Final Report

Water Quality Literature Review and Field Monitoring of 

Active Shale Gas Wells

Phase I

For

“Assessing Environmental Impacts of Horizontal Gas Well Drilling Operations”

Prepared for:

West Virginia Department of Environmental Protection

Division of Air Quality

601 57th Street, SE

Charleston, WV 25304

Prepared by:

Paul Ziemkiewicz, Ph.D., Director

Jennifer Hause, M.S.

Brady Gutta, B.S.

Jason Fillhart, M.S., M.Ed.

Ben Mack M.S.

Melissa O’Neal, B.S.

West Virginia Water Research Institute

West Virginia University

PO Box 6064

Morgantown, WV 26506-6064

Date:

February 15, 2013
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Disclaimer

The contents of these reports reflect the views of the authors who are responsible for the facts 

and the accuracy of the data presented. The contents DO NOT necessarily reflect the official 

views or policies of the State. These reports do not constitute a standard, specification, or 

regulation. Trade or manufacturers' names which may appear herein are cited only because they 

are considered essential to the objectives of these reports. The State of West Virginia does not 

endorse products or manufacturers. These reports were prepared for the West Virginia 

Department of Environmental Protection.
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Table of Contents

DISCLAIMER............................................................................................................................................. I

TABLE OF CONTENTS ..........................................................................................................................II

LIST OF FIGURES ................................................................................................................................. III

LIST OF TABLES....................................................................................................................................IV

LIST OF ABBREVIATIONS ................................................................................................................... V

EXECUTIVE SUMMARY ........................................................................................................................1

BACKGROUND AND OBJECTIVES OF WATER AND WASTE STREAM STUDY .....................8

LITERATURE REVIEW ........................................................................................................................11

INTRODUCTION........................................................................................................................................11

WATER SOURCES FOR HORIZONTAL SHALE GAS WELL DEVELOPMENT IN THE MARCELLUS...............15

Surface Water......................................................................................................................................15

Groundwater.......................................................................................................................................16

Potable Water Supplies.......................................................................................................................16

Flowback Water Reuse........................................................................................................................17

Other Sources......................................................................................................................................17

WATER AND WASTE STREAMS ASSOCIATED WITH HORIZONTAL GAS WELL DEVELOPMENT ..............18

Drilling Wastes – Liquid and Solid Waste Streams............................................................................21

Commonly Used Hydraulic Fracturing Fluids...................................................................................22

Characteristics of Flowback Waters...................................................................................................26

Radioactivity...................................................................................................................................26

ENVIRONMENTAL AND PUBLIC HEALTH CONCERNS ASSOCIATED WITH WATER AND WASTE STREAMS 

FROM THE DEVELOPMENT OF HORIZONTAL SHALE GAS WELLS ...........................................................29

MANAGEMENT OF WATER AND WASTE STREAMS .................................................................................31

SUMMARY OF BEST AVAILABLE PRACTICES AND TECHNOLOGIES FOR WATER AND WASTE STREAMS33

Storage Options and Practices ...........................................................................................................34

Reuse or Recycle Options and Practices ............................................................................................35

Disposal Options and Practices..........................................................................................................38

PROTECTION OF GROUND AND SURFACE WATERS DURING HORIZONTAL SHALE GAS WELL 

DEVELOPMENT STAGES ..........................................................................................................................42

WATER AND WASTE STREAM MONITORING PLAN..................................................................45

BACKGROUND.........................................................................................................................................45

ROLES AND RESPONSIBILITIES................................................................................................................45

STUDY DESIGN........................................................................................................................................45

SAMPLING SITES .....................................................................................................................................51

FIELD SAMPLING METHODS....................................................................................................................72

Groundwater Monitoring....................................................................................................................73

Water Storage for Well Development .................................................................................................76

Moving Waste Stream .........................................................................................................................77
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Waste Storage .....................................................................................................................................80

ANALYTICAL METHODS..........................................................................................................................80

DATA MANAGEMENT..............................................................................................................................83

DATA ANALYSIS, RESULTS AND COMPARISON WITH WATER QUALITY STANDARDS 85

DRILLING MUDS AND CUTTINGS CHARACTERIZATION AND POLLUTANT IDENTIFICATION...................85

HYDRAULIC FRACTURING FLUIDS AND FLOWBACK COMPARISON AND POLLUTANT IDENTIFICATION 87

IMPOUNDMENT INTEGRITY .....................................................................................................................89

IDENTIFICATION OF POTENTIAL HEALTH CONCERNS AND RECOMMENDATIONS.................................102

REFERENCES........................................................................................................................................105

APPENDIX A: WVWRI PROJECT STAFF ......................................................................................110

APPENDIX B: REI CONSULTANTS CHAIN-OF-CUSTODY FORM..........................................111

APPENDIX C: PACE ANALYTICAL CHAIN OF CUSTODY FORM..........................................112

APPENDIX D: INDIVIDUAL SITE CHECKLISTS .........................................................................113

SITE CHECKLIST – CHESAPEAKE DNR A PAD ......................................................................................114

SITE CHECKLIST – LEMONS PAD...........................................................................................................116

SITE CHECKLIST – MAURY PAD............................................................................................................118

SITE CHECKLIST – MILLS WETZEL PAD #2...........................................................................................120

SITE CHECKLIST – MILLS WETZEL PAD #3...........................................................................................122

SITE CHECKLIST – SAND HILL LOCATION ............................................................................................124

SITE CHECKLIST – WEEKLEY PAD ........................................................................................................126

SITE CHECKLIST – WACO/DONNA PAD ................................................................................................128

APPENDIX E: FIELD SPREADSHEETS ..........................................................................................130

List of Figures

FIGURE 1: CENTRALIZED PITS LOCATIONS ................................................................................................54

FIGURE 2: SHL-1 IMPOUNDMENT SAMPLING ............................................................................................55

FIGURE 3: SHL-1 IMPOUNDMENT SAMPLING ............................................................................................55

FIGURE 4: LEMONS PAD – SHAKER TABLE LIQUIDS ..................................................................................56

FIGURE 5: LEMONS PAD – SHAKER TABLE SOLIDS....................................................................................57

FIGURE 6: LEMONS PAD – VERTICAL DRILLING FLUIDS ...........................................................................57

FIGURE 7: MILLS WETZEL PAD #2 SHAKER TABLE (WHERE SAMPLES WERE PULLED) .............................59

FIGURE 8: DONNA PAD PIT SAMPLING OF HYDRAULIC FRACTURING (MAKEUP) WATER ........................60

FIGURE 9: SAMPLING HYDRAULIC FRACTURING FLUIDS AND WATER MIXTURE BEFORE ENTERING WELL

............................................................................................................................................................60

FIGURE 10: SAMPLING LOCATION OF HYDRAULIC FRACTURING FLUIDS..................................................61

FIGURE 11: FLOWBACK SAMPLING POINT AT CONDENSATE TANKS, DONNA PAD ...................................63

FIGURE 12: COMPOSITE FLOWBACK STREAM SAMPLE AT DONNA PAD SINGLE-LINED PIT .....................63

FIGURE 13: WEEKLEY PAD SAMPLE AREA – SAMPLE TAKEN FROM THE NOZZLE (SEE ARROW)...............64
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FIGURE 14: SAMPLE AREA AT THE SAND HILL # 3 AND #4 (AT LOWER RIGHT) PITS .................................65

FIGURE 15: LOCATION OF CONSOL/NOBLE CENTRALIZED PITS ................................................................67

FIGURE 16: CONSOL/NOBLE CENTRALIZED PIT SHL3 ..............................................................................68

FIGURE 17: CONSOL/NOBLE CENTRALIZED PITS SHL2 AND SHL4 ..........................................................69

FIGURE 18: BOTTLES FOR TYPICAL GROUNDWATER SAMPLE...................................................................70

FIGURE 19: COLLECTION OF GROUNDWATER SAMPLE FROM CONSOL/NOBLE CENTRALIZED PIT SHL2.71

FIGURE 20: LOW FLOW SAMPLING AT SHL3 GROUNDWATER MONITORING WELL .................................72

FIGURE 21: RELATIONSHIP BETWEEN TPH AND BENZENE ........................................................................99

FIGURE 22: RELATIONSHIP OF CHLORIDE AND BROMIDE IN SOURCE WATERS.......................................100

FIGURE 23: BARIUM/CHLORIDE (BA/CL) RELATIONSHIP IN IMPOUNDMENT WATER AND GROUNDWATER

..........................................................................................................................................................101

List of Tables

TABLE 1: CHEMICAL CHARACTERISTICS OF INFLUENT AND FLOWBACK WATERS ...................................20

TABLE 2: HYDRAULIC FRACTURING ADDITIVES .......................................................................................25

TABLE 3: WATER AND WASTE STREAM SAMPLING PLAN .........................................................................48

TABLE 4: WATER AND WASTE STREAM PARAMETERS .............................................................................49

TABLE 5: SAMPLING SITE LOCATIONS .......................................................................................................51

TABLE 6: GROUNDWATER MONITORING WELLS AT CONSOL/NOBLE CENTRALIZED PITS .......................66

TABLE 7: REI CONSULTANTS – INORGANIC AND ORGANIC DATA CHECK................................................82

TABLE 8: PACE ANALYTICAL – RADIOACTIVITY DATA CHECK ................................................................83

TABLE 9: AVERAGE CONCENTRATIONS OF INORGANIC PARAMETERS......................................................92

TABLE 10: AVERAGE CONCENTRATIONS OF ORGANIC PARAMETERS .......................................................93

TABLE 11: FIELD RADIATION READINGS FOR DRILL CUTTINGS AND DRILLING MUDS ............................94

TABLE 12: RADIOACTIVITY RESULTS OF DRILLING MUDS AND FLOWBACK SOLIDS SAMPLES................95

TABLE 13: EXCEEDANCES OF DRINKING WATER STANDARDS..................................................................96

TABLE 14: SUMMARY OF RADIOACTIVE DETERMINATIONS FROM FLOWBACK LIQUIDS SAMPLES ..........97

TABLE 15: SUMMARY OF RADIOACTIVE DETERMINATIONS FROM GROUNDWATER MONITORING WELLS

............................................................................................................................................................98

TABLE 16: GROUNDWATER EXPOSURE TO SHALE GAS WASTE STREAMS ..............................................102
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List of Abbreviations

Ag Silver

Alk Alkalinity

Al Aluminum

AMD Acid mine drainage

As Arsenic

ASTM American Society for Testing and Materials

Ba Barium

BOD Biochemical oxygen demand

Br Bromide

BTEX Benzene, toluene, ethylbenzene and xylene

Btu British thermal unit

Ca Calcium

CFR Code of Federal Regulations

Cl Chloride

CO3

2- Carbonate

COC Chain of custody

COD Chemical oxygen demand

Cr Chromium

CSR Code of State Rules

CWA Clean Water Act

CWT Centralized waste treatment facility

DO Dissolved oxygen

DRO Diesel range organics

E&P Exploration and production
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EC Electro-conductivity

EIA Department of Energy’s Energy Information Administration

EPA United States Environmental Protection Agency

FB Flowback

Fe Iron

FR Flame resistant

ft Feet

gpm Gallons per minute

GPS Global Positioning System

GW Groundwater

HCO3 Bicarbonate

HF Hydraulic fracturing, fracking or frac

HFF Hydraulic fracturing fluids

Hg Mercury

I Inorganic (parameters)

K Potassium

LPG Liquefied petroleum gas

MBAS Methylene blue active substances (surfactants)

MCL Maximum contaminant level

MCLG Maximum contaminant level goal

Mg Magnesium

mg/L Milligrams per liter

Mn Manganese

mrem/hr Millirems per hour (rem = roentgen equivalent man)

MU Makeup 
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Na Sodium

ND Not determined

Ni Nickel

NO2 Nitrite

NO3 Nitrate

NORM Naturally occurring radioactive materials

NPDES National Pollutant Discharge Elimination System

OSHA Occupational Safety and Health Administration

Pb Lead

pCi/g Picocuries per gram

pCi/L Picocuries per liter, United States unit for volumetric concentration

PID Photo-ionization detector 

PO4 Phosphate

POTW Publicly owned treatment works

ppb Parts per billion

PPE Personal protective equipment

ppm Parts per million

ppt Parts per trillion

QA/QC Quality Assurance/Quality Control

R Radioactive (parameters)

RCRA Resource Conservation and Recovery Act

RO Reverse osmosis

S Sulfide

SDWA Safe Drinking Water Act

Se Selenium
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SO4 Sulfate

SOPs Standard Operating Procedures

Sr Strontium

SVOC Semi-volatile organic compounds

TDS Total dissolved solids

TENORM Technically enhanced naturally occurring radioactive material

THM Trihalomethane

TOC Total organic carbon

TPH Total petroleum hydrocarbons

TSS Total suspended solids

μg/L Micrograms per liter

μmhos/cm Micromhos per centimeter (1 μmhos/cm = 1 μS/cm)

μS/cm MicroSiemens per centimeter (1 μS/cm = 1 μmhos/cm)

USGS United States Geological Survey

VOC Volatile organic compound

WVDEP West Virginia Department of Environmental Protection 

WVU West Virginia University

WVWRI West Virginia Water Research Institute

Zn Zinc
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Executive Summary

This report summarizes the results of the phase I study “Water Quality Literature Review and 

Field Monitoring of Active Shale Gas Wells.” In addition to the literature review, the phase I

report consists of solid and liquid waste stream characterization and recommendations to reduce 

environmental exposure. It also contains initial results of groundwater monitoring at three 

centralized waste water impoundments. These impoundments were constructed with double 

polymer liners. Monitoring wells were installed at a second impoundment site in mid February 

2013. The phase II report will include results of extended monitoring at the centralized and 

single impoundment sites. 

Legislative Direction 

Although hydraulic fracturing is not a new technique, its rapid development in the Marcellus 

Shale Formation has caused concern regarding the potential risks to human health and the 

environment. On December 14, 2011, the West Virginia Legislature (Code of State Regulations 

§22-6A) enacted the Natural Gas Horizontal Well Control Act. The act directs the West Virginia 

Department of Environmental Protection (WVDEP) to conduct several studies in order to collect 

information and report back its findings and recommendations. In summary the act requires a 

report that addresses the human health issues related to:

• Light and noise

• Air emissions

• Impoundment safety

• Water and waste streams

The scope of the study begins with initial well development and ends with the initiation of gas 

production. In support of these legislative mandates, the WVDEP solicited a team of researchers 
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from West Virginia University (WVU) to conduct these studies. Led by the West Virginia Water 

Research Institute (WVWRI), the WVU researchers studied horizontal gas well development 

activity impacts on air and water quality, generated light and noise, and structural integrity and 

safety of the pits and impoundments retaining fluids from well development. The studies 

included literature reviews followed by direct field monitoring. This report focuses on the 

activities undertaken to conduct the water and solid waste stream study. Findings from the 

air emissions, light and noise study and the pits and impoundments safety study are contained in 

separate reports. 

In 1988, the United States Environmental Protection Agency (EPA) issued a regulatory 

determination stating that control of exploration and production (E&P) wastes under the 

Resource Conservation and Recovery Act (RCRA) Subtitle C regulations is not warranted. 

Hence, E&P wastes have remained exempt from Subtitle C regulations. The RCRA Subtitle C 

exemption, however, did not preclude these wastes from control under state regulations, under 

the less stringent RCRA Subtitle D solid waste regulations, or under other federal regulations. In 

addition, although they are relieved from regulation as hazardous wastes, the exemption does not 

mean these wastes could not present a hazard to human health and the environment if improperly 

managed. For the purposes of this report, waste streams will be indicated as “solid or liquid 

wastes” as defined by RCRA Subtitle D.

Hydraulic fracturing

Hydraulic fracturing (injection of a water-based fluid and sand mixture) technology, coupled 

with horizontal drilling, has facilitated exploitation of huge natural gas reserves in the Devonianage Marcellus Shale Formation of the Appalachian Basin. The most widely used technique for 

stimulating Marcellus gas production involves hydraulic fracturing along a horizontal wellbore

to create a series of thin (generally less than 1 millimeter thick) fractures in the shale. The 
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fractures are filled with a proppant such as sand to keep them open and conduct gas to the 

wellbore where it is conveyed to pipelines for transport and distribution.

The hydraulic fracturing process usually involves surface water withdrawal and disposal of waste 

fluids. When the injection phase is over, 10% to 40% of the injected fluid returns to the surface

through the well casing. These fluids are captured for later reuse or disposal and are referred to 

as flowback. Flowback typically lasts for 4 to 6 weeks during which the water discharge rate 

decreases from about 150 gallons per minute (gpm) to about 1 gpm. Flowback water is highly 

saline with varying amounts of organic contamination. It can be disposed of, either by injection 

into an approved underground injection well, or treated to remove contaminants so that the water 

meets the requirements for either surface release, or for use as makeup water for subsequent 

hydraulic fracturing operations. 

The Study

An extensive literature review was conducted to characterize the water and waste streams 

associated with the development of horizontal shale gas wells including commonly used 

hydraulic fracturing fluids. Specific areas of review included: potential issues related to public 

health and the environment, and safety aspects of hydraulic fracturing development; surface and 

groundwater contamination; and well development practices to protect surface and groundwater

sources during the well development. The literature review was used in developing an on-site 

water and waste stream monitoring plan by defining sample parameters and procedures. The 

water and waste stream monitoring plan was updated as active horizontal well sites were 

monitored and study design and sampling methods were adjusted to field conditions.

The focus of the study was on sampling and chemical analysis of drilling fluids, muds and 

cuttings along with hydraulic fracturing fluids and flowback waters of working hydraulic 
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fracturing sites in the Marcellus Formation in West Virginia. The list of analytical parameters 

used in this study was developed through literature review and finalized in conjunction with the 

staff of WVDEP. The list includes both primary and secondary drinking water contaminants. 

Contaminants were evaluated based on exceedance of maximum contaminant levels as identified 

under the Safe Drinking Water Act (SDWA). 

Permitting the construction of centralized pits for the storage of flowback water has recently 

begun in West Virginia. Groundwater monitoring is required for centralized pits in West 

Virginia and thus groundwater monitoring wells were installed by the permit holder and samples 

collected prior to the use of the pits to store flowback water. As of the date of this study, only 

one permit had been issued for a cluster of three centralized pits. This site was selected for 

groundwater monitoring as well as waste storage monitoring. During well development and 

hydraulic fracturing, these pits contained water for use in hydraulic fracturing fluid makeup. 

After hydraulic fracturing, the impoundments were converted to flowback storage. Water in the 

impoundments was analyzed before and after conversion to flowback storage. Monitoring wells 

were sampled to identify any groundwater contaminants before and after placement of flowback 

in the impoundments.

Site Sampling

In order to meet the timeline specified by WVDEP, sampling reported in this part of the study 

took place between June and December 2012. Multiple wells sites were sampled during that 

period in order to collect data from multiple sites during the various well development and 

completion stages. Active horizontally drilled and hydraulically fractured wells in northern West 

Virginia were sampled to determine contaminant concentrations in:

• Hydraulic fracturing fluids
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• Flowback

• Drilling muds and cuttings

• Groundwater monitoring wells

WVDEP contacted natural gas developers and established access to Marcellus gas well sites for 

WVU researchers to collect water and waste stream samples. Liquid and solid samples were 

collected and analyzed for a wide range of inorganic, organic and radioactive constituents to 

ascertain and document the characteristics of the water and waste streams associated with the 

various stages of horizontal gas well development. While in the field, WVU researchers noted 

current weather conditions and sampling time. They conducted a general radiation sweep of the 

site and of the collected samples with a handheld radiation alert detector that displayed current 

radiation levels in millirems per hour (mrem/hr). They also scanned for off-gases of volatile 

organic compounds (VOCs) with a photo-ionization detector (PID) as part of personal safety 

procedures. Parameters such as pH, specific conductivity, total dissolved solids (TDS), 

dissolved oxygen, salinity and temperature of samples were measured in the field using a multiparameter YSI56 unit. For each stage of horizontal gas well development, at least one site was 

identified for sampling. 

To ensure complete site information was obtained and field monitoring and sampling activities 

remained consistent from site to site, a site checklist was developed. The checklist includes 

information relevant to the site location, stage of well development, samples collected and field 

observations. Samples were sent to certified laboratories. Samples were sent to REI Consultants 

for organic and inorganic compound determinations and to Pace Analytical for radioactivity

analysis. It is important to note that all chemical determinations are for total as opposed to 

dissolved concentrations. It is also important to note that one of the organic parameters, TPH 
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(diesel range), is a measure of all hydrocarbons in the range of C11 to C28. This range includes 

not only diesel fuel but the plant products: vegetable oil and guar gum. The latter is a common 

additive in hydraulic fracturing fluids. Our analyses also included the organic compounds 

benzene, toluene, ethyl benzene and xylene. These, particularly benzene, are superior indicators 

of toxicity. 

The nomenclature for hydraulic fracturing wastewaters is not standardized across the industry. 

For the purposes of this study hydraulic fracturing fluids refer to the fluids injected with 

proppant in order to generate sufficient pressure to create fractures within the targeted formation. 

The term flowback refers to all fluids that return to the wellhead after hydraulic fracturing and 

prior to gas production. This includes hydraulic fracturing fluids, gases, gas liquids and water. 

Produced water consists of fluids that return to the wellhead subsequent to gas production. In 

addition, reference to brines within this report refers to flowback waters with TDS values greater 

than 35,000 milligrams per liter (mg/L). As the well is drilled, muds are used to cool the drill bit, 

control well pressures and lift rock cuttings to the surface. Cuttings and muds are separated at 

the surface where muds are typically recycled. Spent drilling muds and cuttings are removed for 

disposal. 

Findings 

Study objectives include: 1) Characterize drilling muds and cuttings and identify pollutants, 2) 

compare hydraulic fracturing fluids with flowback and identify hazardous pollutants, and 3)

identify if groundwater monitoring wells indicated impoundment leakage. 

1. Characterize drilling muds and cuttings and identify pollutants. Drilling muds were 

analyzed as liquids while drill cuttings were analyzed as solids. With the exception of 

arsenic, mercury, nitrate and selenium, the average concentrations of the primary and 
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secondary drinking water parameters in drilling mud were in excess of all of the 

inorganic drinking water standards. They also exceeded the drinking water standards for 

benzene and surfactants (MBAS) and contained high concentrations of sodium, 

potassium and chloride. TPH (diesel range) was present in all drilling muds with 

concentrations ranging from 23 mg/L to 315 mg/L. Background levels of radiation 

ranged from 0.005 millirems per hour (mrem/hr) to 0.013 mrem/hr. Sample levels of 

radiation ranged from 0.009 mrem/hr to 0.016 mrem/hr. The standard for contamination 

is typically twice background. A review of the individual background levels of radiation 

indicated that this criterion was not exceeded. 

2. Compare hydraulic fracturing fluids with flowback and identify pollutants. Two 

hydraulic fracturing fluids and thirteen flowback samples were analyzed. One hydraulic 

fracturing fluid sample contained benzene in measurable quantities while ten of the 

thirteen flowback samples contained benzene in concentrations in excess of the primary 

drinking water standard of 5 μg/L. Both hydraulic fracturing fluids and all of the drilling 

mud and flowback samples contained total petroleum hydrocarbons (TPH) in the diesel 

range. It is important to note this determination, also known as diesel range organics 

(DRO), does not indicate that diesel is present. Rather, it indicates that hydrocarbons in 

the range of C11 to C28 are present. This could include diesel or common hydraulic 

fracturing fluid additives such as guar gum, an extract of the guar bean used to increase 

the viscosity of the hydraulic fracturing fluid to efficiently deliver the proppant into the 

formation. There was no correlation between concentrations of benzene and TPH (diesel 

range). All flowback samples contained high concentrations of inorganic ions including 

sodium, chloride, bromide and barium.
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3. Impoundment leakage. There was no evidence of significant leakage of flowback from 

the impoundments. Nitrate and lead were detected in monitoring wells in excess of 

primary drinking water standards. The concentration of nitrite exceeded the maximum 

contaminant level (MCL) of 1 mg/L in three of five shallow monitoring wells by a 

maximum of 0.47 mg/L. However, while nitrate exceeded the primary MCL in samples 

taken after conversion of the impoundments to accept flowback, the single lead 

exceedance occurred prior to conversion. As is common in West Virginia wells, iron, 

aluminum and manganese exceeded the secondary drinking water standard in both 

shallow and deep wells both before and after conversion of the impoundments from 

holding freshwater to flowback. The impoundment wells did not, however, indicate 

elevated chloride, bromide or barium concentrations as would be expected if flowback 

leakage occurred in significant quantities. In addition, while flowback contains 

measurable benzene and diesel range organics, neither was detected in the monitoring 

wells. While the monitoring wells detected no contaminants it is not clear that the 

monitoring interval of 146 days was sufficient to capture any leakage from the 

impoundments. A longer sampling is suggested with, perhaps, aquifer permeability 

testing.

Background and Objectives of Water and Waste Stream Study

In West Virginia, around 3,000 wells have been identified as targeting the Marcellus or Utica 

Shale Formations. These wells are reported to have the potential to recover more than 100 

trillion cubic feet of natural gas (1). With current United States annual consumption rates, this 

quantity of natural gas could meet the energy needs of the United States for several decades.
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As pressure for fossil fuel production grows, the proximity of communities to exploration and 

extraction operations increases along with the potential for human exposure to potential hazards 

and pollution. With recent increased activity tapping the gas reserves of the Devonian Shale, 

public concern over the potential impacts of horizontal drilling and hydraulic fracturing has also 

increased. Although hydraulic fracturing is not a new technique, the rate of which it has been 

used recently in the Marcellus Shale Formation has greatly escalated bringing with it elevated 

concerns of environmental impacts. Few studies have been published on the health effects of oil 

and gas exploration and extraction activities on nearby communities. 

The Natural Gas Horizontal Well Control Act enacted by the West Virginia Legislature at CSR 

§22-6A on December 14, 2011, directs the West Virginia Department of Environmental 

Protection (WVDEP) to conduct several studies in order to collect information and report back 

its findings and recommendations. In particular, the following studies were directed by the new 

legislation:

§22-6A-12 (e) Well location restrictions. 

The secretary shall, by December 31, 2012, report to the Legislature on the noise, light, dust and 

volatile organic compounds generated by the drilling of horizontal wells as they relate to the 

well location restrictions regarding occupied dwelling structures pursuant to this section. Upon 

finding, if any, by the secretary that the well location restrictions regarding occupied dwelling 

structures are inadequate or otherwise require alteration to address the items examined in the 

study required by this subsection, the secretary shall have the authority to propose for 

promulgation legislative rules establishing guidelines and procedures regarding reasonable 

levels of noise, light, dust and volatile organic compounds relating to drilling horizontal wells, 

including reasonable means of mitigating such factors, if necessary.
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§22-6A-22 Air quality study and rulemaking.

The secretary shall, by July 1, 2013, report to the Legislature on the need, if any, for further 

regulation of air pollution occurring from well sites, including the possible health impacts, the 

need for air quality inspections during drilling, the need for inspections of compressors, pits and 

impoundments, and any other potential air quality impacts that could be generated from this type 

of drilling activity that could harm human health or the environment. If he or she finds that 

specialized permit conditions are necessary, the secretary shall promulgate legislative rules 

establishing these new requirements.

§22-6A-23 Impoundment and pit safety study; rulemaking.

The secretary shall, by January 1, 2013, report to the Legislature on the safety of pits and 

impoundments utilized pursuant to section nine of this article including an evaluation of whether 

testing and special regulatory provision is needed for radioactivity or other toxins held in the 

pits and impoundments. Upon a finding that greater monitoring, safety and design requirements 

or other specialized permit conditions are necessary, the secretary shall propose for 

promulgation legislative rules establishing these new requirements.

In support of these legislative mandates and at the request of WVDEP, a team of researchers 

from West Virginia University (WVU), led by the West Virginia Water Research Institute 

(WVWRI), examined the effects of gas drilling on surrounding air and groundwater and 

identified potential environmental health and safety impacts of the large pits and impoundments 

used to retain liquids and solids associated with the development of shale gas wells. Research 

teams conducted literature reviews and developed and implemented environmental monitoring 

studies to identify the effects of horizontal gas well development on air and water quality, 

generated light and noise, and structural integrity and safety of the pits and impoundments 
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retaining fluids from well development. To fulfill the obligations of the water and waste stream 

portion of the study titled, “Assessing Environmental Impacts of Horizontal Gas Well Drilling 

Operations,” the objectives include: 

1. Conduct a review of relevant literature on the use of hydraulic fracturing fluids and the 

water and waste streams created during the various stages of horizontal gas well 

development. 

2. Based on the literature review, identify concerns with potential surface and groundwater

contamination that may be caused by horizontal well development and identify protective 

measures for surface and groundwater during the well drilling process.

3. Develop and implement an on-site monitoring plan of the various water and waste 

streams associated with horizontal gas well development to identify potential health 

concerns or associated environmental risks.

4. Analyze the data collected during the monitoring portion of the study and compare results 

to primary and secondary drinking water quality standards. 

5. Note any potential public health concerns or risks to the environment and include in the 

final report to the West Virginia Department of Environmental Protection (WVDEP).

Literature Review

Introduction

Fossil fuels – coal, oil and natural gas – supply more than 85% of the nation’s energy. Natural

gas has a high British thermal unit (Btu) content, is an efficient and reliable energy source and is 

the cleanest burning of the fossil fuels (2). Reliance on natural gas as an energy source will not 

diminish in the foreseeable future. With recent increasing demands on energy, easily accessible 

oil and gas reservoirs decreasing, and success tapping unconventional natural gas resources in 
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the United States, natural gas from unconventional resources is anticipated to become an everincreasing portion of the country’s natural gas reserves. Natural gas from unconventional 

resources currently accounts for nearly half of the country’s total production (3). Development 

of the extensive natural gas reserves contained in the Marcellus Shale deposits promises to be an 

important opportunity for the United States because of its proximity to major markets in the 

northeastern United States (4 and 5). 

Shale gas is a natural gas from shale formations and consists of a combination of hydrocarbon 

gases but is largely made up of methane. Shale gas is found in rock formations beneath the 

surface of the earth and at times is present with oil deposits. Shale is a sedimentary rock made 

up mainly of clay-sized particles that tend to lay flat as sediments accumulate and become 

compacted with additional sediment deposits over time. Organic matter is trapped along with 

these sediments. The sheet-like clay mineral grains and layers of sediment result in a rock with 

limited horizontal permeability and extremely limited vertical permeability. These low 

permeable and often rich-organic units are thought to be the source for much of the hydrocarbon 

gases produced in the basins (6). In other words, shale gas is created and stored within the shale 

bed. Low permeability means the gas trapped in the shale cannot move easily within the rock

and must be stimulated to release the gas and allow it to flow up through the wellbore hole.

Extraction of gas from the Marcellus is considered to be unconventional by the Department of 

Energy’s Energy Information Administration (EIA) because the gas is found within a shale 

formation rather than sandstone or limestone (7). Major shale deposits under development in the 

United States all have the common characteristics of low porosity and permeability. Extraction 

from shale gas reservoirs like the Marcellus requires either vertical or horizontal drilling coupled 
13 | Page

with hydraulic fracturing to access and release the gas. Also required are strategies for sourcing 

makeup water and handling wastewater.

The Marcellus Shale Formation is thought to be among the largest natural gas reserves in the 

world. It covers an area of approximately 95,000 square miles overlaying much of the 

Appalachian Basin stretching from West Virginia in the south through New York in the north. 

The Marcellus Shale is a Middle Devonian-age shale, a member of the Hamilton Group; found 

more than a mile (5,000 to 9,000 feet) underground and ranging in thickness from 50 to 200 feet 

surrounded with limestone below and an additional shale layer above (5). It is an organic rich 

rock, the remnants of an ancient river delta, laced with trapped gas, mostly methane. Driven by 

application of existing technology to tap this natural gas reserve thousands of feet below the 

earth’s surface, development of the Marcellus reservoir has transformed the energy industry 

sending United States natural gas prices to all-time lows and the possibility of the country 

becoming energy-independent within the foreseeable future to an all-time high.

Advances in refining cost-effective horizontal drilling and hydraulic fracturing practices have 

changed the ability to tap unconventional shale reservoirs and produce a sustainable product. 

However, rapid application of these technological advancements has increased concern about 

environmental impacts mainly because of the uncertainty that surrounds the techniques involved. 

It is important to understand the technologies and practices in use and what is needed to prevent 

or minimize potential effects of shale gas development on water resources.

Shale gas development has consisted of drilling and completing vertical and horizontal wells. 

Regardless of the type of well, casing and cement are installed to protect fresh and treatable 

water aquifers. The combination of horizontal drilling and hydraulic fracturing technologies 
14 | Page

provide several environmental and economic advantages over conventionally drilled vertical 

wells. Technological advances allow natural gas companies to use less surface area, drill fewer 

wells to access the same reserves, and generate less wastes (8). Therefore, to optimize recovery 

of shale gas in the most economical way, operators are using more horizontal wells. Horizontal 

drilling exposes more of the formation creating a huge advantage over the use of vertical wells. 

Multiple horizontal wells can be launched from one well pad targeting different zones. Six to 

eight horizontal wells drilled from only one well pad can access the same reservoir volume as 

sixteen vertical wells and the use of these multi-well pads reduces the overall environmental 

impact (3). Reducing the size of the shale operations’ footprint is at the top of the list for 

companies seeking to become more environmentally friendly. Industry is designing their well 

pads to better meet their needs and reduce the impact on the surrounding environment. The use 

of multiple wells with multiple stages of fractures on a single pad is one way. Some companies 

are also moving away from freshwater for hydraulic fracturing of wells and using liquid 

petroleum gases or gels.

Hydraulic fracturing, pumping of a mixture of water, sand and additives under high pressure into 

a shale formation allowing the natural gas to flow out of the shale, is the other component that 

makes recovery of shale gas viable. The casing and cement that is installed during the drilling 

process provides protection for groundwater sources during the hydraulic fracturing process. 

Plus, several hundred to several thousand feet separate the top of the fracture zone of the 

Marcellus and the bottom of the deepest freshwater aquifer layer making it improbable for 

hydraulic fracturing fluids to reach groundwater used as a source of drinking water.

Sustainable development of shale gas in the Marcellus requires the management of large 

volumes of water necessary for the drilling and hydraulic fracturing process to unleash the gas 
15 | Page

from the formation. Challenges associated with the development of shale gas involve the 

management of water – transportation, storage and disposal of the water and waste streams 

created during all stages of well development - in a manner that does not present a threat to 

human health and the surrounding environment. 

Water Sources for Horizontal Shale Gas Well Development in the Marcellus

Exploration of the Marcellus Shale may pose water resource and water supply challenges to the 

gas industry operating in the Appalachian Basin (4). Water used for drilling and hydraulic 

fracturing normally comes from surface waters, groundwater, municipal potable water supplies, 

or reuse of flowback waters, or from some other water source. 

Surface Water

Currently, the preferred source of hydraulic fracturing water is surface water which may be 

transported to the site by pipeline or truck (9). On average, for each horizontal well drilled in 

the Marcellus, three to five million gallons of water are needed to drill and hydraulically fracture

the well. Only about 10% to 40% of this water is recovered and it typically contains high 

concentrations of total dissolved solids (TDS). The remaining water stays in the formation. 

Due to the amount of water loss, large amounts of new makeup water are required to develop

each new gas well. Depending on the number of horizontal wells that may be drilled and

hydraulically fractured in any given basin, water demand may become a critical issue particularly 

during the latter half of the year when stream levels are lowest. The Ohio River Basin is located 

within southwestern New York, western Pennsylvania, and much of West Virginia. It comprises 

all the major rivers and streams that make up the Ohio River. The Marcellus Shale region 

underlies approximately 10% of the Ohio River Basin (10). The Ohio River Basin and its major 

tributaries – the Monongahela and Allegheny Rivers, may be seen as less challenged from a 

water resource perspective when compared to the other river basins within the Marcellus Shale 
16 | Page

area. However, recent evaluations conducted by the West Virginia Water Use Survey and 

Pennsylvania State Water Plan highlight the Ohio River watershed may face some significant 

water resource challenges (4). With many streams and aquifers affected by acid mine drainage, 

supplies of potable water are often limited (4). When comparing shale gas development water 

use with other activities and practices such as agriculture, power generation, recreation and 

municipal consumption, shale gas water use accounts for a very small portion of overall general 

basin use, usually less than 1% (3). 

Besides quantity issues, concerns about the ecological impacts to aquatic resources from water 

withdrawals have been raised throughout the Marcellus Shale region (11). 

Groundwater 

Groundwater in West Virginia is generally of good quality with 42% of the state’s population 

relying on groundwater as the source of their domestic water supply; but, a recent comprehensive 

study by the United States Geological Survey (USGS) raises concerns based on iron, manganese 

and radon levels found in water samples taken from 300 wells around the state. Developing a 

groundwater well near an active Marcellus Shale development area would have to be able to 

provide sufficient yield and not have any impact on nearby drinking water supply wells or 

surface waters (9). To ensure this does not happen, a hydrological study of the area would need

to be conducted prior to drilling the groundwater well.

Potable Water Supplies

Municipal water suppliers are another option to provide a source for freshwater to drilling and 

hydraulic fracturing operations. To the extent that capacity exists to provide water for ratepaying customers as well as shale gas operators, the municipality may agree to provide water for 

hydraulic fracturing.
17 | Page

Flowback Water Reuse

Recycling of flowback and produced water reduces the demand on freshwater supplies and the 

volume of water that requires treatment or disposal. It is unknown if reusing untreated flowback 

waters for hydraulically fracturing new wells would impede gas production. Therefore, most 

shale gas operators treat flowback waters to some degree. Many technical solutions exist to treat 

flowback waters. These technologies are discussed under the Best Available Practices section 

of this report.

Other Sources

Another option may be to use treated acid mine drainage (AMD). AMD is water that has been 

contaminated by contact with pyrite in strip-mine operations, refuse piles or abandoned deep 

mines that results in the formation of sulfuric acid and iron (9). Treatment typically involves 

neutralization and removal of metals such as iron. Common in many areas underlain by the 

Marcellus Shale, treated AMD may be a plausible substitution for surface water. Scaling by 

divalent and trivalent ions is an issue when considering the use of AMD. Some suggest 

treatment to reduce total hardness to 2,500 mg/L (12). A study in 2009 conducted by ProChem 

Tech International, Inc. found that treated AMD was a suitable substitute for freshwater for the 

hydraulic fracturing process of a shale gas well. It required a simpler treatment process 

compared to treatment of return flowback water and allowed an alternative use for AMD other 

than treatment and surface discharge. Using their unique chemical process with no addition of 

calcium hydroxide and inclined plate clarifiers to remove iron below 20 mg/L and keep calcium 

well below 350 mg/L, treated AMD was used in a successful operation in Pennsylvania (12).

The use of AMD water in Marcellus Shale development may provide a win-win solution for coal 

and natural gas industries along with the regulatory agencies that are tasked to oversee activities 
18 | Page

of both industries by providing a use for the AMD instead of treatment and monitoring required 

for discharge.

Water and Waste Streams Associated with Horizontal Gas Well Development 

Several members of the Marcellus shale industry volunteered to participate in a study to develop 

an information base on the nature and composition of influent water and flowback waters 

associated with completions of Marcellus shale gas wells (13). Nineteen well sites were 

identified throughout Pennsylvania and West Virginia where hydraulic fracturing would take 

place. Samples were taken of the: supply water prior to blending of additives, influent water 

following blending with additives but before the addition of sand, flowback samples at varying 

time lapses after hydraulic fracturing, and water from each producing well 90 days after 

completion. 

Results show influent water usually contains moderate to low concentrations of salts. Refer to 

Table 1 (13). The concentration of TDS in flowback increased with time while the flow rate 

decreased with time. Samples showing moderate TDS values in the influent water indicate

implementation of water reuse practices meaning those companies use flowback water in part to 

make up hydraulic fracturing fluid for subsequent fracturing. Oil and grease, and total organic 

carbon (TOC) concentrations in these samples indicate blending of flowback water with 

freshwater. General characteristics of the flowback and produced water are consistent with 

literature values. Typically the dissolved solids in flowback and produced waters from Marcellus 

wells consist of sodium, chloride, calcium and to a lesser extent, strontium, barium and bromide.

Heavy metals of toxicological concern that are often associated with urban industrial activity 

were at very low levels compared to what is typically reported in sludge from municipal 

wastewater facilities. Among the volatile organic constituents tested, nearly 96% were found at 
19 | Page

non-detectable levels and 0.5% was above 1 mg/L. Constituents in produced waters that 

exceeded 100 parts per billion (ppb) included components commonly present in produced waters 

from natural gas operations: benzene, toluene, ethylbenzene and xylene (BTEX); naphthalene; 

several methylated benzene compounds and an alkylated toluene; however, few determinations 

of these compounds exceeded 2 parts per million (ppm; 13). Nearly all halogenated organic 

compounds were at non-detect levels strongly suggesting additives blended with makeup waters 

do not contain concentrations of organic chemicals of concern. The results of this shale gas 

water characterization effort indicate that PCBs, pesticides, and a large fraction of volatile 

organic compounds (VOCs) and semi-volatile organic compounds (SVOCs) should be 

considered unnecessary for the sampling and analysis of flowback waters in the future (13).
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Table 1: Chemical Characteristics of Influent and Flowback Waters

Parameter Units

Influent 

Water Before 

Additives

Influent 

Water After 

Additives

Flowback 

Water 5 Days

Out

Flowback 

Water 14 Days 

Out

pH No units 6.7 – 7.4 5.2 – 8.9 5.8 – 7.2 4.9 – 6.8

Acidity mg/L <5 – 5.5 <5 – 1,230 <5 – 447 <5 – 473

Total Alkalinity mg/L 6.2 – 88.8 5 – 308 48.8 – 327 26.1 – 121

Hardness as 

CaCO3 mg/L 18 – 1,080 26 – 9,500 5,100 – 55,000 630 – 95,000

TSS mg/L <2 – 24 4 – 5,290 10.8 – 3,220 17 – 1,150

Turbidity NTU 1.3 – 33.7 2.7 – 715 2.3 – 1,540 10.5 – 1,090

Chloride mg/L 4.1 – 3,000 18 – 10,700 26,400 –

148,000

1,670 –

181,000

Total Dissolved 

Solids mg/L 35 – 5,510 221 – 27,800 38,500 –

238,000

3,010 –

261,000

Specific 

Conductance μmhos/cm 55 – 10,100 177 – 34,600 79,500 –

470,000

6,800 –

710,000

Total Kjeldahl 

Nitrogen mg/L <3 – 56.4 2.3 – 400 38 – 204 5.6 – 261

Ammonia Nitrogen mg/L 0.017 – 20.8 0.28 – 441 29.4 – 199 3.7 – 359

Nitrate-Nitrite mg/L <0.1 – 3.0 0.1 – 3.1 <0.1 – 1.2 <0.1 – 0.92

Nitrite as N mg/L <0.05 – 4.9 <0.05 – 5 1.2 – 29.3 <2.5 – 77.4

Biochemical 

Oxygen Demand mg/L <2.0 – 110 <2.0 – 2,220* 37.1 – 1,950 2.8 – 2,070

Chemical Oxygen 

Demand mg/L <10 – 924 35.3 – 47,400 195 – 17,700 228 – 21,900

Total Organic 

Carbon mg/L 1.8 – 202 5.6 – 1,260 3.7 – 388 1.2 – 509

Dissolved Organic 

Carbon mg/L 1.4 – 222 5 – 1,270 30.7 – 501 5 – 695

Oil and Grease mg/L Not detected 4.6 – 255 4.6 – 655 <4.6 – 103

Cyanide, Total μg/L <10 – 625 3.5 – 954 <10 – 72.1 <10

Amenable Cyanide mg/L <0.01 – 0.27 <0.01 – 0.87 <0.01 – 0.032 <0.01

Bromide mg/L <0.2 – 31.9 <0.2 – 107 185 – 1,190 15.8 – 1,600

Fluoride mg/L <0.05 – 1.2 <0.05 – 58.3 <0.05 – 17.3 <0.05 - <50

Total Sulfide mg/L 1.6 – 5.6 <3 – 8.8 <3 – 5.6 <3.0 – 3.2

Sulfate mg/L 3.8 – 139 2.9 – 2,920 2.4 – 106 <10 – 89.3

Total Phosphorus mg/L <0.1 – 0.14 <0.1 – 16 <0.01 – 2.5 <0.1 – 2.2

Total Recoverable 

Phenolics mg/L 0.01 – 0.031 <0.01 – 0.77 <0.01 – 0.31 <0.01 – 0.31

Sulfite mg/L 6 – 21.6 <5 – 61.6 2.5 – 38 7.2 – 73.6

Methylene Blue 

Active Substances 

(MBAS)

mg/L <0.05 – 0.962 <0.03 – 0.506 <0.012 – 1.52 <0.05 – 4.6

*BOD readings were reported as g/L not mg/L.
21 | Page

Drilling Wastes – Liquid and Solid Waste Streams

Drilling a horizontal gas well begins the same way as other types of wells. A vertical well is 

drilled to a pre-determined depth, followed by the horizontal or lateral drilling into the targeted 

shale formation. The drilling process itself generates cuttings and muds that must be managed

when removed from the bore hole. Cuttings are made up of rock fragments. Drilling muds are 

made up of a base fluid such as water, mineral oil, or a synthetic oil-based compound; weighting

agent; clay; and a stabilizing organic material such as lignite (15). Drilling muds can also pick 

up characteristics of the various formations as drilling proceeds. 

Cuttings are often transported from the well to the surface by the base fluid that serves to cool 

and lubricate the drill bit. This fluid, which is used only during the drilling phase of well 

development, is commonly referred to as “drilling muds” or “muds.” Barite is sometimes added 

to the fluid for weight (14). In the Marcellus, pressurized air is commonly used as the drilling 

“fluid” during the vertical drilling stage and a liquid waste or slurry for the horizontal drilling 

stage. Drilling muds and cuttings are brought to the surface where the liquids and solids are 

separated via shale shaker tables that consist of large sieves (15). Liquid wastes pass through the 

screen and are collected in an underlying basin. The solid drill cuttings are retained on the top of 

the screen. Shaker tables can recover up to 70% to 80% of the liquid for reuse. Disposal options 

for cuttings include dewatering and haulage to a licensed waste disposal site or burial on-site

with the permission of the landowner and approval from the governing regulatory body. Until 

recently, cuttings disposal pits were generally not lined. Muds are typically reused and sent back 

down the well. Once drilling is completed, muds can be reused to drill another well or be 

properly disposed of in a landfill. 
22 | Page

Commonly Used Hydraulic Fracturing Fluids 

After a well is drilled and casing has been placed, the completion stage, or hydraulic fracturing, 

begins (16). Hydraulic fracturing was first developed in the 1940s to stimulate production from 

oil reservoirs with declining productivity (3). In the production zone of the well, a perforation 

gun shoots holes through the casing and cement at pre-determined locations (11). Hydraulic 

fracturing takes place in stages where hydraulic fracturing fluids are pumped through the 

perforations, and plugs are set. The process is repeated until the length of the production zone 

has been fractured. Hydraulic fracturing takes place under high pressure (around 10,000 psi) to 

create microfractures in the rock formation to allow the gas to be extracted. The sand or other 

proppant holds the new fractures open allowing the gas to flow freely out of the formation and 

into a production well for compression, transmission, and sale. 

Mixed with the water and sand is a chemical cocktail of other ingredients that include friction 

reducers (slickwater), corrosion inhibitors, oxygen scavengers, scale inhibitors and biocides

(disinfectants; 17). The resulting mixture is referred to as hydraulic fracturing fluid and is 

typically created on-site. The water and sand typically make up 98% to 99% of the hydraulic 

fracturing fluid with the rest consisting of the various chemical additives used to improve the 

effectiveness of the fracture and subsequent release of natural gas. Nearly all fluids currently 

used in Marcellus Shale hydraulic fracturing operations are water based or mixed slickwater 

fracturing fluids (5).

Some of the additives used in hydraulic fracturing fluids are used in many common household 

products and foods (8). However, hydraulic fracturing fluids have been found to contain 

hydrochloric or muriatic acid, petroleum distillate, ammonium bisulfate, fluorocarbons, 
23 | Page

naphthalene, butanol, and formaldehyde (18). Many of these chemicals are either carcinogenic 

or can cause a wide range of health problems affecting eyes, skin, lungs and the nervous system. 

In 2010, the United States House of Representatives Committee on Energy and Commerce 

conducted an investigation into the practice of hydraulic fracturing in the United States (19). 

Fourteen leading oil and gas companies were asked to provide information on the types and 

volumes of hydraulic fracturing products used in their fluids between 2005 and 2009. The 

investigation yielded a total of 750 different chemicals and other components used by these 

companies to create their hydraulic fracturing fluids. Components were found to range from 

harmless (table salt and citric acid), to unexpected (instant coffee and walnut hulls), to extremely 

toxic (benzene and lead; 19). Methanol was found to be the most widely used chemical by the 

companies surveyed. Methanol is considered a hazardous air pollutant and is on the candidate 

list for potential regulation under the SDWA (19). Other commonly used chemicals included 

isopropyl alcohol (surfactant), 2-butoxyethanol (foaming agent or surfactant) and ethylene glycol

(scale inhibitor) along with the silicon dioxide (sand proppant). The Committee’s investigation 

also found that the fourteen oil and gas companies surveyed used hydraulic fracturing products 

containing twenty-nine chemicals that are known as or may be possible human carcinogens

regulated under the SDWA due to risks to human health, or listed as hazardous air pollutants

under the Clean Air Act. 

Each company has their own hydraulic fracturing fluid recipes and has typically kept them secret

siting proprietary information (20). The resistance of energy companies to publicly disclose the 

chemicals used to make up their hydraulic fracturing fluids has heightened the concern that these

substances can harm the surrounding environment and negatively impact human health. This is

especially true if there is a way the hydraulic fracturing fluids and thus chemicals can mix with 
24 | Page

nearby groundwater resources. Some companies post information about their fracturing fluids 

on their websites or general websites. An example is www.fracfocus.org which provides a 

general idea as to what additives are used for hydraulic fracturing in the Marcellus Shale. 

Adapted from the West Virginia Oil and Natural Gas Association, Energy in Depth,

Geology.com, and the Society of Petroleum Engineers, common ingredients found in hydraulic 

fracturing fluids used in the Marcellus Shale region and the purpose each serves is summarized 

in Table 2 (21, 22, 23 and 24).
25 | Page

Table 2: Hydraulic Fracturing Additives

Category Main Ingredient Purpose Other Uses

Water Water Expand fracture, deliver 

sand

Landscaping, 

manufacturing

Proppant Silica, Quartz Sand Hold fracture open

Drinking water 

filtration, play sand, 

concrete

Gel Guar Gum or 

Hydroxyethyl Cellulose

Thickens water and

suspends sand

Cosmetics, baked 

goods, ice cream, 

toothpaste

Friction Reducer

1) Petroleum distillate

2) Polyacrylamide

3) Mineral oil

1) Slick water to 

minimize friction

2) Minimizes friction 

between pipe and 

fluids

1) Hair, makeup, skin 

products

2) Soil conditioner, 

water treatment

3) Makeup remover, 

laxatives

Acid Hydrochloric or 

Muriatic Acid

Dissolves minerals and 

initiates cracks in rock Swimming pool cleaner

Anti-Bacterial Agent Glutaraldehyde Eliminates bacteria in 

the water

Disinfectant, medical 

equipment sterilizer

Scale Inhibitor Ethylene Glycol Prevents scale deposits Household cleansers, 

paints, caulk

Breaker

1) Ammonium 

Persulfate

2) Sodium Chloride

Allows delayed 

breakdown of gel

1) Hair coloring, 

disinfectant, 

manufacturing of 

plastics 

2) Table salt

Corrosion Inhibitor

(Oxygen Scavenger)

1) n,n-dimethyl 

formamide

2) Ammonium 

Bisulfite

Prevents pipe corrosion

1) Pharmaceuticals, 

plastics

2) Cosmetics, food and 

beverages

Crosslinker Borate salts

Maintains fluid 

viscosity as temperature 

increases

Laundry detergents, 

hand soaps, cosmetics

Iron Control Citric acid Prevents metal oxides 

precipitation

Food additive, 

beverages

Clay Stabilizer Potassium Chloride Creates brine carrier 

fluid

Table salt substitute, IV 

fluids

pH Adjustment Agent Sodium or Potassium 

Carbonate

Maintains effectiveness 

of other products

Laundry detergents, 

soaps, water softeners

Surfactant Isopropanol

Reduces surface tension 

and increases viscosity 

of fracturing fluids

Glass cleaner, 

deodorant, 

antiperspirant
26 | Page

Characteristics of Flowback Waters

Once the hydraulic fracturing process is completed and the wellbore pressure released, a portion 

of the fracturing fluids and water flows back up the wellbore to the well head. Referred to as 

flowback, this water returns over the life of the well and is collected in tanks or lined pits. The 

Marcellus is considered a desiccated formation. It contains little if any water in most locations. 

Flowback and produced water consist of organic, inorganic and radioactive compounds from the 

originally injected water along with constituents acquired during contact with the formation. 

These may include the additives that were introduced during the hydraulic fracture job as well as 

characteristics of the formation such as salts, oils and greases, metals and organic compounds, 

and may include naturally occurring radioactive materials (NORM). The primary radionuclides 

of concern are isotopes of radium that originate from the decay of uranium and thorium naturally 

present in the subsurface. 

Organic compounds are either separable with de-oiling technologies (such as oils and greases) or 

they are soluble (such as phenol, mono-carboxylic acids glycols), requiring a more complicated 

removal process (9).

Radioactivity

All environmental media contain some level of radioactivity or naturally occurring radioactive 

materials (NORM). There are three main groups of radioactive elements that exist in all soil and 

rock on earth: uranium-238/radium-226 radionuclide series, the thorium-232 radionuclide series, 

and potassium-40 (25). Typical, natural background concentrations of uranium, radium, and 

thorium present in soil and rock in the eastern United States range from 0.5 to 1 pCi/g each and 

10 to 30 pCi/L for potassium-40 (25). Certain commercial minerals, such as gypsum, zirconium 

and titanium used in paint and zircon sand and carborundum used in sandblasting and ceramics 

have radioactivity levels ranging from 5 to 50 pCi/L (26).
27 | Page

Certain materials used or generated in certain industry sectors have higher than background 

levels of NORM or technologically enhanced naturally occurring radioactive materials 

(TENORM; 27). Exposure to naturally occurring radiation makes up the majority of an average 

person’s yearly radiation dose and is generally not considered of significance to health and safety

(49). Certain industries handle significant quantities of NORM, which can mainly be found in 

their waste streams. As potential hazards are identified, monitoring and regulation of such 

materials and activities have increased. Industries known to have NORM issues include: coal, 

oil and gas, metal mining and smelting, phosphate fertilizer industry, building and recycling (49). 

In shale gas development, NORM can be found in drill cuttings, flowback waters and natural gas

(28). NORM are more noticeable in areas where sediments or precipitates tend to accumulate 

such as equipment, pipes and storage tanks, and as a result, exposure may occur when repair 

work is performed (29). Dense steel used in natural gas production blocks alpha and beta 

radiation and greatly reduces transmission of gamma radiation. Since distance reduces exposure, 

risks to the general public are possible when contaminated materials and components such as 

pipe and tankage are mishandled (29). According to the World Nuclear Association, NORM in 

the oil and gas industry poses a problem to workers particularly during maintenance, waste 

transport and processing, and decommissioning (49). In particular, Lead-210 deposits and films 

are only a concern when pipe internals become exposed (49). External exposure due to NORM

in the oil and gas industry is generally low enough not to require protective measures to ensure 

that workers stay beneath their annual dose limits and internal exposures can be minimized 

through hygiene practices (49). 

Radioactivity in the Marcellus Shale varies across the formation. Over time, the radioactive 

isotopes decay with half-lives from a few days to several hundred years. Levels of NORM in 
28 | Page

Marcellus Shale flowback tend to be relatively low with higher concentrations in the later 

flowback waters and produced water. Alpha particles and Radium-226 in some produced waters 

in New York have been found at concentrations exceeding drinking water maximum 

contaminant levels of 15 pCi/L and 5 pCi/L, respectively (26). 

Exposure to radionuclides, even at low levels can raise serious health concerns. Radon gas,

known to exist within the Marcellus has been shown to be a primary cause of lung cancer. The 

EPA has established drinking water guidelines for certain radionuclides: 5 pCi/L for radium, 30 

pCi/L for uranium and 15 pCi/L for total alpha emitters. EPA has also set radium-226 levels in 

wastewater discharges at 60 pCi/L, discharges to land surface at 5 pCi/g and 15 pCi/g to 

subsurface soils. 

The New York Department of Health analyzed three samples of flowback waters from Marcellus 

wells and found elevated levels of gross alpha, gross beta, and radium-226, which is 

characteristic of Devonian-age shales (11). The presence of high levels of radium-226 raised 

several issues: monitoring of NORM need to be evaluated for Marcellus gas wells; levels of 

NORM in flowback waters need to be assessed to determine if additional treatment of the 

flowback waters are needed prior to disposal; and caution should be exercised when considering 

spreading brine waters on roads to keep dust down or for deicing purposes (26). Based on these 

findings, the New York Department of Health recommends continued sampling of flowback 

waters and drilling muds and cuttings. They feel analysis of gross alpha activity, gross beta 

activity and some gamma spectroscopy analysis to be sufficient to assess if further 

characterization of radioactive material is warranted. Although total gross alpha counting 

efficiency is uncertain in samples with high dissolved solids, it is an inexpensive screening tool, 

and if counts exceed 15 pCi/L, additional analysis is warranted (26). The WVDEP may want to 
29 | Page

consider following the lead of the New York Department of Health for monitoring radioactivity 

of water and waste streams returning up-hole. If general analysis of total gross alpha and beta 

counting present concern by yielding sample readings well above twice background radioactivity 

readings, further analysis should be conducted to characterize radiation levels measured and 

determine if additional protective measures need to be implemented for workers and/or nearby 

populations.

Environmental and Public Health Concerns Associated with Water and Waste 

Streams from the Development of Horizontal Shale Gas Wells

Public concerns about water quality from horizontal gas well development include: aquifer and 

drinking water well contamination; waste storage pit leakage; spills of hydraulic fracturing 

fluids; handling of flowback streams; water use and supply; drilling waste disposal; stormwater 

runoff; and blowouts (31). These concerns stem from two related activities: 1) well development 

and completion, and 2) management of water and waste streams (handling, storage and disposal). 

Casing and cement failure to properly bond the well annulus can result in upward migration of 

gas and fluids into shallow drinking water aquifers.

Identifying the cause of contamination of a nearby drinking water well can be difficult. 

Characterization of flowback and produced water chemistry and isotopic composition has been 

employed to identify migration of hydraulic fracturing wastes into drinking water supplies. A 

study conducted by researchers from Duke University found methane gas in drinking water wells 

located within one kilometer of active drilling sites (32). However, there was no baseline data 

available to determine if methane was present in the drinking water wells prior to nearby drilling 

activities commencing. And, methane was detected in nearly all of the drinking water wells 

tested regardless of the proximity to drilling activities. The Duke study did highlight a known 

concern that faulty or leaky well casings at the top of a drilling site may allow methane to 
30 | Page

migrate to nearby water supplies. In Pennsylvania, where this study took place, regulations do 

not exist requiring private drinking water wells to be properly drilled and cased, increasing the

potential of contamination from any nearby activity. A lack of baseline testing of water wells 

prior to well development and completion renders interpretation of the results problematic. 

Published studies and agency investigations indicate no direct connection between hydraulic 

fracturing of shale formations and groundwater contamination (33). A 2011 study by the Center 

for Rural Pennsylvania analyzed water samples from private wells within 2,500 feet of a 

Marcellus Shale gas well (34). Pre-drill and post-drill samples were taken to identify any 

changes in water quality. Samples were analyzed for TDS, chloride, sodium, sulfate, barium, 

strontium and methane. Results indicated there were no statistically significant increases in 

pollutants prominent in drilling waste fluids and the conclusion was drawn that gas well drilling 

had not had a significant effect on water quality of nearby drinking water wells. Nonetheless, 

contamination incidents attributed to poor gas well construction, as was the case of the Duke 

University study of nearby drinking water wells in Pennsylvania, have raised concerns regarding 

the adequacy and/or enforcement of state well construction regulations for both gas production 

and drinking water supply. 

Many who express concern about potential water problems do not differentiate between the 

actual fracturing process and associated stages of horizontal shale gas well development and 

production (35). State regulators and industry representatives define hydraulic fracturing as the 

specific well stimulation operation. However, the general public and media outlets often use the 

term “hydraulic fracturing” or “fracking” to broadly refer to a range of activities associated with 

unconventional gas development. Few published, peer-reviewed scientific reports exist 

documenting potential environmental impacts from hydraulic fracturing. Studies that do exist 
31 | Page

show that the risks depend more on the quality and integrity of the borehole casing and cement 

job rather than the hydraulic fracturing process (36). There is little agreement regarding the risks 

that hydraulic fracturing operations pose to underground sources of drinking water and, as a 

result, Congress has directed the EPA to study the matter further (33).

Management of Water and Waste Streams

Surface activities pose an additional concern for potential groundwater contamination. Leaking 

pits, accidental spills or careless disposal practices of drilling fluids at the production site will 

increase the risk of contaminating nearby water supply wells. Storage, treatment and disposal of 

flowback waters also create additional water quality issues. Leaks from flowback water and 

waste storage pits and surface spills from transporting flowback water or fracking fluids can 

cause contamination of nearby surface and groundwater. Many believe that above-ground 

activity is a greater risk to drinking water resources than below-ground activity and may have 

contributed to the contamination of water supplies in Pavillion, Wyoming (37).

Lined pits that are used to store the flowback water may pose a threat to groundwater and surface 

water resources if these structures are not designed and constructed properly to retain the liquids 

until they are drained and the site closed and reclaimed. Common problems with these structures 

include tears in liners that allow fluids to escape and enter nearby surface waters or seep into 

nearby groundwater.

Surface water contamination from the hydraulic fracturing process may occur if hydraulic 

fracture fluid spills at the wellhead site or if the trucks carrying this fluid leak as they travel to 

and from the wellhead. These spills may be from unused hydraulic fracturing fluid or return 

hydraulic fracturing fluid that comes back up the well during the flowback process. Spill 

prevention measures are necessary because surface spills may pose a greater risk to groundwater 
32 | Page

than the hydraulic fracturing process. Although operators try to ensure spills do not occur, it 

occasionally happens and must be reported to the proper regulatory agencies. Spills are not a 

common occurrence because fluids lost to a spill must be replaced and remediation of 

contaminated soils increases operational costs (5). 

One of the biggest issues with surface water contamination found during the literature review is 

from the treatment of the flowback water at municipal wastewater plants. Flowback water is 

very high in chlorides, sodium and calcium. These chemicals create high TDS levels. Other 

contaminants of concern found in flowback waters include bromide, barium, and traces of 

radiation. Typical wastewater treatment plants are not equipped to remove enough of these 

contaminants to allow release or final disposal into receiving surface waters. The high 

contaminant levels found in flowback water require specialized treatment in order to protect 

surface waters receiving the treated wastewater. High bromide levels have been found to exist in 

surface waters where publicly owned treatment works (POTW) and centralized waste treatment 

(CWT) facilities receiving wastewaters from oil and gas development discharge their effluent. 

These are the same surface waters that downstream drinking water systems pull from to supply 

their customers with drinking water. Most POTWs and CWTs are not equipped to treat bromide 

and thus it passes through their system. Bromides are not necessarily dangerous by themselves;

it is only when they mix with chlorine used by drinking water systems that they become a threat 

to public health. 

A typical Marcellus well pad site is around 3 to 5 acres in size. The area allows for the 

wellheads and a combination of pits, impoundments and tanks to hold drill cuttings, used drilling 

and hydraulic fracturing fluids, freshwater and flowback waters. Access to the well pad adds to 
33 | Page

the overall amount of disturbed land. Appropriate practices need to be in place to control 

stormwater runoff at the well pad as well as around the roads providing access to the site. 

Blowouts are rare occurrences that happen when the fluid injected into the wellhead does not 

fracture the rock around the bottom of the well and the elevated pressure drives the fluid into 

other open and permeable pathways (36). Pathways can include the borehole, other oil and gas 

wells, artesian wells or abandoned wells in the vicinity that cannot handle high pressures. Old 

abandoned wells can also provide a potential pathway for contaminants to enter groundwater 

systems. States estimate that there are over 150,000 abandoned oil and gas wells in the United 

States (35). Blowout prevention equipment installed at the surface prevents pressurized fluids 

encountered during drilling from moving up the well through the space between the drill pipe 

and surface casing (38). A blowout in West Virginia occurred because the drillers reportedly 

encountered an unexpected pocket of methane in an abandoned coal mine below the surface and 

a blowout preventer had not yet been installed (38). Fluids spilled onto the surface from 

blowouts can leach into surrounding soils and groundwater and need to be cleaned up and the 

area remediated. These types of incidents support the need to gather accurate and complete 

information about the subsurface and surrounding area prior to gas well development.

Summary of Best Available Practices and Technologies for Water and Waste 

Streams

Water management (storage, treatment and disposal) technologies available in the Marcellus 

Shale region cover treatment, recycle/reuse and disposal by Class II injection wells of flowback

and produced waters. Industry is looking for alternative ways to manage these wastewaters that 

minimize costs and impacts to the environment. Treatment is the most complex option available 

to manage water and wastes from the development of horizontal shale gas wells. Treatment can 

occur on-site or off-site and in conjunction with reuse options. All treatment methods produce 
34 | Page

some form of residual waste, liquid or sludge, and must be managed to avoid environmental 

harm. Depending upon the end use of the wastewater, various treatment options are available 

and discussed below in respective sections.

Storage Options and Practices

Large quantities of water in a short amount of time are required for hydraulic fracturing 

operations. Water restrictions commonly exist limiting the amount of water that can be 

withdrawn and transported to well sites necessitating the need for some form of water storage. 

The two methods often used to store water on-site or near active hydraulic fracturing operations 

are containment units, typically referred to as tanks, and impoundments.

Tanks are available from many vendors. Rectangular tanks, with a V-bottom or cylindrical 

bottom, with a 21,000 gallon capacity transported by a semi-truck, are most commonly used. 

Because these tanks hold a small volume of water compared to the amount needed for the 

average hydraulic fracturing job, hoses are used to connect several tanks together. To provide a 

1,000,000 gallon storage capacity, 48 tanks are needed, requiring a considerable amount of space 

and an extensive hosing network. Secondary containment constructed around these units serves

to provide additional environmental protection from accidental leaks and spills. Secondary 

containment units look similar to a tray-like structure with raised sides to prevent fluids from 

leaching into soil or washing into nearby surface waters. 

Impoundments can be used in coordination with tanks or alone as a means to provide water 

storage on-site. Impoundments differ from pits in that they hold only freshwater. Pits are used 

to hold flowback waters and other residual water and waste streams from horizontal gas well 

development.
35 | Page

Reuse or Recycle Options and Practices 

A combination of water use restrictions and increased unconventional natural gas development 

will likely increase the demand for non-freshwater supplies for future development operations. 

Care must be exercised when reusing fluids and flowback waters with little or no treatment. 

Flowback waters with high levels of salts, barium and calcium, may cause scaling issues over 

time. Besides salts, flowback waters contain heavy metals and various organic and radioactive 

compounds that may limit reuse options without prior advanced treatment. Major treatment 

processes such as reverse osmosis and distillation are very costly but have been proven to reduce 

constituents present in flowback waters that can cause scaling, compatibility issues with 

hydraulic fracturing fluid additives and increase friction on subsequent hydraulic fracturing jobs. 

In Pennsylvania, industrial treatment followed by reuse is a common method for managing 

wastewaters from the development of Marcellus gas wells (15). 

Because traditional off-site disposal options are not often available in the Marcellus region, reuse 

options are being employed (39). Recycle or reuse of flowback waters reduces the amount of 

wastewater generated and the amount of freshwater needed for hydraulic fracturing operations; 

but, this practice can create concentrated residual by-products that will need to be dealt with. 

Pennsylvania allows the use of Marcellus brines to roadways as long as the brines can meet 

certain water quality requirements (39). Brines are a product of flowback waters that have been 

treated at a CWT designed specifically to handle these wastes. Although this has been a 

common practice in the Marcellus region, environmental concerns have recently increased 

resulting in a closer look at contaminant concentrations of the brines and risks of these pollutants 

washing into nearby waterways (39). 
36 | Page

Land application of hydraulic fracturing fluids is considered an acceptable form of disposal in 

some states where hydraulic fracturing activities are ongoing; however, little information exists 

on impacts these fluids have on vegetation. In 2008, hydraulic fracturing fluids from a gas well 

were applied to a small section of a hardwood forest in West Virginia. During application, 

severe damage and mortality to the ground vegetation was observed (40). Two years after 

application, nearly half of the trees were dead. Soil samples were taken prior to application and 

throughout the two year study period of the application area and adjacent area to evaluate the 

effects of hydraulic fracturing fluids on soil chemistry. Sodium and chloride concentrations in 

the soil were found to be increased 50-fold after application of the hydraulic fracturing fluids

(40). These concentrations did decline over time, likely due to leaching. Researchers 

recommend additional studies into the application rates of hydraulic fracturing fluids and effects 

on vegetation and land resources.

Chemical composition of hydraulic fracturing fluids is designed to optimize performance of the 

fracturing job (17). When reusing flowback waters for additional hydraulic fracturing, it is 

imperative TDS concentrations are kept in check to not negatively affect the ability of the new

hydraulic fracturing fluids. Many operators will blend the flowback waters, treated or untreated, 

with freshwater to achieve the right consistency, keeping TDS values minimal. If the flowback 

waters are untreated, blending will require more freshwater to dilute TDS values. Therefore, it is 

beneficial to treat the flowback waters if freshwater sources are scarce. 

Treatment of water and waste streams from horizontal gas well development can occur on or off 

site. Several companies have developed a wide variety of technologies to treat flowback waters

for reuse from gas wells at the site (on-site). Some form of physical (filtration) or chemical 

(coagulations and flocculation) separation is needed to remove oil and grease and suspended 
37 | Page

matter. Bag or cartridge filtration systems are commonly used to remove suspended solids from 

flowback waters. They offer a compact footprint with a simple design but can be labor intensive. 

The next step for treatment concentrates on reducing levels of hydrocarbons, organics and 

metals. This treatment can be accomplished using a form of membrane system like reverse 

osmosis (RO), ion exchange, or electrodialysis. These membrane systems cannot be used as a 

stand-alone treatment system for Marcellus flowback waters. They require some level of 

pretreatment. Often, some form of disinfection is introduced into the treatment schematic as 

well. Disinfection is often required in unconventional shale plays like the Marcellus prior to 

hydraulic fracturing and especially if recycled flowback waters make up part of the hydraulic 

fracturing fluids (41). Ozone and ultraviolet light are two common forms of disinfection used to 

oxidize biological films and bacteria that may exist in flowback waters. Similar to the membrane 

systems, disinfection systems cannot be used as stand-alone treatment systems and also require 

pretreatment to be effective.

The issue of reducing TDS values has not been addressed by the treatment technologies 

mentioned thus far. Since TDS values are extremely high in flowback waters of the Marcellus, 

any of these treatment options may have difficulty processing flowback waters with TDS values 

over 40,000 mg/L. Thermal distillation and evaporation may be the only option to treat 

flowback waters with TDS values greater than 40,000 mg/L on a regular basis. As of 2010, a 

handful of thermal distillation facilities were operating in the Marcellus region, highlighting the

need to develop and implement additional treatment processes.

Wastewater treatment processes achieve a high water recovery rate by concentrating the solids 

and sludges. However, no practical and cost-effective method exists to remove all NORM. 

Chemical precipitation, ion exchange or activated carbon can remove metals and radium. The 
38 | Page

EPA recommends reverse osmosis treatment of water to remove most forms of radioactive 

particles when treating for drinking water consumption (42). This may be practical as an end of 

treatment process if NORM are still an issue in the discharge waters. 

Energy requirements, need for pretreatment, and the system size needed for these technologies to 

process flowback waters must be considered when evaluating these technologies for on-site 

application. Treatment and reuse of flowback waters will reduce the demand on freshwater 

sources and potentially decrease disposal costs by reducing the amount of wastewater that must 

be hauled away. The disadvantages of treating flowback waters on-site still to be addressed 

include the fluctuations in quantity and quality of flowback waters. The treatment selection for 

one site may not be the best for the next given the variations from well to well and formation to 

formation making it difficult for a one-size-fits-all treatment solution.

Disposal Options and Practices 

With the exception of underground injection via a Class II well, most wastewater management 

strategies for handling water and waste streams from horizontal gas well development require 

some level of treatment. During the treatment of these water and waste streams, residual wastes 

are created that will have high concentrations of heavy metals, salts and other constituents 

limiting disposal options. Often these residual wastes are either sent to an acceptable landfill or 

sent for underground injection. Current practice in the Marcellus Shale region is to transport 

wastewaters to treatment facilities (POTWs or CWTs) or dispose through Class II injection 

wells.

Direct discharge of wastewater from shale gas wells to surface waters is prohibited by federal 

law. POTW can accept wastewaters from shale gas extraction activities as long as the treatment 

facility maintains compliance with all federal, state, and local requirements governing the 
39 | Page

introduction of such wastewaters into the POTW. In other words, POTW need to maintain 

compliance with their national pollutant discharge elimination system (NPDES) permit. When 

considering accepting wastewater from shale gas development, or any other industrial activity, 

the POTW operator needs to know the water quality and quantity characteristics of the 

wastewater to determine if the POTW can process it without upsetting the treatment system or 

allowing pollutants to pass through and be discharged to the receiving water. Wastewater 

treatment facilities, POTWs, may be unable to adequately treat the levels of TDS, metals and 

radioactivity that is sometimes present in flowback water and waste streams. 

TDS concentrations in Marcellus shale waste streams have been found to range from 300 

milligrams per liter (mg/L) to well over 300,000 mg/L with chlorides typically constituting about

50% of the total makeup of TDS (7 and 13). TDS is not significantly reduced or removed by 

most treatment processes utilized at POTWs and therefore pretreatment of the wastewater would 

be required. High concentrations of TDS require advanced wastewater treatment, such as 

distillation, and may cause scaling which requires frequent cleaning of equipment (9). The 

literature reveals some of the common constituents of TDS, at concentrations much less than 

what is typically found in shale waste streams (including the Marcellus), and may result in 

inhibition of activated sludge, nitrification, and anaerobic digestion processes commonly utilized 

at POTWs (7).

High concentrations of chlorides have also been found to disrupt biological treatment processes 

and metals have also been found to precipitate out during treatment creating issues with disposal 

options for biosolids. Bromide, which can be present in shale gas extraction wastewater streams, 

has the potential to pass through the POTW and be present in the final discharge stream as a 

disinfection byproduct that could lead to increased effluent toxicity (43). Because of high levels 
40 | Page

of bromides and TDS found in many of the rivers and streams in Pennsylvania to which POTWs

and CWTs discharge, State regulators recently asked Marcellus Shale Formation operators to 

voluntarily stop disposing of the drilling wastes and flowback waters to these facilities (44).

Radionuclides, referred to as NORM, have been found to exist at fairly high concentrations in 

waste streams from the Marcellus Shale Formation (7). Flowback water has not been 

extensively monitored and studied for NORM. Few studies are available to help understand the 

issue of NORM in POTW and CWT effluent. Because there is a possibility wastewater from 

shale gas extraction activities may pass through a POTW, cause the POTW to violate its permit, 

cause interference with the POTW’s operation, or contaminate biosolids, acceptance of the waste 

is not advisable unless its effects on the treatment system are well understood and the wastewater 

is reasonably expected not to cause pass through or interference (7).

The same pollutants may be of concern to CWTs. CWTs typically use the same treatment 

processes found at POTW but may also include additional coagulation and precipitation 

techniques to help with TDS removal. Yet, many CWTs may not effectively treat shale gas 

extraction wastewaters and, therefore, appropriate limits and pretreatment requirements will need 

to be developed by the permitting and pretreatment control authorities. Additional limits may be 

required to address pollutants present in shale gas extraction wastewaters that were not 

considered in developing the original CWT effluent guideline. These limits will need to be

incorporated into the CWT’s NPDES permit. For such pollutants, permit writers will have to 

include technology-based limits developed on a case-by-case, “best professional judgment” basis

(7). Very few CWTs exist within the Marcellus region, most of which exist in Pennsylvania.
41 | Page

Chemicals used during drilling, as part of the hydraulic fracturing fluids, or other productionrelated activities need to be disclosed to the POTW or CWT as well. The facility in turn must 

notify and receive approval from the appropriate State agency and the EPA prior to accepting 

any waste streams from shale gas extraction operations. 

In 2011, a stream study was conducted in western Pennsylvania on the effects of discharges from 

POTWs and CWTs that accept wastewaters from Marcellus Shale gas sites (45). Salinity stress 

to freshwater systems was found to be the most significant threat to the ecological welfare of the 

streams. Accumulation of radioactivity in the stream sediment represented a long-term legacy of 

NORM in the environment. Based on these findings, researchers determined that gas-produced 

NORM have yet to be quantified in freshwater sediments and suggested further studies to 

measure NORM levels in stream sediment. 

Where injection wells are available, they are used as an option for disposal of flowback waters

and may provide one of the safer means for final disposal. Underground injection requires less 

treatment than other disposal methods, and when done with appropriate safeguards, creates the 

least risk of contaminant release to the environment (39). In the Marcellus region, there are a 

limited number of Class II injection wells scattered throughout Ohio, Pennsylvania and West 

Virginia. These injection wells can be near the well pad and operated by the producer, or off-site 

and operated by a third-party (17). Injection wells access deep formations that have sufficient 

porosity and ability to accept the water. These formations lay far below any groundwater 

aquifers. 

In summary, Marcellus Shale gas operators employ all of the above mentioned options for 

storage, treatment, reuse and disposal of their flowback waters. If waters are not being reused, 
42 | Page

they are taken to a POTW or CWT that will accept the wastewater or dispose of it via a private 

or commercial injection well. 

Protection of Ground and Surface Waters during Horizontal Shale Gas Well 

Development Stages

In addition to treatment, there are various options available to shale gas developers in the 

Marcellus that can be utilized to protect water resources. These options range from the type of 

additives used to make up the hydraulic fracturing fluids, to how fluids are handled during the 

various stages of well development.

Horizontal shale gas wells are typically encased in alternating layers of concrete and steel down 

through aquifers. For wells to produce gas, it is vital there are no leaks of either gas or hydraulic 

fracturing fluids into aquifers or other strata. There are rare occasions that a well may fail during 

drilling or does not produce enough gas to be economical and may have to be abandoned. In this 

case, proper procedures must be followed to abandon the well. 

Many shale gas development operators have abandoned the use of diesel in favor of more 

environmentally friendly fluids such as high paraffinic fluids, mineral oil and plant-based oils 

that possess less toxicity and are reasonably biodegradable (11). There is also the option to use 

waterless fracturing agents such as liquefied petroleum gas (LPG), GasFracTM, or liquid carbon 

dioxide DryFracTM. According to GasFracTM, their system is a closed-loop system that primarily 

uses propane since it is a naturally-occurring hydrocarbon and does not damage the shale 

formations (46).

If the topography is conducive and the distance not great, natural gas developers can also use 

conveyance pipes to carry the various water and fluids to well pads. Depending upon the 

location in the Marcellus, this may be an option to help reduce spill potential and truck traffic. 
43 | Page

Baseline monitoring studies of groundwater are needed before any drilling activity begins. 

Cementing of wellbore casings need to be carried out to the surface. Down-hole pressure testing 

and measurements and casing integrity tests are needed to ensure protection of shallow 

groundwater resources. 

One of the best ways a community’s water system source water can be protected is to have total 

ownership of the land, minerals, and gas and oil rights in the watershed area, or strict land-use 

ordinances or regulations (47). Since this kind of control is usually not possible, there are other 

measures nearby communities and drinking water system operators can make to protect their 

source waters. Source water and wellhead protection plans can be updated to reflect past and 

present gas well development. Transportation routes to and from well pads should be mapped 

and plans developed to handle potential spills that may occur along the way. 

Lab test results from routine drinking water and wastewater system analyses normally obtained

to meet SDWA and NPDES requirements, respectively, will help establish a baseline for any 

future anomalies and will be important to show changes in water quality if changes occur (47).

Drinking water system operators need to keep an eye on their raw water and wastewater system

operators need to watch their influent waste streams for any significant changes. Changes in 

TDS, TSS, conductivity, pH, bromide, chloride, or methane levels may signify that external 

factors may be influencing their system. Monitoring source water for drinking water systems 

and influent for wastewater systems should include VOCs, TDS, conductivity, total suspended

solids (TSS), chloride, bromide, dissolved methane, pH and radon. Systems on a limited budget 

should concentrate on chloride, bromide, conductivity, TDS and pH (47). 
44 | Page

With the boom in developing unconventional gas reservoirs through means of horizontal drilling 

and hydraulic fracturing operations, health and safety concerns from the public and private 

sectors have increased. A new American Society for Testing and Materials (ASTM) committee 

was recently formed to develop standards that will promote best practices for field operations 

and protect downstream air, land and water resources. Although in its initial stage of creation, 

the committee plans to look at all stages of gas well development – from initial site planning and 

investigation through well abandonment activities (48).

Lastly, critical evaluations of horizontal gas well development and their potential impacts on the 

environment must be based on peer-reviewed, scientific analyses of the data. Transparency will 

encourage acceptance of horizontal drilling and hydraulic fracturing activities. Open 

communication between industry, regulatory agencies and the general public is a must for 

successful development of natural gas resources that protects public health and the environment. 
45 | Page

Water and Waste Stream Monitoring Plan

Background

The intent of the Water and Waste Stream Monitoring Plan is to characterize and document 

potential surface and groundwater contamination that may be caused by any of the various stages 

of horizontal gas well development.

Roles and Responsibilities

A list of WVWRI staff directly involved in this study is included in Appendix A along with their 

contact information.

Study Design

The intent of the field sampling described in this monitoring plan is to characterize and 

document water and waste streams associated with the development of a horizontal gas well in 

the Marcellus play and to determine potential impacts from pits and impoundments on nearby 

groundwater resources. Marcellus gas wells at various stages of development have been selected 

for this project. WVWRI researchers worked with state agencies and industry representatives to 

identify the gas well sites and obtain access to the drilling fluids, muds and cuttings, and the 

hydraulic fracturing and flowback waters. WVWRI personnel also obtained information on the 

source water(s) that make up the hydraulic fracturing water, as well as copies of the hydraulic 

fracturing fluid composition breakdown. GPS coordinates were obtained and verified upon 

initial site visits for all gas well locations, sampling points, water withdrawals, permissible 

discharges, and pits and impoundments.

Water samples were collected and analyzed from all applicable impoundments and pits at each 

site studied. In addition, three centralized waste pits in Marshall County were monitored per 

requirements of §22-6A-9 (mandated for study by §22-6A-23). Background samples were 
46 | Page

collected from each monitoring well prior to pit use and post-pit acceptance of waste streams. 

The leak detection systems were monitored for the presence of leaked fluid. One monitoring well 

was placed up-gradient of the pit and two were placed down-gradient of the pit at each study 

location. Additional monitoring wells were installed down-gradient of two of the study pits in a 

deeper aquifer to provide further characterization. Part of this study focuses on sampling and 

analyzing the chemical makeup of drilling fluids, muds and cuttings along with hydraulic 

fracturing and flowback waters of Marcellus gas wells, paying specific attention to organic 

compounds, and determining which of these compounds are of concern for potential 

groundwater contamination. Water samples and samples of solids (cuttings, muds, etc.) from the 

drilling process were also analyzed for radioactivity.

An overview of the various stages of gas well development that were monitored, how often 

samples were collected during each stage, the type of sample - liquid or solid, and the sampling 

date is provided in Table 3. A listing of parameters analyzed for each sample by a commercial 

laboratory facility is provided in Table 4. Method detection limits (MDLs) and EPA method 

numbers for each parameter are also provided in Table 4. Total count and exposure radiation 

were monitored for all liquids and solids from impoundments and pits, as well as all groundwater 

samples. Sampling results were compared to primary and secondary federal drinking water

standards. Daily maximum values, values that exceed maximum contaminant levels, and 

average results for all parameters for each well development stage were determined from 

sampling results. 

Duplicate samples were randomly collected for approximately 10% of all samples taken. Field 

parameters such as pH, specific conductivity (μS/cm), total dissolved solids (mg/L), and 

temperature (oC) were measured in the field using a multi-parameter YSI 556 unit. Duplicate 
47 | Page

samples were obtained prior to sample collection in the field. WVWRI researchers also noted 

visual observations of the surrounding environment and obtained photographs during sampling 

visits.

On any field investigation, a minimum of two WVWRI staff were present. Each staff member 

was required to carry personal protective equipment (PPE) and flame-resistant (FR) clothing 

necessary for access to a well development or well development activity-related site. Minimum 

PPE requirements included: hardhat, safety glasses, metatarsal boots, metacarpal gloves and FR 

clothing. In addition, WVWRI personnel were required to have on hand: full-face respirators 

with combination P100 and organic vapor filters, first aid kits, a flotation device, a handheld 

radiation alert detector displaying current radiation levels in millirems per hour (mrem/hr) and a

6-gas photo ionizer detector (PID). The radiation alert detector and PID were used to scan the 

working environment prior to any sampling or monitoring activity on-site. 
48 | Page

Table 3: Water and Waste Stream Sampling Plan Stage Target Water/Waste Stream Sample Frequency Water/ Waste Stream Sample Phase Water/Waste Stream Point of Collection # Water / Waste Samples per Site Water and Waste Stream Sampling Dates, 2012 Air Monitoring Dates, 2012 Pad Site for Water/Waste Stream Monitoring Water Storage for Well Development Fresh Water Impoundment Fresh water Site specific (# of samples pulled determined by size of impoundment) Liquid Various locations dependent upon impoundment size, up to 8 (1) 6/7 (2) 8/28 (1) N/A (2) WAMS only: moved on 8/25 staying 6 days (1) Consol/Noble Centralized Impoundment (2) Mills Wetzel Pad #3 Liquid Liquid from shaker table, Composite (pit) 3 (1) 8/8, 8/15, 8/22, 10/2 (2) 10/25 Solid Muds from shaker table, Composite (pit)

3 (1) 8/8, 8/15, 8/22, 10/2 

(2) 10/25

Drilling fluid Once Liquid

Determined by site operator

1

(1) 8/8, attempted on 8/20, 8/22, 8/24 (2) Storm - completed drilling before samples could be collected

Liquid

Liquid from shaker table, Composite (pit)

3

(1) 8/8, attempted on 8/20, 8/22, 8/24 (2)Storm - completed drilling before samples could be collected

Solid

Muds from shaker table, Composite (pit)

3

(1) 8/8, attempted on 8/20, 8/22, 8/24 (2) Storm - completed drilling before samples could be collected

Hydraulic Fracturing Water

Tankers/Impoundments/Containers 2 (1) 7/25 only 1 sample (2) 9/11 only 1 sample 

Combined Hydraulic Fracturing Fluid & Freshwater

Stream of fluid going down hole 2 (1) 7/25 only 1 sample (2) 9/11 only 1 sample 

Initial 1

Solid

1

(1) 8/30/12 (2) 8/15 and 8/20 (3) 9/17 for SHL 3 & 4 only (4) TBD (5) 10/2 - one sample only 

Liquid

1

(1) 8/30 (2) 8/15 and 8/20 (3) 9/17 for SHL 3 & 4 only (4) TBD (5) 10/2 - one sample only 

Groundwater 

Monitoring

Pits: 

1 single-lined pit, 3 centralized pits

Each pit's monitoring wells

Prior to any waste entering pit, one following completion of waste entering the pit

Liquid Monitoring wells 6

(1) 6/4, 6/7 and 6/19 - initial; 10/31 - 11/1 - final (2) TBD

(1) N/A (2) N/A

(1) Consol/Noble - three centralized pits (2) EQT Smithburg 28, Dodderidge Co

(1) WAMS on 7/20, sampled 7/23 - 7/28: Trailer on 7/19, collected 7/20 - 8/2, off 8/2 (2) WAMS sampled 8/7 - 8/13, one WAM til 8/18: Trailer on 8/2, collected 8/3 - 8/16, off 8/16 (3) N/A (4) N/A (5) Equipment previously onsite during fracking, ALL Trailer equipment monitoring continuously 8/29 - 9/26: WAMS 

Stream of fluid coming 

up

(1) Lemons Pad (+25 days from 9/6) (2) WVDNR A Pad - Chesapeake

(1) Mills Wetzel Pad #2 (2) WVDNR A Pad - Chesapeake

(1) Waco - ECA Donna Pad (2) Maury Site (1) Waco ECA Donna Pad (2) Weekley Site #1 (3) Consol/Noble Centralized Pits (4) EQT Smithburg 28, Dodderidge Co (5) Maury Site HF done 9/14, Flowback did not start until 10/1, scheduled through 10/6 

(1) 7/27, 8/2, 8/9 and 8/30 (2) 8/15 and 8/20 (3) 8/13, 8/20, 8/28 and 9/17 (4) TBD (5) 10/2 - one sample only short flowback stage 

4

Storage of flowback

Liquid

(1) Trailer 9/26 - 10/16: WAMS 9/27 - 10/2 (2) WAMS 10/19 - 10/25: Trailer on 10/17, collected 10/19 on(1) WAMS collected 8/18 - 8/25: Trailer on 8/16, collected 8/17 - 8/24, off 8/24 (2) Equipment previously on site during vertical, Trailer continuously monitoring since 10/19; drilling occurred 10/25-10/31 but generator unplugged by Chesapeake no data collected: WAMS 10/26 - 10/29 (1) WAMS on 7/20, sampled 7/23 - 7/28: Trailer on 7/19, collected 7/20 - 8/2, off 8/2 (2) WAMS on 8/25, sampling 9/7 - 9/13: Trailer on 8/24, some instruments collecting 8/24 , remaining collecting 8/29, both til 9/14 

Well Drilling and 

Hydraulic 

Fracturing

Vertical 

Drilling

Once/week and composite

Horizontal 

Drilling

Drilling - produced waste 

Once/week and composite

Hydraulic 

Fracturing

Once/week (recording stage of frac)

Drilling - produced waste 

Pits: 

1 single-lined pit, 3 centralized pits

Waste Storage

Composite samples

1/week for first 3 weeks, during week 6

Flowback stream Liquid

Composite 
49 | Page

Table 4: Water and Waste Stream Parameters

Parameter

Preserva

tive

MDL 

(mg/L) Method

EPA MCL

(mg/L unless 

noted) Lab

Inorganics

Silver HNO3 0.001 EPA E200.7 0.1 mg/L, 2o REIC

Alk, Total None 1

EPA

SM2320 B NA REIC

Aluminum HNO3 0.04 EPA E200.7 0.05-0.2, 2o REIC

Arsenic HNO3 0.007 EPA E200.7 0.01 REIC

Barium HNO3 0.002 EPA E200.7 2 REIC

Bromide None 0.05 EPA E300.0 NA REIC

Calcium HNO3 0.05 EPA E200.7 NA REIC

Chloride None 0.1 EPA E300.0 250, 2o REIC

Conductivity None NA

EPA

SM 2510 B NA

REIC & 

Field

Chromium HNO3 0.001 EPA E200.7 0.1 REIC

Iron HNO3 0.01 EPA E200.7 0.3, 2o REIC

Mercury HNO3 0.0001 EPA E245.1 0.002 REIC

Magnesium HNO3 0.05 EPA E200.7 NA REIC

Manganese HNO3 0.001 EPA E200.7 0.05, 2o REIC

Sodium HNO3 0.03 EPA E200.7 NA REIC

Nickel HNO3 0.002 EPA E200.7 NA REIC

pH None NA

EPA

SM4500-H +-B 6.5-8.5

REIC & 

Field

Lead HNO3 0.003 EPA E200.7

0.015 action 

level REIC

Potassium HNO3 0.03 EPA E200.7 NA REIC

Nitrite H2SO4 0.05 EPA 300.0 1 REIC

Nitrate H2SO4 0.2 EPA 300.0 10 REIC

Sulfur HNO3 0.05 EPA E200.7 NA REIC

Selenium HNO3 0.008 EPA E200.7 0.05 REIC

Sulfate None 1 EPA E300.0 250, 2o REIC

Strontium HNO3 0.001 EPA E200.7 NA REIC

Zinc HNO3 0.003 EPA E200.7 5, 2o REIC

Hardness None 1

EPA

SM2340 B NA REIC

Carbonate− None 1

EPA

SM2320 B NA REIC

Bicarbonate None 1

EPA 

SM2320 B NA REIC
50 | Page

Parameter

Preserva

tive

MDL 

(mg/L) Method

EPA MCL

(mg/L unless 

noted) Lab

Phosphate H2SO4 0.02

EPA

SM4500-P BE NA REIC

Total 

Dissolved 

Solids None 5

EPA

SM 2540 C 500, 2o REIC

Total 

Suspended 

Solids None 5

EPA

SM 2540 D NA REIC

Organics

Methane None NA

EPA 

OSW3810 M NA REIC

Ethane None NA

EPA

OSW3810 M NA REIC

Propane None NA

EPA 

SW8260 B NA REIC

Total Organic 

Carbon H2SO4 0.2

EPA

SM 5310 C

Treatment 

technique REIC

Chemical 

Oxygen 

Demand H2SO4 4 EPA E410.4 NA REIC

Oil & Grease HCl 2 EPA E1664 A NA REIC

BTEX HCl

EPA 

SW8260 B

B-0.005, T-1,

E-0.7, X-10 REIC

Styrene HCl 0.38

EPA

SW8260 B 0.1 REIC

Tetrachloroethylene HCl 0.49EPA

SW8260 B 0.005 REIC

Surfactants 

(MBAS) None 0.1

EPA 

SM5540 C 0.05, 2o REIC

Petroleum 

Hydrocarbons None 0.25

EPA

SW8015 NA REIC

Radioactivity Gross Alpha

(pH<2) 

HNO3 NA EPA 900.0m 15 pCi/L Pace

Gross Beta

(pH<2) 

HNO3 NA EPA 900.0m 4 mR/yr Pace

Lead-210

(pH<2) 

HNO3 NA EPA 901.1m NA Pace

Radium-226

(pH<2) 

HNO3 NA EPA 901.1m *

5 pCi/L

combined 226/228 Pace

Radium-228

(pH<2) 

HNO3 NA EPA 901.1m *

5 pCi/L 

Combined 226/228 Pace

Thorium-230, 

-228, -232

(pH<2) 

HNO3 NA HASL 300m NA Pace

Uranium-238,

(pH<2) 

HNO3 NA HASL 300m 30 μg/L (238) Pace

Potassium-40

(pH<2) 

HNO3 NA EPA 901.1m NA Pace

*For liquid samples, Radium-226 is EPA 903.1 and Radium-228 is EPA 904.0.

2° = secondary standards
51 | Page

Sampling Sites

Marcellus gas wells at the various stages of development were selected for this project. WVWRI 

researchers worked with state agencies and industry representatives to identify the gas well sites 

and obtain access to the drilling fluids, muds and cuttings, and the hydraulic fracturing and 

flowback waters. Eight different well sites were monitored as part of this study. Refer to Table 

5 for site location information. A combination of the eight sites was used to capture all phases of 

drilling activity. More information on each site is given in Appendix B. 

Table 5: Sampling Site Locations

Site

Sampling 

Date

Sample 

County Sample Location

Well Development 

Stage

Impoundments (prior to conversion to pit)

SHL - 1 IMP 6/7/12 Marshall Impoundment edge Freshwater

SHL – 2 IMP 6/7/12 Marshall Impoundment edge Freshwater

SHL – 3 IMP 6/7/12 Marshall Impoundment edge Freshwater

MW – 3 IMP 8/28/12 Wetzel Impoundment edge Freshwater

Groundwater Monitoring

SHL – 2, MW - 1 Dry Marshall Monitoring well Freshwater

11/1/12 Marshall Monitoring well After pit conversion

SHL – 2, MW - 2 6/4/12 Marshall Monitoring well Freshwater

10/31/12 Marshall Monitoring well After pit conversion

SHL – 2 MW - 3 6/4/12 Marshall Monitoring well Freshwater

10/31/12 Marshall Monitoring well After pit conversion

SHL – 2 MW - 4 6/19/12 Marshall Monitoring well Freshwater

11/1/12 Marshall Monitoring well After pit conversion

SHL – 4 MW – 1 6/4/12 Marshall Monitoring well Freshwater

10/31/12 Marshall Monitoring well After pit conversion

SHL – 4 MW – 2 6/4/12 Marshall Monitoring well Freshwater

10/31/12 Marshall Monitoring well After pit conversion

SHL – 4 MW - 3 6/4/12 Marshall Monitoring well Freshwater

10/31/12 Marshall Monitoring well After pit conversion

SHL – 3 MW - 4 6/19/12 Marshall Monitoring well Freshwater

11/1/12 Marshall Monitoring well After pit conversion

Hydraulic Fracturing (HF)

HF Water (Waco Donna pad) 7/25/12 Marion Impoundment edge Make-up water

Comb HF (Waco Donna pad) 7/25/12 Marion Blender sample port

Combination make-up 

water and fracturing 
52 | Page

Site

Sampling 

Date

Sample 

County Sample Location

Well Development 

Stage

chemicals

HF Water (Maury pad) 9/11/12 Wetzel Holding tank Make-up water

Comb. HF (Maury pad) 9/11/12 Wetzel After blender

Combination make-up 

water and fracturing 

chemicals

Vertical Drilling

ST 1-1 liquid (Lemons pad) 8/8/12 Wetzel Shaker Table Vertical Drilling

ST 1-1 solid (Lemons pad) 8/8/12 Wetzel Shaker Table Vertical Drilling

ST 1-2 liquid (Lemons pad) 8/15/12 Wetzel Shaker Table Vertical Drilling

ST 1-2 solid (Lemons pad) 8/15/12 Wetzel Shaker Table Vertical Drilling

ST 1-3 (Lemons pad) 8/15/12 Wetzel Shaker Table Vertical Drilling

ST 1-3 solid (Lemons pad) 8/15/12 Wetzel Shaker Table Vertical Drilling

ST 1-4 (Lemons pad) 10/2/12 Wetzel Shaker Table Vertical Drilling

ST 1-4 solid (Lemons pad) 10/2/12 Wetzel Shaker Table Vertical Drilling

ST 2 liquids (Mills Wetzel 2 pad) 8/8/12 Wetzel Shaker Table Vertical Drilling

ST 2 solids (Mills Wetzel 2 pad) 8/8/12 Wetzel Shaker Table Vertical Drilling

DNR ST 3-1-L 10/25/12 Brooke Shaker Table Vertical Drilling

DNR ST 3-1-S 10/25/12 Brooke Shaker Table Vertical Drilling

Waste Storage/Flowback Stream

FS – 1 (Waco Donna pad) 7/27/12 Marion Condensate Tank Flowback

FS –2 (Waco Donna pad) 8/2/12 Marion Condensate Tank Flowback

FS – 3 (Waco Donna pad) 8/9/12 Marion Condensate Tank Flowback

FS – Final (Waco Donna pad) 8/30/12 Marion Condensate Tank Flowback

Donna Pit C (Waco Donna pad) 8/30/12 Marion Condensate Tank Waste Storage

FS – 1 – SHL - 3 8/13/12 Brooke Impoundment Edge Waste Storage

FS – 2 – SHL - 3 8/20/12 Brooke Impoundment Edge Waste Storage

FS – 3 – SHL - 3 8/28/12 Brooke Impoundment Edge Waste Storage

FS – Final – SHL - 3 9/17/12 Brooke Impoundment Edge Waste Storage

SHL – 4 – Comp 9/17/12 Brooke Impoundment Edge Waste Storage

Weekley – FS – 1 8/15/12 Wetzel

Separator before 

disposal tank

Flowback

Weekley – FS – 2 8/20/12 Wetzel

Separator before 

disposal tank

Flowback

Maury – FS – 1 10/2/12 Wetzel

Separator before 

disposal tank

Flowback
53 | Page

Sampling occurred for each stage of drilling activity at the following sites:

Water Storage (Impoundment)

1. Consol/Noble Centralized Impoundments, Impoundments SHL-3 and SHL-2 (sampled 

6/7/2012)

2. Mills Wetzel Pad #3 - Stone Energy (sampled 8/28/2012)

Figure 1 is a map of the three Consol/Noble centralized impoundments-to-pits with incorporated 

coordinates. Figures 2 and 3 illustrate initial sampling activities of the impoundments. 
54 | Page

Figure 1: Centralized Pits Locations
55 | Page

Figure 2: SHL-1 Impoundment Sampling

Figure 3: SHL-1 Impoundment Sampling
56 | Page

Drilling wastes (vertical section)

1. Lemons Pad – Stone Energy (Sampled 8/8/2012, 8/15/2012, 8/22/2012, and 10/2/12 )

2. WVDNR A Pad – Chesapeake Energy (Sampled 10/25/12)

Four samples of liquids and solids (muds and cuttings) generated during the vertical drilling 

phase of a horizontal well were collected from the Lemons Pad – Stone Energy site. The last of 

these samples was taken while air monitoring equipment was in use on the site. The point of 

collection for both the liquid and solid samples at the Lemons Pad is illustrated in Figures 4 and 

5 and Figure 6 shows a sample of the drilling fluids. For the WVDNR A site, one sample of the 

produced drilling solids and liquids was collected. Sample collection at both sites was 

coordinated with the air monitoring team. 

Figure 4: Lemons Pad – Shaker Table Liquids
57 | Page

Figure 5: Lemons Pad – Shaker Table Solids

Figure 6: Lemons Pad – Vertical Drilling Fluids
58 | Page

Drilling wastes (horizontal section)

1. Mills Wetzel Pad #2 – Stone Energy (sampled 8/8/2012, sampling attempted 8/20/2012, 

8/22/2012 and 8/24/2012)

2. WVDNR A Pad – Chesapeake Energy (Sampling not completed due to weather and 

operator finishing drilling early)

One sample of the produced drilling liquids and solids was collected from the Mills Wetzel Pad 

#2 site. However, this sample was not a “true” horizontal drilling sample as the operator was still 

drilling the curve in the borehole and was not yet in the Marcellus shale strata. Information on 

this sample can be found in the vertical drilling section of this study. Several attempts were made 

to obtain additional samples from the Mills Wetzel Pad #2 site. However, due to drilling 

malfunctions and scheduling issues, WVDEP and the WVU project team decided to forgo 

sampling at this site in order to sample water and air at additional sites during various well 

development stages. The shaker table where liquid and solids samples were collected is shown 

in Figure 7.

Sample collection was planned for the WVDNR A Pad site during the vertical drilling phase. 

However, due to a combination of the operator completing drilling more quickly than anticipated 

and poor weather conditions, no sample was obtained. 
59 | Page

Figure 7: Mills Wetzel Pad #2 Shaker Table (where samples were pulled)

Hydraulic Fracturing Fluids

1. Donna Pad - Waco/ECA (sampled on 7/25/2012)

2. Maury Pad – Stone Energy (sampled on 9/11/2012)

Samples of the water used to mix with the hydraulic fracturing fluids (makeup water) were taken 

from the Donna Pad storage pit by using a swing sampler as shown in Figure 8. Samples of the 

hydraulic fracturing fluids and water mixture were taken from the blender prior to entering the 

Donna Pad well. Hydraulic fracturing sampling activities of well pad staff and the location of 

the sampling point are illustrated in Figures 9 and 10. Sample collection was coordinated with 

the air monitoring team at each of the sites. Hydraulic fracturing samples were taken on 9/11/12 

at the Maury Pad. The makeup water sample was retrieved from an on-site holding tank and the 

hydraulic fracturing fluid sample was taken after the blender, prior to entering the Maury Pad 

well. Sampling at the Maury pad was coordinated with the air monitoring team.
60 | Page

Figure 8: Donna Pad Pit Sampling of Hydraulic Fracturing (Makeup) Water

Figure 9: Sampling Hydraulic Fracturing Fluids and Water Mixture before Entering Well
61 | Page

Figure 10: Sampling Location of Hydraulic Fracturing Fluids

Flowback 

1. Donna Pad - WACO/ECA (sampled 7/27/2012, 8/2/2012, 8/9/2012 and 8/30/2012)

2. Weekley Site #1 - Stone Energy (sampled 8/15/2012 and 8/20/2012)

3. Consol/Noble Centralized Pits (SHL-3 and SHL-4) (sampled 8/13/2012, 8/20/2012, 

8/28/2012 and 9/17/2012)

4. EQT Smithburg 28 (will be sampled after monitoring well completion)

5. Maury Site – Stone Energy (sampled 10/2/12)

For each site, a water sample of the fluid stream coming back up-hole was collected at the onset 

of well flowback. Depending upon the site operations, up to three additional water samples of 

the fluid stream from the well were taken during flowback and produced water phases. The 

point of collection depended upon the site and operating procedures in place. These samples 

were collected prior to entering storage facilities or after being contained in storage facilities. A 
62 | Page

composite sample was taken near the end of the flowback stage from the storage facility on-site 

(i.e., pit, container) at the same time the last flowback water sample was taken.

Flowback samples were collected at a condensate tank on the Donna Pad – WACO/ECA as 

shown in Figure 11. Figure 12 shows the point-of-collection for the composite liquid and solids 

sample of flowback/produced water on the Donna Pad. This type of pit structure is typical 

among the sites visited. Figure 13 is the sample area at the Weekley pad. The sample was taken 

from a separator. Figure 14 is the Sand Hill #3 and #4 pits. A composite sample was taken from 

six different points (each corner and the middle of the long sides) in the pit from the Sand Hill #4 

Pit (SHL-4). The six samples were combined into a composite sample, which was used to fill all 

sampling bottleware.
63 | Page

Figure 11: Flowback Sampling Point at Condensate Tanks, Donna Pad

Figure 12: Composite Flowback Stream Sample at Donna Pad Single-Lined Pit
64 | Page

Figure 13: Weekley Pad Sample Area – Sample taken from the nozzle (see arrow)
65 | Page

Figure 14: Sample area at the Sand Hill # 3 and #4 (at lower right) Pits

Groundwater Monitoring

1. Consol/Noble Centralized Pits – Sand Hill Location Pits SHL2, SHL3 and SHL4 

(sampled 6/4/2012, 6/7/2012, 6/19/2012 (initial sampling) and 10/31/12 and 11/112 

(final))

2. EQT Smithburg 28 (Monitoring wells were not drilled and completed in time for 

inclusion in this report. The results of these wells will be included in the Water and 

Waste Report, Phase II.

Please refer to Table 6 and Figures 15, 16 and 17 for additional information concerning the 

groundwater monitoring wells relative to their depths and proximity to the storage pits.
66 | Page

Table 6: Groundwater Monitoring Wells at Consol/Noble Centralized Pits

Site Name Sample Date

Location Relative 

to Pit

Total 

Well 

Depth

(ft)

Depth 

to 

Water

(ft)

SHL-2, MW-1, Noble Pits 6/4/2012 up-gradient 77.02 DRY

SHL-2, MW-2, Noble Pits 6/4/2012 down-gradient 47.61 28.38

SHL-2, MW-3, Noble Pits 6/4/2012 down-gradient 56.98 44.77

SHL-2, MW-4, Noble Pits 

(deep) 6/19/2012 down-gradient 43.7 26.1

SHL-3, MW-1, Noble Pits 6/4/2012 up-gradient 63.70 DRY

SHL-3, MW-2, Noble Pits 6/4/2012 down-gradient 60.59 DRY

SHL-3, MW-3, Noble Pits 6/4/2012 down-gradient 61.83 DRY

SHL-3, MW-4, Noble Pits 

(deep) 6/19/2012 down-gradient 45.65 40.65

SHL-4, MW-1, Noble Pits 6/4/2012 up-gradient 51.4 38.7

SHL-4, MW-2, Noble Pits 6/4/2012 down-gradient 56.92 40.11

SHL-4, MW-3, Noble Pits 6/4/2012 down-gradient 46.82 39.98

SHL-2, MW-1 Noble Pits 11/1/2012 up-gradient 77.02 49.36

SHL-2, MW-2, Noble Pits 10/31/2012 down-gradient 47.61 22.07

SHL-2, MW-3, Noble Pits 10/31/2012 down-gradient 56.98 44.51

SHL-2, MW-4, Noble Pits 

(deep) 11/1/2012 down-gradient 43.7 29.97

SHL-3, MW-1, Noble Pits 11/1/2012 up-gradient 63.70 DRY

SHL-3, MW-2, Noble Pits 11/1/2012 down-gradient 60.59 DRY

SHL-3, MW-3, Noble Pits 11/1/2012 down-gradient 61.83 DRY

SHL-3, MW-4, Noble Pits 

(deep) 11/1/2012 down-gradient 45.65 39.46

SHL-4, MW-1, Noble Pits 10/31/2012 up-gradient 51.4 22.22

SHL-4, MW-2, Noble Pits 10/31/2012 down-gradient 56.92 39.24

SHL-4, MW-3, Noble Pits 10/31/2012 down-gradient 46.82 28.19

Deep wells were installed a further distance downslope of the pits and are in a different aquifer.

The location of SHL-3, MW-4 (a deep well) is down-gradient from the SHL-3 pit as well.
67 | Page

Figure 15: Location of Consol/Noble Centralized Pits
68 | Page

Figure 16: Consol/Noble Centralized Pit SHL3
69 | Page

Figure 17: Consol/Noble Centralized Pits SHL2 and SHL4

Sampling at the EQT Smithburg 28 pad is planned pending the completion of monitoring wells. 

Due to landowner issues, progress was delayed and EQT is in the process of obtaining approvals 

and permits to drill the groundwater monitoring wells. 
70 | Page

Various sampling bottles needed for groundwater sampling collection are shown in Figure 18. 

Sample collection is illustrated in Figure 19. Groundwater monitoring well equipment used for 

the low-flow sampling method (51) is shown in Figure 20.

Figure 18: Bottles for Typical Groundwater Sample
71 | Page

Figure 19: Collection of Groundwater Sample from Consol/Noble Centralized Pit SHL2
72 | Page

Figure 20: Low Flow Sampling at SHL3 Groundwater Monitoring Well

Field Sampling Methods

Refer to Table 3 for corresponding information for the sub-sections below. Sample bottles were 

prepared by the commercial laboratory, REI Consultants (REIC), and provided to WVWRI 

researchers for use. An example of the REIC chain-of-custody form is attached as Appendix C. 

The Pace Analytical chain-of-custody is attached as Appendix D. Samples were stored 

according to the various EPA analytical methods and pick-ups were arranged with REIC and 

Pace Analytical to ensure analysis of samples within specified holding times. 

General Equipment List

1. Decontamination materials

2. All sample containers

3. Cooler with ice
73 | Page

4. Photo-Ionization Detector (PID)

5. GPS unit

6. Handheld radiation alert detector (Radiation Alert Inspector EXP)

7. Field notebook, calculator and field data sheets

8. Multi-parameter water-quality meter with accompanying flow-through cell (YSI-556)

9. Calibration fluids

10. Health and safety plan and all personal protective equipment

11. Five-gallon buckets

12. Nitrile gloves

13. Tools and batteries for all equipment

Groundwater Monitoring

Specified Equipment List for Groundwater Sampling

1. Electronic interface probe for determination of liquid products present and depth-to-water

2. Adjustable rate peristaltic pump and/or standard performance PVC pump with controller

3. Teflon® and silicon tubing

4. Power source

5. Graduated cylinder (flow measuring device)

6. Five-gallon bucket

7. Fifty-five gallon drum for purge water

8. Activated carbon unit (purge water filtration device)
74 | Page

Sampling Procedures for Groundwater Sampling Events

Groundwater sampling proceeded from up-gradient of the pit/impoundment to down-gradient. 

Nitrile gloves were used during all sampling procedures and were changed between well 

locations to prevent sample contamination. Equipment that was not dedicated to a specific well 

was decontaminated using a mild detergent free of interfering residues between sampled wells. 

This approaches follows EPA procedures for “Field Equipment Cleaning and Decontamination” 

that can be found at http://www.epa.gov/epawaste/hazard/testmethods/faq/faqs_sampl.htm.

Water was tested for radioactivity using a radiation alert detector at both the onset of purging 

activities and post-sampling activities. Duplicate samples were obtained for 10% of collected 

samples. Equipment blanks and/or field blanks were also used to ensure sample quality control. 

Sampling procedures were as follows:

1. The lock and cap were removed from the well casing and the headspace of the well was 

monitored for volatile organic compounds (VOCs) with a PID. PID data was recorded in 

a field book. 

2. The depth-to-water was measured from a marked reference point on the casing to the 

nearest 0.01 feet using the interface probe. The initial reading was confirmed by a second 

measurement.

3. The total volume of water in the well casing was determined and recorded, along with all 

other appropriate data, including GPS location, date, time, and screened interval, in a 

field book.

4. (For wells with depth-to-water 27 feet or less from the top of casing). Teflon® tubing 

was lowered to approximately the middle of the pre-determined screened interval. 

Teflon® tubing was connected to the peristaltic pump using silicon tubing and the flowthrough cell with multi-meter was connected to the opposite side of the peristaltic pump. 
75 | Page

Teflon® tubing was attached to the exit point of the flow-through cell and routed into a 5 

gallon bucket to collect purge water. The pump was connected to a power source. 

5. (For wells with depth-to-water greater than 27 feet from the top of casing). Teflon® 

tubing was connected to the standard performance PVC pump and slowly lowered to 

approximately the middle of the pre-determined screened interval. The flow-through cell 

with multi-meter was connected to the pump. Teflon® tubing was attached to the exit 

point of the flow-through cell and routed into a five-gallon bucket to collect purge water. 

The pump was connected to a power source. 

6. Groundwater was pumped at a rate no greater than 0.5 liters per minute. Water-quality 

readings of pH, electrical conductance (EC), temperature (in degrees Celsius), total 

dissolved solids (TDS), oxidation Salinity (Sal), and dissolved oxygen (DO) were 

recorded from the multi-parameter meter after the flow-through cell had been purged and 

after a minimum of one tubing volume. Water-level measurements were taken every 30 

seconds to 5 minutes, which allowed the sampler to control the pumping rate. Water 

drawdown did not exceed 0.33 feet. 

7. Water quality data was recorded every 3 to 5 minutes, depending on pumping rate and 

water drawdown. Grab sampling commenced after stabilization of water quality 

parameters (three consecutive readings of all parameters within 10% of the previous 

reading). 

8. Sample bottles were filled in the order of volatile organic compound bottles first, 

followed by semi-volatile organic compounds, inorganics, and other unfiltered samples. 
76 | Page

9. Samples were immediately cooled and prevented from exposure to sunlight by placing 

them on ice in a dedicated sample cooler. A chain-of-custody was completed and all 

samples were shipped or delivered to the laboratory within specified holding times. 

10. All appropriate equipment was decontaminated using a mild soap/water solution and all 

purge water was properly disposed of following proper EPA procedures for “Field 

Equipment Cleaning and Decontamination” that can be found at: 

http://www.epa.gov/epawaste/hazard/testmethods/faq/faqs_sampl.htm. 

Water Storage for Well Development

Specified Equipment List for Sampling Freshwater Impoundments

1. Swing samplers (dippers)

2. Disposable bottles for use with swing samplers

3. Five-gallon buckets

Sampling Procedures for Freshwater Impoundments

The sample locations selected were dependent on the availability of access to the impoundment 

as well as the safety and well-being of the sampler. If possible, samples were taken from the inlet 

pipes. If the inlet pipes were not discharging water, samples were taken from the edge of the 

impoundment near the inflow point. Grab samples were the method employed for the 

impoundments. Swing samplers and/or direct method sampling via five-gallon buckets were used 

to obtain the sample. The following procedures were used during sample collection: 

1. Sample locations were recorded using a GPS. A PID was used to check for background 

off-gassing of VOCs. The coordinates and PID data were recorded in a field book. A 

handheld radiation alert detector was also used to check for background radiation levels, 

and this data was also recorded in a field book. 
77 | Page

2. A multi-parameter water-quality meter was used to determine water quality readings of 

pH, EC, temperature, TDS, salinity, and DO. One water quality reading was recorded 

during each sampling date due to limited impoundment access. 

3. Samples were retrieved via the direct sampling method by using a swing sampler with a 

disposable bottle or a five-gallon bucket. Handheld radiation alert detector, PID, and 

water quality readings were determined and recorded.

4. If additional water was needed to fill all sample containers, a second sample was obtained 

using step 3. 

5. Sample bottles were filled in the order of volatile organic compound bottles first, 

followed by semi-volatile organic compounds, inorganics, and other unfiltered samples. 

6. Samples were immediately cooled and prevented from exposure to sunlight by placing 

them on ice in a dedicated sample cooler. A chain of custody was completed and all 

samples were shipped or delivered to the laboratory within specified holding times. 

7. All appropriate equipment was decontaminated after each use.

Moving Waste Stream

Specified Equipment List for Sampling Vertical Drilling Operations

1. Sediment samplers (sludge judge)

2. Five-gallon bucket

Sampling Procedures for Vertical Drilling Operations

Drilling produced muds and cuttings were collected once per week for three weeks from a shaker 

table and a final sample was taken six weeks after the third sample. Both liquid and solid phase 

wastes were sampled. The WVDNR A site was only sampled once due to late inclusion into the 

study.
78 | Page

Shaker Table Samples

1. Sample locations were recorded using a GPS. A PID was used to check for background 

off-gassing of VOC’s. The coordinates and PID data were recorded in a field book. A 

handheld radiation alert detector was also used to check for background radiation levels, 

and this data was also recorded in a field book. 

2. A liquid grab sample was obtained using a swing sampler or five-gallon bucket. Water 

quality, PID and radiation alert detector readings were taken and recorded.

3. Liquid samples were filled in the order of volatile organic compound bottles first, 

followed by semi-volatile organic compounds, inorganics, and other unfiltered samples. 

4. Solid samples were obtained using the grab sample method and placed in laboratory 

approved sample bottles. PID and radiation alert detector head space readings were taken 

and recorded. 

5. Samples were immediately cooled and prevented from exposure to sunlight by placing 

them on ice in a dedicated sample cooler. A chain-of-custody was completed and all 

samples were shipped or delivered to the laboratory within specified holding times.

6. All appropriate equipment was decontaminated after each use.

Pit Samples

The pit samples were grab samples. Swing samplers and/or direct method sampling via fivegallon buckets were used. Sample locations were dependent on the accessibility of the pits and 

the safety and well-being of the sample handler.

1. Sample locations were recorded using a GPS. A PID was used to check for background 

off-gassing of VOC’s. The coordinates and PID data were recorded in a field book. A 

handheld radiation alert detector was also used to check for background radiation levels, 

and this data was also recorded in a field book. 
79 | Page

2. Due to site access issues, swing samplers and/or a five-gallon bucket were used to obtain 

the sample from the edge of the pit. Radiation alert detector, water quality, and PID 

readings were taken and recorded. 

3. Step 2 was repeated (if needed) to obtain another sample and fill all sample bottles. All 

remaining water was properly disposed of. 

4. Liquid samples were filled in the order of VOC bottles first, followed by semi-volatile 

organic compounds, inorganics, and other unfiltered samples. 

5. Using a sludge judge sediment sampler, a solid sample was collected from the bottom of 

a pit at the same location as the liquid sample and placed in laboratory-approved sample 

bottles. The solid sample was collected from one point; however, this sample 

approximated a composite sample, as all of the wells flowed into the pit. PID and 

radiation alert detector head space readings were also recorded from the sludge sample. 

6. Sample bottles were filled in the order of VOC bottles first, followed by semi-volatile 

organic compounds and inorganics.

7. Samples were immediately cooled and prevented from exposure to sunlight by placing 

them on ice in a dedicated sample cooler. A chain-of-custody was completed and all 

samples were shipped or delivered to the laboratory within established holding times.

8. All appropriate equipment was decontaminated after each use.

Sampling Procedures for Horizontal Drilling Operations

The sampling procedures for horizontal drilling operations followed the same direct methods as 

the vertical drilling operations. 

Sampling Procedures for Hydraulic Fracturing

Hydraulic fracturing fluid (chemical mixture only) was not sampled because a sample could not 

be obtained immediately after the individual chemicals were mixed together. The chemicals were 
80 | Page

mixed with water before a sample could be obtained. Hydraulic fracturing water (makeup

water) was sampled once from a pit (Donna site) and once from a tank (Maury site). Methods 

from the “sampling procedures for freshwater impoundments” listed above were followed for the 

pit sample. The tank sample was obtained using a five-gallon bucket. Water quality, 

radioactivity, and VOC readings were monitored and recorded in a field book at each site. 

The combined hydraulic fracturing fluid and freshwater mixture was sampled once. The sample 

was obtained in a five-gallon bucket from a sampling port on the blender truck. Water quality, 

radioactivity, and VOC readings were monitored and recorded in a field book. All methods for 

sampling during hydraulic fracturing operations (such as filling bottle ware, sample handling, 

and decontamination) followed proper methods and protocols as aforementioned in this 

document. 

Waste Storage

Flowback Stream

The flowback stream was sampled at various locations during the well production and 

development process. Sample location was dependent upon site accessibility. Methods ranged 

from obtaining grab samples at a pit to sampling ports on separators and condensate tanks. All 

methods for sampling the waste storage (such as filling bottle ware, sample handling, and 

decontamination) followed proper methods and protocols as aforementioned in this document.

Analytical Methods

Standard operating procedures are designed to optimize the accuracy and representativeness of 

water chemistry data. WVWRI technicians have been certified for sample collection following 

EPA standard methods and procedures. Guidelines were followed for sample preparation, 

collection, packaging and transport to maintain the integrity of the samples. Proper chain-ofcustody requirements were adhered to. 
81 | Page

Organics and Inorganics

Samples were stored as required by the various EPA analytical methods and pick-ups arranged 

with the certified laboratory, REIC Consultants, within specified holding times. An example of 

the chain-of-custody form used by REI Consultants is attached as Appendix C. All sample 

analyses and laboratory activities were performed based on REI Consultants standard operating 

procedures and EPA sampling and analyses protocols. Table 7 provides an overview of REI 

Consultants quality assurance and quality control (QA/QC) procedures. This information is 

excerpted from the REI Consultants Quality Manual (52). QC is specifically spelled out in the 

individual standard operating procedures (SOPs) for each analytical test. This table is an 

overview of QC samples that were included and/or required for the various analytical tests. REI 

Consultants were responsible for the regular instrumentation maintenance and quality checks 

required of a certified laboratory. WVWRI was responsible for the regular maintenance, quality 

checks and calibrations of field sampling and monitoring equipment.

Radioactivity

Samples were stored as required by the various EPA analytical methods and pick-ups arranged 

with the certified laboratory, Pace Analytical, within specified holding times. An example of the 

chain-of-custody form used by Pace Analytical is attached as Appendix D. All sample analyses 

and laboratory activities were performed based on Pace Analytical SOPs and EPA sampling and 

analyses protocols. Table 8 provides an overview of Pace Analytical quality assurance and 

quality control (QA/QC) procedures. This information is excerpted from the Pace Analytical 

Quality Manual (53). QC is specifically spelled out in the individual SOPs for each analytical 

test. This table is an overview of QC samples that were included and/or required for the various 

analytical tests. Pace Analytical was responsible for the regular instrumentation maintenance 
82 | Page

and quality checks required of a certified laboratory. WVWRI was responsible for the regular 

maintenance, quality checks and calibrations of field sampling and monitoring equipment.

Table 7: REI Consultants – Inorganic and Organic Data Check

Inorganic Data Checks Organics Data Check

Sample Chain of Custody (COC) Sample Chain of Custody (COC)

Extraction & Analysis sample holding times Extraction & Analysis sample holding times

Calibration: Initial Calibration

• Initial Calibration Verification (ICV) Continuing Calibration Verification (CCV)

• Initial Calibration Verification Blanks

• Continuing Calibration Verification (CCV) Surrogate Recoveries

Blanks Duplicate Samples

Laboratory Control Spike (LCS) Matrix Spike (MS)/Matrix Spike Duplicate (MSD)

Quality Control Spike (QCS) Sample Internal Standard Performance

Duplicate (DUP) Sample Compound Identification

Matrix Spike (MS) Sample Compound Quantitation and Reporting Limits

Field Duplicates System Performance

Method Specific QC Field Duplicates

Overall Assessment Equipment Blanks

Chromatogram Retention Times

Mass Spectrometer Tuning Criteria Compliance

Method Specific QC

Overall Assessment
83 | Page

Table 8: Pace Analytical – Radioactivity Data Check

Radioactivity Data Checks

 Blanks

Method Blank

Laboratory Control Sample (LCS)

Matrix Spike/Matrix Spike Duplicate (MS/MSD)

Sample Duplicates

Surrogates

 Internal Standards

Field Blanks 

Trip Blanks

Data Management

Routine data related to the collection of samples was recorded during each site visit. Data was

written in field record books and transferred to an electronic data file located on the WVWRI 

shared server once field technicians returned to the office. Times, dates and personnel involved 

in data collection were also recorded in field record books and transferred to the electronic data 

file. Copies of chain-of-custody forms for each set of samples sent to REI Consultants and Pace 

Analytical were scanned and included as part of the electronic data file. Other data regarding 

sampling methods or other pertinent information regarding visits and well development was 

recorded in field record books. As needed, the data transferred to the electronic data file was 

reviewed and reported to the WVDEP as part of the monthly progress updates. Photographs 

were used to assist with documenting field activities and conditions. Data collected in the field 

and analytical results obtained from REI Consultants and Pace Analytical were reviewed after 

each site visit and upon receipt from the respective laboratories. Any measurements (parameter, 

concentration) above environmental water quality standards were noted and potential causes 

were investigated. Potential outliers of data were reviewed as well. Outliers include

unexplained spikes in data or unexplained zero/negative readings.
84 | Page

Reference of field and analytical laboratory results to other commercial and industrial activities 

were made as a basis for comparison and understanding of horizontal gas well development 

impacts on the surrounding environment. Based on the data analysis, potential health concerns 

or risks associated with the well development occurring at that site were noted and are included 

as part of the Results section of this report. Long-term monitoring recommendations are 

included as part of the final report to WVDEP as well. 
85 | Page

Data Analysis, Results and Comparison with Water Quality Standards

The study sought to: 

1. Characterize drilling muds and cuttings and identify pollutants. 

2. Compare hydraulic fracturing fluids with flowback and identify pollutants. 

3. Identify whether the groundwater monitoring wells indicate contamination of 

surrounding groundwater as a result of impoundment leakage. 

In the following analysis all determinations below the detection limit were assigned a value of 

zero.

Drilling Muds and Cuttings Characterization and Pollutant Identification

Drilling muds were analyzed as liquids while drill cuttings were analyzed as solids. With the 

exception of arsenic, mercury, nitrate and selenium, the average concentrations of the primary 

and secondary drinking water parameters in drilling mud were in excess of all of the inorganic 

drinking water standards as shown in Table 9. They also exceeded the drinking water standard 

for benzene and surfactant (MBAS) as illustrated in Table 10. Drilling muds contained very 

high concentrations of sodium, potassium and chloride. TPH (diesel range) was present in all 

drilling muds. Concentrations ranged from 23 to 315 mg/L. 

Air monitoring requirements, with respect to the Occupational Safety and Health Administration 

(OSHA), vary depending according to materials and exposures. Monitoring was based on the 

requirements of Hazardous Waste Operations and Emergency Response Regulations (29 CFR 

1910.120(h)) and the United States Environmental Protection Agency Standard Operating Safety 

Guide (Publication 9285.1-03). Nearly all drilling mud and drill cutting samples were higher 

than background with regard to radioactivity. The relation between these field readings and 

regulatory standards is not evident as shown in Table 11. Radiation monitoring was conducted 
86 | Page

utilizing an Inspector EXP Geiger Mueller with an external pancake probe. The Inspector EXP 

is capable of detecting alpha, beta and gamma radiation as required by the previously referenced 

regulations. The meter determined background levels of radiation in milliroentgens per hour 

(mrem/hr). Further, samples were screened for potential radioactivity for possible worker 

exposure and compared to background levels. Alpha, beta and gamma radiation were included 

in background determinations since readings were taken in the open air. However, readings from 

the samples in containers would most likely only represent gamma radiation since alpha and beta 

typically cannot escape the sample container.

Radioactivity readings were obtained for 46 of the 51 samples obtained. Background levels of 

radiation ranged from 0.005 mrem/hr to 0.022 mrem/hr. Sample levels of radiation ranged from 

0.007 mrem/hr to 0.018 mrem/hr. The standard for contamination is typically twice background. 

A review of the individual background levels of radiation indicated that criterion was not 

exceeded in any sample. One sample was exactly twice the background level of radiation for 

that site but less than some of the other background levels from previous readings. The 

acceptable annual dose of radiation for individuals working with radioactive materials is 5,000 

mrem. Based on the readings obtained from the field instrumentation, appropriate sampling 

techniques and Personal Protective Equipment (PPE) would minimize exposure of sampling staff 

to radioactivity.

Table 12 includes radioactivity results received to date for drilling mud samples and one 

flowback solids sample. In the absences of standards for semi-solid to solid materials, the 

drinking water standards for the radioactive parameters were used. Only the standard for gross 

alpha radiation was exceeded. According to EPA 

(http://www.epa.gov/radiation/understand/alpha.html): 
87 | Page

The health effects of alpha particles depend heavily upon how exposure takes place. 

External exposure (external to the body) is of far less concern than internal exposure 

because alpha particles lack the energy to penetrate the outer dead layer of skin. 

However, if alpha emitters have been inhaled, ingested (swallowed), or absorbed into the 

blood stream, sensitive living tissue can be exposed to alpha radiation. The resulting 

biological damage increases the risk of cancer; in particular, alpha radiation is known to 

cause lung cancer in humans when alpha emitters are inhaled. The greatest exposure to 

alpha radiation for average citizens comes from the inhalation of radon and its decay 

products, several of which also emit potent alpha radiation. 

Hydraulic Fracturing Fluids and Flowback Comparison and Pollutant 

Identification 

Three types of liquids used in the horizontal drilling and hydraulic fracturing processes were 

evaluated to determine if drinking water standards were exceeded: Makeup (MU) water consists 

of varying proportions of fresh water and recycled flowback water that is mixed with chemicals 

to make hydraulic fracturing fluids (HFF) which are injected into the formation along with a 

proppant, and flowback (FB) is the fluid which returns via the wellhead to the surface after 

hydraulic fracturing is complete. 

Table 13 compares these fluids with regard to their drinking water exceedances. All flowback 

samples exceeded drinking water standards for barium, chloride, iron, manganese, total dissolved 

solids and radium 226. Eighty-percent of flowback samples exceeded drinking water standards 

for gross alpha, beta and radium 228. The organic parameters benzene, toluene, MBAS and 

styrene exceeded drinking water standards at rates of 77, 23, 15 and 8%, respectively. 

Selenium exceeded the drinking water standard in 23% of flowback samples while chromium 

and lead exceeded their drinking water standards in 8% of the flowback samples. Overall, 

drinking water standards were exceeded for eighteen parameters in the flowback samples.

Six parameters in the hydraulic fracturing fluids exceeded drinking water standards. The 

hydraulic fracturing fluids in this case consisted of diluted flowback which may explain the 

presence of contaminants such as barium, chloride, iron, manganese and benzene albeit in lower 
88 | Page

concentrations than found in flowback. The results suggest that many of the exceedances are the 

result of contaminants acquired while the fluids are in contact with the Marcellus Formation.

Four freshwater (makeup water) samples, two hydraulic fracturing fluids and thirteen flowback 

samples were analyzed. Water quality of water and waste streams deteriorated as gas well 

development stages progressed. The hydraulic fracturing fluid samples included two of makeup 

water only and two of the fully formulated hydraulic fracturing water for injection. One 

hydraulic fracturing fluid sample contained benzene in measurable quantities while ten of 

thirteen flowback samples contained benzene in concentrations in excess of the primary drinking 

water standard of 5 μg/L. 

Both hydraulic fracturing fluids, all of the drilling muds and flowback samples contained 

detectable TPH (diesel range); but, there is no drinking water standard for TPH (diesel range). It 

is important to note, this determination, also known as diesel range organics (DRO) does not 

indicate that diesel is present. Rather, it indicates that hydrocarbons in the range of C11 to C28 

are present. This could include diesel or common hydraulic fracturing fluid additives such as 

guar gum, an extract of the guar bean used to increase the viscosity of the hydraulic fracturing 

fluid to efficiently deliver the proppant into the formation. 

Figure 21 indicates that there is no correlation between benzene and TPH (diesel range). It also 

indicates that for most of the flowback samples, benzene exceeded the primary drinking water 

standard. Only one drilling mud sample and one hydraulic fracturing fluid sample contained 

detectable benzene while all but one hydraulic fracturing fluid/drilling muds sample contained 

detectable TPH (diesel range). This suggests that the source of benzene is likely in the 

formation, rather than the hydraulic fracturing fluid. All flowback samples contained high ionic 
89 | Page

concentrations including sodium, chloride, bromide and barium. Table 9 summarizes the 

average values of the inorganic constituents and Table 10 summarizes the average organic 

concentrations. 

Flowback was tested for radioactivity. The SDWA lists four radioactivity parameters under its 

primary drinking water standards. Our results were compared with the applicable SDWA 

standards. Table 14 indicates that flowback water exceeded the SDWA standard with respect to 

alpha radiation and radium (226 and 228). 

Impoundment Integrity

The impoundments initially contained freshwater which was a mixture of Ohio River water and 

treated mine drainage. Water quality of the freshwater impoundment is indicated in Table 9

under the column labeled “FW impound.” It contained no constituents in excess of SDWA 

limits. There was no evidence of significant leakage of flowback from the impoundments. 

Nitrate and lead were detected in monitoring wells in excess of primary drinking water 

standards. The concentration of nitrite exceeded the MCL (1 mg/L) in three of five shallow 

monitoring wells by a maximum of 0.47 mg/L. However, while nitrate exceeded the primary 

MCL in samples taken after conversion of the impoundments to accept flowback, the single lead 

exceedance occurred prior to conversion as shown in Table 9. As is common in West Virginia 

wells, iron, aluminum and manganese exceed the secondary drinking water standards in both 

shallow and deep wells before and after conversion of the impoundments from holding fresh 

water to flowback (54). After conversion to storage of flowback water, the groundwater 

monitoring wells around the ‘impoundments’ did not, however, indicate elevated chloride, 

bromide or barium concentrations as would be expected if flowback leakage occurred in 

significant quantities. In addition, while flowback contains measurable benzene and TPH 
90 | Page

(diesel), neither was detected in the monitoring wells. See Table 10. One of the deep monitoring 

wells exceeded the primary drinking water level for gross alpha radiation. However, this 

occurred while the impoundment was holding freshwater. See Table 15.

Figure 22 illustrates the relationship between chloride and bromide appears to be a good 

indicator of flowback. All of the flowback samples were aligned along the high end of the 

trendline while hydraulic fracturing fluids (and their makeup water) were aligned along the lower 

end of the same curve indicating lower concentrations of both chloride and bromide. This is a 

log-log graph and zero values cannot be plotted so coordinates with non-detect levels of bromide 

or chloride do not appear. While the chloride and bromide concentrations were high in drilling 

mud, its trendline deviated from the flowback and hydraulic fracturing fluid trendlines mainly 

due to the higher chloride content of drilling mud relative to bromide. This may be due to the 

common use of sodium chloride in drilling mud. In contrast, the water from the freshwater

impoundments and their groundwater monitoring wells contained almost no bromide and little 

chloride. Refer to the lower left hand corner of Figure 22. Samples of Monongahela River 

water from another study are included for comparison. They also appear in the lower left hand 

corner and the trendline is essentially horizontal. These results suggest that the high bromide 

concentrations in flowback water are acquired by salt dissolution within the Marcellus formation. 

The alignment of both hydraulic fracturing fluid and makeup water along the Bromide/Chloride 

(Br/Cl) trendline suggests that the makeup water includes some amount of recycled flowback. 

Three centralized impoundments were sampled before and after they were converted from 

freshwater storage to flowback storage. In addition, their respective monitoring wells were 

sampled before and after the conversion. The barium/chloride (Ba/Cl) ratios were plotted for 

impoundment water and the monitoring wells. Barium was used in this case because it is, like 
91 | Page

bromide, a good marker for flowback water. The Ba/Cl-relationship clearly discriminated 

between flowback and freshwater. Figure 23 shows the clustering of groundwater samples at 

the lower left corner of the figure along with the freshwater impoundment samples (the three 

samples overlay each other). Flowback, on the other hand trends far to the upper right with 

much higher concentrations of both barium and chloride. Note that the highest monitoring well 

values of both barium and chloride occurred when the impoundments were used for freshwater 

storage. Only one of fourteen monitoring well samples exceeded a drinking water standard. 

That sample was for a deep monitoring well during the period when the impoundment was used 

for freshwater storage. The chloride concentration was 348 mg/L while bromide was below 

detect and barium was 0.28 mg/L. The monitoring wells thus showed no evidence of receiving 

leakage from the impoundments. Most significantly, no evidence of flowback leakage was 

detected in the impoundment monitoring. While the monitoring wells detected no contaminants 

it is not clear that the monitoring interval of 146 days was sufficient to capture any leakage from 

the impoundments. A longer sampling is suggested with, perhaps, aquifer permeability testing.
92 | Page

Table 9: Average Concentrations of Inorganic Parameters

• Average concentrations of inorganic parameters tested in Summer and Fall of 2012

• Shaded cells indicate drinking water standard exceeded.

• MDL=minimum detection limit 

• DW=SDWA drinking water standard: a=primary b=secondary FW=freshwater 

• MW=impoundment monitoring well: S=shallow, D=deep, FB=flowback, HF=hydraulic 

fracturing

MDL units DW std MCL

FW 

impound MWS FW MWS FB MWD FW MWD FB

Drilling mud 

(vert sec) HF fluid FB

As 0.007 mg/L a 0.01 0.00 0.00 0.00 0.00 0.00 0.92 0.00 0.00

Ba 0.002 mg/L a 2 0.05 0.08 0.08 0.58 0.26 12.81 5.70 514.68

Cr 0.001 mg/L a 0.1 0.00 0.00 0.00 0.04 0.00 2.60 0.00 0.03

Hg 0.0001 mg/L a 0.002 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Nitrate 0.02 mg/L a 10 0.03 0.37 1.07 0.07 0.13 3.18 0.00 0.02

Nitrite 0.05 mg/L a 1 0.15 0.09 1.10 0.04 0.00 4.90 0.00 0.06

Pb 0.003 mg/L a 0.015 0.00 0.00 0.00 0.02 0.00 1.15 0.00 0.01

Se 0.008 mg/L a 0.05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.06

Ag 0.001 mg/L b 0.1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Al 0.04 mg/L b 0.05 0.0 0.8 2.7 15.0 9.8 1208.0 0.1 1.4

Cl 0.1 mg/L b 250 22.8 2.8 5.9 181.7 5.7 14640.0 4712.3 42683.1

Fe 0.01 mg/L b 0.3 0.0 2.0 3.2 24.8 14.1 2192.0 9.1 67.1

Mn 0.001 mg/L b 0.05 0.0 0.2 0.1 2.2 1.5 22.3 0.6 5.5

pH mg/L b 6.5 7.01 6.66 6.47 6.83 7.20 9.24 7.17 6.61

SO4 1 mg/L b 250 62.2 28.2 28.8 41.6 33.6 1567.7 65.7 38.7

TDS 5 mg/L b 500 241.0 233.6 175.2 408.0 259.0 34550.0 9369.5 74710.8

Zn 0.003 mg/L b 5 0.0 0.0 0.0 0.1 0.1 5.9 0.5 0.1

Br 0.05 mg/L 0.06 0.00 0.00 0.05 0.00 22.50 54.60 465.96

Ca 0.05 mg/L 36.78 59.24 51.82 86.80 101.00 1842.50 528.75 7269.23

K 0.03 mg/L 2.54 1.69 2.25 6.12 6.10 8791.50 29.66 260.06

Mg 0.05 mg/L 6.96 12.68 9.16 18.40 25.80 394.71 68.69 835.00

Na 0.3 mg/L 20.47 4.68 7.08 13.00 10.01 2858.50 2202.50 26202.31

Ni 0.002 mg/L 0.00 0.00 0.00 0.03 0.03 2.19 0.00 0.00

S 0.05 mg/L 23.10 12.91 10.84 14.75 14.55 992.50 19.74 36.16

Sr 0.001 mg/L 0.20 0.23 0.17 0.42 0.44 40.15 62.63 1365.38

alk CO3 1 mg/L 109.78 203.20 103.88 199.00 210.50 1705.00 111.95 187.23

alk HCO3 1 mg/L 0.00 0.00 0.00 0.00 0.00 379.33 0.00 0.00

alk tot 1 mg/L 109.78 203.20 103.88 199.00 210.50 3127.50 111.95 187.23

EC NA μS/cm 428.75 382.60 302.00 762.00 470.00 59550.00 15680.00 107861.54

Hardness 1 mg/L 120.35 200.20 478.00 332.00 358.50 4973.33 1600.00 19588.15

PO4 0.02 mg/L 0.01 0.10 0.00 0.46 0.00 15.53 2.94 8.03

TSS 5 mg/L 2.00 170.20 110.17 2720.00 284.00 47300.00 118.25 211.85
93 | Page

Table 10: Average Concentrations of Organic Parameters

• Average concentrations of organic parameters testing in Summer and Fall of 2012

• Shaded cells indicate drinking water standard exceeded.

• MDL=minimum detection limit 

• DW=SDWA drinking water standard: a=primary b=secondary FW=freshwater 

• MW=impoundment monitoring well: S=shallow, D=deep, FB=flowback, HF=hydraulic 

fracturing

MDL units

DW 

std MCL

FW 

impound MWS FW MWS FB MWD FW MWD FB

Drilling mud 

(vert sec) HF fluid FB

Benzene 0.42 μg/L a 5 0.00 0.00 0.00 0.00 0.00 40.25 7.35 149.59

Ethylbenze 0.43 μg/L a 700 0.00 0.00 0.00 0.00 0.00 9.55 2.18 52.52

Styrene 0.38 μg/L a 100 0.00 0.00 0.00 0.00 0.00 0.00 0.00 10.85

Toluene 0.42 μg/L a 1000 0.00 0.00 0.77 0.30 0.00 80.43 22.08 621.71

Xylene (m,p) 0.9 μg/L a 10000 0.00 0.00 0.00 0.00 0.00 87.50 41.00 698.71

Xylene (o) 0.41 μg/L a 10000 0.00 0.00 0.00 0.00 0.00 22.20 8.75 142.27

MBAS 0.1 mg/L b 0.5 0.08 0.00 0.00 0.00 0.00 67.68 0.00 0.19

COD 4 mg/L 14.25 0.00 0.00 0.00 7.00 5875.00 539.50 1420.08

Ethane NA μl/L 0.00 0.00 0.00 0.00 0.00 0.00 571.19

Methane NA μl/L 0.00 0.00 0.00 0.00 0.00 88.50 3420.48

O&G 2 mg/L 0.00 0.46 1.18 3.80 2.40 53.30 5.95 63.52

propane NA μg/L 0.00 0.00 0.00 0.00 0.00 0.00 0.00 86.92

Tetrachloroethene 0.49 μg/L 0.00 0.00 0.00 0.00 0.00 5.00 0.00 0.00

TOC 0.2 mg/L 2.51 0.58 1.70 0.34 1.22 2362.50 105.36 176.35

TPH (Diesel) 0.067 mg/L 0.00 0.00 0.00 0.00 0.00 130.23 38.71 60.56

TPH (Gas) 0.25 mg/L 0.00 0.00 0.00 0.00 0.00 3.85 1.58 25.75

TPH (Oil) 0.053 mg/L 0.08 0.00 0.00 0.00 0.00 98.45 3.27 10.23
94 | Page

Table 11: Field Radiation Readings for Drill Cuttings and Drilling Muds

Drill cuttings 

(solids)

Drilling Mud 

(liquid)

Mixture (slurry)

Radioactivity 

(mrem/hr)

Background

Radioactivity 

(mrem/hr)

Sample

ST2 at 13:00 

(solids) 0.008 0.009

ST1-1 at 11:00 

(solids) 0.013 0.013

ST1-2 at 10:30 

(solids) 0.011 0.016

ST1-3 at 11:00 

(solid) 0.005 0.009

ST1-4 at 1:30 

(solids) 0.008 0.015

ST1-1 at 11:00 

(liquid) 0.013 0.013

ST1-2 at 10:30 

(liquid) 0.011 0.016

ST1-3 at 11:00 

(liquid) 0.005 0.009

ST1-4 at 1:30 

(liquid) 0.008 0.009

ST2 a6t 13:00 

(slurry) 0.008 0.009

The Inspector EXP displays current radiation levels in millirem per hour (mrem/hr), where rem = roentgen equivalent man (55).

• Radiation readings taken with handheld field alert detector.

• Shaded cells indicate that the samples exceeded background levels.
95 | Page

Table 12: Radioactivity Results of Drilling Muds and Flowback Solids Samples

• Shaded cells indicate SDWA MCL was exceeded.
96 | Page

Table 13: Exceedances of Drinking Water Standards

Horizontal Drilling and Hydraulic 

Fracturing Fluids

• makeup water (MU) 

• hydraulic fracturing fluid 

(HFF) 

• flowback (FB)

Water Quality Parameters

• Inorganic (I) 

• Organic (O) 

• Radioactive (R) 

The latter determinations were only available for 

five flowback samples.
97 | Page

Table 14: Summary of Radioactive Determinations from Flowback Liquids Samples

• Shaded cells indicate SDWA MCL was exceeded.

reported MCL

 FB,FS-1 

(SHL-3)

 FB,FS 2 

(SHL-3)

 FB,FS-3 

(SHL-3)

 FB,FS Final 

(SHL-3)

FB,Comp. 

(SHL-4)

parameter units MCL units 8/13/2012 8/20/2012 8/28/2012 9/17/2012 9/17/2012

Gross Alpha pCi/L 15 pCi/L 8.69 527 372 965 184

Gross Beta pCi/L 4 mr/yr 34 317 138 226 67.8

Lead-210 pCi/L -62.3 NR NR -46.4 -258

Radium-226 pCi/L 5 pCi/L 29.6 1,194 15.4 397 154

Radium-228 pCi/L 5 pCi/L 4.99 216 53.5 132 66.5

Thorium-228 pCi/L 2.35 0.3 0.595 2.24 0.952

Thorium-230 pCi/L 0.411 9.37 0.846 0 0.032

Thorium-232 pCi/L 0.375 -0.008 0 -0.009 0.006

Uranium-238 pCi/L 30 μg/L 1.22 -0.022 0.356 0.097 0.042

Potassium-40 pCi/L 52.8 221 -11.596 6.82 43.2
98 | Page

Table 15: Summary of Radioactive Determinations from Groundwater Monitoring Wells

• Shaded cells indicate SDWA MCL was exceeded.

• Radioactive results from flowback samples are included for comparison purposes.

SDWA MCL SHL-2, MW-2, SHL-2, MW-3, SHL-4, MW-1, SHL-4, MW-2, SHL-4, MW-3, 

Liquids units MCL units 6/4/2012 6/4/2012 6/4/2012 6/4/2012 6/4/2012 average

Gross Alpha pCi/L 15 pCi/L 1.14 -0.253 3.17 0.214 1.08 1.07

Gross Beta pCi/L 50 pCi/L 1.8 0.715 3.32 0.649 1.82 1.66

Lead-210 pCi/L 216 -54.4 334 512 746 351

Radium-226 pCi/L 5 pCi/L 0.646 0.0553 0.229 0.167 0.411 0.30

Radium-228 pCi/L 5 pCi/L 0.637 0.407 0.835 0.283 0.748 0.58

Thorium-228 pCi/L 0.142 0.008 0.538 0.223 -0.023 0.18

Thorium-230 pCi/L -0.029 -0.003 0.29 0.01 0.008 0.06

Thorium-232 pCi/L 0.17 0.006 0.506 0.069 -0.01 0.15

Uranium-238 pCi/L 30 μg/L 0.456 0.19 0.53 0.441 0.531 0.43

Uranium-238 μg/L 30 μg/L 0.68 0.28 0.79 0.66 0.79 0.64

Potassium-40 pCi/L -1.36 -6.23 -32.5 -25.2 -30.8 -19.22

SDWA MCL SHL-2-MW-4, SHL-3-MW-4, 

Liquids units MCL units 6/19/2012 6/19/2012 average

Gross Alpha pCi/L 15 pCi/L 37.8 11.6 24.7

Gross Beta pCi/L 50 pCi/L 18.6 6.73 12.665

Lead-210 pCi/L -1,170 -1,050 -1,110

Radium-226 pCi/L 5 pCi/L 2.82 4.74 3.78

Radium-228 pCi/L 5 pCi/L 0.466 0.679 0.5725

Thorium-228 pCi/L 0.485 1.02 0.7525

Thorium-230 pCi/L 0.029 0.133 0.081

Thorium-232 pCi/L 0.226 0.521 0.3735

Uranium-238 pCi/L 30 μg/L 0.197 0.659 0.428

Uranium-238 μg/L 30 μg/L 0.29 0.98 0.64

Potassium-40 pCi/L 13.2 105 59.1

SDWA MCL

 FS 2, Noble Pits 

(SHL-3)

 FS-3, Noble Pits 

(SHL-3)

 FS Final, Noble 

Pits (SHL-3)

 SHL-4 

Composite, 

Noble Pits (SHLFS-1, Weekly Pad

Liquids units MCL units 8/20/2012 8/28/2012 9/17/2012 9/17/2012 8/15/2012 average

Gross Alpha pCi/L 15 pCi/L 8.69 527 372 965 184 411.338

Gross Beta pCi/L 50 pCi/L 34 317 138 226 67.8 156.56

Lead-210 pCi/L -62.3 NR NR -46.4 -258 -122.233333

Radium-226 pCi/L 5 pCi/L 29.6 1,194 15.4 397 154 358

Radium-228 pCi/L 5 pCi/L 4.99 216 53.5 132 66.5 94.598

Thorium-228 pCi/L 2.35 0.3 0.595 2.24 0.952 1.2874

Thorium-230 pCi/L 0.411 9.37 0.846 0 0.032 2.1318

Thorium-232 pCi/L 0.375 -0.008 0 -0.009 0.006 0.0728

Uranium-238 pCi/L 30 μg/L 1.22 -0.022 0.356 0.097 0.042 0.3386

Uranium-238 μg/L 30 μg/L 1.82 -0.03 0.53 0.14 0.06 0.51

Potassium-40 pCi/L 52.8 221 -11.596 6.82 43.2 62.4448

MW (shallow)

flowback

MW (deep)
99 | Page

Figure 21: Relationship between TPH and Benzene

• The relationship between TPH (diesel range) and benzene is plotted for all samples. 

• Note this is a log-log plot and zero (non-detect) values are not plotted. 

• The red, horizontal line is the primary drinking water limit for benzene.
100 | Page

Figure 22: Relationship of Chloride and Bromide in Source Waters

• All samples were plotted on chloride/bromide axes to determine the orientation of the 

various source waters. 

• Note this is a log-log plot and zero (non-detect) values are not plotted. 

• Trendlines are included along with their models and correlation coefficients.
101 | Page

Figure 23: Barium/Chloride (Ba/Cl) Relationship in Impoundment Water and 

Groundwater

• Groundwater was monitored at three centralized impoundments at the Noble Site. All 

were converted from freshwater (FW) to flowback (FB) storage during the study.

 

• The figure shows the Ba/Cl ratios of the impoundment waters, the monitoring well 

shallow (MWS) and monitoring well deep (MWD) monitoring wells before and after the 

conversion. 

• The blue, horizontal line is the primary drinking water limit for barium and the red, 

vertical line is the secondary drinking water limit for chloride.
102 | Page

Identification of Potential Health Concerns and Recommendations

Three types of water and one solid waste were studied:

• Flowback water

• Drilling muds

• Hydraulic fracturing fluids

• Drill cuttings

Flowback, drilling muds and hydraulic fracturing fluids all exceeded SDWA limits to varying 

degrees. The extent to which they are properly and safely handled will determine the degree of 

human exposure via drinking water. An attempt to prioritize the potential for human exposure 

via groundwater contamination is reflected in Table 16. Transported volume and liquid/solid 

rankings are binomial. It is assumed that exposure increases with volume, particularly to the 

extent that the material is transported off-site. Liquid contaminants are simply more mobile than

any of the solid materials in this study and therefore pose a greater exposure risk. 

Table 16: Groundwater Exposure to Shale Gas Waste Streams

Some materials could not be sampled and are marked ND for not determined. Table 16 is not 

complete as not all of the materials could be sampled within the timeframe of project. With that 

qualification, flowback yields the highest exposure since: it is a liquid; it is transported off site; it
103 | Page

has multiple toxicities and it is produced in high volume. Hydraulic fracturing fluid is not as 

toxic as flowback and it is usually prepared on-site, minimizing transportation risk. It may be 

spilled on the drill pad through accident or during a blowout. Proper lining and containment onsite, however, would minimize exposure to groundwater. Both flowback and hydraulic 

fracturing fluid may escape the wellbore if it is not installed and cemented. The risk of migration 

of these fluids from the target formation to drinking water, considering the distance is remote but 

not absent. Care must be taken to avoid faults and old gas wells that may conduct these fluids to 

potable aquifers.

Drilling mud exceeded the primary and secondary SDWA standards more than the previous two 

materials but its volume is much lower than flowback or hydraulic fracturing fluid. While drill 

cuttings will contain contaminants, the volume is generally such that they are easily isolated onsite and taken to landfills for disposal. Therefore, their exposure risk is low if properly handled. 

For example, storage of flowback in large impoundments resulted in no evidence of leakage. 

This is of particular interest since the impoundment geotechnical study which is part of this 

effort identified several design and construction flaws in impoundment construction. That no 

flowback leakage was detected suggests that the designs are robust. 

This project has significantly improved knowledge of the human health risks associated with 

shale gas development. As a result, diagnostic tools such as the Br/Cl and Ba/Cl ratios for 

identifying flowback contamination have been developed. Flowback was identified as the 

primary waste stream of concern. Practices that prevent environmental and human health 

exposures are critical. The following are recommended:

• Ensure the integrity of the handling chain for each of the waste streams, identify the weak 

points and focus the inspectors’ attention to those areas.

• Ensure the integrity of wellbores and cement.
104 | Page

Future research should focus on filling out the remainder of Table 16. In addition, while the 

scope of this project is limited to the well development and completion stages of shale gas 

extraction, future work regarding chemical exposures at the producing well sites is needed to 

supplement this work.
105 | Page

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4. Development of the Marcellus Shale – Water Resource Challenges; R. Timothy Weston 

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5. Hydraulic Fracturing Considerations for Natural Gas Wells of the Marcellus Shale; 

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Questions, Attachment to memorandum from James Hanlon Director of EPA’s Office of 

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8. The Real Facts about Fracture Stimulation: The Technology Behind America’s New 

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9. Marcellus Shale Water Management Challenges in Pennsylvania; A.W. Gaudlip and L.O. 

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Institute, Society of Petroleum Engineers; SPE 119898; 2008 SPE Shale Gas Production 

Conference; November 2008.

10. Water Resources and Use for Hydraulic Fracturing in the Marcellus Shale Region; J. 

Daniel Arthur, Mike Uretsky and Preston Wilson, ALL Consulting; 2010.
106 | Page

11. Natural Gas Plays in the Marcellus Shale: Challenges and Potential Opportunities; David 

Kargbo, Ron Wilhelm and David Campbell; USEPA; Environmental Science & 

Technology; Volume 44; Number 2010.

12. Treatment of Abandoned Mine Drainage for Use as Marcellus Gas Well Hydrofracture 

Makeup Water; ProChem Tech, International, Inc.; www.prochemtech.com; 2009.

13. Sampling and Analysis of Water Streams Associated with the Development of Marcellus 

Shale Gas Final Report; Thomas Hayes, Gas Technology Institute; for Marcellus Shale 

Coalition; December 2009.

14. Radioactivity in Marcellus Shale Report prepared for Residents for the Preservation of 

Lowman and Chemung (RFPLC); Marvin Resnikoff, Ekaterina Alexandrova and Jackie 

Travers, Radioactive Waste Management Associates; May 2010.

15. Waste Management of Cuttings, Drilling Fluids, Hydrofrack Water and Produced Water; 

New York State Water Resources Institute; 

www.wri.eas.cornell.edu/gas_wells_waste.html.

16. America’s New Energy Future: The Unconventional Oil and Gas Revolution and the U.S. 

Economy Volume 1: National Economic Contributions; An IHS Report; October 2012.

17. Water Management Technologies Used by Marcellus Shale Gas Producers Final Report; 

John Veil, Argonne National Laboratory; Department of Energy Office of Fossil Energy 

FWP-49462; July 2010.

18. Data Confirm Safety of Well Fracturing; Kevin Fisher, The American Oil & Gas 

Reporter, www.aogr,com; July 2010.

19. Chemicals Used in Hydraulic Fracturing; for U.S. House of Representatives Committee 

on Energy & Commerce Minority Staff; April 2011.

20. ‘Environmentally Friendly’ No Longer an Oxymoron to Oil and Gas; Tayvis Dunnahoe, 

Hydraulic Fracturing; www.EPmag.com; August 2012.

21. Marcellus Shale in West Virginia: Hydraulic Fracturing Chart; WVONGA 2012.

22. A Fluid Situation: Typical Solution Used in Hydraulic Fracturing; 

www.energyindepth.org.
107 | Page

23. Hydraulic Fracturing Fluids – Composition and Additives; www.geology.com; 

republished from: Modern Shale Gas Development in the United States by the 

Department of Energy; 2009.

24. Critical Evaluations of Additives Used in Shale Slickwater Fracs; P. Kaufman and G.S. 

Penny, CESI Chemical a Flotek Co., and J. Paktinat, Universal Well Services; Inc. SPE 

119900; 2008 SPE Shale Gas Production Conference; November 2008.

25. Radiological Survey Report: Marcellus Shale Drilling Cuttings; CoPhysics Corporation; 

April 2010.

26. Marcellus Shale Potential Public Health Concerns Correspondence and Supplemental 

Reports: Supplemental Generic Environmental Impact Statement on the Oil & Gas 

Regulatory Program – Well Permit Issuance for Horizontal Drilling and High-Volume 

Hydraulic Fracturing to Develop the Marcellus Shale and other Low-Permeability Gas 

Reservoirs; State of New York Department of Health; July 2009.

27. Incidental TENORM: A Guidance for State Solid Waste Managers; Association of State 

and Territorial Solid Waste Management Officials; April 2011.

28. Radiation Sources in Natural Gas Well Activities; Gayle Nicoll, Occupational Health & 

Safety Online; http://ohsonline.com/articles/. 

29. Evaluating the Environmental Implications of Hydraulic Fracturing in Shale Gas 

Reservoirs; J. Daniel Arthur, Brian Bohm, Bobbi Jo Coughlin and Mark Layne, ALL 

Consulting; 2008.

30. NORM Survey Summary; IOGA News; April 1995.

31. Regulatory Issues in the US, Nancy Sauer; Hydraulic Fracturing; www.EPmag.com; 

August 2012.

32. Methane Contamination of Drinking Water Accompanying Gas-Well Drilling and 

Hydraulic Fracturing; Stephen Osborn, Avner Vengosh, Nathaniel Warner and Robert 

Jackson, Duke University, Durham, North Carolina; 

www.pnas.org/cgi/doi/10.1073/pnas.1100682108; PNAS Early Edition 2011.

33. Hydraulic Fracturing and Safe Drinking Water Act Issues; Mary Tiemann and Adam 

Vann, Congressional Research Service;7-5700; www.crs.gov; R41760; July 2012.
108 | Page

34. The Impact of Marcellus Gas Drilling on Rural Drinking Water Supplies; Elizabeth 

Boyer, Bryan Swistock, James Clark, Mark Madden and Dana Rizzo, Pennsylvania State 

University; for The Center for Rural Pennsylvania; March 2012.

35. Hydraulic Fracturing & Water Resources: Separating the Frack from the Fiction; Heather 

Cooley and Kristina Donnelly, Pacific Institute; June 2012.

36. Hydraulic Fracturing or ‘Fracking’: A Short Summary of Current Knowledge and 

Potential Environmental Impacts; Dave Healy, University of Aberdeen; Aberdeen, 

United Kingdom; May 2012.

37. OIL AND GAS: Information on Shale Resources, Development and Environmental and 

Public Health Risks; United States Government Accounting Office Report to 

Congressional Requestors; September 2012.

38. Addressing the Environmental Risks from Shale Gas Development – Briefing Paper 1; 

Mark Zoback, Stanford University, Saya Kitasei, WorldWatch Institute, and Brad 

Copithorne, Environmental Defense Fund; WorldWatch Institute Natural Gas and 

Sustainable Energy Institute; July 2010.

39. In Fracking’s Wake: New Rules are needed to Protect Our Health and Environment from 

Contaminated Wastewater; Rebecca Hammer, Natural Resource Defense Council, Jeanne 

VanBriesen, Carnegie Mellon University and Larry Levine, Natural Resource Defense 

Council; NRDC Issue Brief, 1B:12-05-A, May 2012.

40. Land Application of Hydrofracturing Fluids Damages a Deciduous Forest Stand in West 

Virginia; Mary Beth Adams, USDA Forest Service; Journal of Environmental Quality, 

Volume 40, July/August 2011.

41. Water Management Essential in Hydraulic Fracturing; Jerry Greenberg; Hydraulic 

Fracturing, www.EPmag.com; August 2012.

42. How to Remove Radioactive Iodine-131 From Drinking Water; Jeff McMahon, Forbes; 

www.forbes.com; April 2011.

43. Local Limits Development Guidance Appendices; USEPA; EPA 833-R-04-002B; July 

2004.
109 | Page

44. Pa.: Marcellus wastewater shouldn’t go to treatment plants; Don Hopey and Sean Hamill, 

Pittsburgh Post-Gazette; http://www.post-gazette.com/sotires/local/breaking/; March 

2012.

45. Disposal of Produced Water from Oil & Gas Exploration: Environmental Impacts on 

Waterways in Western Pennsylvania, Thesis; Cidney Christie, Nicholas School of the 

Environment, Duke University; Durham, North Carolina; April 2012.

46. Service Companies Ease Operator Efforts; MJ Selle; Hydraulic Fracturing; 

www.EPmag.com; August 2012.

47. Tech Brief: Oil & Gas Extraction & Source Water Protection; Zane Satterfield, National 

Environmental Services Center; DWFSOM154DL; Volume 11, Issue 2, Fall/Winter 

2011. 

48. Hydraulic Fracturing: New ASTM International Subcommittee to Develop Needed 

Standards; http://www.astm.org/; Standardization News, November/December 2012.

49. Naturally-Occurring Radioactive Materials (NORM); www.world-nuclear.org, August 

2011.

50. Groundwater Quality in West Virginia, 1993 – 2008; Douglas Chambers, Mark Kozar, 

Jeremy White and Katherine Paybins, USGS West Virginia Water Science Center; 

Scientific Investigations Report, 2012–5186, 60p; 2012.

51. 1996 Low-Flow (Minimal Drawdown) Ground-Water Sampling Procedures; Robert W. 

Puls and Michael J. Barcelona; Environmental Protection Agency; April 1996.

52. Comprehensive Quality Assurance Plan: Revision 28; Effective Date: July 25, 2011; REI 

Consultants, Inc. 2011.

53. Quality Assurance Manual: Revision 15.1; Effective Date: May 5, 2012; Pace Analytical 

Services, Inc. 2012.

54. Ground-water quality in unmined areas and near reclaimed surface coal mines in the 

northern and central Appalachian coal regions, Pennsylvania and West Virginia; 

McAuley, S.D. and Kozar, M.D.; U.S. Geological Survey Scientific Investigations Report 

2006-5059, 57p; 2006.

55. Radiation Alert Quality Handheld Detectors, Inspector+ and Inspector EXP+ User 

Manual, August 29, 2006.
110 | Page

Appendix A: WVWRI Project Staff

Name Role Email Office Telephone Address

Paul Ziemkiewicz, PhD Principal Investigator paul.ziemkiewicz@mail.wvu.edu 304-293-6958

WV Water Research Institute 

West Virginia University 

PO Box 6064 

Morgantown, WV 26506-6064

Jennifer Hause Project Manager jhause@wvu.edu 304-293-7003

WV Water Research Institute 

West Virginia University 

PO Box 6064 

Morgantown, WV 26506-6064

Brady Gutta

Program 

Coordinator/Geologist brady.gutta@mail.wvu.edu 304-293-7002

WV Water Research Institute 

West Virginia University 

PO Box 6064 

Morgantown, WV 26506-6064

Benjamin Mack Research Associate ben.mack@mail.wvu.edu 304-293-7009

WV Water Research Institute 

West Virginia University 

PO Box 6064 

Morgantown, WV 26506-6064

Jason Fillhart Environmental Scientist jefillhart@mail.wvu.edu 304-293-7074

WV Water Research Institute 

West Virginia University 

PO Box 6064 

Morgantown, WV 26506-6064

Melissa O'Neal

Environmental 

Technician/Laboratory 

Manager melissa.o'neal@mail.wvu.edu 304-293-7006

WV Water Research Institute 

West Virginia University 

PO Box 6064 

Morgantown, WV 26506-6064

Doug Patchen, PG Geologist doug.patchen@mail.wvu.edu 304-293-6216

WV Water Research Institute 

West Virginia University 

PO Box 6064 

Morgantown, WV 26506-6064
111 | Page

Appendix B: REI Consultants Chain-of-Custody Form
112 | Page

Appendix C: Pace Analytical Chain of Custody Form
113 | Page

Appendix D: Individual Site Checklists
114 | Page

Site Checklist – Chesapeake DNR A Pad

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study Chesapeake DNR Pad (A) 

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Chesapeake 

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluids

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted from Chesapeake for 

sampling muds and cuttings from the 

shaker table during the vertical portion 

of the drilling process

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Vertical Drilling – 10/25/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site (if relevant)

Not Applicable

Hydraulic Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids (if relevant)

Not Applicable

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

40° 19’ 16.1”N 

80° 32’ 12.2”W

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

• pH = 9.38

• EC = 4 μS/cm

• Temperature = 33.06°

• TDS = 2 mg/L, oil-like 

substance causing interference

with reading

• DO = 9.39 mg/L

• Salinity = 0.0 ppt

Refer to Appendix E also

Duplicate Samples Identify duplicate sampling events Full Duplicate on 10/25/2012

Site Observations Document visual observations of site Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Photographic 

Documentation

Obtain permission prior to and take photos

of site, sample collection, and catalog and 

document photos

No Photos Taken (Operator 

Preference)

Permitting Provide copies of permit for each site to 

WRI

Not Available
115 | Page

Description Task Completed/Notes

Drilling Logs Obtain and provide copies of drilling logs 

to WRI

Received November 2012

Health and 

Safety/Emergency 

Response

Obtain copies of company specific

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

Received November 2012

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location 

Received November 2012

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental

surroundings to be noted

• 11:00 am, 10/25/2012, JF/BM

• Samples taken from shaker 

table

• Drilling depth approximately 

5,300 feet

• 73°F, sunny with some cloud 

cover

• For PID and RAD readings, 

refer to Appendix E

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis section of 

the report
116 | Page

Site Checklist – Lemons Pad

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study Lemons Pad

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Stone Energy

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluids

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted from Stone Energy for 

sampling muds and cuttings from the 

shaker table during the vertical portion 

of the drilling process

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Vertical drilling – 8/8, 8/15, 8/22, and 

10/2/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site

Not Applicable

Hydro Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids

Not Applicable

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

39°39’03.3’’N 

80°47’39.6’’W

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

Refer to Appendix E for all field 

measurements during each individual 

sampling event at this site

Duplicate Samples Identify duplicate sampling events Collected one complete duplicate set 

of both solids and liquids on 10/2/2012

Site Observations Document visual observations of site Refer to the Water and Waste Stream 

Monitoring Plan section of the report 

Photographic 

Documentation

Obtain permission prior to and take photos 

of site, sample collection, and catalog and 

document photos

Completed, included as part of the 

Water and Waste Stream Monitoring 

Plan section of the report 

Permitting and 

Drilling

Provide copies of permit and drilling logs 

for each site to WRI

Partial data received November 2012
117 | Page

Description Task Completed/Notes

Health and 

Safety/Emergency 

Response

Obtain copies of company specific 

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

No

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location 

Partial data received November 2012

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental

surroundings needing to be noted

Refer to Appendix E for all sampling 

specifics during each individual 

sampling event at this site

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis section of 

the report
118 | Page

Site Checklist – Maury Pad

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study Maury Pad

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Stone Energy

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluids

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted from Stone Energy for 

sampling makeup water and 

hydraulic fracturing fluid during the 

hydraulic fracturing process, as well 

as flowback water during the 

flowback stage

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Hydraulic Fracturing – 9/11/2012

Flowback – 10/2/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site

Mixture of recycled water and 

freshwater from local source 

(11%:89%)

Hydro Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids

Received February 2013

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

39°36’58.6’’N 

80°47’00.7’’W

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

Refer to Appendix E for all field 

measurements during each individual 

sampling event at this site

Duplicate Samples Identify duplicate sampling events None

Site Observations Document visual observations of site Refer to the Water and Waste Stream 

Monitoring Plan section of the report 

Photographic 

Documentation

Obtain permission prior to and take photos 

of site, sample collection, and catalog and 

document photos

Completed, included as part of the 

Water and Waste Stream Monitoring 

Plan section of the report

Permitting Provide copies of permit for each site to 

WRI

No

Drilling Logs Obtain and provide copies of drilling logs 

to WRI

Not Applicable
119 | Page

Description Task Completed/Notes

Health and 

Safety/Emergency 

Response

Obtain copies of company specific 

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

No

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location

No

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental

surroundings needing to be noted

Refer to Appendix E for all sampling 

specifics during each individual 

sampling event at this site

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis section of 

the report
120 | Page

Site Checklist – Mills Wetzel Pad #2

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study Mills Wetzel Pad #2 

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Stone Energy

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluids

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted from Stone Energy for 

sampling muds and cuttings from the 

shaker table during the vertical portion of 

the drilling process

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Vertical Drilling – 8/8/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site

Not Applicable

Hydro Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids

Not Applicable

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

39°”N 80°”W

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

• pH = 9.06

• EC = 173,962 μS/cm

• Temperature = 34.22 °C

• TDS = 96,160 mg/L

• DO = 0.17 mg/L

• Salinity = 117.14 ppt

Refer to Appendix E also

Duplicate Samples Identify duplicate sampling events None

Site Observations Document visual observations of site Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Photographic 

Documentation

Obtain permission prior to and take photos 

of site, sample collection, and catalog and 

document photos

Completed, included as part of the Water 

and Waste Stream Monitoring Plan 

section of the report
121 | Page

Description Task Completed/Notes

Permitting Provide copies of permit for each site to 

WRI

No

Drilling Logs Obtain and provide copies of drilling logs 

to WRI

Yes, partial information received on-site

Health and 

Safety/Emergency 

Response

Obtain copies of company specific 

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

No

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location

No

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental 

surroundings needing to be noted

• 1:00 pm, 8/8/2012, JF/BM

• Samples taken from shaker table

• Drilling depth approximately 

5,226 feet, not yet horizontal

• 92 °F, sunny with few clouds

• For PID and RAD readings, refer 

to Appendix E

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis section of the 

report
122 | Page

Site Checklist – Mills Wetzel Pad #3

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study Mills Wetzel Pad #3 Single-Lined 

Impoundment

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Stone Energy

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluids

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted for sampling the 

impoundment near the Mills Wetzel 

#3 Pad

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Impoundment – 8/28/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site

Not Applicable

Hydro Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids

Not Applicable

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

39°31’57.69”N 

80°40’21.88”W

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

• pH = 8.09

• EC = 231 μS/cm

• Temperature = 30.46 °C

• TDS = 150 mg/L

• DO = 7.68 mg/L

• Salinity = 0.11 ppt

Refer to Appendix E also

Duplicate Samples Identify duplicate sampling events None

Site Observations Document visual observations of site Refer to the Water and Waste Stream 

Monitoring Plan section of the report 

Photographic 

Documentation

Obtain permission prior to and take photos 

of site, sample collection, and catalog and 

document photos

Completed, included as part of the 

Water and Waste Stream Monitoring 

Plan section of the report

Permitting Provide copies of permit for each site to 

WRI

No
123 | Page

Description Task Completed/Notes

Drilling Logs Obtain and provide copies of drilling logs 

to WRI

Not Applicable

Health and 

Safety/Emergency 

Response

Obtain copies of company specific

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

No

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location

No

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental

surroundings needing to be noted

• 4:30 pm, 8/28/2012, JF/BM

• Samples taken from MW3 

impoundment

• 84 °F, mostly sunny

• For PID and RAD readings, 

refer to Appendix E

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis section of 

the report 
124 | Page

Site Checklist – Sand Hill Location 

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study SHL-1, 2, 3, and 4, Consol/Noble Sand 

Hill location

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Noble Energy and 

Subcontractor-Moody & Associates

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluid

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted for sampling 

centralized impoundments/pits, 

flowback, and groundwater (via 

groundwater monitor wells)

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Impoundments-6/7/2012

Groundwater – (6/4, 6/7 and 6/19/2012 –

Initial), (10/31 and 11/1/2012 – Final)

Flowback-8/13, 8/20, 8/28 and 9/17/2012

Pits-9/17/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site

Ohio River, Wheeling Creek, and 

return water from previous operations

Hydro Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids

Not Applicable

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

SHL2

-MW-1 39°58’03.79” 80°33’42.87”

-MW-2 39°58’00.85” 80 33’40.94”

-MW-3 39°57’58.49” 80 33’43.26”

-MW-4 39°57’59.14” 80°33’45.22”

-Pit Center 39°58’00.78” 80 33’42.31”

SHL3

-MW-4 39°58’20.57” 80°33’16.32”

-Pit Center 39°58’26.80” 80°33’18.49”

SHL4

-MW-1 39°57’48.81” 80°33’46.15”

-MW-2 39°57’44.06” 80°33’48.76”

-MW-3 39°57’45.05” 80°33’45.58”

-Pit Center 39°57’46.09” 80°33’46.80”

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

Refer to Appendix E for all field 

measurements during each individual 

sampling event at this site

Duplicate Samples Identify duplicate sampling events SHL-4-MW-3, Collected a complete 

set of duplicates during groundwater 

sampling on 10/31/12
125 | Page

Description Task Completed/Notes

Site Observations Document visual observations of site Refer to Water and Waste Stream 

Monitoring Plan section of the report

Photographic 

Documentation

Obtain permission prior to and take photos 

of site, sample collection, and catalog and 

document photos

Completed, included as part of the 

Water and Waste Stream Monitoring 

Plan section of the report

Permitting Provide copies of permit for each site to 

WRI

Yes, Received from Consol and WVU 

CEE

Drilling Logs Obtain and provide copies of drilling logs 

to WRI

Not Applicable

Health and 

Safety/Emergency 

Response

Obtain copies of company specific 

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

Yes, Received from Consol

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location 

Yes, Received from Consol

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental

surroundings needing to be noted

Refer to Appendix E for all sampling 

specifics during each individual 

sampling event at this site

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis section of 

the report
126 | Page

Site Checklist – Weekley Pad

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study Weekley Pad

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Stone Energy

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluids

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted from Stone Energy for 

sampling flowback water during the 

flowback stage

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Flowback – 8/15/12 and 8/20/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site

Unknown

Hydro Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids

Yes, Received February 2013

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

39°36’58.6’’N 

80°47’00.7’’W

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

Refer to Appendix E for all field 

measurements during each individual 

sampling event at this site

Duplicate Samples Identify duplicate sampling events None

Site Observations Document visual observations of site Refer to the Water and Waste Stream 

Monitoring Plan section of the report 

Photographic 

Documentation

Obtain permission prior to and take photos 

of site, sample collection, and catalog and 

document photos

Completed, included as part of the 

Water and Waste Stream Monitoring 

Plan section of the report

Permitting Provide copies of permit for each site to 

WRI

No
127 | Page

Description Task Completed/Notes

Drilling Logs Obtain and provide copies of drilling logs 

to WRI

Not Applicable

Health and 

Safety/Emergency 

Response

Obtain copies of company specific 

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

No

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location

No

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental 

surroundings needing to be noted

Refer to Appendix E for all sampling 

specifics during each individual 

sampling event at this site

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste Stream 

Monitoring Plan section of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis section of 

the report
128 | Page

Site Checklist – Waco/Donna Pad

Description Task Completed/Notes

Site Identification Identify site for ETD-10 study Waco Donna Pad

Industry Contact Initial contact w/ companies to establish site 

access

Main contact-Waco Oil and 

Gas

Access to Site Confirm access to water & waste streams 

based on well stage development:

• Impoundment-freshwater

• Groundwater

• Drilling fluids

• Muds & cuttings

• Hydraulic fracturing fluids

• Hydraulic fracturing water

• Flowback/Produced water

• Pits-flowback storage

Access granted for sampling 

flowback water storage from 

the single-lined pit, hydraulic 

fracturing fluids, and 

flowback water from the 

flowback stage

Contact and 

Scheduling

Contact companies/site supervisor establish 

sampling date(s) and meeting locations

Pit-7/25/12 and 8/30/2012

(Pit was makeup water for 

hydraulic fracturing process)

Flowback-7/27, 8/2, 8/9 and

8/30/2012

Hydraulic Fracturing7/25/2012

Source Water Identify and obtain information on source 

water for hydraulic fracturing operations for 

each site

Nearby pond (surface water 

source)

Hydro Fracturing 

Fluids

Obtain list/breakdown of hydraulic 

fracturing fluids

Yes, Received November 2012

Locations Obtain & confirm GPS coordinates for:

• Well pad location

• Sampling points (if off pad)

• Water withdrawals (if relevant)

• Permitted discharges (if relevant)

• Pits

• Impoundments

• GW monitoring wells

Pit- 39° 34’ 29.30’’ N

 80° 17’ 31.40 W

Pad- 39° 34’ 27.19’’ N

 80° 17’ 39.89’’ W

Field Measurements Measurement of field parameters:

• pH

• Electric conductivity (EC)

• Temperature, °C

• TDS

• DO

• Salinity

Refer to Appendix E for all 

field measurements during each 

individual sampling event at 

this site

Duplicate Samples Identify duplicate sampling events None

Site Observations Document visual observations of site Refer to the Water and Waste 

Stream Monitoring Plan section 

of the report
129 | Page

Description Task Completed/Notes

Photographic 

Documentation

Obtain permission prior to and take photos 

of site, sample collection, and catalog and 

document photos

Completed, included as part of 

the Water and Waste Stream 

Monitoring Plan section of the 

report

Permitting Provide copies of permit for each site to 

WRI

Yes, Received November 2012

Drilling Logs Obtain and provide copies of drilling logs 

to WRI

Yes, Received November 2012

Health and 

Safety/Emergency 

Response

Obtain copies of company specific 

Environmental Health & Safety Plans and 

Emergency Response Plans for 

recordkeeping purposes only

No

Site Mapping Obtain and provide copies of 

maps/diagrams of pad layout & location to 

WRI

Yes, Received November 2012

Sampling Specifics Describe pad activities at time of sampling

Collect samples, noting:

• Time, date, sampler(s)

• Sampling point

• PID measurements

• RAD sweep readings

• Weather conditions

• Other field/environmental

surroundings needing to be noted

Refer to Appendix E for all 

sampling specifics during each 

individual sampling event at 

this site

Preparation of 

Samples

Sample preparation:

• Equipment

• Labeling

• Storage

• Transport

• COC forms 

• Sample pick-up/delivery to 

certified lab

Refer to the Water and Waste 

Stream Monitoring Plan section 

of the report

Sample Verification • Receive results verifying all 

parameters analyzed

Yes

Data Entry Enter data into master spreadsheets Entered, MO/JF

Results Note daily maximum values, average 

results, values exceeding MCLs if 

applicable

Refer to the Data Analysis 

section of the report
130 | Page

Appendix E: Field Spreadsheets
131 | Page

units °C μS/cm (mg/L) pH (mg/L) ppt

Stage Target Sample Identification and Location Date Temp. EC TDS pH DO Salinity

SHL-3-IMP, Noble Pits 6/7/2012 20.72 364 258 8.75 7.51 NS

SHL-2-IMP, Noble Pits 6/7/2012 NS NS NS NS NS NS

SHL-1-IMP, Noble Pits 6/7/2012 22.76 387 263 8.61 9.28 NS

Mills Wetzel #3 IMP 8/28/2012 30.46 231 150 8.09 7.68 0.11

SHL-2, MW-2, Noble Pits 6/4/2012 12.48 286 244 7.08 3.24 NS

SHL-2, MW-3, Noble Pits 6/4/2012 13.53 274 228 7.27 5.63 NS

SHL-4, MW-1, Noble Pits 6/4/2012 13.51 297 248 7.3 6.84 NS

SHL-4, MW-2, Noble Pits 6/4/2012 12.28 281 241 7.73 8.74 NS

SHL-4, MW-3, Noble Pits 6/4/2012 12.28 277 238 7.52 4.61 NS

SHL-2 MW-1, Noble Pits 11/1/2012 11.84 909 590 7.75 4.89 0.45

SHL-2, MW-2, Noble Pits 10/31/2012 11 175 113 6.42 13.12 0.08

SHL-2, MW-3, Noble Pits 10/31/2012 11.05 386 251 7.44 7.35 0.19

SHL-4, MW-1, Noble Pits 10/31/2012 12.2 308 200 6.75 4.35 0.15

SHL-4, MW-2, Noble Pits 10/31/2012 10.64 467 304 7.05 8.73 0.23

SHL-4, MW-3, Noble Pits 10/31/2012 12.31 184 119 6.32 11.89 0.09

SHL-2 MW-4, Noble Pits 6/19/2012 14.82 338 273 7.29 6.36 NS

SHL-3 MW-4, Noble Pits 6/19/2012 21.48 492 342 7.51 6.31 NS

SHL-2 MW-4, Noble Pits 11/1/2012 11.28 427 277 7.3 7.39 0.21

SHL-3 MW-4, Noble Pits 11/1/2012 11.25 470 306 7.32 6.19 0.23

HF Water HF Water, Donna Pad 7/25/2012 26.14 7242 4611 7.96 5.88 NS

Frac Fluid Comb. HF, Donna Pad 7/25/2012 28.99 24192 14602 7.02 7.49 NS

HF Water HF Water, Maury Pad 9/11/2012 13.26 965 627 6.78 4.85 0.48

Frac Fluid Comb. HF, Maury Pad 9/11/2012 23.29 20,597 13,390 6.63 5.78 12.32

ST 2 at 13:00 (slurry) Mills Wetzel #2 8/8/2012 34.22 173962 96160 9.06 0.17 117.14

ST 2 at 13:00 (solids) Mills Wetzel #2 8/8/2012

ST 1-1 at 11:00 (liquid) Lemons Pad 8/8/2012 29.06 110145 66420 10.01 4.11 74.48

ST 1-1 at 11:00 (solids) Lemons Pad 8/8/2012

ST 1-2 at 10:30 (liquid) Lemons Pad 8/15/2012 29.61 42203 27450 7.35 4.63 27.02

ST 1-2 at 10:30 (solids) Lemons Pad 8/15/2012

ST 1-3 at 11:00 (liquid) Lemons Pad 8/22/2012 29.77 14963 9731 8.82 4.19 8.66

ST 1-3 at 11:00 (solid) Lemons Pad 8/22/2012

ST 1-4 at 1:30 (liquid) Lemons Pad 10/2/2012 24.66 10457 6799 12.71 7.31 5.91

ST 1-4 at 1:30 (solid) Lemons Pad 10/2/2012

DNR ST 3-1-L (sludge) DNRA Pad 10/25/2012 33.06 4 2 9.38 9.39 0

DNR ST 3-1-L (sludge) DUP DNRA Pad 10/25/2012 33.06 4 2 9.38 9.39 0

DNR ST 3-1-S (solid) DNRA Pad 10/25/2012

DNR ST 3-1-S (solid) DUP DNRA Pad 10/25/2012

FS -1, Donna Pad 7/27/2012 40.35 94345 47450 6.92 1.47 49.57

FS-2, Donna Pad 8/2/2012 25.86 160501 102700 6.49 0.74 NS

FS-3, Donna Pad 8/9/2012 17.47 133036 101000 7.07 1.28 124.67

FS -Final, Donna Pad 8/30/2012 20.87 170,822 111,000 6.61 1.46 141.44

 FS-1, Noble Pits (SHL-3) 8/13/2012 28.51 16,283 10,590 6.99 1.55 9.5

 FS 2, Noble Pits (SHL-3) 8/20/2012 24.8 125901 81830 6.9 2.69 96.01

 FS-3, Noble Pits (SHL-3) 8/28/2012 28.39 26426 17180 6.16 0.57 16.1

 FS Final, Noble Pits (SHL-3) 9/17/2012 33.04 54461 35400 6.22 1.29 36.08

SHL-4 Composite, Noble Pits (SHL-4) 9/17/2012 27.2 40499 2632 7.07 2.57 25.83

FS-1, Weekly Pad 8/15/2012 27.79 119,710 77,800 6.81 1.24 90.16

FS-2, Weekly Pad 8/20/2012 25.83 132,680 86,230 6.75 0.9 102.48

FS-1, Maury Pad 10/2/2012 28.61 112879 73330 6.86 1.08 83.81

Donna Pit-C (liquid) Donna Pad 8/30/2012 28.23 84044 54630 7.82 9.53 59.11

Donna Pit-C (solid) Donna Pad 8/30/2012

Site Pit

Field Readings/Observations

Fresh Water 

Impoundment Fresh Water

Pits: 

Centralized

Monitoring 

Wells 

(Shallow)

Hydraulic 

Fracturing

Vertical 

Drilling

Drilling - 

produced 

waste

Pits: 

centralized

Monitoring 

Wells (Deep)

Flowback

Site Pit

Centralized 

Pits
132 | Page

units mr/hr mr/hr parameter dependent parameter dependent

Stage Target Sample Identification and Location Date Weather Conditions Ra di oa cti vi ty 

(Background)

Ra di oa cti vi ty 

(Sample) 6-Gas (Background) 6-Gas (Sample)

SHL-3-IMP, Noble Pits 6/7/2012 83° F, Sunny w/s ome cloud cover 0.011 0.011 Non Detect 1% LEL

SHL-2-IMP, Noble Pits 6/7/2012 83° F, Sunny w/s ome cloud cover 0.008 0.016 Non Detect Non Detect

SHL-1-IMP, Noble Pits 6/7/2012 83° F, Sunny w/s ome cloud cover 0.008 0.011 Non Detect Non Detect

Mi l l s Wetzel #3 IMP 8/28/2012 84° F, Mos tly Sunny 0.009 0.014 7% LEL 7% LEL

SHL-2, MW-2, Noble Pits 6/4/2012 86° F, Sunny w/little cloud cover NS NS Non Detect Non Detect

SHL-2, MW-3, Noble Pits 6/4/2012 86° F, Sunny w/little cloud cover NS NS Non Detect Non Detect

SHL-4, MW-1, Noble Pits 6/4/2012 86° F, Sunny w/little cloud cover NS NS Non Detect Non Detect

SHL-4, MW-2, Noble Pits 6/4/2012 86° F, Sunny w/little cloud cover NS NS Non Detect Non Detect

SHL-4, MW-3, Noble Pits 6/4/2012 86° F, Sunny w/little cloud cover NS NS Non Detect Non Detect

SHL-2 MW-1, Noble Pits 11/1/2012 38° F, Overca s t, Ra i n 0.012 0.01 1% LEL, 21.5% O2 1% LEL, 21.5% O2

SHL-2, MW-2, Noble Pits 10/31/2012 40° F, Overca s t, Dri zzl e 0.016 0.013 21.5% O2 Non Detect

SHL-2, MW-3, Noble Pits 10/31/2012 40° F, Overca s t, Dri zzl e 0.013 0.013 21.3% O2 Non Detect

SHL-4, MW-1, Noble Pits 10/31/2012 40° F, Overca s t, Dri zzl e 0.017 0.013 2% LEL, 21.5% O2 1% LEL, 21.3% O2

SHL-4, MW-2, Noble Pits 10/31/2012 40° F, Overca s t, Dri zzl e 0.012 0.016 LEL, 21.1% O2, 2ppm IBL 21.3% O2, 2ppm IBL

SHL-4, MW-3, Noble Pits 10/31/2012 40° F, Overca s t, Dri zzl e 0.016 0.011 1% LEL, 21.1% O2 1% LEL, 21.1% O2

SHL-2 MW-4, Noble Pits 6/19/2012 92° F, Sunny, clear 0.009 0.015 Non Detect Non Detect

SHL-3 MW-4, Noble Pits 6/19/2012 92° F, Sunny, clear 0.011 0.013 Non Detect Non Detect

SHL-2 MW-4, Noble Pits 11/1/2012 38° F, Overca s t, Ra i n 0.022 0.09 21.8% O2 21.6% O2

SHL-3 MW-4, Noble Pits 11/1/2012 38° F, Overca s t, Ra i n 0.015 0.013 1% LEL, 21.5% O2 1% LEL, 21.6% O2, 1ppm IBL

HF Water HF Wa ter, Donna Pa d 7/25/2012 89° F, Sunny w/few clouds 0.015 0.018 Non Detect Non Detect

Fra c Fl ui d Comb. HF, Donna Pad 7/25/2012 89° F, Sunny w/few clouds 0.01 0.012 7.8% LEL Non Detect

HF Water HF Wa ter, Ma ury Pa d 9/11/2012 70°, Sunny, clear 0.016 0.014 87% LEL, 21.9 O2 44% LEL, 21.9 O2

Fra c Fl ui d Comb. HF, Maury Pad 9/11/2012 70°, Sunny, clear 0.011 0.01 1% LEL 2% LEL

ST 2 a t 13:00 (s l urry) Mi l l s Wetzel #2 8/8/2012 92° F, Sunny w/few clouds 0.008 0.009 4% LEL 5%LEL

ST 2 a t 13:00 (s ol i ds ) Mi l l s Wetzel #2 8/8/2012 92° F, Sunny w/few clouds 0.008 0.009 4% LEL 5%LEL

ST 1-1 at 11:00 (liquid) Lemons Pad 8/8/2012 89° F, Sunny w/few clouds 0.013 0.013 Non Detect Non Detect

ST 1-1 at 11:00 (solids) Lemons Pad 8/8/2012 89° F, Sunny w/few clouds 0.013 0.013 Non Detect Non Detect

ST 1-2 at 10:30 (liquid) Lemons Pad 8/15/2012 90° F, Sunny 0.011 0.016 Non Detect 2% LEL

ST 1-2 at 10:30 (solids) Lemons Pad 8/15/2012 90° F, Sunny 0.011 0.016 Non Detect 2%LEL

ST 1-3 at 11:00 (liquid) Lemons Pad 8/22/2012 84° F, Partly Sunny 0.005 0.009 2% LEL 1%LEL

ST 1-3 at 11:00 (solid) Lemons Pad 8/22/2012 84° F, Partly Sunny 0.005 0.009 2% LEL 1%LEL

ST 1-4 at 1:30 (liquid) Lemons Pad 10/2/2012 66° F, Overca s t, Dri zzl e 0.008 0.009 20% LEL 20% LEL

ST 1-4 at 1:30 (solid) Lemons Pad 10/2/2012 66° F, Overca s t, Dri zzl e 0.008 0.015 20% LEL 20% LEL

DNR ST 3-1-L (sludge) DNRA Pad 10/25/2012 73° F, Sunny w/little cloud cover 0.008 0.01 Non Detect 403 IBL, 100% LEL, 77.6 ppm VOC's

DNR ST 3-1-L (s ludge) DUP DNRA Pad 10/25/2012 73° F, Sunny w/little cloud cover 0.008 0.01 Non Detect 403 IBL, 100% LEL, 77.6 ppm VOC's

DNR ST 3-1-S (s ol i d) DNRA Pa d 10/25/2012 73° F, Sunny w/little cloud cover 0.007 0.008 1% LEL 30% LEL, 43.2 ppm VOC's

DNR ST 3-1-S (s olid) DUP DNRA Pad 10/25/2012 73° F, Sunny w/little cloud cover 0.007 0.008 1% LEL 30% LEL, 43.2 ppm VOC's

FS -1, Donna Pad 7/27/2012 83° F, Sunny w/s ome cloud cover 0.019 0.017 3% LEL Non Detect

FS-2, Donna Pad 8/2/2012 80° F, Sunny w/s ome cloud cover 0.011 0.013 Non Detect 2% LEL

FS-3, Donna Pad 8/9/2012 79° F, Sunny w/s ome cloud cover 0.009 0.013 91% LEL 91% LEL

FS -Fi na l , Donna Pa d 8/30/2012 80° F, Sunny, clear 0.011 0.01 1% LEL, 21.2% O2 1% LEL, 21.2% O2

 FS-1, Noble Pits (SHL-3) 8/13/2012 77° F, Sunny w/s ome cloud cover 0.014 0.008 Non Detect 6% LEL

 FS 2, Noble Pits (SHL-3) 8/20/2012 89° F, Sunny w/s ome cloud cover 0.014 0.01 5% LEL 5% LEL

 FS-3, Noble Pits (SHL-3) 8/28/2012 84° F, Mos tly Sunny 0.008 0.013 3% LEL 5%LEL, 43ppm-H2S

 FS Fi na l , Nobl e Pi ts (SHL-3) 9/17/2012 75° F, Sunny w/s ome cloud cover 0.011 0.008 5% LEL 2% LEL, >100ppm H2S

SHL-4 Compos ite, Noble Pits (SHL-4) 9/17/2012 75° F, Sunny w/s ome cloud cover 0.09 0.009 6% LEL 6% LEL, 2ppm IBL

FS-1, Weekly Pad 8/15/2012 90° F, Sunny 0.01 0.007 2% LEL 2% LEL

FS-2, Weekly Pad 8/20/2012 88° F, Sunny 0.008 0.009 3% LEL, 21.2% O2 21% O2

FS-1, Maury Pad 10/2/2012 68° F, Rain, Cloudy 0.011 0.013 26% LEL, >100ppm H2S 38.8% LEL, >2000ppm IBL 

Donna Pit-C (liquid) Donna Pad 8/30/2012 80° F, Sunny, clear 0.014 0.007 4% LEL 3% LEL

Donna Pi t-C (s ol i d) Donna Pa d 8/30/2012 80° F, Sunny, clear 0.014 0.007 4% LEL 3% LEL

Fi el d Rea di ngs /Obs erva ti ons

Si te Pi t

Fresh Water 

Impoundment Fres h Wa ter

Pits: 

Centra l i zed

Monitoring 

Wells 

(Shallow)

Hydra ul i c 

Fracturing

Verti ca l 

Dri l l i ng

Dri l l i ng - 

produced 

waste

Pits: 

centra l i zed

Monitoring 

Wells 

(Deep)

Flowback

Si te Pi t

Centra l i zed 

Pits