Water Consulting Services in Support of the Supplemental Generic 

Environmental Impact Statement for Natural Gas Production 

NYSERDA Contract PO Number 10666 

WATER-RELATED ISSUES ASSOCIATED WITH GAS 

PRODUCTION IN THE MARCELLUS SHALE: 

Additives Use 

Flowback Quality and Quantities 

Regulations 

On-site Treatment 

Green Technologies 

Alternate Water Sources 

Water Well-Testing

Prepared by 

URS Corporation 

Fort Washington, PA 

March 25, 2011 
ii

NOTICE 

This report was prepared by URS Corporation in the course of performing work contracted 

for and sponsored by the New York State Energy Research and Development Authority 

(hereafter "NYSERDA"). The opinions expressed in this report do not necessarily reflect 

those of NYSERDA or the State of New York, and reference to any specific product, service, 

process, or method does not constitute an implied or expressed recommendation or 

endorsement of it. Further, NYSERDA, the State of New York, and the contractor make no 

warranties or representations, expressed or implied, as to the fitness for particular purpose or 

merchantability of any product, apparatus, or service, or the usefulness, completeness, or 

accuracy of any processes, methods, or other information contained, described, disclosed, or 

referred to in this report. NYSERDA, the State of New York, and the contractor make no 

representation that the use of any product, apparatus, process, method, or other information 

will not infringe privately owned rights and will assume no liability for any loss, injury, or 

damage resulting from, or occurring in connection with, the use of information contained, 

described, disclosed, or referred to in this report. 
iii

Table of Contents 

1 Introduction and Scope .......................................................................................................... 1-1

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

1.2 Report Outline .............................................................................................................. 1-2

2 Fracturing Fluid Additives ..................................................................................................... 2-1

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

2.2 Desirable Properties of Fracturing Fluids .................................................................... 2-1

2.3 Classes of Additives ..................................................................................................... 2-1

2.4 Composition of Fracturing Fluids ................................................................................ 2-3

2.5 Selection of Additives ................................................................................................ 2-14

2.6 Additives Sequence .................................................................................................... 2-14

2.7 Summary .................................................................................................................... 2-15

3 Flowback Fluids ...................................................................................................................... 3-1

3.1 Introduction .................................................................................................................. 3-1

3.2 Flowback Fluid Volume .............................................................................................. 3-1

3.3 Trends in Flowback Fluid Volume .............................................................................. 3-2

3.4 Flowback Fluid Composition ....................................................................................... 3-2

3.4.1 Marcellus Shale Coalition Report on Flowback .................................................. 3-6

3.5 Temporal Trends in Flowback Fluids Composition................................................... 3-13

3.6 Summary .................................................................................................................... 3-14

4 Sufficiency of Regulations and Guidelines ............................................................................ 4-1

4.1 Background .................................................................................................................. 4-1

4.2 Water Use Classifications ............................................................................................ 4-2

4.3 Drinking Water ............................................................................................................ 4-5

4.3.1 Federal ................................................................................................................. 4-5

4.3.2 New York State ..................................................................................................... 4-7

4.4 Discharge Limits – SPDES .......................................................................................... 4-8

4.5 Ambient Water Quality Standards and Guidance Values and Groundwater Effluent 

Limitations ................................................................................................................. 4-10

4.6 Lists of Chemicals in Additives and Flowback Addressed in NY Regulations or 

Guidances ................................................................................................................... 4-11

4.7 Rules and Regulations Applicable to Oil, Gas, and Solution Mining Category ........ 4-11

4.7.1 Federal ............................................................................................................... 4-11

4.7.2 New York State ................................................................................................... 4-11

4.8 Other Agencies and Activities with Jurisdiction ........................................................ 4-13

4.9 Conclusions ................................................................................................................ 4-14
iv

5 On-site Flowback Fluids Treatment or Recycling Technologies ........................................ 5-1

5.1 Introduction .................................................................................................................. 5-1

5.2 Flowback Recycling ..................................................................................................... 5-1

5.3 On-site Treatment ........................................................................................................ 5-2

5.3.1 Influent parameters and their concentrations ...................................................... 5-2

5.3.2 Parameters and their concentrations allowable in the effluent ........................... 5-2

5.3.3 Disposal of residuals ............................................................................................ 5-3

5.3.4 Factors affecting on-site treatment ...................................................................... 5-3

5.4 On-site Treatment Technologies .................................................................................. 5-4

5.4.1 Physical Separation ............................................................................................. 5-5

5.4.2 Chemical Separation and Precipitation ............................................................... 5-6

5.4.3 Membranes / Reverse Osmosis ............................................................................. 5-6

5.4.4 Ion Exchange ........................................................................................................ 5-7

5.4.5 Electrodialysis ...................................................................................................... 5-7

5.4.6 Thermal Distillation/Evaporation ........................................................................ 5-8

5.4.7 Crystallization/Zero Liquid Discharge ................................................................ 5-8

5.4.8 Ozone/Ultrasonic/Ultraviolet ............................................................................... 5-9

5.4.9 Comparison of potential on-site treatment technologies ..................................... 5-9

5.5 On-site containment of flowback ............................................................................... 5-10

5.5.1 Frac tanks .......................................................................................................... 5-10

5.5.2 On-site impoundments (storage pits) ................................................................. 5-11

5.6 Exemption of oil and gas waste from federal regulations .......................................... 5-14

5.7 Naturally Occurring Radioactive Materials and Water Treatment ............................ 5-15

5.7.1 Federal and state regulations regarding NORM ............................................... 5-16

5.7.2 Disposal of TENORM produced by natural gas drilling ................................... 5-16

5.7.3 Pre-treatment potential for radium .................................................................... 5-17

5.8 Summary .................................................................................................................... 5-18

6 Potential Environmentally-Friendly Fracturing and Stimulation Technologies .............. 6-1

6.1 Introduction .................................................................................................................. 6-1

6.2 Environmentally-Friendly Fracturing Technology Alternatives .................................. 6-1

6.3 Environmentally-Friendly Chemical Alternatives ....................................................... 6-2

6.3.1 Experience from Drilling in the North Sea .................................................................. 6-4

6.3.2 Environmental Coordination in Europe ....................................................................... 6-4

6.3.2.1 Offshore Chemical Notification Scheme (OCNS) ............................................ 6-5

6.3.2.2 Products Approved by Norway ........................................................................ 6-6

6.3.3 Environmental Coordination in Canada ....................................................................... 6-6

6.4 Summary ...................................................................................................................... 6-6

7 Alternate Water Sources for Hydraulic Fracturing Operations ........................................ 7-1

7.1 Introduction .................................................................................................................. 7-1
v

7.2 Potential Alternate Water Sources ............................................................................... 7-1

7.3 Factors that Affect Usability of Alternate Water Sources ........................................... 7-1

7.4 Summary ...................................................................................................................... 7-3

8 Water Well Sampling Needs .................................................................................................. 8-1

8.1 Introduction .................................................................................................................. 8-1

8.2 Water Well Sampling Requirements in Pennsylvania ................................................. 8-1

8.3 Water Well Sampling Requirements in Ohio .............................................................. 8-1

8.4 Water Well Sampling Requirements in Texas ............................................................. 8-2

8.5 Water Well Sampling Requirements in Kentucky ....................................................... 8-2

8.6 Existing Water Well Protection in New York ............................................................. 8-2

8.7 Enhanced Water Well Protection in New York ........................................................... 8-2

8.8 Indicator Compounds/Elements of Potential Contamination due to Hydraulic 

Fracturing ..................................................................................................................... 8-3

8.9 Summary ...................................................................................................................... 8-4

9 Summary and Closing ............................................................................................................ 9-1

9.1 Summary ...................................................................................................................... 9-1

9.2 Limitations of the Survey ............................................................................................. 9-3

9.3 Closing ......................................................................................................................... 9-4

10 References .............................................................................................................................. 10-1

List of Figures 

Figure 2-1 - Sample Fracturing fluid Composition (12 additives), by Weight, from Fayetteville Shale

 ................................................................................................................................................ 2-4

Figure 2-2 - Sample Fracturing fluid Composition (9 additives), by Weight, from Marcellus Shale . 2-4

Figure 2-3 - Sample Fracturing fluid Composition (6 additives), by Weight, from Marcellus Shale . 2-5

Figure 5-1 - One configuration of potential on-site treatment technologies ....................................... 5-5

List of Tables 

Table 2-1 - Types and Purposes of Additives Proposed for Use in New York State .......................... 2-2

Table 2-2 – Chemical Constituents in Additives,, ............................................................................... 2-6

Table 3-1 - Parameters present in a limited set of flowback analytical results ................................... 3-3

Table 3-2 - Conventional analyses in MSC Study .............................................................................. 3-7

Table 3-3 - Total and dissolved metals analyzed in MSC Study ......................................................... 3-7

Table 3-4 - Volatile Organic Compounds analyzed in MSC Study .................................................... 3-8

Table 3-5 - Semi-Volatile Organics analyzed in MSC Study.............................................................. 3-9

Table 3-6 - Organochlorine pesticides analyzed in MSC Study.......................................................... 3-9

Table 3-7 – PCBs analyzed in MSC Study ....................................................................................... 3-10

Table 3-8 - Organophosphorus Pesticides analyzed in MSC Study .................................................. 3-10

Table 3-9 - Alcohols analyzed in MSC Study ................................................................................... 3-10
vi

Table 3-10 – Glycols analyzed in MSC Study .................................................................................. 3-10

Table 3-11 – Acids analyzed in MSC Study ..................................................................................... 3-10

Table 3-12 – Parameter classes analyzed for in MSC Study ............................................................. 3-11

Table 3-13 – Parameter classes detected in flowback analyticals in MSC Study ............................. 3-11

Table 4-1 - New York Water Use Classifications ............................................................................... 4-3

Table 4-2 - Primary Drinking Water Standards................................................................................. 4-15

Table 4-3 - Secondary Drinking Water Standards ............................................................................. 4-18

Table 4-4 – Specific Contaminants included within NYSDOH POCs Standardsa,b .......................... 4-18

Table 4-5 – Comparison of additives used or proposed for use in NY, parameters detected in 

analytical results of flowback from the Marcellus operations in PA and WV, and parameters 

regulated via primary and secondary drinking water standards, SPDES Program or listed in 

TOGS111 ............................................................................................................................. 4-18

Table 4-6 – Typical concentrations of flowback constituents based on limited samples from PA and 

WV, and regulated in NY, .................................................................................................... 4-37

Table 4-7 - Typical concentrations of parameters that are not regulated, based on limited flowback 

analyses from PA and WV ................................................................................................... 4-41

Table 5-1 – Allowable water quality requirements for fracturing fluids, based on input from one 

expert panel on Barnett Shale ................................................................................................. 5-3

Table 5-2 - Treatment capabilities of EDR and RO Systems .............................................................. 5-7

Table 5-3 - Summary of Characteristics of On-site Flowback Fluid Treatment Technologies ........... 5-9

Table 5-4 - Design specifications for containment ponds as required by state regulations ............... 5-12

Table 5-5 – Radiological data in limited flowback analyticals from PA and WV ............................ 5-15

Table 5-6 - Select characteristics of various treatment technologies currently offered or under design

 .............................................................................................................................................. 5-19

Table 6-1 - Cefas Chemicals Categories based on Hazard Quotient (HQ) ......................................... 6-6
1-1

1 INTRODUCTION AND SCOPE 

1.1 Introduction 

The Marcellus Shale formation has been identified as a potentially major source of natural 

gas. The core formation extends over an eight state area, including parts of New York State. 

The formation is exposed at the surface in some locations and at depths greater than 7,000 

feet at other locations. 

In 1992, the New York State Department of Environmental Conservation (NYSDEC) issued 

a Generic Environmental Impact Statement (GEIS) that provides a comprehensive review of 

the potential environmental impacts of oil and gas drilling and production and how they may 

be mitigated. NYSDEC is now preparing a second draft Supplemental GEIS (dSGEIS) to 

assess issues unique to drilling and high-volume hydraulic fracturing in the Marcellus Shale 

area. The New York State Energy Research and Development Authority (NYSERDA) is 

assisting NYSDEC by developing information and data needed for the dSGEIS. NYSERDA 

has contracted several consultants to research, review, compile, and provide to NYSERDA 

reports that address different aspects of the final scope for the dSGEIS on the Oil, Gas and 

Solution Mining Regulatory Program, which was developed by NYSDEC. The SGEIS will 

be issued by the NYSDEC to establish State Environmental Quality Review (SEQR) 

thresholds for permitting horizontal drilling and high-volume hydraulic fracturing projects to 

develop the Marcellus Shale and other low permeability gas reservoirs. 

The process of high-volume hydraulic fracturing uses relatively large volumes of water, from 

about 0.5 to 6 million gallons per well. Water is typically withdrawn from surface water or 

groundwater sources and stored at each well pad or at centralized facilities until ready to be 

used. The water is then mixed with proprietary concentrations of proppant and other 

additives (the mixture is referred to as fracturing fluid), and pumped down into the well at 

high pressure to fracture the shale. A portion of the fracturing fluid returns to the surface as 

“flowback” fluid1

, which requires appropriate treatment and disposal. 

This report addresses the following topics related to Marcellus Shale operations: 

a. Fracturing fluid additives 

b. Flowback fluids 

c. Sufficiency of regulations and guidelines 

d. On-site flowback fluids treatment or recycling technologies 

e. Potential ‘green’ (environmentally-friendly) hydraulic fracturing technologies 

f. Alternate water sources for hydraulic fracturing operations, and 

g. Water well sampling needs. 

 

1

 Independent Oil & Gas Association of New York (IOGA NY) refers to the returning fracturing fluids as 

produced water. This report distinguishes between flowback and produced water as defined in Section 3-1. 
1-2

The scope of review for each of these topics is briefly described below. 

1.2 Report Outline 

Section 2 provides a review of fracturing fluid additives used in drilling/fracturing 

operations; Section 3 provides a review of flowback fluid volumes and composition. Both of 

these sections draw on publicly available information and from proprietary data from service 

companies and operators received via NYSDEC under a confidentiality agreement. In 

addition, Section 3 includes a summary of the Marcellus Shale Coalition (MSC) study 

findings. In order to protect industry and trade secrets, these two sections present broad 

classes of inputs or the generic constituents of additives or flowback, but not the chemical 

suppliers, product names or the product compositions. 

Section 4 provides a review of federal and New York State regulations and guidelines related 

to water that may impact the oil and gas industry. This section compares the list of 

parameters presently known to be in additives and analytical results for flowback with 

parameters regulated by the Safe Drinking Water Act (SDWA), pollutants regulated by the 

State Pollutant Discharge Elimination System (SPDES) program, or that are addressed in 

guidance through the Technical & Operational Guidance Series 1.1.1 (TOGS111). 

Section 5 surveys on-site treatment or recycling technologies that may potentially be 

available for operations in the Marcellus Shale. 

Section 6 surveys ‘environmentally-friendly’ hydraulic fracturing technologies and 

chemicals, and draws experiences from gas and oil exploration in the North Sea. 

Section 7 surveys potential alternate water sources that may be utilized for hydraulic 

fracturing operations. 

Section 8 surveys existing private water well sampling, testing, and monitoring requirements 

in other states with Marcellus Shale type development activity. This section identifies 

potential additional requirements that may be applied within New York State for private 

water well sampling, testing, and monitoring. This section also identifies potential 

compounds/elements for testing in typical private water wells in New York State in baseline 

and post-drilling modes. 

Section 9 summarizes the findings and lists limitations of the study. 

Section 10 provides a list of references. 
2-1

2 FRACTURING FLUID ADDITIVES 

2.1 Introduction 

Hydraulic fracturing is a process whereby a water, proppant and additives mixture (fracturing 

fluid) is pumped down a well at high pressure. The force of the injection fractures the 

underground rock (shale formation) allowing natural gas to seep through the fractures into 

the wellbore and up to the surface. 

Hydraulic fracturing fluid consists of water, a “proppant” (a material such as sand that keeps 

the opened fractures from resealing after the fracturing fluid vacates the space), and a 

relatively small amount (< 1 percent by volume) of several types of chemical additives. The 

additives serve a number of purposes listed below. After fracturing the shale, a variable 

percentage of the fracturing fluid returns to ground surface as flowback. 

2.2 Desirable Properties of Fracturing Fluids 

Additives are used in hydraulic fracturing operations to elicit certain properties / 

characteristics that would aide and enhance the operation. The desired properties / 

characteristics include [1, 2]: 

 Non-reactive 

 Non-flammable 

 Minimal residuals 

 Minimal potential for scale or corrosion. 

 Low entrained solids 

 Neutral pH (pH 6.5 – 7.5) for maximum polymer hydration 

 Limited formation damage 

 Appropriately modify properties of water to carry proppant deep into the shale 

 Economical to modify fluid properties 

 Minimal environmental effects 

2.3 Classes of Additives 

Table 2-1 lists the types, purposes and examples of additives that have been proposed to date 

for use in hydraulic fracturing of gas wells in New York State. 
2-2

Table 2-1 - Types and Purposes of Additives Proposed for Use in New York State 

Additive Type Description of Purpose Examples of Chemicals2

Proppants “Props” open fractures and allows gas / fluids to flow more freely 

to the well bore 

Sand 

[Sintered bauxite; zirconium 

oxide; ceramic beads] 

Acid Cleans up perforation intervals of cement and drilling mud prior to 

fracturing fluid injection, and provides accessible path to formation 

Hydrochloric acid (HCl, 3% 

to 28%) or muriatic acid 

Breaker Reduces the viscosity of the fluid in order to release proppant into 

fractures and enhance the recovery of the fracturing fluid 

Peroxydisulfates 

Bactericide / 

Biocide / 

Antibacterial 

Agent 

Inhibits growth of organisms that could produce gases (particularly 

hydrogen sulfide) that could contaminate methane gas. Also 

prevents the growth of bacteria which can reduce the ability of the 

fluid to carry proppant into the fractures 

Gluteraldehyde; 2,2-Dibromo3-nitriloprpionamide 

Buffer / pH 

Adjusting Agent 

Adjusts and controls the pH of the fluid in order to maximize the 

effectiveness of other additives such as crosslinkers 

Sodium or potassium 

carbonate; acetic acid 

Clay Stabilizer / 

Control / KCl 

Prevents swelling and migration of formation clays which could 

block pore spaces thereby reducing permeability 

Salts (e.g., tetramethyl 

ammonium chloride, 

Potassium chloride (KCl)) 

Corrosion 

Inhibitor 

(including 

Oxygen 

Scavengers) 

Reduces rust formation on steel tubing, well casings, tools, and 

tanks (used only in fracturing fluids that contain acid) 

Methanol; ammonium 

bisulfate for Oxygen 

Scavengers 

Crosslinker Increases fluid viscosity using phosphate esters combined with 

metals. The metals are referred to as crosslinking agents. The 

increased fracturing fluid viscosity allows the fluid to carry more 

proppant into the fractures. 

Potassium hydroxide; Borate 

salts 

Friction Reducer Allows fracturing fluids to be injected at optimum rates and 

pressures by minimizing friction 

Sodium acrylate-acrylamide 

copolymer; polyacrylamide 

(PAM); petroleum distillates 

Gelling Agent Increases fracturing fluid viscosity, allowing the fluid to carry more 

proppant into the fractures 

Guar gum; petroleum 

distillates 

Iron Control Prevents the precipitation of metal oxides which could plug off the 

formation 

Citric acid 

Scale Inhibitor Prevents the precipitation of carbonates and sulfates (calcium 

carbonate, calcium sulfate, barium sulfate) which could plug off the 

formation 

Ammonium chloride; ethylene 

glycol 

Solvents Additive which is soluble in oil, water & acid-based treatment 

fluids which is used to control the wettability of contact surfaces or 

to prevent or break emulsions 

Various aromatic 

hydrocarbons 

Surfactant Reduces fracturing fluid surface tension thereby aiding fluid 

recovery 

Methanol; isopropanol; 

ethoxylated alcohol 

 

2

 Chemicals in brackets [ ] have not been proposed for use in the State of New York to date, but are known to be 

used in other states or shale formations. 
2-3

2.4 Composition of Fracturing Fluids 

The composition of the fracturing fluid used may vary from one geologic basin/formation to 

another in order to meet the specific needs of each operation; but the range of additive-types 

available for potential use remains the same. There are a number of different products for 

each additive type; however, only one product of each type is typically utilized in any given 

gas well. The selection may be driven by the formation and potential interactions between 

additives. Additionally not all additive types will be utilized in every fracturing job. 

Figure 2-1, Figure 2-2 and Figure 2-3 are three sample compositions, by weight, of fracturing 

fluids. Figure 2-1 [3] is based on data from the Fayetteville Shale3

; Figure 2-2 and Figure 2-3 

[4] are based on data from Marcellus Shale development in Pennsylvania. Based on this data, 

between approximately 80 and 90 percent of the fracturing fluid is water; between 

approximately 8 and 15 percent is proppant; the remainder, typically less than 1 percent, 

consists of chemical additives listed above. The specific fracturing fluid composition, types 

of additives and specific products used would depend on the location and the operator. 

Barnett Shale is considered to be the first instance of extensive hydraulic fracturing 

technology use in horizontal shale wells; the technology was later applied in other areas such 

as the Fayetteville Shale and the Haynesville Shale. Data collected from applications to drill 

Marcellus Shale wells in New York indicate that the typical fracturing fluid composition for 

operations in the Marcellus Shale is similar to that provided for the Fayetteville Shale. Even 

though no horizontal wells have been drilled in the Marcellus Shale in New York, 

applications filed to date indicate that it is realistic to expect that the composition of 

fracturing fluids used for developing the Marcellus Shale in New York would be similar to 

the compositions used in the Fayetteville Shale and Marcellus Shale in Pennsylvania. 

 

3

 Similar to the Marcellus Shale, the Fayetteville Shale is a marine shale rich in unoxidized carbon (i.e. a black 

shale). The two shales are at similar depths, and vertical and horizontal wells have been drilled/fractured in both 

shales. 
2-4

Figure 2-1 - Sample Fracturing fluid Composition (12 additives), by Weight, from 

Fayetteville Shale 

Figure 2-2 - Sample Fracturing fluid Composition (9 additives), by Weight, from 

Marcellus Shale 
2-5

Figure 2-3 - Sample Fracturing fluid Composition (6 additives), by Weight, from 

Marcellus Shale 

Each product within these thirteen classes of additives may be made up of one or more 

chemical constituents. Table 2-2 is a list of chemical constituents and their CAS numbers, 

that have been extracted from complete product chemical composition and Material Safety 

Data Sheets submitted to the NYSDEC. This list is based on over 230 products used or 

proposed for use in hydraulic fracturing operations in the Marcellus Shale area of New York. 

It is important to note that several manufacturers / suppliers provide similar products (i.e. 

chemicals that would serve the same purpose) for any class of additive. Therefore only a 

handful of chemicals from Table 2-2 would be utilized in a single well. Table 2-2 represents 

constituents of all hydraulic-fracturing-related additives submitted to NYSDEC to date for 

potential use in shale wells in the State. 

Data provided to NYSDEC to date indicates similar fracturing fluid compositions for 

vertically and horizontally drilled wells. 
2-6

Table 2-2 – Chemical Constituents in Additives4,5,6

CAS Number7 Chemical Constituent 

106-24-1 (2E)-3,7-dimethylocta-2,6-dien-1-ol 

67701-10-4 (C8-C18) and (C18) Unsaturated Alkylcarboxylic Acid Sodium Salt 

2634-33-5 1,2 Benzisothiazolin-2-one / 1,2-benzisothiazolin-3-one 

95-63-6 1,2,4 trimethylbenzene 

93858-78-7 1,2,4-Butanetricarboxylicacid, 2-phosphono-, potassium salt 

123-91-1 1,4 Dioxane 

3452-07-1 1-eicosene 

629-73-2 1-hexadecene 

104-46-1 1-Methoxy-4-propenylbenzene 

124-28-7 1-Octadecanamine, N, N-dimethyl- / N,N-Dimthyloctadecylamine 

112-03-8 

1-Octadecanaminium, N,N,N-Trimethyl-, Chloride 

/Trimethyloctadecylammonium chloride 

112-88-9 1-octadecene 

40623-73-2 1-Propanesulfonic acid 

1120-36-1 1-tetradecene 

95077-68-2 2- Propenoic acid, homopolymer sodium salt 

98-55-5 2-(4-methyl-1-cyclohex-3-enyl)propan-2-ol 

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

27776-21-2 2,2'-azobis-{2-(imidazlin-2-yl)propane}-dihydrochloride 

73003-80-2 2,2-Dobromomalonamide 

15214-89-8 2-Acrylamido-2-methylpropanesulphonic acid sodium salt polymer 

46830-22-2 2-acryloyloxyethyl(benzyl)dimethylammonium chloride 

52-51-7 2-Bromo-2-nitro-1,3-propanediol 

111-76-2 2-Butoxy ethanol / Ethylene glycol monobutyl ether / Butyl Cellusolve 

1113-55-9 2-Dibromo-3-Nitriloprionamide /2-Monobromo-3-nitriilopropionamide 

104-76-7 2-Ethyl Hexanol 

67-63-0 2-Propanol / Isopropyl Alcohol / Isopropanol / Propan-2-ol 

26062-79-3 2-Propen-1-aminium, N,N-dimethyl-N-2-propenyl-chloride, homopolymer 

9003-03-6 2-propenoic acid, homopolymer, ammonium salt 

25987-30-8 2-Propenoic acid, polymer with 2 p-propenamide, sodium salt / Copolymer 

of acrylamide and sodium acrylate 

71050-62-9 2-Propenoic acid, polymer with sodium phosphinate (1:1) 

66019-18-9 2-propenoic acid, telomer with sodium hydrogen sulfite 

 

4

 Table 2-2 is a list of chemical constituents and their CAS numbers that have been extracted from complete 

chemical compositions and Material Safety Data Sheets submitted to the NYSDEC. 

5

 These are the chemical constituents of all chemical additives proposed to be used in New York for hydraulic 

fracturing operations at shale wells. Only a few additives will be used in a single well; the list of chemical 

constituents used in an individual well will be correspondingly smaller. 

6

 This list would not include chemicals/products that are exclusively used for drilling. 

7

 Chemical Abstracts Service (CAS) is a division of the American Chemical Society. CAS assigns unique 

numerical identifiers to every chemical described in the literature. The intention is to make database searches 

more convenient, as chemicals often have many names. Almost all chemical molecule databases today allow 

searching by CAS number. 
2-7

CAS Number7 Chemical Constituent 

107-19-7 2-Propyn-1-ol / Progargyl Alcohol 

51229-78-8 3,5,7-Triaza-1-azoniatricyclo[3.3.1.13,7]decane, 1-(3-chloro-2-propenyl)-

chloride, 

106-22-9 3,7 - dimethyl-6-octen-1-ol 

5392-40-5 3,7-dimethyl-2,6-octadienal 

115-19-5 3-methyl-1-butyn-3-ol 

104-55-2 3-phenyl-2-propenal 

127-41-3 4-(2,6,6-trimethyl-1-cyclohex-2-enyl)-3-buten-2-one 

121-33-5 4-hydroxy-3-methoxybenzaldehyde 

127087-87-0 4-Nonylphenol Polyethylene Glycol Ether Branched / Nonylphenol 

ethoxylated / Oxyalkylated Phenol 

64-19-7 Acetic acid 

68442-62-6 Acetic acid, hydroxy-, reaction products with triethanolamine 

108-24-7 Acetic Anhydride 

67-64-1 Acetone 

79-06-1 Acrylamide 

38193-60-1 Acrylamide - sodium 2-acrylamido-2-methylpropane sulfonate copolymer 

25085-02-3 Acrylamide - Sodium Acrylate Copolymer /Anionic Polyacrylamide / 2-

Propanoic acid 

69418-26-4 Acrylamide polymer with N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy 

Ethanaminium chloride / Ethanaminium, N, N, N-trimethyl-2-[(1-oxo-2-

propenyl)oxy]-, chloride, polymer with 2-propenamide (9Cl) 

15085-02-3 Acrylamide-sodium acrylate copolymer 

68891-29-2 Alcohols C8-10, ethoxylated, monoether with sulfuric acid, ammonium salt 

68526-86-3 Alcohols, C11-14-iso, C13-rich 

68551-12-2 Alcohols, C12-C16, Ethoxylated /Ethoxylated alcohol 

64742-47-8 Aliphatic Hydrocarbon / Hydrotreated light distillate / Petroleum Distillates / 

Isoparaffinic Solvent / Paraffin Solvent / Napthenic Solvent 

64743-02-8 Alkenes 

68439-57-6 Alkyl (C14-C16) olefin sulfonate, sodium salt 

9016-45-9 Alkylphenol ethoxylate surfactants 

1327-41-9 Aluminum chloride 

68155-07-7 Amides, C8-18 and C19-Unsatd., N,N-Bis(hydroxyethyl) 

73138-27-9 Amines, C12-14-tert-alkyl, ethoxylated 

71011-04-6 Amines, Ditallow alkyl, ethoxylated 

68551-33-7 Amines, tallow alkyl, ethoxylated, acetates 

1336-21-6 Ammonia 

631-61-8 Ammonium acetate 

68037-05-8 Ammonium Alcohol Ether Sulfate 

7783-20-2 Ammonium bisulfate 

10192-30-0 Ammonium Bisulphite 

12125-02-9 Ammonium Chloride 

7632-50-0 Ammonium citrate 

37475-88-0 Ammonium Cumene Sulfonate 

1341-49-7 Ammonium hydrogen-difluoride 

6484-52-2 Ammonium nitrate 
2-8

CAS Number7 Chemical Constituent 

7727-54-0 Ammonium Persulfate / Diammonium peroxidisulphate 

1762-95-4 Ammonium Thiocyanate 

7664-41-7 Aqueous ammonia 

12174-11-7 Attapulgite Clay 

121888-68-4 Bentonite, benzyl(hydrogenated tallow alkyl) dimethylammonium stearate 

complex / organophilic clay 

71-43-2 Benzene 

119345-04-9 Benzene, 1,1'-oxybis, tetratpropylene derivatives, sulfonated, sodium salts 

74153-51-8 Benzenemethanaminium, N,N-dimethyl-N-[2-[(1-oxo-2-

propenyl)oxy]ethyl]-, chloride, polymer with 2-propenamide 

122-91-8 Benzenemethanol,4-methoxy-, 1-formate 

1300-72-7 Benzenesulfonic acid, Dimethyl-, Sodium salt /Sodium xylene sulfonate 

140-11-4 Benzyl acetate 

76-22-2 Bicyclo (2.2.1) heptan-2-one, 1,7,7-trimethyl68153-72-0 Blown lard oil amine 

68876-82-4 Blown rapeseed amine 

1319-33-1 Borate Salt 

10043-35-3 Boric acid 

1303-86-2 Boric oxide / Boric Anhydride 

71-36-3 Butan-1-ol 

68002-97-1 C10 - C16 Ethoxylated Alcohol 

68131-39-5 C12-15 Alcohol, Ethoxylated 

1317-65-3 Calcium Carbonate 

10043-52-4 Calcium chloride 

1305-62-0 Calcium Hydroxide 

1305-79-9 Calcium Peroxide 

124-38-9 Carbon Dioxide 

68130-15-4 Carboxymethylhydroxypropyl guar 

9012-54-8 Cellulase / Hemicellulase Enzyme 

9004-34-6 Cellulose 

10049-04-4 Chlorine Dioxide 

78-73-9 Choline Bicarbonate 

67-48-1 Choline Chloride 

91-64-5 Chromen-2-one 

77-92-9 Citric Acid 

94266-47-4 Citrus Terpenes 

61789-40-0 Cocamidopropyl Betaine 

68155-09-9 Cocamidopropylamine Oxide 

68424-94-2 Coco-betaine 

7758-98-7 Copper (II) Sulfate 

14808-60-7 Crystalline Silica (Quartz) 

7447-39-4 Cupric chloride dihydrate 

1490-04-6 Cyclohexanol,5-methyl-2-(1-methylethyl) 

8007-02-1 Cymbopogon citratus leaf oil 

8000-29-1 Cymbopogon winterianus jowitt oil 
2-9

CAS Number7 Chemical Constituent 

1120-24-7 Decyldimethyl Amine 

2605-79-0 Decyl-dimethyl Amine Oxide 

3252-43-5 Dibromoacetonitrile 

25340-17-4 Diethylbenzene 

111-46-6 Diethylene Glycol 

22042-96-2 Diethylenetriamine penta (methylenephonic acid) sodium salt 

28757-00-8 Diisopropyl naphthalenesulfonic acid 

68607-28-3 Dimethylcocoamine, bis(chloroethyl) ether, diquaternary ammonium salt 

7398-69-8 Dimethyldiallylammonium chloride 

25265-71-8 Dipropylene glycol 

34590-94-8 Dipropylene Glycol Methyl Ether 

139-33-3 Disodium Ethylene Diamine Tetra Acetate 

64741-77-1 Distillates, petroleum, light hydrocracked 

5989-27-5 D-Limonene 

123-01-3 Dodecylbenzene 

27176-87-0 Dodecylbenzene sulfonic acid 

42504-46-1 Dodecylbenzenesulfonate isopropanolamine

50-70-4 D-Sorbitol / Sorbitol 

37288-54-3 Endo-1,4-beta-mannanase, or Hemicellulase 

149879-98-1 Erucic Amidopropyl Dimethyl Betaine 

89-65-6 Erythorbic acid, anhydrous 

54076-97-0 Ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2-propenyl)oxy]-, chloride, 

homopolymer 

107-21-1 Ethane-1,2-diol / Ethylene Glycol 

111-42-2 Ethanol, 2,2-iminobis26027-38-3 Ethoxylated 4-nonylphenol 

9002-93-1 Ethoxylated 4-tert-octylphenol 

68439-50-9 Ethoxylated alcohol 

126950-60-5 Ethoxylated alcohol 

67254-71-1 Ethoxylated alcohol (C10-12) 

68951-67-7 Ethoxylated alcohol (C14-15) 

68439-46-3 Ethoxylated alcohol (C9-11) 

66455-15-0 Ethoxylated Alcohols 

84133-50-6 Ethoxylated Alcohols (C12-14 Secondary) 

68439-51-0 Ethoxylated Alcohols (C12-14) 

78330-21-9 Ethoxylated branch alcohol 

34398-01-1 Ethoxylated C11 alcohol 

78330-21-8 Ethoxylated C11-14-iso, C13-rich alcohols 

61791-12-6 Ethoxylated Castor Oil 

61791-29-5 Ethoxylated fatty acid, coco 

61791-08-0 Ethoxylated fatty acid, coco, reaction product with ethanolamine 

68439-45-2 Ethoxylated hexanol 

9036-19-5 Ethoxylated octylphenol 

9005-67-8 Ethoxylated Sorbitan Monostearate 

9005-70-3 Ethoxylated Sorbitan Trioleate 
2-10

CAS Number7 Chemical Constituent 

118-61-6 Ethyl 2-hydroxybenzoate 

64-17-5 Ethyl alcohol / ethanol 

100-41-4 Ethyl Benzene 

93-89-0 Ethyl benzoate 

97-64-3 Ethyl Lactate 

9003-11-6 Ethylene Glycol-Propylene Glycol Copolymer (Oxirane, methyl-, polymer 

with oxirane) 

75-21-8 Ethylene oxide 

5877-42-9 Ethyloctynol 

8000-48-4 Eucalyptus globulus leaf oil 

61790-12-3 Fatty Acids 

68604-35-3 Fatty acids, C 8-18 and C18-unsaturated compounds with diethanolamine 

68188-40-9 Fatty acids, tall oil reaction products w/ acetophenone, formaldehyde & 

thiourea 

9043-30-5 Fatty alcohol polyglycol ether surfactant

7705-08-0 Ferric chloride 

7782-63-0 Ferrous sulfate, heptahydrate 

50-00-0 Formaldehyde 

29316-47-0 Formaldehyde polymer with 4,1,1-dimethylethyl phenolmethyl oxirane 

153795-76-7 Formaldehyde, polymers with branched 4-nonylphenol, ethylene oxide and 

propylene oxide 

75-12-7 Formamide 

64-18-6 Formic acid 

110-17-8 Fumaric acid 

65997-17-3 Glassy calcium magnesium phosphate 

111-30-8 Glutaraldehyde 

56-81-5 Glycerol / glycerine 

9000-30-0 Guar Gum 

64742-94-5 Heavy aromatic petroleum naphtha 

9025-56-3 Hemicellulase 

7647-01-0 Hydrochloric Acid / Hydrogen Chloride / muriatic acid 

7722-84-1 Hydrogen Peroxide 

64742-52-5 Hydrotreated heavy napthenic (petroleum) distillate 

79-14-1 Hydroxy acetic acid 

35249-89-9 Hydroxyacetic acid ammonium salt 

9004-62-0 Hydroxyethyl cellulose 

5470-11-1 Hydroxylamine hydrochloride 

39421-75-5 Hydroxypropyl guar 

35674-56-7 Isomeric Aromatic Ammonium Salt 

64742-88-7 Isoparaffinic Petroleum Hydrocarbons, Synthetic 

64-63-0 Isopropanol 

98-82-8 Isopropylbenzene (cumene) 

68909-80-8 Isoquinoline, reaction products with benzyl chloride and quinoline 

8008-20-6 Kerosene 

64742-81-0 Kerosine, hydrodesulfurized 
2-11

CAS Number7 Chemical Constituent 

63-42-3 Lactose 

8022-15-9 Lavandula hybrida abrial herb oil 

64742-95-6 Light aromatic solvent naphtha 

1120-21-4 Light Paraffin Oil 

546-93-0 Magnesium Carbonate 

1309-48-4 Magnesium Oxide 

1335-26-8 Magnesium Peroxide 

14807-96-6 Magnesium Silicate Hydrate (Talc) 

1184-78-7 methanamine, N,N-dimethyl-, N-oxide 

67-56-1 Methanol 

119-36-8 Methyl 2-hydroxybenzoate 

68891-11-2 Methyloxirane polymer with oxirane, mono (nonylphenol) ether, branched 

8052-41-3 Mineral spirits / Stoddard Solvent 

64742-46-7 Mixture of severely hydrotreated and hydrocracked base oil 

141-43-5 Monoethanolamine 

44992-01-0 N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy Ethanaminium chloride 

64742-48-9 Naphtha (petroleum), hydrotreated heavy 

91-20-3 Naphthalene 

38640-62-9 Naphthalene bis(1-methylethyl) 

93-18-5 Naphthalene, 2-ethoxy68909-18-2 N-benzyl-alkyl-pyridinium chloride 

68139-30-0 N-Cocoamidopropyl-N,N-dimethyl-N-2-hydroxypropylsulfobetaine 

7727-37-9 Nitrogen, Liquid form 

68412-54-4 Nonylphenol Polyethoxylate 

8000-27-9 Oils, cedarwood 

121888-66-2 Organophilic Clays 

628-63-7 Pentyl acetate 

540-18-1 Pentyl butanoate 

8009-03-8 Petrolatum 

64742-65-0 Petroleum Base Oil 

64741-68-0 Petroleum naphtha 

101-84-8 Phenoxybenzene 

70714-66-8 Phosphonic acid, [[(phosphonomethyl)imino]bis[2,1-

ethanediylnitrilobis(methylene)]]tetrakis-, ammonium salt 

8000-41-7 Pine Oil 

8002-09-3 Pine Oils 

60828-78-6 Poly(oxy-1,2-ethanediyl), a-[3,5-dimethyl-1-(2-methylpropyl)hexyl]-whydroxy25322-68-3 Poly(oxy-1,2-ethanediyl), a-hydro-w-hydroxy / Polyethylene Glycol 

31726-34-8 Poly(oxy-1,2-ethanediyl), alpha-hexyl-omega-hydroxy 

24938-91-8 Poly(oxy-1,2-ethanediyl), α-tridecyl-ω-hydroxy9004-32-4 Polyanionic Cellulose 

51838-31-4 Polyepichlorohydrin, trimethylamine quaternized 

56449-46-8 Polyethlene glycol oleate ester 

9046-01-9 Polyethoxylated tridecyl ether phosphate 
2-12

CAS Number7 Chemical Constituent 

63428-86-4 Polyethylene glycol hexyl ether sulfate, ammonium salt 

62649-23-4 Polymer with 2-propenoic acid and sodium 2-propenoate 

9005-65-6 Polyoxyethylene Sorbitan Monooleate 

61791-26-2 Polyoxylated fatty amine salt 

65997-18-4 Polyphosphate 

127-08-2 Potassium acetate 

12712-38-8 Potassium borate 

1332-77-0 Potassium borate 

20786-60-1 Potassium Borate 

584-08-7 Potassium carbonate 

7447-40-7 Potassium chloride 

590-29-4 Potassium formate 

1310-58-3 Potassium Hydroxide 

13709-94-9 Potassium metaborate 

24634-61-5 Potassium Sorbate 

112926-00-8 Precipitated silica / silica gel 

57-55-6 Propane-1,2-diol, or Propylene glycol 

107-98-2 Propylene glycol monomethyl ether 

68953-58-2 Quaternary Ammonium Compounds 

62763-89-7 Quinoline,2-methyl-, hydrochloride 

15619-48-4 Quinolinium, 1-(phenylmethl),chloride 

8000-25-7 Rosmarinus officinalis l. leaf oil 

7631-86-9 Silica, Dissolved 

5324-84-5 Sodium 1-octanesulfonate 

127-09-3 Sodium acetate 

95371-16-7 Sodium Alpha-olefin Sulfonate 

532-32-1 Sodium Benzoate 

144-55-8 Sodium bicarbonate 

7631-90-5 Sodium bisulfate 

7647-15-6 Sodium Bromide 

497-19-8 Sodium carbonate 

7647-14-5 Sodium Chloride 

7758-19-2 Sodium chlorite 

3926-62-3 Sodium Chloroacetate 

68-04-2 Sodium citrate 

6381-77-7 Sodium erythorbate / isoascorbic acid, sodium salt 

2836-32-0 Sodium Glycolate 

1310-73-2 Sodium Hydroxide 

1301-73-2 Sodium hydroxide 

7681-52-9 Sodium hypochlorite 

7775-19-1 Sodium Metaborate .8H2O 

10486-00-7 Sodium perborate tetrahydrate 

7775-27-1 Sodium persulphate 

68608-26-4 Sodium petroleum sulfonate 

9003-04-7 Sodium polyacrylate 
2-13

CAS Number7 Chemical Constituent 

7757-82-6 Sodium sulfate 

1303-96-4 Sodium tetraborate decahydrate 

7772-98-7 Sodium Thiosulfate 

1338-43-8 Sorbitan Monooleate 

57-50-1 Sucrose 

5329-14-6 Sulfamic acid 

68442-77-3 Surfactant: Modified Amine 

112945-52-5 Syntthetic Amorphous / Pyrogenic Silica / Amorphous Silica 

68155-20-4 Tall Oil Fatty Acid Diethanolamine 

8052-48-0 Tallow fatty acids sodium salt 

72780-70-7 Tar bases, quinoline derivs., benzyl chloride-quaternized 

68647-72-3 Terpene and terpenoids 

68956-56-9 Terpene hydrocarbon byproducts 

533-74-4 Tetrahydro-3,5-dimethyl-2H-1,3,5-thiadiazine-2-thione /Dazomet 

55566-30-8 Tetrakis(hydroxymethyl)phosphonium sulfate (THPS) 

75-57-0 Tetramethyl ammonium chloride 

64-02-8 Tetrasodium Ethylenediaminetetraacetate 

68-11-1 Thioglycolic acid 

62-56-6 Thiourea 

68527-49-1 Thiourea, polymer with formaldehyde and 1-phenylethanone 

68917-35-1 Thuja plicata donn ex. D. don leaf oil 

108-88-3 Toluene 

81741-28-8 Tributyl tetradecyl phosphonium chloride

68299-02-5 Triethanolamine hydroxyacetate 

112-27-6 Triethylene Glycol 

52624-57-4 Trimethylolpropane, Ethoxylated, Propoxylated 

150-38-9 Trisodium Ethylenediaminetetraacetate 

5064-31-3 Trisodium Nitrilotriacetate 

7601-54-9 Trisodium ortho phosphate 

57-13-6 Urea 

25038-72-6 Vinylidene Chloride/Methylacrylate Copolymer 

7732-18-5 Water 

8042-47-5 White Mineral Oil 

11138-66-2 Xanthan gum 

1330-20-7 Xylene 

13601-19-9 Yellow Sodium of Prussiate 

Chemical Constituent

 Aliphatic acids 

 Aliphatic alcohol glycol ether 

 Alkyl Aryl Polyethoxy Ethanol 

 Alkylaryl Sulfonate 

 Anionic copolymer 

 Aromatic hydrocarbons 

 Aromatic ketones 
2-14

Chemical Constituent

 Oxyalkylated alkylphenol 

 Petroleum distillate blend 

 Polyethoxylated alkanol 

 Polymeric Hydrocarbons 

 Salt of amine-carbonyl condensate 

 Salt of fatty acid/polyamine reaction product 

 Sugar 

 Surfactant blend 

 Triethanolamine 

2.5 Selection of Additives 

Information available from well operators, service companies, and chemical suppliers 

indicate that there are a number of breakers, biocides, clay stabilizes, etc. that may be 

selected for any hydraulic fracturing operation. The different product options may not be 

interchangeable because of undesirable chemical reactions that may occur between different 

classes of chemicals. The actual selection of additives is somewhat driven by the specific 

operation. 

Operators have been required to divulge the types of additives, product names, specific 

chemical constituents, and chemical formulas to be used in a hydraulic fracturing operation 

before NYSDEC will issue a well permit. The fact that such information is often considered 

proprietary does not prevent the NYSDEC from requiring full-disclosure of this information. 

The handling of any information submitted to the NYSDEC and claimed to be a trade secret 

is governed by the New York State Public Officer’s Law and the Department’s Records 

Access Regulations. 

2.6 Additives Sequence 

Several types of additives may be used in a single well; however, they are not used at the 

same time. The additives are sequenced to elicit a specific fracturing fluid characteristic at 

different phases of the operation. A typical sequence may include the following: 

 Phase 1: Corrosion inhibitors, iron controls and acids are used in the initial stage to 

reduce rust formation on steel tubing, well casings, tools, and tanks [5]; to prevent 

precipitation of metal oxides which could plug the shale; and to improve fluid access into 

the formation, respectively. 

 Phase 2: Gelling agent, crosslinker, and other additives are used in the second stage to 

improve the fracturing fluid’s capacity (typically by increasing viscosity) to carry 

proppant into the fractures. In addition, bactericide/biocide would be used to prevent the 

growth of bacteria, which can reduce the ability of the fluid to carry proppant into the 

fractures [6]. 
2-15

 Phase 3: Once the proppant is conveyed to the formation, the proppant needs to be 

released into the formation. Therefore a breaker is used to reduce the viscosity of the 

fluid and release the proppant within the fractures and to enhance the recovery of the 

fracturing fluid. Use of friction reducers allows fracturing fluids to be injected at 

optimum rates. Biocides are also used in this stage to inhibit the growth of organisms that 

could potentially produce gases such as hydrogen sulfide that could contaminate natural 

gas. A clay stabilizer may be used to prevent swelling and migration of formation clays 

which could block pore spaces. 

Not all types of additives are used in a single well. The combination of additives and specific 

chemicals used would depend on the particular shale, well and well operator / service 

company. 

2.7 Summary 

Large volumes of water and proppant are used in hydraulic fracturing operations. Small 

quantities of several additives are used to facilitate and enhance fracturing. This section 

identified 13 classes of additives that may be used in shale fracturing. These 13 classes may 

encompass over one thousand chemicals used around the globe. Table 2-2 lists the primary 

constituents found in approximately 230 products used or proposed for use in hydraulic 

fracturing operations in New York. 
3-1

3 FLOWBACK FLUIDS 

3.1 Introduction 

Flowback is one of several waste fluids generated from a gas well. Waste fluids from a gas 

well may be grouped into several categories: top-hole fluids; bottom hole fluids; stimulation 

fluids; and production fluids [7]. 

 Top-hole fluids consist of ‘waste’ fluids generated due to fresh water aquifers that may be 

encountered within the first few hundred feet of drilling. Top-hole fluids do not 

intermingle within the well bore the way bottom hole and stimulation fluids do. 

 Bottom-hole fluids typically consist of fluids generated due to deep salt water zones 

encountered. 

 Stimulation / fracturing fluids are waste fluids generated due to the water, proppants and 

other additives pumped into the shale to improve gas recovery. 

 Production fluids (or Produced Water) are the waste fluids produced with natural gas 

after the well is put into production; their composition is typically similar to bottom hole 

fluids. 

The flowback fluids discussed in this section consist mostly of stimulation fluids and bottomhole fluids. 

3.2 Flowback Fluid Volume 

The volume of flowback fluid from a gas well depends on a variety of factors, including the 

particular shale, the depth and age of the well, and the drilling technique (horizontal vs. 

vertical). 

Typical water usage for hydraulic fracturing is approximately 1.5 million gallons (MG) per 

vertical well and between 2.5 and 5 MG per horizontal well. Limited data indicate that water 

usage may be as little as 0.5 MG or as much as 3 million gallons (MG) per vertical well and 

as much as 6 MG per horizontal well. 

Based on limited data reported to NYSDEC and information from operators in Pennsylvania, 

flowback from Marcellus Shale operations, which includes both vertical and horizontal wells, 

is approximately 20 – 35 percent of fracturing fluids used8, with up to 85 percent from a 

vertical well, and between 10 and 50 percent from horizontal wells reported [9]. 

 

8

 Typical flowback from operations based in Marcellus Shale, as estimated by URS Corporation. These values 

are consistent with those reported in the MSC Study [9]. 
3-2

3.3 Trends in Flowback Fluid Volume 

Flowback occurs over 2-3 weeks after fracturing, and the flowback rate changes with time; 

the actual rate may depend on a variety of factors. Limited time-series data indicates that 

approximately 60 percent of the total flowback occurs in the first four days after fracturing. 

After day 4, the daily flowback rate declines sharply to between approximately 2 – 5 percent 

of the total flowback for approximately 2 weeks. 

3.4 Flowback Fluid Composition 

Flowback fluids include the fracturing fluids pumped into the well, and consist of water and 

additives discussed in the previous section, any new compounds that may have formed due to 

reactions between additives, and substances mobilized from within the shale formation due to 

the fracturing operation. Some portion of the proppant may return to the surface with 

flowback, but operators strive to minimize proppant return: the ultimate goal of hydraulic 

fracturing is to convey and deposit the proppant within fractures in the shale to maximize gas 

flow. 

Marcellus Shale is of marine origin and, therefore, contains high levels of salt [5]. This is 

further evidenced by analytical results of flowback provided to NYSDEC by well operators 

from operations based in Pennsylvania. The results were in different levels of detail. Some 

companies provided analytical results for one day for several wells, while other companies 

provided several analytical results for multiple days of the same well (i.e. time-series). 

Flowback parameters were organized by Chemicals Abstract Service (CAS) number, 

whenever available. 

Typical classes of parameters present in flowback fluid are [1 and 8]: 

 Dissolved Solids (chlorides, sulfates, and calcium)

 Metals (calcium, magnesium, barium, strontium) 

 Suspended solids 

 Mineral scales (calcium carbonate and barium sulfate) 

 Bacteria - acid producing bacteria and sulfate reducing bacteria 

 Friction Reducers 

 Iron solids (iron oxide and iron sulfide) 

 Dispersed clay fines, colloids, and silts 

 Acid Gases (carbon dioxide, hydrogen sulfide) 

A list of parameters detected in a limited set of analytical results is provided in Table 3-1. 

Typical concentrations of parameters, based on limited data from PA and WV, are provided 

in Table 4-6. 
3-3

Table 3-1 - Parameters present in a limited set of flowback analytical results9

CAS Number Parameters Detected in Flowback from PA and WV Operations 

00087-61-6 1,2,3-Trichlorobenzene 

00095-63-6 1,2,4-Trimethylbenzene 

00108-67-8 1,3,5-Trimethylbenzene 

00105-67-9 2,4-Dimethylphenol 

00087-65-0 2,6-Dichlorophenol 

00078-93-3 2-Butanone / Methyl ethyl ketone 

00091-57-6 2-Methylnaphthalene 

00095-48-7 2-Methylphenol 

109-06-8 2-Picoline (2-methyl pyridine) 

00067-63-0 2-Propanol / Isopropyl Alcohol / Isopropanol / Propan-2-ol 

00108-39-4 3-Methylphenol 

00106-44-5 4-Methylphenol 

00072-55-9 4,4 DDE 

00057-97-6 7,12-Dimethylbenz(a)anthracene 

00064-19-7 Acetic acid 

00067-64-1 Acetone 

00098-86-2 Acetophenone 

00107-13-1 Acrylonitrile 

00309-00-2 Aldrin 

07439-90-5 Aluminum 

07440-36-0 Antimony 

07664-41-7 Aqueous ammonia 

12672-29-6 Aroclor 1248 

07440-38-2 Arsenic 

07440-39-3 Barium 

00071-43-2 Benzene 

00050-32-8 Benzo(a)pyrene 

00205-99-2 Benzo(b)fluoranthene 

191-24-2 Benzo(ghi)perylene 

00207-08-9 Benzo(k)fluoranthene 

00100-51-6 Benzyl alcohol 

07440-41-7 Beryllium 

00111-44-4 Bis(2-Chloroethyl) ether 

00117-81-7 Bis(2-ethylhexyl)phthalate / Di (2-ethylhexyl) phthalate 

07440-42-8 Boron 

24959-67-9 Bromide 

00075-25-2 Bromoform 

07440-43-9 Cadmium 

07440-70-2 Calcium 

00124-38-9 Carbon Dioxide 

00075-15-0 Carbondisulfide 

00124-48-1 Chlorodibromomethane 

00067-66-3 Chloroform 

 

9

 This parameter list is a compilation of flowback analytical results provided to NYSDEC by service companies 

with operations in PA and/or WV. 
3-4

CAS Number Parameters Detected in Flowback from PA and WV Operations 

07440-47-3 Chromium 

07440-48-4 Cobalt 

07440-50-8 Copper 

00057-12-5 Cyanide 

00319-85-7 Cyclohexane (beta BHC) 

00058-89-9 Cyclohexane (gamma BHC) 

00055-70-3 Dibenz(a,h)anthracene 

00075-27-4 Dichlorobromomethane 

00084-74-2 Di-n-butyl phthalate 

00122-39-4 Diphenylamine 

00959-98-8 Endosulfan I 

33213-65-9 Endosulfan II 

07421-93-4 Endrin aldehyde 

00107-21-1 Ethane-1,2-diol / Ethylene Glycol 

00100-41-4 Ethyl Benzene 

00206-44-0 Fluoranthene 

00086-73-7 Fluorene 

16984-48-8 Fluoride 

00076-44-8 Heptachlor 

01024-57-3 Heptachlor epoxide 

00193-39-5 Indeno(1,2,3-cd)pyrene 

07439-89-6 Iron 

00098-82-8 Isopropylbenzene (cumene) 

07439-92-1 Lead 

07439-93-2 Lithium 

07439-95-4 Magnesium 

07439-96-5 Manganese 

07439-97-6 Mercury 

00067-56-1 Methanol 

00074-83-9 Methyl Bromide 

00074-87-3 Methyl Chloride 

07439-98-7 Molybdenum 

00091-20-3 Naphthalene 

07440-02-0 Nickel 

00086-30-6 N-Nitrosodiphenylamine 

00085-01-8 Phenanthrene 

00108-95-2 Phenol 

57723-14-0 Phosphorus 

07440-09-7 Potassium 

00057-55-6 Propylene glycol 

00110-86-1 Pyridine 

00094-59-7 Safrole 

07782-49-2 Selenium 

07440-22-4 Silver 

07440-23-5 Sodium 

07440-24-6 Strontium 

14808-79-8 Sulfate 

14265-45-3 Sulfite 

00127-18-4 Tetrachloroethylene 
3-5

CAS Number Parameters Detected in Flowback from PA and WV Operations 

07440-28-0 Thallium 

07440-32-6 Titanium 

00108-88-3 Toluene 

07440-62-2 Vanadium 

07440-66-6 Zinc 

 2-Picoline 

 Alkalinity 

 Alkalinity, Carbonate, as CaCO3 

 Alpha radiation 

 Aluminum, Dissolved 

 Barium Strontium P.S. 

 Barium, Dissolved 

 Beta radiation 

 Bicarbonates 

 Biochemical Oxygen Demand 

 Cadmium, Dissolved 

 Calcium, Dissolved 

 Cesium 137 

 Chemical Oxygen Demand 

 Chloride 

 Chromium (VI) 

 Chromium (VI), dissolved 

 Chromium, (III) 

 Chromium, Dissolved 

 Cobalt, dissolved 

 Coliform 

 Color 

 Conductivity 

 Hardness 

 Heterotrophic plate count 

 Iron, Dissolved 

 Lithium, Dissolved 

 Magnesium, Dissolved 

 Manganese, Dissolved 

 Nickel, Dissolved 

 Nitrate, as N 

 Nitrogen, Total as N 

 Oil and Grease 

 Petroleum hydrocarbons 

 pH 

 Phenols 

 Potassium, Dissolved 

 Radium 

 Radium 226 

 Radium 228 

 Salt 

 Scale Inhibitor 

 Selenium, Dissolved 

 Silver, Dissolved 
3-6

CAS Number Parameters Detected in Flowback from PA and WV Operations 

 Sodium, Dissolved 

 Strontium, Dissolved 

 Sulfide 

 Surfactants 

 Total Alkalinity 

 Total Dissolved Solids 

 Total Kjeldahl Nitrogen 

 Total Organic Carbon 

 Total Suspended Solids 

 Volatile Acids 

 Xylenes 

 Zinc, Dissolved 

 Zirconium 

Note that the parameters listed in Table 2-2 are based on the composition of additives used or 

proposed for use in New York. Table 3-1 parameters are based on analytical results of 

flowback from operations in Pennsylvania or West Virginia. 

The information in the above table is from operations in the Marcellus Shale, but they are not 

from a single comprehensive study. Table 3-1 data are based on analyses performed by 

different laboratories; most operators provided only one sample/analysis per well, a few 

operators provided time-series samples for a single well; the different samples were analyzed 

for various parameters with some overlap of parameters. Even though the data are not strictly 

comparable, they provide valuable insight on the potential composition of flowback at New 

York operations. 

3.4.1 Marcellus Shale Coalition Report on Flowback 

Recognizing the dearth of comparable flowback information within the Marcellus Shale, the 

Marcellus Shale Coalition (MSC) facilitated a more rigorous study in 2009 [9]. The study: 

 Gathered and analyzed flowback samples from 19 gas well sites (names A through S) 

in Pennsylvania or West Virginia. 

 Took samples at different points in time, typically of the influent water stream, and 

flowback water streams 1, 5, 14 and 90 days after stimulating the well. In addition, 

the water supply and the fracturing fluid (referred to as Day 0) were also sampled at a 

few locations. 

 Included both vertical and horizontal wells. 

 All samples were collected by a single contractor. 

 All analyses were performed by a single laboratory.

 Sought input from regulatory agencies in Pennsylvania and West Virginia. 

 Most samples were analyzed for conventional parameters: metals; volatile organic 

compounds (VOCs); semi-volatile organic compounds (SVOCs); organochlorine 

pesticides; polychlorinated biphenyls (PCBs); an organophosphorus pesticide; 
3-7

alcohols; glycols; and acids. The specific parameters analyzed in the MSC report are 

listed by class as follows: 

> 29 conventional parameters in Table 3-2 

> 59 total or dissolved metals in Table 3-3 

> 70 VOCs in Table 3-4 

> 107 SVOCs in Table 3-5 

> 20 organochlorine pesticides in Table 3-6 

> 7 PCB arochlors in Table 3-7 

> 1 organophosphorus pesticide in Table 3-8 

> 5 alcohols in Table 3-9 

> 2 glycols in Table 3-10, and 

> 4 acids in Table 3-11 

Table 3-2 - Conventional analyses in MSC Study 

Acidity Nitrate as N Total phosphorus 

Amenable cyanide Nitrate-nitrite Total suspended solids 

Ammonia nitrogen Nitrite as N Turbidity 

Biochemical oxygen demand Oil & grease (HEM) Total cyanide 

Bromide Specific conductance Total sulfide 

Chemical oxygen demand (COD) Sulfate pH 

Chloride TOC Total recoverable phenolics 

Dissolved organic carbon Total alkalinity Sulfite 

Fluoride Total dissolved solids MBAS (mol.wt 320) 

Hardness, as CaCO3 Total Kjeldahl nitrogen 

Table 3-3 - Total and dissolved metals analyzed in MSC Study 

Aluminum Copper Silver 

Aluminum-dissolved Copper-dissolved Silver-dissolved 

Antimony Iron Sodium 

Antimony-dissolved Iron-dissolved Sodium-dissolved 

Arsenic Lead Strontium 

Arsenic-dissolved Lead-dissolved Strontium-dissolved 

Barium Lithium Thallium 

Barium-dissolved Lithium-dissolved Thallium-dissolved 

Beryllium Magnesium Tin 

Beryllium-dissolved Magnesium-dissolved Tin-dissolved 

Boron Manganese Titanium 

Boron-dissolved Manganese-dissolved Titanium-dissolved 

Cadmium Molybdenum Trivalent chromium 

Cadmium-dissolved Molybdenum-dissolved Zinc 

Calcium Nickel Zinc-dissolved 

Calcium-dissolved Nickel-dissolved Hexavalent chromium-dissolved 

Chromium Potassium Hexavalent chromium 

Chromium-dissolved Potassium-dissolved Mercury 

Cobalt Selenium Mercury-dissolved 

Cobalt-dissolved Selenium-dissolved 
3-8

Table 3-4 - Volatile Organic Compounds analyzed in MSC Study 

1,1,1,2-Tetrachloroethane 2-Chloroethyl vinyl ether Ethylbenzene 

1,1,1-Trichloroethane 2-Hexanone Isopropylbenzene 

1,1,2,2-Tetrachloroethane 4-Chlorotoluene Methyl tert-butyl ether (MTBE) 

1,1,2-Trichloroethane 4-Methyl-2-pentanone (MIBK) Methylene chloride 

1,1-Dichloroethane Acetone Naphthalene 

1,1-Dichloroethene Acrolein n-Butylbenzene 

1,1-Dichloropropene Acrylonitrile n-Propylbenzene 

1,2,3-Trichlorobenzene Benzene p-Isopropyltoluene 

1,2,3-Trichloropropane Benzyl chloride sec-Butylbenzene 

1,2,4-Trichlorobenzene Bromobenzene Styrene 

1,2,4-Trimethylbenzene Bromodichloromethane tert-butyl acetate 

1,2-Dibromo-3-chloropropane Bromoform tert-Butylbenzene 

1,2-Dibromoethane (EDB) Bromomethane Tetrachloroethene 

1,2-Dichlorobenzene Carbon disulfide tetrahydrofuran 

1,2-Dichloroethane Carbon tetrachloride Toluene 

1,2-Dichloropropane Chlorobenzene trans-1,2-Dichloroethene 

1,3,5-Trimethylbenzene Chloroethane trans-1,3-Dichloropropene 

1,3-Dichlorobenzene Chloroform Trichloroethene 

1,3-Dichloropropane Chloromethane Trichlorofluoromethane 

1,4-Dichlorobenzene cis-1,2-Dichloroethene Vinyl acetate 

1,4-Dioxane cis-1,3-Dichloropropene Vinyl chloride 

1-chloro-4-

trifluoromethylbenzene 

Dibromochloromethane Xylenes (total) 

2,2-Dichloropropane Dibromomethane 

2-Butanone Dichlorodifluoromethane 
3-9

Table 3-5 - Semi-Volatile Organics analyzed in MSC Study 

1,2,4,5-Tetrachlorobenzene 7,12-Dimethylbenz(a)anthracene Hexachlorocyclopentadiene 

1,2-Diphenylhydrazine Acenaphthene Hexachloroethane

1,3-Dinitrobenzene Acenaphthylene Hexachloropropene

1,4-Naphthoquinone Acetophenone Indeno(1,2,3-cd)pyrene 

1-Naphthylamine Aniline Isodrin 

2,3,4,6-Tetrachlorophenol Aramite Isophorone 

2,3,7,8-TCDD Benzidine Isosafrole 

2,4,5-Trichlorophenol Benzo(a)anthracene Methyl methanesulfonate 

2,4,6-Trichlorophenol Benzo(a)pyrene Nitrobenzene 

2,4-Dimethylphenol Benzo(b)fluoranthene N-Nitrosodiethylamine 

2,4-Dinitrophenol Benzo(ghi)perylene N-Nitrosodimethylamine 

2,4-Dinitrotoluene Benzo(k)fluoranthene N-Nitrosodi-n-butylamine 

2,6-Dichlorophenol Benzyl alcohol N-Nitrosodi-n-propylamine 

2,6-Dinitrotoluene bis(2-Chloroethoxy)methane N-Nitrosodiphenylamine 

2-Acetylaminofluorene bis(2-Chloroethyl) ether N-Nitrosomethylethylamine 

2-Chloronaphthalene bis(2-Chloroisopropyl) ether N-Nitrosomorpholine 

2-Chlorophenol bis(2-Ethylhexyl) phthalate N-Nitrosopiperidine 

2-Methylnaphthalene Butyl benzyl phthalate N-Nitrosopyrrolidine 

2-Methylphenol Chlorobenzilate O,O,O-Triethyl phosphorothioate 

2-Naphthylamine Chrysene o-Toluidine 

2-Nitroaniline Diallate Parathion 

2-Nitrophenol Dibenz(a,h)anthracene p-Dimethylaminoazobenzene 

2-Picoline Dibenzofuran Pentachlorobenzene 

3,3'-Dichlorobenzidine Diethyl phthalate Pentachloroethane 

3-Methylcholanthrene Dimethoate Pentachloronitrobenzene 

3-Methylphenol & 4-

Methylphenol 

Dimethyl phthalate Pentachlorophenol 

3-Nitroaniline Di-n-butyl phthalate Phenanthrene 

4,6-Dinitro-2-methylphenol Di-n-octyl phthalate Phenol 

4-Aminobiphenyl Dinoseb Phorate 

4-Bromophenyl phenyl ether Diphenylamine Pronamide 

4-Chloro-3-methylphenol Disulfoton Pyrene 

4-Chloroaniline Ethyl methanesulfonate Pyridine 

4-Chlorophenyl phenyl ether Fluoranthene Safrole 

4-Nitroaniline Fluorene Thionazin 

4-Nitrophenol Hexachlorobenzene Tetraethyldithiopyrophosphate 

5-Nitro-o-toluidine Hexachlorobutadiene 

Table 3-6 - Organochlorine pesticides analyzed in MSC Study 

4,4'-DDD delta-BHC Endrin ketone 

4,4'-DDE Dieldrin gamma-BHC (Lindane) 

4,4'-DDT Endosulfan I Heptachlor 

Aldrin Endosulfan II Heptachlor epoxide 

alpha-BHC Endosulfan sulfate Methoxychlor 

beta-BHC Endrin Toxaphene 

Chlordane Endrin aldehyde 
3-10

Table 3-7 – PCBs analyzed in MSC Study 

Aroclor 1016 Aroclor 1242 Aroclor 1260 

Aroclor 1221 Aroclor 1248 

Aroclor 1232 Aroclor 1254 

Table 3-8 - Organophosphorus Pesticides analyzed in MSC Study 

Ethyl parathion 

Table 3-9 - Alcohols analyzed in MSC Study 

2-Propanol Ethanol n-Propanol 

Butyl alcohol Methanol 

Table 3-10 – Glycols analyzed in MSC Study 

Ethylene glycol 

Propylene glycol 

Table 3-11 – Acids analyzed in MSC Study 

Acetic acid Propionic acid 

Butyric acid Volatile acids 

Table 3-12 is a summary of parameter classes analyzed for (shown with a “•”) at each well 

site. Table 3-13 is a summary of parameters detected at quantifiable levels. The check mark 

(√) indicates that several samples detected many parameters within a class. The MSC Study 

Report lists the following qualifiers associated with analytical results: 

 The sample was diluted (from 1X, which means no dilution, to up to 1000X) due to 

concentrations of analytes exceeding calibration ranges of the instrumentation or due 

to potential matrix effect. The laboratory will use best judgment when analyzing 

samples at the lowest dilution factors allowable without causing potential damage to 

the instrumentation. 

 The analyte was detected in the associated lab method blank for the sample. Sample 

results would be flagged with a laboratory-generated single letter qualifier (i.e., “B”). 

 The estimated concentration of the analyte was detected between the method 

detection limit and the reporting limit. Sample results would be flagged with a 

laboratory-generated single letter qualifier (i.e., “J”). These results should be 

considered as estimated concentrations. 

 The observed value was less than the method detection limit. These results will be 

flagged with a “U”. 
3-11

Table 3-12 – Parameter classes analyzed for in MSC Study 

 A B C D E F G H I J K L M N O 

Conventional Analyses • • • • • • • • • • • • • • • Metals • • • • • • • • • • • • • • • VOCs • • • • • • • • • • • • • • • SVOC • • • • • • • • • • • • • • • Organochlorine Pesticides • • • • • • • • • • • • • • • PCBs • • • • • • • • • • • • • • • Organophosphorus Pesticides • • • • • • • • • • • • • • • Alcohols NA • NA • • • • • • • • • • • • Glycols NA • NA • • • • • • • • • • • • Acids NA NA NA • • • • • • • • • • • • 

Table 3-13 – Parameter classes detected in flowback analyticals in MSC Study 

# 

parameters 

analyzed for 

A B C D E F G H I J K L M N 

Conventional Analyses 29 √ √ √ √ √ √ √ √ √ √ √ √ √ √ Metals 59 √ √ √ √ √ √ √ √ √ √ √ √ √ √ VOCs 70 7 6 1 2 2 6 1 5 2 2 3 7 2 1 SVOC 107 3 6 1 5 3 6 2 2 9 8 6 2 1 1 Organochlorine Pesticides 20 0 0 1 1 0 1 0 2 1 2 1 1 1 0 PCBs 7 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Organophosphorus Pesticides 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Alcohols 5 0 1 0 2 0 1 0 0 0 0 0 0 0 0 Glycols 2 0 1 0 2 0 1 0 0 0 0 0 0 0 0 Acids 4 0 0 0 0 1 1 1 1 1 1 1 1 1 2 
3-12

Metals and conventional parameters were detected and quantified in many of the samples and 

these observations are consistent with parameters listed in Table 3-1. However, the frequency 

of occurrence of other parameter classes was much lower: Table 3-13 summarizes the 

number of volatile organic compounds (VOCs), semi-volatile organic compounds (SVOCs), 

PCBs, pesticides, alcohols, glycols and acids observed in samples taken from each well. For 

the purposes of Table 3-13, if a particular parameter was detected in any sample from a 

single well, whether detected in one or all five (Day 0, 1, 5, 14 or 90) samples, it was 

considered to be one parameter. 

 Between 1 and 7 of the 70 volatile organic compounds were detected in samples from 

well sites A through S. VOCs detected included 

1,2,3-Trichlorobenzene Benzene Isopropylbenzene 

1,2,4-Trimethylbenzene Bromoform Naphthalene 

1,3,5-Trimethylbenzene Carbondisulfide Toluene 

2-Butanone Chloroform Xylenes 

Acetone Chloromethane 

Acrylonitrile Ethylbenzene 

 Between 1 and 9 of the 107 semi-volatile organic compounds were detected in 

samples from well sites A through S. SVOCs detected included 

2,4-Dimethylphenol Benzo(b)fluoranthene Fluoranthene 

2,6-Dichlorophenol Benzo(ghi)perylene Fluorene 

2-Methylnaphthalene Benzo(k)fluoranthene Indeno(1,2,3-cd)pyrene 

2-Methylphenol Benzyl alcohol N-Nitrosodiphenylamine 

2-Picoline bis(2-Chloroethyl) ether Phenanthrene 

3-Methylphenol & 4-

Methylphenol 

bis(2-Ethylhexyl) phthalate Phenol 

7,12-

Dimethylbenz(a)anthracene 

Dibenz(a,h)anthracene Pyridine 

Acetophenone Di-n-butyl phthalate Safrole 

Benzo(a)pyrene Diphenylamine 

 At most 3 of the 20 organochlorine pesticides were detected. Organochlorine 

pesticides detected included 

4,4 DDE cyclohexane (gamma BHC) endrin aldehyde 

Aldrin endosulfan I Heptachlor 

cyclohexane (beta BHC) endosulfan II heptachlor epoxide 

 Only 1 (Aroclor 1248) of the 7 PCBs was detected, and that from only one well site. 

 Only 1 organophosphorus pesticide was analyzed for; but it was not detected in any 

sample. 

 Of the 5 alcohols analyzed for, 2 were detected at one well site and 1 each was 

detected at two well sites. Alcohols that were detected are 2-propanol and methanol. 
3-13

 Of the 2 glycols (ethylene glycol and propylene glycol) analyzed for, 1 each was 

detected at three well sites. 

 Of the 4 acids analyzed for, 1 or 2 acids (acetic acid and volatile acids) were detected 

at several well sites. 

Some parameters found in analytical results may be due to additives or supply water used in 

fracturing or drilling; some may be due to reactions between different additives; while others 

may have been mobilized from within the formation; still other parameters may have been 

contributed from multiple sources. Some of the volatile and semi-volatile analytical results 

may be traced back to potential laboratory contamination due to improper ventilation; due to 

chromatography column breakdown; or due to chemical breakdown of compounds during 

injection onto the instrumentation. Further study would be required to identify the specific 

origin of each parameter. 

Nine pesticides and one PCB were identified by the MSC Study that were not identified by 

the flowback analytical results previously received from industry; all other parameters 

identified in the MSC study were already identified in the additives and/or flowback 

information received from industry. 

Pesticides and PCBs do not originate within the shale play. If pesticides or PCBs were 

present in limited flowback samples in PA or WV, pesticides or PCBs would likely have 

been introduced to the shale or water during drilling or fracturing operations. Whether the 

pesticides or PCBs were introduced via additives or source water could not be evaluated with 

available information. 

3.5 Temporal Trends in Flowback Fluids Composition 

The composition of flowback changes with time, depending on a variety of factors. Limited 

time-series Marcellus Shale flowback data from Pennsylvania operations, including data 

from the MSC Study Report, indicate that: 

 The concentrations of total dissolved solids (TDS), chloride, and barium increase 

[7,9]; 

 The levels of radioactivity increase10, and sometimes exceed Maximum Contaminant 

Levels (MCLs) (see Table 4-2 - Primary Drinking Water Standards); 

 Calcium and magnesium hardness increases; 

 Iron concentrations increase, unless iron-controlling additives are used; 

 Sulfate levels decrease; 

 Alkalinity levels decrease, likely due to use of acid; and 

 Concentrations of metals increase11. 

 

10 Limited data from operations in PA and WV have reported the following ranges of radioactivity: alpha 22.41 

– 18950 pCi/L; beta 9.68 – 7445 pCi/L; Radium226 2.58 - 33 pCi/L. 

11 Metals such as aluminum, antimony, arsenic, barium, boron, cadmium, calcium, cobalt, copper, iron, lead, 

lithium, magnesium, manganese, molybdenum, nickel, potassium, radium, selenium, silver, sodium, strontium, 
3-14

Available literature [1] corroborates the above summary regarding the changes in 

composition with time for TDS, chlorides, and barium. Fracturing fluids pumped into the 

well, and mobilization of materials within the shale may be contributing to the changes seen 

in hardness, sulfate, and metals. The specific changes would likely depend on the shale 

formation, fracturing fluids used and fracture operations control. 

3.6 Summary 

Flowback consists of fracturing fluids injected into the shale formation, new compounds that 

may form due to decomposition or reactions between additives, and mobilization of 

substances in the shale formation. The flowback rate and composition change with time. 

Typically, approximately 20-35 percent of fracturing fluids return to the surface over a period 

of approximately 2-3 weeks. Flowback from almost all shale formations appears to have high 

concentrations of TDS (primarily due to chlorides); flowback from the Marcellus Shale 

consists of high concentrations of TDS and barium, and trace amounts of several other 

parameters (reported in Table 3-1). 

 

thallium, titanium, and zinc have been reported in flowback analyses. It is important to note that not all these 

metals were detected in each well. 
4-1

4 SUFFICIENCY OF REGULATIONS AND GUIDELINES 

This section summarizes existing environmental regulations and guidelines that govern the 

use of water associated with well drilling and hydraulic fracturing in New York State. The 

goal is to assess the sufficiency of these regulations and guidelines at regulating the waterrelated aspects of high volume hydraulic fracturing operations. 

4.1 Background 

Water for use at the well pads may be obtained from a variety of sources including surface 

water, groundwater, public water supplies, and treatment system effluents. The water is 

trucked or pumped to the well pads and stored in tanks, pits or impoundments12 until used for 

any of a variety of purposes including well drilling and completion, testing of pipelines, and 

dust control. By far, the largest use of water is for hydraulic fracturing. Hydraulic fracturing 

of the Marcellus Shale will require larger volumes of water to fracture the rocks than have 

previously been utilized in fracturing operations at other gas wells in New York. Each well 

may use between 0.5 and 6 million gallons of water.

As discussed in Section 2.4, hydraulic fracturing fluid typically contains additives which 

increase the effectiveness of the fracturing operations by ensuring that the proppant is 

delivered and remains in the fractures, while preventing corrosion of the well casing 

materials. The well must be constructed so that the fracturing fluid is only pumped into the 

zone targeted for fracturing. 

A large portion of the fluid pumped during hydraulic fracturing remains in the shale 

formation (i.e., is considered consumed), but a significant portion (approximately 20 to 35 

percent) normally returns to the surface as flowback and must be managed in accordance 

with applicable regulations. Existing well construction and fluid containment requirements 

are intended to prohibit any uncontrolled release of fluids to the environment. 

The oil and gas industry has provided information and data to NYSDEC regarding the 

formulation of additives that may be used. The constituents of the fluid may then be 

subjected to evaluation to identify potential areas of concern where additional regulatory 

controls may be needed to sufficiently protect the environment. 

Currently, applicants seeking permits to drill horizontal Marcellus Shale wells where highvolume hydraulic fracturing will be utilized are required to complete a site-specific 

Environmental Impact Statement (EIS), which must take into account the same issues being 

considered in the Supplemental GEIS process and must be consistent with the requirements 

of the State Environmental Quality Review Act and the State Environmental Conservation 

Law (ECL). 

 

12 A pit is typically associated with just one well pad, whereas an impoundment infers a centralized temporary 

water storage location that services several well pads. 
4-2

The ECL is the body of law that established NYSDEC and authorizes its programs; the State 

Public Health Law similarly relates to the New York State Department of Health 

(NYSDOH). The regulations that implement the ECL and the Public Health Law are 

contained in the New York Codes, Rules and Regulations (NYCRR). Of relevance to this 

project are the regulations contained in Title 6 - Environmental Conservation (6NYCRR), 

and Title 10 – Health (10NYCRR). New York environmental and health regulations draw in 

large measure from federal regulations that implement the Clean Water Act (CWA), the Safe 

Drinking Water Act (SDWA), and other legislation. A summary of the applicable regulations 

follows. 

4.2 Water Use Classifications 

Surface water and groundwater sources are classified by the best type use that is or could be 

made of the source. The preservation of these uses is a regulatory requirement in New York. 

6NYCRR Part 701 identifies and assigns the classifications of surface waters and 

groundwaters in New York [10]. 

In general, the discharge of sewage, industrial waste or other wastes may not cause 

impairment of the best usages of the receiving water as specified by the water classifications 

at the location of discharge and at other locations that may be affected by such discharge. In 

addition, for higher quality waters, NYSDEC may impose discharge restrictions (described 

below) in order to protect public health, or the quality of distinguished value or sensitive 

waters. 

A table of water use classifications, usages, and restrictions follows [10]. 
4-3

Table 4-1 - New York Water Use Classifications 

Water Use Class Water Type Best Usages and 

Suitability

Notes

N Fresh Surface 1, 2

AA-Special Fresh Surface 3, 4, 5, 6 Note a

A-Special Fresh Surface 3, 4, 5, 6 Note b

AA Fresh Surface 3, 4, 5, 6 Note c

A Fresh Surface 3, 4, 5, 6 Note d

B Fresh Surface 4, 5, 6

C Fresh Surface 5, 6, 7

D Fresh Surface 5, 7, 8

SA Saline Surface 4, 5, 6, 9 

SB Saline Surface 4, 5, 6,

SC Saline Surface 5, 6, 7

I Saline Surface 5, 6, 10

SD Saline Surface 5, 8

GA Fresh Groundwater 11

GSA Saline Groundwater 12 Note e

GSB Saline Groundwater 13 Note f

Other – T/TS Fresh Surface Trout/Trout 

Spawning

Other – Discharge 

Restriction Category

All Types N/A See descriptions 

below

Best Usage/Suitability Categories [Column 3 of Table 4-1 above] 

1. Best usage for enjoyment of water in its natural condition and, where compatible, as a source of 

water for drinking or culinary purposes, bathing, fishing, fish propagation, and recreation 

2. Suitable for shellfish and wildlife propagation and survival, and fish survival 

3. Best usage as source of water supply for drinking, culinary or food processing purposes 

4. Best usage for primary and secondary contact recreation 

5. Best usage for fishing. 

6. Suitable for fish, shellfish, and wildlife propagation and survival. 

7. Suitable for primary and secondary contact recreation, although other factors may limit the use for 

these purposes. 

8. Suitable for fish, shellfish, and wildlife survival (not propagation) 

9. Best usage for shellfishing for market purposes 

10. Best usage for secondary, but not primary, contact recreation 

11. Best usage for potable water supply 
4-4

12. Best usage for source of potable mineral waters, or conversion to fresh potable waters, or as raw 

material for the manufacture of sodium chloride or its derivatives or similar products 

13. Best usage is as receiving water for disposal of wastes (may not be assigned to any groundwaters 

of the State, unless the commissioner finds that adjacent and tributary groundwaters and the best 

usages thereof will not be impaired by such classification) 

Discharge Restriction Categories – Based on a number of relevant factors and local conditions, per 6 

NYCRR 701.20, discharge restriction categories may be assigned to: (1) waters of particular public 

health concern; (2) significant recreational or ecological waters where the quality of the water is 

critical to maintaining the value for which the waters are distinguished; and (3) other sensitive waters 

where NYSDEC has determined that existing standards are not adequate to maintain water quality. 

1. Per 6 NYCRR 701.22, new discharges may be permitted for waters where discharge restriction 

categories are assigned when such discharges result from environmental remediation projects, 

from projects correcting environmental or public health emergencies, or when such discharges 

result in a reduction of pollutants for the designated waters. In all cases, best usages and standards

will be maintained. 

2. Per 6 NYCRR 701.23, except for storm water discharges, no new discharges shall be permitted 

and no increase in any existing discharges shall be permitted. 

3. Per 6 NYCRR 701.24, specified substance shall not be permitted in new discharges, and no 

increase in the release of the specified substance shall be permitted for any existing discharges. 

Storm water discharges are an exception to these restrictions. The substance will be specified at 

the time the waters are designated. 

Notes [Column 4 of Table 4-1 above]

a. These waters shall contain no floating solids, settleable solids, oil, sludge deposits, toxic wastes, 

deleterious substances, colored or other wastes or heated liquids attributable to sewage, industrial 

wastes or other wastes; there shall be no discharge or disposal of sewage, industrial wastes or 

other wastes into these waters; these waters shall contain no phosphorus and nitrogen in amounts 

that will result in growths of algae, weeds and slimes that will impair the waters for their best 

usages; there shall be no alteration to flow that will impair the waters for their best usages; there 

shall be no increase in turbidity that will cause a substantial visible contrast to natural conditions. 

b. This classification may be given to those international boundary waters that, if subjected to 

approved treatment, equal to coagulation, sedimentation, filtration and disinfection with additional 

treatment, if necessary, to reduce naturally present impurities, meet or will meet NYSDOH 

drinking water standards and are or will be considered safe and satisfactory for drinking water 

purposes. 

c. This classification may be given to those waters that if subjected to pre-approved disinfection 

treatment, with additional treatment if necessary to remove naturally present impurities, meet or 

will meet NYSDOH drinking water standards and are or will be considered safe and satisfactory 

for drinking water purposes. 

d. This classification may be given to those waters that, if subjected to approved treatment equal to 

coagulation, sedimentation, filtration and disinfection, with additional treatment if necessary to 

reduce naturally present impurities, meet or will meet NYSDOH drinking water standards and are 

or will be considered safe and satisfactory for drinking water purposes. 
4-5

e. Class GSA waters are saline groundwaters. The best usages of these waters are as a source of 

potable mineral waters, or conversion to fresh potable waters, or as raw material for the 

manufacture of sodium chloride or its derivatives or similar products. 

f. Class GSB waters are saline groundwaters that have a chloride concentration in excess of 1,000 

milligrams per liter or a total dissolved solids concentration in excess of 2,000 milligrams per liter; 

it shall not be assigned to any groundwaters of the State, unless the NYSDEC finds that adjacent 

and tributary groundwaters and the best usages thereof will not be impaired by such classification. 

Water use classifications are assigned to surface waters and groundwaters throughout New 

York. Regulations governing gas drilling in the Marcellus Shale formation are intended to 

prevent the degradation of water quality that would impair the best use or suitability as 

assigned. 

4.3 Drinking Water 

The protection of drinking water sources and supplies is extremely important for the 

maintenance of public health, and the protection of this water use type is paramount. 

Chemical or biological parameters that are inadvertently released into surface water or 

groundwater sources that are designated for drinking water use can adversely impact or 

disqualify such usage if there are constituents that conflict with applicable standards for 

drinking water. These standards are discussed below. 

4.3.1 Federal 

The SDWA, passed in 1974 and amended in 1986 and 1996, gives the United States 

Environmental Protection Agency (USEPA) the authority to set drinking water standards. 

There are two categories of drinking water standards: primary and secondary. Primary 

standards are legally enforceable and apply to public water supply systems. The secondary 

standards are non-enforceable guidelines that are recommended as standards for drinking 

water. Public water supply systems are not required to comply with secondary standards 

unless a state chooses to adopt them as enforceable standards. New York encourages but 

does not enforce the secondary standards. 

The primary standards are designed to protect drinking water quality by limiting the levels of 

specific contaminants that can adversely affect public health and are known or anticipated to 

occur in drinking water. The determinations of which contaminants to regulate are based on 

peer-reviewed science research and data that evaluates the following factors [11]: 

 Occurrence in the environment and in public water supply systems at levels of 

concern; 

 Human exposure and risks of adverse health effects in the general population and 

sensitive subpopulations; 

 Analytical methods of detection; 
4-6

 Technical feasibility; and 

 Impacts of regulation on water systems, the economy and public health. 

After reviewing health effects studies and considering the risk to sensitive subpopulations, 

USEPA sets a non-enforceable Maximum Contaminant Level Goal (MCLG) for each 

contaminant as public health goals. This is the maximum level of a contaminant in drinking 

water at which no known or anticipated adverse effect on the health of persons would occur, 

and which allows an adequate margin of safety. MCLGs only consider public health and may 

not be achievable given the limits of detection and best available treatment technologies. The 

SDWA prescribes limits in terms of Maximum Contaminant Levels (MCLs) or Treatment 

Techniques, which are achievable at a reasonable cost, to serve as the primary drinking water 

standards. A contaminant generally is classified as microbial in nature or as a 

carcinogenic/non-carcinogenic chemical [12]. 

Secondary contaminants may cause cosmetic effects (such as skin or tooth discoloration) or 

aesthetic effects (such as taste, odor, or color) in drinking water. The numerical secondary 

standards are designed to control these effects to a level desirable to consumers [13]. 

Table 4-2 and Table 4-3, respectively at the end of this section, list contaminants regulated 

by federal primary and secondary drinking water standards [12]. 

In addition to the primary and secondary standards, the USEPA, on March 2, 1998, published 

a National Drinking Water Contaminant Candidate List (CCL), which lists contaminants that 

are [14]: 

 Not already regulated under SDWA, but nevertheless may have adverse health 

effects; 

 Are known or anticipated to occur in public water systems; and 

 May require regulations under SDWA. 

Contaminants on the CCL are prioritized and studied, including monitoring for 

presence/level of selected contaminants13 in selected existing larger public water supply 

systems. If, after the requisite studies and monitoring are completed, the USEPA determines 

regulations are necessary, then the USEPA proceeds with drafting them. Every five years, 

USEPA will repeat the cycle of revising the CCL, making regulatory determinations for 

contaminants and identifying contaminants for unregulated monitoring. In addition, every six 

years, USEPA will re-evaluate existing regulations to determine if modifications are 

necessary [15]. 

In most cases, the USEPA delegates responsibility for implementing drinking water 

standards to the states. 

 

13 Most of the unregulated contaminants with potential of occurring in drinking water are 

pesticides and microbes. 
4-7

4.3.2 New York State 

In New York, a state with delegated authority in this area, drinking water is addressed in 

Article 15, Title 15 of the ECL and administered by the NYSDEC via implementing 

regulations contained in Part 601 of 6NYCRR. 

Anyone planning to operate or operating a public water supply system must obtain a Water 

Supply Permit from NYSDEC before undertaking any of the regulated activities. 

Contact with NYSDEC and submission of a Water Supply Permit application will 

automatically involve the NYSDOH. The NYSDOH has a regulatory role in water quality 

and other sanitary aspects of a project relating to human health. Through the State Sanitary 

Code (Chapter 1 of 10NYCRR), the NYSDOH oversees the suitability of water for human 

consumption. Section 5-1.30 of 10 NYCRR prescribes the required treatment for public 

water systems, which at a minimum includes filtration and disinfection. To assure the safety 

of drinking water in New York, NYSDOH, in cooperation with its partners, the county health 

departments, regulates the operation, design and quality of public water supplies; assures 

water sources are adequately protected, and sets standards for constructing individual water 

supplies. 

The NYSDOH regulates contaminants consistent with the national drinking water standards. 

Section 5-1.51 of 10 NYCRR prescribes the maximum contaminant levels, maximum 

residual disinfectant levels and treatment technique requirements, which are listed in section 

5-1.52 tables 1 through 7 of 10 NYCRR. These tables replicate the national primary and 

secondary standards and CCL. 

In addition, in 1988, for drinking water NYSDOH adopted the 0.005 mg/L MCL for organic 

chemicals belonging to any of six major chemical classes called Principal Organic 

Contaminant (POC)14; 0.05 mg/L MCL for Unspecified Organic Contaminant (UOC)15; and 

0.1 mg/L MCL for Total POCs and UOCs. This means that publicly supplied drinking water 

cannot have more than 0.005 mg/L of any chemical defined as a POC; or more than 0.05 

mg/L of a chemical not already covered by other regulations (UOC); or more than 0.1 mg/L 

of POCs and UOCs combined. 

A comparison of constituents contained in hydraulic fracturing fluids, including those 

reported in the MSC Study, and the contaminants listed in Table 4-2, Table 4-3 and Table 4-4 

is provided in Table 4-5. Nine pesticides and one PCB were identified by the MSC Study 

 

14 The New York State Register dated November 23, 1988, Volume X, Issue 47, lists the POC classes as 

halogenated alkanes; halogenated ethers; halobenzenes and substituted halobenzenes; benzene and alkyl – or 

nitrogen-substituted benzenes; substituted, unsaturated aliphatic hydrocarbons; and halogenated non-aromatic 

cyclic hydrocarbons. The specific contaminants to be analyzed for under POCs are listed in Table 9D - Organic 

Chemicals – POCs of 10 NYCRR Subpart 5-1, and replicated in Table 4-4 herein. 

15 Defined as any organic chemical not covered by another MCL. 
4-8

that were not previously identified by the flowback analytical results received from industry; 

all other parameters identified in the MSC study were already identified in the information 

received from industry. 

It should be noted that the Federal Energy Policy Act of 2005 amended the Underground 

Injection Control (UIC) provisions of the SDWA to exclude hydraulic fracturing from the 

definition of "underground injection." The Fracturing Responsibility and Awareness of 

Chemicals (FRAC) Act bill presently in Congress, if passed, will subject hydraulic fracturing 

to regulation under the SDWA. 

The objective of the federal UIC program is to protect underground sources of drinking water 

from contamination by underground injection of hazardous and non-hazardous fluids. 

Whether or not hydraulic fracturing is regulated under SDWA UIC, protection of 

groundwater resources during oil and gas extraction activities is a responsibility of state 

government, and the cited federal amendment does not diminish the NYSDEC's authority 

over oil and gas well development in New York, including oversight of hydraulic fracturing 

activities to ensure protection of potable groundwater resources. 

4.4 Discharge Limits – SPDES 

The direct or indirect discharge of flowback that includes residuals from additives is subject 

to regulation under New York’s State Pollutant Discharge Elimination System (SPDES). 

Limitations on discharges from point sources, which are derived from federal, regional, and 

state standards and programs, are imposed in New York via the SPDES permit program. The 

USEPA has approved New York’s program for the control of wastewater and stormwater 

discharges in accordance with the Clean Water Act (CWA). Under New York State law, the 

SPDES program is broader in scope than the CWA in that it controls point source discharges 

to groundwaters as well as surface waters. Discharges related to gas drilling activities are 

subject to these controls. 

Applicable water quality standards and effluent limitations are those State and Federal water 

quality standards and effluent limitations to which a discharge is subject under the CWA or 

State law, including but not limited to water quality standards, effluent limitations, best 

management practices, standards of performance, toxic effluent standards and prohibitions, 

pretreatment standards, and ocean discharge criteria. 

Per 6 NYCRR Section 750-1.3, certain discharges are absolutely prohibited, including any 

radiological, chemical or biological warfare agent or high-level radioactive waste, any 

obstruction to anchorage or navigation, and other highly objectionable, conflicting or noncompliant discharges. 

Subsection (a) of 6 NYCRR Section 750-1.11 covers the provisions of SPDES permits and 

lists the citations for the various effluent limitations from the Federal Register (FR) and the 

Code of Federal Regulations (CFR). NYSDEC is responsible to administer these applicable 

effluent limitations and other requirements in the SPDES permits, whenever applicable, as 
4-9

required by the CWA and as may be promulgated by the NYSDEC. These include the 

following: 

(1) Best Practicable Control Technology currently available (BPT) effluent limitations 

under Section 301 of the CWA and 40 CFR Parts 120, 125, 133 and 405-471, inclusive, (see 

section 750-1.24 of this Part); 

(2) Best Conventional Pollutant Control Technology (BCT) new source performance 

standards (NSPS), and other new source performance standards under Section 306 of the 

CWA and 40 CFR Parts 122.29, 129 and 405-471, inclusive (see section 750-1.24 of this 

Part); 

(3) Best Available Technology (BAT) effluent limitation guidelines, effluent 

prohibitions, and pretreatment standards for existing sources under Section 307 of the CWA 

and 40 CFR Parts 129 and 405-471, inclusive (see section 750-1.24 of this Part); 

(4) Ocean discharge criteria adopted by the Federal government pursuant to Section 403 

of the CWA and 40 CFR Part 125, sections 125.120 - 125.124 (see section 750-1.24 of this 

Part); 

(5) Any more stringent limitations, including those: 

(i) Necessary to meet water quality standards, guidance values, effluent limitations or 

schedules of compliance, established pursuant to any state law or regulation 

consistent with Section 510 of the CWA, or the requirements of 40 CFR Part 132 (see 

section 750-1.24 of this Part); 

(ii) Necessary to implement a total maximum daily load/waste load allocation/load 

allocation established pursuant to Section 303(d) of the CWA and 40 CFR Part 130.7 

(see section 750-1.24 of this Part); or 

(iii) Necessary to meet any other State or Federal law or regulation; 

(6) Any more stringent requirements necessary to comply with a plan approved pursuant 

to Section 208(b) of the CWA and 40 CFR Part 35 (see section 750-1.24 of this Part): 

(7) Prior to promulgation by the administrator of applicable effluent standards and 

limitations, BPT effluent limitations and such conditions as the commissioner determines are 

necessary to carry out the provisions of this Part pursuant to Section 402 of the CWA and 40 

CFR Part 125 (see section 750-1.24 of this Part). 

(8) As provided in Section 402(g) of the CWA (see section 750-1.24 of this Part), if the 

SPDES permit is for the discharge of pollutants into the navigable waters of the State from a 

vessel or other floating craft, any applicable regulations promulgated by the U.S. Department 

of Commerce, establishing specifications for safe transportation, handling, carriage, storage, 

and stowage of pollutants. 

(9) Unless otherwise required or authorized by this Part, the provisions or requirements 

of 40 CFR. 122.23 Concentrated animal feeding operations, 40 CFR. Part 122.24 - 
4-10

Concentrated aquatic animal production facilities, 40 CFR Part 122.25 - Aquaculture 

projects, 40 CFR Parts 122.26, 122.30 to 122.37, and 122.42(c) & (d) - Storm Water 

Discharges, 40 CFR Part 122.27 - Silvicultural activities (applicable to SPDES), 40 CFR Part 

122.44 - Establishing limitations, standards, and other permit conditions, 40 CFR Part 122.45 

- Calculating NPDES permit conditions, 40 CFR Part 125 - Criteria and Standards for 

NPDES, 40 CFR Part 133 - Secondary Treatment Regulation, 40 CFR Part 401 - General 

Provisions and 40 CFR Part 403 - General Pretreatment Regulations, except 40 CFR Part 

403.10 (see section 750-1.24 of this Part). 

(10) 40 CFR 122.50 (see section 750-1.24 of this Part). 

(11) The requirements or provisions of this Part. 

Subsection (b) of 6NYCRR Section 750-1.11 covers industrial waste discharges into publicly 

owned treatment works, which must comply with toxic effluent limitations and pretreatment 

standards and with monitoring, reporting, recording, sampling and entry requirements 

provided by Section 307 of the CWA and 40 CFR Parts 129 and 405-471, inclusive; and 

Section 308 of the CWA and 40 CFR Parts 122 and 125 (see section 750-1.24 of this Part); 

or ECL Article 17, or adopted pursuant to ECL Article 17 of this Title. 

The SPDES permit application requires any applicant to provide analytical results for several 

classes of pollutants listed in the following tables: 

Table 6 - Priority Pollutants; 

Table 7 - Other Significant Pollutants with NYSDEC Standards/Guidance Values 

and USEPA/NYSDEC Promulgated Analytical Methods; 

Table 8 - Other Significant Pollutants with USEPA/NYSDEC Promulgated 

Analytical Methods; 

Table 9 - Other Significant Pollutants with NYSDEC Standards/Guidance Values; 

and 

Table 10 - Other Pollutants and Hazardous Substances Required to be Identified in 

ICS by Applicants if Present at Facility in Significant Levels. 

4.5 Ambient Water Quality Standards and Guidance Values and Groundwater 

Effluent Limitations 

Included in the above discussion are those rules and regulations that establish standards that 

generally apply to industrial activities, but that also have applicability to the oil, gas, and 

solution mining industrial category. In addition, a guidance value may be used where a 

standard for a substance or group of substances has not been established for a particular 

water class and type of value [16]. 

Division of Water Technical and Operational Guidance Series 1.1.1 (TOGS111) - Ambient 

Water Quality Standards and Guidance Values and Groundwater Effluent Limitations is a 

compilation of ambient water quality guidance values and groundwater effluent limitations 

for use where there are no standards (in 6 NYCRR 703.5) or regulatory effluent limitations 

(in 6 NYCRR 703.6). 
4-11

4.6 Lists of Chemicals in Additives and Flowback Addressed in NY Regulations or 

Guidances 

Table 4-5, at the end of this section, lists chemical constituents of additives and parameters 

found in a limited number of analytical samples of flowback fluids received via NYSDEC. 

Columns 5-9 of Table 4-5 indicate if any of these chemicals/parameters are regulated by the 

federal primary or secondary drinking water standards, covered in Tables 6-10 of the SPDES 

program, or in Table 1 or 5 of TOGS111. 

Table 4-6 lists parameters found in limited flowback analyses from PA and WV that are 

regulated in NY; this table does not include results from the MSC Study. Column 3 is the 

number of samples that analyzed for the particular parameter; column 4 is the number in 

which the parameter was detected. Columns 5, 6 and 7 provide the minimum, median and 

maximum concentrations detected. 

Table 4-7 lists parameters found in limited flowback analyses from PA and WV that appear 

not to be regulated in NY. Column 2 is the number of samples that analyzed for the particular 

parameter; column 3 is the number in which the parameter was detected. Basic statistics for 

these parameters are in subsequent columns. Given the limited number of analyses performed 

on these parameters, the results and statistics should be used with caution. 

4.7 Rules and Regulations Applicable to Oil, Gas, and Solution Mining Category 

4.7.1 Federal 

40 CFR Part 435 provides guidelines on effluent limitations for the Oil and Gas Extraction 

Point Source Category. These guidelines are taken into consideration when the permitting 

authority develops discharge permit limitations for a point source discharger in this category. 

Subpart C of 40 CFR 435 specifically applies to facilities engaged in the production, field 

exploration, drilling, well completion and well treatment in the oil and gas extraction 

industry that are located on land (i.e., excludes offshore and coastal locations). 

The applicable limits in this subcategory reflect BPT: there shall be no discharge of waste 

water pollutants into navigable waters from any source associated with production, field 

exploration, drilling, well completion, or well treatment (i.e., produced water, drilling muds, 

drill cuttings, and produced sand). 

4.7.2 New York State 

NYSDEC's Division of Mineral Resources administers regulations and a permitting program 

to mitigate to the greatest extent possible any potential environmental impact of gas drilling 

and well operation. 
4-12

6 NYCCR Part 554 addresses drilling practices applicable to oil, gas, and solution salt 

mining activities. Subpart 554.1 prescribes requirements for pollution and migration 

prevention. These requirements include: 

 The prevention of pollution associated with the drilling, casing and completion 

program adopted for any well. 

 A prohibition on pollution of the land and/or of fresh surface water or fresh 

groundwater resulting from exploration or drilling.

 Prior to the issuance of a well-drilling permit for any operation in which the potential 

exists that brine, salt water or other polluting fluids will be produced or obtained 

during drilling operations in sufficient quantities to be deleterious to the surrounding 

environment, the need for the operator to submit and receive approval of a plan for 

the environmentally safe and proper ultimate disposal of such fluids (excluding 

drilling muds, which, as specified by regulation, are not considered to be polluting 

fluids for the purposes of 6 NYCRR 554.1(c)(1)). 

o Depending on the method of disposal chosen by the applicant, a permit for 

discharge and/or disposal may be required by the NYSDEC in addition to the 

well-drilling permit. 

o An applicant may also be required to submit an acceptable contingency plan, 

the use of which shall be required if the primary plan is unsafe or 

impracticable at the time of disposal. 

 A prohibition on the impounding of brine or salt water in an earthen pit where the 

soil underlying the pit is porous and/or is closely underlaid by a gravel, rock or sand 

stratum unless the pit is lined with watertight material. 

o Brine or salt water may be temporarily stored prior to disposal in any 

watertight tank, container or an earthen pit, if underlaid by soil such as heavy 

clay or hardpan. 

o The tank, container or earthen pit must be constructed and maintained so as to 

prevent escape of any fluids, including any amounts that may be added by 

natural precipitation. 

o Storage of brine, salt water or other polluting fluids in such watertight tanks or 

earthen pits, prior to disposal, is limited to a maximum of 45 days after 

cessation of drilling operations, unless NYSDEC approves an extension. 

 The installation of surface casing in all wells to a depth below the deepest potable 

fresh water level. 

o The drilling, casing and completion program adopted for any well must be 

such as to: 
4-13

 Prevent the migration of oil, gas or other fluids from one pool or 

stratum to another; and 

 Exclude oil, gas or other fluids from any underground mining 

properties or rights and to protect them in accordance with prudent 

operations. 

 ECL23-0305(8)(d) provides authority to NYSDEC to require the operator to remedy 

any contamination of a water supply well, and ECL 71-1307 provides authority to 

direct a violator to “reclaim and repair” any impairment to a water supply well. 

The regulation summarized above is supplemented by required casing and cementing 

practices, enforced as permit conditions on each drilling permit. Surface casing must extend 

at least 75 feet beyond the deepest fresh water zone, or 75 feet into competent rock, 

whichever is deeper [17]. In primary and principal aquifers, surface casing must be set at 

least 100 feet below the deepest fresh water zone and at least 100 feet into bedrock. 

Additionally, as stated in the GEIS (p. 9-32), although the cited regulations do mention clay 

and hardpan as options in pit construction, NYSDEC has consistently required plastic liners 

in all temporary earthen drilling pits [18]. 

4.8 Other Agencies and Activities with Jurisdiction 

New York State is a member of compacts established to regulate and protect important 

interstate water resources. These include the Susquehanna River Basin Commission, the 

Delaware River Basin Commission, and the Great Lakes Commission. 

In addition, New York has specific programs, plans, and procedures in place that are focused 

on maintaining or improving ambient water quality in targeted watersheds. These include 

total maximum daily loads, and state or local watershed management or protection plans. 

Although these commissions, programs, plans, and procedures carry the force of law, they 

are specific to individual water bodies or watersheds and, therefore, are not included in this 

review. 

The Emergency Planning and Community Right-to-Know Act (EPCRA) applies to the 

manufacturing sector, including the oil and gas industry (although not oil or gas conveyance 

pipelines). In addition, existing well construction and fluid containment requirements 

sufficiently prohibit any uncontrolled release of fluids to the environment. Also, well permit 

Applicants are required to submit information on hydraulic fracturing fluid composition prior 

to well permit issuance, subject to regulations that protect information identified by 

Applicants as trade secret or confidential commercial information. 

Additional environmental laws exist to address other activities related to gas well drilling in 

the New York Marcellus Shale area. These include the Resource Conservation and Recovery 

Act (RCRA) regarding hazardous waste, the Comprehensive Environmental Response, 

Compensation, and Liability Act (CERCLA) regarding toxic substances, and the Clean Air 

Act (CAA) regarding emissions. A review of the federal and New York regulations that 
4-14

implement these laws and their applicability to the oil and gas industry is beyond the scope of 

this review. 

4.9 Conclusions 

This section provides a summary of federal and New York State environmental regulations 

and guidelines that apply to gas well drilling and extraction in the New York portion of 

Marcellus Shale region related to water use. They are intended to address concerns that the 

oil and gas industry may not be fully subject to certain key provisions of the SWDA, CWA, 

and other water resource-related environmental laws. 

This review provides information regarding the sufficiency of regulatory controls in place in 

New York to protect specified water uses, including drinking water sources, from drilling 

activities, injection of fluids for hydraulic fracturing, and management of flowback or brines 

that flow back to surface during well development or operation. These controls are 

implemented in the permitting process for well drilling and completion; for point source 

discharges via the SPDES program; and where there are no standards or regulatory effluent 

limitations, via Technical & Operational Guidance Series 1.1.1 (TOGS111). In addition, 

drinking water supplies are protected by Federal Drinking Water Standards, and NYSDOH’s 

POC and UOC standards. Except for those parameters listed in Table 4-7, all parameters 

detected in flowback analyticals that were provided by industry via NYSDEC, including 

parameters detected in the MSC Study, are presently addressed by existing Federal or State 

regulations or guidances. 
4-15

Table 4-2 - Primary Drinking Water Standards 

Microorganisms Contaminant MCLG

(mg/L) 

MCL or TT

(mg/L) 

Cryptosporidium 0 TT 

Giardia lamblia 0 TT 

Heterotrophic plate count n/a TT 

Legionella 0 TT 

Total Coliforms (including 

fecal coliform and E. coli) 0 5% 

Turbidity n/a TT 

Viruses (enteric) 0 TT 

MCLG: Maximum contaminant level goal 

MCL: Maximum contaminant level 

TT: Treatment technology

Disinfection 

Byproducts Contaminant MCLG

(mg/L) 

MCL or TT

(mg/L) 

Bromate 0 0.01 

Chlorite 0.8 1 

Haloacetic acids (HAA5) n/a 0.06 

Total Trihalomethanes 

(TTHMs) n/a 0.08 

 

Disinfectants Contaminant MRDLG

(mg/L) 

MRDL 

(mg/L) 

Chloramines (as Cl2) 4.0 4.0 

Chlorine (as Cl2) 4.0 4.0 

Chlorine dioxide (as ClO2) 0.8 0.8 

MRDL: Maximum Residual Disinfectant Level 

MRDLG: Maximum Residual Disinfectant Level Goal 

 

Inorganic 

Chemicals Contaminant CAS number 

MCLG

(mg/L) 

MCL or TT

(mg/L) 

Antimony 07440-36-0 0.006 0.006 

Arsenic 07440-38-2 0 0.01 

as of 01/23/06 

Asbestos 

(fiber >10 micrometers) 01332-21-5 7 million fibers per liter 7 MFL 

Barium 07440-39-3 2 2 

Beryllium 07440-41-7 0.004 0.004 

Cadmium 07440-43-9 0.005 0.005 

Chromium (total) 07440-47-3 0.1 0.1 

Copper 07440-50-8 1.3 

TT; 

Action 

Level=1.3 

Cyanide (as free cyanide) 00057-12-5 0.2 0.2 

Fluoride 16984-48-8 4 4 

Lead 07439-92-1 0 

TT; 

Action 

Level=0.015 
4-16

Inorganic 

Chemicals Contaminant CAS number 

MCLG

(mg/L) 

MCL or TT

(mg/L) 

Mercury (inorganic) 07439-97-6 0.002 0.002 

Nitrate (measured as 

Nitrogen) 10 10 

Nitrite (measured as 

Nitrogen) 1 1 

Selenium 07782-49-2 0.05 0.05 

Thallium 07440-28-0 0.0005 0.002 

Organic 

Chemicals Contaminant CAS number 

MCLG

(mg/L) 

MCL or TT

(mg/L) 

Acrylamide 00079-06-1 0 TT 

Alachlor 15972-60-8 0 0.002 

Atrazine 01912-24-9 0.003 0.003 

Benzene 00071-43-2 0 0.005 

Benzo(a)pyrene (PAHs) 00050-32-8 0 0.0002 

Carbofuran 01563-66-2 0.04 0.04 

Carbon tetrachloride 00056-23-5 0 0.005 

Chlordane 00057-74-9 0 0.002 

Chlorobenzene 00108-907 0.1 0.1 

2,4-Dichloro-phenoxyacetic 

acid (2,4-D) 00094-75-7 0.07 0.07 

Dalapon 00075-99-0 0.2 0.2 

1,2-Dibromo-3-

chloropropane (DBCP) 00096-12-8 0 0.0002 

o-Dichlorobenzene 00095-50-1 0.6 0.6 

p-Dichlorobenzene 00106-46-7 0.075 0.075 

1,2-Dichloroethane 00107-06-2 0 0.005 

1,1-Dichloroethylene 00075-35-4 0.007 0.007 

cis-1,2-Dichloroethylene 00156-59-2 0.07 0.07 

trans-1,2-Dichloroethylene 00156-60-5 0.1 0.1 

Dichloromethane 00074-87-3 0 0.005 

1,2-Dichloropropane 00078-87-5 0 0.005 

Di(2-ethylhexyl) adipate 00103-23-1 0.4 0.4 

Di(2-ethylhexyl) phthalate 00117-81-7 0 0.006 

Dinoseb 00088-85-7 0.007 0.007 

Dioxin (2,3,7,8-TCDD) 01746-01-6 0 0.00000003 

Diquat 0.02 0.02 

Endothall 00145-73-3 0.1 0.1 

Endrin 00072-20-8 0.002 0.002 

Epichlorohydrin 0 TT 

Ethylbenzene 00100-41-4 0.7 0.7 

Ethylene dibromide 00106-93-4 0 0.00005 

Glyphosate 01071-83-6 0.7 0.7 

Heptachlor 00076-44-8 0 0.0004 

Heptachlor epoxide 01024-57-3 0 0.0002 

Hexachlorobenzene 00118-74-1 0 0.001 

Hexachlorocyclopentadiene 00077-47-4 0.05 0.05 
4-17

Organic 

Chemicals Contaminant CAS number 

MCLG

(mg/L) 

MCL or TT

(mg/L) 

Lindane 00058-89-9 0.0002 0.0002 

Methoxychlor 00072-43-5 0.04 0.04 

Oxamyl (Vydate) 23135-22-0 0.2 0.2 

Polychlorinated biphenyls 

(PCBs) 0 0.0005 

Pentachlorophenol 00087-86-5 0 0.001 

Picloram 01918-02-1 0.5 0.5 

Simazine 00122-34-9 0.004 0.004 

Styrene 00100-42-5 0.1 0.1 

Tetrachloroethylene 00127-18-4 0 0.005 

Toluene 00108-88-3 1 1 

Toxaphene 08001-35-2 0 0.003 

2,4,5-TP (Silvex) 00093-72-1 0.05 0.05 

1,2,4-Trichlorobenzene 00120-82-1 0.07 0.07 

1,1,1-Trichloroethane 00071-55-6 0.2 0.2 

1,1,2-Trichloroethane 00079-00-5 0.003 0.005 

Trichloroethylene 00079-01-6 0 0.005 

Vinyl chloride 00075-01-4 0 0.002 

Xylenes (total) 10 10 

Radionuclides Contaminant MCLG

(mg/L) 

MCL or TT

(mg/L) 

Alpha particles 

none 

------------- 

zero 

15 picocuries per Liter (pCi/L) 

Beta particles and photon 

emitters 

none 

------------- 

zero 

4 millirems per year 

Radium 226 and Radium 

228 (combined) 

none 

------------- 

zero 

5 pCi/L 

Uranium zero 30 ug/L 
4-18

Table 4-3 - Secondary Drinking Water Standards 

Contaminant CAS 

number Standard 

 Aluminum 07439-90-5 0.05 to 0.2 mg/L 

 Chloride 250 mg/L 

 Color 15 (color units) 

 Copper 07440-50-8 1.0 mg/L 

 Corrosivity noncorrosive 

 Fluoride 16984-48-8 2.0 mg/L 

 Foaming Agents (surfactants) 0.5 mg/L 

 Iron 07439-89-6 0.3 mg/L 

 Manganese 07439-96-5 0.05 mg/L 

 Odor 3 threshold odor number 

 pH 6.5-8.5 

 Silver 07440-22-4 0.10 mg/L 

 Sulfate 14808-79-8 250 mg/L 

 Total Dissolved Solids 500 mg/L 

 Zinc 07440-66-6 5 mg/L 

Table 4-4 – Specific Contaminants included within NYSDOH POCs Standardsa,b 

Contaminant Standard 

(mg/L) 

 1,1,1,2-Tetrachloroethane 0.005 

 1,1,1-Trichloroethane 0.005 

 1,1,2,2-Tetrachloroethane 0.005 

 1,1,2-Trichloroethane 0.005 

 1,1-Dichloroethane 0.005 

 1,1-Dichloroethene 0.005 

 1,1-Dichloropropene 0.005 

 1,2,3-Trichlorobenzene 0.005 

 1,2,3-Trichloropropane 0.005 

 1,2,4-Trichlorobenzene 0.005 

 1,2,4-Trimethylbenzene 0.005 

 1,2-Dichlorobenzene 0.005 

 1,2-Dichloroethane 0.005 

 1,2-Dichloropropane 0.005 

 1,3,5-Trimethylbenzene 0.005 

 1,3-Dichlorobenzene 0.005 

 1,3-Dichloropropane 0.005 

 1,4-Dichlorobenzene 0.005 

 2,2-Dichloropropane 0.005 

 2-Chlorotoluene 0.005 

 4-Chlorotoluene 0.005 
4-2

Contaminant Standard 

(mg/L) 

 Benzene 0.005 

 Bromobenzene 0.005 

 Bromochloromethane 0.005 

 Bromomethane 0.005 

 Carbon Tetrachloride 0.005 

 Chlorobenzene 0.005 

 Chloroethane 0.005 

 Chloromethane 0.005 

 cis-1,2-Dichloroethene 0.005 

 cis-1,3-Dichloropropene 0.005 

 Dibromomethane 0.005 

 Dichlorodifluoromethane 0.005 

 Ethylbenzene 0.005 

 Hexachlorobutadiene 0.005 

 Isopropylbenzene 0.005 

 Methylene Chloride 0.005 

 m-Xylene 0.005 

 N-Butylbenzene 0.005 

 n-Propylbenzene 0.005 

 o-Xylene 0.005 

 p-Isopropyltoluene 0.005 

 p-Xylene 0.005 

 Sec-Butylbenzene 0.005 

 Styrene 0.005 

 Tert-Butylbenzene 0.005 

 Tetrachloroethene 0.005 

 Toluene 0.005 

 trans-1,2-Dichloroethene 0.005 

 Trans-1,3-Dichloropropene 0.005 

 Trichloroethene 0.005 

 Trichlorofluoromethane 0.005 

a Per 10 NYCRR Subpart 5-1 the MCL for each UOC (which are organic chemicals that are not covered by 

another MCL) is 0.05 mg/L. 

b Per 10 NYCRR Subpart 5-1 the MCL total POCs and UOCs is 0.1 mg/L.
4-18

Table 4-5 – Comparison of additives used or proposed for use in NY, parameters detected in analytical res

from the Marcellus operations in PA and WV16, and parameters regulated via primary and secondary drin

standards, SPDES Program or listed in TOGS111 

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

106-24-1 (2E)-3,7-dimethylocta-2,6-dien-1-ol Yes 

67701-10-4 

(C8-C18) And (C18) Unsaturated Alkylcarboxylic Acid Sodium Salt Yes 

02634-33-5 1,2 Benzisothiazolin-2-one / 1,2- benzisothiazolin-3-one Yes 00087-61-6 1,2,3-Trichlorobenzene Yes Table 9 00095-63-6 1,2,4 trimethylbenzene Yes Yes Table 9 93858-78-7 

1,2,4-Butanetricarboxylicacid, 2-phosphono-, potassium salt Yes 

00108-67-8 1,3,5-Trimethylbenzene Yes Tables 9,10 

16 This table includes parameters detected in the MSC Study. 17 As with Table 2-2, information in the “Used in Additives” column is based on the composition of additives used or proposed for use 18 Parameters marked with (¥) indicates that the compound dissociates, and its components are separately regulated. Not all dissociating 19 As with Table 3-1, information in the “Found in Flowback” column is based on analytical results of flowback from operations 

Virginia. There are/may be products used in fracturing operations in Pennsylvania that have not yet been proposed for use in New Yor

NYSDEC does not have chemical composition data. 

20 Limits marked with a pound sign (#) are based on secondary drinking water standards. 21 SPDES or TOGS typically regulates or provides guidance for the total substance, e.g. iron; and rarely regulates or provides guida

portion, e.g. dissolved iron. The dissolved component is implicitly covered in the total substance. Therefore, the dissolved componen4-5. Flowback analyses provided information for the total and dissolved components of metals, which are listed in Table 3-1 and in Ta

dissolved vs. suspended portions of a substance is valuable when determining potential treatment techniques. 

22 Cells marked with a section sign (§) indicates that if the parameter is not already covered by any other applicable regulation wh

NYCRR applies the default UOC MCL of 0.05 mg/L for each parameter, or 0.1 mg/L for the total POCs and UOCs. Double signs 

compound would be UOC, but that salts would not be UOC. 
4-19

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

00123-91-1 1,4 Dioxane Yes Table 8 03452-07-1 1-eicosene Yes 00629-73-2 1-hexadecene Yes 

104-46-1 1-Methoxy-4-propenylbenzene Yes 124-28-7 

1-Octadecanamine, N, N-dimethyl- / N,NTimethyloctadecylamine Yes 

112-03-8 

1-Octadecanaminium, N,N,N-Trimethyl-, Chloride /Trimethyloctadecylammonium chloride 

Yes 

00112-88-9 1-octadecene Yes 40623-73-2 1-Propanesulfonic acid Yes 01120-36-1 1-tetradecene Yes 

98-55-5 2-(4-methyl-1-cyclohex-3-enyl)propan-2-ol Yes 

10222-01-2 2,2 Dibromo-3-nitrilopropionamide Yes Table 9 27776-21-2 2,2'-azobis-{2-(imidazlin-2-yl)propane}- dihydrochloride Yes 73003-80-2 2,2-Dobromomalonamide Yes 00105-67-9 2,4-Dimethylphenol Yes Table 6 00087-65-0 2,6-Dichlorophenol Yes Table 8 15214-89-8 2-Acrylamido-2-methylpropanesulphonic acid sodium salt polymer Yes 46830-22-2 2-acryloyloxyethyl(benzyl)dimethylammonium chloride Yes 00052-51-7 2-Bromo-2-nitro-1,3-propanediol Yes Table 10 00111-76-2 2-Butoxy ethanol /Ethylene glycol monobutyl ether / Butyl Cellusolve Yes 01113-55-9 2-Dibromo-3-Nitriloprionamide / 2- Monobromo-3-nitriilopropionamide Yes 00104-76-7 2-Ethyl Hexanol Yes 00091-57-6 2-Methylnaphthalene Yes Table 8 00095-48-7 2-Methylphenol Yes Table 8 

109-06-8 2-Picoline (2-methyl pyridine) Yes Table 8 

00067-63-0 2-Propanol / Isopropyl Alcohol / Isopropanol / Propan-2-ol Yes Yes Table 10 
4-20

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

26062-79-3 2-Propen-1-aminium, N,N-dimethyl-N-2- propenyl-chloride, homopolymer Yes 95077-68-2 2-Propenoic acid, homopolymer sodium salt Yes 09003-03-6 2-propenoic acid, homopolymer, ammonium salt Yes 25987-30-8 

2-Propenoic acid, polymer with 2 ppropenamide, sodium salt / Copolymer of acrylamide and sodium acrylate 

Yes 

71050-62-9 2-Propenoic acid, polymer with sodium phosphinate (1:1) Yes 66019-18-9 2-propenoic acid, telomer with sodium hydrogen sulfite Yes 00107-19-7 2-Propyn-1-ol / Progargyl Alcohol Yes 51229-78-8 

3,5,7-Triaza-1-azoniatricyclo[3.3.1.13,7]decane, 1-(3-chloro2-propenyl)-chloride, Yes 

106-22-9 3,7 - dimethyl-6-octen-1-ol Yes 

5392-40-5 3,7-dimethyl-2,6-octadienal Yes 

00115-19-5 3-methyl-1-butyn-3-ol Yes 00108-39-4 3-Methylphenol Yes Table 8 

104-55-2 3-phenyl-2-propenal Yes 127-41-3 

4-(2,6,6-trimethyl-1-cyclohex-2-enyl)-3-buten2-one Yes 

00072-55-9 4,4 DDE Yes Table 6 

121-33-5 4-hydroxy-3-methoxybenzaldehyde Yes 

00106-44-5 4-Methylphenol Yes Table 8 

127087-87-0 

4-Nonylphenol Polyethylene Glycol Ether Branched / Nonylphenol ethoxylated / Oxyalkylated Phenol 

Yes 

00057-97-6 7,12-Dimethylbenz(a)anthracene Yes Table 8 00064-19-7 Acetic acid Yes Yes Table 10 68442-62-6 Acetic acid, hydroxy-, reaction products with triethanolamine Yes 00108-24-7 Acetic Anhydride Yes Table 10 
4-21

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

00067-64-1 Acetone Yes Yes Table 7 00098-86-2 Acetophenone Yes 00079-06-1 Acrylamide Yes 0 TT Table 9 38193-60-1 Acrylamide - sodium 2-acrylamido-2- methylpropane sulfonate copolymer Yes 25085-02-3 Acrylamide - Sodium Acrylate Copolymer or Anionic Polyacrylamide Yes 69418-26-4 

Acrylamide polymer with N,N,N-trimethyl2[1-oxo-2-propenyl]oxy Ethanaminium chloride 

Yes 

15085-02-3 Acrylamide-sodium acrylate copolymer Yes 00107-13-1 Acrylonitrile Yes Table 6 68891-29-2 

Alcohols C8-10, ethoxylated, monoether with sulfuric acid, ammonium salt Yes 

68526-86-3 Alcohols, C11-14-iso-, C13-rich Yes 68551-12-2 Alcohols, C12-C16, Ethoxylated (a.k.a. Ethoxylated alcohol) Yes 00309-00-2 Aldrin Yes 

 Aliphatic acids Yes  Aliphatic alcohol glycol ether Yes 

64742-47-8 

Aliphatic Hydrocarbon / Hydrotreated light distillate / Petroleum Distillates / Isoparaffinic Solvent / Paraffin Solvent / Napthenic Solvent 

Yes 

 Alkalinity, Carbonate, as CaCO3 Yes Table 10 

64743-02-8 Alkenes Yes 68439-57-6 Alkyl (C14-C16) olefin sulfonate, sodium salt Yes 

 Alkyl Aryl Polyethoxy Ethanol Yes  Alkylaryl Sulfonate Yes 

09016-45-9 Alkylphenol ethoxylate surfactants Yes 0.5 mg/L#

 Alpha, Radiation Yes 

none 

---------- 

0 

15 

picocuries 

per Liter 

(pCi/L) 

Table 7 
4-22

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

07439-90-5 Aluminum Yes 0.05 to 0.2 mg/L# Table 7 01327-41-9 Aluminum chloride Yes (¥) 68155-07-7 

Amides, C8-18 and C19-Unsatd., N,NBis(hydroxyethyl) Yes 

73138-27-9 Amines, C12-14-tert-alkyl, ethoxylated Yes 71011-04-6 Amines, Ditallow alkyl, ethoxylated Yes 68551-33-7 Amines, tallow alkyl, ethoxylated, acetates Yes 01336-21-6 Ammonia Yes Yes 00631-61-8 Ammonium acetate Yes Table 10 68037-05-8 Ammonium Alcohol Ether Sulfate Yes (¥) 07783-20-2 Ammonium bisulfate Yes (¥) 10192-30-0 Ammonium Bisulphite Yes (¥) 12125-02-9 Ammonium Chloride Yes (¥) Table 10 07632-50-0 Ammonium citrate Yes (¥) 37475-88-0 Ammonium Cumene Sulfonate Yes (¥) 01341-49-7 Ammonium hydrogen-difluoride Yes (¥) 06484-52-2 Ammonium nitrate Yes (¥) 07727-54-0 Ammonium Persulfate / Diammonium peroxidisulphate Yes (¥) 01762-95-4 Ammonium Thiocyanate Yes Table 10 

 Anionic copolymer Yes 

07440-36-0 Antimony Yes 0.006 0.006 Table 6 07664-41-7 Aqueous ammonia Yes Yes Table 7 

12672-29-6 Aroclor 1248 Yes Table 6 

 Aromatic hydrocarbons Yes  Aromatic ketones Yes 

07440-38-2 Arsenic Yes 0 0.01 Table 6 12174-11-7 Attapulgite Clay Yes 07440-39-3 Barium Yes 2 2 Table 7 

 Barium Strontium P.S. (mg/L) Yes 
4-23

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

121888-68-4 

Bentonite, benzyl(hydrogenated tallow alkyl) dimethylammonium stearate complex / organophilic clay 

Yes 

00071-43-2 Benzene Yes Yes 0 0.005 Table 6 

119345-04-9 Benzene, 1,1'-oxybis, tetratpropylene derivatives, sulfonated, sodium salts Yes 

74153-51-8 

Benzenemethanaminium, N,N-dimethyl-N-[2-[(1-oxo-2-propenyl)oxy]ethyl]-, chloride, polymer with 2-propenamide 

Yes 

122-91-8 Benzenemethanol,4-methoxy-, 1-formate Yes 

1300-72-7 

Benzenesulfonic acid, Dimethyl-, Sodium salt (aka Sodium xylene sulfonate) Yes 

00050-32-8 Benzo(a)pyrene Yes Table 6 00205-99-2 Benzo(b)fluoranthene Yes 

00191-24-2 Benzo(ghi)perylene Yes Table 6 

00207-08-9 Benzo(k)fluoranthene Yes Table 6 

140-11-4 Benzyl acetate Yes 

00100-51-6 Benzyl alcohol Yes Table 8 07440-41-7 Beryllium Yes 0.004 0.004 Table 6 

 Beta, Radiation Yes 

none 

---------- 

0 

4 millirems 

per year Table 7 

 Bicarbonates (mg/L) Yes Table 10 

76-22-2 Bicyclo (2.2.1) heptan-2-one, 1,7,7-trimethyl- Yes 

 Biochemical Oxygen Demand Yes Yes 

00111-44-4 Bis(2-Chloroethyl) ether Yes Table 6 

00117-81-7 Bis(2-ethylhexyl)phthalate / Di(2- ethylhexyl)phthalate Yes 0 0.006 Table 6 68153-72-0 Blown lard oil amine Yes 68876-82-4 Blown rapeseed amine Yes 

1319-33-1 Borate Salt Yes 

10043-35-3 Boric acid Yes 
4-24

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

01303-86-2 Boric oxide / Boric Anhydride Yes 07440-42-8 Boron Yes Table 7 24959-67-9 Bromide Yes Table 7 00075-25-2 Bromoform Yes Table 6 00071-36-3 Butan-1-ol Yes Table 10 68002-97-1 C10 - C16 Ethoxylated Alcohol Yes 68131-39-5 C12-15 Alcohol, Ethoxylated Yes 07440-43-9 Cadmium Yes 0.005 0.005 Table 6 07440-70-2 Calcium Yes Table 8 

1317-65-3 Calcium Carbonate Yes Table 10 

10043-52-4 Calcium chloride Yes (¥) 

1305-62-0 Calcium Hydroxide Yes 1305-79-9 Calcium Peroxide Yes 

00124-38-9 Carbon Dioxide Yes Yes 00075-15-0 Carbondisulfide Yes Table 8 68130-15-4 Carboxymethylhydroxypropyl guar Yes 09012-54-8 Cellulase / Hemicellulase Enzyme Yes 09004-34-6 Cellulose Yes 

 Cesium 137 Yes Via beta radiation  Chemical Oxygen Demand Yes Yes  Chloride Yes 250 mg/L# Table 7 

10049-04-4 Chlorine Dioxide Yes MRDLG = 0.8 MRDL=0.8 Table 10 00124-48-1 Chlorodibromomethane Yes Table 6 00067-66-3 Chloroform Yes Table 6 

78-73-9 Choline Bicarbonate Yes 67-48-1 Choline Chloride Yes 91-64-5 Chromen-2-one Yes 

07440-47-3 Chromium Yes 0.1 0.1 Table 6 00077-92-9 Citric Acid Yes 94266-47-4 Citrus Terpenes Yes 
4-25

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

07440-48-4 Cobalt Yes Table 7 61789-40-0 Cocamidopropyl Betaine Yes 68155-09-9 Cocamidopropylamine Oxide Yes 68424-94-2 Coco-betaine Yes 

 Coliform, Total Yes 0 0.05 Table 7 

 Color Yes 

15 

(Color 

Units)#

 Table 7 

07440-50-8 Copper Yes 1.0#

TT; 

Action 

Level=1.3 

Table 6 

07758-98-7 Copper (II) Sulfate Yes (¥) 14808-60-7 Crystalline Silica (Quartz) Yes Via solids and TSS 07447-39-4 Cupric chloride dihydrate Yes (¥) 00057-12-5 Cyanide Yes 0.2 0.2 Table 6 

00319-85-7 Cyclohexane (beta BHC) Yes Table 6 00058-89-9 Cyclohexane (gamma BHC) Yes 0.0002 0.0002 Table 6 

1490-04-6 Cyclohexanol,5-methyl-2-(1-methylethyl) Yes 8007-02-1 Cymbopogon citratus leaf oil Yes 8000-29-1 Cymbopogon winterianus jowitt oil Yes 

01120-24-7 Decyldimethyl Amine Yes (¥) 02605-79-0 Decyl-dimethyl Amine Oxide Yes (¥) 00055-70-3 Dibenz(a,h)anthracene Yes 03252-43-5 Dibromoacetonitrile Yes Table 9 00075-27-4 Dichlorobromomethane Yes Table 6 25340-17-4 Diethylbenzene Yes 00111-46-6 Diethylene Glycol Yes Table 10 22042-96-2 Diethylenetriamine penta (methylenephonic acid) sodium salt Yes 28757-00-8 Diisopropyl naphthalenesulfonic acid Yes 68607-28-3 Dimethylcocoamine, bis(chloroethyl) ether, diquaternary ammonium salt Yes 
4-26

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

07398-69-8 Dimethyldiallylammonium chloride Yes 00084-74-2 Di-n-butyl phthalate Yes Table 6 00122-39-4 Diphenylamine Yes Table 7 25265-71-8 Dipropylene glycol Yes 34590-94-8 Dipropylene glycol methyl ether Yes 00139-33-3 Disodium Ethylene Diamine Tetra Acetate Yes 64741-77-1 Distillates, petroleum, light hydrocracked Yes 05989-27-5 D-Limonene Yes 00123-01-3 Dodecylbenzene Yes 27176-87-0 Dodecylbenzene sulfonic acid Yes 42504-46-1 Dodecylbenzenesulfonate isopropanolamine Yes 00050-70-4 D-Sorbitol / Sorbitol Yes 37288-54-3 Endo-1,4-beta-mannanase, or Hemicellulase Yes 00959-98-8 Endosulfan I Yes Table 6 33213-65-9 Endosulfan II Yes Table 6 07421-93-4 Endrin aldehyde Yes Table 6 

149879-98-1 Erucic Amidopropyl Dimethyl Betaine Yes 

00089-65-6 Erythorbic acid, anhydrous Yes 54076-97-0 Ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2- propenyl)oxy]-, chloride, homopolymer Yes 00107-21-1 Ethane-1,2-diol / Ethylene Glycol Yes Yes Table 7 

111-42-2 Ethanol, 2,2-iminobis- Yes 

26027-38-3 Ethoxylated 4-nonylphenol Yes 09002-93-1 Ethoxylated 4-tert-octylphenol Yes 68439-50-9 Ethoxylated alcohol Yes 

126950-60-5 Ethoxylated alcohol Yes 

68951-67-7 Ethoxylated alcohol (C14-15) Yes 68439-46-3 Ethoxylated alcohol (C9-11) Yes 66455-15-0 Ethoxylated Alcohols Yes 67254-71-1 Ethoxylated Alcohols (C10-12) Yes 84133-50-6 Ethoxylated Alcohols (C12-14 Secondary) Yes 
4-27

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

68439-51-0 Ethoxylated Alcohols (C12-14) Yes 78330-21-9 Ethoxylated branch alcohol Yes 34398-01-1 Ethoxylated C11 alcohol Yes 78330-21-8 Ethoxylated C11-14-iso, C13-rich alcohols Yes 61791-12-6 Ethoxylated Castor Oil Yes 61791-29-5 Ethoxylated fatty acid, coco Yes 61791-08-0 Ethoxylated fatty acid, coco, reaction product with ethanolamine Yes 68439-45-2 Ethoxylated hexanol Yes 09036-19-5 Ethoxylated octylphenol Yes 09005-67-8 Ethoxylated Sorbitan Monostearate Yes 09005-70-3 Ethoxylated Sorbitan Trioleate Yes 

118-61-6 Ethyl 2-hydroxybenzoate Yes 

00064-17-5 Ethyl alcohol / ethanol Yes 00100-41-4 Ethyl Benzene Yes Yes 0.7 0.7 Table 6 

93-89-0 Ethyl benzoate Yes 

00097-64-3 Ethyl Lactate Yes 09003-11-6 Ethylene Glycol-Propylene Glycol Copolymer (Oxirane, methyl-, polymer with oxirane) Yes 00075-21-8 Ethylene oxide Yes Table 9 05877-42-9 Ethyloctynol Yes 

8000-48-4 Eucalyptus globulus leaf oil Yes 

61790-12-3 Fatty Acids Yes 68604-35-3 

Fatty acids, C 8-18 and C18-unsaturated compounds with diethanolamine Yes 

68188-40-9 Fatty acids, tall oil reaction products w/ acetophenone, formaldehyde & thiourea Yes 09043-30-5 Fatty alcohol polyglycol ether surfactant Yes 0.5 mg/L# 07705-08-0 Ferric chloride Yes Table 10 07782-63-0 Ferrous sulfate, heptahydrate Yes 00206-44-0 Fluoranthene Yes Table 6 00086-73-7 Fluorene Yes Table 6 
4-28

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

16984-48-8 Fluoride Yes 2# 4 Table 7 00050-00-0 Formaldehyde Yes Table 8 29316-47-0 Formaldehyde polymer with 4,1,1- dimethylethyl phenolmethyl oxirane Yes 

153795-76-7 

Formaldehyde, polymers with branched 4-nonylphenol, ethylene oxide and propylene oxide 

Yes 

00075-12-7 Formamide Yes 00064-18-6 Formic acid Yes Table 10 00110-17-8 Fumaric acid Yes Table 10 65997-17-3 Glassy calcium magnesium phosphate Yes 00111-30-8 Glutaraldehyde Yes 00056-81-5 Glycerol / glycerine Yes 09000-30-0 Guar Gum Yes 64742-94-5 Heavy aromatic petroleum naphtha Yes 09025-56-3 Hemicellulase Yes 00076-44-8 Heptachlor Yes 0 0.0002 01024-57-3 Heptachlor epoxide Yes 0 0.0002 

 Heterotrophic plate count Yes n/a TT23

07647-01-0 Hydrochloric Acid / Hydrogen Chloride / muriatic acid Yes 07722-84-1 Hydrogen Peroxide Yes Table 10 64742-52-5 Hydrotreated heavy napthenic distillate Yes 00079-14-1 Hydroxy acetic acid Yes 35249-89-9 Hydroxyacetic acid ammonium salt Yes 09004-62-0 Hydroxyethyl cellulose Yes 05470-11-1 Hydroxylamine hydrochloride Yes 39421-75-5 Hydroxypropyl guar Yes 00193-39-5 Indeno(1,2,3-cd)pyrene Yes Table 6 

23 Treatment Technology specified. 
4-29

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

07439-89-6 Iron Yes 0.3 mg/L# Table 7 35674-56-7 Isomeric Aromatic Ammonium Salt Yes 64742-88-7 Isoparaffinic Petroleum Hydrocarbons, Synthetic Yes 00064-63-0 Isopropanol Yes Table 10 00098-82-8 Isopropylbenzene (cumene) Yes Yes Table 9 68909-80-8 Isoquinoline, reaction products with benzyl chloride and quinoline Yes 08008-20-6 Kerosene Yes 64742-81-0 Kerosine, hydrodesulfurized Yes 00063-42-3 Lactose Yes 

8022-15-9 Lavandula hybrida abrial herb oil Yes 

07439-92-1 Lead Yes 0 

TT; 

Action Level

0.015 

Table 6 

64742-95-6 Light aromatic solvent naphtha Yes 01120-21-4 Light Paraffin Oil Yes 

 Lithium Yes Table 10 

07439-95-4 Magnesium Yes Table 7 

546-93-0 Magnesium Carbonate Yes 

1309-48-4 Magnesium Oxide Yes 1335-26-8 Magnesium Peroxide Yes 

14807-96-6 Magnesium Silicate Hydrate (Talc) Yes 07439-96-5 Manganese Yes 0.05 mg/L# Table 7 07439-97-6 Mercury Yes 0.002 0.002 Table 6 01184-78-7 Methanamine, N,N-dimethyl-, N-oxide Yes 00067-56-1 Methanol Yes Yes Table 10 

119-36-8 Methyl 2-hydroxybenzoate Yes 

00074-83-9 Methyl Bromide Yes Table 6 00074-87-3 Methyl Chloride / chloromethane Yes 0 0.005 Table 6 00078-93-3 Methyl ethyl ketone / 2-Butanone Yes Table 7 
4-30

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

68891-11-2 Methyloxirane polymer with oxirane, mono (nonylphenol) ether, branched Yes 08052-41-3 Mineral spirits / Stoddard Solvent Yes 64742-46-7 Mixture of severely hydrotreated and hydrocracked base oil Yes 07439-98-7 Molybdenum Yes Table 7 00141-43-5 Monoethanolamine Yes 44992-01-0 N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy Ethanaminium chloride Yes 64742-48-9 Naphtha (petroleum), hydrotreated heavy Yes 00091-20-3 Naphthalene Yes Yes Table 6 38640-62-9 Naphthalene bis(1-methylethyl) Yes 00093-18-5 Naphthalene, 2-ethoxy- Yes 68909-18-2 N-benzyl-alkyl-pyridinium chloride Yes 68139-30-0 N-Cocoamidopropyl-N,N-dimethyl-N-2- hydroxypropylsulfobetaine Yes 07440-02-0 Nickel Yes Table 6 

 Nitrate, as N Yes 10 10 Table 7 

07727-37-9 Nitrogen, Liquid form Yes 

 Nitrogen, Total as N Yes 

00086-30-6 N-Nitrosodiphenylamine Yes Table 6 26027-38-3 Nonylphenol Ethoxylate Yes 68412-54-4 Nonylphenol Polyethoxylate Yes 

 Oil and Grease Yes 

8000-27-9 Oils, cedarwood Yes 

121888-66-2 Organophilic Clays Yes 

 Oxyalkylated alkylphenol Yes 

628-63-7 Pentyl acetate Yes 540-18-1 Pentyl butanoate Yes 

8009-03-8 Petrolatum Yes 

64742-65-0 Petroleum Base Oil Yes 
4-31

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

 Petroleum distillate blend Yes 

64742-52-5 Petroleum Distillates Yes 

 Petroleum hydrocarbons Yes 

64741-68-0 Petroleum naphtha Yes 

 pH Yes 6.5-8.5# 

00085-01-8 Phenanthrene Yes Table 6 00108-95-2 Phenol Yes Table 6 

 Phenols Yes Table 6 

101-84-8 Phenoxybenzene Yes 

70714-66-8 

Phosphonic acid, [[(phosphonomethyl)imino]bis[2,1-ethanediylnitrilobis(methylene)]]tetrakis-, ammonium salt 

Yes 

57723-14-0 Phosphorus Yes Table 7 08000-41-7 Pine Oil Yes 

8002-09-3 Pine oils Yes 

60828-78-6 Poly(oxy-1,2-ethanediyl), a-[3,5-dimethyl-1- (2-methylpropyl)hexyl]-w-hydroxy- Yes 25322-68-3 Poly(oxy-1,2-ethanediyl), a-hydro-w-hydroxy / Polyethylene Glycol Yes 24938-91-8 Poly(oxy-1,2-ethanediyl), α-tridecyl- ω- hydroxy Yes 31726-34-8 Poly(oxy-1,2-ethanediyl),alpha-hexyl-omega- hydroxy Yes 

9004-32-4 Polyanionic Cellulose Yes 

51838-31-4 Polyepichlorohydrin, trimethylamine quaternized Yes 56449-46-8 polyethlene glycol oleate ester Yes 

 Polyethoxylated alkanol Yes 

9046-01-9 Polyethoxylated tridecyl ether phosphate Yes 

63428-86-4 

Polyethylene glycol hexyl ether sulfate, ammonium salt Yes 
4-32

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

62649-23-4 Polymer with 2-propenoic acid and sodium 2- propenoate Yes 

 Polymeric Hydrocarbons Yes 

09005-65-6 Polyoxyethylene Sorbitan Monooleate Yes 61791-26-2 Polyoxylated fatty amine salt Yes 65997-18-4 Polyphosphate Yes 07440-09-7 Potassium Yes Table 8 00127-08-2 Potassium acetate Yes 

1332-77-0 Potassium borate Yes 

12712-38-8 Potassium borate Yes 20786-60-1 Potassium borate Yes 00584-08-7 Potassium carbonate Yes 07447-40-7 Potassium chloride Yes 00590-29-4 Potassium formate Yes 01310-58-3 Potassium Hydroxide Yes Table 10 13709-94-9 Potassium metaborate Yes 24634-61-5 Potassium Sorbate Yes 

112926-00-8 Precipitated silica / silica gel Yes 

00057-55-6 Propane-1,2-diol, or Propylene glycol Yes Yes Table 10 00057-55-6 Propylene glycol 00107-98-2 Propylene glycol monomethyl ether Yes Table 10 00110-86-1 Pyridine Yes Table 7 68953-58-2 Quaternary Ammonium Compounds Yes Table 9 62763-89-7 Quinoline,2-methyl-, hydrochloride Yes 15619-48-4 Quinolinium, 1-(phenylmethl),chloride Yes 

 Radium Yes Table 7 

24 TOGS lists this parameter as CAS 58-55-6. 
4-33

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

 Radium 226 Yes 

none 

------------- 

zero 

5 pCi/L Table 7 

 Radium 228 Yes 

none 

------------- 

zero 

5 pCi/L 

8000-25-7 Rosmarinus officinalis l. leaf oil Yes 

00094-59-7 Safrole Yes Table 8 

 Salt of amine-carbonyl condensate Yes  Salt of fatty acid/polyamine reaction product Yes Scale Inhibitor (mg/L) Yes 

07782-49-2 Selenium Yes 0.05 0.05 Table 6 07631-86-9 Silica, Dissolved Yes Table 8 07440-22-4 Silver Yes 0.10 mg/L# Table 6 07440-23-5 Sodium Yes Table 7 05324-84-5 Sodium 1-octanesulfonate Yes 00127-09-3 Sodium acetate Yes 95371-16-7 Sodium Alpha-olefin Sulfonate Yes 00532-32-1 Sodium Benzoate Yes 00144-55-8 Sodium bicarbonate Yes 07631-90-5 Sodium bisulfate Yes 07647-15-6 Sodium Bromide Yes 00497-19-8 Sodium carbonate Yes 07647-14-5 Sodium Chloride Yes 07758-19-2 Sodium chlorite Yes 03926-62-3 Sodium Chloroacetate Yes 00068-04-2 Sodium citrate Yes 06381-77-7 Sodium erythorbate / isoascorbic acid, sodium salt Yes 02836-32-0 Sodium Glycolate Yes 

1301-73-2 Sodium hydroxide Yes 

01310-73-2 Sodium Hydroxide Yes Table 10 
4-34

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

07681-52-9 Sodium hypochlorite Yes Table 10 07775-19-1 Sodium Metaborate .8H2O Yes 10486-00-7 Sodium perborate tetrahydrate Yes 07775-27-1 Sodium persulphate Yes 68608-26-4 Sodium petroleum sulfonate Yes 09003-04-7 Sodium polyacrylate Yes 07757-82-6 Sodium sulfate Yes Table 10 01303-96-4 Sodium tetraborate decahydrate Yes 07772-98-7 Sodium Thiosulfate Yes 01338-43-8 Sorbitan Monooleate Yes 

 Specific Conductivity Yes 

07440-24-6 Strontium Yes Table 9 00057-50-1 Sucrose Yes 

 Sugar Yes 

05329-14-6 Sulfamic acid Yes 14808-79-8 Sulfate Yes 250 mg/L# Table 7 

 Sulfide Yes Table 7 

14265-45-3 Sulfite Yes Table 7 

 Surfactant blend Yes 0.5 mg/L#

68442-77-3 Surfactant: Modified Amine Yes 

 Surfactants MBAS Yes 0.5 mg/L#

112945-52-5 Syntthetic Amorphous / Pyrogenic Silica / Amorphous Silica Yes 

68155-20-4 Tall Oil Fatty Acid Diethanolamine Yes 08052-48-0 Tallow fatty acids sodium salt Yes 72480-70-7 Tar bases, quinoline derivs., benzyl chloride- quaternized Yes 68647-72-3 Terpene and terpenoids Yes 68956-56-9 Terpene hydrocarbon byproducts Yes 00127-18-4 Tetrachloroethylene Yes 0 0.005 Table 6 00533-74-4 Tetrahydro-3,5-dimethyl-2H-1,3,5-thiadiazine- 2-thione / Dazomet Yes 
4-35

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

55566-30-8 Tetrakis(hydroxymethyl)phosphonium sulfate (THPS) Yes 00075-57-0 Tetramethyl ammonium chloride Yes 00064-02-8 Tetrasodium Ethylenediaminetetraacetate Yes 07440-28-0 Thallium Yes 0.0005 0.002 Table 6 00068-11-1 Thioglycolic acid Yes 00062-56-6 Thiourea Yes Table 10 68527-49-1 Thiourea, polymer with formaldehyde and 1- phenylethanone Yes 68917-35-1 Thuja plicata donn ex. D. don leaf oil Yes 07440-32-6 Titanium Yes Table 7 00108-88-3 Toluene Yes Yes 1 1 Table 6 

 Total Dissolved Solids Yes 500 mg/L#  Total Kjeldahl Nitrogen Yes Yes  Total Organic Carbon Yes Yes  Total Suspended Solids Yes Yes 

81741-28-8 Tributyl tetradecyl phosphonium chloride Yes 

 Triethanolamine Yes 

68299-02-5 Triethanolamine hydroxyacetate Yes 00112-27-6 Triethylene Glycol Yes 52624-57-4 Trimethylolpropane, Ethoxylated, Propoxylated Yes 00150-38-9 Trisodium Ethylenediaminetetraacetate Yes 05064-31-3 Trisodium Nitrilotriacetate Yes 07601-54-9 Trisodium ortho phosphate Yes 00057-13-6 Urea Yes 07440-62-2 Vanadium Yes Table 7 25038-72-6 Vinylidene Chloride/Methylacrylate Copolymer Yes 
4-36

CAS 

Number Parameter Name Used in Additives17,18 Found in Flowback19 MCLG (mg/L)20 MCL or TT (mg/L) SPDES Tables21 

 Volatile Acids Yes 25

7732-18-5 Water Yes 8042-47-5 White Mineral Oil Yes 

11138-66-2 Xanthan gum Yes 

 Xylenes Yes Yes 10 10 

13601-19-9 Yellow Sodium of Prussiate Yes 07440-66-6 Zinc Yes 5 mg/L# Table 6 

 Zirconium Yes 

25 Several volatile compounds regulated via SPDES Table 6. Need to evaluate constituents. 
4-37

Table 4-6 – Typical concentrations of flowback constituents based on limited samples from PA and WV, a

NY26,27

CAS # Parameter Name 

Total 

Number of 

Samples 

Number of 

Detects Min Median 

00067-64-1 Acetone 3 1 681 681 

 Acidity, Total 4 4 101 240 

Alkalinity 28 155 155 0 153 

 Alkalinity, Carbonate, as CaCO3 164 163 0 9485 

Total Alkalinity 5 5 28 91 

Alpha, Radiation 15 15 0 166 

07439-90-5 Aluminum 43 12 0.02 0.07 

 Aluminum, Dissolved 22 1 1.37 1.37 

07440-36-0 Antimony 34 1 0.26 0.26 07664-41-7 Aqueous ammonia 48 45 11.3 44.8 07440-38-2 Arsenic 43 7 0.015 0.09 07440-39-3 Barium 48 47 0.553 1450 

 Barium, Dissolved 22 22 0.313 212 

00071-43-2 Benzene 35 14 15.7 479.5 07440-41-7 Beryllium 43 1 422 422 

Beta, Radiation 15 15 0 62 

26 Information presented in Table 4-6 and Table 4-7 is based on limited data from Pennsylvania and West Virginia. Characteris

Marcellus Shale in New York are expected to be similar to flowback from Pennsylvania and West Virginia, but not identical. In addit

tables came from several sources, with likely varying degrees of reliability. Also, the analytical methods used were not all the sa

Sometimes laboratories need to use different analytical methods depending on the consistency and quality of the sample; sometime

required to provide a certain level of accuracy. Therefore, the method detection limits may be different. The quality and composition well can also change within a few days soon after the well is fractured. This data does not control for any of these variables. Additiona

several of these compounds could be traced back to potential laboratory contamination. Further comparisons of analytical result

associated laboratory method blanks may be required to further assess the extent of actual concentrations found in field samples vers

found in field samples due to blank contamination. 

27 This table does not include results from the MSC Study. 28 Different data sources reported alkalinity in different and valid forms. Total alkalinity reported here is smaller than carbonate alkalin

from different sources. 
4-38

CAS # Parameter Name 

Total 

Number of 

Samples 

Number of 

Detects Min Median 

 Bicarbonates 150 150 0 183 

Biochemical Oxygen Demand 38 37 3 200 

00117-81-7 Bis(2-ethylhexyl)phthalate 20 2 10.3 15.9 07440-42-8 Boron 23 9 0.539 2.06 24959-67-9 Bromide 15 15 11.3 607 00075-25-2 Bromoform 26 2 34.8 36.65 07440-43-9 Cadmium 43 6 0.007 0.025 

 Cadmium, Dissolved 22 2 0.017 0.026 

07440-70-2 Calcium 187 186 29.9 4241 

Calcium, Dissolved 3 3 2360 22300 Cesium 137 29 16 2 9.9 10.2 

Chemical Oxygen Demand 38 38 223 5645 Chloride 193 193 287 56900 

00124-48-1 Chlorodibromomethane 26 2 3.28 3.67 07440-47-3 Chromium 43 9 0.009 0.082 

 Chromium (VI), dissolved 19 10 0.0126 0.539  Chromium, Dissolved 22 2 0.058 0.075 

07440-48-4 Cobalt 30 6 0.03 0.3975 

 Cobalt, dissolved 19 1 0.489 0.489  Coliform, Total 5 2 1 42 

 Color 3 3 200 1000 

07440-50-8 Copper 43 8 0.01 0.0245 00057-12-5 Cyanide 7 2 0.006 0.0125 00075-27-4 Dichlorobromomethane 29 1 2.24 2.24 00100-41-4 Ethyl Benzene 38 14 3.3 53.6 16984-48-8 Fluoride 4 2 5.23 392.615 

 Heterotrophic plate count 5 3 25 50 

07439-89-6 Iron 193 168 0 29.2 

 Iron, Dissolved 34 26 6.75 63.25 

07439-92-1 Lead 43 6 0.008 0.035 

29 Regulated under beta particles [19]. 
4-39

CAS # Parameter Name 

Total 

Number of 

Samples 

Number of 

Detects Min Median 

 Lithium 13 13 34.4 90.4 

 Lithium, Dissolved 4 4 24.5 61.35 

07439-95-4 Magnesium 193 180 9 177 

Magnesium, Dissolved 3 3 218 2170 

 Mg as CaCO3 145 145 36 547 

07439-96-5 Manganese 43 29 0.15 1.89 

 Manganese, Dissolved 22 12 0.401 2.975 

07439-97-6 Mercury 30 2 0.0006 0.295 00074-83-9 Methyl Bromide 26 1 2.04 2.04 00074-87-3 Methyl Chloride 26 1 15.6 15.6 07439-98-7 Molybdenum 34 12 0.16 0.44 00091-20-3 Naphthalene 23 1 11.3 11.3 07440-02-0 Nickel 43 15 0.01 0.03 

 Nickel, Dissolved 22 2 0.03 0.0715  Nitrate, as N 1 1 0.025 0.025 

 Nitrogen, Total as N 1 1 13.4 13.4  Oil and Grease 39 9 5 17 

Petroleum hydrocarbons 1 1 0.21 0.21 

 pH 191 191 0 6.6 

00108-95-2 Phenol 20 1 459 459 

 Phenols 35 5 0.05 0.191 

57723-14-0 Phosphorus, as P 3 3 0.89 1.85 07440-09-7 Potassium 33 17 15.5 125 

 Potassium, Dissolved 3 3 84.2 327 

 Radium 6 3 7.7 9.7 

Radium 226 3 3 2.58 4.67 

 Radium 228 3 3 1.15 4.66 

Scale Inhibitor 145 145 315 744 

07782-49-2 Selenium 34 1 0.058 0.058 

 Selenium, Dissolved 22 1 1.06 1.06 

07440-22-4 Silver 43 3 0.129 0.204 

 Silver, Dissolved 22 2 0.056 0.0825 

07440-23-5 Sodium 42 41 83.1 23500 

 Sodium, Dissolved 3 3 9290 54800 
4-40

CAS # Parameter Name 

Total 

Number of 

Samples 

Number of 

Detects Min Median 

07440-24-6 Strontium 36 36 0.501 1115 

 Strontium, Dissolved 22 21 8.47 629 

14808-79-8 Sulfate (as SO4) 193 169 0 1 

Sulfide (as S) 8 1 29.5 29.5 

14265-45-3 Sulfite (as SO3) 3 3 2.56 64 

Surfactants 30 12 12 0.1 0.21 

00127-18-4 Tetrachloroethylene 26 1 5.01 5.01 07440-28-0 Thallium 34 2 0.1 0.18 07440-32-6 Titanium 25 1 0.06 0.06 00108-88-3 Toluene 38 15 2.3 833 

 Total Dissolved Solids 193 193 1530 63800 

07440-62-2 Vanadium 24 1 40.4 40.4 

Total Kjeldahl Nitrogen 25 25 37.5 122 

Total Organic Carbon 31 28 23 69.2 449 

Total Suspended Solids 43 43 16 129 

 Xylenes 38 15 15.3 444 

07440-66-6 Zinc 43 18 0.011 0.036 

 Zinc, Dissolved 22 1 0.07 0.07  Fluid Density 145 145 8.39004 8.7 

Hardness by Calculation 170 170 203 11354 

 Salt % 145 145 0.9 5.8  Specific Conductivity 15 15 1030 110000  Specific Gravity 150 154 0 1.04  Temperature 31 31 0 15.3  Temperature 145 145 24.9 68 

30 Regulated under foaming agents. 31 Regulated via BOD, COD and the different classes/compounds of organic carbon. 
4-41

Table 4-7 - Typical concentrations of parameters that are not regulated, based on 

limited flowback analyses from PA and WV

Parameter Name 

Total Number 

of Samples Detects Min Median Max Units 

Barium Strontium P.S. 145 145 17 1320 6400 mg/L 

Carbon Dioxide 5 5 193 232 294 mg/L 

Zirconium 19 1 0.054 0.054 0.054 mg/L 
5-1

5 ON-SITE FLOWBACK FLUIDS TREATMENT OR RECYCLING 

TECHNOLOGIES 

5.1 Introduction 

New well completion and hydraulic fracturing methods are enabling the recovery of valuable 

onshore natural gas reserves. These new methods also require large volumes of water for the 

fracturing process and then produce flowback fluid with residual additives and high 

concentrations of a few parameters, particularly TDS, and low concentrations of several 

parameters. 

Reasonably good quality water is typically needed to harness the full benefit of fracturing fluid 

additives. Freshwater is therefore an obvious choice. But use of freshwater in hydraulic 

fracturing operations imposes an additional constraint on the resource. 

Flowback fluid disposal is also difficult. Variable percentages of fracturing fluids return to the 

surface as flowback. Presently, dilution and re-use at subsequent wells, trucking to approved 

publicly-owned treatment works (POTW) or out-of-state industrial treatment plants, or 

underground injection wells32 are the disposal options utilized. However, treating flowback fluid 

at POTWs can cause potential excursion of POTW permit limits; also, trucking the water is 

costly. Underground injection removes the water from the natural water cycle. 

On-site treatment (with off-site disposal of the contaminants removed) or recycling is seen as the 

more environmentally sound method for managing flowback. This section surveys on-site 

treatment or recycling options currently used; provides a preliminary evaluation of the extent and 

conditions of such use; and assesses the general applicability of these technologies at hydraulic 

fracturing sites in New York State. 

5.2 Flowback Recycling 

Recycling flowback in hydraulic fracturing operations presently entails primary treatment (i.e. 

settling) and then blending known amounts of flowback with freshwater [3]. Recycling the 

flowback reduces freshwater needs. However, high concentrations of different parameters 

adversely affect the desired fracturing fluid properties. Concentrations of chlorides, calcium, 

magnesium, barium, carbonates, sulfates, solids, microbes, etc. in the flowback are too high to 

use as-is [1]. The demand for friction reducers increases when the chloride concentration 

increases [1]; the demand for scale inhibitors increases when concentrations of calcium, 

magnesium, barium, carbonates, or sulfates increase [ 1]; biocide requirements increase when the 

concentration of microbes increases [6]. The current recycling practice of blending flowback 

 

32 It should be noted that while three fully permitted injection wells are operating for private oil and gas production 

brine disposal in New York, there are no currently operating commercial injection wells and none have been 

permitted for flowback injection. 
5-2

with freshwater attempts to balance the additional freshwater needs with the additional additives 

needs. 

Some form of physical and/or chemical separation (discussed later) is typically needed prior to 

recycling flowback. 

One operator who shared analytical results after using a 50-50 blend of recycled flowback and 

freshwater assessed the blended water’s corrosivity and scaling potential. Field experience 

suggests performing compatibility mixing studies prior to the actual blending flowback and 

freshwater in the field [20]. In addition, experts in the field suggest that flowback fluid and 

freshwater be evaluated multiple times during the year to assess potential seasonal variations and 

their impact on bacterial activity and water quality. Use of friction reducers, scale inhibitors, 

biocides, etc. would need to be modulated based on the composition and characteristics of the 

blend [20]. 

5.3 On-site Treatment 

Regardless of the treatment objective, whether for reuse or direct discharge, the three basic issues 

that need consideration when developing water treatment technologies are: 

1. Influent [i.e. flowback] parameters and their concentrations 

2. Parameters and their concentrations allowable in the effluent [i.e. the reuse or discharge 

water] 

3. Disposal of residuals 

5.3.1 Influent parameters and their concentrations 

Flowback consists of several parameters. Table 4-6 and Table 4-7 provide typical concentrations 

of parameters in flowback. The median value would likely be the appropriate indicator of typical 

concentration. There is no single on-site treatment technique or on-site treatment unit, to date, 

that could treat all parameters in flowback. Therefore, a series of on-site treatment technologies 

is needed to produce a usable treated flowback stream. Stringing together several treatment units 

is costly. However, treating the flowback on-site would reduce freshwater needs, reduce 

flowback disposal costs, and depending on the final quality of the treated flowback, reduce the 

cost and need for additives. 

5.3.2 Parameters and their concentrations allowable in the effluent 

All experts and operators agree that freshwater meets the water quality needs for fracturing 

fluids; they also agree that somewhat lower quality water would be usable for fracturing 

operations. But there is no consensus on the minimum allowable water quality for a fracturing 

operation: different experts suggest different limits for TDS, chloride, calcium, etc. Table 5-1 is a 
5-3

listing of allowable water quality requirements for fracturing fluids based on input from one 

expert panel [1]. 

Table 5-1 – Allowable water quality requirements for fracturing fluids, based on input 

from one expert panel on Barnett Shale 

Constituent Concentration 

Chlorides 3,000 - 90,000 mg/L 

Calcium 350 - 1,000 mg/L 

Suspended Solids < 50 mg/L 

Entrained oil and soluble organics < 25 mg/L 

Bacteria < 100 cells/100 ml 

Barium Low levels 

Flowback characteristics based on limited data from PA and WV are provided in Table 4-6 and 

Table 4-7. 

5.3.3 Disposal of residuals 

Presently there is limited on-site treatment of flowback in the Barnett Shale due to economic 

infeasibility. However, based on feedback from a few operators, when on-site treatment is 

provided, the residuals (or concentrates) are injected into deep and stable strata (UIC wells). The 

regulatory framework for disposal of these residuals is complex and is further discussed later in 

this chapter. 

5.3.4 Factors affecting on-site treatment 

Several factors would influence the decision to utilize on-site treatment and the selection of 

specific treatment options. These include: 

Operational 

 Flowback fluid characteristics, including scaling and fouling tendencies 

 On-site space availability 

 Processing capacity needed 

 Solids concentration in flowback fluid, and solids reduction required 

 Concentrations of hydrocarbons in flowback fluid, and targeted reduction in 

hydrocarbon33 

 Species and levels of radioactivity in flowback 

 

33 Liquid hydrocarbons have not been detected in all Marcellus Shale gas analyses. 
5-4

 Access to freshwater sources 

 Targeted recovery rate 

 Impact of treated water on efficacy of additives 

 Availability of residuals disposal options 

Cost 

 Capital costs associated with treatment systems 

 Transportation costs associated with freshwater 

 Transportation costs associated with disposal of residuals 

 Increase or decrease in fluid additives from using treated flowback fluid 

 Energy costs required to run treatment systems 

 Flowback storage costs 

Environmental 

 On-site topography 

 Density of neighboring population 

 Proximity to freshwater sources 

 Other demands on freshwater in the vicinity 

 Regulatory environment 

5.4 On-site Treatment Technologies 

One of the several on-site treatment technology configurations is illustrated in Figure 5-134. The 

parameters treated are listed at the bottom of the figure. The next few sections present several 

on-site treatment technologies that have been used to some extent in the Barnett Shale or Powder 

River Basin gas extraction operations. In addition, technology providers have begun working 

with gas producers within the Marcellus Shale. A table summarizing many of these vendors’ 

products is provided in Table 5-6. 

 

34 All treatment steps illustrated in Figure 5-1 may not be necessary for flowback from each well. The particular 

characteristics of flowback would determine the specific steps. 
5-5

Figure 5-1 - One configuration of potential on-site treatment technologies 

Some form of physical and/or chemical separation will be required as a part of on-site treatment. 

Physical and chemical separation technologies typically focus on the removal of oil and grease 

and suspended matter from flowback. 

5.4.1 Physical Separation 

Filters, hydrocyclones and centrifuges are some of the technologies used to physically separate 

solids in wastewater. However, none of the flowback treatment vendors appear to utilize 

hydrocyclones or centrifuges in their treatment systems. 

The efficiency of filtration technologies is controlled by the size and quantity of constituents 

within the flowback fluid as well as the pore size and total contact area of the membrane. To 

increase filtration efficiency, one vendor provides a vibrating filtration unit (several different 

pore sizes are available) for approximately $300,000; this unit can filter 25,000 gallons per day. 

Physical 

Separatio

n

Bio 

Reactor 

Chemical 

Precipitati

on

Electrodialysis

Thermal 

Distillatio

n

Reverse 

Osmosis 

Electrodialysis 

Reversal 

Ion 

Exchange 

OR 

OR 

OR 

Oil and 

grease 

Suspended 

Dissolved oils Hydrocarbons

Organics 

Heavy metals 

TDS 
5-6

Microfiltration has been shown to be effective in lab-scale research, nanofiltration has been used 

to treat produced water from off-shore oil rigs, and modular filtration units have been used in the 

Barnett Shale and Powder River Basin [21, 22, 23, 24]. 

5.4.2 Chemical Separation and Precipitation 

Chemical separation utilizes coagulants and flocculants to break emulsions (dissolved oil) and to 

remove suspended particles. Precipitation is accomplished by manipulating flowback chemistry 

such that constituents within the flowback (in particular, metals) will precipitate out of solution. 

This can also be performed sequentially, so that several chemicals will precipitate, resulting in 

cleaner flowback. 

Separation and precipitation are used as pre-treatment steps within multi-step on-site treatment 

processes. Chemical separation units have been used in the Barnett Shale and Powder River 

Basin, and some vendors have proprietary designs for sequential precipitation of metals for 

potential use in the Marcellus Shale [25, 26, 27]. 

If flowback is to be treated solely for blending and re-use as fracturing fluid, chemical 

precipitation may be one of the only steps needed. By precipitation of scale-forming metals (e.g. 

barium, strontium, calcium, magnesium), minimal excess treatment may be required. Prices for 

chemical precipitation systems are dependent upon the cost of the treatment chemicals; one 

vendor quoted a 15 gallon per minute (gpm) system for $450,000 or a 500 gpm system for 

approximately $1 million, with costs ranging from $0.50 to $3 per barrel. 

5.4.3 Membranes / Reverse Osmosis 

Membranes are an advanced form of filtration, and may be used to treat TDS in flowback. The 

technology allows water, the permeate, to pass through the membrane but the membrane blocks 

passage of suspended or dissolved particles larger than the membrane pore size. This method 

may be able to treat TDS concentrations up to approximately 45,000 mg/L, and produce an 

effluent with TDS concentrations between 200 and 500 mg/L. This technology generates a 

residual, the concentrate, which would need proper disposal. The flowback recovery rate for 

most membrane technologies is typically between 50 and 75 percent. It is important to note that 

membrane performance is typically impacted by scaling and/or microbiological fouling; 

therefore, flowback requires extensive pretreatment before it can be sent through a membrane. 

Reverse osmosis (RO) is a membrane technology that uses osmotic pressure on the membrane to 

provide passage of high quality water, producing a concentrated brine effluent that will require 

further treatment and disposal. RO is frequently used in various desalination projects, in both 

modular and permanent configurations. 

RO is a well-proven technology, though it is less efficient under high TDS concentrations. High 

TDS concentrations, such as in Marcellus flowback (Table 4-6), will likely result in large 

quantities of concentrated brine (or reject) that will require further treatment or disposal. When 

designing treatment processes, several vendors use RO as a primary treatment (with appropriate 
5-7

pre-treatment prior to RO); and then use a secondary treatment method for the concentrated 

brine. The secondary treatment can be completed on-site, or the concentrated brine can be 

trucked to a centralized brine treatment facility. 

Modular membrane technology units have been used in many different regions for many 

different projects, including the Barnett Shale. Some firms have developed modular RO 

treatment units, which could potentially be used in the Marcellus [28, 29, 30, 31, 32]. 

5.4.4 Ion Exchange 

Ion exchange units utilize different resins to preferentially remove certain ions. When treating 

flowback, the resin would be selected to preferentially remove sodium ions. The required resin 

volume and size of the ion exchange vessel would depend on the salt concentration and flowback 

volume treated. 

The Higgins Loop is one version of ion exchange that has been successfully used in Midwest 

coal bed methane applications. The Higgins Loop uses a continuous countercurrent of flowback 

fluid and ion exchange resin. High sodium flowback fluid can be fed into the absorption 

chamber to exchange for hydrogen ions. The strong acid cation resin is advanced to the 

absorption chamber through a unique resin pulsing system [33]. 

Modular ion exchange units have been used in the Barnett Shale. 

5.4.5 Electrodialysis 

These treatment units are configured with alternating stacks of cation and anion membranes that 

allow passage of flowback fluid. The electric current applied to the stacks forces anions and 

cations to migrate in different directions [32]. 

Electrodialysis Reversal (EDR) is similar to electrodialysis, but its electric current polarity may 

be reversed as needed. This current reversal acts as a backwash cycle for the stacks, which 

reduces scaling on membranes. EDR offers lower electricity usage than standard RO systems 

and can potentially reduce salt concentrations in the treated water to less than 200 mg/L. 

Modular electrodialysis units have been used in the Barnett Shale and Powder River Basin. 

Table 5-2 - Treatment capabilities of EDR and RO Systems 

Criteria EDR RO 

Acceptable influent TDS (mg/L) 400-3,000 100-15,000

Salt removal capacity 50-95% 90-99% 

Water recovery rate 85-94% 50-75% 

Allowable Influent Turbidity Silt Density Index (SDI) < 12 SDI < 5 

Operating Pressure <50 psi > 100 psi 

Power Consumption Lower for <2,500 mg/L TDS Lower for >2,500 mg/L TDS 
5-8

Criteria EDR RO 

Typical Membrane Life 7-10 years 3-5 years 

5.4.6 Thermal Distillation/Evaporation 

Thermal distillation utilizes evaporation to produce clean, distilled water from the flowback 

fluid. The various evaporative schemes that can be used within this process are generally 

insensitive to scaling, and are therefore more effective at higher TDS concentrations (>150,000 

mg/L) than other treatment technologies. 

Traditionally energy and space intensive, recent industry advancements have produced modular 

distillation/evaporation units that are less cost-prohibitive than older models. Some systems 

have been designed with the option to utilize natural gas that may be available from the well 

pad35, while others use recycled waste heat (primarily from gas compressors at the well pad) as 

the sole heat source. In addition to new sources of thermal energy for distillation systems, some 

vendors have designed systems that require significantly less energy than traditional distillation 

processes. While this makes thermal distillation a more feasible approach to flowback water 

treatment, these lower energy systems are most effective on highly concentrated wastewaters, 

thus minimizing the amount of water needed to be evaporated. Due to these limitations, some 

vendors suggest that thermal distillation/evaporation be used as a secondary treatment; further 

concentrating the wastewater concentrate from a filtration or reverse osmosis treatment system. 

Modular thermal distillation units have been used in the Barnett Shale, and have begun to be 

used in the Marcellus Shale in Pennsylvania. In addition to the units that are already in use, 

several vendors have designs ready for testing, potentially further decreasing costs in the nearfuture [23, 24, 30, 34, 35, 36, 37, 38]. 

Due to the high TDS concentrations found in Marcellus flowback samples, mobile evaporation 

treatment systems appear to be the most feasible system for treatment of flowback water. Many 

vendors who supply evaporation units offer rentals that may be paid for on a volumetric basis. 

Rate quotes from vendors are provided in Table 5-6; the rates are within the general range of $3 

to $4.50 per barrel of flowback. 

5.4.7 Crystallization/Zero Liquid Discharge 

Zero liquid discharge (ZLD) follows the same principles as physical and chemical separation 

(precipitation, centrifuges, etc.) and evaporation, however a ZLD process ensures that all liquid 

effluent is of reusable or dischargeable quality. Additionally, any concentrate from the treatment 

process will be crystallized and will either be used in some capacity on site, will be offered for 

 

35 During initial exploration and production phases, natural gas would likely not be readily available at the well pad. 
5-9

sale as a secondary product if radiological parameters are below an acceptable threshold, or will 

be treated in such a way that it will meet regulations for disposal within a landfill. 

ZLD treatment is a relatively rare, expensive treatment process, and while some vendors suggest 

that the unit can be setup on the well pad, a more cost-effective use of ZLD treatment will be at a 

centralized treatment plant located near users of the systems’ byproducts. In addition to the 

crystallized salts produced by ZLD, treated effluent water and/or steam will also be a product 

that can be used by a third party in some industrial or agricultural setting. 

ZLD treatment systems are in use in a variety of industries, but none have been implemented in a 

natural gas production setting yet. Some technology vendors have advertized ZLD as a 

treatment option in the Marcellus, but the economical feasibility of such a system has not yet 

been demonstrated [30, 35, 37, 38]. 

5.4.8 Ozone/Ultrasonic/Ultraviolet 

These technologies are designed to oxidize and separate most hydrocarbons and heavy metals, 

and oxidize biological films and bacteria from flowback fluid. The microscopic air bubbles in 

supersaturated ozonated water and/or ultrasonic transducers cause oils and suspended solids to 

float. 

Multiple vendors include ozone treatment technologies as one step in their flowback treatment 

process, including treatment for blending and re-use of water in drilling new wells. Systems 

utilizing ozone technology have been successfully used and analyzed in the Barnett Shale [31, 

39]. 

5.4.9 Comparison of potential on-site treatment technologies 

A comparison of performance characteristics associated with on-site treatment technologies is 

provided in Table 5-3. 

Table 5-3 - Summary of Characteristics of On-site Flowback Fluid Treatment 

Technologies

Characteristic Filtration Ion 

Exchange

Reverse 

Osmosis EDR Thermal Distillation

Ozone / 

Ultrasonic / 

Ultraviolet

Energy Cost Low Low Moderate High High Low

Energy Usage 

vs. TDS N/A Low Increase High Increase Independent Increase

Applicable to All Water 

types

All Water 

types

Moderate 

TDS High TDS High TDS All Water types

Plant / Unit size Small / 

Modular

Small / 

Modular Modular Modular Large Small / Modular
5-10

Characteristic Filtration Ion 

Exchange

Reverse 

Osmosis EDR Thermal Distillation

Ozone / 

Ultrasonic / 

Ultraviolet

Microbiological 

Fouling Possible Possible Possible Low N/A Possible

Complexity of 

Technology Low Low

Moderate / 

High 

Maintenance

Regular 

Maintenance Complex Low

Scaling 

Potential Low Low High Low Low Low

Theoretical 

TDS Feed Limit 

(mg/L)

N/A N/A 32,000 40,000 100,000+ Depends on 

turbidity

Pretreatment 

Requirement N/A Filtration Extensive Filtration Minimal Filtration

Final Water 

TDS

No 

impact

200-500 

ppm

200-500 

ppm

200-1000 

ppm

< 10 mg/L Variable

Recovery Rate 

(Feed TDS 

>20,000 mg/L)

N/A N/A 30-50% 60-80% 75-85% Variable

5.5 On-site containment of flowback 

Specific regulations applicable to containment of waste streams are typically governed by the 

type (classification) of waste. The following sections discuss the available containment vessels, 

and the regulations that could potentially apply to flowback. 

Due to the large volumes of water required for hydraulic fracturing operations and the limited 

quantities of water that can be withdrawn and transported in a single day, some form of on-site 

containment is needed. The two predominant methods of achieving on-site containment are the 

construction of artificial impoundments and the use of portable water tanks, commonly called 

frac tanks. Typically, operators utilize a combination of impoundments and frac tanks. 

5.5.1 Frac tanks 

Frac tanks are available from many different vendors and, for the most part, follow similar 

patterns of design. Whether a producer chooses to purchase or to rent frac tanks, there are 

essentially three designs from which to choose. 

The most prevalent design is a 21,000-gallon, V-bottom, rectangular tank with a single axle. 

These tanks are designed to be pulled by any semi-truck with a fifth-wheel hitch. The V-shaped 

bottom of the tank allows for easy cleaning of the interior of the tank (which must be done to 

prolong tank life). 
5-11

Another popular design is very similar to the previous one, however instead of a V-bottom, these 

tanks have a cylindrical bottom. Functionally, there is not much difference between these two 

tank designs. 

The third frac tank design is a skid-mounted cylindrical tank. The main difference between these 

tanks and the wheeled, rectangular tanks previously described is that the cylindrical tanks must 

be loaded onto a flat-bed trailer for transport. While tank transport may be more challenging for 

these tanks, they are available in volumes larger than the 21,000-gallon rectangular tanks. 

Most frac tanks are designed to have at least one man-way, which allows access to the interior of 

the tank for cleaning and maintenance. Additional features that are commonly installed include: 

interior weirs to allow for solids settling, interior epoxy coating to minimize corrosion, volume 

gauges, and various adjustable piping and drainage configurations. Many manufacturers also 

supply geomembrane containment berms that are designed to sit under the frac tanks which will 

capture any spills or stray fluids that escape the tanks. Some manufacturers also offer doublewalled tanks for an extra level of protection; these tanks typically offer less capacity than the 

21,000, single-walled tanks. 

Each frac tank is capable of holding only a small portion of the frac fluid or flowback at any 

given time. To account for this, operators use hoses and connections to connect (“gang”) several 

frac tanks together. If an operator were using the standard 21,000-gallon frac tank, 48 

completely filled tanks would be required to hold a million gallons of fluid on-site. This ganged 

configuration results in large and variable capacity of the water storage system, a feature not 

available if using only an on-site impoundment, however this could prove to be a costly and 

space-consuming approach to on-site fluid containment. 

5.5.2 On-site impoundments (storage pits) 

In coordination with frac tanks or alone, some form of on-site impoundment is typically needed 

for hydraulic fracturing operations. In addition to holding water for fracturing and storing 

flowback, impoundments are commonly used by drillers to hold water and drilling mud, as well 

as by producers to hold produced water and other wastewaters and brines created at the well-site. 

The use of these impoundments, as well as their design, is typically controlled by various state 

regulations. While many states have such regulations, this section of the report will compare 

regulations governing impoundments from two states with current natural gas operations (Texas 

and Pennsylvania) to the comparable, existing New York state regulations. 

Many aspects of Texas’ and Pennsylvania’s impoundment regulations are complementary; 

however they are implemented in slightly different ways. There are three broad differences 

between the two states’ regulations on impoundments. These are in: 

1. The approval process; 

2. Use of synthetic liners; and 

3. Need for leak detection. 
5-12

Texas regulation governing the use of storage pits states that the Texas Railroad Commission 

must approve of the pit design before any oil or gas operator is permitted to use an on-site 

impoundment [40]. The Commission has published a guidance manual specifying design criteria 

which are deemed appropriate [41]. Pennsylvania, on the other hand, incorporated the design 

criteria into the actual regulations [42]. 

The most significant difference between these two states’ containment regulations is in the use of 

synthetic liners. Pennsylvania requires the use of such a liner for all oil and gas-related 

containment ponds; however, Texas allows use of compacted soil without a synthetic liner for 

certain types of containment ponds. Large portions of Texas are underlain by clay soils that, 

when compacted, are expected to meet the state’s permeability requirement. Although not 

applicable for many pits, this potentially gives Texas gas operators, upon regulatory approval, 

the ability to utilize unlined, compacted soil containment ponds – a design option not available in 

Pennsylvania [41]. 

The other significant difference between these two states’ regulations is the requirement for leak 

detection systems for brine containment pits. Texas regulation requires leak detection systems 

for brine containment pits that use a synthetic liner. Other pit types may not be required to have 

a leak detection system, unless determined to be in a hydrologically sensitive area (e.g., regions 

where the groundwater is close to the surface). Pennsylvania, on the other hand, does not require 

a leak detection system. If a liner’s integrity is found to be compromised, alternative storage or 

disposal of the waste must be completed, however there is no regulation requiring an earlydetection system for leaks from on-site containment ponds in Pennsylvania. 

Table 5-4 - Design specifications for containment ponds as required by state regulations 

Design 

Requirement Texas Pennsylvania 

Relevant Code Title 16: Economic Regulation §3.8: Oil 

and Gas Division – Water Protection 

Specifications from: Surface Waste 

Management Manual Chapter IV: Pits 

Title 25: Environmental Protection §78.56: 

Oil and Gas Wells – Environmental 

Protection Performance Standards 

Required 

Freeboard 

Requires that freeboard be “consistent with 

the volume of wastewater to be retained” 

Requires 2 feet of freeboard 

(unless connected to overflow tanks) 

Liner No liner required if compacted soil’s 

permeability is 10-7 cm/sec or less, and is at 

least 2 feet thick 

Synthetic flexible liner required 

Maximum liner 

permeability 

Not explicitly listed, but no more than 10-7

cm/sec 

10-7 cm/sec 

Seam joining Factory seams when possible – seams 

oriented up and down a slope, not across – 

installed by qualified personnel – minimize 

number of seams 

Must be leak-proof, installed per 

manufacturer’s instructions 
5-13

Design 

Requirement Texas Pennsylvania 

Long-term 

stability of liner 

Chemical compatibility with waste; 

mechanical stability during: transport, 

installation, settlement of base soils; resistant 

to UV damage 

Not to be physically or chemically damaged 

by: waste, transportation, handling, 

installation, or use 

Liner subbase Compacted soil – remove rocks and jagged 

irregularities and debris 

Smooth, uniform, and free of materials that 

may cause liner to fail – 6 inches of soil or 

gravel must be between liner and rock layers 

Height above 

groundwater 

Varies - if groundwater is close to surface, 

above ground pit may be required 

20 inches above seasonal high water table 

Leak protection Leak detection system required for synthetic 

liners – required for any pit in a sensitive 

area 

Managed to preserve liner integrity – if not 

able, materials must be removed and 

disposed 

Filling of pit Individual permits will have requirements for 

backfilling pits 

Unless holding material for disposal, pit must 

be removed or filled within 9 months after 

well-drilling is completed (90 days if used 

for well servicing, plugging, or 

recompleting) 

Alternative 

designs 

Flexible regulations provide for different 

design approaches, including other liner 

systems 

Alternate designs - PADEP approval 

required prior to construction 

New York State code allows for oil/gas field brine storage, for a limited time, in watertight tanks, 

containers or earthern pits, if underlain by clay or hardpan, and constructed and maintained so as 

to prevent escape of brine or salt water[43]. See Section 4.7.2 for additional information. The 

GEIS further requires use of a plastic liner for all pits and specifies pit design and construction 

procedures [18]. 

The regulated design criteria for solid waste disposal pits in New York are similar to regulations 

in place for water/flowback storage impoundments in other oil and gas producing states. These 

regulations require double-lined systems, with a leak detection system, as well as several 

groundwater monitoring wells [44]. 

In addition to regulations in place in other states, more stringent state regulation of on-site 

impoundments for oil and gas wastes (including flowback) is recommended by the USEPA. As 

discussed in the following section, adequate state regulation of impoundment design was one of 

the driving reasons the USEPA exempting oil and gas wastes from certain federal waste 

management regulations. Where adequate state regulations do not exist, the USEPA 

recommends that potential deficiencies in the state regulations be addressed appropriately. 
5-14

5.6 Exemption of oil and gas waste from federal regulations 

On-site treatment and containment of drilling mud and flowback fluids requires compliance with 

federal and state regulations. However, this industry is presently exempt from some of the more 

stringent federal regulations. The Resource Conservation Recovery Act (RCRA) governs how 

waste materials are handled and disposed of, including a subcategory of solid wastes that are 

defined as hazardous. Depending on the specific constituents in flowback from a particular 

site/location, as defined by the RCRA, flowback fluid may be considered a solid waste [45]; 

however, regardless of the fluid’s Toxicity Characteristics, because of its exemption from 

RCRA, flowback will be exempt from federal classification as a hazardous waste [46, 47]. 

The USEPA reviewed existing regulations prior to preparing its 1988 regulatory determination 

resulting in the exemption of oil and gas exploration and production wastes from federal 

hazardous waste regulations [48]. That review resulted in the following conclusions: 

 Many samples of oil and gas exploration and production wastes exhibited toxic 

characteristics, although these characteristics alone do not indicate the actual threat to 

human or environmental health. Location and management practices, among other 

factors, help to reduce risks from these wastes. 

 Categorizing these wastes as hazardous under RCRA would have a large (multi-billion 

dollar) economic impact upon the oil and gas industry, with some of the impact being 

passed on to consumers, ultimately resulting in as much as an estimated 12% decrease in 

production. 

 Existing state and federal regulations should provide effective regulation of oil and gas 

wastes, without requiring the stringent RCRA hazardous waste regulation. 

 Certain state regulations, including the design and maintenance criteria for waste 

containment ponds, may not be adequate. 

Table 4-6 is a summary of flowback constituents-related data provided by industry via 

NYSDEC. Similar to the USEPA study, concentrations of most constituents in Table 4-6 are 

lower than required for classification as hazardous due to toxicity. Median concentrations of 

barium, benzene and mercury come close to (or exceed) the regulatory toxicity level. It is 

important to note that, per 40 CFR 261.24, toxic concentrations need to be determined using 

specifically prescribed analytical methods; these methods were not used for analyses reported in 

Table 4-6. 

Barium was detected in nearly all flowback samples that analyzed for barium. This is expected: 

barium is a component of most drilling muds and would therefore be present in flowback. The 

maximum concentration of barium for the Toxicity Characteristic, as provided in 40 CFR 

261.24, is 100 mg/L. The median concentration of barium in Table 4-6 is approximately 1500 

mg/L. 

Similarly, benzene was detected in several flowback samples that analyzed for it. The maximum 

concentration of benzene for the Toxicity Characteristic, as provided in 40 CFR 261.24, is 0.5 
5-15

mg/L. The median concentration of benzene found in samples that analyzed for it was 

approximately 0.5 mg/L. 

Similarly, the mercury Toxicity Characteristic concentration is 0.2 mg/L. The median mercury 

concentration in Table 4-6 is nearly 0.3 mg/L. 

While it is acknowledged that oil and gas exploration and production wastes may indeed have 

toxic characteristics, the EPA concluded that the economic burden imparted on operators if these 

wastes were regulated under RCRA hazardous waste rules was not justified, given other federal 

waste regulations and additional state regulations already in place. 

In addition, the USEPA found that state and federal regulations already in place are sufficient for 

protecting the environment and the public from the hazardous characteristics of these wastes. 

The USEPA argued that the systems in place to protect surface water (National Pollutant 

Discharge Elimination System – NPDES; SPDES in New York) and groundwater (Underground 

Injection Control - UIC) from pollution would regulate the ultimate fate of these wastes. 

5.7 Naturally Occurring Radioactive Materials and Water Treatment 

All environmental media contain Naturally Occurring Radioactive Materials (NORM) and is 

radioactive to some degree. NORM is often exposed during drilling, flowback and production 

operations and may be of particular concern in the Marcellus Shale. Flowback can carry NORM 

with it when it returns to the well pad surface. Radium-226 has a 1,600 year half-life, is 

commonly occurring, and undergoes alpha decay. Radium-228 has a half-life of 5.76 years, and 

undergoes beta decay [49]. 

Alpha and beta radiation, indicators of radioactive decay, were each detected in all flowback 

samples that tested for them. Additionally, some samples were tested for radium-226 and 

radium-228. These results were summarized in Table 4-6, and repeated below in Table 5-5. 

The use of gross alpha and beta analyses as indicators of the concentration of radium isotopes 

may be limited due to the variability in the correlation between gross analytical results and 

concentrations of Ra-226 ad 228. 

The MSC Study Report does not evaluate NORM. 

Table 5-5 – Radiological data in limited flowback analyticals from PA and WV 

Parameter 

Total Number 

of Samples 

Number of 

Detects Minimum Median Maximum Units 

Radium 6 3 7.7 9.7 24 pCi/L 

Radium 226 3 3 2.58 4.67 33 pCi/L 

Radium 228 3 3 1.15 4.66 18.41 pCi/L 

Alpha radiation 15 15 0 166 18950 pCi/L 

Beta radiation 15 15 0 62 7445 pCi/L 
5-16

5.7.1 Federal and state regulations regarding NORM 

The reported levels of NORM in Marcellus Shale flowback samples are relatively low. Limited 

data from PA and WV has indicated higher NORM concentrations in later flowback water than 

in the initial flowback water. Based on limited data, it appears that NORM concentrations in 

production brine are higher than in flowback water. 

Treatment of flowback water or production brine could result in the presence of “processed and 

concentrated NORM,” also known as “technologically-enhanced” NORM (TENORM) in the 

concentrated brine, solids, or sludge, which could potentially be subject to regulation under 6 

NYCRR Part 380. At the federal level, jurisdictional agencies may include the USEPA, the 

Nuclear Regulatory Commission (NRC), Occupational Safety and Health Administration 

(OSHA), and Pipeline and Hazardous Materials Safety Administration (PHMSA). In the 

absence of any delegated state authority, these agencies would have regulatory jurisdiction at 

various points throughout the waste treatment, transportation and disposal processes [50]. 

Various individual states have introduced regulations related to NORM and TENORM, including 

regulatory frameworks for NORM disposal, as described below. In New York, many NORMrelated regulatory responsibilities lie with the NYS Departments of Environmental Conservation 

(NYSDEC) and Health (NYSDOH). The NYSDEC has radiological regulatory authority as well 

as waste regulatory authority, and NYSDOH has regulatory authority over worker and public 

health protection from radiation along with the authority and responsibility to issue licenses to 

operators where radioactivity levels meet specified thresholds. 

5.7.2 Disposal of TENORM produced by natural gas drilling

Efficient wastewater treatment processes typically achieve a high water recovery rate by 

concentrating the solids/sludges, etc. While there are several treatment technologies or methods 

(discussed in Section 5.4) that could potentially treat flowback for one or more constituents, at 

present, there is no practical and cost-effective method to selectively remove NORM or 

processed and concentrated NORM. Therefore the impact of concentrating waste streams that 

could potentially contain NORM must be considered by gas developers and treatment plant 

operators. 

Some states have implemented regulatory frameworks for disposal of oil-and-gas-associated 

waste streams that could contain NORM. The most frequently mentioned methods of disposal 

are: 

 On-site injection into oil/gas well once production has ceased. 

 On-site spreading of waste on land (incorporation into topsoil). 

 Off-site injection into permitted disposal wells. 

 Road application of brine for ice melting purposes [56]. 

 Disposal at permitted RCRA C facilities. 
5-17

 Disposal at permitted low-level radioactive waste repositories (this is a last resort 

disposal method). 

 Off-site brine treatment facilities (permitted to treat produced waters and brines – 

potentially limited influent NORM levels). 

Note that not all these methods are allowed or implemented in all states with oil and gas 

production. In particular, New York’s Part 380 regulations do not provide for a land spreading 

option and the process required under 6 NYCRR Part 364 for a Beneficial Use Determination to 

allow road application would consider radioactivity levels and result in a denial if a public health 

concern is determined to exist. 

In addition to the flowback water and/or treatment concentrates containing NORM or TENORM, 

any equipment used onsite has the potential to become contaminated with built-up radioactive 

material. To address this issue, some states with significant oil and gas production have also 

implemented regulations governing the decontamination and re-use and/or disposal of such 

equipment. 

5.7.3 Pre-treatment potential for radium 

At present, there does not appear to be a commercially used36 treatment method that selectively 

treats/removes radium from flowback or production brine. Chemical precipitation, for example, 

is based on the chemical’s solubility constant/product. The solubility of radium and its 

compounds is similar to the solubility of several other metals and their compounds. Therefore 

isolating it via precipitation, when treating large volumes of waste streams, would be 

challenging. 

Treatment techniques, such as chemical precipitation, ion-exchange or activated carbon that 

remove radium also remove other metals. The treatment capacity (chemical usage, size of ionexchange unit, size of carbon beds, etc.) therefore needs to be sufficiently large to accommodate 

all similar metals in flowback and production brine. Any flowback treatment system would have 

sludge and rejects handling needs; the presence of NORM or processed and concentrated NORM 

would elevate the standard of care needed for handling sludge and rejects [57]. Several of the 

vendors of treatment technologies listed in Table 5-6 suggest removing radium at an earlier 

phase in the treatment process to avoid potential contamination of subsequent treatment units. 

Because of the potential challenges with handling waste streams that may contain processed and 

concentrated NORM, treating flowback with appreciable amounts of NORM would be difficult. 

 

36 Here ‘Commercial Use’ encompasses wastewater treatment beyond flowback, but takes into consideration the 

potential large volumes that would need handling. 
5-18

5.8 Summary 

While costly, on-site treatment of flowback water may offer many advantages to Marcellus gas 

operators. Treatment and re-use of flowback will reduce the quantity of fresh water required for 

fracturing operations, which will in turn reduce withdrawal and trucking costs. On-site treatment 

may also potentially reduce disposal cost of flowback fluids, by decreasing volumes that must be 

trucked to a centralized treatment facility or disposal site. 

On-site treatment technology is not necessarily widely available, although an increasing number 

of producers are beginning to use such systems within the Marcellus Shale in various capacities. 

On-site treatment technologies would likely evolve more rapidly when industry need and 

regulatory environment call for it. 

Several challenges would need to be overcome to successfully implement on-site treatment 

and/or re-use of flowback water. The uncertainties associated with minimum water quality that 

may be utilized in fracturing operations, the large fluctuations in flowback quality, and the 

differences in quality of flowback from different shale formations are all potential issues that 

must be addressed. 

In addition to the above uncertainties, storage, handling, and ultimate disposal of flowback 

concentrates could become further complicated by its potentially hazardous or radioactive 

properties. 

While presently exempt from federal hazardous waste regulations, flowback’s potential 

hazardous characteristics should be considered when designing on-site containment systems. 

Several new flowback treatment systems have been proposed and tested in the last few years. 

Treatment capability will likely continue to improve and treatment costs will likely decline as the 

oil and gas industry begins to utilize treatment technologies more extensively.
5-19

Table 5-6 - Select characteristics of various treatment technologies currently offered or under design37

Vendor Processes used Flowrate/unit Allowable Influent TDS % Recovered as Effluent Effluent quality Footprint/ unit Energy Usage Appr

P

A & B 

Thermal Distillation/ 

Evaporation 

720,000 gpd 

10,000 mg/L >95% 

<5 mg/L TDS Onsite/ modular in addition to a centralized plant High 

Crystallization 150,000 mg/L 50% 

B 

Brine concentration - - - - - - >95% <10 mg/L TDS 

Onsite/ modular units or 

centralized treatment plant Moderate to high 

$50M-

cen

treatm

Evaporation - - - - - - - - - - - - 

Crystallization - - - - - - - - - - - - 

Reverse Osmosis 662,400 gpd 45,000 mg/L 35-45% - - - 

C & D 

Chemical Precipitation 

100,000 gpd custom custom - - - Onsite/ modular Low 

Oxidation 

E 

Oxidation 

- - - 

40,000 mg/L 

chloride - - - on-site reuse Onsite/ modular - contained in frac tanks Moderate Contra

per 

Reverse Osmosis 

F & G 

Filtration 

126,000 gpd/unit - - - 90-95% distilled water (<200 mg/L TDS) Onsite/ portable High $3-$4 

Thermal Distillation/ 

Evaporation 

Oxidation 

H Nanofiltration w/ vibration 316,800 gpd discharge or reuse 80% injection well 4’x4’x16’H Low to moderate $300,

25,000 

I 

Thermal Distillation/ 

Evaporation 72,000 gpd - - - - - - for blending and 

reuse 

Onsite/ modular Moderate to high 

$4 p

Reverse Osmosis 1,008,000 gpd - - - 75% - - - Moderate 

J Thermal Distillation/ Evaporation 330 gpd/unit 150,000 mg/L (41,700 mg/L in test results) 90% < 500 mg/L TDS (106 mg/L TDS in test results) ~ 10 ft2/unit Moderate (low energy evap) 

K Reverse Osmosis 4,500 gpd/unit 45,000 mg/L - - - drinking quality 36' x 7' - modular Moderate 

L Evaporation & Crystallization - - - - - - 95% reuse/ discharge Onsite/ modular units or centralized treatment plant High 

M 

Filtration 

~20,000 gpd/unit no limit 90% steam 20’ x 40’ Low (waste heat) $3-$4 

Evaporation 

Crystallization 

37 This table contains data obtained from flowback treatment system vendors. This information may change at anytime and its inclusion in this table by no means indicates a prefere

Vendors providing different types of treatment units sometimes collaborate in order to provide a complete treatment system. 
5-20

Vendor Processes used Flowrate/unit Allowable Influent TDS % Recovered as Effluent Effluent quality Footprint/ unit Energy Usage Appr

P

N 

Distillation (Mobile Vapor 

Recompression) 105,000 gpd/unit 80,000 mg/L 60-90% <10 mg/L TDS 50' x 50' Moderate $4.50 

Mechanical/ chemical 

separation 

O Chemical Precipitation 300,000 gpd - - - - - - re-use as fracturing fluid 25,000 ft2 Low $0.50 

b
6-1

6 POTENTIAL ENVIRONMENTALLY-FRIENDLY FRACTURING AND 

STIMULATION TECHNOLOGIES 

6.1 Introduction 

Hydraulic fracturing operations involve the use of significant quantities of 

additives/products, albeit in low concentrations, which potentially could have an adverse 

impact on the environment if not properly controlled. The recognition of potential hazards 

has motivated investigation into environmentally-friendly alternatives for hydraulic 

fracturing technologies and chemical additives. 

It is important to note that use of ‘environmentally friendly’ or ‘green’ alternatives may 

reduce, but not entirely eliminate, adverse environmental impacts. Therefore, further research 

into each alternative is warranted to fully understand the potential environmental impacts and 

benefits of using any of the alternatives. In addition, the ‘greenness’ needs to be evaluated in 

a holistic manner, considering the full lifecycle impact of the technology or chemical. 

6.2 Environmentally-Friendly Fracturing Technology Alternatives 

The following environmentally-friendly technology alternatives have been identified as being 

in use in the Marcellus Shale, with other fracturing/stimulation applications or under 

investigation for possible use in Marcellus Shale operations: 

 Liquid carbon dioxide alternative – The use of a liquid carbon dioxide and proppant 

mixture reduces the use of other additives [51]. Carbon dioxide vaporizes leaving only 

the proppant in the fractures. The use of this technique in the US has been limited to 

demonstrations [93]. 

 Nitrogen-based foam alternative – Nitrogen-based foam fracturing was used in vertical 

shale wells in the Appalachian Basin until recently [87]. Nitrogen gas is unable to 

carry appreciable amounts of proppant and the nitrogen foam was found to introduce 

liquid components that can cause formation damage [88]. 

 Liquefied Petroleum Gas (LPG) – The use of LPG, consisting primarily of propane, 

has the advantages of carbon dioxide and nitrogen cited above; additionally, LPG is 

known to be a good carrier of proppant due to the higher viscosity of propane gel [83]. 

Further, mixing LPG with natural gas does not ‘contaminate’ natural gas; and the 

mixture may be separated at the gas plant and recycled [83]. LPG’s high volatility, 

low weight, and high recovery potential make it a good fracturing agent. This 

technology is in limited use in Canada, and no information is publicly available about 

any use in the US. 

 Horizontal and directional wells – These techniques are already in widespread use in 

the Marcellus Shale and other shale gas formations. While these techniques require 

larger quantities of water and additives per well, horizontal and directional wells are 
6-2

considered to be more environmentally-friendly because these types of wells provide 

access to a larger volume of gas/oil than a typical vertical well [93, 89]. 

Several unconventional drilling techniques (e.g. slimhole drilling, coiled tubing, multilateral 

drilling, and dual-well configuration38) have made advances in recent decades and are 

considered to be more environmentally-friendly [90, 91, 93, 58, 85] because of their smaller 

footprint. But there are no known instances of their use at shale plays similar to the 

Marcellus. 

Locating multiple wells in a single pad, particularly multiple horizontal wells in a single pad, 

is a widely used technique that reduces the overall surface footprint. 

6.3 Environmentally-Friendly Chemical Alternatives 

The most significant environmentally friendly change made to date in shale fracturing 

operations in the United States has been the switching from a diesel- (also called oil- or 

synthetic-) based fluid to water based fluid. In 2003, BJ Services Company, Halliburton 

Energy Services, Inc., and Schlumberger Technology Corporation and the USEPA signed a 

voluntary Memorandum of Agreement by which diesel fuel use in hydraulic fracturing fluids 

injected into underground sources of drinking water during hydraulic fracturing of coalbed 

methane wells was eliminated [59, 60]. Diesel contains benzene, naphthalene, toluene, 

ethylbenzene, xylenes, and other potentially harmful compounds. While this agreement was 

limited to shallow coalbed methane wells, diesel was not among the listed constituents used 

for hydraulic fracturing by operators or their service providers who shared data with 

NYSDEC, and its use as a primary component of hydraulic fracturing fluid is not within the 

scope of the SGEIS. While chemical additives are still involved, the fluid used in hydraulic 

fracturing operations is now water-based. 

There are several US-based chemical suppliers who advertise ‘green’ hydraulic fracturing 

additives. For example, Earth-friendly GreenSlurry system from Schlumberger used in both 

the U.K. North Sea and the Gulf of Mexico [61]; Ecosurf EH surfactants by Dow Chemicals; 

or ‘Green’ Chemicals for the North Sea from BASF. USEPA has published the twelve 

principles of green chemistry and a sustainable chemistry hierarchy [62], listed below, yet 

these do not provide a common measure of environmental-friendliness to assess ‘green’ 

hydraulic fracturing additives. 

USEPA’s twelve principles of green chemistry 

1. Prevent waste: Design chemical syntheses to prevent waste, leaving no waste to treat 

or clean up. 

 

38 The dual-well configuration combines a vertical and intersecting horizontal wellbore systems to access 

greater extents of gas resources with a single well site. This has been applied in low-medium permeability 

formations. 
6-3

2. Design safer chemicals and products: Design chemical products to be fully effective, 

yet have little or no toxicity. 

3. Design less hazardous chemical syntheses: Design syntheses to use and generate 

substances with little or no toxicity to humans and the environment. 

4. Use renewable feedstocks: Use raw materials and feedstocks that are renewable rather 

than depleting. Renewable feedstocks are often made from agricultural products or 

are the wastes of other processes; depleting feedstocks are made from fossil fuels 

(petroleum, natural gas, or coal) or are mined. 

5. Use catalysts, not stoichiometric reagents: Minimize waste by using catalytic 

reactions. Catalysts are used in small amounts and can carry out a single reaction 

many times. They are preferable to stoichiometric reagents, which are used in excess 

and work only once. 

6. Avoid chemical derivatives: Avoid using blocking or protecting groups or any 

temporary modifications if possible. Derivatives use additional reagents and generate 

waste. 

7. Maximize atom economy: Design syntheses so that the final product contains the 

maximum proportion of the starting materials. There should be few, if any, wasted 

atoms. 

8. Use safer solvents and reaction conditions: Avoid using solvents, separation agents, 

or other auxiliary chemicals. If these chemicals are necessary, use innocuous 

chemicals. 

9. Increase energy efficiency: Run chemical reactions at ambient temperature and 

pressure whenever possible. 

10. Design chemicals and products to degrade after use: Design chemical products to 

break down to innocuous substances after use so that they do not accumulate in the 

environment. 

11. Analyze in real time to prevent pollution: Include in-process real-time monitoring and 

control during syntheses to minimize or eliminate the formation of byproducts. 

12. Minimize the potential for accidents: Design chemicals and their forms (solid, liquid, 

or gas) to minimize the potential for chemical accidents including explosions, fires, 

and releases to the environment. 

While these twelve principles of green chemistry and a sustainable chemistry hierarchy set 

general characteristics of an environmentally-friendly chemical or technique, they do not 

provide an objective metric for evaluating the environmentally-friendliness. Presently, 

environmentally-friendliness of chemicals used in hydraulic fracturing in the US has been 

measured only subjectively. Vendors/suppliers indicate their products are environmentallyfriendly, but presently, there is no established method in the US to assess the life-cycle 
6-4

impact or impact on all relevant media of these chemicals. The next few sections discuss 

objective metrics used elsewhere in the world. 

6.3.1 Experience from Drilling in the North Sea 

Much of the knowledge regarding environmentally-friendly chemicals used with gas 

exploration is based on drilling operations in the North Sea. Strict environmental guidelines 

regulate the amounts and types of chemicals that may be discharged into the North Sea. Two 

of the initiatives are: 

 The Offshore Chemical Notification Scheme (OCNS) that manages chemical use and 

discharge by the United Kingdom (UK) and Netherlands offshore petroleum industries. 

 The European Union legislation regarding the Environmental Impact Assessment (EIA) 

that requires a comprehensive assessment of the effects of projects on the environment. 

An outcome of these initiatives was a regulation that prohibited the discharge of cuttings 

generated from drilling with synthetic- (i.e. oil/diesel) based drilling fluids where the 

synthetic oil on the cuttings is greater than 1% [63]. Additionally, the UK government 

proposed to phase out the discharge of cuttings contaminated with additional chemicals by 

December 31, 2000 [64]. Since oil-based muds that are often used currently must be 

‘skipped and shipped’ (i.e. containerized and transported back to land for disposal) due to 

these environmental regulations, there is an effort within the industry to develop 

‘environmentally-friendly’ chemical additives that work as well as the traditional chemicals. 

It should be noted that in 2001, the USEPA published effluent limitations and guidelines, 

primarily applicable to offshore operations, on the discharge of synthetic-based drilling fluids 

(SBFs) from oil and gas drilling operations into waters of the United States. 

6.3.2 Environmental Coordination in Europe 

The Convention for the Protection of the Marine Environment of the North-East Atlantic 

(known as the "OSPAR Convention") is the basis for national laws governing the discharge 

of offshore drilling wastes in the waters of the fifteen OSPAR signatory states [65, 33, 84]. 

The effort started in 1972 with the Oslo Convention against dumping; then, in 1974, the 

efforts were broadened by the Paris Convention to cover land-based sources and the offshore 

industry. These two conventions were unified, updated and extended by the 1992 OSPAR 

Convention. 

The Paris Commission facilitated a thorough review of the use and manufacture of additives 

in order to establish the best environmental practice or best available techniques to prevent 

pollution [65]. The OSPAR list of substances that may be used or discharged offshore which 

are considered by OSPAR to Pose Little or No Risk to the Environment (PLONOR) contains 

substances whose use or discharge offshore are subject to expert judgment by the competent 

national authorities or do not need to be strongly regulated. The list of these chemicals may 

be found at http://www.ospar.org/documents/dbase/decrecs/agreements/04-

10_plonor%202008%20revision.doc. 
6-5

The “main environmental acceptability criterion” for the UK government’s decision was 

biodegradation [64], which is consistent with Principle 10 of the Twelve Principles of Green 

Chemistry [66] adopted by the USEPA as part of its Green Chemistry initiative. In the 

Norwegian sector of the North Sea, chemical products must pass biodegradation, 

bioaccumulation, toxicity, and taint tests in order to be permitted for use [67]. Organisation 

for Economic Co-Operation and Development (OECD) North Sea countries require 

chemicals to be tested for ecotoxicity, biodegradation, and bioconcentration/bioaccumulation [64, 65]. 

6.3.2.1 Offshore Chemical Notification Scheme (OCNS) 

The Offshore Chemical Notification Scheme (OCNS) manages chemical use and discharge 

by the UK and Netherlands offshore petroleum industries [68]. OCNS classifies chemicals 

using test protocols approved by OSPAR Harmonised Offshore Chemical Notification 

Format (HOCNF) coordinates the testing requirements for oilfield chemicals throughout the 

Northeast Atlantic sector. 

To assess the potential environmental hazard associated with chemical products that may be 

used in offshore drilling operations, OCNS uses toxicity, biodegradation and 

bioaccumulation data for each chemical to calculate the ratio of Predicted Effect 

Concentration (PEC) against No Effect Concentration (NEC), and publishes the ratio as the 

Hazard Quotient (HQ). HQ is then used to rank products. Several lists of approved products 

that may be used for Production, Completion / Workover, Drilling or Cementing, ranked by 

their HQ may be found at http://www.cefas.co.uk/offshore-chemical-notification-scheme-

(ocns)/hazard-assessment.aspx. 

In the UK, OCNS is regulated by the Department of Energy and Climate Change (DECC) 

with scientific and environmental input from the Centre for Environment, Fisheries and 

Aquaculture Science (Cefas) and the Fisheries Research Services (FRS). In the Netherlands, 

OCNS is regulated by the State Supervision of Mines (SSM) with scientific and 

environmental advice from Cefas and Netherlands government agencies [69]. 

6.3.1.1 Cefas 

Cefas assigns product ratings for additives used by the petroleum industry based on the 

physical, chemical and ecotoxicological properties of products. The assigned hazard groups 

vary from category A (most hazardous) through E (least hazardous), and HQ color from 

purple (most hazardous), through orange, blue, white, and silver, to gold (least hazardous) 

[70]. 
6-6

Table 6-1 - Cefas Chemicals Categories based on Hazard Quotient (HQ) 

Minimum HQ Maximum HQ Category 

>0 <1 Gold 

Hazard 

Level 

Increases 

>=1 <30 Silver 

>=30 <100 White 

>=100 <300 Blue 

>=300 <1000 Orange 

>=1000 Purple 

Several of the product names provided to NYSDEC by operators on the Marcellus Shale are 

on the OCNS; the OCNS-approved product list and may be found at 

http://www.cefas.co.uk/offshore-chemical-notification-scheme-(ocns)/hazardassessment.aspx. OCNS-approved products that were also submitted for approval to 

NYSDEC are not cross-referenced here. 

6.3.2.2 Products Approved by Norway 

Norway is considered to have the most stringent regulatory environment among the OSPAR 

countries. Norwegian State Pollution Control Authority (SFT) also regulates the use of 

drilling muds through discharge permits. SFT assesses water-based fluids using data on bioaccumulation potential and bio-degradability. SFT encourages limiting use and discharges of 

even these approved products. Discharge of unused chemicals into the sea is forbidden [71]. 

 

6.3.3 Environmental Coordination in Canada 

Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) in Canada 

utilizes a system called Offshore Chemical Selection Guidelines for Drilling & Production 

Activities on Frontier Lands. C-NLOPB follows the OCNS to a great extent. 

6.4 Summary 

The ‘environmentally-friendly’ aspect of hydraulic fracturing of deep shale formations 

presently stem from drilling techniques, like horizontal drilling and mutli-well pads with 

smaller overall footprint, and from the use of environmentally-friendly chemicals. 

Several US-based chemicals suppliers advertise ‘green’ chemicals, but there does not seem to 

be a US-based metric to evaluate the environmental-friendliness of these chemicals. 
6-7

In the North Sea area, several countries have established criteria that define environmentalfriendliness, and utilize models and databases to track chemicals’ overall hazardousness 

against those criteria. Similar to NYSDEC, the regulatory authorities in Europe request 

proprietary information from chemicals suppliers, and do not release any proprietary 

information into the public domain. The proprietary recipes for chemical additives are used 

to assess their potential hazard to the environment, and regulate their use as necessary. 

If applicable, New York could choose to evaluate the criteria used in Europe or the US might 

choose to set up an independent scientific entity to evaluate all chemicals proposed for use 

within US territories. However, at this time, it may not be feasible to require the use of 

‘green’ chemicals because presently there is no metric or chemicals approvals process in 

place in the US. The evaluation of the ‘greenness’ of a chemical needs to consider the lifecycle impacts associated with that chemicals; and setting up a metric that provides a 

comprehensive evaluation is difficult. 

It is important to note that several products manufactured by US-based companies, and used 

or proposed for use in the Marcellus Shale in New York, may be found in the European 

approved chemicals lists. 
7-1

7 ALTERNATE WATER SOURCES FOR HYDRAULIC FRACTURING 

OPERATIONS 

7.1 Introduction 

Hydraulic fracturing operations require the use of large quantities of water. Data from the 

Marcellus Shale operations indicate that typical usage is approximately 1 million gallons 

(MG) for a vertical well and between 2.5 and 3.5 MG for a horizontal well, with maximum 

usage up to 6 MG. 

The water sources that are used initially are those that are the most readily accessible at a 

reasonable cost. These sources tend to be municipal (potable) water, surface water, and 

groundwater. Utilizing potable water is more costly and subject to quantity limitations; 

utilizing fresh surface water or groundwater may be less costly but may deplete limited fresh 

water resources, may not be available for withdrawal at the rate needed at all times, may be 

subject to restrictions on interbasin transfers, and may have quality concerns (e.g., affected 

by abandoned mine drainage). Using alternate water sources may be beneficial in replacing 

or supplementing the more conventional sources. 

7.2 Potential Alternate Water Sources 

Alternate hydraulic fracturing water sources that should be considered, where available, 

include: 

 Effluent from municipal or industrial wastewater treatment plants 

 Partial re-use of fracturing water (discussed in Section 5) 

 Non-contact cooling water discharges from industrial plants 

 Saline aquifers 

 Stormwater ponds 

 Impoundments (lakes, reservoirs, quarries) 

 Mine discharges 

 Deep mine pools 

Alternate water sources need to meet a number of criteria before they may be considered for 

hydraulic fracturing, as discussed below. 

7.3 Factors that Affect Usability of Alternate Water Sources 

Operators should consider several factors when evaluating the usability of any particular 

water source. Decisions regarding use vs. non-use could change with time depending on 

innovations in technology and other competing uses for water. Factors affecting usability 

include: 
7-2

Availability – The “owner” of the source needs to be identified, contact made, and 

agreements negotiated. 

Distance/route from the source to the point of use – The costs of trucking large quantities of 

water increases and water supply efficiency decreases when longer distances and travel times 

are involved. Also, the selected routes need to consider roadway wear, bridge weight limits, 

local zoning limits, impacts on residents, and related traffic concerns. 

Available quantity – Fewer larger water sources avoids the need to utilize multiple smaller 

sources. 

Reliability – A source that is less prone to supply fluctuations or periods of unavailability 

would be more highly valued than an intermittent and less steady source. 

Accessibility –Water from deep mines and saline aquifers may be more difficult to access 

than a surface water source unless adequate infrastructure is in place. Access to a municipal 

or industrial plant or reservoir may be inconvenient due to security or other concerns. Access 

to a stream may be difficult due to terrain, competing land uses, or other issues. 

Quality of water – The fracturing fluid serves a very specific purpose at different stages of 

the fracturing process. The composition of the water could affect the efficacy of the additives 

and equipment used. The water may require pre-treatment or additional additives may be 

needed to overcome problematic characteristics. 

Potential concerns with water quality include scaling from precipitation of barium sulfate and 

calcium sulfate [1]; high concentrations of chlorides, which could increase the need for 

friction reducers; very high or low pH (e.g. water from mines); high concentrations of iron 

(water from quarries or mines) which could potentially plug fractures [1]; microbes that can 

accelerate corrosion, scaling or other gas production [6]; and high concentrations of sulfur 

(e.g. water from flue gas desulfurization impoundments), which could contaminate natural 

gas. In addition, water sources of variable quality could present difficulties. 

Similar to reusing or recycling flowback for hydraulic fracturing, experts on hydraulic 

fracturing agree that high quality water is easy and convenient to use, and that somewhat 

lower quality water may also be utilizable for hydraulic fracturing [1]. Perhaps due to the 

additional cost and inconvenience of withdrawing and transporting alternate water sources, 

expectations of water quality are higher of alternate water sources than of recycled flowback. 

Based on the applicable water quality specifications, several of the alternate water sources 

identified in Section 7.2 (such as flowback, saline aquifers, mine discharges and deep mine 

pools) may be usable only after appropriate treatment. 

Permittability – Applicable permits and approvals would need to be identified and assessed 

as to feasibility and schedule for obtaining approvals, conditions and limitations on approval 

that could impact the activity or require mitigation, and initial and ongoing fees and charges. 

Preliminary discussions with regulating authorities would be prudent to identify fatal flaws or 

obstacles. 
7-3

Disposal – Proper disposal of flowback from hydraulic fracturing will be necessary, or 

appropriate treatment for re-use provided. Utilizing an alternate source with sub-standard 

quality water could add to treatment and disposal costs. 

Cost – Sources that have a higher associated cost to acquire, treat, transport, permit, access or 

dispose, typically will be less desirable by industry. 

7.4 Summary 

Theoretically, any water source may be utilized for hydraulic fracturing. But in practice, 

several factors could affect the usability and suitability of these sources. The perceptions of 

usability and suitability would likely change with time based on the value of natural gas 

recovered, innovations in technology related to water treatment, regulations, and costs. Each 

service company and operation would need to evaluate local conditions to determine the 

availability of alternate water sources to a particular gas well. 
8-1

8 WATER WELL SAMPLING NEEDS 

8.1 Introduction 

Based on experiences in other states, there is concern that high-volume hydraulic fracturing 

operations may impact private water wells in the State of New York (the State) by 

contaminating the water well or depleting the resource [72, 73, 75]. However, the USEPA 

found no threat to water sources from hydraulic fracturing [75, 76]. Additionally, Interstate 

Oil and Gas Compact Commission (IOGCC) member states have all stated that there have 

been no cases where hydraulic fracturing has been verified to have contaminated drinking 

water [76]. This section summarizes available information on private water well sampling, 

testing, and monitoring activities performed in a number of states in conjunction with 

hydraulic fracturing of deep shale formations. The desktop research identified relevant 

information for New York, Pennsylvania, Ohio, Kentucky and Texas. 

This section also proposes ‘indicator’ compounds/elements to monitor before and after 

drilling/fracturing to indicate whether there may be a connection between private water well 

contamination and hydraulic fracturing operations. These indicators have been selected using 

limited analytical results of flowback from the Marcellus Shale from operations in New York 

and Pennsylvania. 

8.2 Water Well Sampling Requirements in Pennsylvania 

Section 208 of Pennsylvania’s Oil and Gas Act - Protection of water supplies – requires ‘any 

well operator who affects a public or private water supply by pollution or diminution [to] 

restore or replace the affected supply with an alternate source of water adequate in quantity 

or quality for the purposes served by the supply’ [77]. 

The gas well operator may be held responsible for any drinking water well supply 

contamination or reduction within 1,000 feet of the gas well that is discovered within 6 

months of gas well completion [7]. Pre-drilling monitoring of water wells within 1,000 feet 

of the gas well may, therefore, be driven by both the drinking water supply owner and the gas 

well operator, at the gas well operator’s expense. Post-drilling water supply well monitoring 

by the well operator is presently not required in Pennsylvania. While the drinking water well 

owner may use a ‘Do-it-yourself’ sampling kit, a state-certified laboratory needs to perform 

the analyses if legal action were later required based on the analytical results. 

8.3 Water Well Sampling Requirements in Ohio 

The Ohio Department of Natural Resources administers a pre-drilling water sampling 

program in Ohio. This program requires gas well operators to prepare a sampling plan; the 

actual sampling requirements are determined on a case-by-case basis and may be contingent 

on a variety of factors, including hydrology, geology, and aquifer characteristics. The 

program may require the gas well operator to sample all domestic water supply wells in a 

given area; the actual size of the sampling area varies by operation. 
8-2

The State of Ohio requires analyses of the following parameters to characterize pre-drilling 

water quality: alkalinity, barium, calcium, chloride, conductivity, iron, magnesium, pH, 

potassium, sodium, sulfate, and total dissolved solids (TDS) [78]. 

8.4 Water Well Sampling Requirements in Texas 

The Railroad Commission of Texas has rules in place to protect groundwater and surface 

water resources in Texas. Texas Administrative Code Title 16 Economic Regulation, Part 1- 

Railroad Commission of Texas, Chapter 3 Oil and Gas Division, Rule §3.8 Water Protection 

provides guidance on anti-degradation. Specific information or guidance on water supply 

well protection was not readily found. 

8.5 Water Well Sampling Requirements in Kentucky 

The Kentucky Department of Environmental Protection’s Division of Water does “not 

regulate contaminants in private wells” [79]. Kentucky Administrative Regulations have 

general requirements and guidelines for groundwater protection, but the desktop search did 

not find any specific water supply monitoring requirements associated with natural gas 

drilling in the Devonian Shale [80]. 

8.6 Existing Water Well Protection in New York 

Article 23, Title 3 of the Environmental Conservation Law (ECL) authorizes the New York 

State Department of Environmental Conservation (NYSDEC) to require that oil or gas wells 

be drilled, constructed, operated and plugged, and the surrounding land reclaimed, to prevent 

or remedy "the escape of oil, gas, brine or water out of one stratum into another" and "the 

pollution of freshwater supplies by oil, gas, salt water or other contaminants" [81]. 

NYSDEC requires a full environmental assessment if a proposed oil or gas well is within 

2,000 feet of a municipal well and a supplemental Environmental Impact Statement if the 

proposed oil or gas well is within 1,000 feet. Strict oil or gas well construction requirements 

are expected to protect all groundwater resources, including private wells [82]. 

8.7 Enhanced Water Well Protection in New York 

NYSDEC appears to have a comprehensive program in place to protect municipal wells in 

the State, while protection of private water supply wells is based on gas well construction 

requirements. The State could potentially enhance its protection of private water well 

supplies by implementing the following: 

 NYSDEC may be able to draw from Ohio’s requirements and enhance the State’s 

requirements by providing to potential gas well operators a succinct list of parameters 
8-3

to monitor, at the producer’s expense, in private water wells within a certain distance 

of a proposed gas well, before and after a fracturing operation. 

 NYSDEC could draw from Pennsylvania’s requirements and require any gas well 

operator who affects the quantity or quality of a private water supply to restore or 

replace, within a reasonable timeframe, the affected private water supply with an 

alternate source of water similar in quantity and quality to the original supply. 

8.8 Indicator Compounds/Elements of Potential Contamination due to Hydraulic 

Fracturing 

Limited time-series data of flowback from Marcellus Shale gas wells in Pennsylvania show 

that concentrations of several parameters in flowback increased over the 2 to 3 week period. 

These parameters include: TDS, hardness, calcium, magnesium, bromide, chloride, fluoride, 

chemical oxygen demand, barium, and manganese. Concentrations of sulfates, bicarbonates, 

total Kjeldahl nitrogen, 5-day biological oxygen demand, phosphorus and alkalinity 

decreased with time, likely due to additives used. 

Literature based on flowback data from other shale formations indicates that the 

concentrations of chlorides and TDS (likely heavily influenced by chlorides) increase over 

the flowback period; literature based on flowback data from the Marcellus indicates that the 

concentrations of TDS and barium increase over the flowback period. While other 

parameters may be influenced by mobilization of materials in the shale formation or due to 

fracturing fluids, there is insufficient data at this time to make a definitive determination that 

these other parameters would always be found primarily/exclusively due to fracturing 

operations in the Marcellus Shale area. 

In order to determine if a private water supply well has been contaminated due to hydraulic 

fracturing operations, comprehensive pre- and post-drilling water quality monitoring may be 

warranted39. Such monitoring may be costly, though. 

Monitoring for parameters such as barium, TDS and pH could indicate if the private water 

well has been contaminated due to the fracturing operation. Monitoring for strontium, 

sodium, chloride, hardness (calcium and magnesium), surfactants, total suspended solids 

(TSS), iron, carbonates and bicarbonates could provide a better understanding of the extent 

of potential contamination [7]. 

Diesel is no longer used in fracturing operations, but is used to fuel equipment. Therefore, 

sampling for benzene, which is contained in diesel, could indicate above ground spills. 

 

39 Many water wells in New York are completed in shale formations. Based on NYSDEC’s experience with 

investigating water well complaints, pre-drilling private water well quality may vary due to impact of even an 

undeveloped shale. 
8-4

Monitoring for methane would alert potential uncontrolled emissions due to damaged 

casings, etc. It has also been suggested that an isotopic analysis of carbon in methane could 

determine if the gas is from a shallow source or from a deep reservoir. 

8.9 Summary 

There is concern among the public, particularly among property owners and private water 

supply well owners near hydraulic fracturing operations, about potential well water 

contamination due to fracturing operations. This section surveyed existing private water well 

sampling, testing and monitoring requirements in New York, Pennsylvania, Ohio, Kentucky 

and Texas. 

Barium and TDS are recommended as indicator substances to monitor for, at a minimum, in 

private water supply wells, before and after gas well drilling/fracturing to determine potential 

contamination from the operation. Private water well quality depends on a number of factors, 

including water well construction, potential pre-existing contamination, and natural water 

quantity variations. Therefore, establishing pre-drilling well water conditions is important to 

determine the potential impact of the fracturing operation. 

The frequency and length of monitoring would likely depend on the specific location; but 

may be pre-drilling, then once per month from the start of operations until six months after 

completing fracturing operations; and then once per six months until the well is plugged. As 

with other water-quality-related permits, the frequency may be reduced if the operator 

maintains its record of compliance. Monitoring for additional parameters like pH, strontium, 

sodium, chloride, calcium, magnesium, surfactants, TSS, iron, carbonates, bicarbonates and 

diesel would provide a better understanding of potential contamination of private water well 

supplies due to hydraulic fracturing operations or above ground spills. 
9-1

9 SUMMARY AND CLOSING 

The process of horizontal drilling and high-volume hydraulic fracturing uses large volumes 

of water with small concentrations of chemical additives to assist and enhance drilling and 

fracturing. A portion of the fracturing fluids returns to the surface as flowback. This fluid 

contains variations of additives, parameters that were present in the source water, new 

compounds formed due to reactions between additives and substances mobilized within the 

shale formation. 

There is concern among the public that the chemical additives used for fracturing or 

flowback fluid could contaminate some of the State’s water resources and, as a result, 

interfere with the use of those sources in accordance with their designated use classifications. 

This study addresses this issue, subject to the limited amount of data available for evaluation. 

9.1 Summary 

Section 2 presents 13 classes of chemical additives that may potentially be used in hydraulic 

fracturing operations and, based on proprietary information and MSDS received from service 

companies and operators via the NYSDEC, presents a list of basic compounds and elements 

found in approximately 230 products used or proposed for use in hydraulic fracturing 

operations in New York. 

Section 3 discusses volumes and composition of flowback based on publicly available 

literature and data from well operators, and trends in volume and composition observed 

based on information from one well operator. This section includes a summary of the 

Marcellus Shale Coalition Study Report. It also presents a list of compounds and elements 

based on analytical results of flowback from the Marcellus Shale. 

Section 4 surveys the sufficiency of federal and New York State regulations and guidelines to 

protect water resources in the State. This section provides a preliminary comparison of 

constituents found in additives (in Section 2) and flowback (in Section 3) with 

contaminants/pollutants regulated by the federal drinking water standards, the SPDES 

program, NYSDOH’s POC and UOC Standards, or which have guidance through TOGS111. 

Nearly all the parameters detected in laboratory analyses provided by industry appear to be 

addressed in Federal or State regulations or guidances. 

Section 5 is a preliminary survey of flowback recycling and on-site treatment technologies 

currently used to a limited extent for other drilling/fracturing operations. On-site treatment of 

flowback is costly, and technology is not widely available for use in the Marcellus Shale. 

However, these technologies are evolving to meet industry needs and regulatory 

requirements. At the present time, operators appear to recycle flowback more than treat it. 

Section 6 surveyed ‘environmentally-friendly’ hydraulic fracturing technologies and 

chemicals. It appears that environmentally-friendly technologies are in experimental phases 

or have only been used under conditions different from the Marcellus. The ‘environmentally-
9-2

friendly’ aspect of hydraulic fracturing of deep shale formations presently stems from drilling 

techniques, such as horizontal drilling and multi-well pads with smaller overall footprint, and 

from the use of environmentally-friendly chemicals. While there are inferences to green or 

environmentally-friendly chemicals and technologies, their lifecycle environmental 

performance has not yet been evaluated. 

There is multinational cooperation in Europe regarding oil and gas drilling in the North Sea. 

This study did not evaluate the robustness or efficacy of European efforts, but suggests that 

the OSPAR Convention and the Offshore Chemical Notification Scheme (OCNS) serve as 

the starting point for setting up a framework in New York State (or the US40) to promote 

environmentally-conscious hydraulic fracturing operations. The specific concerns associated 

with onshore vs. offshore operations would likely be different, but the framework, approach 

and lessons learned from offshore operations would likely be applicable at onshore 

operations as well. 

Section 7 is a survey of alternate water sources that may be utilized for hydraulic fracturing 

operations. Several alternate sources might potentially be available in New York, but they are 

not well-bore-ready. Each alternate source has its limitations. Effluent from wastewater 

treatment plants or non-contact once-through cooling water discharge from industrial 

facilities may presently be a significant component of a waterbody41, and its use would likely 

require approvals and permit modifications from waterbody commissions or other agencies. 

Water from saline aquifers, quarries, or mines would likely require significant treatment. 

These sources already contain high concentrations of TDS – the parameter likely of greatest 

operational concern in flowback. Treatment is costly. Innovations in treatment technologies 

and potential use of alternate water sources would likely depend on the value of natural gas 

that may be harvested from the Marcellus, the availability, costs and other competing uses of 

freshwater in the general area, and regulations and guidelines on withdrawal, use, 

consumption, treatment and disposal (i.e. the complete life-cycle) of water used in hydraulic 

fracturing. 

There is concern that hydraulic fracturing operations may contaminate private water wells in 

the vicinity. Section 8 surveys efforts in Pennsylvania and Ohio to potentially preserve water 

quality and quantity in private water wells. NYSDEC has the authority to protect water 

resources in the State, and has a comprehensive program to protect municipal water wells. 

Section 8 draws from experiences and guidelines in Pennsylvania and Ohio to suggest 

enhancements to water resource protection (particularly private water well supplies) in the 

State. In addition, based on analytical results of flowback from the Marcellus obtained from 

operators and published literature, Section 8 suggests a series of parameters to test and 

monitor for in private well water before and after drilling/fracturing a gas well. 

 

40 The USEPA has initiated a study on hydraulic fracturing. 

41 Particularly during low flow period, the relatively consistent discharge rate from POTWs is important to 

maintain minimum flow rates in small waterbodies. 
9-3

9.2 Limitations of the Survey 

This study looked at a variety of subjects associated with hydraulic fracturing within a very 

short period of time. The information is based on limited interactions with service 

companies, telephone interviews and articles from industry experts, or information published 

on websites, and is not based exclusively on peer-reviewed published literature. Composition 

of additives and analytical results of flowback are from service companies and operators who 

voluntarily shared proprietary information with NYSDEC. Such information was used in this 

study under a strict confidentiality agreement. The level of detail of information and data 

from different sources is not consistent. Given these study conditions, information presented 

in this report may be refined in the future as more information becomes available. 

This study likely captures all the classes of chemical additives used in fracturing operations. 

As additional service companies, operators and chemicals suppliers share more information, 

the table with basic constituents in additives (Table 3-1) may be further expanded. 

Except for the analytical results provided by the MSC, the different analyses of flowback 

data tested for different sets of parameters. In addition, different detection methods (which 

have different detection limits) have been used to test for the same parameter. All operators 

testing and reporting concentrations for the same comprehensive list of parameters, 

guidelines on allowable detection methods under different conditions, along with the 

composition and quantity of water and additives used would provide a better understanding 

of constituents in flowback. Flowback composition changes with time. All operators 

monitoring flowback at several pre-specified points in time would also improve 

understanding of flowback. 

On-site treatment and recycling are in pilot phases, and much of the information is presently 

considered to be proprietary. Incentives to innovate and share information would help 

understand the industry’s progress in on-site treatment and recycling. 

Some US-based companies advertise ‘green’ chemicals. But there does not appear to be a 

common metric in place to evaluate environmental-friendliness in the US. New York State 

may be able to draw from experiences in Europe and formulate a metric to objectively 

measure the environmental-friendliness of chemicals or technologies so the industry has a 

specific goal to work towards, and the environmental impact of hydraulic fracturing may be 

measured more objectively. Significant differences between European countries and the US 

include the size, the state-based governance system, and offshore vs. onshore operations. 

European countries are smaller than the US and most environmental regulations and 

requirements apply to the entire country, while in the US regulations and requirements are 

often administered at the state-level. It is imperative that these regulations and requirements 

continue to be administered at the state-level. Interstate collaboration with respect to shale 

development similar to riverbasin commissions would likely be beneficial. 

This study suggests a few parameters to test and monitor for in private water wells before and 

after drilling a gas well in the vicinity. A pilot study to evaluate the appropriateness of these 

parameters may lend greater credibility to the perceived need for a State-wide private well 

testing program. 
9-4

9.3 Closing 

The oil and gas industry has developed innovative technologies to harness natural gas from 

the low-permeability Marcellus Shale formation at depths of several thousand feet. Adequate 

safeguards are necessary to carry out these drilling and fracturing operations in an 

environmentally sensitive manner. The industry has shared proprietary information and 

experiences regarding hydraulic fracturing operations which have been utilized in this report. 

As with other states in the core Marcellus Shale region, New York State is tasked with 

promoting efforts to develop natural gas resources in support of federal and state energy 

policies while protecting and preserving other important resources of the State. This balance 

is reflected in the laws and regulations that have been promulgated to address public needs 

for energy and environmental health. 

Natural gas harvesting from the Marcellus Shale provides an opportunity for agencies, 

industry and the public to work together to develop one resource while protecting and 

preserving other resources and respecting the competing public demands on the State. 
10-1

10 REFERENCES 

[1] Gas Technology Institute (September 26, 2007). Proceedings and Minutes of the 

Hydraulic Fracturing Expert Panel, XTO Facilities, Fort Worth, TX, compiled by 

Tom Hayes of GTI. 

[2] Parshall, J. (undated). Barnett Shale Showcases Tight-gas Development. Journal of 

Petroleum Technology, in: ALL Consulting. 2008. Hydraulic Fracturing 

Considerations for Natural Gas Wells of the Marcellus Shale. 

[3] All Consulting, LLC (2008). Evaluating the Environmental Implications of 

Hydraulic Fracturing in Shale Gas Reservoirs, presented at International Petroleum 

& Biofuels Environmental Conference Albuquerque, NM, November 11-13, 2008. 

[4] Independent Oil & Gas Association of New York (IOGA NY) Response to NY 

DEC SGEIS Information Requests (September 16, 2010), prepared by All 

Consulting Project No. 1284. 

[5] New York State Water Resources Institute at Cornell University (visited 2009). 

Waste Management of Cuttings, Drilling Fluids, Hydrofrac Water and Produced 

Water, at http://wri.eas.cornell.edu/gas_wells_waste.html. 

 [6] Fichter, J.K., Johnson, K., French, K. an Oden, R. 2008. "Use of Microbiocides in 

Barnett Shale Gas Well Fracturing Fluids to Control Bacterially-Related Problems." 

NACE International Corrosion 2008 Conference and Expo. Paper 08658. I pp. 2, 3. 

http://content.nace.org/Store/Downloads/7B772A1BA1- 6E44-DD11-889D0017A446694E.pdf. 

[7] Pennsylvania State University (2009). Gas Well Drilling and Your Private Water 

Supply: Water Facts #28. 

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