Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States Appendices


vvEPA
United States
Environmental Protection
Agency
EPA-600-R-16-236Fb
December 2016
www.epa.gov/hfstudy
Hydraulic Fracturing for Oil and Gas:
Impacts from the Hydraulic Fracturing
Water Cycle on Drinking Water
Resources in the United States
Appendices
Office of Research and Development
Washington, DC

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EPA-600-R-16-236Fb
December 2016
www.epa.gov/hfstudy
Hydraulic Fracturing for Oil and Gas:
Impacts from the Hydraulic
Fracturing Water Cycle on Drinking
Water Resources in the United States
Appendices
Office of Research and Development
U.S. Environmental Protection Agency
Washington, DC 20460

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Disclaimer
This document has been reviewed in accordance with U.S. Environmental Protection Agency policy
and approved for publication. Mention of trade names or commercial products does not constitute
endorsement or recommendation for use.
Preferred citation: U.S. EPA (U.S. Environmental Protection Agency). 2016. Hydraulic Fracturing
for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources
in the United States - Appendices. Office of Research and Development, Washington, DC.
EPA/600/R-16/236Fb.

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Contents
List of Tables	v
List of Figures	ix
List of Text Boxes	xi
Appendix A. The EPA's Study of the Potential Impacts of Hydraulic Fracturing for Oil and
Gas on Drinking Water Resources	A-l
A.l. The EPA's Hydraulic Fracturing Study Publications Cited in This Assessment	A-5
A.2.	Answers to the Secondary Research Questions	A-7
A.2.1. Water Acquisition	A-9
A.2.2. Chemical Mixing	A-ll
A.2.3. Well Injection	A-14
A.2.4. Produced Water Handling	A-15
A.2.5.	Wastewater Disposal and Reuse	A-18
Appendix B. Water Acquisition Supplemental Information	B-l
B.l.	Supplemental Tables	B-3
B.2.	Supplemental Discussion: Potential for Water Acquisition Impacts by Location	B-53
B.2.1.	Oklahoma and Kansas	B-53
B.2.2. Utah, New Mexico, and California	B-55
Appendix C. Chemical Mixing Supplemental Information	C-l
C.l.	Most Frequently Reported Chemicals in Gas- and Oil-Producing Wells	C-3
C.2. Most Frequently Reported Chemicals for Each State	C-7
C.3. Estimating Volume and Mass for 74 Chemicals Reported in Disclosures in the EPA
FracFocus 1.0 Project Database	C-22
C.4. Estimating Spill Rates Based on State Spill Report Data	C-36
C.5. Selected Physicochemical Properties of Organic Chemicals Used in Hydraulic
Fracturing Fluids	C-38
C.6. Details on the EPI (Estimation Programs Interface) Suite™	C-66
C.7.	Top 20 lists for most mobile and least mobile chemicals	C-67
Appendix D. Well Injection Supplemental Information	D-l
D.l.	Design Goals for Well Construction	D-3
D.2. Well Components	D-3
D.2.1. Casing	D-4
D.2.2. Cement	D-6
D.3. Well Completions	D-12
D.4. Mechanical Integrity Testing	D-13
D.4.1. Internal Mechanical Integrity	D-14
D.4.2. External Mechanical Integrity	D-15
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Appendix E. Produced Water Handling Supplemental Information	E-l
E.l. Specific Definitions of the Terms "Produced Water" and "Flowback"	E-3
E.l.l. Produced Water	E-3
E.l.2. Flowback	E-3
E.2. Produced Water Volumes	E-3
E.2.1. Summary of Results from Produced Water Studies	E-13
E.3. Chemical Content of Produced Water	E-17
E.3.1. General Water Quality Parameters	E-17
E.3.2. Salinity and Inorganics	E-22
E.3.3. Metals and Metalloids	E-25
E.3.4. Naturally Occurring Radioactive Material (NORM) and Technically Enhanced
Naturally Occurring Radioactive Material (TENORM)	E-31
E.3.5. Organics	E-34
E.3.6. Chemical Reactions	E-57
E.3.7. Microbial Community Processes and Content	E-58
E.4. Produced Water Content Spatial Trends	E-60
E.4.1. Variability between Plays of the Same Rock Type	E-60
E.4.2. Local Variability	E-62
E.5. North Dakota Spill Analysis	E-62
E.5.1. Materials and Methods	E-62
E.5.2. Results	E-64
E.5.3. Summary of Additional Studies on Spills	E-72
E.6. Evaluation of Impacts	E-73
E.7. Transport Properties	E-78
E.8.	Example Calculation for Roadway Transport	E-79
E.8.1. Estimation of Transport Distance	E-79
E.8.2. Estimation of Wastewater Volumes	E-80
E.8.3. Estimation of Roadway Accidents	E-80
E.8.4. Estimation of Material Release Rates in Crashes	E-81
E.8.5.	Estimation of Volume Released in Accidents	E-81
Appendix F. Wastewater Disposal and Reuse Supplemental Information	F-l
F.l.	Estimates of Wastewater Production in Regions where Hydraulic Fracturing is
Occurring	F-3
F.2. Overview of Treatment Processes for Treating Hydraulic Fracturing Wastewater	F-9
F.2.1.	Basic Treatment	F-9
F.2.2. Advanced Treatment	F-ll
F.3. Treatment Technology Removal Capabilities	F-16
F.4. Treatment for Constituents of Concern	F-23
F.5. Centralized Waste Treatment Facilities and Waste Management Options	F-33
F.5.1. Design of Treatment Trains for CWTs	F-33
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F.5.2. Discharge Options for CWTs	F-41
F.6. Water Reuse	F-41
F.6.1. Factors in Considering Reuse	F-42
F.6.2. Water Quality for Reuse	F-43
F.7. Hydraulic Fracturing Wastewater Impacts on POTWs	F-45
F.8.	Hydraulic Fracturing Wastewater and Disinfection Byproducts	F-46
F.8.1. Disinfection Byproducts	F-46
F.8.2.	Studies Modeling Bromide in Receiving Waters from CWT Effluents	F-47
Appendix G. Identification and Hazard Evaluation of Chemicals across the Hydraulic
Fracturing Water Cycle Supplemental Information	G-l
G.l.	Introduction	G-3
G.2. Criteria for Selection and Inclusion of Reference Value (RfV), Oral Slope Factor (OSF),
and Qualitative Cancer Classification Data Sources	G-3
G.2.1.	Included Sources	G-5
G.2.2. Excluded Sources	G-5
G.3. Glossary of Toxicity Value Terminology	G-6
G.4.	Additional Tools for Hazard Evaluation	G-10
G.4.1. Threshold of Toxicological Concern (TTC)	G-10
G.4.2. Organisation for Economic Co-operation and Development (OECD) Quantitative
Structure-Activity Relationship (QSAR) Toolbox	G-ll
G.4.3. Application of Data from High Throughput Screening Assays	G-ll
Appendix H. Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced
Water	H-l
H.l.	Supplemental Tables and Information	H-3
Appendix I. Unit Conversions	1-1
Appendix). Glossary	J-l
J.l. Introduction	J-3
J.2. Glossary Terms and Definitions	J-3
Appendix K. Appendix References	K-l
iv

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List of Tables
Table A-l. Titles, descriptions, and citations for the EPA's hydraulic fracturing study
publications cited in this assessment A-5
Table B-l. Average annual hydraulic fracturing water use and consumption in 2011 and
2012 compared to total annual water use and consumption in 2010 by state B-3
Table B-2. Average annual hydraulic fracturing water use and consumption in 2011 and
2012 compared to total annual water use and consumption in 2010 by county B-5
Table B-3. Comparison of water use per well estimates from the EPAFracFocus 1.0 project
database (U.S. EPA, 2015c) and literature sources B-21
Table B-4. Comparison of well counts from the EPA FracFocus 1.0 project database (U.S.
EPA, 2015c) and state databases for North Dakota, Pennsylvania, and West Virginia B-22
Table B-5. Water use per hydraulically fractured well as reported in the EPA FracFocus 1.0
project database (U.S. EPA, 2015c) by state and basin, covering the time period of January
2011 through February 2013 B-23
Table B-6. Estimated percent domestic use water from groundwater and self-supplied by
county in 2010 B-27
Table B-7. Projected hydraulic fracturing water use by Texas counties between 2015 and
2060, expressed as a percentage of 2010 total county water use B-41
Table C-l. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0
project database for gas-producing wells, with the number of disclosures (for reported
chemicals), percentage of disclosures, and the median maximum concentration (% by mass)
of that chemical in hydraulic fracturing fluid C-3
Table C-2. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0
project database for oil-producing wells, with the number of disclosures (for reported
chemicals), percentage of disclosures, and the median maximum concentration (% by mass)
of that chemical in hydraulic fracturing fluid C-5
Table C-3. (a) Chemicals most frequently reported in disclosures in the EPAFracFocus 1.0
project database for each state and number (and percentage) of disclosures where a
chemical is reported for that state, Alabama to Montana; (b) Chemicals most frequently
reported in disclosures in the EPA FracFocus 1.0 project database for each state and
number (and percentage) of disclosures where a chemical is reported for that state, New
Mexico to Wyoming C-7
Table C-4. Estimated mean, median, 5th percentile, and 95th percentile volumes in gallons for
chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database,
where density information was available C-24
Table C-5. Estimated mean, median, 5th percentile, and 95th percentile volumes in liters for
chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database,
where density information was available C-27
Table C-6. Calculated mean, median, 5th percentile, and 95th percentile chemical masses
reported in 100 or more disclosures in the EPAFracFocus 1.0 project database, where
density information was available C-30
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Table C-7. Associated chemical densities and references used to calculate chemical mass
and estimate chemical volume	C-33
Table C-8. Estimations of spill rates	C-37
Table C-9. Selected physicochemical properties of organic chemicals reported as used in
hydraulic fracturing fluids	C-38
Table C-10. Ranking of the 20 most mobile organic chemicals, as determined by the largest
log Kow, with CASRN, percent of wells where the chemical is reported from January 1, 2011
to February 28, 2013 (U.S. EPA, 2015c), and physicochemical properties (log Kow, solubility,
and Henry's law constant) as estimated by EPI Suite™	C-68
Table C-ll. Ranking of the 20 least mobile organic chemicals, as determined by the largest
log Kow, with CASRN, percent of wells where the chemical is reported from January 1, 2011
to February 28, 2013 (U.S. EPA, 2015c), and physicochemical properties (log Kow,
solubility, and Henry's law constant) as estimated by EPI Suite™	C-70
Table E-l. Produced water characteristics for wells by basin, formation, and resource type	E-4
Table E-2. Reported concentrations of general water quality parameters in produced water
for unconventional shale and tight formations, presented as: average (minimum-maximum)
or median (minimum-maximum)	E-l8
Table E-3. Reported concentrations of general water quality parameters in produced water
for coalbed basins, presented as: average (minimum-maximum)	E-21
Table E-4. Reported concentrations (mg/L) of inorganic constituents contributing to salinity
in produced water from unconventional reservoirs (including shale and tight formations),
presented as: average (minimum-maximum) or median (minimum-maximum)	E-23
Table E-5. Reported concentrations (mg/L) of inorganic constituents contributing to salinity
in produced water for coalbed methane basins, presented as: average (minimum-
maximum) 	E-2 5
Table E-6. Reported concentrations (mg/L) of metals and metalloids from produced water
from unconventional reservoirs (including shale and tight formations), presented as:
average (minimum-maximum) or median (minimum-maximum)	E-27
Table E-7. Reported concentrations (mg/L) of metals and metalloids from produced water
from coalbed methane, presented as: average (minimum-maximum)	E-30
Table E-8. Reported concentrations (in pCi/L) of radioactive constituents in produced water
in unconventional reservoirs (including shale and tight sandstones), presented as: average
(minimum-maximum) or median (minimum-maximum)	E-32
Table E-9. Concentrations of select organic parameters in produced water from
unconventional reservoirs (including shale, a tight formation, and coalbed methane),
presented as: average (minimum-maximum) or median (minimum-maximum)	E-36
Table E-10. Classes of organic compounds and representative example compounds found in
coal bed methane and gas shale formations (Orem etal., 2014)	E-38
Table E-ll. Reported concentrations (ng/L) of organic constituents in produced water for
two shale formations, presented as: average (minimum-maximum) or median (minimum-
maximum)	E-42
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Table E-12. Reported concentrations of organic constituents in 65 samples of produced
water from the Black Warrior CBM Basin (Alabama and Mississippi), presented as: average
(minimum-maximum) E-44
Table E-13. Organic chemical concentrations reported from three specific studies of
produced water (Khan etal., 2016; Lester etal., 2015; Orem etal., 2007) E-45
Table E-14. Volume distribution in gallons (minimum, 25th percentile, median, 75th
percentile and maximum) for each type of spill in North Dakota for 2015 E-70
Table E-15. Numbers of 2015 North Dakota spills in ranges defined by the spill volume
statistics (Table E-13) for each type E-70
Table E-16. Number of 2015 North Dakota spills which exceed thresholds (20,000 gal,
40,000 gal, and 400,000 gal) for each type of spill E-71
Table E-17. Outline of Northeastern Pennsylvania Retrospective Case Study QAPP E-74
Table E-18. Source delineation analysis table from the EPA retrospective case study in Wise
County, Texas E-76
Table E-19. Combination truck crashes in 2012 for the 2,469,094 registered combination
trucks, which traveled 163,358 million miles E-80
Table E-20. Large truck crashes in 2012 E-80
Table E-21. Chances of a crash releasing produced water based on the total produced water
volume per well, transport distances, crash rates, and material release rates E-82
Table F-l. Estimated volumes (millions of gallons) of wastewater based on state data for
selected years and numbers of wells producing fluid. The wastewater is likely associated
with an unknown combination of wells not hydraulically fractured and some hydraulically
fractured F-4
Table F-2. Removal efficiency of different hydraulic fracturing wastewater constituents
using various wastewater treatment technologies.3 F-16
Table F-3. Estimated effluent concentrations for example constituents based on treatment
process removal efficiencies F-20
Table F-4. Studies of removal efficiencies and influent/effluent data for various processes
and facilities F-24
Table F-5. Treatment processes for hydraulic fracturing wastewater organic constituents F-3 2
Table F-6. Examples of centralized waste treatment facilities F-35
Table F-7. Water quality requirements for reuse F-43
Table G-l. (a) Chemicals reported to be used in hydraulic fracturing fluids, with available
chronic oral RfVs, OSFs, and qualitative cancer classifications from United States federal
sources; (b) Chemicals reported to be used in hydraulic fracturing fluids, with available
chronic oral RfVs and OSFs from state sources; (c) Chemicals reported to be used in
hydraulic fracturing fluids, with available chronic oral RfVs and OSFs from international
sources; (d) Chemicals reported to be used in hydraulic fracturing fluids, with available less-
than-chronic oral RfVs and OSFs; (e) Available qualitative cancer classifications for
chemicals reported to be used in hydraulic fracturing fluids G-l2
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Table G-2. (a) Chemicals reported to be detected in produced water, with available chronic
oral RfVs, OSFs, and qualitative cancer classifications from United States federal sources; (b)
Chemicals reported to be detected in produced water, with available chronic oral RfVs and
OSFs from state sources; (c) Chemicals reported to be detected in produced water, with
available chronic oral RfVs and OSFs from international sources; (d) Chemicals reported to
be detected in produced water, with available less-than-chronic oral RfVs and OSFs; (e)
Available qualitative cancer classifications for chemicals reported to be detected in
produced water	G-41
Table H-l. Sources used to create lists of chemicals used in fracturing fluids or detected in
produced water	H-3
Table H-2. Chemicals reported to be used in hydraulic fracturing fluids	H-8
Table H-3. List of generic names of chemicals reportedly used in hydraulic fracturing fluids	H-62
Table H-4. Chemicals detected in produced water	H-75
Table H-5. Chemicals detected in produced water for which a specific, valid CASRN could
not be identified	H-105
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List of Figures
Figure A-l. Timeline of activities in the EPA's hydraulic fracturing study A-4
Figure A-2. Structure of the EPA's hydraulic fracturing study A-8
Figure B-l. Major U.S. EIA shale plays and basins for Oklahoma and Kansas B-53
Figure B-2. Major U.S. EIA shale plays and basins for Utah, New Mexico, and California B-56
Figure C-l. Histograms of physicochemical properties organic chemicals claimed as
confidential by industry that were used in the hydraulic fracturing process C-72
Figure D-l. Atypical staged cementing process D-ll
Figure D-2. Examples of well completion types D-12
Figure E-l. Fraction of injected hydraulic fracturing fluid recovered from six vertical (top)
and eight horizontal (bottom) wells completed in the Marcellus Shale E-13
Figure E-2. Example of flowback and produced water from the Marcellus Shale, illustrating
rapid decline in water production and cumulative return of approximately 30% of the
volume of hydraulic fracturing fluid E-14
Figure E-3. Percent of hydraulic fracturing fluid recovered for Marcellus Shale wells in West
Virginia (2010 -2012) E-15
Figure E-4. Barnett Shale monthly water-production percentiles (5th, 30th, 50th, 70th, and
90th) and number of wells with data (dashed line) E-l 6
Figure E-5. Barnett Shale production data for approximately 72 months E-16
Figure E-6. Illustration of a "box" or "box and whisker" plot E-63
Figure E-7. Median, mean, and maximum volume of oil spills in North Dakota for 2001 to
2015 E-64
Figure E-8. Median, mean, and maximum volume of "other" spills in North Dakota for 2002
to 2015 E-65
Figure E-9. Count of spills and active wells in North Dakota for the years 2001 to 2015 E-66
Figure E-10. Number of spills in North Dakota from 2001 to 2015 separated by type and by
"contained" versus "not contained." E-67
Figure E-ll. Median volume (gal) of spills in North Dakota from 2001 to 2015 separated by
type and by "contained" versus "not contained." E-68
Figure E-12. Yearly sum of spill volume (gal) of spills in North Dakota from 2001 to 2015
separated by type and by "contained" versus "not contained." E-69
Figure E-13. Numbers of contained spills in North Dakota by cause for 2014 and 2015 E-71
Figure E-14. Numbers of not contained spills in North Dakota by cause for 2014 and 2015 E-72
Figure E-15. Quality assurance blanks illustrating giving their purpose, brief procedure, and
the span of their scope (modified from US EPA Region 3 Quality Control Tools: Blanks, April
27, 2009) E-75
Figure F-l. Electrocoagulation unit F-10
Figure F-2. Photograph of reverse osmosis system F-12
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Figure F-3. Picture of mobile electrodialysis units in Wyoming	F-13
Figure F-4. Picture of a mechanical vapor recompression unit near Decatur, Texas	F-14
Figure F-5. Mechanical vapor recompression process design - Maggie Spain Facility	F-14
Figure F-6. Picture of a compressed bed ion exchange unit	F-15
Figure F-7. Full discharge water process used in the Pinedale Anticline field	F-34
Figure F-8. Diagram of treatment for reuse of flowback and produced water	F-45
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List of Text Boxes
Text Box D-l. Selected Industry-Developed Specifications and Recommended Practices for
Well Construction in North America	D-4
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Appendix A - The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
Appendix A. The EPA's Study of the Potential
Impacts of Hydraulic Fracturing for Oil and
Gas on Drinking Water Resources

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Appendix A- The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
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Appendix A - The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
Appendix A. The EPA's Study of Hydraulic Fracturing for
Oil and Gas and Its Potential Impact on Drinking Water
Resources
In 2009, atthe urging of the U.S. Congress, the EPA initiated a study of hydraulic fracturing for oil
and gas and its relationship to drinking water resources (hereafter the EPA's hydraulic fracturing
study). The national study culminates with this report, the Hydraulic Fracturing for Oil and Gas:
Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United
States.
The EPA's hydraulic fracturing study consisted of many elements. It included independent
research projects conducted by EPA scientists and contractors, and involved the analysis of
existing data, scenario and modeling evaluations, laboratory studies, toxicological assessments,
and case studies. A list of the ensuing EPA publications is presented in Table A-l. The EPA's
hydraulic fracturing study also included the development of this report, which is a state-of-the-
science synthesis of available data and information, as well as the EPA's own research.
Throughout, the EPA consulted with the Agency's independent Science Advisory Board (SAB) on
the scope of its hydraulic fracturing study and the progress made on each of the research projects.
The timeline of this work is presented in Figure A-l. The SAB also conducted a peer review of both
the EPA's Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources
(U.S. EPA, 2011a, hereafter Study Plan) and the Hydraulic Fracturing for Oil and Gas: Impacts from
the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States, as described
in Chapter 1.
Stakeholder engagement also played an important role in the development and implementation of
the EPA's hydraulic fracturing study. The EPA held public meetings across the United States to
hear feedback from stakeholders on the proposed study design and scope. In addition, while
conducting the hydraulic fracturing study, the EPA engaged with technical, subject-matter experts
on relevant topics in a series of technical workshops and roundtables (Figure A-l).
A-3

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Appendix A - The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
STUDY
time
STUDY ACTIVITIES
US Congress urges the EPA
to conduct a study (Fall 2009)
SAB ACTIVITIES
SAB advisory on scoping documents
(March - June 2010)
STAKEHOLDER
ENGAGEMENT
Meetings with stakeholders to
identify concerns and study scope
(July-August 2010)
Z
iD
i/>
LU
Release draft Study Plan
(February 2011)

Technical workshops
(February - March 2011)
O
Release final Study Plan
(November 2011)
SAB peer review of draft Study Plan*
(February - August 2011)
Public comments accepted by SAB
(February - August 2011)
X
(J
Release Progress Report*
(December 2012)

Technical roundtables* and
public request for data
and information
(November 2012)
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Technical workshops*
(February-July 2013)
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D
Q
Z
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Release EPA technical reports
and scientific journal articles
(May 2013-July 2016)
SAB consultation on
Progress Report (May 2013)
Public comments accepted by SAB
(December 2012- May 2013)
u

SAB briefing on new and
emerging information related to
hydraulicfracturing
(November 2013)

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Technical roundtables*
(December 2013)
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Release draft assessment*
(June 2015)


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SAB peer review of draft assessment
(June 2015-July 2016)
Public comments accepted by SAB
(June 2015-June 2016)
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Release final assessment*
(December 2016)
*Webinars conducted to provide updates

Figure A-l. Timeline of activities in the EPA's hydraulic fracturing study.
On the left are activities related to the development of products from the EPA's hydraulic fracturing study, in the
center are interactions between the EPA and the SAB, and on the right are stakeholder engagement activities.
A-4

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Appendix A - The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
A.l. The EPA's Hydraulic Fracturing Study Publications Cited in This
Assessment
In this section, we provide a table of publications that were completed as part of the EPA's
hydraulic fracturing study and cited in this assessment We also indicate projects that were
originally part of the Study Plan but that did not result in a publication. The full list of publications
under the EPA's hydraulic fracturing study is updated and available at
https://www.epa.gov/hfstudy.
Table A-l. Titles, descriptions, and citations for the EPA's hydraulic fracturing study
publications cited in t
lis assessment.
Research project
Description
Citations/Notes
Analysis of existing data
Literature Review
Review and assessment of existing papers and
reports, focusing on peer-reviewed literature
Literature review is incorporated into
this assessment.
Spills Database Analysis
Characterization of hydraulic fracturing-
related spills using information obtained from
selected state and industry data sources
U.S. EPA (2015i)
Service Company
Analysis
Analysis of information provided by nine
hydraulic fracturing service companies in
response to a September 2010 information
request on hydraulic fracturing operations
Analysis of data received is
incorporated into this assessment.3
Well File Review
Analysis of information provided by nine oil
and gas operators in response to an August
2011 information request for 350 well files
U.S. EPA (2015k)
U.S. EPA (2016a)
Analysis of data received is also
incorporated into this assessment.15
FracFocus Analysis
Analysis of water and chemical use data for
hydraulic fracturing wells compiled from
FracFocus 1.0, the national hydraulic
fracturing chemical registry operated by the
Ground Water Protection Council and the
Interstate Oil and Gas Compact Commission
U.S. EPA (2015a)
U.S. EPA (2015b)
U.S. EPA (2015c)
Scenario evaluations
Subsurface Migration
Modeling
Numerical modeling of subsurface fluid
migration scenarios that explore the potential
for fluids, including liquids and gases, to move
from the fractured zone to drinking water
aquifers
Kim and Moridis (2013)
Kim et al. (2014)
Kim and Moridis (2015)
Kim et al. (2016)
Reagan et al. (2015)
Rutavist et al. (2013)
Rutavist et al. (2015)
A-5

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Appendix A- The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
Research project
Description
Citations/Notes
Surface Water Modeling
Modeling of concentrations of selected
chemicals at public water supplies
downstream from wastewater treatment
facilities that discharge treated hydraulic
fracturing wastewater to surface waters
Weaver et al. (2016)
Water Availability
Modeling
Assessment and modeling of current and
future scenarios exploring the impact of
water usage for hydraulic fracturing on
drinking water availability in the Upper
Colorado River Basin and the Susquehanna
River Basin
U.S. EPA (2015d)
Laboratory studies
Source Apportionment
Studies
Identification and quantification of the
source(s) of high bromide and chloride
concentrations at public water supply intakes
downstream from wastewater treatment
plants discharging treated hydraulic fracturing
wastewater to surface waters
U.S. EPA (20151)
Wastewater Treatability
Studies
Assessment of the efficiency of common
wastewater treatment processes on removing
selected chemicals found in hydraulic
fracturing wastewater
None
Br-DBP Precursor
Studies
Assessment of the ability of bromide and
brominated compounds present in hydraulic
fracturing wastewater to form brominated
disinfection byproducts (Br-DBPs) during
drinking water treatment processes
None
Analytical Method
Development
Development of analytical methods for
selected chemicals found in hydraulic
fracturing fluids or wastewater
DeArmond and DiGoregorio (2013a)
DeArmond and DiGoregorio (2013b)
U.S. EPA (2014b)
U.S. EPA (2014f)
Toxicity assessment
Toxicity Assessment
Toxicity assessment of chemicals reportedly
used in hydraulic fracturing fluids or found in
hydraulic fracturing wastewater
Yost et al. (2016a)
Yost et al. (2016b)
Yost et al. (In Press)
Case studies
Retrospective case studies: Investigations of whether reported drinking water impacts may be associated
with or caused by hydraulic fracturing activities
Las Animas and
Huerfano Counties,
Colorado
Investigation of potential drinking water
impacts from coalbed methane extraction in
the Raton Basin
U.S. EPA (2015h)
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Research project
Description
Citations/Notes
Dunn County, North
Dakota
Investigation of potential drinking water
impacts from a well blowout during hydraulic
fracturing for oil in the Bakken Shale
U.S. EPA (2015f)
Bradford County,
Pennsylvania
Investigation of potential drinking water
impacts from shale gas development in the
Marcellus Shale
U.S. EPA (2014d)
Washington County,
Pennsylvania
Investigation of potential drinking water
impacts from shale gas development in the
Marcellus Shale
U.S. EPA (2015g)
Wise County, Texas
Investigation of potential drinking water
impacts from shale gas development in the
Barnett Shale
U.S. EPA (2015i)
Prospective case studies Investigation of potential impacts of hydraulic fracturing through collection of
samples from a site before, during, and after well pad construction and hydraulic fracturing
The EPA was unable to find suitable locations that met both the scientific criteria of a rigorous prospective
study and the business needs of potential partners.
a Data received and incorporated into this document is cited as: U.S. EPA (U.S. Environmental Protection Agency). (2013). Data
received from oil and gas exploration and production companies, including hydraulic fracturing service companies 2011 to
2013. Non-confidential business information source documents are located in Federal Docket ID: EPA-HQ-ORD2010-0674.
Available at http://www.regulations.gov.
b Data received and incorporated into this document is cited as: U.S. EPA (U.S. Environmental Protection Agency). (2011).
Sampling data for flowback and produced water provided to EPA by nine oil and gas well operators (non-confidential business
information). US Environmental Protection Agency.
http://www.regulations.eov/#!docketDetail:rpp=100:so=DESC:sb=docld:po=0:D=EPA-HQ-QRD-2010-0674.
A.2. Answers to the Secondary Research Questions
The EPA's Study Plan (U.S. EPA. 2011a) was organized around the five stages of the hydraulic
fracturing water cycle. Each stage of the hydraulic fracturing water cycle was associated with a
primary research question (Figure A-2). Nested within each primary research question was a set of
secondary research questions. The primary and secondary research questions provided a
framework for exploring how hydraulic fracturing water cycle activities could potentially impact
drinking water resources. Research projects, undertaken using different types of research
approaches (i.e., analysis of existing data, scenario evaluations, laboratory studies, toxicity
assessment, and case studies), were designed to provide information relevant to answering the
secondary research questions.
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Appendix A- The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
Water Cycle
Stage
Primary
Research
Questions
Primary
Research
Question
Secondary
Research
Questions
Research
Projects
5 Stages
5 Questions
Secondary
Research
Question 1
Research
Project 1
Research
Project 2
Secondary
Research
Question 2
Research
Project 3
Secondary
Research
Question 3
Research
Project 4
17
Questions
Figure A-2. Structure of the EPA's hydraulic fracturing study.
This diagram shows the generalized elements of the study and how they relate to one another.
The primary research questions included:
•	Water acquisition: What are the potential impacts of large volume water withdrawals from
groundwater and surface water on drinking water resources?
•	Chemical mixing: What are the possible impacts of hydraulic fracturing fluid surface spills
on or near well pads on drinking water resources?
•	Well injection: What are the possible impacts of the injection and fracturing process on
drinking water resources?
•	Produced water handling: What are the possible impacts of flowback and produced water
(collectively referred to as "hydraulic fracturing wastewater") surface spills on or near
well pads on drinking water resources?
•	Wastewater disposal and reuse: What are the possible impacts of inadequate treatment of
hydraulic fracturing wastewater on drinking water resources?
In this section we present answers to the secondary research questions posed in the Study Plan as a
way of providing continuity between the Study Plan and this assessment Answers were informed
by the knowledge accumulated and synthesized from the EPA's hydraulic fracturing study,
including the scientific literature reviewed for this assessment
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A.2.1. Water Acquisition
• What are the types of water used for hydraulic fracturing?
The three major types of water used for hydraulic fracturing are surface water, groundwater, and
reused hydraulic fracturing wastewater. Because trucking can be a major expense, operators tend
to use water sources as close to the well pad as possible. Operators usually self-supply surface
water or groundwater directly, but may also obtain water through public water systems or other
suppliers. Hydraulic fracturing operations in the eastern United States rely predominantly on
surface water, whereas operations in more semi-arid to arid western states use either surface
water or groundwater. In some areas of the country, operators rely entirely on groundwater
supplies (e.g., western Texas).
Fresh water (from both surface water and groundwater sources) currently supplies the vast
majority of water used for hydraulic fracturing. However, the reuse of hydraulic fracturing
wastewater for injection reduces the demand on fresh water sources. Nationally, the proportion of
water used in hydraulic fracturing that comes from reused hydraulic fracturing wastewater is
generally low; in a survey of literature values from 10 states, basins, or plays, we found a median
value of 5%, with this percentage varying by location (Table 4-2). Available data on reuse trends
indicate increasing reuse of wastewater over time in both Pennsylvania and West Virginia, likely
due to the lack of nearby disposal options. Reuse as a percentage of water injected is typically lower
in other areas, in part because of the availability of disposal wells (Chapter 8).
• How much water is used per well?
The median amount of water used nationally per hydraulically fractured well was approximately
1.5 million gal (5.7 million L) in 2011 and through early 2013 based on disclosures to FracFocus
(U.S. EPA. 2015a, c). This increased to approximately 2.7 million gal (10.2 million L) in 2014, driven
by a proportional increase in horizontal wells that, on average, use more water per well (estimated
from data reported in Gallegos etal.. 20151 (Figure 4-1). These national estimates represent a
variety of fractured well types, including types requiring much less water per well than horizontal
shale gas wells. Thus, published estimates for horizontal shale gas wells are typically higher (e.g.,
approximately 4 million gal (15 million L) per well fVengosh etal.. 20141. and should not be applied
to all fractured wells to derive national estimates.
There was also wide variation within and among states and basins in the median per well water
volumes reported in 2011 and 2012, from more than 5 million gal (19 million L) in Arkansas and
Louisiana to less than 1 million gal (3.8 million L) in Colorado, Wyoming, Utah, New Mexico, and
California (U.S. EPA. 2015a). This variation results from several factors, including geology, well
length, and fracturing fluid formulation.
• How might cumulative water withdrawals for hydraulic fracturing affect drinking
water quantity?
Hydraulic fracturing uses billions of gallons of water every year at the national and state scales, and
even in some counties. When expressed relative to total water use or consumption at these scales,
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however, hydraulic fracturing generally accounts for only a small percentage, usually less than 1%.
These percentages are higher in specific counties. Annual hydraulic fracturing water use was 10%
or more compared to 2010 total water use in 6.5% of counties with FracFocus disclosures in 2011
and 2012, 30% or more in 2.2% of counties, and 50% or more in 1.0% of counties (see Table B-2).
Consumption estimates follow the same pattern, with higher percentages in each category:
hydraulic fracturing water consumption was 10%, 30%, and 50% or more of 2010 total water
consumption in 13.5%, 6.2%, and 4.0% of counties with FracFocus disclosures (see Table B-2).
Thus, hydraulic fracturing represents a relatively large user and consumer of water in these
counties.
Whether water quantity impacts occur from water acquisition for hydraulic fracturing depends on
the balance between water withdrawals and availability. From our survey of the literature and our
county level assessments, southern and western Texas appear to have the highest potential for
impacts, of the areas assessed in this chapter, given the combination of high hydraulic fracturing
water use, relatively low water availability, intense periods of drought, and reliance on declining
groundwater resources. Importantly, our results do not preclude the possibility of local water
quantity impacts in areas with comparatively lower potential, nor do they necessarily mean
impacts have occurred in the high potential areas. Our survey provides an indicator of areas with
higher potential for impacts, and could be used to target resources for future studies.
Local impacts to drinking water resources have occurred in areas with increased hydraulic
fracturing activity. In a detailed case study, Scanlonetal. (20141 observed generally adequate water
supplies for hydraulic fracturing in the Eagle Ford play in southern Texas, except in specific
locations. They found excessive drawdown of groundwater locally, with estimated declines of
approximately 100 to 200 ft (30 to 60 m) in a small proportion of the play (~6% of the area) after
hydraulic fracturing activity increased in 2009. In 2011, drinking water wells in an area
overlapping the Haynesville Shale ran out of water due to higher-than-normal groundwater
withdrawals and drought fLA Ground Water Resources Commission. 20121. Hydraulic fracturing
water use likely contributed to these conditions, along with other water users and the lack of
precipitation. By contrast, two EPA case studies in the Upper Colorado and the Susquehanna River
Basins found minimal impacts from current hydraulic fracturing water withdrawals (U.S. EPA.
2015dl (Sections 4.5. and 4.5). These site-specific findings emphasize the need to focus on regional
and local dynamics when considering the impacts from hydraulic fracturing water withdrawals.
• What are the possible impacts of water withdrawals for hydraulic fracturing on water
quality?
Water withdrawals for hydraulic fracturing, similar to all water withdrawals, have the potential to
alter the quality of drinking water resources. Groundwater withdrawals exceeding natural recharge
rates decrease water storage in aquifers, potentially mobilizing contaminants or allowing the
infiltration of lower-quality water from the land surface or adjacent formations. Pumping can also
promote changes in reduction-oxidation (redox) conditions and mobilize chemicals from geologic
sources (e.g., uranium). Withdrawals can also decrease groundwater discharge to streams,
potentially affecting surface water quality. Areas with declining groundwater resources,
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particularly in drought-prone regions, are most likely to experience water quality impacts from
hydraulic fracturing water withdrawals.
Surface water withdrawals also have the potential to affect water quality, particularly in smaller
streams. Withdrawals may lower water levels and alter stream flow, decreasing a stream's capacity
to dilute contaminants. Studies by the EPA show that streams can be vulnerable to changes in water
quality due to water withdrawals, most notably smaller streams or during periods of low flow (U.S.
EPA. 2015d). Managing the rate and timing of surface water withdrawals (e.g., passby flows) can
help mitigate potential impacts on water quality.
A.2.2. Chemical Mixing
• What is currently known about the frequency, severity, and causes of spills of
hydraulic fracturing fluids and additives?
There has not been much work on the frequency of spills of hydraulic fracturing fluids and
additives. Using spills data from three states (Pennsylvania, Colorado, and North Dakota), there is
an estimated median of 2.6 reported spills for every 100 wells, with a range of 0.4 to 12.2. These
values are uncertain because these rates used different criteria for including a spill, what the
denominator is for the well type (e.g., drilled or finished), and includes more than hydraulic
fracturing fluids and additives. Using solely the North Dakota database, we estimate 2.6 reported
spills of injected fluid or chemical per 100 wells fractured (Rahm etal., 2015; U.S. EPA. 2015i;
Brantley etal.. 2014: Gradient. 2013).1 Estimates of the frequency of on-site spills from hydraulic
fracturing operations were unavailable for other areas. It is unknown whether these spill estimates
are representative of national occurrences.
The severity of a spill depends on several factors, including: spill amount (mass, volume,
concentration), the fate and transport of the spill, if it reaches a water resource, the characteristics
of the receiving water resource, and the hazard associated with the chemicals themselves. There is
little known on the severity of hydraulic fracturing fluid and additive spills. The reported volume
of chemicals or hydraulic fracturing fluid spilled range of 5 to 19,320 gal (19 to 73,130 L), with a
median volume of 420 gal (1,600 L) per spill. Spill reports contain little information on chemical-
specific spill composition. Spilled fluids were often described by their additive type (e.g., acids,
biocides, friction reducers, cross-linkers, gels,) or as a blended hydraulic fracturing fluid. Specific
chemicals mentioned in spill reports included hydrochloric acid and potassium chloride.
Spill causes included equipment failure, human error, failure of container integrity, and other (e.g.,
weather and vandalism). The most common cause was equipment failure. Equipment failure
included blowout preventer failure, corrosion, and failed valves. More than 30% of the chemical or
hydraulic fracturing fluid spills characterized by the EPA came from fluid storage units (e.g., tanks,
totes, and trailers) (U.S. EPA. 2015i).
1 Spill frequency estimates are for a given number of wells over a given period of time. These are not annual estimates nor
are they for over a lifetime of the wells.
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• What are the identities and volumes of chemicals used in hydraulic fracturing fluids,
and how might this composition vary at a given site and across the country?
The EPA has identified 1,084 different chemicals used in chemical mixing. A recent study of
FracFocus disclosure data reported an additional 263 new CASRNs, increasing the total number of
chemicals identified as used by approximately 24% (Konschnik and Davalu. 20161. Industry use of
confidential business information (CBI) is one factor that likely limits the completeness of these
chemical lists. The EPA's analysis of disclosures to FracFocus 1.0 found that 11% of ingredients
were reported to FracFocus as CBI fU.S. EPA. 2015a). and the more recent analysis by Konschnik
and Davalu (20161 indicated a 5.6% increase in the number of CBI ingredients.
Hydraulic fracturing chemicals cover a wide range of chemical classes and a wide range of
physicochemical properties. The chemicals include acids, aromatic hydrocarbons, bases,
hydrocarbon mixtures, polymers, and surfactants. Thirty-two chemicals, excluding water, quartz,
and sodium chloride, have been reported to be used at 10% or more sites. The ten most common
chemicals (excluding quartz) are methanol, hydrotreated light petroleum distillates, hydrochloric
acid, isopropanol, ethylene glycol, peroxydisulfuric acid diammonium salt, sodium hydroxide, guar
gum, glutaraldehyde, and propargyl alcohol. These chemicals can be present in multiple additives.
Methanol, hydrotreated light petroleum distillates, and hydrochloric acid are the three chemicals
reported to be used in more than half of all frac jobs, with methanol being used at 72% of all sites.
Operators used a median of 14 unique chemicals per well according to the EPA's analysis of
disclosures to FracFocus 1.0 fU.S. EPA. 2015al.
The composition of hydraulic fracturing fluids varies by state, by well, and within the same service
company and geologic formation. This variability likely results from several factors, including the
geology of the formation, production goals, the availability and cost of different chemicals, and
operator preference fU.S. EPA. 2015al.
The estimated median volumes of individual chemicals injected per well ranged from a few gallons
to thousands of gallons, with a median of 650 gal (2,500 L) per chemical per well fU.S. EPA. 2015cl.
There is an estimated 9,100 gal (34,000 L) to 30,000 gal (114,000L) of chemicals used per well.
• What are the chemical, physical, and toxicological properties of hydraulic fracturing
chemical additives?
The EPA identified 1,084 different chemicals reported to be used in hydraulic fracturing fluid from
2005 to 2013. Of these, 455 (more than 40%) were individual organic chemicals with
physicochemical properties that vary, from fully miscible to insoluble and from highly hydrophobic
to highly hydrophilic. We were able to estimate the physicochemical properties of these 455
chemicals using the EPA's Estimation Program Interface (EPI) Suite™ software. Of the 20 most
frequently used chemicals, three have low mobility: (1) distillates, petroleum, hydrotreated light;
(2) solvent naphtha, petroleum, heavy aromatic; and, (3) naphthalene. These chemicals have the
potential to act as long term sources of contamination if spilled on-site.
The chemicals with determinable physicochemical properties were not necessarily the chemicals
most frequently reported as used in hydraulic fracturing fluids or activities. Of the 455 chemicals
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for which physicochemical properties were available, 18 of the top 20 most mobile chemicals were
included in 2% or less of disclosures fU.S. EPA. 2015cl However, two highly mobile chemicals,
choline chloride and tetrakis (hydroxymethyl) phosphonium sulfate were reported in 14% and
11% of disclosures, respectively. These two chemicals are relatively more common, and, if spilled,
would move quickly through the environment with the flow of water.
Of the 1,084 chemicals identified by the EPA as used in hydraulic fracturing fluids, chronic oral RfVs
and/or OSFs from selected federal, state, and international sources were available for 98 (9%) of
these chemicals. From the federal sources alone, chronic oral RfVs were available for 81 chemicals
(7%), and OSFs were available for 15 chemicals (1%). Chronic oral RfVs and OSFs from these
selected sources were not available for the majority of chemicals used in hydraulic fracturing fluid,
representing a potential data gap with regard to hazard identification. Of the chemicals that have
these selected toxicity values, health effects associated with chronic oral exposure include the
potential for carcinogenesis, immune system effects, changes in body weight, changes in blood
chemistry, cardiotoxicity, neurotoxicity, liver and kidney toxicity, and reproductive and
developmental toxicity.
When considering the hazard evaluation of these chemicals on a nationwide scale, chemicals such
as propargyl alcohol stand out for their relatively low RfVs, high frequency of use, and expected
transport and mobility in water. However, the EPA's analysis of disclosures to FracFocus 1.0
indicates that most chemicals are used infrequently on a nationwide scale. Potential exposures to
the majority of these chemicals are likely to be a local issue, rather than a national one. Accordingly,
potential hazard and risk considerations for hydraulic fracturing fluid additives are best made on a
site-specific, well-specific basis.
• If spills occur, how might hydraulic fracturing chemical additives contaminate
drinking water resources?
The potential for spilled fluids to contaminate groundwater or surface water resources depends on
the characteristics of the spill, the environmental fate and transport of the spilled fluid, and spill
response activities. Spill characteristics (e.g., the volume and chemical composition of the spilled
fluid) describe the identity and volume of chemicals that enter the environment due to a spill. The
environmental fate and transport of the spilled fluid describes how spilled chemicals move and
transform in the environment. Spill response activities include actions designed to remove spilled
fluids from the environment Because all of these factors influence whether spilled fluids reach
groundwater and surface water resources, they affect the frequency and severity of potential
impacts to drinking water resources from spills during the chemical mixing stage of the hydraulic
fracturing water cycle.
The movement of spilled hydraulic fracturing fluids and additives through the environment is
difficult to assess, because of the site-specific and chemical-specific nature of spills and because
hydraulic fracturing-related spills typically involve complex mixtures of chemicals. In the absence
of site-specific studies of actual spills, we relied on fundamental environmental fate and transport
principles to describe how hydraulic fracturing fluids and chemicals used in hydraulic fracturing
fluids can move through the environment to drinking water resources.
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The environmental fate and transport of hydraulic fracturing fluids and chemicals depend on site-
specific environmental conditions and the physicochemical properties of the chemicals spilled. Site-
specific environmental characteristics can affect how spilled liquids move through soil into the
subsurface or over the land surface. Generally, highly permeable soils or preferential flow paths can
allow spilled liquids to move quickly into and through the subsurface, limiting the opportunity for
spilled liquids to move over land to surface water resources. When spilled liquids move
underground, the distance between the land surface and the groundwater resource can affect
whether spilled liquids reach groundwater. Large spills volumes are more likely to be able to travel
the distance between the land surface and the groundwater resource and impact the latter. In low
permeability soils, spilled liquids are less able to move into the subsurface and are more likely to
move over the land surface. When spilled liquids move over the land surface, the volume spilled and
the distance between the source of the spill and nearby surface water resources can affect whether
the spilled liquid reaches surface water.
A.2.3. Well Injection
• How effective are current well construction practices at containing fluids—both
liquids and gases—before, during, and after fracturing?
A well will be exposed to the highest stress during the relatively brief phase of injection for
hydraulic fracturing. If the well cannot withstand these stresses, the casing or cement can fail,
resulting in the unintended movement of hydraulic fracturing fluids or naturally-occurring liquids
or gases into the surrounding environment and, potentially, an impact on drinking water quality.
These failures can be the result of inadequate design and/or construction, or degradation of the
casing and/or cement that allows fluid to move laterally from inside the well to the formation or
vertically along the wellbore from the production zone to shallower drinking water resources.
The presence of multiple layers of casing strings can isolate and protect geologic zones containing
drinking water. Most wells used in hydraulic fracturing operations are designed with one or more
of these layers of casing.
Cementing of the surface casing to below the lowest drinking water resource is a key protective
measure to prevent hydraulic fracturing fluids, or other fluids, from reaching drinking water
resources. Most states require this fGWPC. 20141: however, our data indicate adequate casing
and/or cement are not present in all wells. For example, studies in Wyoming and Colorado have
documented wells with partially uncemented surface casing fFleckenstein et al.. 2015: WYOGCC.
20141.
The presence of properly placed, adequate cement in those portions of the well that intersect
porous or permeable water- and/or hydrocarbon-bearing zones can also prevent fluids from
moving into drinking water resources. Wells with cement that does not resist formation or
operational stresses have the potential to promote unintended subsurface fluid movement In
Bainbridge Township, Ohio, hydraulic fracturing was performed in a well with improperly
emplaced and inadequate cement This resulted in natural gas movement upward along the
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wellbore, contamination of the drinking water aquifer, and the loss of 26 private drinking water
wells fBair etal.. 20101.
Even in optimally designed and constructed wells, metal casings and cement can degrade over
time—either as a result of aging or stresses exerted over years of operations—and affect the
integrity of the well. We have limited access to data and information regarding the degree to which
the integrity of wells is verified before or after hydraulic fracturing operations.
• Can subsurface migration of fluids—both liquids and gases—to drinking water
resources occur, and what local geologic or artificial features might allow this?
The presence of artificial penetrations, such as inadequately constructed or degraded offset wells or
undetected abandoned wells near the well undergoing hydraulic fracturing, can provide pathways
that allow fluid movement to drinking water resources. If the fractures created during hydraulic
fracturing intersect a nearby, previously-fractured production well or its fracture network,
hydraulic fracturing fluids or other fluids can move to that well in an event known as well
communication or a "frac hit" flackson etal.. 2013al. Instances of well communication have
occurred in New Mexico (Vaidvanathan. 20141 and Texas (Craig etal.. 20121. Additionally,
abandoned wells near a well undergoing hydraulic fracturing can provide a pathway for vertical
fluid movement to drinking water resources, if those wells were not properly plugged or the plugs
and cement have degraded over time. This can be a significant issue in areas with legacy (i.e.,
historic) oil and gas exploration and when wells are re-entered and fractured (or re-fractured) to
increase production in a reservoir.
Some hydraulic fracturing operations involve the injection of fluids into formations with relatively
limited vertical separation from drinking water resources. Where the separation between the
production zone and drinking water resource is small, and where natural or induced fractures
transecting the layers between these formations are present, there is an increased potential for
impacts to drinking water quality.
Hydraulic fracturing is also performed within formations that meet the salinity threshold used in
some definitions of a drinking water resource, in addition to the broader definition of a drinking
water resource developed for this assessment By definition, these hydraulic fracturing operations
affect the quality of the drinking water resources.
A.2.4. Produced Water Handling
• What is currently known about the frequency, severity, and causes of spills offlowback
and produced water?
Surface spills of produced water from unconventional oil and gas production have occurred across
the country. Some produced water spills have affected drinking water resources, including private
drinking water wells. Analysis of data from North Dakota suggests a produced water spill rate of 5
to 7 spills per 100 active production wells. Of these, an estimated 84% are confined to the
production or exploration facility and expected to have a lower potential to impact drinking water
resources. Half of the spills are estimated to be less than 1,000 gal (3,800 L), but a small number of
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large spills have occurred. For example, in North Dakota in 2015, there were 12 releases of 21,000
gal (79,000 L) or more out of a total of 609 spills. The largest reported spill was 2.9 million gal (11.0
million L). The causes identified for these spills are container and equipment failures, human error,
well communication, blowouts, pipeline leaks, and dumping. Although specific impacts from a few
spills have been documented, the severity of most spills is unknown.
• What is the composition of hydraulic fracturing flowback and produced water, and
what factors might influence this composition?
The geochemical content of water flowing back initially reflects injected fluids. After initial
flowback, returning fluid geochemistry shifts to reflect the geochemistry of formation waters and
formation solids. According to the available literature and data, conventional and unconventional
produced water content are often similar with respect to the occurrence and concentration of many
constituents. Much produced water is generally characterized as saline (with the exception of most
coalbed methane produced water) and enriched in major anions, cations, metals, naturally
occurring radionuclides, and organics. The composition of produced water must be determined
through sampling and analysis, both of which have limitations. Sampling limitations include
equipment configurations that make it difficult to access representative fluids. Analytical
limitations include identifying target analytes in advance, without sufficient knowledge of the
composition of the fluid sampled, as well as the lack of appropriate analytical methods.
Typically, unconventional produced water contains low levels of heavy metals. However, elevated
strontium and barium levels are characteristic of Marcellus Shale produced water. Elevated levels
of technologically enhanced naturally occurring radioactive materials (TENORM) have also been
documented in the Marcellus Shale produced water. Other formations also contain TENORM, but
fewer data are available. Composition data were limited, in general. Most of the available data on
produced water content were for shale formations and CBM basins, while few data were available
for sandstone formations.
Recent published research has identified several hundred organic chemicals in produced water.
Many of these are naturally-occurring constituents of petroleum, while fewer are known hydraulic
fracturing chemicals. The identification of many organic chemicals in produced water depends on
the availability of advanced laboratory analytical methods and equipment Much less is known
about subsurface transformation products and only a few have been identified. Recent research
shows that subsurface transformation reactions may reduce concentrations of some hydraulic
fracturing additives through oxidation (gelling agents and friction reducers), may create
chlorinated and brominated organic compounds, and that surfactants (i.e., glycols) may be resistant
to degradation and remain in produced water.
Hydraulic fracturing flowback and produced water composition is influenced by the composition of
injected hydraulic fracturing fluids, the targeted geological formation and associated hydrocarbon
products, the stratigraphic environment, and subsurface processes and residence time. Spatial
variability of produced water content occurs between plays of different rock type (e.g., coal vs.
sandstone), between plays of the same rock type (e.g., Barnett Shale vs. Bakken Shale), and within
formations of the same source rock (e.g., northeastern vs. southwestern Marcellus Shale).
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• What are the chemical, physical, and toxicological properties of hydraulic fracturing
flowback and produced water constituents?
This assessment identified 599 chemicals that are reported to have been detected in hydraulic
fracturing produced water. These include chemicals that are added to hydraulic fracturing fluids
during the chemical mixing stage, as well as naturally occurring organic chemicals, metals, naturally
occurring radioactive material, and other subterranean chemicals that may be mobilized by the
hydraulic fracturing process.
The identified constituents of produced water include inorganic chemicals (cations and anions in
the form of metals, metalloids, non-metals, and radioactive materials), organic chemicals and
compounds, and unidentified materials measured as TOC (total organic carbon) and DOC (dissolved
organic carbon). Some constituents are readily transported with water (i.e., chloride and bromide),
while others depend strongly on the geochemical conditions in the receiving water body (i.e.,
radium and barium), and assessment of their transport is based on site-specific factors. Using the
EPA's EPI Suite software, we were able to obtain actual or estimated physicochemical properties for
521 (87%) individual organic chemicals of the 599 chemicals identified in produced water. The EPI
Suite™ results are constrained by their applicability to one temperature (25 °C), and salinity (low).
Temperature changes impact Henry's law constant, Kow, and solubility, and depend on the
characteristics of the chemical and ions present. In some cases, the effect changes exponentially
with salinity. Therefore, property values that depart from the EPI Suite™ values are expected for
the 599 chemicals identified in produced water at elevated temperature and salinity. Although little
is known concerning attenuation of hydraulic fracturing fluid constituents, Kekacs etal. (2015)
report that salinity above 40,000 mg/L initially inhibited aerobic degradation of the organic
constituents of a synthetic fracturing fluid (for 6.5 days), even though the bacterial communities
were pre-acclimated to the salts.
Of the 599 chemicals identified by the EPA as detected in produced water, chronic oral RfVs and/or
OSFs from selected federal, state, and international sources were available for 120 (20%) of these
chemicals. From the federal sources alone, chronic oral RfVs were available for 97 chemicals (16%),
and OSFs were available for 30 chemicals (5%). Of the chemicals that have these selected toxicity
values, health effects associated with chronic oral exposure include the potential for carcinogenesis,
immune system effects, changes in body weight, changes in blood chemistry, pulmonary toxicity,
neurotoxicity, liver and kidney toxicity, and reproductive and developmental toxicity.
In a hazard evaluation of produced water data, chemicals such as benzene, pyridine, and
naphthalene stood out for their relatively lower RfVs, high average concentrations, and expected
transport and mobility in water. However, the chemicals present in produced water are likely to
vary on a regional and well-specific basis as a result of geological differences, as well as differences
between hydraulic fracturing fluid formulations. Therefore, potential hazard and risk
considerations are best made on a site-specific basis.
A-17

-------
Appendix A- The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
• If spills occur, how might hydraulic fracturing flowback and produced water
contaminate drinking water resources?
Both the scientific literature and published reports have shown that produced water spills have
impacted drinking water resources. Spills of produced water may impact drinking water resources
if the spill or release is of sufficient volume and duration to reach the resource at a sufficient
concentration. During the first few months of production produced water is most likely to contain
hydraulic fracturing additives and have low salinity. Later, the composition of shale-gas produced
water will be dominated by high salinity. Spilled produced water can flow overland to reach surface
water resources. Some of that water might infiltrate to impact soils and groundwater. Which path
the spill takes depends on different conditions, such as the distance to a water receptor, spill
volume, soil characteristics, and the physicochemical properties of the chemical. Of the produced
water spills documents by the EPA, 17 (8%) reached surface water resources and 1 (0.4%) was
documented to reach groundwater (U.S. EPA. 2015H. although groundwater impacts from 107
additional spills were unknown. More spills (141 or 63%) impacted soil, and the impacts of 30
spills were unknown.
A.2.5. Wastewater Disposal and Reuse
• What are the common treatment and disposal methods for hydraulic fracturing
wastewater, and where are these methods practiced?
The majority of hydraulic fracturing wastewater in the United States is disposed of via underground
injection wells. As of 2014-2015, most states where hydraulic fracturing occurs have access to an
adequate number of Class IID injection wells regulated under the Underground Injection Control
(UIC) Program. The Marcellus Shale region, especially the northeastern region, is an exception. Due
to the lack of available injection wells, wastewater reuse, with or without treatment beforehand (at
centralized waste treatment facilities (CWTs) or mobile facilities), is currently the primary means
of wastewater management and may continue to increase in western shale plays as the practice
becomes encouraged and economically favorable. Other methods of management used to a lesser
degree include evaporation and agricultural use (for low-total dissolved solids (TDS) wastewater),
both of which occur in the western United States.
• How effective are conventional POTWs and commercial treatment systems in
removing organic and inorganic contaminants of concern in hydraulic fracturing
wastewater?
Publicly owned treatment works (POTWs) using basic treatment processes cannot effectively
reduce TDS concentrations in highly saline hydraulic fracturing wastewater. CWTs that use
advanced treatment processes such as mechanical vapor recompression, distillation, and reverse
osmosis have been shown to remove TDS constituents with removal efficiencies ranging from 97%
to over 99% (Table F-4). These advanced treatment processes can also remove other constituents
found in hydraulic fracturing wastewater such as metals, cations, anions, and some organics.
A-18

-------
Appendix A - The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
Indirect discharge, where wastewater is pretreated by a CWT and sent to a POTW, may be an
effective option for hydraulic fracturing wastewater treatment (with restrictions on contaminant
concentrations in the pretreated wastewater). This option would require careful planning to ensure
that the pretreated wastewater blended with POTW influent is of appropriate quality to prevent
deleterious effects on biological processes in the POTW or the pass-through of contaminants.
Facilities that treat wastewater for reuse and employ only basic treatment are unable to remove all
contaminants in hydraulic fracturing wastewater, especially if the CWTs do not include specific
processes (e.g., distillation, advanced oxidation, adsorption) that target constituents of concern.
Depending on the water quality requirements for a particular site, these lower quality treated
waters may be of adequate quality for reuse in subsequent hydraulic fracturing operations (and will
be less costly).
• What are the potential impacts from surface water disposal of treated hydraulic
fracturing wastewater on drinking water treatment facilities?
Inadequate bromide and iodide removal from treated hydraulic fracturing wastewater has the
potential to affect surface water quality and place a burden on downstream drinking water
treatment facilities due to the formation of disinfection byproducts (DBPs). This occurs when
bromide and iodide react with organic carbon and drinking water disinfectants. Although sampling
data are limited both for treated wastewaters and receiving waters, bromide has reached drinking
water resources via some discharges. One utility in Pennsylvania found that elevated bromide in
their source water led to elevated disinfection byproducts in their treated drinking water.
Ammonium in hydraulic fracturing wastewater could also impact downstream drinking water
supplies by altering disinfection chemistry. Other constituents (e.g., including radionuclides,
barium, and organic compounds) may impact drinking water resources if they are present in high
concentrations in the wastewater and the applied wastewater treatment does not adequately
remove them. Constituents such as radium, metals, and organics can also accumulate in sediments
downstream of discharge points.
As of 2014-2015, there is a lack of data on the concentrations of most hydraulic fracturing
wastewater constituents in the water near drinking water intakes in regions with hydraulic
fracturing activity. Therefore, it is not known whether or to what degree these contaminants have
affected drinking water systems.
A-19

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Appendix A- The EPA's Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources
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A-20

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Appendix B - Water Acquisition Supplemental Information
Appendix B. Water Acquisition Supplemental
Information
B-l

-------
Appendix B - Water Acquisition Supplemental Information
This page is intentionally left blank.
B-2

-------
Appendix B - Water Acquisition Supplemental Information
Appendix B. Water Acquisition Supplemental
Information
B.l. Supplemental Tables
Table B-l. Average annual hydraulic fracturing water use and consumption in 2011 and 2012
compared to total annual water use and consumption in 2010 by state.
Hydraulic fracturing water use data from the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). Annual total
water use data from the U.S. Geological Survey (USGS) Water Census (Maupin et al., 2014). Estimates of
consumption were derived from hydraulic fracturing water use and total water use data. States listed in
descending order by the volume of hydraulic fracturing water use.
State
Total annual water
use in 2010
(millions of gal)a b
Average annual
hydraulic
fracturing water
use in 2011 and
2012
(millions of gal)c
Hydraulic
fracturing water
use compared to
total water use
(%)d
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)d'e
Texas
9,052,000
19,942
0.2
0.7
Pennsylvania
2,967,450
5,105
0.2
1.4
Arkansas
4,124,500
3,676
0.1
0.1
Colorado
4,015,000
3,277
0.1
0.1
Oklahoma
1,157,050
2,949
0.3
0.8
Louisiana
3,117,100
2,462
0.1
0.4
North Dakota
419,750
2,181
0.5
2.9
West Virginia
1,288,450
657
0.1
0.5
Wyoming
1,715,500
538
<0.1
<0.1
New Mexico
1,153,400
371
<0.1
<0.1
Ohio
3,445,600
273
<0.1
0.1
Utah
1,627,900
251
<0.1
<0.1
Montana
2,792,250
155
<0.1
<0.1
Kansas
1,460,000
66
<0.1
<0.1
California
13,870,000
44
<0.1
<0.1
Michigan
3,942,000
28
<0.1
<0.1
Mississippi
1,434,450
18
<0.1
<0.1
B-3

-------
Appendix B - Water Acquisition Supplemental Information
State
Total annual water
use in 2010
(millions of gal)a'b
Average annual
hydraulic
fracturing water
use in 2011 and
2012
(millions of gal)c
Hydraulic
fracturing water
use compared to
total water use
(%)d
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)d'e
Alaska'
397,850
7
<0.1
<0.1
Virginia
2,792,250
1
<0.1
<0.1
Alabama
3,635,400
1
<0.1
<0.1
Total for all 20 states
64,407,900
42,001
0.1
0.2
a Texas, Colorado, Pennsylvania, North Dakota, Oklahoma, and Utah all made some degree of reporting to the FracFocus
national registry mandatory rather than voluntary during this time period analyzed, January 1, 2011, to February 28, 2013.
Three other states started requiring disclosure to either FracFocus or the state (Louisiana, Montana, and Ohio), and five states
required or began requiring disclosure to the state (Arkansas, Michigan, New Mexico, West Virginia, and Wyoming). Alabama,
Alaska, California, Kansas, Mississippi, and Virginia did not have reporting requirements during the period of time studied (U.S.
EPA. 2015a).
bState-level data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on January 27, 2015. Total water
withdrawals per day (located in downloaded Table 1) were multiplied by 365 days to estimate total water use for the year
(Maupin et al.. 2014).
c Average of water used for hydraulic fracturing in 2011 and 2012 based on the EPA FracFocus 1,0 project database (U.S. EPA.
2015c).
d Percentages were calculated by averaging annual water use for hydraulic fracturing in the EPA FracFocus 1.0 project database
in 2011 and 2012 for a given state (U.S. EPA. 2015c). and then dividing by 2010 USGS total water use (Maupin et al.. 2014) and
multiplying by 100. Note that the annual hydraulic fracturing water use based on the EPA FracFocus 1.0 project database (the
numerator) was not added to the 2010 total USGS water use value in the denominator, and the percentage is simply calculated
as by dividing annual hydraulic fracturing use by 2010 total water use or consumption. This was done because of the difference
in years between the two datasets, and because the USGS 2010 Census (Maupin et al.. 2014) already included an estimate of
hydraulic fracturing water use in its mining category. This approach is also consistent with that of other literature on this topic;
see Nicot and Scanlon (2012).
e Consumption values were calculated with use-specific consumption rates predominantly from the USGS, including 19.2% for
public supply, 19.2% for domestic use, 60.7% for irrigation, 60.7% for livestock, 14.8% for industrial uses, 14.8% for mining
(Sollev et al.. 1998). and 2.7% for thermoelectric power (Diehl and Harris. 2014). We used a rate of 71.6% for aquaculture
(Verdegem and Bosma. 2009) (evaporation per kg fish + infiltration per kg)/(total water use per kg) *100. These rates were
multiplied by each USGS water use value (Maupin et al.. 2014) to yield a total water consumption estimate. To calculate a
consumption amount for hydraulic fracturing, we used a consumption rate of 82.5%. This was calculated by taking the median
value for all reported produced water/injected water percentages in Tables 7-1 and 7-2 of this assessment and then subtracting
from 100%. If a range of values was given, the midpoint was used. Note that this is likely a low estimate of consumption since
much of this return water is not subsequently treated and reused, but rather disposed of in injection wells—see Chapter 8.
f All reported hydraulic fracturing disclosures for Alaska passed state locational quality assurance methods, but not county
methods (U.S. EPA. 2015c). Thus, only state-level cumulative values were reported here, and no county-level data are provided
in subsequent tables.
B-4

-------
Appendix B - Water Acquisition Supplemental Information
Table B-2. Average annual hydraulic fracturing water use and consumption in 2011 and 2012
compared to total annual water use and consumption in 2010 by county.
The counties listed contained wells used for hydraulic fracturing based on the EPA FracFocus 1.0 project database
(U.S. EPA, 2015c). Annual total water use data from the USGS Water Census (Maupin et al., 2014). Estimates of
consumption derived from hydraulic fracturing water use and total water use data.
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Alabama
Jefferson
29,685.5
0.6
<0.1
<0.1

Tuscaloosa
14,319.0
0.5
<0.1
<0.1
Arkansas
Cleburne
9,471.8
740.9
7.8
32.9

Conway
10,643.4
798.1
7.5
21.2

Faulkner
3,204.7
284.0
8.9
13.7

Independence
57,195.5
80.3
0.1
0.3

Logan
1,525.7
2.4
0.2
0.3

Sebastian
1,365.1
0.6
<0.1
<0.1

Van Buren
1,587.8
899.6
56.7
168.8

White
32,131.0
869.8
2.7
4.7
California
Yell
1,507.5
<0.1
<0.1
<0.1

Colusa
304,782.3
<0.1
<0.1
<0.1

Glenn
221,420.0
<0.1
<0.1
<0.1

Kern
788,359.9
41.7
<0.1
<0.1

Los Angeles
1,118,363.7
0.2
<0.1
<0.1

Sutter
263,511.8
0.2
<0.1
<0.1

Ventura
262,610.2
1.8
<0.1
<0.1
Colorado
Adams
84,285.8
3.2
<0.1
<0.1

Arapahoe
68,255.0
4.0
<0.1
<0.1

Boulder
84,537.7
4.1
<0.1
<0.1

Broomfield
2,336.0
4.5
0.2
0.4

Delta
131,221.2
0.5
<0.1
<0.1
B-5

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Colorado,
Dolores
2,040.4
0.1
<0.1
<0.1
cont.
El Paso
42,380.2
<0.1
<0.1
<0.1

Elbert
5,040.7
<0.1
<0.1
<0.1

Fremont
53,366.7
0.6
<0.1
<0.1

Garfield
95,436.6
1,804.2
1.9
2.7

Jackson
126,968.9
1.0
<0.1
<0.1

La Plata
122,873.6
3.5
<0.1
<0.1

Larimer
150,690.3
5.4
<0.1
<0.1

Las Animas
26,911.5
7.9
<0.1
<0.1

Mesa
275,476.5
122.1
<0.1
0.1

Moffat
62,093.8
14.5
<0.1
<0.1

Morgan
67,901.0
3.9
<0.1
<0.1

Phillips
21,509.5
0.2
<0.1
<0.1

Rio Blanco
97,513.4
147.3
0.2
0.2

Routt
74,460.0
0.1
<0.1
<0.1

San Miguel
13,848.1
0.3
<0.1
<0.1

Weld
168,677.5
1,149.4
0.7
1.0

Yuma
80,595.7
0.4
<0.1
<0.1
Kansas
Barber
2,164.5
9.9
0.5
0.7

Clark
1,898.0
0.8
<0.1
0.1

Comanche
3,011.3
25.6
0.9
1.2

Finney
102,685.5
2.4
<0.1
<0.1

Grant
47,128.8
0.2
<0.1
<0.1

Gray
69,379.2
3.3
<0.1
<0.1

Harper
1,357.8
17.3
1.3
2.0

Haskell
72,496.3
0.1
<0.1
<0.1
B-6

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Kansas, cont.
Hodgeman
8,460.7
2.7
<0.1
<0.1

Kearny
64,134.2
<0.1
<0.1
<0.1

Lane
5,628.3
0.8
<0.1
<0.1

Meade
55,958.2
<0.1
<0.1
<0.1

Morton
17,403.2
<0.1
<0.1
<0.1

Ness
1,478.3
1.6
0.1
0.2

Seward
57,443.7
<0.1
<0.1
<0.1

Sheridan
26,393.2
0.7
<0.1
<0.1

Stanton
41,420.2
<0.1
<0.1
<0.1

Stevens
72,124.0
0.1
<0.1
<0.1

Sumner
3,442.0
0.2
<0.1
<0.1
Louisiana
Allen
8,942.5
0.1
<0.1
<0.1

Beauregard
10,161.6
2.3
<0.1
0.1

Bienville
4,810.7
108.9
2.3
10.0

Bossier
5,599.1
110.1
2.0
4.9

Caddo
53,644.1
153.6
0.3
1.7

Calcasieu
81,621.3
0.1
<0.1
<0.1

Caldwell
1,398.0
<0.1
<0.1
<0.1

Claiborne
952.7
3.8
0.4
1.1

DeSoto
13,373.6
1,085.9
8.1
47.4

East Feliciana
1,350.5
3.7
0.3
0.7

Jackson
1,456.4
<0.1
<0.1
<0.1

Lincoln
3,000.3
3.3
0.1
0.3

Natchitoches
12,530.5
12.7
0.1
0.2

Rapides
199,976.2
1.7
<0.1
<0.1

Red River
1,606.0
569.6
35.5
83.2
B-7

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Louisiana, cont.
Sabine
1,522.1
395.2
26.0
76.6

Tangipahoa
7,329.2
1.9
<0.1
0.1

Union
1,481.9
4.9
0.3
1.0

Webster
2,664.5
1.2
<0.1
0.1

West Feliciana
15,191.3
2.3
<0.1
0.1

Winn
846.8
1.1
0.1
0.4
Michigan
Cheboygan
2,777.7
<0.1
<0.1
<0.1

Gladwin
850.5
1.1
0.1
0.4

Kalkaska
1,233.7
24.0
1.9
3.7

Missaukee
1,423.5
<0.1
<0.1
<0.1

Ogemaw
1,179.0
<0.1
<0.1
<0.1

Roscommon
1,000.1
2.4
0.2
0.9
Mississippi
Amite
792.1
14.4
1.8
3.8

Wilkinson
1,270.2
3.2
0.3
0.4
Montana
Daniels
1,408.9
0.6
<0.1
0.1

Garfield
1,631.6
0.5
<0.1
<0.1

Glacier
46,760.2
5.1
<0.1
<0.1

Musselshell
26,827.5
0.4
<0.1
<0.1

Richland
94,797.8
83.5
0.1
0.1

Roosevelt
31,539.7
52.1
0.2
0.2

Rosebud
71,412.3
3.5
<0.1
<0.1

Sheridan
7,354.8
9.7
0.1
0.2
New Mexico
Chaves
88,078.2
2.8
<0.1
<0.1

Colfax
17,450.7
0.7
<0.1
<0.1

Eddy
70,612.9
225.6
0.3
0.5
B-8

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
New Mexico,
cont.
Harding
1,168.0
0.1
<0.1
<0.1

Lea
64,057.5
113.7
0.2
0.3

Rio Arriba
39,080.6
16.5
<0.1
0.1

Roosevelt
63,367.7
<0.1
<0.1
<0.1

San Juan
125,432.3
11.6
<0.1
<0.1

Sandoval
23,922.1
0.4
<0.1
<0.1
North Dakota
Billings
762.9
44.4
5.8
16.2

Bottineau
1,164.4
0.1
<0.1
<0.1

Burke
394.2
63.6
16.1
40.8

Divide
806.7
102.2
12.7
18.6

Dunn
1,076.8
309.5
28.7
43.1

Golden Valley
208.1
4.6
2.2
3.8

Mckenzie
13,753.2
588.4
4.3
6.2

Mclean
7,873.1
12.2
0.2
0.4

Mountrail
1,248.3
449.4
36.0
98.3

Stark
1,168.0
48.0
4.1
8.5

Williams
7,705.2
558.5
7.2
11.3
Ohio
Ashland
2,033.1
1.5
0.1
0.2

Belmont
65,528.5
1.9
<0.1
0.1

Carroll
1,127.9
152.7
13.5
37.3

Columbiana
3,763.2
30.7
0.8
2.2

Coshocton
53,775.5
5.4
<0.1
0.1

Guernsey
2,379.8
8.4
0.4
0.7

Harrison
481.8
16.5
3.4
7.3

Jefferson
632,917.3
26.2
<0.1
0.1
B-9

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Ohio, cont.
Knox
3,270.4
l.l
<0.1
0.1

Medina
3,540.5
1.3
<0.1
0.1

Muskingum
6,018.9
5.1
0.1
0.3

Noble
478.2
8.3
1.7
3.4

Portage
18,414.3
3.2
<0.1
0.1

Stark
16,479.8
2.4
<0.1
<0.1

Tuscarawas
14,165.7
6.7
<0.1
0.2

Wayne
6,051.7
1.7
<0.1
0.1
Oklahoma
Alfalfa
2,996.7
182.7
6.1
12.0

Beaver
15,341.0
23.1
0.2
0.3

Beckham
4,099.0
108.0
2.6
4.7

Blaine
3,763.2
203.3
5.4
9.3

Bryan
5,062.6
10.3
0.2
0.4

Caddo
24,064.5
25.4
0.1
0.3

Canadian
5,584.5
441.9
7.9
15.6

Carter
159,906.5
161.9
0.1
0.5

Coal
1,193.6
85.9
7.2
21.5

Custer
3,281.4
19.0
0.6
1.2

Dewey
10,953.7
162.6
1.5
6.2

Ellis
8,486.3
184.3
2.2
3.2

Garvin
16,279.0
15.0
0.1
0.4

Grady
13,537.9
111.5
0.8
2.3

Grant
5,569.9
77.8
1.4
5.2

Harper
3,266.8
8.8
0.3
0.4

Hughes
3,394.5
30.5
0.9
2.2

Jefferson
4,496.8
<0.1
<0.1
<0.1
B-10

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Oklahoma,
cont.
Johnston
1,671.7
32.9
2.0
4.7
Kay
16,957.9
17.3
0.1
0.4
Kingfisher
3,744.9
10.2
0.3
0.5
Kiowa
5,022.4
0.1
<0.1
<0.1
Latimer
1,062.2
0.6
0.1
0.1
Le Flore
8,635.9
0.3
<0.1
<0.1
Logan
4,077.1
4.2
0.1
0.3
Love
2,011.2
4.4
0.2
0.5
Major
6,321.8
1.2
<0.1
<0.1
Marshall
2,613.4
98.4
3.8
7.2
McClain
2,952.9
2.1
0.1
0.2
Noble
12,990.4
25.3
0.2
1.8
Oklahoma
47,836.9
1.2
<0.1
<0.1
Osage
6,971.5
3.8
0.1
0.2
Pawnee
4,839.9
15.7
0.3
1.4
Payne
4,332.6
9.9
0.2
0.6
Pittsburg
6,314.5
349.0
5.5
16.0
Roger Mills
2,847.0
235.5
8.3
12.6
Seminole
124,837.3
0.1
<0.1
<0.1
Stephens
49,990.4
27.7
0.1
0.3
Texas
110,208.1
0.1
<0.1
<0.1
Washita
3,310.6
102.1
3.1
5.4
Woods
4,139.1
155.1
3.7
10.9
B-ll

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Pennsylvania
Allegheny
234,140.2
13.6
<0.1
<0.1

Armstrong
65,853.3
55.7
0.1
1.8

Beaver
157,793.2
30.5
<0.1
0.2

Blair
8,303.8
5.9
0.1
0.2

Bradford
4,354.5
1,059.4
24.3
78.2

Butler
5,730.5
121.8
2.1
6.0

Cameron
292.0
6.6
2.3
4.1

Centre
16,560.1
38.5
0.2
0.5

Clarion
1,843.3
8.1
0.4
1.4

Clearfield
111,051.3
111.5
0.1
2.3

Clinton
6,161.2
94.4
1.5
3.0

Columbia
3,810.6
5.6
0.1
0.4

Crawford
5,091.8
2.4
<0.1
0.1

Elk
7,876.7
37.5
0.5
1.9

Fayette
16,465.2
120.2
0.7
2.7

Forest
744.6
7.7
1.0
1.6

Greene
13,023.2
359.0
2.8
24.7

Huntingdon
5,121.0
2.7
0.1
0.2

Indiana
21,819.7
16.2
0.1
0.7

Jefferson
1,730.1
13.8
0.8
1.7

Lawrence
36,598.6
27.0
0.1
1.0

Lycoming
5,854.6
704.6
12.0
33.8

McKean
4,723.1
60.5
1.3
4.9

Potter
2,281.3
16.5
0.7
1.0

Somerset
10,833.2
5.8
0.1
0.2

Sullivan
222.7
66.5
29.9
79.8
B-12

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Pennsylvania,
cont.
Susquehanna
1,617.0
751.3
46.5
123.4

Tioga
2,909.1
566.3
19.5
47.3

Venango
2,989.4
2.4
0.1
0.3

Warren
5,099.1
2.3
<0.1
0.2

Washington
130,535.0
433.7
0.3
4.6

Westmoreland
14,607.3
207.0
1.4
3.8

Wyoming
4,788.8
150.0
3.1
15.2
Texas
Andrews
23,363.7
236.2
1.0
2.7

Angelina
5,540.7
0.8
<0.1
<0.1

Archer
2,536.8
0.1
<0.1
<0.1

Atascosa
15,038.0
327.3
2.2
4.0

Austin
2,555.0
2.1
0.1
0.1

Bee
3,087.9
20.0
0.6
1.1

Borden
2,427.3
8.0
0.3
1.0

Bosque
3,544.2
0.7
<0.1
<0.1

Brazos
24,790.8
7.7
<0.1
0.1

Brooks
1,204.5
1.5
0.1
0.3

Burleson
10,694.5
3.0
<0.1
<0.1

Cherokee
24,845.6
0.5
<0.1
<0.1

Clay
1,963.7
<0.1
<0.1
<0.1

Cochran
24,035.3
3.0
<0.1
<0.1

Coke
12,713.0
0.3
<0.1
<0.1

Colorado
52,465.1
0.1
<0.1
<0.1

Concho
2,832.4
<0.1
<0.1
<0.1

Cooke
4,533.3
454.3
10.0
29.9
B-13

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Texas, cont.
Cottle
733.7
0.3
<0.1
0.1

Crane
8,566.6
92.3
l.i
5.7

Crockett
4,281.5
279.0
6.5
29.5

Crosby
27,261.9
1.3
<0.1
<0.1

Culberson
14,311.7
37.7
0.3
0.4

Dallas
112,204.7
5.6
<0.1
<0.1

Dawson
28,842.3
17.5
0.1
0.1

DeWitt
2,394.4
546.6
22.8
48.6

Denton
60,684.9
455.0
0.7
2.3

Dimmit
4,073.4
1,794.2
44.0
81.3

Ector
21,958.4
226.5
1.0
4.6

Edwards
332.2
<0.1
<0.1
<0.1

Ellis
8,530.1
4.2
<0.1
0.1

Erath
5,876.5
0.8
<0.1
<0.1

Fayette
9,008.2
13.7
0.2
1.2

Fisher
2,854.3
1.8
0.1
0.1

Franklin
1,956.4
<0.1
<0.1
<0.1

Freestone
297,861.9
53.9
<0.1
0.5

Frio
20,589.7
127.5
0.6
0.9

Gaines
121,778.6
21.6
<0.1
<0.1

Garza
5,234.1
0.6
<0.1
<0.1

Glasscock
20,680.9
598.1
2.9
4.2

Goliad
142,963.2
<0.1
<0.1
<0.1

Gonzales
7,121.2
577.9
8.1
17.6

Grayson
8,143.2
9.3
0.1
0.3

Gregg
33,010.6
9.4
<0.1
0.2
B-14

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Texas, cont.
Grimes
112,500.3
15.5
<0.1
0.3

Hansford
43,643.1
2.9
<0.1
<0.1

Hardeman
2,230.2
0.4
<0.1
<0.1

Hardin
2,376.2
0.1
<0.1
<0.1

Harrison
11,869.8
141.6
1.2
6.0

Hartley
113,555.2
1.9
<0.1
<0.1

Haskell
12,143.6
0.1
<0.1
<0.1

Hemphill
3,150.0
263.9
8.4
16.3

Hidalgo
171,630.3
8.0
<0.1
<0.1

Hockley
46,314.9
3.0
<0.1
<0.1

Hood
9,351.3
76.0
0.8
2.2

Houston
3,686.5
8.6
0.2
0.6

Howard
10,811.3
97.6
0.9
2.7

Hutchinson
34,437.8
0.3
<0.1
<0.1

Irion
1,335.9
411.4
30.8
74.5

Jack
2,241.1
14.0
0.6
2.2

Jefferson
88,585.5
<0.1
<0.1
<0.1

Jim Hogg
306.6
0.1
<0.1
0.1

Johnson
9,241.8
582.0
6.3
18.5

Jones
5,679.4
<0.1
<0.1
<0.1

Karnes
1,861.5
1,055.2
56.7
120.1

Kenedy
456.3
0.2
0.1
0.1

Kent
6,132.0
0.4
<0.1
<0.1

King
1,485.6
<0.1
<0.1
<0.1

Kleberg
1,171.7
3.4
0.3
0.5

Knox
9,800.3
<0.1
<0.1
<0.1
B-15

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Texas, cont.
La Salle
2,474.7
1,288.7
52.1
93.7

Lavaca
3,763.2
45.0
1.2
2.0

Lee
3,120.8
1.2
<0.1
0.1

Leon
2,171.8
56.2
2.6
6.6

Liberty
20,662.7
<0.1
<0.1
<0.1

Limestone
11,158.1
10.7
0.1
0.9

Lipscomb
11,015.7
89.0
0.8
1.1

Live Oak
1,916.3
294.0
15.3
40.1

Loving
781.1
138.4
17.7
94.1

Lynn
19,892.5
1.1
<0.1
<0.1

Madison
1,554.9
45.3
2.9
8.2

Marion
3,606.2
5.9
0.2
0.9

Martin
14,063.5
432.0
3.1
4.7

Maverick
20,498.4
52.4
0.3
0.4

McMullen
657.0
745.9
113.5
350.4

Medina
19,228.2
0.2
<0.1
<0.1

Menard
1,014.7
<0.1
<0.1
<0.1

Midland
12,891.8
307.4
2.4
3.7

Milam
16,665.9
4.9
<0.1
0.1

Mitchell
6,559.1
11.0
0.2
0.3

Montague
3,989.5
925.3
23.2
77.8

Montgomery
32,565.3
0.2
<0.1
<0.1

Moore
57,075.1
<0.1
<0.1
<0.1

Nacogdoches
5,891.1
271.7
4.6
12.5

Navarro
18,699.0
4.8
<0.1
0.1

Newton
2,263.0
0.2
<0.1
<0.1
B-16

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Texas, cont.
Nolan
4,124.5
4.5
0.1
0.2

Nueces
85,767.7
1.0
<0.1
<0.1

Ochiltree
21,348.9
33.3
0.2
0.2

Oldham
2,124.3
1.3
0.1
0.1

Orange
150,128.2
0.3
<0.1
<0.1

Palo Pinto
18,403.3
9.6
0.1
0.3

Panola
6,365.6
346.5
5.4
20.7

Parker
8,241.7
261.7
3.2
9.8

Pecos
52,954.2
8.2
<0.1
<0.1

Polk
204,009.5
0.2
<0.1
<0.1

Potter
2,029.4
0.4
<0.1
<0.1

Reagan
9,333.1
410.5
4.4
7.8

Reeves
20,772.2
164.2
0.8
1.1

Roberts
7,690.6
38.2
0.5
1.2

Robertson
158,344.3
45.4
<0.1
0.2

Runnels
2,847.0
<0.1
<0.1
<0.1

Rusk
582,134.9
65.8
<0.1
0.3

Sabine
799.4
31.1
3.9
13.9

San Augustine
1,131.5
182.1
16.1
50.8

San Patricio
4,172.0
1.1
<0.1
<0.1

Schleicher
967.3
27.0
2.8
5.0

Scurry
14,187.6
1.1
<0.1
<0.1

Shelby
4,920.2
133.6
2.7
8.2

Sherman
78,073.5
<0.1
<0.1
<0.1

Smith
11,231.1
0.2
<0.1
<0.1

Somervell
746,005.3
4.8
<0.1
<0.1
B-17

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Texas, cont.
Starr
9,552.1
5.0
0.1
0.1

Stephens
13,446.6
2.6
<0.1
0.1

Sterling
719.1
36.6
5.1
11.9

Stonewall
923.5
0.9
0.1
0.3

Sutton
1,153.4
1.6
0.1
0.3

Tarrant
104,430.2
1,443.0
1.4
3.9

Terrell
543.9
0.1
<0.1
<0.1

Terry
48,362.5
7.5
<0.1
<0.1

Tyler
1,872.5
0.1
<0.1
<0.1

Upshur
8,610.4
0.2
<0.1
<0.1

Upton
7,975.3
462.6
5.8
14.2

Van Zandt
4,139.1
0.1
<0.1
<0.1

Walker
4,478.6
3.4
0.1
0.2

Waller
9,829.5
0.1
<0.1
<0.1

Ward
6,909.5
107.3
1.6
4.6

Washington
2,430.9
2.2
0.1
0.2

Webb
15,862.9
1,117.8
7.0
18.2

Wharton
81,606.7
<0.1
<0.1
<0.1

Wheeler
6,522.6
858.0
13.2
21.5

Wichita
25,936.9
0.1
<0.1
<0.1

Wilbarger
12,683.8
0.2
<0.1
<0.1

Willacy
15,209.6
0.1
<0.1
<0.1

Wilson
7,843.9
84.5
1.1
1.7

Winkler
5,274.3
7.7
0.1
0.5

Wise
24,966.0
529.7
2.1
8.9

Wood
19,334.1
0.2
<0.1
<0.1
B-18

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
Texas, cont.
Yoakum
77,325.3
7.5
<0.1
<0.1

Young
21,162.7
0.1
<0.1
<0.1

Zapata
2,697.4
1.1
<0.1
0.1

Zavala
14,410.2
130.0
0.9
1.3
Utah
Carbon
15,067.2
7.3
<0.1
0.1

Duchesne
119,811.3
85.5
0.1
0.1

San Juan
10,632.5
0.3
<0.1
<0.1

Sevier
52,512.6
<0.1
<0.1
<0.1

Uintah
100,229.0
157.5
0.2
0.2
Virginia
Buchanan
313.9
0.6
0.2
0.3

Dickenson
1,741.1
0.8
<0.1
0.2

Wise
1,927.2
0.1
<0.1
<0.1
West Virginia
Barbour
773.8
19.9
2.6
6.9

Brooke
4,551.6
54.8
1.2
5.1

Doddridge
405.2
78.5
19.4
69.4

Hancock
28,718.2
1.2
<0.1
<0.1

Harrison
20,232.0
40.2
0.2
1.9

Lewis
901.6
2.4
0.3
0.8

Marion
5,982.4
70.1
1.2
4.9

Marshall
158,358.9
84.5
0.1
0.7

Monongalia
42,102.8
6.8
<0.1
0.1

Ohio
3,825.2
116.5
3.0
10.4

Pleasants
24,703.2
<0.1
<0.1
<0.1

Preston
2,890.8
8.4
0.3
1.4

Ritchie
587.7
2.8
0.5
1.7

Taylor
824.9
52.9
6.4
17.6

Tyler
4,934.8
2.1
<0.1
0.2

Upshur
1,814.1
34.9
1.9
6.8
B-19

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Total annual
water use in
2010
(millions of
gal)a
Average annual
hydraulic fracturing
water use in 2011
and 2012 (millions
of gal)b
Hydraulic
fracturing
water use
compared to
total water
use (%)c
Hydraulic
fracturing water
consumption
compared to total
water
consumption (%)c'd
West Virginia,
cont.
Webster
1,292.1
2.3
0.2
0.3
Wetzel
1,467.3
78.2
5.3
11.9
Wyoming
Big Horn
143,368.4
2.9
<0.1
<0.1
Campbell
44,318.3
11.7
<0.1
0.1
Carbon
137,130.5
4.5
<0.1
<0.1
Converse
56,972.9
106.8
0.2
0.3
Fremont
186,150.0
28.2
<0.1
<0.1
Goshen
144,248.0
5.8
<0.1
<0.1
Hot Springs
28,572.2
0.3
<0.1
<0.1
Johnson
43,205.1
<0.1
<0.1
<0.1
Laramie
86,297.0
18.3
<0.1
<0.1
Lincoln
74,562.2
0.8
<0.1
<0.1
Natrona
62,885.9
1.8
<0.1
<0.1
Niobrara
25,148.5
0.1
<0.1
<0.1
Park
111,317.7
0.9
<0.1
<0.1
Sublette
61,006.1
314.8
0.5
0.7
Sweetwater
61,699.6
39.4
0.1
0.1
Uinta
79,518.9
0.6
<0.1
<0.1
Washakie
60,400.2
1.1
<0.1
<0.1
a County-level data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on November 11, 2014. Total
daily water withdrawals were multiplied by 365 days to estimate total water use for the year (Maupin et al.. 2014).
b Average of water used for hydraulic fracturing in 2011 and 2012, based on the EPA FracFocus 1.0 project database (U.S. EPA.
2015c).
c Percentages were calculated by averaging annual water use for hydraulic fracturing in the EPA FracFocus 1.0 project database
in 2011 and 2012 for a given county (U.S. EPA. 2015c). and then dividing by 2010 USGS total water use for that county (Maupin
et al.. 2014) and multiplying by 100.
d Consumption values were calculated with use-specific consumption rates predominantly from the USGS, including 19.2% for
public supply, 19.2% for domestic use, 60.7% for irrigation, 60.7% for livestock, 14.8% for industrial uses, 14.8% for mining
(Sollev et al.. 1998). and 2.7% for thermoelectric power (Diehl and Harris. 2014). We used a rate of 71.6% for aquaculture
(Verdeeem and Bosma. 2009) (evaporation per kg fish + infiltration per kg)/(total water use per kg)*100. These rates were
multiplied by each USGS water use value (Maupin et al.. 2014) to yield a total water consumption estimate. To calculate a
consumption amount for hydraulic fracturing, we used a consumption rate of 82.5%. This was calculated by taking the median
value for all reported produced water/injected water percentages in Tables 7-1 and 7-2 of this assessment and then subtracting
from 100%. If a range of values was given, the midpoint was used. Note that this is likely a low estimate of consumption since
much of this return water is not subsequently treated and reused, but rather disposed of in injection wells—see Chapter 8.
B-20

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Appendix B - Water Acquisition Supplemental Information
Table B-3. Comparison of water use per well estimates from the EPA FracFocus 1.0 project
database (U.S. EPA. 2015c) and literature sources.
State
Basin3
Water use per well
(gal) - EPA FracFocus
1.0 project database
estimate15
Water use per well (gal)
- Literature estimate15'0
EPA FracFocus 1.0
project database
estimate as a
percentage of
literature estimate
(%)
Colorado
Denver
403,686
2,900,000
14
North Dakota
-
2,140,842
2,200,000
97
Oklahoma
-
2,591,778
3,000,000
86
Pennsylvaniad
-
4,301,701
4,450,000
97
Texas
Fort Worth
3,881,220
4,500,000
86
Texas
Salt
3,139,980
4,000,000
78
Texas
Western Gulf
3,777,648
4,600,000
82
Average6
-
-
-
77
Median6
-
-
-
86
a In cases where a basin is not specified, estimates were for the entire state and not specific to a particular basin. Basin
boundaries for the EPA FracFocus 1.0 project database estimates were determined from data from the U.S. EIA (U.S. EPA.
2015b).
bThe type of literature estimate determined the specific comparison with the EPA FracFocus 1.0 project database. If averages
were given in the literature (as for North Dakota and Pennsylvania), those values were compared with EPA FracFocus 1.0
project database averages; where medians were given in the literature (as for Colorado, Oklahoma, and Texas), they were
compared with EPA FracFocus 1.0 project database medians.
c Literature estimates were from the following sources: Colorado (Goodwin et al.. 2014). North Dakota (North Dakota State
Water Commission. 2014). Pennsylvania (Mitchell et al.. 2013). and Texas (Nicot and Scanlon. 2012)—see far right-column and
footnotes in Table B-5 for details on literature estimates. Where the literature provided a range, the mid-point was used. Only
literature estimates that were not directly derived from FracFocus were included.
d The results from Mitchell et al. (2013) were used for Pennsylvania since they were derived from Pennsylvania Department of
Environment Protection (PA DEP) records. Estimates from Hansen et al. (2013) were not included here because they were
based on data from the FracFocus national registry.
e Average and median percentage calculations were not weighted by the number of wells for a given estimate.
B-21

-------
Appendix B - Water Acquisition Supplemental Information
Table B-4. Comparison of well counts from the EPA FracFocus 1.0 project database (U.S. EPA. 2015c) and state databases for
North Dakota, Pennsylvania, and West Virginia.
State
EPA FracFocus 1.0 project database
well counts3
State database well counts
EPA FracFocus 1.0 project database
counts as a percentage
of state database counts
2011
2012
Total
2011
2012
Total
2011
2012
Total
North Dakotab
613
1,458
2,071
1,225
1,740
2,965
50%
84%
70%
Pennsylvania0
1,137
1,257
2,394
1,963
1,347
3,310
58%
93%
72%
West Virginiad
93
176
269
214
251
465
43%
70%
58%
Average
-
-
-
-
-
-
50%
82%
67%
a EPA FracFocus 1.0 project database wells counts (U.S. EPA. 2015c).
b For North Dakota state well counts, we used a North Dakota Department of Mineral Resources online database containing a list of horizontal wells completed in the Bakken
Formation. Data for North Dakota were accessed on July 9, 2014 at https://www.dmr.nd.gov/oilgas/bakkenwells.asp.
c For Pennsylvania state well counts, we used completed horizontal wells as a proxy for hydraulically fractured wells in the state. The Pennsylvania Department of Environmental
Protection has online databases of permitted and spudded wells, which differentiate between conventional and unconventional wells and can generate summary statistics at
both the county and state scale. The number of spudded wells (i.e., wells drilled) provided a better comparison with the number of hydraulically fractured wells in the EPA
FracFocus 1.0 project database than that of permitted wells. The number of permitted wells was nearly double that of spudded in 2011 and 2012, indicating that almost half of
the wells permitted were not drilled in that same year. Therefore, we used spudded wells here. Data for Pennsylvania were accessed on February 11, 2014 from
http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspxP/Oil Gas/Spud External Data.
d For West Virginia state well counts, data on the number of hydraulically fractured wells per year were received from the West Virginia Department of Environmental Protection
on February 25, 2014.
B-22

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Appendix B - Water Acquisition Supplemental Information
Table B-5. Water use per hydraulically fractured well as reported in the EPA FracFocus 1.0 project database (U.S. EPA. 2015c) by
state and basin, covering the time period of January 2011 through February 2013.
This table highlights 15 of the 20 states accounting for almost all disclosures reported in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). All EPA
FracFocus 1.0 project database estimates were limited to disclosures with valid state, county, and volume information. Other literature estimates are also
included where available. NA indicates other literature estimates were not available.
State
Basin/Total3
Number of
disclosures
Mean
(gal)
Median
(gal)
10th
percentile
(gal)
90th
percentile
(gal)
Literature estimates
Arkansas
Arkoma
1,423
5,190,254
5,259,965
3,234,963
7,121,249
NA
Total
1,423
5,190,254
5,259,965
3,234,963
7,121,249
NA
California
San Joaquin
677
131,653
77,238
22,100
285,029
NA
Other
34
132,391
36,099
13,768
361,192
NA
Total
711
131,689
76,818
21,462
285,306
130,000 gal (average)15
Colorado
Denver
3,166
753,887
403,686
143,715
2,588,946
2.9 million gal (median, Wattenberg
field of Niobrara play)0
Uinta-Piceance
1,520
2,739,523
1,798,414
840,778
5,066,380
NA
Raton
146
108,003
95,974
24,917
211,526
NA
Other
66
605,740
183,408
34,412
601,816
NA
Total
4,898
1,348,842
463,462
147,353
3,092,024
NA
Kansas
Total
121
1,135,973
1,453,788
10,836
2,227,926
NA
Louisiana
TX-LA-MS Salt
939
5,289,100
5,116,650
2,851,654
7,984,838
NA
Other
27
896,899
232,464
87,003
3,562,400
NA
Total
966
5,166,337
5,077,863
1,812,099
7,945,630
NA
Montana
Williston
187
1,640,085
1,552,596
375,864
3,037,398
NA
Other
20
945,541
1,017,701
157,639
1,575,197
NA
Total
207
1,572,979
1,455,757
367,326
2,997,552
NA
B-23

-------
Appendix B - Water Acquisition Supplemental Information
State
Basin/Total3
Number of
disclosures
Mean
(gal)
Median
(gal)
10th
percentile
(gal)
90th
percentile
(gal)
Literature estimates
New Mexico
Permian
732
991,369
426,258
89,895
2,502,923
NA
San Juan
363
159,680
97,734
27,217
313,919
NA
Other
50
33,787
8,358
1,100
98,841
NA
Total
1,145
685,882
175,241
35,638
1,871,666
NA
North Dakota
Williston
2,109
2,140,842
2,022,380
969,380
3,313,482
NA
Total
2,109
2,140,842
2,022,380
969,380
3,313,482
2.2 million gal (average)d
Ohio
Appalachian
146
4,206,955
3,887,499
2,885,568
5,571,027
NA
Total
146
4,206,955
3,887,499
2,885,568
5,571,027
NA
Oklahoma
Anadarko
935
3,742,703
3,259,774
1,211,700
6,972,652
Many formations reported6
Arkoma
158
6,323,750
6,655,929
172,375
9,589,554
Many formations reported6
Ardmore
98
6,637,332
8,021,559
81,894
8,835,842
Many formations reported6
Other
592
1,963,480
1,866,144
1,319,247
2,785,352
NA
Total
1,783
3,539,775
2,591,778
1,260,906
7,402,230
3 million gal (median)6
Pennsylvania
Appalachian
2,445
4,301,701
4,184,936
2,313,649
6,615,981
4.1-4.6 million gal (average, Marcellus
play, Susquehanna River Basin)f
Total
2,445
4,301,701
4,184,936
2,313,649
6,615,981
4.1-4.58 and 4.3-4.6h million gal
(average)
Texas
Permian
8,419
1,068,511
841,134
40,090
1,814,633
Many formations reported1
Western Gulf
4,549
3,915,540
3,777,648
173,832
6,786,052
4.5-4.7 million gal (median, Eagle
Ford play)1
Fort Worth
2,564
3,880,724
3,881,220
923,381
6,649,406
4.5 million gal (median, Barnett play)'
TX-LA-MS Salt
626
4,261,363
3,139,980
193,768
10,010,707
6-7.5 million gal (median, Texas-
Haynesville play) and 0.5-1 million gal
(median, Cotton Valley play)1
B-24

-------
Appendix B - Water Acquisition Supplemental Information
State
Basin/Total3
Number of
disclosures
Mean
(gal)
Median
(gal)
10th
percentile
(gal)
90th
percentile
(gal)
Literature estimates
Texas, cont.
Anadarko
604
4,128,702
3,341,310
492,421
8,292,996
Many formations reported'
Other
120
1,601,897
184,239
21,470
5,678,588
NA
Total
16,882
2,494,452
1,420,613
58,709
6,115,195
Not reported by state1
Utah
Uinta-Piceance
1,396
375,852
304,105
77,166
770,699
NA
Other
10
58,874
56,245
28,745
97,871
NA
Total
1,406
373,597
302,075
76,286
769,360
NA
West Virginia
Appalachian
273
5,034,217
5,012,238
3,170,210
7,297,080
NA
Total
273
5,034,217
5,012,238
3,170,210
7,297,080
4.7-6 million gal (average)8
Wyoming
Greater Green River
861
841,702
752,979
147,020
1,493,266
NA
Powder River
351
739,129
5,927
5,353
2,863,182
NA
Other
193
613,618
41,664
22,105
1,818,606
NA
Total
1,405
784,746
322,793
5,727
1,837,602
NA
a Basin boundaries for the EPA FracFocus 1.0 project database well locations were determined from data from the U.S. EIA (U.S. EPA. 2015b).
b Literature estimates for California were from a California Council on Science and Technology report using data from FracFocus (CCST. 2014).
c Literature estimates for the Denver Basin were from Goodwin et al. (2014). Goodwin et al. (2014) assessed 200 randomly sampled wells in the Wattenberg Field of the Denver
Basin (Niobrara Play), using industry data for wells operated by Noble Energy, drilled between January 1, 2010, and July 1, 2013. Water consumption is reported rather than
water use, but Goodwin et al. (2014) assume, based on Noble Energy practices, that water use and water consumption were identical because none of the flowback or produced
water is reused for hydraulic fracturing. Goodwin et al. reported drilling water consumed, hydraulic fracturing water consumed, and total water consumed. We present hydraulic
fracturing water consumption here (hydraulic fracturing water consumption was approximately 95% of the total).
d Literature estimates for North Dakota were from an informational bulletin from the North Dakota State Water Commission (2014). No further information was available.
e Murray (2013). who assessed water use for oil and gas operations from 2000-2010 for eight formations in Oklahoma using data from the Oklahoma Corporation Commission. It
is not possible to extract an estimate corresponding to 2011-2012 from Murray without the raw data, because medians were presented for the 10-year period rather than
separated by year.
f The range of average annual water use per hydraulically fractured well in the Susquehanna River Basin for 2011 and 2012, calculated from SRBC (2016).
g Hansen et al. (2013). using data from FracFocus via Skytruth for Pennsylvania as a whole, the range of annual averages is reported for 2011 and 2012. Similarly, for West
Virginia, the range of annual averages is reported for 2011 and 2012 (partial year).
B-25

-------
Appendix B - Water Acquisition Supplemental Information
h Mitchell et al. (2013). using data reported to the Pennsylvania Department of Environmental Protection. Mitchell et al. (2013) reported water use in the Ohio River Basin for
2011 and 2012 (partial year) for horizontal and vertical wells. Here we report results for horizontal wells, which made up the majority of wells over the two-year period (i.e.,
93%, 1,191 horizontal wells versus 96 vertical wells). A range is reported as before because the average water use differed between the two years.
' Literature estimates for Texas were from Nicot et al. (2012). using proprietary data from IHS. In most cases, Nicot et al. (2012) reported at the play scale or smaller, rather than
the EIA basin scale used for the EPA FracFocus 1.0 project database. We reference 2011 and 2012 (partial year) for Nicot et al. (2012) where possible to overlap with the period
of study for the EPA FracFocus 1.0 project database, though more years were available for most formations. A range is reported for some medians because median water use
was different for the two years. There were five formations reported for the Permian Basin (Wolfberry, Wolfcamp, Canyon, Clearfork, and San Andres-Greyburg). The most
active area in the Permian Basin in 2011-2012 was the Wolfberry, which reported a median of 1 to 1.1 million gal (3.8 to 4.2 million L) per well—these were mostly vertical wells.
For the TX-LA-MS Salt Basin Nicot et al. (2012) reported two formations (TX-Haynesville and Cotton Valley), with similar levels of activity in 2011-2012. Wells in TX-Haynesville
were predominantly horizontal, while those in Cotton Valley were predominantly vertical (though horizontal wells in Cotton Valley were also reported). There were three fields
reported in the Anadarko Basin (Granite Wash, Cleveland, and Marmaton). The most active area in the Anadarko Basin in 2011-2012 was the Granite Wash, which reported a
median of 3.3 to 5.2 million gal (12 to 20 million L) per well and where wells were mostly horizontal.
B-26

-------
Appendix B - Water Acquisition Supplemental Information
Table B-6. Estimated percent domestic use water from groundwater and self-supplied by
county in 2010.
Counties listed contained hydraulically fractured wells with valid state, county, and volume information (U.S. EPA,
2015c). Data estimated from the USGS Water Census (Maupin et al., 2014).
State
County
Percent domestic use
water from groundwater3,15
Percent domestic use
water self supplied3'0
Alabama
Jefferson
11.9
0.8

Tuscaloosa
10.7
6.1
Arkansas
Cleburne
0.0
0.0

Conway
8.6
8.6

Faulkner
48.0
3.5

Independence
20.5
9.4

Logan
0.0
0.0

Sebastian
0.0
0.0

Van Buren
6.4
6.4

White
0.4
0.0

Yell
1.8
1.8
California
Colusa
97.9
10.3

Glenn
96.5
21.6

Kern
74.5
1.7

Los Angeles
45.0
4.2

Sutter
19.4
4.6

Ventura
30.9
3.9
Colorado
Adams
18.1
2.8

Arapahoe
19.3
1.3

Boulder
1.7
1.5

Broomfield
0.0
0.0

Delta
59.6
28.4

Dolores
55.2
51.4

El Paso
19.6
5.1

Elbert
100.0
75.2

Fremont
15.6
15.6
B-27

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Colorado, cont.
Garfield
36.7
28.5

Jackson
84.4
40.7

La Plata
24.4
11.3

Larimer
2.3
0.8

Las Animas
26.3
16.0

Mesa
7.3
6.2

Moffat
36.4
25.8

Morgan
57.9
4.9

Phillips
100.0
25.3

Rio Blanco
60.2
32.5

Routt
22.6
5.9

San Miguel
71.4
32.5

Weld
4.7
0.7

Yuma
100.0
38.1
Kansas
Barber
100.0
19.0

Clark
100.0
24.2

Comanche
100.0
19.2

Finney
100.0
2.1

Grant
100.0
23.8

Gray
100.0
36.4

Harper
100.0
10.3

Haskell
100.0
35.2

Hodgeman
100.0
42.3

Kearny
100.0
14.6

Lane
100.0
24.1

Meade
100.0
25.4

Morton
100.0
21.7

Ness
100.0
24.2

Seward
100.0
15.7
B-28

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Kansas, cont.
Sheridan
100.0
44.9

Stanton
100.0
29.8

Stevens
100.0
25.9

Sumner
51.3
0.0
Louisiana
Allen
100.0
7.5

Beauregard
100.0
20.6

Bienville
100.0
16.8

Bossier
29.4
14.6

Caddo
12.2
8.8

Calcasieu
98.3
12.7

Caldwell
100.0
6.5

Claiborne
100.0
10.4

DeSoto
55.8
21.8

East Feliciana
100.0
11.8

Jackson
100.0
13.8

Lincoln
100.0
4.2

Natchitoches
23.2
11.4

Rapides
100.0
3.3

Red River
83.2
27.6

Sabine
67.5
36.2

Tangipahoa
100.0
26.9

Union
100.0
11.2

Webster
100.0
11.3

West Feliciana
100.0
2.4

Winn
100.0
16.4
Michigan
Cheboygan
100.0
76.4

Gladwin
100.0
84.5

Kalkaska
100.0
89.0

Missaukee
100.0
90.6
B-29

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Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Michigan, cont.
Ogemaw
100.0
90.8

Roscommon
100.0
91.9
Mississippi
Amite
100.0
26.0

Wilkinson
100.0
11.1
Montana
Daniels
100.0
29.4

Garfield
100.0
70.0

Glacier
62.1
17.7

Musselshell
89.9
54.5

Richland
100.0
30.8

Roosevelt
84.2
20.9

Rosebud
51.3
10.3

Sheridan
100.0
31.0
New Mexico
Chaves
100.0
11.8

Colfax
30.7
2.6

Eddy
100.0
2.2

Harding
100.0
25.0

Lea
100.0
17.4

Rio Arriba
84.0
42.3

Roosevelt
100.0
8.9

San Juan
14.6
12.9

Sandoval
98.9
23.2
North Dakota
Billings
NA
33.3

Bottineau
100.0
13.7

Burke
100.0
12.5

Divide
100.0
12.5

Dunn
100.0
21.4

Golden Valley
100.0
7.7

Mckenzie
75.8
15.7

Mclean
12.5
9.9
B-30

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Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
North Dakota, cont.
Mountrail
65.7
11.5

Stark
NA
5.7

Williams
27.4
7.3
Ohio
Ashland
98.8
57.4

Belmont
76.4
8.9

Carroll
96.4
76.4

Columbiana
63.2
43.2

Coshocton
99.3
34.9

Guernsey
37.6
9.5

Harrison
65.6
45.9

Jefferson
33.1
10.2

Knox
99.2
41.1

Medina
98.4
83.1

Muskingum
93.4
17.0

Noble
8.0
8.0

Portage
32.6
18.3

Stark
91.2
30.9

Tuscarawas
94.0
23.5

Wayne
99.1
49.0
Oklahoma
Alfalfa
100.0
14.6

Beaver
100.0
47.9

Beckham
100.0
10.6

Blaine
100.0
8.8

Bryan
26.0
7.8

Caddo
45.4
35.1

Canadian
100.0
0.0

Carter
17.5
0.5

Coal
31.5
27.5

Custer
70.8
13.2
B-31

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Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Oklahoma, cont.
Dewey
100.0
22.5

Ellis
100.0
31.4

Garvin
41.3
15.8

Grady
100.0
34.2

Grant
100.0
13.2

Harper
100.0
22.6

Hughes
23.6
6.7

Jefferson
13.5
1.8

Johnston
53.4
1.1

Kay
39.2
4.6

Kingfisher
100.0
28.3

Kiowa
10.3
0.0

Latimer
12.6
12.6

Le Flore
14.3
13.1

Logan
61.1
34.6

Love
100.0
3.8

Major
100.0
28.1

Marshall
20.1
4.4

Mcclain
95.9
23.9

Noble
23.3
14.3

Oklahoma
22.0
2.5

Osage
18.0
14.9

Pawnee
38.2
27.7

Payne
47.9
12.6

Pittsburg
0.6
0.0

Roger Mills
80.1
19.4

Seminole
78.8
16.1

Stephens
99.2
14.9

Texas
100.0
10.9
B-32

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Oklahoma, cont.
Washita
53.9
18.2

Woods
100.0
14.7
Pennsylvania
Allegheny
15.7
15.3

Armstrong
45.3
36.8

Beaver
54.7
26.8

Blair
34.9
24.0

Bradford
100.0
65.2

Butler
51.8
42.8

Cameron
29.0
29.0

Centre
93.1
21.3

Clarion
61.5
55.8

Clearfield
38.4
22.7

Clinton
48.4
38.1

Columbia
77.5
56.7

Crawford
97.7
66.0

Elk
25.3
15.6

Fayette
19.2
16.1

Forest
100.0
78.3

Greene
31.9
31.9

Huntingdon
73.2
57.8

Indiana
52.2
49.1

Jefferson
60.7
46.1

Lawrence
40.5
38.8

Lycoming
60.0
29.3

McKean
56.6
33.3

Potter
93.7
58.1

Somerset
42.6
33.5

Sullivan
100.0
76.9

Susquehanna
79.9
74.7
B-33

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Pennsylvania, cont.
Tioga
81.3
58.3

Venango
95.9
32.7

Warren
96.9
49.4

Washington
21.6
21.5

Westmoreland
21.3
19.8

Wyoming
100.0
70.6
Texas
Andrews
100.0
23.4

Angelina
100.0
9.8

Archer
16.9
16.9

Atascosa
100.0
16.3

Austin
100.0
55.6

Bee
100.0
52.5

Borden
100.0
71.4

Bosque
88.7
30.3

Brazos
100.0
2.1

Brooks
100.0
35.3

Burleson
100.0
42.9

Cherokee
87.5
26.1

Clay
44.6
36.7

Cochran
100.0
23.3

Coke
29.0
28.9

Colorado
100.0
45.4

Concho
96.8
5.0

Cooke
75.5
8.9

Cottle
100.0
21.4

Crane
100.0
14.3

Crockett
100.0
42.5

Crosby
35.6
19.0

Culberson
100.0
13.8
B-34

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Texas, cont.
Dallas
1.0
0.7

Dawson
100.0
33.8

DeWitt
100.0
42.3

Denton
9.0
3.6

Dimmit
100.0
30.5

Ector
100.0
28.3

Edwards
100.0
42.1

Ellis
32.2
7.9

Erath
100.0
43.3

Fayette
100.0
27.6

Fisher
NA
36.8

Franklin
0.9
0.0

Freestone
100.0
31.2

Frio
100.0
20.4

Gaines
100.0
45.5

Garza
20.1
17.2

Glasscock
NA
100.0

Goliad
NA
66.7

Gonzales
96.8
15.9

Grayson
56.0
4.2

Gregg
20.8
14.1

Grimes
100.0
26.0

Hansford
100.0
16.4

Hardeman
87.6
13.3

Hardin
100.0
29.5

Harrison
43.8
24.8

Hartley
100.0
39.7

Haskell
100.0
15.7

Hemphill
100.0
27.5
B-35

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Texas, cont.
Hidalgo
9.2
1.6

Hockley
100.0
27.4

Hood
70.8
39.8

Houston
79.7
36.6

Howard
100.0
19.8

Hutchinson
27.3
14.9

Irion
100.0
50.0

Jack
46.7
43.8

Jefferson
25.0
5.8

Jim Hogg
NA
25.0

Johnson
34.9
6.8

Jones
60.5
60.5

Karnes
100.0
17.6

Kenedy
100.0
25.0

Kent
100.0
37.5

King
100.0
33.3

Kleberg
100.0
1.9

Knox
86.2
24.2

La Salle
100.0
43.3

Lavaca
100.0
56.0

Lee
100.0
15.9

Leon
100.0
41.4

Liberty
98.5
42.5

Limestone
46.5
32.5

Lipscomb
100.0
23.5

Live Oak
32.8
32.1

Loving
NA
0.0

Lynn
64.1
32.2

Madison
100.0
66.9
B-36

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Texas, cont.
Marion
13.7
8.4

Martin
100.0
48.9

Maverick
27.6
27.6

McMullen
100.0
40.0

Medina
98.0
23.6

Menard
36.4
36.4

Midland
100.0
22.1

Milam
82.5
41.1

Mitchell
100.0
14.7

Montague
57.1
49.7

Montgomery
100.0
26.6

Moore
100.0
8.1

Nacogdoches
55.6
21.6

Navarro
22.0
22.0

Newton
100.0
63.7

Nolan
100.0
17.6

Nueces
5.6
5.6

Ochiltree
100.0
16.8

Oldham
100.0
58.8

Orange
99.1
41.2

Palo Pinto
11.7
11.7

Panola
96.6
58.7

Parker
63.5
41.1

Pecos
100.0
31.3

Polk
41.9
41.7

Potter
100.0
12.6

Reagan
100.0
16.2

Reeves
100.0
31.1

Roberts
100.0
33.3
B-37

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Texas, cont.
Robertson
97.1
22.5

Runnels
13.5
13.5

Rusk
90.7
41.8

Sabine
76.2
69.0

San Augustine
78.0
74.4

San Patricio
88.8
21.8

Schleicher
100.0
40.0

Scurry
32.5
27.7

Shelby
66.2
58.2

Sherman
100.0
33.3

Smith
48.0
13.7

Somervell
87.7
69.3

Starr
23.2
23.2

Stephens
13.5
13.5

Sterling
NA
18.8

Stonewall
NA
40.0

Sutton
100.0
26.7

Tarrant
3.7
1.3

Terrell
100.0
25.0

Terry
100.0
16.7

Tyler
100.0
73.6

Upshur
54.1
23.2

Upton
100.0
15.2

Van Zandt
65.7
39.0

Walker
57.7
30.6

Waller
100.0
37.2

Ward
100.0
4.5

Washington
48.2
36.0

Webb
99.4
0.5
B-38

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
Texas, cont.
Wharton
100.0
45.9

Wheeler
100.0
31.3

Wichita
8.8
2.9

Wilbarger
100.0
11.5

Willacy
28.4
28.4

Wilson
100.0
6.9

Winkler
100.0
3.8

Wise
51.3
50.4

Wood
21.3
12.9

Yoakum
100.0
36.0

Young
19.3
18.9

Zapata
13.9
13.9

Zavala
100.0
15.2
Utah
Carbon
50.0
1.2

Duchesne
57.1
10.4

San Juan
68.3
47.5
Utah
Sevier
100.0
10.0

Uintah
87.7
3.1
Virginia
Buchanan
NA
27.6

Dickenson
2.5
2.5

Wise
5.9
2.3
West Virginia
Barbour
24.1
24.8

Brooke
33.4
6.8

Doddridge
60.6
62.1

Hancock
67.7
6.9

Harrison
8.8
8.9

Lewis
29.5
30.3

Marion
5.8
4.9

Marshall
96.5
12.0
B-39

-------
Appendix B - Water Acquisition Supplemental Information
State
County
Percent domestic use
water from groundwater3'15
Percent domestic use
water self supplied3'0
West Virginia, cont.
Monongalia
5.3
5.5

Ohio
5.4
3.4

Pleasants
100.0
27.9

Preston
66.1
41.0

Ritchie
45.2
46.4

Taylor
14.9
14.9

Tyler
44.4
39.2

Upshur
27.3
27.8

Webster
41.9
43.2

Wetzel
96.3
28.6
Wyoming
Big Horn
79.4
11.3

Campbell
100.0
0.6

Carbon
63.8
6.7

Converse
96.5
17.0

Fremont
49.3
23.7

Goshen
100.0
21.1

Hot Springs
31.9
8.2

Johnson
40.8
35.4

Laramie
38.1
13.0

Lincoln
82.4
9.0

Natrona
69.0
6.6

Niobrara
100.0
16.3

Park
18.9
13.7

Sublette
54.6
22.1

Sweetwater
3.5
0.4

Uinta
19.5
11.5

Washakie
100.0
16.0
a Data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on November 11, 2014. Domestic water
use is water used for indoor household purposes such as drinking, food preparation, bathing, washing clothes and dishes,
flushing toilets, and outdoor purposes such as watering lawns and gardens (Maupin et al.. 2014).
b Percent domestic water use from groundwater estimated with the following equation: (Domestic public supply volume from
groundwater + Domestic self-supplied volume from groundwater)/ Domestic total water use volume * 100. Domestic public
supply volume from groundwater was estimated by multiplying the volume of domestic water from public supply by the ratio of
public supply volume from groundwater to total public supply volume.
c Percent domestic water use self-supplied estimated by dividing the volume of domestic water self-supplied by total domestic
water use volume.
B-40

-------
Appendix B - Water Acquisition Supplemental Information
Table B-7. Projected hydraulic fracturing water use by Texas counties between 2015 and 2060, expressed as a percentage of 2010
total county water use.
Hydraulic fracturing water use data from Nicot et al. (2012). Total water use data from 2010 from the USGS Water Census (Maupin et al., 2014). All 254 Texas
counties are listed by descending order of percentages in 2030.
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
McMullen
126.2
137.0
152.1
165.1
176.7
164.0
145.3
126.6
108.0
89.3
Irion
36.1
59.2
70.5
63.7
53.4
43.1
32.8
22.4
12.1
5.4
La Salle
58.4
58.3
59.7
60.8
61.9
54.6
45.3
36.0
26.7
17.4
San Augustine
60.2
56.2
52.2
48.2
44.2
40.2
36.2
32.1
28.1
24.1
Sterling
12.0
32.0
39.9
40.5
41.0
34.7
28.3
21.9
15.6
10.7
Dimmit
38.2
38.1
38.9
39.0
38.7
33.9
27.9
22.0
16.0
10.1
Sabine
9.6
19.2
28.7
38.3
35.1
31.9
28.7
25.6
22.3
19.2
Leon
9.9
19.3
27.0
34.6
32.9
29.0
25.1
21.2
17.3
13.5
Karnes
48.1
43.0
37.9
32.6
27.2
21.8
16.4
11.0
5.6
0.2
Loving
13.1
17.4
23.4
29.4
28.8
26.2
23.6
20.9
18.3
15.7
Shackelford
0.0
7.9
15.7
23.6
21.2
18.9
16.5
14.1
11.8
9.4
Madison
5.5
11.8
15.7
19.7
17.4
15.2
13.0
10.9
8.7
6.5
Schleicher
10.5
15.8
19.1
19.7
17.1
14.5
11.9
9.3
6.7
4.7
Sutton
0.0
11.0
15.1
19.1
23.2
20.6
18.1
15.5
12.9
10.3
Shelby
11.0
20.4
19.4
18.4
17.4
15.7
14.1
12.5
10.9
9.3
DeWitt
26.9
24.1
21.4
18.4
15.4
12.3
9.3
6.3
3.2
0.2
Hemphill
25.7
23.1
20.5
17.8
15.2
12.6
10.0
7.3
4.7
2.1
Terrell
0.0
9.7
13.2
16.8
20.4
18.2
15.9
13.6
11.3
9.0
Coryell
7.0
24.4
22.8
16.5
10.1
3.8
0.0
0.0
0.0
0.0
B-41

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Montague
28.6
24.5
20.4
16.3
12.2
8.2
4.1
0.0
0.0
0.0
Crockett
7.6
12.5
14.8
13.4
11.2
9.1
6.9
4.7
2.5
1.1
Upton
12.1
15.2
14.1
12.9
11.7
9.8
7.9
5.9
4.0
2.7
Borden
3.1
8.6
12.0
12.1
12.2
10.3
8.4
6.4
4.5
3.1
Live Oak
13.3
12.4
11.5
11.8
12.2
12.7
13.2
11.7
9.8
7.8
Reagan
11.2
14.0
12.7
11.3
9.9
8.1
6.4
4.6
2.8
1.6
Clay
3.2
5.9
8.6
11.3
10.3
9.4
8.4
7.5
6.6
5.6
Wheeler
17.6
15.3
13.1
10.8
8.6
6.3
4.1
1.8
0.0
0.0
Lavaca
7.9
13.2
12.0
10.7
9.4
8.1
6.7
5.4
4.0
2.7
Washington
0.0
6.7
11.8
10.7
9.6
8.6
7.5
6.4
5.3
4.3
Nacogdoches
7.9
11.4
10.7
10.0
9.2
8.3
7.5
6.6
5.7
4.9
Hill
17.1
14.7
12.2
9.8
7.3
4.9
2.4
0.0
0.0
0.0
Jack
3.5
5.3
7.1
8.8
7.9
7.1
6.2
5.3
4.4
3.5
Panola
7.2
10.2
9.2
8.5
7.7
7.0
6.3
5.5
4.8
4.0
Jim Hogg
4.8
6.4
8.0
8.0
6.9
6.0
4.9
3.9
2.9
1.8
Howard
4.4
7.1
8.5
8.0
6.8
5.6
4.4
3.2
2.1
1.3
Parker
3.7
5.0
6.3
7.6
6.8
6.1
5.3
4.5
3.8
3.0
Hamilton
8.8
10.7
8.9
7.1
5.3
3.5
1.8
0.0
0.0
0.0
Johnson
14.2
11.9
9.5
7.1
4.7
2.4
0.0
0.0
0.0
0.0
Midland
6.7
8.3
7.7
7.1
6.2
5.2
4.1
3.0
2.0
1.2
Kenedy
4.1
5.4
6.8
6.8
5.9
5.1
4.1
3.3
2.4
1.6
Fayette
3.9
8.4
7.6
6.6
5.5
4.4
3.4
2.3
1.2
0.2
B-42

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Lee
2.1
4.1
5.3
6.5
5.8
5.1
4.3
3.6
2.9
2.1
Winkler
2.9
3.8
5.1
6.3
6.0
5.4
4.7
4.1
3.4
2.8
Wilson
6.7
7.7
7.0
6.2
5.4
4.6
3.9
3.1
2.3
1.5
Martin
5.7
7.1
6.5
6.0
5.3
4.4
3.5
2.6
1.8
1.2
Burleson
1.0
2.9
4.3
5.7
5.1
4.5
3.9
3.3
2.6
2.0
Atascosa
6.3
5.7
5.6
5.6
5.6
5.6
5.0
4.2
3.4
2.7
Bosque
1.8
3.0
4.3
5.5
5.1
4.6
4.2
3.7
3.2
2.8
Webb
7.5
7.1
6.3
5.4
4.6
3.8
3.1
2.3
1.4
0.5
Gonzales
8.0
7.1
6.2
5.3
4.4
3.6
2.7
1.8
0.9
0.0
Marion
1.1
2.4
3.8
5.1
5.2
4.7
4.2
3.7
3.2
2.7
Harrison
4.3
6.1
5.5
5.1
4.6
4.2
3.7
3.3
2.9
2.4
Eastland
0.0
3.9
5.9
5.0
4.2
3.3
2.5
1.7
0.8
0.0
Archer
1.0
2.4
3.6
4.9
4.5
4.1
3.7
3.3
2.9
2.5
Zavala
4.7
5.5
5.2
4.9
4.6
4.3
4.0
3.4
2.7
2.0
Roberts
6.9
6.0
5.1
4.2
3.4
2.5
1.6
0.7
0.0
0.0
Maverick
2.5
3.0
3.6
4.2
4.8
4.5
4.0
3.6
3.1
2.6
Cooke
11.9
9.3
6.7
4.1
1.5
0.0
0.0
0.0
0.0
0.0
Ward
2.7
3.2
4.2
4.1
4.0
3.6
3.2
2.7
2.3
1.9
Austin
0.0
1.2
2.5
3.7
3.4
3.0
2.6
2.2
1.9
1.5
Reeves
1.4
1.8
2.7
3.7
3.9
3.6
3.3
3.0
2.6
2.3
Glasscock
3.1
4.1
3.9
3.6
3.1
2.6
2.1
1.5
1.0
0.7
Tyler
1.9
2.6
3.2
3.2
2.8
2.4
2.0
1.6
1.1
0.7
B-43

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Hood
1.4
2.0
2.6
3.2
2.9
2.6
2.2
1.9
1.6
1.3
Garza
1.5
2.0
2.5
2.9
2.7
2.4
2.1
1.8
1.5
1.2
Andrews
2.3
3.0
2.9
2.7
2.6
2.3
2.0
1.7
1.4
1.1
Crane
1.3
1.7
2.1
2.6
3.1
2.8
2.5
2.2
1.9
1.7
Erath
0.9
1.4
1.9
2.4
2.2
2.0
1.8
1.6
1.4
1.2
Wise
3.6
3.2
2.8
2.4
2.0
1.6
1.2
0.8
0.4
0.0
Upshur
0.2
0.9
1.7
2.4
2.9
2.6
2.3
2.1
1.8
1.5
Mitchell
1.2
1.6
2.0
2.4
2.1
1.9
1.7
1.4
1.2
0.9
Ector
1.5
2.0
2.1
2.3
2.2
1.9
1.7
1.4
1.2
1.0
Culberson
0.3
0.4
1.3
2.2
2.9
2.6
2.4
2.1
1.9
1.6
Lipscomb
1.7
3.0
2.6
2.1
1.7
1.3
0.8
0.4
0.0
0.0
Angelina
0.4
0.9
1.5
2.1
2.2
2.0
1.8
1.6
1.4
1.2
Houston
2.1
2.7
2.4
2.1
1.8
1.5
1.2
0.9
0.6
0.3
Frio
1.8
1.8
1.9
1.9
1.8
1.8
1.7
1.5
1.2
0.9
Newton
1.8
2.3
2.1
1.8
1.6
1.3
1.0
0.8
0.5
0.3
Kleberg
1.0
1.4
1.7
1.7
1.5
1.3
1.1
0.8
0.6
0.4
Brooks
1.0
1.3
1.7
1.7
1.5
1.2
1.0
0.8
0.6
0.4
Brazos
0.4
0.9
1.2
1.5
1.4
1.2
1.0
0.8
0.7
0.5
Comanche
0.4
0.7
1.0
1.4
1.2
1.1
1.0
0.8
0.7
0.5
Ochiltree
0.6
1.1
1.5
1.2
1.0
0.7
0.5
0.2
0.0
0.0
Palo Pinto
0.3
0.6
0.9
1.2
1.1
1.0
0.8
0.7
0.6
0.5
Limestone
0.9
1.0
1.1
1.2
1.1
1.0
0.8
0.7
0.6
0.4
B-44

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Duval
0.7
0.9
1.1
1.1
1.0
0.8
0.7
0.5
0.4
0.3
Stephens
0.1
0.4
0.8
1.1
1.0
0.9
0.8
0.6
0.5
0.4
Dawson
0.5
0.8
1.0
1.1
1.1
1.0
0.8
0.6
0.5
0.3
Scurry
0.0
0.6
0.8
1.0
1.2
1.1
0.9
0.8
0.7
0.5
Bee
0.8
1.1
1.1
1.0
0.9
0.7
0.6
0.4
0.3
0.1
Val Verde
0.0
0.5
0.8
0.9
1.1
1.0
0.9
0.8
0.6
0.5
Colorado
<0.1
0.3
0.6
0.9
0.8
0.7
0.6
0.5
0.4
0.4
Tarrant
2.1
1.7
1.3
0.9
0.4
0.0
0.0
0.0
0.0
0.0
Zapata
0.5
0.7
0.8
0.8
0.7
0.6
0.5
0.4
0.3
0.2
Ellis
0.3
0.5
0.6
0.8
0.7
0.6
0.6
0.5
0.4
0.3
Jim Wells
0.4
0.6
0.7
0.7
0.6
0.5
0.4
0.4
0.3
0.2
Lynn
0.0
0.4
0.6
0.7
0.8
0.8
0.7
0.6
0.5
0.4
Henderson
0.1
0.3
0.5
0.7
0.8
0.7
0.6
0.5
0.4
0.4
Hansford
0.0
0.4
0.8
0.7
0.5
0.4
0.3
0.2
0.1
0
Gaines
0.2
0.3
0.5
0.5
0.5
0.4
0.4
0.3
0.2
0.2
Gregg
0.1
0.2
0.3
0.4
0.4
0.4
0.4
0.3
0.3
0.2
Refugio
0.2
0.3
0.4
0.4
0.3
0.3
0.2
0.2
0.1
0.1
Caldwell
0.4
0.5
0.4
0.4
0.3
0.3
0.2
0.2
0.1
0.1
Pecos
0.1
0.1
0.2
0.4
0.5
0.4
0.4
0.3
0.3
0.2
Anderson
0.1
0.2
0.3
0.4
0.4
0.4
0.4
0.3
0.3
0.2
Young
0.0
0.1
0.2
0.4
0.3
0.3
0.3
0.2
0.2
0.1
San Patricio
0.2
0.3
0.4
0.4
0.3
0.3
0.2
0.2
0.1
0.1
B-45

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Smith
0.1
0.1
0.2
0.3
0.4
0.3
0.3
0.3
0.2
0.2
Cherokee
0.1
0.2
0.2
0.3
0.4
0.3
0.3
0.2
0.2
0.2
McLennan
0.1
0.1
0.2
0.3
0.3
0.2
0.2
0.2
0.2
0.1
Terry
0.0
0.2
0.2
0.3
0.3
0.3
0.3
0.2
0.2
0.2
Starr
0.2
0.2
0.3
0.3
0.2
0.2
0.2
0.1
0.1
0.1
Cochran
0.1
0.2
0.2
0.2
0.3
0.2
0.2
0.2
0.2
0.1
Jasper
0.2
0.3
0.2
0.2
0.2
0.1
0.1
0.1
0.1
<0.1
Dallas
0.2
0.3
0.2
0.2
0.1
0.1
<0.1
0.0
0.0
0.0
Robertson
0.1
0.2
0.2
0.2
0.2
0.1
0.1
0.1
0.1
0.1
Grimes
<0.1
0.1
0.1
0.2
0.1
0.1
0.1
0.1
0.1
0.1
Yoakum
0.1
0.1
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
Freestone
0.1
0.1
0.1
0.2
0.2
0.1
0.1
0.1
0.1
0.1
Cass
<0.1
0.1
0.1
0.2
0.2
0.2
0.1
0.1
0.1
0.1
Hutchinson
0.0
0.1
0.2
0.1
0.1
0.1
0.1
<0.1
<0.1
0.0
Rusk
<0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
<0.1
Willacy
<0.1
0.1
0.1
0.1
0.1
0.1
0.1
<0.1
<0.1
<0.1
Victoria
<0.1
0.1
0.1
0.1
0.1
0.1
<0.1
<0.1
<0.1
<0.1
Sherman
0.0
0.0
<0.1
0.1
0.1
0.1
<0.1
<0.1
<0.1
<0.1
Calhoun
<0.1
0.1
0.1
0.1
0.1
0.1
<0.1
<0.1
<0.1
<0.1
Lubbock
0.0
0.0
<0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
Jackson
<0.1
<0.1
0.1
0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Matagorda
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
B-46

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Polk
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Wharton
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Nueces
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Hidalgo
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Cameron
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Somervell
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Goliad
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Brazoria
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Fort Bend
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Aransas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Armstrong
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Bailey
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Bandera
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Bastrop
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Baylor
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Bell
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Bexar
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Blanco
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Bowie
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Brewster
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Briscoe
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Brown
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
B-47

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Burnet
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Callahan
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Camp
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Carson
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Castro
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Chambers
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Childress
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Coke
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Coleman
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Collin
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Collingsworth
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Comal
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Concho
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Cottle
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Crosby
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Dallam
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Deaf Smith
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Delta
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Denton
1.7
1.1
0.6
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Dickens
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Donley
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Edwards
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
B-48

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
El Paso
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Falls
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Fannin
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Fisher
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Floyd
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Foard
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Franklin
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Galveston
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Gillespie
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Gray
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Grayson
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Guadalupe
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hale
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hall
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hardeman
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hardin
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Harris
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hartley
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Haskell
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hays
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hockley
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hopkins
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
B-49

-------
Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Hudspeth
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Hunt
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Jeff Davis
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Jefferson
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Jones
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Kaufman
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Kendall
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Kent
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Kerr
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Kimble
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
King
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Kinney
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Knox
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Lamar
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Lamb
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Lampasas
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Liberty
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Llano
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
McCulloch
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Mason
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Medina
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Menard
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
B-50

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Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Milam
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Mills
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Montgomery
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Moore
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Morris
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Motley
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Navarro
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Nolan
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Oldham
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Orange
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Parmer
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Potter
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Presidio
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Rains
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Randall
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Real
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Red River
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Rockwall
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Runnels
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
San Jacinto
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
San Saba
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Stonewall
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
B-51

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Appendix B - Water Acquisition Supplemental Information
Texas county
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b'c
2015
2020
2025
2030
2035
2040
2045
2050
2055
2060
Swisher
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Taylor
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Throckmorton
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Titus
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Tom Green
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Travis
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Trinity
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Uvalde
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Van Zandt
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Walker
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Waller
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Wichita
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Wilbarger
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Williamson
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Wood
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
a Total water use data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on April 21, 2015 (Maupin et al.. 2014). Data from Nicot et al. (2012)
transcribed.
b Percentages calculated by dividing projected hydraulic fracturing water use volumes from Nicot et al. (2012) by 2010 total water use from the USGS (Maupin et al.. 2014) and
multiplying by 100. Note, the projected hydraulic fracturing water use volume from Nicot et al. (2012) was not added to the 2010 total USGS water use value in the
denominator, and is simply expressed as a percentage compared to 2010 total water use. This was done because of the difference in years between the two datasets, and
because the USGS 2010 Water Census (Maupin et al.. 2014) included hydraulic fracturing water use estimates in their mining category. This approach is consistent with that of
other literature on this topic; see Nicot and Scanlon (2012). Estimates of projected hydraulic fracturing water use as a percentage of 2010 total water use exceeded 100% when
projected hydraulic fracturing water use exceeded 2010 total water use in that county in 2010.
c Percentages less than 0.1 were not rounded and simply noted as "<0.1," but where the percentage was actually zero because there was no projected hydraulic fracturing water
use we noted that as "0.0."
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Appendix B - Water Acquisition Supplemental Information
B.2. Supplemental Discussion: Potential for Water Acquisition Impacts by
Location
This section includes an expanded discussion of the potential for water acquisition impacts by
location. This discussion provides further examples of the concepts illustrated in Chapter 4, Section
4.5, and includes a discussion for Oklahoma and Kansas (Section B.2.1) and Utah, New Mexico, and
California (Section B.2.2).
B.2.1. Oklahoma and Kansas
Oklahoma had the fifth most disclosures in the EPA FracFocus 1.0 project database (5.0% of
disclosures) (Table B-5, Figure 4-4), Three major basins—the Anadarko, which includes the
Woodford play; the Arkoma, which includes the Fayetteville play; and the Ardmore, which includes
the Woodford play—contain 67% of the disclosures in Oklahoma (Table B-5, Figure B-l). Few wells
were reported for Kansas (Kansas disclosures comprise 0.4% of the EPA FracFocus 1.0 project
database), but because of the shared geology of the Cherokee Platform across the two states, we
group Kansas with Oklahoma. Oklahoma and Kansas were two of the three states where a large
fraction of wells were not associated with a basin defined by the U.S. EI A fU.S. EPA. 2015cl (Table
B-5).1
Anadarko
i
Woodford
P/ay^
Arkoma
| EIA Plays
EIA Basins
Figure B-l. Major U.S. EIA shale
Source: EIA (2015).
•Alaska was the other state in the EPA FracFocus 1.0 project database where the U.S. EIA shale basins did not adequately
describe well locations, with all 37 wells in Alaska not associated with a U.S. EIA basin. For all other states, U.S. EIA shale
basins captured 86%-100% of the wells in the EPA FracFocus 1.0 project database ("U.S. EPA. 2015cl
Ardmore
plays and basins for Oklahoma and Kansas.
B-53

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Appendix B - Water Acquisition Supplemental Information
Types of water used: Water for hydraulic fracturing in Oklahoma and Kansas comes from both
surface and groundwater fKansas Water Office. 2014: Taylor. 20121. Data on temporary water use
permits in Oklahoma (which make up the majority of water use permits for Oklahoma oil and gas
mining) show that, in 2011, approximately 63% and 37% of water for hydraulic fracturing came
from surface and groundwater, respectively fTaylor. 20121 (Table 4-1). General water use in
Oklahoma follows an east-west divide, with the eastern half dependent on surface sources and the
western half relying heavily on groundwater fOWRB. 20141. Water obtained for fracturing is
assumed to fit this pattern as well. No data are available on the proportion of hydraulic fracturing
water that is sourced from surface versus groundwater resources in Kansas.
For both Oklahoma and Kansas, data are also lacking to describe the extent to which reused
wastewater is used as a percentage of total injected volume. However, the quality of Oklahoma's
Woodford Shale wastewater has been described as low in TDS, and thus reuse could reduce the
demand for fresh water fKuthnertetal.. 20121.
Water use per well: Estimates of median water use per well in Oklahoma include 2.6 million gal (9.8
million L) and 3 million gal (11 million L) (U.S. EPA: Murray. 2013. respectively). Water use for
hydraulic fracturing increased from 2000 to 2011, driven by volumes required for fracturing
horizontal wells across the state fMurray. 20131. Within the state, there are wide ranges in water
use for different formations. According to the EPA FracFocus 1.0 project database, the Ardmore and
Arkoma Basins of Oklahoma had the highest median water use in the country, with medians of 8.0
and 6.7 million gal (30.3 and 25.4 million L) per well, respectively; whereas the Anadarko Basin had
lower median water use per well (3.3 million gal (12.5 million L) (Table B-5). Wells not associated
with a U.S. EIA basin had a median of 1.9 million gal (7.2 million L) per well (Table B-5). It is not
clear why lower water volumes were reportedly used in unassociated wells, but Oklahoma has
several CBM deposits in the eastern part of the state where very low water use per well has been
reported (i.e., less than approximately 300,000 gal (1.1 million L) in the Arbuckle and Hartshorne
formations) fMurray. 20131. Median water use per well in Kansas was 1.5 million gal (5.7 million
L), focused mostly in a five-county area in the south-central and southwest portions of the state
(Table B-5).
Water use/consumption at the county scale: Operators reported using an average of 71.9 million gal
(272.2 million L) of water annually in Oklahoma counties with reported fracturing activity in 2011
and 2012; in Kansas, this value was 3.5 million gal (13.2 million L) (Table B-2). Average hydraulic
fracturing water use in 2011 and 2012 did not exceed 10% of 2010 total water use in any county in
Oklahoma or Kansas (Table B-2). However, there were six counties in Oklahoma (Alfalfa, Canadian,
Coal, Pittsburg, Rogers Mills, and Woods) where fracturing water consumption exceeded 10% of
2010 total county water consumption.
Potential for impacts: The potential for impacts on drinking water resources appears to be low in
Oklahoma and Kansas at the county scale, since hydraulic fracturing water use and consumption
are generally low as a percentage of total water use, consumption, and availability at this scale
(Text Box 4-2, Figure 4-6a,b). If local impacts to water quantity or quality do occur, they are more
likely to happen in western Oklahoma than in the eastern half of the state or Kansas. Of the six
Oklahoma counties where fracturing consumption exceeded 10% of 2010 water consumption,
B-54

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Appendix B - Water Acquisition Supplemental Information
three (Alfalfa, Canadian, and Roger Mills) are in the western half of the state where surface water
availability is lowest (Figure 4-7a). Surface water is fully allocated in the Panhandle and West
Central regions, encompassing much of the state's northwestern quadrant (OWRB. 20141. As a
result, residents generally rely on groundwater in western Oklahoma (Table B-6), and it is likely
that fracturing does as well.
Projecting out to 2060, Oklahoma's Water Plan concludes that aquifer storage depletions are likely
in the Panhandle and West Central regions due to over-pumping, particularly for irrigation (OWRB.
20141. Groundwater depletions are anticipated to be small relative to storage, but will be the
largest in summer months and may lead to higher pumping costs, the need for deeper water wells,
lower water yields, and detrimental effects on water quality fOWRB. 20141. Drought conditions are
likely to exacerbate this problem, and Oklahoma's Water Plan raises the potential for climate
change to affect future water supplies in the state (OWRB. 20141. In the adjacent Texas Panhandle,
future irrigation needs may go unmet fTWDB. 20121. and this may be the case in western Oklahoma
as well.
Aquifer depletions in western Oklahoma may be associated with groundwater quality degradation,
particularly under drought conditions. The central portion of the Ogallala aquifer underlying the
Oklahoma Panhandle and western Oklahoma contains elevated levels of some constituents (e.g.,
nitrate) due to over-pumping, although generally it is of better quality than the southern portion of
the aquifer (Gurdak et al.. 20091. Additional groundwater withdrawals for hydraulic fracturing in
western Oklahoma may add to these water quality issues, particularly in combination with other
substantial water uses (e.g., irrigation) fGurdak et al.. 20091.
B.2.2. Utah, New Mexico, and California
Together, Utah, New Mexico, and California accounted for approximately 9% of disclosures in the
EPAFracFocus 1.0 project database (3.8%, 3.1% and 1.9% of disclosures, respectively) (Table B-5,
Figure 4-4). Almost all reported hydraulic fracturing in Utah and California was in the Uinta-
Piceance Basin (99%) and San Joaquin Basin (95%), respectively. Activity in New Mexico mostly
occurs in the Permian and San Juan Basins, which together comprised 96% of reported disclosures
in that state (Figure B-2).
B-55

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Appendix B - Water Acquisition Supplemental Information
Uirita-Pii
nee
San
Joaquin
San Juan
Permian
EIA Plays
EIA Basins
Figure B-2. Major U.S. EIA shale plays and basins for Utah, New Mexico, and California.
Source: EIA (2015).
Types of water used: Of these three states, California has the most information available on the
sources of water used for hydraulic fracturing. Most current and proposed fracturing activity occurs
in Kern County in the San Joaquin Basin, where operators depend mainly on surface water
purchased from nearby irrigation districts fCCST. 20141. California irrigation districts receive water
allocated by the State Water Project, and deliveries may be restricted or eliminated during drought
years fCCST. 20141.1 In addition to publicly-supplied surface water, operators may also self-supply
a smaller proportion of water from on-site groundwater wells fCCST, 20141. Most water used for
hydraulic fracturing in California is fresh (91% of annual water used in well stimulation) fCCST.
2015a). Approximately 13% of water demand for hydraulic fracturing is offset by the reuse of
wastewater, according to well stimulation records fCCST. 2015al (Table 4-2).
The source, quality, and provisioning of water used for hydraulic fracturing in Utah and New
Mexico are not as well characterized. A 2010 New Mexico water use report summarizes
withdrawals for a variety of water use categories, and 26% and 74% of mining water use (which
includes water used for oil and gas production) came from surface and groundwater withdrawals,
respectively (NM OSE. 20131. If hydraulic fracturing water use in New Mexico follows the same
pattern as other mining uses (e.g., for metals, coal, geothermal), then it is likely that groundwater is
the primary source. To our knowledge, no data are available to characterize the source of water for
1 The California State Water Project is a water storage and distribution system maintained by the California Department of
Water Resources, which provides water for urban and agricultural water suppliers in Northern California, the San
Francisco Bay Area, the San Joaquin Valley, the Central Coast, and Southern California fCalifornia Department of Water
Resources. 20151.
B-56

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Appendix B - Water Acquisition Supplemental Information
hydraulic fracturing operations in Utah. In addition, data are lacking on the reuse of wastewater as
a proportion of total water injected for both Utah and New Mexico.
Water use per well: Median water use per well in Utah, New Mexico, and California is lower than in
other states in the EPA FracFocus 1.0 project database: Utah ranks 13th (approximately 302,000 gal
or 1.14 million L), New Mexico ranks 14th (approximately 175,000 gal or 662,000 L), and California
ranks 15th (approximately 77,000 gal or 291,000 L) out of the 15 states (Table B-5). A possible
explanation for the low water use per well in Utah and New Mexico is the presence of CBM in the
Uinta (Utah) and San Juan (New Mexico) Basins. Low water use per well in California is attributed
to the prevalence of vertical wells and the use of crosslinked gels. Vertical wells dominate because
the complex geology precludes long horizontal drilling and fracturing fCCST. 20141.
For California, the California Council on Science and Technology (CCST) reports average water use
per well of 130,000 gal (490,000 L), which agrees with the state average of approximately 131,700
gal (498,500 L) according to the EPA FracFocus 1.0 project database fCCST. 20141 (Table B-5); this
is to be expected, because estimates from CCST are also based on data submitted to FracFocus.
Water use/consumption at the county scale: Hydraulic fracturing in Utah, New Mexico, and
California uses relatively small amounts of water at the county scale compared to most other states
(Table B-l). Only in four counties (Duchesne and Uintah Counties in Utah, and Eddy and Lea
Counties in New Mexico) did hydraulic fracturing operators use more than 50 million gal (189
million L) annually in 2011 and 2012 (Table B-2). Fracturing water use and consumption did not
exceed 1% of 2010 total water use and consumption in any county.
Potential for impacts: At present, hydraulic fracturing does not use or consume much water
compared to other users or consumers in Utah, New Mexico, and California at the county scale
(Figure 4-2a,b). Likewise, it also does not use much water compared to county level water
availability estimates (Text Box 4-2, Figure 4-6a,b). In general, however, Utah, New Mexico, and
California have low surface water availability (Figure 4-7a), high groundwater dependence (Figure
4-7b), and have experienced frequent periods of drought over the last decade (National Drought
Mitigation Center. 20151. All of these factors increase the potential for localized impacts. In
California, two recent studies conclude changes in water quantity or quality are possible in the San
Joaquin Basin due to hydraulic fracturing withdrawals, especially within Kern County where oil and
gas activities are concentrated and fresh water is in limited supply (Tiedeman etal.. 2016: CCST.
2015a). The combination of factors also suggest future problems could arise if hydraulic fracturing
water withdrawals increase substantially in these states beyond present levels, without
commensurate steps to reduce fresh water demand.
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Appendix C - Chemical Mixing Supplemental Information
Appendix C. Chemical Mixing Supplemental
Information

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Appendix C - Chemical Mixing Supplemental Information
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C-2

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Appendix C - Chemical Mixing Supplemental Information
Appendix C. Chemical Mixing Supplemental Information
C.l. Most Frequently Reported Chemicals in Gas- and Oil-Producing Wells
Table C-l. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0 project
database for gas-producing wells, with the number of disclosures (for reported chemicals),
percentage of disclosures, and the median maximum concentration (% by mass) of that
chemical in hydraulic fracturing fluid.
Chemicals ranked by frequency of occurrence (U.S. EPA, 2015c). See Text Box 5-2 for more information.
Chemical name
CASRN
Number of
disclosures
Percentage of
disclosures
Median maximum
concentration in hydraulic
fracturing fluid (% by mass)
Hydrochloric acid
7647-01-0
12,351
72.8%
15%
Methanol
67-56-1
12,269
72.3%
30%
Distillates, petroleum,
hydrotreated light
64742-47-8
11,897
70.1%
30%
Isopropanol
67-63-0
8,008
47.2%
30%
Water
7732-18-5
7,998
47.1%
63%
Ethanol
64-17-5
6,325
37.3%
5%
Propargyl alcohol
107-19-7
5,811
34.2%
10%
Glutaraldehyde
111-30-8
5,635
33.2%
30%
Ethylene glycol
107-21-1
5,493
32.4%
35%
Citric acid
77-92-9
4,832
28.5%
60%
Sodium hydroxide
1310-73-2
4,656
27.4%
5%
Peroxydisulfuric acid,
diammonium salt
7727-54-0
4,618
27.2%
100%
Quartz
14808-60-7
3,758
22.1%
10%
2,2-Dibromo-3-
nitrilopropionamide
10222-01-2
3,668
21.6%
100%
Sodium chloride
7647-14-5
3,608
21.3%
30%
Guar gum
9000-30-0
3,586
21.1%
60%
Acetic acid
64-19-7
3,563
21.0%
50%
2-Butoxyethanol
111-76-2
3,325
19.6%
10%
Naphthalene
91-20-3
3,294
19.4%
5%
Solvent naphtha, petroleum,
heavy arom.
64742-94-5
3,287
19.4%
30%
C-3

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Number of
disclosures
Percentage of
disclosures
Median maximum
concentration in hydraulic
fracturing fluid (% by mass)
Quaternary ammonium
compounds, benzyl-C12-16-
alkyldimethyl, chlorides
68424-85-1
3,259
19.2%
7%
Potassium hydroxide
1310-58-3
2,843
16.8%
15%
Ammonium chloride
12125-02-9
2,483
14.6%
10%
Choline chloride
67-48-1
2,477
14.6%
75%
Poly(oxy-l,2-ethanediyl)-
nonylphenyl-hydroxy (mixture)
127087-87-0
2,455
14.5%
5%
Sodium chlorite
7758-19-2
2,372
14.0%
10%
1,2,4-Trimethylbenzene
95-63-6
2,229
13.1%
1%
Carbonic acid, dipotassium salt
584-08-7
2,154
12.7%
60%
Methenamine
100-97-0
2,134
12.6%
1%
Formic acid
64-18-6
2,118
12.5%
60%
Didecyl dimethyl ammonium
chloride
7173-51-5
2,063
12.2%
10%
N,N-Dimethylformamide
68-12-2
1,892
11.2%
13%
Phenolic resin
9003-35-4
1,852
10.9%
5%
Thiourea polymer
68527-49-1
1,702
10.0%
30%
Polyethylene glycol
25322-68-3
1,696
10.0%
60%
C-4

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Appendix C - Chemical Mixing Supplemental Information
Table C-2. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0 project
database for oil-producing wells, with the number of disclosures (for reported chemicals),
percentage of disclosures, and the median maximum concentration (% by mass) of that
chemical in hydraulic fracturing fluid.
Chemicals ranked by frequency of occurrence (U.S. EPA, 2015c).
Chemical name
CASRN
Number of
disclosures
Percentage of
disclosures
Median maximum
concentration in
hydraulic fracturing
fluid (% by mass)
Methanol
67-56-1
12,484
71.8%
30%
Distillates, petroleum, hydrotreated
light
64742-47-8
10,566
60.8%
40%
Peroxydisulfuric acid, diammonium salt
7727-54-0
10,350
59.6%
100%
Ethylene glycol
107-21-1
10,307
59.3%
30%
Hydrochloric acid
7647-01-0
10,029
57.7%
15%
Guar gum
9000-30-0
9,110
52.4%
50%
Sodium hydroxide
1310-73-2
8,609
49.5%
10%
Quartz
14808-60-7
8,577
49.4%
2%
Water
7732-18-5
8,538
49.1%
67%
Isopropanol
67-63-0
8,031
46.2%
15%
Potassium hydroxide
1310-58-3
7,206
41.5%
15%
Gluta raldehyde
111-30-8
5,927
34.1%
15%
Propargyl alcohol
107-19-7
5,599
32.2%
5%
Acetic acid
64-19-7
4,623
26.6%
30%
2-Butoxyethanol
111-76-2
4,022
23.1%
10%
Solvent naphtha, petroleum, heavy
arom.
64742-94-5
3,821
22.0%
5%
Sodium chloride
7647-14-5
3,692
21.2%
25%
Ethanol
64-17-5
3,536
20.3%
45%
Citric acid
77-92-9
3,310
19.0%
60%
Phenolic resin
9003-35-4
3,109
17.9%
5%
Naphthalene
91-20-3
3,060
17.6%
5%
Nonyl phenol ethoxylate
9016-45-9
2,829
16.3%
20%
Diatomaceous earth, calcined
91053-39-3
2,655
15.3%
100%
C-5

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Number of
disclosures
Percentage of
disclosures
Median maximum
concentration in
hydraulic fracturing
fluid (% by mass)
Methenamine
100-97-0
2,559
14.7%
1%
Tetramethylammonium chloride
75-57-0
2,428
14.0%
1%
Carbonic acid, dipotassium salt
584-08-7
2,402
13.8%
60%
Ethoxylated propoxylated C12-14
alcohols
68439-51-0
2,342
13.5%
2%
Choline chloride
67-48-1
2,264
13.0%
75%
Boron sodium oxide
1330-43-4
2,228
12.8%
30%
Tetrakis(hydroxymethyl)phosphonium
sulfate
55566-30-8
2,130
12.3%
50%
1,2,4-Trimethylbenzene
95-63-6
2,118
12.2%
1%
Boric acid
10043-35-3
2,070
11.9%
25%
Polyethylene glycol
25322-68-3
2,025
11.7%
5%
2-Mercaptoethanol
60-24-2
2,012
11.6%
100%
2,2-Dibromo-3-nitrilopropionamide
10222-01-2
1,988
11.4%
98%
Formic acid
64-18-6
1,948
11.2%
60%
Sodium persulfate
7775-27-1
1,914
11.0%
100%
Phosphonic acid
13598-36-2
1,865
10.7%
1%
Sodium tetraborate decahydrate
1303-96-4
1,862
10.7%
30%
Potassium metaborate
13709-94-9
1,682
9.7%
60%
Ethylenediaminetetraacetic acid
tetrasodium salt hydrate
64-02-8
1,676
9.6%
0%
Poly(oxy-l,2-ethanediyl)-nonylphenyl-
hydroxy (mixture)
127087-87-0
1,668
9.6%
5%
C-6

-------
Appendix C - Chemical Mixing Supplemental Information
C.2. Most Frequently Reported Chemicals for Each State
Table C-3a. Chemicals most frequently reported in disclosures in the EPA FracFocus 1.0 project database for each state and
number (and percentage) of disclosures where a chemical is reported for that state, Alabama to Montana.
The 20 most frequently reported hydraulic fracturing fluid chemicals were identified for the 20 states that reported in disclosures in the EPA FracFocus 1.0
project database, resulting in a total of 93 chemicals. The chemicals were ranked by counting the number of states where that chemical was in the top 20;
chemicals used most widely among the most states come first. For example, methanol is reported in 19 of 20 states, so methanol is ranked first (U.S. EPA,
2015c).
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Methanol
67-56-1
55
(100%)

1333
(99.7%)
228
(39.0%)
2883
(63.3%)
77
(79.4%)
596
(59.2%)
13
(92.9%)
3
(75%)
121
(62.7%)
Distillates,
petroleum,
hydrotreated light
64742-47-8

9
(45%)
743
(55.6%)
322
(55.0%)
3358
(73.7%)
87
(89.7%)
844
(83.9%)
14
(100%)
4
(100%)
115
(59.6%)
Ethylene glycol
107-21-1
55
(100%)
20
(100%)
291
(21.8%)
350
(59.8%)

61
(62.9%)
341
(33.9%)
10
(71.4%)
3
(75%)
95
(49.2%)
Isopropanol
67-63-0
55
(100%)
13
(65%)
586
(43.9%)

2586
(56.8%)
24
(24.7%)
515
(51.2%)
11
(78.6%)

123
(63.7%)
Quartz
14808-60-7

20
(100%)

519
(88.7%)
1048
(23.0%)
22
(22.7%)
377
(37.5%)

2
(50%)
124
(64.2%)
Sodium hydroxide
1310-73-2

20
(100%)
285
(21.3%)
403
(68.9%)
996
(21.9%)
27
(27.8%)
535
(53.2%)

2
(50%)
105
(54.4%)
Ethanol
64-17-5


603
(45.1%)

2258
(49.6%)
78
(80.4%)
420
(41.7%)

4
(100%)

Guar gum
9000-30-0

10
(50%)

545
(93.2%)


494
(49.1%)

2 (50%)
83
(43.0%)
Hydrochloric acid
7647-01-0
55
(100%)

1330
(99.5%)

2408
(52.9%)
82
(84.5%)
569
(56.6%)


45
(23.3%)
Peroxydisulfuric acid,
diammonium salt
7727-54-0

10
(50%)

484
(82.7%)

21
(21.6%)
273
(27.2%)
8
(57.1%)

119
(61.7%)
Propargyl alcohol
107-19-7


813
(60.8%)


69
(71.1%)
299
(29.7%)
5
(35.7%)


C-7

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Glutaraldehyde
111-30-8


737
(55.1%)


73
(75.3%)
364
(36.3%)

2
(50%)

Naphthalene
91-20-3
55
(100%)



1363
(29.9%)
41
(42.3%)
293
(29.2%)
12
(85.7%)

95
(49.2%)
2-Butoxyethanol
111-76-2
55
(100%)
20
(100%)





11
(78.6%)


Citric acid
77-92-9





45
(46.4%)




Saline
7647-14-5




1574
(34.5%)

408
(40.6%)

2
(50%)

Solvent naphtha,
petroleum, heavy
arom.
64742-94-5




1507
(33.1%)
42
(43.3%)



135
(70.0%)
Quaternary
ammonium
compounds, benzyl-
C12-16-
alkyldimethyl,
chlorides
68424-85-1


375
(28.0%)


52
(53.6%)


2
(50%)

2,2-Dibromo-3-
nitrilopropionamide
10222-01-2
55
(100%)



2215
(48.6%)


10
(71.4%)

70
(36.3%)
Potassium hydroxide
1310-58-3






340
(33.8%)

4
(100%)
115
(59.6%)
Choline chloride
67-48-1




1235
(27.1%)





Polyethylene glycol
25322-68-3
55
(100%)






7
(50%)

69
(35.8%)
1,2,4-
Trimethylbenzene
95-63-6




1211
(26.63%)
39
(40.2%)




Ammonium chloride
12125-02-9


277
(20.7%)

1280
(28.0%)





C-8

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Diatomaceous earth,
calcined
91053-39-3

20
(100%)

417
(71.3%)






Didecyl dimethyl
ammonium chloride
7173-51-5


317
(23.7%)





2
(50%)

Sodium chlorite
7758-19-2






352
(35.0%)

4
(100%)

Sodium erythorbate
6381-77-7


435
(32.5%)


29
(29.9%)




N,N-
Dimethylformamide
68-12-2










Nonyl phenol
ethoxylate
9016-45-9










Poly(oxy-l,2-
ethanediyl)-
nonylphenyl-hydroxy
(mixture)
127087-87-
0



1150
(25.2%)
39
(40.2%)





Sodium persulfate
7775-27-1








4
(100%)

Tetramethylammoni
um chloride
75-57-0









85
(44.0%)
1,2-Propylene glycol
57-55-6







10
(71.4%)


5-Chloro-2-methyl-
3(2H)-isothiazolone
26172-55-4

20
(100%)

389
(66.5%)






Acetic acid
64-19-7




959
(21.0%)

284
(28.2%)



Ammonium acetate
631-61-8








2
(50%)

Boric acid
10043-35-3

3
(15%)








C-9

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Carbonic acid,
dipotassium salt
584-08-7




1159
(25.4%)





Cristobalite
14464-46-1

20
(100%)

389
(66.5%)






Formic acid
64-18-6
55 (100%)





293
(29.1%)



Hemicellulase
enzyme
9012-54-8










Hemicellulase
enzyme concentrate
9025-56-3



395
(67.5%)






Iron(ll) sulfate
heptahydrate
7782-63-0







7
(50%)


Magnesium chloride
7786-30-3

20
(100%)

389
(66.5%)






Magnesium nitrate
10377-60-3

20
(100%)

389
(66.5%)






Phenolic resin
9003-35-4










Sodium hypochlorite
7681-52-9




1046
(23.0%)





Sodium tetraborate
decahydrate
1303-96-4

14
(70%)








Solvent naphtha,
petroleum, heavy
aliph.
64742-96-7







7
(50%)
2
(50%)

l-Butoxy-2-propanol
5131-66-8



315
(53.8%)






1-Propanol
71-23-8




1232
(27.0%)





C-10

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
1,2-
Ethanediaminium, N,
N'-bis[2-[bis(2-
hydroxyethyl) methyl
ammonio]ethyl]-
N,N'bis(2-
hydroxyethyl)-N,N'-
dimethyl-
,tetrachloride
138879-
94-4


343
(58.6%)







2-bromo-3-
nitrilopropionamide
1113-55-9










2-Ethylhexanol
104-76-7









83
(43.0052%)
2-Methyl-3(2H)-
isothiazolone
2682-20-4

20
(100%)

389
(66.5%)






2-Propenoic acid,
polymer with 2-
propenamide
9003-06-9










Alkenes, C>10
.alpha.-
64743-02-8


241
(18.0%)







Benzene, l,l'-oxybis-
, tetrapropylene
derivs., sulfonated
119345-
03-8









50
(25.9%)
Benzenesulfonic acid,
dodecyl-, compd.
with Nl-(2-
aminoethyl)-l,2-
ethanediamine (1:?)
40139-72-8









48
(24.9%)
Benzyldimethyldodec
ylammonium
chloride
139-07-1


268
(20.0%)







Benzylhexadecyldime
thylammonium
chloride
122-18-9


268
(20.0%)







C-ll

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Boron sodium oxide
1330-43-4



361
(61.7%)






C10-C16 ethoxylated
alcohol
68002-97-1

3
(15%)








Calcium chloride
10043-52-4

20
(100%)








Carbon dioxide
124-38-9







7
(50%)


Cinnamaldehyde (3-
phenyl-2-propenal)
104-55-2
55
(100%)









Diethylene glycol
111-46-6










Diethylene glycol
monobutyl ether
112-34-5







7
(50%)


Diethylenetriamine
111-40-0









55
(28.5%)
Distillates,
petroleum,
hydrotreated light
paraffin ic
64742-55-8



314
(53.7%)






Distillates,
petroleum,
hydrotreated middle
64742-46-7

3
(15%)








Ethoxylated C12-16
alcohols
68551-12-2










Ethoxylated C14-15
alcohols
68951-67-7


241
(18.0%)







Formic acid,
potassium salt
590-29-4










Glycerin, natural
56-81-5







7
(50%)


C-12

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Isotridecanol,
ethoxylated
9043-30-5



312
(53.3%)






Methenamine
100-97-0






298
(29.6%)



Naphtha, petroleum,
hydrotreated heavy
64742-48-9










Poly(oxy-l,2-
ethanediyl), .alpha.,
.alpha.'-[[(9Z)-9-
octadecenylimino]di-
2,1-ethanediyl]
bis[.omega.-hydroxy-
26635-93-8







9
(64.3%)


Potassium chloride
7447-40-7







7
(50%)


Sodium bromate
7789-38-0







7
(50%)


Sodium perborate
tetrahydrate
10486-00-7










Sulfamic acid
5329-14-6








2
(50%)

Terpenes and
Terpenoids, sweet
orange-oil
68647-72-3








2
(50%)

Tetradecyl dimethyl
benzyl ammonium
chloride
139-08-2


268
(20.0%)







Tetrakis(hydroxymet
hyl)phosphonium
sulfate
55566-30-8










Thiourea polymer
68527-49-1


384
(28.7%)







C-13

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Alabama
Alaska
Arkansas
California
Colorado
Kansas
Louisiana
Michigan
Mississippi
Montana
Tri-n-butyl tetradecyl
phosphonium
chloride
81741-28-8










Trisodium phosphate
7601-54-9





19
(19.6%)




C-14

-------
Appendix C - Chemical Mixing Supplemental Information
Table C-3b. Chemicals most frequently reported in disclosures in the EPA FracFocus 1.0 project database for each state and
number (and percentage) of disclosures where a chemical is reported for that state, New Mexico to Wyoming.
The 20 most frequently reported hydraulic fracturing fluid chemicals were identified for the 20 states that reported in disclosures in the EPA FracFocus 1.0
project database, resulting in a total of 93 chemicals. The chemicals were ranked by counting the number of states where that chemical was in the top 20;
chemicals used most widely among the most states come first. For example, methanol is reported in 19 of 20 states, so methanol is ranked first (U.S. EPA,
2015c).
Chemical name
CASRN
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsyl-
vania
Texas
Utah
Virginia
West
Virginia
Wyoming
Methanol
67-56-1
1012
(90.8%)
1059
(53.3%)
76
(52.1%)
1270
(70.3%)
1633
(68.6%)
12664
(78.5%)
984
(78.5%)
48
(60.8%)
153
(64.0%)
460
(38.4%)
Distillates, petroleum,
hydrotreated light
64742-47-8
699
(62.7%)
943
(47.5%)
122
(83.6%)
1270
(70.3%)
1434
(60.2%)
10677
(66.1%)
934
(74.5%)

196
(82.0%)
612
(51.1%)
Ethylene glycol
107-21-1
503
(45.1%)
724
(36.4%)
83
(56.8%)
843
(46.7%)
807
(33.9%)
9591
(59.4%)
1065
(85.0%)
22
(27.8%)
141
(59.0%)

Isopropanol
67-63-0
695
(62.3%)
739
(37.2%)
71
(48.6%)
764
(42.28%)
735
(30.9%)
7731
(47.9%)
661
(52.8%)
43
(54.4%)
74
(31.0%)
516
(43.1%)
Quartz
14808-60-7
762
(68.3%)
920
(46.3%)
66
(45.2%)
491
(27.2%)

6869
(42.6%)
503
(40.1%)

53
(22.2%)
356
(29.7%)
Sodium hydroxide
1310-73-2
329
(29.5%)
1028
(51.7%)

490
(27.1%)
406
(17.0%)
7371
(45.7%)
466
(37.2%)


688
(57.4%)
Ethanol
64-17-5
529
(47.4%)
545
(27.4%)
87
(59.6%)
838
(46.4%)
388
(16.3%)
3439
(21.3%)

50
(63.3%)
130
(54.3%)
298
(24.9%)
Guar gum
9000-30-0
702
(63.0%)
1094
(55.1%)
74
(50.7%)
457
(25.3%)
538
(22.6%)
6863
(42.5%)
538
(42.9%)

55
(23.0%)
823
(68.7%)
Hydrochloric acid
7647-01-0
880
(78.9%)

145
(99.3%)
1372
(75.9%)
2279
(95.7%)
11424
(70.8%)
1064
(84.9%)
68
(86.1%)
229
(95.8%)

Peroxydisulfuric acid,
diammonium salt
7727-54-0
836
(75.0%)
1089
(54.8%)
93
(63.7%)
713
(39.5%)

8666
(53.7%)
483
(38.5%)

128
(53.6%)
771
(64.4%)
Propargyl alcohol
107-19-7
760
(68.2%)

72
(49.3%)
732
(40.5%)
1371
(57.6%)
6269
(38.8%)
456
(36.4%)
22
(27.8%)
138
(57.7%)

C-15

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsyl-
vania
Texas
Utah
Virginia
West
Virginia
Wyoming
Glutaraldehyde
111-30-8
632
(56.7%)

105
(71.9%)
989
(54.7%)
819
(34.4%)
6470
(40.1%)


169
(70.7%)
260
(21.7%)
Naphthalene
91-20-3

864
(43.5%)

448
(24.8%)


478
(38.1%)
7
(8.9%)


2-Butoxyethanol
111-76-2
412
(37.0%)



498
(20.9%)
3898
(24.1%)
663
(52.9%)
70
(88.6%)
62
(25.9%)

Citric acid
77-92-9
447
(40.1%)

96
(65.8%)
644
(35.6%)
701
(29.4%)
3820
(23.7%)
992
(79.2%)
63
(79.8%)
98
(41.0%)

Saline
7647-14-5

491
(24.7%)



3462
(21.4%)

7
(8.9%)
53
(22.2%)
274
(22.9%)
Solvent naphtha,
petroleum, heavy arom.
64742-94-5

981
(49.4%)

557
(30.8%)

2751
(17.0%)

7
(8.9%)

415
(34.6%)
Quaternary ammonium
compounds, benzyl-C12-
16-alkyldimethyl,
chlorides
68424-85-1


54
(37.0%)
597
(33.0%)
373
(15.7%)



53
(22.2%)

2,2-Dibromo-3-
nitrilopropionamide
10222-01-2




804
(33.8%)


22
(27.8%)


Potassium hydroxide
1310-58-3

1176
(59.2%)
106
(72.6%)


6369
(39.5%)




Choline chloride
67-48-1
384
(34.4%)

55
(37.7%)



649
(51.8%)
45
(57.0%)


Polyethylene glycol
25322-68-3

567
(28.5%)


688
(28.9%)





1,2,4-Trimethyl benzene
95-63-6

496
(25.0%)





7
(8.9%)


Ammonium chloride
12125-02-9




732
(30.7%)



50
(20.9%)

C-16

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsyl-
vania
Texas
Utah
Virginia
West
Virginia
Wyoming
Diatomaceous earth,
calcined
91053-39-3
419
(37.6%)





435
(34.7%)



Didecyl dimethyl
ammonium chloride
7173-51-5


46
(31.6%)





49
(20.5%)

Sodium chlorite
7758-19-2

482
(24.3%)







271
(22.6%)
Sodium erythorbate
6381-77-7







10
(12.7%)
76
(31.8%)

N,N-Dimethylformamide
68-12-2


68
(46.6%)
355
(19.6%)


410
(32.7%)



Nonyl phenol ethoxylate
9016-45-9
333
(29.9%)





447
(35.7%)
25
(31.6%)


Poly(oxy-l,2-ethanediyl)-
nonylphenyl-hydroxy
(mixture)
127087-87-0







7
(8.9%)


Sodium persulfate
7775-27-1




373
(15.7%)




308
(25.7%)
Tetramethylammonium
chloride
75-57-0

579
(29.1%)







315
(26.3%)
1,2-Propylene glycol
57-55-6







22
(27.8%)


5-Chloro-2-methyl-3(2H)-
isothiazolone
26172-55-4










Acetic acid
64-19-7










Ammonium acetate
631-61-8









323
(27.0%)
Boric acid
10043-35-3


82
(56.2%)







C-17

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsyl-
vania
Texas
Utah
Virginia
West
Virginia
Wyoming
Carbonic acid,
dipotassium salt
584-08-7

482
(24.2%)








Cristobalite
14464-46-1










Formic acid
64-18-6










Hemicellulase enzyme
9012-54-8




367
(15.4%)


11
(13.9%)


Hemicellulase enzyme
concentrate
9025-56-3
331
(29.7%)









Iron(ll) sulfate
heptahydrate
7782-63-0







22
(27.8%)


Magnesium chloride
7786-30-3










Magnesium nitrate
10377-60-3










Phenolic resin
9003-35-4
419
(37.6%)




2903
(18.0%)




Sodium hypochlorite
7681-52-9









282
(23.5%)
Sodium tetraborate
decahydrate
1303-96-4









265
(22.1%)
Solvent naphtha,
petroleum, heavy aliph.
64742-96-7










l-Butoxy-2-propanol
5131-66-8










1-Propanol
71-23-8










C-18

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsyl-
vania
Texas
Utah
Virginia
West
Virginia
Wyoming
1,2-Ethanediaminium, N,
N'-bis[2-[bis(2-
hydroxyethyl)
methylammonio]ethyl]-
N,N'bis(2-hydroxyethyl)-
N,N'-dimethyl-,
tetrachloride
138879-94-4










2-Bromo-3-
nitrilopropionamide
1113-55-9







11
(13.9%)


2-Ethylhexanol
104-76-7










2-Methyl-3(2H)-
isothiazolone
2682-20-4










2-Propenoic acid, polymer
with 2-propenamide
9003-06-9






486
(38.8%)



Alkenes, C>10 .alpha.-
64743-02-8










Benzene, l,l'-oxybis-,
tetrapropylene derivs.,
sulfonated
119345-03-8










Benzenesulfonic acid,
dodecyl-, compd. with Nl-
(2-aminoethyl)-l,2-
ethanediamine (1:?)
40139-72-8










Benzyldimethyldodecylam
monium chloride
139-07-1










Benzylhexadecyldimethyla
mmonium chloride
122-18-9










Boron sodium oxide
1330-43-4










C10-C16 ethoxylated
alcohol
68002-97-1










C-19

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsyl-
vania
Texas
Utah
Virginia
West
Virginia
Wyoming
Calcium chloride
10043-52-4










Carbon dioxide
124-38-9










Cinnamaldehyde (3-
phenyl-2-propenal)
104-55-2










Diethylene glycol
111-46-6


45
(30.8%)







Diethylene glycol
monobutyl ether
112-34-5










Diethylenetriamine
111-40-0










Distillates, petroleum,
hydrotreated light
paraffin ic
64742-55-8










Distillates, petroleum,
hydrotreated middle
64742-46-7










Ethoxylated C12-16
alcohols
68551-12-2








57
(23.8%)

Ethoxylated C14-15
alcohols
68951-67-7










Formic acid, potassium
salt
590-29-4









361
(30.1%)
Glycerin, natural
56-81-5










Isotridecanol, ethoxylated
9043-30-5










Methenamine
100-97-0










Naphtha, petroleum,
hydrotreated heavy
64742-48-9









384
(32.1%)
C-20

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsyl-
vania
Texas
Utah
Virginia
West
Virginia
Wyoming
Poly(oxy-l,2-ethanediyl),
. alpha.,, alpha. '-[[(9Z)-9-
octadecenylimino]di-2,l-
ethanediyl] bis[. omega.-
hydroxy-
26635-93-8










Potassium chloride
7447-40-7










Sodium bromate
7789-38-0










Sodium perborate
tetrahydrate
10486-00-7



351
(19.4%)






Sulfamic acid
5329-14-6










Terpenes and terpenoids,
sweet orange-oil
68647-72-3










Tetradecyl dimethyl
benzyl ammonium
chloride
139-08-2










Tetrakis(hydroxymethyl)p
hosphonium sulfate
55566-30-8






945
(75.4%)



Thiourea polymer
68527-49-1










Tri-n-butyl tetradecyl
phosphonium chloride
81741-28-8




350
(14.7%)





Trisodium phosphate
7601-54-9










C-21

-------
Appendix C - Chemical Mixing Supplemental Information
C.3. Estimating Volume and Mass for 74 Chemicals Reported in Disclosures in
the EPA FracFocus 1.0 Project Database
Volume and mass were estimated using the chemical data reported in the disclosures in the EPA
FracFocus 1.0 project database. The total hydraulic fracturing fluid volume reported was used to
calculate the total fluid mass by assuming the fluid has a density of 1 g/mL. This is a simplifying
assumption based on the fact that more than 93% of disclosures are inferred to use water as a base
fluid. Water had a median concentration of 88% (by mass) in the fracturing fluid, with 10th and 90th
percentiles of 77% and 95%. Roughly 2% of disclosures reported the use of non-aqueous base
fluids, which contained roughly 60% (median) water fU.S. EPA. 2015c! The use of non-aqueous
base fluids would introduce additional error in our calculations. We made the simplifying
assumption that this error is negligible. Some disclosures reported using brine, which has a density
between 1.0 and 1.1 g/mL. This would introduce at most an error of 10% for the fluid calculation
(the difference of a chemical being present at 10 versus 9 gal, 1,000 versus 900 gal). We also
assume that the mass of chemicals present in calculating the total fluid mass is negligible. Given that
<2% of the fluid volume are chemicals, and assuming the density of which is 3 mg/L, the error
introduced is approximately 6%. For reference, for the chemicals we are calculating volumes,
chlorine dioxide is the densest at 2.757 mg/L. Chemical with densities less than 1 mg/L introduce
approximately <1% error.
Next, the mass of each chemical per disclosure was calculated. Each chemical is reported in
disclosures to FracFocus 1.0 as a maximum concentration by mass in the hydraulic fracturing fluid.
This introduces error, as we only know that it is equal to or less than this mass fraction. In EPA's
analysis of the EPA FracFocus 1.0 project database fU.S. EPA. 2015al. an example additive is
comprised of three chemicals with maximum ingredient concentration of 60% in the additive and a
maximum concentration of 0.22% in the hydraulic fracturing fluid. Each of the three chemicals
cannot be present at 60%. Because of how chemical information was reported to FracFocus 1.0, we
have no way to know the actual proportions of each chemical in the additive and thus must
calculate chemical mass based on the given information. Therefore, our calculations likely
overestimate actual volumes. However, in some cases, the concentration in the additive that is
given is less than 100% and only one chemical is listed in the additive. In these cases, it appears that
the disclosure is reporting the concentration of that chemical in water. Hydrogen chloride (HC1) is
listed as the sole ingredient in the acid additive, and the maximum concentration is 40% by mass. In
this case, the HC1 is diluted down to 40%, so the total volume would be underestimated.
After all the chemical masses are calculated, the volume is calculated by dividing chemical mass by
density.
Given the limited information available, due to the limits of the FracFocus 1.0 chemical reporting
and general lack of publicly available data, and despite the errors associated with these
calculations, these calculations provide context for the general magnitude of volumes for each of the
chemicals used on-site. These calculations are used to calculate median volumes for each chemical
on a per well basis. These volume calculations are for the chemicals themselves, not the additives.
C-22

-------
Appendix C - Chemical Mixing Supplemental Information
The analysis considered 34,495 disclosures and 672,358 ingredient records that met selected
quality assurance criteria, including: completely parsed; unique combination of fracture date and
API well number; fracture date between January 1, 2011, and February 28, 2013; criteria for water
volumes; valid CASRN; and valid concentrations. Disclosures that did not meet quality assurance
criteria (4,035) or other, query-specific criteria were excluded from our analysis.
Density data were gathered from Reaxys® and other sources as noted. Reaxys®
f http: //www.elsevier.com /online-tools/reaxvs] is an online database of chemistry literature and
data. Direct density source, as provided by Reaxys®, is provided in Table C-7.
Reporting hydraulic fracturing well records to FracFocus 1.0 was required in six of the 20 states
with data in FracFocus between January 1, 2011, and February 28, 2013. An additional three states
required disclosure to either FracFocus or the state, and five states required reporting to the state.
Reporting to FracFocus 1.0 was optional in other states. Some states changed their reporting
requirements during the course of the study. The EPA FracFocus 1.0 project database, developed
using data directly from FracFocus 1.0, therefore does not encompass all data on chemicals used in
hydraulic fracturing. As stated in Text Box 4-2, this mix of voluntary and mandatory disclosure
requirements limits the completeness of data included in the EPA FracFocus 1.0 project database
for estimating hydraulic fracturing fluid compositions and volumes. According to a comparison
between the EPA FracFocus 1.0 project database reported fluid volumes and literature values,
water use per well was reported to be about 86% of the literature values (median of estimated
values; see Chapter 4, Text Box 4-1). If the fluid volume is underreported, then estimated chemical
volumes based on fluid volume would be similarly underestimated. Using the underreporting of
86%, then the estimated median chemical volume would be 760 gal (2,900 L).
C-23

-------
Appendix C - Chemical Mixing Supplemental Information
Table C-4. Estimated mean, median, 5th percentile, and 95th percentile volumes in gallons for
chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database,
where density information was available.
Chemicals are listed in alphabetical order. Density information came from Reaxys® and other sources. All density
sources are referenced in Table C-7.
Name
CASRN
Volume (gal)
Mean
Median
5th
Percentile
95th
Percentile
(4R)-l-methyl-4-(prop-l-en-2-
yl)cyclohexene
5989-27-5
2,702
406
0
19,741
l-Butoxy-2-propanol
5131-66-8
167
21
5
654
1-Decanol
112-30-1
28
4
0
33
1-Octanol
111-87-5
5
4
0
10
1-Propanol
71-23-8
128
55
6
367
1,2-Propylene glycol
57-55-6
13,105
72
4
61,071
1,2,4-Trimethylbenzene
95-63-6
38
6
0
43
2-Butoxyethanol
111-76-2
385
26
0
1,811
2-Ethylhexanol
104-76-7
100
11
0
292
2-Mercaptoethanol
60-24-2
1,175
445
0
4,194
2,2-Dibromo-3-nitrilopropionamide
10222-01-2
183
5
0
341
Acetic acid
64-19-7
646
47
0
1,042
Acetic anhydride
108-24-7
239
50
3
722
Acrylamide
79-06-1
95
3
0
57
Adipic acid
124-04-9
153
0
0
109
Aluminum chloride
7446-70-0
2
0
0
0
Ammonia
7664-41-7
44
35
2
138
Ammonium acetate
631-61-8
839
117
0
1,384
Ammonium chloride
12125-02-9
526
58
3
548
Ammonium hydroxide
1336-21-6
7
2
0
14
Benzyl chloride
100-44-7
52
0
0
40
Carbonic acid, dipotassium salt
584-08-7
467
113
0
1,729
Chlorine dioxide
10049-04-4
31
11
0
28
Choline chloride
67-48-1
2,131
290
28
4,364
C-24

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Volume (gal)
Mean
Median
5th
Percentile
95th
Percentile
Cinnamaldehyde (3-phenyl-2-propenal)
104-55-2
68
3
0
697
Citric acid
77-92-9
163
20
l
269
Dibromoacetonitrile
3252-43-5
22
13
l
45
Diethylene glycol
111-46-6
168
16
0
102
Diethylenetriamine
111-40-0
92
21
0
207
Dodecane
112-40-3
190
31
0
151
Ethanol
64-17-5
831
121
1
2,645
Ethanolamine
141-43-5
70
30
0
283
Ethyl acetate
141-78-6
0
0
0
0
Ethylene glycol
107-21-1
614
184
4
2,470
Ferric chloride
7705-08-0
0
0
0
0
Formalin
50-00-0
200
0
0
8
Formic acid
64-18-6
501
38
1
1,229
Fumaric acid
110-17-8
2
0
0
12
Gluta raldehyde
111-30-8
1,313
122
2
1,165
Glycerin, natural
56-81-5
413
109
10
911
Glycolic acid
79-14-1
38
10
4
94
Hydrochloric acid
7647-01-0
28,320
3,110
96
26,877
Isopropanol
67-63-0
2,095
55
0
1,264
Isopropylamine
75-31-0
83
121
0
172
Magnesium chloride
7786-30-3
14
0
0
2
Methanol
67-56-1
1,218
110
2
3,731
Methenamine
100-97-0
3,386
100
0
3,648
Methoxyacetic acid
625-45-6
36
4
2
115
N,N-Dimethylformamide
68-12-2
119
10
0
216
Naphthalene
91-20-3
72
12
0
204
Nitrogen, liquid
7727-37-9
41,841
26,610
3,091
108,200
Ozone
10028-15-6
15,844
15,473
8,785
26,063
C-25

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Volume (gal)
Mean
Median
5th
Percentile
95th
Percentile
Peracetic acid
79-21-0
300
268
50
663
Phosphonic acid
13598-36-2
1,201
0
0
3
Phosphoric acid Divosan X-Tend
formulation
7664-38-2
13
4
0
15
Potassium acetate
127-08-2
209
1
0
994
Propargyl alcohol
107-19-7
183
2
0
51
Saline
7647-14-5
876
85
0
1,544
Saturated sucrose
57-50-1
1
1
0
2
Silica, amorphous
7631-86-9
6,877
8
0
38,371
Sodium carbonate
497-19-8
228
16
0
1,319
Sodium formate
141-53-7
0
0
0
0
Sodium hydroxide
1310-73-2
551
38
0
1,327
Sulfur dioxide
7446-09-5
0
0
0
0
Sulfuric acid
7664-93-9
3
0
0
3
tert-Butyl hydroperoxide (70% solution
in Water)
75-91-2
156
64
0
557
Tetramethylammonium chloride
75-57-0
970
483
2
3,508
Thioglycolic acid
68-11-1
55
7
2
229
Toluene
108-88-3
18
0
0
11
Tridecane
629-50-5
190
31
0
190
Triethanolamine
102-71-6
846
60
0
2,264
Triethyl phosphate
78-40-0
55
1
0
533
Triethylene glycol
112-27-6
5,198
116
28
945
Triisopropanolamine
122-20-3
46
4
1
330
Trimethyl borate
121-43-7
83
40
4
283
Undecane
1120-21-4
273
29
0
1,641
C-26

-------
Appendix C - Chemical Mixing Supplemental Information
Table C-5. Estimated mean, median, 5th percentile, and 95th percentile volumes in liters for
chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database,
where density information was available.
Chemicals are listed in alphabetical order. Density information came from Reaxys® and other sources. All density
sources are referenced in Table C-7.
Name
CASRN
Volume (L)
Mean
Median
5th
Percentile
95th
Percentile
(4R)-l-methyl-4-(prop-l-en-2-
yl)cyclohexene
5989-27-5
10,229
1,536
0
74,729
l-Butoxy-2-propanol
5131-66-8
631
80
18
2,475
1-Decanol
112-30-1
107
14
1
123
1-Octanol
111-87-5
21
14
1
39
1-Propanol
71-23-8
483
208
22
1,391
1,2-Propylene glycol
57-55-6
49,607
274
15
231,179
1,2,4-Trimethylbenzene
95-63-6
145
24
0
165
2-Butoxyethanol
111-76-2
1,459
98
0
6,856
2-Ethylhexanol
104-76-7
377
40
1
1,106
2-Mercaptoethanol
60-24-2
4,449
1,685
0
15,878
2,2-Dibromo-3-nitrilopropionamide
10222-01-2
692
18
0
1,292
Acetic acid
64-19-7
2,446
176
0
3,945
Acetic anhydride
108-24-7
906
189
12
2,734
Acrylamide
79-06-1
361
10
0
216
Adipic acid
124-04-9
578
0
0
414
Aluminum chloride
7446-70-0
6
0
0
0
Ammonia
7664-41-7
166
134
7
523
Ammonium acetate
631-61-8
3,177
444
0
5,238
Ammonium chloride
12125-02-9
1,992
218
12
2,074
Ammonium hydroxide
1336-21-6
27
6
1
52
Benzyl chloride
100-44-7
196
1
0
151
Carbonic acid, dipotassium salt
584-08-7
1,769
429
0
6,544
Chlorine dioxide
10049-04-4
117
43
1
106
Choline chloride
67-48-1
8,068
1,096
107
16,521
C-27

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Volume (L)
Mean
Median
5th
Percentile
95th
Percentile
Cinnamaldehyde (3-phenyl-2-propenal)
104-55-2
258
12
0
2,638
Citric acid
77-92-9
618
77
5
1,019
Dibromoacetonitrile
3252-43-5
82
50
4
170
Diethylene glycol
111-46-6
636
61
1
384
Diethylenetriamine
111-40-0
347
80
0
785
Dodecane
112-40-3
719
117
0
572
Ethanol
64-17-5
3,144
458
6
10,011
Ethanolamine
141-43-5
264
112
0
1,070
Ethyl acetate
141-78-6
0
0
0
0
Ethylene glycol
107-21-1
2,324
697
14
9,349
Ferric chloride
7705-08-0
0
0
0
0
Formalin
50-00-0
756
2
0
31
Formic acid
64-18-6
1,896
144
2
4,653
Fumaric acid
110-17-8
9
0
0
46
Gluta raldehyde
111-30-8
4,972
462
6
4,409
Glycerin, natural
56-81-5
1,565
412
38
3,447
Glycolic acid
79-14-1
146
39
14
356
Hydrochloric acid
7647-01-0
107,204
11,772
362
101,741
Isopropanol
67-63-0
7,932
210
1
4,786
Isopropylamine
75-31-0
314
458
0
652
Magnesium chloride
7786-30-3
52
0
0
8
Methanol
67-56-1
4,609
416
6
14,125
Methenamine
100-97-0
12,817
378
0
13,810
Methoxyacetic acid
625-45-6
136
17
8
436
N,N-Dimethylformamide
68-12-2
449
38
2
819
Naphthalene
91-20-3
271
44
0
774
Nitrogen, liquid
7727-37-9
158,384
100,731
11,700
409,583
Ozone
10028-15-6
59,976
58,570
33,254
98,658
C-28

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Volume (L)
Mean
Median
5th
Percentile
95th
Percentile
Peracetic acid
79-21-0
1,137
1,016
190
2,511
Phosphonic acid
13598-36-2
4,547
2
0
11
Phosphoric acid Divosan X-Tend
formulation
7664-38-2
51
15
0
57
Potassium acetate
127-08-2
790
3
0
3,762
Propargyl alcohol
107-19-7
693
9
0
193
Saline
7647-14-5
3,317
321
0
5,844
Saturated sucrose
57-50-1
5
2
0
6
Silica, amorphous
7631-86-9
26,031
32
0
145,251
Sodium carbonate
497-19-8
862
62
0
4,991
Sodium formate
141-53-7
1
1
0
1
Sodium hydroxide
1310-73-2
2,087
144
1
5,024
Sulfur dioxide
7446-09-5
2
0
0
0
Sulfuric acid
7664-93-9
10
0
0
12
tert-Butyl hydroperoxide (70% solution in
Water)
75-91-2
591
242
0
2,109
Tetramethylammonium chloride
75-57-0
3,672
1,830
8
13,279
Thioglycolic acid
68-11-1
208
28
6
868
Toluene
108-88-3
69
0
0
41
Tridecane
629-50-5
721
118
0
721
Triethanolamine
102-71-6
3,203
228
0
8,570
Triethyl phosphate
78-40-0
209
6
0
2,019
Triethylene glycol
112-27-6
19,676
439
106
3,579
Triisopropanolamine
122-20-3
174
16
4
1,249
Trimethyl borate
121-43-7
314
152
16
1,072
Undecane
1120-21-4
1,035
111
0
6,212
C-29

-------
Appendix C - Chemical Mixing Supplemental Information
Table C-6. Calculated mean, median, 5th percentile, and 95th percentile chemical masses
reported in 100 or more disclosures in the EPA FracFocus 1.0 project database, where density
information was available.
Density information came from Reaxys® and other sources. All density sources are referenced in Table C-7.
Number of disclosures reported for each chemical is also included.
Name
CASRN
Mass (kg)
Disclosures
Mean
Median
5th
Percentile
95th
Percentile
(4R)-l-methyl-4-(prop-l-en-2-
yl)cyclohexene
5989-27-5
8,593
1,290
0
62,772
578
l-Butoxy-2-propanol
5131-66-8
555
71
16
2,178
773
1-Decanol
112-30-1
89
12
1
102
434
1-Octanol
111-87-5
17
12
1
32
434
1-Propanol
71-23-8
386
167
18
1,113
1,481
1,2-Propylene glycol
57-55-6
51,095
282
15
238,114
1,023
1,2,4-Trimethylbenzene
95-63-6
126
21
0
143
3,976
2-Butoxyethanol
111-76-2
1,313
88
0
6,170
6,778
2-Ethylhexanol
104-76-7
313
34
0
918
1,291
2-Mercaptoethanol
60-24-2
489
185
0
1,747
2,051
2,2-Dibromo-3-
nitrilopropionamide
10222-01-2
1,660
44
0
3,102
4,927
Acetic acid
64-19-7
2,544
183
0
4,103
7,643
Acetic anhydride
108-24-7
969
203
12
2,925
1,377
Acrylamide
79-06-1
408
11
0
244
251
Adipic acid
124-04-9
785
0
0
564
233
Aluminum chloride
7446-70-0
15
0
0
0
122
Ammonia
7664-41-7
111
90
4
351
398
Ammonium acetate
631-61-8
3,718
520
0
6,129
1,504
Ammonium chloride
12125-02-9
2,530
277
16
2,633
3,288
Ammonium hydroxide
1336-21-6
48
11
2
94
1,173
Benzyl chloride
100-44-7
214
1
0
165
1,833
Carbonic acid, dipotassium salt
584-08-7
4,298
1,042
0
15,902
4,093
Chlorine dioxide
10049-04-4
321
117
3
291
331
Choline chloride
67-48-1
9,440
1,282
125
19,329
4,241
C-30

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Mass (kg)
Disclosures
Mean
Median
5th
Percentile
95th
Percentile
Cinnamaldehyde (3-phenyl-2-
propenal)
104-55-2
284
13
0
2,902
1,377
Citric acid
77-92-9
989
123
8
1,630
7,503
Dibromoacetonitrile
3252-43-5
193
118
11
403
272
Diethylene glycol
111-46-6
712
68
1
430
1,732
Diethylenetriamine
111-40-0
330
76
0
746
784
Dodecane
112-40-3
539
88
0
429
131
Ethanol
64-17-5
2,484
361
4
7,908
9,233
Ethanolamine
141-43-5
267
113
0
1,081
585
Ethyl acetate
141-78-6
0
0
0
0
110
Ethylene glycol
107-21-1
2,557
767
15
10,283
14,767
Ferric chloride
7705-08-0
0
0
0
0
118
Formalin
50-00-0
816
2
0
34
456
Formic acid
64-18-6
2,313
176
2
5,677
3,781
Fumaric acid
110-17-8
15
0
0
75
224
Gluta raldehyde
111-30-8
4,972
462
6
4,409
10,963
Glycerin, natural
56-81-5
1,972
519
47
4,343
1,829
Glycolic acid
79-14-1
217
58
21
530
595
Hydrochloric acid
7647-01-0
107,204
11,772
362
101,741
20,996
Isopropanol
67-63-0
6,187
163
1
3,733
15,058
Isopropylamine
75-31-0
213
311
0
444
255
Magnesium chloride
7786-30-3
120
1
0
18
1,113
Methanol
67-56-1
3,641
329
5
11,159
23,225
Methenamine
100-97-0
15,380
454
0
16,572
4,412
Methoxyacetic acid
625-45-6
161
20
9
514
584
N,N-Dimethylformamide
68-12-2
422
36
2
770
2,972
Naphthalene
91-20-3
220
35
0
627
5,945
Nitrogen, liquid
7727-37-9
129,875
82,599
9,594
335,858
713
Ozone
10028-15-6
129
126
71
212
209
C-31

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Mass (kg)
Disclosures
Mean
Median
5th
Percentile
95th
Percentile
Peracetic acid
79-21-0
1,251
1,117
209
2,762
221
Phosphonic acid
13598-36-2
7,730
3
0
18
2,216
Phosphoric acid Divosan X-Tend
formulation
7664-38-2
48
14
0
54
315
Potassium acetate
127-08-2
1,216
5
0
5,793
325
Propargyl alcohol
107-19-7
658
9
0
183
10,771
Saline
7647-14-5
7,197
696
0
12,682
6,673
Saturated sucrose
57-50-1
6
2
0
7
125
Silica, amorphous
7631-86-9
57,267
71
0
319,553
2,423
Sodium carbonate
497-19-8
2,191
158
0
12,678
396
Sodium formate
141-53-7
2
1
1
2
204
Sodium hydroxide
1310-73-2
4,445
306
2
10,701
12,585
Sulfur dioxide
7446-09-5
2
0
0
0
224
Sulfuric acid
7664-93-9
18
0
0
22
402
tert-Butyl hydroperoxide (70%
solution in water)
75-91-2
532
218
0
1,898
814
Tetramethylammonium chloride
75-57-0
4,296
2,141
10
15,537
3,162
Thioglycolic acid
68-11-1
277
37
8
1,155
156
Toluene
108-88-3
59
0
0
35
214
Tridecane
629-50-5
541
88
0
541
132
Triethanolamine
102-71-6
3,588
255
0
9,599
1,498
Triethyl phosphate
78-40-0
222
6
0
2,140
991
Triethylene glycol
112-27-6
22,038
491
119
4,008
528
Triisopropanolamine
122-20-3
177
17
4
1,274
251
Trimethyl borate
121-43-7
292
141
14
997
294
Undecane
1120-21-4
766
82
0
4,597
241
C-32

-------
Appendix C - Chemical Mixing Supplemental Information
Table C-7. Associated chemical densities and references used to calculate chemical mass and
estimate chemical volume.
Name
CASRN
Density (g/mL)
Reference
(4R)-l-methyl-4-(prop-l-en-2-yl)cyclohexene
5989-27-5
0.84
Deiove Tanzi et al. (2012)
l-Butoxy-2-propanol
5131-66-8
0.88
Paletal. (2013)
1-Decanol
112-30-1
0.83
Faria et al. (2013)
1-Octanol
111-87-5
0.82
Dubev and Kumar (2013)
1-Propanol
71-23-8
0.8
Rani and Maken (2013)
1,2-Propylene glycol
57-55-6
1.03
Moosavi et al. (2013)
1,2,4-Trimethylbenzene
95-63-6
0.87
He et al. (2008)
2-Butoxyethanol
111-76-2
0.9
Dhondge et al. (2010)
2-Ethylhexanol
104-76-7
0.83
Laavi et al. (2012)
2-Mercaptoethanol
60-24-2
0.11
Rawat et al. (1976)
2,2-Dibromo-3-nitrilopropionamide
10222-01-2
2.4
Fels (1900)
Acetic acid
64-19-7
1.04
Thalladi et al. (2000)
Acetic anhydride
108-24-7
1.07
Radwan and Hanna (1976)
Acrylamide
79-06-1
1.13
Carpenter and Davis (1957)
Adipic acid
124-04-9
1.36
Thalladi et al. (2000)
Aluminum chloride
7446-70-0
2.48
Sigma-Aldrich (2015a)
Ammonia
7664-41-7
0.67
Harlow et al. (1997)
Ammonium acetate
631-61-8
1.17
Biltz and Balz (1928)
Ammonium chloride
12125-02-9
1.27
Havnes (2014)
Ammonium hydroxide
1336-21-6
1.8
Xiao et al. (2013)
Benzyl chloride
100-44-7
1.09
Sarkar et al. (2012)
Carbonic acid, dipotassium salt
584-08-7
2.43
Sigma-Aldrich (2014b)
Chlorine dioxide
10049-04-4
2.757
Havnes (2014)
Choline chloride
67-48-1
1.17
Shanlev and Collin (1961)
Cinnamaldehyde (3-phenyl-2-propenal)
104-55-2
1.1
Masood et al. (1976)
Citric acid
77-92-9
1.6
Bennett and Yuill (1935)
Dibromoacetonitrile
3252-43-5
2.37
Wilt (1956)
Diethylene glycol
111-46-6
1.12
Chasib (2013)
Diethylenetriamine
111-40-0
0.95
Dubev and Kumar (2011)
Dodecane
112-40-3
0.75
Baragi et al. (2013)
Ethanol
64-17-5
0.79
Kiselev et al. (2012)
Ethanolamine
141-43-5
1.01
Blanco et al. (2013)
C-33

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Density (g/mL)
Reference
Ethyl acetate
141-78-6
0.89
Laavi et al. (2013)
Ethylene glycol
107-21-1
1.1
Rodnikova et al. (2012)
Ferric chloride
7705-08-0
2.9
Havnes (2014)
Formalin
50-00-0
1.08
Alfa Aesar (2015)
Formic acid
64-18-6
1.22
Casanova et al. (1981)
Fumaric acid
110-17-8
1.64
Huffman and Fox (1938)
Gluta raldehyde
111-30-8
1
Oka (1962)
Glycerin, natural
56-81-5
1.26
Egorov et al. (2013)
Glycolic acid
79-14-1
1.49
Piiper (1971)
Hydrochloric acid
7647-01-0
1
Steinhauser et al. (1990)
Isopropanol
67-63-0
0.78
Zhang et al. (2013)
Isopropylamine
75-31-0
0.68
Sarkar and Rov (2009)
Magnesium chloride
7786-30-3
2.32
Havnes (2014)
Methanol
67-56-1
0.79
Kiselev et al. (2012)
Methenamine
100-97-0
1.2
Mak (1965)
Methoxyacetic acid
625-45-6
1.18
Havnes (2014)
N,N-Dimethylformamide
68-12-2
0.94
Smirnovand Badelin (2013)
Naphthalene
91-20-3
0.81
Dvshin et al. (2008)
Nitrogen, liquid
7727-37-9
0.82
finemech (2012)
Ozone
10028-15-6
0.002144
Havnes (2014)
Peracetic acid
79-21-0
1.1
Sigma-Aldrich (2015b)
Phosphonic acid
13598-36-2
1.7
Sigma-Aldrich (2014a)
Phosphoric acid Divosan X-Tend formulation
7664-38-2
0.94
Fadeeva et al. (2004)
Potassium acetate
127-08-2
1.54
Havnes (2014)
Propargyl alcohol
107-19-7
0.95
Viiava Kumar et al. (1996)
Saline
7647-14-5
2.17
Sigma-Aldrich (2010)
Saturated sucrose
57-50-1
1.13
Hagen and Kaatze (2004)
Silica, amorphous
7631-86-9
2.2
Fuiino et al. (2004)
Sodium carbonate
497-19-8
2.54
Havnes (2014)
Sodium formate
141-53-7
1.97
Fuess et al. (1982)
Sodium hydroxide
1310-73-2
2.13
Havnes (2014)
Sulfur dioxide
7446-09-5
1.3
Sigma-Aldrich (2015c)
Sulfuric acid
7664-93-9
1.83
Sigma-Aldrich (2015d)
C-34

-------
Appendix C - Chemical Mixing Supplemental Information
Name
CASRN
Density (g/mL)
Reference
tert-Butyl hydroperoxide (70% solution in
water)
75-91-2
0.9
Sigma-Aldrich (2007)
Tetramethylammonium chloride
75-57-0
1.17
Havnes (2014)
Thioglycolic acid
68-11-1
1.33
Biilmann (1906)
Toluene
108-88-3
0.86
Martinez-Reina et al. (2012)
Tridecane
629-50-5
0.75
Zhang et al. (2011)
Triethanolamine
102-71-6
1.12
Blanco et al. (2013)
Triethyl phosphate
78-40-0
1.06
Krakowiak et al. (2001)
Triethylene glycol
112-27-6
1.12
Afzal et al. (2009)
Triisopropanolamine
122-20-3
1.02
IUPAC (2014)
Trimethyl borate
121-43-7
0.93
Sigma-Aldrich (2015e)
Undecane
1120-21-4
0.74
de Oliveira et al. (2011)
C-35

-------
Appendix C - Chemical Mixing Supplemental Information
C.4. Estimating Spill Rates Based on State Spill Report Data
Several studies have provided estimates for the frequency of hydraulic fracturing-related spills.
This section compiles analyses for three states: Pennsylvania, Colorado, and North Dakota (Table
C-8).
In Pennsylvania, spills related to hydraulic fracturing activity are estimated to occur at a rate
between 0.4 to 12.2 reported spills per 100 wells installed in the Marcellus Shale. Three studies
(Rahm etal., 2015; Brantley et al., 2014; Gradient, 2013") calculated a spill rate for the Marcellus
Shale in Pennsylvania using reports from the Pennsylvania Department of Environmental
Protection (PA DEP) Oil and Gas Compliance Report Database. The PA DEP database provides a
searchable format based on Notices of Violations from routine inspections or investigations of spill
reports or complaints. Each study had different criteria for inclusion, presented in Table C-8,
resulting in a range of rates even when using the same data source. Spill estimates include different
criteria for how the rates were calculated. All three of these sources consider spills that occur
during hydraulic fracturing activity. These include produced water, hydraulic fracturing chemicals,
and diesel. Brantley etal. (2014") present data for major spills (> 400 gal or 1,514 L) that reached a
water body, which would be a low-end estimate of the total number of spills occuring on site.
In Colorado, there is an estimated average of 1.3 reported spills on or near the well pad for every
100 hydraulically fractured wells, based on spill reports from the Colorado Oil and Gas
Conservation Commission (COGCC) Information System. In its study of spills related to hydraulic
fracturing, the EPA determined that Colorado spill reports were the most detailed spill reports from
among the nine state data sources investigated and generally provided more of the information
needed to determine whether a spill was related to hydraulic fracturing (U.S. EPA. 2015j). Here, we
estimate the spill rate in Colorado by dividing the number of hydraulic fracturing-related spills
identified by the EPA (U.S. EPA, 2015j, Appendix B") by the number of wells hydraulically fractured
in Colorado for specific time periods between January 2006 and April 2012. We used three data
sources to estimate the number of wells: (1) there were 172 reported spills in Colorado for the
15,000 wells fractured from January 2006 to April 2012 (Drillinglnfo. 2012). (2) there were 50
reported spills in Colorado for the 3,559 wells fractured from January 2011 to April 2012 (U.S. EPA,
2015c). and (3) there were 41 reported spills in Colorado for the 3,000 wells fractured from
September 2009 to October 2010 (U.S. EPA. 2013a). These data give an estimated average of 1.3
reported spills on or near the well pad for every 100 hydraulically fractured wells (Table C-8).
In North Dakota, using the North Dakota spills database, there were an estimated 2.6 reported
spills of hydraulic fracturing fluids and chemicals per 100 wells fractured in 2015 (North Dakota
Department of Health. 2015: see Appendix E). There were 22 reported spills of injection fluid and
17 spills of injection chemical. In 2015, there were 1490 wells fractured (North Dakota Department
of Mineral Resources. 2016). Due to including only spills of fluids and chemicals, this estimate may
fall on the low side.
The spill rates presented in Table C-8 are based on spill reports found in three state data sources
and are limited by both the spills reported in the state data sources and the inclusion criteria
defined by each of the studies. Spills identified from state data sources are likely a subset of the
total number of spills that occurred within a state for a specified time period. Some spills may not
C-36

-------
Appendix C - Chemical Mixing Supplemental Information
be recorded in state data sources, because they do not meet the spill reporting requirements in
place at the time of the spill. Additionally, the PA DEP Notices of Violation may include spills not
specifically related to hydraulic fracturing, such as spills of drilling fluids.
The inclusion criteria used by each of the studies affects which spills are used to calculate a spill
rate. More restrictive criteria, such as only counting spills that were greater than 400 gal (1,514 L),
results in a lower number of spills being used for estimating spill rates, while less restrictive
criteria, such as all spills from wells marked unconventional in the PA DEP database, results in a
greater number of spills being used for estimating spill rates. Rahm et al. applied the least
restrictive criteria of the four studies (i.e., spills from unconventional wells) when identifying spills,
while Brantley etal. applied more restrictive criteria (i.e., spills of > 400 gal or 1,514 L in which
spilled fluids reached a surface water body). This would contribute to the different spill rates
calculated by these two studies.
Based on previous studies and the analysis here, hydraulic fracturing-related spills rates in
Pennsylvania, Colorado, and North Dakota range from 0.4 to 12.2 reported spills per 100 wells, with
a median rate of 2.6 reported spills for every 100 wells. These numbers may not be representative
of national spill rates or rates in other regions.
Table C-8. Estimations of spill rates.
Spill rates from four different sources. Each source used different criteria to identify and include spills in their
analysis.
Spill rate3
Data source
Time period
Inclusion criteria
Information source
0.4b, 0.8°
PA DEPd
2008 - 2013
Volume spilled > 400 gal; all spills
reported to reach water body.6
Brantlev et al. (2014)

3.3f
PA DEPd
2009 - 2012
"Unconventional" well; spills with
unknown volumes not included. Includes
any spill during HF activities
Gradient (2013)
12.26, H.6h
PA DEPd
2007 - July
2013
"Unconventional" well based on
environmental violation rates.
Rahm et al. (2015)

1.3'
COGCC
Jan 2006 -
May 2012
Specifically related to hydraulic fracturing
on or near well pad
U.S. EPA (2013a)
2.6'
ND
2015
Spills reported as injection fluid (22) or
injection chemical (17)
North Dakota Department
of Health (2015)
Median Spill Rate: 2.6 reported spills per 100 wells
a Spill rate is the number of reported spills per 100 wells.
b Spill rate is calculated as the number of spills per 100 wells spudded.
c Spill rate is calculated as number of spills per 100 wells completed.
d PA DEP (2016).
e 32 spills >400 gal: 9 were brine (e.g., produced water), 7 were gel or hydraulic fracturing fluids, 5 were hydrostatic test waters
or sediments, 2 were unknown, 1 was diesel.
'Spill rate is calculated as the number of spills per 100 wells installed,
s Mean spill rate is calculated as the number of spills per 100 wells drilled.
h Median spill rate is calculated as the number of spills per 100 drilled.
' Spill rate is calculated as the number of spills per 100 wells fractured.
J COGCC (2016).
C-37

-------
Appendix C - Chemical Mixing Supplemental Information
C.5. Selected Physicochemical Properties of Organic Chemicals Used in Hydraulic Fracturing Fluids
Table C-9. Selected physicochemical properties of organic chemicals reported as used in hydraulic fracturing fluids.
Properties are provided for chemicals, where available from EPI Suite™ version 4.1 (U.S. EPA, 2012b). Selected physicochemical properties of organic chemicals
reported as used in hydraulic fracturing fluids. In the table, indicates no information is available.
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
(13Z)-N,N-bis(2-hydroxyethyl)-N-
methyldocos-13-en-l-aminium chloride
120086-58-0
4.38
-
0.3827
3.32 x 10"15
-
-
(2,3-Dihydroxypropyl)trimethyl
ammonium chloride
34004-36-9
-5.8
-
1.00 x 106
9.84 x 10"18
-
-
(E)-Crotonaldehyde
123-73-9
0.6
-
4.15 x 104
5.61 x 10"5
1.90 x 10"5
1.94 x 10"5
[Nitrilotris(methylene)]tris-phosphonic
acid pentasodium salt
2235-43-0
-5.45
-3.53
1.00 x 106
1.65 x 10"34
-
-
l-(l-Naphthylmethyl)quinolinium
chloride
65322-65-8
5.57
-
0.02454
1.16 x 10"7
-
-
l-(Alkyl* amino)-3-aminopropane
*(42%C12, 26%C18, 15%C14, 8%C16,
5%C10, 4%C8)
68155-37-3
4.74
-
23.71
6.81 x 10"8
2.39 x 10"8
-
l-(Phenylmethyl)pyridinium Et Me
derivatives, chlorides
68909-18-2
4.1
-
14.13
1.78 x 10"5
-
-
1,2,3-Trimethylbenzene
526-73-8
3.63
3.66
75.03
7.24 x 10"3
6.58 x 10"3
4.36 x 10"3
1,2,4-Trimethylbenzene
95-63-6
3.63
3.63
79.59
7.24 x 10"3
6.58 x 10"3
6.16 x 10"3
l,2-Benzisothiazolin-3-one
2634-33-5
0.64
-
2.14 x 104
6.92 x 10"9
-
-
l,2-Dibromo-2,4-dicyanobutane
35691-65-7
1.63
-
424
3.94 x 10"10
-
-
C-38

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
1,2-Dimethylbenzene
95-47-6
3.09
3.12
224.1
6.56 x 10"3
6.14 x 10"3
5.18 x 10"3
1,2-Ethanediaminium, N,N'-bis[2-[bis(2-
hydroxyethyl)methylammonio]ethyl]-
N,N'-bis(2-hydroxyethyl)-N,Nl-dimethyl-,
tetrachloride
138879-94-4
-23.19
-
1.00 x 106
2.33 x 10"35
-
-
1,2-Propylene glycol
57-55-6
-0.78
-0.92
8.11 x 105
1.74 x 10"7
1.31 x 10"10
1.29 x 10"8
1,2-Propylene oxide
75-56-9
0.37
0.03
1.29 x 105
1.60 x 10"4
1.23 x 10"4
6.96 x 10"5
1,3,5-Triazine
290-87-9
-0.2
0.12
1.03 x 105
1.21 x 10"6
-
-
l,3,5-Triazine-l,3,5(2H,4H,6H)-triethanol
4719-04-4
-4.67
-
1.00 x 106
1.08 x 10"11
-
-
1,3,5-Trimethylbenzene
108-67-8
3.63
3.42
120.3
7.24 x 10"3
6.58 x 10"3
8.77 x 10"3
1,3-Butadiene
106-99-0
2.03
1.99
792.3
7.79 x 10"2
7.05 x 10"2
7.36 x 10"2
1,3-Dichloropropene
542-75-6
2.29
2.04
1,994
2.45 x 10"2
3.22 x 10"3
3.55 x 10"3
1,4-Dioxane
123-91-1
-0.32
-0.27
2.14 x 105
5.91 x 10"6
1.12 x 10"7
4.80 x 10"6
1,6-Hexanediamine
124-09-4
0.35
-
5.34 x 105
3.21 x 10"9
7.05 x 10"10
-
1,6-Hexanediamine dihydrochloride
6055-52-3
0.35
-
5.34 x 105
3.21 x 10"9
7.05 x 10"10
-
l-[2-(2-Methoxy-l-methylethoxy)-l-
methylethoxy]-2-propanol
20324-33-8
-0.2
-
1.96 x 105
2.36 x 10"11
4.55 x 10"13
-
l-Amino-2-propanol
78-96-6
-1.19
-0.96
1.00 x 106
4.88 x 10"10
2.34 x 10"10
-
1-Benzylquinolinium chloride
15619-48-4
4.4
-
6.02
1.19 x 10"6
-
-
1-Butanol
71-36-3
0.84
0.88
7.67 x 104
9.99 x 10"6
9.74 x 10"6
8.81 x 10"6
l-Butoxy-2-propanol
5131-66-8
0.98
-
4.21 x 104
1.30 x 10"7
4.88 x 10"8
-
C-39

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
l-Decanol
112-30-1
3.79
4.57
28.21
5.47 x 10"5
7.73 x 10"5
3.20 x 10"5
l-Dodecyl-2-pyrrolidinone
2687-96-9
5.3
4.2
5.862
7.12 x 10"7
-
-
1-Eicosene
3452-07-1
10.03
-
1.26 x 10"5
1.89 x 101
6.74 x 101
-
l-Ethyl-2-methylbenzene
611-14-3
3.58
3.53
96.88
8.71 x 10"3
9.52 x 10"3
5.53 x 10"3
1-Hexadecene
629-73-2
8.06
-
0.001232
6.10
1.69 x 101
-
1-Hexanol
111-27-3
1.82
2.03
6,885
1.76 x 10"5
1.94 x 10"5
1.71 x 10"5
l-Methoxy-2-propanol
107-98-2
-0.49
-
1.00 x 106
5.56 x 10"8
1.81 x 10"8
9.20 x 10"7
1-Octadecanamine, acetate (1:1)
2190-04-7
7.71
-
0.04875
9.36 x 10"4
2.18 x 10"3
-
1-Octadecanamine, N,N-dimethyl-
124-28-7
8.39
-
0.008882
4.51 x 10"3
3.88 x 10"2
-
1-Octadecene
112-88-9
9.04
-
1.256x 10"4
10.7
3.38 x 101
-
1-Octanol
111-87-5
2.81
3
814
3.10 x 10"5
3.88 x 10"5
2.45 x 10"5
1-Pentanol
71-41-0
1.33
1.51
2.09 x 104
1.33 x 10"5
1.38 x 10"5
1.30 x 10"5
1-Propanaminium, 3-chloro-2-hydroxy-
N,N,N-trimethyl-, chloride
3327-22-8
-4.48
-
1.00 x 106
9.48 x 10"17
-
-
1-Propanesulfonic acid
5284-66-2
-1.4
-
1.00 x 106
2.22 x 10"8
-
-
1-Propanol
71-23-8
0.35
0.25
2.72 x 105
7.52 x 10"6
6.89 x 10"6
7.41 x 10"6
1-Propene
115-07-1
1.68
1.77
1,162
1.53 x 10"1
1.58 x 10"1
1.96 x 10"1
l-tert-Butoxy-2-propanol
57018-52-7
0.87
-
5.24 x 104
1.30 x 10"7
5.23 x 10"8
-
1-Tetradecene
1120-36-1
7.08
-
0.01191
3.46
8.48
-
C-40

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
l-Tridecanol
112-70-9
5.26
-
4.533
1.28 x 10"4
2.18 x 10"4
-
1-Undecanol
112-42-5
4.28
-
43.04
7.26 x 10"5
1.09 x 10"4
-
2-(2-Butoxyethoxy)ethanol
112-34-5
0.29
0.56
7.19 x 104
1.52 x 10"9
4.45 x 10"11
7.20 x 10"9
2-(2-Ethoxyethoxy)ethanol
111-90-0
-0.69
-0.54
8.28 x 105
8.63 x 10"10
2.23 x 10"11
2.23 x 10"8
2-(2-Ethoxyethoxy)ethyl acetate
112-15-2
0.32
-
3.09 x 104
5.62 x 10"8
7.22 x 10"10
2.29 x 10"8
2-(Dibutylamino)ethanol
102-81-8
2.01
2.65
3,297
9.70 x 10"9
1.02 x 10"8
-
2-(Hydroxymethylamino)ethanol
34375-28-5
-1.53
-
1.00 x 106
1.62 x 10"12
-
-
2-(Thiocyanomethylthio)benzothiazole
21564-17-0
3.12
3.3
41.67
6.49 x 10"12
-
-
2,2'-(Diazene-l,2-diyldiethane-l,l-
diyl)bis-4,5-dihydro-lH-imidazole
dihydrochloride
27776-21-2
2.12
-
193.3
3.11 x 10"14
-
-
2,2'-(Octadecylimino)diethanol
10213-78-2
6.85
-
0.08076
1.06 x 10"8
7.39 x 10"12
-
2,2'-[Ethane-l,2-
diylbis(oxy)]diethanamine
929-59-9
-2.17
-
1.00 x 106
2.50 x 10"13
8.10 x 10"16
-
2,2'-Azobis(2-amidinopropane)
dihydrochloride
2997-92-4
-3.28
-
1.00 x 106
1.21 x 10"14
-
-
2,2-Dibromo-3-nitrilopropionamide
10222-01-2
1.01
0.82
2,841
6.16 x 10"14
-
1.91 x 10"8
2,2-Dibromopropanediamide
73003-80-2
0.37
-
1.00 x 104
3.58 x 10"14
-
-
2,4-Hexadienoic acid, potassium salt,
(2E,4E)-
24634-61-5
1.62
1.33
1.94 x 104
5.72 x 10"7
4.99 x 10"8
-
2,6,8-Trimethyl-4-nonanol
123-17-1
4.48
-
24.97
9.63 x 10"5
4.45 x 10"4
-
C-41

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
2-Acrylamido-2-methyl-l-propanesulfonic
acid
15214-89-8
-2.19
-
1.00 X 106
5.18 x 10"15
-
-
2-Amino-2-methylpropan-l-ol
124-68-5
-0.74
-
1.00 X 106
6.48 x 10"10
-
-
2-Aminoethanol hydrochloride
2002-24-6
-1.61
-1.31
1.00 x 106
3.68 x 10"10
9.96 x 10"11
-
2-Bromo-3-nitrilopropionamide
1113-55-9
-0.31
-
3,274
5.35 x 10"13
-
-
2-Butanone oxime
96-29-7
1.69
0.63
3.66 x 104
1.04 x 10"5
-
-
2-Butoxy-l-propanol
15821-83-7
0.98
-
4.21 x 104
1.30 x 10"7
4.88 x 10"8
-
2-Butoxyethanol
111-76-2
0.57
0.83
6.45 x 104
9.79 x 10"8
2.08 x 10"8
1.60 x 10"6
2-Dodecylbenzenesulfonic acid- N-(2-
aminoethyl)ethane-l,2-diamine(l:l)
40139-72-8
4.78
-
0.7032
6.27 x 10"8
-
-
2-Ethoxyethanol
110-80-5
-0.42
-0.32
7.55 x 105
5.56 x 10"8
1.04 x 10"8
4.70 x 10"7
2-Ethoxynaphthalene
93-18-5
3.74
-
38.32
4.13 x 10"5
4.06 x 10"4
-
2-Ethyl-l-hexanol
104-76-7
2.73
-
1,379
3.10 x 10"5
4.66 x 10"5
2.65 x 10"5
2-Ethyl-2-hexenal
645-62-5
2.62
-
548.6
2.06 x 10"4
4.88 x 10"4
-
2-Ethylhexyl benzoate
5444-75-7
5.19
-
1.061
2.52 x 10"4
2.34 x 10"4
-
2-Hydroxyethyl acrylate
818-61-1
-0.25
-0.21
5.07 x 105
4.49 x 10"9
7.22 x 10"10
-
2-Hydroxyethylammonium hydrogen
sulphite
13427-63-9
-1.61
-1.31
1.00 x 106
3.68 x 10"10
9.96 x 10"11
-
2-Hydroxy-N,N-bis(2-hydroxyethyl)-N-
methylethanaminium chloride
7006-59-9
-6.7
-
1.00 x 106
4.78 x 10"19
-
-
2-Mercaptoethanol
60-24-2
-0.2
-
1.94 x 105
1.27 x 10"7
3.38 x 10"8
1.80 x 10"7
C-42

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
2-Methoxyethanol
109-86-4
-0.91
-0.77
1.00 X 106
4.19 x 10"8
7.73 x 10"9
3.30 x 10"7
2-Methyl-l-propanol
78-83-1
0.77
0.76
9.71 x 104
9.99 x 10"6
1.17 x 10"5
9.78 x 10"6
2-Methyl-2,4-pentanediol
107-41-5
0.58
-
3.26 x 104
4.06 x 10"7
3.97 x 10"10
-
2-Methyl-3(2H)-isothiazolone
2682-20-4
-0.83
-
5.37 x 105
4.96 x 10"8
-
-
2-Methyl-3-butyn-2-ol
115-19-5
0.45
0.28
2.40 x 105
1.04 x 10"6
-
3.91 x 10"6
2-Methylbutane
78-78-4
2.72
-
184.6
1.29
1.44
1.40
2-Methylquinoline hydrochloride
62763-89-7
2.69
2.59
498.5
7.60 x 10"7
2.13 x 10"6
-
2-Phosphono-l,2,4-butanetricarboxylic
acid
37971-36-1
-1.66
-
1.00 x 106
1.17 x 10"26
-
-
2-Phosphonobutane-l,2,4-tricarboxylic
acid, potassium salt (l:x)
93858-78-7
-1.66
-
1.00 x 106
1.17 x 10"26
-
-
2-Propenoic acid, 2-(2-
hydroxyethoxy)ethyl ester
13533-05-6
-0.52
-0.3
3.99 x 105
6.98 x 10"11
1.54 x 10"12
-
3-(Dimethylamino)propylamine
109-55-7
-0.45
-
1.00 x 106
6.62 x 10"9
4.45 x 10"9
-
3,4,4-Trimethyloxazolidine
75673-43-7
0.13
-
8.22 x 105
6.63 x 10"6
-
-
3,5,7-Triazatricyclo(3.3.1.13,7))decane, 1-
(3-chloro-2-propenyl)-, chloride, (Z)-
51229-78-8
-5.92
-
1.00 x 106
1.76 x 10"8
-
-
3,7-Dimethyl-2,6-octadienal
5392-40-5
3.45
-
84.71
3.76 x 10"4
4.35 x 10"5
-
3-Hydroxybutanal
107-89-1
-0.72
-
1.00 x 106
4.37 x 10"9
2.28 x 10"9
-
3-Methoxypropylamine
5332-73-0
-0.42
-
1.00 x 106
1.56 x 10"7
1.94 x 10"8
-
3-Phenylprop-2-enal
104-55-2
1.82
1.9
2,150
1.60 x 10"6
3.38 x 10"7
-
C-43

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
4,4-Dimethyloxazolidine
51200-87-4
-0.08
-
1.00 X 106
3.02 x 10"6
-
-
4,6-Dimethyl-2-heptanone
19549-80-5
2.56
-
528.8
2.71 x 10"4
4.55 x 10"4
-
4-[Abieta-8,ll,13-trien-18-yl(3-oxo-3-
phenylpropyl)amino]butan-2-one
hydrochloride
143106-84-7
7.72
-
0.002229
2.49 x 10"12
1.20 x 10"14
-
4-Ethyloct-l-yn-3-ol
5877-42-9
2.87
-
833.9
4.27 x 10"6
-
-
4-Hydroxy-3-methoxybenzaldehyde
121-33-5
1.05
1.21
6,875
8.27 x 10"11
2.81 x 10"9
2.15 x 10"9
4-Methoxybenzyl formate
122-91-8
1.61
-
2,679
1.15 x 10"6
2.13 x 10"6
-
4-Methoxyphenol
150-76-5
1.59
1.58
1.65 x 104
3.32 x 10"8
5.35 x 10"7
-
4-Methyl-2-pentanol
108-11-2
1.68
-
1.38 x 104
1.76 x 10"5
3.88 x 10"5
4.45 x 10"5
4-Methyl-2-pentanone
108-10-1
1.16
1.31
8,888
1.16 x 10"4
1.34 x 10"4
1.38 x 10"4
4-Nonylphenol
104-40-5
5.99
5.76
1.57
5.97 x 10"6
1.23 x 10"5
3.40 x 10"5
5-Chloro-2-methyl-3(2H)-isothiazolone
26172-55-4
-0.34
-
1.49 x 105
3.57 x 10"8
-
-
Acetaldehyde
75-07-0
-0.17
-0.34
2.57 x 105
6.78 x 10"5
6.00 x 10"5
6.67 x 10"5
Acetic acid
64-19-7
0.09
-0.17
4.76 x 105
5.48 x 10"7
2.94 x 10"7
1.00 x 10"7
Acetic acid, C6-8-branched alkyl esters
90438-79-2
3.25
-
117.8
9.60 x 10"4
1.07 x 10"3
-
Acetic acid, hydroxy-, reaction products
with triethanolamine
68442-62-6
-2.48
-1
1.00 x 106
4.18 x 10"12
3.38 x 10"19
7.05 x 10"13
Acetic acid, mercapto-, monoammonium
salt
5421-46-5
0.03
0.09
2.56 x 105
1.94 x 10"8
-
-
Acetic anhydride
108-24-7
-0.58
-
3.59 x 105
3.57 x 10"5
-
5.71 x 10"6
C-44

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Acetone
67-64-1
-0.24
-0.24
2.20 x 105
4.96 x 10"5
3.97 x 10"5
3.50 x 10"5
Acetonitrile, 2,2',2"-nitrilotris-
7327-60-8
-1.39
-
1.00 x 106
2.61 x 10"15
-
-
Acetophenone
98-86-2
1.67
1.58
4,484
9.81 x 10"6
1.09 x 10"5
1.04 x 10"5
Acetyltriethyl citrate
77-89-4
1.34
-
688.2
6.91 x 10"11
-
-
Acrolein
107-02-8
0.19
-0.01
1.40 x 105
3.58 x 10"5
1.94 x 10"5
1.22 x 10"4
Acrylamide
79-06-1
-0.81
-0.67
5.04 x 105
5.90 x 10"9
-
1.70 x 10"9
Acrylic acid
79-10-7
0.44
0.35
1.68 x 105
2.89 x 10"7
1.17 x 10"7
3.70 x 10"7
Acrylic acid, with sodium-2-acrylamido-2-
methyl-l-propanesulfonate and sodium
phosphinate
110224-99-2
-2.19
-
1.00 x 106
5.18 x 10"15
-
-
Alcohols, CIO-12, ethoxylated
67254-71-1
5.47
-
0.9301
1.95 x 10"2
2.03 x 10"2
-
Alcohols, Cll-14-iso-, C13-rich
68526-86-3
5.19
-
5.237
1.28 x 10"4
2.62 x 10"4
-
Alcohols, Cll-14-iso-, C13-rich,
ethoxylated
78330-21-9
4.91
-
5.237
1.25 x 10"6
7.73 x 10"7
-
Alcohols, C12-13, ethoxylated
66455-14-9
5.96
-
0.2995
2.58 x 10"2
2.87 x 10"2
-
Alcohols, C12-14, ethoxylated
propoxylated
68439-51-0
6.67
-
0.02971
7.08 x 10"4
1.23 x 10"4
-
Alcohols, C12-14-secondary
126950-60-5
5.19
-
5.237
1.28 x 10"4
3.62 x 10"4
-
Alcohols, C12-16, ethoxylated
68551-12-2
6.45
-
0.09603
3.43 x 10"2
4.06 x 10"2
-
Alcohols, C14-15, ethoxylated
68951-67-7
7.43
-
0.009765
6.04 x 10"2
8.10 x 10"2
-
Alcohols, C6-12, ethoxylated
68439-45-2
4.49
-
8.832
1.10 x 10"2
1.02 x 10"2
-
C-45

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Alcohols, C7-9-iso-, C8-rich, ethoxylated
78330-19-5
2.46
-
1,513
3.04 x 10"7
1.38 x 10"7
-
Alcohols, C9-11, ethoxylated
68439-46-3
4.98
-
2.874
1.47 x 10"2
1.44 x 10"2
-
Alcohols, C9-ll-iso-, ClO-rich,
ethoxylated
78330-20-8
4.9
-
3.321
1.47 x 10"2
2.39 x 10"2
-
Alkanes, C12-14-iso-
68551-19-9
6.65
-
0.03173
1.24 x 101
2.28 x 101
-
Alkanes, C13-16-iso-
68551-20-2
7.63
-
0.003311
2.19 x 101
4.55 x 101
-
Alkenes, C>10 alpha-
64743-02-8
8.55
-
0.0003941
8.09
2.39 x 101
-
Alkyl* dimethyl ethylbenzyl ammonium
chloride *(50%C12, 30%C14,17%C16,
3%C18)
85409-23-0_l
3.97
-
3.23
1.11 x 10"11
-
-
Alkyl* dimethyl ethylbenzyl ammonium
chloride *(60%C14, 30%C16, 5%C12,
5%C18)
68956-79-6
4.95
-
0.3172
1.96 x 10"11
-
-
Alkylbenzenesulfonate, linear
42615-29-2
4.71
-
0.8126
6.27 x 10"8
-
-
alpha-Lactose monohydrate
5989-81-1
-5.12
-
1.00 x 106
4.47 x 10"22
9.81 x 10"45
-
alpha-Terpineol
98-55-5
3.33
2.98
371.7
1.58 x 10"5
3.15 x 10"6
1.22 x 10"5
Amaranth
915-67-3
1.63
-
1.789
1.49 x 10"30
-
-
Aminotrimethylene phosphonic acid
6419-19-8
-5.45
-3.53
1.00 x 106
1.65 x 10"34
-
-
Ammonium acetate
631-61-8
0.09
-0.17
4.76 x 105
5.48 x 10"7
2.94 x 10"7
1.00 X 10"7
Ammonium acrylate
10604-69-0
0.44
0.35
1.68 x 105
2.89 x 10"7
1.17 x 10"7
3.70 x 10"7
Ammonium citrate (1:1)
7632-50-0
-1.67
-1.64
1.00 x 106
8.33 x 10"18
-
4.33 x 10"14
C-46

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Ammonium citrate (2:1)
3012-65-5
-1.67
-1.64
1.00 X 106
8.33 x 10"18
-
4.33 x 10"14
Ammonium dodecyl sulfate
2235-54-3
2.42
-
163.7
1.84 x 10"7
-
-
Ammonium hydrogen carbonate
1066-33-7
-0.46
-
8.42 x 105
6.05 x 10"9
-
-
Ammonium lactate
515-98-0
-0.65
-0.72
1.00 x 106
1.13 x 10"7
-
8.13 x 10"8
Anethole
104-46-1
3.39
-
98.68
2.56 x 10"4
2.23 x 10"3
-
Aniline
62-53-3
1.08
0.9
2.08 x 104
1.90 x 10"6
2.18 x 10"6
2.02 x 10"6
Benactyzine hydrochloride
57-37-4
2.89
-
292.1
2.07 x 10"10
-
-
Benzamorf
12068-08-5
4.71
-
0.8126
6.27 x 10"8
-
-
Benzene
71-43-2
1.99
2.13
2,000
5.39 x 10"3
5.35 x 10"3
5.55 x 10"3
Benzene, C10-16-alkyl derivatives
68648-87-3
8.43
9.36
0.0002099
1.78 x 10"1
3.97 x 10"1
-
Benzenesulfonic acid
98-11-3
-1.17
-
6.90 x 105
2.52 x 10"9
-
-
Benzenesulfonic acid, (1-methylethyl)-,
37953-05-2
0.29
-
2.46 x 104
4.89 x 10"9
-
-
Benzenesulfonic acid, (1-methylethyl)-,
ammonium salt
37475-88-0
0.29
-
2.46 x 104
4.89 x 10"9
-
-
Benzenesulfonic acid, (1-methylethyl)-,
sodium salt
28348-53-0
0.29
-
2.46 x 104
4.89 x 10"9
-
-
Benzenesulfonic acid, C10-16-alkyl
derivatives, compounds with
cyclohexylamine
255043-08-4
4.71
-
0.8126
6.27 x 10"8
-
-
C-47

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Benzenesulfonic acid, C10-16-alkyl
derivatives, compounds with
triethanolamine
68584-25-8
5.2
-
0.255
8.32 x 10"8
-
-
Benzenesulfonic acid, C10-16-alkyl
derivatives, potassium salts
68584-27-0
5.2
-
0.255
8.32 x 10"8
-
-
Benzenesulfonic acid, dodecyl-, branched,
compounds with 2-propanamine
90218-35-2
4.49
-
1.254
6.27 x 10"8
-
-
Benzenesulfonic acid, mono-C10-16-alkyl
derivatives, sodium salts
68081-81-2
4.22
-
2.584
4.72 x 10"8
-
-
Benzoic acid
65-85-0
1.87
1.87
2,493
1.08 x 10"7
4.55 x 10"8
3.81 x 10"8
Benzyl chloride
100-44-7
2.79
2.3
1,030
2.09 x 10"3
3.97 x 10"4
4.12 x 10"4
Benzyldimethyldodecylammonium
chloride
139-07-1
2.93
-
36.47
7.61 x 10"12
-
-
Benzylhexadecyldimethylammonium
chloride
122-18-9
4.89
-
0.3543
2.36 x 10"11
-
-
Benzyltrimethylammonium chloride
56-93-9
-2.47
-
1.00 x 106
3.37 x 10"13
-
-
Bicine
150-25-4
-3.27
-
3.52 x 105
1.28 x 10"14
-
-
Bis(l-methylethyl)naphthalenesulfonic
acid, cyclohexylamine salt
68425-61-6
2.92
-
43.36
9.29 x 10"10
-
-
Bis(2-chloroethyl) ether
111-44-4
1.56
1.29
6,435
1.89 x 10"4
4.15 x 10"7
1.70 x 10"5
Bisphenol A
80-05-7
3.64
3.32
172.7
9.16 x 10"12
-
-
Bronopol
52-51-7
-1.51
-
8.37 x 105
6.35 x 10"21
-
-
C-48

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Butane
106-97-8
2.31
2.89
135.6
9.69 x 10"1
8.48 x 10"1
9.50 x 10"1
Butanedioic acid, sulfo-, l,4-bis(l,3-
dimethylbutyl) ester, sodium salt
2373-38-8
3.98
-
0.1733
1.61 x 10"12
-
-
Butene
25167-67-3
2.17
2.4
354.8
2.03 x 10"1
2.68 x 10"1
2.33 x 10"1
Butyl glycidyl ether
2426-08-6
1.08
0.63
2.66 x 104
4.37 x 10"6
5.23 x 10"7
2.47 x 10"5
Butyl lactate
138-22-7
0.8
-
5.30 x 104
8.49 x 10"5
-
1.92 x 10"6
Butyryl trihexyl citrate
82469-79-2
8.21
-
5.56 x 10"5
3.65 x 10"9
-
-
C.I. Acid Red 1
3734-67-6
0.51
-
6.157
3.73 x 10"29
-
-
C.I. Acid Violet 12, disodium salt
6625-46-3
0.59
-
3.379
2.21 x 10"30
-
-
C.I. Pigment Red 5
6410-41-9
7.65
-
4.38 x 10"5
4.36 x 10"21
-
-
C.I. Solvent Red 26
4477-79-6
9.27
-
5.68 x 10"5
5.48 x 10"13
4.66 x 10"13
-
CIO-16-Alkyldimethylamines oxides
70592-80-2
2.87
-
89.63
1.14 x 10"13
-
-
C10-C16 Ethoxylated alcohol
68002-97-1
4.99
-
4.532
1.25 x 10"6
4.66 x 10"7
-
C12-14 tert-Alkyl ethoxylated amines
73138-27-9
3.4
-
264.2
1.29 x 10"10
-
-
Calcium dodecylbenzene sulfonate
26264-06-2
4.71
-
0.8126
6.27 x 10"8
-
-
Camphor
76-22-2
3.04
2.38
339.1
7.00 x 10"5
-
8.10 x 10"5
Carbon dioxide
124-38-9
0.83
0.83
2.57 x 104
1.52 x 10"2
-
1.52 x 10"2
Carbonic acid, dipotassium salt
584-08-7
-0.46
-
8.42 x 105
6.05 x 10"9
-
-
Chloromethane
74-87-3
1.09
0.91
2.26x 104
8.20x 10"3
8.88x 10"3
8.82x 10"3
C-49

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Chlorobenzene
108-90-7
2.64
2.84
400.5
3.99x 10"3
4.55x 10"3
3.11x 10"3
Choline bicarbonate
78-73-9
-5.16
-
1.00 x 106
2.03 x 10"16
-
-
Choline chloride
67-48-1
-5.16
-
1.00 x 106
2.03 x 10"16
-
-
Citric acid
77-92-9
-1.67
-1.64
1.00 x 106
8.33 x 10"18
-
4.33 x 10"14
Citronellol
106-22-9
3.56
3.91
105.5
5.68 x 10"5
2.13 x 10"5
-
Coconut trimethylammonium chloride
61789-18-2
1.22
-
2,816
9.42 x 10"11
-
-
Coumarin
91-64-5
1.51
1.39
5,126
6.95 x 10"6
-
9.92 x 10"8
Cumene
98-82-8
3.45
3.66
75.03
1.05 x 10"2
1.23 x 10"2
1.15 x 10"2
Cyclohexane
110-82-7
3.18
3.44
43.02
2.55 x 10"1
1.94 x 10"1
1.50 x 10"1
Cyclohexanol
108-93-0
1.64
1.23
3.37 x 104
4.90 x 10"6
3.70 x 10"6
4.40 x 10"6
Cyclohexanone
108-94-1
1.13
0.81
2.41 x 104
5.11 x 10"5
1.28 x 10"5
9.00 x 10"6
Cyclohexylamine sulfate
19834-02-7
1.63
1.49
6.40 x 104
1.38 x 10"5
-
4.16 x 10"6
D&C Red no. 28
18472-87-2
9.62
-
1.64 x 10"8
6.37 x 10"21
-
-
D&C Red no. 33
3567-66-6
0.48
-
11.87
1.15 x 10"26
-
-
Daidzein
486-66-8
2.55
-
568.4
3.91 x 10"16
-
-
Dapsone
80-08-0
0.77
0.97
3,589
3.11 x 10"14
-
-
Dazomet
533-74-4
0.94
0.63
1.94 x 104
2.84 x 10"3
-
4.98 x 10"10
Decyldimethylamine
1120-24-7
4.46
-
82.23
4.68 x 10"4
2.45 x 10"3
-
D-Glucitol
50-70-4
-3.01
-2.2
1.00 x 106
7.26 x 10"13
2.94 x 10"29
-
C-50

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
D-Gluconic acid
526-95-4
-1.87
-
1.00 X 106
4.74 x 10"13
-
-
D-Glucopyranoside, methyl
3149-68-6
-2.5
-
1.00 X 106
1.56 x 10"14
2.23 x 10"24
-
D-Glucose
50-99-7
-2.89
-3.24
1.00 x 106
9.72 x 10"15
1.62 x 10"26
-
Di(2-ethylhexyl) phthalate
117-81-7
8.39
7.6
0.001132
1.18 x 10"5
1.02 x 10"5
2.70 x 10"7
Dibromoacetonitrile
3252-43-5
0.47
-
9,600
4.06 x 10"7
-
-
Dichloromethane
75-09-2
1.34
1.25
1.10 x 104
9.14 x 10"3
3.01 x 10"3
3.25 x 10"3
Didecyldimethylammonium chloride
7173-51-5
4.66
-
0.9
6.85 x 10"10
-
-
Diethanolamine
111-42-2
-1.71
-1.43
1.00 x 106
3.92 x 10"11
3.46 x 10"15
3.87 x 10"11
Diethylbenzene
25340-17-4
4.07
3.72
58.86
1.16 x 10"2
1.47 x 10"2
2.61 x 10"3
Diethylene glycol
111-46-6
-1.47
-
1.00 x 106
2.03 x 10"9
1.20 x 10"13
-
Diethylene glycol monomethyl ether
111-77-3
-1.18
-
1.00 x 106
6.50 x 10"10
1.65 x 10"11
-
Diethylenetriamine
111-40-0
-2.13
-
1.00 x 106
3.10 x 10"13
1.09 x 10"14
-
Diisobutyl ketone
108-83-8
2.56
-
528.8
2.71 x 10"4
4.55 x 10"4
1.17 x 10"4
Diisopropanolamine
110-97-4
-0.88
-0.82
1.00 x 106
6.91 x 10"11
1.90 x 10"14
-
Diisopropylnaphthalene
38640-62-9
6.08
-
0.2421
1.99 x 10"3
1.94 x 10"3
-
Dimethyl adipate
627-93-0
1.39
1.03
7,749
9.77 x 10"7
1.28 x 10"7
2.31 x 10"6
Dimethyl glutarate
1119-40-0
0.9
0.62
2.02 x 104
7.36 x 10"7
9.09 x 10"8
6.43 x 10"7
Dimethyl succinate
106-65-0
0.4
0.35
3.96 x 104
5.54 x 10"7
6.43 x 10"8
-
Dimethylaminoethanol
108-01-0
-0.94
-
1.00 x 106
1.77 x 10"9
1.77 x 10"9
3.73 x 10"7
C-51

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Dimethyldiallylammonium chloride
7398-69-8
-2.49
-
1.00 X 106
7.20 x 10"12
-
-
Diphenyl oxide
101-84-8
4.05
4.21
15.58
1.18 x 10"4
2.81 x 10"4
2.79 x 10"4
Dipropylene glycol
25265-71-8
-0.64
-
3.11 x 105
3.58 x 10"9
6.29 x 10"10
-
Di-sec-butylphenol
31291-60-8
5.41
-
3.723
3.74 x 10"6
6.89 x 10"6
-
Disodium
dodecyl(sulphonatophenoxy)benzenesulp
honate
28519-02-0
5.05
-
0.0353
6.40 x 10"16
-
-
Disodium ethylenediaminediacetate
38011-25-5
-4.79
-
1.00 x 106
1.10 x 10"16
-
-
Disodium ethylenediaminetetraacetate
dihydrate
6381-92-6
-3.86
-
2.28 x 105
1.17 x 10"23
-
5.77 x 10"16
D-Lactic acid
10326-41-7
-0.65
-0.72
1.00 x 106
1.13 x 10"7
-
8.13 x 10"8
D-Limonene
5989-27-5
4.83
4.57
4.581
3.80 x 10"1
-
3.19 x 10"2
Docusate sodium
577-11-7
6.1
-
0.001227
5.00 x 10"12
-
-
Dodecane
112-40-3
6.23
6.1
0.1099
9.35
1.34 x 101
8.18
Dodecylbenzene
123-01-3
7.94
8.65
0.001015
1.34 x 10"1
2.81 x 10"1
-
Dodecylbenzenesulfonic acid
27176-87-0
4.71
-
0.8126
6.27 x 10"8
-
-
Dodecylbenzenesulfonic acid,
monoethanolamine salt
26836-07-7
4.71
-
0.8126
6.27 x 10"8
-
-
Epichlorohydrin
106-89-8
0.63
0.45
5.06 x 104
5.62 x 10"5
2.62 x 10"6
3.04 x 10"5
Ethanaminium, N,N,N-trimethyl-2-[(l-
oxo-2-propenyl)oxy]-, chloride
44992-01-0
-3.1
-
1.00 x 106
6.96 x 10"15
-
-
C-52

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Ethane
74-84-0
1.32
1.81
938.6
5.50 x 10"1
4.25 x 10"1
5.00 x 10"1
Ethanol
64-17-5
-0.14
-0.31
7.92 x 105
5.67 x 10"6
4.88 x 10"6
5.00 x 10"6
Ethanol, 2,2',2"-nitrilotris-,
tris(dihydrogen phosphate) (ester),
sodium salt
68171-29-9
-3.13
-
1.00 x 106
3.08 x 10"36
-
-
Ethanol, 2-[2-[2-
(tridecyloxy)ethoxy]ethoxy]-, hydrogen
sulfate, sodium salt
25446-78-0
2.09
-
42
9.15 x 10"13
-
-
Ethanolamine
141-43-5
-1.61
-1.31
1.00 x 106
3.68 x 10"10
9.96 x 10"11
-
Ethoxylated dodecyl alcohol
9002-92-0
4.5
-
14.19
9.45 x 10"7
3.30 x 10"7
-
Ethyl acetate
141-78-6
0.86
0.73
2.99 x 104
2.33 x 10"4
1.58 x 10"4
1.34 x 10"4
Ethyl acetoacetate
141-97-9
-0.2
0.25
5.62 x 104
1.57 x 10"7
-
1.20 x 10"6
Ethyl benzoate
93-89-0
2.32
2.64
421.5
4.61 x 10"5
2.45 x 10"5
7.33 x 10"5
Ethyl lactate
97-64-3
-0.18
-
4.73 x 105
4.82 x 10"5
-
5.83 x 10"7
Ethyl salicylate
118-61-6
3.09
2.95
737.1
6.04 x 10"6
3.01 x 10"9
-
Ethylbenzene
100-41-4
3.03
3.15
228.6
7.89 x 10"3
8.88 x 10"3
7.88 x 10"3
Ethylene
74-85-1
1.27
1.13
3,449
9.78 x 10"2
1.62 x 10"1
2.28 x 10"1
Ethylene glycol
107-21-1
-1.2
-1.36
1.00 x 106
1.31 x 10"7
5.60 x 10"11
6.00 x 10"8
Ethylene oxide
75-21-8
-0.05
-0.3
2.37 x 105
1.20 x 10"4
5.23 x 10"5
1.48 x 10"4
Ethylenediamine
107-15-3
-1.62
-2.04
1.00 x 106
1.03 x 10"9
1.77 x 10"10
1.73 x 10"9
Ethylenediaminetetraacetic acid
60-00-4
-3.86
-
2.28 x 105
1.17 x 10"23
-
5.77 x 10"16
C-53

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Ethylenediaminetetraacetic acid
tetrasodium salt
64-02-8
-3.86
-
2.28 x 105
1.17 x 10"23
-
5.77 x 10"16
Ethylenediaminetetraacetic acid,
disodium salt
139-33-3
-3.86
-
2.28 x 105
1.17 x 10"23
-
5.77 x 10"16
Ethyne
74-86-2
0.5
0.37
1.48 x 104
2.40 x 10"2
2.45 x 10"2
2.17 x 10"2
Fatty acids, C18-unsaturated, dimers
61788-89-4
14.6
-
2.31 x 10"10
4.12 x 10"8
9.74 x 10"9
-
FD&C Blue no. 1
3844-45-9
-0.15
-
0.2205
2.25 x 10"35
-
-
FD&C Yellow no. 5
1934-21-0
-1.82
-
7.388
1.31 x 10"28
-
-
FD&C Yellow no. 6
2783-94-0
1.4
-
242.7
3.26 x 10"23
-
-
Formaldehyde
50-00-0
0.35
0.35
5.70 x 104
9.29 x 10"5
6.14 x 10"5
3.37 x 10"7
Formamide
75-12-7
-1.61
-1.51
1.00 x 106
1.53 x 10"8
-
1.39 x 10"9
Formic acid
64-18-6
-0.46
-0.54
9.55 x 105
7.50 x 10"7
5.11 x 10"7
1.67 x 10"7
Formic acid, potassium salt
590-29-4
-0.46
-0.54
9.55 x 105
7.50 x 10"7
5.11 x 10"7
1.67 x 10"7
Fumaric acid
110-17-8
0.05
-0.48
1.04 x 105
1.35 x 10"12
8.48 x 10"14
-
Furfural
98-01-1
0.83
0.41
5.36 x 104
1.34 x 10"5
-
3.77 x 10"6
Furfuryl alcohol
98-00-0
0.45
0.28
2.21 x 105
2.17 x 10"7
-
7.86 x 10"8
Galantamine hydrobromide
69353-21-5
2.29
-
1,606
1.70 x 10"13
-
-
Gluconic acid
133-42-6
-1.87
-
1.00 x 106
4.74 x 10"13
-
-
Glutaraldehyde
111-30-8
-0.18
-
1.67 x 105
1.10 x 10"7
2.39 x 10"8
-
Glycerol
56-81-5
-1.65
-1.76
1.00 x 106
6.35 x 10"9
1.51 x 10"15
1.73 x 10"8
C-54

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Glycine, N-(carboxymethyl)-N-(2-
hydroxyethyl)-, disodium salt
135-37-5
-3.04
-
1.90 x 105
3.90 x 10"17
-
-
Glycine, N-(hydroxymethyl)-,
monosodium salt
70161-44-3
-3.41
-
7.82 x 105
1.80 x 10"12
-
-
Glycine, N,N-bis(carboxymethyl)-,
trisodium salt
5064-31-3
-3.81
-
7.39 x 105
1.19 x 10"16
-
-
Glycine, N-[2-
[bis(carboxymethyl)amino]ethyl]-N-(2-
hydroxyethyl)-, trisodium salt
139-89-9
-4.09
-
4.31 x 105
3.81 x 10"24
-
-
Glycolic acid
79-14-1
-1.07
-l.ii
1.00 x 106
8.54 x 10"8
6.29 x 10"11
-
Glycolic acid sodium salt
2836-32-0
-1.07
-l.ii
1.00 x 106
8.54 x 10"8
6.29 x 10"11
-
Glyoxal
107-22-2
-1.66
-
1.00 x 106
3.70 x 10"7
-
3.33 x 10"9
Glyoxylic acid
298-12-4
-1.4
-
1.00 x 106
2.98 x 10"9
-
-
Heptane
142-82-5
3.78
4.66
3.554
2.27
2.39
2.00
Hexadecyltrimethylammonium bromide
57-09-0
3.18
-
28.77
2.93 x 10"10
-
-
Hexane
110-54-3
3.29
3.9
17.24
1.71
1.69
1.80
Hexanedioic acid
124-04-9
0.23
0.08
1.67 x 105
9.53 x 10"12
8.10 x 10"13
4.71 x 10"12
Hydroxyvalerenic acid
1619-16-5
3.31
-
282.1
-
-
-
Indole
120-72-9
2.05
2.14
1,529
8.86 x 10"7
1.99 x 10"6
5.28 x 10"7
Isoascorbic acid
89-65-6
-1.88
-1.85
1.00 x 106
4.07 x 10"8
-
-
Isobutane
75-28-5
2.23
2.76
175.1
9.69 x 10"1
1.02
1.19
C-55

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Isobutene
115-11-7
2.23
2.34
399.2
2.40 x 10"1
2.34 x 10"1
2.18 x 10"1
Isooctanol
26952-21-6
2.73
-
1,379
3.10 x 10"5
4.66 x 10"5
9.21 x 10"5
Isopentyl alcohol
123-51-3
1.26
1.16
4.16 x 104
1.33 x 10"5
1.65 x 10"5
1.41 x 10"5
Isopropanol
67-63-0
0.28
0.05
4.02 x 105
7.52 x 10"6
1.14 x 10"5
8.10 x 10"6
Isopropanolamine dodecylbenzene
42504-46-1
7.94
8.65
0.001015
1.34 x 10"1
2.81 x 10"1
-
Isopropylamine
75-31-0
0.27
0.26
8.38 x 105
1.34 x 10"5
-
4.51 x 10"5
Isoquinoline
119-65-3
2.14
2.08
1,551
6.88 x 10"7
4.15 x 10"7
-
Isoquinoline, reaction products with
benzyl chloride and quinoline
68909-80-8
2.14
2.08
1,551
6.88 x 10"7
4.15 x 10"7
-
Isoquinolinium, 2-(phenylmethyl)-,
chloride
35674-56-7
4.4
-
6.02
1.19 x 10"6
-
-
Lactic acid
50-21-5
-0.65
-0.72
1.00 x 106
1.13 x 10"7
-
8.13 x 10"8
Lactose
63-42-3
-5.12
-
1.00 x 106
4.47 x 10"22
9.81 x 10"45
-
Lauryl hydroxysultaine
13197-76-7
-1.3
-
7.71 x 104
1.04 x 10"21
-
-
L-Dilactide
4511-42-6
1.65
-
3,165
1.22 x 10"5
-
-
L-Glutamic acid
56-86-0
-3.83
-3.69
9.42 x 105
1.47 x 10"14
-
-
L-Lactic acid
79-33-4
-0.65
-0.72
1.00 x 106
1.13 x 10"7
-
8.13 x 10"8
Methane
74-82-8
0.78
1.09
2,610
4.14 x 10"1
6.58 x 10"1
6.58 x 10"1
Methanol
67-56-1
-0.63
-0.77
1.00 x 106
4.27 x 10"6
3.62 x 10"6
4.55 x 10"6
Methenamine
100-97-0
-4.15
-
1.00 x 106
1.63 x 10"1
-
1.64 x 10"9
C-56

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Methoxyacetic acid
625-45-6
-0.68
-
1.00 X 106
4.54 x 10"8
8.68 x 10"9
6.42 x 10"9
Methyl salicylate
119-36-8
2.6
2.55
1,875
4.55 x 10"6
2.23 x 10"9
9.81 x 10"5
Methyl vinyl ketone
78-94-4
0.41
-
6.06 x 104
2.61 x 10"5
1.38 x 10"5
4.65 x 10"5
Methylcyclohexane
108-87-2
3.59
3.61
28.4
3.39 x 10"1
3.30 x 10"1
4.30 x 10"1
Methylene bis(thiocyanate)
6317-18-6
0.62
-
2.72 x 104
2.61 x 10"8
-
-
Methylenebis(5-methyloxazolidine)
66204-44-2
-0.58
-
1.00 x 106
1.07 x 10"7
-
-
Morpholine
110-91-8
-0.56
-0.86
1.00 x 106
1.14 x 10"7
3.22 x 10"9
1.16 x 10"6
Morpholinium, 4-ethyl-4-hexadecyl-,
ethyl sulfate
78-21-7
4.54
-
0.9381
2.66 x 10"12
-
-
N-(2-Acryloyloxyethyl)-N-benzyl-N,N-
dimethylammonium chloride
46830-22-2
-1.39
-
4.42 x 105
5.62 x 10"16
-
-
N-(3-Chloroallyl)hexaminium chloride
4080-31-3
-5.92
-
1.00 x 106
1.76 x 10"8
-
-
N,N,N-Trimethyl-3-((l-
oxooctadecyl)amino)-l-propanaminium
methyl sulfate
19277-88-4
4.38
-
0.7028
2.28 x 10"16
-
-
N,N,N-Trimethyloctadecan-l-aminium
chloride
112-03-8
4.17
-
2.862
5.16 x 10"10
-
-
N,N'-Dibutylthiourea
109-46-6
2.57
2.75
2,287
4.17 x 10"6
-
-
N,N-Dimethyldecylamine oxide
2605-79-0
1.4
-
2,722
4.88 x 10"14
-
-
N,N-Dimethylformamide
68-12-2
-0.93
-1.01
9.78 x 105
7.38 x 10"8
-
7.39 x 10"8
C-57

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
N,N-Dimethylmethanamine
hydrochloride
593-81-7
0.04
0.16
1.00 X 106
3.65 x 10"5
1.28 x 10"4
1.04 x 10"4
N,N-Dimethyl-methanamine-N-oxide
1184-78-7
-3.02
-
1.00 X 106
3.81 x 10"15
-
-
N,N-dimethyloctadecylamine
hydrochloride
1613-17-8
8.39
-
0.008882
4.51 x 10"3
3.88 x 10"2
-
N,N'-Methylenebisacrylamide
110-26-9
-1.52
-
7.01 x 104
1.14 x 10"9
-
-
Naphthalene
91-20-3
3.17
3.3
142.1
5.26 x 10"4
3.70 x 10"4
4.40 x 10"4
Naphthalenesulfonic acid, bis(l-
methylethyl)-
28757-00-8
2.92
-
43.36
9.29 x 10"10
-
-
Naphthalenesulphonic acid, bis (1-
methylethyl)-methyl derivatives
99811-86-6
4.02
-
3.45
1.13 x 10"9
-
-
Naphthenic acid ethoxylate
68410-62-8
3.41
-
112.5
3.62 x 10"8
2.74 x 10"9
-
Nitrilotriacetamide
4862-18-4
-4.75
-
1.00 x 106
1.61 x 10"18
-
-
Nitrilotriacetic acid
139-13-9
-3.81
-
7.39 x 105
1.19 x 10"16
-
-
Nitrilotriacetic acid trisodium
monohydrate
18662-53-8
-3.81
-
7.39 x 105
1.19 x 10"16
-
-
N-Methyl-2-pyrrolidone
872-50-4
-0.11
-0.38
2.48 x 105
3.16 x 10"8
-
3.20 x 10"9
N-Methyldiethanolamine
105-59-9
-1.5
-
1.00 x 106
8.61 x 10"11
2.45 x 10"14
3.14 x 10"11
N-Methylethanolamine
109-83-1
-1.15
-0.94
1.00 x 106
8.07 x 10"10
2.50 x 10"10
-
N-Methyl-N-hydroxyethyl-N-
hydroxyethoxyethylamine
68213-98-9
-1.78
-
1.00 x 106
1.34 x 10"12
5.23 x 10"17
-
C-58

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
N-Oleyl diethanolamide
13127-82-7
6.63
-
0.1268
9.35 x 10"9
1.94 x 10"12
-
Oleic acid
112-80-1
7.73
7.64
0.01151
4.48 x 10"5
1.94 x 10"5
-
Pentaethylenehexamine
4067-16-7
-3.67
-
1.00 x 106
8.36 x 10"24
2.56 x 10"27
-
Pentane
109-66-0
2.8
3.39
49.76
1.29
1.20
1.25
Pentyl acetate
628-63-7
2.34
2.3
996.8
5.45 x 10"4
4.45 x 10"4
3.88 x 10"4
Pentyl butyrate
540-18-1
3.32
-
101.9
9.60 x 10"4
8.88 x 10"4
-
Peracetic acid
79-21-0
-1.07
-
1.00 x 106
1.39 x 10"6
-
2.14 x 10"6
Phenanthrene
85-01-8
4.35
4.46
0.677
5.13 x 10"5
2.56 x 10"5
4.23 x 10"5
Phenol
108-95-2
1.51
1.46
2.62 x 104
5.61 x 10"7
6.58 x 10"7
3.33 x 10"7
Phosphonic acid
(dimethylamino(methylene))
29712-30-9
-1.9
-
1.00 x 106
1.00 x 10"24
-
-
Phosphonic acid, (((2-[(2-hydroxyethyl)
(phosphonomethyl)amino)ethyl)imino]bis
(methylene))bis-, compd. with 2-
aminoethanol
129828-36-0
-6.73
-
1.00 x 106
5.29 x 10"42
-
-
Phosphonic acid, (1-hydroxyethylidene)
bis-, potassium salt
67953-76-8
-0.01
-
1.34 x 105
9.79 x 10"26
-
-
Phosphonic acid, (1-hydroxyethylidene)
bis-, tetrasodium salt
3794-83-0
-0.01
-
1.34 x 105
9.79 x 10"26
-
-
Phosphonic acid, [[(phosphonomethyl)
imino]bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-
15827-60-8
-9.72
-
1.00 x 106
-
-
-
C-59

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Phosphonic acid, [[(phosphonomethyl)
imino]bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-, ammonium salt
(l:x)
70714-66-8
-9.72
-
1.00 X 106
-
-
-
Phosphonic acid, [[(phosphonomethyl)
imino]bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-, sodium salt
22042-96-2
-9.72
-
1.00 X 106
-
-
-
Phosphonic acid, [[(phosphonomethyl)
imino]bis[6,l-hexanediylnitrilobis
(methylene)]]tetrakis-
34690-00-1
-5.79
-
1.00 x 106
-
-
-
Phthalic anhydride
85-44-9
2.07
1.6
3,326
6.35 x 10"6
-
1.63 x 10"8
Poly(oxy-l,2-ethanediyl),
,alpha.-(octylphenyl)-.omega.-hydroxy-,
branched
68987-90-6
5.01
-
3.998
1.24 x 10"7
1.07 x 10"6
-
Potassium acetate
127-08-2
0.09
-0.17
4.76 x 105
5.48 x 10"7
2.94 x 10"7
1.00 X 10"7
Potassium oleate
143-18-0
7.73
7.64
0.01151
4.48 x 10"5
1.94 x 10"5
-
Propane
74-98-6
1.81
2.36
368.9
7.30 x 10"1
6.00 x 10"1
7.07 x 10"1
Propanol, l(or 2)-(2-
methoxymethylethoxy)-
34590-94-8
-0.27
-
4.27 x 105
1.15 x 10"9
1.69 x 10"9
-
Propargyl alcohol
107-19-7
-0.42
-0.38
9.36 x 105
5.88 x 10"7
-
1.15 x 10"6
Propylene carbonate
108-32-7
0.08
-0.41
2.58 x 105
3.63 x 10"4
-
3.45 x 10"8
Propylene pentamer
15220-87-8
6.28
-
0.05601
3.92 x 10"1
1.09 x 10"3
-
p-Xylene
106-42-3
3.09
3.15
228.6
6.56 x 10"3
6.14 x 10"3
6.90 x 10"3
C-60

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Pyrimidine
289-95-2
-0.06
-0.4
2.87 x 105
2.92 x 10"6
-
-
Pyrrole
109-97-7
0.88
0.75
3.12 x 104
9.07 x 10"6
7.73 x 10"6
1.80 x 10"5
Quaternary ammonium compounds, di-
C8-10-alkyldimethyl, chlorides
68424-95-3
2.69
-
90.87
2.20 x 10"10
-
-
Quinaldine
91-63-4
2.69
2.59
498.5
7.60 x 10"7
2.13 x 10"6
-
Quinoline
91-22-5
2.14
2.03
1,711
6.88 x 10"7
1.54 x 10"6
1.67 x 10"6
Rhodamine B
81-88-9
6.03
-
0.0116
-
-
-
Sodium 1-octanesulfonate
5324-84-5
1.06
-
5,864
9.15 x 10"8
-
-
Sodium 2-mercaptobenzothiolate
2492-26-4
2.86
2.42
543.4
3.63 x 10"8
-
-
Sodium acetate
127-09-3
0.09
-0.17
4.76 x 105
5.48 x 10"7
2.94 x 10"7
1.00 X 10"7
Sodium benzoate
532-32-1
1.87
1.87
2,493
1.08 x 10"7
4.55 x 10"8
3.81 x 10"8
Sodium bicarbonate
144-55-8
-0.46
-
8.42 x 105
6.05 x 10"9
-
-
Sodium bis(tridecyl) sulfobutanedioate
2673-22-5
11.15
-
7.46 x 10"9
8.51 x 10"11
-
-
Sodium C14-16 alpha-olefin sulfonate
68439-57-6
4.36
-
2.651
4.95 x 10"7
-
-
Sodium caprylamphopropionate
68610-44-6
-0.26
-
615.1
1.19 x 10"9
2.45 x 10"10
-
Sodium carbonate
497-19-8
-0.46
-
8.42 x 105
6.05 x 10"9
-
-
Sodium chloroacetate
3926-62-3
0.34
0.22
1.95 x 105
1.93 x 10"7
8.88 x 10"8
9.26 x 10"9
Sodium decyl sulfate
142-87-0
1.44
-
1,617
1.04 x 10"7
-
-
Sodium D-gluconate
527-07-1
-1.87
-
1.00 x 106
4.74 x 10"13
-
-
C-61

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Sodium diacetate
126-96-5
0.09
-0.17
4.76 x 105
5.48 x 10"7
2.94 x 10"7
1.00 X 10"7
Sodium dichloroisocyanurate
2893-78-9
1.28
-
3,613
3.22 x 10"12
-
-
Sodium dl-lactate
72-17-3
-0.65
-0.72
1.00 x 106
1.13 x 10"7
-
8.13 x 10"8
Sodium dodecyl sulfate
151-21-3
2.42
-
163.7
1.84 x 10"7
-
-
Sodium erythorbate (1:1)
6381-77-7
-1.88
-1.85
1.00 x 106
4.07 x 10"8
-
-
Sodium ethasulfate
126-92-1
0.38
-
1.82 x 104
5.91 x 10"8
-
-
Sodium formate
141-53-7
-0.46
-0.54
9.55 x 105
7.50 x 10"7
5.11 x 10"7
1.67 x 10"7
Sodium hydroxymethanesulfonate
870-72-4
-3.85
-
1.00 x 106
4.60 x 10"13
-
-
Sodium l-lactate
867-56-1
-0.65
-0.72
1.00 x 106
1.13 x 10"7
-
8.13 x 10"8
Sodium maleate (l:x)
18016-19-8
0.05
-0.48
1.04 x 105
1.35 x 10"12
8.48 x 10"14
-
Sodium N-methyl-N-oleoyltaurate
137-20-2
4.43
-
0.4748
1.00 x 10"12
-
-
Sodium octyl sulfate
142-31-4
0.46
-
1.58 x 104
5.91 x 10"8
-
-
Sodium salicylate
54-21-7
2.24
2.26
3,808
1.42 x 10"8
5.60 x 10"12
7.34 x 10"9
Sodium sesquicarbonate
533-96-0
-0.46
-
8.42 x 105
6.05 x 10"9
-
-
Sodium thiocyanate
540-72-7
0.58
-
4.36 x 104
1.46 x 10"4
-
-
Sodium trichloroacetate
650-51-1
1.44
1.33
1.20 x 104
2.39 x 10"8
-
1.35 x 10"8
Sodium xylenesulfonate
1300-72-7
-0.07
-
5.89 x 104
3.06 x 10"9
-
-
Sorbic acid
110-44-1
1.62
1.33
1.94 x 104
5.72 x 10"7
4.99 x 10"8
-
Sorbitan sesquioleate
8007-43-0
14.32
-
2.31 x 10"11
7.55 x 10"12
1.25 x 10"16
-
C-62

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Sorbitan, mono-(9Z)-9-octadecenoate
1338-43-8
5.89
-
0.01914
1.42 x 10"12
5.87 x 10"20
-
Sorbitan, monooctadecanoate
1338-41-6
6.1
-
0.01218
1.61 x 10"12
2.23 x 10"19
-
Sorbitan, tri-(9Z)-9-octadecenoate
26266-58-0
22.56
-
1.12 x 10"19
4.02 x 10"11
2.68 x 10"13
-
Styrene
100-42-5
2.89
2.95
343.7
2.76 x 10"3
2.81 x 10"3
2.75 x 10"3
Sucrose
57-50-1
-4.27
-3.7
1.00 x 106
4.47 x 10"22
-
-
Sulfan blue
129-17-9
-1.34
-
50.67
1.31 x 10"26
-
-
Sulfuric acid, mono-C12-18-alkyl esters,
sodium salts
68955-19-1
3.9
-
5.165
4.29 x 10"7
-
-
Sulfuric acid, mono-C6-10-alkyl esters,
ammonium salts
68187-17-7
0.46
-
1.58 x 104
5.91 x 10"8
-
-
Symclosene
87-90-1
0.94
-
4,610
6.19 x 10"11
-
-
tert-Butyl hydroperoxide
75-91-2
0.94
-
1.97 x 104
1.60 x 10"5
-
-
tert-Butyl perbenzoate
614-45-9
2.89
-
159.2
2.06 x 10"4
-
-
Tetradecane
629-59-4
7.22
7.2
0.009192
1.65 x 101
2.68 x 101
9.20
Tetradecyldimethylbenzylammonium
chloride
139-08-2
3.91
-
3.608
1.34 x 10"11
-
-
Tetraethylene glycol
112-60-7
-2.02
-
1.00 x 106
4.91 x 10"13
5.48 x 10"19
-
Tetraethylenepentamine
112-57-2
-3.16
-
1.00 x 106
2.79 x 10"20
4.15 x 10"23
-
Tetrakis(hydroxymethyl)phosphonium
sulfate
55566-30-8
-5.03
-
1.00 x 106
9.17 x 10"13
-
-
Tetramethylammonium chloride
75-57-0
-4.18
-
1.00 x 106
4.17 x 10"12
-
-
C-63

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Thiamine hydrochloride
67-03-8
0.95
-
3,018
8.24 x 10"17
-
-
Thiocyanic acid, ammonium salt
1762-95-4
0.58
-
4.36 x 104
1.46 x 10"4
-
-
Thioglycolic acid
68-11-1
0.03
0.09
2.56 x 105
1.94 x 10"8
-
-
Thiourea
62-56-6
-1.31
-1.08
5.54 x 105
1.58 x 10"7
-
1.98 x 10"9
Toluene
108-88-3
2.54
2.73
573.1
5.95 x 10"3
5.73 x 10"3
6.64 x 10"3
Tributyl phosphate
126-73-8
3.82
4
7.355
3.19 x 10"6
-
1.41 x 10"6
Tributyltetradecylphosphonium chloride
81741-28-8
11.22
-
7.90 x 10"7
2.61 x 10"1
-
-
Tridecane
629-50-5
6.73
-
0.02746
1.24 x 101
1.90 x 101
2.88
Triethanolamine
102-71-6
-2.48
-1
1.00 x 106
4.18 x 10"12
3.38 x 10"19
7.05 x 10"13
Triethanolamine hydrochloride
637-39-8
-2.48
-1
1.00 x 106
4.18 x 10"12
3.38 x 10"19
7.05 x 10"13
Triethanolamine hydroxyacetate
68299-02-5
-2.97
-
1.00 x 106
6.28 x 10"11
-
-
Triethyl citrate
77-93-0
0.33
-
2.82 x 104
6.39 x 10"10
-
3.84 x 10"9
Triethyl phosphate
78-40-0
0.87
0.8
1.12 x 104
5.83 x 10"7
-
3.60 x 10"8
Triethylene glycol
112-27-6
-1.75
-1.75
1.00 x 106
3.16 x 10"11
2.56 x 10"16
-
Triethylenetetramine
112-24-3
-2.65
-
1.00 x 106
9.30 x 10"17
6.74 x 10"19
-
Triisopropanolamine
122-20-3
-1.22
-
1.00 x 106
9.77 x 10"12
4.35 x 10"18
-
Trimethanolamine
14002-32-5
-3.95
-
1.00 x 106
1.42 x 10"8
-
-
Trimethylamine
75-50-3
0.04
0.16
1.00 x 106
3.65 x 10"5
1.28 x 10"4
1.04 x 10"4
Tripotassium citrate monohydrate
6100-05-6
-1.67
-1.64
1.00 x 106
8.33 x 10"18
-
4.33 x 10"14
C-64

-------
Appendix C - Chemical Mixing Supplemental Information
Chemical name
CASRN
Log Kow
Water solubility
estimate from
log Kow
(mg/L at 25°C)
Henry's law constant
(atm-m3/mol at 25°C)
Estimated
Measured
Bond
method
Group
method 25
Measured
Tripropylene glycol monomethyl ether
25498-49-1
-0.2
-
1.96 x 105
2.36 x 10"11
4.55 x 10"13
-
Trisodium citrate
68-04-2
-1.67
-1.64
1.00 x 106
8.33 x 10"18
-
4.33 x 10"14
Trisodium citrate dihydrate
6132-04-3
-1.67
-1.64
1.00 x 106
8.33 x 10"18
-
4.33 x 10"14
Trisodium ethylenediaminetetraacetate
150-38-9
-3.86
-
2.28 x 105
1.17 x 10"23
-
5.77 x 10"16
Trisodium ethylenediaminetriacetate
19019-43-3
-4.32
-
1.00 x 106
3.58 x 10"20
-
-
Tromethamine
77-86-1
-1.56
-
1.00 x 106
8.67 x 10"13
-
-
Undecane
1120-21-4
5.74
-
0.2571
7.04
9.52
1.93
Urea
57-13-6
-1.56
-2.11
4.26 x 105
3.65 x 10"10
-
1.74 x 10"12
Xylenes
1330-20-7
3.09
3.2
207.2
6.56 x 10"3
6.14 x 10"3
7.18 x 10"3
C-65

-------
Appendix C - Chemical Mixing Supplemental Information
C.6. Details on the EPI (Estimation Programs Interface) Suite™
The EPI (Estimation Programs Interface) Suite™ (U.S. EPA. 2012b) is an open-source, Windows®-
based suite of physicochemical property and environmental fate estimation programs developed by
the EPA's Office of Pollution Prevention and Toxics and Syracuse Research Corporation. More
information on EPI Suite™ is available at http: //www.epa.gov/oppt/exposure/pubs/episuite.htm.
Although only physicochemical properties from EPI Suite™ are provided here, other sources of
information were also consulted. QikProp fSchrodinger. 20121 and LeadScope fLeadscope Inc..
20121 are commercial products designed primarily as drug development and screening tools.
Properties generated by QikProp and LeadScope are generally more relevant to drug development
than to environmental assessment
QikProp is specifically focused on drug discovery and provides predictions for physically significant
descriptors and pharmaceutically (and toxicologically) relevant properties useful in predicting
ADME (adsorption, distribution, metabolism, and excretion) characteristics of drug candidates.
QikProp's use of whole-molecule descriptors that have a straightforward physical interpretation (as
opposed to fragment-based descriptors).
LeadScope is a program designed for interpreting chemical and biological screening data that can
assist pharmaceutical scientists in finding promising drug candidates. The software organizes the
chemical data by structural features familiar to medicinal chemists. Graphs are used to summarize
the data, and structural classes are highlighted that are statistically correlated with biological
activity. It incorporates chemically-based data mining, visualization, and advanced informatics
techniques (e.g., prediction tools, scaffold generators).
Physicochemical properties of chemicals were generated from the two-dimensional (2-D) chemical
structures from the EPA National Center for Computational Toxicology's Distributed Structure-
Searchable Toxicity (NCCT DSSTox) Database Network in structure-data file (SDF) format For EPI
Suite™ properties, both the desalted and non-desalted 2-D files were run using the program's batch
mode (i.e., processing many molecules at once) to calculate environmentally-relevant, chemical
property descriptors. The chemical descriptors in QikProp require 3-D chemical structures. For
these calculations, the 2-D desalted chemical structures were converted to 3-D using the Rebuild3D
function in the Molecular Operating Environment software (CCG. 20111. All computed
physicochemical properties are added into the structure-data file prior to assigning toxicological
properties.
Both LeadScope and Qikprop software require input of desalted structures. Therefore, the
structures were desalted, a process where salts and complexes are simplified to the neutral,
uncomplexed form of the chemical, using the "Desalt Batch" option in the ACD Labs ChemFolder. All
LeadScope general chemical descriptors (Parent Molecular Weight, AlogP, Hydrogen Bond
Acceptors, Hydrogen Bond Donors, Lipinski Score, Molecular Weight, Parent Atom Count, Polar
Surface Area, and Rotatable Bonds) were calculated by default
C-66

-------
Appendix C - Chemical Mixing Supplemental Information
C.7. Top 20 lists for most mobile and least mobile chemicals
Table C-10 and Table C-ll present the 20 highest and lowest log Kow (approximate surrogate for
most mobile and least mobile) chemicals, known to be used in hydraulic fracturing fluids,
respectively, as ranked by log Kow¦ These were taken from the list of 917 chemicals with estimated
values for physicochemical properties. These tables also include values for aqueous solubility and
Henry's law constant, as well as frequency of use, based on chemical information reported in
disclosures in the EPA FracFocus 1.0 project database fU.S. EPA. 2015a. c).
Table C-10 shows the chemicals that have the lowest log Kow and are, thus, the most mobile. These
chemicals are fully miscible (i.e., they will mix completely with water), which means they may move
through the environment at high concentrations, leading to greater severity of impact These
chemicals generally have low volatility, based on their negative log Henry's law constants (i.e., will
remain in water and will not be lost to the air). These chemicals will dissolve in water and move
rapidly through the environment (e.g., via infiltration into the subsurface or via overland flow to
surface waters). Chemicals exhibiting this combination of properties have greater potential to cause
immediate impacts to drinking water resources. Most of the chemicals in the table were
infrequently reported (<2% of wells) in the EPA FracFocus 1.0 project database (U.S. EPA. 2015a).
However, choline chloride (14% of wells), used for clay control, and
tetrakis(hydroxymethyl)phosphonium sulfate (11% of wells), abiocide, were more commonly
reported.
Table C-ll shows the chemicals that have the highest log Kow and are, thus, the least mobile. The
estimated aqueous solubilities for some of these chemicals are extremely low, with highest
solubilities of <10 ng/L. Therefore, the concentration of these chemicals dissolved in water will be
low. The estimated Henry's law constants are more variable for these low-mobility chemicals.
Chemicals with high log Kow values (>0) and high Henry's law constants will sorb strongly to organic
phases and solids and may volatilize. However, their strong preference for the organic or solid
phase may slow or reduce volatilization. The chemicals with low Henry's law constants will readily
sorb to organic phases and solids. Less mobile chemicals will move slowly through the soil and have
potentially delayed and longer-term impacts to drinking water resources. Seven of the chemicals in
were reported in disclosures in the EPA FracFocus 1.0 project database (U.S. EPA. 2015c). Five were
reported infrequently (<1% of wells). Tri-n-butyltetradecylphosphonium chloride (6% of wells),
used as a biocide, and C>10-alpha-alkenes (8% of wells), a mixture of alpha-olefins with carbon
numbers greater than 10 used as a corrosion inhibitor, were more commonly reported. The least
mobile organic chemical is sorbitan, tri-(9Z)-9-octadecenoate, a mineral oil co-emulsifier (0.05% of
wells), with an estimated log Kow of 22.56.1
1 Sorbitan, tri-(9Z]-9-octadecenoate, CASRN 26266-58-0, is soluble in hydrocarbons and insoluble in water, listed as an
effective coupling agent and co-emulsifier for mineral oil f Santa Cruz Biotechnology. 2015: ChemicalBook. 20101
C-67

-------
Appendix C - Chemical Mixing Supplemental Information
Table C-10. Ranking of the 20 most mobile organic chemicals, as determined by the largest log Kow, with CASRN, percent of wells
where the chemical is reported from January 1, 2011 to February 28, 2013 (U.S. EPA. 2015c). and physicochemical properties (log
Kow, solubility, and Henry's law constant) as estimated by EPI Suite™.
For organic salts, parameters are estimated using the desalted form.
Rank
Chemical name
CASRN
Percent of
wells
(U.S. EPA.
2015c)a
Estimated
log Kow
(unitless)b
Estimated
water
solubility
(mg/L @
25°C)C
Estimated Henry's
law constant
(atm m3/mole @
25°C)d
1
1,2-Ethanediaminium, N,N'-bis[2-[bis(2-
hydroxyethyl)methylammonio]ethyl]-N,N'-bis(2-
hydroxyethyl)-N,N'-dimethyl-, tetrachloride
138879-94-4
2%
-23.19
1.00 X 106
2.33 x 10"35
2
Phosphonic acid, [[(phosphonomethyl)imino]bis [2,1-
ethanediylnitrilobis(methylene)]]tetrakis-
15827-60-8
0.2%
-9.72
1.00 X 106
NA
3
Phosphonic acid, [[(phosphonomethyl)imino]bis [2,1-
ethanediylnitrilobis(methylene)]]tetrakis-, sodium salt
22042-96-2
0.07%
-9.72
1.00 x 106
NA
4
Phosphonic acid, [[(phosphonomethyl)imino]bis [2,1-
ethanediylnitrilobis(methylene)]]tetrakis-, ammonium salt
(l:x)
70714-66-8
NA
-9.72
1.00 x 106
NA
5
Phosphonic acid, (((2-[(2-hydroxyethyl) (phosphonomethyl)
amino)ethyl)imino]bis(methylene))bis-, compd. with 2-
aminoethanol
129828-36-0
NA
-6.73
1.00 x 106
5.29 x 10"42
6
2-Hydroxy-N,N-bis(2-hydroxyethyl)-N-
methylethanaminium chloride
7006-59-9
NA
-6.7
1.00 x 106
4.78 x 1019
7
N-(3-Chloroallyl)hexaminium chloride
4080-31-3
0.02%
-5.92
1.00 x 106
1.76 x 10"8
8
3,5,7-Triazatricyclo(3.3.1.1 (superscript 3,7))decane, l-(3-
chloro-2-propenyl)-, chloride, (Z)-
51229-78-8
NA
-5.92
1.00 x 106
1.76 x 10"8
9
(2,3-dihydroxypropyl)trimethylammonium chloride
34004-36-9
NA
-5.8
1.00 x 106
9.84 x 1018
C-68

-------
Appendix C - Chemical Mixing Supplemental Information
Rank
Chemical name
CASRN
Percent of
wells
(U.S. EPA.
2015c)a
Estimated
log Kow
(unitless)b
Estimated
water
solubility
(mg/L @
25°C)C
Estimated Henry's
law constant
(atm m3/mole @
25°C)d
10
Phosphonic acid, [[(phosphonomethyl)imino]bis [6,1-
hexanediylnitrilobis(methylene)]]tetrakis-
34690-00-1
0.006%
-5.79
1.00 X 106
NA
n
[Nitrilotris(methylene)]tris-phosphonic acid pentasodium
salt
2235-43-0
0.5%
-5.45
1.00 X 106
1.65 x 10"34
12
Aminotrimethylene phosphonic acid
6419-19-8
2%
-5.45
1.00 x 106
1.65 x 10"34
13
Choline chloride
67-48-1
14%
-5.16
1.00 x 106
2.03 x 1016
14
Choline bicarbonate
78-73-9
0.2%
-5.16
1.00 x 106
2.03 x 1016
15
alpha-Lactose monohydrate
5989-81-1
NA
-5.12
1.00 x 106
4.47 x 10"22
16
Lactose
63-42-3
NA
-5.12
1.00 x 106
4.47 x 10"22
17
Tetrakis(hydroxymethyl)phosphonium sulfate
55566-30-8
11%
-5.03
1.00 x 106
9.17 x 1013
18
Disodium ethylenediaminediacetate
38011-25-5
0.6%
-4.79
1.00 x 106
1.10 x 1016
19
Nitrilotriacetamide
4862-18-4
NA
-4.75
1.00 x 106
1.61 x 1018
20
l,3,5-Triazine-l,3,5(2H,4H,6H)-triethanol
4719-04-4
0.2%
-4.67
1.00 x 106
1.08 x 1011
a Some of the chemicals in these tables have NA (not available) listed as the number of wells, which means that these chemicals have been used in hydraulic fracturing, but they
were not reported to disclosures in the EPA FracFocus 1.0 project database for the time period of the study (January 1, 2011, to February 28, 2013) (U.S. EPA. 2015c). Analysis
considered 34,675 disclosures and 676,376 ingredient records that met selected quality assurance criteria, including: completely parsed; unique combination of fracture date
and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures that did not meet our quality assurance
criteria (3,855) or other, query-specific criteria were excluded from our analysis.
b Log Kow is estimated using the KOWWIN™ model, which uses an atom/fragment contribution method.
c Water solubility is estimated using the WSKOWWIN™ model, which estimates a chemical's solubility from Kow and any applicable correction factors.
d Henry's law constant is estimated using the HENRYWIN™ model using the bond contribution method.
C-69

-------
Appendix C - Chemical Mixing Supplemental Information
Table C-ll. Ranking of the 20 least mobile organic chemicals, as determined by the largest log Kow, with CASRN, percent of wells
where the chemical is reported from January 1, 2011 to February 28, 2013 (U.S. EPA. 2015c). and physicochemical properties (log
Kow, solubility, and Henry's law constant) as estimated by EPI Suite™.
For organic salts, parameters are estimated using the desalted form.
Rank
Chemical name
CASRN
Percent of
wells
(U.S. EPA.
2015c)a
Estimated log
Kow (unitless)b
Estimated water
solubility
(mg/L @ 25°C)C
Estimated Henry's law
constant
(atm m3/mole @ 25°C)d
1
Sorbitan, tri-(9Z)-9 octadecenoate
26266-58-0
0.05%
22.56
1.12 x 10 19
4.02 x 10 11
2
Fatty acids, C18-unsatd., dimers
61788-89-4
NA
14.6
2.31 x 1010
4.12 x 10 08
3
Sorbitan sesquioleate
8007-43-0
0.02%
14.32
2.31 x 1011
7.55 x 10 12
4
Tri-n-butyltetradecyl-phosphonium
chloride
81741-28-8
6%
11.22
7.90 x 10"7
2.61 x 10 1
5
Sodium bis(tridecyl) sulfobutanedioate
2673-22-5
NA
11.15
7.46 x 10"9
8.51 x 10 11
6
1-Eicosene
3452-07-1
NA
10.03
1.26 x 10"5
1.89 x 101
7
D&C Red 28
18472-87-2
NA
9.62
1.64 x 10"8
6.37 x 10"21
8
C.I. Solvent Red 26
4477-79-6
NA
9.27
5.68 x 10"5
5.48 x 10 13
9
1-Octadecene
112-88-9
NA
9.04
1.256 x 10"4
1.07 x 101
10
Alkenes, C>10 alpha-
64743-02-8
8%
8.55
3.941 x 10"4
8.09 x 10°
11
Dioctyl phthalate
117-84-0
NA
8.54
4.236 x 10"4
1.18 x 10"5
12
Benzene, C10-16-alkyl derivs.
68648-87-3
0.5%
8.43
2.099 x 10"4
1.78 x 10 1
13
Di(2-ethylhexyl) phthalate
117-81-7
NA
8.39
1.132 x 10"3
1.18 x 10"5
14
1-Octadecanamine, N,N-dimethyl-
124-28-7
NA
8.39
8.882 x 10"3
4.51 x 10"3
15
N,N-dimethyloctadecylamine
hydrochloride
1613-17-8
NA
8.39
8.882 x 10"3
4.51 x 10"3
C-70

-------
Appendix C - Chemical Mixing Supplemental Information
Rank
Chemical name
CASRN
Percent of
wells
(U.S. EPA.
2015c)a
Estimated log
Kow (unitless)b
Estimated water
solubility
(mg/L @ 25°C)C
Estimated Henry's law
constant
(atm m3/mole @ 25°C)d
16
Butyryl trihexyl citrate
82469-79-2
0.03%
8.21
5.56 x 10"5
3.65 x 10"9
17
1-Hexadecene
629-73-2
NA
8.06
1.232 x 10"3
6.10 x 10°
18
Benzo(g,h,i)perylene
191-24-2
NA
7.98
7.321 x 10"4
1.26 x 10"2
19
Dodecylbenzene
123-01-3
NA
7.94
1.015 x 10"3
1.34 x 10 1
20
Isopropanolamine dodecylbenzene
42504-46-1
0.02%
7.94
1.015 x 10"3
1.34 x 10 1
a Some of the chemicals in these tables have NA (not available) listed as the number of wells, which means that these chemicals have been used in hydraulic fracturing, but they
were not reported in disclosures in the EPA FracFocus 1.0 project databases for the time period of the study (January 1, 2011, to February 28, 2013) (U.S. EPA. 2015c). Analysis
considered 34,675 disclosures and 676,376 ingredient records that met selected quality assurance criteria, including: completely parsed; unique combination of fracture date
and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures that did not meet these quality
assurance criteria (3,855) or other, query-specific criteria were excluded from our analysis.
b Log Kow is estimated using the KOWWIN™ model, which uses an atom/fragment contribution method.
c Water solubility is estimated using the WSKOWWIN™ model, which estimates a chemical's solubility from Kow and any applicable correction factors.
d Henry's law constant is estimated using the HENRYWIN™ model using the bond contribution method.
C-71

-------
Appendix C - Chemical Mixing Supplemental Information
4	4
Most mobile	least mobile	Most mobile	
3.5	3.5
® 3	S 3	II
« 2.5	„ 2.5!
llJ. i lU
-10	-5	0	5	10	-25 -20 -15 -10 -5 0 5
Measured log Kow [L/kg]	Estimated log Kow [L/kg]
Least So ub e
Most Soluble
-15 -10 -5 0 5 10
Estimated log Solubility [mg/L @ 25C]
20
Stays in water
Readily escapes to air
11.
50 -40 -30 -20 -10
10 20 30 40 50
Estimated log Henry's Law Constant [atm m3 mole 1 @ 25C]
Figure C-l. Histograms of physicochemical properties organic chemicals claimed as
confidential by industry that were used in the hydraulic fracturing process.
Measured vaiues of log Kow (upper left). Estimated physicochemical properties for log Kow (upper right), log
solubility (lower left), and log Henry's law constant (lower right) for all chemicals. Physicochemical properties (log
Kow, solubility, and Henry's law constant) estimated by EPI Suite™. Source: U.S. EPA (2013a).
C-72

-------
Appendix D - Well Injection Supplemental Information
Appendix D. Well Injection Supplemental
Information
D-l

-------
Appendix D - Well Injection Supplemental Information
This page is intentionally left blank.
D-2

-------
Appendix D - Well Injection Supplemental Information
Appendix D. Well Injection Supplemental Information
This appendix presents the goals for the design and construction of oil and gas production wells,
the well components used to achieve those goals, and methods for testing well integrity to help
verify that the goals for well performance are achieved. This information provides additional
background for the well component discussions presented in Chapter 6. Information on the
pathways associated with the well that can cause fluid movement into drinking water resources is
presented in Chapter 6.
D.l. Design Goals for Well Construction
Simply stated, production wells are designed to move oil and gas from the production zone (within
the oil and gas reservoir) into the well and then through the well to the surface. There are typically
a variety of goals for well design (Renpu. 20111. but the main purposes are facilitating the flow of
oil and gas from the hydrocarbon reservoirs to the well (production management) while isolating
that oil and gas and the hydrocarbon reservoirs from nearby groundwater resources (zonal
isolation).
To achieve these goals, operators design and construct wells to have and maintain mechanical
integrity throughout the life of the well. A properly designed and constructed well has two types of
mechanical integrity: internal and external. Internal mechanical integrity refers to the absence of
significant leakage within the production tubing, casing, or packer. External mechanical integrity
refers to the absence of significant leakage along the well outside of the casing.
Achieving mechanical integrity involves designing the well components to resist the stresses they
will encounter. Each well component must be designed to withstand all of the stresses to which the
well will be subjected, including burst pressure, collapse, tensile, compression (or bending), and
cyclic stresses (see Section 6.2.1 for additional information on these stresses). Well materials
should also be compatible with the fluids (including liquids or gases) with which they come into
contact to prevent leaks caused by corrosion.
These goals are accomplished by the use of one or more layers of casing, cement, and mechanical
devices (such as packers), which provide the main barrier preventing migration of fluids from the
well into drinking water resources. It should be noted that design conditions will change depending
on the specific geology of the site. Technology in the field of hydraulic fracturing is also rapidly
evolving with new technologies and techniques being continually developed. Therefore while the
following sections outline basic design goals and concepts, they cannot anticipate all possible
design conditions.
D.2. Well Components
Casing and cement are used in the design and construction of wells to achieve the goals of
mechanical integrity and zonal isolation. Several industry-developed specifications and best
practices for well construction have been established to guide well operators in the construction
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process; see Text Box D-l.1 The sections below describe options available for casing, cement, and
other well components.
Text Box D-l. Selected Industry-Developed Specifications and Recommended Practices for
Well Construction in North America.
American Petroleum Institute (API)
• API Guidance Document HF1—Hydraulic Fracturing Operations—Well Construction and Integrity
Guidelines fAPI. 2009a1
• API RP 10B-2—Recommended Practice for Testing Well Cements fAPI. 20131
• API RP 10D-2—Recommended Practice for Centralizer Placement and Stop Collar Testing fAPI. 20041
• API RP 5C1—Recommended Practices for Care and Use of Casing and Tubing fAPI. 19991
• API RP 65-2—Isolating Potential Flow Zones during Well Construction fAPI. 2010a1
• API Specification 1 OA—Specification on Cements and Materials for Well Cementing fAPI. 2010b1
• API Specification 11D1—Packers and Bridge Plugs fAPI. 2009b1
• API Specification 5CT—Specification for Casing and Tubing fAPI. 20111
• API RP 100-1 - Hydraulic Fracturing Well Integrity and Fracture Containment 1st Edition fAPI. 20151
Canadian Association of Petroleum Producers (CAPP) and Enform
• Hydraulic Fracturing Operating Practices: Wellbore Construction and Quality Assurance fCAPP. 20131
• Interim Industry Recommended Practice Volume #24—Fracture Stimulation: Inter-wellbore
Communication fEnform. 20131
Marcellus Shale Coalition (MSC)
• Recommended Practices—Drilling and Completions fMSC. 20131
D.2.1. Casing
Casing is steel pipe that is placed into the wellbore (the cylindrical hole drilled through the
subsurface rock formation) to maintain the stability of the wellbore, to transport the hydrocarbons
from the subsurface to the surface, and to prevent intrusion of other fluids into the well and
wellbore. Up to four types of casing may be present in a well, including (from largest to smallest-
diameter): conductor casing, surface casing, intermediate casing, and production casing. Each is
described below.
D.2.1.1. Types of Casing
The conductor casing is the largest diameter string of casing. It is typically in the range of 30 in.
(76 cm) to 42 in. (107 cm) in diameter fHvne. 20121. Its main purpose is to prevent unconsolidated
material, such as sand, gravel, and soil, from collapsing into the wellbore. Therefore, the casing is
1 Information is not available to determine how often these practices are used or how well they prevent the development
of pathways for fluid movement to drinking water resources.
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typically installed from the surface to the top of the bedrock or other consolidated formations. The
conductor casing may or may not be cemented in place.
The next string of casing is the surface casing. A typical surface casing diameter is 13.75 in. (34.93
cm), but diameter can vary fHvne. 20121. The surface casing's main purposes are to isolate any
groundwater resources that are to be protected by preventing fluid migration along the wellbore
once the casing is cemented and to provide a sturdy structure to which blow-out prevention
equipment can be attached. For these reasons, the surface casing most commonly extends from the
surface to some distance beneath the lowermost geologic formation containing groundwater
resources to be protected. The specific depth to which the surface casing is set is often governed by
the depth of the groundwater resource as defined and identified for protection in state regulations.
Intermediate casing is typically used in wells to control pressure in an intermediate-depth
formation. It may be used to reduce or prevent exposure of weak formations to pressure from the
weight of the drilling fluid or cement or to allow better control of over-pressured formations. The
intermediate casing extends from the surface through the formation of concern. There may be more
than one string of concentric intermediate casing present or none at all, depending on the
subsurface geology. Intermediate casing may be cemented, especially through over-pressured
zones; however, it is not always cemented to the surface. Intermediate casing, when present, is
often 8.625 in. (21.908 cm) in diameter but can vary fHvne. 20121.
Production casing extends from the surface into the production zone. The main purposes of the
production casing are to isolate the hydrocarbon product from fluids in surrounding formations
and to transport the product to the surface. It can also be used to inject hydraulic fracturing fluids,
receive produced water during hydraulic fracturing operations (e.g., if tubing or a temporary
fracturing string is not present), and prevent other fluids from mixing with and diluting the
produced hydrocarbons. The production casing is generally cemented to some point above the
production zone. Production casing is often 5.5 in. (14.0 cm) in diameter but can vary fHvne. 20121.
Liners are another type of metal tubular (casing-like) well component that can be used to fulfill the
same purposes as intermediate and production casing in the production zone. Like casing, they are
steel pipe, but differ in that they do not extend from the production zone to the surface. Rather, they
are connected to the next largest string of casing by a hanger that is attached to the casing. A frac
sleeve is a specialized type of liner that is used during fracturing. It has plugs that can be opened
and closed by dropping balls from the surface (see the discussion of well completions below for
additional information on the use of frac sleeves).
Production tubing is the smallest, innermost steel pipe in the well and is distinguished from casing
by not being cemented in place. It is used to transport the hydrocarbons to the surface. Fracturing
may be done through the tubing if present, or through the production casing. Because casing cannot
be replaced, tubing is often used, especially if the hydrocarbons contain corrosive substances such
as hydrogen sulfide or carbon dioxide. Tubing may not be used in high-volume production wells.
Typical tubing diameter is between 1.25 in. (3.18 cm) and 4.5 in. (11.4 cm) (Hvne. 20121.
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D.2.1.2. Casing Design Considerations
The stresses that the casing will experience are key factors to consider in designing the casing. If the
casing is not designed with sufficient resistance to the stresses it will face, it can fail. Stresses that
may cause failure of casing include: pressure exerted during hydraulic fracturing operations, cyclic
pressure from multi-stage fracturing, pressure from the formation, and stresses encountered
during installation of the casing especially around bends fKing and Valencia. 2016: Cheremisinoff
and Davletshin. 20151. Maximum values for each of these stresses can be calculated, and the casing
can be designed to resist them. Generally, the inner layers such as tubing are designed to collapse
before the outer casing will burst (King and Valencia. 20161. Casing strength can be improved by
choosing stronger materials or by increasing casing thickness.
Another factor to consider in casing design is corrosion. The casing may be exposed to corrosive
substances such as carbon dioxide, hydrogen sulfide, natural brines, and acids used during
fracturing. Corrosion resistance may be achieved by using corrosion resistant alloys or by lining the
casing fKingand Valencia. 2016: Sved and Cutler. 20101. Abrasion from proppant during fracturing
can also lead to casing erosion problems (King and Valencia. 20161.
Joint design and installation are equally important in casing design as they are a frequent location
of casing leaks fKingand Valencia. 20161. Joint failure can occur due to poor design, installation
errors, and stress corrosion.
D.2.2. Cement
Cement is the main barrier preventing fluid movement along the wellbore outside the casing. It also
lends mechanical strength to the well and protects the casing from corrosion by naturally occurring
formation fluids. Cement is placed in the annulus, which is the space between two adjacent casings
or the space between the outermost casing and the rock formation through which the wellbore was
drilled. The sections below describe considerations for selecting cement and additives, as well as
cementing procedures and techniques.
D.2.2.1. Considerations for Cementing
The length and location of the casing section to be cemented and the composition of the cement can
vary based on numerous factors, including the presence and locations of weak formations, over- or
under-pressured formations, or formations containing fluids; formation permeability; and
temperature. State requirements for oil and gas production well construction and the relative costs
of well construction options are also factors.
Improper cementing can lead to the formation of channels (small connected voids) in the cement,
which can—if they extend across multiple formations or connect to other existing channels or
fractures—present pathways for fluid migration. This section describes some of the considerations
and concerns for proper cement placement and techniques and materials that are available to
address these concerns. Careful selection of cements (and additives) and design of the cementing
job can avoid integrity problems related to cement
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To select the appropriate cement type, properties, and additives, operators consider the required
strength needed to withstand downhole conditions and compatibility with subsurface chemistry, as
described below:
• The cement design needs to achieve the strength required under the measured or
anticipated downhole conditions. Factors that are taken into account to achieve proper
strength can include density, thickening time, the presence of free water, compressive
strength, and formation permeability fRenpu. 20111. Commonly, cement properties are
varied during the process, with a "weaker" (i.e., less dense) lead cement, followed by a
"stronger" (denser) tail cement The lead cement is designed with a lower density to
reduce pressure on the formation and better displace drilling fluid without a large concern
for strength. The stronger tail cement provides greater strength for the deeper portions of
the well the operator considers as requiring greater strength.
• The compatibility of the cement with the chemistry of formation fluids, hydrocarbons,
and hydraulic fracturing fluids is important for maintaining well integrity through the life
of the well. Most oil and gas wells are constructed using some form of Portland cement.
Portland cement is a specific type of cement consisting primarily of calcium silicates with
additional iron and aluminum. Industry specifications for recommended cements are
determined by the downhole pressure, temperature, and chemical compatibility required.
There are a number of considerations in the design and execution of a cement job. Proper
centralization of the casing within the wellbore is one of the more important considerations. Others
include the potential for lost cement, gas invasion, cement shrinkage, incomplete removal of drilling
mud, settling of solids in the wellbore, and water loss into the formation while curing. These
concerns, and techniques available to address them, include the following:
• Improper centralization of the casing within the wellbore can lead to preferential flow
of cement on the side of the casing with the larger space and little to no cement on the side
closer to the formation. If the casing is not centered in the wellbore, cement will flow
unevenly during the cement job, leading to the formation of cement channels. Kirksev
(2013) notes that, if the casing is off-center by just 25%, the cement job is almost always
inadequate. Centralizers are used to keep the casing in the center of the hole and allow an
even cement job. To ensure proper centralization, centralizers are placed at regular
intervals along the casing fAPI. 2010al. Centralizer use is especially key in horizontal wells,
as the casing will tend to settle (due to gravity) to the bottom of the wellbore if the casing
is not centered (Sabins. 1990). leading to inadequate cement on the lower side. Although
some operators have avoided using centralizers on horizontal wells because of problems
with stuck pipe, improved centralizer designs have allowed increased use of centralizers in
horizontal wells fLandry etal.. 20151.
• Lost cement (sometimes referred to as lost returns) refers to cement that moves out of
the wellbore and into the formation instead of filling up the annulus between the casing
and the formation. Lost cement can occur in weak formations that fail (fracture) under
pressure of the cement or in particularly porous, permeable, or naturally fractured
formations. Lost cement can result in lack of adequate cement across a water- or brine-
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bearing zone. To avoid inadequate placement of cement due to lost cement, records of
nearby wells can be examined to determine zones where lost cement returns occur fAPI.
2009a). If records from nearby wells are not available, cores and logs may be used to
identify any high-permeability or mechanically weak formations that might lead to lost
cement Steps can then be taken to eliminate or reduce loss of cement to the formation.
Staged cementing (see below) can reduce the hydrostatic pressure on the formation and
may avoid fracturing weak formations fLyons and Pligsa. 20041. Additives such as
cellulose or polymers are also available that will lessen the flow of cement into highly
porous formations (API. 2010a: Ali etal.. 2009).
• Gas invasion and cement shrinkage during cement setting can also cause channels and
poor bonding. As cement sets, it begins to lose the ability to transmit pressure to the
surrounding formation. During the cementing process, the hydrostatic pressure from the
cement column keeps formation gas from entering the cement As the cement sets
(hardens), the hydrostatic pressure decreases; if it becomes less than the formation
pressure, gas can enter the cement, leading to channels. Cement shrinkage occurs as the
cement sets under a high pressure; shrinking can be made worse by left over drilling mud
or too large of a space between the casing and formation fOvarhossein and Dusseault.
20151. Such shrinkage can lead to channels or microannuli along the cement column.
These problems can be avoided by using cement additives that increase setting time or
expand to offset shrinkage (McDaniel et al.. 2014: Woitanowicz. 2008: Dusseault etal..
20001. Foamed cement can help alleviate problems with shrinkage, although care needs to
be taken in cement design to ensure the proper balance of pressure between the cement
column and formation (API. 2010a). Cement additives such as latex are also available that
will expand upon contact with certain fluids such as hydrocarbons. These cements, termed
self-healing cements, are relatively new but have shown early promise in some fields (Ali
etal.. 20091. Self-healing cements have been found to increase the compressive strength of
the cement by 10%, tensile strength by 48%, Poisson's ratio by 66%, and Young's modulus
by 56% (Shadravan and Amani. 2015). Rotating the casing during cementing will also
delay cement setting by agitating the cement. Another technique called pulsation, where
pressure pulses are applied to the cement while it is setting, also can delay cement setting
and loss of hydrostatic pressure until the cement is strong enough to resist gas penetration
fSteinetal.. 20031.
• Another important issue is removal of drilling mud. Inadequate removal of drilling mud
can prevent cement from filling the entire space between the casing and the formation,
resulting in channels in the cement after the mud is eroded away by formation fluids
(Tackson and Dussealt. 2014). If drilling mud is not completely removed, it can gather on
one side of the wellbore and prevent that portion of the wellbore from being adequately
cemented. The drilling mud can then be eroded away after the cement sets, leaving a
channel. Drilling mud can be removed by circulating a denser fluid (spacer fluid) to flush
the drilling mud out (Kirksev. 2013: Brufatto etal.. 2003). Mechanical devices called
scratchers can also be attached to the casing, and the casing rotated or reciprocated to
scrape drilling mud from the wellbore fHvne. 2012: Crook. 20081. The spacer fluid, which
is circulated prior to the cement to wash the drilling fluid out of the wellbore, must be
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designed with the appropriate properties and pumped in such a way that it displaces the
drilling fluid without mixing with the cement fKirksev. 2013: API. 2010a: Brufatto et al..
20031.
• Also of concern in horizontal wells is the possibility of solids settling at the bottom of the
wellbore and free water collecting at the top of the wellbore. This can lead to channels and
poor cement bonding. The cement slurry must be properly designed for horizontal wells to
minimize free water and solids settling.
• If there is free water in the cement, pressure can cause water loss into the formation,
leaving behind poor cement or channels fliang etal.. 20121. In horizontal wells, free water
can also accumulate at the top of the wellbore, forming a channel (Sabins. 19901.
Minimizing free water in the cement design and using fluid loss control additives can help
control the loss of water (Ross and King. 20071.
• Fracturing in stages can lead to cyclic stresses being exerted on the cement (King and
Valencia. 20161. During fracturing, the cooler temperature fluids are injected into the well
at high pressure, resulting in temperature and pressure changes downhole. When
injection stops, the temperature returns to the higher reservoir temperatures and
pressure returns to normal. One study has found such cycling can lead to temperature
changes of as much as 176°F (80°C) (Tian etal.. 20151. Exposing cement to several cycles
of temperature and pressure variation can lead to a number of problems. Stress may cause
cracks in the cement, especially at locations of existing defects in the cement fDe Andrade
etal.. 2015: Sved and Cutler. 20101. Differences between the rates at which steel and
cement expand can lead to debonding between the cement and casing. Contraction of
fluids at lower temperatures can also create vacuums in some situations, which can stress
the casing and cement fTian etal.. 20151. Using cement with lower anelastic strength and
higher tensile and impact strength may help alleviate problems caused by cyclic stresses
(McDaniel etal.. 20141. Self-sealing cements, as described above, may also seal cracks that
are initiated during cycling. Some studies have found the ability of such cements to seal
flow through cracks in as little as 30 minutes fCavanagh etal.. 20071. Foamed cements
have also been found to hold up better to pressure cycles than standard cement slurries
fSpaulding. 20151.
D.2.2.2. Cement Placement Techniques
The primary cement job is most commonly conducted by pumping the cement down the inside of
the casing, then out the bottom of the casing where it is then forced up the space between the
outside of the casing and the formation. (The cement can also be placed in the space between two
casings.) If continuous cement (i.e., a sheath of cement placed along the entire wellbore) is
desired, cement is circulated through the annulus until cement that is pumped down the central
casing flows out of the annulus at the surface. A spacer fluid is often pumped ahead of cement to
remove any excess drilling fluid left in the wellbore; even if the operator does not plan to circulate
cement to the surface, the spacer fluid will still return to the surface, as this is necessary to remove
the drilling mud from the annulus. If neither the spacer fluid nor the cement returns to the surface,
this indicates that fluids are being lost into the formation.
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Staged cementing is a technique that reduces pressure on the formation by decreasing the height
(and therefore the weight) of the cement column. This may be necessary if the estimated weight
and pressure associated with standard cement emplacement could damage zones where the
formation intersected is weak. The reduced hydrostatic pressure at the bottom of the cement
column can also reduce the loss of water to permeable formations, improving the quality of the
cement job. In multiple-stage cementing, cement is circulated to just below a cement collar placed
between two sections of casing. A cement collar will have been placed between two sections of
casing, just above, with ports that can be opened by dropping a weighted tool. Two plugs—which
are often referred to as bombs or darts because of their shape—are then dropped. The first plug is
dropped once the desired cement for the first stage has been pushed out of the casing by a spacer
fluid. It closes the section of the well below the cement collar and stops cement from flowing into
the lower portion of the well. The second plug (or opening bomb) opens the cement ports in the
collar, allowing cement to flow into the annulus between the casing and formation. Cement is then
circulated down the wellbore, out the cement ports, into the annulus, and up to the surface. Once
cementing is complete, a third plug is dropped to close the cement ports, preventing the newly
pumped cement from flowing back into the well fLvons and Pligsa. 20041: see Figure D-l.
Another less commonly used primary cementing technique is reverse circulation cementing. This
technique has been developed to decrease the force exerted on weak formations. In reverse
circulation cementing, the cement is pumped down the annulus directly between the outside of the
outermost casing and the formation. This essentially allows use of lower density cement and lower
pumping pressures. With reverse circulation cementing, greater care must be taken in calculating
the required cement, ensuring proper cement circulation, and locating the beginning and end of the
cemented portion.
Another method used to cement specific portions of the well without circulating cement along the
entire wellbore length is to use a cement basket. A cement basket is a device that attaches to the
well casing. It is made of flexible material such as canvas or rubber that can conform to the shape of
the wellbore. The cement basket acts as a one-way barrier to cement flow. Cement can be circulated
up the wellbore past the cement basket, but when circulation stops the basket prevents the cement
from falling back down the wellbore. Cement baskets can be used to isolate weak formations or
formations with voids. They can also be placed above large voids such as mines or caverns with
staged cementing used to cement the casing above the void.
If any deficiencies are identified, remedial cementing may be performed. The techniques available
to address deficiencies in the primary cement job including cement squeezes or top-job cementing.
A cement squeeze injects cement under high pressure to fill in voids or spaces in the primary
cement job caused by high pressure, failed formations, or improper removal of drilling mud.
Although cement squeezes can be used to fix deficiencies in the primary cement job, they require
the well to be perforated, which can weaken the well and make it susceptible to degradation by
pressure and temperature cycling as would occur during fracturing (Crescent. 2011). Another
method of secondary cementing is the top job. In a top job, cement is pumped down the annulus
directly to fill the remaining uncemented space when cement fails to circulate to the surface.
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Second-stage slurry
Second-stage flow path
Circulating ports
Cement collar
Opening bomb
First-stage slurry

First-stage flow path
Note: Figure not to scale
Figure D-l, A typical staged cementing process.
Two-Stage Cementing Process
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D.3. Well Completions
Completion refers to how the well is prepared for production and how flow is established between
the formation and the surface. Figure D-2 presents examples of well completion types, including
cased, formation packer, and open hole completion.
Ground Surface
Legend
Cement
Casing
Wellbore
Induced fracture
Cemented Casing
Completion
Fracture stage
Perforations
II
Formation Packer
Completion
Fracture stage
^ PI

TY\
" T p
Open Hole
Completion
Fracture stage
Uiil
Note: Not to scale. Conductor casing not sh own.
Figure D-2. Examples of well completion types.
Configurations shown include cased, formation packer, and open hole completion. From U.S. EPA (2015k).
A cased completion, where the casing extends to the end of the wellbore and is cemented in place,
is the most common configuration of the well in the production zone (U.S. EPA. 2015k).
Perforations are made through the casing and cement and into the formation using tools called
"perf guns" that deliver small explosive charges or other devices, such as sand jets. Hydraulic
fracturing then is conducted through the perforations. This is a common technique in wells that
produce from several different depths and in low-permeability formations that are fractured
fRenpu. 2011], While perforations do control the initiation point of the fracture, this can be a
disadvantage if the perforations are not properly aligned with the local stress field. If the
perforations are not aligned, the fractures will twist to align with the stress field, leading to
tortuosity in the fractures and making fluid movement through them more difficult fCramer. 20081.
Fracturing stages can be isolated from each other using various mechanisms such as plugs or baffle
rings, which close off a section of the well when a ball of the correct size is dropped down the well.
A packer is a mechanical device used to selectively seal off certain sections of the wellbore. Packers
can be used to seal the space between the tubing and casing, between two casings, or between the
production casing and formation. The packer has one or more rubber elements that can be
manipulated downhole to increase in diameter and make contact with the inner wall of the next-
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largest casing or the formation, effectively sealing the annulus created between the outside of the
tubing and the inside of the casing. Packers vary in how they are constructed and how they are set,
based on the downhole conditions in which they are used. There are two types of packers: internal
packers and formation packers. Internal packers are used to seal the space between the casing and
tubing or between two different casings. They prevent fluid movement into the annulus by isolating
the outer casing layers from produced or formation fluids. Formation packers seal the space
between the casing and the formation and are often used to isolate fracture stages; they can be used
to separate an open hole completion into separate fracture stages. Packers can seal an annulus by
several different mechanisms. Mechanical packers expand mechanically against the formation and
can exert a significant force on the formation fMcDaniel and Rispler. 20091. They are typically less
than 5 ft (1.5 m) long and can be used in wells with tighter doglegs fSenters etal.. 20161. Swellable
packers have elastomer sealing elements that swell when they come into contact with a triggering
fluid such as water or hydrocarbons. They exert less force on the formation and can seal larger
spaces but take some time to fully swell fMcDaniel and Rispler. 20091. Swellable packers are longer
and can be affected by thermal changes during fracturing. Cyclic stresses during fracturing can also
cause packer failure fSenters etal.. 20161. Internal mechanical integrity tests such as pressure tests
can verify that the packer is functioning as designed and has not corroded or deteriorated.
In an open hole completion, the production casing extends just into the production zone and the
entire length of the wellbore through the production zone is left uncased. This is only an option in
formations where the wellbore is stable enough to not collapse into the wellbore. In formations that
are unstable, a slotted liner may be used in open hole completions to control sand production
fRenpu. 20111. Perforations are not needed in an open hole completion, since the production zone
is not cased. An open hole completion can be fractured in a single stage or in multiple stages.
If formations are to be fractured in stages, additional completion methods are needed to separate
the stages from each other and control the location of the fractures. One possibility is use of a liner
with formation packers to isolate each stage. The liner is equipped with sliding sleeves that can be
opened by dropping balls down the casing to open each stage. Fracturing typically occurs from the
end of the well and continues toward the beginning of the production zone.
D.4. Mechanical Integrity Testing
While proper design and construction of the well's casing and cement are important, it is also
important to verify the well was constructed and is performing as designed. Mechanical integrity
tests (MITs) can verify that the well was constructed as planned and can detect damage to the
production well that occurs during operations, including hydraulic fracturing activities. Verifying
that a well has mechanical integrity can prevent potential impacts to drinking water resources or
loss of hydrocarbon products by providing early warning of a problem with the well or cement and
allowing repairs.
It is important to note that if a well fails an MIT, this does not mean the well has failed or that an
impact on drinking water resources has occurred. An MIT failure is a warning that one or more
components of the well are not performing as designed and is an indication that corrective actions
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are necessary. If well remediation is not performed, a loss of well integrity could occur, which could
result in fluid movement from the well.
D.4.1. Internal Mechanical Integrity
Internal mechanical integrity is an absence of significant leakage in the tubing, casing, or packers
within the well system. Loss of internal mechanical integrity is usually due to corrosion or
mechanical failure of the well's tubular and mechanical components.
Internal mechanical integrity can be tested by the use of pressure testing, annulus pressure
monitoring, ultrasonic monitoring, and casing inspection logs or caliper logs:
• Pressure testing involves raising the pressure in the wellbore to a set level and shutting
in the well. If the well has internal mechanical integrity, the pressure should remain
constant with only small changes due to temperature fluctuation. Typically, the well is
shut in (i.e., production is stopped and the wellhead valves closed) for a time prescribed by
regulation, and if the pressure remains within a given percent of the original reading, the
well is considered to have passed the test Usually, the well is pressure tested to the
maximum expected pressure; for a well to be used for hydraulic fracturing, this would be
the pressure applied during hydraulic fracturing. Performing a pressure test on each
casing before the next casing is drilled ensures the casing can withstand subsequent
stresses and allows repairs if necessary before problems can develop fCheremisinoff and
Davletshin. 20151. Pressure tests, however, can cause debonding of the cement from the
casing, so test length is often limited to reduce this effect (API. 2010a],
• If the annulus between the tubing and casing is sealed by a packer, annulus pressure
monitoring can give an indication of the integrity of the tubing and casing. If the tubing,
casing, and packer all have mechanical integrity, the pressure in the annulus should not
change except for small changes in response to temperature fluctuations. The annulus can
be filled with a non-corrosive liquid and the level of the liquid can be used as another
indication of the integrity of the casing, tubing, and packer. The advantage of monitoring
the tubing/production casing annulus is that it can give a continuous, real-time indication
of the internal integrity of the well. This is the only MIT test likely to detect problems
during normal well operations. Even if the annulus is not filled with a fluid, monitoring its
pressure can indicate leaks. If pressure builds up in the annulus and then recovers quickly
after having bled off, that condition is referred to as sustained casing pressure or surface
casing vent flow and is a sign of a leak in the tubing or casing (Watson and Bachu. 2009).
Monitoring of annuli between other sets of casings can also provide information on the
integrity of those casings. It can also provide information on external mechanical integrity
for annuli open to the formation (see Section D.4.2 for additional information on external
MITs). Tacksonetal. (2013b) also note that monitoring annular pressure allows the
operator to vent gas before it accumulates enough pressure to cause migration into
drinking water resources. Measuring annulus flow rate also allows detection of gas
flowing into the annulus fArthur. 20121.
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• A newer tool uses ultrasonic monitors to detect leaks in casing and other equipment It
measures the attenuation of an ultrasonic signal as it is transmitted through the wellbore.
The tool measures transmitted ultrasonic signals as it is lowered down the wellbore. The
tool can pick up ultrasonic signals created by a leak, similar to noise logs. The tool only has
a range of a few feet but is claimed to detect leaks as small as half a cup per minute (Julian
etal.. 20071.
• Caliper logs have mechanical fingers that extend from a central tool and measure the
distance from the center of the wellbore to the side of the casing. Running a caliper log can
identify areas where corrosion has altered the diameter of the casing or where holes have
formed in the casing. Caliper logs may also detect debris or obstructions in the well. Casing
inspection and caliper logs are primarily used to determine the condition of the casing.
Regular use of them may identify problems such as corrosion and allow mitigation before
they cause a loss of integrity to the casing. To run these logs in a producing well, the tubing
must first be pulled.
• Casing inspection logs are instruments lowered into the casing to inspect the casing for
signs of wear or corrosion. One type of casing log uses video equipment to detect
corrosion or holes. Another type uses electromagnetic pulses to detect variations in metal
thickness. Running these logs in a producing well requires the tubing to be pulled.
If an internal mechanical integrity problem is detected, the location of the problem must be found.
Caliper or casing inspection logs can detect locations of holes in casing. Locations of leaks can also
be detected by sealing off different sections of the well using packers and performing pressure tests
on each section until the faulty section is located. If the leaks are in the tubing or a packer, the
problem may be remedied by replacing the well component Casing leaks may be remedied by
performing a cement squeeze (Section D.2.2).
D.4.2. External Mechanical Integrity
External well mechanical integrity is demonstrated by establishing the absence of significant fluid
movement along the outside of the casing, either between the outer casing and cement or between
the cement and the wellbore. Failure of an external MIT can indicate improper cementing or
degradation of the cement emplaced in the annular space between the outside of the casing and the
wellbore. This type of failure can lead to movement of fluids out of intended production zones and
toward drinking water resources.
Several types of logs are available to evaluate external mechanical integrity, including temperature
logs, noise logs, oxygen activation logs, radioactive tracer logs, and cement evaluation logs.
• Temperature logs measure the temperature in the wellbore, and are capable of
measuring small changes in temperature. They can be performed using instruments that
are lowered down the well on a wireline, or they can be done using fiber optic sensors
permanently installed in the well. When performed immediately after cementing, they can
detect the heat from the cement setting and determine the location of the top of cement
After the cement has set, temperature logs can sense the difference in temperatures
D-15

-------
Appendix D - Well Injection Supplemental Information
between formation fluids and injected or produced fluids. They may also detect
temperature changes due to cooling or warming caused by flow. In this way, temperature
logs may detect movement of fluid outside the casing in the wellbore (Arthur. 20121.
Temperature logs require interpretation of the causes of temperature changes and are
therefore subject to varying results among different users.
• Noise logs are sensitive microphones that are lowered down the well on a wireline. They
are capable of detecting small noises caused by flowing fluids, such as fluids flowing
through channels in the cement fArthur. 20121. They are most effective at detecting fast-
moving gas leaks and less successful with more slowly moving liquid migration.
• Oxygen activation logs consist of a neutron source and one or more detectors that are
lowered on a wireline. The neutron source bombards oxygen molecules surrounding the
wellbore and converts them into unstable nitrogen molecules that rapidly decay back to
oxygen, emitting gamma radiation in the process. Gamma radiation detectors above or
below the neutron source measure how quickly the oxygen molecules are moving away
from the source, thereby determining flow associated with water.
• Radioactive tracer logs involve release of a radioactive tracer and then passing a
detector up or down the wellbore to measure the path the tracers have taken. They can be
used to determine if fluid is flowing up the wellbore. Tracer logs can be very sensitive but
may be limited in the range over which leaks can be detected.
• Cement evaluation logs (also known as cement bond logs) are acoustic logs consisting of
an instrument that sends out acoustic signals along with receivers, separated by some
distance, that record the acoustic signals. As the acoustic signals pass through the casing,
they will be attenuated to an extent, depending on whether the pipe is free or is bonded to
cement By analyzing the return acoustic signal, the degree of cement bonding with the
casing can be determined. The cement evaluation log measures the sound attenuation as
sound waves passing through the cement and casing. There are different types of cement
evaluation logs available. Some instruments can only return an average value over the
entire wellbore. Other instruments are capable of measuring the cement bond radially.
Newer acoustic logging techniques with features such as flexural attenuation and acoustic
impedance maps can identify channels as small as an inch (2.5 cm) in diameter fLandrv et
al.. 20151. Cement logs do not actually determine whether fluid movement through the
annulus is occurring. They only can determine whether cement is present in the annulus
and in some cases can give a qualitative assessment of the quality of the cement in the
annulus. Cement evaluation logs are used to calculate a bond index which varies between
0 and 1, with 1 representing the strongest bond and 0 representing the weakest bond. It
should be noted that these type of tests cannot detect whether or not fluid migration is
occurring. They only indicate whether cement is present and give a qualitative indication
of the degree of bonding of any cement present Because interpretation of these logs are
qualitative, there is also a great deal of subjectivity in their results.
If the well fails an external MIT, damaged or missing cement may be repaired using a cement
squeeze (Woitanowicz. 20081. A cement squeeze involves injection of cement slurry into voids
D-16

-------
Appendix D - Well Injection Supplemental Information
behind the casing or into permeable formations. Different types of cement squeezes are available
depending on the location of the void needing to be filled and well conditions fKirksev. 20131.
Cement squeezes are not always successful, however, and may need to be repeated to successfully
seal off flow fWoitanowicz. 20081.
D-17

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Appendix D - Well Injection Supplemental Information
This page is intentionally left blank.
D-18

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Appendix E - Produced Water Handling Supplemental Information
Appendix E. Produced Water Handling
Supplemental Information

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Appendix E - Produced Water Handling Supplemental Information
This page is intentionally left blank.
E-2

-------
Appendix E - Produced Water Handling Supplemental Information
Appendix E. Produced Water Handling Supplemental
Information
E.l. Specific Definitions of the Terms "Produced Water" and "Flowback"
Various organizations have used different definitions of the terms "produced water" and
"flowback." Several examples follow:
E.l.l. Produced Water
The American Petroleum Institute (API): "Produced water is any of the many types of water
produced from oil and gas wells" fAPI. 2010cl.
The U.S. Department of Energy (DOE): "Produced water is water trapped in underground
formations that is brought to the surface along with oil or gas" fVeil etal.. 20041.
The American Water Works Association (AWWA): "Produced water is the combination of flowback
and formation water that returns to the surface along with the oil and natural gas" (AWWA. 2013).
E.l.2. Flowback
API: "The fracture fluids that return to the surface after a hydraulic fracture is completed" (API.
2010c").
AWWA: "Fracturing fluids that return to the surface through the wellbore after hydraulic fracturing
is complete" (AWWA. 2013).
Other definitions include production of hydrocarbons from the well fBarbot etal.. 2013: U.S. EPA.
2012el. or specify a time period fUSGS. 2014: Haluszczak etal.. 2013: Warner etal.. 2013b: Hayes
and Severin. 2012a: Hayes. 2009).
E.2. Produced Water Volumes
The EPA fU.S. EPA. 2015ml estimates of flowback volumes and long-term produced water volumes
used to generate the summaries appearing in Table 7-3 of Chapter 7 appear below in Table E-l.
E-3

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-l. Produced water characteristics for wells by basin, formation, and resource type.
Source: U.S. EPA (2016b).
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
Anadarko
Caney
Shale
H
8.1
4.4 -12
11
-
-
0
-
-
0
Cleveland
Tight
H
1.7
0.2-4
928
-
12-40
2
410
59 - 2,000
1,160
V
0.18
0.033-3
15
50
50-50
1
66
56 - 400
130
Granite Wash
Tight
H
4.9
0.2-8.3
924
-
6.5-22
2
980
10 - 2,400
762
V
0.53
0.085-3
72
50
50-50
1
520
330 - 790
1,397
D
-
-
0
-
-
0
480
160 - 940
83
Mississippi
Lime
Tight
H
2
1.3-5
3,301
50
50-50
1
-
37,000 -
120,000
4
V
0.34
0.016 -
0.71
59
-
-
0
10
0.71-38
16
Woodford
Shale
H
5.2
1-12
3,243
34
20-50
3
5,500
3,200 -
6,400
198
V
0.36
0.015 -
1.6
11
-
-
0
-
-
0
D
1.6
0.21-
1.9
10
-
-
0
-
-
0
Clinton-
Medina
Tight
V
-
-
0
-
-
0
7.9
1
1
1
m
551
E-4

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
Appalachian
Devonian
Shale
V
-
-
0
-
-
0
13
4.8-19
197
Marcellus
Shale
H
4.6
0.9-11
17,316
7.1
4-47
4,374
820
54-
13,000
6,494
Shale
V
0.25
0.11-
5.4
116
40
21-60
7
200
94 -1,000
741
D
0.16
0.092 -
0.17
6
-
-
0
-
-
0
Utica
Shale
H
6.8
1-13
1,108
2.5
0.66-
27
684
800
420-
1,700
764
Arkoma
Fayetteville
Shale
H
5
1.7-11
3,014
-
10-20
2
430
150-
2,300
2,305
Denver-
Julesburg
Codell
Tight
H
3.5
2.4-7.1
234
16
-
36
400
110-
1,100
179
V
0.23
0.11-
0.46
97
0
0-4
13
59
47 -120
158
D
0.26
0.14-
0.5
362
0
0-3
8
46
18-71
667
Codell-
Niobrara
Tight
H
2.8
2.7-5.4
65
7.2
7.2-7.2
32
75
19 - 560
38
V
0.3
0.15-
0.4
490
2.8
-
21
33
13-65
2,113
D
0.4
0.2-
0.46
806
0
0-5
11
45
28-70
1,853
E-5

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
Denver
Julesburg,
cont.
Muddy J.
Tight
H
1.4
0.44-
2.6
6
-
-
0
860
220-
1,100
6
V
0.27
0.12-
0.45
139
0.09
-
15
120
52 - 550
340
D
0.42
0.17-
0.62
758
0
0-0
11
63
39 -110
1,106
Niobrara
Shale
H
2.9
1.9-5.1
1,435
16
1.8-
100
173
760
120-
1,300
1,213
V
0.24
0.015 -
0.31
455
33
1.6-90
29
330
15 - 600
5,808
D
0.36
0.13-
2.9
25
-
-
0
41
8.1-590
38
Fort Worth
Barnett
Shale
H
3.7
1-7.3
26,495
30
21-40
11
530
240-
4,200
11,957
V
1.3
0.38-
1.9
3,773
-
-
0
230
140 - 390
2,416
D
1.2
0.48-
1.6
96
-
-
0
210
79-410
481
Green River
Hilliard-
Baxter-
Mancos
Shale
H
1.7
1-5.6
2
-
-
0
-
-
0
Lance
Tight
H
-
-
0
-
-
0
730
350-
1,100
6
E-6

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
Green River,
cont.
Lance
Tight
V
1.5
0.82-
3.9
37
3.3
0.88-
50
38
610
410 - 840
61
D
.97
0.65-
2.1
881
12
1.8-40
187
650
420-
1,100
2,787
Mancos
Shale
H
15
1.8-24
24
3.1
0.063-
17
8
770
-
26
D
5.4
0.12-20
10
-
-
0
140
0.83-
1,400
36
Mesa verde
Tight
H
-
-
0
-
-
0
220
130 - 480
5
V
0.16
0.13-
0.22
21
18
6.3-43
15
440
120 - 780
33
D
0.19
0.11-
0.3
448
9.3
0.7-36
94
380
150-610
856
Illinois
New Albany
Shale
H
-
-
0
-
-
0
2,940
2,940 -
2,940
1
Michigan
Antrim
Shale
V
0.05
0.05-
0.05
1
-
25-75
2
1,300
530-
4,600
7
Permian
Avalon &
Bone Spring
Shale
H
2.3
1.2-5.7
965
19
4.9-40
48
2,700
2,100-
5,700
1,171
V
0.4
0.07-
1.3
21
-
-
0
2,000
1,000 -
4,800
68
D
1.8
1.2-3.4
40
33
12-57
36
1,300
800-
3,300
94
E-7

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
Permian,
cont.
Barnett-
Woodford
Shale
H
2.1
LO
1
LO
O
2
-
-
0
-
-
0
Delaware
Shale
H
1.3
0.42 - 3
85
79
9.7-
230
20
9,400
5,000 -
29,000
232
V
0.19
0.044 -
0.38
141
210
84 - 580
19
1,600
1,100-
3,800
412
D
0.26
0.15-
0.4
47
-
-
0
4,500
2,400 -
5,700
90
Devonian
(TX)
Shale
H
0.47
0.091-
5.5
43
-
-
0
1,700
630-
2,700
325

V
0.14
0.075-1
187
-
-
0
3,700
1,400 -
5,400
306
D
0.11
0.037 -
0.13
11
-
-
0
2,400
250-
12,000
40
Morrow
Tight
V
-
-
0
-
-
0
130
41-290
7
D
-
-
0
-
-
0
140
34 - 2,200
66
Spraberry
Tight
H
1.3
0.069 -
6.5
29
-
-
0
1,000
420-
3,800
41
V
0.91
0.071-
1.6
449
-
-
0
1,000
670-
1,500
936
D
1
0.06-
1.5
16
-
-
0
1,200
660-
2,500
42
E-8

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
Permian,
cont.
Trend Area
Tight
H
8.3
2.4-12
991
-
-
0
890
530-
3,900
457
V
1.1
0.58-
1.9
8,733
-
-
0
780
690 - 920
15,494
D
1
1
^|-
o
41
-
-
0
620
370-
1,500
50
Wolfcamp
Shale
H
6.7
1.4 -12
1,775
16
12-23
12
3,500
450-
15,000
1,237
V
1.6
0.18-
2.3
383
-
-
0
780
460-
1,400
1,142
D
1.8
0.17-3
12
-
-
0
1,700
750-
3,600
170
Piceance &
Uinta
Mesa verde
Tight
D
--
-
0
-
-
0
510
130 - 700
52
Hermosa
Shale
D
--
-
0
-
-
0
47
27 - 260
21
Powder River
Mowry
Shale
H
2.5
0.76-
7.4
15
15
4.3-
580
14
450
61-2,100
16
San Juan
Dakota
Tight
V
0.16
0.061-
0.34
85
1.6
-
22
75
35 - 490
81
D
0.12
0.063 -
0.32
136
4.1
o
ID
1
1
29
230
53 - 950
511
Mesa verde
Tight
V
--
-
0
-
-
0
43
14 - 560
5
D
--
-
0
-
-
0
21
15 -180
49
E-9

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
San Juan,
cont.
Pictured Cliffs
Tight
H
--
--
0
-
-
0
370
190 - 720
7
D
--
--
0
-
-
0
4,700
1,200 -
8,200
6
TX-LA-MS
Bossier
Shale
H
3.8
2.6-5.4
12
-
-
0
37
5.6-370
47
V
0.61
0.22-
1.7
82
-
-
0
230
4.8-480
1,143
D
0.55
0.18-
1.1
48
-
-
0
150
1.2 - 300
304
Cotton Valley
Tight
H
4.4
0.25-
8.5
433
60
60-60
1
710
410-
2,600
689
V
0.27
0.018-
1.4
355
60
60-60
1
700
490 - 890
9,267
D
0.45
0.046-4
79
60
60-60
1
620
240 - 980
1,912
Haynesville
Shale
H
5.7
0.95-15
3,855
5.2
5.2-30
3
910
84 -1,200
2,575
V
0.9
0.2-2.5
2
-
-
0
330
210-560
230
D
3.9
1.9-7.3
35
-
-
0
660
130-
1,200
204
Travis Peak
Tight
H
3
0.25-6
2
-
-
0
710
110-
4,200
7
V
0.17
0.032-4
36
-
-
0
630
270 - 930
1,046
D
--
-
0
-
-
0
520
140 - 800
134
E-10

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
TX-LA-MS,
cont.
Tuscaloosa
Shale
H
11
6.1-14
28
-
-
0
-
-
0
V
13
4.7 -19
11
-
-
0
7,400
220-
51,000
64
Western Gulf
Austin Chalk
Tight
H
1.7
0.83-
5.4
134
-
-
0
2,200
980-
5,100
752
V
--
-
0
-
-
0
97
21-1,500
51
Eagle Ford
Shale
H
4.8
1-14
12,810
4.2
00
1
1
rsj
1,800
1,900
88 - 6,200
7,971
V
0.94
0.23-2
8
-
-
0
1,200
510-
2,300
12
D
--
-
0
-
-
0
4,300
3,000 -
5,600
5
Edwards
Tight
H
--
-
0
-
-
0
2,300
1,000 -
24,000
266
V
--
-
0
-
-
0
560
150-
2,100
32
D
--
-
0
-
-
0
160
69 - 290
6
Olmos
Tight
H
1.9
0.37-6
246
-
-
0
180
13 - 700
229
V
0.11
0.078-
0.21
50
-
-
0
78
52 - 370
1,120
D
--
-
-
-
-
0
51
15 - 470
16
Pearsall
Shale
H
3.5
ID
LO
1
UD
47
-
-
0
160
53 -1,500
51
E-ll

-------
Appendix E - Produced Water Handling Supplemental Information
Basin
Formation
Resource
type
Well type
Fracturing fluid
(Mgal)
Flowback (% of fracturing
fluid returned)
Long-term produced
water rates (gpd)
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Rangeb
Data
points0
Weighted
average3
Range3
Data
points0
Western
Gulf, cont.
Vicksburg
Tight
V
0.21
0.072 -
0.61
158
-
-
0
700
330 - 990
702
D
0.23
0.11-
0.63
40
-
-
0
830
390-
1,400
193
Wilcox Lobo
Tight
H
0.33
0.082 -
2.4
8
-
-
0
370
250-610
84
V
0.1
0.042 -
0.6
56
-
-
0
650
400 - 940
1,084
D
0.094
0.058-
0.16
14
-
-
0
500
300-
4,200
395
Williston
Bakken
Shale
H
2.4
0.35-10
8,103
19
5-47
225
910
500-
3,800
7,309
V
0.16
0.04-
2.7
6
-
-
0
2,400
150-
5,100
5
indicates no data; H, horizontal well; D, directional well; V, vertical well.
a For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a median value.
b For some formations, the number of data points was not reported in the data source. In these instances, the EPA reported the number of data points as equal to one, even if
the source reported a range and median value.
c For some formations, the number of data points was not reported in the data source. In these instances, this table reports that number as 1, except if the source reported a
range in which case this table reports the number of data points as 2.
E-12

-------
Appendix E - Produced Water Handling Supplemental Information
E.2.1. Summary of Results from Produced Water Studies
Data were collected from six vertical and eight horizontal wells in the Marcellus Shale of
Pennsylvania and West Virginia fHaves. 20091. The author collected samples of flowback after one,
five, and 14 days after hydraulic fracturing was completed, as well as a produced water sample 90
days after completion of the wells. Both the vertical and horizontal wells showed their largest
volume of flowback between one and five days after fracturing as shown in Figure E-l.
MSC Study FB volumes (Vertical Wells)
5 0.4
1
0.9
0.8
—A Vertical
-B Vertical
-H Vertical
- N Vertical
-Q Vertical
-S Vertical
20
80
40	60
Time (days)
MSC Study FB volumes (Horizontal Wells)
100
V 0.4
0
—C Horizontal
—D Horizontal
—E Horizontal
—F Horizontal
—G Horizontal
—K Horizontal
-M Horizontal
—O Horizontal
20
80
100
40	60
Time (days)
Figure E-l. Fraction of injected hydraulic fracturing fluid recovered from six vertical (top) and
eight horizontal (bottom) wells completed in the Marcellus Shale.
Data used with permission from Haves (2009).
E-13

-------
Appendix E - Produced Water Handling Supplemental Information
The wells continued to produce water, and at 90 days, samples were available from four each of the
horizontal and vertical wells. The vertical wells produced on average 7,600 gal/day (29,000 L/day)
and the horizontal wells a similar 8,400 gal/day (32,000 L/day). Results from one Marcellus Shale
study were fitted to a power curve (Ziemkiewicz etal.. 20141 (Figure E-2). These and the Hayes
f20091 data show decreasing rates of flowback with time. In West Virginia, water recovered at the
surface within 30 days following injection or before 50% of the hydraulic fracturing fluid volume is
returned to the surface is reported as flowback. Data from wells in the Marcellus Shale in West
Virginia (Hansen et al.. 20131 reveal the variability of recovery from wells in the same formation
and that the amount of hydraulic fracturing fluid recovered was estimated to be less than 15% from
over 80% of the wells (Figure E-3).
60
bO
40
>-
™ 30
T3
ro
E
20
10
0
Figure E-2. Example of flowback and produced water from the Marcellus Shale, illustrating
rapid decline in water production and cumulative return of approximately 30% of the volume
of hydraulic fracturing fluid.
Source: Ziemkiewicz et al. (2014). Ziemkiewicz, P; Quaranta, JD; McCawley, M. (2014). Practical measures for
reducing the risk of environmental contamination in shale energy production. Environ. Sci.: Processes & Impacts
16:1692-1699. Reproduced with permission from The Royal Society of Chemistry.
http://dx.doi.org/10.1039/C3EM0051QK.
35%
v = 0-Q82X0'2*36
R2 =0.9882
30%
25%
20%
15%
10%
5%
0%
v = lo.oeax^667
R2 = 0.9207
amil III III III III HHiunriTTTTrrr
Month after Initial frac
~ flowback/produced water o % flowback
E-14

-------
Appendix E - Produced Water Handling Supplemental Information
40
% •%	i% *?% <5% %j
Percent recovered
Figure E-3. Percent of hydraulic fracturing fluid recovered for Marcellus Shale wells in West
Virginia (2010 - 2012).
One data point showing 98% recovery omitted. Source: Hansen et al. (2013). Reprinted with permission from
Downstream Strategies, San Jose State University, and Earthworks Oil & Gas Accountability Project.
Nicotetal. (20141 show a counter-example where the produced water exceeded the amount of
hydraulic fracturing fluid injected. When the produced water data were presented as the
percentage of hydraulic fracturing fluid, the median exceeded 100% at around 36 months (Figure
E-4 and Figure E-5). This means that roughly 50% of the wells were producing more water than
was used in stimulating production. Nicotetal. (20141 did not identify the source or mechanism for
the excess water. Systematic breaching of the underlying karstic Ellenburger Formation was not
believed likely; nor was operator efficiency or skill. A number of geologic factors that could impact
water migration were identified by DOE f20111 in the Barnett Shale, including fracture height,
aperture size, and density, fracture mineralization, the presence of karst chimneys underlying parts
of the Barnett Shale, and others, but the impact of these on water migration was not determined.
E-15

-------
Appendix E - Produced Water Handling Supplemental Information
20,000
£. 15,000
t_
0
1
GL
¦C
C
9
5
10.000
5000
Wells
12.000
10.000
8000
6000
4000
2000
Months
Figure E-4. Barnett Shale monthly water-production percentiles (5th, 30th, 50th, 70th, and 90th)
and number of wells with data (dashed line).
FP is the amount of water that flows back to the surface, commingled with water from the formation. Reprinted
with permission from Nicot, JP; Scanlon, BR; Reedy, RC; Costley, RA. (2014). Source and fate of hydraulic fracturing
water in the Barnett Shale: A historical perspective [Supplemental Information]. Environ Sci Technol 48: 2464-
2471. Copyright 2014 American Chemical Society.
200 -rzz
12.000
10,000
s 150 -
£ 100 -
90 %
Wells
i	1	1	r
0 12 24 36 48 60 72
w
7D
£
CD
•*—i
c
o
N
'i—
o
sz
u_
o
q3
jd
E
u
Months
Figure E-5. Barnett Shale production data for approximately 72 months.
Flowback and produced water are reported as the percentage of hydraulic fracturing fluid. The dashed line shows
the number of horizontal wells included. Data for each percentile show declining production with time, but the
median production exceeds 100% of the hydraulic fracturing fluid. FP is the amount of water that flows back to the
surface, commingled with water from the formation. Reprinted with permission from Nicot, JP; Scanlon, BR;
Reedy, RC; Costley, RA. (2014). Source and fate of hydraulic fracturing water in the Barnett Shale: A historical
perspective. Environ Sci Technol 48: 2464-2471. Copyright 2014 American Chemical Society.
E-16

-------
Appendix E - Produced Water Handling Supplemental Information
E.3. Chemical Content of Produced Water
In the main text of Chapter 7, we describe aspects of flowback and produced water composition,
including temporal changes in water quality parameters of flowback (Section 7.3.3) and major
classes of compounds in produced water (Section 7.3.4). In Section 7.3.4.2, we describe variability
as occurring on three levels: between different rock types (e.g., coal vs. sandstone), between
formations composed of the same rock types (e.g., Barnett Shale vs. Bakken Shale), and within
formations of the same rock type (e.g., northeastern vs. southwestern Marcellus Shale). In this
appendix, we present data from the literature that illustrate the differences among these three.
E.3.1. General Water Quality Parameters
As noted in Section 7.3.4.3, the EPA identified data characterizing the content of flowback and
produced water from unconventional reservoirs including 12 shale and tight formations and
coalbed methane (CBM) basins. These formations and basins span 18 states. Note that in this
subsection we treat all fluids as produced water. As a consequence, the variability of reported
concentrations is likely higher than if the data could be standardized to a specific point on the
flowback-to-produced water continuum. Table E-2 and Table E-3 provide supporting data on
general water quality parameters of produced water in shale, tight formations, and coal seams for
12 formations.
E-17

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-2. Reported concentrations of general water quality parameters in produced water for unconventional shale and tight
formations, presented as: average (minimum-maximum) or median (minimum-maximum).
Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians.
Parameter
Units
Shales
Tight formations
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley
Group'
Devonian
Sandstoneg
Mesaverde'
Oswego'
States
n/a
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT, WY
OK
Acidity
mg/L
-
NC
(ND-ND)
-
NC
(<5 - 473)
162
(5-925)
-
-
-
-
Alkalinity
mg/L
-
725
(215 -
1,240)
1,347
(811-1,896)
165
(8-577)
99.8
(7.5-577)
-
99
(43 -194)
-
582
(207 -
1,220)
Ammonium
mg/L
-
-
-
-
-
89
(40-131)
-
-
-
Bicarbonate
mg/L
291 (122
-610)
-
-
-
-
-
524 (ND-
8,440)
2,230 (1,281 -
13,650)
-
Biochemical
oxygen
demand (BOD)
mg/L
-
582
(101 -
2,120)
-
-
141
(2.8-
12,400)
-
-
-
-
Carbonate
mg/L
-
-
-
-
-
-
-
227
(ND-1,680)
-
Chloride
mg/L
119,000
(90,000 -
133,000)
34,700
(9,600 -
60,800)
9,156
(5,507 -
12,287)
57,447
(64 —
196,000)
49,000
(64.2-
196,000)
101,332
(3,167 —
221,498.7)
132,567
(58,900 -
207,000)
4,260
(8 - 75,000)
44,567
(23,000 -
75,000)
Chemical
oxygen
demand
mg/L
-
2,945
(927 -
3,150)
-
15,358
(195 -
36,600)
4,670
(195 -
36,600)
-
-
-
-
E-18

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Units
Shales
Tight formations
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley
Group'
Devonian
Sandstoneg
Mesaverdef
Oswego'
States
n/a
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT, WY
OK
DO
mg/L
-
-
-
-
-
-
0.8
(0.2-2.5)
-
-
DOC
mg/L
-
11.2
(5.5-65.3)
-
-
117
(3.3-5,960)
-
-
-
-
Hardness as
CaC03
mg/L
-
5,800
(3,500 -
21,000)
-
34,000
(630 -
95,000)
25,000
(156 -
106,000)
-
-
-
-
Oil and grease
mg/L
-
163.5
(88.2-
1,430)
-
74
(5 - 802)
16.85
(4.7 - 802)
-
-
-
-
PH
U
5.87 (5.47
-6.53)
7.05
(6.5-7.2)
-
6.6
(5.1-8.4)
6.5
(4.9-7.9)
-
6.3
(5.5-6.8)
8
(5.8-11.62)
6.3
(6.1-6.4)
Specific
conductivity
US/cm
213,000
(205,000
220,800)
111,500
(34,800 -
179,000)
-
-
183,000
(479 -
763,000)
-
184,800
(118,000-
211,000)
-
-
Specific gravity
--
1.13
(1.0961-
1.155)
-
-
-
-
-
-
-
-
TDS
mg/L
196,000
(150,000
219,000)
50,550
(16,400-
97,800)
13,290
(9,972 -
15,721)
106,390
(680-
345,000)
87,800
(680-
345,000)
164,683
(5,241-
356,666)
235,125
(106,000-
354,000)
15,802
(1,032 -125,304)
73,082
(56,541-
108,813)
E-19

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Units
Shales
Tight formations
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley
Group'
Devonian
Sandstoneg
Mesaverde'
Oswego'
States
n/a
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT, WY
OK
Total Kjeldahl
nitrogen
mg/L
-
171
(26-298)
-
-
94.9
(5.6-312)
-
-
-
-
TOC
mg/L
-
9.75
(6.2-36.2)
-
160
(1.2-
1,530)
89.2
(1.2-5,680)
198
(184-212)
-
-
-
Total
suspended
solids
mg/L
-
242
(120-535)
-
352
(4 - 7,600)
127
(6.8-3,220)
-
-
-
-
Turbidity
NTU
-
239
(144-314)
-
-
126
(2.3-1,540)
-
-
-
-
n/a, not applicable; no value available; NC, not calculated; ND, not detected; SU= standard units; boldeditalic numbers are medians
a Stepan et al. (2010). n = 3. Concentrations were calculated based on Stepan et al.'s raw data. Samples had charge balance errors of 1.74, -0.752, and -0.220%
b Haves and Severin (2012a). n = 16. This data source reported concentrations without direct presentation of raw data.
c Warner et al. (2013a).c n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included.
d Barbot et al. (2013). n = 134 - 159. This data source reported concentrations without direct presentation of raw data.
e Haves (2009). n = 31 --67. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks
omitted.
f Blondes et al. (2014). Cotton Valley Group, n=2; Mesa Verde, n = 1 - 407; Oswego, n = 4-30. Concentrations were calculated based on raw data presented in the U.S.
Geological Survey (USGS) National Produced Water Database v2.0.
sDresel and Rose (2010). n = 3 - 15. Concentrations were calculated based on Dresel and Rose's raw data.
E-20

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-3. Reported concentrations of general water quality parameters in produced water
for coalbed basins, presented as: average (minimum-maximum).	
Parameter
Units
Black Warrior3
Powder Riverb
Ratonb
San Juanb
States
n/a
AL, MS
MT, WY
CO, NM
AZ, CO, NM, UT
Alkalinity
mg/L
355 (3 -1,600)
1,384 (653-2,672)
1,107 (130-2,160)
3,181(51-11,400)
Ammonium
mg/L
3.60 (0.16-8.91)
-
-
-
Bicarbonate
mg/L
427 (2-1,922)
1,080 (236 - 3,080)
1,124(127-2,640)
3,380 (117 -13,900)
Carbonate
mg/L
3 (0 - 64)
2.17 (0.00-139.0)
51.30 (1.30-
316.33)
40.17 (0.00-1,178)
Chloride
mg/L
9,078 (11-42,800)
21 (BDL-282)
787 (4.8-8,310)
624 (BDL-20,100)
Chemical oxygen
demand
mg/L
830 (0 -10,500)
-
-
-
Dissolved oxygen
mg/L
-
1.07 (0.11-3.48)
0.39 (0.01-3.52)
0.51(0.04-1.69)
DOC
mg/L
3.37 (0.53-61.41)
3.18(1.09-8.04)
1.26 (0.30-8.54)
3.21(0.89-11.41)
Hardness as
CaCC>3
mg/L
871(3-6,150)
-
-
-
Hydrogen sulfide
mg/L
-
-
4.41 (BDL-190.0)
23.00
(23.00-23.00)
Oil and grease
mg/L
-
-
9.10 (0.60-17.6)
-
PH
SU
7.5 (5.3-9.0)
7.71(6.86-9.16)
8.19 (6.90-9.31)
7.82 (5.40-9.26)
Phosphate
mg/L
0.435 (0.026 -
3.570)
BDL (BDL-BDL)
0.04 (BDL-1.00)
1.89 (BDL-9.42)
Specific
conductivity
US/cm
20,631
(718-97,700)
1,598
(413 - 4,420)
3,199
(742 -11,550)
5,308
(232 -18,066)
TDS
mg/L
14,319
(589-61,733)
997
(252-2,768)
2,512
(244 -14,800)
4,693
(150-39,260)
Total Kjeldahl
nitrogen
mg/L
6.08 (0.15-38.40)
0.48 (BDL-4.70)
2.61 (BDL-26.10)
0.46 (BDL-3.76)
TOC
mg/L
6.03 (0.00 -103.00)
3.52 (2.07-6.57)
1.74 (0.25-13.00)
2.91 (0.95-9.36)
Total suspended
solids
mg/L
78 (0 - 2,290)
11.0 (1.4-72.7)
32.3 (1.0-580.0)
47.2 (1.4-236.0)
Turbidity
NTU
74 (0 - 539)
8.2 (0.7-57.0)
4.5 (0.3-25.0)
61.6 (0.8-810.0)
n/a, not applicable; no value available; BDL, below detection limit.
a DOE (2014). n = 206. Concentrations were calculated based on raw data presented in the reference.
b Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without
presentation of raw data.
E-21

-------
Appendix E - Produced Water Handling Supplemental Information
E.3.2. Salinity and Inorganics
Table E-4 and Table E-5 provide supporting data on salinity and inorganic constituents of produced
water for 12 formations.
E.3.2.1. Processes Controlling Salinity and Inorganics Concentrations
Multiple mechanisms likely control elevated salt concentrations in flowback and produced water
and are largely dependent upon post-injection fluid interactions and the formation's stratigraphic
and hydrogeologic environment fBarbotetal.. 20131. High inorganic ionic loads observed in
flowback and produced water are expressed as TDS.
Subsurface brines or formation waters are saline fluids associated with the targeted formation.
Shale and sandstone brines are typically much more saline than coalbed waters. After hydraulic
fracturing fluids are injected into the subsurface, the hydraulic fracturing fluids (which are typically
not sources of high TDS) contact in-situ brines, which typically contain high ionic loads (Haluszczak
etal.. 20131.
Deep brines, present in over- or underlying strata, may naturally migrate into targeted formations
over geologic time or artificially intrude if a saline aquifer is breached during hydraulic fracturing
(Chapman etal.. 2012: Maxwell. 2011: Blauch etal.. 20091. Whether it is through natural or induced
intrusion, saline fluids may contact the producing formation and introduce novel salinity sources to
the produced water (Chapman et al.. 20121. Despite the general use of fresh water for hydraulic
fracturing fluid, some elevated salts in produced water may result from the use of reused saline
flowback or produced water as a hydraulic fracturing base fluid fHaves. 20091.
E-22

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-4. Reported concentrations (mg/L) of inorganic constituents contributing to salinity in produced water from
unconventional reservoirs (including shale and tight formations), presented as: average (minimum-maximum) or median
(minimum-maximum).
Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians.
Parameter
Shale
Tight Formations
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley
Group'
Devonian
Sandstoneg
Mesaverdef
Oswego'
States
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT,
WY
OK
Bromide
-
589
(117-798)
ill
(96 -144)
511 (0.2-
1,990)
512
(15.8-1,990)
498
(32-1,338)
1,048
(349 -1,350)
-
-
Calcium
9,680 (7,540
-13,500)
1,600 (1,110 -
6,730)
317
(221-386)
7,220 (38 -
41,000)
7,465
(173 - 33,000)
19,998 (181 -
51,400)
20,262 (8,930
- 34,400)
212
(1.01-4,580)
5,903 (3,609 -
8,662)
Chloride
119,000
(90,000 -
133,000)
34,700 (9,600
- 60,800)
9,156 (5,507 -
12,287)
57,447
(64 —
196,000)
49,000
(64.2-
196,000)
101,332
(3,167 —
221,498.7)
132,567
(58,900 -
207,000)
4,260
(8 - 75,000)
44,567 (23,000 -
75,000)
Fluoride
-
3.8
(3.5-12.8)
-
-
0.975
(0.077-32.9)
-
-
-
-
Iodine
-
-
-
-
-
20
(1-36)
39
(11-56)
1.01
(1.01-1.01)
-
Nitrate as N
-
-
NC
(ND-ND)
-
1.7
(0.65-15.9)
-
-
0.6
(0.6-0.6)
-
Nitrite as N
-
4.7
(3.5-38.1)
-
-
11.8
(1.1-146)
-
-
-
-
Phosphorus
NC
(ND - 0.03)
0.395
(0.19-0.7)
-
-
0.3(0.08-
21.8)
-
-
-
-
Potassium
2,970
(0 - 5,770)
316
(80 - 750)
-
-
337
(38-3,950)
1,975
(8-7,099)
858
(126-3,890)
160
(4-2,621)
-
E-23

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Shale
Tight Formations
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley
Group'
Devonian
Sandstoneg
Mesaverdef
Oswego'
States
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT,
WY
OK
Silica
7
(6.41-7)
-
52
(13 -160)
-
-
4
(4-4)
-
-
-
Sodium
61,500
(47,100-
74,600)
18,850 (4,370
- 28,200)
3,758 (3,152 -
4,607)
21,123
(69-
117,000)
21,650
(63.8-95,500)
39,836 (1,320
-85,623.24)
58,160
(24,400 -
83,300)
5,828 (132 -
48,817)
19,460(13,484-
31,328)
Sulfate
660
(300 -1,000)
709
(120 -1,260)
NC
(ND - 3)
71
(0-763)
58.9
(2.4-348)
407
(ND-
2,200.46)
20
(1-140)
837
(ND-14,612)
183
(120-271)
Sulfide
-
NC
(ND-ND)
-
-
3.2
(1.6-5.6)
-
0.7
(0.1-2.5)
-
-
Sulfite
-
-
-
-
12.4
(5.2-73.6)
-
-
-
-
TDS
196,000
(150,000 -
219,000)
50,550
(16,400-
97,800)
13,290
(9,972 -
15,721)
106,390
(680-
345,000)
87,800
(680-
345,000)
164,683
(5,241-
356,666)
235,125
(106,000-
354,000)
15,802
(1,032 -
125,304)
73,082
(56,541-
108,813)
-, no value available; NC, not calculated; ND, not detected. Bolded italic numbers are medians.
aStepan et al. (2010). n = 3. Concentrations were calculated based on Stepan et al.'s raw data. Samples had charge balance errors of 1.74, -0.752, and -0.220%
b Haves and Severin (2012a). n = 16. This data source reported concentrations without presentation of raw data.
cWarner et al. (2013b). n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included.
d Barbot et al. (2013). n = 95 - 159. This data source reported concentrations without presentation of raw data.
e Haves (2009). n = 8-65. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks
omitted.
f Blondes et al. (2014) Cotton Valley Group, n = 2; Mesa Verde, n = 1 - 407; Oswego, n = 4 - 30. Concentrations were calculated based on raw data presented in the USGS
National Produced Water Database v2.0.
eDresel and Rose (2010). n = 3 - 15. Concentrations were calculated based on Dresel and Rose's raw data.
E-24

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-5. Reported concentrations (mg/L) of inorganic constituents contributing to salinity
in produced water for coalbed methane basins, presented as: average (minimum-maximum).
Parameter
Black Warrior3
Powder Riverb
Ratonb
San Juanb
State
AL, MS
MT, WY
CO, NM
AZ, CO, NM, UT
Barium
45.540 (0.136-352)
0.61(0.14-2.47)
1.67 (BDL-27.40)
10.80 (BDL-74.0)
Boron
0.185 (0-0.541)
0.17 (BDL-0.39)
0.36 (BDL-4.70)
1.30 (0.21-3.45)
Bromide
-
0.09 (BDL-0.26)
4.86 (0.04-69.60)
9.77 (BDL-43.48)
Calcium
218 (0-1,640)
32.09 (2.00-154.0)
14.47 (0.81-269.0)
53.29 (1.00-5,530)
Chloride
9,078(11-42,800)
21 (BDL-282)
787 (4.8-8,310)
624 (BDL-20,100)
Fluoride
6.13 (0.00-22.60)
1.57 (0.40-4.00)
4.27 (0.59-20.00)
1.76 (0.58-10.00)
Magnesium
68.12 (0.18-414.00)
14.66 (BDL-95.00)
3.31(0.10-56.10)
15.45 (BDL-511.0)
Nitrate
8.70 (0.00-127.50)
-
-
-
Nitrite
0.03 (0.00-2.08)
-
-
-
Phosphorus
0.32 (0.00-5.76)
-
-
-
Potassium
12.02 (0.46-74.00)
11.95 (BDL-44.00)
6.37 (BDL-29.40)
26.99 (BDL-970.0)
Silica
8.66 (1.04-18.10)
6.46 (4.40-12.79)
7.05 (4.86-10.56)
12.37 (3.62-37.75)
Sodium
4,353 (126 -16,700)
356 (12 -1,170)
989 (95 - 5,260)
1,610 (36-7,834)
Strontium
11.354 (0.015 -142.000)
0.60 (0.10-1.83)
5.87 (BDL-47.90)
5.36 (BDL-27.00)
Sulfate
5.83 (0.00-302.00)
5.64 (BDL-300.0)
14.75 (BDL-253.00)
25.73 (BDL-1,800)
TDS
14,319 (589-61,733)
997 (252-2,768)
2,512 (244-14,800)
4,693 (150-39,260)
no value available; BDL, below detection limit.
3 DOE (2014). n = 206. Concentrations were calculated based on the authors' raw data.
b Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without
presentation of raw data.
E.3.3. Metals and Metalloids
Table E-6 and Table E-7 provide supporting data on metal constituents of produced water for 12
formations.
E.3.3.1. Processes Controlling Mineral Precipitation and Dissolution
Hydraulic fracturing treatments introduce fluids into the subsurface that are not in equilibrium
with respect to formation mineralogy. Subsurface geochemical equilibrium modeling and
saturation indices are therefore used to assess the solution chemistry of produced water from
unconventional reservoirs and the subsequent likelihood of precipitation and dissolution reactions
fEngle and Rowan. 2014: Barbot etal.. 20131. Dissolution and precipitation reactions between
E-25

-------
Appendix E - Produced Water Handling Supplemental Information
fracturing fluids, formation solids, and formation water contribute to the chemistry of flowback and
produced water.
Depending upon the formation chemistry and composition of the hydraulic fracturing fluid, the
hydraulic fracturing fluid may initially have a lower ionic strength than existing formation fluids.
Consequently, salts, carbonate, sulfate, and silicate minerals may undergo dissolution or
precipitation. Proppants may also undergo dissolution or serve as nucleation sites for precipitation
(McLin etal.. 20111.
Currently, relatively little literature quantitatively explores subsurface dissolution and
precipitation reactions between hydraulic fracturing fluids and formation solids and water.
However, the processes that take place will likely be a function of the solubilities of the minerals,
the chemistry of the fluid, pH, redox conditions, and temperature.
Documented dissolution processes in unconventional reservoirs include the dissolution of feldspar
followed by sodium enrichment in coalbed produced water (Rice etal.. 20081. Dissolution of
barium-rich minerals (barite (BaSCU) and witherite (BaCOs)), and strontium-rich minerals (celestite
(SrSCU) and strontianite (SrCO;j}} are known to enrich shale produced waters in barium and
strontium fChapman et al.. 2 0121.
Known precipitation processes in unconventional reservoirs include the precipitation of carbonate
and subsequent reduction of calcium and magnesium concentrations in coalbed produced water
fRice etal.. 20081. Additionally, calcium carbonate precipitation is suspected to cause declines in pH
and alkalinity levels in shale produced water (Barbot etal.. 20131.
The subsurface processes associated with fluid-rock interactions take place over a scale of weeks to
months through the generation of flowback and produced water. Note that the types and extent of
subsurface dissolution and precipitation reactions change with time, from injection through
flowback and production. For instance, Engle and Rowan (20141 found that early Marcellus Shale
flowback was under-saturated with respect to gypsum (CaSO^FhO), halite (NaCl), celestite,
strontianite, and witherite, indicating that these minerals would dissolve in the subsurface. Fluids
were oversaturated with respect to barite. Saturation indices for gypsum, halite, celestite, and
barite all increased during production. Knowing when dissolution and precipitation will likely
occur is important, because dissolution and precipitation of minerals change formation
permeability and porosity, which can affect production (Andre etal.. 20061.
E-26

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-6. Reported concentrations (mg/L) of metals and metalloids from produced water from unconventional reservoirs
(including shale and tight formations), presented as: average (minimum-maximum) or median (minimum-maximum).
Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians. Note
that calcium, potassium, and sodium appear in Table E-4.
Parameter
Shale
Tight Formation
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley Group'
Devonian
Sandstoneg
Mesaverde'
Oswego'
States
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT,
WY
OK
Aluminum
-
0.43 (0.37-
2.21)
-
-
2.57
(0.22-47.2)
-
-
-
-
Antimony
-
NC
(ND-ND)
-
-
0.028
(0.018-
0.038)
-
-
-
-
Arsenic
-
NC
(ND-ND)
-
-
0.101
(0.013 -
0.124)
-
-
-
-
Barium
10
(0 - 24.6)
3.6 (0.93 -
17.9)
4
(3-5)
2,224 (0.24
-13,800)
542.5
(2.590-
13,900)
160 (ND-
400.52)
1,488 (7 -
4,370)
139
(4-257)

Beryllium
-
NC (ND-ND)
-
-
-
-
-
-
-
Boron
116
(39.9-192)
30.3 (7.0 -
31.9)
4.800
(2.395-
21.102)
-
12.2
(0.808-145)
37
(2 -100)
-
10
(1-14.2)
-
Cadmium
-
NC
(ND-ND)
-
-
-
-
-
-
-
Chromium
-
0.03 (0.01 -
0.12)
-
-
0.079
(0.011-
0.567)
-
-
-
-
Cobalt
-
0.01 (0.01-
0.01)
-
-
-
-
-
-
-
E-27

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Shale
Tight Formation
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley Group'
Devonian
Sandstoneg
Mesaverde'
Oswego'
States
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT,
WY
OK
Copper
NC
(ND - 0.21)
0.29 (0.06 -
0.52)
-
-
0.506
(0.253 -
4.150)
0.7
(0.48 -1)
0.04 (0.01-
0.13)
-
-
Iron
96
(ND -120)
24.9 (12.1-
93.8)
7
(1-13)
-
53.65
(2.68-574)
-
188
(90-458)
9
(1-29)
61
(41-78)
Lead
-
0.02 (0.01 -
0.02)
-
-
0.066
(0.003 -
0.970)
-
0.02 (0.01-
0.04)
-
-
Lithium
-
19.0 (2.56-
37.4)
9.825
(2.777-
28.145)
-
53.85
(3.410-323)
23
(1-53)
97.8(20.2-
315)
3
(1-33)
-
Magnesium
1,270 (630 -
1,750)
255
(149-755)
61
(47-75)
632
(17-2,550)
678
(40.8-2,020)
1,363 (27 -
3,712.98)
2,334 (797 -
3,140)
74
(1-2,394)
753
(486 -
1,264)
Manganese
7
(4-10.2)
0.86 (0.25-
2.20)
2
(2-3)
-
2.825
(0.369 -
18.600)
30.33 (30.33-
30.33)
19
(5.6-68)
-
-
Mercury
-
NC
(ND-ND)
-
-
0.00024
-
-
-
-
Molybdenum
NC
(ND - <0.2)
0.02 (0.02 -
0.03)
-
-
-
-
-
-
-
Nickel
-
0.04 (0.03 -
0.05)
-

0.419
(0.068 -
0.769)
-
-
-
-
Selenium
-
0.03 (0.03 -
0.04)
-
-
0.004
-
-
-
-
E-28

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Shale
Tight Formation
Bakken3
Barnettb
Fayetteville0
Marcellus
Cotton
Valley Group'
Devonian
Sandstoneg
Mesaverdef
Oswego'
States
MT, ND
TX
AR
PAd
PA, WVe
LA, TX
PA
CO, NM, UT,
WY
OK
Silver
-
-
-
-
4
(3-6)
-
-
-
-
Strontium
764
(518-1,010)
529 (48 -
1,550)
27
(14-49)
1,695 (0.6 -
8,460)
1,240
(0.580-
8,020)
2,312 (39 -
9,770)
3,890 (404 -
13,100)
-
-
Thallium
-
NC
(ND - 0.14)
-
-
0.168
-
-
-
-
Tin
-
NC
(ND-ND)
-
-
-
-
-
-
-
Titanium
-
0.02 (0.02 -
0.03)
-
-
-
-
-
-
-
Zinc
7
(2-11.3)
0.15 (0.10-
0.36)
-
-
0.391
(0.087 - 247)
-
0.20 (0.03-
1.26)
-
-
no value available; NC, not calculated; ND, not detected; BDL, below detection limit. Bolded italic numbers are medians.
aStepan et al. (2010). n = 3. Concentrations were calculated based on Stepan et al.'s raw data.
b Haves and Severin (2012a). n = 16. This data source reported concentrations without presentation of raw data.
cWarner et al. (2013a). n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included.
d Barbot et al. (2013). n = 151 - 159. This data source reported concentrations without presentation of data.
e Haves (2009). n = 48. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks omitted.
f Blondes et al. (2014). Cotton Valley Group, n = 2; Mesa Verde, n = 1 - 407; Oswego, n = 4 - 30. Concentrations were calculated based on raw data presented in the USGS
National Produced Water Database v2.0.
eDresel and Rose (2010). n = 3 - 15. Concentrations were calculated based on Dresel and Rose's raw data.
E-29

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-7. Reported concentrations (mg/L) of metals and metalloids from produced water
from coalbed methane, presented as: average (minimum-maximum).	
Parameter
Black Warrior3
Powder Riverb
Ratonb
San Juanb
States
AL, MS
MT, WY
CO, NM
AZ, CO, NM, UT
Aluminum
0.037 (0-0.099)
0.018 (BDL-0.124)
0.193 (BDL-2,900)
0.069 (BDL-0.546)
Antimony
0.006 (0.00-0.022)
BDL(BDL-BDL)
BDL (BDL-BDL)
BDL (BDL-BDL)
Arsenic
0.002 (0.0-0.085)
0.001 (BDL-0.004)
0.010 (BD-0.060)
0.001 (BDL-0.020)
Barium
45.540 (0.136-352)
0.61 (0.14-2.47)
1.67 (BDL-27.40)
10.80 (BDL-74.0)
Beryllium
0.0 (0.0-0.008)
BDL (BDL-BDL)
BDL (BDL-BDL)
BDL (BDL-BDL)
Boron
0.185 (0-0.541)
0.17 (BDL-0.39)
0.36 (BDL-4.70)
1.30 (0.21-3.45)
Cadmium
0.001(0.00-0.015)
BDL (BDL-0.002)
0.002 (BDL-0.003)
0.002 (BDL-0.006)
Calcium
218 (0-1,640)
32.09 (2.00-154.0)
14.47 (0.81-269.0)
53.29 (1.00-5,530)
Cesium
0.011 (0.0-0.072)
-
-
-
Chromium
0.002 (0.0-0.351)
0.012 (BDL-0.250)
0.105 (BDL-3.710)
0.002 (BDL-0.023)
Cobalt
0.023 (0.00-0.162)
BDL (BDL-BDL)
0.001 (BDL-0.018)
0.001 (BDL-0.017)
Copper
0.001 (0.0-0.098)
0.078 (BDL-1.505)
0.091 (BDL-4.600)
0.058 (BDL-0.706)
Iron
8.956 (0.045-93.100)
1.55 (BDL-190.0)
7.18 (0.09-95.90)
6.20 (BDL-258.0)
Lead
0.008 (0.00-0.250)
BDL (BDL-BDL)
0.023 (BDL-0.233)
0.023 (BDL-0.390)
Lithium
1.157 (0-8.940)
0.13 (BDL-0.34)
0.32 (0.01-1.00)
1.61 (0.21-4.73)
Magnesium
68.12 (0.18-414.00)
14.66 (BDL-95.00)
3.31 (0.10-56.10)
15.45 (BDL-511.0)
Manganese
0.245 (0.006-4.840)
0.02 (BDL-0.16)
0.11(0.01-2.00)
0.19 (BDL-1.34)
Mercury
0.000 (0.000 - 0.000)
-
-
-
Molybdenum
0.002 (0-0.083)
0.005 (BDL-0.029)
0.002 (BDL-0.035)
0.020 (BDL-0.040)
Nickel
0.015 (0.0-0.358)
0.141 (BDL-2.61)
0.015 (0.004-0.11)
0.020 (BDL-0.13)
Potassium
12.02 (0.46-74.00)
11.95 (BDL-44.00)
6.37 (BDL-29.40)
26.99 (BDL-970.0)
Rubidium
0.013 (0.0-0.114)
-
-
-
Selenium
0.002 (0.00-0.063)
0.006 (BDL-0.046)
0.017 (BDL-0.100)
0.018 (BDL-0.067)
Silver
0.015 (0.0-0.565)
0.003 (0.003-0.003)
0.015 (BDL-0.140)
BDL (BDL-BDL)
Sodium
4,353 (126 -16,700)
356 (12-1,170)
989 (95-5,260)
1,610 (36-7,834)
Strontium
11.354 (0.015-
142.000)
0.60 (0.10-1.83)
5.87 (BDL-47.90)
5.36 (BDL-27.00)
Thallium
-
-
-
-
E-30

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Black Warrior3
Powder Riverb
Ratonb
San Juanb
States
AL, MS
MT, WY
CO, NM
AZ, CO, NM, UT
Tin
0.00 (0.00-0.009)
0.006 (BDL-0.028)
0.008 (BDL-0.021)
0.017 (BDL-0.039)
Titanium
0.003 (0.0-0.045)
BDL (BDL-0.002)
BDL (BDL-0.002)
0.004 (BDL-0.020)
Vanadium
0.001 (0.0-0.039)
BDL (BDL-BDL)
0.001 (BDL-0.013)
BDL (BDL-BDL)
Zinc
0.024 (0.0-0.278)
0.063 (BDL-0.390)
0.083 (0.010-3.900)
0.047 (0.005 -
0.263)
-, no value available; BDL, below detection limit.
3 DOE (2014). n = 206. Concentrations were calculated based on the authors' raw data.
b Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without
presentation of raw data.
E.3.4. Naturally Occurring Radioactive Material (NORM) and Technically Enhanced Naturally
Occurring Radioactive Material (TENORM)
E.3.4.1. Produced Water Levels of TENORM
Background data on TENORM in the Marcellus Shale and Devonian sandstones are given in Table
E-8.
E.3.4.2. Mobilization of Naturally Occurring Radioactive Material
In oil and gas production in both conventional and unconventional reservoirs, radionuclides native
to the targeted formation return to the surface with produced water. The principal radionuclides
found in oil and gas produced waters include radium-226 of the uranium-238 decay series and
radium-228 of the thorium-232 decay series fWhite. 19921. Levels of TENORM in produced water
are controlled by geologic and geochemical interactions between injected and formation fluids, and
the targeted formation fBank. 20111. Mechanisms controlling NORM mobilization into produced
water include (1) the TENORM content of the targeted formation; (2) factors governing the release
of radionuclides, particularly radium, from the reservoir matrix; and (3) the geochemistry of the
produced water fChoppin. 2007. 2006: Fisher. 19981.
Elevated uranium levels in formation solids have been used to identify potential areas of natural
gas production for decades fFertl and Chilingar. 19881. Marine black shales are estimated to contain
3 - 250 ppm uranium depending on depositional conditions fUSGS. 19611. Shales that bear
significant levels of uranium include the Barnett in Texas, the Woodford in Oklahoma, the New
Albany in the Illinois Basin, the Chattanooga Shale in the southeastern United States, and a group of
black shales in Kansas and Oklahoma fSwanson. 19551.
Bank etal. f20121 identified Marcellus samples with uranium ranging from 4-72 ppm, with an
average of 30 ppm. Chermak and Schreiber (20141 compiled mineralogy and trace element data
available in the literature for nine U.S. hydrocarbon-producing shales. In this combined data set,
uranium levels among different shale plays were found to vary over three orders of magnitude,
with samples of the Utica Shale containing approximately 0-5 ppm uranium and samples of the
Woodford Shale containing uranium in the several-hundred-ppm range.
E-31

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-8. Reported concentrations (in pCi/L) of radioactive constituents in produced water in unconventional reservoirs
(including shale and tight sandstones), presented as: average (minimum-maximum) or median (minimum-maximum).
Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians.







Devonian
Parameter


Marcellus


Sandstone3


PA NORM Study (PA DEP. 2015)






Produced Water,
Produced Water,






Conventional
Unconventional


States
NY, PAb
Fracturing Fluid0
Flowbackd
Reservoirs®
Reservoirs'
wvg
PA

6,845
5,020
10,700

11,300
5,866

Gross alpha
(ND-123,000)
(0.695-54,100)
(288-71,000)
1,835 (465 - 2,570)
(2,400 - 41,700)
(1.84-20,920)
-

1,170
1,010
2,400


1,172

Gross beta
(ND -12,000)
(0.815 -14,900)
(742-21,300)
909 (402 -1,140)
3,445 (1,500 - 7,600)
(9.6-4,664)
-

1,869
2,160
4,500


358
2,367
Radium-226
(ND-16,920)
(64.0-21,000)
(551-25,500)
243 (81 - 819)
6,300 (1,700-26,600)
(15.4-1,194)
(200 - 5,000)


218





Radium-228
557 (ND-2,589)
(4.5-1,640)
633 (248 -1,740)
128 (26 - 896)
941 (366 -1,900)
94.6 (4.99-216)
-

2,530






Total Radium
(0.192-18,045)

-
371 (107 -1,715)
7,180 (2,336 - 28,500)

-


283





Potassium40

(10.5-456)
461 (88.5-2,630)


62.44 (nd-221)

Thorium230





2.13 (0-9.37)

Thorium232





0.07 (0-0.38)

Uranium235
1 (ND - 20)

-
-
-

-
Uranium238
42 (ND - 497)

-
-
-
0.34
-
n/a, not applicable; no value available; BDL, below detection limit. Bolded italic numbers are medians.
3 Dresel and Rose (2010). n = 3. Concentrations presented were calculated based on Dresel and Rose's raw data.
b Rowan et al. (2011). n = 51 total radium; n = 30 gross beta. Concentrations presented were calculated based on Rowan et al.'s raw data for Marcellus samples. Uranium data
from Barbot et al. (2013) n = 14.
CPA PEP (2015). n = 11. Data reported in Table 3-13 of the referenced paper.
d PA PEP (2015). n = 9. Data reported in Table 3-14 of the referenced paper.
e PA PEP (2015). n = 9. Values calculated from Table 3-15 for unfiltered samples of the referenced paper.
f PA PEP (2015). n = 4. Values calculated from Table 3-15 for unfiltered samples of the referenced paper.
sZiemkiewicz and He (2015). n = 5. Pata reported in Table 1 of the referenced paper.
E-32

-------
Appendix E - Produced Water Handling Supplemental Information
Vine (19561 reported that the principal uranium-bearing coal deposits of the United States are
found in Cretaceous and Tertiary formations in the northern Great Plains and Rocky Mountains; in
some areas of the West, coal deposits have been found with uranium concentrations in the range of
thousands of ppm or greater. In contrast, most Mississippian, Pennsylvanian, and Permian coals in
the north-central and eastern United States contain less than 10 ppm uranium, rarely containing
50 ppm or more.
Organic-rich shales and coals are enriched in uranium, thorium, and other trace metals in
concentrations above those seen in typical shales or sedimentary rocks fDiehl etal.. 2004: USGS.
1997: Wignall and Myers. 1988: Tourtelot. 1979: Vine and Tourtelot. 19701. Unlike shales and coals,
sandstones are generally not organic-rich source rocks themselves. Instead, hydrocarbons migrate
into these formations over long periods of time (Clark and Veil. 20091. Since TENORM and organic
contents are typically positively correlated due to the original, reduced depositional environment
fFertl and Chilingar. 19881. it is unlikely that sandstones would be enriched in TENORM to the same
extent as oil- and gas-bearing shales and coals. Therefore, concern related to TENORM within
produced water is focused on operations targeting shales and coalbeds.
Radium is most soluble and mobile in chloride-rich, high-TDS, reducing environments fSturchio et
al.. 2001: Zapecza and Szabo. 1988: Langmuir and Riese. 19851. In formation fluids with high TDS,
calcium, potassium, magnesium, and sodium compete with dissolved radium for sorption sites,
limiting radium sorption onto solids and allowing it to accumulate in solution at higher
concentrations fFisher. 1998: Webster etal.. 19951. The positive correlation between TDS and
radium is well established and TDS is a useful indicator of radium and TENORM activity within
produced water, especially in lithologically homogenous reservoirs (Rowan etal.. 2011: Sturchio et
al.. 2001: Fisher. 1998: Kraemer and Reid. 19841.
Uranium and thorium are poorly soluble under reducing conditions and are therefore more
concentrated in formation solids than in solution (Fisher. 1998: Kraemer and Reid. 1984: Langmuir
and Herman. 19801. However, because uranium becomes more soluble in oxidizing environments,
the introduction of relatively oxygen-rich fracturing fluids may promote the temporary
mobilization of uranium during hydraulic fracturing and early flowback. In addition, the physical
act of hydraulic fracturing creates fresh fractures and exposes organic-rich and highly reduced
surfaces from which radionuclides could be released from the rock into formation fluids.
Produced water geochemistry determines, in part, the fate of subsurface radionuclides, particularly
radium. Radium may remain in the host mineral or it may be released into formation fluids, where
it can remain in solution as the dissolved Ra2+ ion, be adsorbed onto oxide grain coatings or clay
particles by ion exchange, substitute for other cations during the precipitation of minerals, or form
complexes with chloride, sulfate, and carbonate ions (Rowan etal.. 2011: Sturchio etal.. 2001:
Langmuir and Riese. 19851. Uranium- and thorium-containing materials with a small grain size, a
large surface-to-volume ratio, and the presence of uranium and thorium near grain surfaces
promote the escape of radium into formation fluids. Vinson et al. (20091 point to alpha decay along
fracture surfaces as a primary control on radium mobilization in crystalline bedrock aquifers.
E-33

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Appendix E - Produced Water Handling Supplemental Information
Radium may also occur in formation fluids due to other processes, such as the decay of dissolved
parent isotopes and adsorption-desorption reactions on formation surfaces fSturchio etal.. 20011.
Preliminary results from fluid-rock interaction studies (Bank. 20111 indicate that a significant
percentage of uranium in the Marcellus Shale may be subject to mobilization by hydrochloric acid,
which is used as a fracturing fluid additive. More complete understanding these processes will
determine the extent to which such processes might influence the TENORM content of flowback
and produced water.
E.3.5. Organics
Background data on organics in seven formations is given in Table E-9. Classes of organic
compounds identified in produced water are given in Table E-10. Tables H-4 and H-5 give the entire
list of chemicals identified as components of produced water. Along with the organic chemicals
appearing in Table E-9, Table E-lOa presents additional organic chemicals with measured
concentrations in produced water. Table E-ll presents data from two studies of the Marcellus
Shale. Table E-12 presents data from CBM produced water, while Table E-13 presents data on
organics identified in shale and CBM water.
Several classes of naturally occurring organic chemicals are present in produced waters in
conventional and unconventional reservoirs, with large concentration ranges (Lee and Neff. 20111.
These organic classes include total organic carbon (TOC); saturated hydrocarbons; BTEX (benzene,
toluene, ethylbenzene, and xylenes); and polyaromatic hydrocarbons (PAHs) (Table E-10). While
TOC concentrations in produced water are detected at the milligrams to grams per liter level,
concentrations of individual organic compounds are typically detected at the micrograms to
milligrams per liter level.
TOC indicates the level of dissolved and undissolved organics in produced water, including non-
volatile and volatile organics fAcharva etal.. 20111. TOC concentrations in conventional produced
water vary widely from less than 0.1 mg/L to more than 11,000 mg/L. Average TOC concentrations
in produced water in unconventional reservoirs range from less than 2.00 mg/L in the Raton CBM
basin to approximately 200 mg/L in the Cotton Valley Group sandstones, although individual
measurements have exceeded 5,000 mg/L in the Marcellus Shale (Table E-9).
Dissolved organic carbon (DOC) is a general indicator of organic loading and is the fraction of
organic carbon available for complexing with metals and supporting microbial growth. DOC values
in produced water in unconventional reservoirs range from less than 1.50 mg/L (average) in the
Raton Basin to more than 115 mg/L (median) in the Marcellus Shale (Table E-9). Individual DOC
concentrations in the Marcellus Shale produced water approach 6,000 mg/L. For comparison, DOC
levels in fresh water systems are typically below 5 mg/L.
Biochemical oxygen demand (BOD) is a conventional pollutant under the U.S. Clean Water Act It is
an indirect measure of biodegradable organics in produced water and an estimate of the oxygen
demand on a receiving water. Median BOD levels for Barnett and Marcellus Shales produced water
exceed 30 mg/L, and both reported maximum concentrations exceeding 12,000 mg/L (Table E-9).
E-34

-------
Appendix E - Produced Water Handling Supplemental Information
In some circumstances wide variation in produced water median BOD levels may be reflective of
flowback reuse in fracturing fluids fHaves. 20091.
Lastly, BTEX is associated with petroleum. Benzene was found in produced water from several
basins: average produced water benzene concentration from the Barnett Shale was 680 ng/L, from
the Marcellus Shale was 220 ng/L (median), and from the San Juan Basin was 150 ng/L (Table E-9).
Total BTEX concentrations for conventional produced water vary widely from less than 100 ng/L to
nearly 580,000 ng/L. For comparison, average total BTEX concentrations in produced water in
unconventional reservoirs range from 20 ng/L in the Raton Basin to nearly 3,000 |ig/L in the
Marcellus (Table E-9). From these data, average total BTEX levels in shale produced water are one
to two orders of magnitude higher than those in CBM produced water.
In addition to BTEX, a variety of volatile and semi-volatile organic compounds have been detected
in shale and coalbed produced water. Shale produced water contains naphthalene, alkylated
toluenes, and methylated aromatics in the form of several benzene and phenol compounds, as
shown in Table E-ll. Like BTEX, naphthalene, methylated phenols, and acetophenone are
associated with petroleum. Detected shale produced water organics such as acetone, 2-butanone,
carbon disulfide, and pyridine are potential remnants of additives used as friction reducers or
industrial solvents fHaves. 20091.
Hayes (2009) characterized the content of Marcellus Shale produced water including organics
(Table E-ll). The author tested for the majority of VOCs and SVOCs, pesticides and PCBs, based on
the recommendation of the Pennsylvania and West Virginia Departments of Environmental
Protection. Less than 0.5% of VOCs and 0.03% of SVOCs in the produced water were detected above
1 mg/L. More than 96% of VOCs, 98% of SVOCs, and virtually all pesticides and PCBs were at
nondetectable levels.
Orem etal. (2014) provided a list of classes of organic compounds in coalbed methane and gas shale
produced and formation water (Table E-10). As described in the main text of Chapter 7, these
included aromatics, polyaromatic hydrocarbons, heterocyclic compounds, aromatic amines,
phenols, phthalates, aliphatic alcohols, fatty acids and nonaromatic compounds. Many of these are
naturally occurring components of petroleum hydrocarbons, but the list also contains chemicals
that have been used as hydraulic fracturing fluid additives, namely, hexahydro-l,3,5-trimethyl-
l,3,5-triazine-2-thione (a biocide), ethylene glycol, dibutyl phthalate, quinoline, and naphthalene, to
list a few. See Table H-2.
The organic profile of CBM produced water is characterized by high levels of aromatic and
halogenated compounds compared to other produced water in unconventional reservoirs
(Sirivedhin and Dallbauman. 2004). PAHs and phenols are the most common organic compounds
found in coalbed produced water. Produced water from coalbeds in the Black Warrior Basin mainly
contains phenols, multiple naphthalic PAHs, and various decanoic and decenoic fatty acids (Table
E-12). CBM-associated organics are also known to include biphenyls, alkyl aromatics,
hydroxypyridines, aromatic amines, and nitrogen-, oxygen-, and sulfur-bearing heterocyclics (Orem
etal., 2014; Pashin etal., 2014; Benko and Drewes, 2008; Orem etal., 2007; Fisher and Santamaria,
20021.
E-35

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-9. Concentrations of select organic parameters in produced water from unconventional reservoirs (including shale, a tight
formation, and coalbed methane), presented as: average (minimum-maximum) or median (minimum-maximum).
Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians.
Parameter
Unit
Shale
Tight
Formation
Coal
Barnett3
Marcellus
Cotton Valley
Groupd
Powder
River®
Raton6
San Juane
Black Warrior'
States
n/a
TX
PAb
PA, WVC
LA, TX
MT, WY
CO, NM
AZ, CO, NM,
UT
AL, MS
TOC
mg/L
9.75
(6.2-36.2)
160
(1.2-
1,530)
89.2
(1.2-5680)
198
(184-212)
3.52 (2.07-
6.57)
1.74 (0.25-
13.00)
2.91(0.95-
9.36)
6.03 (0.00-
103.00)
DOC
mg/L
11.2
(5.5-65.3)

117
(3.3-
5,960)
-
3.18(1.09-
8.04)
1.26 (0.30-
8.54)
3.21(0.89-
11.41)
3.37 (0.53-
61.41)
BOD
mg/L
582
(101-2,120)
-
141
(2.8-
12,400)
-
-
-
-
-
Oil and grease
mg/L
163.5
(88.2-1,430)
74
(5 - 802)
16.9
(4.7-802)
-
-
9.10 (0.60-
17.6)
-
-
Benzene
Hg/L
680
(49 - 5,300)
-
220
(5.8-
2,000)
-
-
4.7 (BDL-
220.0)
149.7 (BDL-
500.0)
-
Toluene
Hg/L
760
(79-8,100)
-
540
(5.1-
6,200)
-
-
4.7 (BDL-78.0)
1.7
(BDL- 6.2)
-
Ethylbenzene
Hg/L
29
(2.2-670)
-
42
(7.6-650)
-
-
0.8 (BDL-18.0)
10.5 (BDL-
24.0)
-
Xylenes
Hg/L
360
(43 -1,400)
-
300 (15 -
6,500)
-
-
9.9 (BDL-
190.0)
121.2 (BDL-
327.0)
-
E-36

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Unit
Shale
Tight
Formation
Coal
Barnett3
Marcellus
Cotton Valley
Groupd
Powder
River®
Raton®
San Juan®
Black Warrior'
States
n/a
TX
PAb
PA, WVC
LA, TX
MT, WY
CO, NM
AZ, CO, NM,
UT
AL, MS
Average total
BTEX®
Hg/L
1,829
2,910
1,102
-
-
20.1
283.1
-
n/a, not applicable; no value available; BDL, below detection limit. Boldeditalic numbers are medians.
3 Haves and Severin (2012a). n = 16. This data source reported concentrations without presentation of raw data.
b Barbot et al. (2013). n = 55 for TOC; n = 62 for oil and grease; no presentation of raw data.
c Haves (2009). n = 13-67. Concentrations were calculated based on Hayes' raw data. Both flowback and produced water included. Non-detects and contaminated blanks
omitted.
d Blondes et al. (2014). n = 2. Concentrations were calculated based on raw data presented in the USGS National Produced Water Database v2.0.
e Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without presentation of raw data.
f DOE (2014). n = 206. Concentrations were calculated based on the authors' raw data.
s Average total BTEX was calculated by summing the average/median concentrations of benzene, toluene, ethylbenzene, and xylenes for a unique formation or basin. Minimum
to maximum ranges were not calculated due to inaccessible raw data.
E-37

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-10. Classes of organic compounds and representative example compounds found in
coal bed methane and gas shale formations (Orem et al.. 2014).
Compounds also identified as having been used in hydraulic fracturing fluids (Table H-2) are given in bold and italic
type.
Extractable hydrocarbons identified in CBM and shale produced and formation water
Type
Location
Compound classes
Representative example compounds
CBM
Powder River Basin
Wyoming
PAHs
Dimethylnaphthalene
tetramethylphenanthrene
phenanthrenone
pyrene


Heterocyclic
compounds
Benzisothiazole
3,4-dihydrol,9(2H,10H)Acridinedione
2(3H)-Benzothiazolone


Aromatic amines
Dioctyldiphenylamine
diphenylamine
2-methyl-N-phenyl Benzenamine


Phenols
Nonylphenols
4,40-(l-methylethylidene)bis-phenol
methoxy-methylphenol


Other aromatics
Trimethyl benzene
2,4-dimethyl-l-(l-methylpropyl)-benzene


Phthalates
Diethylphthalate
dibutyl phthalate
benzyl butyl phthalate
didecyl phthalate


Fatty acids
Dodecanoic acid
n-hexadecanoic acid
tetradecanoic acid


Nonaromatic
compounds
Kaur-16-ene (a diterpene)
2-[2-[4-(l,1,3,3-
tetramethylbutyl)phenoxy]ethoxy]-ethanol

Tongue River Basin
Montana
PAHs
l-Methyl-7-(l-methylethyl)phenanthrene
1-methylnaphthalene
2-methylnaphthalene


Heterocyclic
compounds
Benzothiazole


Aromatic amines
Diethyltoluamide


Phenols
2,4-Bis(l,l-dimethylethyl)phenol
p-tert-butyl-phenol


Other aromatics
l-Ethyl-2,4-dimethyl-benzene
E-38

-------
Appendix E - Produced Water Handling Supplemental Information
Extractable hydrocarbons identified in CBM and shale produced and formation water
Type
Location
Compound classes
Representative example compounds
CBM, cont.
Tongue River Basin
Montana, cont.
Phthalates
Alkyl phthalates


Fatty acids
Tetradecanoic acid
octadecanoic acid


Nonaromatic
compounds
Pentadecane
pentacosane

Black Warrior
Basin Alabama
PAHs
Methylnaphthalene
dimethylnaphthalene


Heterocyclic
compounds
Benzothiazole
dibenzothiophene
caprolactam
quinoline
isoquinoline


Phenols
Dimethylphenol
4-(l,l,3,3-tetramethylbutyl)-phenol
2,4-bis(l, l-dimethylethyl)-phenol


Other aromatics
Acetophenone
biphenyl
methylbiphenyl


Phthalates
Dioctyl phthalate
dibutyl phthalate


Fatty acids
Hexadecanoic acid


Nonaromatic
compounds
Alkyl phosphates

Illinois Basin
Illinois
PAHs
Naphthalene
methylnaphthalene
methylphenanthrene


Heterocyclic
compounds
Benzothiazole


Phenols
2,4-Bis(l,l-dimethylethyl)-phenol


Other aromatics
l-(3-Methylbutyl)-2,3,4-trimethyl-benzene


Phthalates
Alkyl phthalates


Fatty acids
Hexadecanoic acid
octadecanoic acid


Nonaromatic
compounds
C23-C36 alkanes
2,6-di(tert-butyl)-4-hydroxy-4-methyl-2,5-
cyclohexadien-l-on
E-39

-------
Appendix E - Produced Water Handling Supplemental Information
Extractable hydrocarbons identified in CBM and shale produced and formation water
Type
Location
Compound classes
Representative example compounds
CBM, cont.
Williston Basin
North Dakota
PAHs
Naphthalene
methylnaphthalene
methylphenanthrene


Heterocyclic
compounds
Benzothiazole


Phenols
Bis(l,l-dimethylethyl)-phenol
trichlorophenol
4,4'-(l-methylethylidene)bis-phenol


Other aromatics
Benzophenone


Phthalates
Alkyl phthalates
benzyl butyl phthalate


Fatty acids
C12, C14, C16, C18 fatty acids


Nonaromatic
compounds
C23-C35 alkanes
alkyl phosphates
2,6-bis(l, l-dimthylethyl)-2,5-cyclohexadiene-l,4-
dione
Shale gas
Marcellus Shale
Pennsylvania
PAHs
Decahydro-4,4,8,9,10-pentamethylnaphthalene


Heterocyclic
compounds
Hexahydro-l,3,5-trimethyl-l,3,5-triazine-2-thione
(a biocide)


Aliphatic alcohols
Ethylene glycol
diethylene glycol monododecyl ether
triethylene glycol monodocecyl ether


Other aromatics
(l-Methoxyethyl)-benzene


Phthalates
Di-n-octyl phthalate


Fatty acids
C12, C14, C16, C18 fatty acids


Nonaromatic
compounds
C11-C37 alkanes/alkenes
2,2,4-trimethyl-l,3-pentanediol
tetramethylbutanedinitrile

New Albany Shale
Indiana and Kentucky
PAHs
1,2,3,4-Tetrahydro-naphthalene
naphthalene
methylphenanthrene
pyrene
perylene


Heterocyclic
compounds
Benzothiazole
trimethyl-piperdine
quinoline
quinindoline
E-40

-------
Appendix E - Produced Water Handling Supplemental Information
Extractable hydrocarbons identified in CBM and shale produced and formation water
Type
Location
Compound classes
Representative example compounds
Shale gas, cont.
New Albany Shale
Indiana and
Kentucky, cont.
Aromatic amines
3,3'-5,5'-Tetramethyl-[l,l'-biphenyl]-4,4'-diamine


Phenols
Bis(l,l-dimethylethyl)-phenol
tert-butyl-phenol
bis-(l,l-dimethylethyl)-phenol


Other aromatics
Triphenyl phosphate
methylbiphenyl
octylphenyl ethoxylate


Phthalates
Alkyl phthalates


Fatty acids
Dodecanoic acid
tetradecanoic acid
octadecanoic acid


Nonaromatic
compounds
2-(2-Butoxyethoxy)ethanol
E-41

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-ll. Reported concentrations (|ig/L) of organic constituents in produced water for two
shale formations, presented as: average (minimum-maximum) or median (minimum-
maximum).
Both averages and medians are reported because this table summarizes published information and authors
differed in their use of averages or medians.
Parameter
Barnett3
Marcellusb
States
TX
MD, NY, OH, PA, VA, WY
Acetone
145 (27 - 540)
83 (14 - 5,800)
Carbon disulfide
-
400 (19-7,300)
Chloroform
-
28
Isopropylbenzene
35 (0.8-69)
120 (86 -160)
Naphthalene
238 (4.8-3,100)
195 (14-1,400)
Phenolic compounds
119.65 (9.3-230)
-
1,2,4-Trimethylbenzene
173 (6.9 -1,200)
66.5(7.7-4,000)
1,3,5-Trimethylbenzene
59 (6.4-300)
33 (5.2-1,900)
1,2-Diphenylhydrazine
4.2 (0.5-7.8)
-
1,4-Dioxane
6.5(3.1-12)
-
2-Methylnaphthalene
1,362 (5.4 - 20,000)
3.4 (2 -120)
2-Methylphenol
28.3 (5.8-76)
13 (11-15)
2,4-Dichlorophenol
(ND-15)
-
2,4-Dimethylphenol
14.5 (8.3-21)
12
3-Methylphenol	and
4-Methylphenol
41(7.8-100)
11.5 (0.35-16)
Acetophenone
(ND - 4.6)
13 (10-22)
Benzidine
(ND-35)
-
Benzo(a)anthracene
(ND -17.0)
-
Benzo(a)pyrene
(ND-130.0)
6.7
Benzo(b)fluoranthene
42.2 (0.5-84.0)
10
Benzo(g,h,i)perylene
42.3 (0.7-84.0)
6.9
Benzo(k)fluoranthene
32.8 (0.6-65.0)
5.9
Benzyl alcohol
81.5 (14.0-200)
41 (17 - 750)
Bis(2-Ethylhexyl) phthalate
210 (4.8-490)
20 (9.6-870)
Butyl benzyl phthalate
34.3 (1.9-110)
-
E-42

-------
Appendix E - Produced Water Handling Supplemental Information
Parameter
Barnett3
Marcellusb
States
TX
MD, NY, OH, PA, VA, WY
Chrysene
120 (0.57 - 240)
-
Di-n-octyl phthalate
(ND - 70)
15
Di-n-butyl phthalate
41(1.5-120)
14 (11-130)
Dibenz(a,h)anthracene
77 (3.2 -150)
3.2 (2.3-11)
Diphenylamine
5.3(0.6-10.0)
-
Fluoranthene
(ND - 0.18)
6.1
Fluorene
0.8(0.46-1.3)
8.4
lndeno(l,2,3-cd)pyrene
71 (2.9 -140)
3.1 (2.4-9.5)
N-Nitrosodiphenylamine
8.9(7.8-10)
2.7
N-Nitrosomethylethylamine
(ND - 410)
-
Phenanthrene
107 (0.52 -1,400)
9.75 (3 - 22)
Phenol
63 (17-93)
10 (2.4-21)
Pyrene
0.2 (ND - 0.18)
13
Pyridine
413 (100-670)
250 (10-2,600)
no value available; ND, not detected.
3 Haves and Severin (2012a). n = 16. Data from days 1-23 of flowback. This data source reported concentrations without
presentation of raw data.
b Haves (2009). n = 1 - 35. Data from days 1 - 90 of flowback. Concentrations were calculated from Hayes' raw data. Non-
detects and contaminated blanks omitted.
E-43

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-12. Reported concentrations of organic constituents in 65 samples of produced water
from the Black Warrior CBM Basin (Alabama and Mississippi), presented as: average
(minimum-maximum).	
Parameter
Number of observations
Concentration (ng/L)a
Benzothiazole
45
0.25 (0.01-3.04)
Caprolactam
10
0.75 (0.02-2.39)
Cyclic octaatomic sulfur
29
1.06 (0.10-9.63)
Dimethyl-naphthalene
39
0.79 (0.01-9.51)
Dioctyl phthalate
57
0.21(0.01-2.30)
Dodecanoic acid
30
1.13 (0.67-2.52)
Hexadecanoic acid
50
1.58(1.17-3.02)
Hexadecenoic acid
25
1.69 (1.13-8.37)
Methyl-biphenyl
18
0.25 (0.01-2.13)
Methyl-naphthalene
52
0.77 (0.01-15.55)
Methyl-quinoline
31
0.96 (0.03-3.75)
Naphthalene
49
0.41(0.01-6.57)
Octadecanoic acid
32
1.95 (1.62-3.73)
Octadecenoic acid
29
1.87 (1.60-3.47)
Phenol, 2,4-bis(l,l-dimethyl)
21
0.45 (0.01-4.94)
Phenol, 4-(l,l,3,3-tetramethyl)
17
1.65 (0.01-18.34)
Phenolic compounds
-
19.06 (ND-192.00)
Tetradecanoic acid
53
1.51(0.94-5.32)
Tributyl phosphate
23
0.26 (0.01-2.66)
Trimethyl-naphthalene
23
0.65 (0.01-4.49)
Triphenyl phosphate
6
1.18 (0.01-6.77)
no value available.
a DOE (2014). Concentrations were calculated based on the authors' raw data.
E-44

-------
Appendix E - Produced Water Handling Supplemental Information
Table E-13. Organic chemical concentrations reported from three specific studies of produced water (Khan et al.. 2016: Lester et
al.. 2015: Orem et al.. 2007).
The complete list of chemicals which were identified in produced water are listed in Tables H-4 and H-5.
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
(Z)-9-Tricosene
0.98



c
Orem et al. (2007)
1-(2-Hydroxy-5-methylphenyl)-
2-hexen-l-one
0.29



c
Orem et al. (2007)
l,l-Dimethyl-l,2,3,4-
tetrahydro-7-isopropyl
phenanthrene
0.19

0.68

c
Orem et al. (2007)
l,2-Di-but-2-enyl-cyclohexane
0.77



c
Orem et al. (2007)
l,2-Di-but-2-enyl-
cyclohexanone
0.09



c
Orem et al. (2007)
l,4-[ 13C]-1,2,3,4-Tetra hyd ro-5-
naphthaleneamine
0.33



c
Orem et al. (2007)
1,4-dioxane
60



c
Lester et al. (2015)
1,6-Dimethyl-4(1-
methylethyl)naphthalene
0.01

0.32

c
Orem et al. (2007)
1,7,11-
Trimethylcyclotetradecane
1.06



c
Orem et al. (2007)
1,7,11-Trimethyl-
cyclotetradecane
0.47



c
Orem et al. (2007)
l-lMethylenebis(4-methyl)-
benzene
0.09

0.11

c
Orem et al. (2007)
15-lsobutyl-(13.a.H)-
isocopalane
1.75



c
Orem et al. (2007)
E-45

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
17-Pentatriacontene
1



c
Orem et al. (2007)
l-Allyl-3-methylindole-2-
carbaldehyde
0.49



c
Orem et al. (2007)
l-Allyl-3-methylindole-2-
carbaldehyde
1.49



c
Orem et al. (2007)
l-Butyl-2-ethyloctahydro-4,7-
epoxy
0.9



c
Orem et al. (2007)
1-Chloro-octadecane
2.12



c
Orem et al. (2007)
1-Docosene
2.33



c
Orem et al. (2007)
l-Ethyl-9,10-anthracenedione
0.04

0.12

c
Orem et al. (2007)
1-Hexacosene
2.04



c
Orem et al. (2007)
l-Methyl-7-(l-
methylethyl)phenanthrene
0.02

3.19

c
Orem et al. (2007)
l-Methyl-9H-fluorene
0.51



c
Orem et al. (2007)
1-Nonadecene
2.15



c
Orem et al. (2007)
2-(2-Butoxyethoxy)-ethanol
0.45



c
Orem et al. (2007)
2(3H)-Benzothiazolone
0.04

3.9

c
Orem et al. (2007)
2-(Methylthio)-benzothiazole
0.05

0.54

c
Orem et al. (2007)
2,3',5-
Trimethyldiphenylmethane
0.04

0.05

c
Orem et al. (2007)
2,3-Dihydro-l,l,2,3,3-
pentamethyl-lH-indene
0.45



c
Orem et al. (2007)
E-46

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
2,4,6-Trimethyl-azulene
0.49



c
Orem et al. (2007)
2,4-dimethylphenol
790



c
Lester et al. (2015)
2,5-Cyclohexadiene-l,4-dione
0.01

0.08

c
Orem et al. (2007)
2,6,10,14-T etra methy 1-
hexadecane
1.65



c
Orem et al. (2007)
2,6,10-Trimethyl-dodecane
0.96



c
Orem et al. (2007)
2,6-Bis(dimethylethyl)-2,5-
cyclohexadiene-l,4-dione
0.04

0.28

c
Orem et al. (2007)
2,6-Bis(dimethylethyl)-phenol
0.31



c
Orem et al. (2007)
2-[2-[4-(l,1,3,3-
Tetramethylbutyl)phenoxy]eth
oxy]-ethanol
0.08

1.34

c
Orem et al. (2007)
22-Tricosenoic acid
0.43



c
Orem et al. (2007)
28-Nor-17.a.(H)-hopane
1.26



c
Orem et al. (2007)
28-Nor-17.a.(H)-hopane
0.84



c
Orem et al. (2007)
2a,7a-(Epoxymethano)-2H-
cyclobutyl
0.33



c
Orem et al. (2007)
2-Butanone
240



c
Orem et al. (2007)
2-Dodecen-l-yl(-)succinic
anhydride
1.16



c
Orem et al. (2007)
2-Ethylhexyl diphenyl
phosphate (Octicizer)
0.1

0.75

c
Orem et al. (2007)
2-Mercaptobenzothiazole
0.89



c
Orem et al. (2007)
E-47

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
2-Methyl-8-propyl-dodecane
0.52



c
Orem et al. (2007)
2-methylnaphthalene
4



c
Lester et al. (2015)
2-Methyl-nonadecane
2.58



c
Orem et al. (2007)
2-Methyl-N-phenyl-
benzenamine
0.41

3.53

c
Orem et al. (2007)
2-methylphenol
150



c
Lester et al. (2015)
2-Octadecyl-propane-l,3-diol
0.42



c
Orem et al. (2007)
3&4 methylphenol
170



c
Lester et al. (2015)
3-(4-Methoxyphenyl)-2-
ethylhexylester-2-propenoic
acid
0.01

2.78

c
Orem et al. (2007)
3-(4-Methoxyphenyl)-2-
propenoic acid
0.06

0.16

c
Orem et al. (2007)
3-(Hexahydro-lH-azepin-l-yl)-
l,l-dioxide-l,2-benzisothiazole
0.66



c
Orem et al. (2007)
3,4-Dihydro-
l,9(2H,10H)acridinedione
0.02

1.35

c
Orem et al. (2007)
3,5-Di-tetra-butyl-4-
hydroxybenzaldehyde
0.42



c
Orem et al. (2007)
4-(l-Methyl-phenylethyl)-
phenol
1.18



c
Orem et al. (2007)
4-(4-Ethylcyclohexyl)-
cyclohexene
1.66



c
Orem et al. (2007)
E-48

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
4,40-(l-Methylethylidene)bis-
phenol
<=16.17



c
Orem et al. (2007)
4,4-Diacetyldiphenylmethane
0.37



c
Orem et al. (2007)
4,6,8-Trimethyl-2-
propylazulene
0.4



c
Orem et al. (2007)
4-Hydroxy-3-methoxy-
benzaldehyde
4.31



c
Orem et al. (2007)
4-Propyl-xanthen-9-one
0.03

0.07

c
Orem et al. (2007)
5-(l,l-Dimethylethyl)-lH-
indene
0.03

0.1

c
Orem et al. (2007)
5,6-
Azulenedimethanol,l,2,3,3a,8,
0.4



c
Orem et al. (2007)
7-Bromomethyl-pentadec-7-
ene
2.77



c
Orem et al. (2007)
7-Bromomethyl-pentadec-7-
ene
0.92



c
Orem et al. (2007)
7-Ethenylphenanthrene
0.04

0.22

c
Orem et al. (2007)
7-Tetradecyne
0.38



c
Orem et al. (2007)
8-Hexadecyne
0.28



c
Orem et al. (2007)
8-lsopropyl-2,5-dimethyl-
terralin
0.36



c
Orem et al. (2007)
9,10-Dimethoxy-2,3-
dihydroanthracene
0.04

0.34

c
Orem et al. (2007)
9H-Fluoren-9-ol
0.07

0.32

c
Orem et al. (2007)
E-49

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
9-Methoxyfluorene
0.06

0.18

c
Orem et al. (2007)
9-Methoxyfluorene
0.54



c
Orem et al. (2007)
9-Phenyl-tetrahydro-lH-
benz[f]isoindol-l-one
0.24



c
Orem et al. (2007)
9-Phenyl-tetrahydro-lH-
benz[f]isoindol-l-one
0.24



c
Orem et al. (2007)
Acetone
16,000



s
Lester et al. (2015)
Alkyl benzene
74,630
1,119,350
5,092,600
1,698,910
s
Khan et al. (2016)
Alkyl naphthalene
380
1,460
4,200
1,180
s
Khan et al. (2016)
Alkyl propo-benzene
9,340
61,900
209,150
67,220
s
Khan et al. (2016)
Benzene
1,500
107,320
778,510
271,570
s
Khan et al. (2016)
Benzenemethanol
0.33



c
Orem et al. (2007)
Benzisothiazole derivative
0.06

0.32

c
Orem et al. (2007)
Benzothiazole
0.51

14.27

c
Orem et al. (2007)
Benzyl butyl phthalate
0.04

0.33

c
Orem et al. (2007)
Biphenyl
0.16

0.3

c
Orem et al. (2007)
Bis(2-ethylhexyl) phthalate
29



s
Lester et al. (2015)
Bis(2-ethylhexyl)-hexanedioic
acid
0.13

0.7

c
Orem et al. (2007)
Bis-(octylphenyl)-amine
0.05

0.19

c
Orem et al. (2007)
Butanoic acid, butyl ester
0.44



c
Orem et al. (2007)
E-50

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
butyl benzyl phthalate
4.2



s
Lester et al. (2015)
Caffeine
0.09

0.5

c
Orem et al. (2007)
Chloro-benzene
20
100
350
110
s
Khan et al. (2016)
Cholesterol
0.26



c
Orem et al. (2007)
Cyclotriacontane
1.08



c
Orem et al. (2007)
Dibutyl phthalate
<=1.27



c
Orem et al. (2007)
Didecyl phthalate
<=7.23



c
Orem et al. (2007)
Diethyl phthalate
<=14.9



c
Orem et al. (2007)
Dihydro-(-)-neocloven-(ll)
0.1

1.04

c
Orem et al. (2007)
Dihydro-l-methylphenanthrene
1.06



c
Orem et al. (2007)
Dihydrophenanthrene
0.03

0.48

c
Orem et al. (2007)
Dimethyl phthalate
0.11

0.28

c
Orem et al. (2007)
15



s
Lester et al. (2015)
Dimethyl-biphenyl
0.07

2.01

c
Orem et al. (2007)
Dimethyl-ethylindene
0.02

0.07

c
Orem et al. (2007)
Dimethylnaphthalene
0.01

1.44

c
Orem et al. (2007)
Dimethylphenanthrene
0.62

1.49

c
Orem et al. (2007)
Dimethylphenol
1.38



c
Orem et al. (2007)
Dimethyl-
tetracyclo[5.2.1.0(2,6)-
0(3,5)]decane
0.27



c
Orem et al. (2007)
E-51

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
Di-n-octyl phthalate
0.58

4.63

c
Orem et al. (2007)
Dioctyldiphenylamine
0.03

0.18

c
Orem et al. (2007)
Diphenylamine
0.04

3.73

c
Orem et al. (2007)
Diphenylmethane
0.01

0.43

c
Orem et al. (2007)
Di-tetra-butyl-4-
hydroxbenzaldehyde
0.16

0.53

c
Orem et al. (2007)
Docosane
1.94



c
Orem et al. (2007)
Dodecanoic acid
1.33

1.7

c
Orem et al. (2007)
Drometrizole
0.91



c
Orem et al. (2007)
Ethylbenzene
2,010
72,610
399,840
134,630
s
Khan et al. (2016)
Ethyl dimethyl azulene
0.46



c
Orem et al. (2007)
Ethyl phenylmethyl benzene
0.1



c
Orem et al. (2007)
Ethyl-cyclodocosane
1.54



c
Orem et al. (2007)
Ethyl-cyclodocosane
0.65



c
Orem et al. (2007)
Ethyl-tetrahydronaphthalene
0.46



c
Orem et al. (2007)
Fluorene
0.05

0.24

c
Orem et al. (2007)
Heptacosane
0.95



c
Orem et al. (2007)
Hexacosane
1.73



c
Orem et al. (2007)
Isopropyl myristate
1.79



c
Orem et al. (2007)
Kaur-16-ene
0.06

1.36

c
Orem et al. (2007)
E-52

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
Methoxyanthracene
0.04

0.22

c
Orem et al. (2007)
Methoxynaphthalene
derivative
0.04

0.25

c
Orem et al. (2007)
Methyl-(2,5-dimethoxyphenol)-
methanoate
0.31



c
Orem et al. (2007)
Methyl(Z)-3,3-diphenyl-4-
hexenoate
2



c
Orem et al. (2007)
Methyl-2-octylcyclopropene-l-
octane
0.38



c
Orem et al. (2007)
Methyl-2-quinolinecarboxylic
acid
6.65



c
Orem et al. (2007)
Methyl-9H-fluorene
0.52

1.16

c
Orem et al. (2007)
Methylanthracene
0.07

0.48

c
Orem et al. (2007)
Methyl-biphenyl
0.15

1

c
Orem et al. (2007)
Methylethylnaphthalene
0.55



c
Orem et al. (2007)
Methylnaphthalene
0.14

0.48

c
Orem et al. (2007)
Methylphenanthrene
0.03

1.37

c
Orem et al. (2007)
Methylpyrene
0.01

0.02

c
Orem et al. (2007)
Naphthalene
0.26

0.66

c
Orem et al. (2007)
Naphthalenone derivative
0.11

1.38

c
Orem et al. (2007)
n-Hexadecanoic acid
0.63

2.56

c
Orem et al. (2007)
Nonyl-phenol
0.09

7.91

c
Orem et al. (2007)
E-53

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
Octahydroanthracene
0.54



c
Orem et al. (2007)
Other alkyl phenols
<=5.89



c
Orem et al. (2007)
Other aromatic compounds
0.01

0.42

c
Orem et al. (2007)
Other benzenamines
0.06

0.25

c
Orem et al. (2007)
Other benzene alkyl
compounds
0.02

0.62

c
Orem et al. (2007)
Other heterocyclics
<=17.87



c
Orem et al. (2007)
Other indene derivatives
0.09

0.16

c
Orem et al. (2007)
Other naphthalene alkyl
compounds
0.04

0.82

c
Orem et al. (2007)
Other phthalates
<=18.68



c
Orem et al. (2007)
Other terpenoid compounds
0.12

0.37

c
Orem et al. (2007)
Pentacosane
1.54



c
Orem et al. (2007)
Pentadecanoic acid
0.84



c
Orem et al. (2007)
Phenanthrene
0.06

0.52

c
Orem et al. (2007)
3



s
Lester et al. (2015)
Phenanthrene derivative
0.07



c
Orem et al. (2007)
Phenanthrene-l-carboxlic acid
0.02

0.12

c
Orem et al. (2007)
Phenanthrenone
0.05

0.09

c
Orem et al. (2007)
Phenol
830



s
Lester et al. (2015)
Phosphoric acid, tributyl ester
0.1

18.96

c
Orem et al. (2007)
E-54

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
Propane-diphenyl
0.03

0.22

c
Orem et al. (2007)
p-Tert-butylphenol
0.07

0.19

c
Orem et al. (2007)
p-Xylene
10
150
460
160
s
Khan et al. (2016)
Pyrene
0.01

0.04

c
Orem et al. (2007)
0.9



s
Lester et al. (2015)
Pyreno[4,5-c]furan
1.83



c
Orem et al. (2007)
Quinolo-furazan derivative
0.82



c
Orem et al. (2007)
Squalene
<=0.24



c
Orem et al. (2007)
Sterane
0.51



c
Orem et al. (2007)
Tetracosane
1.86



c
Orem et al. (2007)
Tetradecane
0.54



c
Orem et al. (2007)
Tetradecanoic acid
0.15

0.54

c
Orem et al. (2007)
Tetrahydro-
dimethylnaphthalene
0.19

3.25

c
Orem et al. (2007)
Tetrahydromethylnaphthalene
0.01

0.69

c
Orem et al. (2007)
Tetrahydronaphthalene
0.06

0.82

c
Orem et al. (2007)
Tetrahydrophenanthrene
0.03

0.42

c
Orem et al. (2007)
Tetrahydro-
trimethylnaphthalene
0.5



c
Orem et al. (2007)
Tetramethylacenaphthylene
0.03

0.07

c
Orem et al. (2007)
Tetramethylnaphthalene
0.43

0.79

c
Orem et al. (2007)
E-55

-------
Appendix E - Produced Water Handling Supplemental Information
Chemical
Minimum or
only value
(ms/l)
Average
(Hg/L)
Maximum
(M-g/ L)
Standard
deviation
(M-g/ L)
Formation type
(S for shale,
C for coalbed)
Reference
Tetramethylphenanthrene
0.01

0.68

c
Orem et al. (2007)
Toluene
100
1,560
5,610
1,940
s
Khan et al. (2016)
Total xylenes
30



s
Lester et al. (2015)
Tricosane
1.7



c
Orem et al. (2007)
Tricyclo[4.4.0.0(3,9)]decane
0.26



c
Orem et al. (2007)
Tridecanedial
0.86



c
Orem et al. (2007)
Trimethoxy-benzaldehyde
0.39



c
Orem et al. (2007)
Trimethylnaphthalene
0.04

2.6

c
Orem et al. (2007)
Trimethylphenanthrene
0.04

0.12

c
Orem et al. (2007)
Triphenyl phosphate
0.07

0.21

c
Orem et al. (2007)
E-56

-------
Appendix E - Produced Water Handling Supplemental Information
E.3.6. Chemical Reactions
Section 7.3.4.9 describes general aspects of subsurface chemical reactions that might occur during
hydraulic fracturing operations. Here we augment the discussion by describing subsurface chemical
processes.
E.3.6.1. Injected Chemical Processes
Hydraulic fracturing injects relatively oxygenated fluids into a reducing environment, which may
mobilize trace or major constituents into solution. Injection of oxygenated fluids may lead to
short-term changes in the subsurface redox state, as conditions may shift from reducing to
oxidizing. The chemical environment in hydrocarbon-rich unconventional reservoirs, such as black
shales, is generally reducing, as evidenced by the presence of pyrite and methane (Engle and
Rowan. 2014: Dresel and Rose. 20101. For black shales, reducing conditions are a product of
original accumulations of organic matter whose decay depleted oxygen to create rich organic
sediments within oil- and gas-producing formations fTourtelot. 1979: Vine and Tourtelot. 19701.
Yet reactions resulting from temporary redox shifts are likely to be less important than those
resulting from other longer-term physical and geochemical processes. Temporary subsurface redox
shifts may be due to the short timeframe for fluid injection (a few days to a few weeks).
Hydraulic fracturing fluid injection introduces novel chemicals into the subsurface.1 As such, the
geochemistry of injected and native fluids will not be in equilibrium. Over the course of days to
months, a complex series of reactions will equilibrate disparate fluid chemistries. The evolution of
flowback and produced water geochemistry are dependent upon the exposure of formation solids
and fluids to novel chemicals within hydraulic fracturing fluid. Additives interact with reservoir
solids and either mobilize constituents or themselves become adsorbed to solids. Such additives
include metallic salts, elemental complexes, salts of organic acids, organometallics, and other metal
compounds (Montgomery. 2013: House of Representatives. 20111.
The salts, elemental complexes, organic acids, organometallics, and other metal-containing
compounds may interact with metals and metalloids in the target formation through processes
such as ion exchange, adsorption, desorption, chelation, and complexation. For instance, natural
organic ligands (e.g., citrate) are molecules that can form coordination compounds with heavy
metals such as cadmium, copper, and lead fMartinez and McBride. 2001: Stumm and Morgan. 1981:
Bloomfield etal.. 19761. Citrate-bearing compounds are used in hydraulic fracturing fluids as
surfactants, iron control agents, and biocides. Studies of the additives' interactions with formation
solids at concentrations representative of hydraulic fracturing fluids are lacking.
Furthermore, pH will likely play a role in the nature and extent of these processes, as the low pH of
hydraulic fracturing fluids may mobilize trace constituents. The pH of hydraulic fracturing fluids
may differ from existing subsurface conditions due to the use of dilute acids (e.g., hydrochloric or
acetic) used for cleaning perforations and fractures during hydraulic fracturing treatments
fMontgomery. 2013: GWPC and ALL Consulting. 20091. Metals within formation solids may be
1 For more information on additive usage, refer to Chapter 5 (Chemical Mixing].
E-57

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Appendix E - Produced Water Handling Supplemental Information
released through the dissolution of acid-soluble phases such as iron and manganese oxides or
hydroxides fYang et al.. 2009: Kashem et al.. 2 007: Filgueiras etal.. 20021. Thus, the pH of hydraulic
fracturing fluids, or changes in system pH that may occur as fluid recovery begins, may influence
which metals and metalloids are likely to be retained within the formation and which may be
recovered in flowback. Ultimately, more research is needed to fully understand how the injection of
hydraulic fracturing fluids affects subsurface geochemistry and resultant flowback and produced
water chemistry.
E.3.7. Microbial Community Processes and Content
By design, hydraulic fracturing releases hydrocarbons and other reduced mineral species from
freshly fractured shale, sandstone, and coal, resulting in saltier in situ fluids, the release of
formation solids, and increased interconnected fracture networks with rich colonization surfaces
that are ideal for microbial growth fWuchter etal.. 2013: Curtis. 20021. The use of biocides, in
contrast, is intended to inhibit microbial growth. Recent work by Kahrilas et al. fin Pressl
performed laboratory experiments to simulate downhole chemistry of the biocide glutaraldehyde
at 200 °C temperature, 10 MPa pressure, and high salinity. The laboratory results suggested that in
hot, alkaline shales, the effectiveness of glutaraldehyde as a biocide is limited by contact time; and
is not so limited in cooler, more acidic, saline formations like the Marcellus.
Depending upon the formation, microorganisms may be native to the subsurface and/or introduced
from non-sterile equipment and fracturing fluids. Additionally, microorganisms compete for novel
organics in the form of additives fWuchter etal.. 2013: Arthur etal.. 20091. Since large portions of
hydraulic fracturing fluid can remain emplaced in the targeted formation, long-term microbial
activity is supported through these novel carbon and energy resources fOrem etal.. 2014: Murali
Mohan etal.. 2013a: Struchtemever and Elshahed. 2012: Bottero etal.. 20101. Such physical and
chemical changes to the environment at depth stimulate microbial activity and influence flowback
and produced water content in important ways.
Several studies characterizing produced water from unconventional reservoirs (i.e., the Barnett,
Marcellus, Utica, and Antrim Shales) indicate thattaxa with recurring physiologies compose shale
flowback and produced water microbial communities (Murali Mohan etal.. 2013b: Wuchter etal..
20131. Such physiologies include sulfur cyclers (e.g., sulfidogens: sulfur, sulfate, and thiosulfate
reducers); fermenters; acetogens; hydrocarbon oxidizers; methanogens; and iron, manganese, and
nitrate reducers (Davis etal.. 20121.
Based on their physiologies, microorganisms cycle substrates at depth by mobilizing or
sequestering constituents in and out of solution. Mobilization can occur through biomethylation,
complexation, and leaching. Sequestration can occur through intracellular sequestration,
precipitation, and sorption to biomass.
The extent to which constituents are mobilized or sequestered depends upon the prevailing
geochemical environment after hydraulic fracturing and through production. Significant
environmental factors that influence the extent of microbially mediated reactions are increases in
ionic content (i.e., salinity, conductivity, total nitrogen, bromide, iron, and potassium); decreases in
E-58

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Appendix E - Produced Water Handling Supplemental Information
acidity, and organic and inorganic carbon; the availability of diverse electron acceptors and donors;
and the availability of sulfur-containing compounds fCluffetal.. 2014: Murali Mohan etal.. 2013b:
Davis etal.. 20121. Examples follow that illustrate how subsurface microbial activity influences the
content of produced water.
Under prevailing anaerobic and reducing conditions, microorganisms can mobilize or sequester
metals found in produced water from unconventional reservoirs (Gadd. 20041. Microbial enzymatic
reduction carried out by chromium-, iron-, manganese-, and uranium-reducing bacteria can both
mobilize and sequester metals fVanengelen etal.. 2008: Garcia etal.. 2004: Mata etal.. 2002:
Gauthier etal.. 1992: Myers and Nealson. 1988: Lovlev and Phillips. 19861. For instance, iron and
manganese species go into solution when reduced, while chromium and uranium species
precipitate when reduced fGadd. 2004: Newman. 2001: Ahmann et al.. 19941.
Metals can also be microbially solubilized by complexing with extracellular metabolites,
siderophores (metal-chelating compounds), and microbially generated bioligands (e.g., organic
acids) fGlorius etal.. 2008: Francis. 2007: Gadd. 2004: Hernlem etal.. 19991. For example,
Pseudomonas spp. secrete acids that act as bioligands to form complexes with uranium(VI) fGlorius
etal.. 20081.
Many sulfur-cycling taxa have been found in hydraulic fracturing flowback and produced water
communities fMurali Mohan etal.. 2013b: Mohan etal.. 20111. Immediately following injection,
microbial sulfate reduction is stimulated by diluting high-salinity formation waters with fresh
water (high salinities inhibit sulfate reduction). Microbial sulfate reduction oxidizes organic matter
and decreases aqueous sulfate concentrations, thereby increasing the solubility of barium (Cheung
etal.. 2010: Lovlev and Chapelle. 19951.
Sulfidogens also reduce sulfate, as well as elemental sulfur and other sulfur species (e.g.,
thiosulfate) prevalent in the subsurface, contributing to biogenic sulfide or hydrogen sulfide gas in
produced water (Alain etal.. 2002: Ravotetal.. 19971. Sulfide can also sequester metals in sulfide
phases (Ravotetal.. 1997: Lovlev and Chapelle. 19951. Sources of sulfide also include formation
solids (e.g., pyrite in shale) and remnants of drilling muds (e.g., barite and sulfonates), or other
electron donor sources fDavis etal.. 2012: Kim etal.. 2010: Collado etal.. 2009: Grabowski etal..
20051.
Additionally, anaerobic hydrocarbon oxidizers associated with shale produced water can readily
degrade simple and complex carbon compounds across a considerable salinity and redox range
fMurali Mohan etal.. 2013b: Fichter etal.. 2012: Timmis. 2010: Lalucatetal.. 2006: Yakimov etal..
2005: McGowan et al.. 2004: Hedlund etal.. 2001: Cavol etal.. 1994: Gauthier etal.. 1992: Zeikus et
al.. 19831.
Lastly, microbial fermentation produces organic acids, alcohols, and gases under anaerobic
conditions, as is the case during methanogenesis. Some nitrogen-cycling genera have been
identified in shale gas systems. These include genera involved in nitrate reduction and
denitrification (Kim etal.. 2010: Yoshizawa etal.. 2010: Yoshizawaetal.. 2009: Lalucatetal.. 20061.
E-59

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These genera likely couple sugar, organic carbon, and sulfur species oxidation to nitrate reduction
and denitrification processes.
Consequently, using a variety of recurring physiologies, microorganisms mobilize and sequester
constituents in and out of solution to influence the content of produced water.
E.4. Produced Water Content Spatial Trends
E.4.1. Variability between Plays of the Same Rock Type
E.4.1.1. Shale Formation Variability
The content of shale produced water varies geographically, as shown by data from four formations
(the Bakken, Barnett, Fayetteville, and Marcellus Shales; see Table E-2, Table E-4, Table E-6, Table
E-8, Table E-9, and Table E-ll). For several constituents, variability between shale formations is
common. The average/medianTDS concentrations in the Marcellus (87,800 to 106,390 mg/L ) and
Bakken (196,000 mg/L) Shales are one order of magnitude greater than the average TDS
concentrations reported for the Barnett and Fayetteville Shales (Table E-2). As Fayetteville
produced water contains the lowest reported average TDS concentration (13,290 mg/L), average
concentrations for many inorganics (i.e., bromide, calcium, chloride, magnesium, sodium, and
strontium) that contribute to dissolved solids loads are the lowest compared to average
concentrations for the same inorganics in Bakken, Barnett, and Marcellus produced water (Table
E-4 and Table E-6). Average concentrations for metals reported within Bakken and Marcellus
produced water are also higher than those within the Barnett or Fayetteville formations (Table
E-6).
Additionally, Marcellus produced water is enriched in barium (average concentration of 2,224 mg/1
in Barbotetal. (2013) or median calculated from Hayes (2009) of 542.5 mg/L) and strontium
(average concentration of 1,695 mg/L (Barbot etal.. 2013) or median calculated from Hayes (2009)
of 1,240 mg/L) by one to three orders of magnitude compared to Bakken, Barnett, and Fayetteville
produced water (Table E-6). Subsequently, radionuclide variability expressed as isotopic ratios
(e.g., radium-228/radium-226, strontium-87/strontium-86) are being used to determine the
reservoir source for produced water (Chapman etal.. 2012: Rowan etal.. 2011: Blauch etal.. 2009).
Lastly, Barnett and Bakken produced waters are enriched in sulfate.
Although organic data are limited, average BTEX concentrations are higher in Marcellus compared
to Barnett produced water by one order of magnitude, whereas concentrations of benzene alone
are marginally higher in Barnett compared to Marcellus produced water (Table E-9 and Table
E-ll).
E.4.1.2. Tight Formation Variability
The average concentrations for various constituents in tight formation produced water vary
geographically between sandstone formations (the Cotton Valley Group, Devonian sandstone, and
the Mesaverde and Oswego), as shown in Table E-2, Table E-4, Table E-6, Table E-8, and Table E-9.
The average TDS concentrations in the Devonian sandstone (235,125 mg/L) and Cotton Valley
E-60

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Appendix E - Produced Water Handling Supplemental Information
Group (164,683 mg/L) are one to two orders of magnitude greater than the average TDS
concentrations reported for the Mesaverde (15,802 mg/L) and Oswego Formations (73,082 mg/L)
(Table E-2). Mesaverde produced water also contained the lowest average concentrations for many
of the inorganic components of TDS (i.e., calcium, chloride, iron, magnesium, and sodium) (Table
E-4 and Table E-6).
Little variability was reported in pH between these four tight formations (E-2). Mesaverde
produced water was enriched in sulfate, with an average concentration of 837 mg/L (Table E-4),
whereas Devonian produced water was enriched in barium, which had an average concentration of
1,488 mg/L (Table E-6).
E.4.1.3. Coalbed Variability
Geochemical analysis showed that the Powder River Basin is predominately characterized by
bicarbonate water types with a large intrusion of sodium-type waters across a large range of
magnesium and calcium concentrations fDahm etal.. 20111.1 In contrast, the Raton Basin is typified
by sodium-type waters with low calcium and magnesium concentrations. A combination of Powder
River and Raton produced water compositional characteristics typifies the San Juan Basin (Dahm et
al.. 20111. Lastly, Black Warrior Basin produced water is differentiated based upon its sodium
bicarbonate- or sodium chloride-type waters fDOE. 2014: Pashin etal.. 20141.
Regional variability is observed in average produced water concentrations for various constituents
of four CBM basins (Powder River, Raton, San Juan, and Black Warrior (Table E-3, Table E-5, Table
E-7, Table E-9, and Table E-12), but particularly between produced water of the Black Warrior
Basin and the others. As the average TDS concentration in Black Warrior Basin produced water
(14,319 mg/L) is one to two orders of magnitude higher than that of the other three presented in
Table E-5, average concentrations for TDS contributing ions (i.e., calcium, chloride, and sodium)
were also higher than in the Powder River, Raton, and San Juan Basins. These high levels follow
from the marine depositional environment of the Black Warrior Basin fHorsev. 19811.
Powder River Basin produced water has the lowest average TDS concentration (997 mg/L), which
is consistent with Dahm etal. f20111 reporting that nearly a quarter of all the produced water
sampled from the Powder River Basin meets the U.S. drinking water secondary standard for TDS
(less than 500 mg/L).2 In addition, the Black Warrior Basin appears to be slightly enriched in
barium, compared to the other three CBM basins (Table E-5). Lastly, the three western CBM basins
1 Water is classified as a "tyPe" if the dominant dissolved ion is greater than 50% of the total. A sodium-type water
contains more that 50% of the cation milliequivalents (mEq] as sodium. Similarly, a sodium-bicarbonate water contains
50%o of the cation mEq as sodium, and 50%> ofthe anion mEq as bicarbonate fUSGS. 20021.
2 MCL refers to the highest level of a contaminant that is allowed in drinking water. MCLs are enforceable standards. These
include primary MCLs for barium, cadmium, chromium, lead, mercury, and selenium. National Secondary Drinking Water
Regulations (NSDWRs or secondary standards] are non-enforceable guidelines regulating contaminants that may cause
cosmetic effects (such as skin or tooth discoloration] or aesthetic effects (such as taste, odor, or color] in drinking water.
Secondary MCLs are recommended for aluminum, chloride, copper, iron, manganese, pH, silver, sulfate, TDS, and others.
See http://water.epa.gOv/drink/contaminants/index.cfm#Primarv for more information.
E-61

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(Powder River, Raton, and San Juan) are much more alkaline and enriched in bicarbonate than their
eastern counterpart (the Black Warrior Basin; Table E-3).
Average concentrations of benzene, ethylbenzene, and xylenes are higher in San Juan compared to
Raton produced water by two orders of magnitude, whereas concentrations of toluene are
marginally higher in Raton compared to San Juan produced water (Table E-9).
E.4.2. Local Variability
Spatial variability of produced water content frequently exists within a single producing formation.
For instance, Marcellus Shale barium levels increase along a southwest to northeast transect
(Barbotetal.. 20131. Additionally, produced water from the northern and southern portions of the
San Juan Basin differ in TDS, due to groundwater recharge in the northern basin leading to higher
chloride concentrations than in the southern portion fDahm etal.. 2011: Van Voast. 20031.
Spatial variability of produced water content also exists at a local level due to the stratigraphy
surrounding the producing formation. For example, deep saline aquifers, if present in the over- or
underlying strata, may over geologic time encroach upon shales, coals, and sandstones via fluid
intrusion processes fBlauch etal.. 20091. Evidence of deep brine migration from adjacent strata into
shallow aquifers via natural faults and fractures has been noted previously in the Michigan Basin
and the Marcellus Shale (Vengosh etal.. 2014: Warner etal.. 2012: Weaver etal.. 19951. By
extension, in situ hydraulic connectivity, which is stimulated by design during hydraulic fracturing,
may lead to the migration of brine-associated constituents in under- and overlying strata into
producing formations, as discussed in Chapter 6.
E.5. North Dakota Spill Analysis
E.5.1. Materials and Methods
Incidents were reported to the North Dakota Department of Health from across the Bakken Gas
Shale, Late Devonian to Early Mississippian in age. We reviewed incidents occurring during the
years 2001-2015, and categorized them by release type: salt water (SW), oil, and other.1 First, two
years (2014 and 2015) of Oil Field dataset was retrieved from the North Dakota Spills Database
Website operated by the North Dakota Department of Health, Division of Water Quality
f http://www.ndhealth.gOv/EHS/Spills/l. The entire public dataset to date was later (March 15,
2016) obtained directly from the ND Department of Health for our analysis of the years 2001 to
2015. The data from 2014 and 2105 were used to summarize causes of spills.
Our method of data-cleaning involved eliminating data with empty cells (NA), or reports of "0"
values. If data were presented as "0" bbl or gal for SW, oil, and other spills, we omitted those values
from the dataset (n= 434). Additionally, cells containing "0" or "NA" for SW, oil, and other reported
spills were omitted from the dataset (n= 98). A single spill with unit "lbs", referring to dust used in
1 The "other" category also includes spills categorized as: freshwater, condensate, drilling mud, injection fluid, emulsion,
injection chemical, petroleum, product, misc, uncharacterized, oil and water, freshwater and brine, and drill cuttings.
Some incidents did not release a liquid as, for example, the release could have only been gas.
E-62

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Appendix E - Produced Water Handling Supplemental Information
processing of drill cuttings, was omitted (n=l). All values were converted to barrels (bbl when
necessary).
The dataset containing SW, oil, and other, was further divided into three datasets based on spill
type. The compiled statistics only included releases with volumes above (SW: n=6238, oil: n=4882,
and other: n=9863). Unlike the Oklahoma study reported in the main text fFisher and Sublette.
20051. we are not able to identify salt water spills whose volume was not estimated.
The spill rates were determined by dividing the spill counts and volumes by the number of active
production wells. The latter data were obtained from the North Dakota Oil and Gas Division web
site fhttps://www.dmr.nd.gov/oilgas/stats/statisticsvw.asp). Monthly well counts are available for
the years of interest, and we used the active well count for December of each year in our
calculations. Alternatively different months or the average for the entire year could be used.
Through testing we found no meaningful differences in the estimates. The median (or middle)
volume of produced water (SW) spills was consistently about 340 gal (1,300 L) for the period 2001
to 2015 (Figure 7-13).1 The data are represented by box plots in the main text (Figure E-6).
Maximum
75th percentile
50th percentile (median)
25th percentile
Minimum
Figure E-6. Illustration of a "box" or "box and whisker" plot.
1 50% of spill volumes were below and 50% above the median value. Medians are less sensitive to extreme values than
means (averages]. Means above the median indicate that the distribution is skewed by a relatively small number of
incidents with high spill volumes.
E-63

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Appendix E - Produced Water Handling Supplemental Information
E.5.2. Results
For comparison with the other types of spilled liquids, after 2009 the median volume for oil spills
tended toward 130 gal (480 L) for oil (Figure H-7) and 210 gal (790 L) for all other spills (Figure
E-8). In each case, however, the mean numbers of spills were higher than the medians, indicating
that although the majority of SW spills were 340 gal (1,300 L) or less, larger volume spills occurred
and increased the mean value. For SW spills, the largest spill recorded was 2,900,000 gal
(11,000,000 L) occurring in January 2015. Although most of the SW spills contained 340 gal (1,300
L) or less, large spills (400,000 gal (11,000,000 L) or more) occurred in 2013, 2014, and 2015
(Figure 7-13).
1,000,000
100,000
cu
3

10,000
1,000
100






¦
/ \
~
D r





\
i
/
/
/
]













> ' * * '
1	 1 1
> o
	1
-	Median
-	Mean
-	Maximum
2000 2002 2004 2006 2008 2010 2012 2014 2016
Year
Figure E-7. Median, mean, and maximum volume of oil spills in North Dakota for 2001 to
2015.
E-64

-------
Appendix E - Produced Water Handling Supplemental Information
10,000,000
Mean
Maximum
100 -I—
2000 2002 2004 2006 2008 2010 2012 2014 2016
Year
Figure E-8. Median, mean, and maximum volume of "other" spills in North Dakota for 2002 to
2015.
The number of spills increased with increasing numbers of active wells (Figure E-9). Each type of
spill decreased from 2014 to 2015 (Figure E-9). From 2001 to 2007 the rate of oil and produced
water spills were roughly the same (Figure E-9), afterwards there were fewer produced water
spills. From 2010 to 2015, the rate of produced water spills ranged from 4.7 to 7.2 per hundred
active wells; oil spills from 6.1 to 10.0 per hundred active wells and other spills from 1.7 to 3.7 per
hundred active wells. By the end of 2015 there were over 13,000 active production wells in North
Dakota, and these fractions corresponded to 613 produced water, 825 oil, and 369 other spills
(Figure E-9). Although there were more oil than produced water spills, the median and maximum
produced water spills were larger than the median oil spills.
E-65

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Appendix E - Produced Water Handling Supplemental Information
14,000
12,000
10,000
4,000
2,000
3 —9	8	S-—£
2000 2002 2004 2006 2008 2010 2012 2014 2016
Year
Figure E-9. Count of spills and active wells in North Dakota for the years 2001 to 2015.
-------
Appendix E - Produced Water Handling Supplemental Information
SW Total
SW Contained
SW Not Contained
nrrTTfTmf
^ O -
rrTlTffTtff
mnrTfVn-rl I I j~H
2001-2015
2001-2015
2001-2015
Oil Total
1-nrffflTTT
Oil Contained
J2 o —
¦n-rrffflTT
Oil Not Contained

2001-2015
2001-2015
2001-2015
Other Total
Other Contained
Other Not Contained
-JTffh
= o -
Q- to
CO
a3
5 g
—rTrriTi
= O -
2001-2015
2001-2015
2001-2015
Figure E-10. Number of spills in North Dakota from 2001 to 2015 separated by type arid by
"contained" versus "not contained."
E-67
-------
Appendix E - Produced Water Handling Supplemental Information
Total
Contained
Not Contained
= o _
dhnndW]
nrmmfWrm
rrMfljl Tlhi
2001-2015
2001-2015
2001-2015
2001-2015	2001-2015	2001-2015
Figure E-ll. Median volume (gal) of spills in North Dakota from 2001 to 2015 separated by
type and by "contained" versus "not contained."
E-68
-------
Appendix E - Produced Water Handling Supplemental Information
Total
Contained
Not Contained
r-TTmHTh-rff
x ¦' rj i rm

al
2001-2015
2001-2015
2001-2015
S
E
rs
co
Hrfiln

2001-2015
2001-2015
2001-2015
E
=:
f)
JU

2001-2015	2001-2015	2001-2015
Figure E-12. Yearly sum of spill volume (gal) of spills in North Dakota from 2001 to 2015
separated by type and by "contained" versus "not contained."
The distribution of spills of each type is skewed. For 2015, the medians range from 8 to 80 gal (300
to 3,000 L) (considering contained and not contained of each type) but the maximums are much
higher ranging from 50,000 to 2,900,000 gal (190,000 to 11,000,000 L) (Table E-14 and Table
E-15). Further, the maximums are much higher than the 75th percentiles, indicating a relatively
small number of large spills. Only a very few spills occur that are greater than 20,000 gal (80,000 L)
(Table E-16). In the case of produced water, there were 12 spills over 20,000 gal (80,000 L), five
over 40,000 gal (160,000 L), and one greater than 400,000 gal (1,600,000 L) (Table E-16).
E-69
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Appendix E - Produced Water Handling Supplemental Information
Spill causes were discussed for the composited produced water spills in the main text Although
small in absolute numbers, proportionately more pipeline leaks, "other," and stuffing box leaks
caused produced water spills in 2015 (Figure E-14 and Figure E-15).
Table E-14. Volume distribution in gallons (minimum, 25th percentile, median, 75th percentile
and maximum) for each type of spill in INI
orth Dakota
or 2015.
Type
Spills
Min
25th
Med
75th
Max
Oil
Contained
1
40
130
420
94,000

Not Contained
1
40
80
290
105,000

All
1
40
130
340
105,000
Other
Contained
0.04
80
210
840
50,000

Not Contained
2
80
840
840
105,000

All
0.04
80
210
840
105,000
SW
Contained
1
80
340
1,300
340,000

Not Contained
1
130
420
2,100
2,900,000

All
1
80
340
1,300
2,900,000
Table E-15. Numbers of 2015 North Dakota spills in ranges defined by the spill
volume statistics (Table E-14
for each type.


Count
Type
Status
Min < x < 25th
25th < x < Med
Med < x < 75th
75th < x < Max
Oil
Contained
71
212
188
158

Not
Contained
59
29
57
51

All
130
257
217
221
Other
Contained
55
32
44
35

Not
Contained
12
9
0
21

All
67
35
50
56
SW
Contained
77
184
127
141

Not
Contained
21
18
21
24

All
94
202
163
154
E-70
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Appendix E - Produced Water Handling Supplemental Information
Table E-16. Number of 2015 North Dakota spills which exceed thresholds (20,000 gal, 40,000
gal, and 400,001
3 gal) for each type of spill.
Type
Status
Size
> 20,000 gal
> 40,000 gal
> 400,000 gal
Oil
Contained
3
3
0
Not Contained
2
1
0
All
5
4
0
Other
Contained
1
1
0
Not Contained
2
2
0
All
3
3
0
SW
Contained
6
2
0
Not Contained
6
3
1
All
12
5
1
O
LO
CM
O
LO
2014
2015
ilThrh-n
~~~n= a*,

I—
<:
o




BS
o


0
3=

0
03
CD
03
03
03
03
03
03

o
3

0
sz
0
0
0
0
0
0
l+—
CL
O
£


o








o
03
c

a)
0
XL
0
X
0
CL
0
(/)

Q_
o
o

>
C
C
o
>
E


.o
i .


o
—
03
03
_Q
o

CO

0
c
O
0
c
c

c
03
CD
Q.
Q.

0
i—
O)
c
o
Z5
Q.
0
>

03
0
i—

0
E
Q-
o






"4—'






o





to






O"
CO











0
Figure E-13. Numbers of contained spills in North Dakota by cause for 2014 and 2015.
E-71
-------
Appendix E - Produced Water Handling Supplemental Information




¦ 2014




¦ 2015
Da
i-i
DaJdL
(J
[
[
~
D
~
0

03
0)
c
o
o
0
c
c
O)
c
Q.
Q.
~0
>
03
>
Figure E-14. Numbers of not contained spills in North Dakota by cause for 2014 and 2015.
E.5.3. Summary of Additional Studies on Spills
Gross etal. (20131 analyzed the Colorado Oil and Gas Conservation Commission's database for
groundwater BTEX concentrations linked to storage and production facilities between July 2010
and July 2011 in Weld County, CO. Only spills with an impact on groundwater were included in the
study. The 77 reported spills accounted for less than 0.5% of nearly 18,000 active wells. Forty-six of
the 77 spills consisted of produced water and oil. Of the remaining spills, 23 consisted of only oil
and eight consisted of only produced water. Thus the results that follow include cases with no
produced water spill. From these composited spills, benzene concentrations in 90% of the
groundwater samples exceeded 5 |ig/L, the U.S. drinking water standard. Additionally, 30% of
toluene, 12% of ethylbenzene, and 8% of xylene sample concentrations exceeded 1 mg/L, 0.7 mg/L
and 10 mg/L, respectively fGross etal.. 20131.
Based on five spills for which volumes were reported, the average volume of a produced water spill
was 294 gal (1,110 L), ranging from 42 (160 L) to 1,176 gal (4,450 L) fGross etal.. 20131. Spill areas
averaged 2,120 ft2 (197 m2) with an average depth of 7 ft (2 m). Tank battery systems and
production facilities were the biggest volume sources of spills with groundwater impacts.
Equipment failure was the most common cause of spills with groundwater impacts. Of the 77
reported spills, secondary containment was absent from 51 of them (Gross etal.. 20131.
E-72
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Appendix E - Produced Water Handling Supplemental Information
As noted from the Colorado (Gross etal.. 20131 and Oklahoma (Fisher and Sublette. 20051 studies,
oil releases may occur alongside produced water spills. Review of recent oil field incidents in North
Dakota (from information on the state's website at http: //www.ndhealth.gOv/EHS/Spills/l also
shows incidents with both produced water and oil releases. Oil releases are characterized by a
number of features including their unique hydrocarbon composition and physical properties.
Impacts can include: surface runoff, infiltration into soils, formation of sheens and oil slicks on
surface waters, evaporation, oxidation, biodegradation, emulsion formation, and particle deposition
CU.S. EPA. 1999bl.
Brantley etal. T20141 reviewed PA DEP's online oil and gas compliance database for notices of
violation issued to companies developing gas resources in unconventional reservoirs. Between May
2009 and April 2013, eight spills of flowback and produced water ranging from more than 4,000 gal
(15,000 L) to more than 57,000 gal (220,000 L) reached surface water resources. The spills
typically resulted in local impacts to environmental receptors and required remediation and
monitoring. However, the study indicated the likelihood of a leak or spill of hydraulic fracturing-
related fluids was low (less than 1%, based on 32 large spills out of more than
4,000 complete wells). Due to lack of data, specific impacts to the eight receiving surface waters
were not discussed, other than noting the produced water had contacted the surface water.
E.6. Evaluation of Impacts
As an example of set of criteria for assessing sites potentially contaminated by hydraulic fracturing
activities, the U.S. EPA (2012el developed an approach to study sites with suspected impacts from
hydraulic fracturing activities. The approach was based on a tiered scheme where results from each
tier are used to refine activities in higher tiers. The four tiers, with some modification, are as
follows:
Verify potential issue:
•	Evaluate existing data and information from operators, private citizens, federal, state and
local agencies, and tribes (as appropriate). Including studies of local groundwater quality
that might have been conducted by USGS.
•	Conduct site visits.
•	Interview stakeholders and interested parties.
Determine approach for detailed investigations:
•	Establish sampling locations
•	Conduct initial sampling of water wells, taps, surface water, and soils.
•	Identify potential evidence of drinking water contamination.
•	Develop conceptual site model describing possible sources and pathways of the reported
or potential contamination.
•	Develop, calibrate, and test fate and transport model(s).
E-73
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Appendix E - Produced Water Handling Supplemental Information
Conduct detailed investigations to detect and evaluate potential sources of contamination:
•	Conduct additional sampling of soils, aquifer, surface water, and produced water
pits/tanks where present
•	Conduct additional testing, including further water testing with new monitoring points,
soil gas surveys, geophysical testing, well mechanical integrity testing, and stable isotope
analyses.
•	Refine conceptual site model and further test exposure scenarios.
•	Refine fate and transport model(s) based on new data.
Determine the source(s) of any impacts to drinking water resources:
•	Develop multiple lines of evidence to determine the source(s) of impacts to drinking water
resources.
•	Exclude possible sources and pathways of the reported contamination.
•	Assess uncertainties associated with conclusions regarding the source (s) of impacts.
This tiered assessment strategy provides an outline for collecting data and evaluating lines of
evidence to determine whether impacts have occurred. An outline of the quality assurance project
plan (QAPP) for the EPA's Retrospective case study in northeastern Pennsylvania: Study of the
potential impacts of hydraulic fracturing on drinking water resources fU.S. EPA. 2014d. 2012d] is
given in Table E-17, and a graphical presentation of the relationships among quality assurance
blanks is shown in Figure E-15. Table E-18 summarizes the lines of evidence used in the EPA's
Retrospective case study in Wise County, Texas: Study of the potential impacts of hydraulic fracturing
on drinking water resources fU.S. EPA. 2015il.
Table E-17. Outline of Northeastern Pennsylvania Retrospective Case Study QAPP.
Topic
Elements
Sampling Process Design
Background information on geology, hydrology, and geochemistry
Groundwater and surface water monitoring
Sampling Methods
Domestic wells
Surface waters: springs, ponds, and streams
Sampling Handling and Custody
Water sample labeling
Water sample packing, shipping, and receipt at laboratories
Analytical Methods
Groundwater and surface water
Quality Control
Quality metrics for aqueous analysis
Measured and Calculated solute concentration data evaluation
Detection limits
QA/QC calculations
E-74
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Appendix E - Produced Water Handling Supplemental Information
Topic
Elements
Instrumentation
Testing, inspection, and maintenance
Equipment calibration and frequency
Acceptance of supplies and consumables
Non-direct Data
Assurance of Quality of 3rd party data (i.e., USGS background water quality
data, university research publications)
Data Management
Recording
Storage
Analysis
Assessment and Oversight
Assessments
Assessment Reporting
Data Validation and Usability
Data review, verification, and validation
Verification and validation methods
Reconciliation with user requirements
Equipment Blank: Assess any cross-contamination in sampling, and equipment decontamination.
Analyte-free water poured through/over decontaminated field equipment
Field Blank: Assess arty cross-contamination in field sampling.
Analyte-free water poured into contain®, pt eserved, and shipped with field samples
Trip Blank: Assess contaminationintroduced during shipping and field handling. Aciean
sample of matrix taken from laboratory to field and back. Typically used only for volatiles
Method Blank: Assess contamination during laboratory sampling procedures. A blank is
prepared in the laboratory to represent the matrix as closely as possible.
<	>
Instrument Blank: Assess contamination in the instrument itself. A laboratory
blank analyzed with the field samples.
<	>
Figure E-15. Quality assurance blanks illustrating giving their purpose, brief procedure, and
the span of their scope (modified from US EPA Region 3 Quality Control Tools: Blanks, April
27, 2009).
For example, the equipment blank spans all aspects of sampling and analysis from field to laboratory, while the
instrument blank only assess contamination in the instrument itself. Reviewing results from all of these blanks
could narrow down the source of sample cross-contamination.
E-75
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Appendix E - Produced Water Handling Supplemental Information
Table E-18. Source delineation analysis table from the
EPA retrospective case study in Wise County, Texas.
Well
Technique
Brine
Sea Water
Halite/
Road Salt
Landfill
Leachate
Sewage/
Septic Tank
Animal Waste
WISETXGW01
Bromide vs. Boron
Yes
Yes
Yes
No
No
No

Chloride vs. Magnesium
Yes
Yes
No
No
No
No

Chloride vs. Bromide
Yes
Yes
Yes
No
No
Yes

Chloride vs. Bicarbonate
Yes
Yes
Yes
No
No
No

Chloride vs. Calcium
Yes
Yes
Yes
No
No
No

Chloride vs. Potassium
Yes
Yes
Yes
No
No
No

Chloride vs. Sodium
Yes
Yes
Yes
No
No
No

Chloride vs. Sulfate
Yes
Yes
Yes
No
No
No

CI/Br
Yes
Yes
Yes
Yes
No
No

Cl/I
Yes
Yes
Yes
Yes
No
Yes

K/Rb
Yes
Yes
No Data3
No Data3
No Data3
No Data3

Sr Isotope
Yes
No Data3
No Data3
No Data3
No Data3
No Data3

Percentage Of Yesb
100
100
90
20
0
20
WISETXGW05
Bromide vs. Boron
No
No
No
No
No
No

Chloride vs. Magnesium
No
No
No
No
Yes
Yes

Chloride vs Bromide
No
No
No
No
No
No

Chloride vs. Bicarbonate
No
No
No
Yes
No
Yes

Chloride vs. Calcium
No
No
No
No
Yes
Yes

Chloride vs. Potassium
Yes
Yes
Yes
Yes
Yes
Yes

Chloride vs. Sodium
Yes
No
No
Yes
Yes
Yes
E-76
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Appendix E - Produced Water Handling Supplemental Information
Well
Technique
Brine
Sea Water
Halite/
Road Salt
Landfill
Leachate
Sewage/
Septic Tank
Animal Waste
WISETXGW05,
cont.
Chloride vs. Sulfate
Yes
Yes
Yes
No
No
No
CI/Br
No
No
No
No
No
No
Cl/I
No Data3
No Data3
No Data3
No Data3
No Data3
No Data3
K/Rb
Yes
Yes
No Data3
No Data3
No Data3
No Data3
Sr Isotope
Yes
No Data3
No Data3
No Data3
No Data3
No Data3
Percentage Of Yesb
45
30
22
33
44
46
WISETXGW08
Bromide vs. Boron
Yes
Yes
Yes
No
No
No
Chloride vs. Magnesium
Yes
Yes
No
No
No
No
Chloride vs. Bromide
Yes
Yes
Yes
No
No
Yes
Chloride vs. Bicarbonate
Yes
Yes
Yes
No
No
No
Chloride vs. Calcium
Yes
Yes
Yes
No
No
No
Chloride vs. Potassium
Yes
Yes
Yes
No
No
No
Chloride vs. Sodium
Yes
Yes
Yes
No
No
No
Chloride vs. Sulfate
Yes
Yes
Yes
No
No
No
CI/Br
Yes
Yes
Yes
Yes
No
No
Cl/I
Yes
Yes
Yes
Yes
No
Yes
K/Rb
Yes
Yes
No Datab
No Datab
No Datab
No Datab
Sr lsotopeb
Yes
No Datab
No Datab
No Datab
No Datab
No Datab
Percentage Of Yesb
100
100
90
20
0
20
a Although there was no data for the other sources, the analysis done for brine sources is consistent with brines as a source of the observed impacts (see Figure 50 and the
discussion in the "Source Identification" section of this report).
b K/Rb and Sr isotope data were not found in the literature for these sources.
E-77
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Appendix E - Produced Water Handling Supplemental Information
E.7. Transport Properties
The identified constituents of flowback and produced water include inorganic chemicals in the form
of cations and anions (including various types of metals, metalloids, and non-metals, and
radioactive materials, among others) and organic chemicals, including identified compounds in
various classes, and unidentified materials measured as TOC and DOC. Environmental transport of
these chemicals depends on the properties of the chemical and properties of the environment, and
is extensively discussed in Section 5.8.3.
Transport of inorganic chemicals depends on the nature of groundwater and vadose zone flow, and
potential reactions among the inorganic chemical, solid surfaces, and geochemistry of the water.
Some inorganic anions (i.e., chloride and bromide) move with their carrier liquid and are mostly
impacted by physical transport mechanisms: flow of water and dispersion. In addition to the flow-
related processes, transport of most inorganics depends upon three mechanisms related to
partitioning to the solid phase: adsorption, absorption, and precipitation. The effects of these
mechanisms depend on both chemical and site-specific environmental characteristics, including the
surface reactivity, solubility, and redox sensitivity of the contaminant; the type and abundance of
reactive mineral phases, and the ground-water chemistry (U.S. EPA. 2007). Generalized
characterization of inorganic transport is not possible, but through the use of transport models, the
effects of physical transport mechanisms and chemical processes can be integrated. Examples of
transport models for reactive metals include the Geochemist's Workbench (Bethke. 2014) and
Hydrus (Simunek etal.. 1998).
Properties of organic chemicals which tend to affect the likelihood that a chemical will reach and
impact drinking water resources if spilled include high chemical mobility in water and low
volatility. Biodegradation, which depends on properties of the chemical, subsurface
microorganisms, and the environment, governs the fate of these contaminants.
Using the EPA chemical database EPI Suite™, we were able to obtain actual or estimated
physicochemical properties for 521 of the individual organic chemicals identified in produced
water and listed in Appendix H. A portion of these, 59, are used in the chemical mixing stage (Table
C-9). The EPI Suite™ results are constrained by their applicability to one temperature (25 °C), and
salinity (low). Temperature changes impact Henry's law constant, Kow, and solubility, and depend
on the characteristics of the chemical and ions present (Borrirukwisitsak etal.. 2012:
Schwarzenbach etal.. 2002). In some cases, the effect changes exponentially with salinity
(Schwarzenbach etal.. 2002). Therefore, property values that depart from the EPI Suite™ values
are expected for produced water at elevated temperature and salinity. Although little is known
concerning attenuation of hydraulic fracturing fluid constituents, Kekacs etal. f20151 report that
salinity above 40,000 mg/L initially inhibited aerobic degradation of the organic constituents of a
synthetic fracturing fluid (for 6.5 days), even though the bacterial communities were pre-
acclimated to the salts.
E-78
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Appendix E - Produced Water Handling Supplemental Information
E.8. Example Calculation for Roadway Transport
This section provides background information for the roadway transport calculation appearing in
Chapter 7.
An estimate of releases from truck transport of produced water could be made as follows:
Produced water volume per well
Total number of truckloads =	-	-	-	-
Produced water volume per truck
Then the total distance traveled by all trucks is given by:
Total distance traveled = Total number of truckloads x Distance per truck
The number of crashes impacting drinking water resources can be estimated from:
Fraction of crashes impacting drinking water resources
= Fraction of crashes releasing waste that impacts drinking water resources
x Fraction of all crashes releasing waste x Crash rate
x Total distance traveled
Because the chances of a crash is low, the results are expressed as one truck trip with a crash to
total truck trips without a crash (Table E-21). Estimates of all but one of the quantities in these
calculations can be made from various literature sources, which are described in the subsequent
sections. A key parameter is the number of crashes of trucks per distance traveled. In 2012, the U.S.
Department of Transportation (DOT) estimated that the number of crashes per 100 million
highway miles driven of a type of large truck was 110, which is a relatively small number. A key
parameter that is unknown is the number of crashes which impact drinking water resources, so
definitive estimates of impacts to drinking water resources cannot be made. Alternatively, as an
upper bound on drinking water resource impacts, the fraction of crashes which release waste can
be estimated.
E.8.1. Estimation of Transport Distance
In a study of wastewater management for the Marcellus Shale, Rahm etal. (20131 used data
reported to the Pennsylvania Department of Environmental Protection (PA DEP) to estimate the
average distance wastewater was transported. For the period from 2008 to 2010, the distance
transported was approximately 100 km, but it was reduced by 30% for 2011. The reduction was
attributed to increased treatment infrastructure in Lycoming County, an area of intensive hydraulic
fracturing operations in northeastern Pennsylvania. For the part of Pennsylvania within the
Susquehanna River Basin, Gilmore etal. (20131 estimated the likely transport distances for drilling
waste to landfills (256 km or 159 mi); produced water to disposal wells (388 km or 241 mi); and
commercial wastewater treatment plants (CWTPs) (158 km or 98 mi). These distances are longer
than the values from Rahm etal. (20131. in part, because wells in the Susquehanna Basin are
further to the east of Ohio disposal wells and some CWTPs.
E-79
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Appendix E - Produced Water Handling Supplemental Information
E.8.2. Estimation of Wastewater Volumes
In an example water balance calculation, Gilmore etal. (20131 used 380,000 gal (1.4 million L) of
flowback as the volume transported to CWTPs, 450,000 gal (1.7 million L) of flowback transported
to injection wells, and 130,000 gal (490,000 L) ofun-reusable treated water also transported to
injection wells for a total estimated wastewater volume of 960,000 gal (3.6 million L) per well.
E.8.3. Estimation of Roadway Accidents
The U.S. Department of Transportation (DOT) published statistics on roadway accidents fU.S.
Department of Transportation. 20121 which indicate that the combined total of combination truck
crashes in 2012 was 179,736, or 110 per 100 million vehicle miles (1.77 million km) (Table E-19).
As an indicator of the uncertainty of these data, DOT reported 122,240 large truck crashes from a
differing set of databases (Table E-20), with a rate of 75 per 100 million vehicle miles, which is 68%
of the number of combination truck crashes.
Table E-19. Combination truck crashes in 2012 for the 2,469,094 registered combination
trucks, which traveled 163,358 million miles.
Source: U.S. Department of Transportation (2012). A combination truck is defined as a truck tractor pulling any
number of trailers.
Type of crash
Combination trucks
involved in crashes
Rates per 100 million vehicle miles
traveled by combination trucks
Property damage only
135,000
82.8
Injury
42,000
25.5
Fatal
2,736
1.74
Total
179,736
110
Table E-20. Large truck crashes in 2012.
Source: U.S. Department of Transportation (2012). A large truck is defined as a truck with a gross vehicle weight
rating greater than 10,000 pounds.
Type of crash
Total crashes
Large trucks with cargo tanks
Number
Percentage
Towaway crashes
72,644
4,364
6.0%
Injury
45,794
3,245
7.1%
Fatal
3,802
360
9.5%
Totals
122,240
7,969
6.5%
E-80
-------
Appendix E - Produced Water Handling Supplemental Information
E.8.4. Estimation of Material Release Rates in Crashes
Estimates ranging from 5.6% to 36% have been made for the probability of material releases from
crashed trucks. Craft (20041 used data from three databases to estimate the probability of spills in
fatality accidents at 36%, which may overestimate the probability for all types of accidents (Rozell
and Reaven. 20121.1 The U.S. Department of Transportation f20121 provides estimates of
hazardous materials releases from large truck crashes. For all types of hazardous materials carried,
408 of 2,903 crashes, or 14%, were known to have hazardous materials releases. The occurrence of
a release was unknown for 18% of the crashes. These crashes were not distinguished by truck type,
so they likely overestimated the number of tanker crashes. Harwoodetal. (19931 used accident
data from three states (California, Illinois, and Michigan) to develop hazardous materials release
rate estimates for different types of roadways, accidents, and settings (urban or rural). For
roadways in rural settings the probability of release ranged from 8.1% to 9.0%, while in urban
settings the probability ranged from 5.6% to 6.9%.
E.8.5. Estimation of Volume Released in Accidents
Based on the estimated volumes, disposal distances, truck sizes, and accident rates used by Gilmore
etal. (20131. Rahm etal. (20131. and King (20121. the total travel distance by trucks ranges from
9,620 mi (14,900 km) to 22,875 mi (36,814 km) per well (Table E-21).
Based on the varying assumptions of each author (Gilmore etal.. 2013: King. 2012: Rahm and Riha.
20121 the chances of an accident which releases produced water over the lifetime of a well ranges
from 1:110 to 1:13,000 (Table E-21).2 These estimates are dependent on the volumes, transport
distances, and crash rates chosen for analysis. The results show, however, that the expected
number of releases is relatively low.
Several limitations are inherent in this analysis, including differing rural road accident rates and
highway rates, differing wastewater endpoints, and differing amounts of produced water transport
Further, the estimates present an upper bound on impacts, because not all releases of wastewater
would reach or impact drinking water resources.
Impacts to groundwater might occur following a spill on land. When the liquid is highly saline, its
migration is affected by its high density and viscosity compared with that of fresh water. When
spilled flowback or produced water flows over land, a fraction of the liquid is subject to infiltration.
The fraction depends on the rate of release, surface cover (i.e., pavement, cracked pavement,
vegetation, bare soil, etc.), slope of the land surface, subsurface permeability, and the moisture
content in the subsurface.
1	The three databases were the Trucks Involved in Fatal Accidents developed by the Center for National Truck Statistics at
the University of Michigan, the National Automotive Sampling System's General Estimates System (GES] produced by the
National Highway Transportation Safety Agency, and the Motor Carrier Management Information System (MCMIS] Crash
File produced by the Federal Motor Carrier Safety Administration.
2	The chances of a crash releasing produced water are calculated from the material release rate times the crash rate times
the total miles traveled. The results are expressed as 1 to the reciprocal of this number (i.e., 1:5,900].
E-81
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Appendix E - Produced Water Handling Supplemental Information
Table E-21. Chances of a crash releasing produced water based on the total produced water volume per well, transport distances,
crash rates, and material release rates.
Action
Waste per well
(million gal)
Trucks
(20 m3/truck)a
Miles traveled
per truck
Total miles
traveled
(per well)
Chances of a Crash Releasing
Produced Water
Material release rate bounds'3
3.4%
5.6%
36%
Crash rate (per 100 million miles)
28
75
110
75
110
Gilmore et al. (2013) distance estimates
Produced water to CWTP
0.38
72
29.6
2,131
n/a
n/a
n/a
n/a
n/a
Produced water to disposal
well
0.45
85
147
12,495
n/a
n/a
n/a
n/a
n/a
CWTP effluent to disposal well
0.13
25
133
3,325
n/a
n/a
n/a
n/a
n/a
Total
0.96
182

17,951
1:5,900
1:1,300
1:210
1:910
1:140
Rahm et al. (2013) distance estimates
Transport 100 km
0.96
182
62.1
11,300
1:9,300
1:2,100
1:330
1:1,400
1:220
Transport 70 km
0.96
182
43.5
9,620
1:13,000
1:3,000
1:470
1:2,100
1:320
Kina (2012) distance estimates
Assumptions of King (2012)
5.0
915
25
22,875
1:4,600
1:1,000
1:162
1:710
1:110
3 Kine (2012) assumed a truck volume of 5,440 gal (20,600 L) versus the assumption of 5,300 gal (20,100 L) for the other rows of the table.
b King (2012) assumed a release rate of 3.4% from truck crashes and an accident rate of 28 crashes per 100 million mi (160 million km).
E-82
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Appendix F. Wastewater Disposal and Reuse
Supplemental Information
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
This page is intentionally left blank.
F-2
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Appendix F. Wastewater Disposal and Reuse
Supplemental Information
This appendix provides additional information for context and background to support the
discussions of hydraulic fracturing wastewater management and treatment in Chapter 8.
Information in this appendix includes: estimates of volumes of wastewater generated compiled for
several states in regions where hydraulic fracturing is occurring; an overview of the technologies
that can be used to treat hydraulic fracturing wastewater; reported and estimated removal
efficiencies for specific treatment technologies and contaminants of concern; a description of
common technologies currently in use at centralized waste treatment plants (CWTs) and their
discharge options; considerations for water reuse in hydraulic fracturing and the necessary water
quality; and legacy impacts of hydraulic fracturing on publicly owned treatment works (POTWs).
Discussion is also provided on disinfection byproduct (DBP) formation concerns related to
hydraulic fracturing.
F.l. Estimates of Wastewater Production in Regions where Hydraulic
Fracturing is Occurring
Table F-l presents estimated wastewater volumes for several states in areas with hydraulic
fracturing activity. These data were compiled from production data available in state databases and
were tabulated by year. For California, data were compiled for Kern County, where about 95% of
California's hydraulic fracturing takes place fCCST. 2015b! Production records from Colorado,
Utah, and Wyoming include the producing formation for each well reported. Data presented for
these three states include statewide estimates as well as estimates for selected basins that were
identified in the literature as targets for hydraulic fracturing. Data from New Mexico are available in
files for three basins (the Permian, Raton, and San Juan) as well as for the state as a whole.
Results in Table F-l illustrate some of the challenges associated with obtaining estimates of
hydraulic fracturing wastewater volumes, especially using publicly available data. Some of the
estimates likely include volumes from conventional wells that are not hydraulically fractured. For
example, the well counts for California, Colorado, Utah, and Wyoming were in the thousands or tens
of thousands at least as early as 2000, several years before the surge of modern hydraulic fracturing
began in the mid-2000s. The data used for California were from Kern County where hydraulic
fracturing is conducted, but are not specific to hydraulic fracturing activity. Where producing
formations are listed, but there is no indication of whether the well was hydraulically fractured, the
accuracy of the estimates depends on whether hydraulically fractured formations were correctly
identified based on other information. If formations (and the associated wells) were inadvertently
omitted, the volumes will be underestimates.
F-3
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
Table F-l. Estimated volumes (millions of gallons) of wastewater based on state data for selected years and numbers of wells
producing fluid. The wastewater is likely associated with an unknown combination of wells not hydraulically fractured and some
hydraulically fractured.
State
Basin
Principal
lithologies
Data
type
2000
2004
2008
2010
2011
2012
2013
2014
Comments
California
San
Joaquin3
Shale,
unconsoli-
dated sands
Produced
water
46,000
48,000
58,000
65,000
71,000
75,000
74,000
-
Data from CA Department of
Conservation, Oil and Gas
Division.3 Produced water
data compiled for Kern
County. Data may also
represent contributions from
production without hydraulic
fracturing. Not specified
whether flowback is
included.



Wells
33,695
39,088
46,519
49,201
51,031
51,567
52,763

Colorado
All basins
with hy-
draulically
fractured
formations

Produced
water
7,300
11,000
21,000
14,000
12,000
12,000
7,700

Data from CO Oil and Gas
Conservation Commission.15
Produced water includes
flowback. Data filtered for
formations indicated in
literature as undergoing
hydraulic fracturing and
matched to corresponding
basins. Example basins
selected for presentation as
well as estimated state total.



Wells
11,264
14,934
28,282
33,929
35,999
38,371
37,618
-


Denver
Sandstone,
shale
Produced
water
140
160
170
160
160
150
110
-




Wells
1,829
1,511
1,277
1,204
1,193
1,131
1,072
-

F-4
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
State
Basin
Principal
lithologies
Data
type
2000
2004
2008
2010
2011
2012
2013
2014
Comments
Colorado,
cont.
Piceance
Sandstone
Produced
water
3,500
5,800
9,300
6,900
6,500
6,800
4,300
-




Wells
1,134
2,478
6,486
9,105
10,057
10,868
10,954
-


Raton
Coalbed
methane
Produced
water
2,400
4,100
8,900
4,300
3,200
2,700
2,100
-




Wells
681
1,634
2,795
2,734
2,778
2,710
2,545
-


San Juan
Coalbed
methane
Produced
water
1,000
1,100
1,300
2,000
1,200
1,100
650
-




Wells
1,183
1,605
1,975
2,220
2,308
2,328
2,333
-

New Mexico
Permian
Shale,
sandstone
Produced
water





31,000
31,000
20,000
Data from New Mexico Oil
Conservation Division.0 Data
provided by the state broken
out by basin. Unclear how
much contribution from
production without hydraulic
fracturing. Produced water
includes flowback.



Wells
-
-
-
-
-
29,839
30,386
30,287


Raton
Coalbed
methane
Produced
water
-
-
-
-
-
510
540
310




Wells
-
-
-
-
-
1,495
1,502
1,526


San Juan
Coalbed
methane
Produced
water
-
-
-
-
-
1,700
2,000
1,100




Wells
-
-
-
-
-
22,492
22,349
22,076

F-5
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
State
Basin
Principal
lithologies
Data
type
2000
2004
2008
2010
2011
2012
2013
2014
Comments
New
Mexico,
cont.
Total
"
Produced
water
-
-
-
-
-
33,000
34,000
22,000




Wells
-
-
-
-
-
53,826
54,237
53,889

Utah
All basins
with hy-
draulically
fractured
formations

Produced
water
1,200
1,200
2,300
2,400
2,700
2,900
3,400
2,800
Data from State of Utah Oil
and Gas Program.d Produced
water may or may not
include flowback. Data
filtered by formation
indicated in the literature as
hydraulically fractured and
matched to basins. Data
presented for selected basins
as well as for all formations
likely to be hydraulically
fractured.



Wells
3,080
4,377
7,409
8,432
9,101
10,075
10,661
10,900


Kaiparow-
its/ Uinta
Coalbed
methane
Produced
water
860
740
1,300
1,400
1,800
2,000
2,400
1,900




Wells
1,718
2,517
3,761
4,329
4,838
5,538
6,046
6,334


San Juan/
Uinta
Coalbed
methane
Produced
water
2
49
350
270
240
230
190
120




Wells
62
223
910
933
959
951
867
870


Uinta
Shale/sand-
stone
Produced
water
350
420
560
680
700
640
830
790




Wells
1,067
1,396
2,282
2,745
2,888
3,115
3,257
3,223

F-6
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
State
Basin
Principal
lithologies
Data
type
2000
2004
2008
2010
2011
2012
2013
2014
Comments
Wyoming
All basins
with hy-
draulically
fractured
formations

Produced
water
1,300
1,400
1,300
1,500
1,600
1,700
1,600
1,800
Data from Wyoming Oil and
Gas Conservation
Commission.6 Produced
water may include flowback.
Data filtered by formation
indicated in the literature as
hydraulically fractured and
matched to basins. Data
presented for selected basins
as well as for all formations
likely to be hydraulically
fractured.



Wells
3,470
3,378
3,585
3,620
3,728
3,843
4,030
4,213


Big Horn
Sandstone
Produced
water
380
350
350
380
430
440
420
440




Wells
365
359
387
397
412
414
407
403


Denver
Sandstone
Produced
water
54
44
49
59
76
90
97
170




Wells
142
118
124
140
167
204
230
278


Green River
Sandstone/
shale
Produced
water
0
1
2
8
5
5
9
15




Wells
44
44
60
67
67
59
64
67


Powder
River
Coalbed
methane
Produced
water
690
630
620
660
700
840
970
1,100




Wells
1,953
1,900
2,001
2,028
2,119
2,207
2,352
2,565


Wind River/
Powder
River
Sandstone/
shale
Produced
water
130
330
330
400
420
290
110
41

F-7
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
State
Basin
Principal
lithologies
Data
type
2000
2004
2008
2010
2011
2012
2013
2014
Comments
Wyoming,
cont.
Wind River/
Powder
River, cont.
Sandstone/
shale, cont.
Wells
966
957
1,013
988
963
959
977
900

a California Department of Conservation, Oil and Gas Division. Oil & Gas - Online Data. Monthly Production and Injection Databases:
ftp://ftp.consrv.ca.gov/pub/oil/new database format/.
b Colorado Oil and Gas Conservation Commission. Data: Downloads: Production Data: http://cogcc.state.co.us/data2.html#/downloads.
c New Mexico Oil Conservation Division. Production Data. Production Summaries: All Wells Data: http://gotech.nmt.edu/gotech/Petroleum Data/allwells.aspx.
d Utah Department of Natural Resources. Division of Oil, Gas, and Mining. Data Research Center. Database Download Files:
http://oilgas.ogm.utah.gov/Data Center/DataCenter.cfm#production.
e Wyoming Oil and Gas Conservation Commission. Production files by county and year:
http://wogcc. state. wv.us/productioncountvvear.cfm?Oops=#oops#&RequestTimeOut=6500.
F-8
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
F.2. Overview of Treatment Processes for Treating Hydraulic Fracturing
Wastewater
Treatment technologies discussed in this appendix are classified as basic or advanced. Basic
treatment technologies are ineffective for reducing total dissolved solids (TDS) and are typically not
labor intensive. Advanced treatment technologies can remove TDS and/or are complex in nature
(e.g., energy- and labor-intensive).
F.2.1. Basic Treatment
Basic treatment technologies include physical separation, coagulation/oxidation,
electrocoagulation, sedimentation, and disinfection. These technologies are effective at removing
total suspended solids (TSS), oil and grease, scale-forming compounds, and metals, and they can
minimize microbial activity. Basic treatment is typically incorporated in a permanent treatment
facility (i.e., fixed location), but can also be part of a mobile unit for on-site treatment applications.
F.2.1.1. Physical Separation
The most basic treatment needed for oil and gas wastewaters, including those from hydraulic
fracturing operations, is separation to remove suspended solids and oil and grease. The separation
method largely depends on the type(s) of resource (s) targeted by the hydraulic fracturing
operation. Down-hole separation techniques, including mechanical blocking devices and water
shut-off chemicals (e.g., specialized polymers) to prevent or minimize water flow to the well, may
be used during production in shale plays containing greater amounts of liquid hydrocarbons. To
treat water at the surface, separation technologies such as hydrocyclones, dissolved air or induced
gas flotation systems, media (sand) filtration, and biological aerated filters can remove suspended
solids and some organics from hydraulic fracturing wastewater.
Media filtration can also remove hardness and some metals if chemical precipitation (i.e.,
coagulation, lime softening) is also employed (Boschee. 2014). An example of a CWT that uses
chemical precipitation and media filtration to treat hydraulic fracturing waste is the Water Tower
Square Gas Well Wastewater Processing Facility in Pennsylvania (Table F-6). One or more of these
technologies is typically used prior to advanced treatment such as reverse osmosis (RO) because
advanced treatment processes foul, scale, or otherwise do not operate effectively in the presence of
TSS, certain organics, and/or some metals and metalloid compounds (Boschee. 2014: Drewes etal..
2009). The biggest challenge associated with use of these separation technologies is solids disposal
from the resulting sludge flgunnu and Chen. 20141.
F.2.1.2. Coagulation/Oxidation
Coagulation is the process of agglomerating small, unsettleable particles into larger particles to
promote settling. Chemical coagulants such as alum, iron chloride, and polymers can be used to
precipitate TSS, some dissolved solids (except monovalent ions such as sodium and chloride), and
metals from hydraulic fracturing wastewater. Adjusting the pH using chemicals such as lime or
caustic soda can increase the potential for some constituents, including dissolved metals, to form
precipitates. Chemical precipitation is often used in industrial wastewater treatment as a
F-9
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
pretreatment step to decrease the pollutant loading on subsequent advanced treatment
technologies; this strategy can save time, money, energy consumption, and the lifetime of the
infrastructure.
Processes using advanced oxidation and precipitation have been applied to hydraulic fracturing
wastewaters in on-site and mobile systems. Hydroxyl radicals generated by cavitation processes
and the addition of ozone can degrade organic compounds and inactivate micro-organisms. The
process can also aid in the precipitation of ions that cause hardness and scaling in the treated water
(e.g., calcium, magnesium). The process can also reduce sulfate and carbonate concentrations in the
treated water. With the removal of constituents that contribute to scaling, this type of treatment
can be very effective for on-site reuse of wastewater fElv et ai. 20111.
The produced solid residuals from coagulation/oxidation processes typically require further
treatment, such as de-watering fDuraisamv et al.. 2013: Hammer and VanBriesen. 20121.
F.2.1.3. Electrocoagulation
Electrocoagulation (EC) (Figure F-l) combines the principles of coagulation and electrochemistry
into one process fGomes et al.. 20091. An electrical current added to the wastewater produces
coagulants that then neutralize the charged particles, causing them to destabilize, precipitate, and
settle. EC may be used in place of, or in addition to, chemical coagulation. EC can be effective for
removal of organics, TSS, and metals, but it is not effective at removing TDS and sulfate
(Halliburton. 20141. Although it is still considered an emerging technology for unconventional oil
and gas wastewater treatment, EC has been used in mobile treatment systems to treat hydraulic
fracturing wastewaters fHalliburton. 2014: Igunnu and Chen. 20141. This technology has the
potential to cause scaling corrosion, and bacterial growth fGomes et al.. 20091.
Figure F-l. Electrocoagulation unit.
Source: Durikel (2013). Photo courtesy of Pioneer Natural Resources.
F-10
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Testing of EC has been performed in the Green River Basin (Halliburton. 20141 and the Eagle Ford
Shale fGomes etal.. 20091. While showing promising results in some trials, results of these early
studies have illustrated challenges, with removal efficiencies impacted by factors such as pH and
salt content.
F.2.1.4. Sedimentation
Treatment plants may include sedimentation tanks, clarifiers, or some other form of settling basin
to allow larger particles to settle out of the water where they can eventually be collected,
dewatered, and disposed of at a landfill or other approved location. These types of tanks/basins all
serve the same purpose - to reduce the amount of solids going to subsequent processes (i.e., to
prevent overload of the media filters).
F.2.1.5. Disinfection
Some hydraulic fracturing applications may require disinfection to kill bacteria after treatment and
prior to reuse or discharge. Chlorine is a common disinfectant. Chlorine dioxide, ozone, or
ultraviolet light can also be used. This is an important step for reused water because bacteria can
cause problems for further hydraulic fracturing operations by multiplying rapidly and causing
build-up in the wellbore, which decreases gas extraction efficiency.
F.2.2. Advanced Treatment
Advanced treatment technologies consist of membranes (RO, nanofiltration, ultrafiltration,
microfiltration, electrodialysis, forward osmosis, and membrane distillation), thermal distillation
technologies, crystallizers, ion exchange, and adsorption. These technologies are effective for
removing TDS and/or targeted compounds. They typically require pretreatment to remove solids
and other constituents that may damage or otherwise impede the technology from operating as
designed. Advanced treatment technologies can be energy-intensive and are typically employed
when a purified water effluent is necessary for direct discharge, indirect discharge, or reuse. In
some instances, these water treatment technologies can use methane generated by the gas well as
an energy source. Some advanced treatment technologies can be made mobile for on-site treatment
F.2.2.1. Membranes
Pressure-Driven Membrane Processes
Pressure-driven membrane processes, including microfiltration, ultrafiltration, nanofiltration, and
RO (Figure F-2), are being used in some settings to treat oil and gas wastewater. These processes
use hydraulic pressure to overcome the osmotic pressure of the influent waste stream, forcing clean
water through the membrane (Drewes et al.. 20091. Microfiltration and ultrafiltration processes are
advanced processes that do not reduce TDS but can remove TSS and some metals and organics
fDrewes etal.. 20091. RO and nanofiltration are capable of removing TDS, including anions and
radionuclides. RO, however, may be limited to treating TDS levels of less than 35,000 mg/L (Shaffer
etal.. 2013: Younos and Tulou. 20051. Boron is not easily removed by RO, achieving less than 50%
removal at neutral pH (Drewes etal.. 20091.
F-ll
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
Figure F-2. Photograph of reverse osmosis system.
Source: U.S. DPI (2016).
Osmotic-Driven Membrane Processes
Forward osmosis, an emerging technology for treating hydraulic fracturing wastewater, uses an
osmotic pressure gradient across a membrane to draw water from a low osmotic solution (the feed
water) to a high osmotic solution (the draw solution) (Drewes etal.. 2009). The draw solution
(typically composed of sodium chloride) becomes diluted as more water passes through the
membrane while the feed side becomes more concentrated. For the diluted draw solution, a
separation process is employed to further treat the product water and concentrate the sodium
chloride for reuse.
Thermally-Drive Membrane Processes
Another emerging technology, membrane distillation, relies on a thermal gradient across a
membrane surface to volatilize pure water and capture it in the distillate (Drewes etal.. 20091
Membrane distillation has shown promise in removing heavy metals and boron from wastewaters
fCamacho etal.. 20131.
F.2.2.2. Electrodialysis
Electrodialysis relies on electrodes (anode and cathode) and ion exchange membranes to separate
positively- and negatively-charged contaminants from the feed water fDrewes et al.. 20091 (Figure
F-12
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
F-3). Electrodialysis has been considered for use by the shale gas industry, but is currently not
widely utilized fALL Consulting. 20131. TDS concentrations above 15,000 mg/L are difficult to treat
by electrodialysis (ALL Consulting. 20131. and oil and divalent cations (e.g., calcium, iron,
magnesium) can foul/scale the membranes (Haves and Severin. 2012b: Guolin etal.. 20081.
Pretreatment is necessary to avoid membrane scaling fALL Consulting. 2013: DrewesetaL 20091.

Figure F-3. Picture of mobile electrodialysis units in Wyoming,
Source: DOE (20061. Reproduced with permission from ALL Consulting.
F.2.2.3. Thermal Distillation
Thermal distillation technologies, such as mechanical vapor recompression (MVR) (Figure F-4) and
dewvaporation, use liquid-vapor separation by applying heat to the waste stream, vaporizing the
water to separate out impurities, and condensing the vapor into distilled water fDrewes etal..
2009: LEau LLC. 2008: Hamieh and Beckman. 20061. MVR and dewvaporation can treat high-TDS
waters and have been proven in the field as effective for treating oil and gas wastewater fHaves and
Severin. 2012b: Drewes etal.. 20091. Like RO, these processes are energy-intensive and are used
when the objective is very clean water (i.e., TDS less than 500 mg/L) for direct/indirect discharge
or if clean water is needed for reuse. As with membrane processes, scaling is an issue with these
technologies, and scale inhibitors may be needed for them to operate effectively flgunnu and Chen.
20141.
F-13
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Figure F-4. Picture of a mechanical vapor recompression unit near Decatur, Texas.
Source: Drewes et al. (2009). Reproduced with permission.
CWTs such as the Judsonia Central Water Treatment Facility (Arkansas], Casella-Altela Regional
Environmental Services (Pennsylvania), and Clarion Altela Environmental Services (Pennsylvania)
have National Pollutant Discharge Elimination System (NPDES) permits and use MVR or thermal
distillation for TDS removal. Figure F-5 shows a diagram of the treatment train at another facility,
the Maggie Spain facility in Texas, which used MVR in its treatment of Barnett Shale wastewater
fHaves and Severin. 2012a!
Flowback
Delivery
Storage Reservoir
Influent
Sample
Flash Mixer
Lime and
Polymer,
pH 10
Units p
1
1
Ml
Condensate
Samples (3)
H
Concentrated
Brine to
Deep Well
or Reuse
Surge Tank
Post Clarifier Acid to pH 4
Sample
Distillate
Samples (3)
Product Water Storage
Product Water
to Reuse or Discharge
Lamella
Separator
2 Filter Presses
Filtrate
Sludge Cake
to Landfill
Figure F-5. Mechanical vapor recompression process design - Maggie Spain Facility.
Adapted from: Haves and Severin (2012al. Reproduced with permission.
F-14
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Crystallizers can be employed at CWTs to treat high-TDS waters or to further concentrate the waste
stream from a distillation process, reducing residual waste disposal volumes. The crystallized salt
can be landfilled, deep-well injected, or used to produce pure salt products that may be salable
fErtel etal.. 20131.
Another thermal method, freeze-thaw evaporation, involves spraying wastewater onto a freezing
pad, allowing ice crystals to form, and the brine mixture that remains in solution to drain from the
ice fDrewes etal.. 20091. In warmer weather, the ice thaws and the purified water is collected. This
technology cannot treat waters with high methanol concentrations and is only suitable for areas
where the temperature is below freezing in the winter months flgunnu and Chen. 20141. In
addition, freeze-thaw evaporation can only reduce TDS concentrations to approximately 1,000
mg/L, which is higher than the 500 mg/L TDS surface water discharge limit required by most
permits flgunnu and Chen. 20141.
F.2.2.4. Ion Exchange and Adsorption
Ion exchange (Figure F-6) is the process of exchanging ions on a media referred to as resin for
unwanted ions in the water. Ion exchange is used to treat for target ions that may be difficult to
remove by other treatment technologies or that may interfere with the effectiveness of advanced
treatment processes.
Figure F-6. Picture of a compressed bed ion exchange unit.
Source: Drewes et al. (20091 Reproduced with permission.
Adsorption is the process of adsorbing contaminants onto a charged granular media surface.
Adsorption technologies can effectively remove organics, heavy metals, and some anions flgunnu
and Chen. 20141. With ion exchange and adsorption processes, the type of resin or adsorptive
media used (e.g., activated carbon, organoclay, zeolites] dictates the specific contaminants that will
be removed from the water fDrewes etal.. 2009: Fakhru'l-Razi etal. 20091.
F-15
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Because they can be easily overloaded by contaminants, ion exchange and adsorption treatment
processes are generally used as a polishing step following other treatment processes or as a unit
process in a treatment train rather than as stand-alone treatment (Drewes etal.. 20091. Stand-alone
units require more frequent regeneration and/or replacement of the spent media making these
technologies more costly to operate flgunnu and Chen. 20141. The Pinedale Anticline Water
Reclamation Facility located in Wyoming uses an ion exchange unit with boron-selective resin as a
polishing step to treat hydraulic fracturing wastewater specifically for boron fBoschee. 20121
(Figure F-7).
F.3. Treatment Technology Removal Capabilities
Table F-2 provides removal efficiencies for common hydraulic fracturing wastewater constituents
by treatment technology. With the exception of TSS and TDS, the studies cited demonstrate removal
for a subset of constituents in a category (e.g., Gomes etal. (20091 reported that electrodialysis was
an effective treatment for oil and grease, not all organics). The removal efficiencies include ranges
of 1 to 33% (denoted by +), 34% to 66% (denoted by ++), and greater than 66% removal (denoted
by +++). Cells denoted with indicate that the treatment technology is not suitable for removal of
that constituent or group of constituents. If a particular treatment technology only lists removal
efficiencies for TDS, it can be assumed that, in some cases, cations and anions would also be
removed by that technology; therefore, where specific results were not provided in literature, cells
denoted with "Assumed" refer to cations and anions that comprise TDS.
Table F-2. Removal efficiency of different hydraulic fracturing wastewater constituents using
various wastewater treatment technologies.3
Treatment
technology
Hydraulic fracturing wastewater constituents
TSS
TDS
Anions
Metals
Radio-
nuclides
Organics
Hydrocyclones
+++
(Duraisamv et
al„ 2013)
"


"
++
(Duraisamv et al.,
2013)
Evaporation
(freeze-thaw
evaporation)
+++
(Igunnu and
Chen, 2014;
Drewes et al..
+++
(Igunnu and
Chen, 2014;
Drewes et al..
Assumed
+++
(Igunnu and
Chen, 2014;
Drewes et al..

+++
(Igunnu and
Chen, 2014;
Duraisamv et al..
2009)
2009; Arthur
etal., 2005)
2009; Arthur
etal., 2005)
2013; Drewes et
al., 2009)
Filtration
(granular media)
+++
(Barrett, 2010)


+++b
(Duraisamv et
al., 2013)

+++
(Shafer, 2011;
Drewes et al.,
2009)
Chemical
precipitation
+++
(Fakhru'l-Razi
etal., 2009)


+++
(Fakhru'l-Razi
et al., 2009;
+++c
(Zhang et al.,
2014)
+++
(Fakhru'l-Razi et
al., 2009)

AWWA, 1999)


F-16
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
Treatment
technology
Hydraulic fracturing wastewater constituents
TSS
TDS
Anions
Metals
Radio-
nuclides
Organics
Sedimentation
(clarifier)
++
(NMSU DACC
WUTAP, 2007)






Dissolved air
flotation
+++
(Shammas,
2010)




++/+++
(Duraisamv et al.,
2013; Fakhru'l-
Razi et al., 2009)
Electro-
coagulation
+++
(Igunnu and
Chen, 2014;


+
(Igunnu and
Chen, 2014)

+++
(Igunnu and
Chen, 2014;
Bukhari, 2008)

Duraisamv et al..

2013; Fakhru'l-
Razi et al., 2009)
Advanced
oxidation and
precipitation

+
(Abrams,
2013)

+/+++
(Abrams,
2013)

+++d
(Duraisamv et al.,
2013; Fakhru'l-
Razi et al., 2009)
Reverse osmosis

++/+++e
(Alzahrani et
al., 2013;
Drewes et al.,
2009)
+++
(Alzahrani et
al., 2013;
Arthur et al.,
2005)
++/+++f
(Alzahrani et
al., 2013;
Drewes et al.,
2009; AWWA,
1999)
+++
(Drewes et
al., 2009)
+/++/+++g
(Drewes et al.,
2009; Munter,
2000)
Membrane
filtration (UF/MF)
+++
(Arthur et al.,
2005)


+++
(Fakhru'l-Razi
et al., 2009)

++/+++
(Duraisamv et al.,
2013; Fakhru'l-


Razi et al., 2009;
Haves and
Arthur, 2004;
AWWA, 1999 )h
Forward osmosis

+++
(Drewes et al.,
2009)
Assumed
Assumed


Distillation,
including thermal
distillation (e.g.,
mechanical vapor
recompression
(MVR))

+++'
(Haves et al.,
2014; Bruff
and Jikich,
2011; Drewes
+++
(Bruff and
Jikich, 2011;
Drewes et al.,
2009)
+++
(Haves et al.,
2014; Bruff
and Jikich,
2011; Drewes
+++
(Bruff and
Jikich, 2011;
Drewes et
al., 2009)
+/++/+++
(Haves et al.,
2014; Duraisamv
et al., 2013;
Drewes et al..
et al., 2009)

et al., 2009)

2009; Fakhru'l-


Razi et al., 2009)
Ion exchange


+++
(Drewes et
al., 2009)
+++
(Drewes et al.,
2009; Arthur
et al., 2005)
+++
(Drewes et
al., 2009)
+/++/+++
(Fakhru'l-Razi et
al., 2009;
Munter, 2000)J
F-17
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
Treatment
technology
Hydraulic fracturing wastewater constituents
TSS
TDS
Anions
Metals
Radio-
nuclides
Organics
Crystallization
-
+++
(ER, 2014)
Assumed
Assumed
-
-
Electrodialysis

+++k
(Drewes et al.,
2009; Gomes
++/+++
(Banasiak and
Schafer,
+/++/+++
(Banasiak and
Schafer, 2009)


et al., 2009;
Arthur et al.,
2005)
2009)

Capacitive
deionization
(emerging
technology)

+++'
(Drewes et al.,
2009)




Adsorption"1


+/++/+++"
(Habuda-
Stanic et al.,
2014)
+++
(Igunnu and
Chen, 2014;
Drewes et al.,
2009)

+/++/+++
(Arthur et al.,
2005; Haves and
Arthur, 2004;
Munter, 2000)
Biological
treatment
+++
(Igunnu and
Chen, 2014;




+/++/+++
(Igunnu and
Chen, 2014;
Drewes et al.,
2009)
Drewes et al.,
2009; Fakhru'l-
Razi et al., 2009)
Constructed
wetland/reed
beds
++/+++
(Manios et al.,
2003)
+
(Arthur et al.,
2005)

++/+++
(Fakhru'l-Razi
et al., 2009)

+/ +++
(Fakhru'l-Razi et
al., 2009; Arthur



et al., 2005)
a To the extent possible, removal efficiencies are based on an individual treatment technology that does not assume extensive
pretreatment or combined treatment processes. However, it should be noted that some processes such as RO, media filtration,
and sedimentation cannot effectively operate without pretreatment.
b Pretreatment (pH adjustment, aeration, solids separation) required.
c Radium co-precipitation with barium sulfate.
d The Fenton process.
eTypically requires pretreatment. Not a viable technology if TDS influent >50,000 mg/L.
f Iron and manganese oxides will foul the membranes.
g Some organics will foul the membranes (e.g., organic acids).
h Ultrafiltration membrane was modified with nanoparticles.
' Can typically handle high TDS concentrations.
j Resin consisted of modified zeolites that targeted removal of BTEX.
k Influent TDS for this technology should be <8,000 mg/L.
1 Specific technology was an electronic water purifier which is a hybrid of capacitive deionization. Influent TDS for this
technology should be <3,000 mg/L.
m Typically polishing step, otherwise can overload bed quickly with organics.
" Removal efficiency is dependent on the type of adsorbent used and the water quality characteristics (e.g., pH).
F-18
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
F.3.1. Estimated Treatment Removal Efficiencies
There are relatively few studies that have evaluated the ability of individual treatment processes to
remove constituents from hydraulic fracturing wastewater and reported the resulting water
quality. Furthermore, although a specific technology may demonstrate a high removal percentage
for a particular constituent, if the influent concentration of that constituent is extremely high, the
constituent concentration in the treated water may still exceed permit limits and/or disposal
requirements. Table F-3 presents estimated effluent concentrations that could be produced by a
variety of unit treatment processes for several example constituents and for various influent
concentrations. This analysis uses simple calculations pairing average hydraulic fracturing
wastewater concentrations from Chapter 7 and Appendix E with treatment process removal
efficiencies reported in the literature in Table F-2. This analysis is intended to highlight the
potential impacts of influent concentration on treatment outcome and to illustrate the relative
capabilities of various treatment processes for an example set of constituents. The removal
efficiencies represent a variety of studies (primarily at bench and pilot scale) that have been
conducted using either conventional or hydraulic fracturing wastewater. Removal efficiency for a
given treatment process can vary due to a number of factors, and constituent removal may be
different in a full-scale facility that uses several processes. Thus, the calculations shown in Table F-3
are intended to be rough approximations for illustrative purposes.
As an example, radium in wastewater from the Marcellus Shale and Upper Devonian sandstones can
be in the thousands of pCi/L. With a 95% removal rate, chemical precipitation may result in effluent
that still exceeds 100 pCi/L. Distillation and RO might produce effluent with concentrations in the
tens of pCi/L. A radium concentration of 120 pCi/L, however, could be reduced to less than 5 pCi/L
by RO or distillation. Wastewater with barium concentrations in the range of 140 - 160 mg/L (e.g.,
the Cotton Valley and Mesaverde tight sands) might be reduced to concentrations under 5 mg/L by
distillation and roughly 11-13 mg/L by RO. Barium concentrations in the thousands of mg/L
would be substantially reduced by any of several processes, but might still be relatively high,
potentially exceeding 100 mg/L. Table F-3 also illustrates the potential for achieving low
concentrations of organic compounds in wastewater treated with freeze-thaw evaporation or
advanced oxidation and precipitation.
F-19
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
Table F-3. Estimated effluent concentrations for example constituents based on treatment process removal efficiencies.
Shale/
sandstone
play
Contaminant
Units
(for all
entries)
MCL
Avg.
influent
conc.
Freeze-thaw
evaporation
Media filtration
Chemical precipitation
Flotation (DAF)
Electro-coagulation
Advanced oxidation and
precipitation
Reverse osmosis
Membrane filtration
(UF/MF)
Distillation
Ion exchange
Elect rod ialysis
Adsorption
Biological treatment
(biodisks, BAFs)
Constructed wetland
Bakken
Barium
mg/L
2
10

1



0.44
0.8

0.1-
0.03
ND-
0.7



2.2
Barnett
Barium
mg/L
2
3.6

0.4



0.16
0.29

0.0036
-0.11
ND-
0.3



0.8
Fayetteville
Barium
mg/L
2
4

0.4



0.18
0.32

0.04-
0.12
ND-
0.3



0.9
Marcellus
Barium
mg/L
2
2200

220



98
180

22-
67
ND-
160



490
Cotton Valley
Barium
mg/L
2
160

16



7
13

1.6-
4.8
ND-
11



35
Mesa Verde
Barium
mg/L
2
140

14



6.1
11

1.4-
4.2
ND-
9.7



31
Marcellus
Cadmium
Pg/L
5
25
2.5
2.5




13




5

15
Bakken
Strontium
mg/L
-
760

76






7.6-
23
53




Barnett
Strontium
mg/L
-
530

53






5.3-
16
37




Fayetteville
Strontium
mg/L
-
27

2.7






0.27-
0.81
1.9




Marcellus
Strontium
mg/L
-
1700

170






17-
51
120




Cotton Valley
Strontium
mg/L
-
2300

230






23-
69
160




F-20
-------
71
NJ
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Cotton Valley
Marcellus
Barnett
Marcellus
Marcellus
Devonian
Sandstone
Marcellus
Devonian
Sandstone
Shale/
sandstone
play
Benzene
Benzene
Oil and grease
Oil and grease
CO
O
a
CO
O
a
H
o
o
H
o
o
—1
o
o
Total radium
Radium 228
Radium 226
Radium 226
Strontium
Contaminant
£
1—
£
1—
mg/L
mg/L
mg/L
mg/L
mg/L
pCi/L
pCi/L
pCi/L
pCi/L
pCi/L
pCi/L
mg/L
Units
(for all
entries)
Ln
Ln
!
:
!
!
!
:
!
Ln
:
:
!
:
MCL
UJ
cn
O
cn
00
O
4^
I-*
cn
o
4^
O
Ln
00
O
NJ
O
O
I-*
cn
o
to
00
2500
I-*
NJ
O
2400
cn
NJ
o
3900
Avg.
influent
conc.
UJ
cn
cn
00












Freeze-thaw
evaporation


4^
i-*
cn









UJ
o
Media filtration









130-
1800
6.2-
85
120-
1700
32-
440

Chemical precipitation














Flotation (DAF)




4^
Ln
00








Electro-coagulation














Advanced oxidation and
precipitation









NJ
Ln
I-*
NJ
NJ
4^
cn
NJ

Reverse osmosis
i-*
o
UJ
i-*
o
4^
i-*
cn


4^
UJ
NJ
O
NJ





Membrane filtration
(UF/MF)
UJ
cn
00







25-
76
1.2-
3.6
24-
71
6.2-
19
39-
120
Distillation




20-
30
290-
440



I-*
00
o
00
4^
I-*
o
4^
4^
NJ
O
Ion exchange


UJ
00










Elect rodia lysis
Ln
00
i-*
i-*
o
O
4^
i-*


20-
59
16-
48
0.9-
2.9





Adsorption


I-*
tD
4^
UJ
NJ
1
cn
29-
87
44-
71
35-
58
NJ
i-*
1
4^





Biological treatment
(biodisks, BAFs)
:z:
a
:z:
a
4^
4^
to
00
UJ
k)
4^
NJ
O
I-*
cn
I-*





Constructed wetland
Oj
3
><'
>1
I
5
©
Q
3
a.
%
Co
C
¦Q
¦Q

-------
o
ii
Q_
fD
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Shale/
sandstone
play
1,2,4-Trimethyl-
benzene
1,2,4-Trimethyl-
benzene
1,2,4-Trimethyl-
benzene
1,2,4-Trimethyl-
benzene
Naphthalene
Naphthalene
BTEX
BTEX
Xylenes
Xylenes
Ethyl benzene
Ethyl benzene
Toluene
Toluene
Contaminant
£
£
£
£
£
£
£
£
£
£
£
£
£
£
Units
(for all
entries)
I
I
I
I
I
I
I
1
10,000
10,000
o
o
o
o
1,000
1,000
MCL
UJ
I-*
o
Ln
tD
4^
UJ
O
I-*
o
UJ
cn
o
NJ
4^
O
2900
1800
1300
UJ
cn
o
I-*
Ln
O
NJ
tD
1100
cn
o
Avg.
influent
conc.






NJ
tD
O
I-*
00
o
I-*
UJ
o
UJ
cn
I-*
Ln
NJ
Id
I-*
I-*
o
cn
Freeze-thaw
evaporation














Media filtration














Chemical precipitation










tD
O
i-*


Flotation (DAF)














Electro-coagulation
I-*
NJ
O
NJ
4^
I-*
o
1
I
5
©
o
a.
%
Co
c
¦Q
¦Q
§
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
F.4. Treatment for Constituents of Concern
Constituents of concern in hydraulic fracturing wastewater include TSS, TDS, anions (e.g., chloride,
bromide, and sulfate), metals, radionuclides, and organic compounds (see Section 8.3 and Chapter
7). If the end use of the wastewater necessitates treatment, a variety of technologies can be
employed to remove or reduce the constituent concentrations. Table F-4 provides an overview of
influent and effluent results and removal percentages for constituents of concern at oil and gas
treatment facilities reported in literature (both conventional and unconventional) and the specific
technology(ies) used to remove them.
F-23
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
Table F-4. Studies of removal efficiencies and influent/effluent data for various processes and facilities.
Constituents
of concern
Location and results
Pinedale Anticline
Water Reclamation
Facility, Wyoming
(Shafer. 2011)
Maggie Spain Water-
Recycling Facility,
Barnett Shale, Texas
(Haves et al.. 2014)
Judsonia, Sunnydale,
Arkansas
(U.S. EPA. 2015e)
9-month study treating
Marcellus Shale waste
using thermal
distillation
(Boschee. 2014: Bruff
and Jikich. 2011)
San Ardo Water
Reclamation Facility, San
Ardo, California
(conventional oil and gas)
(Dahm and Chaoman.
2014: Webb et al.. 2009)
TSS
Results not reported.
90%
Inf. = 1,272 mg/L
Eff. = 9 mg/L
Chemical oxidation,
coagulation, and
clarification
No influent data.
Eff.: <4 mg/L
Meets NPDES Permit
Settling, biological
treatment, and induced
gas flotation
>90%
Inf.: 35 to 114 mg/L
Eff.: <3 to 3 mg/L
100 micron mesh bag filter
Results not reported.
TDS
>99%
Inf. = 8,000 to 15,000
mg/L
Eff. = 41 mg/L
RO
99.7%
Inf. = 49,550 mg/L
Eff. = 171 mg/L
MVR (3 units in parallel)
Results not reported.
MVR
98%
Inf.: 22,350 to 37,600
mg/L
Eff.: 9 to 400 mg/L
Thermal distillation
97%
Inf. = 7,000 mg/L
Eff. = 180 mg/L
Ion exchange softening and
double-pass RO
F-24
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
Constituents
of concern
Location and results
Pinedale Anticline
Water Reclamation
Facility, Wyoming
(Shafer. 2011)
Maggie Spain Water-
Recycling Facility,
Barnett Shale, Texas
(Haves et al.. 2014)
Judsonia, Sunnydale,
Arkansas
(U.S. EPA. 2015e)
9-month study treating
Marcellus Shale waste
using thermal
distillation
(Boschee, 2014; Bruff
and Jikich. 2011)
San Ardo Water
Reclamation Facility, San
Ardo, California
(conventional oil and gas)
(Dahm and Chapman.
2014: Webb et al.. 2009)
Anions
Chloride: >99%
Inf. = 3,600 to 6,750 mg/L
Eff. = 18 mg/L
RO
Sulfate: 99%
Inf. = 10 to 100 mg/L
Eff. = non-detect
Clarification and filtration
Sulfate: 98%
Inf. = 309 mg/L
Eff. = 6 mg/L
Chemical oxidation,
coagulation, clarification,
and MVR
Sulfate:
No influent data.
Eff.: 12 mg/L
Meets NPDES Permit
MVR
Bromide: >99%
Inf.: 101 to 162.5 mg/L
Eff.: <0.1 to 1.6 mg/L
Chloride: 98%
Inf.: 9,760 to 16,240 mg/L
Eff.: 2.9 to 184.2 mg/L
Sulfate: 93%
Inf.: 20.4 to <100 mg/L
Eff.: <1 to 2.2 mg/L
Fluoride: 96%
Inf.: <2 to <20 mg/L
Eff.: <0.2 to 0.42 mg/L
Thermal distillation
Chloride: >99%
Inf. = 3,400 mg/L
Eff. = 11 mg/L
Double-pass RO
Sulfate: 6%
Inf. = 133 mg/L
Eff. = 125 mg/L
Sulfuric acid is added after
RO to neutralize the pH so
no sulfate removal is
expected.
F-25
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information

Location and results




9-month study treating
San Ardo Water

Pinedale Anticline
Maggie Spain Water-
Inrlcnnia Qnnnurlslo
Marcellus Shale waste
Reclamation Facility, San
Constituents
Water Reclamation
Recycling Facility,
juudunid; ouimyudie,
Arkancac
using thermal
Ardo, California
of concern
Facility, Wyoming
Barnett Shale, Texas
nl l\CI 119CI9
Ml^ FPA 2015p)
distillation
(conventional oil and gas)

(Shafer. 2011)
(Haves et al.. 2014)
IUiJi trtti favlJCI
(Boschee, 2014; Bruff
(Dahm and Chapman.




and Jikich. 2011)
2014: Webb et al.. 2009)
Metals
Boron: 99%
Iron: >99%
Cobalt:
Copper: >99%
Sodium: 98%

Inf. = 15 to 30 mg/L
Inf. = 28 mg/L
No influent data.
Inf. = <0.2 to <1.0 mg/L
Inf. = 2,300 mg/L

Eff. = non-detect
Eff. =0.1 mg/L
Eff.: <0.007 mg/L
Eff. = <0.02 to <0.08 mg/L
Eff. = 50 mg/L

Ion exchange
For iron, 90% attributed to

Zinc: inf below detect
Boron: >99%


chemical oxidation,
Arsenic:
Inf. = <0.2 to <1.0 mg/L
Inf. = 26 mg/L


coagulation, and
No influent data.
Eff. = <0.02 to 0.05 mg/L
Eff. =0.1 mg/L


clarification
Eff.: <0.001 mg/L






Barium: >99%
RO with elevated influent


Boron: 98%
Cadmium:
Inf. = 260.5 to 405.5 mg/L
PH


Inf. = 17 mg/L
No influent data.
Eff. =<0.1 to 4.54 mg/L



Eff. = 0.4 mg/L
Eff.: <0.0001 mg/L






Strontium: 98%



Barium: >99%
Chromium:
Inf. = 233 to 379 mg/L



Inf. = 15 mg/L
No influent data.
Eff. = 0.026 to 3.93 mg/L



Eff. =0.1 mg/L
Eff.: <0.007 mg/L






Iron:



Calcium: >99%
Copper:
Inf. = 13.9 to 22.9 mg/L



Inf. = 2,916 mg/L
No influent data.
Eff. = <0.02 to 0.06 mg/L



Eff. = 3.2 mg/L
Eff.: <0029 mg/L
Boron: 97%



Magnesium: >99%

Inf. = <1 to 3.12 mg/L



Inf. = 316 mg/L
Lead:
Eff. = 0.02 to 0.06 mg/L



Eff. = 0.4 mg/L
No influent data.





Eff.: <0.001 mg/L


F-26
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information

Location and results
Constituents
of concern
Pinedale Anticline
Water Reclamation
Facility, Wyoming
(Shafer. 2011)
Maggie Spain Water-
Recycling Facility,
Barnett Shale, Texas
(Haves et al.. 2014)
Judsonia, Sunnydale,
Arkansas
(U.S. EPA. 2015e)
9-month study treating
Marcellus Shale waste
using thermal
distillation
(Boschee, 2014; Bruff
and Jikich. 2011)
San Ardo Water
Reclamation Facility, San
Ardo, California
(conventional oil and gas)
(Dahm and Chapman.
2014: Webb et al.. 2009)
Metals, cont.

Sodium: >99%
Inf. = 10,741 mg/L
Eff. = 14.3 mg/L
Strontium: >99%
Inf. = 505 mg/L
Eff. = 0.5 mg/L
MVR
Mercury:
No influent data.
Eff.: <0.005 mg/L
Zinc:
No influent data.
Eff.: 0.02 mg/L
Meets NPDES permit
except for TMDLs for
hexavalent chromium and
mercury
Settling, biological
treatment, induced gas
flotation, and MVR
Calcium: 98%
Inf. = 1,175 to 1,933 mg/L
Eff. = 0.36 to 22.2 mg/L
Sodium: 98%
Inf. = 4,712 to 7,781 mg/L
Eff. = 0.37 to 87.9 mg/L
Arsenic: 82%
Inf. =<0.01 to 0.028 mg/L
Eff. = <0.005 mg/L
Thermal distillation

F-27
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information

Location and results
Constituents
of concern
Pinedale Anticline
Water Reclamation
Facility, Wyoming
(Shafer. 2011)
Maggie Spain Water-
Recycling Facility,
Barnett Shale, Texas
(Haves et al.. 2014)
Judsonia, Sunnydale,
Arkansas
(U.S. EPA. 2015e)
9-month study treating
Marcellus Shale waste
using thermal
distillation
(Boschee, 2014; Bruff
and Jikich. 2011)
San Ardo Water
Reclamation Facility, San
Ardo, California
(conventional oil and gas)
(Dahm and Chapman.
2014: Webb et al.. 2009)
Radionuclides
Results not reported.
Results not reported.
Not regulated under
permit - believed to be
absent.
Radium-226: 97% - 99%
Inf. = 130 to 162 pCi/L
Eff. =0.224 to 2.87 pCi/L
Radium-228: 97% - 99%
Inf. = 45 to 85.5 pCi/L
Eff. = 0.259 to 1.32 pCi/L
Gross Alpha: 97% - >99%
Inf. = 161 to 664 pCi/L
Eff. = 0.841 to 6.49 pCi/L
Gross Beta: 98% - >99%
Inf. = 79.7 to 847 pCi/L
Eff. = 0.259 to 1.57 pCi/L
Thermal distillation
Results not reported.
F-28
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information

Location and results




9-month study treating
San Ardo Water

Pinedale Anticline
Maggie Spain Water-
Judsonia, Sunnydale,
Arkansas
(U.S. EPA. 2015e)
Marcellus Shale waste
Reclamation Facility, San
Constituents
Water Reclamation
Recycling Facility,
using thermal
Ardo, California
of concern
Facility, Wyoming
Barnett Shale, Texas
distillation
(conventional oil and gas)

(Shafer. 2011)
(Haves et al.. 2014)
(Boschee, 2014; Bruff
and Jikich. 2011)
(Dahm and Chapman.
2014: Webb et al.. 2009)
Organics
Oil & Grease: 99%
TPH:>80%
Biochemical oxygen
Acetone: 93%
Results not reported.

Inf. = 50 to 2,400 mg/L
Inf. = 388 mg/L
demand:
Inf. = 8.71 to 13.8 mg/L


Eff. = non-detect
Eff. = 4.6 mg/L
No influent data.
Eff.: <2 mg/L
Eff. =0.524 to 0.949 mg/L


BTEX: 99%
BTEX: 94%

Toluene: >80%


Inf. = 28 to 80 mg/L
Inf. = 3.3 mg/L
Oil & Grease:
Inf. = 0.0083 to 0.0015


Eff. = non-detect
Eff. = 0.2 mg/L
No influent data.
Eff.: <5 mg/L
mg/L
Eff. = non-detect to 0.0013


GRO:99%
TOC: 48%

mg/L


Inf. = 88 to 420 mg/L
Inf. = 42 mg/L
Benzo (k) fluoranthene:



Eff. = non-detect
Eff. = 22 mg/L
No influent data.
Eff.: <0.005 mg/L
Methane: >99%
Inf. =0.748 to 5.49 mg/L


DRO:99%
Coagulation,

Eff. = non-detect to 0.0013


Inf. = 77 to 1,100 mg/L
sedimentation, MVR
Bis (2-Ethylhexyl)
mg/L


Eff. = non-detect

Phthalate:
No influent data.
DRO: 0 to 82%


Methanol: 99%

Eff.: <0.001 mg/L
Inf. = 4 to 7.1 mg/L


Inf. =40 to 1,500 mg/L


Eff. = 0.99 to 4.9 mg/L


Eff. = non-detect

Butyl benzyl phthalate:
No influent data.
Oil & Grease: No removal


Oil-water separator,

Eff.: <0.001 mg/L



anaerobic and aerobic


Thermal distillation


biological treatment,

Meets NPDES permit



coagulation, flocculation,





flotation, sand filtration,

Settling, biological



membrane bioreactor,

treatment, induced gas



and ultrafiltration

flotation, and MVR


F-29
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
F.4.1. Total Suspended Solids
The reduction of TSS is typically required before wastewater can be reused for subsequent
hydraulic fracturing jobs. Hydraulic fracturing wastewaters containing suspended solids can plug
the well and damage equipment if reused for other fracturing operations (Tiemann et al.. 2 014:
Hammer and VanBriesen. 20121. For treated water that is discharged to a surface water body, the
EPA has a secondary treatment standard for POTWs that limits TSS in the effluent to 30 mg/L (30-
day average). In addition, most advanced treatment technologies require the removal of TSS prior
to treatment to avoid operational problems, such as membrane fouling/scaling, and to extend the
life of the treatment unit.
TSS removal efficiencies shown in Table F-4 (90% and over 90%) were achieved with chemical
oxidation, coagulation, and clarification, as well as filtration. Technologies that remove TSS have
also been employed in another Marcellus Shale study (sedimentation and filtration) (Mantell.
20131: Utica Shale (chemical precipitation and filtration) fMantell. 20131: Barnett Shale (chemical
precipitation and inclined plate clarifier, >90% removal) fHaves etal.. 20141: and Utah (EC, 90%
removal) (Halliburton. 20141.
F.4.2. Total Dissolved Solids
The TDS concentration of hydraulic fracturing wastewater is a key treatment consideration, with
the required level of TDS removal dependent upon the intended use of the treatment effluent
POTW treatment and basic treatment processes at a CWT (i.e., chemical precipitation,
sedimentation, and filtration) are typically not reliable methods for removing TDS. Reduction
requires more advanced treatment processes such as RO, nanofiltration, thermal distillation
(including MVR), evaporation, and/or crystallization fOlsson etal.. 2013: Boschee. 2012: Drewes et
al.. 20091. Pretreatment (e.g., chemical precipitation, flotation, etc.) is typically needed to remove
constituents that may cause fouling or scaling with the advanced treatment processes or to remove
specific constituents not removed by a particular advanced process. TDS removal efficiencies
reported in Table F-4 ranged from 97% to >99% with RO, thermal distillation, MVR, and ion
exchange softening with a double pass RO.
RO and thermal distillation processes can treat waste streams with TDS concentrations up to
35,000 mg/L and more than 100,000 mg/L, respectively fT iemann et al.. 2 0141. Extremely high TDS
waters may require a series of advanced treatment processes to remove TDS to desired levels.
However, the cost of treating high-TDS waters may preclude facilities from choosing treatment if
other options, such as deep well injection, are available and more cost-effective (Tiemann etal..
20141.
F.4.3. Anions
Although chemical precipitation processes can reduce concentrations of multivalent anions such as
sulfate, monovalent anions (e.g., bromide and chloride) are not removed by basic treatment
processes and require more advanced treatment such as RO, thermal distillation (including MVR),
evaporation, and/or crystallization (Hammer and VanBriesen. 20121. As shown in Table F-4, anion
F-30
-------
Appendix F - Wastewater Disposal and Reuse Supplemental Information
removal efficiencies in the four studies where sulfate removal was measured ranged from 93% to
>99%.
F.4.4. Metals and Metalloids
Removal of dissolved and precipitated metals and metalloids is commonly needed prior to
discharge to a waterbody or reuse. The facilities in Table F-4 report removals of 98%-99% for a
number of metals. Other work demonstrating effective removal includes a 99% reduction in barium
using chemical precipitation (Marcellus Shale region) (Warner et al.. 2013a) and over 90% boron
removal with RO (at pH of 10.8) at two California facilities fWebb etal.. 2009: Kennedv/lenks
Consultants. 20021. However, influent concentration must be considered together with removal
efficiency to determine whether effluent quality meets the requirements dictated by end use or by
regulations. In the case of the facility described by Kennedv/lenks Consultants (2002). the boron
effluent concentration of 1.9 mg/L (average influent concentration of 16.5 mg/L) was not low
enough to meet California's action level of 1 mg/L.
F.4.5. Radionuclides
Data on radionuclide removals achieved in active treatment plants are scarce. The literature does
provide some data from the Marcellus Shale region on use of distillation and chemical precipitation
(co-precipitation of radium with barium sulfate). As shown in Table F-4, one nine-month pilot scale
study conducted by Bruffand Tikich (2011) reported that distillation treatment produced removal
efficiencies between 97% and >99% for radium, gross alpha, and gross beta, and 71% to 90% for
thorium. In a separate study, Warner etal. f2013bl reported that a CWT was estimated to have
achieved over 99% removal of radium via co-precipitation of radium with barium sulfate (radium
226 influent of 3231 pCi/L and effluent of 4 pCi/L; radium 228 influent of 452 pCi/L and effluent of
2 pCi/L). However, in both studies, radionuclides were detected in effluent samples, and the CWT
was discharging to a surface water body during this time (Warner etal.. 2013b: Bruff and Tikich.
20111 (Section 8.5.2). Between 2010 and 2012, samples of wastewater effluent from a western
Pennsylvania CWT contained a mean radium level of 4 pCi/L fWarner etal.. 2013al.
F.4.6. Organics
Facilities have demonstrated the capability to treat for organic compounds in hydraulic fracturing
wastewaters. Table F-4 shows that one facility achieved 99% removal of oil and grease, BTEX
(benzene, toluene, ethylbenxene, xylenes), gasoline range organics (GRO), diesel range organics
(DRO), and methanol while another facility reported >80% removal of total petroleum
hydrocarbons (TPH), 94% removal of BTEX, and 48% removal of total organic carbon (TOC).
Given the variety of properties among classes of organic constituents, different treatment processes
maybe required depending upon the types of organic compounds needing removal. Table F-5 lists
treatment processes and the classes of organic compounds they can treat It should be noted that in
many studies, rather than testing for several organic constituents, researchers often measure
organics in terms of biochemical oxygen demand and/or chemical oxygen demand, which are
indirect measures of the amount of organic compounds in the water. Organic compounds may also
be measured and/or reported in groupings such as TPH (which includes GRO, DRO, oil and grease),
F-31
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
volatile organic compounds (VOCs) (which include BTEX), and semi-volatile organic compounds
(SVOCs).
Table F-5. Treatment processes for hydraulic fracturing wastewater organic constituents.
Treatment processes
Organic compounds removed
References
Adsorption with activated carbon
Soluble organic compounds
Fakhru'l-Razi et al. (2009)
Adsorption with organoclay media
Insoluble organic compounds
Fakhru'l-Razi et al. (2009)
Air stripping
Volatile organic compounds
Tchobanoglous et al. (2013)
Dissolved air flotation
Volatile organic compounds, dispersed oil
Drewes et al. (2009)
Freeze/thaw evaporation3
TPH, volatile organic compounds, semi-
volatile organic compounds
Duraisamv et al. (2013); Drewes
et al. (2009)
Ion exchange (with modified
zeolites)
BTEX, chemical oxygen demand,
biochemical oxygen demand
Haves et al. (2014); Duraisamv et
al. (2013); Drewes et al. (2009);
Fakhru'l-Razi et al. (2009);
Munter (2000)
Distillation
BTEX, polycyclic aromatic hydrocarbons
(PAHs)
Haves et al. (2014); Duraisamv et
al. (2013); Drewes et al. (2009);
Fakhru'l-Razi et al. (2009).
Chemical precipitation
Oil & grease
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Chemical Oxidation
Oil & grease
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Media filtration (walnut shell
media or sand)
Oil & grease
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Microfiltration
Oil & grease
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Ultrafiltration
Oil & grease, BTEX
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Reverse osmosisb
Dissolved organics
Drewes etal. (2009); U.S. EPA
(2005)
Electrocoagulation
Chemical oxygen demand, Biochemical
oxygen demand
Fakhru'l-Razi et al. (2009)
Biologically aerated filters
Oil & grease, TPH, BTEX
Fakhru'l-Razi et al. (2009)
Reed bed technologies
Oil & grease, TPH, BTEX
Fakhru'l-Razi et al. (2009)
Hydrocyclone separators
Dispersed oil
Drewes et al. (2009)
a Technology cannot be used if the methanol concentration in the hydraulic fracturing wastewater exceeds 5%.
b RO will remove specific classes of organic compounds with removal efficiencies dependent on the compound's structure and
the physical and chemical properties of the hydraulically fractured wastewater. Organoacids will foul membranes.
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
F.5. Centralized Waste Treatment Facilities and Waste Management Options
CWTs are designed to treat for site-specific wastewater constituents so that the effluent meets the
requirements of the designated disposal option(s) (i.e., reuse, direct/indirect discharge). The most
basic treatment processes that a CWT might use include (Easton. 2014: Duhon. 20121:
•	Physical treatment technologies such as dissolved air or induced gas flotation systems,
media filtration, hydrocyclones, and settling including sedimentation/clarification;
•	Chemical treatment technologies such as chemical precipitation (coagulation) and
chemical oxidation; and
•	Biological treatment technologies such as biological aerated filter systems and reed beds.
Although these technologies are effective at removing oil and grease, suspended solids, scale-
forming compounds, and some heavy metals, advanced processes such as RO, thermal distillation,
or evaporation are necessary if TDS should be reduced as required by the intended disposal option.
This section provides an overview of treatment technologies employed at CWTs treating for oil and
gas wastewaters and their discharge options.
F.5.1. Design of Treatment Trains for CWTs
Based on the chemical composition of the hydraulic fracturing wastewater and the desired effluent
water quality, a series of treatment technologies will most likely be necessary. The possible
combinations of unit processes combined into treatment trains are extensive. One report identified
41 different treatment unit processes that have been used in the treatment of oil and gas
wastewater and 19 unique treatment trains fDrewes et al.. 20091. Fakhru'l-Razi etal. f20091 also
provide examples of process flow diagrams that have been used in pilot-scale and commercial
applications for treating oil and gas wastewater. Figure F-7 shows the treatment train for the
Pinedale Anticline Facility as of 2012, which includes pretreatment for dispersed oil, VOCs, and
heavy metals and advanced treatment for removal of TDS, dissolved organics, and boron. This CWT
can either discharge to surface water or provide the treated wastewater to operators for reuse.
F-33
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
DISCHARGE WATER PROCESS
OIL / WATER
SEPARATOR
ANAEROBIC
BASIN
AERATION
BASIN
BORON ION
EXCHANGE
CLARIFI ER
>
SAND
U

Fl LTER
n



MEMBRANE
BIOREACTOR

BIOREACTOR

KEY:
PROCESS
I PRODUCTS
Figure F-7. Full discharge water process used in the Pinedale Anticline field.
Source: Redrawn and adapted from a figure in Boschee (2012).
Table F-6 provides information on some CWTs in locations across the country and the processes
they employ. The table also notes for each facility whether data on effluent quality are readily
available. Comprehensive and systematic data on influent and effluent quality from CWTs that treat
to a variety of water quality levels are difficult to procure. This makes it challenging to understand
removal efficiencies and resulting effluent quality, especially when a facility offers varying degrees
of treatment to meet the water quality needs for different end uses (e.g., reuse vs. discharge). For
those facilities with NPDES permits, discharge monitoring report (DMR) data may be available for
some constituents, although if the facility does not discharge regularly, these data will be sporadic.
As of July 2016, the Pinedale Anticline Facility, the Judsonia Facility, the Eureka Resources Standing
Stone Facility, and Wellington Operating Company's facility appear to be the only CWTs in Table
F-6 discharging to surface water or a groundwater aquifer.1
1 For Pinedale Anticline Water Reclamation Facility, surface water discharges are permitted under 40 CFR 435 Subpart E
(beneficial use subcategoiy agricultural and wildlife water] not 40 CFR 437 (the discharge permit for CWTs]. For the
purposes of this assessment, this facility is included with CWTs.
F-34
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Table F-6. Examples of centralized waste treatment facilities.
Facility
Locality
Description of
unit processes
Does CWT have a
NPDES permit for
discharge?
Does CWT
provide
effluent for
reuse?
Does CWT have
advanced
process for TDS
removal?
What is the status of
the facility as of July,
2016?
Are effluent quality
data available
through literature
search?
Pinedale
Anticline
Water
Reclamation
Facility
WY
Oil/water
separation,
biological
treatment, aeration,
clarification, sand
filtration,
bioreactor,
membrane
bioreactor, RO, ion
exchange, and
desalinization
No - However,
facility is permitted
to discharge under
40 CFR435 Subpart
E (WY0054224).
Facility is permitted
to discharge up to
25% of its effluent
stream
Yes
Yes, RO (Boschee,
2014, 2012)
The treatment plant
produces treated water
for reuse and for
discharge to outfalls
located at the New Fork
River and at Sand Draw.
Yes - DMR data
available on Wyoming
DEQ website. Some
information can also be
obtained from Shafer
(2011).
SEECO-
Judsonia
Water Reuse
Recycling
Facility
AR
Settling, biological
treatment, induced
gas flotation, and
MVR
Yes - AR0052051
Yes
Yes, MVR
The treatment plant
provides treated water
for reuse and for
discharge to surface
water. Based on DMR
data from late 2015-
early 2016, the system is
discharging treated
water to a surface water
body, though
intermittently.
DMR data available
Eureka
Resources -
Williamsport
2nd Street
Facility
PA
Settling, oil/water
separation,
chemical
precipitation,
clarification, MVR.
Can treat with or
without TDS
removal.
No - However,
future plans to
install RO for direct
discharge capability
Yes
Yes, MVR
PerErtel etal. (2013),
the facility provides
treatment wastewater
for reuse and indirect
discharge. The facility
treats entirely or almost
entirely hydraulic
fracturing wastewater.
No
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Appendix F - Wastewater Disposal and Reuse Supplemental Information




Does CWT
Does CWT have

Are effluent quality



Does CWT have a
provide
advanced
What is the status of
data available


Description of
NPDES permit for
effluent for
process for TDS
the facility as of July,
through literature
Facility
Locality
unit processes
discharge?
reuse?
removal?
2016?
search?
Eureka
PA
Settling, oil/water
Yes - PA0232351
Yes
Yes, MVR,
The facility can provide
No
Resources -

separation,


crystallizer
treated wastewater for

Standing

chemical



reuse and also has

Stone Facility,

precipitation,



received an NPDES

Bradford

clarification, MVR,



permit for direct

County

crystallization



discharge.







The facility treats







hydraulic fracturing







wastewater.

Wellington
CO
Dissolved air
Shallow
Yes
Yes, RO but only
Per Stewart (2013), the
No
Operating

flotation, pre-
groundwater

after the water is
facility is providing

Company, LLC

filtration,
percolation pit

sent to an aquifer
treated wastewater for

- 3W

microfiltration with
permits issued by

storage and
reuse, for agricultural

Production

ceramic
COGCC-281818

recovery well
use, to a shallow well to

Water

membranes,
and 281824


augment the municipal

Treatment

activated carbon



drinking water supply,

Facility

adsorption. Water is



and for discharge to the



pumped to rapid-



Colorado River.



infiltration pit which







then percolates to a







tributary aquifer.







The aquifer supplies







water to an RO







plant (Alzahrani et







al.. 2013).





F-36
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Facility
Locality
Description of
unit processes
Does CWT have a
NPDES permit for
discharge?
Does CWT
provide
effluent for
reuse?
Does CWT have
advanced
process for TDS
removal?
What is the status of
the facility as of July,
2016?
Are effluent quality
data available
through literature
search?
Casella Altela
Regional
Environmental
Services
(CARES)
McKean
Facility
McKean
County, PA
Pretreatment
system (not defined
in literature) and
thermal distillation
Yes - PA0102288
Yes
Yes -thermal
distillation
The treatment plant is
capable of reuse and
recycle for fracturing
operations and surface
water discharge of
excess water. However,
the vendor has indicated
that the facility is only
treating water for
reuse/recycle as of early
2015.
No-just NPDES
discharge requirements
Clarion Altela
Environmental
Services
(CAES) Facility
Clarion
County, PA
Pretreatment
system (not defined
in literature) and
thermal distillation
Yes - PA0103632
Yes
Yes -thermal
distillation
The treatment plant is
capable of reuse and
recycle for fracturing
operations and surface
water discharge of
excess water. However,
the facility has indicated
that it is only treating
water for reuse/recycle
as of early 2015.
No-just NPDES
discharge requirements
Terraqua
Resource
Management
(aka. Water
Tower Square
Gas Well
Wastewater
Processing
Facility)
Lycoming
County, PA
Equalization tanks,
oil-water separation
via chemical
addition (sulfuric
acid, emulsion
breaker), pH
adjustment,
coagulation,
flocculation,
inclined plate
clarifier, sand
filtration
No
Yes
No - However,
TARM recognizes
that they can't
discharge, until
they install TDS
treatment
Listed as proposed CWT,
Part 1 NPDES permit
issued, awaiting Part II
WQM application per PA
DEP website visited
August 25, 2016. (See
DEP's list of Waste
Water Treatment
Facilities and
http://mshaletaskforce.
ors/Slte Locations.html)
No
F-37
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Facility
Locality
Description of
unit processes
Does CWT have a
NPDES permit for
discharge?
Does CWT
provide
effluent for
reuse?
Does CWT have
advanced
process for TDS
removal?
What is the status of
the facility as of July,
2016?
Are effluent quality
data available
through literature
search?
Maggie Spain
Water-
Recycling
Facility
Decatur, TX
Settling, flash mixer
with lime and
polymer addition,
inclined plate
clarifier, surge tank,
MVR
No
Yes
Yes-MVR
The facility
reuses/recycles treated
water for fracturing
operations. It is unclear
if the MVR mobile unit is
still at this facility. A
pilot study is in progress
at the facility that began
in 2015 looking at the
addition of a hollow
fiber air stripping
membrane unit for C02
removal prior to an
UF/RO unit.
Yes - Some information
can be obtained from
Haves et al. (2014).
Fountain
Quail/NAC
Services -
Kenedy
Kenedy, TX
Oil-water separator,
coagulation,
flocculation,
sedimentation,
filtration, MVR.
No
Yes
Yes-MVR
According to its website,
the facility
reuses/recycles treated
water for fracturing
operations
(http://www.fountainau
ail.com/water-recvcling-
No






solutions/clean-
brine/case-
studies/eagle-ford-
shale-texas).

Purestream -
Gonzales
facility
Gonzales, TX
Induced gas
flotation and MVR
No
Yes
Yes - MVR
Per Dahm and Chapman
(2014) commercial
operations deployed
March 2014 for
reuse/recycle for
fracturing operations.
No
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
Facility
Locality
Description of
unit processes
Does CWT have a
NPDES permit for
discharge?
Does CWT
provide
effluent for
reuse?
Does CWT have
advanced
process for TDS
removal?
What is the status of
the facility as of July,
2016?
Are effluent quality
data available
through literature
search?
FourPoint
Energy, LLC
(formerly
owned by Linn
Energy -
Granite Wash
Wheeler
County, TX
Induced gas
flotation and MVR
No
Yes
Yes - MVR
AVARA system installed
for reuse/recycle in June
2014, according to
http://purestream.com/
index.php/water-
management/vapor-
recompression/photos-
and-videos.
Assume still operational
but status unclear as
new private company
acquired Linn Energy's
oil and gas assets in
2014.
No
Fluid Recovery
Service
Josephine
Facility3
PA
Oil-water separator,
aeration, chemical
precipitation with
sodium sulfate,
lime, and a polymer,
inclined plate
clarifier
PA0095273
Permit renewal
application
submitted and
under review by PA
DEP.
No
No
The facility stopped
accepting Marcellus
wastewater September
30. 2011 (Ferraretal.,
2013). It treats
conventional oil and gas
wastewater.
The facility plans to
upgrade to include
evaporative technology
to attain monthly
average TDS levels of
500 mg/L or less. Not
upgraded as of July,
2016.
Yes - Some effluent
results obtained from
Ferrar et al. (2013) and
Warner et al. (2013a).
Also minimal DMR data
from the EPA.
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Appendix F - Wastewater Disposal and Reuse Supplemental Information




Does CWT
Does CWT have

Are effluent quality



Does CWT have a
provide
advanced
What is the status of
data available


Description of
NPDES permit for
effluent for
process for TDS
the facility as of July,
through literature
Facility
Locality
unit processes
discharge?
reuse?
removal?
2016?
search?
Fluid Recovery
PA
Oil-water separator,
PA0101508
No
No
This facility is not
Minimal DMR data from
Service

aeration, chemical



accepting wastewater
the EPA.
Franklin

precipitation with
Permit renewal


from hydraulic

Facility3

sodium sulfate,
lime, and a polymer,
inclined plate
clarifier
application
submitted and
under review by PA
DEP.


fracturing operations as
of July 2016. It treats
conventional oil and gas
wastewater. The facility
plans to upgrade to
include evaporative
technology to attain
monthly average TDS
levels of 500 mg/L or
less. Not upgraded as of
July, 2016.

Hart
PA
Oil-water separator,
PA0095443
No
No
This facility is not
Minimal DMR data from
Resources-

aeration, chemical



accepting wastewater
the EPA.
Creekside

precipitation with
Permit renewal


from hydraulic

Facility3

sodium sulfate,
lime, and a polymer,
inclined plate
clarifier
application
submitted and
under review by PA
DEP.


fracturing operations as
of July 2016. It treats
conventional oil and gas
wastewater. The facility
plans to upgrade to
include evaporative
technology to attain
monthly average TDS
levels of 500 mg/L or
less. Not upgraded as of
July, 2016.

3 As of May 15, 2013, these facilities are under an administrative order (AO). According to the AO, these facilities must comply with a monthly effluent limit for TDS not to exceed
500 mg/L. This will allow them to treat high-saline wastewaters typical of unconventional oil and gas operations. To meet the requirements of the AO, they have applied to the
Pennsylvania Department of Environmental Protection (PA DEP) for a NPDES permit and are planning to install treatment for TDS.
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
F.5.2. Discharge Options for CWTs
Direct discharge CWTs are allowed to discharge treated wastewater directly to surface waters
under the NPDES permit program. Discharge limitations may be based on water quality standards
in the NPDES and technology-based effluent limitation guidelines under 40 CFR Part 437. In
addition, permitting authorities have permitted facilities for discharge under 40 CFR 435, Subpart
E.	Judsonia Central Water Treatment Facility in Sunnydale, Arkansas is permitted to directly
discharge treated effluent from produced water from the Fayetteville Shale play to Byrd pond
located on the property. Pinedale Anticline Field Wastewater Treatment Facility in Wyoming, WY,
originally designed to treat produced water from tight gas plays in the Pinedale Anticline Field to
levels suitable for reuse, was upgraded to include desalinization and RO treatment for discharge to
a local river. CWTs with NPDES discharge permits may also opt to treat oil and gas wastewater for
reuse as shown in Table F-6. Some facilities have the ability to treat wastewater to different
qualities (e.g., with or without TDS removal), which they might do to target various reuse water
quality criteria. Both the Judsonia and Pinedale facilities discussed above have the ability to employ
either TDS- or non-TDS-removal treatments depending on the customers' needs.
Indirect discharge CWTs may treat hydraulic fracturing wastewater and then discharge the treated
wastewater effluent to a POTW. Discharge to the POTW is controlled by an Industrial User
mechanism, which incorporates pretreatment standards established in 40 CFR Part 437. Two
facilities, one located in Pennsylvania (Eureka Resources) and the other in Ohio (Patriot Water
Treatment), include indirect discharge as an option in wastewater treatment. The Eureka-
Williamsport facility accepts wastewater (primarily from the Marcellus Shale play) and either
treats it for reuse or discharges it to the local POTW. The Patriot facility offers services to hydraulic
fracturing operators in the Marcellus and Utica Shale plays for removal of solids and metals using
chemical treatment As of March 2015, however, the Patriot facility is limited by the Ohio
Environmental Protection Agency to accepting only "low salinity" (<50,000 mg/L TDS) produced
water and may only discharge 100,000 gal (380,000 L) per day to the Warren Ohio POTW.
Zero-discharge CWTs do not discharge treated wastewater; instead, the wastewater is treated and
reused in subsequent hydraulic fracturing operations. WVWRI (2012) state that this practice
reduces potential effects on surface drinking water resources by reducing both direct and indirect
discharges. Zero-discharge facilities may offer varying levels of treatment, including minimal
treatment (for example, filtration), low-level treatment (chemical precipitation), and/or advanced
treatment (evaporation, crystallization). Reserved Environmental Services (RES) in Mt Pleasant,
Pennsylvania, is a zero liquid discharge facility permitted by PA DEP to treat wastewater from the
Marcellus Shale play for reuse. Residual solids are dewatered and sent to a landfill. Treated
wastewater effluent is stored, monitored, and chlorinated for reuse fONG Services. 20151.
F.6.	Water Reuse
With the scarcity of freshwater supplies and limited access to disposal wells in some areas of the
country, reuse of hydraulic fracturing wastewaters for subsequent hydraulic fracturing activity has
become more prevalent (Section 8.4.4). This section discusses factors to consider in adopting reuse
and the recommended or otherwise observed water quality needed.
F-41
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
F.6.1. Factors in Considering Reuse
In making the decision whether to manage wastewater via reuse, operators have several factors to
consider (Slutz etal.. 2012: NPC. 20111:
•	Wastewater generation rates compared to water demand for future fracturing operations,
•	Wastewater quality and treatment requirements for use in future operations,
•	The costs and benefits of wastewater management for reuse compared with other
management strategies,
•	Available infrastructure and treatment technologies, and
•	Regulatory considerations.
Among these factors, costs may be the most significant driver, weighing the costs of transportation
from the generating well to the treatment facility and to the new well against the costs for transport
to alternative locations (a disposal well or CWT). Trucking large quantities of water can be
relatively expensive (from $0.50 to $8.00 per barrel), rendering on-site treatment technologies and
reuse potentially economically competitive in some settings fDahm and Chapman. 2014: Guerra et
al.. 20111. Also, logistics, including proximity of the water sources for aggregation, may be a factor
in implementing reuse. For example, Boschee f20141 notes that in the Permian Basin, older
conventional wells are linked by pipelines to a centralized transfer facility, enabling movement of
treated water to areas where it is needed for reuse.
Regulatory factors may facilitate reuse. In 2013, the Texas Railroad Commission adopted rules
intended to encourage statewide water conservation. These rules facilitate reuse by eliminating the
need for a permit when operators reuse on their own lease or transfer the fluids to another
operator for use in hydraulic fracturing fRushton and Castaneda. 20141. Data for the years after
2013 will allow evaluation of whether reuse increased after this regulatory change.
Recommended compositional ranges for the base fluid used to formulate hydraulic fracturing fluid
may shift in the future as fracturing fluid technology continues to develop. Development of
fracturing mixture additives that are brine-tolerant have allowed for the use of high TDS
wastewaters (up to tens of thousands of mg/L) for reuse in fracturing fTiemann et al.. 2 014: GTI.
2012: Minnich. 20111. Some new fracturing fluid systems are claimed to be able to tolerate salt
concentrations exceeding 300,000 mg/L (Boschee. 20141. This greater flexibility in acceptable
water chemistry can facilitate reuse both logistically and economically by reducing treatment
needs.
Reuse rates may also fluctuate with changes in the supply and demand of treated wastewater and
the availability of fresh water. Flowback may be preferable to later-stage produced water for reuse
because it is typically generated in larger quantities from a single location as opposed to water
produced later on, which is generated in smaller volumes over time from many different locations.
Flowback also tends to have lower TDS concentrations than later-stage produced water. In the
Marcellus, TDS has been shown to increase from tens of thousands to about 100,000 mg/L during
the first 30 days fBarbotetal.. 2013: Malonev and Yoxtheimer. 20121: see Chapter 7. As more wells
F-42
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Appendix F - Wastewater Disposal and Reuse Supplemental Information
go into production, the changing production rate and quality of wastewaters generated in a region
need to be taken into account, as well as a possible reduction in the demand for reused water as
plays mature (Lutz etal.. 2013: Hayes and Severin. 2012b: Slutz etal.. 20121.
F.6.1.1. On-Site Treatment for Reuse
On-site systems that treat produced water for reuse can reduce potential impacts on drinking
water resources associated with transportation and disposal, and they can facilitate the logistics of
reuse by preparing the water close to well sites. These systems sometimes consist of mobile units
containing one or more treatment processes that can be moved from site to site to treat waters in
newly developed sites that are not yet producing at full-scale. Semi-permanent facilities that serve
specific areas also exist ("Halldorson. 2013: Boschee. 2012).
Treatment systems are typically tailored for site-specific produced water chemical concentrations
and desired water quality treatment goals, including whether significant TDS removal is needed. If
low TDS water is needed, more advanced treatment will be required (as discussed in Section F.2).
This more extensive treatment can increase the treatment costs by three to four times compared to
treatment systems that do not remove TDS (Halldorson. 20131. On-site facilities may be warranted
where truck hauling or seasonal accessibility to and from a central facility is an issue fBoschee.
2014: Tiemann etal.. 20141. Operators may also consider on-site facilities if they have not fully
committed to an area and the well counts are initially low. In those instances, they can later decide
to add or remove units based on changing production volumes fBoschee. 20141.
F.6.2. Water Quality for Reuse
As of 2016, there is no consensus on the water quality requirements for reuse of wastewater for
hydraulic fracturing, and operator opinions vary on the minimum standards for the water quality
needed for fracturing fluids fVidic etal.. 2013: Acharva etal.. 20111. Table F-7 provides a list of
constituents and the recommended or observed target concentrations for reuse applications. The
wide concentration ranges for many constituents (e.g., TDS ranging from 500 to 70,000 mg/L)
suggest that water quality requirements for reuse are dictated by operation-specific requirements,
including operator preference and selection of fracturing fluid chemistry.
Table F-7. Water quality requirements for reuse.
Source: U.S. EPA (2015m).
Constituent
Reasons for limiting
concentrations
Recommended or observed base fluid target
concentrations (mg/L, after blending)13
TDS
Fluid stability
500 - 70,000
Chloride
Fluid stability
2,000 - 90,000
Sodium
Fluid stability
2,000 - 5,000
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Constituent
Reasons for limiting
concentrations
Recommended or observed base fluid target
concentrations (mg/L, after blending)13
Metals
Iron
Scaling
LO
1
1
1
Strontium
Scaling
l
Barium
Scaling
2-38
Silica
Scaling
20
Calcium
Scaling
50 - 4,200
Magnesium
Scaling
10 -1,000
Sulfate
Scaling
124 -1,000
Potassium
Scaling
100 - 500
Scale formers3
Scaling
2,500
Other
Phosphate
Not Reported
10
TSS
Plugging
50 -1,500
Oil
Fluid stability
5-25
Boron
Fluid stability
0-10
pH (S.U.)
Fluid stability
1
00
1
LO
UD
Bacteria (counts/mL)
Bacterial growth
0 -10,000
a Includes total of barium, calcium, manganese, and strontium.
b Unless otherwise noted.
Wastewater quality can be managed for reuse either by blending it with freshwater and allowing
dilution to bring the concentrations of problematic constituents to an acceptable range or through
treatment fVeil. 20101. Treatment, if needed, can be conducted at facilities that are mobile, semi-
permanent modular systems, or fully permanent CWTs fNicotetal.. 20121. At a minimum, hydraulic
fracturing service providers generally prefer that the wastewater be treated to remove TSS,
microorganisms, and constituents that form scale or inhibit crosslinking in gelled fluid systems
fBoschee. 20141. Figure F-8 shows a schematic of a treatment system to treat wastewater for reuse
that can remove suspended solids, hardness, and organic constituents.
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Frac
Flowback
Water
Oil
Byproduct
Air
Oxidation:
Chlorine Dioxide
Lime or
Caustic
Sodium
Sulfate
Soda
Ash
Acid

Treated
Water
GAC:
Organics Polish
Precip/Clarifier:
Hardness Removal
Sand Filter:
TSS Removal
COM Smith, adapted by The Cadmus Group
Figure F-8. Diagram of treatment for reuse of flowback and produced water.
Source: Kimball (2010). Reprinted with permission from CDM Smith.
In the Marcellus, the wastewater to be reused is generally treated with oil/gas-water separation,
filtration, and dilution fMa et al.. 20141. Although many Marcellus treatment facilities only supply
basic reuse treatment that removes oil and solids, advanced treatment facilities that use techniques
such as RO or distillation methods are also in operation (Veil. 20101.
Reuse concerns can vary with the type of hydraulic fracturing fluid used (e.g., slickwater, linear gel,
crosslinked gel, foam] (Wasvlishen and Fulton. 20121 and the anticipated changes in water
chemistry over time during the transition from flowback to produced water (Hammer and
VanBriesen. 20121. Elevated TDS is a concern, but residual constituents from previous fluid
mixtures (e.g., breakers] may also cause difficulties when reusing water for subsequent fracturing
operations fMontgomery. 2013: Walsh. 20131.
F.7. Hydraulic Fracturing Wastewater Impacts on POTWs
Wastewater treatment processes used by POTWs are generally not designed or operated to treat
wastewater containing high salt concentrations (>0.1-5% salt], and sudden increases in chloride
concentration above 5-8 g/L may cause problems for wastewater treatment fLudzack and Noran.
19651. Four basic problems for biological treatment of saline water have been described fWoolard
and Irvine. 19951: (1] microbes in POTW treatment systems tend to be sensitive to changes in ionic
strength; (2] microbial metabolic functions are disrupted, leading to decreased degradation of
carbon compounds; (3] effluent suspended solids are increased due to cell lysis and/or a reduction
in organisms that promote flocculation; and (4] the extent to which biomass at a POTW can
acclimate to a salty environment is limited. To address concerns with high salinity and other
contaminants that are either not removed by or can adversely impact the POTW treatment system,
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EPA has promulgated pretreatment standards intended to prevent pollutants in unconventional oil
and gas wastewaters from reaching POTWs (Chapter 8).
If indirect discharge to a POTW is being considered or is employed, some adaptations can be useful
for wastewater treatment trains at C WTs handling hydraulic fracturing wastewater to meet the
established federal limits. For example, biological pre-treatment may be beneficial as an added
process prior to indirect discharge from a CWT to a POTW for removal of organic contaminants.
Specialized treatment systems using salt-tolerant bacteria may be beneficial as an additional level
of treatment for pre-treating (or polishing) wastewaters at CWTs. (These processes differ from
conventional biological processes in standard wastewater treatment, which are not suitable for
large volumes of hydraulic fracturing wastewater). In particular, membrane bioreactors (MBRs)
have been examined for the treatment of oil and gas wastewater (Dao etal.. 2013: Kose etal.. 2012:
Miller. 2011). MBRs provide advantages over conventional aeration basin processes as they can be
incorporated into existing treatment trains more easily and have a much smaller areal footprint
than aeration basins.
F.8. Hydraulic Fracturing Wastewater and Disinfection Byproducts
F.8.1. Disinfection Byproducts
This section provides background information on disinfection byproducts (DBPs) and their
formation to support the discussion in Section 8.5.1 of Chapter 8 regarding impacts on surface
waters and downstream drinking water utilities due to elevated bromide and iodide in hydraulic
fracturing wastewaters.
Regulated DBPs are a small subset of the full spectrum of DBPs that include other chlorinated,
brominated, iodated, and nitrogenous DBPs. Some of the emerging unregulated DBPs may be more
toxic than their regulated counterparts (Harkness etal.. 2015: McGuire etal.. 2014: Parker et al..
20141. Of the many types of DBPs that can form when drinking water is disinfected, Safe Drinking
Water Act (SDWA) Stage 1 and Stage 2 DBP Rules regulate four total trihalomethanes (TTHM), five
haloacetic acids (HAA5), bromate, and chlorite fU.S. EPA. 20061.
Most brominated DBPs form when water containing organic material and bromide reacts with a
disinfectant such as chlorine or chloramines during drinking water treatment Parameters that
affect DBP formation include concentration and type of organic material, disinfectant type,
disinfectant concentration, pH, water temperature, and disinfectant contact time. In addition, many
studies have found that elevated bromide levels correlate with increased DBP formation (AWWA.
2010: Obolenskv and Singer. 2008: Matamoros etal.. 2007: Hua etal.. 2006: Yang and Shang. 20041.
Some studies found similar results for iodide as well fMcGuire etal.. 2014: Parker etal.. 20141. Pope
etal. f20071 reported that increased bromide levels are the second best indicator of DBP formation,
with pH being the best.
In addition, research finds that higher levels of bromide and iodide contribute to increased
concentrations of the brominated and iodated forms of DBPs (both regulated and unregulated),
which tend to be more cytotoxic, genotoxic, and carcinogenic than chlorinated species (McGuire et
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al.. 2014: Parker etal.. 2014: States etal.. 2013: Krasner. 2009: Richardson etal.. 20071. Studies
generally report that the ratios of halogen incorporation into DBPs reflect the ratio of halogen
concentrations in the source water ("Criquetetal., 2012; lones etal., 2012; Obolensky and Singer,
2008") but that bromide is preferentially incorporated into halogenated DBPs ("McGuire etal., 2014;
Parker etal., 2014; States etal., 2013; Krasner, 2009; Obolensky and Singer, 2008; Richardson etal.,
2007; Hua et al., 2006").
From a regulatory perspective, elevated bromide levels create difficulties in meeting drinking water
maximum contaminant levels (MCLs). When the TTHM are predominately in the form of
brominated DBPs, the higher molecular weight of bromide (79.9 g/mol) relative to chloride (35.5
g/mol) causes the overall mass of the TTHM sum to increase. This can lead to elevated
concentrations of TTHM, in turn potentially leading to violations of the TTHM MCL for the drinking
water utility (Francis etal.. 20091.
High bromide levels are also cited as causing formation of nitrogenous DBP N-
nitrosodimethylamine (NDMA) in water disinfected with chloramines (Luh and Marinas. 20121.
Although NDMA is not regulated by the EPA as of 2016, it is listed as a priority toxic pollutant, and
the EPA is planning to evaluate NDMA and other nitrosamines as candidates for regulation during
the six-year review of the Microbial and Disinfection Byproducts (MDBP) rules fU.S. EPA. 2014al.
F.8.2. Studies Modeling Bromide in Receiving Waters from CWT Effluents
Contaminant modeling by Weaver etal. (20161 found that reducing effluent concentrations (e.g.,
discharging flowback versus produced water), discharging during higher stream flow periods, and
using a pulsing or intermittent discharge can reduce bromide levels in receiving streams. Input data
for the model came from several sources. Effluent bromide concentrations and permitted discharge
flows came from eight commercial wastewater treatment plants in western Pennsylvania. Receiving
stream flows were based on U.S. Geological Survey gage data. Data on flow accretion based on an
analysis of tracer data from literature and EPA studies. The model assessed both steady-state and
transient scenarios. The steady-state model assumed fixed discharges and flows and calculated
mass and volume flow balance in a river network. The transient (i.e., pulsed or intermittent
discharge) model simulations were based on a model developed by Weaver etal. (2016) assuming
discharges of 12, 8, and 4 hours per day as well as a 24-hour simulation for comparison to a steady-
state scenario. For steady-state scenarios, bromide concentrations were lowest under high flow
conditions in the source water and with lower concentrations of bromide in the effluent. Bromide
concentrations were generally lower for the pulsed scenarios than for the steady-state discharge
scenarios.
In a separate study, U.S. EPA (2015ml evaluated the relative contributions of bromide, chloride,
nitrate, and sulfate from CWTs primarily treating hydraulic fracturing wastewater to the Allegheny
River Basin and to two downstream public water system intakes. The Allegheny River and its
tributaries receive runoff and discharges containing an array of contaminants. Contaminant sources
include discharges from CWTs for oil and gas wastewater, runoff from acid mine drainage and
mining operations, discharges from coal-fired electric power stations, industrial wastewater
treatment plant effluents, and POTW discharges. The Allegheny River is the water supply for
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thirteen public water systems that serve over 500,000 people in western Pennsylvania
underscoring the importance of a full understanding of upstream contaminant contributions.
In Pennsylvania, wastewater produced from hydraulic fracturing of the Marcellus formation has
been mostly diverted from CWTs and POTWs that discharge to public waters in the state to other
management practices such as reuse fHammer and VanBriesen. 20121. Wastewater produced from
hydraulic fracturing of non-Marcellus formations, however, continues to be sent to CWTs and
POTWs on the Allegheny River.
In order to quantify relative contributions of anions as a contaminant source at public drinking
water system intakes, an EPA source apportionment study determined relative contributions of
bromide from several upstream activities fU.S. EPA. 2015ml. The study developed chemical source
profiles for discharges upstream of the drinking water system intakes, characterized water quality
in the river upstream and downstream of the CWTs and other facilities, characterized the water
quality at the drinking water system intakes, and analyzed the sampling data collected with the EPA
Positive Matrix Factorization (PMF) receptor model. The study focused on low-flow conditions.
Researchers found that CWTs and coal-fired power plants with flue gas desulfurization were
responsible for the majority of bromide at the two public water supply intakes. CWTs accounted for
a substantial contribution of bromide, with 88-89% at one intake and 37% atthe other. Coal-fired
power plants with flue gas desulfurization were the other substantial contributors, with 50% atthe
second intake but less than 1% at the first Sediment and acid mine drainage were also minor
contributors in the range of 1 to 11% fU.S. EPA. 2015ml.
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Appendix G. Identification and Hazard Evaluation of
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Supplemental Information
G.l. Introduction
Appendix G provides detail and supporting information on the oral reference values (RfVs) and oral
slope factors (OSFs) that were identified in Chapter 9 of this assessment1 Section G.2 provides
detail on the criteria used to select sources of RfVs, OSFs, and qualitative cancer classifications for
chemicals used or detected in hydraulic fracturing processes, and lists all sources that were
considered for this study. Section G.3 provides a glossary of the toxicity terminology that is used by
these various sources. Section G.4 provides a brief description of other potential tools and
approaches that could be used by stakeholders to prioritize and estimate toxicity of chemicals that
have a limited toxicity database. Lastly, all of the toxicity data collected from the sources that met
the criteria for inclusion in this study are provided. Table G-la through G-le show the available
RfVs, OSFs, and qualitative cancer classifications for chemicals used in hydraulic fracturing fluids,
and Table G-2a through Table G-2e show the available RfVs, OSFs, and qualitative cancer
classifications for chemicals detected in produced water from hydraulically fractured wells. These
tables also indicate whether each chemical has available data on physicochemical properties or
occurrence.
G.2. Criteria for Selection and Inclusion of Reference Value (RfV), Oral Slope
Factor (OSF), and Qualitative Cancer Classification Data Sources
The criteria listed below were used to evaluate the quality of RfVs, OSFs, and qualitative cancer
classifications considered for use in the hazard analyses conducted in Chapter 9. These criteria
were originally outlined in the hydraulic fracturing research plan fU.S. EPA. 2011a) and interim
progress report fU.S. EPA. 2012el Only data sources that met these criteria were considered of
sufficient quality to be included in the analyses.
The following criteria had to be met for a source to be deemed of sufficient quality:
1. The body or organization generating or producing the peer-reviewed RfVs, peer-reviewed
OSFs, or peer reviewed qualitative assessment must be a governmental or
intergovernmental body.
a.	Governmental bodies include sovereign states, and federated states/units.
b.	Intergovernmental bodies are those whose members are sovereign states, and the
subdivisions or agencies of such intergovernmental bodies. The United Nations is
an example of an intergovernmental body. The International Agency for Research
1 As defined in Chapter 9, the term RfV refers to reference values for noncancer effects occurring via the oral route of
exposure and for chronic durations, except where noted.
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on Cancer (IARC) is an agency of the World Health Organization (WHO), which is
itself an agency of the United Nations. Thus, IARC is considered a subdivision of the
United Nations.
2.	The data source must include peer-reviewed RfVs, peer-reviewed OSFs, or peer reviewed
qualitative assessments.
a.	A committee that is established to derive the RfVs, OSFs, or qualitative
assessments can have members of that same committee provide the peer review,
so long as either the entire committee, or members of the committee who did not
participate in the derivation of a specific section of a work product, conduct the
review.
b.	Peer reviewers who work for grantees of the organization deriving the RfVs, OSFs,
or qualitative assessments are generally allowed, and this will not be considered to
constitute a conflict/duality of interest.
c.	Peer reviewers may work in the same or different office, so long as they did not
participate in any way in the development of the product, and these individuals
must be free of conflicts/duality of interest with respect to the chemical(s)
assigned.
i. For instance, peer reviewers for Program X, conducted by Office A, may
also be employed by Office A so long as they did not participate in the
creation of the Program X product they are reviewing.
3.	The RfVs, OSFs, or qualitative assessments must be based on peer-reviewed scientific data.
a. There are cases where industry reports that were not published in a peer-
reviewed, scholarly journal may be used, if the industry report has been
adequately peer-reviewed by an external body (external to the group generating
the report, and external to the group generating the peer-reviewed RfVs, peer-
reviewed OSFs, or peer-reviewed qualitative assessment) that is free of
conflicts/dualities of interest.
4.	The RfVs, OSFs, or qualitative assessments must be focused on protection of the general
public.
a. Sources that are focused on workers are not appropriate as workers are assumed
to accommodate additional risk than the general public due to their status as
workers.
5.	The body generating the values or qualitative assessments must be free of conflicts of
interest with respect to the chemicals for which it derives RfVs, OSFs, or qualitative
assessments.
a. If a body generating the RfVs, OSFs, or qualitative assessments accepts funding
from an interested party (i.e., a company or organization that may be impacted by
past, present, or future values or qualitative assessments), then the body has a
conflict of interest
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b. For instance, if a non-profit organization is funded by an industry trade group, and
the non-profit generates RfVs, OSFs, or qualitative assessments for chemicals that
trade group is interested in, then the non-profit is considered to have a conflict of
interest with respect to those chemicals.
It is important to note that having a conflict/duality of interest for one chemical is sufficient to
disqualify the entire database, as it is assumed that conflicts/dualities of interest may exist for
other chemicals as well.
G.2.1. Included Sources
We applied our criteria to 16 different sources of RfVs and/or OSFs. After application of our criteria,
we were left with eight sources. For those sources which did not meet our criteria, we provide an
explanation of why they were excluded.
The following sources were evaluated, met our criteria, and were selected as sources of reference
doses or cancer slope factors for this analysis:
•	U.S. EPA Integrated Risk Information System (IRIS).
•	U.S. EPA Human Health Benchmarks for Pesticides (HHBP).
•	U.S. EPA Provisional Peer-Reviewed Toxicity Values (PPRTVs).
•	U.S. Agency for Toxic Substances and Disease Registry (ATSDR) Minimal Risk Levels
(MRLs).
•	California EPA (CalEPA) Toxicity Criteria Database.
•	International Programme on Chemical Safety (IPCS) Concise International Chemical
Assessment Documents (CICAD).
The following sources were evaluated, met our criteria, and were selected as sources of qualitative
cancer classifications:
•	International Agency for Research on Cancer (IARC).
•	US National Toxicology Program (NTP) Report on Carcinogens (RoC).
RfVs, OSFs, and qualitative cancer characterizations from these data sources are listed in Tables G-
la through G-le for chemicals used in hydraulic fracturing fluid formulation, and Tables G-2a
through G-2e for chemicals reported in hydraulic fracturing produced water.
In addition, Table G-la and Table G-2a also list the EPA's drinking water maximum contaminant
levels (MCLs) and maximum contaminant goal levels (MCLG) when available. These values are
generally based on IRIS values, and MCLs are treatment-based.
G.2.2. Excluded Sources
The following sources were excluded:
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•	American Conference of Governmental Industrial Hygienists: The assessments
derived by this body are specific to workers and are not generalizable to the general
public. In addition, this body is not a governmental or intergovernmental body. Thus, these
values were excluded based on criteria 1 and 4.
•	European Chemicals Bureau, Classification and Labeling Annex I of Directive
67/548/EEC: These assessments are not based on peer-reviewed values, but are based on
data supplied by manufacturers. Further, the enabling legislation states that
"Manufacturers, importers, and downstream users shall examine the information...to
ascertain whether it is adequate, reliable and scientifically valid for the purpose of the
evaluation..." This clearly demonstrates that the data and the evaluation are not required
to be peer-reviewed. Thus, these values were excluded based on criterion 2.
•	Toxicology Excellence for Risk Assessment's (TERA's) International Toxicity
Estimates for Risk Assessment (ITER): The ITER database is developed by TERA a
501(c)(3) non-profit TERA accepts funding from various sources, including interested
parties that may be impacted by their assessment work. Thus, ITER is excluded based on
criteria 1 and 5.
•	Other U.S. states: The EPA evaluated values from all states that had values reported on
their websites. If a state's values were determined to be largely duplicative of the EPA's
values (e.g., the state adopts EPA values, such as the regional screening levels, and does
not typically generate its own peer-reviewed values), that state's values were no longer
considered. The EPA contacted those states whose values were determined to not be
duplicative of the EPA's values, and confirmed whether or not a peer review process was
used to develop the state's values. The EPA determined that of the states with values not
duplicative of the EPA's values, only California's values met all of the EPA's criteria for this
report Other states with publicly accessible RfVs and/or OSFs include: Alabama, Florida,
Hawaii, and Texas.
•	WHO Guidelines for Drinking-Water Quality: The WHO Guidelines' values are not RfVs,
but rather drinking water values.
G.3. Glossary of Toxicity Value Terminology
This section defines the toxicity values and qualitative cancer classifications that are frequently
found in the sources identified above.
Lowest-observed-adverse-effect level (LOAEL): The lowest exposure level at which there are
biologically significant increases in frequency or severity of adverse effects between the exposed
population and its appropriate control group. Source: U.S. EPA (2011c).
Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive
toxicant at which the chemical would have no observable adverse reproductive effect, assuming
exposure at 1,000 times that level. Source: OEHHA (2012).
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Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in
drinking water. MCLs are set as close to the MCLG as feasible using the best available analytical and
treatment technologies and taking cost into consideration. MCLs are enforceable standards. Source:
U.S. EPA ("2012a").
Maximum contaminant level goal (MCLG): A non-enforceable health benchmark goal which is set
at a level at which no known or anticipated adverse effect on the health of persons is expected to
occur and which allows an adequate margin of safety. Source: U.S. EPA (2012a).
Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance
at or below which the substance is unlikely to pose a measurable risk of harmful (adverse),
noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a
specified time period (acute, intermediate, or chronic). MRLs should not be used as predictors of
harmful (adverse) health effects.
•	Chronic MRL: Duration of exposure is 365 days or longer.
•	Intermediate MRL: Duration of exposure is >14 to 364 days.
•	Acute MRL: Duration of exposure is 1 to 14 days.
Source: ATSDR C20091.
No-observed-adverse-effect level (NOAEL): The highest exposure level at which there are no
biologically significant increases in the frequency or severity of adverse effect between the exposed
population and its appropriate control; some effects may be produced at this level, but they are not
considered adverse or precursors of adverse effects. Source: U.S. EPA (2011c).
Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased
cancer risk from a lifetime oral exposure to an agent This estimate, usually expressed in units of
proportion (of a population) affected per mg/kg-day, is generally reserved for use in the low-dose
region of the dose-response relationship, that is, for exposures corresponding to risks less than 1 in
100. Source: U.S. EPA f2011cl.
Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of
a daily oral exposure to the human population (including sensitive subgroups) that is likely to be
without an appreciable risk of deleterious effects during a lifetime. It can be derived from a NOAEL,
LOAEL, or benchmark dose, with uncertainty factors generally applied to reflect limitations of the
data used. Generally used in the EPA's noncancer health assessments.
•	Chronic RfD: Duration of exposure is up to a lifetime.
•	Subchronic RfD (sRFD): Duration of exposure is up to 10% of an average lifespan.
•	Acute RfD: Duration of exposure is 24 hours or less.
Source: U.S. EPA f2011cl.
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Reference value (RfV): An estimate of an exposure for a given duration to the human population
(including susceptible subgroups) that is likely to be without an appreciable risk of adverse health
effects over a lifetime. RfV is a generic term not specific to a given route of exposure. In the context
of this report, the term RfV refers to reference values for noncancer effects occurring via the oral
route of exposure and for chronic durations, except where noted. Source: U.S. EPA f2011cl
Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass
basis, to which an individual in a (sub) population may be exposed daily over its lifetime without
appreciable health risk. Source: WHO (2015).
Qualitative cancer classifications: A system used for the hazard identification of potential
carcinogens, in which human data, animal data, and other supporting evidence are combined to
characterize the weight of evidence (WOE) regarding the potential of an agent to cause cancer in
humans.
•	EPA 1986 guidelines: Under the EPA's 1986 risk assessment guidelines, the WOE was
described by categories "A through E," with Group A for known human carcinogens
through Group E for agents with evidence of noncarcinogenicity. Five standard WOE
descriptors were used:
o A: Human carcinogen.
o Bl: Probable human carcinogen—based on limited evidence of carcinogenicity in
humans and sufficient evidence of carcinogenicity in animals.
o B2: Probable human carcinogen—based on sufficient evidence of carcinogenicity in
animals.
o C: Possible human carcinogen.
o D: Not classifiable as to human carcinogenicity.
o E: Evidence of noncarcinogenicity for humans.
Source: U.S. EPA f2011c1.
•	EPA 1996 proposed guidelines: The EPA's 1996 proposed guidelines outlined a major
change in the way hazard evidence was weighted in reaching conclusions about the human
carcinogenic potential of agents. These guidelines replaced the WOE letter categories with
the use of standard descriptors of conclusions incorporated into a brief narrative. Three
categories of descriptors with the narrative were used:
o Known/likely.
o Cannot be determined.
o Not likely.
Source: U.S. EPA (19961.
•	EPA 1999 guidelines: The 1999 guidelines adopted a framework incorporating hazard
identification, dose-response assessment, exposure assessment, and risk characterization
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with an emphasis on characterization of evidence and conclusions in each part of the
assessment Five descriptors summarizing the WOE in the narrative were used:
o Carcinogenic to humans.
o Likely to be carcinogenic to humans.
o Suggestive evidence of carcinogenicity, but not sufficient to assess human
carcinogenic potential.
o Data are inadequate for an assessment of human carcinogenic potential.
o Not likely to be carcinogenic to humans.
Source: U.S. EPA C1999a1.
•	EPA 2005 guidelines: The approach outlined in the EPA's 2005 guidelines for carcinogen
risk assessment considers all scientific information in determining whether and under
what conditions an agent may cause cancer in humans and provides a narrative approach
to characterize carcinogenicity rather than categories. Five standard WOE descriptors are
used as part of the narrative:
o Carcinogenic to humans.
o Likely to be carcinogenic to humans.
o Suggestive evidence of carcinogenic potential.
o Inadequate information to assess carcinogenic potential.
o Not likely to be carcinogenic to humans.
Source: U.S. EPA C2011cl
•	IARC Monographs on the evaluation of carcinogenic risks to humans: The IARC
classifies carcinogen risk as a matter of scientific judgement that reflects the strength of
the evidence derived from studies in humans, in experimental animals, from mechanistic
data, and from other relevant data. Five WOE classifications are used:
o Group 1: Carcinogenic to humans.
o Group 2A: Probably carcinogenic to humans.
o Group 2B: Possibly carcinogenic to humans.
o Group 3: Not classifiable as to its carcinogenicity to humans.
o Group 4: Probably not carcinogenic to humans.
Source: IARC C20151
•	NTP: The NTP describes the results of individual experiments on a chemical agent and
notes the strength of the evidence for conclusions regarding each study. Negative results,
in which the study animals do not have a greater incidence of neoplasia than control
animals, do not necessarily mean that a chemical is not a carcinogen, inasmuch as the
experiments are conducted under a limited set of conditions. Positive results demonstrate
that a chemical is carcinogenic for laboratory animals under the conditions of the study
and indicate that exposure to the chemical has the potential for hazard to humans. For
G-9
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
each separate experiment, one of the following five categories is selected to describe the
findings. These categories refer to the strength of the experimental evidence and not to
potency or mechanism.
o Clear evidence of carcinogenic activity.
o Some evidence of carcinogenic activity.
o Equivocal evidence of carcinogenic activity.
o No evidence of carcinogenic activity.
o Inadequate study of carcinogenic activity.
Source: NTP C2014al.
• The RoC is a congressionally mandated, science-based, public health report that identifies
agents, substances, mixtures, or exposures (collectively called "substances") in our
environment that may potentially put people in the United States at increased risk for
cancer. NTP prepares the RoC on behalf of the Secretary of the Health and Human Services.
The listing criteria in the RoC Document are:
o Known to be a human carcinogen.
o Reasonably anticipated to be a human carcinogen.
Source: NTP C2014bl.
G.4. Additional Tools for Hazard Evaluation
In addition to the methods and approaches utilized in this chapter, there are other potential tools
that could be used by stakeholders to prioritize and estimate toxicity of chemicals that have a
limited toxicity database. We describe three such approaches here. This list is not intended to be
exhaustive, but provides examples of tools that stakeholders may find useful when faced with many
data-poor chemicals at a field site. Toxicity predictions from these additional data sources can be
either quantitative or qualitative, and may be used to fill and address gaps related to risk
assessment.
G.4.1. Threshold of ToxicologicaI Concern (TTC)
The TTC approach is a risk assessment tool based on the concept that there is an exposure
threshold value for all chemicals below which there is a very low probability of risk to human
health fKroes etal.. 2005: Kroes etal.. 20041. The TTC approach proposes that such a de minimis
value can be identified for many chemicals based on knowledge of chemical structure fLapenna and
Worth. 2011: Kroes etal.. 2005: Kroes etal.. 20041. The estimated TTC is integrated with an
estimate of human exposure to that chemical, and used by the model to determine if there is
potential for concern or if more detailed chemical specific data are necessary fKroes etal.. 2005:
Kroes etal.. 20041. As a preliminary step in risk assessment, this approach can be applied as a
screening tool, for ranking and prioritization, and as an indicator of data needs fLapenna and
Worth. 2011: Kroes etal.. 2005: Kroes etal.. 20041.
G-10
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
The various TTC approaches are based on a decision tree proposed by Cramer etal. f!9781. which
classifies chemicals into categories of high (Class III), medium (Class II), or low (Class I) level of
concern, based on structure and reactivity. Based on the analysis of chronic oral toxicity data within
each of these structural classes, Munro etal. f!9961 proposed oral intake TTC values of 1.5, 9.0, and
30 |J.g/kg body weight/day for Class III, II, and I, respectively. A tiered decision tree proposed by
Kroes et al. (Kroes etal.. 2005: Kroes etal.. 2004) expanded these approaches by including
structural alerts for possible genotoxic and/or high potency carcinogens as well as a TTC value for
organophosphates. Recently, in order to help facilitate the consistent and transparent application of
the TTC approach, a freely available software tool - Toxtree (http://toxtree.sourceforge.net/) - was
developed by the European Commission Joint Research Centre (JRC) for predicting toxicological
effects and mechanism of action fLapenna and Worth. 20111. Toxtree implements the approaches
relevant to TTC assessment, including the original Cramer decision tree and the expanded TTC
decision tree by fKroes etal.. 20041. and includes improvements to the original Cramer scheme to
overcome to potential for chemical misclassification.
G.4.2. Organisation for Economic Co-operation and Development (OECD) Quantitative
Structure-Activity Relationship (QSAR) Toolbox
The OECD QSAR Toolbox is another available QSAR-based software tool developed to fill in toxicity
data gaps for assessing the hazards of chemicals fOECD. 20161. and serves as a platform that
incorporates various modules, databases, and structure-activity relationship models from a wide
range of sources. This approach also implements read-across concepts by grouping chemicals into
categories based on profiles related to physicochemical properties, human health, ecotoxicity, and
environmental fate. The main features of the OECD QSAR Toolbox are: identification of relevant
structural characteristics and potential mechanism or mode of action of a target chemical;
identification of other chemicals that have the same structural characteristics and/or mechanism or
mode of action; and use of existing experimental data to fill the data gap(s). The Toolbox's key
strengths are for screening environmental fate endpoints, physicochemical properties, acute
ecotoxicity endpoints and toxicity endpoints such as skin/eye irritation, sensitization and
mutagenicity.
G.4.3. Application of Data from High Throughput Screening Assays
In addition to the tools outlined above, there have been recent advances in emerging technologies
such as high throughput screening (HTS) assays that may aid in prioritizing chemical inventories
for potential hazard (Wambaugh etal.. 2013). HTS assays are in vitro assays that allow rapid
screening of chemicals for potential toxicity and biological activity across multiple cellular
pathways and targets fWetmore etal.. 2012: Rotroffetal.. 20101. Recent advances have been made
in dosimetry methods that extrapolate in vitro concentration data to a human oral equivalent dose,
providing a quantitative estimate of the dose of a chemical that would result in an adverse effect
fWetmore etal.. 2015: Wetmore et al.. 2012: Tudson etal.. 2011: Rotroffetal.. 20101. HTS data may
also be combined with emerging methods to estimate exposure potential, providing a method to
refine risk-based prioritization for chemicals with limited toxicity information fWambaugh et al..
20131. Consequently, the integration of data from emerging technologies with estimates of human
oral dose and exposure may provide another potential approach to address risk management needs
when in vivo toxicology data are not available.
G-ll
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-la. Chemicals reported to be used in hydraulic fracturing fluids, with available chronic oral RfVs, OSFs, and qualitative
cancer classifications from United States federal sources.
Chemicals from the FracFocus database are listed first, ranked by IRIS reference dose (RfD). The symbol indicates that no value was available from the
sources consulted. Additionally, an "x" indicates the availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties data from EPI
Suite™ (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water.
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goal®
(MCLG)
(mg/L)
MCLf
(mg/L)
Acrylamide
79-06-1
X
X
0.002
0.5
"Likely to be
carcinogenic
to humans"
-
-
-
0.001
-
0
TTg
Propargyl alcohol
107-19-7
X
X
0.002
-
-
-
-
-
-
-
-
-
Furfural
98-01-1
X
X
0.003
-
-
-
-
-
-
0.01
-
-
Benzene
71-43-2
X
X
0.004
0.015-
0.055
A (Human
carcinogen)
-
-
-
0.0005
-
0
0.005
Dichloromethane
75-09-2
X
X
0.006
0.002
"Likely to be
carcinogenic
in humans"
-
-
-
0.06
-
0
0.005
1,2,3-Trimethyl-
benzene
526-73-8
X
X
0.01
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
1,2,4-Tri methyl-
benzene
95-63-6
X
X
0.01
-
-
-
-
-
-
-
-
-
G-12
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
1,3,5-Trimethyl-
benzene
108-67-8
X
X
0.01
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
Trimethylbenzene
25551-13-7
X

0.01
-
-
-
-
-
-
-
-
-
Chlorobenzene
108-90-7
X
X
0.02
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
0.1
0.1
Naphthalene
91-20-3
X
X
0.02
-
"Data are
inadequate
to assess
human
carcinogenic
potential"
-
-
-
-
-
-
-
1,3-Dichloropro-
pene
542-75-6
X
X
0.03
0.05
"Likely to be
a human
carcinogen"
-
-
-
0.03
-
-
-
1,4-Dioxane
123-91-1
X
X
0.03
0.1
"Likely to be
carcinogenic
to humans"
-
-
-
0.1
-
-
-
G-13
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg /
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Chlorine dioxide
10049-04-4
X

0.03
-
"Data are
inadequate
to assess
human
carcino-
genicity"
-
-
-
-
-
-
-
Sodium chlorite
7758-19-2
X

0.03
-
"Data are
inadequate
to assess
human
carcino-
genicity"
-
-
-
-
-
1
0.8
Bisphenol A
80-05-7
X
X
0.05
-
-
-
-
-
-
-
-
-
Bisphenol A
80-05-7
X
X
0.05
-
-
-
-
-
-
-
-
-
Toluene
108-88-3
X
X
0.08
-
"Inadequate
information
to assess the
carcinogenic
potential"
-
-
-
-
-
1
1
1-Butanol
71-36-3
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
2-Butoxyethanol
111-76-2
X
X
0.1
-
"Not likely to
be carcino-
genic to
humans"
-
-
-
-
-
-
-
G-14
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Acetophenone
98-86-2
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Cumene
98-82-8
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Ethylbenzene
100-41-4
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
0.7
0.7
Boron
7440-42-8
X

0.2
-
"Data are
inadequate
to assess the
carcinogenic
potential"
-
-
-
-
-
-
-
Formaldehyde
50-00-0
X
X
0.2
-
B1 (Probable
human
carcinogen)
-
-
-
0.2
-
-
-
Xylenes
1330-20-7
X
X
0.2
-
"Data are
inadequate
to assess the
carcinogenic
potential"
-
-
-
0.2
-
10
10
2-Methyl-l-
propanol
78-83-1
X
X
0.3
-
-
-
-
-
-
-
-
-
G-15
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Phenol
108-95-2
X
X
0.3
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
-
-
-
Acetone
67-64-1
X
X
0.9
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
-
-
-
Ethyl acetate
141-78-6
X
X
0.9
-
-
-
-
IN
-
-
-
-
Ethylene glycol
107-21-1
X
X
2
-
-
-
-
-
-
-
-
-
Methanol
67-56-1
X
X
2
-
-
-
-
-
-
-
-
-
Benzoic acid
65-85-0
X
X
4
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
(E)-Crotonaldehyde
123-73-9
X
X
-
-
C (Possible
human
carcinogen)
0.001
-
-
-
-
-
-
1,2-Propylene
glycol
57-55-6
X
X
-
-
-
20
-
NL
-
-
-
-
G-16
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
2-(2-Butoxyethoxy)
ethanol
112-34-5
X
X
-
-
-
0.03
-
IN
-
-
-
-
2-(Thiocyanomethy
lthio)benzothiazole
21564-17-0
X
X
-
-
-
-
-
-
-
0.01
-
-
Aluminum
7429-90-5
X

-
-
-
1
-
IN
1
-
-
-
Ammonium
phosphate
7722-76-1
X

-
-
-
49
-
IN
-
-
-
-
Aniline
62-53-3
X
X
-
0.0057
B2 (Probable
human
carcinogen)
0.007
-
-
-
-
-
-
Benzenesulfonic
acid, C10-16-alkyl
derivs.
68584-22-5
X

-
-
-
-
-
-
-
0.5
-
-
Benzyl chloride
100-44-7
X
X
-
0.17
B2 (Probable
human
carcinogen)
0.002
-
-
-
-
-
-
Bis(2-chloroethyl)
ether
111-44-4
X
X
-
1.1
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
Didecyldimethyl-
ammonium
chloride
7173-51-5
X
X
-
-
-
-
-
-
-
0.1
-
-
Dodecylbenzene-
sulfonic acid
27176-87-0
X
X
-
-
-
-
-
-
-
0.5
-
-
Epichlorohydrin
106-89-8
X
X
-
0.0099
B2 (Probable
human
carcinogen)
0.006
-
-
-
-
0
-
G-17
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Ethylenediamine
107-15-3
X
X
-
-
D (Not
classifiable as
to human
carcino-
genicity)
0.09
-
IN
-
-
-
-
Formic acid
64-18-6
X
X
-
-
-
0.9
-
IN
-
-
-
-
Hexanedioic acid
124-04-9
X
X
-
-
-
2
-
-
-
-
-
-
Hydrazine
302-01-2
X

-
3
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
Iron
7439-89-6
X

-
-
-
0.7
-
IN
-
-
-
-
Mineral oil -
includes paraffin oil
8012-95-1
X

-
-
-
3
-
IN
-
-
-
-
N, N-Dimethylfor-
m amide
68-12-2
X
X
-
-
-
0.1
-
IN
-
-
-
-
o-Xyiene
95-47-6
X
X
-
-
-
-
-
-
0.2
-
10
10
Phosphoric acid
7664-38-2
X

-
-
-
48.6
-
IN
-
-
-
-
Potassium
phosphate, tribasic
7778-53-2
X

-
-
-
49
-
IN
-
-
-
-
Quaternary
ammonium
compounds,
benzyl-C12-16-
alkyldimethyl,
chlorides
68424-85-1
X

-
-
-
-
-
-
-
0.44
-
-
G-18
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Quinoline
91-22-5
X
X
-
3
"Likely to be
carcinogenic
in humans"
-
-
-
-
-
-
-
Sodium chlorate
7775-09-9
X

-
-
-
-
-
-
-
0.03
-
-
Sodium
trimetaphosphate
7785-84-4
X

-
-
-
49
-
IN
-
-
-
-
Tetrasodium
pyrophosphate
7722-88-5
X

-
-
-
49
-
IN
-
-
-
-
Tricalcium
phosphate
7758-87-4
X

-
-
-
49
-
IN
-
-
-
-
Triphosphoric acid,
pentasodium salt
7758-29-4
X

-
-
-
49
-
IN
-
-
-
-
Trisodium
phosphate
7601-54-9
X

-
-
-
49
-
IN
-
-
-
-
Arsenic
7440-38-2


0.0003
1.5
A (Human
carcinogen)
-
-
-
0.0003
-
0
0.01
Phosphine
7803-51-2


0.0003
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Acrolein
107-02-8

X
0.0005
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
-
-
-
G-19
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Chromium (VI)
18540-29-9


0.003
-
Inhaled: A
(Human
carcinogen);
Oral: D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
0.0009
-
-
-
Di(2-ethylhexyl)
phthalate
117-81-7

X
0.02
0.014
B2 (Probable
human
carcinogen)
-
-
-
0.06
-
0
0.006
Chlorine
7782-50-5


0.1
-
-
-
-
-
-
-
-
-
Styrene
100-42-5

X
0.2
-
-
-
-
-
-
-
0.1
0.1
Zinc
7440-66-6


0.3
-
"Inadequate
information
to assess
carcinogenic
potential"
-
-
-
0.3
-
-
-
Acrylic acid
79-10-7

X
0.5
-
-
-
-
IN
-
-
-
-
Chromium (III)
16065-83-1


1.5
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
-
-
-
Phthalic anhydride
85-44-9

X
2
-
-
-
-
-
-
-
-
-
Cyclohexanone
108-94-1

X
5
-
-
-
-
IN
-
-
-
-
G-20
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Frac
Focus
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
RfDa
(mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer
WOE
character-
ization
Chronic
oral
MRLd
(mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
1,2-Propylene
oxide
75-56-9

X
-
0.24
B2 (Probable
human
carcinogen)
-
-
-
-
0.001
-
-
2-(2-Ethoxyethoxy)
ethanol
111-90-0

X
-
-
-
0.06
-
IN
-
-
-
-
2-Methoxyethanol
109-86-4

X
-
-
-
0.005
-
IN
-
-
-
-
Lead
7439-92-1


-
-
B2 (Probable
human
carcinogen)
-
-
-
-
-
0
TT;
Action
LevehO.
015h
Phosphoric acid,
aluminium sodium
salt
7785-88-8


-
-
-
49
-
IN
-
-
-
-
Phosphoric acid,
diammonium salt
7783-28-0


-
-
-
49
-
IN
-
-
-
-
Polyphosphoric
acids, sodium salts
68915-31-1


-
-
-
49
-
IN
-
-
-
-
p-Xylene
106-42-3

X
-
-
-
-
-
-
0.2
-
10
10
Sodium
pyrophosphate
7758-16-9


-
-
-
49
-
IN
-
-
-
-
Tributyl phosphate
126-73-8

X
-
-
-
0.01
0.009
LI
0.08
-
-
-
CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer Reviewed Toxicity Values; ATSDR = Agency for Toxic
Substances and Disease Registry; HHBP = Human Health Benchmarks for Pesticides; NPDWRs = National Primary Drinking Water Regulations.
a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population (including sensitive subgroups)
that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observed-
adverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally used in the EPA's
noncancer health assessments. Chronic RfD: Duration of exposure is up to a lifetime.
G-21
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime oral exposure to an agent. This estimate, usually
expressed in units of proportion (of a population) affected per mg/kg-day, is generally reserved for use in the low dose region of the dose response relationship, that is, for
exposures corresponding to risks less than 1 in 100.
c Weight of evidence (WOE) characterization for carcinogenicity: A system used for characterizing the extent to which the available data support the hypothesis that an agent
causes cancer in humans. See glossary for details.
d Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of
harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs
should not be used as predictors of harmful (adverse) health effects. Chronic MRL: Duration of exposure is 365 days or longer.
e Maximum contaminant level goal (MCLG): A non-enforceable health benchmark goal which is set at a level at which no known or anticipated adverse effect on the health of
persons is expected to occur and which allows an adequate margin of safety.
f Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in drinking water. MCLs are set as close to the MCLG as feasible using the best available
analytical and treatment technologies and taking cost into consideration. MCLs are enforceable standards.
g In public water systems, acrylamide is regulated by a Treatment Technique (TT). Public water systems must certify annually that when acrylamide is used to treat water, the
combination of dose and monomer level does not exceed 0.05% dosed at 1 mg/l (or equivalent).
h In public water systems, lead is regulated by a Treatment Technique (TT) that requires systems to control the corrosiveness of their water. If more than 10% of tap water
exceeds the action level of 0.015 mg/l, water systems must take additional steps.
G-22
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-lb. Chemicals reported to be used in hydraulic fracturing fluids, with available
chronic oral RfVs and OSFs from state sources.
Chemicals from the FracFocus database are listed first, ranked by CalEPA maximum allowable daily level (MADL).
The symbol indicates that no value was available from the sources consulted. Additionally, an "x" indicates the
availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties data from EPI Suite™
(see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water.
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
CalEPA
Oral MADLa
(Hg/day)
OSFb (per
mg/kg-day)
Ethylene oxide
75-21-8
X
X
20
0.31
Benzene
71-43-2
X
X
24
0.1
Acrylamide
79-06-1
X
X
140
4.5
N-Methyl-2-pyrrolidone
872-50-4
X
X
17000
-
1,3-Butadiene
106-99-0
X
X
-
0.6
1,3-Dichloropropene
542-75-6
X
X
-
0.091
1,4-Dioxane
123-91-1
X
X
-
0.027
Aniline
62-53-3
X
X
-
0.0057
Benzyl chloride
100-44-7
X
X
-
0.17
Bis(2-chloroethyl) ether
111-44-4
X
X
-
2.5
Dichloromethane
75-09-2
X
X
-
0.014
Epichlorohydrin
106-89-8
X
X
-
0.08
Ethylbenzene
100-41-4
X
X
-
0.011
Hydrazine
302-01-2
X

-
3
Nitrilotriacetic acid
139-13-9
X
X
-
0.0053
Nitrilotriacetic acid trisodium
monohydrate
18662-53-8
X
X
-
0.01
Thiourea
62-56-6
X
X
-
0.072
Lead
7439-92-1


0.5
0.0085
Chromium (VI)
18540-29-9


8.2
0.5
G-23
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
CalEPA
Oral MADLa
(Hg/day)
OSFb (per
mg/kg-day)
Di(2-ethylhexyl) phthalate
117-81-7

X
20 (neonate male);
58 (infant male);
410 (adult)
0.003
2-Methoxyethanol
109-86-4

X
63
-
2-Ethoxyethanol
110-80-5

X
750
-
1,2-Propylene oxide
75-56-9

X
-
0.24
Arsenic
7440-38-2


-
9.5
CASRN = Chemical Abstract Service Registry Number; CalEPA = California Environmental Protection Agency.
a Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive toxicant at which the chemical
would have no observable adverse reproductive effect, assuming exposure at 1,000 times that level.
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime
oral exposure to an agent. This estimate, usually expressed in units of proportion (of a population) affected per mg/kg day, is
generally reserved for use in the low-dose region of the dose-response relationship, that is, for exposures corresponding to
risks less than 1 in 100.
G-24
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-lc. Chemicals reported to be used in hydraulic fracturing fluids, with available
chronic oral RfVs and OSFs from international sources.
Chemicals from the FracFocus database are listed first, ranked by CICAD reference value (TDI- tolerable daily
intake). An "x" indicates the availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical
properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids
and produced water.
Chemical name
CASRN
FracFocus data
available
Physicochemical
data available
IPCS CICAD Chronic
TDIa (mg/kg-day)
Potassium iodide
7681-11-0
X

0.01
Sodium iodide
7681-82-5
X

0.01
Copper(l) iodide
7681-65-4
X

0.01
Ethylene glycol
107-21-1
X
X
0.05
D-Limonene
5989-27-5
X
X
0.1
Glyoxal
107-22-2
X
X
0.2
N-Methyl-2-pyrrolidone
872-50-4
X
X
0.6
Chromium (VI)
18540-29-9


0.0009
Strontium chloride
10476-85-4


0.13
CASRN = Chemical Abstract Service Registry Number; IPCS = International Programme on Chemical Safety; CICAD = Concise
International Chemical Assessment Documents.
a Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass basis, to which an individual in
a (sub) population may be exposed daily over its lifetime without appreciable health risk.
G-25
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-ld. Chemicals reported to be used in hydraulic fracturing fluids, with available less-
than-chronic oral RfVs and OSFs.
Chemicals from the FracFocus database are listed first, ranked by PPRTV subchronic reference dose (sRfD). The
symbol indicates that no value was available from the sources consulted. Additionally, an "x" indicates the
availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties data from EPI Suite™
(see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water.
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical
data
available
PPRTV
ATSDR
sRfDa
(mg/kg-day)
Acute oral
MRLb
(mg/kg-day)
Inter-mediate
oral MRLb
(mg/kg-day)
Benzyl chloride
100-44-7
X
X
0.002
-
-
Epichlorohydrin
106-89-8
X
X
0.006
-
-
(E)-Crotonaldehyde
123-73-9
X
X
0.01
-
-
Benzene
71-43-2
X
X
0.01
-
-
Ethylbenzene
100-41-4
X
X
0.05
-
0.4
Chlorobenzene
108-90-7
X
X
0.07
-
0.4
Ethylenediamine
107-15-3
X
X
0.2
-
-
2-(2-Butoxyethoxy)eth
anol
112-34-5
X
X
0.3
-
-
Hexane
110-54-3
X
X
0.3
-
-
N,N-Dimethylform-
amide
68-12-2
X
X
0.3
-
-
Xylenes
1330-20-7
X
X
0.4
1
0.4
Antimony trioxide
1309-64-4
X

0.5
-
-
Ethyl acetate
141-78-6
X
X
0.7
-
-
Iron
7439-89-6
X

0.7
-
-
Toluene
108-88-3
X
X
0.8
0.8
0.02
Formic acid
64-18-6
X
X
0.9
-
-
Hexanedioic acid
124-04-9
X
X
2
-
-
Benzoic acid
65-85-0
X
X
4
-
-
1,2-Propylene glycol
57-55-6
X
X
20
-
-
Mineral oil - includes
paraffin oil
8012-95-1
X

30
-
-
Phosphoric acid
7664-38-2
X

48.6
-
-
G-26
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical
data
available
PPRTV
ATSDR
sRfDa
(mg/kg-day)
Acute oral
MRLb
(mg/kg-day)
Inter-mediate
oral MRLb
(mg/kg-day)
Ammonium phosphate
7722-76-1
X

49
-
-
Potassium phosphate,
tribasic
7778-53-2
X

49
-
-
Sodium
trimetaphosphate
7785-84-4
X

49
-
-
Tetra sodium
pyrophosphate
7722-88-5
X

49
-
-
Tricalcium phosphate
7758-87-4
X

49
-
-
Triphosphoric acid,
pentasodium salt
7758-29-4
X

49
-
-
Trisodium phosphate
7601-54-9
X

49
-
-
1,3-Dichloropropene
542-75-6
X
X
-
-
0.04
1,4-Dioxane
123-91-1
X
X
-
5
0.5
2-Butoxyethanol
111-76-2
X
X
-
0.4
0.07
Acetone
67-64-1
X
X
-
-
2
Acrylamide
79-06-1
X
X
-
0.01
0.001
Aluminum
7429-90-5
X

-
-
1
Boron
7440-42-8
X

-
0.2
0.2
Dichloromethane
75-09-2
X
X
-
0.2
-
Ethylene glycol
107-21-1
X
X
-
0.8
0.8
Formaldehyde
50-00-0
X
X
-
-
0.3
Naphthalene
91-20-3
X
X
-
0.6
0.6
o-Xylene
95-47-6
X
X
-
1
0.4
Phenol
108-95-2
X
X
-
1
-
Sodium chlorite
7758-19-2
X

-
-
0.1
Antimony trichloride
10025-91-9


0.0004
-
-
2-Methoxyethanol
109-86-4

X
0.02
-
-
Tributyl phosphate
126-73-8

X
0.03
1.1
0.08
Acrylic acid
79-10-7

X
0.2
-
-
G-27
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical
data
available
PPRTV
ATSDR
sRfDa
(mg/kg-day)
Acute oral
MRLb
(mg/kg-day)
Inter-mediate
oral MRLb
(mg/kg-day)
2-(2-Ethoxyethoxy)
ethanol
111-90-0

x
0.6
-
-
Cyclohexanone
108-94-1

x
2
-
-
Phosphoric acid,
aluminium sodium salt
7785-88-8


49
-
-
Phosphoric acid,
diammonium salt
7783-28-0


49
-
-
Polyphosphoric acids,
sodium salts
68915-31-1


49
-
-
Sodium
pyrophosphate
7758-16-9


49
-
-
Acrolein
107-02-8

X
-
-
0.004
Arsenic
7440-38-2


-
0.005
-
Chromium (VI)
18540-29-9


-
-
0.005
Copper
7440-50-8


-
0.01
0.01
Di(2-ethylhexyl)
phthalate
117-81-7

X
-
-
0.1
p-Xylene
106-42-3

X
-
1
0.4
Styrene
100-42-5

X
-
0.1
-
Zinc
7440-66-6


-
-
0.3
CASRN = Chemical Abstract Service Registry Number; PPRTV = Provisional Peer Reviewed Toxicity Values; ATSDR = Agency for
Toxic Substances and Disease Registry; HHBP = Human Health Benchmarks for Pesticides.
a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the
human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a
lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observed-adverse-effect level (LOAEL), or
benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally
used in the EPA's noncancer health assessments. Subchronic RfD (sRFD): Duration of exposure is up to 10% of an average
lifespan.
b Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the
substance is unlikely to pose a measurable risk of harmful (adverse), noncancerous effects. MRLs are calculated for a route of
exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs should not be used as
predictors of harmful (adverse) health effects. Acute MRL: Duration of exposure is 1 to 14 days. Intermediate MRL: Duration of
exposure is >14 to 364 days.
G-28
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-le. Available qualitative cancer classifications for chemicals reported to be used in
hydraulic fracturing fluids.
Chemicals from the FracFocus database are listed first, with chemicals classified as known carcinogens by one or
more sources listed first. See the Appendix G glossary (Section G.3) for details on the weight of evidence
characterizations. The symbol indicates that no value was available from the sources consulted. Additionally,
an "x" indicates the availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties
data from EPI Suite™ (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and
produced water. Cancer classifications from IRIS and PPRTV are also listed in Table G-la.
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
1,3-Butadiene
106-99-0
X
X
"Carcinogenic
to humans"
-
1
Known
Arsenic
7440-38-2


A (Human
carcinogen)
-
1
Known
Benzene
71-43-2
X
X
A (Human
carcinogen)
-
1
Known
Chromium (VI)
18540-29-9


Inhaled: A
(Human
carcinogen);
Oral: D (Not
classifiable as
to human
carcino-
genicity)
-
1
Known
Ethan ol
64-17-5
X
X
-
-
1
-
Ethylene oxide
75-21-8
X
X
-
-
1
Known
Formaldehyde
50-00-0
X
X
B1 (Probable
human
carcinogen)
-
1
Known
Nickel sulfate
7786-81-4
X

-
-
1
-
Nickel(ll) sulfate
hexahydrate
10101-97-0


-
-
1
-
Quartz-alpha
(Si02)
14808-60-7
X

-
-
1
-
Sulfuric acid
7664-93-9
X

-
-
1
Known
(E)-
Crotonaldehyde
123-73-9
X
X
C (Possible
human
carcinogen)
-
-
-
G-29
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
1,2-Propylene
oxide
75-56-9

X
B2 (Probable
human
carcinogen)
-
2B
RAHC
1,3-
Dichloropropene
542-75-6
X
X
"Likely to be
a human
carcinogen"
-
2B
RAHC
1,4-Dioxane
123-91-1
X
X
"Likely to be
carcinogenic
to humans"
-
26
RAHC
4-Methyl-2-
pentanone
108-10-1
X
X
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
2B
-
Acetaldehyde
75-07-0
X
X
62 (Probable
human
carcinogen)
-
26
RAHC
Acrylamide
79-06-1
X
X
"Likely to be
carcinogenic
to humans"
-
2A
RAHC
Aniline
62-53-3
X
X
B2 (Probable
human
carcinogen)
-
3
-
Antimony
trioxide
1309-64-4
X

-
Inhaled:
"Suggestive
evidence of
carcinogenic
potential";
Oral: "Data are
inadequate for
an assessment
of human
carcinogenic
potential"
2B
-
Attapulgite
12174-11-7
X

-
-
2B or 3
-
Benzyl chloride
100-44-7
X
X
62 (Probable
human
carcinogen)
-
-
-
G-30
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Bis(2-chloroethyl)
ether
111-44-4
X
X
B2 (Probable
human
carcinogen)
-
3
-
Carbon black
1333-86-4


-
-
2B
-
Coconut oil
acid/Diethanola-
mine condensate
(2:1)
68603-42-9
X

-
-
2B
-
Cumene
98-82-8
X
X
D (Not
classifiable as
to human
carcino-
genicity)
-
2B
RAHC
Di(2-ethylhexyl)
phthalate
117-81-7

X
B2 (Probable
human
carcinogen)
-
2B
RAHC
Dibromoaceto-
nitrile
3252-43-5
X
X
-
-
2B
-
Dichloromethane
75-09-2
X
X
"Likely to be
carcinogenic
in humans"
-
2A
RAHC
Diethanolamine
111-42-2
X
X
-
-
2B
-
Epichlorohydrin
106-89-8
X
X
B2 (Probable
human
carcinogen)
-
2A
RAHC
Ethylbenzene
100-41-4
X
X
D (Not
classifiable as
to human
carcino-
genicity)
-
2B
-
Hydrazine
302-01-2
X

B2 (Probable
human
carcinogen)
-
2A
RAHC
Lead
7439-92-1


B2 (Probable
human
carcinogen)
-
2B
RAHC
G-31
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
N, N-Dimethylfor-
mamide
68-12-2
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
2A
-
Naphthalene
91-20-3
X
X
"Data are
inadequate to
assess human
carcinogenic
potential"
-
2B
RAHC
Nitrilotriacetic
acid
139-13-9
X
X
-
-
2B
RAHC
Quinoline
91-22-5
X
X
"Likely to be
carcinogenic
in humans"
-
-
-
Styrene
100-42-5

X
-
-
2B
RAHC
Thiourea
62-56-6
X
X
-
-
3
RAHC
Titanium dioxide
13463-67-7
X

-
-
2B

Tributyl
phosphate
126-73-8

X
-
"Likely to be
carcinogenic to
humans"
-
-
1,2,3-
Trimethylbenzene
526-73-8
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
1,3,5-
Trimethylbenzene
108-67-8
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
1-Butanol
71-36-3
X
X
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
G-32
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
l-Propene
115-07-1
X
X
-
-
3
-
l-tert-Butoxy-2-
propanol
57018-52-7
X
X
-
-
3
-
2-(2-Butoxyeth-
oxy)ethanol
112-34-5
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
2-(2-Ethoxyeth-
oxy) ethanol
111-90-0

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
2-Butoxyethanol
111-76-2
X
X
"Not likely to
be
carcinogenic
to humans"
-
3
-
2-
Methoxyethanol
109-86-4

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Acetone
67-64-1
X
X
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
Acetophenone
98-86-2
X
X
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
G-33
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Acrolein
107-02-8

X
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
3
-
Acrylic acid
79-10-7

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
3
-
Aluminum
7429-90-5
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Amaranth
915-67-3
X
X
-
-
3
-
Ammonium
phosphate
7722-76-1
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Benzoic acid
65-85-0
X
X
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
Boron
7440-42-8
X

"Data are
inadequate to
assess the
carcinogenic
potential"
-
-
-
Chlorine dioxide
10049-04-4
X

"Data are
inadequate
to assess
human
carcino-
genicity"
-
-
-
G-34
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Chlorobenzene
108-90-7
X
X
D (Not
classifiable as
to human
carcino-
genicity)



Chloromethane
74-87-3
X
X
"Carcinogenic
potential
cannot be
determined"
-
3
-
Chromium (III)
16065-83-1


"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
3
-
Coumarin
91-64-5

X
-
-
3
-
Cyclohexanone
108-94-1

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
3
-
Dapsone
80-08-0
X
X
-
-
3
-
D-Limonene
5989-27-5
X
X
-
-
3
-
Ethyl acetate
141-78-6
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Ethylene
74-85-1
X
X
-
-
3
-
Ethylenediamine
107-15-3
X
X
D (Not
classifiable as
to human
carcino-
genicity)
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
FD&C Blue no. 1
3844-45-9
X
X
-
-
3
-
G-35
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
FD&C Yellow 6
2783-94-0

X
-
-
3
-
Formic acid
64-18-6
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Furfural
98-01-1
X
X
-
-
3
-
Hematite
1317-60-8
X

-
-
3
-
Hexane
110-54-3
X
X
"Inadequate
information
to assess the
carcinogenic
potential"
-
-
-
Hydrochloric acid
7647-01-0
X

-
-
3
-
Hydrogen
peroxide
7722-84-1
X

-
-
3
-
Iron
7439-89-6
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Iron(lll) oxide
1309-37-1
X

-
-
3
-
Isopropanol
67-63-0
X
X
-
-
3
-
Latex 2000 TM
9003-55-8


-
-
3
-
Ligroine
8032-32-4


-
-
3
-
Mineral oil -
includes paraffin
oil
8012-95-1
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Mineral spirits
64475-85-0


-
-
3
-
Morpholine
110-91-8
X
X
-
-
3
-
G-36
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Pentane
109-66-0
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Petroleum
8002-05-9
X

-
-
3
-
Phenanthrene
85-01-8

X
-
-
3
-
Phenol
108-95-2
X
X
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
3
-
Phosphine
7803-51-2


D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
Phosphoric acid
7664-38-2
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Phosphoric acid,
aluminium
sodium salt
7785-88-8


-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Phosphoric acid,
diammonium salt
7783-28-0


-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Policapram
(Nylon 6)
25038-54-4
X

-
-
3
-
G-37
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Poly(tetrafluoro-
ethylene)
9002-84-0
X

-
-
3
-
Polyphosphoric
acids, sodium
salts
68915-31-1


-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Polyvinyl acetate
copolymer
9003-20-7


-
-
3
-
Polyvinyl alcohol
9002-89-5


-
-
3
-
Polyvinylpyrroli-
done
9003-39-8
X

-
-
3
-
Potassium
phosphate,
tribasic
7778-53-2
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Rhodamine B
81-88-9

X
-
-
3
-
Silica
7631-86-9
X

-
-
3
-
Sodium bisulfite
7631-90-5
X

-
-
3
-
Sodium chlorite
7758-19-2
X

"Data are
inadequate
to assess
human
carcino-
genicity"
-
3
-
Sodium
metabisulfite
7681-57-4
X

-
-
3
-
Sodium
pyrophosphate
7758-16-9


-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Sodium sulfite
7757-83-7
X

-
-
3
-
G-38
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Sodium
trimetaphos-
phate
7785-84-4
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Stoddard solvent
8052-41-3
X

-
-
3
-
Sulfan blue
129-17-9
X
X
-
-
3
-
Sulfur dioxide
7446-09-5
X

-
-
3
-
Talc
14807-96-6
X

-
-
3
-
Tetra sodium
pyrophosphate
7722-88-5
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Toluene
108-88-3
X
X
"Inadequate
information
to assess the
carcinogenic
potential"
-
3
-
Tricalcium
phosphate
7758-87-4
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Triethanolamine
102-71-6
X
X
-
-
3
-
Triphosphoric
acid, penta-
sodium salt
7758-29-4
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Trisodium
phosphate
7601-54-9
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
G-39
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
FracFocus
data
available
Physico-
chemical data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARC0
RoCd
Xylenes
1330-20-7
X
X
"Data are
inadequate to
assess the
carcinogenic
potential"
-
3
-
Zeolites
1318-02-1


-
-
3
-
Zinc
7440-66-6


"Inadequate
information
to assess
carcinogenic
potential"
-
-
-
1,2-Propylene
glycol
57-55-6
X
X
-
"Not likely to
be carcinogenic
to humans"
-
-
CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer
Reviewed Toxicity Values; IARC = International Agency for Research on Cancer Monographs; RoC = National Toxicology Program
13th Report on Carcinogens.
a IRIS assessments use the EPA's 1986,1996,1999, or 2005 guidelines to establish descriptors for summarizing the weight of
evidence as to whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details.
b PPRTV assessments use the EPA's 1999 guidelines to establish descriptors for summarizing the weight of evidence as to
whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details.
cThe IARC summarizes the weight of evidence as to whether a contaminant is or may be carcinogenic using five weight of
evidence classifications: Group 1: Carcinogenic to humans; Group 2A: Probably carcinogenic to humans; Group 2B: Possibly
carcinogenic to humans; Group 3: Not classifiable as to its carcinogenicity to humans; Group 4: Probably not carcinogenic to
humans. See glossary in Appendix G for details.
d The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated
to be a human carcinogen.
G-40
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-2a. Chemicals reported to be detected in produced water, with available chronic oral RfVs, OSFs, and qualitative cancer
classifications from United States federal sources.
Chemicals are ranked by IRIS reference dose (RfD). The symbol indicates that no value was available from the sources consulted. Additionally, an "x"
indicates the availability of measured concentration data in produced water (see Appendix E) and physicochemical properties data from EPI Suite™ (see
Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water.
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goal8
(MCLG)
(mg/L)
MCLf
(mg/L)
Heptachlor
epoxide
1024-57-3

X
0.000013
9.1
B2 (Probable
human
carcinogen)
-
-
-
-
-
0
0.0002
Phosphorus
7723-14-0
x

0.00002
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Aldrin
309-00-2

X
0.00003
17
B2 (Probable
human
carcinogen)
-
-
-
0.00003
-
-
-
Dieldrin
60-57-1

X
0.00005
16
B2 (Probable
human
carcinogen)
-
-
-
0.00005
-
-
-
Arsenic
7440-38-2
X

0.0003
1.5
A (Human
carcinogen)
-
-
-
0.0003
-
0
0.01
Lindane
58-89-9

X
0.0003
-
-
-
-
-
-
-
0.0002
0.0002
G-41
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Antimony
7440-36-0
X

0.0004
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
0.006
0.006
Acrolein
107-02-8

X
0.0005
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
-
-
-
Heptachlor
76-44-8

X
0.0005
4.5
B2 (Probable
human
carcinogen)
-
-
-
-
-
0
0.0004
Cyanide
57-12-5

X
0.0006
-
"Inadequate
information
to assess the
carcinogenic
potential"
-
-
-
-
-
0.2
0.2
Pyridine
110-86-1
X
X
0.001
-
-
-
-
-
-
-
-
-
Methyl bromide
74-83-9

X
0.0014
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
0.02
-
-
G-42
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Beryllium
7440-41-7
X

0.002
-
B1 (Probable
human
carcinogen)
-
-
-
0.002
-
0.004
0.004
Propargyl
alcohol
107-19-7

X
0.002
-
-
-
-
-
-
-
-
-
2,4-
Dichlorophenol
120-83-2
X
X
0.003
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
Benzidine
92-87-5
X
X
0.003
230
A (Human
carcinogen)
-
-
-
-
-
-
-
Chromium (VI)
18540-29-9
X

0.003
-
Inhaled: A
(Human
carcinogen;
Oral: D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
0.0009
-
-
-
2-Methylnaphth
alene
91-57-6
X
X
0.004
-
"Data are
inadequate
to assess
human
carcinogenic
potential"
-
-
-
0.04
-
-
-
Benzene
71-43-2
X
X
0.004
0.015-
0.055
A (Human
carcinogen)
-
-
-
0.0005
-
0
0.005
G-43
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Molybdenum
7439-98-7
X

0.005
-
-
-
-
-
-
-
-
-
Selenium
7782-49-2
X

0.005
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
0.005
-
0.05
0.05
Silver
7440-22-4
X

0.005
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Dichlorometh-
ane
75-09-2

X
0.006
0.002
"Likely to be
carcinogenic
in humans"
-
-
-
0.06
-
0
0.005
Tetrachloro-
ethene
127-18-4

X
0.006
0.0021
"Likely to be
carcinogenic
in humans"
-
-
-
0.008
-
0
0.005
1,2,3-Trimethyl-
benzene
526-73-8

X
0.01
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
1,2,4-Trichloro-
benzene
120-82-1

X
0.01
-
D (Not
classifiable as
to human
carcino-
genicity)
-
0.029
"Likely to be
carcinogenic
to humans"
0.1
-
0.07
0.07
G-44
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
1,2,4-Tri methyl-
benzene
95-63-6
X
X
0.01
-
-
-
-
-
-
-
-
-
1,3,5-Trimethyl-
benzene
108-67-8
X
X
0.01
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
Chloroform
67-66-3
X
X
0.01
-
B2 (Probable
human
carcinogen)
-
-
-
0.01
-
-
-
Trimethylben-
zene
25551-13-7


0.01
-
-
-
-
-
-
-
-
-
2,4-
Dimethylphenol
105-67-9
X
X
0.02
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
Bromodichloro-
methane
75-27-4

X
0.02
0.062
B2 (Probable
human
carcinogen)
-
-
-
0.02
-
-
-
Bromoform
75-25-2

X
0.02
0.0079
B2 (Probable
human
carcinogen)
-
-
-
0.02
-
-
-
G-45
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Chlorobenzene
108-90-7

X
0.02
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
0.1
0.1
Chlorodibromo-
methane
124-48-1

X
0.02
0.084
C (Possible
human
carcinogen)
-
-
-
0.09
-
-
-
Di(2-ethylhexyl)
phthalate
117-81-7
X
X
0.02
0.014
B2 (Probable
human
carcinogen)
-
-
-
0.06
-
0
0.006
Naphthalene
91-20-3
X
X
0.02
-
"Data are
inadequate
to assess
human
carcinogenic
potential"
-
-
-
-
-
-
-
Diphenylamine
122-39-4
X
X
0.025
-
-
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
0.1
-
-
1,4-Dioxane
123-91-1
X
X
0.03
0.1
"Likely to be
carcinogenic
to humans"
-
-
-
0.1
-
-
-
G-46
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Pyrene
129-00-0
X
X
0.03
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Fluoranthene
206-44-0
X
X
0.04
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
Fluorene
86-73-7
X
X
0.04
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Bisphenol A
80-05-7

X
0.05
-
-
-
-
-
-
-
-
-
m-Cresol
108-39-4
X
X
0.05
-
C (Possible
human
carcinogen)
-
-
-
-
-
-
-
o-Cresol
95-48-7
X
X
0.05
-
C (Possible
human
carcinogen)
-
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
G-47
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Toluene
108-88-3
X
X
0.08
-
"Inadequate
information
to assess the
carcinogenic
potential"
-
-
-
-
-
1
1
1-Butanol
71-36-3

X
0.1
-
D (Not
classifiable as
to human
carcinogenicit
y)
-
-
-
-
-
-
-
2-
Butoxyethanol
111-76-2

X
0.1
-
"Not likely to
be carcino-
genic to
humans"
-
-
-
-
-
-
-
Acetophenone
98-86-2
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Carbon disulfide
75-15-0
X
X
0.1
-
-
-
-
-
-
-
-
-
Chlorine
7782-50-5


0.1
-
-
-
-
-
-
-
-
-
Cumene
98-82-8
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
G-48
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Dibutyl
phthalate
84-74-2
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Ethylbenzene
100-41-4
X
X
0.1
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
0.7
0.7
Nitrite
14797-65-0
X

0.1
-
-
-
-
-
-
-
1
1
Manganese
7439-96-5
X

0.14
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Barium
7440-39-3
X

0.2
-
"Not likely to
be carcino-
genic to
humans"
-
-
-
0.2
-
2
2
Benzyl butyl
phthalate
85-68-7
X
X
0.2
-
C (Possible
human
carcinogen)
-
-
-
-
-
-
-
Boron
7440-42-8
X

0.2
-
"Data are
inadequate
to assess the
carcinogenic
potential"
-
-
-
-
-
-
-
G-49
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Xylenes
1330-20-7
X
X
0.2
-
"Data are
inadequate
to assess the
carcinogenic
potential"
-
-
-
0.2
-
10
10
Phenol
108-95-2
X
X
0.3
-
"Data are
inadequate
to assess
human
carcino-
genicity"
-
-
-
-
-
-
-
Zinc
7440-66-6
X

0.3
-
"Inadequate
information
to assess
carcinogenic
potential"
-
-
-
0.3
-
-
-
Biphenyl
92-52-4
X
X
0.5
0.008
"Suggestive
evidence of
carcinogenic
potential"
-
-
-
-
-
-
-
Caprolactam
105-60-2
X
X
0.5
-
-
-
-
-
-
-
-
-
Methyl ethyl
ketone
78-93-3

X
0.6
-
"Data are
inadequate
to assess
carcinogenic
potential"
-
-
-
-
-
-
-
Strontium
7440-24-6
X

0.6
-
-
-
-
-
-
-
-
-
G-50
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Diethyl
phthalate
84-66-2

X
0.8
-
D (Not
classifiable as
to human
carcino-
genicity)
-
-
-
-
-
-
-
Acetone
67-64-1
X
X
0.9
-
"Data are
inadequate
to assess
human
carcino-
genicity"
-
-
-
-
-
-
-
Chromium (III)
16065-83-1
X

1.5
-
"Data are
inadequate
to assess
human
carcino-
genicity"
-
-
-
-
-
-
-
Nitrate
14797-55-8
X

1.6
-
-
-
-
-
-
-
10
10
Ethylene glycol
107-21-1

X
2
-
-
-
-
-
-
-
-
-
Methanol
67-56-1

X
2
-
-
-
-
-
-
-
-
-
Cadmium
7440-43-9
X

0.0005
(water)
-
B1 (Probable
human
carcinogen)
-
-
-
0.0001
-
0.005
0.005
1,1-Dichloro-
ethane
75-34-3

X
-
-
C (Possible
human
carcinogen)
0.2
-
-
-
-
-
-
1,2-Diphenyl-
hydrazine
122-66-7
X
X
-
0.8
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
G-51
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
1,2-Propylene
glycol
57-55-6

X
-
-
-
20
-
"Not likely
to be
carcinogenic
to humans"
-
-
-
-
1-Methylnaph-
thalene
90-12-0

X
-
-
-
0.007
0.029
-
0.07
-
-
-
2-(2-Butoxy-
ethoxy)ethanol
112-34-5

X
-
-
-
0.03
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
2-Chloroethanol
107-07-3

X
-
-
-
0.02
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
0.045
-
-
Acrylonitrile
107-13-1

X
-
0.54
B1 (Probable
human
carcinogen)
-
-
-
0.04
-
-
-
Alpha particle
12587-46-1
X

-
-
-
-
-
-
-
-
-
15
Aluminum
7429-90-5
X

-
-
-
1
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
1
-
-
-
G-52
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Benz(a)anthra-
cene
56-55-3
X
X
-
-
B2 (Probable
human
carcinogen)
-
0.7
-
-
-
-
-
Benzo(a)pyrene
50-32-8
X
X
-
7.3
B2 (Probable
human
carcinogen)
-
-
-
-
-
0
0.0002
Benzyl alcohol
100-51-6
X
X
-
-
-
0.1
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
Benzyl chloride
100-44-7

X
-
0.17
B2 (Probable
human
carcinogen)
0.002
-
-
-
-
-
-
Beta particle
12587-47-2
X

-
-
-
-
-
-
-
-
-
4
beta-
Hexachloro
cyclohexane
319-85-7

X
-
1.8
C (Possible
human
carcinogen)
-
-
-
-
-
-
-
Bis(2-chloro-
ethylj ether
111-44-4

X
-
1.1
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
Butylbenzene
104-51-8

X
-
-
-
0.05
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
G-53
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Cobalt
7440-48-4
X

-
-
-
0.0003
-
"Likely to be
carcinogenic
to humans"
-
-
-
-
Copper
7440-50-8
X

-
-
-
-
-
-
-
-
1.3
FT;
Action
Level=1.3
g
Dibenzothio-
phene
132-65-0

X
-
-
-
0.01
-
-
-
-
-
-
Fluoride
16984-48-8
X

-
-
-
-
-
-
-
-
4
4
Formic acid
64-18-6

X
-
-
-
0.9
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
Hydrazine
302-01-2


-
3
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
Iron
7439-89-6
X

-
-
-
0.7
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
G-54
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Lead
7439-92-1
X

-
-
B2 (Probable
human
carcinogen)
-
-
-
-
-
0
TT;
Action
LevehO.O
15 9
Lithium
7439-93-2
X

-
-
-
0.002
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
m,p-Cresol
mixture
NOCAS_
24858


-
-
-
-
-
-
0.1
-
-
-
m-Xylene
108-38-3

X
-
-
-
-
-
-
0.2
-
10
10
N,N-Dimethyl-
formamide
68-12-2

X
-
-
-
0.1
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
N-Nitrosodi-
phenylamine
86-30-6
X
X
-
0.0049
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
N-Nitroso-N-
methylethyl-
amine
10595-95-6
X
X
-
22
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
G-55
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Nonane
111-84-2

X
-
-
-
0.0003
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
o-Xylene
95-47-6

X
-
-
-
-
-
-
0.2
-
10
10
p,p'-DDE
72-55-9

X
-
0.34
B2 (Probable
human
carcinogen)
-
-
-
-
-
-
-
Phorate
298-02-2

X
-
-
-
-
-
-
-
0.0005
-
-
p-Xylene
106-42-3

X
-
-
-
-
-
-
0.2
-
10
10
Quinoline
91-22-5

X
-
3
"Likely to be
carcinogenic
in humans"
-
-
-
-
-
-
-
Radium
7440-14-4
X

-
-
-
-
-
-
-
-
-
5 pCi/L
Radium-226
13982-63-3
X

-
-
-
-
-
-
-
-
-
5 pCi/L
Radium-228
15262-20-1
X

-
-
-
-
-
-
-
-
-
5 pCi/L
Thallium
7440-28-0
X

-
-
-
-
-
-
-
-
0.0005
0.002
Tributyl
phosphate
126-73-8
X
X
-
-
-
0.01
0.009
"Likely to be
carcinogenic
to humans"
0.08
-
-
-
Uranium-235
15117-96-1
X

-
-
-
-
-
-
-
-
-
30
Uranium-238
7440-61-1
X

-
-
-
-
-
-
-
-
-
30
G-56
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
IRIS
PPRTV
ATSDR
HHBP
NPDWRs
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic
RfDa (mg/
kg-day)
OSFb
(per mg/
kg-day)
Cancer WOE
character-
ization
Chronic oral
MRLd (mg/
kg-day)
Chronic
RfDa
(mg/kg-
day)
Public
health
goale
(MCLG)
(mg/L)
MCLf
(mg/L)
Vanadium
7440-62-2
X

-
-
"Data are
inadequate
to assess
carcinogenic
potential"
0.00007
-
"Data are
inadequate
for an
assessment
of human
carcinogenic
potential"
-
-
-
-
CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer Reviewed Toxicity Values; ATSDR = Agency for Toxic
Substances and Disease Registry; HHBP = Human Health Benchmarks for Pesticides; NPDWRs = National Primary Drinking Water Regulations.
a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population (including sensitive subgroups)
that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observed-
adverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally used in the EPA's
noncancer health assessments. Chronic RfD: Duration of exposure is up to a lifetime.
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime oral exposure to an agent. This estimate, usually
expressed in units of proportion (of a population) affected per mg/kg day, is generally reserved for use in the low dose region of the dose response relationship, that is, for
exposures corresponding to risks less than 1 in 100.
c Weight of evidence (WOE) characterization for carcinogenicity: A system used for characterizing the extent to which the available data support the hypothesis that an agent
causes cancer in humans. See glossary for details.
d Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of
harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs
should not be used as predictors of harmful (adverse) health effects. Chronic MRL: Duration of exposure is 365 days or longer.
e Maximum contaminant level goal (MCLG): A non-enforceable health benchmark goal which is set at a level at which no known or anticipated adverse effect on the health of
persons is expected to occur and which allows an adequate margin of safety.
f Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in drinking water. MCLs are set as close to the MCLG as feasible using the best available
analytical and treatment technologies and taking cost into consideration. MCLs are enforceable standards.
g In public water systems, lead and copper are regulated by a Treatment Technique (TT) that requires systems to control the corrosiveness of their water. If more than 10% of
tap water exceeds the action level, water systems must take additional steps. For copper, the action level is 1.3 mg/l, and for lead is 0.015 mg/l.
G-57
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-2b. Chemicals reported to be detected in produced water, with available chronic oral
RfVs and OSFs from state sources.
Chemicals are ranked by CalEPA maximum allowable daily level (MADL). The symbol indicates that no value
was available from the sources consulted. Additionally, an "x" indicates the availability of measured concentration
data in produced water (see Appendix E) and physicochemical properties data from EPI Suite™ (see Appendix C).
Italicized chemicals are found in both hydraulic fracturing fluids and produced water.
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
CalEPA
Oral MADLa
(Hg/day)
OSFb(per
mg/kg-day)
Lead
7439-92-1
X

0.5
0.0085
Cadmium
7440-43-9
X

4.1
15
Chromium (VI)
18540-29-9
X

8.2
0.5
Dibutyl phthalate
84-74-2
X
X
8.7
-
Benzene
71-43-2
X
X
24
0.1
Benzyl butyl phthalate
85-68-7
X
X
1200
-
1,2-Benzenedicarboxylic acid,
l,2-bis(8-methylnonyl) ester
89-16-7

X
2200
-
Diisodecyl phthalate
26761-40-0

X
2,200
-
Di(2-ethylhexyl) phthalate
117-81-7
X
X
20 (neonate
male); 58 (infant
male); 410 (adult)
0.003
1,2,4-Trichlorobenzene
120-82-1

X
-
0.0036
1,4-Dioxane
123-91-1
X
X
-
0.027
7,12-Dimethylbenz(a)anthracene
57-97-6

X
-
250
Acrylonitrile
107-13-1

X
-
1
Aldrin
309-00-2

X
-
17
Arsenic
7440-38-2
X

-
9.5
Benz(a)anthracene
56-55-3
X
X
-
1.2
Benzidine
92-87-5
X
X
-
500
Benzo(a)pyrene
50-32-8
X
X
-
2.9
Benzo(b)fluoranthene
205-99-2
X
X
-
1.2
Benzo(k)fluoranthene
207-08-9
X
X
-
1.2
Benzyl chloride
100-44-7

X
-
0.17
G-58
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
CalEPA
Oral MADLa
(Hg/day)
OSFb(per
mg/kg-day)
beta-Hexachlorocyclohexane
319-85-7

X
-
1.5
Bis(2-chloroethyl) ether
111-44-4

X
-
2.5
Bromodichloromethane
75-27-4

X
-
0.13
Bromoform
75-25-2

X
-
0.011
Chloroform
67-66-3
x
X
-
0.019
Chrysene
218-01-9
X
X
-
0.12
Dibenz(a,h)anthracene
53-70-3
X
X
-
4.1
Dichloromethane
75-09-2

X
-
0.014
Dieldrin
60-57-1

X
-
16
Ethylbenzene
100-41-4
X
X
-
0.011
Heptachlor
76-44-8

X
-
4.1
Heptachlor epoxide
1024-57-3

X
-
5.5
Hydrazine
302-01-2


-
3
lndeno(l,2,3-cd)pyrene
193-39-5
X
X
-
1.2
Lindane
58-89-9

X
-
1.1
N-Nitrosodiphenylamine
86-30-6
X
X
-
0.009
N-Nitroso-N-methylethylamine
10595-95-6
X
X
-
22
p,p'-DDE
72-55-9

X
-
0.34
Safrole
94-59-7

X
-
0.22
Tetrachloroethene
127-18-4

X
-
0.051
CASRN = Chemical Abstract Service Registry Number; CalEPA = California Environmental Protection Agency.
a Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive toxicant at which the chemical
would have no observable adverse reproductive effect, assuming exposure at 1,000 times that level.
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime
oral exposure to an agent. This estimate, usually expressed in units of proportion (of a population) affected per mg/kg day, is
generally reserved for use in the low-dose region of the dose-response relationship, that is, for exposures corresponding to
risks less than 1 in 100.
G-59
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-2c. Chemicals reported to be detected in produced water, with available chronic oral
RfVs and OSFs from international sources.
Chemicals are ranked by CICAD reference value (TDI- tolerable daily intake). An "x" indicates the availability of
measured concentration data in produced water (see Appendix E) and physicochemical properties data from EPI
Suite™ (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water.
Chemical name
CASRN
Concentration
data available
Physicochemical
data available
IPCS CICAD Chronic
TDIa (mg/kg-day)
Heptachlor
76-44-8

X
0.0001
Chromium (VI)
18540-29-9
X

0.0009
Mercury
7439-97-6
X

0.002
Beryllium
7440-41-7
X

0.002
Iodine
7553-56-2
X

0.01
Chloroform
67-66-3
X
X
0.015
Barium
7440-39-3
X

0.02
Ethylene glycol
107-21-1

X
0.05
Tetrachloroethene
127-18-4

X
0.05
D-Limonene
5989-27-5

X
0.1
Strontium
7440-24-6
X

0.13
Benzyl butyl phthalate
85-68-7
X
X
1.3
Diethyl phthalate
84-66-2

X
5
CASRN = Chemical Abstract Service Registry Number; IPCS = International Programme on Chemical Safety; CICAD = Concise
International Chemical Assessment Documents.
a Tolerable Daily Intake (TDI): An estimate of the intake of a substance, expressed on a body mass basis, to which an individual
in a (sub) population may be exposed daily over its lifetime without appreciable health risk.
G-60
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-2d. Chemicals reported to be detected in produced water, with available less-than-chronic oral RfVs and OSFs.
Chemicals are ranked by PPRTV subchronic reference dose (sRfD). The symbol indicates that no value was available from the sources consulted.
Additionally, an "x" indicates the availability of measured concentration data in produced water (see Appendix E) and physicochemical properties data from EPI
Suite™ (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water.
Chemical name
CASRN
Concen-
tration data
available
Physico-
chemical data
available
PPRTV
ATSDR
HHBP
SRfD3
(mg/kg-day)
Acute oral
MRLb
(mg/kg-day)
Intermediate
oral MRLb
(mg/kg-day)
Acute RfDa
(mg/kg-day)
Aldrin
309-00-2

X
0.00004
0.002
-
-
Antimony
7440-36-0
X

0.0004
-
-
-
Vanadium
7440-62-2
X

0.0007
-
0.01
-
Benzyl chloride
100-44-7

X
0.002
-
-
-
Lithium
7439-93-2
X

0.002
-
-
-
Cobalt
7440-48-4
X

0.003
-
0.01
-
Nonane
111-84-2

X
0.003
-
-
-
2-Methylnaphthalene
91-57-6
X
X
0.004
-
-
-
Methyl bromide
74-83-9

X
0.005
-
0.003
0.02
1,2,3-Trichlorobenzene
87-61-6

X
0.008
-
-
-
Bromodichloromethane
75-27-4

X
0.008
0.04
-
-
Benzene
71-43-2
X
X
0.01
-
-
-
2,4-Dichlorophenol
120-83-2
X
X
0.02
-
0.003
-
p-Cresol
106-44-5
X
X
0.02
-
-
-
Bromoform
75-25-2

X
0.03
0.7
0.2
-
Tributyl phosphate
126-73-8
X
X
0.03
1.1
0.08
-
2,4-Dimethylphenol
105-67-9
X
X
0.05
-
-
-
G-61
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration data
available
Physico-
chemical data
available
PPRTV
ATSDR
HHBP
sRfDa
(mg/kg-day)
Acute oral
MRLb
(mg/kg-day)
Intermediate
oral MRLb
(mg/kg-day)
Acute RfDa
(mg/kg-day)
Ethylbenzene
100-41-4
X
X
0.05
-
0.4
-
Chlorobenzene
108-90-7

X
0.07
-
0.4
-
Chlorodibromomethane
124-48-1

X
0.07
0.1
-
-
1,2,4-Trichlorobenzene
120-82-1

X
0.09
-
0.1
-
Butylbenzene
104-51-8

X
0.1
-
-
-
Fluoranthene
206-44-0
X
X
0.1
-
0.4
-
2-Chloroethanol
107-07-3

X
0.2
-
-
0.045
o-Cresol
95-48-7
X
X
0.2
-
-
-
2-(2-Butoxyethoxy)ethanol
112-34-5

X
0.3
-
-
-
Benzyl alcohol
100-51-6
X
X
0.3
-
-
-
Hexane
110-54-3

X
0.3
-
-
-
N, N-Dimethylformamide
68-12-2

X
0.3
-
-
-
Pyrene
129-00-0
X
X
0.3
-
-
-
Xylenes
1330-20-7
X
X
0.4
l
0.4
-
Iron
7439-89-6
X

0.7
-
-
-
Toluene
108-88-3
X
X
0.8
0.8
0.02
-
Formic acid
64-18-6

X
0.9
-
-
-
1,1-Dichloroethane
75-34-3

X
2
-
-
-
1,2-Propylene glycol
57-55-6

X
20
-
-
-
1,4-Dioxane
123-91-1
X
X
-
5
0.5
-
2-Butoxyethanol
111-76-2

X
-
0.4
0.07
-
G-62
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration data
available
Physico-
chemical data
available
PPRTV
ATSDR
HHBP
sRfDa
(mg/kg-day)
Acute oral
MRLb
(mg/kg-day)
Intermediate
oral MRLb
(mg/kg-day)
Acute RfDa
(mg/kg-day)
Acetone
67-64-1
X
X
-
-
2
-
Acrolein
107-02-8

X
-
-
0.004
-
Acrylonitrile
107-13-1

X
-
0.1
0.01
-
Aluminum
7429-90-5
X

-
-
1
-
Arsenic
7440-38-2
X

-
0.005
-
-
Barium
7440-39-3
X

-
-
0.2
-
beta-Hexachlorocyclohexane
319-85-7

X
-
0.05
0.0006
-
Boron
7440-42-8
X

-
0.2
0.2
-
Cadmium
7440-43-9
X

-
-
0.0005
-
Carbon disulfide
75-15-0
X
X
-
0.01
-
-
Chloroform
67-66-3
X
X
-
0.3
0.1
-
Chromium (VI)
18540-29-9
X

-
-
0.005
-
Copper
7440-50-8
X

-
0.01
0.01
-
Di(2-ethylhexyl) phthalate
117-81-7
X
X
-
-
0.1
-
Dibutyl phthalate
84-74-2
X
X
-
0.5
-
-
Dichloromethane
75-09-2

X
-
0.2
-
-
Dieldrin
60-57-1

X
-
-
0.0001
-
Diethyl phthalate
84-66-2

X
-
7
6
-
Diethyltoluamide
134-62-3

X
-
-
1
-
Dioctyl phthalate
117-84-0
X
X
-
3
0.4
-
Ethylene glycol
107-21-1

X
-
0.8
0.8
-
G-63
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical name
CASRN
Concen-
tration data
available
Physico-
chemical data
available
PPRTV
ATSDR
HHBP
sRfDa
(mg/kg-day)
Acute oral
MRLb
(mg/kg-day)
Intermediate
oral MRLb
(mg/kg-day)
Acute RfDa
(mg/kg-day)
Fluorene
86-73-7
X
x
-
-
0.4
-
Heptachlor
76-44-8

x
-
0.0006
0.0001
-
Lindane
58-89-9

X
-
0.003
0.00001
-
m,p-Cresol mixture
NOCAS_24858


-
-
0.1
-
m-Xylene
108-38-3

X
-
1
0.4
-
Naphthalene
91-20-3
X
X
-
0.6
0.6
-
o-Xylene
95-47-6

X
-
1
0.4
-
Phenol
108-95-2
X
X
-
1
-
-
Phosphorus
7723-14-0
X

-
-
0.0002
-
p-Xylene
106-42-3

X
-
1
0.4
-
Strontium
7440-24-6
X

-
-
2
-
Tetrachloroethene
127-18-4

X
-
0.008
0.008
-
Tin
7440-31-5
X

-
-
0.3
-
Zinc
7440-66-6
X

-
-
0.3
-
CASRN = Chemical Abstract Service Registry Number; PPRTV = Provisional Peer Reviewed Toxicity Values; ATSDR = Agency for Toxic Substances and Disease Registry; HHBP =
Human Health Benchmarks for Pesticides.
a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population (including sensitive subgroups)
that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observed-
adverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally used in the EPA's
noncancer health assessments. Subchronic RfD (sRFD): Duration of exposure is up to 10% of an average lifespan. Acute RfD: Duration of exposure is 24 hours or less.
b Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of
harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs
should not be used as predictors of harmful (adverse) health effects. Acute MRL: Duration of exposure is 1 to 14 days. Intermediate MRL: Duration of exposure is >14 to 364
days.
G-64
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Table G-2e. Available qualitative cancer classifications for chemicals reported to be detected
in produced water.
Chemicals classified as known carcinogens by one or more sources are listed first. The symbol indicates that no
value was available from the sources consulted. Additionally, an "x" indicates the availability of measured
concentration data in produced water (see Appendix E) and physicochemical properties data from EPI Suite™ (see
Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. Cancer
classifications from IRIS and PPRTV are also listed in Table G-2a.
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Alpha particle
12587-46-1
X

-
-
1
-
Arsenic
7440-38-2
X

A (Human
carcinogen)
-
1
Known
Benzene
71-43-2
X
X
A (Human
carcinogen)
-
1
Known
Benzidine
92-87-5
X
X
A (Human
carcinogen)
-
1
Known
Benzo(a)pyrene
50-32-8
X
X
B2 (Probable
human carcinogen)
-
1
RAHC
Beryllium
7440-41-7
X

B1 (Probable
human carcinogen)
-
1
Known
Beta particle
12587-47-2
X

-
-
1
-
Cadmium
7440-43-9
X

B1 (Probable
human carcinogen)
-
1
Known
Chromium (VI)
18540-29-9
X

Inhaled: A (Human
carcinogen); Oral:
D (Not classifiable
as to human
carcinogenicity)
-
1
Known
Lindane
58-89-9

X
-
-
1
RAHC
Radium-226
13982-63-3
X

-
-
1
-
Radium-228
15262-20-1
X

-
-
1
-
Ethan ol
64-17-5

X
-
-
1
-
Radium
7440-14-4
X

-
-
1
-
1,2,4-
Trichloro benzene
120-82-1

X
D (Not classifiable
as to human
carcinogenicity)
"Likely to be
carcinogenic to
humans"
-
-
G-65
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
1,2-Diphenyl-
hydrazine
122-66-7
X
X
B2 (Probable
human carcinogen)
-
-
RAHC
1,4-Dioxane
123-91-1
X
X
"Likely to be
carcinogenic to
humans"
-
2B
RAHC
2-Mercapto-
benzothiazole
149-30-4
X
X
-
-
2A
-
Acrylonitrile
107-13-1

X
B1 (Probable
human carcinogen)
-
2B
RAHC
Aldrin
309-00-2

X
B2 (Probable
human carcinogen)
-
3
-
Benz(a)anthra-
cene
56-55-3
X
X
B2 (Probable
human carcinogen)
-
2B
RAHC
Benzo(b)fluoran-
thene
205-99-2
X
X
-
-
2B
RAHC
Benzo(k)fluoran-
thene
207-08-9
X
X
-
-
2B
RAHC
Benzophenone
119-61-9

X
-
-
2B
-
Benzyl butyl
phthalate
85-68-7
X
X
C (Possible human
carcinogen)
-
3
-
beta-Hexachloro-
cyclohexane
319-85-7

X
C (Possible human
carcinogen)
-
-
-
Biphenyl
92-52-4
X
X
"Suggestive
evidence of
carcinogenic
potential"
-
-
-
Bis(2-chloroethyl)
ether
111-44-4

X
B2 (Probable
human carcinogen)
-
3
-
Bromodichloro-
methane
75-27-4

X
B2 (Probable
human carcinogen)
-
2B
RAHC
Bromoform
75-25-2

X
B2 (Probable
human carcinogen)
-
3
-
Chlorodibromo-
methane
124-48-1

X
C (Possible human
carcinogen)
-
3
-
G-66
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Chloroform
67-66-3
X
X
B2 (Probable
human carcinogen)
-
2B
RAHC
Chrysene
218-01-9
X
X
B2 (Probable
human carcinogen)
-
2B
-
Cobalt
7440-48-4
X

-
"Likely to be
carcinogenic to
humans"
2B
-
Cumene
98-82-8
X
X
D (Not classifiable
as to human
carcinogenicity)
-
2B
RAHC
Di(2-ethylhexyl)
phthalate
117-81-7
X
X
B2 (Probable
human carcinogen)
-
2B
RAHC
Dibenz(a,h)an-
thracene
53-70-3
X
X
-
-
2A
RAHC
Dichloromethane
75-09-2

X
"Likely to be
carcinogenic in
humans"
-
2A
RAHC
Dieldrin
60-57-1

X
B2 (Probable
human carcinogen)
-
3
-
Ethylbenzene
100-41-4
X
X
D (Not classifiable
as to human
carcinogenicity)
-
2B
-
Heptachlor
76-44-8

X
B2 (Probable
human carcinogen)
-
2B
-
Heptachlor
epoxide
1024-57-3

X
B2 (Probable
human carcinogen)
-
-
-
lndeno(l,2,3-
cd)pyrene
193-39-5
X
X
-
-
2B
RAHC
Lead
7439-92-1
X

B2 (Probable
human carcinogen)
-
2B
RAHC
m-Cresol
108-39-4
X
X
C (Possible human
carcinogen)
-
-
-
G-67
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Naphthalene
91-20-3
X
X
"Data are
inadequate to
assess human
carcinogenic
potential"
-
2B
RAHC
Nickel
7440-02-0
X

-
-
2B
RAHC
Nitrate
14797-55-8
X

-
-
2A
-
Nitrite
14797-65-0
X

-
-
2A
-
N-Nitrosodiphen-
ylamine
86-30-6
X
X
B2 (Probable
human carcinogen)
-
3
-
N-Nitroso-N-
methylethylamine
10595-95-6
X
X
B2 (Probable
human carcinogen)
-
2B
-
o-Cresol
95-48-7
X
X
C (Possible human
carcinogen)
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
p-Cresol
106-44-5
X
X
C (Possible human
carcinogen)
-
-
-
p,p'-DDE
72-55-9

X
B2 (Probable
human carcinogen)
-
-
-
Safrole
94-59-7

X
-
-
2B
RAHC
Tetrachloroeth-
ene
127-18-4

X
"Likely to be
carcinogenic in
humans"
-
2A
RAHC
1,1-
Dichloroethane
75-34-3

X
C (Possible human
carcinogen)
-
-
-
Benzyl chloride
100-44-7

X
B2 (Probable
human carcinogen)
-
-
-
Hydrazine
302-01-2


B2 (Probable
human carcinogen)
-
2A
RAHC
G-68
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
N, N-Dimethylfor-
mamide
68-12-2

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
2A
-
Quinoline
91-22-5

X
"Likely to be
carcinogenic in
humans"
-
-
-
Tributyl
phosphate
126-73-8
X
X
-
"Likely to be
carcinogenic to
humans"
-
-
Dibromoaceto-
nitrile
3252-43-5

X
-
-
2B
-
Acetaldehyde
75-07-0

X
B2 (Probable
human carcinogen)
-
2B
RAHC
1,2,3-Trichloro-
benzene
87-61-6

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
1,3,5-
Trimethylbenzene
108-67-8
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
2,4-
Dichlorophenol
120-83-2
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
2,4-
Dimethylphenol
105-67-9
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
G-69
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
2,5-Cyclohexa-
diene-l,4-dione
106-51-4
X
X
-
-
3
-
2-Methylnaph-
thalene
91-57-6
X
X
"Data are
inadequate to
assess human
carcinogenic
potential"
-
-
-
Acetone
67-64-1
X
X
"Data are
inadequate for an
assessment of
human
carcinogenic
potential"
-
-
-
Acetophenone
98-86-2
X
X
D (Not classifiable
as to human
carcinogenicity)
-
-
-
Acrolein
107-02-8

X
"Data are
inadequate for an
assessment of
human
carcinogenic
potential"
-
3
-
Aluminum
7429-90-5
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Antimony
7440-36-0
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Benzo(g,h,i)peryl-
ene
191-24-2
X
X
-
-
3
-
G-70
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Benzyl alcohol
100-51-6
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Boron
7440-42-8
X

"Data are
inadequate to
assess the
carcinogenic
potential"
-
-
-
Butylbenzene
104-51-8

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Caffeine
58-08-2
X
X
-
-
3
-
Chloromethane
74-87-3

X
"Carcinogenic
potential cannot be
determined"
-
3
-
Cholesterol
57-88-5
X
X
-
-
3
-
Chromium
7440-47-3


-
-
3
-
Chromium (III)
16065-83-1
X

"Data are
inadequate for an
assessment of
human
carcinogenic
potential"
-
3
-
Cyanide
57-12-5

X
"Inadequate
information to
assess the
carcinogenic
potential"
-
-
-
delta-
Hexachlorocyclo-
hexane
319-86-8

X
D (Not classifiable
as to human
carcinogenicity)
-
-
-
G-71
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Dibenzothiophene
132-65-0

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
3
-
Dibutyl phthalate
84-74-2
X
X
D (Not classifiable
as to human
carcinogenicity)
-
-
-
Diethyl phthalate
84-66-2

X
D (Not classifiable
as to human
carcinogenicity)
-
-
-
Dimethyl
phthalate
131-11-3
X
X
D (Not classifiable
as to human
carcinogenicity)
-
-
-
Diphenylamine
122-39-4
X
X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Fluoranthene
206-44-0
X
X
D (Not classifiable
as to human
carcinogenicity)
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
3
-
Fluorene
86-73-7
X
X
D (Not classifiable
as to human
carcinogenicity)
-
3
-
Fluoride
16984-48-8
X

-
-
3
-
Formic acid
64-18-6

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
G-72
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Iron
7439-89-6
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Isopropanol
67-63-0

X
-
-
3
-
Lithium
7439-93-2
X

-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Manganese
7439-96-5
X

D (Not classifiable
as to human
carcinogenicity)
-
-
-
Mercury
7439-97-6
X

D (Not classifiable
as to human
carcinogenicity)
-
3
-
Methyl bromide
74-83-9

X
D (Not classifiable
as to human
carcinogenicity)
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
3
-
Methyl ethyl
ketone
78-93-3

X
"Data are
inadequate to
assess carcinogenic
potential"
-
-
-
Perylene
198-55-0

X
-
-
3
-
Phenanthrene
85-01-8
X
X
-
-
3
-
Phenol
108-95-2
X
X
"Data are
inadequate for an
assessment of
human
carcinogenic
potential"
-
3
-
G-73
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
Phosphorus
7723-14-0
X

D (Not classifiable
as to human
carcinogenicity)
-
-
-
Pyrene
129-00-0
X
X
D (Not classifiable
as to human
carcinogenicity)
-
3
-
Pyridine
110-86-1
X
X
-
-
3
-
Selenium
7782-49-2
X

D (Not classifiable
as to human
carcinogenicity)
-
3
-
Silica
7631-86-9


-
-
3
-
Silver
7440-22-4
X

D (Not classifiable
as to human
carcinogenicity)
-
-
-
Toluene
108-88-3
X
X
"Inadequate
information to
assess the
carcinogenic
potential"
-
3
-
Vanadium
7440-62-2
X

"Data are
inadequate to
assess the
carcinogenic
potential"
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Xylenes
1330-20-7
X
X
"Data are
inadequate to
assess the
carcinogenic
potential"
-
3
-
Zinc
7440-66-6
X

"Inadequate
information to
assess carcinogenic
potential"
-
-
-
G-74
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARCC
RoCd
2-Chloroethanol
107-07-3

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Nonane
111-84-2

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
2-Butoxyethanol
111-76-2

X
"Not likely to be
carcinogenic to
humans"
-
3
-
D-Limonene
5989-27-5

X
-
-
3
-
Chlorobenzene
108-90-7

X
D (Not classifiable
as to human
carcinogenicity)
-
-
-
1-Butanol
71-36-3

X
D (Not classifiable
as to human
carcinogenicity)
-
-
-
Hydrochloric acid
7647-01-0


-
-
3
-
2-(2-Butoxyeth-
oxy)ethanol
112-34-5

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
Hexane
110-54-3

X
"Inadequate
information to
assess the
carcinogenic
potential"
-
-
-
G-75
-------
Appendix G - Identification and Hazard Evaluation of Chemicals across
the Hydraulic Fracturing Water Cycle Supplemental Information
Chemical
name
CASRN
Concen-
tration
data
available
Physico-
chemical
data
available
Qualitative cancer classification
IRIS3
PPRTVb
IARC0
RoCd
Pentane
109-66-0

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
1,2,3-Trimethyl-
benzene
526-73-8

X
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
-
-
1,2-Propylene
glycol
57-55-6

X
-
"Not likely to be
carcinogenic to
humans"
-
-
Barium
7440-39-3
X

"Not likely to be
carcinogenic to
humans"
-
-
-
Caprolactam
105-60-2
x
X
-
-
4
-
CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer
Reviewed Toxicity Values; IARC = International Agency for Research on Cancer Monographs; RoC = National Toxicology Program
13th Report on Carcinogens.
a IRIS assessments use the EPA's 1986,1996,1999, or 2005 guidelines to establish descriptors for summarizing the weight of
evidence as to whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details.
b PPRTV assessments use the EPA's 1999 guidelines to establish descriptors for summarizing the weight of evidence as to
whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details.
c The IARC summarizes the weight of evidence as to whether a contaminant is or may be carcinogenic using five weight of
evidence classifications: Group 1: Carcinogenic to humans; Group 2A: Probably carcinogenic to humans; Group 2B: Possibly
carcinogenic to humans; Group 3: Not classifiable as to its carcinogenicity to humans; Group 4: Probably not carcinogenic to
humans. See glossary in Appendix G for details.
d The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated
to be a human carcinogen.
G-76
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Appendix H. Chemicals Identified in Hydraulic
Fracturing Fluids and/or Produced Water
H-l
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
This page is intentionally left blank.
H-2
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Appendix H. Chemicals Identified in Hydraulic Fracturing
Fluids and/or Produced Water
H.l. Supplemental Tables and Information
The EPA identified authoritative sources for information on hydraulic fracturing-related chemicals
and, to the extent possible, verified the chemicals used in hydraulic fracturing fluids and detected in
produced water of hydraulically fractured wells. The EPA used 28 sources of information to identify
the chemicals used in hydraulic fracturing fluids or detected in produced water of hydraulically
fracturing wells. The sources include compilations of industry-provided data (all Toxic Substance
Control Act (TSCA) confidential business information (CBI) chemical lists handled by the EPA were
managed in accordance with TSCA CBI procedures); publications that represent collaborations
between state, non-profit, academic, and/or industry groups; and peer-reviewed journal articles.
Most of the listed chemicals were cited by multiple sources.
Seven of the 28 sources obtained information about the chemicals used in hydraulic fracturing
fluids from Material Safety Data Sheets (MSDSs) provided by chemical manufacturers for the
products they sell, as required by the Occupational Safety and Health Administration (OSHA). The
MSDSs must list all hazardous ingredients if they comprise at least 1% of the product; for
carcinogens, the reporting threshold is 0.1%. However, chemical manufacturers may withhold
information (e.g., chemical name, concentration of the substance in a mixture) about a hazardous
substance from MSDSs if it is claimed as confidential business information (CBI), provided that
certain conditions are met (OSHA. 2013).
Table H-l. Sources used to create lists of chemicals used in fracturing fluids or detected in
produced water.
The number next to each citation in the reference column corresponds to numbers in the reference columns found
in Table H-2, Table H-3, Table H-4, and Table H-5.
Reference
Citation
House of Representatives (U.S. House of Representatives). (2011). Chemicals used in
hydraulic fracturing. Washington, D.C.: U.S. House of Representatives, Committee on
Energy and Commerce, Minority Staff.
http://www.conservation.ca.gov/dog/general information/Documents/Hvdraulic%
House of Representatives
(2011)a (1)
ic-Fracturing-Chemicals-2011-4-18.pdf.
Colborn, T; Kwiatkowski, C; Schultz, K; Bachran, M. (2011). Natural gas operations
from a public health perspective. Hum Ecol Risk Assess 17: 1039-1056.
http://dx.doi.org/10.1080/10807039.2011.605662.
Colborn et al. (2011)a (2)
NYSDEC (New York State Department of Environmental Conservation). (2011).
Revised draft supplemental generic environmental impact statement (SGEIS) on the
oil, gas and solution mining regulatory program: Well permit issuance for horizontal
drilling and high-volume hydraulic fracturing to develop the Marcellus shale and
other low-permeability gas reservoirs. Albany, NY: NY SDEC.
http://www.dec.nv.gov/energv/75370.html.
NYSDEC (2011)a b (3)
H-3
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Reference
Citation
U.S. EPA (U.S. Environmental Protection Agency). (2013). Data received from oil and
gas exploration and production companies, including hydraulic fracturing service
companies 2011 to 2013. Non-confidential business information source documents
are located in Federal Docket ID: EPA-HQ-ORD2010-0674. Available at
http://www. regulations, gov.
U.S. EPA (2013a)a (4)
Material Safety Data Sheets, (a) Encana/Halliburton Energy Services, Inc.: Duncan,
Oklahoma. Provided by Halliburton Energy Services during an onsite visit by the EPA
on May 10, 2010; (b) Encana Oil and Gas (USA), Inc.: Denver, Colorado. Provided to
US EPA Region 8.
Material Safetv Data
Sheetsa (5)
U.S. EPA (U.S. Environmental Protection Agency). (2004). Evaluation of impacts to
underground sources of drinking water by hydraulic fracturing of coalbed methane
reservoirs. (EPA/816/R-04/003). Washington, DC.: U.S. Environmental Protection
Agency, Office of Solid Waste.
U.S. EPA (2004)a (6)
PA DEP (Pennsylvania Department of Environmental Protection). (2010). Chemicals
used by hydraulic fracturing companies in Pennsylvania for surface and hydraulic
fracturing activities. Harrisburg, PA: Pennsylvania Department of Environmental
Protection (PADEP).
http://files.dep.state.pa.us/OilGas/BOGM/BOGMPortalFiles/MarcellusShale/Frac%20
PA DEP (2010)a (7)
list%206-30-2010.pdf.

U.S. EPA (U.S. Environmental Protection Agency). (2015). Analysis of hydraulic
fracturing fluid data from the FracFocus chemical disclosure registry 1.0: Project
database [EPA Report], (EPA/601/R-14/003). Washington, D.C.: U.S. Environmental
Protection Agency, Office of Research and Development.
http://www2.epa.gov/hfstudv/epa-proiect-database-developed-fracfocus-l-
disclosures.
U.S. EPA (2015c)a (8)
Hayes, T. (2009). Sampling and analysis of water streams associated with the
development of Marcellus shale gas. Des Plaines, IL: Marcellus Shale Coalition http://
energyindepth.org/wp-content/uploads/marcellus/2012/ll/MSCommission-
Report.pdf.
Haves (2009)b (9)
U.S. EPA (U.S. Environmental Protection Agency). (2011). Sampling data for flowback
and produced water provided to EPA by nine oil and gas well operators (non-
confidential business information). US Environmental Protection Agency.
http://www. regulations.gov/#!docketDetail;rpp=100;so=DESC;sb=docld;po=0; D=EPA-
U.S. EPA (2011b)b (10)
HQ-ORD-2010-0674.

Akob, DM; Cozzarelli, IM; Dunlap, DS; Rowan, EL; Lorah, MM. (2015). Organic and
inorganic composition and microbiology of produced waters from Pennsylvania shale
gas wells. Appl Geochem 60: 116-125.
http://dx.doi.Org/10.1016/i.apgeochem.2015.04.011.
Akobetal. (2015)b (11)
Cluff, M; Hartsock, A; Macrae, J; Carter, K; Mouser, PJ. (2014). Temporal changes in
microbial ecology and geochemistry in produced water from hydraulically fractured
Marcellus Shale Gas Wells. Environ Sci Technol 48: 6508-6517.
http://dx.doi.org/10.1021/es501173p.
Cluff etal. (2014)b (12)
H-4
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Reference
Citation
Digiulio, DC; Jackson, RB. (2016). Impact to underground sources of drinking water
and domestic wells from production well stimulation and completion practices in the
Pavillion, Wyoming, Field. Environ Sci Technol 50: 4524-4536.
http://dx.doi.org/10.1021/acs.est.5b04970.
Digiulio and Jackson
(2016)b (13)
Geological Survey of Alabama. (2014). Water management strategies for improved
coalbed methane production in the Black Warrior Basin. (DE-FE0000888).
Washington, DC: U.S. Department of Energy, National Energy Technology Library.
https://www.netl.doe.gov/research/oil-and-gas/natural-gas-resources/00888-
Geological Survev of
Alabama (2014)b (14)
geosurvevalabama.
Hayes, T; Severin, B. (2012). Characterization of flowback water from the the
Marcellus and the Barnett shale regions. Barnett and Appalachian shale water
management and reuse technologies. (08122-05.09; Contract 08122-05). Hayes, T;
Severin, B. http://www.rpsea.org/media/files/proiect/2146b3a0/08122-05-RT-
Characterization Flowback Waters Marcellus Barnett Shale Regions-03-20-12.pdf.
Haves and Severin
(2012a)b (15)
Khan, NA; Engle, M; Dungan, B; Holguin, FO; Xu, P; Carroll, KC. (2016). Volatile-organic
molecular characterization of shale-oil produced water from the Permian Basin.
Chemosphere 148: 126-136. http://dx.doi.Org/10.1016/i.chemosphere.2015.12.116.
Khan et al. (2016)b (16)
Lester, Y; Ferrer, 1; Thurman, EM; Sitterley, KA; Korak, JA; Aiken, G; Linden, KG. (2015).
Characterization of hydraulic fracturing flowback water in Colorado: Implications for
water treatment. Sci Total Environ 512-513: 637-644.
http://dx.doi.Org/10.1016/i.scitotenv.2015.01.043.
Lester et al. (2015)b (17)
Maguire-Boyle, SJ; Barron, AR. (2014). Organic compounds in produced waters from
shale gas wells. Environ Sci Process Impacts 16: 2237-2248.
http://dx.doi.org/10.1039/c4em00376d.
Maguire-Bovle and
Barron (2014)b (18)
Olsson, 0; Weichgrebe, D; Rosenwinkel, KH. (2013). Hydraulic fracturing wastewater
in Germany: Composition, treatment, concerns. Environ Earth Sci 70: 3895-3906.
http://dx.doi.org/10.1007/sl2665-013-2535-4.
Olsson et al. (2013)b (19)
Orem, WH; Tatu, CA; Lerch, HE; Rice, CA; Bartos, TT; Bates, AL; Tewalt, S; Corum, MD.
(2007). Organic compounds in produced waters from coalbed natural gas wells in the
Powder River Basin, Wyoming, USA. Appl Geochem 22: 2240-2256.
http://dx.doi.Org/10.1016/i.apgeochem.2007.04.010.
Orem etal. (2007)b (20)
Orem, W; Tatu, C; Varonka, M; Lerch, H; Bates, A; Engle, M; Crosby, L; Mcintosh, J.
(2014). Organic substances in produced and formation water from unconventional
natural gas extraction in coal and shale. Int J Coal Geol 126: 20-31.
http://dx.doi.Org/10.1016/i.coal.2014.01.003.
Orem etal. (2014)b (21)
Thacker, JB; Carlton, DD, Jr; Hildenbrand, ZL; Kadjo, AF; Schug, KA. (2015). Chemical
analysis of wastewater from unconventional drilling operations. Water 7:1568-1579.
http://dx.doi.org/10.3390/w7041568.
Thacker etal. (2015)b (22)
Thurman, EM; Ferrer, 1; Blotevogel, J; Borch, T. (2014). Analysis of hydraulic fracturing
flowback and produced waters using accurate mass: Identification of ethoxylated
surfactants. Anal Chem 86: 9653-9661. http://dx.doi.org/10.1021/ac502163k.
Thurman et al. (2014)b
(23)
H-5
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Reference
Citation
Rowan, EL; Engle, MA; Kirby, CS; Kraemer, TF. (2011). Radium content of oil- and gas-
field produced waters in the northern Appalachian Basin (USA): Summary and
discussion of data. (Scientific Investigations Report 20115135). Reston, VA: U.S.
Geological Survey. http://pubs.usgs.gov/sir/2011/5135/.
Rowan et al. (2011)b (24)
PA DEP (Pennsylvania Department of Environmental Protection). (2015).
Technologically enhanced naturally occurring radioactive materials (TENORM) study
report. Harrisburg, PA.
PA DEP (2015)b (25)
Ziemkiewicz, PF; He, YT. (2015). Evolution of water chemistry during Marcellus Shale
gas development: A case study in West Virginia. Chemosphere 134: 224-231.
http://dx.doi.Org/10.1016/i.chemosphere.2015.04.040.
Ziemkiewicz and He
(2015)b (26)
Dresel, PE; Rose, AW. (2010). Chemistry and origin of oil and gas well brines in
western Pennsylvania (pp. 48). (Open-File Report OFOG 1001.0). Harrisburg, PA:
Pennsylvania Geological Survey, 4th ser.
http://www.marcellus.psu.edu/resources/PDFs/brines.pdf.
Dresel and Rose (2010)b
(27)
Barbot, E; Vidic, NS; Gregory, KB; Vidic, RD. (2013). Spatial and temporal correlation
of water quality parameters of produced waters from Devonian-age shale following
hydraulic fracturing. Environ Sci Technol 47: 2562-2569.
Barbot etal. (2013)b (28)
a Sources used to identify chemicals used in hydraulic fracturing fluids.
b Sources used to identify chemicals detected in produced water.
Once it had identified chemicals used in hydraulic fracturing fluids and chemicals detected in
produced water, the EPA conducted an initial review of the chemicals for preliminary validation of
provided chemical name and Chemical Abstracts Service Registry Number (CASRN) combinations.
A CASRN is a numeric identifier assigned by the Chemical Abstracts Service (CAS) to a chemical
substance when it enters the CAS Registry Database.
The EPA Office of Research and Development's National Center for Computational Toxicology
(NCCT) processed and provided the final list of curated CASRN-chemical name matches with
validated chemical structures from NCCT's Distributed Structure-Searchable Toxicity Database
(DSSTox) (U.S. EPA. 2013b). As of late 2016, the DSSTox database exceeds 700,000 chemical
substances. The highest quality, manually curated subset (~25,000 chemical substances) focuses on
chemicals of relevance to environmental exposures, toxicity, and bioactivity. Additional content
(~130,000 chemical substances) imported from the EPA's Substance Registry System (SRS)
chemicals and the National Library of Medicine (NLM)'s ChemID library comprises a portion the
DSSTox database with intermediate quality fNLM. 2014: U.S. EPA. 2014el. The remainder of the
chemical substances are imported from lower quality, uncurated public resources such as PubChem
f https://pubchem.ncbi.nlm.nih. gov/1. The entire DSSTox database is searchable through the EPA
public CompTox Dashboard fhttps://comptox.epa.gov/dashboard).
The DSSTox database is distinguished from other publicly available chemical databases by the
manual curation workflow applied to high-priority EPA chemical lists, as well as by the
enforcement of unique (1:1:1) mappings of CASRN to a single "preferred name" and unique
H-6
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
chemical structure. Initial automated-processing of a CASRN and/or chemical name list yields
various types of corrections, notes, and mappings to registered DSSTox chemical substance records.
The simplest include: (1) CASRN- exact chemical name match; (2) CASRN-synonym chemical name
match; (3) CASRN-match through mapping of a "deleted" CASRN that is no longer in use to an
"active" CASRN; (4) Auto-repair of common errors in CASRN formatting resulting in a CASRN- exact
or synonym chemical name match. These four situations are considered valid "matches" and the
records are mapped to a DSSTox ID directly.
Other situations (such as when a CASRN-chemical name appears mismatched in an original source
of information or when only a chemical name without a CASRN is provided in the original source)
require various levels of curation review prior to final mapping of a CASRN to a single chemical
name and unique structure. The general methodology for resolving conflicts between CASRN-
chemical name combinations and other chemical identification issues differed slightly depending
on the data provided by each source. To resolve CASRN-chemical name issues in data provided by
the nine service companies, the EPA worked with each company to verify the CASRN-chemical
name matches proposed by NCCT. In cases of CASRN-chemical name mismatches in data provided
by FracFocus, chemical names were considered primary to the CASRN (i.e., the name overrode the
CASRN). When the chemical name was non-specific and the CASRN was valid, then the CASRN was
considered primary to the chemical name, and the correct specific chemical name from DSSTox was
assigned to the CASRN. For all other sources of information, the CASRN was considered primary
unless it was invalid or missing. In such cases, the chemical name was primary.
When no CASRN-chemical name match is possible, the chemical may undergo manual curation
review and require registration of new DSSTox substance-structure records. Each registered
DSSTox substance record, in turn, is assigned a Curation Quality Score that indicates the level of
curation (automated vs. manual) and reliability of the CASRN-chemical name-structure association.
The manual DSSTox curation process is carried out in accordance with the published DSSTox
Chemical Information Quality Review Procedures fftp: //ftp.epa.gov/dsstoxftp/DSSTox Archive
20150930/DSSTox ChemlnfOAProcedures 20150930.pdf).
Individual chemicals or chemical mixtures with valid CASRN-chemical name matches that are used
in hydraulic fracturing fluids are presented in Table H-2. Generic chemicals used in hydraulic
fracturing fluids (i.e., encompassing a general class of chemicals) or chemicals without a valid
CASRN-chemical name match are presented in Table H-3. Chemicals with valid CASRN-chemical
name matches that have been detected in produced water are presented in Table H-4. Generic
chemicals or chemicals without a valid CASRN-chemical name match that have been detected in
produced water are presented in Table H-5. Chemicals with valid CASRN-chemical name matches
found in both fracturing fluids and produced water are also indicated in Table H-2 and Table H-4.
In total, 1,606 chemicals with valid CASRN-chemical name matches were reported to be used in
hydraulic fracturing fluids and/or detected in produced water from hydraulically fractured wells.
This total number comprises 1,084 chemicals reported to be used in hydraulic fracturing fluids
from 2005-2013 and 599 chemicals detected in produced water according to the sources of
information that we summarized. The number of chemicals reported to be used in hydraulic
fracturing fluids from 2005-2013 that were also detected in produced water was 77.
H-7
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Table H-2. Chemicals reported to be used in hydraulic fracturing fluids.
Chemicals were reported to be used in hydraulic fracturing fluids from 2005-2013, according to the references cited. An "X" indicates the availability of
physicochemical properties from EPI Suite™ (Appendix C) and selected toxicity data (Appendix G). An empty cell indicates no information was available from
the sources we consulted. Reference number corresponds to the citation in Table H-l.
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
(13Z)-N,N-bis(2-hydroxyethyl)-N-methyldocos-13-en-l-aminium
chloride
120086-58-0

X

l
(2,3-dihydroxypropyl)trimethylammonium chloride
34004-36-9

X

8
(E)-Crotonaldehyde
123-73-9

X
X
1,4
[Nitrilotris(methylene)]tris-phosphonic acid pentasodium salt
2235-43-0

X

1
l-(l-Naphthylmethyl)quinolinium chloride
65322-65-8

X

1
l-(Alkyl* amino)-3-aminopropane *(42%C12, 26%C18,15%C14, 8%C16,
5%C10, 4%C8)
68155-37-3

X

8
l-(Phenylmethyl)pyridinium Et Me derivs., chlorides
68909-18-2

X

1, 2, 3, 4, 6, 8
1,2,3-Trimethylbenzene
526-73-8
X
X
X
1,4
1,2,4-Trimethylbenzene
95-63-6
X
X
X
1, 2, 3, 4, 5
l,2-Benzisothiazolin-3-one
2634-33-5

X

1, 3,4
l,2-Dibromo-2,4-dicyanobutane
35691-65-7

X

1,4
1,2-Ethanediamine, polymer with 2-methyloxirane
25214-63-5



8
1,2-Ethanediaminium, N,N'-bis[2-[bis(2-
hydroxyethyl)methylammonio]ethyl]-N,N'-bis(2-hydroxyethyl)-N,Nl-
dimethyl-, tetrachloride
138879-94-4

X

1,4
1,2-Propylene glycol
57-55-6
X
X
X
1, 2, 3, 4, 8
1,2-Propylene oxide
75-56-9

X
X
1,4
1,3,5-Triazine
290-87-9

X

8
H-8
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
l,3,5-Triazine-l,3,5(2H,4H,6H)-triethanol
4719-04-4

X

1,4
1,3,5-Trimethylbenzene
108-67-8
X
X
X
1,4
1,3-Butadiene
106-99-0

X
X
8
1,3-Dichloropropene
542-75-6

X
X
8
1,4-Dioxane
123-91-1
X
X
X
2, 3,4
l,4-Dioxane-2,5-dione, 3,6-dimethyl-, (3R,6R)-, polymer with (3S,6S)-
3,6-dimethyl-l,4-dioxane-2,5-dione and (3R,6S)-rel-3,6-dimethyl-l,4-
dioxane-2,5-dione
9051-89-2



1, 4,8
1,6-Hexanediamine
124-09-4

X

1,2
1,6-Hexanediamine dihydrochloride
6055-52-3

X

1
l-[2-(2-Methoxy-l-methylethoxy)-l-methylethoxy]-2-propanol
20324-33-8

X

4
l-Amino-2-propanol
78-96-6

X

8
1-Benzylquinolinium chloride
15619-48-4

X

1, 3,4
1-Butanol
71-36-3
X
X
X
1, 2, 3, 4, 7
l-Butoxy-2-propanol
5131-66-8

X

8
1-Decanol
112-30-1

X

1,4
l-Dodecyl-2-pyrrolidinone
2687-96-9

X

1,4
1-Eicosene
3452-07-1

X

3
l-Ethyl-2-methylbenzene
611-14-3
X
X

4
1-Hexadecene
629-73-2
X
X

3
1-Hexanol
111-27-3

X

1, 4,8
1-Hexanol, 2-ethyl-, manuf. of, by products from, distn. residues
68609-68-7



4
H-9
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
lH-lmidazole-l-ethanamine, 4,5-dihydro-, 2-nortall-oil alkyl derivs.
68442-97-7



2,4
l-Methoxy-2-propanol
107-98-2

X

1, 2, 3, 4
1-Octadecanamine, acetate (1:1)
2190-04-7

X

8
1-Octadecanamine, N,N-dimethyl-
124-28-7

X

1, 3,4
1-Octadecene
112-88-9
X
X

3
1-Octanol
111-87-5

X

1,4
1-Pentanol
71-41-0

X

8
1-Propanaminium, 3-amino-N-(carboxymethyl)-N,N-dimethyl-, N-coco
acyl derivs., chlorides, sodium salts
61789-39-7



1
1-Propanaminium, 3-amino-N-(carboxymethyl)-N,N-dimethyl-, N-coco
acyl derivs., inner salts
61789-40-0



1, 2, 3, 4
1-Propanaminium, 3-chloro-2-hydroxy-N,N,N-trimethyl-, chloride
3327-22-8

X

8
1-Propanaminium, N-(3-aminopropyl)-2-hydroxy-N,N-dimethyl-3-sulfo-,
N-coco acyl derivs., inner salts
68139-30-0



1, 3,4
1-Propanaminium, N-(carboxymethyl)-N,N-dimethyl-3-[(l-
oxooctyl)amino]-, inner salt
73772-46-0



8
1-Propanesulfonic acid
5284-66-2

X

3
1-Propanol
71-23-8
X
X

1, 2, 4, 5
1-Propanol, zirconium(4+) salt
23519-77-9



1, 4,8
1-Propene
115-07-1

X
X
2
l-tert-Butoxy-2-propanol
57018-52-7

X
X
8
1-Tetradecene
1120-36-1

X

3
1-Tridecanol
112-70-9

X

1,4
H-10
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
l-Undecanol
112-42-5

X

2
2-(2-Butoxyethoxy)ethanol
112-34-5
X
X
X
2,4
2-(2-Ethoxyethoxy)ethanol
111-90-0

X
X
1,4
2-(2-Ethoxyethoxy)ethyl acetate
112-15-2

X

1,4
2-(Dibutylamino)ethanol
102-81-8

X

1,4
2-(Hydroxymethylamino)ethanol
34375-28-5

X

1,4
2-(Thiocyanomethylthio)benzothiazole
21564-17-0

X
X
2
2,2'-(diazene-l,2-diyldiethane-l,l-diyl)bis-4,5-dihydro-lH-imidazole
dihydrochloride
27776-21-2

X

3
2,2'-(Octadecylimino)diethanol
10213-78-2

X

1
2,2'-[Ethane-l,2-diylbis(oxy)]diethanamine
929-59-9

X

1,4
2,2'-Azobis(2-amidinopropane) dihydrochloride
2997-92-4

X

1,4
2,2-Dibromo-3-nitrilopropionamide
10222-01-2
X
X

1, 2, 3, 4, 6, 7, 8
2,2-Dibromopropanediamide
73003-80-2

X

3
2,4-Hexadienoic acid, potassium salt, (2E,4E)-
24634-61-5

X

3
2,6,8-Trimethyl-4-nonanol
123-17-1

X

8
2-Acrylamide - 2-propanesulfonic acid and N,N-dimethylacrylamide
copolymer
NOCAS_51252



2
2-Acrylamido -2-methylpropanesulfonic acid copolymer
NOCAS_51255



8
2-Acrylamido-2-methyl-l-propanesulfonic acid
15214-89-8

X

1,3
2-Amino-2-methylpropan-l-ol
124-68-5

X

8
2-Aminoethanol ester with boric acid (H3BO3) (1:1)
10377-81-8



8
H-ll
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
2-Aminoethanol hydrochloride
2002-24-6

X

4,8
2-Bromo-3-nitrilopropionamide
1113-55-9

X

1, 2, 3, 4, 5
2-Butanone oxime
96-29-7

X

1
2-Butenediamide, (2E)-, N,N'-bis[2-(4,5-dihydro-2-nortall-oil alkyl-lH-
imidazol-l-yl)ethyl] derivs.
68442-77-3



3, 8
2-Butoxy-l-propanol
15821-83-7

X

8
2-Butoxyethanol
111-76-2
X
X
X
1, 2, 3, 4, 6,7, 8
2-Dodecylbenzenesulfonic acid- n-(2-aminoethyl)ethane-l,2-
diamine(l:l)
40139-72-8

X

8
2-Ethoxyethanol
110-80-5

X
X
6
2-Ethoxynaphthalene
93-18-5

X

3
2-Ethyl-l-hexanol
104-76-7
X
X

1,1, 3, A, 5
2-Ethyl-2-hexenal
645-62-5

X

2
2-Ethylhexyl benzoate
5444-75-7

X

4
2-Hydroxyethyl acrylate
818-61-1

X

1,4
2-Hydroxyethylammonium hydrogen sulphite
13427-63-9

X

1
2-Hydroxy-N,N-bis(2-hydroxyethyl)-N-methylethanaminium chloride
7006-59-9

X

8
2-Mercaptoethanol
60-24-2

X

1,4
2-Methoxyethanol
109-86-4

X
X
4
2-Methyl-l-propanol
78-83-1

X
X
1, 2,4
2-Methyl-2,4-pentanediol
107-41-5

X

1, 2,4
2-Methyl-3(2H)-isothiazolone
2682-20-4

X

1, 2,4
H-12
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
2-Methyl-3-butyn-2-ol
115-19-5

X

3
2-Methylbutane
78-78-4

X

2
2-Methylquinoline hydrochloride
62763-89-7

X

3
2-Phosphono-l,2,4-butanetricarboxylic acid
37971-36-1

X

1,4
2-Phosphonobutane-l,2,4-tricarboxylic acid, potassium salt (l:x)
93858-78-7

X

1
2-Propanol, aluminum salt
555-31-7



1
2-Propen-l-aminium, N,N-dimethyl-N-2-propenyl-, chloride,
homopolymer
26062-79-3



3
2-Propenamide, homopolymer
25038-45-3



8
2-Propenoic acid, 2-(2-hydroxyethoxy)ethyl ester
13533-05-6

X

4
2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-
propenoate
36089-45-9



8
2-Propenoic acid, 2-methyl-, polymer with 2-propenoic acid, sodium salt
28205-96-1



8
2-Propenoic acid, 2-methyl-, polymer with sodium 2-methyl-2-[(l-oxo-
2-propen-l-yl)amino]-l-propanesulfonate (1:1)
136793-29-8



8
2-Propenoic acid, ethyl ester, polymer with ethenyl acetate and 2,5-
furandione, hydrolyzed
113221-69-5



4,8
2-Propenoic acid, ethyl ester, polymer with ethenyl acetate and 2,5-
furandione, hydrolyzed, sodium salt
111560-38-4



8
2-Propenoic acid, polymer with 2-propenamide, sodium salt
25987-30-8



3, 4,8
2-Propenoic acid, polymer with ethene, zinc salt
28208-80-2



8
2-Propenoic acid, polymer with ethenylbenzene
25085-34-1



8
H-13
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
2-Propenoic acid, polymer with sodium ethanesulfonate,
peroxydisulfuric acid, disodium salt- initiated, reaction products with
tetrasodium ethenylidenebis (phosphonata)
397256-50-7



8
2-Propenoic acid, polymer with sodium phosphinate (1:1), sodium salt
129898-01-7



8
2-Propenoic acid, sodium salt (1:1), polymer with sodium 2-methyl-2-
((l-oxo-2-propen-l-yl)amino)-l-propanesulfonate (1:1)
37350-42-8



1
2-Propenoic acid, telomer with sodium 4-ethenylbenzenesulfonate
(1:1), sodium 2-methyl-2-[(l-oxo-2-propen-l-yl)amino]-l-
propanesulfonate (1:1) and sodium sulfite (1:1), sodium salt
151006-66-5



4
2-Propenoic, polymer with sodium phosphinate
71050-62-9



3,4
3-(Dimethylamino)propylamine
109-55-7

X

8
3,4,4-Trimethyloxazolidine
75673-43-7

X

8
3,5,7-Triazatricyclo(3.3.1.1(superscript 3,7))decane, l-(3-chloro-2-
propenyl)-, chloride, (Z)-
51229-78-8

X

3
3,7-Dimethyl-2,6-octadienal
5392-40-5

X

3
3-Hydroxybutanal
107-89-1

X

1, 2,4
3-Methoxypropylamine
5332-73-0

X

8
3-Phenylprop-2-enal
104-55-2

X

1, 2, 3, 4, 7
4,4-Dimethyloxazolidine
51200-87-4

X

8
4,6-Dimethyl-2-heptanone
19549-80-5

X

8
4-[Abieta-8,ll,13-trien-18-yl(3-oxo-3-phenylpropyl)amino]butan-2-one
hydrochloride
143106-84-7

X

1,4
4-Ethyloct-l-yn-3-ol
5877-42-9

X

1, 2, 3, 4
4-Hydroxy-3-methoxybenzaldehyde
121-33-5

X

3
H-14
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
4-Methoxybenzyl formate
122-91-8

X

3
4-Methoxyphenol
150-76-5

X

4
4-Methyl-2-pentanol
108-11-2

X

1,4
4-Methyl-2-pentanone
108-10-1

X
X
5
4-Nonylphenol
104-40-5

X

8
4-Nonylphenol polyethoxylate
68412-54-4



2, 3,4
5-Chloro-2-methyl-3(2H)-isothiazolone
26172-55-4

X

1, 2,4
Acetaldehyde
75-07-0
X
X
X
1,4
Acetic acid
64-19-7
X
X

1, 2, 3, 4, 5, 6, 7, 8
Acetic acid ethenyl ester, polymer with ethenol
25213-24-5



1,4
Acetic acid, C6-8-branched alkyl esters
90438-79-2

X

4
Acetic acid, hydroxy-, reaction products with triethanolamine
68442-62-6

X

3
Acetic acid, mercapto-, monoammonium salt
5421-46-5

X

2,8
Acetic acid, reaction products with acetophenone, cyclohexylamine,
formaldehyde and methanol
224635-63-6



8
Acetic anhydride
108-24-7

X

1, 2, 3, 4, 7
Acetone
67-64-1
X
X
X
1, 3, 4, 6
Acetonitrile, 2,2',2"-nitrilotris-
7327-60-8

X

1,4
Acetophenone
98-86-2
X
X
X
1
Acetyltriethyl citrate
77-89-4

X

1,4
Acrolein
107-02-8
X
X
X
2
Acrylamide
79-06-1

X
X
1, 2, 3, 4
H-15
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Acrylamide/ sodium acrylate copolymer
25085-02-3



1, 2, 3, 4, 8
Acrylamide-sodium-2-acrylamido-2-methlypropane sulfonate
copolymer
38193-60-1



1, 2, 3, 4
Acrylic acid
79-10-7

X
X
2,4
Acrylic acid, with sodium-2-acrylamido-2-methyl-l-propanesulfonate
and sodium phosphinate
110224-99-2

X

8
Alcohols (C13-C15), ethoxylated
64425-86-1



8
Alcohols, CIO-12, ethoxylated
67254-71-1

X

3
Alcohols, CIO-14, ethoxylated
66455-15-0



3
Alcohols, Cll-14-iso-, C13-rich
68526-86-3

X

3
Alcohols, Cll-14-iso-, C13-rich, butoxylated ethoxylated
228414-35-5



1
Alcohols, Cll-14-iso-, C13-rich, ethoxylated
78330-21-9

X

3, 4,8
Alcohols, C12-13, ethoxylated
66455-14-9

X

4
Alcohols, C12-14, ethoxylated
68439-50-9



2, 3, 4, 8
Alcohols, C12-14, ethoxylated propoxylated
68439-51-0

X

1, 3, 4, 8
Alcohols, C12-14-secondary
126950-60-5

X

1, 3,4
Alcohols, C12-14-secondary, ethoxylated
84133-50-6



3, 4,8
Alcohols, C12-15, ethoxylated
68131-39-5



3,4
Alcohols, C12-16, ethoxylated
68551-12-2

X

3, 4,8
Alcohols, C14-15, ethoxylated
68951-67-7

X

3, 4,8
Alcohols, C6-12, ethoxylated
68439-45-2

X

3, 4,8
Alcohols, C7-9-iso-, C8-rich, ethoxylated
78330-19-5

X

2, 4,8
H-16
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Alcohols, C8-10, ethoxylated propoxylated
68603-25-8



3
Alcohols, C9-11, ethoxylated
68439-46-3

X

3,4
Alcohols, C9-ll-iso-, ClO-rich, ethoxylated
78330-20-8

X

1, 2, 4, 8
Alkanes C10-16-branched and linear
90622-52-9



4
Alkanes, C10-14
93924-07-3



1
Alkanes, C12-14-iso-
68551-19-9

X

2, 4,8
Alkanes, C13-16-iso-
68551-20-2

X

1,4
Alkenes, C>10 .alpha.-
64743-02-8

X

1, 3, 4, 8
Alkenes, C>8
68411-00-7



1
Alkenes, C24-25 alpha-, polymers with maleic anhydride, docosyl esters
68607-07-8



8
Alkyl quaternary ammonium with bentonite
71011-24-0



4
Alkyl* dimethyl ethylbenzyl ammonium chloride *(50%C12, 30%C14,
17%C16, 3%C18)
NOCAS_34320

X

8
Alkyl* dimethyl ethylbenzyl ammonium chloride *(60%C14, 30%C16,
5%C12, 5%C18)
68956-79-6

X

8
Alkylbenzenesulfonate, linear
42615-29-2

X

1, 4,6
Almandite and pyrope garnet
1302-62-1



1,4
alpha-[3.5-dimethyl-l-(2-methylpropyl)hexyl]-omega-hydroxy-poly(oxy-
1,2-ethandiyl)
60828-78-6



3
alpha-Amylase
9000-90-2



4
alpha-Lactose monohydrate
5989-81-1

X

8
alpha-Terpineol
98-55-5

X

3
Alumina
1344-28-1



1, 2,4
H-17
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Aluminatesilicate
1327-36-2



8
Aluminum
7429-90-5
X

X
1, 4,6
Aluminum calcium oxide (AI2Ca04)
12042-68-1



2
Aluminum chloride
7446-70-0



1,4
Aluminum chloride hydroxide sulfate
39290-78-3



8
Aluminum chloride, basic
1327-41-9



3,4
Aluminum oxide (AI203)
90669-62-8



8
Aluminum oxide silicate
12068-56-3



1, 2,4
Aluminum silicate
12141-46-7



1, 2,4
Aluminum sulfate
10043-01-3



1,4
Amaranth
915-67-3

X
X
4
Amides, C8-18 and C18-unsatd., N,N-bis(hydroxyethyl)
68155-07-7



3
Amides, coco, N-[3-(dimethylamino)propyl]
68140-01-2



1,4
Amides, coco, N-[3-(dimethylamino)propyl], alkylation products with
chloroacetic acid, sodium salts
70851-07-9



1,4
Amides, coco, N-[3-(dimethylamino)propyl], alkylation products with
sodium 3-chloro-2-hydroxypropanesulfonate
70851-08-0



8
Amides, coco, N-[3-(dimethylamino)propyl], N-oxides
68155-09-9



1, 3,4
Amides, from C16-22 fatty acids and diethylenetriamine
68876-82-4



3
Amides, tall-oil fatty, N,N-bis(hydroxyethyl)
68155-20-4



3,4
Amides, tallow, N-[3-(dimethylamino)propyl],N-oxides
68647-77-8



1,4
Amine oxides, cocoalkyldimethyl
61788-90-7



8
H-18
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Amines, C14-18; C16-18-unsaturated, alkyl, ethoxylated
68155-39-5



l
Amines, C8-18 and C18-unsatd. alkyl
68037-94-5



5
Amines, coco alkyl
61788-46-3



4
Amines, coco alkyl, acetates
61790-57-6



1,4
Amines, coco alkyl, ethoxylated
61791-14-8



8
Amines, coco alkyldimethyl
61788-93-0



8
Amines, dicoco alkyl
61789-76-2



8
Amines, dicoco alkylmethyl
61788-62-3



8
Amines, ditallow alkyl, acetates
71011-03-5



8
Amines, hydrogenated tallow alkyl, acetates
61790-59-8



4
Amines, N-tallow alkyltrimethylenedi-, ethoxylated
61790-85-0



8
Amines, polyethylenepoly-, ethoxylated, phosphonomethylated
68966-36-9



1,4
Amines, polyethylenepoly-, reaction products with benzyl chloride
68603-67-8



1
Amines, tallow alkyl
61790-33-8



8
Amines, tallow alkyl, ethoxylated, acetates (salts)
68551-33-7



1, 3,4
Amines, tallow alkyl, ethoxylated, phosphates
68308-48-5



4
Aminotrimethylene phosphonic acid
6419-19-8

X

1, 4,8
Ammonia
7664-41-7
X


1, 2, 3, 4, 7
Ammonium (lauryloxypolyethoxy)ethyl sulfate
32612-48-9



4
Ammonium acetate
631-61-8

X

1, 3, 4, 5, 8
Ammonium acrylate
10604-69-0

X

8
Ammonium acrylate-acrylamide polymer
26100-47-0



2, 4,8
H-19
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Ammonium bisulfate
7803-63-6



2
Ammonium bisulfite
10192-30-0



1, 2, 3, 4, 1
Ammonium chloride
12125-02-9



1, 2, 3, 4, 5, 6, 8
Ammonium citrate (1:1)
7632-50-0

X

3
Ammonium citrate (2:1)
3012-65-5

X

8
Ammonium dodecyl sulfate
2235-54-3

X

1
Ammonium fluoride
12125-01-8



1,4
Ammonium hydrogen carbonate
1066-33-7

X

1,4
Ammonium hydrogen difluoride
1341-49-7



1, 3, 4, 7
Ammonium hydrogen phosphonate
13446-12-3



4
Ammonium hydroxide
1336-21-6



1, 3,4
Ammonium lactate
515-98-0

X

8
Ammonium ligninsulfonate
8061-53-8



2
Ammonium nitrate
6484-52-2



1, 2,3
Ammonium phosphate
7722-76-1


X
1,4
Ammonium sulfate
7783-20-2



1, 2, 3, 4, 6
Ammonium thiosulfate
7783-18-8



8
Amorphous silica
99439-28-8



1,7
Anethole
104-46-1

X

3
Aniline
62-53-3

X
X
2,4
Antimony pentoxide
1314-60-9



1,4
Antimony trichloride
10025-91-9


X
1,4
H-20
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Antimony trioxide
1309-64-4


X
8
Arsenic
7440-38-2
X

X
4
Ashes, residues
68131-74-8



4
Asphalt, sulfonated, sodium salt
68201-32-1



2
Attapulgite
12174-11-7


X
2,3
Aziridine, polymer with 2-methyloxirane
31974-35-3



4,8
Barium sulfate
7727-43-7



1, 2,4
Bauxite
1318-16-7



1, 2,4
Benactyzine hydrochloride
57-37-4

X

8
Bentonite
1302-78-9



1, 2, 4, 6
Bentonite, benzyl(hydrogenated tallow alkyl) dimethylammonium
stearate complex
121888-68-4



3,4
Benzamorf
12068-08-5

X

1,4
Benzene
71-43-2
X
X
X
1, 3,4
Benzene, l,l'-oxybis-, sec-hexyl derivs., sulfonated, sodium salts
147732-60-3



8
Benzene, l,l'-oxybis-, tetrapropylene derivs., sulfonated
119345-03-8



8
Benzene, l,l'-oxybis-, tetrapropylene derivs., sulfonated, sodium salts
119345-04-9



3, 4,8
Benzene, C10-16-alkyl derivs.
68648-87-3

X

1
Benzene, ethenyl-, polymer with 2-methyl-l,3-butadiene, hydrogenated
68648-89-5



8
Benzenemethanaminium, N,N-dimethyl-N-(2-((l-oxo-2-propen-l-
yl)oxy)ethyl)-, chloride (1:1), polymer with 2-propenamide
74153-51-8



3
Benzenesulfonic acid
98-11-3

X

2
H-21
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Benzenesulfonic acid, (1-methylethyl)-,
37953-05-2

X

4
Benzenesulfonic acid, (1-methylethyl)-, ammonium salt
37475-88-0

X

3,4
Benzenesulfonic acid, (1-methylethyl)-, sodium salt
28348-53-0

X

8
Benzenesulfonic acid, C10-16-alkyl derivs.
68584-22-5


X
1,4
Benzenesulfonic acid, C10-16-alkyl derivs., compds. with
cyclohexylamine
255043-08-4

X

1
Benzenesulfonic acid, C10-16-alkyl derivs., compds. with
triethanolamine
68584-25-8

X

8
Benzenesulfonic acid, C10-16-alkyl derivs., potassium salts
68584-27-0

X

1, 4,8
Benzenesulfonic acid, dodecyl-, branched, compds. with 2-propanamine
90218-35-2

X

4
Benzenesulfonic acid, mono-C10-16 alkyl derivs., compds. with 2-
propanamine
68648-81-7



1,4
Benzenesulfonic acid, mono-C10-16-alkyl derivs., sodium salts
68081-81-2

X

8
Benzoic acid
65-85-0

X
X
1, 4,7
Benzyl chloride
100-44-7
X
X
X
1, 2, 4, 8
Benzyldimethyldodecylammonium chloride
139-07-1

X

2,8
Benzylhexadecyldimethylammonium chloride
122-18-9

X

8
Benzyltrimethylammonium chloride
56-93-9

X

8
Bicine
150-25-4

X

1,4
Bio-Perge
55965-84-9



8
Bis(l-methylethyl)naphthalenesulfonic acid, cyclohexylamine salt
68425-61-6

X

1
Bis(2-chloroethyl) ether
111-44-4
X
X
X
8
Bisphenol A
80-05-7
X
X
X
4
H-22
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Bisphenol A/ Epichlorohydrin resin
25068-38-6



1, 2,4
Bisphenol A/ Novolac epoxy resin
28906-96-9



1,4
Blast furnace slag
65996-69-2



2,3
Borax
1303-96-4



1, 2, 3, 4, 6
Boric acid
10043-35-3



1, 2, 3, 4, 6, 7
Boric acid (H3BO3), compd. with 2-aminoethanol (l:x)d
26038-87-9



8
Boric oxide
1303-86-2



1, 2, 3, 4
Boron
7440-42-8
X

X
8
Boron potassium oxide (B4K207)
1332-77-0



8
Boron potassium oxide (B4K207), tetrahydrate
12045-78-2



8
Boron potassium oxide (B5K08)
11128-29-3



1
Boron sodium oxide
1330-43-4



1, 2,4
Boron sodium oxide pentahydrate
12179-04-3



8
Bronopol
52-51-7

X

1, 2, 3, 4, 6
Butane
106-97-8

X

2,5
Butanedioic acid, sulfo-, l,4-bis(l,3-dimethylbutyl) ester, sodium salt
2373-38-8

X

1
Butene
25167-67-3

X

8
Butyl glycidyl ether
2426-08-6

X

1,4
Butyl lactate
138-22-7

X

1,4
Butyryl trihexyl citrate
82469-79-2

X

8
C.I. Acid Red 1
3734-67-6

X

4
C.I. Acid violet 12, disodium salt
6625-46-3

X

4
H-23
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
C.I. Pigment Red 5
6410-41-9

X

4
C.I. Solvent Red 26
4477-79-6

X

4
CIO-16-Alkyldimethylamines oxides
70592-80-2

X

4
C10-C16 ethoxylated alcohol
68002-97-1

X

1, 2, 3, 4, 8
Cll-15-Secondary alcohols ethoxylated
68131-40-8



1, 2,8
C12-14 tert-alkyl ethoxylated amines
73138-27-9

X

3
C8-10 Alcohols
85566-12-7



8
Calcined bauxite
66402-68-4



2,8
Calcium aluminate
12042-78-3



2
Calcium bromide
7789-41-5



4
Calcium carbide (CaC2)
75-20-7



8
Calcium chloride
10043-52-4



1, 2, 3, 4, 1
Calcium dichloride dihydrate
10035-04-8



1,4
Calcium dodecylbenzene sulfonate
26264-06-2

X

4
Calcium fluoride
7789-75-5



1,4
Calcium hydroxide
1305-62-0



1, 2, 3, 4
Calcium hypochlorite
7778-54-3



1, 2,4
Calcium magnesium hydroxide oxide
58398-71-3



4
Calcium oxide
1305-78-8



1, 2, 4, 7
Calcium peroxide
1305-79-9



1, 3, 4, 8
Calcium sulfate
7778-18-9



1, 2,4
Calcium sulfate dihydrate
10101-41-4



2
H-24
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Camphor
76-22-2

X

3
Canola oil
120962-03-0



8
Carbon black
1333-86-4


X
1, 2,4
Carbon dioxide
124-38-9
X
X

1, 3, 4, 6
Carbonic acid calcium salt (1:1)
471-34-1



1, 2,4
Carbonic acid, dipotassium salt
584-08-7

X

1, 2, 3, 4, 8
Carboxymethyl cellulose
9000-11-7



8
Carboxymethyl guar gum, sodium salt
39346-76-4



1, 2,4
Castor oil
8001-79-4



8
Cedarwood oil
8000-27-9



3
Cellophane
9005-81-6



1,4
Cellulose
9004-34-6



1, 2, 3, 4
Chloride
16887-00-6
X


4,8
Chlorine
7782-50-5
X

X
2
Chlorine dioxide
10049-04-4


X
1, 2, 3, 4, 8
Chlorobenzene
108-90-7
X
X
X
8
Chloromethane
74-87-3
X
X
X
8
Choline bicarbonate
78-73-9

X

3, 8
Choline chloride
67-48-1

X

1, 3, 4, 7, 8
Chromium (III)
16065-83-1
X

X
2,6
Chromium (VI)
18540-29-9
X

X
6
Chromium acetate, basic
39430-51-8



2
H-25
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Chromium(lll) acetate
1066-30-4



1,2
Citric acid
77-92-9

X

1, 2, 3, 4, 7
Citronella oil
8000-29-1



3
Citronellol
106-22-9

X

3
Citrus extract
94266-47-4



1, 3, 4, 8
Coal, granular
50815-10-6



1, 2,4
Cobalt(ll) acetate
71-48-7



1,4
Coco-betaine
68424-94-2



3
Coconut oil
8001-31-8



8
Coconut oil acid/Diethanolamine condensate (2:1)
68603-42-9


X
1
Coconut trimethylammonium chloride
61789-18-2

X

1,8
Copper
7440-50-8
X

X
1,4
Copper sulfate
7758-98-7



1, 4,8
Copper(l) chloride
7758-89-6



1,4
Copper(l) iodide
7681-65-4


X
1, 2, 4, 6
Copper(ll) chloride
7447-39-4



1, 3,4
Copper(ll) sulfate, pentahydrate
7758-99-8



8
Corn flour
68525-86-0



4
Corn sugar gum
11138-66-2



1, 2,4
Corundum (Aluminum oxide)
1302-74-5



4,8
Cottonseed, flour
68308-87-2



2,4
Coumarin
91-64-5

X
X
3
H-26
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Cremophor(R) EL
61791-12-6



1,3
Cristobalite
14464-46-1



1, 2,4
Crystalline silica, tridymite
15468-32-3



1, 2,4
Cumene
98-82-8
X
X
X
1, 2, 3, 4
Cupric chloride dihydrate
10125-13-0



1, 4,7
Cyclohexane
110-82-7

X

1,7
Cyclohexanol
108-93-0

X

8
Cyclohexanone
108-94-1

X
X
1,4
Cyclohexylamine sulfate
19834-02-7

X

8
D&C Red 28
18472-87-2

X

4
D&C Red No. 33
3567-66-6

X

8
Daidzein
486-66-8

X

8
Dapsone
80-08-0

X
X
1,4
Dazomet
533-74-4

X

1, 2, 3, 4, 7, 8
Decamethylcyclopentasiloxane
541-02-6



8
Decyldimethylamine
1120-24-7

X

3,4
Deuterium oxide
7789-20-0



8
D-Glucitol
50-70-4

X

1, 3,4
D-Gluconic acid
526-95-4

X

1,4
D-Glucopyranoside, methyl
3149-68-6

X

2
D-Glucose
50-99-7

X

1,4
Di(2-ethylhexyl) phthalate
117-81-7
X
X
X
1,4
H-27
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Diammonium peroxydisulfate
7727-54-0



1, 2, 3, 4, 6,7, 8
Diatomaceous earth
68855-54-9



2,4
Diatomaceous earth, calcined
91053-39-3



1, 2,4
Dibromoacetonitrile
3252-43-5
X
X
X
1, 2, 3, 4, 8
Dicalcium silicate
10034-77-2



1, 2,4
Dichloromethane
75-09-2
X
X
X
8
Didecyldimethylammonium chloride
7173-51-5

X
X
1, 2, 4, 8
Diethanolamine
111-42-2

X
X
1, 2, 3, 4, 6
Diethylbenzene
25340-17-4

X

1, 3,4
Diethylene glycol
111-46-6

X

1, 2, 3, 4, 7
Diethylene glycol monomethyl ether
111-77-3

X

1, 2,4
Diethylenetriamine
111-40-0

X

1, 2, 4, 5
Diethylenetriamine reaction product with fatty acid dimers
68647-57-4



2
Diisobutyl ketone
108-83-8

X

8
Diisopropanolamine
110-97-4

X

8
Diisopropylnaphthalene
38640-62-9

X

3,4
Dimethyl adipate
627-93-0

X

8
Dimethyl glutarate
1119-40-0

X

1,4
Dimethyl polysiloxane
63148-62-9



1, 2,4
Dimethyl succinate
106-65-0

X

8
Dimethylaminoethanol
108-01-0

X

2,4
Dimethyldiallylammonium chloride
7398-69-8

X

3,4
H-28
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Diphenyl oxide
101-84-8

X

3
Dipotassium monohydrogen phosphate
7758-11-4



5
Dipropylene glycol
25265-71-8

X

1, 3,4
Di-sec-butylphenol
31291-60-8

X

1
Disodium dodecyl(sulphonatophenoxy)benzenesulphonate
28519-02-0

X

1
Disodium ethylenediaminediacetate
38011-25-5

X

1,4
Disodium ethylenediaminetetraacetate dihydrate
6381-92-6

X

1
Disodium octaborate
12008-41-2



4,8
Disodium octaborate tetrahydrate
12280-03-4



1,4
Disodium sulfide
1313-82-2



8
Distillates, petroleum, catalytic reformer fractionator residue, low-
boiling
68477-31-6



1,4
Distillates, petroleum, heavy arom.
67891-79-6



1,4
Distillates, petroleum, hydrodesulfurized light catalytic cracked
68333-25-5



1
Distillates, petroleum, hydrodesulfurized middle
64742-80-9



1
Distillates, petroleum, hydrotreated heavy naphthenic
64742-52-5



1, 2, 3, 4
Distillates, petroleum, hydrotreated heavy paraffinic
64742-54-7



1, 2,4
Distillates, petroleum, hydrotreated light
64742-47-8



1, 2, 3, 4, 5, 7, 8
Distillates, petroleum, hydrotreated light naphthenic
64742-53-6



1, 2,8
Distillates, petroleum, hydrotreated light paraffinic
64742-55-8



8
Distillates, petroleum, hydrotreated middle
64742-46-7



1, 2, 3, 4, 8
Distillates, petroleum, light catalytic cracked
64741-59-9



1,4
H-29
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Distillates, petroleum, light hydrocracked
64741-77-1



3
Distillates, petroleum, solvent-dewaxed heavy paraffinic
64742-65-0



1
Distillates, petroleum, solvent-refined heavy naphthenic
64741-96-4



1,4
Distillates, petroleum, steam-cracked
64742-91-2



1,4
Distillates, petroleum, straight-run middle
64741-44-2



1, 2,4
Distillates, petroleum, sweetened middle
64741-86-2



1,4
Ditallow alkyl ethoxylated amines
71011-04-6



3
D-Lactic acid
10326-41-7

X

1,4
D-Limonene
5989-27-5
X
X
X
1, 3, 4, 5, 7, 8
Docusate sodium
577-11-7

X

1
Dodecamethylcyclohexasiloxane
540-97-6



8
Dodecane
112-40-3
X
X

8
Dodecylbenzene
123-01-3

X

3,4
Dodecylbenzenesulfonic acid
27176-87-0

X
X
2, 3, 4, 8
Dodecylbenzenesulfonic acid, monoethanolamine salt
26836-07-7

X

1,4
Edifas B
9004-32-4



2, 3,4
EDTA, copper salt
12276-01-6



1, 5,6
Endo-l,4-.beta.-mannanase
37288-54-3



3, 8
Epichlorohydrin
106-89-8

X
X
1, 4,8
Epoxy resin
25085-99-8



1, 4,8
Erucic amidopropyl dimethyl betaine
149879-98-1



1,3
Ethanaminium, N,N,N-trimethyl-2-[(l-oxo-2-propenyl)oxy]-, chloride
44992-01-0

X

3
H-30
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Ethanaminium, N,N,N-trimethyl-2-[(l-oxo-2-propenyl)oxy]-,chloride,
polymer with 2-propenamide
69418-26-4



1, 3,4
Ethanaminium, N,N,N-trimethyl-2-[(2-methyl-l-oxo-2-propen-l-yl)oxy]-,
chloride (1:1), polymer with 2-propenamide
35429-19-7



8
Ethanaminium, N,N,N-trimethyl-2-[(2-methyl-l-oxo-2-propenyl)oxy]-,
methyl sulfate, homopolymer
27103-90-8



8
Ethane
74-84-0

X

2,5
Ethanol
64-17-5
X
X
X
1, 2, 3, 4, 5, 6, 8
Ethanol, 2,2',2"-nitrilotris-, tris(dihydrogen phosphate) (ester), sodium
salt
68171-29-9

X

4
Ethanol, 2,2'-iminobis-, N-coco alkyl derivs., N-oxides
61791-47-7



1
Ethanol, 2,2'-iminobis-, N-tallow alkyl derivs.
61791-44-4



1
Ethanol, 2,2'-oxybis-, reaction products with ammonia, morpholine
derivs. residues
68909-77-3



4,8
Ethanol, 2,2-oxybis-, reaction products with ammonia, morpholine
derivs. residues, acetates (salts)
68877-16-7



4
Ethanol, 2,2-oxybis-, reaction products with ammonia, morpholine
derivs. residues, reaction products with sulfur dioxide
102424-23-7



4
Ethanol, 2-[2-[2-(tridecyloxy)ethoxy]ethoxy]-, hydrogen sulfate, sodium
salt
25446-78-0

X

1,4
Ethanol, 2-amino-, polymer with formaldehyde
34411-42-2



4
Ethanol, 2-amino-, reaction products with ammonia, by-products from,
phosphonomethylated
68649-44-5



4
Ethanolamined
141-43-5

X

1, 2, 3, 4, 6, 8
Ethoxylated dodecyl alcohol
9002-92-0

X

4
H-31
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Ethoxylated hydrogenated tallow alkylamines
61790-82-7



4
Ethoxylated, propoxylated trimethylolpropane
52624-57-4



3
Ethyl acetate
141-78-6

X
X
1, 4,7
Ethyl acetoacetate
141-97-9

X

1,4
Ethyl benzoate
93-89-0

X

3
Ethyl lactate
97-64-3

X

3
Ethyl salicylate
118-61-6

X

3
Ethylbenzene
100-41-4
X
X
X
1, 2, 3, 4, 7
Ethylcellulose
9004-57-3



2
Ethylene
74-85-1

X
X
8
Ethylene glycol
107-21-1
X
X
X
1, 2, 3, 4, 6, 7, 8
Ethylene oxide
75-21-8

X
X
1, 2, 3, 4
Ethylenediamine
107-15-3

X
X
2,4
Ethylenediaminetetraacetic acid
60-00-4

X

1, 2,4
Ethylenediaminetetraacetic acid tetrasodium salt
64-02-8

X

1, 2, 3, 4
Ethylenediaminetetraacetic acid, diammonium copper salt
67989-88-2



4
Ethylenediaminetetraacetic acid, disodium salt
139-33-3

X

1, 3, 4, 8
Ethyne
74-86-2

X

7
Fats and Glyceridic oils, vegetable, hydrogenated
68334-28-1



8
Fatty acid, tall oil, hexa esters with sorbitol, ethoxylated
61790-90-7



1,4
Fatty acids, C 8-18 and C18-unsaturated compounds with
diethanolamine
68604-35-3



3
H-32
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Fatty acids, C14-18 and C16-18-unsatd., distn. residues
70321-73-2



2
Fatty acids, C18-unsatd., dimers
61788-89-4

X

2
Fatty acids, C18-unsatd., dimers, compds. with ethoxylated tall-oil fatty
acid-polyethylenepolyamine reaction products
68132-59-2



8
Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated
68308-89-4



8
Fatty acids, coco, ethoxylated
61791-29-5



3
Fatty acids, coco, reaction products with diethylenetriamine and soya
fatty acids, ethoxylated, chloromethane-quaternized
68604-75-1



8
Fatty acids, coco, reaction products with ethanolamine, ethoxylated
61791-08-0



3
Fatty acids, tall oil, reaction products with acetophenone, formaldehyde
and thiourea
68188-40-9



3
Fatty acids, tall-oil
61790-12-3



1, 2, 3, 4
Fatty acids, tall-oil, reaction products with diethylenetriamine
61790-69-0



1,4
Fatty acids, tall-oil, reaction products with diethylenetriamine, maleic
anhydride, tetraethylenepentamine and triethylenetetramine
68990-47-6



8
Fatty acids, tallow, sodium salts
8052-48-0



1,3
Fatty acids, vegetable-oil, reaction products with diethylenetriamine
68153-72-0



3
Fatty quaternary ammonium chloride
61789-68-2



1,4
FD&C Blue no. 1
3844-45-9

X
X
1,4
FD&C Yellow 5
1934-21-0

X

8
FD&C Yellow 6
2783-94-0

X
X
8
Ferric chloride
7705-08-0



1, 3,4
Ferric sulfate
10028-22-5



1,4
H-33
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Ferrous sulfate monohydrate
17375-41-6



2
Ferumoxytol
1309-38-2



8
Fiberglass
65997-17-3



2, 3,4
Formaldehyde
50-00-0

X
X
1, 2, 3, 4
Formaldehyde polymer with 4,l,l-(dimethylethyl)phenol and
methyloxirane
29316-47-0



3
Formaldehyde polymer with methyl oxirane, 4-nonylphenol and oxirane
63428-92-2



4,8
Formaldehyde, polymer with 4-(l,l-dimethylethyl)phenol, 2-
methyloxirane and oxirane
30704-64-4



1, 2, 4, 8
Formaldehyde, polymer with 4-(l,l-dimethylethyl)phenol, 2-
methyloxirane, 4-nonylphenol and oxirane
68188-99-8



8
Formaldehyde, polymer with 4-nonylphenol and oxirane
30846-35-6



1,4
Formaldehyde, polymer with 4-nonylphenol and phenol
40404-63-5



8
Formaldehyde, polymer with ammonia and phenol
35297-54-2



1,4
Formaldehyde, polymer with bisphenol A
25085-75-0



4
Formaldehyde, polymer with Nl-(2-aminoethyl)-l,2-ethanediamine,
benzylated
70750-07-1



8
Formaldehyde, polymer with nonylphenol and oxirane
55845-06-2



4
Formaldehyde, polymers with branched 4-nonylphenol, oxirane and 2-
methyloxirane
153795-76-7



1,3
Formaldehyde/amine
NOCAS_51232



1, 2, 3, 4
Formamide
75-12-7

X

1, 2, 3, 4
Formic acid
64-18-6
X
X
X
1, 2, 3, 4, 6, 7
Formic acid, potassium salt
590-29-4

X

1, 3,4
H-34
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Frits, chemicals
65997-18-4



8
Fuel oil, no. 2
68476-30-2



1,2
Fuels, diesel
68334-30-5



2
Fuels, diesel, no. 2
68476-34-6



2, 4,8
Fuller's earth
8031-18-3



2
Fumaric acid
110-17-8

X

1, 2, 3, 4, 6
Fumes, silica
69012-64-2



8
Furfural
98-01-1

X
X
1,4
Furfuryl alcohol
98-00-0

X

1,4
Galantamine hydrobromide
69353-21-5

X

8
Gas oils, petroleum, straight-run
64741-43-1



1,4
Gelatin
9000-70-8



1,4
Gilsonite
12002-43-6



1, 2,4
Gluconic acid
133-42-6

X

7
Glutaraldehyde
111-30-8
X
X

1, 2, 3, 4, 7
Glycerides, C14-18 and C16-18-unsatd. mono- and di-
67701-32-0



8
Glycerol
56-81-5

X

1, 2, 3, 4, 5
Glycine, N-(carboxymethyl)-N-(2-hydroxyethyl)-, disodium salt
135-37-5

X

1
Glycine, N-(hydroxymethyl)-, monosodium salt
70161-44-3

X

8
Glycine, N,N-bis(carboxymethyl)-, trisodium salt
5064-31-3

X

1, 2, 3, 4
Glycine, N-[2-[bis(carboxymethyl)amino]ethyl]-N-(2-hydroxyethyl)-,
trisodium salt
139-89-9

X

1
H-35
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Glycolic acid
79-14-1
X
X

1, 3,4
Glycolic acid sodium salt
2836-32-0

X

1, 3,4
Glyoxal
107-22-2

X
X
1, 2,4
Glyoxylic acid
298-12-4

X

1
Goethite (Fe(OH)O)
1310-14-1



8
Guar gum
9000-30-0



1, 2, 3, 4, 7, 8
Guar gum, carboxymethyl 2-hydroxypropyl ether, sodium salt
68130-15-4



1, 2, 3, 4, 7
Gypsum (Ca(S04).2H20)
13397-24-5



2,4
Hematite
1317-60-8


X
1, 2,4
Hemicellulase
9012-54-8



1, 2, 3, 4, 5
Hemicellulase enzyme concentrate
9025-56-3



3,4
Heptane
142-82-5
X
X

1,2
Heptene, hydroformylation products, high-boiling
68526-88-5



1,4
Hexadecyltrimethylammonium bromide
57-09-0

X

1
Hexane
110-54-3
X
X
X
5
Hexanedioic acid
124-04-9

X
X
1, 2, 4, 6
Humic acids, commercial grade
1415-93-6



2
Hydrazine
302-01-2
X

X
8
Hydrocarbons, terpene processing by-products
68956-56-9



1, 3,4
Hydrochloric acid
7647-01-0
X

X
1, 2, 3, 4, 5, 6, 7, 8
Hydrogen fluoride
7664-39-3



1, 2,4
Hydrogen peroxide
7722-84-1


X
1, 3,4
H-36
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Hydrogen sulfide
7783-06-4



1,2
Hydroxyethylcellulose
9004-62-0



1, 2, 3, 4
Hydroxylamine hydrochloride
5470-11-1



1, 3,4
Hydroxylamine sulfate (2:1)
10039-54-0



4
Hydroxypropyl cellulose
9004-64-2



2,4
Hydroxypropyl guar gum
39421-75-5



1, 3, 4, 5, 6, 8
Hydroxyvalerenic acid
1619-16-5

X

8
Hypochlorous acid
7790-92-3



8
lllite
12173-60-3



8
llmenite (FeTi03), conc.
98072-94-7



8
Indole
120-72-9

X

2
Inulin, carboxymethyl ether, sodium salt
430439-54-6



1,4
Iridium oxide
12030-49-8



8
Iron
7439-89-6
X

X
2,4
Iron oxide
1332-37-2



1,4
Iron oxide (Fe304)
1317-61-9



4
Iron(ll) sulfate
7720-78-7



2
Iron(ll) sulfate heptahydrate
7782-63-0



1, 2, 3, 4
Iron(lll) oxide
1309-37-1


X
1, 2,4
Isoascorbic acid
89-65-6

X

1, 3,4
Isobutane
75-28-5

X

2
Isobutene
115-11-7

X

8
H-37
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Isooctanol
26952-21-6

X

1, 4,5
Isopentyl alcohol
123-51-3

X

1,4
Isopropanol
67-63-0
X
X
X
1, 2, 3, 4, 6, 7
Isopropanolamine dodecylbenzene
42504-46-1

X

1, 3,4
Isopropylamine
75-31-0

X

1,4
Isoquinoline
119-65-3
X
X

8
Isoquinoline, reaction products with benzyl chloride and quinoline
68909-80-8

X

3
Isoquinolinium, 2-(phenylmethyl)-, chloride
35674-56-7

X

3
Isotridecanol, ethoxylated
9043-30-5



1, 3, 4, 8
Kaolin
1332-58-7



1, 2,4
Kerosine, petroleum, hydrodesulfurized
64742-81-0



1, 2,4
Kieselguhr
61790-53-2



1, 2,4
Kyanite
1302-76-7



1, 2,4
Lactic acid
50-21-5

X

1, 4,8
Lactose
63-42-3

X

3
Latex 2000 TM
9003-55-8


X
2,4
Lauryl hydroxysultaine
13197-76-7

X

1
Lavandula hybrida abrial herb oil
8022-15-9



3
L-Dilactide
4511-42-6

X

1,4
Lead
7439-92-1
X

X
1,4
Lecithin
8002-43-5



4
L-Glutamic acid
56-86-0

X

8
H-38
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Lignite
129521-66-0



2
Lignosulfuric acid
8062-15-5



2
Ligroine
8032-32-4


X
8
Limestone
1317-65-3



1, 2, 3, 4
Linseed oil
8001-26-1



8
L-Lactic acid
79-33-4

X

1, 4,8
Magnesium carbonate (1:1)
7757-69-9



8
Magnesium carbonate (l:x)
546-93-0



1, 3,4
Magnesium chloride
7786-30-3



1, 2,4
Magnesium chloride hexahydrate
7791-18-6



4
Magnesium hydroxide
1309-42-8



1,4
Magnesium iron silicate
19086-72-7



1,4
Magnesium nitrate
10377-60-3



1, 2,4
Magnesium oxide
1309-48-4



1, 2, 3, 4
Magnesium peroxide
14452-57-4



1,4
Magnesium phosphide
12057-74-8



1
Magnesium silicate
1343-88-0



1,4
Magnesium sulfate
7487-88-9



8
Maleicacid homopolymer
26099-09-2



8
Methanamine-N-methyl polymer with chloromethyl oxirane
25988-97-0



4
Methane
74-82-8

X

2,5
Methanol
67-56-1
X
X
X
1, 2, 3, 4, 5, 6, 7, 8
H-39
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Methenamine
100-97-0

X

1, 2,4
Methoxyacetic acid
625-45-6

X

8
Methyl cellulose
9004-67-5



8
Methyl salicylate
119-36-8

X

1, 2, 3, 4, 7
Methyl vinyl ketone
78-94-4

X

1,4
Methylcyclohexane
108-87-2
X
X

1
Methylene bis(thiocyanate)
6317-18-6

X

2
Methylenebis(5-methyloxazolidine)
66204-44-2

X

2
Methyloxirane polymer with oxirane, mono (nonylphenol) ether,
branched
68891-11-2



3
Mica
12001-26-2



1, 2, 4, 6
Mineral oil - includes paraffin oil
8012-95-1


X
4,8
Mineral spirits
64475-85-0


X
2
Mono- and di- potassium salts of phosphorous acid
13492-26-7



8
Montmorillonite
1318-93-0



2
Morpholine
110-91-8

X
X
1, 2,4
Morpholinium, 4-ethyl-4-hexadecyl-, ethyl sulfate
78-21-7

X

8
MT 6
76-31-3



8
Mullite
1302-93-8



1, 2, 4, 8
N-(2-Acryloyloxyethyl)-N-benzyl-N,N-dimethylammonium chloride
46830-22-2

X

3
N-(3-Chloroallyl)hexaminium chloride
4080-31-3

X

8
H-40
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
N,N,N-Trimethyl-2[l-oxo-2-propenyl]oxy ethanaminimum chloride,
homopolymer
54076-97-0



3
N,N,N-Trimethyl-3-((l-oxooctadecyl)amino)-l-propanaminium methyl
sulfate
19277-88-4

X

1
N,N,N-Trimethyloctadecan-l-aminium chloride
112-03-8

X

1, 3,4
N,N'-Dibutylthiourea
109-46-6

X

1,4
N,N-Dimethyldecylamine oxide
2605-79-0

X

1, 3,4
N,N-Dimethylformamide
68-12-2
X
X
X
1, 2, 4, 5, 8
N,N-Dimethylmethanamine hydrochloride
593-81-7

X

1, 4, 5, 7
N,N-Dimethyl-methanamine-N-oxide
1184-78-7

X

3
N,N-dimethyloctadecylamine hydrochloride
1613-17-8

X

1,4
N,N'-Methylenebisacrylamide
110-26-9

X

1,4
Naphtha, petroleum, heavy catalytic reformed
64741-68-0



1, 2, 3, 4
Naphtha, petroleum, hydrotreated heavy
64742-48-9



1, 2, 3, 4, 8
Naphthalene
91-20-3
X
X
X
1, 2, 3, 4, 5, 7
Naphthalenesulfonic acid, bis(l-methylethyl)-
28757-00-8

X

1, 3,4
Naphthalenesulfonic acid, polymer with formaldehyde, sodium salt
9084-06-4



2
Naphthalenesulphonic acid, bis (l-methylethyl)-methyl derivatives
99811-86-6

X

1
Naphthenic acid ethoxylate
68410-62-8

X

4
Navy fuels JP-5
NOCAS_25704



1, 2, 3, 4, 8
Nickel sulfate
7786-81-4


X
2
Nickel(ll) sulfate hexahydrate
10101-97-0


X
1,4
H-41
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Nitriles, tallow, hydrogenated
61790-29-2



4
Nitrilotriacetamide
4862-18-4

X

1, 4,7
Nitrilotriacetic acid
139-13-9

X
X
1,4
Nitrilotriacetic acid trisodium monohydrate
18662-53-8

X
X
1,4
Nitrogen
7727-37-9



1, 2, 3, 4, 6
N-Methyl-2-pyrrolidone
872-50-4

X
X
1,4
N-Methyldiethanolamine
105-59-9

X

2, 4,8
N-Methylethanolamine
109-83-1

X

4
N-Methyl-N-hydroxyethyl-N-hydroxyethoxyethylamine
68213-98-9

X

4
N-Oleyl diethanolamide
13127-82-7

X

1,4
Nonyl nonoxynol-10
9014-93-1



4
Nonylphenol (mixed)
25154-52-3



1,4
Octamethylcyclotetrasiloxane
556-67-2



8
Octoxynol-9
9036-19-5



1, 2, 3, 4, 8
Oil of eucalyptus
8000-48-4



3
Oil of lemongrass
8007-02-1



3
Oil of rosemary
8000-25-7



3
Oleic acid
112-80-1

X

2,4
Olivine-group minerals
1317-71-1



4
Orange terpenes
8028-48-6



4
Oxirane, 2-methyl-, polymer with oxirane, ether with (chloromethyl)
oxirane polymer with 4,4~-(l-methylidene) bis[phenol]
68036-95-3



8
H-42
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Oxirane, 2-methyl-, polymer with oxirane, mono(2-ethylhexyl) ether
64366-70-7



8
Oxirane, 2-methyl-, polymer with oxirane, monodecyl ether
37251-67-5



8
Oxirane, methyl-, polymer with oxirane, mono-C10-16-alkyl ethers,
phosphates
68649-29-6



1,4
Oxygen
7782-44-7



4
o-Xylene
95-47-6
X
X
X
4
Ozone
10028-15-6



8
Paraffin waxes and Hydrocarbon waxes
8002-74-2



1
Paraformaldehyde
30525-89-4



2
PEG-10 Hydrogenated tallow amine
61791-26-2



1,3
Pentaethylenehexamine
4067-16-7

X

4
Pentane
109-66-0
X
X
X
2,5
Pentyl acetate
628-63-7

X

3
Pentyl butyrate
540-18-1

X

3
Peracetic acid
79-21-0

X

8
Perboric acid, sodium salt, monohydrate
10332-33-9



1,8
Perlite
93763-70-3



4
Petrolatum, petroleum, oxidized
64743-01-7



3
Petroleum
8002-05-9


X
1,2
Petroleum distillate hydrotreated light
6742-47-8



8
Phenanthrene
85-01-8
X
X
X
6
Phenol
108-95-2
X
X
X
1, 2,4
H-43
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Phenol, 4,4'-(l-methylethylidene)bis-, polymer with 2-
(chloromethyl)oxirane, 2-methyloxirane and oxirane
68123-18-2



8
Phenol-formaldehyde resin
9003-35-4



1, 2, 4, 7
Phosphine
7803-51-2


X
1,4
Phosphonic acid
13598-36-2



1,4
Phosphonic acid (dimethylamino(methylene))
29712-30-9

X

1
Phosphonic acid, (((2-[(2-
hydroxyethyl)(phosphonomethyl)amino)ethyl)imino]bis(methylene))bis-
, compd. with 2-aminoethanol
129828-36-0

X

1
Phosphonic acid, (l-hydroxyethylidene)bis-, potassium salt
67953-76-8

X

4
Phosphonic acid, (l-hydroxyethylidene)bis-, tetrasodium salt
3794-83-0

X

1,4
Phosphonic acid, [[(phosphonomethyl)imino]bis[2,l-
ethanediylnitrilobis(methylene)]]tetrakis-
15827-60-8

X

1, 2,4
Phosphonic acid, [[(phosphonomethyl)imino]bis[2,l-
ethanediylnitrilobis(methylene)]]tetrakis-, ammonium salt (l:x)
70714-66-8

X

3
Phosphonic acid, [[(phosphonomethyl)imino]bis[2,l-
ethanediylnitrilobis(methylene)]]tetrakis-, sodium salt
22042-96-2

X

3
Phosphonic acid, [[(phosphonomethyl)imino]bis[6,l-
hexanediylnitrilobis(methylene)]]tetrakis-
34690-00-1

X

1, 4,8
Phosphonic acid, [[(phosphonomethyl)imino]bis[6,l-
hexanediylnitrilobis(methylene)]]tetrakis-, sodium salt (l:x)
35657-77-3



8
Phosphoric acid
7664-38-2


X
1, 2,4
Phosphoric acid, aluminium sodium salt
7785-88-8


X
1,2
Phosphoric acid, ammonium salt (l:x)
10124-31-9



8
Phosphoric acid, ammonium salt (1:3)
10361-65-6



8
H-44
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Phosphoric acid, diammonium salt
7783-28-0


X
2
Phosphoric acid, mixed decyl and Et and octyl esters
68412-60-2



1
Phosphorous acid
10294-56-1



1
Phthalic anhydride
85-44-9

X
X
1,4
Pine oils
8002-09-3



1, 2,4
Pluronic F-127
9003-11-6



1, 3, 4, 8
Policapram (Nylon 6)
25038-54-4


X
1,4
Poly (acrylamide-co-acrylic acid), partial sodium salt
62649-23-4



3,4
Poly(acrylamide-co-acrylic acid)
9003-06-9



4,8
Poly(lactide)
26680-10-4



1
Poly(oxy-l,2-ethanediyl), ,alpha.-(nonylphenyl)-.omega.-hydroxy-,
phosphate
51811-79-1



1,4
Poly(oxy-l,2-ethanediyl), ,alpha.-(octylphenyl)-.omega.-hydroxy-,
branched
68987-90-6

X

1,4
Poly(oxy-l,2-ethanediyl),.alpha.,.alpha.'-[[(9Z)-9-octadecenylimino]di-
2,l-ethanediyl]bis[.omega.-hydroxy-
26635-93-8



1,4
Poly(oxy-l,2-ethanediyl), .alpha.-[(9Z)-l-oxo-9-octadecenyl]-. omega.-
hydroxy-
9004-96-0



8
Poly(oxy-l,2-ethanediyl), .alpha.-hydro-.omega.-hydroxy-, mono-ClO-
14-alkyl ethers, phosphates
68585-36-4



8
Poly(oxy-l,2-ethanediyl), .alpha.-hydro-.omega.-hydroxy-, mono-C8-10-
alkyl ethers, phosphates
68130-47-2



8
Poly(oxy-l,2-ethanediyl), .alpha.-isodecyl-. omega.-hydroxy-
61827-42-7



8
H-45
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Poly(oxy-l,2-ethanediyl), .alpha.-sulfo-.omega.-hydroxy-, C10-16-alkyl
ethers, sodium salts
68585-34-2



8
Poly(oxy-l,2-ethanediyl), .alpha.-sulfo-.omega.-hydroxy-, C12-14-alkyl
ethers, sodium salts
68891-38-3



1,4
Poly(oxy-l,2-ethanediyl), alpha-(2,3,4,5-tetramethylnonyl)-omega-
hydroxy
68015-67-8



1
Poly(oxy-l,2-ethanediyl), alpha-(nonylphenyl)-omega-hydroxy-
,branched, phosphates
68412-53-3



1
Poly(oxy-l,2-ethanediyl), alpha-hexyl-omega-hydroxy
31726-34-8



3, 8
Poly(oxy-l,2-ethanediyl), alpha-hydro-omega-hydroxy-, (9Z)-9-
octadecenoate
56449-46-8



3
Poly(oxy-l,2-ethanediyl), alpha-hydro-omega-hydroxy-, ether with
alpha-fluoro-omega-(2-hydroxyethyl)poly(difluoromethylene) (1:1)
65545-80-4



1
Poly(oxy-l,2-ethanediyl), alpha-hydro-omega-hydroxy-, ether with D-
glucitol (2:1), tetra-(9Z)-9-octadecenoate
61723-83-9



8
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-(decyloxy)-, ammonium
salt (1:1)
52286-19-8



4
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-(hexyloxy)-, ammonium
salt (1:1)
63428-86-4



1, 3,4
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-(hexyloxy)-, C6-10-alkyl
ethers, ammonium salts
68037-05-8



3,4
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-(nonylphenoxy)-
9081-17-8



4
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-(octyloxy)-, ammonium
salt (1:1)
52286-18-7



4
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-hydroxy-, C10-12-alkyl
ethers, ammonium salts
68890-88-0



8
H-46
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Poly(oxy-l,2-ethanediyl), alpha-tridecyl-omega-hydroxy-
24938-91-8



1, 3,4
Poly(oxy-l,2-ethanediyl), alpha-undecyl-omega-hydroxy-, branched and
linear
127036-24-2



1
Poly-(oxy-l,2-ethanediyl)-alpha-undecyl-omega-hydroxy
34398-01-1



1, 3, 4, 8
Poly(oxy-l,2-ethanediyl)-nonylphenyl-hydroxy branched
127087-87-0



1, 2, 3, 4
Poly(sodium-p-styrenesulfonate)
25704-18-1



1,4
Poly(tetrafluoroethylene)
9002-84-0


X
8
Poly[imino(l,6-dioxo-l,6-hexanediyl)imino-l,6-hexanediyl]
32131-17-2



2
Polyacrylamide
9003-05-8



1, 2, 4, 6
Polyacrylate/ polyacrylamide blend
NOCAS_51256



2
Polyacrylic acid, sodium bisulfite terminated
66019-18-9



3
Polyethylene glycol
25322-68-3



1, 2, 3, 4, 7, 8
Polyethylene glycol (9Z)-9-octadecenyl ether
9004-98-2



8
Polyethylene glycol ester with tall oil fatty acid
68187-85-9



1
Polyethylene glycol monobutyl ether
9004-77-7



1,4
Polyethylene glycol mono-C8-10-alkyl ether sulfate ammonium
68891-29-2



1, 3,4
Polyethylene glycol nonylphenyl ether
9016-45-9



1, 2, 3, 4, 8
Polyethylene glycol tridecyl ether phosphate
9046-01-9



1, 3,4
Polyethyleneimine
9002-98-6



4
Polyglycerol
25618-55-7



2
Poly-L-aspartic acid sodium salt
34345-47-6



8
Polyoxyethylene sorbitan trioleate
9005-70-3



3
H-47
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Polyoxyethylene(10)nonylphenyl ether
26027-38-3



1, 2, 3, 4, 8
Polyoxyl 15 hydroxystearate
70142-34-6



8
Polyoxypropylenediamine
9046-10-0



1
Polyphosphoric acids, esters with triethanolamine, sodium salts
68131-72-6



1
Polyphosphoric acids, sodium salts
68915-31-1


X
1,4
Polypropylene glycol
25322-69-4
X


1, 2,4
Polypropylene glycol glycerol triether, epichlorohydrin, bisphenol A
polymer
68683-13-6



1
Polyquaternium 5
26006-22-4



1,4
Polysorbate 20
9005-64-5



8
Polysorbate 60
9005-67-8



3,4
Polysorbate 80
9005-65-6



3,4
Polyvinyl acetate copolymer
9003-20-7


X
2
Polyvinyl acetate, partially hydrolyzed
304443-60-5



8
Polyvinyl alcohol
9002-89-5


X
1, 2,4
Polyvinyl alcohol/polyvinyl acetate copolymer
NOCAS_50147



2
Polyvinylidene chloride
9002-85-1



8
Polyvinylpyrrolidone
9003-39-8


X
8
Portland cement
65997-15-1



2,4
Potassium acetate
127-08-2

X

1, 3,4
Potassium aluminum silicate
1327-44-2



5
Potassium antimonate
29638-69-5



1,4
H-48
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Potassium bisulfate
7646-93-7



8
Potassium borate
12712-38-8



3
Potassium borate (l:x)
20786-60-1



1,3
Potassium carbonate sesquihydrate
6381-79-9



5
Potassium chloride
7447-40-7



1, 2, 3, 4, 5, 6, 7
Potassium dichromate
7778-50-9



4
Potassium hydroxide
1310-58-3



1, 2, 3, 4, 6
Potassium iodide
7681-11-0


X
1,4
Potassium metaborate
13709-94-9



1, 2, 3, 4, 8
Potassium oleate
143-18-0

X

4
Potassium oxide
12136-45-7



1,4
Potassium persulfate
7727-21-1



1, 2,4
Potassium phosphate, tribasic
7778-53-2


X
8
Potassium sulfate
7778-80-5



2
Propane
74-98-6

X

2,5
Propanol, l(or 2)-(2-methoxymethylethoxy)-
34590-94-8

X

1, 2, 3, 4
Propargyl alcohol
107-19-7
X
X
X
1, 2, 3, 4, 5, 6, 7, 8
Propylene carbonate
108-32-7

X

1,4
Propylene pentamer
15220-87-8

X

1
p-Xylene
106-42-3
X
X
X
1,4
Pyridine, alkyl derivs.
68391-11-7



1,4
Pyridinium, l-(phenylmethyl)-, alkyl derivs., chlorides
100765-57-9



4,8
H-49
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Pyridinium, l-(phenylmethyl)-, C7-8-alkyl derivs., chlorides
70914-44-2



6
Pyrimidine
289-95-2

X

2
Pyrrole
109-97-7

X

2
Quartz-alpha (Si02)
14808-60-7


X
1, 2, 3, 4, 5, 6, 8
Quaternary ammonium compounds (2-ethylhexyl) hydrogenated tallow
alkyl)dimethyl, methyl sulfates
308074-31-9



8
Quaternary ammonium compounds, (oxydi-2,l-ethanediyl)bis[coco
alkyldimethyl, dichlorides
68607-28-3



2, 3, 4, 8
Quaternary ammonium compounds, benzyl(hydrogenated tallow
alkyl)dimethyl, bis(hydrogenated tallow alkyl)dimethylammonium salt
with bentonite
71011-25-1



8
Quaternary ammonium compounds, benzylbis(hydrogenated tallow
alkyl)methyl, salts with bentonite
68153-30-0



2, 5,6
Quaternary ammonium compounds, benzyl-C10-16-
alkyldimethyl, chlorides
68989-00-4



1,4
Quaternary ammonium compounds, benzyl-C12-16-alkyldimethyl,
chlorides
68424-85-1


X
1, 2, 4, 8
Quaternary ammonium compounds, benzyl-C12-18-alkyldimethyl,
chlorides
68391-01-5



8
Quaternary ammonium compounds, benzylcoco alkyldimethyl,
chlorides
61789-71-7



8
Quaternary ammonium compounds, bis(hydrogenated tallow
alkyl)dimethyl, salts with bentonite
68953-58-2



2, 3, 4, 8
Quaternary ammonium compounds, bis(hydrogenated tallow
alkyl)dimethyl, salts with hectorite
71011-27-3



2
Quaternary ammonium compounds, di-C8-10-alkyldimethyl, chlorides
68424-95-3

X

2
H-50
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Quaternary ammonium compounds, dicoco alkyldimethyl, chlorides
61789-77-3



l
Quaternary ammonium compounds, pentamethyltallow
alkyltrimethylenedi-, dichlorides
68607-29-4



4
Quaternary ammonium compounds, trimethyltallow alkyl, chlorides
8030-78-2



1,4
Quinaldine
91-63-4

X

8
Quinoline
91-22-5
X
X
X
2,4
Raffinates (petroleum)
68514-29-4



5
Raffinates, petroleum, sorption process
64741-85-1



1, 2, 4, 8
Residual oils, petroleum, solvent-refined
64742-01-4



5
Residues, petroleum, catalytic reformer fractionator
64741-67-9



1, 4,8
Rhodamine B
81-88-9

X
X
4
Rosin
8050-09-7



1,4
Rutile titanium dioxide
1317-80-2



8
Sand
308075-07-2



8
Scandium oxide
12060-08-1



8
Sepiolite
63800-37-3



2
Silane, dichlorodimethyl-, reaction products with silica
68611-44-9



2,4
Silica
7631-86-9
X

X
1, 2, 3, 4, 8
silica gel, cryst. -free
112926-00-8



3,4
Silica, amorphous, fumed, cryst.-free
112945-52-5



1, 3,4
Silica, vitreous
60676-86-0



1, 4,8
Silicic acid, aluminum potassium sodium salt
12736-96-8



4
H-51
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Siloxanes (Polysiloxane)
9011-19-2



4
Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated
propoxylated
68937-55-3



8
Siloxanes and Silicones, di-Me, Me hydrogen
68037-59-2



8
Siloxanes and silicones, di-Me, polymers with Me silsesquioxanes
68037-74-1



4
Siloxanes and Silicones, di-Me, reaction products with silica
67762-90-7



4
Siloxanes and silicones, dimethyl,
63148-52-7



4
Silwet L77
27306-78-1



1
Sodium 1-octanesulfonate
5324-84-5

X

3
Sodium 2-mercaptobenzothiolate
2492-26-4

X

2
Sodium acetate
127-09-3

X

1, 3,4
Sodium aluminate
1302-42-7



2,4
Sodium benzoate
532-32-1

X

3
Sodium bicarbonate
144-55-8

X

1, 2, 3, 4, 7
Sodium bis(tridecyl) sulfobutanedioate
2673-22-5

X

4
Sodium bisulfite
7631-90-5


X
1, 3,4
Sodium borate
1333-73-9



1, 4, 6, 7
Sodium bromate
7789-38-0



1, 2,4
Sodium bromide
7647-15-6



1, 2, 3, 4, 7
Sodium bromosulfamate
1004542-84-0



8
Sodium C14-16 alpha-olefin sulfonate
68439-57-6

X

1, 3,4
Sodium caprylamphopropionate
68610-44-6

X

4
H-52
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Sodium carbonate
497-19-8

X

1, 2, 3, 4, 8
Sodium chlorate
7775-09-9


X
1,4
Sodium chloride
7647-14-5



1, 2, 3, 4, 5, 8
Sodium chlorite
7758-19-2


X
1, 2, 3, 4, 5, 8
Sodium chloroacetate
3926-62-3

X

3
Sodium cocaminopropionate
68608-68-4



1
Sodium decyl sulfate
142-87-0

X

1
Sodium D-gluconate
527-07-1

X

4
Sodium diacetate
126-96-5

X

1,4
Sodium dichloroisocyanurate
2893-78-9

X

2
Sodium dl-lactate
72-17-3

X

8
Sodium dodecyl sulfate
151-21-3

X

8
Sodium erythorbate (1:1)
6381-77-7

X

1, 3, 4, 8
Sodium ethasulfate
126-92-1

X

1
Sodium formate
141-53-7

X

2,8
Sodium hydrogen sulfate
7681-38-1



4
Sodium hydroxide
1310-73-2



1, 2, 3, 4, 7, 8
Sodium hydroxymethanesulfonate
870-72-4

X

8
Sodium hypochlorite
7681-52-9



1, 2, 3, 4, 8
Sodium iodide
7681-82-5


X
4
Sodium ligninsulfonate
8061-51-6



2
Sodium l-lactate
867-56-1

X

8
H-53
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Sodium maleate (l:x)
18016-19-8

X

8
Sodium metabisulfite
7681-57-4


X
1
Sodium metaborate
7775-19-1



3,4
Sodium metaborate dihydrate
16800-11-6



1,4
Sodium metaborate tetrahydrated
10555-76-7



1, 4,8
Sodium metasilicate
6834-92-0



1, 2,4
Sodium molybdate(VI)
7631-95-0



8
Sodium nitrate
7631-99-4



2
Sodium nitrite
7632-00-0



1, 2,4
Sodium N-methyl-N-oleoyltaurate
137-20-2

X

4
Sodium octyl sulfate
142-31-4

X

1
Sodium oxide
1313-59-3



1
Sodium perborate
11138-47-9



4
Sodium perborate tetrahydrate
10486-00-7



1, 4, 5, 8
Sodium peroxoborate
7632-04-4



1
Sodium persulfate
7775-27-1



1, 2, 3, 4, 7, 8
Sodium phosphate
7632-05-5



1,4
Sodium polyacrylate
9003-04-7



1, 2, 3, 4
Sodium pyrophosphate
7758-16-9


X
1, 2,4
Sodium salicylate
54-21-7

X

1,4
Sodium sesquicarbonate
533-96-0

X

1,2
Sodium silicate
1344-09-8



1, 2,4
H-54
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Sodium starch glycolate
9063-38-1



2
Sodium sulfate
7757-82-6



1, 2, 3, 4
Sodium sulfite
7757-83-7


X
2, 4,8
Sodium thiocyanate
540-72-7

X

1,4
Sodium thiosulfate
7772-98-7



1, 2, 3, 4
Sodium thiosulfate, pentahydrate
10102-17-7



1,4
Sodium trichloroacetate
650-51-1

X

1,4
Sodium trimetaphosphate
7785-84-4


X
8
Sodium xylenesulfonate
1300-72-7

X

1, 3,4
Sodium zirconium lactate
15529-67-6



8
Sodium zirconium lactic acid (4:4:1)
10377-98-7



1,4
Solvent naphtha, petroleum, heavy aliph.
64742-96-7



2, 4,8
Solvent naphtha, petroleum, heavy arom.
64742-94-5



1, 2, 4, 5, 8
Solvent naphtha, petroleum, light aliph.
64742-89-8



8
Solvent naphtha, petroleum, light arom.
64742-95-6



1, 2,4
Sorbic acid
110-44-1

X

8
Sorbitan sesquioleate
8007-43-0

X

4
Sorbitan, mono-(9Z)-9-octadecenoate
1338-43-8

X

1, 2, 3, 4
Sorbitan, monooctadecanoate
1338-41-6

X

8
Sorbitan, tri-(9Z)-9-octadecenoate
26266-58-0

X

8
Spirit of ammonia, aromatic
8013-59-0



8
Stannous chloride dihydrate
10025-69-1



1,4
H-55
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Starch
9005-25-8



1, 2,4
Steam cracked distillate, cyclodiene dimer, dicyclopentadiene polymer
68131-87-3



1
Stoddard solvent
8052-41-3


X
1, 3,4
Stoddard solvent IIC
64742-88-7



1, 2,4
Strontium chloride
10476-85-4


X
4
Styrene
100-42-5

X
X
2
Subtilisin
9014-01-1



8
Sucrose
57-50-1

X

1, 2, 3, 4
Sulfamic acid
5329-14-6



1,4
Sulfan blue
129-17-9

X
X
8
Sulfate
14808-79-8
X


1,4
Sulfo NHS Biotin
119616-38-5



8
Sulfomethylated quebracho
68201-64-9



2
Sulfonic acids, C10-16-alkane, sodium salts
68608-21-9



6
Sulfonic acids, petroleum
61789-85-3



1
Sulfonic acids, petroleum, sodium salts
68608-26-4



3
Sulfur dioxide
7446-09-5


X
2, 4,8
Sulfuric acid
7664-93-9


X
1, 2, 4, 7
Sulfuric acid, mono-C12-18-alkyl esters, sodium salts
68955-19-1

X

4
Sulfuric acid, mono-C6-10-alkyl esters, ammonium salts
68187-17-7

X

1, 4,8
Symclosene
87-90-1

X

2
Talc
14807-96-6


X
1, 3, 4, 6, 7
H-56
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Tall oil
8002-26-4



4,8
Tall oil Imidazoline
61791-36-4



4
Tall oil, compound with diethanolamine
68092-28-4



1
Tall oil, ethoxylated
65071-95-6



4,8
Tall-oil pitch
8016-81-7



4
Tallow alkyl amines acetate
61790-60-1



8
Tar bases, quinoline derivatives, benzyl chloride-quaternized
72480-70-7



1, 3,4
Tegin M
8043-29-6



8
Terpenes and Terpenoids, sweet orange-oil
68647-72-3



1, 3, 4, 8
Terpineol
8000-41-7



1,3
tert-Butyl hydroperoxide
75-91-2

X

1,4
tert-Butyl perbenzoate
614-45-9

X

1
Tetra-calcium-alumino-ferrite
12068-35-8



1, 2,4
Tetradecane
629-59-4
X
X

8
Tetradecyldimethylbenzylammonium chloride
139-08-2

X

1, 4,8
Tetraethylene glycol
112-60-7

X

1,4
Tetraethylenepentamine
112-57-2

X

1,4
Tetrakis(hydroxymethyl)phosphonium sulfate
55566-30-8

X

1, 2, 3, 4, 7
Tetramethyl orthosilicate
681-84-5



1
Tetramethylammonium chloride
75-57-0

X

1, 2, 3, 4, 7, 8
Tetrasodium pyrophosphate
7722-88-5


X
8
Thiamine hydrochloride
67-03-8

X

8
H-57
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Thiocyanic acid, ammonium salt
1762-95-4

X

2, 3,4
Thioglycolic acid
68-11-1

X

1, 2, 3, 4
Thiourea
62-56-6

X
X
1, 2, 3, 4, 6
Thiourea, polymer with formaldehyde and 1-phenylethanone
68527-49-1



1, 4,8
Thuja plicata donn ex. D. don leaf oil
68917-35-1



3
Tin(ll) chloride
7772-99-8



1
Titanium dioxided
13463-67-7


X
1, 2, 4, 8
Titanium(4+) 2-[bis(2-hydroxyethyl)amino]ethanolate propan-2-olate
(1:2:2)
36673-16-2



1
Titanium, isopropoxy (triethanolaminate)
74665-17-1



1,4
Toluene
108-88-3
X
X
X
1, 3,4
Tributyl phosphate
126-73-8
X
X
X
1, 2,4
Tributyltetradecylphosphonium chloride
81741-28-8

X

1, 3,4
Tricalcium phosphate
7758-87-4


X
1,4
Tricalcium silicate
12168-85-3



1, 2,4
Tridecane
629-50-5
X
X

8
Triethanolamine
102-71-6

X
X
1, 2,4
Triethanolamine hydrochloride
637-39-8

X

8
Triethanolamine hydroxyacetate
68299-02-5

X

3
Triethanolamine polyphosphate ester
68131-71-5



1, 4,8
Triethyl citrate
77-93-0

X

1,4
Triethyl phosphate
78-40-0

X

1,4
H-58
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Triethylene glycol
112-27-6

X

1, 2,3
Triethylenetetramine
112-24-3

X

4
Triisopropanolamine
122-20-3

X

1,4
Trimethanolamine
14002-32-5

X

3
Trimethyl borate
121-43-7



8
Trimethylamine
75-50-3

X

8
Trimethylamine quaternized polyepichlorohydrin
51838-31-4



1, 2, 3, 4, 5, 8
Trimethylbenzene
25551-13-7
X

X
1, 2,4
Triphosphoric acid, pentasodium salt
7758-29-4


X
1,4
Tripoli
1317-95-9



4
Tripotassium citrate monohydrate
6100-05-6

X

4
Tripropylene glycol monomethyl ether
25498-49-1

X

2
Trisodium citrate
68-04-2

X

3
Trisodium citrate dihydrate
6132-04-3

X

1,4
Trisodium ethylenediaminetetraacetate
150-38-9

X

1,3
Trisodium ethylenediaminetriacetate
19019-43-3

X

1, 4,8
Trisodium phosphate
7601-54-9


X
1, 2,4
Trisodium phosphate dodecahydrate
10101-89-0



1
Tritan R (X-100)
92046-34-9



8
Triton X-100
9002-93-1



1, 3,4
Tromethamine
77-86-1

X

3,4
Tryptone
73049-73-7



8
H-59
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Ulexite
1319-33-1



1, 2, 3, 8
Undecane
1120-21-4
X
X

3, 8
Undecanol, branched and linear
128973-77-3



8
Urea
57-13-6

X

1, 2, 4, 8
Vermiculite
1318-00-9



2
Vinyl acetate ethylene copolymer
24937-78-8



1,4
Vinylidene chloride/methylacrylate copolymer
25038-72-6



4
Water
7732-18-5



2, 4,8
White mineral oil, petroleum
8042-47-5



1, 2,4
Xylenes
1330-20-7
X
X
X
1, 2,4
Yeast extract
8013-01-2



8
Zeolites
1318-02-1


X
8
Zinc
7440-66-6
X

X
2
Zinc carbonate
3486-35-9



2
Zinc chloride
7646-85-7



1,2
Zinc oxide
1314-13-2



1,4
Zinc sulfate monohydrate
7446-19-7



8
Zirconium nitrate
13746-89-9



2,6
Zirconium oxide sulfate
62010-10-0



1,4
Zirconium oxychloride
7699-43-6



1, 2,4
Zirconium(IV) chloride tetrahydrofuran complex
21959-01-3



5
Zirconium(IV) sulfate
14644-61-2



2,6
H-60
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical name3
CASRNb
Known
constituent of
produced water
Physico-
chemical
properties
Selected
toxicity
data0
Reference
Zirconium, l,l'-((2-((2-hydroxyethyl)(2-
hydroxypropyl)amino)ethyl)imino)bis(2-propanol) complexes
197980-53-3



4
Zirconium, acetate lactate oxo ammonium complexes
68909-34-2



4,8
Zirconium, chloro hydroxy lactate oxo sodium complexes
174206-15-6



4
Zirconium, hydroxylactate sodium complexes
113184-20-6



1,4
Zirconium,tetrakis[2-[bis(2-hydroxyethyl)amino-kN]ethanolato-kO]-
101033-44-7



1, 2, 4, 5
a DSSTox chemical names assigned to the listed CASRN can be reformatted or change over time with additional curation review. In the case that a chemical name in this table no
longer matches the DSSTox chemical name for a listed CASRN, the CASRN would be presumed to be the invariant identifier.
bSome chemicals are designated as "NOCAS_" which are DSSTox database-specific CAS-like identifiers assigned to a listed chemical name or substance.
c Chemicals are flagged as having selected toxicity data available if they have one or more oral reference values, oral slope factors, or qualitative cancer classifications available
from the sources presented in Appendix G.
d Four chemicals have data in the EPA's FracFocus 1.0 project database for CASRNs that are different from those in this table: Ethanolamine, CASRN 9007-33-4; Sodium
metaborate tetrahydrate, CASRN 35585-58-1; Boric acid (H3BO3), compd. with 2-aminoethanol (l:x), CASRN 68425-67-2; and Titanium dioxide, CASRN 98084-96-9. Three of
these (9007-33-4, 68425-67-2, and 98084-96-9) are "deleted" CASRNs, and so were not included in this table; instead, the chemical name has been remapped here to the
current "active" CASRNs. CASRN 35585-58-1 is listed for sodium metaborate tetrahydrate in the EPA's FracFocus 1.0 project database, but is assigned to a different chemical
(disodium dioxoborate) in the EPA's Distributed Structure-Searchable Toxicity (DSSTox) Database, and so was not included in this table.
H-61
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Table H-3. List of generic names of chemicals reportedly used in hydraulic fracturing fluids.
In some cases, the generic chemical name masks a specific chemical name and CASRN provided to the EPA and
claimed as CBI by one or more of the nine hydraulic fracturing service companies.
Generic chemical name
Reference
2-Substituted aromatic amine salt
1,4
Acetylenic alcohol
1
Acrylamide acrylate copolymer
4
Acrylamide copolymer
1,4
Acrylamide modified polymer
4
Acrylamide-sodium acrylate copolymer
4
Acrylate copolymer
1
Acrylic copolymer
1
Acrylic polymer
1,4
Acrylic resin
4
Acyclic hydrocarbon blend
1,4
Acylbenzylpyridinium choride
8
Alcohol alkoxylate
1,4
Alcohol and fatty acid blend
2
Alcohol ethoxylates
4
Alcohols
1,4
Alcohols, C9-C22
1,4
Aldehydes
1, 4,5
Alfa-alumina
1,4
Aliphatic acids
1, 2, 3, 4
Aliphatic alcohol
2
Aliphatic alcohol glycol ether
3,4
Aliphatic alcohols, ethoxylated
2
Aliphatic amine derivative
1
Aliphatic carboxylic acid
4
Alkaline bromide salts
1,4
Alkaline metal oxide
4
Alkanes/alkenes
4
H-62
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Alkanolamine derivative
2
Alkanolamine/aldehyde condensate
1, 2,4
Alkenes
1,4
Alklaryl sulfonic acid
1,4
Alkoxylated alcohols
1
Alkoxylated amines
1,4
Alkyaryl sulfonate
1, 2, 3, 4
Alkyl alkoxylate
1,4
Alkyl amide
4
Alkyl amine
1,4
Alkyl amine blend in a metal salt solution
1,4
Alkyl aryl amine sulfonate
4
Alkyl aryl polyethoxy ethanol
3,4
Alkyl dimethyl benzyl ammonium chloride
4
Alkyl esters
1,4
Alkyl ether phosphate
4
Alkyl hexanol
1,4
Alkyl ortho phosphate ester
1,4
Alkyl phosphate ester
1,4
Alkyl phosphonate
4
Alkyl pyridines
2
Alkyl quaternary ammonium chlorides
1,4
Alkyl quaternary ammonium salt
4
Alkylamine alkylaryl sulfonate
4
Alkylamine salts
2
Alkylaryl sulfonate
1,4
Alkylated quaternary chloride
1, 2,4
Alkylated sodium naphthalenesulphonate
2
Alkylbenzenesulfonate
2
Alkylbenzenesulfonic acid
1, 4,5
H-63
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Alkylethoammonium sulfates
l
Alkylphenol ethoxylates
1,4
Alkylpyridinium quaternary
4
Alphatic alcohol polyglycol ether
2
Aluminum oxide
1,4
Amide
4
Amidoamine
1,4
Amine
1,4
Amine compound
4
Amine oxides
1,4
Amine phosphonate
1,4
Amine salt
1
Amino compounds
1,4
Amino methylene phosphonic acid salt
1,4
Ammonium alcohol ether sulfate
1,4
Ammonium salt
1,4
Ammonium salt of ethoxylated alcohol sulfate
1,4
Amorphous silica
4
Amphoteric surfactant
2
Anionic acrylic polymer
2
Anionic copolymer
1,4
Anionic polyacrylamide
1, 2,4
Anionic polyacrylamide copolymer
1, 4,6
Anionic polymer
1, 3,4
Anionic surfactants
2, 4,6
Antifoulant
1,4
Antimonate salt
1,4
Aqueous emulsion of diethylpolysiloxane
2
Aromatic alcohol glycol ether
1
Aromatic aldehyde
1,4
H-64
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Aromatic hydrocarbons
3,4
Aromatic ketones
1, 2, 3, 4
Aromatic polyglycol ether
1
Arsenic compounds
4
Ashes, residues
4
Bentone clay
4
Biocide
4
Biocide component
1,4
Bis-quaternary methacrylamide monomer
4
Blast furnace slag
4
Borate salts
1, 2,4
Cadmium compounds
4
Carbohydrates
1, 2,4
Carboxylmethyl hydroxypropyl guar
4
Cationic polyacrylamide
4
Cationic polymer
2,4
Cedar fiber, processed
2
Cellulase enzyme
1
Cellulose derivative
1, 2,4
Cellulose ether
2
Cellulosic polymer
2
Ceramic
4
Chlorous ion solution
1
Chromates
1,4
Chrome-free lignosulfonate compound
2
Citrus rutaceae extract
4
Common white
4
Complex alkylaryl polyo-ester
1
Complex aluminum salt
1,4
Complex carbohydrate
2
H-65
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Complex organometallic salt
l
Complex polyamine salt
7
Complex substituted keto-amine
1
Complex substituted keto-amine hydrochloride
1
Copper compounds
6
Coric oxide
4
Cotton dust (raw)
2
Cottonseed hulls
2
Cured acrylic resin
1,4
Cured resin
1, 4,5
Cured urethane resin
1,4
Cyclic alkanes
1,4
Defoamer
4
Dibasic ester
4
Dicarboxylic acid
1,4
Diesel
1, 4,6
Dimethyl silicone
1,4
Dispersing agent
1
Emulsifier
4
Enzyme
4
Epoxy
4
Epoxy resin
1,4
Essential oils
1,4
Ester Salt
2,4
Esters
2,4
Ether compound
4
Ether salt
4
Ethoxylated alcohol blend
4
Ethoxylated alcohol/ester mixture
4
Ethoxylated alcohols
1, 2, 4, 5, 7
H-66
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Ethoxylated alkyl amines
1,4
Ethoxylated amine blend
4
Ethoxylated amines
1,4
Ethoxylated fatty acid
4
Ethoxylated fatty acid ester
1,4
Ethoxylated nonionic surfactant
1,4
Ethoxylated nonylphenol
1, 2,4
Ethoxylated sorbitol esters
1,4
Ethylene oxide-nonylphenol polymer
4
Fatty acid amine salt mixture
4
Fatty acid ester
1, 2,4
Fatty acid tall oil
1,4
Fatty acid, ethoxylate
4
Fatty acids
1
Fatty alcohol alkoxylate
1,4
Fatty alkyl amine salt
1,4
Fatty amine carboxylates
1,4
Fatty imidazoline
4
Fluoroaliphatic polymeric esters
1,4
Formaldehyde polymer
1
Glass fiber
1,4
Glyceride esters
2
Glycol
4
Glycol blend
2
Glycol ethers
1, 4,7
Ground cedar
2
Ground paper
2
Guar derivative
1,4
Guar gum
4
Haloalkyl heteropolycycle salt
1,4
H-67
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Hexanes
l
High molecular weight polymer
2
High pH conventional enzymes
2
Hydrocarbons
1
Hydrogen solvent
4
Hydrotreated and hydrocracked base oil
1,4
Hydrotreated distillate, light C9-16
4
Hydrotreated heavy naphthalene
5
Hydrotreated light distillate
2,4
Hydrotreated light petroleum distillate
4
Hydroxyalkyl imino carboxylic sodium salt
2
Hydroxycellulose
6
Hydroxyethyl cellulose
1, 2,4
Imidazolium compound
4
Inner salt of alkyl amines
1,4
Inorganic borate
1,4
Inorganic chemical
4
Inorganic particulate
1,4
Inorganic salt
2,4
Iso-alkanes/n-alkanes
1,4
Isomeric aromatic ammonium salt
1,4
Latex
2,4
Lead compounds
4
Low toxicity base oils
1,4
Lubra-Beads course
4
Maghemite
1,4
Magnetite
1,4
Metal salt
1
Metal salt solution
1
Mineral
1,4
H-68
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Mineral fiber
2
Mineral filler
1
Mineral oil
4
Mixed titanium ortho ester complexes
1,4
Modified acrylamide copolymer
2,4
Modified acrylate polymer
4
Modified alkane
1,4
Modified bentonite
4
Modified cycloaliphatic amine adduct
1,4
Modified lignosulfonate
2,4
Naphthalene derivatives
1,4
Neutralized alkylated napthalene sulfonate
4
Nickel chelate catalyst
4
Nonionic surfactant
1
N-tallowalkyltrimethylenedia mines
4
Nuisance particulates
1, 2,4
Nylon
4
Olefinic sulfonate
1,4
Olefins
1,4
Organic acid salt
1,4
Organic acids
1,4
Organic alkyl amines
4
Organic chloride
4
Organic modified bentonite clay
4
Organic phosphonate
1,4
Organic phosphonate salts
1,4
Organic phosphonic acid salts
1,4
Organic polymer
4
Organic polyol
4
Organic salt
1,4
H-69
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Organic sulfur compound
1,4
Organic surfactants
1
Organic titanate
1,4
Organo amino silane
4
Organo phosphonic acid
4
Organo phosphonic acid salt
4
Organometallic ammonium complex
1
Organophilic clay
4
Oxidized tall oil
2
Oxoaliphatic acid
2
Oxyalkylated alcohol
1,4
Oxyalkylated alkyl alcohol
2,4
Oxyalkylated alkylphenol
1, 2, 3, 4
Oxyalkylated fatty acid
1,4
Oxyalkylated fatty alcohol salt
2
Oxyalkylated phenol
1,4
Oxyalkylated phenolic resin
4
Oxyalkylated polyamine
1
Oxyalkylated tallow diamine
2
Oxyethylated alcohol
2
Oxylated alcohol
1,4
P/F resin
4
Paraffin inhibitor
4
Paraffinic naphthenic solvent
1
Paraffinic solvent
1,4
Paraffins
1
Pecan shell
2
Petroleum distallate blend
2, 3,4
Petroleum gas oils
1
Petroleum hydrocarbons
4
H-70
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Petroleum solvent
2
Phosphate ester
1,4
Phosphonate
2
Phosphonic acid
1,4
Phosphoric acid, mixed polyoxyalkylene aryl and alkyl esters
4
Plasticizer
1,2
Polyacrylamide copolymer
4
Polyacrylamides
1
Polyacrylate
1,4
Polyactide resin
4
Polyalkylene esters
4
Polyaminated fatty acid
2
Polyaminated fatty acid surfactants
2
Polyamine
1,4
Polyamine polymer
4
Polyanionic cellulose
1
Polyaromatic hydrocarbons
6
Polycyclic organic matter
6
Polyelectrolyte
4
Polyether polyol
2
Polyethoxylated alkanol
2, 3,4
Polyethylene copolymer
4
Polyethylene glycols
4
Polyethylene wax
4
Polyglycerols
2
Polyglycol
2
Polyglycol ether
6
Polylactide resin
4
Polymer
2,4
Polymeric hydrocarbons
3,4
H-71
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Polymerized alcohol
4
Polymethacrylate polymer
4
Polyol phosphate ester
2
Polyoxyalkylene phosphate
2
Polyoxyalkylene sulfate
2
Polyoxyalkylenes
1, 4,7
Polyphenylene ether
4
Polyphosphate
4
Polypropylene glycols
2
Polyquaternary amine
4
Polysaccaride polymers in suspension
2
Polysaccharide
4
Polysaccharide blend
4
Polyvinylalcohol/polyvinylactetate copolymer
4
Potassium chloride substitute
4
Quarternized heterocyclic amines
4
Quaternary amine
2,4
Quaternary amine salt
4
Quaternary ammonium chloride
4
Quaternary ammonium compound
1, 2,4
Quaternary ammonium salts
1, 2,4
Quaternary compound
1,4
Quaternary salt
1,4
Quaternized alkyl nitrogenated compd
4
Red dye
4
Refined mineral oil
2
Resin
4
Salt of amine-carbonyl condensate
3,4
Salt of fatty acid/polyamine reaction product
3,4
Salt of phosphate ester
1
H-72
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Salt of phosphono-methylated diamine
1,4
Salts
4
Salts of oxyalkylated fatty amines
4
Sand
4
Sand, AZ silica
4
Sand, brown
4
Sand, sacked
4
Sand, white
4
Secondary alcohol
1,4
Silica sand, 100 mesh, sacked
4
Silicone emulsion
1
Silicone ester
4
Sodium acid pyrophosphate
4
Sodium calcium magnesium polyphosphate
4
Sodium phosphate
4
Sodium salt of aliphatic amine acid
2
Sodium xylene sulfonate
4
Softwood dust
2
Starch blends
6
Substituted alcohol
1, 2,4
Substituted alkene
1
Substituted alklyamine
1,4
Substituted alkyne
4
Sulfate
4
Sulfomethylated tannin
2,5
Sulfonate
4
Sulfonate acids
1
Sulfonate surfactants
1
Sulfonated asphalt
2
Sulfonic acid salts
1,4
H-73
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Generic chemical name
Reference
Sulfur compound
1,4
Sulphonic amphoterics
4
Sulphonic amphoterics blend
4
Surfactant blend
3,4
Surfactants
1, 2,4
Synthetic copolymer
2
Synthetic polymer
4
Tallow soap
4
Telomer
4
Terpenes
1,4
Titanium complex
4
Triethanolamine zirconium chelate
14
Triterpanes
4
Vanadium compounds
4
Wall material
1
Walnut hulls
1, 2,4
Zirconium complex
2,4
Zirconium salt
4
H-74
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Table H-4. Chemicals detected in produced water.
An "X" indicates the availability of physicochemical properties from EPI Suite™ (Appendix C) and selected toxicity data (Appendix G). An empty cell indicates no
information was available from the sources we consulted. Reference number corresponds to the citation in Table H-l. Formation type indicated by: "S" (shale),
"C" (coalbed), or "U" (uncertain). This refers both to unknown formation types and chemicals in produced water that occur in other types of formations not
specified.
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
2,6-di(tert-butyl)-4-hydroxy-4-methyl-
2,5-cyclohexadien-l-on
10396-80-2

X

Name
c
21
(l,3-Dimethylbutyl)cyclohexane
61142-19-6

X

Name
s
18
(l-Butylheptyl)cyclohexane
13151-80-9

X

Name
s
18
(l-Methoxyethyl)-benzene
4013-34-7



Name
s,c
21
(l-Methyl-l-buten-l-yl)benzene
53172-84-2

X

Name
s
18
(l-Pentyloctyl)cyclohexane
13151-91-2

X

Name
s
18
(l-Propylnonyl)cyclohexane
13151-84-3

X

Name
s
18
(3E)-3-Heptene
14686-14-7

X

Name
s
18
(3R)-3,7-Dimethyloct-6-enal
2385-77-5

X

Name
s
18
(4Z)-2-Methyl-4-tetradecene
866760-27-2

X

Name
s
18
(9E)-8-Methyl-9-tetradecen-l-yl
acetate
912629-93-7

X

Name
s
18
(E)-5-Decene
7433-56-9

X


s
18
(E)-5-Methylspiro[3,5]nonan-l-one
65147-56-0

X

Name;
CASRN
s
18
(Z)-l,2-Dimethylcyclohexane
2207-01-4

X


s
18
(Z)-l,2-Dimethylcyclopentane
1192-18-3

X

Name
s
18
(Z)-l,3-Dimethylcyclohexane
638-04-0

X

Name
s
18
H-75
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
(Z)-l-Ethyl-2-methylcyclopentane
930-89-2

X

Name
s
18
(Z)-l-Ethyl-3-methylcyclohexane
19489-10-2

X

Name
s
18
(Z)-5-Octen-l-ol
64275-73-6

X

Name
s
18
(Z)-9-Methylundec-4-ene
74630-56-1

X

Name
s
18
(Z)-9-Tricosene
27519-02-4

X


c
18, 20
1-Heptadecene
6765-39-5

X


s
18
l-(l,5-Dimethylhexyl)-4-(4-
methylpentyl)cyclohexane
56009-20-2

X

Name
s
18
l-(2,4-Dimethylphenyl)ethanone
89-74-7

X

Name
s
16
l-(2-Furanyl)-3-butene-l,2-diol
19261-13-3

X

Name
s
16
l-(3-Methylbutyl)-2,3,4-tri methyl-
benzene
107997-59-1

X

Name
c
21
l-(Butan-2-yl)-4-methylbenzene
1595-16-0

X

Name
s
18
l-(Cyclohexylmethyl)-4-
methylcyclohexane
66826-95-7

X


s
18
l-(Pentyloxy)hexane
32357-83-8

X

Name
s
18
1,8,10-Pentadecatriene
1227308-82-8

X


s
18
1,1,3,5-Tetramethylcyclohexane
4306-65-4

X


s
18
1,1,3-Trimethylcyclohexane
3073-66-3

X

Name
s
18
1,1,3-Trimethylcyclopentane
4516-69-2

X

Name
s
18
1,12-Dibromododecane
3344-70-5

X


s
18
1,1-Dichloroethane
75-34-3

X
X

s
18
H-76
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
l,l-Dimethyl-l,2,3,4-tetrahydro-7-
isopropyl phenanthrene
27530-79-6

X

Name
c
20
1,1-Dimethylcyclohexane
590-66-9

X


s
18
1,1-Dimethylcyclopropane
1630-94-0

X


s
18
l,l'-Methylenebis(4-methyl)-benzene
4957-14-6

X

Name
c
20
l,l'-Oxybisdecane
2456-28-2

X


s
18
1,2,3,4-T etra hydro-2,5,7-
trimethylnaphthalene
65001-61-8

X


s
18
1,2,3,4-T etra hydro-2,5,8-
trimethylnaphthalene
30316-17-7

X


s
18
1,2,3,4-Tetra hydro-naphthalene
119-64-2

X

Name
s,c
21
1,2,3,4-Tetramethylcyclohexane
3726-45-2

X


s
18
1,2,3,4-Tetramethylnaphthalene
3031-15-0

X


s
18
1,2,3-Trichlorobenzene
87-61-6

X
X

s
3,9
1,2,3-Trimethylbenzene
526-73-8
X
X
X

s
18
1,2,3-Trimethylcyclopentane
2815-57-8

X


s
18
1,2,4,5-Tetramethylbenzene
95-93-2

X

Name
s
18
1,2,4-Trichlorobenzene
120-82-1

X
X

s
9
1,2,4-Trimethylbenzene
95-63-6
X
X
X

s,c
3, 9, 10, 13, 15, 18,
22
1,2,4-Trimethylcyclohexane
2234-75-5

X


s
18
1,2,4-Trimethylcyclopentane
2815-58-9

X


s
18
H-77
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
1,2-Benzenedicarboxylic acid, 1,2-
bis(8-methylnonyl) ester
89-16-7

X
X
Name
s
18
1,2-Benzenedicarboxylic acid, 1-butyl
2-(8-methylnonyl) ester
42343-36-2

X

Name
s
18
l,2-Di-but-2-enyl-cyclohexane
NOCAS_873054

X


c
20
1,2-Dimethyl-l-cycloheptene
20053-89-8

X

Name
s
18
l,2-Dimethyl-4-ethylbenzene
934-80-5

X

Name
s
18
1,2-Diphenylhydrazine
122-66-7

X
X

s
15
1,2-Epoxydodecane
2855-19-8

X

Name
s
18
1,2-Epoxyhexadecane
7320-37-8

X

Name
s
18
1,2-Propylene glycol
57-55-6
X
X
X

s
3, 9, 22
1,3,5-Trimethylbenzene
108-67-8
X
X
X
Name
s,c
3, 9, 10, 13, 15, 18,
22
1,3,5-Trimethylcyclohexane
1839-63-0

X


s
18
l,3-Dimethyl-4-ethylbenzene
874-41-9

X

Name
s,c
18,21
1,3-Dimethyladamantane
702-79-4

X

Name
c
13
1,3-Dimethylcyclohexane
591-21-9

X


s
18
1,3-Dimethylcyclopentane
2453-00-1

X


s
18
1,4,5,8-Tetramethylnaphthalene
2717-39-7

X


s
16
1,4,5-Trimethylnaphthalene
2131-41-1

X


s
18
1,4,6-Trimethylnaphthalene
2131-42-2

X


s
18
l,4-Dihydro-l,4-methanonaphthalene
4453-90-1

X


s
18
H-78
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
l,4-Dimethyl-2,3-
diazabicyclo[2.2.1]hept-2-ene
71312-54-4

X

Name
s
16
1,4-Dimethylcyclohexane
589-90-2

X


s
18
1,4-Dimethylnaphthalene
571-58-4

X


s
18
1,4-Dioxane
123-91-1
X
X
X

s
9, 10, 15
1,4-Hexadecansultone
15224-88-1

X

Name
s
18
1,5,7-Trimethyl-1,2,3,4-
tetrahydronaphthalene
21693-55-0

X

Name
s
18
1,54-Dibromotetrapentacontane
852228-22-9

X


s
18
l,5-Dimethyl-7-
oxabicyclo[4.1.0]heptane
162239-52-3

X


s
18
1,5-Dimethylnaphthalene
571-61-9

X


s
18
1,6-Dimethyl-4(1-
methylethyl)naphthalene
483-78-3

X

Name
c
20
1,6-Dimethylnaphthalene
575-43-9

X


s
18
10-Pentadecen-l-ol
129396-62-9

X


s
18
10,4-Dihydroxy-70-methoxy-2,30-
dimethyl-,()-[l,20-binaphthalene]-
5,50,8,80-tetrone
119736-96-8

X

Name
s
18
10-Methylicosane
54833-23-7

X

Name
s
18
10-Methylnonadecane
56862-62-5

X


s
18
ll-(l-Ethylpropyl)-heneicosane
55282-11-6

X

Name
s
18
ll,13-Dimethyl-12-tetradecen-l-yl
acetate
400037-00-5

X

Name
s
18
H-79
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
13-Tetradecen-l-ol
67400-04-8

X


s
18
13-Tetradecen-l-yl acetate
56221-91-1

X

Name
s
18
14-Bromo-l-tetradecene
74646-31-4

X


s
18
14-Methylhexadecanal
93815-50-0

X


s
18
15-lsobutyl-(13.a.H)-isocopalane
228729-94-0

X

Name
c
20
17-Methylpentatriacontane
56987-83-8

X


s
18
la,9b-Dihydro-lH-
cyclopropa[l]phenanthrene
949-41-7

X

Name
s
18
l-Allyl-3-methylindole-2-carbaldehyde
123731-75-9

X

Name
c
20
1-Bromo-ll-iodoundecane
139123-69-6

X


s
18
1-Bromohexadecane
112-82-3

X


s
18
1-Bromooctadecane
112-89-0

X


s
18
1-Bromopentadecane
629-72-1

X


s
18
1-Butanol
71-36-3
X
X
X
Name
s
22
l-Butyl-2-ethyloctahydro-lH-4,7-
epoxyinden-5-ol
62583-58-8

X

Name
c
20
l-Butyl-2-pentylcyclopentane
61142-52-7

X


s
18
1-Chloro-Heptacosane
62016-79-9

X

Name
s
18
1-Chlorohexadecane
4860-03-1

X


s
18
1-Decene
872-05-9

X


s
18
1-Docosanethiol
7773-83-3

X


s
18
1-Dodecene
112-41-4

X


s
18
H-80
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
l-Dotriacontanol
6624-79-9

X


s
18
l-Ethyl-2,3-dimethylbenzene
933-98-2

X


s
18
l-Ethyl-2-methylbenzene
611-14-3
X
X


s
18
l-Ethyl-2-methylcyclohexane
3728-54-9

X


s
18
l-Ethyl-2-methylcyclopentane
3726-46-3

X


s
18
l-Ethyl-3-methylcyclohexane
3728-55-0

X


s
18
l-Ethyl-4-methylcyclohexane
3728-56-1

X


s
18
l-Ethyl-9,10-anthracenedione
24624-29-1

X

Name
c
20
1-Ethylidene-lH-indene
2471-83-2

X


s
18
1-Fluorododecane
334-68-9

X


s
18
1-Hentetracontanol
40710-42-7

X


s
18
1-Hexacosanol
506-52-5

X


s
18
1-Hexacosene
18835-33-1




c
20
1-Hexadecene
629-73-2
X
X


s
18
l-lodo-2-methylundecane
73105-67-6

X


s
18
l-lsopropyl-2,3-dimethylcyclopentane
489-20-3

X

Name
s
18
l-Methyl-l,2-cyclohexanediol
6296-84-0

X


s
18
l-Methyl-2-pentylcyclohexane
54411-01-7

X


s
18
l-Methyl-3-(l-
methylethyl)cyclopentane
53771-88-3

X

Name
s
18
l-Methyl-3-propylbenzene
1074-43-7

X

Name
s
16
H-81
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
l-Methyl-7-(l-
methylethyl)phenanthrene
483-65-8

X

Name
c
20,21
l-Methyl-7-oxabicyclo[4.1.0]heptane
1713-33-3

X


s
18
1-Methylene-lH-indene
2471-84-3

X


s
18
1-Methylfluorene
1730-37-6

X

Name
c
20
1-Methylnaphthalene
90-12-0

X
X

s,c
18, 21, 22
1-Naphthol
90-15-3

X


s
22
1-Nonene
124-11-8

X


s
18
1-Octadecanethiol
2885-00-9

X


s
18
1-Octadecene
112-88-9
X
X


s
18
l-Oxopyridin-2-ylamine
14150-95-9

X

Name
s
18
l-Pentyl-2-propylcyclopentane
62199-51-3

X


s
18
1-Propanol
71-23-8
X
X


s
22
1-Propoxyhexane
53685-78-2

X


s
18
1-Propylcyclohexene
2539-75-5

X


s
18
1-Tricosene
18835-32-0

X


s
18
1-Tridecene
2437-56-1

X


s
18
2-(2-Buten-l-yl)-l,3,5-
trimethylbenzene
63435-25-6

X


s
18
2-(2-Butoxyethoxy)ethanol
112-34-5
X
X
X

s,c
21
2(3H)-Benzothiazolone
934-34-9

X


c
20,21
2-(Methylthio)-benzothiazole
615-22-5

X

Name
c
20
H-82
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
2,10-Dimethylundecane
17301-27-8

X


s
18
2,2,3,3-Tetramethylhexane
13475-81-5

X


s
18
2,2,4-trimethyl-l,3-pentanediol
144-19-4

X


s,c
21
2,2-Dibromo-3-nitrilopropionamide
10222-01-2
X
X


s
11
2,2-Dichloro-3,6-dimethyl-l-oxa-2-
silacyclohexa-3,5-diene
69586-09-0

X


s
18
2,3',5-Trimethyldiphenylmethane
61819-81-6

X


c
20
2,3,6-Trimethylnaphthalene
829-26-5

X


s
18
2,3-Dihydro-l,l,2,3,3-pentamethyl-lH-
indene
1203-17-4

X


c
20
2,3-Dimethyldecahydronaphthalene
1008-80-6

X

Name
s
18
2,3-Dimethyldecane
17312-44-6

X


s
18
2,3-Dimethylheptane
3074-71-3

X


s
18
2,3-Dimethylnaphthalene
581-40-8

X


s
18
2,3-Dimethylundecane
17312-77-5

X


s
18
2,3-Heptanedione
96-04-8

X

Name
s
16
2,4,6-Trimethyl-azulene
NOCAS_873044



Name
c
20
2,4-Bis(l, l-dimethylethyl)phenol
96-76-4

X

Name
c
21
2,4-Dichloro-5-oxohex-2-enedioic acid
56771-78-9

X

Name
s
18
2,4-Dichlorophenol
120-83-2

X
X

s
15
2,4-dimethyl-l-(l-methylpropyl)-
benzene
1483-60-9



Name
c
21
2,4-Dimethylheptane
2213-23-2

X


s
18
H-83
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
2,4-Dimethylhexane
589-43-5

X


s
18
2,4-Dimethylphenol
105-67-9

X
X

s,c
3, 9, 10, 13, 15
2,4-Dimethylundecane
17312-80-0

X


s
18
2,5,9-Trimethyldecane
62108-22-9

X


s
18
2,5-Cyclohexadiene-l,4-dione
106-51-4

X
X
Name
c
20
2,5-Dimethyldodecane
56292-65-0

X


s
18
2,6,10-Trimethyl-9-undecenoic acid
97993-62-9

X


s
18
2,6,10-Trimethylpentadecane
3892-00-0

X


s
18
2,6,10-Trimethylundec-9-enal
141-13-9

X

Name
s
18
2,6,10-Trimethylundecanoic acid
1115-94-2

X


s
18
2,6,11-Trimethyldodecane
31295-56-4

X


s
18
2,6-Bis(dimethylethyl)-2,5-
cyclohexadiene-l,4-dione
719-22-2

X

Name
c
20
2,6-Dichlorophenol
87-65-0

X


s
3,9
2,6-Dimethyldecane
13150-81-7

X


s
18
2,6-Dimethylheptane
1072-05-5

X


s
18
2,6-Dimethylnaphthalene
581-42-0

X


s
18
2,6-Di-tert-butylphenol
128-39-2

X

Name
c
10,14, 20
2,7-Dimethylnaphthalene
582-16-1

X


s
18
2-[2-[4-(l,l,3,3-
tetramethylbutyl)phenoxy]ethoxy]-
ethanol
2315-61-9

X

Name
c
20,21
22-Tricosenoic acid
65119-95-1

X


c
20
H-84
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
28-Nor-17.a.(H)-hopane
204781-73-7

X

Name
c
20
2-Aminoimidazole
7720-39-0

X

Name
s
18
2-Butoxyethanol
111-76-2
X
X
X

s
22
2-Butyloctan-l-ol
3913-02-8

X

Name
s
18
2-Chloroethanol
107-07-3

X
X

s
18
2-Dodecen-l-yl(-)succinic anhydride
25377-73-5

X

Name
c
20
2'-Dodecyl- l,l':3',l"-tercyclopentane
55282-68-3

X

Name
s
18
2-Ethyl-l,l,3-trimethylcyclohexane
442662-72-8

X


s
18
2-Ethyl-l-decanol
21078-65-9

X


s
18
2-Ethyl-l-hexanol
104-76-7
X
X


s
22
2-Ethylhexyl diphenyl phosphate
(Octicizer)
1241-94-7

X

Name
c
20
2-Hexyl-l-decanol
2425-77-6

X


s
18
2-Hydroxy-2-methylbut-3-en-l-yl 2-
methylbut-2-enoate
1418543-90-4

X

Name
s
18
2-Hydroxy-4-(propan-2-yl)cyclopent-2-
en-l-one
54639-82-6

X

Name
s
18
2-lmino-5,6-dihydro-2H-
cyclopenta[d][l,3]thiazol-3(4H)-ol
738528-09-1

X

Name
s
18
2-Mercaptobenzothiazole
149-30-4

X
X

c
20
2-Methoxyfuran
25414-22-6

X


s
16
2-Methyl-2-butene
513-35-9

X


s
18
2-Methyl-7-octadecene
51050-50-1

X


s
18
H-85
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
2-Methyl-8-propyl-dodecane
55045-07-3

X

Name
c
20
2-Methylbut-l-ene
563-46-2

X

Name
s
18
2-Methyldecane
6975-98-0

X


s
18
2-Methyldodecan-l-ol
22663-61-2

X

Name
s
18
2-Methyldodecane
1560-97-0

X


s
18
2-Methylheptane
592-27-8

X


s
18
2-Methylnaphthalene
91-57-6

X
X

s,c
3, 9, 10, 13, 15, 16,
18, 21, 22
2-Methyl-nonadecane
52845-07-5

X

Name
c
20
2-Methylnonane
871-83-0

X


s
18
2-Methyl-N-phenyl-benzenamine
1205-39-6

X

Name
c
21
2-Methyloctane
3221-61-2

X


s
18
2-Methylpentadecane
1560-93-6

X


s
18
2-Methylpentane
107-83-5

X


s
18
2-Methylphenanthrene
2531-84-2

X


s
18
2-Methylpropanoic acid
79-31-2

X


u
10
2-Methylpyridine
109-06-8

X


s
3,9
2-Methyltetradecane
1560-95-8

X


s
18
2-Methyltridecane
1560-96-9

X


s
18
2-Methylundecane
7045-71-8

X


s
18
2-Naphthalenol
135-19-3

X

Name
s
22
2-Octadecyl-propane-l,3-diol
5337-61-1

X

Name
c
20
H-86
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
2-Octene
111-67-1

X


s
18
2-Pentyl-2-nonenal
3021-89-4

X


s
18
2-Phenylpentane
2719-52-0

X

Name
s
18
3-(4-Methoxyphenyl)-2-
ethylhexylester-2-propenoic acid
5466-77-3

X

Name
c
20
3-(4-Methoxyphenyl)-2-propenoic acid
830-09-1



Name
c
20
3-(Hexahydro-lH-azepin-l-yl)-l,l-
dioxide-l,2-benzisothiazole
309735-29-3

X

Name
c
20
3,3,5,5-Tetramethylcyclopentene
38667-10-6

X

Name
s
18
3,3'-5,5'-Tetramethyl-[l,r-biphenyl]-
4,4'-diamine
54827-17-7

X

Name
s,c
21
3,4-Dihydro-l,9(2H,10H)acridinedione
80061-31-0

X

Name
c
21
3,5,24-Trimethyltetracontane
55162-61-3

X


s
18
3,5-Dimethyloctane
15869-93-9

X


s
18
3,5-Di-tert-butyl-4-
hydroxybenzaldehyde
1620-98-0

X

Name
c
20
3,6-Dimethylundecane
17301-28-9

X


s
18
3,7-Dimethyldecane
17312-54-8

X


s
18
3,7-Dimethylnonane
17302-32-8

X


s
18
3,7-Dimethyloct-7-enal
141-26-4

X

Name
s
18
3,7-Dimethylundecane
17301-29-0

X


s
18
3,8-Dimethyldecane
17312-55-9

X


s
18
3,9-Dimethylundecane
17301-31-4

X


s
18
H-87
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
3-Cyclohexylpropan-l-ol
1124-63-6

X

Name
s
18
3-Cyclopentyl-2-methylpropan-l-ol
264258-62-0

X

Name
s
18
3-Ethyl-2-methylheptane
14676-29-0

X


s
18
3-Ethylhexane
619-99-8

X


s
18
3-Ethyltoluene
620-14-4

X

Name
s
18
3-Methyl-l-heptene
4810-09-7

X


s
18
3-Methyl-2-(2-oxopropyl)furan
87773-62-4

X

Name
s
18
3-Methyl-3-hexene
42154-69-8

X


s
18
3-Methylcyclohexene
591-48-0

X


s
16
3-Methylcyclopentadecan-l-one
541-91-3

X

Name
s
18
3-Methyldecane
13151-34-3

X


s
18
3-Methyldodecane
17312-57-1

X


s
18
3-Methylnonane
5911-04-6

X


s
18
3-Methyloctane
2216-33-3

X


s
18
4-(l,l,3,3-Tetramethylbutyl)phenol
140-66-9

X

Name
c
14,21
4,4-Diacetyldiphenylmethane
790-82-9

X

Name
c
20
4,4-Dimethyl-2-(l-
methylethenyl)cyclopentanone
343270-53-1

X

Name
s
18
4,6,8-Trimethyl-2-propylazulene
160951-15-5

X


c
20
4,6-Dimethyldodecane
61141-72-8

X


s
18
4-[l-(2-Methylphenyl)ethyl]phenol
35770-76-4

X

Name
c
20
4-Decene
19398-89-1

X


s
18
H-88
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
4-Ethyl-2,3-dimethylhex-2-ene
959028-24-1

X

Name
s
18
4-Ethyl-5-octyl-2,2-
bis(trifluoromethyl)-l,3-dioxolane, cis-
38274-72-5

X

Name
s
18
4-Ethyloctane
15869-86-0

X


s
18
4-Methyl-2-pentene
4461-48-7

X


s
18
4-Methyl-2-phenyl-2-pentenal
26643-91-4

X

Name
s
18
4-Methyldecane
2847-72-5

X


s
18
4-Methyldocosane
25117-30-0

X


s
18
4-Methyldodec-3-en-l-ol
1372101-59-1

X

Name
s
18
4-Methylheptane
589-53-7

X


s
18
4-Methylnonane
17301-94-9

X


s
18
4-Methyloctane
2216-34-4

X


s
18
4-Methyltetradecane
25117-24-2

X


s
18
4-Methyltridecane
26730-12-1

X


s
18
4-Methylundecane
2980-69-0

X


s
18
4-Phenyl-l-buten-4-ol
936-58-3

X

Name
s
18
4-Propyl-3-heptene
4485-13-6

X


s
18
4-Propylcyclohexanone
40649-36-3

X


s
18
4-Propylheptane
3178-29-8

X


s
18
4-Propyl-xanthen-9-one
108837-05-4

X

Name
c
20
5-(l,l-Dimethylethyl)-lH-indene
NOCAS_873045




c
20
5-Butyl-6-hexyloctahydro-lH-indene
55044-36-5

X


s
18
H-89
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
5-Methyldecane
13151-35-4

X


s
18
5-Methyltetradecane
25117-32-2

X


s
18
5-Methyltridecane
25117-31-1

X


s
18
6-Methyl-6-ethylfulvene
3141-02-4

X

Name
s
18
6-Methyltridecane
13287-21-3

X


s
18
6-Methylundecane
17302-33-9

X


s
18
7,12-Dimethylbenz(a)anthracene
57-97-6

X
X

s
3,9
7-Bromomethyl-pentadec-7-ene
941228-34-8

X

Name
c
20
7-Ethenylphenanthrene
68593-94-2

X

Name
c
20
7-Methylpentadecane
6165-40-8

X


s
18
7-Methyltridecane
26730-14-3

X


s
18
7-Tetradecyne
35216-11-6

X


c
20
8-Hexadecyne
19781-86-3

X


c
20
8-Methylundec-3-ene
876314-66-8

X

Name
s
18
9-Hexacosene
71502-22-2

X


s
18
9-Methylanthracene
779-02-2

X


s
18
9-Methylnonadecane
13287-24-6

X


s
18
Acetaldehyde
75-07-0
X
X
X

s
22
Acetate
71-50-1

X


s,c
11,21
Acetic acid
64-19-7
X
X


s
3, 9, 10, 12
Acetone
67-64-1
X
X
X

s
3, 9, 10, 15, 18
Acetophenone
98-86-2
X
X
X

s,c
3, 9, 15, 21, 22
H-90
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Acetyl tributyl citrate
77-90-7

X

Name
s
18
Acrolein
107-02-8
X
X
X

s
9
Acrylonitrile
107-13-1

X
X

s
3,9
Adamantane
281-23-2

X


c
13
Aldrin
309-00-2

X
X

s
3,9
Alpha particle
12587-46-1


X
Name
s
24, 25, 26
alpha-Farnesene
502-61-4

X

Name
s
18
alpha-Methyl-lH-imidazole-l-ethanol
37788-55-9

X

Name
s
18
Aluminum
7429-90-5
X

X

s
3, 9, 10
Ammonia
7664-41-7
X



s
3, 9, 10, 18
Antimony
7440-36-0


X

s
3, 9, 10
Aroclor 1248
12672-29-6

X


s
3,9
Arsenic
7440-38-2
X

X

s
3, 9, 10
Barium
7440-39-3


X

s
3, 9, 10
Benz(a)anthracene
56-55-3

X
X
Name;
CASRN
s
15
Benzene
71-43-2
X
X
X

s,c
3, 9, 10, 12, 13, 16,
22
Benzene, 1,3 (or l,4)-dimethyl-
179601-23-1



Name
c
13
Benzidine
92-87-5

X
X

s
15
Benzo(a)pyrene
50-32-8

X
X

s
3, 9, 15
Benzo(b)fluoranthene
205-99-2

X
X

s
3, 9, 15
H-91
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Benzo(g,h,i)perylene
191-24-2

X
X

s
3, 9, 10, 15
Benzo(k)fluoranthene
207-08-9

X
X

s
3, 9, 15
Benzophenone
119-61-9

X
X

c
21
Benzothiazole
95-16-9

X


s,c
14, 20, 21
Benzyl alcohol
100-51-6

X
X
Name
s
3, 9, 10, 15, 20
Benzyl butyl phthalate
85-68-7

X
X
Name
c
20,21
Benzyl chloride
100-44-7
X
X
X

s
22
Beryllium
7440-41-7


X

s
3, 9, 10
Beta particle
12587-47-2


X
Name
s
24, 25, 26
beta-Hexachlorocyclohexane
319-85-7

X
X

s
3,9
biphenyl
92-52-4

X
X

c
20,21
Bis(l,l-dimethylethyl)-phenol
26746-38-3

X

Name
s,c
21
Bis(2-chloroethyl) ether
111-44-4
X
X
X

s
3,9
Bis(2-ethylhexyl) isophthalate
137-89-3

X

Name
s
18
Bis(dichloromethyl) ether
20524-86-1

X

Name
s
18
Bis-(octylphenyl)-amine
26603-23-6



Name
c
20
Bisphenol A
80-05-7
X
X
X
Name
s
22
Boron
7440-42-8
X

X

s
3, 9, 10
Bromide
24959-67-9




s
3, 9, 10
Bromodichloromethane
75-27-4

X
X

s
3
Bromoform
75-25-2

X
X

s
3, 9, 10
Butanenitrile
109-74-0

X


s
16
H-92
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Butanoic acid
107-92-6

X


s
9, 10
Butanoic acid, butyl ester
109-21-7

X

Name
c
20
Butyl 8-methylnonyl phthalate
89-18-9

X

Name
s
18
Butylbenzene
104-51-8

X
X
Name
s,c
9, 10, 13
Butylcyclohexane
1678-93-9

X


s
18
Butyrate
461-55-2

X


s
11
Cadmium
7440-43-9


X

s
3, 9, 10
Caesium
7440-46-2



Name
c
14
Caesium-137
10045-97-3




s
3
Caffeine
58-08-2

X
X

c
20
Calcium
7440-70-2




s
3, 9, 10
Caprolactam
105-60-2

X
X

c
14,21
Carbon dioxide
124-38-9
X
X


s
3, 9, 10
Carbon disulfide
75-15-0

X
X

s
3, 9, 22
Chloride
16887-00-6
X



s
3, 9, 10
Chlorine
7782-50-5
X

X

s
3, 10
Chlorobenzene
108-90-7
X
X
X
Name
s
16
Chlorodibromomethane
124-48-1

X
X

s
3
Chloroform
67-66-3

X
X

s
3, 9, 10, 18
Chloromethane
74-87-3
X
X
X

s
3, 10, 22
Chloromethyl 5-chloropentyl ether
145912-11-4

X

Name
s
18
Cholesterol
57-88-5

X
X

c
20
H-93
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Chromium
7440-47-3


X

s
3, 9, 10
Chromium (III)
16065-83-1
X

X

s
3
Chromium (VI)
18540-29-9
X

X

s
3, 10
Chrysene
218-01-9

X
X

s
15
cis-l,4-Dimethyladamantane
24145-89-9

X

Name
s
18
cis-Octahydro-4a-methyl-2(lH)-
naphthalenone
938-06-7

X

Name
s
18
Cobalt
7440-48-4


X

s
3, 9, 10
Copper
7440-50-8
X

X

s
3, 9, 10
Cumene
98-82-8
X
X
X
Name
s
3, 9, 22
Cyanide
57-12-5

X
X

s
3, 9, 10
Cyclohexyl mercaptoacetate
16849-98-2

X

Name
s
18
Cyclohexylbenzene
827-52-1

X


s
18
Cyclopentadecane
295-48-7

X


s
18
Cyclotetracosane
297-03-0

X


s
18
Cyclotetradecane
295-17-0

X


s
18
Cyclotridecane
295-02-3

X


s
18
Decahydro-l-methyl-2-
methylenenaphthalene
90548-09-7

X


s
18
Decahydro-2-methylnaphthalene
2958-76-1

X

Name
s
18
Decalin
91-17-8

X

Name
s
18
Decylcyclohexane
1795-16-0

X


s
18
H-94
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
delta-Hexachlorocyclohexane
319-86-8

X
X

s
9
Di(2-ethylhexyl) phthalate
117-81-7
X
X
X
Name
s
3, 9, 10, 18
Dibenz(a,h)anthracene
53-70-3

X
X

s
3, 9, 15
Dibenzosuberol
1210-34-0

X

Name
s
18
dibenzothiophene
132-65-0

X
X

c
21
Dibromoacetonitrile
3252-43-5
X
X
X

s
11
Dibutyl hexanedioate
105-99-7

X

Name
s
18
Dibutyl phthalate
84-74-2

X
X

s,c
3, 9, 10, 20, 21
Dichloromethane
75-09-2
X
X
X
Name
s
9, 10, 18
didecyl phthalate
84-77-5

X


s
18
Dieldrin
60-57-1

X
X

s
9
Diethyl phthalate
84-66-2

X
X
Name
s,c
9, 20, 21
Diethyltoluamide
134-62-3

X
X
Name
c
21
Diisodecyl phthalate
26761-40-0

X
X
Name
s
18
Diisooctyl phthalate
27554-26-3

X

Name
s
18
Dimethyl phthalate
131-11-3

X
X

c
20
Dimethylnaphthalene
28804-88-8



Name
c
20,21
Dimethylphenol
1300-71-6




c
20,21
Dimethyl-tetracyclo[5.2.1.0(2,6)-
0(3,5)]decane
74646-38-1

X

Name
c
20
DINP
28553-12-0

X

Name
s
18
Dioctadecyloate phosphoric acid
3037-89-6

X


s
18
H-95
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Dioctyl hexanedioate
123-79-5

X

Name
s
18
Dioctyl phthalate
117-84-0

X
X
Name
s
9, 10, 14, 18, 21
Diphenylamine
122-39-4

X
X

s,c
3, 9, 15, 20, 21
Diphenylmethane
101-81-5

X


c
20
Di-tert-butyl nitroxide
2406-25-9

X

Name
s
16
D-Limonene
5989-27-5
X
X
X

s
22
Dodecane
112-40-3
X
X


s
12,18
Dodecanoic acid
143-07-7

X


s,c
14, 20, 21
Dotriacontane
544-85-4

X


s
18
Drometrizole
2440-22-4

X

Name
c
20
Endosulfan 1
959-98-8

X


s
3,9
Endosulfan II
33213-65-9

X


s
3,9
Endrin aldehyde
7421-93-4

X


s
3,9
Ethanol
64-17-5
X
X
X

s
22
Ethyl glycylglycinate
627-74-7

X

Name
s
18
Ethylbenzene
100-41-4
X
X
X

s,c
3, 9, 10, 13, 18, 22
Ethylcyclohexane
1678-91-7

X


s
18
Ethylcyclopentane
1640-89-7

X


s
18
Ethylene glycol
107-21-1
X
X
X

s,c
3, 9, 21, 22
Farnesol
4602-84-0

X

Name
s
18
Fluoranthene
206-44-0

X
X

s
3, 9, 15
Fluorene
86-73-7

X
X

s,c
3, 9, 10, 15, 20
H-96
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Fluoride
16984-48-8


X

s
3, 9, 10
Formate
71-47-6

X

Name
s
11,19
Formic acid
64-18-6
X
X
X

u
10
Glutaraldehyde
111-30-8
X
X


s
22
Glycolic acid
79-14-1
X
X


s
18
Heptachlor
76-44-8

X
X

s
3,9
Heptachlor epoxide
1024-57-3

X
X

s
3,9
Heptacosane
593-49-7

X


s,c
18, 20
Heptane
142-82-5
X
X


s
18
Heptanoic acid
111-14-8

X


u
10
Heptylcyclohexane
5617-41-4

X


s
18
Hex-3-yne
928-49-4

X

Name
s
18
Hexadecahydropyrene
2435-85-0

X


s
18
Hexadecanoic acid
57-10-3

X


c
14,21
Hexane
110-54-3
X
X
X

s
18
Hexanoic acid
142-62-1

X


u
10
Hexatriacontane
630-06-8

X


s
18
Hexylcyclohexane
4292-75-5

X


s
18
Hydratropaldehyde
93-53-8

X

Name
s
18
Hydrazine
302-01-2
X

X

s
18
Hydrochloric acid
7647-01-0
X

X

s
18
Hydroxyacetonitrile
107-16-4

X


s
18
H-97
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
lmidazo[l,2-a]pyrimidine
274-95-3

X


s
18
lndeno(l,2,3-cd)pyrene
193-39-5

X
X

s
3, 9, 15
Iodine
7553-56-2


X

s
9, 14
Iron
7439-89-6
X

X

s
3, 9, 10
Isobutylbenzene
538-93-2

X

Name
s
18
Isobutylcyclohexane
1678-98-4

X

Name
s
18
Isopropanol
67-63-0
X
X
X

s
3, 9, 22
Isopropyl myristate
110-27-0

X

Name
c
20
Isoquinoline
119-65-3
X
X


c
21
Isovaleric acid
503-74-2

X


u
10
Kaur-16-ene
562-28-7

X

Name
c
21
Lead
7439-92-1
X

X

s
3, 9, 10
Lindane
58-89-9

X
X

s
3,9
Lithium
7439-93-2


X

s
3, 9, 10
m,p-Cresol mixture
NOCAS_24858


X
Name
c
10
Magnesium
7439-95-4




s
3, 9, 10
Manganese
7439-96-5


X

s
3, 9, 10
m-Cresol
108-39-4

X
X
Name
s,c
3, 9, 10, 13, 15
m-Cymene
535-77-3

X

Name
s
18
Menthol
1490-04-6

X

Name
s
18
Mercury
7439-97-6


X

s
3, 9, 10
Methanol
67-56-1
X
X
X

s
3, 9, 22
H-98
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Methyl biphenyl, mixed isomers
28652-72-4



Name
c
14,21
Methyl bromide
74-83-9

X
X

s
3,9
Methyl crotonate
18707-60-3

X

Name
s
18
Methyl ethyl ketone
78-93-3

X
X
Name
s
3, 9, 10
Methyl(Z)-3,3-diphenyl-4-hexenoate
119296-91-2

X

Name
c
20
Methylcyclohexane
108-87-2
X
X


s
18
Methylenecyclohexane
1192-37-6

X

CASRN
s
18
Methylnaphthalene
1321-94-4



Name
c
20,21
Methylquinoline
27601-00-9



Name
c
14
Molybdenum
7439-98-7


X

s
3, 9, 10
m-xylene
108-38-3

X
X
Name
s
18
N,N-Dimethylformamide
68-12-2
X
X
X

s
22
Naphthalene
91-20-3
X
X
X

s,c
3, 9, 10, 11, 12, 13,
14,15, 20, 21, 22
Nickel
7440-02-0


X

s
3, 9, 10
Nitrate
14797-55-8


X

s,c
3, 9, 10
Nitrite
14797-65-0


X

s,c
3, 9, 10
N-Nitrosodiphenylamine
86-30-6

X
X

s
3, 9, 10, 15
N-Nitroso-N-methylethylamine
10595-95-6

X
X
Name
s
9, 15
Nonacosane
630-03-5

X


s
18
Nonahexacontanoic acid
40710-32-5

X


s
18
Nonane
111-84-2

X
X

s
18
H-99
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Norphytane
1921-70-6

X

Name
s
18
o-Cresol
95-48-7

X
X
Name
s,c
3, 9, 10, 13, 15
Octadecanoic acid
57-11-4

X


s,c
14,21
Octahydro-2-methylpentalene
3868-64-2

X


s
18
Octane
111-65-9

X


s
18
Octasulfur
10544-50-0



Name
c
14
O-Decylhydroxylamine
29812-79-1

X


s
18
O-lsobutylhydroxylamine
5618-62-2

X

Name
s
16
o-Xylene
95-47-6
X
X
X

s
18
p,p'-DDE
72-55-9

X
X

s
3,9
p-Cresol
106-44-5

X
X
Name
s,c
3, 9, 10, 13, 15
p-Cymene
99-87-6

X

Name
s
9, 10, 18
Pentadecanoic acid
1002-84-2

X


c
20
Pentane
109-66-0
X
X
X

s
16
Pentanoic acid
109-52-4

X


u
10
Pentatriacontane
630-07-9

X


s
18
Pentylcyclohexane
4292-92-6

X


s
18
Pentylhydroperoxide
74-80-6

X


s
18
perylene
198-55-0

X
X

s,c
21
Phenanthrene
85-01-8
X
X
X

s,c
3, 9, 10, 15, 16, 20
Phenanthrene-l-carboxlic acid
27875-89-4

X

Name
c
20
Phenol
108-95-2
X
X
X

s,c
3, 9, 10, 13, 15
H-100
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Phorate
298-02-2

X
X

s
9
Phosphorus
7723-14-0


X

s
3,9
Polypropylene glycol
25322-69-4
X



s
23
Potassium
7440-09-7




s
3, 9, 10
Propane-diphenyl
25167-94-6



Name
c
20
Propargyl alcohol
107-19-7
X
X
X

s
22
Propionate
72-03-7

X

Name
c
21
Propionic acid
79-09-4

X


u
10
Propyl cyanate
1768-36-1

X

Name
s
16
Propylbenzene
103-65-1

X

Name
s
9, 13, 16, 18
Propylcyclohexane
1678-92-8

X


s
18
Propylcyclopentane
2040-96-2

X


s
18
p-Tert-butylphenol
98-54-4

X

Name
c
21
p-Xylene
106-42-3
X
X
X

s,c
13, 22
Pyrene
129-00-0

X
X

s,c
9, 10, 15, 20, 21
Pyreno[4,5-c]furan
15123-40-7




c
20
Pyridine
110-86-1

X
X

s
3, 9, 10, 15
Pyruvate
57-60-3

X


s
11
Quinoline
91-22-5
X
X
X

s,c
21
Radium
7440-14-4


X

s
3
Radium-226
13982-63-3


X

s
3, 10, 24, 25, 26, 27
Radium-228
15262-20-1


X

s
3, 10, 24, 25, 26
H-101
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
rel-(lR,2S)-l,2-Diethylcyclohexadecane
14113-60-1

X

Name
s
18
Rubidium
7440-17-7




c
14
Safrole
94-59-7

X
X

s
3,9
sec-Butylbenzene
135-98-8

X


s,c
9, 13
Selenium
7782-49-2


X

s
3, 9, 10
Silica
7631-86-9
X

X

u
10
Silicon
7440-21-3




u
10
Silver
7440-22-4


X

s
3, 9, 10
Sodium
7440-23-5




s
3, 9, 10
Sterane
50-24-8

X

Name
c
20
Strontium
7440-24-6


X

s
3, 9, 10
Sulfate
14808-79-8
X



s
3, 9, 10
Sulfide
18496-25-8




s
9, 14
Sulfite
14265-45-3




s
3
syn-l,6:8,13-Bismethano[14]annulene
55821-04-0

X

Name
s
18
tert-Butylbenzene
98-06-6

X


c
13
Tetrachloroethene
127-18-4

X
X
Name
s
3, 9, 11
Tetracontane
4181-95-7

X


s
18
Tetradecanal
124-25-4

X


s
18
Tetradecane
629-59-4
X
X


s,c
18, 20
Tetradecanoic acid
544-63-8

X


s,c
14, 20, 21
Tetradecyl trifluoroacetate
6222-02-2

X

Name
s
18
H-102
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
tetramethylbutanedinitrile
3333-52-6

X

Name
s,c
21
Thallium
7440-28-0


X

s
3, 9, 10
Tin
7440-31-5


X

s
9, 10
Titanium
7440-32-6




s
3, 9, 10
Toluene
108-88-3
X
X
X

s
3, 9, 10, 12, 13, 18,
22
trans-l,4-Dimethyladamantane
24145-88-8

X

Name
s
18
Triacontane
638-68-6

X


s
18
Tributyl citrate
77-94-1

X

Name
s
18
Tributyl phosphate
126-73-8
X
X
X
Name
c
14
Trichlorodocosylsilane
7325-84-0

X


s
18
trichlorophenol
25167-82-2




c
21
Tricyclo[4.4.0.0(3,9)]decane
NOCAS_873040

X


c
20
Tridecanal
10486-19-8

X


s
18
Tridecane
629-50-5
X
X


s
18
Tridecanedial
63521-76-6

X


c
20
T ridecyloate-2,2,3,3,4,4,4-
heptafluorobutanoic acid
959088-59-6

X


s
18
Triethylene glycol monododecyl ether
3055-94-5

X


s,c
13,21
Trimethylbenzene
25551-13-7
X

X
Name
s,c
12,21
Triphenyl phosphate
115-86-6

X


s,c
14, 20, 21
Tritetracontane
7098-21-7

X


s
18
H-103
-------
Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name3
CASRNb
Known
constituent of
hydraulic
fracturing fluid
Physico-
chemical
properties
Selected
toxicity
data0
NCCT
CASRN or
name
changed
Formation
type
Reference
Undecane
1120-21-4
X
X


s
12,18
Undecyl heptafluorobutanoate
959103-74-3

X

Name
s
18
Uranium-235
15117-96-1


X

s
28
Uranium-238
7440-61-1


X

s
26, 28
Vanadium
7440-62-2


X

s
3, 10
Vellerdiol
51276-18-7

X

Name
c
20
Xylenes
1330-20-7
X
X
X
Name
s
3, 9, 10
Zinc
7440-66-6
X

X

s
3, 9, 10
Zirconium
7440-67-7




s
3, 9, 10
a The following chemicals were found in literature Reference #18 as being present in produced water, but were inadvertently not included in our chemical name/CASRN
matching process. Chemical name/CASRN match was made by the authors of that study and may or may not reflect the preferred match as appears in DSSTox: 1-
Chlorooctadecane, CASRN 3386-33-2; 1-Nonadecene, CASRN 18435-45-5; 17-Pentatriacontene, CASRN 6971-40-0; 2,6,10-Trimethyldodecane, CASRN 3891-98-3; 2,6,10,14-
Tetramethylhexadecane, CASRN 638-36-8; Cyclotriacontane, CASRN 297-35-8; Docosane, CASRN 629-97-0; Hexacosane, CASRN 630-01-3; Pentacosane, CASRN 629-99-2;
Tetracosane, CASRN 646-31-1; and Tricosane, CASRN 638-67-5. Ten out of 11 of these chemicals appear to have physicochemical properties available (all except
Cyclotriacontane) and none have selected toxicity data.
bSome chemicals are designated as "NOCAS_" which are DSSTox database-specific CAS-like identifiers assigned to a listed substance name.
c Chemicals are flagged as having selected toxicity data available if they have one or more oral reference values, oral slope factors, or qualitative cancer classifications available
from the sources presented in Appendix G.
d Chemicals indicated as having a "CASRN" or "Name" change were changed from one or more of the original references cited in the table during the matching process.
H-104
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Table H-5. Chemicals detected in produced water for which a specific, valid CASRN could not
be identified.
These chemicals are either chemically ambiguous or too general for a definitive CASRN to be assigned (e.g.,
stereoisomerism not defined, groups of related compounds).
Chemical Name
Formation Type
Reference
1,1,3-Trimethylcyclopentane
s
18
1,2,4,5-Tetramethylbenzene
s
18
1,6,7-Trimethylnaphthalene
s,c
14,18
l,7,ll-Trimethyl-4-(l-methylethyl)-cyclotetradecane
s
18
1-Chloro-octadecane
s
18
1-Docosene
c
20
l-Methyl-3-propylbenzene
s
18
2,6,10-Trimethyl-dodecane
s
18
2,6-Dimethyloctane
s
18
2,6-Dimethylundecane
s
18
Decane
s
18
Eicosane
s
18
Heptadecane
s
18
Hexadecane
s
18
N-dodecyl-N,N-dimethylamine
s
22
N-tetradecyl-N,N-dimethylamine
s
22
Octacosane
s
18
Octadecane
s
18
Pentadecane
s,c
18,21
Tetratetracontane
s
18
Trimethylbenzenes
s,c
20
Alkyl naphthalene
s
16
Alkyl propo-benzene
s
16
Trimethyl-piperdine
s,c
21
Ethyl-tetrahydronaphthalene
c
20
Alkyl benzene
s
16
Alkyl phosphates
c
21
H-105
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name
Formation Type
Reference
Alkyl phthalates
s,c
21
Bis(2-ethylhexyl)-hexanedioic acid
c
20
C11-C37 alkanes/alkenes
s,c
21
C12, C14, C16, C18 fatty acids
s,c
21
C23-C35 alkanes
c
21
C23-C36 alkanes
c
21
Dimethylphenanthrene
c
20
Dioctyldiphenylamine
c
20,21
Ethyl-cyclodocosane
c
20
Methyl-(2,5-dimethoxyphenol)-methanoate
c
20
Octahydroanthracene
c
20
Octylphenyl ethoxylate
s,c
21
Phenanthrenone
c
20,21
Tetramethylacenaphthylene
c
20
Tetramethylbenzenes
s
12
Tetramethylnaphthalene
c
20
Tetramethylphenanthrene
c
20,21
Trimethylnaphthalene
s,c
12, 20
Trimethylphenanthrene
c
20
1,2-Benzenedicarboxylic acid, 1,2-didecyl ester
s
18
N-hexadecanoic acid
c
20,21
Methyl-biphenyl
s,c
21
1,7,11-Trimethyl-cyclotetradecane
c
20
P-tert-butyl-phenol, p-tert-butyl-
c
21
2a,7a-(Epoxymethano)-2H-cyclobutyl
c
20
Di-tetra-butyl-4-hydroxbenzaldehyde
c
20
Phenanthrene derivative
c
20
Bisphenol F Isomer
s
22
Methoxynaphthalene derivative
c
20
Naphthalenone derivative
c
20
H-106
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name
Formation Type
Reference
Other alkyl phenols
c
20
Other aromatic compounds
c
20
Other benzenamines
c
20
Other benzene alkyl compounds
c
20
Other heterocyclics
c
20
Other indene derivatives
c
20
Other naphthalene alkyl compounds
c
20
Other phthalates
c
20
Other terpenoid compounds
c
20
Quinolo-furazan derivative
c
20
Benzisothiazole derivative
c
20
1-Methylphenanthrene
s
18
Poly(ethylene glycol) bis(carboxymethyl) ether
s
23
Squalene
c
20
Tetrahydro-dimethylnaphthalene
c
21
Trimethoxy-benzaldehyde
c
20
Methylpyrene
c
20
Quinindoline
s,c
21
Benzisothiazole
c
21
Ethyl phenylmethyl benzene
c
20
Dimethyl-ethylindene
c
20
Dihydrophenanthrene
c
20
9-Phenyl-tetrahydro-lH-benz[f]isoindol-l-one
c
20
Methylanthracene
c
20
Methoxyanthracene
c
20
Dimethyl-biphenyl
c
20
Methoxy-methylphenol
c
21
Methylphenanthrene
s,c
20,21
Tert-butyl-phenol
s,c
21
Methyl-2-quinolinecarboxylic acid
c
20
H-107
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name
Formation Type
Reference
Methylethylnaphthalene
c
20
Tetrahydromethylnaphthalene
c
20
Tetrahydrophenanthrene
c
20
Dihydro-l-methylphenanthrene
c
20
1,7,11-Trimethylcyclotetradecane
c
20
Tetrahydro-trimethylnaphthalene
c
20
l-(2-Hydroxy-5-methylphenyl)-2-hexen-l-one
c
20
Ethyl dimethyl azulene
c
20
9- Meth oxyf 1 u o re n e
c
20
l,2-Di-but-2-enyl-cyclohexanone
c
20
9H-Fluoren-9-ol
c
20
l,4-[13C]-l,2,3,4-Tetrahydro-5-naphthaleneamine
c
20
Dihydro-(-)-neocloven-(ll)
c
20
4-(4-Ethylcyclohexyl)-cyclohexene
c
20
Methyl-2-octylcyclopropene-l-octane
c
20
Decahydro-4,4,8,9,10-pentamethylnaphthalene
s,c
21
Hexahydro-l,3,5-trimethyl-l,3,5-triazine-2-thione (a biocide)
s,c
21
8-lsopropyl-2,5-dimethyl-terralin
c
20
9,10-Dimethoxy-2,3-dihydroanthracene
c
20
PEG-C-EO10a
s
22
PEG-C-E023
s
23
PEG-C-E033
s
23
PEG-C-E043
s
23
PEG-C-E053
s
23
PEG-C-E063
s
23
PEG-C-E073
s
23
PEG-C-E083
s
23
PEG-C-E093
s
23
PEG-EO10b
s
23
PEG-E04b
s
23
H-108
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
Chemical Name
Formation Type
Reference
PEG-E05b
s
23
PEG-E06b
s
23
PEG-E07b
s
23
PEG-E08b
s
23
PEG-E09b
s
23
PPG-POIO0
s
23
PPG-P020
s
23
PPG-P030
s
23
PPG-P040
s
23
PPG-P050
s
23
PPG-P060
s
23
PPG-P070
s
23
PPG-P080
s
23
PPG-P090
s
23
a Polyethylene glycol carboxylates containing between four to 10 ethylene oxide monomers.
b Polyethylene glycols containing between four to 10 ethylene oxide monomers.
c Polypropylene glycols containing between two and 10 proplyene oxide monomers.
H-109
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
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H-110
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Appendix I - Unit Conversions
Appendix I. Unit Conversions
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Appendix I - Unit Conversions
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1-2
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Appendix I - Unit Conversions
Appendix I. Unit Conversions
LENGTH
1 in (inch)
1 ft (foot)
1 mi (mile)
AREA
2.54 cm (centimeters)
25.4 mm (millimeters)
25,400 [im (microns)
0.3048 m (meters)
30.48 cm
5,280 ft
1,609.344 m
1.6093 km (kilometers)
1 ft2 (square foot)
1 acre
1 mi2
MASS
0.0929 m2 (square meters)
43,560 ft2
0.0016 mi2 (square miles)
0.4047 ha (hectares)
4,046.825 m2
639.9974 ac
258.9988 ha
2.5899 km2 (square kilometers)
1 lb (pound)
1 ton (short ton, U.S.)
453.5924 g (grams)
0.4536 kg (kilograms)
2,000 lb
907.185 kg
0.9072 metric tons
1-3
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
VOLUME OR CAPACITY (LIQUID MEASURE)
1 bbl (barrel)	=
1 gal
1 Mgal (million gallons)	=
1 ft3
1 mi3 (cubic mile)	=
CONCENTRATION	
1 mg/L (milligram per liter)	=
42 gal (gallons, U.S.)
158.9873 L (liters)
231 in3 (cubic inches)
0.1337 ft3 (cubic feet)
3.7854 L
0.0039 m3 (cubic meters)
3.7854 x 10"9 Mm3 (million cubic meters)
1.3368 x 105 ft3
1,728 in3
7.4805 gal
28.3169 L
0.0283 m3
4.1682 km3 (cubic kilometers)
1.0 x 10"6 kg/L (kilograms per liter)
1.0 x 10"3 g/L (grams per liter)
1.000	|ig/L (micrograms per liter)
1.001	ppm (parts per million)
8.3454 x 10"6 lb/gal (pounds per gallon)
6.2428 x 10"5 lb/ft3 (pounds per cubic foot)
SPEED
1 mi/hr (mile per hour)	=	1.4666 ft/s (feet per second)
=	0.4470 m/s (meters per second)
DENSITY
1 g/mL	= 1,000 g/L
= 1.0 x 106 mg/L
1-4
-------
Appendix I - Unit Conversions
VOLUME PER UNIT TIME
1 ft3/s (cubic foot per second)
1 ft3/day (cubic feet per day)
1 bbl/day (barrel per day)
PRESSURE
448.8312 gpm (gallons per minute)
0.6163 Mgpd (million gallons per day)
28.3169 L/s (liters per second)
0.0283 m3/s (cubic meters per second)
0.0052 gpm
7.4805 gpd
0.0283 m3/d (cubic meters per day)
42 gpd
158.9873 L/d (liters per day)
1 psi (pound per square inch)
RADIATION
6,894.7573 Pa (pascals)
0.068 atm (standard atmospheres)
Activity
1 Ci (curie)
1 Bq (becquerel)
1 pCi
3.7 x 1010 decays per second
2.703 x 10-" ci
27.027 pCi (picocuries)
0.037 Bq
0.037 decays per second
2.22 decays per minute
Exposure
1 rem (roentgen equivalent in man)
1 Sv
ELECTRIC CONDUCTANCE
0.01 Sv (sieverts)
1 J/kg (joule per kilogram)
1 S (siemen)
TEMPERATURE
1 fl-1 (reciprocal of resistance)
1 A/V (ampere per volt)
1 kg-1 • m-2 • s3 • A2 (second cubed- ampere squared
per kilogram-square meter)
1.0 x 106 [j.S (microsiemens)
[°F (degrees, Fahrenheit) - 32] x 5/9 =
°C (degrees, Celsius)
1-5
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Appendix H - Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water
PERMEABILITY
1 cm2
1 D
1.0 x 10-4 m2
1.0 x 108 D (darcys)
1.0 x 10-12 m2
1,000 mD (millidarcys)
1.0 x 106 [iD (microdarcys)
1-6
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Appendix] - Glossary
Appendix J. Glossary
J-i
-------
Appendix] - Glossary
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1-2
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Appendix] - Glossary
Appendix J. Glossary
J.l. Introduction
This glossary is intended to provide definitions for scientific and technical terms used in the rest of
the document For most terms, a citation is provided that indicates the reference from which a
definition was reprinted or adapted. For terms without a citation, the definition was developed for
the purposes of this assessment In some cases, terms in this glossary may also have a legal or
regulatory definition in addition to the definition provided; the definitions of these terms in the
glossary are not intended to replace or modify any such legal or regulatory definitions. The terms in
this glossary do not constitute terms of art for legal or regulatory purposes.
J.2. Glossary Terms and Definitions
Abandoned well: A well that is no longer being used, either because it is not economically
producing or it cannot be used because of its poor condition.
Acid mine drainage: Flow of water from areas that have been mined for coal or other mineral ores.
The water has a low pH because of its contact with sulfur bearing material and is harmful to
aquatic organisms fU.S. EPA. 2013dl
Additive: A single chemical or chemical mixture designed to serve a specific purpose in the
hydraulic fracturing fluid.
Adsorption: Adhesion of molecules of gas, liquid, or dissolved solids to a surface (U.S. EPA. 2013d).
Advection: A mechanism for moving chemicals in flowing water, where a chemical moves along
with the flow of the water itself.
Aeration: The process of mixing air with water or soil. It promotes biological degradation of
organic matter in water. The process may be passive (as when waste is exposed to air) or active (as
when a mixing or bubbling device introduces the air) fU.S. EPA. 2013dl
Aerobic mesophiles: Microorganisms that use oxygen for energy production and are tolerant of
moderate temperatures.
Analyte: The element, ion, or compound that an analysis seeks to identify; the compound of interest
CU.S. EPA. 2013dl.
Annulus: Refers to either the space between the casing of a well and the wellbore or the space
between any two strings of tubing or casing (U.S. EPA. 2013d).
API number: A unique identifying number for all oil and gas wells drilled in the United States. The
system was developed by the American Petroleum Institute fOil and Gas Mineral Services. 20101.
Aquifer: A water-bearing geologic formation, group of formations, or part of a formation.
Groundwater is the water in an aquifer.
J-3
-------
Appendix] - Glossary
Base fluid: The fluid into which additives and proppants are mixed to formulate a hydraulic
fracturing fluid.
Basin: A depression in the crust of the earth, caused by plate tectonic activity and subsidence, into
which sediments accumulate. Sedimentary basins vary from bowl shaped to elongated troughs.
Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental
margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with
appropriate depth and duration of burial, then a petroleum system can develop within the basin.
Most basins contain some amount of shale, thus providing opportunities for shale gas exploration
and production (Schlumberger. 20141.
Bedding plane: The surface that separates two layers of stratified rocks.
Biogenic: Methane that is produced in shallower formations by bacterial activity in anaerobic
conditions. It is the ultimate dissimilation product of microbially mediated reactions of organic
molecules.
Blowout preventer (BOP): Casinghead equipment that prevents the uncontrolled flow of oil, gas,
and mud from the well by closing around the drill pipe or sealing the hole (Oil and Gas Mineral
Services, 2010). BOPs are typically a temporary component of the well, in place only during drilling
and perhaps through hydraulic fracturing operations
Brackish water: A general term used for water having a salinity content intermediate between
fresh water and sea water, although it may also have a more specific definition, such as the 1,000 -
10,000 mg/L TDS value used in some USGS publications.
BTEX: An acronym for benzene, toluene, ethylbenzene, and xylenes. These chemicals are a group of
single ringed aromatic hydrocarbon based on the benzene structure. These compounds are found in
petroleum and are of specific importance because of their health effects.
British thermal unit (Btu): A measure of the heat (or energy) content of fuels.
Caliper log: A log that is used to check for any wellbore irregularities. It is run prior to primary
cementing as a means of calculating the amount of cement needed. Also run in conjunction with
other open hole logs for log corrections or run on cased holes to evaluate metal loss (NYSDEC.
2011).
Capillarity: The action by which the surface of a liquid in contact with a solid is elevated or lowered
depending on the relative attraction of the molecules of the liquid for each other (cohesion) and for
those of the solid (adhesion). Capillary forces arise from the differential attraction between
immiscible fluids and solid surfaces; these are the forces responsible for capillary rise in small-
diameter tubes and porous materials fadapted from Pake. 19781.
Casing: Steel pipe that is lowered into a wellbore. Casing extends from the bottom of the hole to the
surface fSchlumberger. 20141.
1-4
-------
Appendix] - Glossary
Casing, fully cemented: Casing that had a continuous cement sheath from the bottom of the casing
to at least the next larger and overlying casing (or the ground surface, if it is a surface casing).
Casing, partially cemented: Casing that had some portion of the casing that was cemented from
the bottom of the casing to at least the next larger and overlying casing (or ground surface, if it is a
surface casing), but is not fully cemented.
Casing, uncemented: Casing with no cement anywhere along the casing, from the bottom of the
casing to at least the next larger and overlying casing (or ground surface, if it is a surface casing).
Casing inspection log: An in situ record of casing thickness and integrity, to determine whether
and to what extent the casing has undergone corrosion. The term refers to an individual
measurement, or a combination of measurements using acoustic, electrical, and mechanical
techniques, to evaluate the casing thickness and other parameters. The log is usually presented with
the basic measurements and an estimate of metal loss. Today the terms casing evaluation log and
pipe-inspection log are used synonymously (Schlumberger. 2014).
Casing string: An assembled length of steel pipe configured to suit a specific wellbore.
Chemical Abstract Service Registry Number (CASRN): A unique numeric identifier for only one
substance, which serves as a link to information about a specific chemical substance. The CAS
registry covers substances identified from the scientific literature from 1957 to the present, with
additional substances going back to the early 1900s fCAS Registry Service. 20161. For simplicity, we
refer to both pure chemicals and chemical substances that are mixtures, which have a single CASRN,
as "chemicals."
Cation exchange capacity: The total amount of cations (positively charged ions) that a soil can hold.
Cement: Material used to support and seal the well casing to the rock formations exposed in the
wellbore. Cement also protects the casing from corrosion and prevents movement of fluids up the
borehole flJ.S. EPA.2013d1
Cement bond log: A representation of the integrity of the cement job, specifically whether the
cement is adhering solidly to the outside of the casing (Schlumberger. 2014). Used to calculate a
bond index, which varies between 0 and 1, with 1 representing the strongest bond and 0
representing the weakest bond.
Cement squeeze: A remedial cementing operation designed to force cement into leak paths in
wellbore tubulars. The required squeeze pressure is achieved by carefully controlling pump
pressure. Squeeze cementing operations may be performed to repair poor primary cement jobs,
isolate perforations, or repair damaged casing or liner (Schlumberger. 2014).
Centralized waste treatment facility (CWT): Any facility that treats (for disposal, recycling or
recovery of material) any hazardous or non-hazardous industrial wastes, hazardous or non-
hazardous industrial wastewater, and/or used material received from off-site fU.S. EPA. 2012cl.
1-5
-------
Appendix] - Glossary
Coalbed methane: Methane contained in coal seams. A coal seam is a layer or stratum of coal
parallel to the rock stratification fU.S. EPA. 2013dl.
Collapse pressure: The pressure at which a tube, or vessel, will catastrophically deform as a result
of differential pressure acting from outside to inside of the vessel or tube fSchlumberger. 20141.
Collar: A threaded coupling used to join two lengths of pipe such as production tubing, casing, or
liner. The type of thread and style of collar varies with the specifications and manufacturer of the
tubing fSchlumberger. 20141.
Combination truck: A truck tractor or a truck tractor pulling any number of trailers fU.S.
Department of Transportation. 20121.
Community water system: A public water system which serves at least 15 service connections
used by year-round residents or regularly serves at least 25 year-round residents fU.S. EPA.
2013d).
Completion: A term used to describe the assembly of equipment at the bottom of the well that is
needed to enable production from an oil or gas well. It can also refer to the activities and methods
(including hydraulic fracturing) used to prepare a well for production following drilling.
Complexation: A reaction between two chemicals that form a new complex, either through
covalent bonding or ionic forces. This often results in one chemical solubilizing the other.
Compressive strength: Measure of the ability of a substance to withstand compression fNYSDEC.
20111.
Conductor casing: This large diameter casing is usually the first string of casing in a well. It is set or
driven into the unconsolidated material where the well will be drilled to keep the loose material
from caving in fNYSDEC. 20111.
Confidential business information (CBI): Information that is claimed by the submitter to be
entitled to confidential treatment, such as trade secrets, commercial or financial information, or
other information that has been claimed as confidential. This information is generally not publicly
available. The EPA may have special procedures for handling such information. Further discussion
of information claimed to be CBI, including the EPA's process for determining the validity of such
claims, is contained in 40 CFR. Part 2.
Contaminant: A substance that is either present in an environment where it does not belong or is
present at levels that might cause harmful (adverse) health effects (U.S. EPA. 2013d).
Conventional rock formation: Permeable groups of rock with many large, well-connected pore
spaces that allow fluids to move within the rock formation. See also conventional reservoir.
Crosslinked gel: A fluid with polymers that have been linked together through a chemical bond.
The polymer chains link together to form larger chemical structures with higher viscosity.
Increased viscosity allows the fracturing fluid to carry more proppant into the fractures.
1-6
-------
Appendix] - Glossary
Crude oil: A general term for unrefined petroleum or liquid petroleum fSchlumberger. 20141.
Cumulative effect: Combined changes in the environment that can take place as a result of multiple
activities over time and/or space.
Cumulative water use/cumulative water: Refers to the amount of water used or consumed by all
hydraulic fracturing wells in a given area per year.
Cyclical stress: Refers to stress caused by frequent or rapid changes in temperature or pressure.
Deviated well: Any non-horizontal well in which the well bottom is intentionally located at a
distance (e.g., hundreds of feet) laterally from the wellhead.
Directional drilling: The practice of controlling the direction and deviation (angle) of a wellbore
during drilling (SPE. 2016). This enables drilling the wellbore in a predetermined orientation to a
targeted area in the subsurface. Directional drilling is required for drilling a deviated or horizontal
well and is common in unconventional reservoirs.
Discharge: Any emission (other than natural seepage), intentional or unintentional. Includes, but is
not limited to, spilling, leaking, pumping, pouring, emitting, emptying, or dumping (U.S. EPA.
2013d)- Or, where groundwater flows to the surface at springs or through the bottoms of lakes and
rivers.
Disclosure: With respect to the FracFocus Registry, all data submitted for a specific oil and gas
production well for a specific fracture date.
Disinfection byproduct (DBP): A compound formed by the reaction of a disinfectant such as
chlorine with organic material in the water supply (U.S. EPA. 2013d).
Domestic water use: Includes indoor and outdoor water uses at residences, and includes, but is
not limited to, uses such as drinking, food preparation, bathing, washing clothes and dishes,
flushing toilets, watering lawns and gardens, and maintaining pools (USGS. 2015).
Drill bit: The tool used to crush or cut rock during drilling of the well. Most bits work by scraping or
crushing the rock as part of a rotational motion, while some bits work by pounding the rock
vertically fSchlumberger. 2014).
Drill collar: A component of a drill string that provides weight on the drill bit for drilling the well.
Drill collars are thick walled tubular pieces machined from solid bars of steel, usually plain carbon
steel but sometimes of nonmagnetic nickel copper alloy or other nonmagnetic premium alloys
fSchlumberger. 2014).
Drill cutting: The small pieces of broken and ground-up rock generated during the well drilling
process.
Drill string: The combination of the drillpipe, the bottomhole assembly, and any other tools used to
make the drill bit turn at the bottom of the wellbore fSchlumberger. 20141.
1-7
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Appendix] - Glossary
Drilling fluid: Any of a number of liquid and gaseous fluids and mixtures of fluids and solids used
when drilling wellbores fadapted from Schlumberger. 20141.
Drinking water resource: Any groundwater or surface water that now serves, or in the future
could serve, as a source of drinking water for public or private use fU.S. EPA. 2013dl.
Dry gas: Refers to natural gas that occurs in the absence of liquid hydrocarbons (adapted from
Schlumberger. 20141.
Effluent: Waste material being discharged into the environment, either treated or untreated fU.S.
EPA. 2013dl. For the purposes of this assessment, effluent refers to liquid waste material.
Facultative anaerobes: Microorganisms that can use oxygen for energy production if it is present
in their environment, but can also use alternatives for energy production if no oxygen is present
Factor: A feature of hydraulic fracturing operations or an environmental condition that affects the
frequency or severity of impacts.
Fault: A fracture or fracture zone along which there has been displacement of the sides relative to
each other fNYSDEC. 20111.
Field: Area of oil and gas production with at least one common reservoir for the entire area fOil and
Gas Mineral Services. 20101.
Flowback: The term is defined multiple ways in the literature. In general, it is either fluids
predominantly containing hydraulic fracturing fluid that return from a well to the surface or a
process used to prepare the well for production.
Fluid: A substance that flows when exposed to an external pressure; fluids include both liquids and
gases.
Fluid formulation: The entire suite of chemicals, proppant, and base fluid injected into a well
during hydraulic fracturing fU.S. EPA. 2013dl.
Formation: A body of earth material with distinctive and characteristic properties and a degree of
homogeneity in its physical properties fU.S. EPA. 2013dl.
Formation packer: A specialized well casing part that has the same inner diameter as the casing
but whose outer diameter expands to make contact with the formation and seal the annulus
between the uncemented casing and formation, preventing migration of fluids.
Formation fluid: Fluid that occurs naturally within the pores of rock. These fluids consist primarily
of water, with varying concentrations of total dissolved solids, but may also contain oil or gas.
Sometimes referred to as native fluids, native brines, or reservoir fluids.
FracFocus Registry: A registry for oil and gas well operators to disclose information about
hydraulic fracturing well locations, and water and chemical use during hydraulic fracturing
1-8
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Appendix] - Glossary
operations. The registry was developed by the Ground Water Protection Council and the Interstate
Oil and Gas Compact Commission.
Fracture: A crack or breakage surface within a rock.
Fracture complexity: The ratio of horizontal-to-vertical fracture volume distribution, as defined
by Fisher andWarpinski (20121. Fracture complexity is higher in fractures with a larger horizontal
component
Fracture geometry: Refers to characteristics of the fracture such as height, aperture, orientation,
and azimuth.
Fracture half-length: The radial distance from a wellbore to the outer tip of a fracture propagated
from that well fSchlumberger. 20141.
Freeboard: The vertical distance between the level of the water in an impoundment and the
overflow elevation (an outfall or the lowest part of the berm).
Fresh water: Qualitatively refers to water with relatively low TDS (total dissolved solids) that is
most readily available for drinking water currently. We do not use the term to imply an exact TDS
limit, except in Chapter 2 where it refers to water having TDS content up to 3,000 milligrams per
liter.
Frequency: The number of impacts per a given unit (e.g., per geographic area, per unit time, per
number of hydraulically fractured wells, per number of water bodies). Reflecting the scientific
literature, the most common representation of frequency in this assessment is the number of
impacts per hydraulically fractured well.
Gelation: The process in the setting of the cement where it begins to solidify and lose its ability to
transmit pressure to the formation.
Gelled fluid: Fracturing fluids that are usually water-based with added gels to increase the fluid
viscosity to aid in the transport of proppants fSpellman. 2012: Gupta and Valko. 20071.
Groundwater: In the broadest sense, all subsurface water; more commonly that part of the
subsurface water in the saturated zone (Sollev etal.. 19981.
Groundwater age: Refers to how long the water has been in the ground.
Groundwater availability: The amount of groundwater that is available regardless of legal or
physical availability fTWDB. 20121.
Groundwater supply: The amount of groundwater that can be produced given current permits
and existing infrastructure (TWDB. 20121.
Halite: A soft, soluble evaporate mineral commonly known as salt or rock salt Can be critical in
forming hydrocarbon traps and seals because it tends to flow rather than fracture during
1-9
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Appendix] - Glossary
deformation, thus preventing hydrocarbons from leaking out of a trap even during and after some
types of deformation fSchlumberger. 20141.
Hazard evaluation: A component of risk assessment that involves gathering and evaluating data on
the types of health injuries or diseases (e.g., cancer) that may be produced by a chemical and on the
conditions of exposure under which such health effects are produced.
Hazard identification: A process for determining if a chemical or a microbe can cause adverse
health effects in humans and what those effects might be fU.S. EPA. 2013dl.
Henry's law constant: Ratio of a chemical's vapor pressure in the atmosphere to its solubility in
water. The higher the Henry's law constant, the more volatile the compound will be from water
fNYSDEC. 20111.
Horizontal drilling: Drilling a portion of a well horizontally to expose more of the formation
surface area to the wellbore f Oil and Gas Mineral Services. 20101. This is a type of directional
drilling.
Horizontal well: A well that is drilled vertically downward up to a point known as the kickoff point,
where the well turns toward the horizontal, extending into and parallel with the approximately
horizontal targeted producing formation. Directional drilling is required to drill a horizontal well.
Hydraulic fracturing: A stimulation technique used to increase production of oil and gas.
Hydraulic fracturing involves the injection of fluids under pressures great enough to fracture the
oil- and gas-production formations fU.S. EPA. 2011al.
Hydraulic fracturing fluids: Engineered fluids, typically consisting of a base fluid, additives, and
proppant that are pumped under high pressure into the well to create and hold open fractures in
the formation.
Hydraulic fracturing wastewater: Produced water that is managed using practices that include,
but are not limited to, reuse in subsequent hydraulic fracturing operations, treatment and
discharge, and injection into disposal wells. The term is being used in this study as a general
description of certain waters and is not intended to constitute a term of art for legal or regulatory
purposes.1
Hydraulic fracturing water cycle: The cycle of water in the hydraulic fracturing process,
encompassing the acquisition of water, chemical mixing of the fracturing fluid, injection of the fluid
into the formation, the production and handling of produced water, and the ultimate treatment and
disposal of hydraulic fracturing wastewaters.
1 This general description does not, and is not intended to, provide that the production, recovery, or recycling of oil,
including the production, recovery, or recycling of produced water, constitutes "wastewater treatment" for the purposes
of the Oil Pollution Prevention regulation (with the exception of dry gas operations], which includes the Spill Prevention,
Control, and Countermeasure rule and the Facility Response Plan rule, 40 CFR112 et seq.
J-io
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Appendix] - Glossary
Hydraulic gradient: Slope of a water table or potentiometric surface. More specifically, change in
the hydraulic head per unit of distance in the direction of the maximum rate of decrease fU.S. EPA.
2013d).
Hydrocarbon: An organic compound containing only hydrogen and carbon, often occurring in
petroleum, natural gas, and coal fU.S. EPA. 2013dl.
Hydrophilic: A chemical property that describes a tendency to dissolve in water. Literally, "water
loving."
Hydrophobic: A chemical property that describes a tendency to be soluble in nonpolar solvents
and sparingly soluble in water. Literally, "water fearing."
Hydrostatic pressure: The pressure exerted by a column of fluid at a given depth. In Chapter 6, it
refers to the pressure exerted by a column of drilling mud or cement on the formation at a
particular depth.
Imbibition: The displacement of a non-wet fluid (i.e., gas) by a wet fluid (typically water) f adapted
from Pake. 1978).
Immiscible: The chemical property in which two or more liquids or phases are incapable of
attaining homogeneity fU.S. EPA. 2013dl.
Impact: Any change in the quality or quantity of drinking water resources, regardless of severity,
that results from an activity in the hydraulic fracturing water cycle.
Induced fracture: A fracture created during hydraulic fracturing.
Integrated risk information system (IRIS): An electronic database that contains the EPA's latest
descriptive and quantitative regulatory information about chemical constituents. Files on chemicals
maintained in IRIS contain information related to both noncarcinogenic and carcinogenic health
effects fU.S. EPA. 2013dl.
Intermediate casing: Casing that seals off intermediate depths and geologic formations that may
have considerably different reservoir pressures than deeper zones to be drilled (Devereux. 1998:
Baker. 19791.
Karst: A type of topography that results from dissolution and collapse of carbonate rocks, such as
limestone, dolomite, and gypsum, and that is characterized by closed depressions or sinkholes,
caves, and underground drainage (Sollev etal.. 1998).
Kill fluid: A weighted fluid with a density that is sufficient to overcome the formation pressure and
prevent fluids from flowing up the wellbore.
Large truck: A truck with a gross vehicle weight rating greater than 10,000 pounds fU.S.
Department of Transportation. 20121.
Lateral: A horizontal section of a well.
J-ll
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Appendix] - Glossary
Leakoff: The fraction of the injected fluid that infiltrates into the formation (e.g., through an
existing natural fissure) and is not recovered during production (i.e., it does not return through the
well to the surface) (Economides etal.. 2007). Fluids that leak off and are not recovered are
sometimes referred to as "lost" fluids.
Linear gel: A series of chemicals linked together so that they form a chain.
Liner: A casing string that does not extend to the top of the wellbore, but instead is anchored or
suspended from inside the bottom of the previous casing string fSchlumberger. 20141.
Lost cement: Refers to a failure of the cement to be circulated back to the surface during
construction of the well, indicating that the cement has escaped into the formation.
Lowest-observable-adverse effect level (LOAEL): The lowest exposure level at which there are
biologically significant increases in the frequency or severity of adverse effects between the
exposed population and its appropriate control group (U.S. EPA. 2011c).
Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive
toxicant at which the chemical would have no observable adverse reproductive effect, assuming
exposure at 1,000 times that level (OEHHA. 2012).
Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in
drinking water. MCLs are set as close to the MCLG as feasible using the best available analytical and
treatment technologies and taking cost into consideration. MCLs are enforceable standards (U.S.
EPA. 2012a").
Maximum contaminant level goal (MCLG): A non-enforceable health benchmark goal which is set
at a level at which no known or anticipated adverse effect on the health of persons is expected to
occur and which allows an adequate margin of safety (U.S. EPA. 2012a)
Mechanical integrity: The absence of significant leakage within the injection tubing, casing, or
packer (known as internal mechanical integrity), or outside of the casing (known as external
mechanical integrity) fU.S. EPA. 2013dl.
Microaerophiles: Microorganisms that require small amounts of oxygen for energy production.
Microannuli: Very small openings that form between the cement and its surroundings and that
may serve as pathways for fluid migration to drinking water resources.
Microseismic monitoring: A technique to track the propagation of a hydraulic fracture as it
advances through a formation fSchlumberger. 20141.
Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance
at or below which the substance is unlikely to pose a measurable risk of harmful (adverse),
noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a
specified time period (acute, intermediate, or chronic). MRLs should not be used as predictors of
harmful (adverse) health effects fATSDR. 20161.
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Appendix] - Glossary
Mobility: The ratio of effective permeability to phase viscosity. The overall mobility is a sum of the
individual phase viscosities. Well productivity is directly proportional to the product of the mobility
and the layer thickness product (Schlumberger. 20141.
National Pollution Discharge Elimination System (NPDES): A national program under Section
402 of the Clean Water Act for regulation of discharges of pollutants from point sources to waters of
the United States. The Clean Water Act prohibits the discharge of pollutants from any point source
into waters of the United States, except as authorized by the Act, which may include issuance of an
NPDES permit
National Secondary Drinking Water Regulations (NSDWR): Non-enforceable guidelines
regulating contaminants that may cause cosmetic effects (such as skin or tooth discoloration) or
aesthetic effects (such as taste, odor, or color) in drinking water (also referred to as secondary
standards) fU.S. EPA. 2014cl.
Natural gas: A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases in porous
formations beneath the earth's surface, often in association with petroleum. The principal
constituent of natural gas is methane fSchlumberger. 20141.
Natural organic matter (NOM): Complex organic compounds that are formed from decomposing
plant animal and microbial material in soil and water (U.S. EPA. 2013d).
Naturally Occurring Radioactive Materials (NORM): Radioactive materials found in nature that
have not been moved or concentrated by human activities.
No-observed-adverse-effect level (NOAEL): NOAEL is defined as the highest exposure level at
which there are no biologically significant increases in the frequency or severity of adverse effect
between the exposed population and its appropriate control; some effects may be produced at this
level, but they are not considered adverse or precursors of adverse effects (U.S. EPA. 2011c).
Non-community water system: Water systems that supply water to at least 25 of the same people
or have 15 service connections at least six months per year, but not year-round (U.S. EPA. 2013c).
National Toxicology Program (NTP): The NTP describes the results of individual experiments on
a chemical agent and notes the strength of the evidence for conclusions regarding each study. For
more information, see Appendix G.
Octanol-water partition coefficient (Kow): A coefficient representing the ratio of the solubility of
a compound in octanol (a nonpolar solvent) to its solubility in water (a polar solvent). The higher
the Kow, the more nonpolar the compound. Log Kow is generally used as a relative indicator of the
tendency of an organic compound to adsorb to soil. Log Kow values are generally inversely related
to aqueous solubility and directly proportional to molecular weight (U.S. EPA. 2013d).
Offset well: An abandoned (i.e., plugged), inactive, or actively producing well near a well that is
used for hydraulic fracturing.
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Appendix] - Glossary
Open hole completion: A well completion that has no casing or liner set across the reservoir
formation, allowing the produced fluids to flow directly into the wellbore fSchlumberger. 20141.
Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased
cancer risk from a lifetime oral exposure to an agent. This estimate, usually expressed in units of
proportion (of a population) affected per mg/kg day, is generally reserved for use in the low dose
region of the dose response relationship, that is, for exposures corresponding to risks less than 1 in
100 (TJ.S. EPA. 2011cl.
Soil adsorption coefficient [Koc)'- A coefficient that provides a measure of the ability of a chemical
to sorb (adhere) to the organic portion of soil, sediment, and sludge. The higher the Koc, the more
likely a compound is to adsorb to soils and sediments, and the less likely it is to migrate with water.
Along with log Kow, log Koc is used as a relative indicator of the tendency of an organic compound to
adsorb to soil.
Orphaned well: An inactive oil or gas well with no known (or financially solvent) owner.
Overburden: Material of any nature, consolidated or unconsolidated, that overlies a deposit of
useful minerals or ores fU.S. EPA. 2013dl.
Packer: A mechanical device that expands to selectively seal off certain sections of the wellbore to
keep fluid from migrating within the annulus. Packers can be used to seal the space between the
tubing and casing, between two casings, or between the production casing and the surrounding
rock formation (Schlumberger. 2014).
Pad fluid: A mixture of base fluid, typically water and additives without solid, designed to create,
elongate, and enlarge fractures along the natural channels of the formation when injected under
high pressure at the start of the hydraulic fracturing process.
Partial cementing: Cementing a casing string of a well along only a portion of its length.
Passby flow: A prescribed, low-streamflow threshold below which withdrawals are not allowed
fU.S. EPA. 2015dl.
Peer review: A documented critical review of a specific major scientific and/or technical work
product. Peer review is intended to uncover any technical problems or unresolved issues in a
preliminary or draft work product through the use of independent experts. This information is then
used to revise the draft so that the final work product will reflect sound technical information and
analyses. The process of peer review enhances the scientific or technical work product so that the
decision or position taken by the EPA, based on that product, has a sound and credible basis fU.S.
EPA. 2013d").
Perforation: The communication tunnel created from the casing or liner into the reservoir
formation through which injected fluids and oil or gas flows. Also refers to the process of creating
communication channels, e.g., via the use of a jet perforating gun.
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Appendix] - Glossary
Permeability: The ability of fluids (including oil and gas) to flow through well-connected pores or
small openings in the rock. Also referred to as intrinsic or absolute permeability.
Persistence: The length of time a compound stays in the environment, once introduced. A
compound may persist for less than a second or indefinitely.
Physicochemical property: The inherent physical and chemical properties of a molecule such as
boiling point, density, physical state, molecular weight, vapor pressure, etc. These properties define
how a chemical interacts with its environment fU.S. EPA. 2013dl
Play: A set of oil or gas accumulations sharing similar geologic, geographic properties, such as
source rock, hydrocarbon type, and migration pathways f Oil and Gas Mineral Services. 20101.
Poisson's ratio: A ratio of transverse-to-axial (or latitudinal-to-longitudinal) strain; characterizes
how a material is deformed under pressure.
Polar molecule: A molecule with a slightly positive charge at one part of the molecule and a slightly
negative charge on another. The water molecule, H2O, is an example of a polar molecule, where the
molecule is slightly positive around the hydrogen atoms and negative around the oxygen atom.
Porosity: A measure of empty space for a given volume of material, or the percentage of the
material (e.g., rock or soil) volume that can be occupied by oil, gas, or water.
Principal aquifer: A regionally extensive aquifer or aquifer system that has the potential to be
used as a source of potable water.
Private (non-public) water system: Water systems that serve fewer than 15 connections and
fewer than 25 individuals (U.S. EPA. 1991).
Produced water: Water that flows from the subsurface through oil and gas wells to the surface as a
by-product of oil and gas production.
Production casing: The deepest casing set in a well that serves primarily as the conduit for
producing fluids, although when cemented to the wellbore, this casing can also serve to seal off
other subsurface zones including groundwater resources (Devereux. 1998: Baker. 1979).
Production well: A well that is used to bring fluids (such as oil or gas) to the surface.
Production zone: Refers to the portion of a subsurface rock zone that contains oil or gas to be
extracted (sometimes using hydraulic fracturing). The production zone is sometimes referred to as
the target zone or targeted rock formation.
Proppant/propping agent: A granular substance (sand grains, aluminum pellets, or other
material) that is carried in suspension by the fracturing fluid and that serves to keep the cracks
open when fracturing fluid is withdrawn after a fracture treatment fU.S. EPA. 2013dl.
Protected groundwater resource: All aquifers, or their portions, that the state or other regulatory
agency requires to be protected from fluid migration through or along wellbores.
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Appendix] - Glossary
Public water system source: The source of the surface water or groundwater used by a public
water system, including source wells, intakes, reservoirs, infiltration galleries, and springs.
Public water system: Water systems that provide water for human consumption from surface
water or groundwater through pipes or other infrastructure to at least 15 service connections or
serve an average of at least 25 people for at least 60 days a year fSafe Drinking Water Act. 20021.
Publicly owned treatment works (POTW): Any device or system used in the treatment (including
recycling and reclamation) of municipal sewage or industrial wastes of a liquid nature that is owned
by a state or municipality. This definition includes sewers, pipes, or other conveyances only if they
convey wastewater to a POTW providing treatment (U.S. EPA. 2013d).
Quality assurance (QA): An integrated system of management activities involving planning,
implementation, documentation, assessment, reporting, and quality improvement to ensure that a
process, item, or service is of the type and quality needed and expected by the customer (U.S. EPA.
2013d).
Quality assurance project plan (QAPP): A formal document describing in comprehensive detail
the necessary quality assurance procedures, quality control activities, and other technical activities
that need to be implemented to ensure that the results of the work performed will satisfy the stated
performance or acceptance criteria (U.S. EPA. 2013d).
Quality management plan: A document that describes a quality system in terms of the
organizational structure, policy and procedures, functional responsibilities of management and
staff, lines of authority, and required interfaces for those planning, implementing, documenting, and
assessing all activities conducted fU.S. EPA. 2013dl.
Radioactive tracer log: A record of the presence of radioactive tracer material placed in or around
the wellbore to measure fluid movement in injection wells (Schlumberger. 2014).
Radionuclide: Radioactive particle, man made or natural, with a distinct atomic weight number.
Emits radiation in the form of alpha or beta particles, or as gamma rays. Can have a long life as soil
or water pollutant. Prolonged exposure to radionuclides increases the risk of cancer fU.S. EPA.
201M).
Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of
a daily oral exposure to the human population (including sensitive subgroups) that is likely to be
without an appreciable risk of deleterious effects during a lifetime. It can be derived from a NOAEL,
LOAEL, or benchmark dose, with uncertainty factors generally applied to reflect limitations of the
data used. Generally used in EPA's noncancer health assessments (U.S. EPA. 2011c).
Reference value (RfV): An estimate of an exposure or dose for a given duration to the human
population (including susceptible subgroups) that is likely to be without an appreciable risk of
adverse health effects over a lifetime. RfV is a generic term not specific to a given route of exposure
(U.S. EPA. 2011c). In the context of this report, the term RfV refers to reference values for
J-16
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Appendix] - Glossary
noncancer effects occurring via the oral route of exposure and for chronic durations, except where
noted.
Relative permeability: A dimensionless property allowing for comparison of the different abilities
of fluids to flow in multiphase settings. If a single fluid is present, its relative permeability is equal to
1, but the presence of multiple fluids generally inhibits flow and decreases the relative permeability.
Reservoir: A geologic formation where hydrocarbons collect under pressure over geological time.
Conventional reservoir: A reservoir in which buoyant forces keep hydrocarbons in place
below a sealing caprock. Reservoir and fluid characteristics of conventional reservoirs
typically permit oil or natural gas to flow readily into wellbores. The term is used to make a
distinction from shale and other unconventional reservoirs, in which gas might be
distributed throughout the reservoir at the basin scale, and in which buoyant forces or the
influence of a water column on the location of hydrocarbons within the reservoir are not
significant fSchlumberger. 20141.
Unconventional reservoir: A reservoir characterized by lower permeability than
conventional reservoirs. It can be the same formation where hydrocarbons are formed and
also serve as the source for hydrocarbons that migrate and accumulate in conventional
reservoirs. Unconventional reservoirs can include methane-rich coalbeds and oil- and/or
gas-bearing shales and tight sands.
Residuals: The solids generated or retained during the treatment of wastewater fU.S. EPA. 2013d).
Safe Drinking Water Act (SDWA): The act designed to protect the nation's drinking water supply
by establishing national drinking water standards (maximum contaminant levels or specific
treatment techniques) and by regulating underground injection control wells fU.S. EPA. 2013d).
Sandstone: A clastic sedimentary rock whose grains are predominantly sand sized. The term is
commonly used to imply consolidated sand or a rock made of predominantly quartz sand, although
sandstones often contain feldspar, rock fragments, mica, and numerous additional mineral grains
held together with silica or another type of cement The relatively high porosity and permeability of
sandstones make them good reservoir rocks fSchlumberger. 20141.
Science Advisory Board (SAB): A federal advisory committee that provides a balanced, expert
assessment of scientific matters relevant to the EPA. An important function of the Science Advisory
Board is to review EPA's technical programs and research plans fU.S. EPA. 2013d).
Service company: A company that assists well operators by providing specialty services, including
hydraulic fracturing fU.S. EPA. 2013d).
Severity: The magnitude of change in the quality or quantity of a drinking water resource as
measured by a given metric (e.g., duration, spatial extent, contaminant concentration).
Shale: A fine-grained, fissile, detrital sedimentary rock formed by consolidation of clay- and silt-
sized particles into thin, relatively impermeable layers fSchlumberger. 20141.
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Appendix] - Glossary
Shale gas: Natural gas generated and stored in shale.
Shale oil: Oil present in reservoirs that are made up of shale.
Shut in: The process of sealing off a well by either closing the valves at the wellhead, a downhole
safety valve, or a blowout preventer.
Slickwater: A type of fracturing fluid designed to have a low viscosity to reduce friction loss when
pumping the fracturing fluid downhole. The critical additive in a slickwater is friction reducer,
which allows pumping at high rates fBarati and Liang. 20141.
Solubility: The amount of mass of a compound that will dissolve in a unit volume of solution fU.S.
EPA. 2013d").
Sorption: The general term used to describe the partitioning of a chemical between soil and water
and depends on the nature of the solids and the properties of the chemical.
Source water: Surface water or groundwater, or reused wastewater, acquired for use in hydraulic
fracturing.
Spacer fluid: A fluid pumped into the well during construction before the cement to clean drilling
mud out of the wellbore.
Spud (spud a well): To start the well drilling process by removing rock, dirt, and other
sedimentary material with the drill bit fU.S. EPA. 2013dl.
Spill: Any unintended release of fluids. Hydraulic fracturing-related spills are spills that occur at
any phase within the hydraulic fracturing water cycle. These include chemicals, additives, hydraulic
fracturing fluids (chemical mixing phase); flowback and produced water; wastewater.
Stages (frac stages): A single reservoir interval that is hydraulically stimulated in succession with
other intervals.
Stimulation: Refers to (1) injecting fluids to clear the well or pore spaces near the well of drilling
mud or other materials that create blockage and inhibit optimal production (i.e., matrix treatment)
and (2) injecting fluid to fracture the rock to optimize the production of oil or gas.
Stray gas: Refers to the phenomenon of natural gas (primarily methane) migrating into shallow
drinking water resources or to the surface.
Subsurface formation: a mappable body of rock of distinctive rock type(s) and characteristics
(such as permeability and porosity) with a unique stratigraphic position.
Surface casing: The shallowest cemented casing, with the widest diameter. Cemented surface
casing generally serves as an anchor for blowout protection equipment and to seal off drinking
water resources fBaker. 19791.
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Appendix] - Glossary
Surface water: All water naturally open to the atmosphere (rivers, lakes, reservoirs, ponds,
streams, impoundments, seas, estuaries, etc.) fU.S. EPA. 2013dl.
Surfactant: Used during the hydraulic fracturing process to decrease liquid surface tension and
improve fluid passage through the pipes fU.S. EPA. 2013dl.
Sustained casing pressure: The pressure in any well annulus that is measurable at the wellhead
and rebuilds after it is bled down, not caused solely by temperature fluctuations or imposed by the
operator. If the pressure is relieved by venting natural gas from the annulus to the atmosphere, it
will build up again once the annulus is closed (i.e., the pressure is sustained) fSkierven etal.. 20111.
The return of pressure indicates that there is a small leak in a casing or through uncemented or
poorly cemented intervals that exposes the annulus to a pressured source of gas. It is possible to
have pressure in more than one of the annuli.
Targeted rock formation: The portion of a subsurface rock formation that contains oil or gas to be
extracted (sometimes called the "target zone" or the "production zone").
Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass
basis, to which an individual in a (sub) population may be exposed daily over its lifetime without
appreciable health risk (WHO. 2015).
Technically recoverable resource: The volumes of oil and natural gas that could be produced
with current technology, regardless of oil and natural gas prices and production costs fEIA. 20131.
Technologically Enhanced Naturally Occurring Radioactive Material (TENORM): defined by
EPA as naturally occurring radioactive materials (NORM) that have been concentrated or exposed
to the accessible environment as a result of human activities such as manufacturing, mineral
extraction, or water processing.
Temperature log: A log of the temperature of the fluids in the wellbore; a differential temperature
log records the rate of change in temperature with depth and is sensitive to very small changes fU.S.
EPA. 2013dl.
Tensile strength: The force per unit cross sectional area required to pull a substance apart
(Schlumberger. 2014).
Thermogenic: Methane that is produced by high temperatures and pressures in deep formations
over geologic timescales. Thermogenic methane is formed by the thermal breakdown, or cracking,
of organic material that occurs during deep burial of sediment
Tight oil: Oil found in relatively impermeable reservoir rock fSchlumberger. 20141.
Total dissolved solids (TDS): The quantity of dissolved material in a given volume of water. Total
dissolved solids can include salts (e.g., sodium chloride), dissolved metals, radionuclides, and
dissolved organics fU.S. EPA. 2013dl. Salinity and total dissolved solids are frequently
interchangeable terms.
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Appendix] - Glossary
Total petroleum hydrocarbons (TPH): A large family of several hundred chemical compounds
that originally come from crude oil. TPH is a mixture of chemicals, but they are all made mainly
from hydrogen and carbon, called hydrocarbons. TPH are divided into groups of petroleum
hydrocarbons that act alike in soil or water. These groups are called petroleum hydrocarbon
fractions. Each hydrocarbon fraction contains many individual chemicals. Some chemicals that may
be found in TPH are hexane, jet fuels, mineral oils, benzene, toluene, xylenes, naphthalene, and
fluorene, as well as other petroleum products and gasoline components fATSDR. 20111.
Toxicity: The degree to which a substance or mixture of substances can harm humans or animals.
Acute toxicity involves harmful effects in an organism through a single or short-term exposure.
Chronic toxicity is the ability of a substance or mixture of substances to cause harmful effects over
an extended period, usually upon repeated or continuous exposure, sometimes lasting for the entire
life of the exposed organism. Subchronic toxicity is the ability of the substance to cause effects for
more than 1 year but less than the lifetime of the exposed organism (U.S. EPA. 2013d).
Tubing: The smallest, innermost steep pipe set within a completed well, either hung directly from
the wellhead or secured at its bottom using a packer. Tubing is not typically cemented in the well.
Underground Injection Control (UIC): The program under the Safe Drinking Water Act that
regulates the use of wells to emplace fluids into the ground (U.S. EPA. 2013d).
Underground Injection Control (UIC) Class II well: Refers to wells that inject fluids associated
with oil and gas production, including for (1) disposal of fluids brought to the surface in connection
with oil or natural gas production, (2) for enhanced recovery of oil or natural gas, and (3) for
storage of hydrocarbons which are liquid at standard temperature and pressure. Adapted from §
144.6(b).
Underground Injection Control (UIC) Class IID well: Within the types of operations that can
occur for UIC Class II wells (see above), refers to wells used for the disposal of fluids brought to the
surface in connection with oil or natural gas production. Also known as wells for saltwater
disposal.
Underground source of drinking water (USDW): An aquifer or its portion that currently supplies
a public water system; or which contains a sufficient quantity of groundwater to supply a public
water system, and either now supplies water for human consumption, or contains fewer than
10,000 mg/L TDS and is not exempted. Defined in the federal regulations that implementthe UIC
program (20 CFR 144.3).
Unsaturated zone: The soil zone above the water table that is only partially filled by water; also
referred to as the "vadose zone."
Vapor pressure: The force per unit area exerted by a vapor in an equilibrium state with its pure
solid, liquid, or solution at a given temperature. Vapor pressure is a measure of a substance's
propensity to evaporate. Vapor pressure increases exponentially with an increase in temperature
CU.S. EPA. 2013dl.
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Appendix] - Glossary
Vertical separation distance: Measured vertically from the shallowest point of hydraulic
fracturing to the bottom of the drinking water resource. If measured along a wellbore from the
shallowest point of hydraulic fracturing to the bottom of the drinking water resource, this is
referred to as measured depth, which may be a straight vertical distance below ground or may
follow a more complicated path if the wellbore is not straight and vertical.
Vertical well: A well in which the wellbore is vertical throughout its entire length, from the
wellhead at the surface to the production zone.
Viscosity: A measure of the internal friction of a fluid that provides resistance to shear within the
fluid, informally referred to as how "thick" a fluid is.
Volatile: Readily vaporizable at a relatively low temperature fU.S. EPA. 2013dl.
Volatilization: The process in which a chemical leaves the liquid phase and enters the gas phase.
Wastewater: See hydraulic fracturing wastewater.
Wastewater treatment: Chemical, biological, and mechanical procedures applied to an industrial
or municipal discharge or to any other sources of contaminated water in order to remove, reduce,
or neutralize contaminants fU.S. EPA. 2013dl.
Water availability: There is no standard definition for water availability, and it has not been
assessed recently at the national scale fU.S. GAP. 20141. Instead, a number of water availability
indicators have been suggested fe.g.. Roy etal.. 20051. Here, availability is most often used to
qualitatively refer to the amount of a location's water that could, currently or in the future, serve as
a source of drinking water fU.S. GAP. 20141. which is a function of water inputs to a hydrologic
system (e.g., rain, snowmelt, groundwater recharge) and water outputs from that system occurring
either naturally or through competing demands of users.
Water consumption: Water that is removed from the local hydrologic cycle following its use (e.g.,
via evaporation, transpiration, incorporation into products or crops, consumption by humans or
livestock), and is therefore unavailable to other water users (Maupin et al.. 20141.
Water intensity: The amount of water used per unit of energy obtained fNicot etal.. 2014:
Laurenzi and Tersev. 20131
Water reuse: Any hydraulic fracturing wastewater that is used to offset total fresh water
withdrawals for hydraulic fracturing, regardless of the level of treatment required.
Water sensitivity: a formation's physicochemical properties are affected in the presence of water.
An example of a water sensitive formation would be one where the soil particles swell when water
is added, reducing the permeability of the formation.
Water table: The top, or uppermost surface, of groundwater. Below the water table, the ground is
saturated with water.
1-21
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Appendix] - Glossary
Water use: Water withdrawn for a specific purpose, part or all of which may be returned to the
local hydrologic cycle.
Water withdrawal: The volume of water removed from its source, either the groundwater or
diverted from a surface water source, for use, regardless of how much of that volume is returned to
the local hydrologic cycle or consumed without being returned to the hydrologic cycle fNicotetal..
2014: Laurenzi and Tersev. 20131.
Weight-of-evidence (WOE) characterization for carcinogenicity: A system used for
characterizing the extent to which the available data support the hypothesis that an agent causes
cancer in humans. The U.S. EPA issued guidelines in 1986,1996,1999, and 2005. For more
information, see Appendix G.
Well blowout: The uncontrolled flow of fluids out of a well.
Well communication: When activities in a well that is being stimulated affect abandoned or active
(producing) offset wells or their fracture networks. Also referred to as a "frac hit".
Well logging: A continuous measurement of physical properties in or around the well with
electrically powered instruments to infer formation properties. Measurements may include
electrical properties (resistivity and conductivity), sonic properties, active and passive nuclear
measurements, measurements of the wellbore, pressure measurement, formation fluid sampling,
sidewall coring tools, and others. Measurements may be taken via a wireline, which is a wire or
cable that is used to deploy tools and instruments downhole and that transmits data to the surface
(adapted from Schlumberger. 2014).
Well operator: A company that controls and operates oil and gas wells fU.S. EPA. 2013dl.
Well orientation: A well's inclination from verticality. Wells drilled straight downward are
considered to be vertical, wells drilled directionally to end up parallel to the production zone's
bedding plane are considered horizontal, and directionally drilled wells that are neither vertical nor
horizontal are referred to as deviated. In industry usage, a well's orientation commonly refers both
to its inclination from vertical and the azimuthal (compass) direction of a directionally drilled
wellbores.
Well pad: A temporary drilling site, usually constructed of local materials such as sand and gravel.
After the drilling operation is over, most of the pad is usually removed or plowed back into the
ground fNYSDEC. 20111.
Wellbore: The drilled hole or borehole, including the open hole or uncased portion of the well.
Wet gas: Refers to natural gas that typically contains less than 85% methane along with ethane and
more complex hydrocarbons.
Wettability: The ability of a liquid to maintain contact with a solid surface. When wettability is
high, a liquid droplet will lie flat across a surface, maximizing the area of contact between the liquid
J-22
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Appendix] - Glossary
and the solid. When wettability is low, a liquid droplet will approach a spherical shape, minimizing
the area of contact between the liquid and solid.
Wetting/nonwetting: The preferential attraction of a fluid to the surface. In typical reservoirs,
water preferentially wets the surface, and gas is nonwetting fadapted from Pake. 19781.
Workover: Refers to any maintenance activity performed on a well that involves ceasing
operations and removing the wellhead.
Young's modulus: A ratio of stress to strain that is a measure of the rigidity of a material.
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Appendix] - Glossary
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Appendix K. Appendix References
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Appendix K - References
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Front cover (top): Illustrations of activities in the hydraulic fracturing water cycle.
From left to right: Water Acquisition, Chemical Mixing, Well Injection, Produced Water Handling,
and Wastewater Disposal and Reuse.
Front cover (bottom): Aerial photographs of hydraulic fracturing activities.
Left: Near Williston, North Dakota. Image ©J Henry Fair / Flights provided by LightHawk.
Right: Springville Township, Pennsylvania. Image ©J Henry Fair / Flights provided by LightHawk.
Back cover: Top left: DOE/NETL. All other images courtesy of the U.S. EPA.
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