ATTACHMENT D

SPECIFIED OIL AND GAS WELL ACTIVITIES EMISSIONS INVENTORY UPDATE
SPECIFIED OIL & GAS WELL ACTIVITIES 

EMISSIONS INVENTORY UPDATE

FINAL REPORT

Prepared for:

Texas Commission on Environmental Quality

Air Quality Division

Prepared by:

Eastern Research Group, Inc.

August 1, 2014

www.erg.com
ERG N0. 0292.03.026.001

Specified Oil & Gas Well Activities Emissions Inventory Update

FINAL REPORT

Prepared for:

Michael Ege

Texas Commission on Environmental Quality

Air Quality Division

Building E, Room 245 S

Austin, TX 78711-3087

Prepared by:

Bryan Lange

Mike Pring

Stephen Treimel

Eastern Research Group, Inc.

1600 Perimeter Park Dr., Suite 200

Morrisville, NC 27560

August 1, 2014
Table of Contents

List of Acronyms.............................................................................................................. iii

Executive Summary..........................................................................................................iv

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

Purpose of This Study ......................................................................................... 1-1

2. Oil and Gas Producing Regions in Texas........................................................... 2-1

3. Hydraulic Pump Engines ................................................................................... 3-1

3.1 Literature Review.................................................................................... 3-1

3.1.1 Oil and Gas Emission Inventory, Eagle Ford Shale – Technical 

Report........................................................................................... 3-1

3.1.2 Hydraulic Technology – Optimizing Completion Design for the 

Eagle Ford Shale ..........................................................................3-4

3.1.3 Comparing Emissions from Hydraulic Operations Using Activity 

Data and Fuel Consumption........................................................3-6

3.1.4 Hydraulic Stimulation in the Haynesville Shale.......................... 3-7

3.2 Hydraulic Pump Engine Survey and Findings ....................................... 3-7

3.3 Recommendations for Using the Survey Findings............................... 3-10

3.4 Hydraulic Pump Engine Emission Factors .......................................... 3-10

4. Mud Degassing................................................................................................... 4-1

4.1 Available Mud Degassing Emission Factors...........................................4-2

4.2 Mud Degassing Vendor Data .................................................................. 4-5

4.3 Mud Degassing Survey Findings ............................................................4-6

4.4 Mud Degassing Emission Factors........................................................... 4-7

5. NSPS Subpart OOOO Inventory Evaluation ......................................................5-1

5.1 Construction, Modification, Reconstruction, and Affected Facilities.... 5-2

5.2 Effect of NSPS Subpart OOOO on the TCEQ Oil and Gas Nonpoint Area 

Source Oil and Gas Emissions Inventory ............................................... 5-2

5.3 Natural Gas Well Completions ............................................................... 5-3

5.4 Pneumatic Controllers .......................................................................... 5-10

5.5 Oil and Condensate Storage Vessels ......................................................5-11

6. Conclusions ........................................................................................................ 6-1

Attachment A Hydraulic Pump Survey Letter ............................................................A6-1

Attachment B Mud Degassing Survey Letter................................................................ 6-1

Attachment C Survey Results (TCEQ Hydraulic Pump Engine Study Findings.xlsx). C-1

i
Attachment D Updated Oil and Gas Nonpoint Area Source Emissions Estimation Tool 

(ERG Appendix E_2013 with updates to Basin information.xlsx) ..............................D-1

List of Tables

Table 3-1. Emission Factors Used for Calculating Engine Emissions.............................3-3

Table 3-2. Emission Models Used for Estimating Emissions .........................................3-6

Table 3-3. Hydraulic Pump Engine Survey Data, by Region...........................................3-9

Table 3-4. Companies Responding to the Survey............................................................3-9

Table 3-5. Hydraulic Pump Engine Emission Factors ..................................................3-10

Table 4-1. Mud Degassing Vented Emission Factors ..................................................... 4-4

Table 4-2. Basin-Level and State-Level Average Natural Gas Stream Composition 

Profiles............................................................................................................................. 4-8

Table 4-3. Mud Degassing Composition (Gas Wells)..................................................... 4-9

Table 4-4. Mud Degassing Composition (Oil Wells)...................................................... 4-9

Table 5-1. NSPS Subpart OOOO Summary...................................................................... 5-1

Table 5-2. Gas Well Completions.....................................................................................5-3

Table 5-3. New Gas Wells 10/15/12 – 12/31/13.............................................................5-10

Table 5-4. Updated Basin-Weighted Average Bleed Rate (Gas Wells) ..........................5-11

Table 5-5. Percentage of 2013 Oil and Condensate Production Subject to Subpart OOOO 

Requirements .................................................................................................................5-16

List of Figures

Figure 2-1. Oil and Gas Basins in Texas...........................................................................2-2

ii
List of Acronyms

Acronym Definition

AACOG Alamo Area Council of Governments

AP-42 U.S. EPA’s Compilation of Air Pollutant Emission Factors

API American Petroleum Institute

bbl Barrel

BPA Beaumont-Port Arthur

BTEX Benzene, Toluene, Ethylbenzene, Xylene

CenSARA Central States Air Resource Agencies

CO Carbon Monoxide

CO2 Carbon Dioxide

EDF Environmental Defense Fund

EPA U.S. Environmental Protection Agency

ERG Eastern Research Group, Inc.

ENVIRON Environ International Corporation

HGB Houston-Galveston-Brazoria

lbs Pounds

MMscf Million standard cubic feet

NOx Oxides of Nitrogen

NSPS New Source Performance Standard

PM10 Particulate Matter less than10 microns in aerodynamic diameter

PTE Potential to Emit

ppm Parts per million

psig Pounds per square inch gauge

RRC Railroad Commission of Texas

scf Standard cubic feet

SO2 Sulfur Dioxide

TCEQ Texas Commission on Environmental Quality

TCAT Texas Center for Applied Technology

TERP Texas Emissions Reduction Plan

tpy Tons per year

VOC Volatile Organic Compound

UBD Under-balanced drilling

URS URS Corporation

iii
Executive Summary

Eastern Research Group, Inc. (ERG) is currently under contract with the Texas 

Commission on Environmental Quality (TCEQ) under Work Order No. 582-11-99776-

FY14-26 to provide nonpoint area source oil and gas emissions inventory estimates for 

mud degassing activities and hydraulic pump engines used at well drilling sites in Texas. 

ERG also determined the effects of the provisions of the recently revised New Source 

Performance Standards (NSPS) Subpart OOOO (Standards of Performance for Crude 

Oil and Natural Gas Production, Transmission and Distribution) on the 2013 emissions 

inventory estimates. This report describes ERG’s findings relative to survey efforts 

undertaken to collect information on mud degassing activities and the use of hydraulic 

pump engines in the eight oil and gas basins found in Texas, an analysis of available 

mud degassing and hydraulic pump engine emission factor data, and an examination of 

the effects on emissions from the equipment located at upstream oil and gas sources as 

the requirements of Subpart OOOO are implemented.

Drilling mud is a blend of water, oil, or synthetic fluids, special clays, and other 

additives. Mud is used during drilling to cool and lubricate the drill bit, remove cuttings 

to the surface, and control pressure in the wellbore. As drilling proceeds through gasbearing formations, gas becomes entrained in the drilling mud. After the mud comes to 

the surface, the entrained gas is released, resulting in volatile organic compound (VOC)

and methane emissions. 

Hydraulic pump engines are used during well completions to inject mixtures of water, 

proppants, and other additives at high pressure into petroleum-bearing rock formations 

to create fissures in the rock. The resulting fissures increase the conductivity of the 

source rock, increasing the flow rate of petroleum liquids and gas to the wellbore. This 

technique improves hydrocarbon recovery rates in petroleum-bearing formations that 

would otherwise be unproductive. The engines are typically diesel-fired engines and are 

a source of nitrogen oxides (NOx), carbon monoxide (CO), VOC, and particulate matter 

(PM) emissions. These emissions typically occur only once during the completion of a 

well, but are significant in magnitude.

NSPS Subpart OOOO requires operators of certain equipment at upstream oil and gas 

production sites to control emissions from that equipment beginning in October 2012. 

These requirements only apply to equipment newly constructed or modified after 

August 23, 2011. As new wells are completed each year to replace older, non-productive 

wells, the requirements of Subpart OOOO will apply to an increasing percentage of the 

wells in Texas over time. Total emissions from the classes of affected equipment will 

continue to decrease over time as more equipment becomes subject to Subpart OOOO 

control requirements.

iv
ERG recommends that the TCEQ calculate emissions from mud degassing activities 

during well drilling using county-level well spud data and the emission factor data 

obtained under this study. ERG recommends that the TCEQ calculate emissions from 

hydraulic pump engines based on the county-level horizontal well completion data and 

the activity and emission factor data obtained under this study. ERG recommends that 

the TCEQ calculate emissions from Subpart OOOO affected facilities based on countylevel data on the number of new well completions since October 2012, Subpart OOOO 

emission standards, and the emission factors developed in this and previous studies.

v
1. Introduction

Eastern Research Group, Inc. (ERG) is currently under contract with the Texas 

Commission on Environmental Quality (TCEQ) under Work Order No. 582-11-99776-

FY14-26 to provide updates to TCEQ’s nonpoint area source oil and gas emissions 

inventory estimates. Specifically under this effort, ERG evaluated activity and emissions 

data needed to characterize typical emissions from hydraulic pump engines and mud 

degassing equipment located at upstream oil and gas production sites in Texas. 

Information relative to this analysis was obtained through a survey of oil and gas 

producers operating in Texas, as well as a comprehensive literature review and 

interviews with industry experts familiar with the operating characteristics and any 

ongoing studies for these processes.

In addition, ERG evaluated the effects of the provisions of the recently revised New 

Source Performance Standards (NSPS) Subpart OOOO (Standards of Performance for 

Crude Oil and Natural Gas Production, Transmission and Distribution) on the inventory 

estimates. The results of these analyses were then used to update TCEQ’s nonpoint area 

source oil and gas emissions inventory calculator.

Purpose of This Study

The purpose of this study is to develop and refine the methodologies and 

characterization factors needed to generate emission estimates from hydraulic pump 

engines and mud degassing activities at oil and gas wells across Texas, as well as to 

evaluate and incorporate controls required under NSPS Subpart OOOO. This was 

accomplished by:

• Conducting a review of available literature;

• Conducting a phone and email survey of Texas oil and gas producers;

• Researching the availability of emission factors specific to hydraulic pump 

engines and mud degassing;

• Analyzing the requirements of NSPS Subpart OOOO; and

• Proposing control factors and revised operating/equipment parameters to reflect 

the requirements of the NSPS.

ERG first conducted a review of available literature, looking for data on emissions from 

mud degassing, hydraulic pump engines, and the impacts of NSPS Subpart OOOO, 

which affects new or modified sources as early as August 2011, dependent upon 

equipment type. Academic and technical literature on equipment characterization,

emissions control techniques, and available state and federal environmental agency 

guidance on calculating emissions from these operations were examined. Additionally, 

ERG conducted a targeted phone survey of Texas oil and gas producers, requesting 

information on the use of hydraulic pump engines and mud degassing operations at 

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their oil and gas wells. Several oil and gas producers were interviewed, to gather 

information on current practices and trends in the industry that are specific to Texas.

Using this information, ERG developed region-specific activity data and emission 

factors for use in updating the statewide oil and gas nonpoint area source emissions 

inventory for the source categories of interest. 

1-2
2. Oil and Gas Producing Regions in Texas

There are several distinct oil- and gas-producing regions in Texas. These regions, also 

referred to as basins, reservoirs, source rock, or productive formations, are 

characterized by differences in petrogeology, age, depth below surface, type of 

petroleum hydrocarbon produced (liquids, gas, both), and many other characteristics 

that make them unique from one another. Even within a single region, there exists

considerable heterogeneity. These differences are very important for evaluating the 

emissions that occur from production activities at wells in these basins. Drilling 

companies, fracturing companies, and production companies (operators) utilize 

practices that may be unique to each region, and emissions from their activities can vary 

accordingly. This study accounts for these differences, where they are known.

Figure 2-1 identifies eight oil and gas basins found in Texas. These basin boundaries are 

determined at the level of the county, and are based on geographical areas having 

similar petrogeology. By doing this, emissions from oil and gas production activities can 

be more accurately allocated to a county, based on county-level activity and production 

data, and emission factors determined at the basin-level. Note that the Eagle Ford Shale 

has historically been considered part of the Western Gulf Basin for inventory purposes, 

but due to the recent high level of activity in this area, it has been broken out as a 

separate region to more accurately characterize the unique types of processes and 

operations occurring to develop this play.

TCEQ’s nonpoint area source air emissions inventory estimates for upstream oil and gas 

operations are based on county-level activity and equipment/emissions profiles. Activity

data, such as oil and gas well counts and oil and gas production are as reported by the

Railroad Commission of Texas (RRC)1. The equipment characterization and emissions

data used in the inventory has been developed and refined over the last several years 

from a variety of studies, including TCEQ’s “Characterization of Oil and Gas Production

Equipment and Develop a Methodology to Estimate Statewide Emissions” 2 and a 2012 

study “2011 Oil and Gas Emission Inventory Enhancement Project for CenSARA 

States” conducted by the Central States Air Resources Agencies (CenSARA).3

1 2013 oil and gas activity data provided by the TCEQ, based on a January 2014 extract of information by the 

RRC and provided to the TCEQ in March 2014. 2 “Characterization of Oil and Gas Production Equipment and Develop a Methodology to Estimate Statewide 

missions”, TCEQ, November 24, 2010. 3 “2011 Oil and Gas Emission Inventory Enhancement Project for CenSARA States”, Environ International 

Corporation and Eastern Research Group, Inc. December 21, 2012.

2-1

 
Figure 2-1. Oil and Gas Basins in Texas

This study sought to build upon these previous efforts to determine:

• Equipment characteristics and operational profiles of hydraulic pump engines 

used to stimulate wells in Texas;

• The appropriate emission factors to use for hydraulic pump engines used in 

Texas;

• The types of drilling mud used to drill oil and gas wells in Texas;

• The appropriate emissions profile data to use for mud degassing during oil and 

gas well drilling in Texas; and

• The implications of the recent revisions to the NSPS Subpart OOOO on the TCEQ 

nonpoint area source oil and gas emissions inventory.

2-2 
3. Hydraulic Pump Engines

ERG investigated the use of hydraulic pump engines at drilling sites in Texas. The intent 

of this part of our study was to determine the frequency, quantity, location, and 

operating characteristics of these activities across the state, so that these emissions 

could be more accurately estimated in the TCEQ’s nonpoint area source inventory. In 

arriving at the determinations presented in this report, ERG conducted a literature 

review, conducted a survey of oil and gas producers, gathered data on well completions 

from the RRC, reviewed data on engine emission factors, and interviewed industry 

representatives.

Hydraulic fracturing or stimulation involves the high pressure injection of a mixture of 

water, sand, proppants, and small amounts of chemicals and additives, to create fissures 

or fractures in rock formations. The fissures and fractures created during these

operations stimulate an increase in the flow of natural gas and liquid hydrocarbons from 

the productive formation to the wellbore.4 Hydraulic stimulation is used in petroleumbearing formations that would normally be non-productive due to low porosity or 

permeability.5 The intent is to increase the rate of recovery of petroleum liquids and gas 

from the reservoir surrounding the wellbore. Hydraulic stimulation is an expensive 

process, costing $135,000 or more per well6, so operators use it when they judge that 

the increased productivity of the well will pay for the cost of this additional step.

3.1 Literature Review

ERG conducted a review of recent literature on well drilling techniques in general and 

hydraulic stimulation practices in particular, with the intent to gain a better

understanding of the technique and the equipment required. ERG also reviewed 

literature on the petroleum geology in Texas, examining how well stimulation practices 

vary between the different oil and gas-producing formations in Texas. The following 

studies, articles, and web pages were found to be relevant.

3.1.1 Oil and Gas Emission Inventory, Eagle Ford Shale – Technical Report

The Alamo Area Council of Governments (AACOG), in cooperation with the TCEQ, 

published a study in April 2014, entitled “Oil and Gas Emission Inventory, Eagle Ford 

4 Ginna Rodriguez and Chenchen Ouyang, “Air Emissions Characterization and Management For Natural Gas 

Hydraulic Fracturing Operations In the United States”, Masters Thesis project, Univ. of Michigan, April 2013. 5 Porosity of a rock is a measure of the empty spaces) in a material, and is a fraction of the volume of void spaces 

divided by the total volume. Permeability is a measure of the ability of a material (such as rocks) to transmit 

fluids. 6 These are average cost figures for a USA well in 2011. Source: Michael Economides, “Hydraulic Fracturing: The 

State of the Art”, Energy Tribune, August 26, 2011. Online: http://www.energytribune.com/8672/hydraulicfracturing-the-state-of-the-art-2#sthash.rjPkQxRS.dpbs

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Shale”.7 This study focused exclusively on the oil and gas operations in the Eagle Ford 

Shale formation in south Texas. The study examined the unique characteristics of the 

geology, hydrocarbon production, and production equipment used in the Eagle Ford 

Shale, and developed an air emissions inventory for oil and gas operations located in 

that region. The study gathered data on production, drill rig counts, well counts, well 

characteristics, and nonroad equipment from the RRC, companies that provide 

hydraulic pumping services,8 TCEQ, oil and gas companies, and previous studies to 

compile a comprehensive view of the type and amount of equipment currently in use. 

The study then combined these activity data parameters with emissions factors from 

TCEQ’s Drill Rigs Emission Inventory,9 equipment manufacturers, the results of Texas 

Center for Applied Technology (TCAT) surveys,10 and other sources, to develop an air 

emissions inventory. The study also examined development trends in the region, and, 

based on predicted production increases in the future, developed estimates of air 

emissions for 2015 and 2018 under three development scenarios.11

Of particular significance to this present study is the fact that the AACOG study 

estimated emissions from the use of hydraulic pump engines in the Eagle Ford Shale for 

the year 2012. The study examined data on hydraulic stimulation activity from studies 

done on other shale plays such as in Colorado,12 the Marcellus Shale13 in the northeast, 

the Barnett14 and Haynesville15 Shales in Texas, and from studies done by Ohio EPA and 

7 This study was finalized by the authors on November 30th, 2013 and accepted as final by TCEQ on April 4, 

2014. 8 Schlumberger, Baker-Hughes, and Halliburton are three of the largest companies providing hydraulic pumping 

services for the oil and gas production industry. 9 Texas Commission on Environmental Quality, “Development of Texas Statewide Drilling Rigs Emission 

Inventories for the Years 1990, 1993, 1996, and 1999 through 2040”, by Eastern Research Group, Inc., August 

15, 2011. Online: 

http://www.tceq.texas.gov/assets/public/implementation/air/am/contracts/reports/ei/5821199776FY1105-

20110815-ergi-drilling_rig_ei.pdf 10 Texas Center for Applied Technology (TCAT), “Environmentally Friendly Drilling Systems Program Hydraulic 

Fracturing Phase Emissions Profile (Air Emissions Field Survey No. 1)”, Nov. 2011. 11 The study predicted air emissions under low, medium and high development scenarios. These development 

scenarios were based on estimates of ultimate recoverable reserves from the region, the number of drill rigs 

available, interviews with industry representatives about their plans for future development, production decline 

curves for wells in the region, and the prices for natural gas and petroleum liquids. 12 Amnon Bar‐Ilan, John Grant, Rajashi Parikh, Ralph Morris, ENVIRON International Corporation, “Oil and Gas 

Mobile Sources Pilot Study”, July 2011. Online: http://www.wrapair2.org/documents/2011-

07_P3%20Study%20Report%20(Final%20July-2011).pdf 13 All Consulting, “NY DEC SGEIS Information Requests”. Prepared for Independent Oil & Gas Association, 

Project no.: 1284, Sept. 16, 2010. Online: 

http://catskillcitizens.org/learnmore/20100916IOGAResponsetoDECChesapeake_IOGAResponsetoDEC.pdf 14 Al Armendariz, “Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for CostEffective Improvements”, Prepared for Environmental Defense Fund, Jan. 26, 2009. Online: 

http://www.edf.org/sites/default/files/9235_Barnett_Shale_Report.pdf 15 John Grant, Lynsey Parker, Amnon Bar-Ilan, Sue Kemball-Cook, and Greg Yarwood, ENVIRON International 

Corporation, “Development of an Emission Inventory for Natural Gas Exploration and Production in the 

Haynesville Shale and Evaluation of Ozone Impacts”, August 31, 2009. Online: 

http://www.netac.org/UserFiles/File/NETAC/9_29_09/Enclosure_2b.pdf

3-2

 
the U.S. Dept. of Interior.16 The AACOG study’s authors also interviewed industry 

representatives, gathering information on how hydraulic stimulation equipment and 

processes have changed over time. The interviewers gathered information on: engine 

horsepower, the average amount of time it took to fracture a well, the number of 

fracturing stages, load factor, and the amount of water used. Like this study, the 

previous studies cited in the AACOG report used engine count, engine horsepower, 

hours of operation, and load factor to determine the emissions from a typical hydraulic 

fracturing job. Unlike this present study, the AACOG report used aerial imagery as part 

of their basis for estimating the number of hydraulic pump engines used at sites in the 

Eagle Ford Shale. Although imagery from 14 sites indicated that an average of 13.9 

engines were used, the study’s authors choose to use 12 engines per site in their 

emissions calculations, based on data from other studies and information obtained from 

local fracturing companies. The AACOG study based their load factor (30%) on 

information collected from hydraulic pump operators in the Eagle Ford play. The factors 

used in the AACOG study for calculating engine emissions from hydraulic fracturing are 

shown in Table 3-1.

Table 3-1. Emission Factors Used for Calculating Engine Emissions

Factor Description Factor and Units Source:

Number of Engines 12 / job TCAT Eagle Ford Survey, ERG's Fort Worth Natural Gas Study, 

Aerial Imagery, Local Sources

Engine Horsepower 2,250 hp TCAT Eagle Ford Survey, ERG's Drill Rig Emission Inventory for 

TCEQ

Total Hours per Job 54 hrs / job ENVIRON’s Haynesville Shale Report

Load Factor 30% Local Sources

Engine Emission Factors 4.56g NOx/hp-hr

0.24g VOC/hp-hr

2.67g CO/hp-hr

TCEQ’s TERP emission factors for Tier 2 Engines17

TCEQ’s TERP emission factors for Tier 2 Engines

TexN Model18

Thus, the AACOG study concluded that the total power expended by hydraulic pump 

engines to stimulate a typical well in the Eagle Ford Shale is 437,400 hp-hr.

The study noted that hydraulic stimulation practices have changed in the last few years, 

and described some of those changes. As more wells are completed in the Eagle Ford

play, operators gain a better understanding of what works best in the geologic 

conditions presented by the source rock in the Eagle Ford Shale. A careful comparison 

16 U.S. Department of the Interior, Bureau of Land Management, “Tumbleweed II Exploratory Natural Gas Drilling 

Project”, DOI-BLM-UTG010-2009-0090-EA, June 2010. Online: 

http://www.blm.gov/pgdata/etc/medialib/blm/ut/lands_and_minerals/oil_and_gas/november_2011.Par.24530.Fil

e.dat/ 17 TCEQ, April 24, 2010. “Texas Emissions Reduction Plan (TERP): Emissions Reduction Incentive Grants 

Program Technical Supplement No. 2, Non-Road Equipment”. 18 TCEQ, August 18, 2008, Texas NONROAD (TexN) Model Version 1.0, Online: 

ftp://amdaftp.tceq.texas.gov/pub/Nonroad_EI/TexN/TexN_Users_Guide.pdf

3-3

 
of the AACOG study data and that from studies of hydraulic completions in other shale 

plays revealed that the techniques in the Eagle Ford that produce the best results are 

qualitatively different than those practices that lead to good results in other plays. This 

will be examined further in the next study reviewed for this report.

3.1.2 Hydraulic Technology – Optimizing Completion Design for the Eagle 

Ford Shale

ERG reviewed two studies published in The American Oil and Gas Reporter that 

detailed new approaches to hydraulic fracturing in the Eagle Ford Shale.

A study entitled “Approach Optimizes Completion Design”, published in the August 

2011 edition of The American Oil and Gas Reporter19 examined the effect of a reservoirspecific completion strategy that accounts for the site-specific characteristics of the 

reservoir rock. The source rock at a well in DeWitt County was studied prior to 

fracturing. Analysis revealed that the reservoir rock was a clay-rich limestone with low 

quartz content and a low Young’s modulus,20 compared to the rock in the Barnett Shale, 

which is a very brittle siltstone with a high Young’s modulus. The study examined how 

the properties of the reservoir rock played a role in determining what fracturing 

procedures and materials would provide the best results in opening the reservoir rock to 

allow the maximum gas and liquids to flow to the wellbore. Whole core data from a 

vertical section and mud log data from the lateral section were examined for the rocks’ 

petrophysical characteristics and used to develop a completion strategy for each stage of 

the completion. The fluid mix was designed to control clay swelling, decrease the 

viscosity of the fluid over time, and inject larger than normal sized proppants to account 

for the relative softness of the rock. The large proppants were chosen to prevent 100% 

embedment of the proppant in the fracture face, which would, in effect, seal up the 

fractures that the hydraulic pumps create during the process. Each stage of the lateral 

was completed differently to account for changes in the brittleness/ductility index of the 

rock. Production data from the well, compared to that from other wells, showed that the 

production on this hybrid completion was superior to that produced from similar wells 

completed in the Eagle Ford using slick-water fracs.21 The study authors concluded that 

the higher conductivity achieved with the hybrid completion accounted for the higher 

production.

19 The American Oil and Gas Reporter, “Approach Optimizes Completion Design”, R. Borstmayer, N. Sargent, A. 

Wagner, and J. Mullen, August 2011. 20 Young’s Modulus is a measure of the stiffness of an elastic isotropic material and is used to predict how much a 

material sample extends under tension or shortens under compression. It might also be considered a measure of 

the brittleness or ductility of the rock. 21 Compared to production from the three slick-water fraced wells examined in the study, production from the 

hybrid fraced well ranged from 750 – 2,250% higher, based on barrel oil equivalent production of gas and oil.

3-4

 
This 2011 study, published in a widely-available industry publication, showed that using 

a site-specific hybrid completion technique unique to the Eagle Ford Shale can increase 

well production by significant margins over using a completion technique typically used 

in other shale plays. ERG assumes that all other fracturing companies working in the 

Eagle Ford will quickly adopt these techniques. Although the study did state that the 

lateral length was 3,800 feet, it did not publish any information on the engine power or 

time spent to fracture each of the 11 stages. Therefore, total engine power requirements 

for this well could not be compared to the results from other studies conducted on other 

shale plays.

A study entitled “Pilot Wells Test Stimulation Approach”, published in the June 2011 

edition of The American Oil and Gas Reporter22 examined the effect of monitoring realtime microseismic activity in the reservoir rock during hydraulic fracturing for two 

wells. The study examined the effect of changing the hydraulic pumping schedule 

(pressure, time, proppants) using the microseismic monitoring, and found that “a 

stimulation technique that uses a shutdown during pumping to allow pressure 

relaxation, or equilibration, prior to reinitiating the fracturing process proved highly 

successful in increasing the estimated stimulated volume (ESV) in the reservoir rock.”

The stimulation team changed their techniques for each stage of fracturing, varying the 

pressure and timing, based on the microseismic results from previous stages, with the 

intent to contain the fracturing within the target zone (which ranges from 100 to 300+ 

feet thick). The production logs from the wells showed positive correlation “between 

production contribution and the ESV derived from the analysis of microseismic 

monitoring done during hydraulic stimulation.” For the first well, pressure was slowly 

increased for each stage, containing the fracture in the target zone. For the second well, 

the stimulation team utilized significant variations in pumping pressure for five of the 

seventeen stages, to allow pressure relaxation for a period of 2 – 14 hours, prior to 

resuming pumping and finishing the fracture stage.

This article reported average lateral lengths were greater than 5,000 feet, and the 

number of stages at 10 -17 per lateral. The study did not publish any information on the 

engine power or time spent to hydraulically stimulate either of these wells. Therefore, 

total engine power requirements for these wells could not be compared to the results 

from other studies conducted on other shale plays.

22 The American Oil and Gas Reporter, “Pilot Wells Test Stimulation Approach” A. Inamdar, T. Ogundare, D. 

Purcell, R. Malpani, K. Atwood, K. Brook, and A. Erwemi, June 2011.

3-5

 
3.1.3 Comparing Emissions from Hydraulic Operations Using Activity Data 

and Fuel Consumption

A Masters’ Thesis project examined emissions from hydraulic stimulation operations in 

both the Eagle Ford Shale and the Marcellus Shale.23 This study was unique in that the 

authors evaluated five air emissions models: three models were based on activity levels 

per source and two models were based on fuel consumption per source. The three 

models based on activity levels used data and methodology similar to that used in the 

AACOG study described above, the differences being in the use of load factors and 

emission factors. The general equation for these three activity-based models is: 

Emissions = emission factor x horsepower x load factor x operating time.

The models based on fuel consumption differed in that one used total fuel consumption 

and AP-42 emission factors24 while the second calculated emissions based on fuel 

consumption rate, hours of operation, and EPA Nonroad Tier 2 standards.25 Both fuel 

consumption models used a constant for fuel density (7.11 lb/gal) and brake-specific fuel 

consumption for the equipment. The general equation for the two fuel usage models is: 

Emissions = emission factor x brake-specific fuel consumption x fuel density x fuel 

consumption

The authors collected detailed engine activity and fuel usage data26 from two well 

fracturing sites and applied it to the five models. The five models are described in 

Table 3-2.

Table 3-2. Emission Models Used for Estimating Emissions

Model Source of Engine Emission Factors Assumptions27

Activity Model 1 U.S.EPA – AP-42, Chapter 3.4 100% Load

Activity Model 2 U.S.EPA – AP-42, Chapter 3.4 Average Load, based on local data

Activity Model 3 U.S.EPA – Nonroad Tier 2 standards Average Load, based on local data

Fuel Usage Model 1 U.S.EPA – AP-42, Chapter 3.4 100% Load

Fuel Usage Model 2 U.S.EPA – Nonroad Tier 2 standards Average Load, based on local data

23 Ginna Rodriguez and Chenchen Ouyang, “Air Emissions Characterization and Management For Natural Gas 

Hydraulic Fracturing Operations in the United States”, Masters Thesis project, Univ. of Michigan, April 2013. 24 Emission factors were from AP-42, Chapter 3.4, Large Stationary Diesel and All Stationary Dual-fuel Engines, 

October 1996. 25 All of the frac pump engines in the study were Tier 2 models. 26 The authors determined that the average fuel used for a fracturing job is 22,100 gallons for the Eagle Ford Shale 

and 20,800 gallons for the Marcellus Shale. 27 The average load factor is based on data collected onsite, and then weighting different loads during different 

portions of the job over the total time the frac pumps are used. For Fuel Usage Model 2, the fuel consumption 

rate is based on average load.

3-6

 
Total emissions were calculated from the engines used to power the hydraulic pumps, 

blender, frac control unit, hydration unit, sand king, and water transfer pump for each 

of the five models. By comparing results from the five models, the authors found that 

the magnitude of emissions is most sensitive to the emission factor and the load factor 

for the engines. The study found that emissions from the hydraulic pump engines 

account for 83-94% of all emissions from the engines used in hydraulic fracturing 

operations.

3.1.4 Hydraulic Stimulation in the Haynesville Shale

The Halliburton Company, a major provider of hydraulic pump services, produced a 

short brochure on the complex, heterogeneous conditions in the Haynesville Shale.28

The brochure included the following information:

• The Haynesville Shale is approximately 10,500–13,500 ft deep, and its porosity is 

higher than other shales, indicating its ability to contain more gas;

• It has higher reservoir pressure than other North American unconventional shale 

plays;

• Average well vertical depths are 11,800 ft with bottomhole temperatures 

averaging 330°F, and wellhead treating pressures during stimulation commonly 

exceeding 10,000 psi. As a result, wells here require almost twice the amount of 

hydraulic horsepower29 and more advanced fluid chemistry than other shale 

plays in the Southern U.S.; and

• In these deep wells, with fracture gradients of 1 psi/ft and low Young’s modulus, 

there is also concern about the ability to sustain production with adequate 

fracture conductivity.

Based on the low Young’s modulus, ERG would expect that the proppants used in the 

Haynesville Shale would be similar to that used in Eagle Ford Shale (e.g., larger in size), 

in order to maintain fracture conductivity to the wellbore after the fracture process is 

completed. 

3.2 Hydraulic Pump Engine Survey and Findings

The hydraulic pump engines survey targeted oil and gas production companies and 

attempted to obtain information on the use of hydraulic pump engines during well 

completion activities at oil and gas wells. The companies targeted had significant recent 

activity in the six regions of interest for the survey. 

28 Halliburton, Haynesville Shale, http://www.halliburton.com/en-US/ps/solutions/unconventional-resources/shalegas-oil/shale-plays/haynesville-shale.page?node-id=hgjyd46z and http://www.halliburton.com/enUS/ps/solutions/unconventional-resources/shale-gas-oil/shale-plays/haynesville-shale.page?node-id=hgjyd46z

29 While ERG’s survey results for wells in the Haynesville Shale of East Texas appear to be at odds with this claim, 

the one company that submitted survey data gave us data for 7 vertical wells. The Halliburton Company is 

referencing the amount of hydraulic horsepower needed for stimulation of horizontal wells.

3-7

 
For the hydraulic pump engine survey, ERG attempted to contact persons at oil and gas 

production companies who were responsible for environmental and regulatory 

compliance. Letters were sent to a total of 93 contacts at 86 separate regional company 

offices located in Texas, Oklahoma, and surrounding states. The letters explained the 

survey, requested cooperation in gathering data, and included sample data collection 

forms. The survey letter requested data on the location, the type of well, the number of 

engines used, the horsepower of the engines, the percent full load for the engines, the 

number of fracturing stages, and the duration of each fracturing stage. The companies 

selected were identified from previous TCEQ surveys as companies which had provided 

data, and from the RRC database as operating companies that completed a significant30

number of wells in the targeted basins during the year 2013. See Attachment A for the 

hydraulic pump engine letter and survey materials.

ERG followed up the letters with phone calls to each company contact until contact was 

made. In many cases, emails were sent to the company, either as a follow up to a 

telephone conversation, or in the event no telephone contact could be made. During 

phone calls, ERG requested participation and explained the survey to potential 

respondents. 

ERG collected data on the use of hydraulic pump engines used during well 

completions for 79 wells from nine companies. The survey asked questions about:

• Location (County);

• Type of well (oil or gas well);

• Number of engines used;

• Horsepower of the engines;

• Percent full load for the engines;

• Number of fracturing stages; and

• Duration of each fracturing stage.

The data submitted for these 79 wells was compared with RRC data on the actual 

number of horizontal and vertical wells completed by each reporting company in 2013, 

by region and county, well type (oil or gas) and wellbore profile (horizontal, vertical, 

directional). The data was compiled into a spreadsheet, sorted by region, and 

calculations were performed to determine basin and state averages. This data is shown 

in Table 3-3:

30 For purposes of this survey, a ‘significant’ number of wells completed by an operating company in 2013 ranged 

from 12 to over 100. Companies were found by querying the RRC database on the number of well completions, 

by district. 

3-8

 
Table 3-3. Hydraulic Pump Engine Survey Data, by Region

Basin

Average 

Number 

of Engines

Average 

Horsepower 

Average % 

Load 

Average 

Number of 

Fracturing 

Stages

Average 

Duration 

of each 

Stage 

(hours)

Average 

Total 

Horsepowerhours Per 

Job

Anadarko Basin 15 2200 48% 10.4 1.58 254,563 

Eagle Ford Shale 23 2290 76% 16.6 2.28 1,223,667 

East Texas 

Basin/Haynesville 

Shale 8 1814 36% 2.1 1.04 11,271 

Permian Basin 10 2313 36% 16.8 1.38 266,639

Statewide 

Average 14 2154 49% 11.5 1.57 439,035

Seven (7) additional companies responded to the survey with information to the effect 

that “Our company has not fractured any wells in those counties in 2013.” ERG 

considered this to be useful information, as it provided information on those newly 

completed wells that were not hydraulically stimulated.

ERG obtained information on all 16 company’s wells from the RRC database31 for the 

basins of interest. This data included the region and county, well type (oil or gas) and 

wellbore profile (horizontal, vertical, directional). The number of wells represented by 

companies that responded but did not fracture any wells typically only represented a few 

wells. Many of these companies produced natural gas, and the market prices for natural 

gas for the past few years have not supported any new exploration. This data is shown in 

Table 3-4.

Table 3-4. Companies Responding to the Survey

Region

Companies 

Who Filled 

Out Survey 

Completely

Companies 

Reporting "No 

Wells 

Fractured"

Number of 

Wells 

Reported

Number of 

Wells 

Completed in 

2013

Wells 

Completed 

in 2013 by 

Reporter

Reporter’s 

2013 Wells 

as % of Total

Anadarko Basin 1 0 8 847 111 13.1%

Eagle Ford Shale 5 0 48 3,182 654 20.6%

East Texas 

Basin/Haynesville 

Shale

1 0 7 678 7 1.03%

Fort Worth 0 1 - - - -

Permian Basin 2 2 16 8,864 382 4.3%

Western Gulf 0 4 - - - -

31 Data for well completions in 2013 was obtained using an operator-specific data query on the Railroad 

Commission website. Online: http://www.rrc.state.tx.us/about-us/resource-center/research/online-researchqueries/

3-9

 
Attachment C contains the results of the hydraulic pump engine survey.

3.3 Recommendations for Using the Survey Findings

ERG recommends that the TCEQ use the findings in Table 3-3 above for estimating 

emissions from hydraulic pump engines. Where basin data was available, it has been 

used. For all other basins, the individual basin factors were averaged to determine a 

statewide value, which was then used in the other basins.

3.4 Hydraulic Pump Engine Emission Factors

For the 2011 base year TCEQ oil and gas nonpoint area source inventory, TCEQ used 

emission factors from the 2012 CenSARA study, which were derived using EPA’s 

NONROAD2008 model. To update these factors for this study, average emission factors 

for 2013 and 2014 inventory years were developed. Using EPA’s NONROAD2008 

model, updated factors were developed based on the oil equipment source category bin 

(SCC 2270010010), and a diesel sulfur content of 15 ppm. Average emission factors were 

developed for engines between 1,000 and 3,000 horsepower, consistent with the engine 

sizes observed in the survey.

Table 3-5 below shows the emission factors for hydraulic pump engines for the 2011, 

2013, and 2014 inventory years. As can be seen in the table, the emission factors have 

decreased over time as new engines replace older engines, resulting in a higher 

percentage of engines subject to the more stringent Tier 4 engine standards.

Table 3-5. Hydraulic Pump Engine Emission Factors

Pollutant 2011 (g/hp-hr)a 2013 (g/hp-hr)b 2014 (g/hp-hr)b

PM10 0.227 0.184 0.172

NOx 5.831 5.081 4.775

CO 1.318 1.076 1.021

VOCc 0.368 0.328 0.317

SO2 0.010 0.0046 0.0045 a 2011 emission factors from CenSARA Inventory.

b 2013 and 2014 emission factors from EPA’s NONROAD Model. c VOC emission factor includes exhaust and crankcase emissions.

To account for this updated hydraulic pump engine information in the inventory, the 

Hydraulic Fracturing Pumps tab of the TCEQ oil and gas nonpoint area source 

emissions estimation calculator was revised as follows: 

• The PM10, NOx, CO, VOC, and SO2 emission factors were updated to the 2013 

values shown in Table 3-5;

• Table A was added to include the hydraulic pump engine operating 

characteristics for each basin from Table 3-3; and

3-10
• In the County-level emissions table: columns H through L were revised to lookup 

the appropriate operating factors from Table A. 

Attachment D contains the updated TCEQ oil and gas nonpoint area source emissions 

estimation calculator (“ERG AppendixE_2013 with updates to Basin information.xls”) 

reflecting the changes to the inventory for hydraulic pump engines using the updated 

operating characteristics and emission factor data in Tables 3-3 and 3-5.

3-11
4. Mud Degassing

Drilling mud is a mixture of special clays and additives with water, oil, or synthetic 

matter. Considerable heat and friction are generated by the drill bit as it removes rock at 

the bottom of the well. During drilling, the drilling mud is continuously pumped 

through the drill string and out through the drill bit. The circulating drilling fluid cools 

and lubricates the drill bit, and moves cuttings upwards through the wellbore toward the 

surface. Mud must have the capacity to suspend the fragments of solid material removed 

by the drill bit. If the mud does not circulate quickly enough, the drilled cuttings in the 

wellbore may accumulate and the drill string may get stuck.

To properly control the drilled materials and cutting suspension, the properties of 

drilling fluid are tested frequently at the rig site by a mud engineer using procedures 

specified in “Recommended Practice for Field Testing Water-Based Drilling Fluids”, API 

Standard Method RP 13B-1. Measured properties include density and viscosity. 

Viscosity must be high enough that the drill cuttings will remain suspended, but low 

enough such that the pumps can overcome the friction and pump the mud up and out of 

the wellbore. Low-viscosity mud allows sand and cuttings to settle out, and gas to escape 

at the surface.32 Mud density must be carefully controlled, and is gradually increased by 

the mud engineer through addition of special additives to the drill mud as the depth of 

the well increases. This is done to counteract formation pressure, which increases with 

depth.

As the drill bit approaches and penetrates oil and gas-bearing layers of rock (the 

producing formation or “play”), the mud engineer must be sure that the weight of the 

column of mud exceeds the pressure of fluids or gases in the productive formation. If 

not, and the subsurface pressure exceeds the downward pressure from the weight of the 

mud in the wellbore, a blowout may occur. Blowouts are both costly and dangerous, and 

drilling companies take extensive measures to prevent them. Still, the RRC records 

indicate that 24 blowouts occurred in Texas in 2013.33

In a broad sense, drilling mud can be classified as water-based, oil-based, synthetic, or 

an emulsion. The term “oil-based” is used for drilling mud prepared from petroleum

distilled liquids, whereas the term “synthetic” is used for drilling mud prepared from 

non-aqueous liquids prepared from the reaction of organic building blocks, such as 

ethylene or methane.34 Water-based muds may be fresh or saltwater based and typically 

include a type of clay that will stay suspended for a time after agitation has stopped. Oil32 Lyons, William C. Working Guide to Drilling Equipment and Operations. Amsterdam: Gulf Pub./Elsevier, 2010. 

<http://public.eblib.com/EBLPublic/PublicView.do?ptiID=535200>. 33 Railroad Commission of Texas, “Blowouts and Well Control Problems”, Online: http://www.rrc.state.tx.us/oilgas/compliance-enforcement/blowouts-and-well-control-problems/ 34 Growcock, Frederick B., and Arvind D. Patel. "The Revolution in Non-Aqueous Drilling Fluids (AADE-11-

NTCE-33)." AADE National Technical Conference and Exhibition Held at the Hilton Houston North Hotel, 

Houston, Texas, April 12-14, 2011. (2011). <http://www.slb.com/resources/technical_papers/miswaco/AADE11-NTCE-33.aspx>.

4-1

 
based and synthetic muds are generally expensive and hard to dispose of, but they are 

well suited for drilling the producing zones of deep, high temperature holes in which 

water-based muds solidify. 35

Under-balanced drilling (UBD) describes a situation in which the hydrodynamic 

pressure of the drilling mud and circulating fluids in the well bore is less than the 

pressure of the well formation. This drilling technique can require surface equipment to 

separate drilling mud and hydrocarbons for recirculation, storage, flaring, and 

disposal.36 UBD can cause a kick or a blowout to occur where there is an influx of 

reservoir fluid or gas into the wellbore. When properly managed, UBD allows for greater 

drilling velocity (aka rate of penetration). 37 When mud is over-balanced, it is forced into 

the surrounding rocks, and the solid particles form a filter or mud cake. This stabilizes 

the sides of the well and prevents subsurface fluids from flowing into the well. Overbalanced drilling is more typical.38

It is common to have a mud gas separator or degasser equipment located at the surface 

of the well to separate and safely remove large pockets of free gas from the drilling mud 

returned to the surface, but one is only used when drilling through the producing 

formation. It is necessary to remove the gas because it reduces the mud weight. Gas 

separators are effective on both water-based and oil-based muds. The vented gas may 

include toxic gases (such as hydrogen sulfide) from the drilling fluids processing system. 

One manufacturer of mud gas separators, GN Solids America, equips their separators 

with an electric ignition device to flare toxic gases.39 Vacuum separators utilize negative 

pressure to withdraw entrained gases from the mud. In order for this to work, mud

exiting the wellbore is pumped through a venturi choke. The pressure drops on the 

outlet side of the choke, enabling the entrained gases to expand and easily separate from 

the drilling mud. Atmospheric separators pump mud into a thin layer, relying on density 

differences between the gas and the mud to liberate gas. One separator design utilizes 

the thin layer approach inside a vacuum chamber to speed separation of gas from the 

drilling mud. 

4.1 Available Mud Degassing Emission Factors

Limited information on the emissions from drilling mud is available, but there is a 

consensus opinion that a 1977 U.S. EPA publication “Atmospheric Emissions from 

35 Lyons, William C. Working Guide to Drilling Equipment and Operations. Amsterdam: Gulf Pub./Elsevier, 2010. 

<http://public.eblib.com/EBLPublic/PublicView.do?ptiID=535200>. 36 LeBlanc, Chris, Marco Amorim, and Roberto Piacentini. "Case Study: a High Throughput Mud-Gas Separator 

for Underbalanced Drilling." Offshore Technology Conference Held in Rio De Jeneiro, Brazil, 4-6 October 2011 37 Personal communication with Bill Brannan of Nicklos Drilling Company. June 6, 2014 38 Oil & Gas Production Protocol, published in February 2010 by The Climate Registry

39 GN Solids America LLC. "Mud Gas Separator - GNZYQ Mud Gas Separator Features and Benefits." Web

Accessed: 11 June 2014. <http://www.gnsolidsamerica.com/mud-gas-separator.html>.

4-2

 
Offshore Oil and Gas Development and Production” 40 is the best currently available 

estimate. The estimate presented in this study is based on engineering calculations of 

emissions from mud degassing at an offshore gas well using a water-based mud. The 

water-based emission rate represents gas liberated from rock drilled out of the wellbore,

when drilling through a producing formation. The calculation assumes a penetration 

rate of 400 feet per day, 25% porosity, and reservoir pressure of 4,000 psig. The oilbased emission rate was calculated by assuming emissions from oil-based drilling mud 

were equivalent to emissions from diesel fuel stored in a fixed-roof storage tank with a 

turnover factor of 0.5.41 The surface area of exposed mud is small. The gases separated 

from the mud in the mud separator are not counted. Although the mud turnover speeds 

vary over the course of the drilling event, this was not considered.

Four recent publications cite the 1977 EPA report as the original source for mud 

degassing factors:

• The American Petroleum Institute (API) publication “Compendium of 

Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry”42

discusses mud degassing, and recommends that “site-specific methane 

concentration data should be used to estimate these emissions”. The API 

document cites the mud degassing emission factors reported by US EPA in 1977.

• The Climate Registry’s “Oil and Gas Production Protocol”43 discusses emissions 

from mud degassing in the case of an underbalanced drilling operation, where 

the pressure in the wellbore is kept lower than the gas and fluid pressure in the 

formation being drilled. However, the discussion lacks a specific formula, and 

states that the volume of gas vented must be measured or estimated based on 

downhole pressure, wellbore diameter, and the duration of underbalanced 

drilling. Although other publications have mentioned that the drilling 

penetration rate is faster, and formation damage is lessened using underbalanced 

drilling, none suggests that underbalanced drilling is used when drilling 

producing shale formations, due to the risk of blowout. The Climate Registry 

document cites the mud degassing emission factors reported by US EPA in 1977.

• A report prepared by ENVIRON and ERG for the CenSARA States44 cites the mud 

degassing emission factors reported by US EPA in 1977; and

• A report prepared by ERG for the TCEQ45 cites the mud degassing emission 

factors reported by US EPA in 1977.

40 "Atmospheric Emissions from Offshore Oil and Gas Development and Production". U.S. Environmental 

Protection Agency, EPA-450/3-77-026, June, 1977. 41 Turnover factor is the ratio of throughput to tank capacity [See US EPA – Office of Air Quality Planning and 

Standards. Compilation of Air Pollutant Emission Factors AP-42, Section 7.1 Organic Liquid Storage Tanks. 

September 2006]. 42 American Petroleum Institute, “Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas 

Industry”, August 2009 43 Climate Registry, “Oil and Gas Production Protocol”, Version 1.0, February 2010. 44 ENVIRON, “2011 Oil and Gas Emission Inventory Enhancement Project for CenSARA States”, prepared for the 

Central States Air Resources Agencies, December 21, 2012. 45 Eastern Research Group, “Offshore Oil and Gas Platform Report - Final Report”, August 16, 2010.

4-3

 
The most generally recognized mud degassing emissions factors are shown in Table 4-1, 

as presented in the API Compendium document. 

Table 4-1. Mud Degassing Vented Emission 

Factors

Mud Type Emission Factor

(tonnes CH4 / drilling day)a

Water-based 0.2605

Oil-based 0.0586

Synthetic 0.0586

a Note: 1 tonne = 1 metric ton = 2, 204.62262 pounds.

Additionally, the following studies were reviewed:

• In a recent study46 published in the Proceedings of the National Academy of 

Sciences, the results of aerial sampling of methane in the air above wells being 

drilled in southwestern Pennsylvania (Marcellus Shale) was examined. The 

authors estimated that 34 grams methane per second was being released from 

wells in the drilling stage. Examination of the gas composition suggested that the 

methane plumes did not come from the shale rock, but arose from shallow coal 

pockets producing coal bed methane as the well was drilled through these 

formations. The methane was not directly attributed to drilling mud.

• A study sponsored by the Arkansas Department of Environment Quality entitled 

“Emissions Inventory & Ambient Air Monitoring of Natural Gas Production in 

the Fayetteville Shale Region”47 examined air emissions from gas production 

activities in the Fayetteville Shale of Arkansas. Ambient monitoring was 

performed around the perimeter of six drilling sites, three hydraulic fracturing 

sites, four compressor stations, and a control site. The study found that 

concentrations of VOC at the sites other than drilling sites were at or below 

instrument detection limits, but that air samples around drilling sites had 

average VOC concentrations around 678 parts per billion.48 The authors 

identified the likely source of VOC emissions as open tanks of oil-based drilling 

mud and cuttings.49 The study did not identify the chemical composition of the 

VOC emissions, nor did it attempt to quantify emissions. The study noted that 

VOC emissions from gas production in the Fayetteville Shale were relatively low 

due to the low VOC content of the gas produced there (0.05% VOC), relative to 

the VOC content of gas produced in the Barnett Shale in Texas (8.2% VOC). Also, 

the Fayetteville Shale is a dry gas with little or no condensable hydrocarbons. 

46 Dana Caulton, et.al., “Toward A Better Understanding And Quantification Of Methane Emissions From Shale 

Gas Development”, April 14, 2014. Online: http://www.pnas.org/content/early/2014/04/10/1316546111.abstract 47 David Lyon & Toby Chu, Arkansas Dept. of Environmental Quality, “Emissions Inventory & Ambient Air 

Monitoring of Natural Gas Production in the Fayetteville Shale Region”, November 22, 2011. 48 Although there is no NAAQS standard for VOC, volatile hydrocarbons do contribute to ozone formation, and 

some of the VOCs produced during oil and gas exploration are also hazardous air pollutants. Without gas 

speciation data, the actual risk posed by these VOCs to the workers is unknown.

49 A company drilling in the Fayetteville Shale reported that an average well required 8.4 days to drill with an 

average lateral length of 4,985 feet, and that drilling normally utilizes oil-based drilling mud.

4-4

 
These two studies show that knowledge of site- or region-specific VOC content of gases 

is necessary for accurately estimating emissions from mud degassing. 

In addition to the literature review, a number of individuals were contacted in an effort 

to determine if there were any current or recent emissions studies directly evaluating 

emissions from drilling mud:

• ERG contacted Dr. David Allen at The University of Texas at Austin. Dr. Allen is 

part of a group researching the climate impacts of natural gas.50 The group’s 

paper “Measurements of methane emissions at natural gas production sites in the 

United States,” made no reference to mud degassing measurements.51 Dr. Allen 

was not aware of any ongoing efforts to further characterize emissions from mud 

degassing.

• ERG contacted API and URS (their contractor and lead author of the 

compendium). Neither was aware of any more recent studies on mud degassing. 

Karin C. Ritter of API was not aware of any such studies either, but agreed to 

relay the TCEQ’s interest in evaluating emissions from mud degassing to API 

members. 52

• ERG also contacted David Lyon, the author of the Fayetteville Shale study 

mentioned above, who is currently with the Environmental Defense Fund (EDF). 

EDF is currently conducting a series of studies looking at emissions from 

upstream and midstream oil and gas exploration and production activities. 

Mr. Lyon was not aware of past or present research into mud degassing beyond 

the studies identified above.53

4.2 Mud Degassing Vendor Data

ERG identified five manufacturers of mud degassers and attempted to contact them to 

obtain information on mud degasser usage patterns across Texas. Unfortunately, these 

companies were unwilling to share customer details or mud degasser usage patterns. 

ERG also reviewed available online literature from companies that manufacture mud 

degassing equipment:

• Derrick Equipment Company,54 based in Houston, Texas, manufactures a mud 

degassing machine that utilizes thin film, high surface area, impact, turbulence, 

and vacuum technologies to quickly and efficiently remove entrained gases from 

water and oil-based drilling muds. Combined with other equipment in their line 

of products, the degasser processes used drill mud so that it can be quickly reused 

in the drilling operation.

50 Whittenberg, Lauren. "First Academic Study Released in EDF’s Groundbreaking Methane Emissions Series." 

Environmental Defense Fund, 13 Sept. 2013. Accessed: 11 June 2014. <http://www.edf.org/media/firstacademic-study-released-edf%E2%80%99s-groundbreaking-methane-emissions-series>. 51 Personal communication with Dr. David Allen at The University of Texas at Austin. April 30, 2014. 52 Personal communication with Karin C. Ritter of API and Terri Shires of URS Corporation. April 24, 2014 and 

April 29, 2014. 53 Personal communication with David Lyon, May 5, 2014. 54 Derrick Equipment Company, “Vacu-Flo Degasser”, http://www.derrickequipment.com/home.aspx

4-5

 
• National Oilwell Varco,55 based in Houston, Texas, manufactures a complete line 

of drilling fluid mixing, cleaning, cooling, pumping, and monitoring equipment. 

Their website indicates that “The mud (drilling fluid) system components 

condition the drilling fluid with the goal of lowering maintenance cost and 

decreasing the chance of equipment failure and hole and drilling problems.” 

While this vendor information provided background knowledge about the process and 

equipment used in mud degassing, no emissions information was available from these 

sources.

4.3 Mud Degassing Survey Findings

The mud degassing survey targeted drilling companies and attempted to obtain 

information relating to mud degassing activities during drilling operations at oil and gas 

wells. The drilling companies provide rigs, equipment and crews to drill and service 

wells. The companies targeted had significant recent activity in the six regions of 

interest for the survey. These regions of interest are: Anadarko basin, Permian basin, 

Western Gulf basin, Bend Arch-Fort Worth basin/Barnett Shale, East Texas 

basin/Haynesville Shale, and the Eagle Ford Shale. As there is little gas or oil production 

in the Palo Duro and Marathon Thrust Belt basins, these areas were not targeted in this 

survey.

For the mud degassing survey, ERG attempted to contact persons responsible for 

drilling operations at the regional offices of their respective companies. Letters were 

sent to a total of 111 contacts at 64 separate regional company offices, representing 

38 different drilling companies. The letters explained the survey, requested cooperation 

in gathering data, and included sample data collection forms. The survey letter 

requested data on the location, the type of well, the type of drilling mud used, the 

number of drilling days per well, and any control equipment used. See Attachment B for 

the mud degassing letter and survey materials. The companies selected were identified 

from the RigData database as companies that had drilled a significant number of wells56

in the six regions of interest in the past three years. 

ERG followed up the letters with phone calls to each company contact until contact was 

made. In many cases, emails were sent to the company, either as a follow up to a 

telephone conversation, or in the event no telephone contact could be made. During 

phone calls, ERG requested participation and explained the survey to potential 

respondents. 

The mud degassing survey failed to produce any useful results or data. Most of the 

drilling companies contacted did not respond to repeated voice messages left for them. 

Of the three contacts that ERG spoke with, all indicated that they did not have the 

55 National Oilwell VARCO, http://www.nov.com/home.aspx?langtype=1033 56 For purposes of this survey, a ‘significant’ number of wells drilled by a drilling company ranged from 7 to 1198, 

depending upon the basin, with the average being 138.

4-6

 
information we were seeking, or that it would be too difficult to obtain. One respondent 

indicated that mud formulation is the purview of the oil and gas companies, and not the 

drilling contractor and that they did not maintain records of mud usage or 

composition.57

The lack of response to the mud degassing survey by the drilling operations personnel 

may be due to several reasons: 

• Some companies may feel this type of information is confidential in nature and 

wish to protect their operating practices;

• Drilling companies are not used to responding to air quality data collection

surveys, and do not have the institutional capacity to respond;

• There was no real incentive for the drilling companies to participate, as drilling 

companies do not report emissions from their operations directly to TCEQ, and 

have no formal relationship with TCEQ as a regulated entity;

• The information requested was either not kept by the drilling companies, or was 

saved in different departments within a company, making it inconvenient to 

compile information on a particular well; and

• The operations people contacted were too busy managing drilling operations to 

respond.

One respondent indicated that they could not count on the roughnecks to provide the 

correct information on the type of mud used at every stage in the drilling process. 

Another indicated that the mud engineer for the operations company (the owner of the 

well) would be the person that would have the information, and requested that we 

contact them directly. This approach proved unsuccessful as well.

4.4 Mud Degassing Emission Factors

While no useful data was obtained as part of the survey, ERG was able to develop basinspecific mud degassing emission factors for Texas based upon the API emission factors 

originally derived from the 1977 EPA study. Using natural gas dehydrator data derived 

from a recent TCEQ study, 58 natural gas composition profiles for five oil and gas basins 

in Texas were calculated, along with a state averaged natural gas composition profile. 

This information is shown in Table 4-2 below.

Use of the wet stream data for estimating mud degassing emissions from gas wells is 

appropriate, and such data is readily available through dehydrator emissions inventory 

reports submitted to TCEQ. The wet stream, or “wet gas” composition data from the 

dehydrators is assumed to be representative of the composition of any gas released 

during mud degassing. This information was then used to develop updated mud 

degassing emission factors for mud degassing at gas wells based on the Texas-specific 

gas composition data. The resultant mud degassing composition data as used in the 

emissions calculation is shown in Table 4-3.

57 Personal communication with Bill Brannan of Nicklos Drilling Company. June 6, 2014 58 “Condensate Tank Oil and Gas Activities”, Texas Commission on Environmental Quality, Air Quality Division, 

October 20, 2012.

4-7

 
Table 4-2. Basin-Level and State-Level Average Natural Gas Stream Composition Profiles

Composition in Weight 

%

Anadarko Basin Bend Arch-Fort Worth 

Basin East Texas Basin Permian Basin Western Gulf State Average Profile

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Dry 

Stream

Wet 

Stream

Water 0.04 0.13 0.01 0.11 0.01 0.12 0.01 0.13 0.01 0.11 0.01 0.11

Carbon Dioxide 1.54 1.57 4.02 4.00 4.18 4.14 2.00 1.84 2.66 2.66 3.32 3.32

Hydrogen Sulfide 0.06 0.06 0.00 0.00 0.00 0.00 0.18 0.17 0.00 0.45 0.05 0.16

Nitrogen 2.07 2.06 2.56 2.53 1.36 1.34 2.87 2.83 0.76 0.73 1.78 1.75

Methane 79.66 79.70 73.99 73.34 81.31 80.70 61.68 58.39 77.15 76.53 75.13 74.31

Ethane 6.57 6.56 8.25 8.18 5.93 6.02 12.97 12.64 7.24 7.19 7.99 7.88

Propane 4.20 4.20 4.95 5.02 2.53 2.57 9.44 11.02 4.80 4.79 4.96 5.11

Isobutane 0.83 0.83 0.95 0.97 0.90 0.93 1.42 1.64 1.49 1.48 1.17 1.22

n-Butane 1.72 1.72 1.89 2.06 1.00 1.02 3.31 4.39 1.58 1.57 1.78 1.95

Isopentane 0.63 0.63 0.76 0.83 0.60 0.67 1.21 1.34 0.92 0.92 0.84 0.87

n-Pentane 0.67 0.67 1.02 1.09 0.44 0.48 1.10 1.47 0.66 0.65 0.76 0.83

Cyclopentane 0.04 0.04 0.11 0.15 0.16 0.15 0.03 0.07 0.11 0.07 0.07 0.11

n-Hexane 0.47 0.28 0.23 0.54 0.24 0.24 0.66 0.72 0.23 0.27 0.27 0.41

Cyclohexane 0.05 0.05 0.18 0.13 0.14 0.14 0.36 0.43 0.22 0.27 0.18 0.22

Other Hexanes 0.66 0.66 0.32 0.27 0.48 0.52 0.99 1.16 0.78 0.69 0.59 0.59

Heptanes 0.33 0.33 0.42 0.42 0.33 0.39 0.67 0.65 0.37 0.48 0.42 0.42

Methylcyclohexane 0.11 0.11 0.10 0.10 0.05 0.11 0.19 0.18 0.21 0.21 0.16 0.21

Benzene 0.04 0.04 0.04 0.04 0.09 0.13 0.26 0.29 0.04 0.08 0.08 0.08

Toluene 0.05 0.05 0.01 0.01 0.05 0.05 0.18 0.17 0.05 0.10 0.05 0.05

Ethylbenzene 0.01 0.01 0.00 0.01 0.01 0.01 0.05 0.05 0.01 0.01 0.01 0.01

Xylenes 0.02 0.06 0.01 0.02 0.01 0.03 0.05 0.05 0.02 0.06 0.02 0.03

C8+ Heavies 0.25 0.25 0.18 0.18 0.19 0.25 0.38 0.37 0.67 0.67 0.36 0.36

VOCa 10.06 9.93 11.17 11.84 7.20 7.68 20.30 24.00 12.17 12.32 11.72 12.46

Total Hydrocarbons b 96.29 96.19 93.41 93.36 94.44 94.40 94.95 95.03 96.57 96.04 94.84 94.65

a VOC includes Propane through C8+ Heavies

b Total Hydrocarbons includes VOC, Methane, and Ethane

4-8
Table 4-3. Mud Degassing Composition (Gas Wells)

Basin CH4 mol % VOC MW VOC mol %

Anadarko 90.68 55.91 3.24

Bend Arch-Fort Worth 87.59 55.48 4.09

East Texas 91.49 59.04 2.37

Marathon Thrust Belta 88.36 56.35 4.22

Palo Duroa 88.36 56.35 4.22

Permian 78.53 54.72 9.46

Western Gulf 89.94 57.60 4.03

a The data for Marathon Thrust Belt and Palo Duro is the statewide average.

For oil wells, use of the same natural gas dehydrator data is not appropriate since

casinghead gas (gas produced from oil wells) typically has less methane (and more VOC) 

than gas produced at gas wells. Additionally, as the gas from oil wells is not always 

collected, the gas analysis data used to estimate emissions from dehydration and needed 

to develop the profiles shown in Table 4-2 will not be available.

Therefore, to develop Texas-specific mud degassing information for oil wells, ERG 

utilized data from the 2012 CenSARA study. As part of that effort, oil well mud 

degassing composition information was obtained for the Anadarko and Permian basins 

(with data for the Permian basin used for the Marathon Thrust Belt basin, which 

includes two counties in southwest Texas adjacent to the Permian basin). ERG then 

used the data from the Anadarko and Permian basins to develop a statewide averaged 

profile, which was applied to the remaining basins. Table 4-4 presents the results of this 

analysis.

Table 4-4. Mud Degassing Composition (Oil Wells)

Basin CH4 mol % VOC MW VOC mol %

Anadarko 82.93 55.42 5.98

Bend Arch-Fort Wortha 81.78 54.32 6.52

East Texasa 81.78 54.32 6.52

Marathon Thrust Belt 80.62 53.22 7.06

Palo Duroa 81.78 54.32 6.52

Permian 80.62 53.22 7.06

Western Gulfa 81.78 54.32 6.52

a The data for Bend Arch-Fort Worth, East Texas, Palo Duro, and Western Gulf is the statewide 

average.

Attachment D contains the updated TCEQ oil and gas nonpoint area source emissions 

estimation calculator (“ERG AppendixE_2013 with updates to Basin information.xls”) 

reflecting the changes to the inventory for drilling mud degassing using the updated 

composition data in Tables 4-3 and 4-4.

4-9
5. NSPS Subpart OOOO Inventory Evaluation

The intent of NSPS Subpart OOOO59 is to reduce emissions of criteria pollutants at new, 

modified, or reconstructed affected facilities at oil and gas production, gathering, gas 

processing, and gas transmission/storage sites. NSPS Subpart OOOO does not regulate 

greenhouse gas emissions or hazardous air pollutants.

The facility types affected by Subpart OOOO include: natural gas wells that are 

hydraulically fractured, centrifugal compressors using wet seals, reciprocating 

compressors, continuous bleed natural-gas driven pneumatic controllers, storage vessels 

with a potential to emit (PTE) six tons per year (tpy) or more of VOC, piping component

equipment (pump, pressure relief device, open-ended valve or line, valve, and flange or 

other connector in VOC or wet gas service) within a process unit located at onshore 

natural gas processing plants, and sweetening units located at onshore natural gas 

processing plants. NSPS Subpart OOOO applies to these facilities if they are newly 

constructed, modified, or reconstructed after August 23, 2011. Compliance dates vary by 

the facility type.

Table 5-1 shows the affected facilities, industry segment, compliance standard, and 

compliance dates for oil and gas units and processes regulated under Subpart OOOO. 

Table 5-1 also indicates if the affected facility is included in TCEQ’s oil and gas nonpoint 

area source inventory.

Table 5-1. NSPS Subpart OOOO Summary

Affected Facility Area 

Source?

Industry Segment or 

Location Compliance Standard Compliance Date

Natural gas wells 

hydraulically-fractured prior 

to 1/1/2015

Yes Well sites (production) Combust flowback 

emissions from 

completions

10/15/2012

Natural gas wells 

hydraulically-fractured on or 

after 1/1/2015

Yes Well sites (production) Recover and reuse/sell 

or combust flowback 

emissions from 

completions

01/01/2015

Centrifugal compressors 

using wet seals

No Gathering and NG 

processing plants

95% reduction of VOC 10/15/2012

Reciprocating compressors No Gathering and NG 

processing plants

Change rod packing 

every three years

10/15/2012

Continuous bleed naturalgas driven pneumatic 

controllers

Yes Production (well sites) 

and gathering

6 scfh bleed rate 10/15/2012

Continuous bleed naturalgas driven pneumatic 

controllers 

No NG processing plants Zero bleed rate 10/15/2012

59 40 CFR 60, Subpart OOOO—Standards of Performance for Crude Oil and Natural Gas Production, Transmission 

and Distribution, http://www.ecfr.gov/cgi-bin/textidx?SID=f701fdccf601c0b3200249b0ca81fbb6&node=40:7.0.1.1.1.103&rgn=div6#40:7.0.1.1.1.103.297.2

5-1

 
Table 5-1. NSPS Subpart OOOO Summary

Affected Facility Area 

Source?

Industry Segment or 

Location Compliance Standard Compliance Date

Group I Storage Vessels 

(construction, modification 

or reconstruction 

commenced after 

8/23/2011 and on or before 

4/12/2013)

Yes Production (well sites), 

gathering, NG 

processing, and NG 

transmission sites

Reduce VOC emissions 

by 95%, or maintain 

actual VOC emissions at 

less than 4 tpy without 

controls

04/15/2015, 

or within 

60 days after 

startup

Group II Storage Vessels 

(construction, modification 

or reconstruction 

commenced after April 12, 

2013)

Yes Production (well sites), 

gathering, NG

processing, and NG 

transmission sites

Reduce VOC emissions 

by 95%, or maintain 

actual VOC emissions at 

less than 4 tpy without 

controls

04/15/2014, 

or within 

60 days after 

startup

Equipment Leaks (pump, 

pressure relief device, openended valve or line, valve, 

and flange or other 

connector in VOC or wet gas 

service)

No Onshore NG processing 

plants

Implement a LDAR 

program. Leaks > 500 

ppm must be repaired.

10/15/2012

Sweetening Units No Onshore NG processing 

plants

Reduce SO2 as 

calculated

10/15/2012

5.1 Construction, Modification, Reconstruction, and Affected Facilities

NSPS Subpart OOOO requirements apply only to the types of facilities listed above that 

are newly constructed, modified, or reconstructed after August 23, 2011. “Construction” 

is defined as the fabrication, erection, or installation of a new affected “facility.” 

Relocating an affected facility is not construction, modification, or reconstruction. 

“Modification” is defined as any physical or operational change to an existing facility 

which results in an increase in the hourly potential emission rate of any pollutant to 

which the NSPS standard applies.60 Changes that do not constitute a modification 

include: increasing hours of operation, an increase in production rate without a capital 

expenditure, use of an alternative fuel or material if the source could utilize it prior, 

addition of an air pollution control device, change in ownership, and routine 

maintenance, repair, and replacement. “Reconstruction” is defined as replacing 

components at an existing facility, such that the capital cost of new components exceeds 

50% of the capital cost of a comparable new facility, and it is technologically and 

economically feasible to meet applicable standards.

5.2 Effect of NSPS Subpart OOOO on the TCEQ Oil and Gas Nonpoint Area 

Source Oil and Gas Emissions Inventory

As shown above in Table 5-1, the following facilities/processes included in the TCEQ 

nonpoint area source inventory are affected by the rule:

60 40 CFR 60.14. An increase in emissions of a pollutant not regulated by the NSPS Subpart OOOO is not a 

modification.

5-2

 
• Natural gas wells hydraulically-fractured after 10/15/2012 and prior to 1/1/2015;

• Natural gas wells hydraulically-fractured on or after 1/1/2015;

• Continuous bleed natural-gas driven pneumatic controllers (at well sites);

• Group I Storage Vessels (at well sites); and

• Group II Storage Vessels (at well sites).

Since the NSPS regulations only affect facilities if they are newly constructed, modified, 

or reconstructed after August 23, 2011, an analysis was conducted to determine how to 

implement the required controls for each affected facility type in the inventory based on 

the requirements of the rule. Each of the affected source types is discussed in detail 

below, indicating how the affected percentage of the equipment population was 

determined, what the required controls are for each source type, and how these 

requirements were incorporated into the 2013 TCEQ oil and gas nonpoint area source 

emissions estimation calculator.

5.3 Natural Gas Well Completions

Under the requirements of NSPS Subpart OOOO, completions at natural gas wells that 

were hydraulically fractured after October 15, 2012 must be controlled with a flare. 

Completions at gas wells that are hydraulically fractured after January 1, 2015 must be 

controlled by capturing the gas for reuse or sale (reduced emissions completions) or 

flaring for exempted wells. There are currently no requirements in the rule to control 

emissions from oil well completions.

Information on the number of gas well completions that are hydraulically fractured is 

not readily available. However, information on the counts of vertical and horizontal gas 

wells spuds in 201361 is available. Therefore, ERG determined the percentage of gas well

completions that were hydraulically fractured by assuming that the percentage of 

horizontal spuds in a county was equivalent to the percentage of horizontal completions, 

and that all horizontal well completions were hydraulically fractured. Using county-level 

data on the number of horizontal and vertical gas well spuds, the percent of all new gas 

wells that were horizontal, and therefore assumed to be hydraulically fractured, at the 

county level was determined. This data is included Table 5-2.

Table 5-2. Gas Well Completions

County

Vertical 

Spud 

Count

Horizontal 

Spud 

Count

% 

Horizontal 

Spuds

ANDERSON 0 0 0%

ANDREWS 1 0 0%

ANGELINA 0 2 100%

ARANSAS 2 0 0%

ARCHER 0 0 0%

61 2013 annual data was extracted January 2014 by the RRC and provided to TCEQ in March 2014.

5-3

 
Table 5-2. Gas Well Completions

County

Vertical 

Spud 

Count

Horizontal 

Spud 

Count

% 

Horizontal 

Spuds

ARMSTRONG 0 0 0%

ATASCOSA 0 0 0%

AUSTIN 0 1 100%

BAILEY 0 0 0%

BANDERA 0 0 0%

BASTROP 0 0 0%

BAYLOR 0 0 0%

BEE 25 5 17%

BELL 0 0 0%

BEXAR 0 0 0%

BLANCO 0 0 0%

BORDEN 0 0 0%

BOSQUE 0 0 0%

BOWIE 0 0 0%

BRAZORIA 4 8 67%

BRAZOS 0 0 0%

BREWSTER 0 0 0%

BRISCOE 0 0 0%

BROOKS 11 3 21%

BROWN 0 0 0%

BURLESON 0 0 0%

BURNET 0 0 0%

CALDWELL 0 0 0%

CALHOUN 1 0 0%

CALLAHAN 2 0 0%

CAMERON 0 0 0%

CAMP 0 0 0%

CARSON 0 0 0%

CASS 0 0 0%

CASTRO 0 0 0%

CHAMBERS 0 2 100%

CHEROKEE 4 1 20%

CHILDRESS 0 0 0%

CLAY 1 1 50%

COCHRAN 0 0 0%

COKE 0 0 0%

COLEMAN 1 0 0%

COLLIN 0 0 0%

COLLINGSWORTH 0 0 0%

COLORADO 0 2 100%

COMAL 0 0 0%

COMANCHE 1 0 0%

CONCHO 0 0 0%

COOKE 0 9 100%

CORYELL 0 0 0%

COTTLE 1 0 0%

CRANE 0 0 0%

5-4
Table 5-2. Gas Well Completions

County

Vertical 

Spud 

Count

Horizontal 

Spud 

Count

% 

Horizontal 

Spuds

CROCKETT 2 0 0%

CROSBY 0 0 0%

CULBERSON 0 0 0%

DALLAM 0 0 0%

DALLAS 0 2 100%

DAWSON 0 0 0%

DE WITT 1 64 98%

DEAF SMITH 0 0 0%

DELTA 0 0 0%

DENTON 0 28 100%

DICKENS 0 0 0%

DIMMIT 1 192 99%

DONLEY 0 0 0%

DUVAL 8 0 0%

EASTLAND 0 0 0%

ECTOR 0 0 0%

EDWARDS 1 0 0%

EL PASO 0 0 0%

ELLIS 0 0 0%

ERATH 0 0 0%

FALLS 0 0 0%

FANNIN 0 0 0%

FAYETTE 0 0 0%

FISHER 0 0 0%

FLOYD 0 0 0%

FOARD 0 0 0%

FORT BEND 3 2 40%

FRANKLIN 0 0 0%

FREESTONE 20 5 20%

FRIO 0 4 100%

GAINES 0 0 0%

GALVESTON 0 2 100%

GARZA 0 0 0%

GILLESPIE 0 0 0%

GLASSCOCK 0 0 0%

GOLIAD 3 0 0%

GONZALES 0 0 0%

GRAY 0 0 0%

GRAYSON 0 1 100%

GREGG 4 3 43%

GRIMES 1 0 0%

GUADALUPE 0 0 0%

HALE 0 0 0%

HALL 0 0 0%

HAMILTON 0 0 0%

HANSFORD 0 0 0%

HARDEMAN 0 0 0%

5-5
Table 5-2. Gas Well Completions

County

Vertical 

Spud 

Count

Horizontal 

Spud 

Count

% 

Horizontal 

Spuds

HARDIN 0 1 100%

HARRIS 5 1 17%

HARRISON 28 15 35%

HARTLEY 0 0 0%

HASKELL 0 0 0%

HAYS 0 0 0%

HEMPHILL 36 45 56%

HENDERSON 2 0 0%

HIDALGO 30 12 29%

HILL 0 0 0%

HOCKLEY 0 0 0%

HOOD 0 21 100%

HOPKINS 0 0 0%

HOUSTON 3 0 0%

HOWARD 0 0 0%

HUDSPETH 0 0 0%

HUNT 0 0 0%

HUTCHINSON 0 0 0%

IRION 2 0 0%

JACK 5 0 0%

JACKSON 7 4 36%

JASPER 0 0 0%

JEFF DAVIS 0 0 0%

JEFFERSON 1 7 88%

JIM HOGG 2 2 50%

JIM WELLS 7 0 0%

JOHNSON 0 34 100%

JONES 0 0 0%

KARNES 0 96 100%

KAUFMAN 0 0 0%

KENDALL 0 0 0%

KENEDY 2 1 33%

KENT 0 0 0%

KERR 0 0 0%

KIMBLE 0 0 0%

KING 0 0 0%

KINNEY 0 0 0%

KLEBERG 15 3 17%

KNOX 0 0 0%

LA SALLE 1 81 99%

LAMAR 0 0 0%

LAMB 0 0 0%

LAMPASAS 0 0 0%

LAVACA 10 0 0%

LEE 1 0 0%

LEON 6 4 40%

LIBERTY 3 2 40%

5-6
Table 5-2. Gas Well Completions

County

Vertical 

Spud 

Count

Horizontal 

Spud 

Count

% 

Horizontal 

Spuds

LIMESTONE 13 0 0%

LIPSCOMB 0 15 100%

LIVE OAK 7 53 88%

LLANO 0 0 0%

LOVING 0 4 100%

LUBBOCK 0 0 0%

LYNN 0 0 0%

MADISON 3 0 0%

MARION 0 1 100%

MARTIN 0 0 0%

MASON 0 0 0%

MATAGORDA 1 5 83%

MAVERICK 0 0 0%

MCCULLOCH 0 0 0%

MCLENNAN 0 0 0%

MCMULLEN 2 36 95%

MEDINA 0 0 0%

MENARD 0 0 0%

MIDLAND 0 0 0%

MILAM 0 0 0%

MILLS 0 0 0%

MITCHELL 0 0 0%

MONTAGUE 0 81 100%

MONTGOMERY 0 0 0%

MOORE 5 0 0%

MORRIS 0 0 0%

MOTLEY 0 0 0%

NACOGDOCHES 0 2 100%

NAVARRO 0 0 0%

NEWTON 1 2 67%

NOLAN 1 0 0%

NUECES 7 5 42%

OCHILTREE 1 5 83%

OLDHAM 0 0 0%

ORANGE 0 3 100%

PALO PINTO 7 1 13%

PANOLA 51 58 53%

PARKER 0 54 100%

PARMER 0 0 0%

PECOS 0 0 0%

POLK 1 0 0%

POTTER 0 0 0%

PRESIDIO 0 0 0%

RAINS 0 0 0%

RANDALL 0 0 0%

REAGAN 0 0 0%

REAL 0 0 0%

5-7
Table 5-2. Gas Well Completions

County

Vertical 

Spud 

Count

Horizontal 

Spud 

Count

% 

Horizontal 

Spuds

RED RIVER 0 0 0%

REEVES 0 12 100%

REFUGIO 11 0 0%

ROBERTS 2 9 82%

ROBERTSON 16 2 11%

ROCKWALL 0 0 0%

RUNNELS 0 0 0%

RUSK 7 22 76%

SABINE 0 0 0%

SAN AUGUSTINE 0 13 100%

SAN JACINTO 2 1 33%

SAN PATRICIO 9 6 40%

SAN SABA 0 0 0%

SCHLEICHER 0 0 0%

SCURRY 0 0 0%

SHACKELFORD 2 0 0%

SHELBY 3 9 75%

SHERMAN 5 0 0%

SMITH 0 0 0%

SOMERVELL 0 0 0%

STARR 42 5 11%

STEPHENS 18 0 0%

STERLING 0 0 0%

STONEWALL 0 0 0%

SUTTON 0 0 0%

SWISHER 0 0 0%

TARRANT 0 218 100%

TAYLOR 0 0 0%

TERRELL 0 0 0%

TERRY 0 0 0%

THROCKMORTON 3 0 0%

TITUS 0 0 0%

TOM GREEN 0 0 0%

TRAVIS 0 0 0%

TRINITY 0 0 0%

TYLER 2 3 60%

UPSHUR 0 0 0%

UPTON 0 0 0%

UVALDE 0 0 0%

VAL VERDE 0 0 0%

VAN ZANDT 0 0 0%

VICTORIA 7 0 0%

WALKER 0 0 0%

WALLER 5 0 0%

WARD 0 0 0%

WASHINGTON 0 0 0%

WEBB 22 201 90%

5-8
Table 5-2. Gas Well Completions

County

Vertical 

Spud 

Count

Horizontal 

Spud 

Count

% 

Horizontal 

Spuds

WHARTON 7 0 0%

WHEELER 30 85 74%

WICHITA 0 0 0%

WILBARGER 0 0 0%

WILLACY 4 0 0%

WILLIAMSON 0 0 0%

WILSON 0 0 0%

WINKLER 0 0 0%

WISE 2 119 98%

WOOD 0 1 100%

YOAKUM 0 0 0%

YOUNG 1 0 0%

ZAPATA 3 2 40%

ZAVALA 0 0 0%

To address the changes in the inventory as a result of the requirements of NSPS Subpart 

OOOO as described above, the following changes have been made to the “Gas Well 

Completions” tab of TCEQ’s oil and gas nonpoint area source emissions estimation 

calculator:

• In the Basin-Level Data table: added column for flaring capture/control 

efficiency. Assumed a value of 95% for all basins;

• In the Basin-Level Data table: added cells for NOx and CO flaring emission 

factors. The values are 0.068 and 0.37 lb/MMSCF, respectively, for all basins;

• In the County-level emissions table: added a column to show % of completions 

controlled (flared);

• In the County-level emissions table: modified the title in column I to read 

“Uncontrolled VOC Emissions (tons/event)”;

• In the County-level emissions table: modified the formula in column J to reflect 

controls; and

• In the County-level emissions table: added columns K and L for NOx and CO 

emissions. 

These changes reflect the impact of the NSPS Subpart OOOO requirements on 

hydraulically-fractured gas well completions after October 15, 2012, which will affect the 

2013 and 2014 emissions inventories as hydraulically-fractured gas wells completed 

after this date must be controlled with flaring. The additional calculations for NOx and 

CO reflect the combustion emissions from the flare. Note that beginning January 1, 

2015, hydraulically-fractured gas well completions must be conducted using reduced 

emissions completions or flaring. This requirement will need to be considered in future 

inventories.

5-9
Attachment D contains the updated TCEQ oil and gas nonpoint area source emissions 

estimation calculator (“ERG AppendixE_2013 with updates to Basin information.xls”) 

reflecting the changes to the inventory for natural gas well completions as a result of the 

requirements of NSPS Subpart OOOO.

5.4 Pneumatic Controllers

Under the requirements of NSPS Subpart OOOO, pneumatic devices at oil and gas wells 

that were completed after October 15, 2012 must achieve a leak rate of six scf/hr or less.

In the current inventory, the leak rate for pneumatic devices at oil wells is estimated to 

be less than six scf/hr for every basin. Therefore, the calculation for emissions from

pneumatic devices at oil wells has not been revised.

To determine the effects on the 2013 emissions inventory of this requirement for gas 

wells, the percentage of affected gas wells was needed. This was determined by 

calculating the percent of total gas wells in production in 2013 that were completed after 

October 15, 2012. ERG used RRC county-level data on well counts and district level data 

on well completions to estimate the number of wells completed at the county level for 

the periods October 15, 2012 to December 31, 2012, and January 1, 2013 to December 

31, 2013. ERG then calculated the percentage of new wells in each county using the 

county-level sum of new wells (since October 15, 2012) and the current county-level well 

count. This data is included in Table 5-3.

Table 5-3. New Gas Wells 10/15/12 – 12/31/13

Basin Name

2012 New Gas Wells 

(10/15/12 –

12/31/12)

2013 New 

Gas Wells

Total Gas 

Wells in 2013

New Wells (10/15/12 

– 12/31/13) as 

Percent of Total

Anadarko Basin 69 526 12,036 4.9%

Bend Arch-Fort 

Worth Basin 275 1,425 22,388 7.6%

Eagle Ford Shale 86 1,220 11,156 11.7%

East Texas 

Basin/Haynesville 

Shale 113 340 19,931 2.3%

Palo Duro Basin 5 37 934 4.5%

Permian Basin 44 317 18,215 2.0%

Western Gulf 81 599 10,598 6.4%

Once the percentage of affected wells was known, an updated basin-weighted average 

bleed rate could be determined by assuming that all pneumatic devices at new wells 

would have a bleed rate of six scf/hr, while the bleed rates for pneumatic devices at 

existing wells (in existence prior to October 15, 2012) would not change. Table 5-4

presents the bleed rates for existing pneumatic devices, for new pneumatic devices (at 

gas wells brought into production after October 15, 2012), and the updated 2013 basinweighted average bleed rate of all pneumatic devices within a basin.

5-10
Table 5-4. Updated Basin-Weighted Average Bleed Rate (Gas Wells)

Basin Name

Bleed Rate, Pre 

10/15/2012 Devices 

(scf/hr/device)

Bleed Rate, Post 

10/15/2012 Devices 

(scf/hr/device)

2013 Basin Weighted 

Average Bleed Rate 

(scf/hr/device)

Anadarko Basin 12.45 6 12.13

Bend Arch-Fort Worth Basin 6.2 6 6.18

Eagle Ford Shale 10.75 6 10.19

East Texas Basin/Haynesville Shale 17.59 6 17.33

Palo Duro Basin 8.58 6 8.46

Permian Basin 8.79 6 8.73

Western Gulf 7.78 6 7.67

As can be seen in the table, for the 2013 inventory, the average bleed rate of pneumatic 

devices at gas wells has slightly declined in each basin. Over time, as the percentage of 

wells subject to the six (scf/hr) bleed rate limitation increases, the average bleed rate of 

pneumatic devices will continue to decline.

In the Gas Well Pneumatic Devices tab of the TCEQ oil and gas nonpoint area source

emissions estimation calculator, the column titled “Basin Bleed Rate (scf/hr)” was 

revised to “Basin Weighted Average Bleed Rate (scf/hr/device)” to reflect the updated 

bleed rates shown in Table 5-4. These changes reflect the impact of the Subpart OOOO 

requirements on gas well pneumatic devices at wells completed after October 15, 2012 

on the 2013 emissions inventory. 

Attachment D contains the updated TCEQ oil and gas nonpoint area source emissions 

estimation calculator (“ERG AppendixE_2013 with updates to Basin information.xls”) 

reflecting the changes to the inventory for pneumatic controllers as a result of the 

requirements of NSPS Subpart OOOO.

5.5 Oil and Condensate Storage Vessels

Storage vessels are defined as a single tank or other vessel that contains an 

accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced 

water. Fuel and chemical injection tanks, skid-mounted/mobile tanks, process vessels, 

and pressure vessels are excluded. Subpart OOOO applies to storage tanks installed, 

modified, or reconstructed after August 23, 2011, having a PTE of VOC greater than or 

equal to six tpy, and located in the: oil and natural gas production, oil and natural gas 

gathering, natural gas processing, or natural gas transmission and storage segments of 

the industry.

Under the requirements of the rule, storage vessels are separated into two groups based 

on date of construction/modification. Group I storage vessels are those vessels 

constructed, reconstructed, or modified after August 23, 2011, and on or before April 12, 

2013. The PTE of Group I storage vessels must be estimated no later than October 15, 

2013. Any Group I storage vessel determined to have a PTE greater than six tpy must be 

5-11
in compliance with the emission standards by April 15, 2015. Therefore, for purposes of 

revising the 2013 inventory, no control is assumed for Group I storage tanks as controls 

for these tanks are not required until 2015.

Group II storage vessels are those vessels constructed, reconstructed, or modified after 

April 12, 2013. The PTE of Group II storage vessels must be estimated no later than 

thirty days after startup. Any Group II storage vessel with PTE greater than six tpy must 

be in compliance with the emission standards by April 15, 2014 or within 60 days after 

startup. Pursuant to 40 CFR 60.5365, the PTE from storage vessels can be calculated via 

testing or by using a generally accepted model or calculation methodology, based on the 

maximum average daily throughput. Note that the current TCEQ area source emissions 

inventory accounts for a percentage reduction due to control devices installed on 

existing equipment at condensate tanks. 62

A comparison of storage vessel PTE vs. throughput, using current TCEQ area source

emissions inventory emission factors for oil storage tanks (1.60 lb VOC released per 

barrel of oil throughput) and condensate storage tanks (3.15 – 11.02 lb VOC per barrel of 

throughput), shows that an oil storage tank with throughput of less than 20 bbl per day 

has a PTE of less than six tpy of VOC, before the effect of any controls.63 Since the TCEQ 

air emissions inventory emission factors for condensate storage tanks vary by region,64

the throughput of condensate that results in a PTE of less than six tpy varies across 

Texas. For example, condensate production of 2.5 bbl/day in the Western Gulf basin

results in PTE of less than six tpy VOC, while condensate production of 10 bbl/day in the 

Anadarko basin results in PTE of less than six tpy VOC, before the effect of any controls. 

Vapors that are collected and re-routed to a process do not count towards PTE. A study 

conducted by ERG for TCEQ in 2012 on condensate tank emissions65 showed that many 

operators were installing multi-stage depressurizing devices and condensers on their 

wells to capture and sell that portion of their petroleum production that might have 

previously been lost as emissions. As these devices increase production recovery 

efficiency, they are not controls, so PTE would be calculated after the effect of these 

devices.

For any storage tank with a PTE greater than six tpy, VOC emissions must be reduced by 

95% (capture + control) using either a closed vent system and a control device or a 

floating roof. Control devices must undergo a performance test, except for: flares that 

62 Control factors for VOC emissions from condensate storage tanks are as follows: Anadarko basin-17.1%, Bend 

Arch-Fort Worth-11.8%, East Texas-10.5%, Eagle Ford Shale-46.0%, Permian-19.5%, and Western Gulf-12.2%. 63 Based on emissions of 1.6 lb VOC per bbl oil throughput: 1.6 lb/bbl x 365 days/yr x 1 ton/2,000 lb x 20 bbl/day 

= 5.84 tpy of VOC. 64 VOC emissions per bbl of condensate throughput: Anadarko basin-3.15, Bend Arch-Fort Worth-9.76, East 

Texas-4.22, Eagle Ford Shale-10.46, Permian-7.07, and Western Gulf-11.03. Calculation methodology is 

identical to that for oil. 65 “Condensate Tank Oil and Gas Activities”, Texas Commission on Environmental Quality, Air Quality Division, 

October 20, 2012. 

5-12

 
are designed and operated in accordance with §60.18(b), large boilers or process heaters 

(> 44 megawatts), hazardous waste incinerators, or a control device that meets the 

performance requirements of §60.5412(a). To account for declining production, the 

control device can be removed from controlled storage vessels whose actual 

uncontrolled emissions drop to less than four tpy for more than 12 months. Control 

devices must also meet continuous monitoring requirements.

Since Group I storage vessels have until April 15, 2015 to comply, the effect of Subpart 

OOOO on emissions from these wells has not been considered for the 2013 inventory. 

For Group II storage vessels, the set of storage vessels that will need to be considered 

are those storage vessels that commenced production from April 12, 2013 through 

December 31, 2013. To determine the number of wells and the liquids production of the 

storage vessels at oil and gas production sites that were required to control emissions 

beginning June 11, 2013 (60 days after a date of 1st production of April 12, 2013), ERG 

used RRC lease-level data on oil and condensate production and TCEQ’s basin-specific 

VOC emission factors for oil and condensate storage tanks66,67 to estimate the number, 

percentage, and liquids production of oil and gas wells completed since August 23, 2011 

whose storage vessels have a PTE of VOC greater than six tpy. Although the Subpart 

OOOO compliance dates are different for isolated new wells and new wells located on a 

pad with an existing well, in doing these calculations, ERG assumed that all new wells 

are isolated and that production from a single well goes into a single storage tank. To 

simplify the determination of when a well begins production, ERG assumed that 

production begins on the date of completion. To simplify the determination of when a 

storage tank began complying with Subpart OOOO requirements, ERG assumed that 

storage tanks were in compliance on the date of completion.

The RRC lease-level data indicate that 2,638 new oil wells and 766 new gas wells were 

completed after April 12, 2013, and before January 1, 2014. Emissions calculations 

based on liquids production information and basin-specific emission factors for those 

wells described above show that 1,557 new oil wells and 356 new gas wells producing 

liquids are subject to the Subpart OOOO control requirements for the year 2013. The 

2013 production represented by these wells (83,932,001 bbl oil and 8,636,341 bbl 

condensate) was compared with the total production for all new wells completed after 

April 12, 2013 and before January 1, 2014 (86,451,460 bbl oil and 8,719,058 bbl 

condensate), indicate that 97.1% of all new oil production and 99.1% of all new 

condensate production are subject to Subpart OOOO requirements for storage vessels.

When the 2013 oil and condensate production represented by these subject wells is 

compared with RRC data for 2013 statewide oil and condensate production 

(687,486,763 bbl oil and 107,651,266 bbl condensate), the data show that 12.2% of total 

66 “Characterization of Oil and Gas Production Equipment and Develop a Methodology to Estimate Statewide 

missions”, TCEQ, November 24, 2010 67 “Condensate Tank Oil and Gas Activities”, TCEQ, October 10, 2012

5-13

 
statewide 2013 oil production and 8.02% of total statewide 2013 condensate production 

is subject to Subpart OOOO storage vessel control requirements. The breakdown by 

basin is shown in Table 5-5.

To account for these controls in the inventory, the Oil Storage Tanks tab of the TCEQ oil 

and gas nonpoint area source emissions estimation calculator was revised as follows:

• A new table was added with data showing the percentage of basin-level oil 

production that is subject to Subpart OOOO requirements for 2013;

• A new table was added showing the emission control requirements (95% control) 

for oil production that is subject to Subpart OOOO requirements;

• A column was added to the County-level emissions table to account for % of 2013 

production controlled; and

• In the County-level emissions table, the calculations for VOC, Benzene, Toluene, 

Ethylbenzene, and Xylene were revised to reflect the changes in emissions due to 

the Subpart OOOO control requirements for emissions from storage vessels 

constructed after April 12, 2013.

In the Condensate Storage Tanks tab of the TCEQ oil and gas nonpoint area source 

emissions estimation calculator, similar changes were made. The calculation for the 

control percentage for each basin is complicated by the fact that a survey68 conducted in 

2012 showed that a significant percentage of statewide condensate production was 

already controlled. For 2012, the control factor for storage tanks that already had 

recovery or control devices installed ranged from 11.8% for condensate-producing gas 

wells in the Bend Arch-Fort Worth Basin to 46% for gas wells in the Eagle Ford Shale. 

Since the wells constructed in 2013 that are subject to Subpart OOOO requirements are 

new wells with the requirement to control emissions from storage vessels, ERG made 

the simplifying assumption that the percent of regional condensate production 

represented by these new 2013 wells would be added to the control percentage of the 

production that was already controlled. As required by the rule, the control percentage 

applied to the new subject wells is 95%.

Therefore, the Condensate Storage Tank EFs tab of the TCEQ oil and gas nonpoint area 

source emissions estimation calculator was revised as follows:

• The Control Factors in Table A and Table B were revised to increase the existing 

regional control factors by the percentages shown above (and reflecting the 95% 

control requirement for controlled production). These revised control factors are 

used in the emissions calculations in the Condensate Storage Tanks tab of the 

spreadsheet;

• Table C was added to show the % of total production within a basin that is subject 

to the NSPS control requirements; and

• A table was added to show the required NSPS control of 95%.

68 “Condensate Tank Oil and Gas Activities”, TCEQ, October 10, 2012

5-14

 
No revisions were needed to the Condensate Storage Tanks tab of the TCEQ oil and gas 

nonpoint area source emissions estimation calculator as the control factors are pulled 

from the Condensate Storage Tank EFs tab and inherently incorporate the NSPS 

Subpart OOOO control requirements.

Attachment D contains the updated TCEQ oil and gas nonpoint area source emissions 

estimation calculator (“ERG AppendixE_2013 with updates to Basin information.xls”) 

reflecting the changes to the inventory for storage vessels as a result of the requirements 

of NSPS Subpart OOOO.

5-15
Table 5-5. Percentage of 2013 Oil and Condensate Production Subject to Subpart OOOO 

Requirements

Basin

Oil Condensate

Production 

Subject to 

Subpart 

OOOO (bbl) 

Total 

Production 

(bbl)

% of 

Production 

Subject to 

Subpart 

OOOO

Production 

Subject to 

Subpart 

OOOO (bbl) 

Total 

Production 

(bbl)

% of Production 

Subject to Subpart 

OOOO

Anadarko Basin 174,099 10,609,144 1.6% 1,066,246 14,038,374 7.60%

Bend Arch-Fort Worth Basin 787,645 20,391,120 3.9% 328,549 5,147,458 6.38%

Eagle Ford Shale 75,495,269 263,909,215 28.6% 6,493,095 68,335,461 9.50%

East Texas Basin 85,893 7,994,511 1.1% 13,158 624,895 2.11%

East Texas Basin/Haynesville Shale 76,800 6,087,890 1.3% 118,595 4,109,868 2.89%

Marathon Thrust Belt 0 5,668 0.0% 0 54,345 0.00%

Palo Duro Basin 558,642 4,124,773 13.5% 3,644 55,043 6.62%

Permian Basin 5,592,846 344,009,390 1.6% 964 2,472,622 0.04%

Western Gulf 789,990 16,494,090 4.8% 576,967 9,366,101 6.16%

Western Gulf/Beaumont-Port Arthur 13,247 2,512,043 0.5% 355 1,905,094 0.02%

Western Gulf/Houston-GalvestonBrazoria 369,936 11,348,919 3.3% 39,014 1,542,005 2.53%

5-16
6. Conclusions

ERG recommends that the TCEQ update the nonpoint area source oil and gas emissions 

inventory as described in this report for the following source types:

• Condensate storage tanks;

• Gas well completions;

• Gas well pneumatic devices;

• Hydraulic pump engines;

• Mud degassing (oil and gas wells); and

• Oil storage tanks.

Under the requirements of the recently revised NSPS Subpart OOOO (Standards of 

Performance for Crude Oil and Natural Gas Production, Transmission and 

Distribution), certain new condensate storage tanks, gas well completions, gas well 

pneumatic devices, and oil storage tanks require emissions control or emissions 

reduction strategies. Based on the findings of this study, the rule revisions have had a

particularly notable impact on emissions from oil and condensate tanks due to the 

increase in hydrocarbon liquids production in Texas over the last few years. As new 

liquids production is brought on-line, particularly in areas such as the Eagle Ford Shale, 

storage tank control requirements are triggered such that emissions on a per barrel 

basis are much lower than from older wells.

For mud degassing, limited data was available to improve the current emissions 

estimate. This source category is not regulated; is not covered under Subpart W of the 

Greenhouse Gas Reporting Rule; and has not typically been considered a large emitting 

source. However, Texas-specific gas composition data were used to refine the estimates 

for mud degassing to reflect basin-specific gas composition in Texas.

Finally, updates to the input variables used to estimate emissions from hydraulic pump 

engines have resulted in a large increase in emissions for this category. Previously, 

emissions were based on input variables developed under the CenSARA 2012 emissions 

inventory project which reflected an average of 3.5 engines rated at 1,258 hp operating 

for approximately 9 hours to complete well perforation and stimulation. As shown in 

Table 3 above, well stimulation operations in Texas require significantly more engines, 

at a higher hp, and increased operational time to complete the process.

Attachment D contains an updated version of TCEQ’s oil and gas nonpoint area source 

emissions estimation tool reflecting the revisions described above.

6-1
Attachment A

Hydraulic Pump Survey Letter
Dear [Insert Operator_Contact_Name], [Insert Operator_Contact_Title] 

[Insert Operator_Company_Name] [Date]

Eastern Research Group (ERG), an independent research organization, is conducting a study on 

emissions from pump engines used in hydraulic stimulation and perforation activities for the 

Texas Commission on Environmental Quality (TCEQ). The purpose of this study is to develop 

equipment inventories and usage data for estimating emissions from hydraulic pump engines for 

each of the oil and gas producing regions in Texas. The study results will assist the TCEQ in 

refining the Texas air emissions inventory.

Hydraulic pump engine emissions are currently estimated by TCEQ using activity data from a 

2012 Central States Air Resources Agencies (CenSARA) study. The purpose of this survey is to 

gather Texas-specific data on hydraulic pump engine activities so that TCEQ can refine its 

emissions estimates. To support this effort, the TCEQ is seeking information from Texas oil and 

gas drilling/hydraulic stimulation companies to assist in development of refined, county-specific 

equipment and usage data. 

We are asking for your participation in this voluntary survey that will involve sharing 

information regarding the number and horsepower of engines used, and the amount of time they 

are used. Individual wells and rigs do not need to be identified. The information your company 

provides will be used for statistical purposes only in order to develop county-level and basinlevel estimates and will not be republished or disseminated for other purposes. The information 

you provide will be held confidential.

ERG will contact your company via phone to discuss this effort and collect any information you 

are willing to share. We are seeking basin-specific hydraulic pump engine usage information for 

oil and gas well sites hydraulically stimulated in the [Insert Basin_name] [Insert counties_text]

The specific information we are requesting for each well hydraulically stimulated in 2013:

• County • Number of engines • Number of fracturing stages

• Well type (oil or gas) • Horsepower of engines • Duration of each fracturing stage

• Percent full load for engines (hours)

A table on the reverse side of this letter shows the type of data we wish to collect.

We appreciate your assistance in this study. If you have any questions on the technical aspects of 

the study, please contact me at (919) 468-7902, or via email at stephen.treimel@erg.com. 

Completed surveys should be sent to my attention. Questions concerning the scope of this study 

or ERG’s relationship with TCEQ may be directed to the TCEQ Project Manager, Michael Ege, 

at (512) 239-5706, or via email at Michael.Ege@tceq.texas.gov. 

Sincerely,

Stephen Treimel, Environmental Scientist

Eastern Research Group, Inc.

A-1
Operator Name: [Insert Operator_Company_Name]

Basin and Counties: [Insert Basin_name] basin: [Insert counties_text] 

Instructions: Provide the data listed below for up to ten separate well sites located in the counties listed above. To avoid biasing the 

survey results, we ask that you please select the well sites at random from all of the wells you worked on in this region in 2013.

Site # County

Well type 

(oil or gas) a

Number of 

Engines

Horsepower of 

Engines

Percent Full 

Load for Engines 

(when active)

Number of 

Fracturing Stages

Duration of Each 

Fracturing Stage 

(hours)

a Does the Texas Railroad Commission consider this well a gas well (G) or an oil well (O)? 

Completed surveys can be emailed to me at stephen.treimel@erg.com or printed and mailed to my attention at: Eastern Research Group, 

1600 Perimeter Park Drive, Morrisville, NC 27560.

A-2
Attachment B

Mud Degassing Survey Letter
Dear [Insert Operator_Contact_Name], [Insert Operator_Contact_Title] 

[Insert Operator_Company_Name] [Date]

Eastern Research Group (ERG), an independent research organization, is conducting a study on 

emissions from drilling mud degassing for the Texas Commission on Environmental Quality 

(TCEQ). The purpose of this study is to develop activity estimates for estimating emissions from 

mud degassing activities during well drilling for each of the oil and gas producing regions in 

Texas. The study results will assist the TCEQ in refining the Texas air emissions inventory. 

Emissions from mud degassing are currently estimated by TCEQ using EPA default water-based 

mud emission factors from the Climate Registry Reporting Protocol and activity data from a 

2012 Central States Air Resource Agencies (CenSARA) study. The purpose of this survey is to 

gather Texas-specific data on drilling mud usage, characteristics, and mud degassing activities so 

that TCEQ can refine its emissions estimates. To support this effort, the TCEQ is seeking 

information from Texas oil and gas drilling companies to assist in development of refined, 

county-specific equipment and usage data. 

We are asking for your participation in this voluntary survey that will involve sharing 

information regarding the location, the type of well, the type of drilling mud used, the number of 

drilling days per well, and any control equipment used. Individual wells and rigs do not need to 

be identified. The information your company provides will be used for statistical purposes only 

in order to develop county-level and basin-level estimates and will not be republished or 

disseminated for other purposes. The information you provide will be held confidential.

ERG will contact your company via phone to discuss this effort and collect any information you 

are willing to share. We are seeking basin-specific mud degassing emissions information for oil 

and gas wells drilled/recompleted in the [Insert Basin_name] [Insert counties_text] The specific 

information we are requesting for each well drilled or recompleted in 2013:

• County • Type of mud used (water- or oil-based)

• Well type (oil or gas) • Number of drilling days per well

• New well or recompletion • Are emissions from degassing equipment controlled?

A table on the reverse side of this letter shows the type of data we wish to collect.

We appreciate your assistance in this study. If you have any questions on the technical aspects of 

the study, please contact me at (919) 468-7902, or via email at stephen.treimel@erg.com. 

Completed surveys should be sent to my attention. Questions concerning the scope of this study 

or ERG’s relationship with TCEQ may be directed to the TCEQ Project Manager, Michael Ege, 

at (512) 239-5706, or via email at Michael.Ege@tceq.texas.gov. 

Sincerely,

Stephen Treimel, Environmental Scientist

Eastern Research Group, Inc.

B-1
Operator Name: [Insert Operator_Company_Name]

Basin and Counties: [Insert Basin_name] [Insert counties_text] 

Instructions: Provide the data listed below for up to ten separate well sites located in the basin/counties listed above. To avoid biasing 

the survey results, we ask that you please select the well sites at random from the wells drilled in this region in 2013.

Site # County

Well type 

(oil or gas) a

New well or 

Recompletion

Type of mud used (waterbased, oil-based, synthetic)Number of 

drilling days

Are emissions from 

degassing equipment 

controlled? (Y/N)

Percent Control 

(%)

a Does the Texas Railroad Commission consider this well a gas well (G) or an oil well (O)? 

Completed surveys can be emailed to me at stephen.treimel@erg.com or printed and mailed to my attention at: Eastern Research 

Group, 1600 Perimeter Park Drive, Morrisville, NC 27560.

B-2
Attachment C

Survey Results

(TCEQ Hydraulic Pump Engine Study Findings.xlsx)
Attachment D

Updated Oil and Gas Nonpoint Area Source Emissions 

Estimation Tool

(ERG Appendix E_2013 with updates to Basin information.xlsx)