13.16 50.57 9.34 9.06

2015 103.67 12.38 13.30 51.11 9.44 9.15

2016 104.06 12.43 13.35 51.30 9.47 9.19

2017 104.99 12.54 13.47 51.76 9.56 9.27

2018 105.93 12.65 13.59 52.22 9.64 9.35

2019 106.86 12.76 13.70 52.66 9.72 9.43

2020 107.58 12.84 13.79 53.00 9.78 9.49

2021 107.83 12.87 13.82 53.10 9.80 9.50

2022 108.81 12.99 13.94 53.55 9.88 9.59

2023 109.89 13.12 14.07 54.07 9.98 9.68

2024 109.97 13.13 14.08 54.09 9.98 9.68

2025 110.18 13.15 14.10 54.18 9.99 9.69

2026 109.54 13.08 14.02 53.87 9.94 9.64

2027 109.43 13.06 14.01 53.81 9.92 9.63

2028 108.82 12.99 13.93 53.50 9.87 9.57

2029 107.93 12.89 13.81 53.06 9.79 9.49

2030 107.53 12.84 13.76 52.86 9.75 9.46

2031 106.88 12.76 13.68 52.55 9.69 9.40

2032 106.37 12.70 13.61 52.30 9.65 9.36

2033 105.51 12.60 13.51 51.91 9.58 9.29

2034 104.74 12.50 13.41 51.52 9.50 9.22

2035 103.90 12.40 13.31 51.13 9.43 9.15

2036 103.90 12.40 13.31 51.13 9.43 9.15

2037 103.90 12.40 13.31 51.13 9.43 9.15
4-30 

Year NOx SO2 VOC CO PM10 PM2.5

2038 103.90 12.40 13.31 51.13 9.43 9.15

2039 103.90 12.40 13.31 51.13 9.43 9.15

2040 103.90 12.40 13.31 51.13 9.43 9.15

Annual county-level NOx emissions were also investigated for the Controlled scenario 

for the 2010 base year, in order to help identify the areas of the state with the greatest 

level of drill rig emissions. Table 4-16 presents these emissions, with counties ranked 

from highest to lowest. Of the 206 counties with non-zero emissions in 2010, only a 

small fraction were responsible for a preponderance of total statewide emissions. For 

example, the top 14 counties were responsible for 50 percent of total NOx emissions. In 

addition, 7 of the 14 counties were located in (largely rural) West Texas, with the others 

being Tarrant, Johnson, Wise, and Denton counties (North Central Texas), Freestone 

and Panola counties (East Texas), and Webb County (South Texas). 

Table 4-16. County NOx Emissions Totals, Controlled Scenario (2010) 

FIPS County Tons/Year Cumulative %

439 Tarrant 1,632.98 6.66%

317 Martin 1,324.56 12.06%

461 Upton 1,273.69 17.25%

383 Reagan 1,164.95 22.00%

251 Johnson 1,047.99 26.27%

135 Ector 1,011.87 30.39%

3 Andrews 980.95 34.39%

329 Midland 721.62 37.33%

479 Webb 694.8 40.17%

497 Wise 514.32 42.26%

173 Glasscock 504.44 44.32%

121 Denton 433.11 46.09%

161 Freestone 433.03 47.85%

365 Panola 421.83 49.57%

165 Gaines 373.75 51.09%

483 Wheeler 370.65 52.60%

371 Pecos 348.75 54.03%

227 Howard 320.98 55.33%

255 Karnes 311.04 56.60%

235 Irion 291.87 57.79%

211 Hemphill 289.36 58.97%

105 Crockett 282.67 60.12%

337 Montague 262.71 61.19%

419 Shelby 259.64 62.25%

475 Ward 236.08 63.22%

283 La Salle 232.37 64.16%

203 Harrison 227.85 65.09%
4-31 

FIPS County Tons/Year Cumulative %

215 Hidalgo 225.99 66.01%

347 Nacogdoches 222.19 66.92%

505 Zapata 216.28 67.80%

427 Starr 210.66 68.66%

401 Rusk 201.5 69.48%

97 Cooke 200.72 70.30%

357 Ochiltree 188.96 71.07%

413 Schleicher 179.59 71.80%

395 Robertson 177.54 72.52%

389 Reeves 176.32 73.24%

435 Sutton 172.21 73.95%

481 Wharton 172.14 74.65%

123 DeWitt 158.52 75.29%

295 Lipscomb 157.55 75.94%

405 San Augustine 155.09 76.57%

367 Parker 150.98 77.18%

311 McMullen 150.94 77.80%

293 Limestone 145.96 78.39%

391 Refugio 144.86 78.98%

127 Dimmit 143.87 79.57%

47 Brooks 139.06 80.14%

415 Scurry 134.14 80.68%

245 Jefferson 133.87 81.23%

501 Yoakum 131.12 81.76%

115 Dawson 128.3 82.29%

393 Roberts 122.48 82.79%

289 Leon 116.99 83.26%

297 Live Oak 108.8 83.71%

355 Nueces 107.95 84.15%

301 Loving 107.11 84.58%

285 Lavaca 97.93 84.98%

177 Gonzales 94.38 85.37%

261 Kenedy 93.38 85.75%

41 Brazos 90.03 86.12%

431 Sterling 84.69 86.46%

361 Orange 83.33 86.80%

489 Willacy 82.35 87.14%

131 Duval 81.38 87.47%

485 Wichita 76.19 87.78%

221 Hood 74.31 88.08%

199 Hardin 68.64 88.36%

219 Hockley 67.65 88.64%

321 Matagorda 67.39 88.91%

273 Kleberg 66.33 89.18%

457 Tyler 65.94 89.45%
4-32 

FIPS County Tons/Year Cumulative %

13 Atascosa 65.29 89.72%

239 Jackson 64.66 89.98%

291 Liberty 64.46 90.24%

433 Stonewall 63.89 90.50%

137 Edwards 61.49 90.75%

25 Bee 58.59 90.99%

39 Brazoria 57.6 91.23%

33 Borden 55.83 91.46%

495 Winkler 52.08 91.67%

103 Crane 50.77 91.87%

407 San Jacinto 50.76 92.08%

313 Madison 50.26 92.29%

373 Polk 49.57 92.49%

73 Cherokee 47.28 92.68%

469 Victoria 45.59 92.87%

51 Burleson 44.74 93.05%

71 Chambers 44.6 93.23%

263 Kent 44.02 93.41%

335 Mitchell 44 93.59%

353 Nolan 43.79 93.77%

351 Newton 43.02 93.94%

149 Fayette 40.43 94.11%

175 Goliad 40.32 94.27%

423 Smith 39.27 94.43%

183 Gregg 38.85 94.59%

409 San Patricio 36.96 94.74%

89 Colorado 36.58 94.89%

249 Jim Wells 36.19 95.04%

163 Frio 30.75 95.16%

9 Archer 29.84 95.29%

113 Dallas 29.66 95.41%

185 Grimes 29.19 95.53%

323 Maverick 29.14 95.64%

237 Jack 29.09 95.76%

151 Fisher 27.72 95.88%

493 Wilson 26.57 95.98%

139 Ellis 26.37 96.09%

287 Lee 26.06 96.20%

125 Dickens 25.23 96.30%

429 Stephens 24.78 96.40%

181 Grayson 24.73 96.50%

167 Galveston 24.13 96.60%

207 Haskell 23.33 96.70%

241 Jasper 22.93 96.79%

399 Runnels 22.62 96.88%
4-33 

FIPS County Tons/Year Cumulative %

169 Garza 21.69 96.97%

443 Terrell 20.9 97.06%

477 Washington 20.61 97.14%

81 Coke 20.57 97.22%

217 Hill 20.45 97.31%

363 Palo Pinto 20.41 97.39%

507 Zavala 19.35 97.47%

107 Crosby 19.25 97.55%

205 Hartley 18.76 97.62%

157 Fort Bend 18.72 97.70%

195 Hansford 18.38 97.78%

417 Shackelford 18.03 97.85%

403 Sabine 17.79 97.92%

503 Young 17.74 97.99%

339 Montgomery 17.63 98.07%

213 Henderson 17.44 98.14%

253 Jones 17.4 98.21%

305 Lynn 16.97 98.28%

201 Harris 16.46 98.34%

15 Austin 15.72 98.41%

57 Calhoun 15.4 98.47%

7 Aransas 15.37 98.53%

499 Wood 15.21 98.60%

451 Tom Green 15.15 98.66%

445 Terry 14.53 98.72%

303 Lubbock 14.12 98.77%

327 Menard 13.94 98.83%

473 Waller 13.57 98.89%

79 Cochran 12.86 98.94%

247 Jim Hogg 11.67 98.99%

459 Upshur 11.44 99.03%

359 Oldham 11.13 99.08%

225 Houston 11.05 99.12%

447 Throckmorton 10.04 99.16%

1 Anderson 9.95 99.20%

487 Wilbarger 9.88 99.24%

315 Marion 9.73 99.28%

331 Milam 9.28 99.32%

83 Coleman 9.22 99.36%

269 King 8.77 99.40%

189 Hale 6.92 99.42%

197 Hardeman 6.85 99.45%

425 Somervell 6.52 99.48%

49 Brown 6.09 99.50%

59 Callahan 6.05 99.53%
4-34 

FIPS County Tons/Year Cumulative %

341 Moore 6.02 99.55%

95 Concho 5.9 99.58%

61 Cameron 5.87 99.60%

467 Van Zandt 5.86 99.62%

101 Cottle 5.79 99.65%

377 Presidio 5.54 99.67%

159 Franklin 5.29 99.69%

67 Cass 4.73 99.71%

37 Bowie 4.65 99.73%

233 Hutchinson 4.49 99.75%

5 Angelina 4.24 99.77%

379 Rains 3.9 99.78%

77 Clay 3.85 99.80%

223 Hopkins 3.7 99.81%

441 Taylor 3.52 99.83%

63 Camp 3.24 99.84%

275 Knox 3.14 99.85%

187 Guadalupe 3.11 99.87%

155 Foard 2.99 99.88%

325 Medina 2.95 99.89%

35 Bosque 2.88 99.90%

349 Navarro 2.77 99.91%

375 Potter 2.71 99.92%

55 Caldwell 2.59 99.93%

143 Erath 2.43 99.94%

133 Eastland 2.29 99.95%

109 Culberson 2.01 99.96%

279 Lamb 1.86 99.97%

385 Real 1.26 99.97%

23 Baylor 0.92 99.98%

231 Hunt 0.87 99.98%

307 McCulloch 0.8 99.99%

93 Comanche 0.8 99.99%

257 Kaufman 0.59 99.99%

179 Gray 0.46 99.99%

421 Sherman 0.44 99.99%

471 Walker 0.34 100.00%

411 San Saba 0.27 100.00%

193 Hamilton 0.2 100.00%

21 Bastrop 0.19 100.00%

145 Falls 0.16 100.00%

29 Bexar 0.09 100.00%

281 Lampasas 0.05 100.00%

309 McLennan 0.04 100.00%
4-35 

Trends in annual NOx emissions were plotted for the top 10 counties for the entire 

analysis period, as shown below in Figure 4-10. While there is some relative variation in 

historical estimates, most county trends follow the general pattern seen in the statewide 

totals (see Figure 4-3).Figures 4-11, 4-12, and 4-13 display the county-level distribution 

of annual NOx, VOC, and PM2.5 emissions for the 2010 base year. 
4-36 

Figure 4-10. Annual NOx Emissions by Year – Top 10 Counties (2010 basi
4-37 

Figure 4-11. 2010 Annual NOx Emissions by County (Tons/Year) 
4-38 

Figure 4-12. 2010 Annual VOC Emissions by County (Tons/Year)
4-39 

Figure 4-13. 2010 Annual PM2.5 Emissions by County (Tons/Year)
4-40 

4.4.2 CERS XML Files 

Once the emissions inventories were completed, CERS XML-formatted input files were 

prepared. For purposes of XML preparation, SCC 23-10-000-220 (Industrial Processes 

- Oil and Gas Exploration and Production - All Processes - Drill Rigs) was used, 

consistent with the 2009 study. ERG uploaded the CERS XML files to the TexAER test 

server to ensure the files were complete and accurate and in a format consistent with the 

TexAER area source file data requirements. 

4.5 Quality Assurance 

ERG conducted a variety of quality assurance checks consistent with the requirements 

of the Quality Assurance Project Plan (QAPP) submitted to the TCEQ for this effort. Key 

spreadsheet inputs and calculations used to estimate emissions were checked to ensure 

accuracy, and final emission estimates were evaluated for internal and external 

consistency, as described in detail in Drill Rig QA-QC_1.xlsx, submitted to the TCEQ as 

part of deliverable 2.2 of this effort. Errors identified during the QA were resolved and 

emissions estimates were subsequently revised prior to generation of the final XML files 

developed for TexAER. 

The quality assurance tracking spreadsheet referred to above was broken into several 

components, each intended to evaluate different aspects of the study calculations. First, 

basic calculations were checked in ERG's working files, in order to identify potential 

errors in worksheet equations and data table inputs. Individual steps in the calculation 

QA process are listed separately, noting the goal of each QA check, how the check was 

performed, and the outcome of the check. If a check found an error, the correction 

result was also documented. A second set of QA checks were performed on the 

emissions inventory results themselves to help ensure consistency with expected results 

and the reasonableness of projection trends. Quantitative comparisons were made the 

with 2008 base year inventory results from the previous study, as well as more 

qualitative evaluations of emissions trends in relation to projected activity and the 

effectiveness the various engine and fuel controls being phased in over time. The 

following highlights some of the key findings from this analysis. 

Key findings from the evaluation of final emission estimates include the following. First, 

the time series charts generated for the pollutants appear to follow a reasonable trend 

for future year projections, with significant activity and emissions drop offs occurring 

between 2008 and 2009. The differences in trends across pollutants appear to be 

explained by the differential impact of emission control phase-in schedules, as discussed 

in Section 4.4.1 above. 

The results from the current study were also compared against the 2008 base year 

findings from the previous study, as summarized in Table 4-17. 
4-41 

Table 4-17. Comparison of Statewide 2008 Annual Emissions Totals 

(Tons/Year), Current and Previous Studies, Controlled Scenario 

Year Study CO NOx PM10 PM2.5 SO2 VOC

2008 Previous 16,721 55,238 2,543 2,467 956 4,326

2008 Current 17,745 59,261 2,696 2,615 1,033 4,593

2008 % Diff 6.1% 7.3% 6.0% 6.0% 8.0% 6.2%

As seen in the table, the 2008 criteria pollutant emissions were found to be between 6 

and 8 percent higher in current emission inventory than in 2009 study. The ERG staff 

responsible for processing the TRC data confirmed that an enhanced methodology was 

adopted for the current study to include additional drilling activity that was not included 

in the 2009 effort. This resulted in an increase of 8 percent in the statewide drill depth 

totals (163,348 v. 151,204). Since drill depth increases were not distributed uniformly 

across counties or well types (which have different emission factors), the resulting 

emission impact generally did not increase on a one-to-one basis with activity. However, 

as SO2 emissions do in fact vary on a 1:1 basis with activity, independent of engine 

model year and emission standard, we see a precise match for this pollutant with 

activity (8 percent as expected). 

Finally, trend graphs were generated to compare the difference between controlled and 

uncontrolled emissions scenarios (see Figures 4-14 through 4-18). As noted above, 1990 

emission rates were used to represent the uncontrolled case for all scenario years. 

Controlled and uncontrolled emissions are shown in the following figures over the entire 

scenario year range. 

Figure 4-14. Controlled and Uncontrolled Emissions Projections 

(NOx Tons/Year) 
4-42 

Figure 4-15. Controlled and Uncontrolled Emissions Projections 

(CO Tons/Year) 

Figure 4-16. Controlled and Uncontrolled Emissions Projections 

(VOC Tons/Year) 
4-43 

Figure 4-17. Controlled and Uncontrolled Emissions Projections 

(PM10 Tons/Year) 

Figure 4-18. Controlled and Uncontrolled Emissions Projections 

(SO2 Tons/Year) 

The difference between the controlled and uncontrolled emissions deviate more and 

more over time, as expected. The NOx deviation shown above is not significant until 

substantial penetration of Tier 3+ emission standards in the late 2000’s. The emissions 

benefit is more pronounced earlier for CO, VOC, and PM due to the greater benefit of 

the Tier 2 emission standards in the early 2000’s, as discussed above in Section 4.4.1. 

SO2 deviation shows the most abrupt increase (in 2010 when ultra-low diesel sulfur 
4-44 

regulations are enacted), since emissions for this pollutant depends on fuel sulfur 

changes alone, as opposed to fleet turnover. 
5-1 

5. Conclusions and Recommendations 

This study presents comprehensive, statewide emissions inventories for Texas for 

drilling rig engines. These inventories were prepared using well drilling activity data 

obtained through permit records from the TRC, combined with emissions data derived 

through detailed drilling rig engine data collected through a bottom-up survey effort 

conducted for the 2009 study. The study represents a significant improvement upon the 

2009 effort, utilizing improved gap filling methods for the TRC dataset to obtain a more 

complete and accurate set of drill rig activity. In addition, this study utilized historical 

drilling data from the TRC to estimate past emissions, rather than relying on surrogate 

based back-casting from a base year, as was done in the previous study. Finally, the 

study greatly expanded the time horizon of the previous study, ranging from 1990 with 

projections through 2040. The result is a reliable, temporally resolved profile of countylevel drilling activity emissions. The successful update of the TexAER system with this 

data, associated with a new area source SCC, will allow for improved SIP and trend 

analysis for all regions of the state. 

Based on the projected oil and gas production levels in Texas from the EIA, drilling 

activity is estimated to remain relatively constant across the state from 2011 through 

2035. However, the continued phase-in of more stringent Non-Road diesel engine 

emission standards should cause a steady decrease in drilling-related emissions over 

time. SO2 emissions levels in particular are estimated to have fallen precipitously due to 

the introduction of the ultra-low sulfur standards for diesel fuel in 2010, and should 

remain extremely low for the foreseeable future. 

An analysis of county-level data found that the vast majority of Texas counties produced 

some level of emissions associated with drilling activities (206 of 254 counties) in the 

2010 base year. However, the county-level distribution of NOx emissions is highly 

skewed, with 14 counties being responsible for 50 percent of total statewide NOx in 

2010. In addition, the preponderance of the high NOx emitting counties were 

predominantly in West and North-Central Texas. 

While the emissions inventory results provide an excellent basis for assessing historical 

emissions levels, significant sources of uncertainty remain. Most importantly, 

projections of future activity are highly uncertain, subject to significant rises and falls 

depending upon economic factors and associated oil and gas prices. Accordingly, 

periodic refinement of the activity data used for projected years 2011 through 2040 is 

strongly recommended to account for such factors. In addition, the contribution of 

fracturing operations to drilling activity emissions remains unknown at this time. Given 

that fracturing activities occur at the end of the completion phase, that the engines 

involved are brought in after the removal of the main drilling equipment, and that 
5-2 

fracturing may recur in the future at undetermined intervals to re-invigorate flows, 

fracturing emissions may merit a new SCC to facilitate future inventory development. 
6-1 

6. References 

1. ARB, 2001. Speciation Profile Database. Internet address: 

http://www.arb.ca.gov/ei/speciate/interopt01.htm 

2. Bommer, P, 2008. A Primer of Oil Well Drilling, A Basic Text of Oil and Gas Drilling, 

Seventh Edition. The University of Texas at Austin, Petroleum Extension Service. 2008. 

3. Energy Information Administration (EIA), 2009. Supplemental Tables to the Annual 

Energy Outlook 2009, Updated Reference Case with ARRA, Data Tables 113 and 114. 

Data released April 2009. Washington, D.C. Internet address: 

http://www.eia.doe.gov/oiaf/aeo/supplement/stimulus/regionalarra.html 

4. Power Systems Research (PSR), Comprehensive Engine-Powered Vehicle and 

Equipment OEM Database, pp. 47-49, 1998. 

5. Texas Commission on Environmental Quality (TCEQ), 2007. Emissions from Oil and 

Gas Production Facilities, 2007. Prepared by Eastern Research Group, Inc. August 31, 

2007. 

6. Texas Commission on Environmental Quality (TCEQ), 2009. Drilling Rig Emission 

Inventory for the State of Texas. 2009. Prepared by Eastern Research Group, Inc. July 15, 

2009. 

7. Texas Commission on Environmental Quality (TCEQ), 2009. New Oil and Gas SCCs. 

Data provided by Greg Lauderdale, TCEQ. June 2, 2009. Email communication from 

Greg Lauderdale, TCEQ to Mike Pring, Eastern Research Group, Inc. 

8. Texas Commission on Environmental Quality (TCEQ), 2009a. NIF 3.0 Formatting for 

TEXAER. Data provided by Greg Lauderdale, TCEQ. June 24, 2009. Email 

communication from Greg Lauderdale, TCEQ to Mike Pring, Eastern Research Group, 

Inc. 

9. U.S. EPA, 2005. User’s Guide for the Final NONROAD2005 Model. EPA-420-R-05-

013. U.S. Environmental Protection Agency, Office of Air and Radiation. December. 

10. U.S. EPA, 2005a. Conversion Factors for Hydrocarbon Emission Components. EPA-420-

R-05-015. U.S. Environmental Protection Agency, Office of Air and Radiation. 

December. 
Appendix A. Annual HAP Emissions by Species (lbs/yr) 
A-1 

Annual PM Toxics by Year (Lbs/Year) 

Year Antimony Arsenic Cadmium Cobalt Chlorine Lead Manganese Nickel Mercury Ph1990 182.41 25.33 202.68 55.74 1743.01 212.81 202.68 96.27 152.01 1993 203.64 28.28 226.26 62.22 1945.86 237.58 226.26 107.48 169.70 1996 203.17 28.22 225.74 62.08 1941.39 237.03 225.74 107.23 169.31 1999 126.70 17.60 140.77 38.71 1210.66 147.81 140.77 66.87 105.58 2000 174.42 24.22 193.80 53.29 1666.65 203.49 193.80 92.05 145.35 2001 202.32 28.10 224.80 61.82 1933.31 236.04 224.80 106.78 168.60 2002 142.43 19.78 158.25 43.52 1360.98 166.17 158.25 75.17 118.69 2003 183.43 25.48 203.81 56.05 1752.78 214.00 203.81 96.81 152.86 2004 193.52 26.88 215.02 59.13 1849.17 225.77 215.02 102.13 161.26 2005 227.76 31.63 253.07 69.59 2176.38 265.72 253.07 120.21 189.80 2006 182.80 25.39 203.11 55.86 1746.76 213.27 203.11 96.48 152.33 2007 172.21 23.92 191.34 52.62 1645.53 200.91 191.34 90.89 143.51 2008 194.09 26.96 215.65 59.30 1854.60 226.43 215.65 102.43 161.74 2009 92.33 12.82 102.59 28.21 882.26 107.72 102.59 48.73 76.94 2010 76.00 10.56 84.44 23.22 726.21 88.67 84.44 40.11 63.33 2011 75.39 10.47 83.77 23.04 720.39 87.95 83.77 39.79 62.82 2012 76.32 10.60 84.80 23.32 729.30 89.04 84.80 40.28 63.60 2013 48.37 6.72 53.75 14.78 462.23 56.43 53.75 25.53 40.31 2014 48.60 6.75 54.00 14.85 464.36 56.70 54.00 25.65 40.50 2015 48.46 6.73 53.85 14.81 463.10 56.54 53.85 25.58 40.39 2016 47.75 6.63 53.05 14.59 456.26 55.71 53.05 25.20 39.79 2017 39.83 5.53 44.25 12.17 380.56 46.46 44.25 21.02 33.19 2018 29.70 4.13 33.00 9.08 283.81 34.65 33.00 15.68 24.75 2019 29.80 4.14 33.12 9.11 284.80 34.77 33.12 15.73 24.84 2020 29.87 4.15 33.18 9.13 285.39 34.84 33.18 15.76 24.89 2021 17.29 2.40 19.21 5.28 165.18 20.17 19.21 9.12 14.41 2022 17.31 2.40 19.24 5.29 165.44 20.20 19.24 9.14 14.43 2023 17.39 2.42 19.32 5.31 166.17 20.29 19.32 9.18 14.49 2024 22.87 3.18 25.41 6.99 218.51 26.68 25.41 12.07 19.06 2025 22.80 3.17 25.34 6.97 217.88 26.60 25.34 12.03 19.00 
A-2 

Year Antimony Arsenic Cadmium Cobalt Chlorine Lead Manganese Nickel Mercury Ph2026 25.69 3.57 28.55 7.85 245.50 29.97 28.55 13.56 21.41 2027 16.39 2.28 18.21 5.01 156.59 19.12 18.21 8.65 13.66 2028 16.25 2.26 18.06 4.97 155.28 18.96 18.06 8.58 13.54 2029 13.71 1.90 15.24 4.19 131.05 16.00 15.24 7.24 11.43 2030 13.61 1.89 15.12 4.16 130.03 15.88 15.12 7.18 11.34 2031 12.76 1.77 14.17 3.90 121.90 14.88 14.17 6.73 10.63 2032 12.59 1.75 13.99 3.85 120.34 14.69 13.99 6.65 10.49 2033 10.65 1.48 11.83 3.25 101.76 12.42 11.83 5.62 8.87 2034 10.53 1.46 11.70 3.22 100.65 12.29 11.70 5.56 8.78 2035 10.42 1.45 11.58 3.19 99.61 12.16 11.58 5.50 8.69 2036 7.16 0.99 7.96 2.19 68.41 8.35 7.96 3.78 5.97 2037 7.14 0.99 7.94 2.18 68.25 8.33 7.94 3.77 5.95 2038 7.13 0.99 7.92 2.18 68.12 8.32 7.92 3.76 5.94 2039 7.12 0.99 7.91 2.17 68.00 8.30 7.91 3.76 5.93 2040 7.11 0.99 7.90 2.17 67.90 8.29 7.90 3.75 5.92 
A-3 

Annual TOG Toxics by Year (Lbs/Year) 

Year 1,3‐Butadiene N‐Hexane 2,2,4‐Trimethylpentane Methylalcohol Formaldehyde Acetaldehyde 1990 13,364 11,253 21,100 2,110 1,034,618 516,958 1993 15,209 12,808 24,015 2,401 1,177,514 588,357 1996 15,613 13,147 24,651 2,465 1,208,736 603,957 1999 10,688 9,001 16,876 1,688 827,484 413,461 2000 14,659 12,345 23,146 2,315 1,134,927 567,078 2001 17,024 14,336 26,880 2,688 1,318,011 658,557 2002 11,408 9,606 18,012 1,801 883,187 441,293 2003 14,679 12,362 23,178 2,318 1,136,492 567,860 2004 15,624 13,157 24,669 2,467 1,209,603 604,390 2005 18,485 15,566 29,186 2,919 1,431,093 715,060 2006 15,961 13,441 25,202 2,520 1,235,748 617,454 2007 17,150 14,442 27,079 2,708 1,327,782 663,440 2008 17,731 14,932 27,997 2,800 1,372,789 685,928 2009 8,501 7,159 13,423 1,342 658,177 328,865 2010 7,126 6,001 11,252 1,125 551,700 275,662 2011 6,660 5,609 10,517 1,052 515,663 257,656 2012 6,625 5,579 10,460 1,046 512,899 256,275 2013 6,513 5,484 10,283 1,028 504,212 251,935 2014 6,530 5,499 10,310 1,031 505,551 252,604 2015 6,536 5,504 10,320 1,032 506,013 252,834 2016 6,526 5,496 10,305 1,030 505,288 252,472 2017 5,470 4,606 8,636 864 423,469 211,591 2018 4,492 3,783 7,093 709 347,781 173,772 2019 4,518 3,804 7,133 713 349,773 174,768 2020 4,536 3,820 7,163 716 351,213 175,487 2021 3,212 2,705 5,072 507 248,707 124,269 2022 3,231 2,721 5,102 510 250,154 124,992 2023 3,256 2,742 5,142 514 252,116 125,972 2024 3,692 3,109 5,829 583 285,839 142,822 2025 3,692 3,109 5,829 583 285,805 142,806 
A-4 

Year 1,3‐Butadiene N‐Hexane 2,2,4‐Trimethylpentane Methylalcohol Formaldehyde Acetaldehyde 2026 3,985 3,355 6,291 629 308,487 154,139 2027 2,824 2,378 4,460 446 218,673 109,262 2028 2,799 2,357 4,419 442 216,685 108,269 2029 3,038 2,558 4,796 480 235,173 117,507 2030 3,023 2,546 4,773 477 234,057 116,949 2031 3,003 2,528 4,741 474 232,461 116,152 2032 2,980 2,510 4,705 471 230,720 115,282 2033 2,591 2,181 4,090 409 200,561 100,212 2034 2,569 2,164 4,057 406 198,932 99,398 2035 2,548 2,145 4,023 402 197,242 98,554 2036 2,461 2,073 3,886 389 190,551 95,211 2037 2,460 2,072 3,885 388 190,471 95,171 2038 2,459 2,071 3,883 388 190,404 95,138 2039 2,459 2,070 3,882 388 190,347 95,109 2040 2,458 2,070 3,881 388 190,299 95,085 

Year Benzene Toluene Ethylbenzene O‐Xylene M‐Xylene P‐Xylene Styrene Isopropylbenzene(Cume1990 140,669 103,392 21,804 23,914 42,904 7,033 4,220 1,41993 160,097 117,671 24,815 27,216 48,830 8,005 4,803 1,61996 164,342 120,791 25,473 27,938 50,124 8,217 4,930 1,61999 112,506 82,692 17,438 19,126 34,314 5,625 3,375 1,12000 154,307 113,416 23,918 26,232 47,064 7,715 4,629 1,52001 179,199 131,711 27,776 30,464 54,656 8,960 5,376 1,72002 120,080 88,259 18,612 20,414 36,624 6,004 3,602 1,22003 154,520 113,572 23,951 26,268 47,128 7,726 4,636 1,52004 164,460 120,878 25,491 27,958 50,160 8,223 4,934 1,62005 194,574 143,012 30,159 33,078 59,345 9,729 5,837 1,92006 168,015 123,491 26,042 28,562 51,244 8,401 5,040 1,62007 180,528 132,688 27,982 30,690 55,061 9,026 5,416 1,82008 186,647 137,186 28,930 31,730 56,927 9,332 5,599 1,82009 89,487 65,773 13,870 15,213 27,294 4,474 2,685 8
A-5 

Year Benzene Toluene Ethylbenzene O‐Xylene M‐Xylene P‐Xylene Styrene Isopropylbenzene(Cume2010 75,010 55,132 11,627 12,752 22,878 3,751 2,250 72011 70,110 51,531 10,867 11,919 21,384 3,506 2,103 72012 69,735 51,255 10,809 11,855 21,269 3,487 2,092 62013 68,554 50,387 10,626 11,654 20,909 3,428 2,057 62014 68,736 50,521 10,654 11,685 20,964 3,437 2,062 62015 68,798 50,567 10,664 11,696 20,984 3,440 2,064 62016 68,700 50,494 10,648 11,679 20,953 3,435 2,061 62017 57,576 42,318 8,924 9,788 17,561 2,879 1,727 52018 47,285 34,754 7,329 8,038 14,422 2,364 1,419 42019 47,556 34,954 7,371 8,084 14,505 2,378 1,427 42020 47,752 35,097 7,402 8,118 14,564 2,388 1,433 42021 33,815 24,854 5,241 5,748 10,313 1,691 1,014 32022 34,011 24,998 5,272 5,782 10,373 1,701 1,020 32023 34,278 25,194 5,313 5,827 10,455 1,714 1,028 32024 38,863 28,564 6,024 6,607 11,853 1,943 1,166 32025 38,859 28,561 6,023 6,606 11,852 1,943 1,166 32026 41,942 30,828 6,501 7,130 12,792 2,097 1,258 42027 29,731 21,852 4,608 5,054 9,068 1,487 892 22028 29,461 21,654 4,566 5,008 8,986 1,473 884 22029 31,975 23,501 4,956 5,436 9,752 1,599 959 32030 31,823 23,390 4,933 5,410 9,706 1,591 955 32031 31,606 23,230 4,899 5,373 9,640 1,580 948 32032 31,369 23,056 4,862 5,333 9,568 1,568 941 32033 27,269 20,042 4,227 4,636 8,317 1,363 818 22034 27,047 19,880 4,192 4,598 8,249 1,352 811 22035 26,817 19,711 4,157 4,559 8,179 1,341 805 22036 25,908 19,042 4,016 4,404 7,902 1,295 777 22037 25,897 19,034 4,014 4,402 7,899 1,295 777 22038 25,888 19,028 4,013 4,401 7,896 1,294 777 22039 25,880 19,022 4,011 4,400 7,893 1,294 776 22040 25,873 19,017 4,010 4,398 7,891 1,294 776 2
Appendix B. Texas County Groupings Used for Growth Factor 

Projection Assignment 
B-1 

Midcontinent = District 10

County TRC Distr.

Armstrong 10

Briscoe 10

Carson 10

Castro 10

Childress 10

Collingsworth 10

Dallam 10

Deaf Smith 10

Donley 10

Gray 10

Hall 10

Hansford 10

Hartley 10

Hemphill 10

Hutchinson 10

Lipscomb 10

Moore 10

Ochiltree 10

Oldham 10

Parmer 10

Potter 10

Randall 10

Roberts 10

Sherman 10

Swisher 10

Wheeler 10

Southwest = Districts 7b, 7c, 8, 8a, 9

County TRC Distr.

Andrews 8

Archer 9

Bailey 8A

Baylor 9

Borden 8A

Brewster 8

Brown 7B

Callahan 7B

Clay 9

Cochran 8A

Coke 7C

Coleman 7B

Comanche 7B
B-2 

Southwest = Districts 7b, 7c, 8, 8a, 9

County TRC Distr.

Concho 7C

Cooke 9

Coryell 7B

Cottle 8A

Crane 8

Crockett 7C

Crosby 8A

Culberson 8

Dawson 8A

Denton 9

Dickens 8A

Eastland 7B

Ector 8

El Paso 8

Erath 7B

Fisher 7B

Floyd 8A

Foard 9

Gaines 8A

Garza 8A

Glasscock 8

Grayson 9

Hale 8A

Hamilton 7B

Hardeman 9

Haskell 7B

Hockley 8A

Hood 7B

Howard 8

Hudspeth 8

Irion 7C

Jack 9

Jeff Davis 8

Jones 7B

Kent 8A

Kimble 7C

King 8A

Knox 9

Lamb 8A

Lampasas 7B

Loving 8

Lubbock 8A

Lynn 8A

McCulloch 7C
B-3 

Southwest = Districts 7b, 7c, 8, 8a, 9

County TRC Distr.

Martin 8

Menard 7C

Midland 8

Mills 7B

Mitchell 8

Montague 9

Motley 8A

Nolan 7B

Palo Pinto 7B

Parker 7B

Pecos 8

Presidio 8

Reagan 7C

Reeves 8

Runnels 7C

San Saba 7B

Schleicher 7C

Scurry 8A

Schackelford 7B

Somervell 7B

Stephens 7B

Sterling 8

Stonewall 7B

Sutton 7C

Taylor 7B

Terrell 7C

Terry 8A

Throckmorton 7B

Tom Green 7C

Upton 7C

Ward 8

Wichita 9

Wilbarger 9

Winkler 8

Wise 9

Yoakum 8A

Young 9

Gulf Coast = All other Districts

County TRC Distr.

Anderson 6

Angelina 6

Aransas 4

Atascosa 1
B-4 

Gulf Coast = All other Districts

County TRC Distr.

Austin 3

Bandera 1

Bastrop 1

Bee 2

Bell 1

Bexar 1

Blanco 1

Bosque 5

Bowie 6

Brazoria 3

Brazos 3

Brooks 4

Burleson 3

Burnet 1

Caldwell 1

Calhoun 2

Cameron 4

Camp 6

Cass 6

Chambers 3

Cherokee 6

Collin 5

Colorado 3

Comal 1

Dallas 5

Delta 5

De Witt 2

Dimmit 1

Duval 4

Edwards 1

Ellis 5

Falls 5

Fannin 5

Fayette 3

Fort Bend 3

Franklin 6

Freestone 5

Frio 1

Galveston 3

Gillespie 1

Goliad 2

Gonzales 1

Gregg 6

Grimes 3
B-5 

Gulf Coast = All other Districts

County TRC Distr.

Guadalupe 1

Hardin 3

Harris 3

Harrison 6

Hays 1

Henderson 5

Hidalgo 4

Hill 5

Hopkins 5

Houston 6

Hunt 5

Jackson 2

Jasper 3

Jefferson 3

Jim Hogg 4

Jim Wells 4

Johnson 5

Karnes 2

Kaufman 5

Kendall 1

Kenedy 4

Kerr 1

Kinney 1

Kleberg 4

Lamar 5

La Salle 1

Lavaca 2

Lee 3

Leon 5

Liberty 3

Limestone 5

Live Oak 2

Llano 1

McLennan 5

McMullen 1

Madison 3

Marion 6

Mason 1

Matagorda 3

Maverick 1

Medina 1

Milam 1

Montgomery 3

Morris 6
B-6 

Gulf Coast = All other Districts

County TRC Distr.

Nacogdoches 6

Navarro 5

Newton 3

Nueces 4

Orange 3

Panola 6

Polk 3

Rains 5

Real 1

Red River 6

Refugio 2

Robertson 5

Rockwall 5

Rusk 6

Sabine 6

San Augustine 6

San Jacinto 3

San Patricio 4

Shelby 6

Smith 6

Starr 4

Tarrant 5

Titus 6

Travis 1

Trinity 3

Tyler 3

Upshur 6

Uvalde 1

Val Verde 1

Van Zandt 5

Victoria 2

Walker 3

Waller 3

Washington 3

Webb 4

Wharton 3

Willacy 4

Williamson 1

Wilson 1

Wood 6

Zapata 4

Zavala 1
Appendix C. Total Drilling Depth by County by Model Rig Well 

Type Category 

(see file “Activity_workup1.xlsx”) 
Appendix D. Annual and OSD County-Level Emission Estimates 

(see file “Drill_Rigs_Workup4.xlsx”)