A TTACHMENT J

DEVELOPMENT OF TEXAS STATEWIDE DRILLING R IGS EMISSION

INVENTORIES FOR THE YEARS 1990, 1993, 19 96, AND 1999 THROUGH 2040

## D EVELOPMENT OF 

## T EXAS 

## S TATEWIDE



## D RILLING 

## R IGS 

## E MISSION



## I NVENTORIES FOR THE YEARS 

## 1990,

1993, 1996, AND 

## 1999 THROUGH



## 2040

F INAL 

## R EPORT

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 Statewid e 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 Count y 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 Ri g 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 Projec ted Growth Factors 2011-2035+ ....................................... 4-9

Table 4-4. Model Rig E ngine Parameters ................................................................................. 4-10

Table 4-5. PM 10 

### Speciation Factors .......................................................................................... 4-12

Table 4-6. TOG Speci ation Factors .......................................................................................... 4 -12

Table 4-7. Annual Weighted Aver age 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/H orizontal 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 (T ons/Day), Uncontrolled Scenario ................ 4-29

Table 4-16. County NO

x 

### 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 (NO

x 

### and CO Tons/Year) ................................... 1-3

Figure 1-2. Statewide Drilling Rig Estimates (VOC and SO 2 

### Tons/Year) ................................. 1-4

Figure 1-3. Statewide Drilling Rig Estimates (PM 10 

### and PM 2.5 

### Tons/Year) .............................. 1-4

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

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

Figure 4-3. Statewide Drilling Rig Emi ssions – Controlled Scenario (NO

x 

### and CO

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

Figure 4-4. Statewide Drilling Rig Emissions – Controlled Scenario (VOC and SO 2



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

Figure 4-5. Statewide Drilling Rig Em issions – Controlled Scenario (PM 10 

### and PM 2.5



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

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

Figure 4-7. Statewide Drilling Rig Emi ssions – Uncontrolled Scenario (NO

x 

### and CO

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

Figure 4-8. Statewide Drilling Rig Emissions – Uncontrolled Scenario (VOC and SO 2



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

Figure 4-9. Statewide Drilling Rig Emi ssions – Uncontrolled Scenario (PM 10 

### and PM 2.5



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

Figure 4-10. Annual NO

x 

### Emissions by Year – Top 10 Counties (2010 basis) ....................... 4-36

Figure 4-11. 2010 Annual NO

x 

### 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 PM 2.5 

### Emissions by County (Tons/Year) ........................................ 4-39

Figure 4-14. Controlled and Uncont rolled Emissions Projections (NO

x 

### Tons/Year) .............. 4-41

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

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

Figure 4-17. Controlled and Uncont rolled Emissions Projections (PM 10 

### Tons/Year) ............ 4-43

Figure 4-18. Controlled and Uncont rolled Emissions Projections (SO 2 

### 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

NO

x Nitrogen Oxides

OSD Ozone Season Daily

PM 10 PM with particle diameter less than 10 micrometers

PM 2.5 PM with particle diameter less than 2.5 micrometers

QAPP Quality Assurance Project Plan

SCC Source Classification Code

SIP State Implementation Plan

SO 2 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 th e 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 ex panded upon by improving the activity data

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

engine emission profiles developed in the 2 009 study. The improved well activity data

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

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

characterization data were then used to de velop controlled and uncontrolled drilling rig

engine emissions inventories for the year s 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 (ac tual number of drilling days)

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

 Average well depth

Target pollutants for this stud y include nitrogen oxides (NO

x 

### ), volatile organic

compounds (VOC), carbon monoxide (CO), particulate matter (PM

10 

### and PM

2.5 

### ), sulfur

dioxide (SO

2 

### ), 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 Administra tion (EIA) oil and gas production growth

estimates were used to develop the pr ojections for the years 2011 forward.

Emissions estimates developed from this in ventory project may be used for improved

input data to photochemical air quality di spersion 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 Reposi tory) 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 - Oi l 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 PM

10 

### and PM

2.5 

### 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 Drilli ng Rig Estimates (Tons/Year)

Year CO NO X PM 2.5 PM 10 SO 2 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 NO X PM 2.5 PM 10 SO 2 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 Dr illing Rig Estimates (NO

x 

### and CO Tons/Year)

### 1-4 Figure 1-2. Statewide Drilling Rig Estimates (VOC and SO 2 

### Tons/Year)

Figure 1-3. Statewide Dr illing Rig Estimates (PM 10 

### and PM 2.5 

### 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, ra ther than relying on surrogate based backcasting from a base year, as was done in th e 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 up date 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 de crease in drilling-related emissions over

time. SO

2 

### emissions levels in particular are esti mated 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 associat ed with drilling activities (206 of 254 counties) in the

2010 base year. However, the county-level distribution of NO

x 

### emissions is highly

skewed, with 14 counties being responsible for 50 percent of total statewide NO

x 

### in

2010. In addition, the preponderance of the high NO

x 

### 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 uncert ain, subject to significant rises and falls

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

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

strongly recommended to account for such fa ctors. 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 th e 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 ex panded upon by improving the activity data

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

engine emission profiles developed in the 2 009 study. The improved well activity data

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

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

characterization data were then used to de velop controlled and uncontrolled drilling rig

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

While drilling activities are generally shor t-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 acti vities can generate

substantial amounts of NO

x 

### 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 NO

x 

### emission

levels associated with drilling activity.

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

were used to develop emi ssions estimates of VOC, NO

x 

### , CO, PM

10 

### and PM

2.5 

### , SO

2 

### , and

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

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

Section 3.0 of this report provides an overvi ew 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 dri lling rig emission profiles were developed,

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

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

Section 5.0 summarizes the conclusions for th is 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, ho rizontal, 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 Ma ster 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 thes e 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 independen t sets of engines. Th e first set of engines

(draw works engines) are used to provide powe r 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 auxiliar y equipment found on the drill site such as

lighting equipment and heating and air conditi oning for crew quarters and office space.

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

required. There are typically two mud pump s 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, wi th 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 SC R house is then used to provide power to

separate motors on the rig. In this configu ration, 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 ty pically 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 re lative expense of engines versus motors, both

in terms of initial cost and maintenance. Toda y, 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 ga s. 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 plu gged 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, calle d 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-s ite 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 enha nced 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 pr opagate 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 fo rmations, 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 afte r 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 ex haustion 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 fr om 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 re servoir is commonly done. In high angle or

horizontal wells, it is common to perfor m 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 NO

x 

### emissions due to the very high horsepower requirements.

### 4-1 

## 4. Emissions Inventory Development and Results

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

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

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

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

characterize activity and emi ssions for all significant source s 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 leve ls of emissions. In addition, the survey

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

inventory estimates were li mited to diesel engines.

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

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

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

three are involved in drilling activities. Th e 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 re garding fracturing, but the responses were

highly variable in content and format. In ge neral, 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 conta cted did not provide any data.

2 Note that these pump engines are different than the pu mps 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 com piled by the TRC or otherwise made readily

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

However, images of individual well completio n 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 Petroleu m 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 ar e frequently completed by hand, with

inconsistent data being reported by individu al 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 emissi ons 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) maintain s 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, 20 11. 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 activi ties 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 hori zontal), 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 defi nitively if activity

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

administrative records, and no drilling acti vity 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 ac tivity 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 identifi ed approximately 4% of the data as having

either a Spud Date or a Drilling Completi on 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 identifi ed as having drilling activities occurring

during one of the 15 years of interest.

Prior to calculating the activity data needed to calculate estimate d 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 Co mpletion 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 prio ritized 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 occurre d 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 dept h 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 we re 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 an d the Spud Date. The “Average Drilling

Rate” was then used to pro-rate the total drilli ng 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 dept h of 4,500 feet. Based on the Spud Date

and Drilling End Date, it is assumed that dr illing 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 f eet 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 perm it 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 ri g 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 cov ered 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 data base), ERG successfully characterized and

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

be characterized adequately due to irre solvable data gaps or similar data

inconsistencies.

4.1.2 Projected Activity

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

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

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

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

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

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

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

Portions of Texas fall into three EIA Region s: 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 in dicating each of the TRC Districts.

Figure 4-2. TRC Districts 4

4 http://www.rrc.state.tx.us/f orms/maps/ogdi visionmap.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 crud e oil and natural gas production for the

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

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

This data was then used to calculate a proj ected 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 oi l 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 tota ls 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 vo latile economic nature of oil and gas prices.4-7Table 4-1. Projected Crude Oil Production 2010-2035EIARegionCrudeOilProduction(MMBBL/day)20102011201221032014201520162017201820192020202120222023GulfCoast0.530.580.600.620.620.640.660.670.690.710.720.720.730.75Midcontinent0.340.330.340.340.340.350.360.370.370.400.420.460.510.56Southwest0.940.970.991.011.021.031.051.071.091.111.111.101.111.11%Changefrom2010GulfCoast9.8%13.2%16.7%18.1%21.9%24.8%27.8%31.2%34.7%36.4%37.2%38.7%41.5%Midcontinent‐5.3%‐2.1%‐0.7%‐0.3%1.7%4.5%6.6%8.8%15.3%21.2%34.2%49.0%62.0%Southwest3.2%5.6%7.0%8.7%9.8%11.2%14.0%16.2%17.7%18.2%17.4%17.6%17.9%EIARegionCrudeOilProduction(MMBBL/day)202420252026202720282029203020312032203320342035GulfCoast0.750.750.730.730.720.720.710.710.700.680.680.66Midcontinent0.600.620.640.650.650.650.660.650.640.640.620.60Southwest1.101.101.091.091.081.061.051.041.031.021.000.99%Changefrom2010GulfCoast41.5%41.4%39.4%38.6%36.9%35.9%35.7%34.5%33.5%29.8%28.1%24.6%Midcontinent74.1%79.9%85.2%87.9%89.7%89.7%91.4%90.0%84.9%84.6%81.6%75.4%Southwest17.3%16.8%15.9%15.8%14.5%13.2%11.9%10.6%9.2%8.5%6.0%5.0%4-8Table 4-2. Projected Natural Gas Production 2010-2035EIARegionNaturalGasProduction(trillioncubicfeet)20102011201221032014201520162017201820192020202120222023GulfCoast4.254.194.214.284.284.264.164.094.033.994.004.004.013.97Midcontinent3.173.163.173.183.153.123.052.982.912.852.742.742.732.73Southwest4.254.184.144.164.144.134.074.013.963.903.903.883.903.92%Changefrom2010GulfCoast‐1.3%‐1.0%0.7%0.9%0.3%‐1.9%‐3.6%‐5.0%‐6.1%‐5.9%‐5.8%‐5.5%‐6.4%Midcontinent‐0.2%0.0%0.5%‐0.6%‐1.4%‐3.7%‐6.0%‐8.0%‐10.1%‐13.4%‐13.6%‐13.7%‐14.0%Southwest‐1.7%‐2.5%‐2.1%‐2.5%‐2.7%‐4.3%‐5.6%‐6.9%‐8.3%‐8.2%‐8.7%‐8.3%‐7.7%EIARegionNaturalGasProduction(trillioncubicfeet)202420252026202720282029203020312032203320342035GulfCoast3.954.004.014.044.064.034.003.983.994.004.034.08Midcontinent2.702.702.682.672.672.622.592.582.572.582.582.61Southwest3.923.933.913.893.903.873.893.923.974.024.074.12%Changefrom2010GulfCoast‐6.9%‐5.9%‐5.5%‐4.8%‐4.3%‐5.0%‐5.7%‐6.2%‐6.1%‐5.8%‐5.0%‐3.9%Midcontinent‐14.8%‐14.8%‐15.3%‐15.6%‐15.8%‐17.3%‐18.2%‐18.4%‐18.9%‐18.6%‐18.4%‐17.6%Southwest‐7.6%‐7.5%‐8.0%‐8.4%‐8.3%‐8.9%‐8.4%‐7.7%‐6.5%‐5.4%‐4.2%‐2.9%

### 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 tota l 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 appl ied 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 en gine 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 engi nes used on mechanical rigs and electrical

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

were developed for each mo del 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., me chanical 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 de veloped 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 fo r 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 numb er 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, an d the average age of the engines used on the

electrical rigs for these we ll types is only two years.

4.2.2 Model Rig Emission Factors

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

model was modified to develo p 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 fo r expected reductions in emissions over

time due to the phasing in of EPA’s emissi ons 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 NO NROAD to reflect the appropriate hours per

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

for each of the three rig types). Modifi cations were made fo r SCC 2270010010 (Diesel

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

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

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

NONROAD OPT files (input files containin g 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/scenari o year combination fo r this analysis.

Hazardous air pollutant (HAP) emission fa ctors 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 2 009 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), th ese emissions are actually classified as area sources emissions and reported

as such to the TCEQ.

### 4-12 Table 4-5. PM 10 

### Speciation Factors

HAP HAP CAS # Weight Fraction of PM 10

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



### SO

2 

### emissions were based on fuel sulfur con tent profiles for Texas obtained from

historical fuel sampling data performed for th e 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 mo del, weighted by the number of wells in

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

presented in Table 4-7 reflecting the re duced 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 fo r each engine type were derived from

NONROAD outputs. The activity levels en tered into NONROAD corresponded to the

hours required to drill 1,000 feet, so NONR OAD 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 mo del year (from NONROAD’s by-model-year

output), and then multiplying by the average number of engi nes 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 (correspondi ng 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 emission s per 1,000 feet of drilling activity for this

engine, the mass emissions associated with th is 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 pe r 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 fo r each engine category/we ll 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, PM

10 

### is assumed to be equivalent to PM,

while the PM

2.5 

### fraction of PM

10 

### 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 NO

x SO 2 VOC CO PM 10 PM 2.5 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 NO

x SO 2 VOC CO PM 10 PM 2.5 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 Vertic al Wells > 7,000 feet (tons/1,000 feet)

Year NO

x SO 2 VOC CO PM 10 PM 2.5 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 NO

x SO 2 VOC CO PM 10 PM 2.5 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 NO

x SO 2 VOC CO PM 10 PM 2.5 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 NO

x SO 2 VOC CO PM 10 PM 2.5 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 NO

x SO 2 VOC CO PM 10 PM 2.5 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 a ggregated by model rig well type category,

and the emission factor profile for each mo del 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 work s engines used for shallow vertical wells (<

7,000 feet).

For 2006 onward, NO

x 

### 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 th ese 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, NO

x 

### emissions were estimated as follows:

Total county level emissions were then dete rmined 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, NO

x 

### emissions in 2008 for

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

ENO

x 

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

ENO

x 

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

ENO

x 

### = 33.1 (tons/yr)

4.4 Results

4.4.1 Emission Summary

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

annual and ozone-season daily criteria emissi ons 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 emissi on rates generated using the

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

emission controls and represent “uncontrolle d” 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 fo r each analysis year. Depending upon

the analysis year in question, one or mo re 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. No ne of these rules are accounted for in the

Uncontrolled scenario.

### 4-21 HAP emissions estimates and by-county breako uts 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 Em issions Totals (Tons/Year),

Controlled Scenario

Year NO

x SO 2 VOC CO PM 10 PM 2.5

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 NO

x SO 2 VOC CO PM 10 PM 2.5

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 Ri g Emissions – Controlled Scenario

(NO

x 

### and CO Tons/Year)

### 4-23 Figure 4-4. Statewide Drilling Ri g Emissions – Controlled Scenario

(VOC and SO 2 

### Tons/Year)

Figure 4-5. Statewide Drilling Ri g Emissions – Controlled Scenario (PM 10



### and PM 2.5 

### Tons/Year)

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

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

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

4-6 presents the corresponding statewide drilli ng 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 emissi on 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 Dr illing Rig Activity (000’s feet)

NO

x 

### and SO

2 

### emissions trends display a somewhat different pattern during this time,

however. NO

x 

### 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 NO

x 

### reductions are found with the introduction of the Tier 3 and

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

SO

2 

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

these levels are constant over time, SO

2 

### emissions will track drilling activity in a one-toone fashion. SO

2 

### emissions are seen to go negligible levels with the introduction of the

Tier 4 ultra-low sulfur requirements after 2 009. Other emission rates are projected to

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

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

Ozone season day (OSD) emissions were ca lculated 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 re lative emissions over time do not change

compared to the annual emissions cases above.

### 4-25 Table 4-13. Statewide OSD Emi ssions Totals (Tons/Day),

Controlled Scenario

Year NO

x SO 2 VOC CO PM 10 PM 2.5

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 NO

x SO 2 VOC CO PM 10 PM 2.5

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 Em issions Totals (Tons/Year),

Uncontrolled Scenario

Year NO

x SO 2 VOC CO PM 10 PM 2.5

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 NO

x SO 2 VOC CO PM 10 PM 2.5

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 Ri g Emissions – Uncontrolled Scenario

(NO

x 

### and CO Tons/Year)

### 4-28 Figure 4-8. Statewide Drilling Ri g Emissions – Uncontrolled Scenario

(VOC and SO 2 

### Tons/Year)

Figure 4-9. Statewide Drilling Ri g Emissions – Uncontrolled Scenario

(PM 10 

### and PM 2.5 

### Tons/Year)

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

emissions for all pollutants would be substa ntially 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-t o-year changes shown above are exclusively

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

### 4-29 Table 4-15. Statewide OSD Emi ssions Totals (Tons/Day),

Uncontrolled Scenario

Year NO

x SO 2 VOC CO PM 10 PM 2.5

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 NO

x SO 2 VOC CO PM 10 PM 2.5

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 NO

x 

### emissions were also investigated for the Controlled scenario

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

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

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

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

example, the top 14 counties were responsible for 50 percent of total NO

x 

### 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 NO

x 

### 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 NO

x 

### 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 follo w the general pattern seen in the statewide

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

of annual NO

x 

### , VOC, and PM

2.5 

### emissions for the 2010 base year.4-36Figure 4-10. Annual NOxEmissions by Year – Top 10 Counties (2010 basis)4-37Figure 4-11. 2010 Annual NOxEmissions by County (Tons/Year)4-38Figure 4-12. 2010 Annual VOC Emissions by County (Tons/Year)4-39Figure 4-13. 2010 Annual PM2.5Emissions by County (Tons/Year)

### 4-40 4.4.2 CERS XML Files

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

prepared. For purposes of XML preparat ion, 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 upload ed 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 assuranc e 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 we re 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 subseq uently revised prior to genera tion 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 work ing 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 se t 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 fr om 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 con trols being phased in over time. The

following highlights some of the key findings from this analysis.

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

the time series charts generated for the po llutants 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 emissi on control phase-in schedules, as discussed

in Section 4.4.1 above.

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

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

### 4-41 Table 4-17. Comparison of Statewid e 2008 Annual Emissions Totals

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

Year Study CO NO

x PM 10 PM 2.5 SO 2 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 inve ntory than in 2009 study. The ERG staff

responsible for processing the TRC data confi rmed that an enhanced methodology was

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

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

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

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

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

as SO

2 

### emissions do in fact vary on a 1:1 ba sis 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 co mpare 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 Unco ntrolled Emissions Projections

(NO

x 

### Tons/Year)

### 4-42 Figure 4-15. Controlled and Unco ntrolled Emissions Projections

(CO Tons/Year)

Figure 4-16. Controlled and Unco ntrolled Emissions Projections

(VOC Tons/Year)

### 4-43 Figure 4-17. Controlled and Unco ntrolled Emissions Projections

(PM 10 

### Tons/Year)

Figure 4-18. Controlled and Unco ntrolled Emissions Projections

(SO 2 

### Tons/Year)

The difference between the controlled and uncontrolled emissions deviate more and

more over time, as expected. The NO

x 

### 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.

SO

2 

### deviation shows the most abrupt increase (in 2010 when ultra-low diesel sulfur

### 4-44 regulations are enacted), since emissions fo r this pollutant depends on fuel sulfur

changes alone, as opposed to fleet turnover.

### 5-1 

## 5. Conclusions and Recommendations

This study presents comprehensive, statew ide 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 re presents a significant improvement upon the

2009 effort, utilizing improved gap filling me thods 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 th e previous study, ranging from 1990 with

projections through 2040. The result is a reliable, temporally resolved profile of countylevel drilling activity emission s. 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 de crease in drilling-related emissions over

time. SO

2 

### emissions levels in particular are esti mated 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 associat ed with drilling activities (206 of 254 counties) in the

2010 base year. However, the county-level distribution of NO

x 

### emissions is highly

skewed, with 14 counties being responsible for 50 percent of total statewide NO

x 

### in

2010. In addition, the preponderance of the high NO

x 

### 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 uncert ain, subject to significant rises and falls

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

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

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

fracturing operations to drilling activity em issions 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 undeterm ined intervals to re-invigorate flows,

fracturing emissions may meri t a new SCC to facilitate future inventory development.

### 6-1 

## 6. References

1. ARB, 2001. Speciation Profile Da tabase. Internet address:

http://www.arb.ca.gov/ei/s peciate/interopt01.htm

2. Bommer, P, 2008. A Primer of Oil Well Drillin g, 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. Washi ngton, D.C. Internet address:

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

4. Power Systems Research (PSR), Compre hensive 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 Qual ity (TCEQ), 2009. Dr illing Rig Emission

Inventory for the State of Texas. 2009. Prepar ed 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 La uderdale, 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 th e 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 fo r Hydrocarbon Emission Components. EPA-420-

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

December.

## Appendix A. Annual HAP Em issions by Species (lbs/yr)A-1Annual PM Toxics by Year (Lbs/Year)YearAntimonyArsenicCadmiumCobaltChlorineLeadManganeseNickelMercuryPhosphorousSelenium1990182.4125.33202.6855.741743.01212.81202.6896.27152.01643.5050.671993203.6428.28226.2662.221945.86237.58226.26107.48169.70718.3956.571996203.1728.22225.7462.081941.39237.03225.74107.23169.31716.7356.441999126.7017.60140.7738.711210.66147.81140.7766.87105.58446.9635.192000174.4224.22193.8053.291666.65203.49193.8092.05145.35615.3048.452001202.3228.10224.8061.821933.31236.04224.80106.78168.60713.7556.202002142.4319.78158.2543.521360.98166.17158.2575.17118.69502.4639.562003183.4325.48203.8156.051752.78214.00203.8196.81152.86647.1050.952004193.5226.88215.0259.131849.17225.77215.02102.13161.26682.6953.752005227.7631.63253.0769.592176.38265.72253.07120.21189.80803.4963.272006182.8025.39203.1155.861746.76213.27203.1196.48152.33644.8850.782007172.2123.92191.3452.621645.53200.91191.3490.89143.51607.5147.842008194.0926.96215.6559.301854.60226.43215.65102.43161.74684.6953.91200992.3312.82102.5928.21882.26107.72102.5948.7376.94325.7225.65201076.0010.5684.4423.22726.2188.6784.4440.1163.33268.1121.11201175.3910.4783.7723.04720.3987.9583.7739.7962.82265.9620.94201276.3210.6084.8023.32729.3089.0484.8040.2863.60269.2521.20201348.376.7253.7514.78462.2356.4353.7525.5340.31170.6513.44201448.606.7554.0014.85464.3656.7054.0025.6540.50171.4413.50201548.466.7353.8514.81463.1056.5453.8525.5840.39170.9713.46201647.756.6353.0514.59456.2655.7153.0525.2039.79168.4513.26201739.835.5344.2512.17380.5646.4644.2521.0233.19140.5011.06201829.704.1333.009.08283.8134.6533.0015.6824.75104.788.25201929.804.1433.129.11284.8034.7733.1215.7324.84105.148.28202029.874.1533.189.13285.3934.8433.1815.7624.89105.368.30202117.292.4019.215.28165.1820.1719.219.1214.4160.984.80202217.312.4019.245.29165.4420.2019.249.1414.4361.084.81202317.392.4219.325.31166.1720.2919.329.1814.4961.354.83202422.873.1825.416.99218.5126.6825.4112.0719.0680.676.35202522.803.1725.346.97217.8826.6025.3412.0319.0080.446.33A-2YearAntimonyArsenicCadmiumCobaltChlorineLeadManganeseNickelMercuryPhosphorousSelenium202625.693.5728.557.85245.5029.9728.5513.5621.4190.637.14202716.392.2818.215.01156.5919.1218.218.6513.6657.814.55202816.252.2618.064.97155.2818.9618.068.5813.5457.334.51202913.711.9015.244.19131.0516.0015.247.2411.4348.383.81203013.611.8915.124.16130.0315.8815.127.1811.3448.013.78203112.761.7714.173.90121.9014.8814.176.7310.6345.003.54203212.591.7513.993.85120.3414.6913.996.6510.4944.433.50203310.651.4811.833.25101.7612.4211.835.628.8737.572.96203410.531.4611.703.22100.6512.2911.705.568.7837.162.93203510.421.4511.583.1999.6112.1611.585.508.6936.772.9020367.160.997.962.1968.418.357.963.785.9725.261.9920377.140.997.942.1868.258.337.943.775.9525.201.9820387.130.997.922.1868.128.327.923.765.9425.151.9820397.120.997.912.1768.008.307.913.765.9325.111.9820407.110.997.902.1767.908.297.903.755.9225.071.97A-3Annual TOG Toxics by Year (Lbs/Year)Year1,3‐ButadieneN‐Hexane2,2,4‐TrimethylpentaneMethylalcoholFormaldehydeAcetaldehydePropionaldehyde199013,36411,25321,1002,1101,034,618516,95868,224199315,20912,80824,0152,4011,177,514588,35777,647199615,61313,14724,6512,4651,208,736603,95779,706199910,6889,00116,8761,688827,484413,46154,566200014,65912,34523,1462,3151,134,927567,07874,839200117,02414,33626,8802,6881,318,011658,55786,912200211,4089,60618,0121,801883,187441,29358,239200314,67912,36223,1782,3181,136,492567,86074,942200415,62413,15724,6692,4671,209,603604,39079,763200518,48515,56629,1862,9191,431,093715,06094,368200615,96113,44125,2022,5201,235,748617,45481,487200717,15014,44227,0792,7081,327,782663,44087,556200817,73114,93227,9972,8001,372,789685,92890,52420098,5017,15913,4231,342658,177328,86543,40120107,1266,00111,2521,125551,700275,66236,38020116,6605,60910,5171,052515,663257,65634,00420126,6255,57910,4601,046512,899256,27533,82120136,5135,48410,2831,028504,212251,93533,24820146,5305,49910,3101,031505,551252,60433,33720156,5365,50410,3201,032506,013252,83433,36720166,5265,49610,3051,030505,288252,47233,31920175,4704,6068,636864423,469211,59127,92420184,4923,7837,093709347,781173,77222,93320194,5183,8047,133713349,773174,76823,06520204,5363,8207,163716351,213175,48723,16020213,2122,7055,072507248,707124,26916,40020223,2312,7215,102510250,154124,99216,49620233,2562,7425,142514252,116125,97216,62520243,6923,1095,829583285,839142,82218,84920253,6923,1095,829583285,805142,80618,846A-4Year1,3‐ButadieneN‐Hexane2,2,4‐TrimethylpentaneMethylalcoholFormaldehydeAcetaldehydePropionaldehyde20263,9853,3556,291629308,487154,13920,34220272,8242,3784,460446218,673109,26214,42020282,7992,3574,419442216,685108,26914,28920293,0382,5584,796480235,173117,50715,50820303,0232,5464,773477234,057116,94915,43420313,0032,5284,741474232,461116,15215,32920322,9802,5104,705471230,720115,28215,21420332,5912,1814,090409200,561100,21213,22520342,5692,1644,057406198,93299,39813,11820352,5482,1454,023402197,24298,55413,00620362,4612,0733,886389190,55195,21112,56520372,4602,0723,885388190,47195,17112,56020382,4592,0713,883388190,40495,13812,55620392,4592,0703,882388190,34795,10912,55220402,4582,0703,881388190,29995,08512,549YearBenzeneTolueneEthylbenzeneO‐XyleneM‐XyleneP‐XyleneStyreneIsopropylbenzene(Cumene)Naphthalene1990140,669103,39221,80423,91442,9047,0334,2201,4076,3301993160,097117,67124,81527,21648,8308,0054,8031,6017,2041996164,342120,79125,47327,93850,1248,2174,9301,6437,3951999112,50682,69217,43819,12634,3145,6253,3751,1255,0632000154,307113,41623,91826,23247,0647,7154,6291,5436,9442001179,199131,71127,77630,46454,6568,9605,3761,7928,0642002120,08088,25918,61220,41436,6246,0043,6021,2015,4042003154,520113,57223,95126,26847,1287,7264,6361,5456,9532004164,460120,87825,49127,95850,1608,2234,9341,6457,4012005194,574143,01230,15933,07859,3459,7295,8371,9468,7562006168,015123,49126,04228,56251,2448,4015,0401,6807,5612007180,528132,68827,98230,69055,0619,0265,4161,8058,1242008186,647137,18628,93031,73056,9279,3325,5991,8668,399200989,48765,77313,87015,21327,2944,4742,6858954,027A-5YearBenzeneTolueneEthylbenzeneO‐XyleneM‐XyleneP‐XyleneStyreneIsopropylbenzene(Cumene)Naphthalene201075,01055,13211,62712,75222,8783,7512,2507503,375201170,11051,53110,86711,91921,3843,5062,1037013,155201269,73551,25510,80911,85521,2693,4872,0926973,138201368,55450,38710,62611,65420,9093,4282,0576863,085201468,73650,52110,65411,68520,9643,4372,0626873,093201568,79850,56710,66411,69620,9843,4402,0646883,096201668,70050,49410,64811,67920,9533,4352,0616873,091201757,57642,3188,9249,78817,5612,8791,7275762,591201847,28534,7547,3298,03814,4222,3641,4194732,128201947,55634,9547,3718,08414,5052,3781,4274762,140202047,75235,0977,4028,11814,5642,3881,4334782,149202133,81524,8545,2415,74810,3131,6911,0143381,522202234,01124,9985,2725,78210,3731,7011,0203401,531202334,27825,1945,3135,82710,4551,7141,0283431,543202438,86328,5646,0246,60711,8531,9431,1663891,749202538,85928,5616,0236,60611,8521,9431,1663891,749202641,94230,8286,5017,13012,7922,0971,2584191,887202729,73121,8524,6085,0549,0681,4878922971,338202829,46121,6544,5665,0088,9861,4738842951,326202931,97523,5014,9565,4369,7521,5999593201,439203031,82323,3904,9335,4109,7061,5919553181,432203131,60623,2304,8995,3739,6401,5809483161,422203231,36923,0564,8625,3339,5681,5689413141,412203327,26920,0424,2274,6368,3171,3638182731,227203427,04719,8804,1924,5988,2491,3528112701,217203526,81719,7114,1574,5598,1791,3418052681,207203625,90819,0424,0164,4047,9021,2957772591,166203725,89719,0344,0144,4027,8991,2957772591,165203825,88819,0284,0134,4017,8961,2947772591,165203925,88019,0224,0114,4007,8931,2947762591,165204025,87319,0174,0104,3987,8911,2947762591,164

## Appendix B. Texas County Grou pings 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 De pth 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”)