### Water Consulting Services in Support of the Supplem ental Generic Environmental Impact Statement for Natural Gas Prod uction

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 Rese arch and Development Authority (hereafter "NYSERDA"). The opinions expressed in th is report do not necessarily reflect those of NYSERDA or the State of New York, and refe rence to any specific product, service, process, or method does not constitute an implied o r expressed recommendation or endorsement of it. Further, NYSERDA, the State of N ew 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 servi ce, or the usefulness, completeness, or accuracy of any processes, methods, or other inform ation contained, described, disclosed, or referred to in this report. NYSERDA, the State of N ew York, and the contractor make no representation that the use of any product, apparat us, process, method, or other information will not infringe privately owned rights and will a ssume no liability for any loss, injury, or damage resulting from, or occurring in connection w ith, 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 Addres sed in NY Regulations or
Guidances .........................................

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

4.7 Rules and Regulations Applicable to Oil, Gas, and S olution 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 Tech nologies ........................................ 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 th e 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 technolog ies ..................................... 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 regulat ions .......................................... 5-1 4

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 S timulation Technologies .............. 6-1

6.1 Introduction ......................................

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

6.2 Environmentally-Friendly Fracturing Technology Alte rnatives .................................. 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 Op erations ........................................ 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 So urces ........................................... 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 Contamina tion 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 (1 2 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 Propose d 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 M SC 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 N YSDOH POCs Standards a,b .......................... 4-18 Table 4-5 – Comparison of additives used or propose d for use in NY, parameters detected in analytical results of flowback from the Marcellus o perations 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 cons tituents based on limited samples from PA and WV, and regulated in NY, ..........................

................................................... ....................... 4-37 Table 4-7 - Typical concentrations of parameters th at are not regulated, based on limited flowback analyses from PA and WV ...........................

................................................... ..................... 4-41 Table 5-1 – Allowable water quality requirements fo r fracturing fluids, based on input from one expert panel on Barnett Shale .....................

................................................... ......................... 5-3 Table 5-2 - Treatment capabilities of EDR and RO Sy stems ............................................. ................. 5-7 Table 5-3 - Summary of Characteristics of On-site F lowback Fluid Treatment Technologies ........... 5- 9 Table 5-4 - Design specifications for containment p onds as required by state regulations ............. .. 5-12 Table 5-5 – Radiological data in limited flowback a nalyticals from PA and WV ......................... ... 5-15
Table 5-6 - Select characteristics of various treat ment technologies currently offered or under design

.................................................. ................................................... ......................................... 5-19 Table 6-1 - Cefas Chemicals Categories based on Haz ard Quotient (HQ) ................................. ........ 6-6

### 1-1



## 1 INTRODUCTION AND SCOPE

1.1 Introduction

The Marcellus Shale formation has been identified a s 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 loc ations and at depths greater than 7,000
feet at other locations.

In 1992, the New York State Department of Environme ntal Conservation (NYSDEC) issued a Generic Environmental Impact Statement (GEIS) tha t 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 draf t Supplemental GEIS (dSGEIS) to assess issues unique to drilling and high-volume hy draulic fracturing in the Marcellus Shale area. The New York State Energy Research and Develo pment Authority (NYSERDA) is assisting NYSDEC by developing information and data needed for the dSGEIS. NYSERDA has contracted several consultants to research, rev iew, 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 devel oped by NYSDEC. The SGEIS will be issued by the NYSDEC to establish State Environm ental Quality Review (SEQR) thresholds for permitting horizontal drilling and h igh-volume hydraulic fracturing projects to develop the Marcellus Shale and other low permeabil ity gas reservoirs.

The process of high-volume hydraulic fracturing use s 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 conc entrations 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” fluid 1 

### , 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 tech nologies

e. Potential ‘green’ (environmentally-friendly) hydrau lic fracturing technologies
f. Alternate water sources for hydraulic fracturing op erations, and

g. Water well sampling needs.

1 Independent Oil & Gas Association of New York (IOG A NY) refers to the returning fracturing fluids as produced water. This report distinguishes between f lowback and produced water as defined in Section 3- 1.

### 1-2

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

1.2 Report Outline

Section 2 provides a review of fracturing fluid add itives used in drilling/fracturing operations; Section 3 provides a review of flowback fluid volumes and composition. Both of these sections draw on publicly available informati on 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 Marce llus Shale Coalition (MSC) study findings. In order to protect industry and trade se crets, these two sections present broad classes of inputs or the generic constituents of ad ditives or flowback, but not the chemical suppliers, product names or the product composition s.

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 a nalytical 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 Guidan ce Series 1.1.1 (TOGS111).

Section 5 surveys on-site treatment or recycling te chnologies that may potentially be available for operations in the Marcellus Shale.

Section 6 surveys ‘environmentally-friendly’ hydrau lic fracturing technologies and chemicals, and draws experiences from gas and oil e xploration 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 sampl ing, testing, and monitoring requirements in other states with Marcellus Shale type developme nt activity. This section identifies potential additional requirements that may be appli ed within New York State for private water well sampling, testing, and monitoring. This section also identifies potential compounds/elements for testing in typical private w ater wells in New York State in baseline and post-drilling modes.

Section 9 summarizes the findings and lists limitat ions 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 “pr oppant” (a material such as sand that keeps the opened fractures from resealing after the fract uring 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 groun d surface as flowback.

2.2 Desirable Properties of Fracturing Fluids

Additives are used in hydraulic fracturing operatio ns to elicit certain properties / characteristics that would aide and enhance the ope ration. 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 hydra tion

 

### Limited formation damage

 

### Appropriately modify properties of water to carry p roppant 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 Propose d for Use in New York State

Additive Type Description of Purpose Examples of Ch emicals 2

Proppants “Props” open fractures and allows gas / f luids 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 fracturin g fluid Peroxydisulfates

Bactericide /
Biocide /
Antibacterial Agent Inhibits growth of organisms that could produce gas es (particularly

hydrogen sulfide) that could contaminate methane ga s. Also prevents the growth of bacteria which can reduce th e 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 t o maximize the

effectiveness of other additives such as crosslinke rs 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 casing s, tools, and

tanks (used only in fracturing fluids that contain acid) Methanol; ammonium bisulfate for Oxygen Scavengers

Crosslinker Increases fluid viscosity using phospha te esters combined with

metals. The metals are referred to as crosslinking agents. The increased fracturing fluid viscosity allows the flu id to carry more proppant into the fractures. Potassium hydroxide; Borate
salts

Friction Reducer Allows fracturing fluids to be inj ected 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 ox ides which could plug off the

formation Citric acid

Scale Inhibitor Prevents the precipitation of carbo nates and sulfates (calcium

carbonate, calcium sulfate, barium sulfate) which c ould 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 f or use in the State of New York to date, but are kn own 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 va ry 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 ea ch type is typically utilized in any given gas well. The selection may be driven by the format ion 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 sam ple compositions, by weight, of fracturing fluids. Figure 2-1 [3] is based on data from the F ayetteville Shale 3 

### ; Figure 2-2 and Figure 2-3 [4] are based on data from Marcellus Shale developm ent in Pennsylvania. Based on this data, between approximately 80 and 90 percent of the frac turing fluid is water; between approximately 8 and 15 percent is proppant; the rem ainder, typically less than 1 percent, consists of chemical additives listed above. The sp ecific fracturing fluid composition, types of additives and specific products used would depen d on the location and the operator.

Barnett Shale is considered to be the first instanc e of extensive hydraulic fracturing technology use in horizontal shale wells; the techn ology 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 tha t 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 real istic 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 S hale is a marine shale rich in unoxidized carbon (i .e. a black shale). The two shales are at similar depths, and v ertical and horizontal wells have been drilled/frac tured in both
shales.

### 2-4

Figure 2-1 - Sample Fracturing fluid Composition (1 2 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 addit ives may be made up of one or more
chemical constituents. Table 2-2 is a list of chem ical constituents and their CAS numbers, that have been extracted from complete product chem ical composition and Material Safety
Data Sheets submitted to the NYSDEC. This list is b ased 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 an y class of additive. Therefore only a
handful of chemicals from Table 2-2 would be utiliz ed in a single well. Table 2-2 represents constituents of all hydraulic-fracturing-related ad ditives submitted to NYSDEC to date for potential use in shale wells in the State.

Data provided to NYSDEC to date indicates similar f racturing fluid compositions for vertically and horizontally drilled wells.

### 2-6

Table 2-2 – Chemical Constituents in Additives 4 , 5 , 6

CAS Number 7 Chemical Constituent
106-24-1 (2E)-3,7-dimethylocta-2,6-dien-1-ol
67701-10-4 (C8-C18) and (C18) Unsaturated Alkylcarb oxylic Acid Sodium Salt
2634-33-5 1,2 Benzisothiazolin-2-one / 1,2-benzisot hiazolin-3-one
95-63-6 1,2,4 trimethylbenzene
93858-78-7 1,2,4-Butanetricarboxylicacid, 2-phospho no-, 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-Dim thyloctadecylamine

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 sa lt
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 ac id sodium salt polymer
46830-22-2 2-acryloyloxyethyl(benzyl)dimethylammoni um chloride
52-51-7 2-Bromo-2-nitro-1,3-propanediol
111-76-2 2-Butoxy ethanol / Ethylene glycol monobut yl ether / Butyl Cellusolve
1113-55-9 2-Dibromo-3-Nitriloprionamide /2-Monobrom o-3-nitriilopropionamide
104-76-7 2-Ethyl Hexanol
67-63-0 2-Propanol / Isopropyl Alcohol / Isopropano l / Propan-2-ol
26062-79-3 2-Propen-1-aminium, N,N-dimethyl-N-2-pro penyl-chloride, homopolymer
9003-03-6 2-propenoic acid, homopolymer, ammonium s alt
25987-30-8 2-Propenoic acid, polymer with 2 p-prope namide, sodium salt / Copolymer

of acrylamide and sodium acrylate
71050-62-9 2-Propenoic acid, polymer with sodium ph osphinate (1:1)
66019-18-9 2-propenoic acid, telomer with sodium hy drogen sulfite

4 Table 2-2 is a list of chemical constituents and t heir CAS numbers that have been extracted from comp lete chemical compositions and Material Safety Data Shee ts submitted to the NYSDEC.

5 These are the chemical constituents of all chemica l additives proposed to be used in New York for hyd raulic fracturing operations at shale wells. Only a few ad ditives will be used in a single well; the list of chemical
constituents used in an individual well will be cor respondingly smaller.

6 This list would not include chemicals/products tha t 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 i n the literature. The intention is to make database searches more convenient, as chemicals often have many names . Almost all chemical molecule databases today allo w searching by CAS number.

### 2-7 CAS Number 7 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-bu ten-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-methy lpropane 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-trime thyl-2-[(1-oxo-2- propenyl)oxy]-, chloride, polymer with 2-propenamid e (9Cl)
15085-02-3 Acrylamide-sodium acrylate copolymer
68891-29-2 Alcohols C8-10, ethoxylated, monoether w ith sulfuric acid, ammonium salt

68526-86-3 Alcohols, C11-14-iso, C13-rich
68551-12-2 Alcohols, C12-C16, Ethoxylated /Ethoxyla ted alcohol
64742-47-8 Aliphatic Hydrocarbon / Hydrotreated lig ht distillate / Petroleum Distillates /

Isoparaffinic Solvent / Paraffin Solvent / Naptheni c 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(h ydroxyethyl)
73138-27-9 Amines, C12-14-tert-alkyl, ethoxylated
71011-04-6 Amines, Ditallow alkyl, ethoxylated
68551-33-7 Amines, tallow alkyl, ethoxylated, aceta tes

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 Number 7 Chemical Constituent
7727-54-0 Ammonium Persulfate / Diammonium peroxidi sulphate
1762-95-4 Ammonium Thiocyanate
7664-41-7 Aqueous ammonia
12174-11-7 Attapulgite Clay
121888-68-4 Bentonite, benzyl(hydrogenated tallow a lkyl) dimethylammonium stearate

complex / organophilic clay

71-43-2 Benzene
119345-04-9 Benzene, 1,1'-oxybis, tetratpropylene d erivatives, sulfonated, sodium salts
74153-51-8 Benzenemethanaminium, N,N-dimethyl-N-[2- [(1-oxo-2-

propenyl)oxy]ethyl]-, chloride, polymer with 2-prop enamide
122-91-8 Benzenemethanol,4-methoxy-, 1-formate
1300-72-7 Benzenesulfonic acid, Dimethyl-, Sodium s alt /Sodium xylene sulfonate
140-11-4 Benzyl acetate
76-22-2 Bicyclo (2.2.1) heptan-2-one, 1,7,7-trimeth yl68153-72-0 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 Number 7 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 (methylenephoni c acid) sodium salt
28757-00-8 Diisopropyl naphthalenesulfonic acid
68607-28-3 Dimethylcocoamine, bis(chloroethyl) ethe r, 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 hydrocrack ed

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 Hemicellulas e 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 alcohol s 61791-12-6 Ethoxylated Castor Oil

61791-29-5 Ethoxylated fatty acid, coco
61791-08-0 Ethoxylated fatty acid, coco, reaction p roduct 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 Number 7 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 Copolyme r (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-dimethyl ethyl 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 / m uriatic 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, Sy nthetic
64-63-0 Isopropanol
98-82-8 Isopropylbenzene (cumene)
68909-80-8 Isoquinoline, reaction products with ben zyl chloride and quinoline

8008-20-6 Kerosene
64742-81-0 Kerosine, hydrodesulfurized

### 2-11 CAS Number 7 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 hyd rocracked base oil

141-43-5 Monoethanolamine
44992-01-0 N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy E thanaminium 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-hydro xypropylsulfobetaine
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)imin o]bis[2,1-

ethanediylnitrilobis(methylene)]]tetrakis-, ammoniu m salt

8000-41-7 Pine Oil

8002-09-3 Pine Oils
60828-78-6 Poly(oxy-1,2-ethanediyl), a-[3,5-dimethy l-1-(2-methylpropyl)hexyl]-whydroxy25322-68-3 Poly(oxy-1,2-ethanediyl), a-hydro-w-hydr oxy / Polyethylene Glycol
31726-34-8 Poly(oxy-1,2-ethanediyl), alpha-hexyl-om ega-hydroxy
24938-91-8 Poly(oxy-1,2-ethanediyl), α -tridecyl- ω -hydroxy9004-32-4 Polyanionic Cellulose
51838-31-4 Polyepichlorohydrin, trimethylamine quat ernized
56449-46-8 Polyethlene glycol oleate ester
9046-01-9 Polyethoxylated tridecyl ether phosphate

### 2-12 CAS Number 7 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, so dium 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 .8H 2 O
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 Number 7 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 chl oride-quaternized
68647-72-3 Terpene and terpenoids
68956-56-9 Terpene hydrocarbon byproducts
533-74-4 Tetrahydro-3,5-dimethyl-2H-1,3,5-thiadiazi ne-2-thione /Dazomet
55566-30-8 Tetrakis(hydroxymethyl)phosphonium sulfa te (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, Propoxy lated
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 Copol ymer
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, bioci des, clay stabilizes, etc. that may be selected for any hydraulic fracturing operation. Th e different product options may not be interchangeable because of undesirable chemical rea ctions that may occur between different
classes of chemicals. The actual selection of addit ives is somewhat driven by the specific operation.

Operators have been required to divulge the types o f 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 th at such information is often considered proprietary does not prevent the NYSDEC from requir ing full-disclosure of this information. The handling of any information submitted to the NY SDEC 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 sequen ce may include the following:

 

### Phase 1: Corrosion inhibitors, iron controls and ac ids 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 addi tives 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, bacterici de/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 forma tion, 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 f racturing 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 su lfide that could contaminate natural gas. A clay stabilizer may be used to prevent swell ing and migration of formation clays which could block pore spaces.

Not all types of additives are used in a single wel l. 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 hyd raulic fracturing operations. Small quantities of several additives are used to facilit ate 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 t he globe. Table 2-2 lists the primary constituents found in approximately 230 products us ed 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 f rom a gas well. Waste fluids from a gas well may be grouped into several categories: top-ho le 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 dr illing. Top-hole fluids do not intermingle within the well bore the way bottom hol e and stimulation fluids do.

 

### Bottom-hole fluids typically consist of fluids gene rated due to deep salt water zones
encountered.

 

### Stimulation / fracturing fluids are waste fluids ge nerated due to the water, proppants and other additives pumped into the shale to improve ga s recovery.

 

### Production fluids (or Produced Water) are the waste fluids produced with natural gas after the well is put into production; their compos ition is typically similar to bottom hole
fluids.

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

3.2 Flowback Fluid Volume

The volume of flowback fluid from a gas well depend s on a variety of factors, including the particular shale, the depth and age of the well, an d the drilling technique (horizontal vs. vertical).

Typical water usage for hydraulic fracturing is app roximately 1.5 million gallons (MG) per vertical well and between 2.5 and 5 MG per horizont al well. Limited data indicate that water usage may be as little as 0.5 MG or as much as 3 mi llion gallons (MG) per vertical well and as much as 6 MG per horizontal well.

Based on limited data reported to NYSDEC and inform ation from operators in Pennsylvania, flowback from Marcellus Shale operations, which inc ludes both vertical and horizontal wells, is approximately 20 – 35 percent of fracturing flui ds used 8 

### , with up to 85 percent from a vertical well, and between 10 and 50 percent from h orizontal wells reported [9].

8 Typical flowback from operations based in Marcellu s Shale, as estimated by URS Corporation. These val ues 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, an d 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 occu rs in the first four days after fracturing. After day 4, the daily flowback rate declines sharp ly 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 pumpe d into the well, and consist of water and additives discussed in the previous section, any ne w compounds that may have formed due to reactions between additives, and substances mobiliz ed from within the shale formation due to the fracturing operation. Some portion of the propp ant 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 wi thin 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 f or several wells, while other companies provided several analytical results for multiple da ys of the same well (i.e. time-series). Flowback parameters were organized by Chemicals Abs tract Service (CAS) number,
whenever available.

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

 

### Dissolved Solids (chlorides, sulfates, and calcium)

 

### Metals (calcium, magnesium, barium, strontium)

 

### Suspended solids

 

### Mineral scales (calcium carbonate and barium sulfat e)

 

### Bacteria - acid producing bacteria and sulfate redu cing 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 a nalytical results is provided in Table 3-1. Typical concentrations of parameters, based on limi ted 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 results 9

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 / Isoprop anol / 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-ethyl hexyl) 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 a nalytical results provided to NYSDEC by service com panies 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 ba sed 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 Vi rginia.

The information in the above table is from operatio ns in the Marcellus Shale, but they are not from a single comprehensive study. Table 3-1 data a re based on analyses performed by different laboratories; most operators provided onl y 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 paramet ers. Even though the data are not strictly comparable, they provide valuable insight on the po tential composition of flowback at New York operations.

3.4.1 Marcellus Shale Coalition Report on Flowback

Recognizing the dearth of comparable flowback infor mation 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 s timulating 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 Pennsylvan ia and West Virginia.

 

### Most samples were analyzed for conventional paramet ers: metals; volatile organic compounds (VOCs); semi-volatile organic compounds ( SVOCs); organochlorine pesticides; polychlorinated biphenyls (PCBs); an or ganophosphorus pesticide;

### 3-7 alcohols; glycols; and acids. The specific paramete rs 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 so lids 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-dissolve d Antimony Iron Sodium Antimony-dissolved Iron-dissolved Sodium-dissolved

Arsenic Lead Strontium

Arsenic-dissolved Lead-dissolved Strontium-dissolve d

Barium Lithium Thallium

Barium-dissolved Lithium-dissolved Thallium-dissolv ed Beryllium Magnesium Tin Beryllium-dissolved Magnesium-dissolved Tin-dissolv ed Boron Manganese Titanium Boron-dissolved Manganese-dissolved Titanium-dissol ved Cadmium Molybdenum Trivalent chromium Cadmium-dissolved Molybdenum-dissolved Zinc

Calcium Nickel Zinc-dissolved

Calcium-dissolved Nickel-dissolved Hexavalent chrom ium-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 te rt-butyl ether (MTBE) 1,1,2-Trichloroethane 4-Methyl-2-pentanone (MIBK) M ethylene 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-Butylben zene 1,2,4-Trichlorobenzene Bromobenzene Styrene 1,2,4-Trimethylbenzene Bromodichloromethane tert-bu tyl acetate 1,2-Dibromo-3-chloropropane Bromoform tert-Butylben zene 1,2-Dibromoethane (EDB) Bromomethane Tetrachloroeth ene 1,2-Dichlorobenzene Carbon disulfide tetrahydrofura n 1,2-Dichloroethane Carbon tetrachloride Toluene 1,2-Dichloropropane Chlorobenzene trans-1,2-Dichlor oethene 1,3,5-Trimethylbenzene Chloroethane trans-1,3-Dichl oropropene 1,3-Dichlorobenzene Chloroform Trichloroethene 1,3-Dichloropropane Chloromethane Trichlorofluorome thane 1,4-Dichlorobenzene cis-1,2-Dichloroethene Vinyl ac etate 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)anth racene Hexachlorocyclopentadiene 1,2-Diphenylhydrazine Acenaphthene Hexachloroethane 1,3-Dinitrobenzene Acenaphthylene Hexachloropropene 1,4-Naphthoquinone Acetophenone Indeno(1,2,3-cd)pyr ene 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 met hanesulfonate 2,4,6-Trichlorophenol Benzo(a)pyrene Nitrobenzene 2,4-Dimethylphenol Benzo(b)fluoranthene N-Nitrosodi ethylamine 2,4-Dinitrophenol Benzo(ghi)perylene N-Nitrosodimet hylamine 2,4-Dinitrotoluene Benzo(k)fluoranthene N-Nitrosodi -n-butylamine 2,6-Dichlorophenol Benzyl alcohol N-Nitrosodi-n-pro pylamine 2,6-Dinitrotoluene bis(2-Chloroethoxy)methane N-Nit rosodiphenylamine 2-Acetylaminofluorene bis(2-Chloroethyl) ether N-Ni trosomethylethylamine 2-Chloronaphthalene bis(2-Chloroisopropyl) ether N -Nitrosomorpholine 2-Chlorophenol bis(2-Ethylhexyl) phthalate N-Nitros opiperidine 2-Methylnaphthalene Butyl benzyl phthalate N-Nitros opyrrolidine 2-Methylphenol Chlorobenzilate O,O,O-Triethyl phosp horothioate 2-Naphthylamine Chrysene o-Toluidine

2-Nitroaniline Diallate Parathion 2-Nitrophenol Dibenz(a,h)anthracene p-Dimethylamino azobenzene

2-Picoline Dibenzofuran Pentachlorobenzene 3,3'-Dichlorobenzidine Diethyl phthalate Pentachlor oethane 3-Methylcholanthrene Dimethoate Pentachloronitroben zene 3-Methylphenol & 4- Methylphenol Dimethyl phthalate Pentachlorophenol

3-Nitroaniline Di-n-butyl phthalate Phenanthrene 4,6-Dinitro-2-methylphenol Di-n-octyl phthalate Phe nol 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 Tetraethyldithiopyr ophosphate

5-Nitro-o-toluidine Hexachlorobutadiene



### Table 3-6 - Organochlorine pesticides analyzed in M SC 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 analyz ed for (shown with a “ • ”) at each well site. Table 3-13 is a summary of parameters detect ed at quantifiable levels. The check mark ( √ 

### ) indicates that several samples detected many para meters within a class. The MSC Study Report lists the following qualifiers associated wi th analytical results:

 

### The sample was diluted (from 1X, which means no dil ution, to up to 1000X) due to concentrations of analytes exceeding calibration ra nges of the instrumentation or due to potential matrix effect. The laboratory will use best judgment when analyzing samples at the lowest dilution factors allowable wi thout causing potential damage to
the instrumentation.

 

### The analyte was detected in the associated lab meth od blank for the sample. Sample results would be flagged with a laboratory-generate d single letter qualifier (i.e., “B”).

 

### The estimated concentration of the analyte was dete cted between the method detection limit and the reporting limit. Sample res ults 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 detecti on limit. These results will be flagged with a “U”.3-11Table 3-12 – Parameter classes analyzed for in MSCStudyA B C D E F G H I J K L M N O P Q R SConventional Analyses• ••••••••••••••••••Metals• ••••••••••••••••••VOCs• ••••••••••••••••••SVOC• ••••••••••••••••••Organochlorine Pesticides• ••••••••••••••••••PCBs• ••••••••••••••••••OrganophosphorusPesticides• ••••••••••••••••••AlcoholsNA•NA••••••••••••••••GlycolsNA•NA••••••••••••••••AcidsNA NA NA••••••••••••••••Table 3-13 – Parameter classes detected in flowbackanalyticals in MSC Study#parametersanalyzed forA B C D E F G H I J K L M N O P Q R SConventional Analyses 29√ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √Metals 59√ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √ √VOCs 70 7 6 1 2 2 6 1 5 2 2 3 7 2 1 2 7 1 5 5SVOC 107 3 6 1 5 3 6 2 2 9 8 6 2 1 1 1 6 1 7 6OrganochlorinePesticides20 0 0 1 1 0 1 0 2 1 2 1 1 1 0 0 0 2 3 2PCBs 7 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 0OrganophosphorusPesticides1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0Alcohols 5 0 1 0 2 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0Glycols 2 0 1 0 2 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0Acids 4 0 0 0 0 1 1 1 1 1 1 1 1 1 2 1 1 1 2 2

### 3-12

Metals and conventional parameters were detected an d quantified in many of the samples and these observations are consistent with parameters l isted in Table 3-1. However, the frequency of occurrence of other parameter classes was much l ower: Table 3-13 summarizes the number of volatile organic compounds (VOCs), semi-v olatile organic compounds (SVOCs), PCBs, pesticides, alcohols, glycols and acids obser ved in samples taken from each well. For the purposes of Table 3-13, if a particular paramet er was detected in any sample from a single well, whether detected in one or all five (D ay 0, 1, 5, 14 or 90) samples, it was considered to be one parameter.

 

### Between 1 and 7 of the 70 volatile organic compound s 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 co mpounds were detected in samples from well sites A through S. SVOCs detecte d included

2,4-Dimethylphenol Benzo(b)fluoranthene Fluoranthen e 2,6-Dichlorophenol Benzo(ghi)perylene Fluorene 2-Methylnaphthalene Benzo(k)fluoranthene Indeno(1,2 ,3-cd)pyrene 2-Methylphenol Benzyl alcohol N-Nitrosodiphenylamin e 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 epo xide

 

### Only 1 (Aroclor 1248) of the 7 PCBs was detected, a nd 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 dete cted are 2-propanol and methanol.

### 3-13  

### Of the 2 glycols (ethylene glycol and propylene gly col) analyzed for, 1 each was
detected at three well sites.

 

### Of the 4 acids analyzed for, 1 or 2 acids (acetic a cid 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 reaction s 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 vola tile and semi-volatile analytical results may be traced back to potential laboratory contamin ation due to improper ventilation; due to chromatography column breakdown; or due to chemical breakdown of compounds during injection onto the instrumentation. Further study w ould 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 sha le play. If pesticides or PCBs were present in limited flowback samples in PA or WV, pe sticides or PCBs would likely have been introduced to the shale or water during drilli ng 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, depe nding on a variety of factors. Limited
time-series Marcellus Shale flowback data from Penn sylvania 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 increase 10 

### , and sometimes exceed Maximum Contaminant Levels (MCLs) (see Table 4-2 - Primary Drinking Wat er Standards);

 

### Calcium and magnesium hardness increases;

 

### Iron concentrations increase, unless iron-controlli ng additives are used;

 

### Sulfate levels decrease;

 

### Alkalinity levels decrease, likely due to use of ac id; and

 

### Concentrations of metals increase 11



### .

10 Limited data from operations in PA and WV have rep orted the following ranges of radioactivity: alpha 22.41 – 18950 pCi/L; beta 9.68 – 7445 pCi/L; Radium 226 2.58 - 33 pCi/L.

11 Metals such as aluminum, antimony, arsenic, barium , boron, cadmium, calcium, cobalt, copper, iron, le ad, lithium, magnesium, manganese, molybdenum, nickel, potassium, radium, selenium, silver, sodium, stront ium,

### 3-14

Available literature [1] corroborates the above sum mary regarding the changes in composition with time for TDS, chlorides, and bariu m. Fracturing fluids pumped into the well, and mobilization of materials within the shal e may be contributing to the changes seen in hardness, sulfate, and metals. The specific chan ges would likely depend on the shale formation, fracturing fluids used and fracture oper ations control.

3.6 Summary

Flowback consists of fracturing fluids injected int o 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 rat e and composition change with time. Typically, approximately 20-35 percent of fracturin g fluids return to the surface over a period of approximately 2-3 weeks. Flowback from almost al l 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 regu lations and guidelines that govern the use of water associated with well drilling and hydr aulic fracturing in New York State. The goal is to assess the sufficiency of these regulati ons 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 trea tment system effluents. The water is trucked or pumped to the well pads and stored in ta nks, pits or impoundments 12 

### until used for any of a variety of purposes including well drillin g and completion, testing of pipelines, and dust control. By far, the largest use of water is f or 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 a t 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 f luid typically contains additives which increase the effectiveness of the fracturing operat ions by ensuring that the proppant is delivered and remains in the fractures, while preve nting 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 hydrauli c fracturing remains in the shale formation (i.e., is considered consumed), but a sig nificant portion (approximately 20 to 35 percent) normally returns to the surface as flowbac k and must be managed in accordance with applicable regulations. Existing well construc tion and fluid containment requirements are intended to prohibit any uncontrolled release o f fluids to the environment.

The oil and gas industry has provided information a nd data to NYSDEC regarding the formulation of additives that may be used. The cons tituents 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 hori zontal Marcellus Shale wells where highvolume hydraulic fracturing will be utilized are re quired to complete a site-specific Environmental Impact Statement (EIS), which must ta ke into account the same issues being considered in the Supplemental GEIS process and mus t be consistent with the requirements of the State Environmental Quality Review Act and t he State Environmental Conservation Law (ECL).

12 A pit is typically associated with just one well p ad, whereas an impoundment infers a centralized tem porary water storage location that services several well p ads.

### 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 an d the Public Health Law are contained in the New York Codes, Rules and Regulati ons (NYCRR). Of relevance to this project are the regulations contained in Title 6 - Environmental Conservation (6NYCRR), and Title 10 – Health (10NYCRR). New York environme ntal and health regulations draw in large measure from federal regulations that impleme nt 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 classifie d 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 classifi cations of surface waters and groundwaters in New York [10].

In general, the discharge of sewage, industrial was te or other wastes may not cause impairment of the best usages of the receiving wate r 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 imp ose discharge restrictions (described below) in order to protect public health, or the qu ality of distinguished value or sensitive

waters.

A table of water use classifications, usages, and r estrictions 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 Tabl e 4-1 above]

1. Best usage for enjoyment of water in its natural co ndition and, where compatible, as a source of water for drinking or culinary purposes, bathing, f ishing, 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 recrea tion

5. Best usage for fishing.

6. Suitable for fish, shellfish, and wildlife propagat ion and survival.

7. Suitable for primary and secondary contact recreati on, 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 wa stes (may not be assigned to any groundwaters of the State, unless the commissioner finds that ad jacent and tributary groundwaters and the best usages thereof will not be impaired by such classif ication)

Discharge Restriction Categories – Based on a numbe r 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 eco logical waters where the quality of the water is critical to maintaining the value for which the wat ers are distinguished; and (3) other sensitive wate rs 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 he alth emergencies, or when such discharges result in a reduction of pollutants for the designa ted waters. In all cases, best usages and standards
will be maintained.

2. Per 6 NYCRR 701.23, except for storm water discharg es, 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 b e 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 re strictions. 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, sett leable 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 sli mes that will impair the waters for their best usages; there shall be no alteration to flow that w ill 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 internati onal boundary waters that, if subjected to approved treatment, equal to coagulation, sedimenta tion, filtration and disinfection with additional treatment, if necessary, to reduce naturally presen t impurities, meet or will meet NYSDOH drinking water standards and are or will be conside red safe and satisfactory for drinking water

purposes.



### c. This classification may be given to those waters th at if subjected to pre-approved disinfection treatment, with additional treatment if necessary t o remove naturally present impurities, meet or will meet NYSDOH drinking water standards and are o r will be considered safe and satisfactory for drinking water purposes.



### d. This classification may be given to those waters th at, if subjected to approved treatment equal to coagulation, sedimentation, filtration and disinfec tion, with additional treatment if necessary to reduce naturally present impurities, meet or will m eet NYSDOH drinking water standards and are or will be considered safe and satisfactory for dri nking 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 pota ble waters, or as raw material for the
manufacture of sodium chloride or its derivatives o r 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 co ncentration 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 ther eof will not be impaired by such classification.



### Water use classifications are assigned to surface w aters and groundwaters throughout New York. Regulations governing gas drilling in the Mar cellus 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 suppli es 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 inadvert ently released into surface water or groundwater sources that are designated for drinkin g water use can adversely impact or disqualify such usage if there are constituents tha t 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 19 96, gives the United States Environmental Protection Agency (USEPA) the authori ty to set drinking water standards. There are two categories of drinking water standard s: primary and secondary. Primary standards are legally enforceable and apply to publ ic water supply systems. The secondary standards are non-enforceable guidelines that are r ecommended 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 drink ing water quality by limiting the levels of specific contaminants that can adversely affect pub lic health and are known or anticipated to occur in drinking water. The determinations of whic h contaminants to regulate are based on peer-reviewed science research and data that evalua tes the following factors [11]:

 

### Occurrence in the environment and in public water s upply 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 consider ing the risk to sensitive subpopulations,
USEPA sets a non-enforceable Maximum Contaminant Le vel Goal (MCLG) for each contaminant as public health goals. This is the max imum level of a contaminant in drinking water at which no known or anticipated adverse effe ct on the health of persons would occur, and which allows an adequate margin of safety. MCLG s 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 Contamin ant Levels (MCLs) or Treatment Techniques, which are achievable at a reasonable co st, 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) i n 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 sta ndards [12].

In addition to the primary and secondary standards, the USEPA, on March 2, 1998, published a National Drinking Water Contaminant Candidate Lis t (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 s ystems; and

 

### May require regulations under SDWA.

Contaminants on the CCL are prioritized and studied , including monitoring for presence/level of selected contaminants 13 

### in selected existing larger public water supply systems. If, after the requisite studies and monito ring 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, ma king regulatory determinations for contaminants and identifying contaminants for unreg ulated 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 f or implementing drinking water
standards to the states.

13 

### Most of the unregulated contaminants with potentia l 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 th is 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 6 

### NYCRR.

Anyone planning to operate or operating a public wa ter 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 Suppl y 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 th e 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 filtrati on and disinfection. To assure the safety of drinking water in New York, NYSDOH, in cooperati on with its partners, the county health departments, regulates the operation, design and qu ality of public water supplies; assures water sources are adequately protected, and sets st andards for constructing individual water supplies.

The NYSDOH regulates contaminants consistent with t he national drinking water standards. Section 5-1.51 of 10 NYCRR prescribes the maximum c ontaminant levels, maximum residual disinfectant levels and treatment techniqu e 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 ado pted the 0.005 mg/L MCL for organic chemicals belonging to any of six major chemical cl asses 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 th at publicly supplied drinking water cannot have more than 0.005 mg/L of any chemical de fined as a POC; or more than 0.05 mg/L of a chemical not already covered by other reg ulations (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 lis ted 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, 198 8, Volume X, Issue 47, lists the POC classes as halogenated alkanes; halogenated ethers; halobenzen es and substituted halobenzenes; benzene and alkyl – or nitrogen-substituted benzenes; substituted, unsatur ated aliphatic hydrocarbons; and halogenated non-ar omatic cyclic hydrocarbons. The specific contaminants to b e analyzed for under POCs are listed in Table 9D - Organic Chemicals – POCs of 10 NYCRR Subpart 5-1, and repli cated in Table 4-4 herein.

15 Defined as any organic chemical not covered by ano ther MCL.

### 4-8

that were not previously identified by the flowback analytical results received from industry; all other parameters identified in the MSC study we re already identified in the information received from industry.

It should be noted that the Federal Energy Policy A ct of 2005 amended the Underground Injection Control (UIC) provisions of the SDWA to e xclude hydraulic fracturing from the definition of "underground injection." The Fracturi ng 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 prot ect underground sources of drinking water from contamination by underground injection of haza rdous and non-hazardous fluids. Whether or not hydraulic fracturing is regulated un der SDWA UIC, protection of groundwater resources during oil and gas extraction activities is a responsibility of state government, and the cited federal amendment does no t diminish the NYSDEC's authority over oil and gas well development in New York, incl uding oversight of hydraulic fracturing activities to ensure protection of potable groundwa ter resources.

4.4 Discharge Limits – SPDES

The direct or indirect discharge of flowback that i ncludes residuals from additives is subject to regulation under New York’s State Pollutant Disc harge Elimination System (SPDES). Limitations on discharges from point sources, which are derived from federal, regional, and state standards and programs, are imposed in New Yo rk via the SPDES permit program. The USEPA has approved New York’s program for the contr ol 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 t hat it controls point source discharges to groundwaters as well as surface waters. Discharg es related to gas drilling activities are subject to these controls.

Applicable water quality standards and effluent lim itations 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 quali ty standards, effluent limitations, best management practices, standards of performance, tox ic effluent standards and prohibitions, pretreatment standards, and ocean discharge criteri a.

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 h ighly objectionable, conflicting or noncompliant discharges.

Subsection (a) of 6 NYCRR Section 750-1.11 covers t he provisions of SPDES permits and
lists the citations for the various effluent limita tions from the Federal Register (FR) and the Code of Federal Regulations (CFR). NYSDEC is respon sible 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 th e NYSDEC. These include the following:

(1) Best Practicable Control Technology currently avail able (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, inclu sive (see section 750-1.24 of this Part);

(3) Best Available Technology (BAT) effluent limitation guidelines, effluent prohibitions, and pretreatment standards for existi ng sources under Section 307 of the CWA and 40 CFR Parts 129 and 405-471, inclusive (see se ction 750-1.24 of this Part);

(4) Ocean discharge criteria adopted by the Federal gov ernment 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, guid ance values, effluent limitations or schedules of compliance, established pursuant to an y state law or regulation consistent with Section 510 of the CWA, or the requ irements of 40 CFR Part 132 (see section 750-1.24 of this Part);

(ii) Necessary to implement a total maximum daily l oad/waste load allocation/load allocation established pursuant to Section 303(d) o f 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 (se e section 750-1.24 of this Part):

(7) Prior to promulgation by the administrator of appli cable effluent standards and limitations, BPT effluent limitations and such cond itions 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 secti on 750-1.24 of this Part), if the SPDES permit is for the discharge of pollutants int o the navigable waters of the State from a vessel or other floating craft, any applicable regu lations promulgated by the U.S. Department of Commerce, establishing specifications for safe t ransportation, handling, carriage, storage, and stowage of pollutants.

(9) Unless otherwise required or authorized by this Par t, the provisions or requirements of 40 CFR. 122.23 Concentrated animal feeding opera tions, 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, an d 122.42(c) & (d) - Storm Water Discharges, 40 CFR Part 122.27 - Silvicultural acti vities (applicable to SPDES), 40 CFR Part 122.44 - Establishing limitations, standards, and o ther 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 Regula tion, 40 CFR Part 401 - General
Provisions and 40 CFR Part 403 - General Pretreatme nt 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 in dustrial 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 Artic le 17 of this Title.

The SPDES permit application requires any applicant to provide analytical results for several classes of pollutants listed in the following table s:
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/N YSDEC Promulgated

Analytical Methods; Table 9 - Other Significant Pollutants with NYSDEC Standards/Guidance Values;

and

Table 10 - Other Pollutants and Hazardous Substance s Required to be Identified in

ICS by Applicants if Present at Facility in Signifi cant Levels.

4.5 Ambient Water Quality Standards and Guidance Values and Groundwater
Effluent Limitations

Included in the above discussion are those rules an d 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 Guidanc e Series 1.1.1 (TOGS111) - Ambient Water Quality Standards and Guidance Values and Gro undwater Effluent Limitations is a compilation of ambient water quality guidance value s and groundwater effluent limitations for use where there are no standards (in 6 NYCRR 70 3.5) or regulatory effluent limitations (in 6 NYCRR 703.6).

### 4-11

4.6 Lists of Chemicals in Additives and Flowback Addres sed in NY Regulations or
Guidances

Table 4-5, at the end of this section, lists chemic al 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 c hemicals/parameters are regulated by the federal primary or secondary drinking water standar ds, 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 flowbac k analyses from PA and WV that are regulated in NY; this table does not include result s 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 flowbac k analyses from PA and WV that appear not to be regulated in NY. Column 2 is the number o f samples that analyzed for the particular parameter; column 3 is the number in which the para meter was detected. Basic statistics for these parameters are in subsequent columns. Given t he limited number of analyses performed on these parameters, the results and statistics sho uld be used with caution.

4.7 Rules and Regulations Applicable to Oil, Gas, and S olution Mining Category

4.7.1 Federal

40 CFR Part 435 provides guidelines on effluent lim itations for the Oil and Gas Extraction Point Source Category. These guidelines are taken i nto 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 fac ilities engaged in the production, field exploration, drilling, well completion and well tre atment in the oil and gas extraction industry that are located on land (i.e., excludes o ffshore and coastal locations).

The applicable limits in this subcategory reflect B PT: there shall be no discharge of waste water pollutants into navigable waters from any sou rce associated with production, field exploration, drilling, well completion, or well tre atment ( 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 pot ential environmental impact of gas drilling and well operation.

### 4-12

6 NYCCR Part 554 addresses drilling practices appli cable to oil, gas, and solution salt mining activities. Subpart 554.1 prescribes require ments for pollution and migration prevention. These requirements include:

 

### The prevention of pollution associated with the dri lling, casing and completion program adopted for any well.

 

### A prohibition on pollution of the land and/or of fr esh 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 fl uids 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 an d receive approval of a plan for the environmentally safe and proper ultimate dispos al of such fluids (excluding drilling muds, which, as specified by regulation, a re 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 a pplicant, a permit for discharge and/or disposal may be required by the NY SDEC in addition to the well-drilling permit.

o An applicant may also be required to submit an acce ptable contingency plan, the use of which shall be required if the primary p lan is unsafe or impracticable at the time of disposal.

 

### A prohibition on the impounding of brine or salt wa ter 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 mat erial.

o Brine or salt water may be temporarily stored prior to disposal in any watertight tank, container or an earthen pit, if un derlaid by soil such as heavy clay or hardpan.

o The tank, container or earthen pit must be construc ted 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 flu ids in such watertight tanks or earthen pits, prior to disposal, is limited to a ma ximum of 45 days after cessation of drilling operations, unless NYSDEC app roves 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 f rom one pool or stratum to another; and

 Exclude oil, gas or other fluids from any undergrou nd mining properties or rights and to protect them in accorda nce with prudent operations.

 

### ECL23-0305(8)(d) provides authority to NYSDEC to re quire the operator to remedy any contamination of a water supply well, and ECL 7 1-1307 provides authority to direct a violator to “reclaim and repair” any impai rment to a water supply well.

The regulation summarized above is supplemented by required casing and cementing practices, enforced as permit conditions on each dr illing permit. Surface casing must extend at least 75 feet beyond the deepest fresh water zon e, 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 a nd at least 100 feet into bedrock. Additionally, as stated in the GEIS (p. 9-32), alth ough 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 Susqu ehanna River Basin Commission, the Delaware River Basin Commission, and the Great Lake s Commission.

In addition, New York has specific programs, plans, and procedures in place that are focused on maintaining or improving ambient water quality i n targeted watersheds. These include total maximum daily loads, and state or local water shed management or protection plans.

Although these commissions, programs, plans, and pr ocedures carry the force of law, they are specific to individual water bodies or watershe ds 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 ind ustry (although not oil or gas conveyance pipelines). In addition, existing well construction and fluid containment requirements sufficiently prohibit any uncontrolled release of f luids to the environment. Also, well permit Applicants are required to submit information on hy draulic fracturing fluid composition prior to well permit issuance, subject to regulations tha t protect information identified by Applicants as trade secret or confidential commerci al information.

Additional environmental laws exist to address othe r activities related to gas well drilling in
the New York Marcellus Shale area. These include th e Resource Conservation and Recovery Act (RCRA) regarding hazardous waste, the Comprehen sive Environmental Response, Compensation, and Liability Act (CERCLA) regarding toxic substances, and the Clean Air Act (CAA) regarding emissions. A review of the fede ral 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 a re intended to address concerns that the oil and gas industry may not be fully subject to ce rtain key provisions of the SWDA, CWA,
and other water resource-related environmental laws

.

This review provides information regarding the suff iciency 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 fract uring, and management of flowback or brines that flow back to surface during well development o r operation. These controls are implemented in the permitting process for well dril ling and completion; for point source discharges via the SPDES program; and where there a re no standards or regulatory effluent limitations, via Technical & Operational Guidance S eries 1.1.1 (TOGS111). In addition, drinking water supplies are protected by Federal Dr inking 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 Cl 2 ) 4.0 4.0

Chlorine (as Cl 2 ) 4.0 4.0

Chlorine dioxide (as ClO 2 ) 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 N YSDOH POCs Standards a,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 (wh ich 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 U OCs is 0.1 mg/L.4-18Table 4-5 – Comparison of additives used or proposed for use in NY, parameters detected in analyticalresults of flowbackfrom the Marcellus operations in PA and WV16, and parameters regulated via primary and secondary drinking waterstandards, SPDES Program or listed in TOGS111CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC22106-24-1 (2E)-3,7-dimethylocta-2,6-dien-1-olYes §67701-10-4(C8-C18) And (C18) UnsaturatedAlkylcarboxylic Acid Sodium SaltYes §§02634-33-51,2 Benzisothiazolin-2-one / 1,2-benzisothiazolin-3-oneYes §00087-61-6 1,2,3-TrichlorobenzeneYes Table 9 Tables 1,5 POC00095-63-6 1,2,4 trimethylbenzene Yes Yes Table 9Tables 1,5 POC93858-78-71,2,4-Butanetricarboxylicacid, 2-phosphono-,potassium saltYes §00108-67-8 1,3,5-TrimethylbenzeneYes Tables 9,10 Tables 1,5 POC16This table includes parameters detected in the MSCStudy.17As with Table 2-2, information in the “Used in Additives” column is based on the composition of additives used or proposed for use in New York.18Parameters marked with (¥) indicates that the compound dissociates, and its components are separatelyregulated. Not all dissociating compounds are marked.19As with Table 3-1, information in the “Found in Flowback” column is based on analytical results of flowback from operations in Pennsylvania or WestVirginia. There are/may be products used in fracturing operations in Pennsylvania that have not yet been proposed for use in New York for which, therefore, theNYSDEC does not have chemical composition data.20Limits marked with a pound sign (#) are based on secondary drinking water standards.21SPDES or TOGS typically regulates or provides guidance for the total substance, e.g. iron; and rarelyregulates or provides guidance for only its dissolvedportion, e.g. dissolved iron. The dissolved component is implicitly covered in the total substance. Therefore, the dissolved component is not included inTable4-5. Flowback analyses provided information for thetotal and dissolved components of metals, which are listed in Table 3-1 and in Table 4-6. Understanding thedissolved vs. suspended portions of a substance isvaluable when determining potential treatment techniques.22Cells marked with a section sign (§) indicates that if the parameter is not already covered by any other applicable regulation which provides an MCL, 10NYCRR applies the default UOC MCL of 0.05 mg/L foreach parameter, or 0.1 mg/L for the total POCs andUOCs. Double signs (§§) indicate that the freecompound would be UOC, but that salts would not beUOC.4-19CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2200123-91-1 1,4 DioxaneYes Table 8 §03452-07-1 1-eicoseneYes §00629-73-2 1-hexadeceneYes §104-46-1 1-Methoxy-4-propenylbenzeneYes §124-28-71-Octadecanamine, N, N-dimethyl- / N,NTimethyloctadecylamineYes §112-03-81-Octadecanaminium, N,N,N-Trimethyl-,Chloride /TrimethyloctadecylammoniumchlorideYes §00112-88-9 1-octadeceneYes §40623-73-2 1-Propanesulfonic acidYes §01120-36-1 1-tetradeceneYes §98-55-5 2-(4-methyl-1-cyclohex-3-enyl)propan-2-olYes §10222-01-2 2,2 Dibromo-3-nitrilopropionamide YesTable 9 Tables 1,527776-21-22,2'-azobis-{2-(imidazlin-2-yl)propane}-dihydrochlorideYes §73003-80-2 2,2-Dobromomalonamide Yes §00105-67-9 2,4-DimethylphenolYes Table 6 Tables 1,500087-65-0 2,6-DichlorophenolYes Table 815214-89-82-Acrylamido-2-methylpropanesulphonic acidsodium salt polymerYes §46830-22-22-acryloyloxyethyl(benzyl)dimethylammoniumchlorideYes §00052-51-7 2-Bromo-2-nitro-1,3-propanediol YesTable 1000111-76-22-Butoxy ethanol /Ethylene glycol monobutylether / Butyl CellusolveYes §01113-55-92-Dibromo-3-Nitriloprionamide / 2-Monobromo-3-nitriilopropionamideYes §00104-76-7 2-Ethyl Hexanol Yes §00091-57-6 2-MethylnaphthaleneYes Table 8 Tables 1,300095-48-7 2-MethylphenolYes Table 8109-06-8 2-Picoline (2-methyl pyridine) Yes Table 8 Table 300067-63-02-Propanol / Isopropyl Alcohol / Isopropanol /Propan-2-olYes Yes Table 104-20CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2226062-79-32-Propen-1-aminium, N,N-dimethyl-N-2-propenyl-chloride, homopolymerYes §95077-68-2 2-Propenoic acid, homopolymer sodium salt Yes §09003-03-62-propenoic acid, homopolymer, ammoniumsaltYes §25987-30-82-Propenoic acid, polymer with 2 ppropenamide, sodium salt / Copolymer ofacrylamide and sodium acrylateYes §71050-62-92-Propenoic acid, polymer with sodiumphosphinate (1:1)Yes §66019-18-92-propenoic acid, telomer with sodiumhydrogen sulfiteYes §00107-19-7 2-Propyn-1-ol / Progargyl Alcohol Yes§51229-78-83,5,7-Triaza-1-azoniatricyclo[3.3.1.13,7]decane, 1-(3-chloro2-propenyl)-chloride,Yes §106-22-9 3,7 - dimethyl-6-octen-1-olYes §5392-40-5 3,7-dimethyl-2,6-octadienalYes POC00115-19-5 3-methyl-1-butyn-3-ol Yes §00108-39-4 3-MethylphenolYes Table 8104-55-2 3-phenyl-2-propenalYes POC127-41-34-(2,6,6-trimethyl-1-cyclohex-2-enyl)-3-buten2-oneYes §00072-55-9 4,4 DDEYes Table 6 Tables 1,5121-33-5 4-hydroxy-3-methoxybenzaldehydeYes §00106-44-5 4-MethylphenolYes Table 8127087-87-04-Nonylphenol Polyethylene Glycol EtherBranched / Nonylphenol ethoxylated /Oxyalkylated PhenolYes §00057-97-6 7,12-Dimethylbenz(a)anthraceneYes Table 8 Table 300064-19-7 Acetic acidYes Yes Table 1068442-62-6Acetic acid, hydroxy-, reaction products withtriethanolamineYes §00108-24-7 Acetic Anhydride Yes Table 104-21CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2200067-64-1 AcetoneYes Yes Table 7 Tables 1,500098-86-2 AcetophenoneYes Table 300079-06-1 AcrylamideYes 0 TT Table 9 Tables 1,538193-60-1Acrylamide - sodium 2-acrylamido-2-methylpropane sulfonate copolymerYes §25085-02-3Acrylamide - Sodium Acrylate Copolymer orAnionic PolyacrylamideYes §69418-26-4Acrylamide polymer with N,N,N-trimethyl2[1-oxo-2-propenyl]oxy EthanaminiumchlorideYes §15085-02-3 Acrylamide-sodium acrylate copolymer Yes§00107-13-1 AcrylonitrileYes Table 6 Tables 1,568891-29-2Alcohols C8-10, ethoxylated, monoether withsulfuric acid, ammonium saltYes §§68526-86-3 Alcohols, C11-14-iso-, C13-rich Yes§68551-12-2Alcohols, C12-C16, Ethoxylated (a.k.a.Ethoxylated alcohol)Yes §00309-00-2 AldrinYes Tables 1,5Aliphatic acids Yes §Aliphatic alcohol glycol ether Yes §64742-47-8Aliphatic Hydrocarbon / Hydrotreated lightdistillate / Petroleum Distillates / IsoparaffinicSolvent / Paraffin Solvent / Napthenic SolventYes §Alkalinity, Carbonate, as CaCO3 Yes Table 1064743-02-8 AlkenesYes §68439-57-6 Alkyl (C14-C16) olefin sulfonate, sodiumsalt Yes §Alkyl Aryl Polyethoxy Ethanol Yes §Alkylaryl Sulfonate Yes §09016-45-9 Alkylphenol ethoxylate surfactants Yes0.5 mg/L#Alpha, Radiation Yesnone----------015picocuriesper Liter(pCi/L)Table 7 Tables 1,54-22CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2207439-90-5 AluminumYes0.05 to0.2 mg/L#Table 7 Tables 1,501327-41-9 Aluminum chloride Yes (¥)68155-07-7Amides, C8-18 and C19-Unsatd., N,NBis(hydroxyethyl)Yes73138-27-9 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 AmmoniaYes Yes00631-61-8 Ammonium acetate Yes Table 1068037-05-8 Ammonium Alcohol Ether Sulfate Yes (¥)§07783-20-2 Ammonium bisulfate Yes (¥)10192-30-0 Ammonium Bisulphite Yes (¥)12125-02-9 Ammonium Chloride Yes (¥) Table 1007632-50-0 Ammonium citrate Yes (¥)37475-88-0 Ammonium Cumene Sulfonate Yes (¥)01341-49-7 Ammonium hydrogen-difluoride Yes (¥)06484-52-2 Ammonium nitrate Yes (¥)07727-54-0Ammonium Persulfate / DiammoniumperoxidisulphateYes (¥)01762-95-4 Ammonium Thiocyanate Yes Table 10Anionic copolymerYes07440-36-0 AntimonyYes 0.006 0.006 Table 6 Tables 1,507664-41-7 Aqueous ammonia Yes Yes Table 7 Tables1,512672-29-6 Aroclor 1248Yes Table 6Aromatic hydrocarbons Yes §Aromatic ketones Yes §07440-38-2 ArsenicYes 0 0.01 Table 6 Tables 1,512174-11-7 Attapulgite Clay Yes07440-39-3 BariumYes 2 2 Table 7 Tables 1,5Barium Strontium P.S. (mg/L) Yes4-23CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC22121888-68-4Bentonite, benzyl(hydrogenated tallow alkyl)dimethylammonium stearate complex /organophilic clayYes §00071-43-2 BenzeneYes Yes 0 0.005 Table 6 Tables 1,5 POC119345-04-9Benzene, 1,1'-oxybis, tetratpropylenederivatives, sulfonated, sodium saltsYes §74153-51-8Benzenemethanaminium, N,N-dimethyl-N-[2-[(1-oxo-2-propenyl)oxy]ethyl]-, chloride,polymer with 2-propenamideYes §122-91-8 Benzenemethanol,4-methoxy-, 1-formateYes §1300-72-7Benzenesulfonic acid, Dimethyl-, Sodium salt(aka Sodium xylene sulfonate)Yes §00050-32-8 Benzo(a)pyreneYes Table 600205-99-2 Benzo(b)fluorantheneYes Tables 1,500191-24-2 Benzo(ghi)peryleneYes Table 6 Table 300207-08-9 Benzo(k)fluorantheneYes Table 6 Tables 1,5140-11-4 Benzyl acetateYes §00100-51-6 Benzyl alcoholYes Table 8 Table 307440-41-7 BerylliumYes 0.004 0.004 Table 6 Tables 1,5Beta, RadiationYesnone----------04 milliremsper yearTable 7 Tables 1,5Bicarbonates (mg/L) Yes Table 1076-22-2 Bicyclo (2.2.1) heptan-2-one, 1,7,7-trimethyl-Yes §Biochemical Oxygen Demand Yes Yes00111-44-4 Bis(2-Chloroethyl) etherYes Table 6 Tables 1,500117-81-7Bis(2-ethylhexyl)phthalate / Di(2-ethylhexyl)phthalateYes 0 0.006 Table 6 Tables 1,568153-72-0 Blown lard oil amine Yes68876-82-4 Blown rapeseed amine Yes1319-33-1 Borate SaltYes10043-35-3 Boric acidYes4-24CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2201303-86-2 Boric oxide / Boric Anhydride Yes07440-42-8 BoronYes Table 7 Tables 1,524959-67-9 BromideYes Table 7 Tables 1,500075-25-2 BromoformYes Table 6 Tables 1,500071-36-3 Butan-1-olYes Table 10 Tables 1,568002-97-1 C10 - C16 Ethoxylated Alcohol Yes §68131-39-5 C12-15 Alcohol, Ethoxylated Yes §07440-43-9 CadmiumYes 0.005 0.005 Table 6 Tables 1,507440-70-2 CalciumYes Table 81317-65-3 Calcium Carbonate Yes Table 1010043-52-4 Calcium chloride Yes (¥)1305-62-0 Calcium Hydroxide Yes1305-79-9 Calcium Peroxide Yes00124-38-9 Carbon Dioxide Yes Yes00075-15-0 CarbondisulfideYes Table 8 Tables 1,568130-15-4 Carboxymethylhydroxypropyl guar Yes§09012-54-8 Cellulase / Hemicellulase Enzyme Yes§09004-34-6 CelluloseYes §Cesium 137YesVia betaradiationChemical Oxygen Demand Yes YesChlorideYes 250 mg/L#Table 7 Tables 1,510049-04-4 Chlorine Dioxide YesMRDLG =0.8MRDL=0.8 Table 1000124-48-1 Chlorodibromomethane Yes Table 6 Tables 1,500067-66-3 ChloroformYes Table 6 Tables 1,578-73-9 Choline Bicarbonate Yes §§67-48-1 Choline Chloride Yes §§91-64-5 Chromen-2-oneYes §07440-47-3 ChromiumYes 0.1 0.1 Table 6 Tables 1,500077-92-9 Citric AcidYes §94266-47-4 Citrus Terpenes Yes §4-25CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2207440-48-4 CobaltYes Table 7 Table 161789-40-0 Cocamidopropyl Betaine Yes §68155-09-9 Cocamidopropylamine Oxide Yes §68424-94-2 Coco-betaineYes §Coliform, TotalYes 0 0.05 Table 7ColorYes15(ColorUnits)#Table 707440-50-8 CopperYes 1.0#TT;ActionLevel=1.3Table 6 Tables 1,507758-98-7 Copper (II) Sulfate Yes (¥)14808-60-7 Crystalline Silica (Quartz) YesVia solidsand TSS07447-39-4 Cupric chloride dihydrate Yes (¥)00057-12-5 CyanideYes 0.2 0.2 Table 6 Tables 1,500319-85-7 Cyclohexane (beta BHC)Yes Table 6 Tables 1,500058-89-9 Cyclohexane (gamma BHC)Yes 0.0002 0.0002 Table 6 Tables 1,51490-04-6 Cyclohexanol,5-methyl-2-(1-methylethyl)Yes §8007-02-1 Cymbopogon citratus leaf oil Yes8000-29-1 Cymbopogon winterianus jowitt oilYes01120-24-7 Decyldimethyl Amine Yes (¥) §02605-79-0 Decyl-dimethyl Amine Oxide Yes (¥)§00055-70-3 Dibenz(a,h)anthraceneYes Table 303252-43-5 Dibromoacetonitrile Yes Table 9 Tables 100075-27-4 Dichlorobromomethane Yes Table 6 Tables 1,525340-17-4 Diethylbenzene Yes §00111-46-6 Diethylene Glycol Yes Table 1022042-96-2Diethylenetriamine penta (methylenephonicacid) sodium saltYes §28757-00-8 Diisopropyl naphthalenesulfonic acid Yes§68607-28-3Dimethylcocoamine, bis(chloroethyl) ether,diquaternary ammonium saltYes §4-26CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2207398-69-8 Dimethyldiallylammonium chloride Yes§00084-74-2 Di-n-butyl phthalateYes Table 6 Tables 1,500122-39-4 DiphenylamineYes Table 7 Tables 1,525265-71-8 Dipropylene glycol Yes §34590-94-8 Dipropylene glycol methyl ether Yes§00139-33-3 Disodium Ethylene Diamine Tetra AcetateYes §64741-77-1 Distillates, petroleum, light hydrocracked Yes05989-27-5 D-LimoneneYes §00123-01-3 Dodecylbenzene Yes §27176-87-0 Dodecylbenzene sulfonic acid Yes §42504-46-1 Dodecylbenzenesulfonate isopropanolamineYes §00050-70-4 D-Sorbitol / Sorbitol Yes §37288-54-3 Endo-1,4-beta-mannanase, or Hemicellulase Yes §00959-98-8 Endosulfan IYes Table 6 Table 333213-65-9 Endosulfan IIYes Table 6 Table 307421-93-4 Endrin aldehydeYes Table 6 Tables 1,5149879-98-1 Erucic Amidopropyl Dimethyl Betaine Yes§00089-65-6 Erythorbic acid, anhydrous Yes §54076-97-0Ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2-propenyl)oxy]-, chloride, homopolymerYes §00107-21-1 Ethane-1,2-diol / Ethylene Glycol Yes Yes Table 7 Tables 1,5111-42-2 Ethanol, 2,2-iminobis-Yes §26027-38-3 Ethoxylated 4-nonylphenol Yes09002-93-1 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 §4-27CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2268439-51-0 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 §61791-08-0Ethoxylated fatty acid, coco, reaction productwith ethanolamineYes68439-45-2 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-hydroxybenzoateYes §00064-17-5 Ethyl alcohol / ethanol Yes00100-41-4 Ethyl BenzeneYes Yes 0.7 0.7 Table 6 Tables 1,5 POC93-89-0 Ethyl benzoateYes §00097-64-3 Ethyl LactateYes §09003-11-6Ethylene Glycol-Propylene Glycol Copolymer(Oxirane, methyl-, polymer with oxirane)Yes §00075-21-8 Ethylene oxide Yes Table 9 Tables 1,505877-42-9 EthyloctynolYes §8000-48-4 Eucalyptus globulus leaf oilYes61790-12-3 Fatty AcidsYes §68604-35-3Fatty acids, C 8-18 and C18-unsaturatedcompounds with diethanolamineYes68188-40-9Fatty acids, tall oil reaction products w/acetophenone, formaldehyde & thioureaYes09043-30-5 Fatty alcohol polyglycol ether surfactant Yes 0.5 mg/L#§07705-08-0 Ferric chloride Yes Table 1007782-63-0 Ferrous sulfate, heptahydrate Yes00206-44-0 FluorantheneYes Table 6 Tables 1,500086-73-7 FluoreneYes Table 6 Tables 1,54-28CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2216984-48-8 FluorideYes 2#4 Table 7 Tables 1,500050-00-0 FormaldehydeYes Table 8 Tables 1,529316-47-0Formaldehyde polymer with 4,1,1-dimethylethyl phenolmethyl oxiraneYes §153795-76-7Formaldehyde, polymers with branched 4-nonylphenol, ethylene oxide and propyleneoxideYes §00075-12-7 FormamideYes §00064-18-6 Formic acidYes Table 1000110-17-8 Fumaric acidYes Table 1065997-17-3 Glassy calcium magnesium phosphate Yes00111-30-8 Glutaraldehyde Yes §00056-81-5 Glycerol / glycerine Yes §09000-30-0 Guar GumYes §64742-94-5 Heavy aromatic petroleum naphtha Yes§09025-56-3 HemicellulaseYes §00076-44-8 HeptachlorYes 0 0.0002 Tables 1,501024-57-3 Heptachlor epoxideYes 0 0.0002 Tables 1,5Heterotrophic plate count Yes n/a TT2307647-01-0Hydrochloric Acid / Hydrogen Chloride /muriatic acidYes07722-84-1 Hydrogen Peroxide Yes Table 1064742-52-5 Hydrotreated heavy napthenic distillateYes00079-14-1 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)pyreneYes Table 6 Tables 1,523Treatment Technology specified.4-29CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2207439-89-6 IronYes 0.3 mg/L#Table 7 Tables 1,535674-56-7 Isomeric Aromatic Ammonium Salt Yes§64742-88-7Isoparaffinic Petroleum Hydrocarbons,SyntheticYes §00064-63-0 IsopropanolYes Table 1000098-82-8 Isopropylbenzene (cumene) Yes Yes Table 9 Tables 1,5 POC68909-80-8Isoquinoline, reaction products with benzylchloride and quinolineYes §08008-20-6 KeroseneYes64742-81-0 Kerosine, hydrodesulfurized Yes00063-42-3 LactoseYes8022-15-9 Lavandula hybrida abrial herb oilYes07439-92-1 LeadYes 0TT;Action Level0.015Table 6 Tables 1,564742-95-6 Light aromatic solvent naphtha Yes§01120-21-4 Light Paraffin Oil Yes §LithiumYes Table 1007439-95-4 MagnesiumYes Table 7 Tables 1,5546-93-0 Magnesium Carbonate Yes1309-48-4 Magnesium Oxide Yes1335-26-8 Magnesium Peroxide Yes14807-96-6 Magnesium Silicate Hydrate (Talc) Yes07439-96-5 ManganeseYes 0.05 mg/L#Table 7 Tables 1,507439-97-6 MercuryYes 0.002 0.002 Table 6 Tables 1,501184-78-7 Methanamine, N,N-dimethyl-, N-oxide Yes§00067-56-1 MethanolYes Yes Table 10119-36-8 Methyl 2-hydroxybenzoateYes §00074-83-9 Methyl BromideYes Table 6 Tables 1,5 POC00074-87-3 Methyl Chloride / chloromethane Yes 0 0.005 Table 6 Tables 1,5 POC00078-93-3 Methyl ethyl ketone / 2-ButanoneYes Table 7 Tables 1,54-30CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2268891-11-2Methyloxirane polymer with oxirane, mono(nonylphenol) ether, branchedYes §08052-41-3 Mineral spirits / Stoddard Solvent Yes64742-46-7Mixture of severely hydrotreated andhydrocracked base oilYes07439-98-7 MolybdenumYes Table 700141-43-5 Monoethanolamine Yes §44992-01-0N,N,N-trimethyl-2[1-oxo-2-propenyl]oxyEthanaminium chlorideYes §64742-48-9 Naphtha (petroleum), hydrotreated heavyYes §00091-20-3 NaphthaleneYes Yes Table 6 Tables 1,538640-62-9 Naphthalene bis(1-methylethyl) Yes§00093-18-5 Naphthalene, 2-ethoxy- Yes §68909-18-2 N-benzyl-alkyl-pyridinium chloride Yes§68139-30-0N-Cocoamidopropyl-N,N-dimethyl-N-2-hydroxypropylsulfobetaineYes §07440-02-0 NickelYes Table 6 Tables 1,5Nitrate, as NYes 10 10 Table 7 Tables 1,507727-37-9 Nitrogen, Liquid form YesNitrogen, Total as N Yes Table 500086-30-6 N-NitrosodiphenylamineYes Table 6 Tables 1,526027-38-3 Nonylphenol Ethoxylate Yes68412-54-4 Nonylphenol Polyethoxylate Yes §Oil and GreaseYes Table 58000-27-9 Oils, cedarwoodYes121888-66-2 Organophilic Clays YesOxyalkylated alkylphenol Yes §628-63-7 Pentyl acetateYes §540-18-1 Pentyl butanoateYes §8009-03-8 PetrolatumYes64742-65-0 Petroleum Base Oil Yes §4-31CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC22Petroleum distillate blend Yes §64742-52-5 Petroleum Distillates YesPetroleum hydrocarbons Yes §64741-68-0 Petroleum naphtha Yes §pHYes 6.5-8.5#Table 500085-01-8 PhenanthreneYes Table 6 Tables 1,500108-95-2 PhenolYes Table 6 Tables 1,5PhenolsYes Table 6 Tables 1,5101-84-8 PhenoxybenzeneYes §70714-66-8Phosphonic acid,[[(phosphonomethyl)imino]bis[2,1-ethanediylnitrilobis(methylene)]]tetrakis-,ammonium saltYes57723-14-0 PhosphorusYes Table 7 Table 108000-41-7 Pine OilYes8002-09-3 Pine oilsYes60828-78-6Poly(oxy-1,2-ethanediyl), a-[3,5-dimethyl-1-(2-methylpropyl)hexyl]-w-hydroxy-Yes §25322-68-3Poly(oxy-1,2-ethanediyl), a-hydro-w-hydroxy /Polyethylene GlycolYes §24938-91-8Poly(oxy-1,2-ethanediyl),α-tridecyl-ω-hydroxyYes §31726-34-8Poly(oxy-1,2-ethanediyl),alpha-hexyl-omega-hydroxyYes9004-32-4 Polyanionic Cellulose Yes51838-31-4Polyepichlorohydrin, trimethylaminequaternizedYes §56449-46-8 polyethlene glycol oleate ester Yes§Polyethoxylated alkanol Yes §9046-01-9 Polyethoxylated tridecyl ether phosphateYes §63428-86-4Polyethylene glycol hexyl ether sulfate,ammonium saltYes §4-32CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2262649-23-4Polymer with 2-propenoic acid and sodium 2-propenoateYes §Polymeric Hydrocarbons Yes §09005-65-6 Polyoxyethylene Sorbitan Monooleate Yes§61791-26-2 Polyoxylated fatty amine salt Yes §65997-18-4 Polyphosphate Yes07440-09-7 PotassiumYes Table 800127-08-2 Potassium acetate Yes1332-77-0 Potassium borate Yes12712-38-8 Potassium borate Yes20786-60-1 Potassium borate Yes00584-08-7 Potassium carbonate Yes07447-40-7 Potassium chloride Yes00590-29-4 Potassium formate Yes01310-58-3 Potassium Hydroxide Yes Table 1013709-94-9 Potassium metaborate Yes24634-61-5 Potassium Sorbate Yes112926-00-8 Precipitated silica / silica gel Yes00057-55-6 Propane-1,2-diol, or Propylene glycol Yes Yes Table 10 Table 32400057-55-6 Propylene glycol00107-98-2 Propylene glycol monomethyl ether YesTable 1000110-86-1 PyridineYes Table 7 Tables 1,568953-58-2 Quaternary Ammonium Compounds Yes Table 9 Tables 162763-89-7 Quinoline,2-methyl-, hydrochloride Yes15619-48-4 Quinolinium, 1-(phenylmethl),chloride YesRadiumYes Table 724TOGS lists this parameter as CAS 58-55-6.4-33CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC22Radium 226Yesnone-------------zero5 pCi/L Table 7 Tables 1,5Radium 228Yesnone-------------zero5 pCi/L Tables 1,58000-25-7 Rosmarinus officinalis l. leaf oilYes00094-59-7 SafroleYes Table 8 Table 3Salt of amine-carbonyl condensate YesSalt of fatty acid/polyamine reaction product YesScale Inhibitor (mg/L) Yes §07782-49-2 SeleniumYes 0.05 0.05 Table 6 Tables 1,507631-86-9 Silica, Dissolved Yes Table 807440-22-4 SilverYes 0.10 mg/L#Table 6 Tables 1,507440-23-5 SodiumYes Table 7 Tables 1,505324-84-5 Sodium 1-octanesulfonate Yes00127-09-3 Sodium acetate Yes95371-16-7 Sodium Alpha-olefin Sulfonate Yes00532-32-1 Sodium Benzoate Yes00144-55-8 Sodium bicarbonate Yes07631-90-5 Sodium bisulfate Yes07647-15-6 Sodium Bromide Yes00497-19-8 Sodium carbonate Yes07647-14-5 Sodium Chloride Yes07758-19-2 Sodium chlorite Yes03926-62-3 Sodium Chloroacetate Yes00068-04-2 Sodium citrateYes06381-77-7Sodium erythorbate / isoascorbic acid, sodiumsaltYes02836-32-0 Sodium Glycolate Yes1301-73-2 Sodium hydroxideYes01310-73-2 Sodium Hydroxide Yes Table 104-34CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2207681-52-9 Sodium hypochlorite Yes Table 1007775-19-1 Sodium Metaborate .8H2O Yes10486-00-7 Sodium perborate tetrahydrate Yes07775-27-1 Sodium persulphate Yes68608-26-4 Sodium petroleum sulfonate Yes09003-04-7 Sodium polyacrylate Yes07757-82-6 Sodium sulfate Yes Table 1001303-96-4 Sodium tetraborate decahydrate Yes07772-98-7 Sodium Thiosulfate Yes01338-43-8 Sorbitan Monooleate YesSpecific Conductivity Yes07440-24-6 StrontiumYes Table 9 Table 100057-50-1 SucroseYesSugarYes05329-14-6 Sulfamic acidYes14808-79-8 SulfateYes 250 mg/L#Table 7 Tables 1,5SulfideYes Table 7 Tables 1,514265-45-3 SulfiteYes Table 7 Table 1Surfactant blend Yes 0.5 mg/L#68442-77-3 Surfactant: Modified Amine YesSurfactants MBAS Yes 0.5 mg/L#112945-52-5Syntthetic Amorphous / Pyrogenic Silica /Amorphous SilicaYes68155-20-4 Tall Oil Fatty Acid Diethanolamine Yes08052-48-0 Tallow fatty acids sodium salt Yes72480-70-7Tar bases, quinoline derivs., benzyl chloride-quaternizedYes68647-72-3 Terpene and terpenoids Yes §68956-56-9 Terpene hydrocarbon byproducts Yes00127-18-4 Tetrachloroethylene Yes 0 0.005 Table 6Tables 1,5 POC00533-74-4Tetrahydro-3,5-dimethyl-2H-1,3,5-thiadiazine-2-thione / DazometYes4-35CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC2255566-30-8Tetrakis(hydroxymethyl)phosphonium sulfate(THPS)Yes00075-57-0 Tetramethyl ammonium chloride Yes §00064-02-8 Tetrasodium EthylenediaminetetraacetateYes §07440-28-0 ThalliumYes 0.0005 0.002 Table 6 Tables 1,500068-11-1 Thioglycolic acid Yes00062-56-6 ThioureaYes Table 1068527-49-1Thiourea, polymer with formaldehyde and 1-phenylethanoneYes68917-35-1 Thuja plicata donn ex. D. don leaf oilYes07440-32-6 TitaniumYes Table 700108-88-3 TolueneYes Yes 1 1 Table 6 Tables 1,5 POCTotal Dissolved Solids Yes 500 mg/L#Table 5Total Kjeldahl Nitrogen Yes YesTotal Organic Carbon Yes YesTotal Suspended Solids Yes Yes81741-28-8 Tributyl tetradecyl phosphonium chlorideYesTriethanolamineYes §68299-02-5 Triethanolamine hydroxyacetate Yes00112-27-6 Triethylene Glycol Yes §52624-57-4Trimethylolpropane, Ethoxylated,PropoxylatedYes §00150-38-9 Trisodium Ethylenediaminetetraacetate Yes §05064-31-3 Trisodium Nitrilotriacetate Yes §07601-54-9 Trisodium ortho phosphate Yes00057-13-6 UreaYes07440-62-2 VanadiumYes Table 7 Table 125038-72-6Vinylidene Chloride/MethylacrylateCopolymerYes4-36CASNumberParameter NameUsed inAdditives17,18Found inFlowback19MCLG(mg/L)20MCL or TT(mg/L)SPDESTables21TOGS111TablesPOC /UOC22Volatile AcidsYes257732-18-5 WaterYes8042-47-5 White Mineral Oil Yes11138-66-2 Xanthan gumYesXylenesYes Yes 10 10 Table 1,5 POC13601-19-9 Yellow Sodium of Prussiate Yes07440-66-6 ZincYes 5 mg/L#Table 6 Tables 1,5ZirconiumYes25Several volatile compounds regulated via SPDES Table 6. Need to evaluate constituents.4-37Table 4-6 – Typical concentrations of flowback constituents based on limited samples from PA and WV, and regulated inNY26,27CAS # Parameter NameTotalNumber ofSamplesNumber ofDetectsMin Median Max Units00067-64-1 Acetone3 1 681 681 681μg/LAcidity, Total4 4 101 240 874 mg/LAlkalinity28155 155 0 153 384 mg/LAlkalinity, Carbonate, as CaCO3 164 163 0 9485 48336mg/LTotal Alkalinity5 5 28 91 94mg/LAlpha, Radiation15 15 0 166 18950pCi/L07439-90-5 Aluminum43 12 0.02 0.07 1.2mg/LAluminum, Dissolved22 1 1.37 1.37 1.37 mg/L07440-36-0 Antimony34 1 0.26 0.26 0.26mg/L07664-41-7 Aqueous ammonia48 45 11.3 44.8 382mg/L07440-38-2 Arsenic43 7 0.015 0.09 0.123mg/L07440-39-3 Barium48 47 0.553 1450 15700mg/LBarium, Dissolved22 22 0.313 212 19200 mg/L00071-43-2 Benzene35 14 15.7 479.5 1950μg/L07440-41-7Beryllium43 1 422 422 422mg/LBeta, Radiation15 15 0 62 7445pCi/L26Information presented in Table 4-6 and Table 4-7 is based on limited data from Pennsylvania and WestVirginia. Characteristics of flowback from theMarcellus Shale in New York are expected to be similar to flowback from Pennsylvania and West Virginia, but not identical. In addition, the raw data forthesetables came from several sources, with likely varying degrees of reliability. Also, the analytical methods used were not all the same for given parameters.Sometimes laboratories need to use different analytical methods depending on the consistency and quality of the sample; sometimes the laboratories are onlyrequired to provide a certain level of accuracy. Therefore, the method detection limits may be different. The quality and composition of flowback from asinglewell can also change within a few days soon after the well is fractured. This data does not control for any of these variables. Additionally, it should be noted thatseveral of these compounds could be traced back topotential laboratory contamination. Further comparisons of analytical results with those results fromassociated laboratory method blanks may be requiredto further assess the extent of actual concentrations found in field samples versus elevated concentrationsfound in field samples due to blank contamination.27This table does not include results from the MSC Study.28Different data sources reported alkalinity in different and valid forms. Total alkalinity reported here is smaller than carbonate alkalinity because thedata camefrom different sources.4-38CAS # Parameter NameTotalNumber ofSamplesNumber ofDetectsMin Median Max UnitsBicarbonates150 150 0 183 1708mg/LBiochemical Oxygen Demand38 37 3 200 4450mg/L00117-81-7 Bis(2-ethylhexyl)phthalate20 2 10.3 15.9 21.5μg/L07440-42-8 Boron23 9 0.539 2.06 26.8mg/L24959-67-9 Bromide15 15 11.3 607 3070mg/L00075-25-2 Bromoform26 2 34.8 36.65 38.5μg/L07440-43-9 Cadmium43 6 0.007 0.025 1.2mg/LCadmium, Dissolved22 2 0.017 0.026 0.035 mg/L07440-70-2 Calcium187 186 29.9 4241 123000mg/LCalcium, Dissolved3 3 2360 22300 31500mg/LCesium 1372916 2 9.9 10.2 10.5pCi/LChemical Oxygen Demand38 38 223 5645 33300mg/LChloride193 193 287 56900 228000mg/L00124-48-1 Chlorodibromomethane26 2 3.28 3.67 4.06μg/L07440-47-3 Chromium43 9 0.009 0.082 760mg/LChromium (VI), dissolved19 10 0.0126 0.539 7.81 mg/LChromium, Dissolved22 2 0.058 0.075 0.092 mg/L07440-48-4 Cobalt30 6 0.03 0.3975 0.62 mg/LCobalt, dissolved19 1 0.489 0.489 0.489 mg/LColiform, Total5 2 1 42 83 Col/100mLColor3 3 200 1000 1250 PCU07440-50-8 Copper43 8 0.01 0.0245 0.157 mg/L00057-12-5 Cyanide7 2 0.006 0.0125 0.019 mg/L00075-27-4 Dichlorobromomethane29 1 2.24 2.24 2.24 μg/L00100-41-4 Ethyl Benzene38 14 3.3 53.6 164 μg/L16984-48-8 Fluoride4 2 5.23 392.615 780 mg/LHeterotrophic plate count5 3 25 50 565 CFU/mL07439-89-6 Iron193 168 0 29.2 810 mg/LIron, Dissolved34 26 6.75 63.25 196 mg/L07439-92-1 Lead43 6 0.008 0.035 27.4mg/L29Regulated under beta particles [19].4-39CAS # Parameter NameTotalNumber ofSamplesNumber ofDetectsMin Median Max UnitsLithium13 13 34.4 90.4 297mg/LLithium, Dissolved4 4 24.5 61.35 144 mg/L07439-95-4 Magnesium193 180 9 177 3190mg/LMagnesium, Dissolved3 3 218 2170 3160mg/LMg as CaCO3145 145 36 547 8208 mg/L07439-96-5 Manganese43 29 0.15 1.89 97.6mg/LManganese, Dissolved22 12 0.401 2.975 18 mg/L07439-97-6Mercury30 2 0.0006 0.295 0.59mg/L00074-83-9 Methyl Bromide26 1 2.04 2.04 2.04μg/L00074-87-3 Methyl Chloride26 1 15.6 15.6 15.6μg/L07439-98-7 Molybdenum34 12 0.16 0.44 1.08mg/L00091-20-3 Naphthalene23 1 11.3 11.3 11.3μg/L07440-02-0 Nickel43 15 0.01 0.03 0.137mg/LNickel, Dissolved22 2 0.03 0.0715 0.113 mg/LNitrate, as N1 1 0.025 0.025 0.025mg/LNitrogen, Total as N1 1 13.4 13.4 13.4mg/LOil and Grease39 9 5 17 1470mg/LPetroleum hydrocarbons1 1 0.21 0.21 0.21mg/LpH191 191 0 6.6 8.58S.U.00108-95-2 Phenol20 1 459 459 459μg/LPhenols35 5 0.05 0.191 0.44mg/L57723-14-0 Phosphorus, as P3 3 0.89 1.85 4.46mg/L07440-09-7 Potassium33 17 15.5 125 7810mg/LPotassium, Dissolved3 3 84.2 327 7080 mg/LRadium6 3 7.7 9.7 24pCi/LRadium 2263 3 2.58 4.67 33pCi/LRadium 2283 3 1.15 4.66 18.41pCi/LScale Inhibitor145 145 315 744 1346mg/L07782-49-2 Selenium34 1 0.058 0.058 0.058mg/LSelenium, Dissolved22 1 1.06 1.06 1.06 mg/L07440-22-4 Silver43 3 0.129 0.204 6.3mg/LSilver, Dissolved22 2 0.056 0.0825 0.109 mg/L07440-23-5 Sodium42 41 83.1 23500 96700mg/LSodium, Dissolved3 3 9290 54800 77400 mg/L4-40CAS # Parameter NameTotalNumber ofSamplesNumber ofDetectsMin Median Max Units07440-24-6 Strontium36 36 0.501 1115 5841mg/LStrontium, Dissolved22 21 8.47 629 7290 mg/L14808-79-8 Sulfate (as SO4)193 169 0 1 1270mg/LSulfide (as S)8 1 29.5 29.5 29.5mg/L14265-45-3 Sulfite (as SO3)3 3 2.56 64 64mg/LSurfactants3012 12 0.1 0.21 0.61mg/L00127-18-4 Tetrachloroethylene26 1 5.01 5.01 5.01μg/L07440-28-0 Thallium34 2 0.1 0.18 0.26mg/L07440-32-6 Titanium25 1 0.06 0.06 0.06mg/L00108-88-3 Toluene38 15 2.3 833 3190μg/LTotal Dissolved Solids193 193 1530 63800 337000mg/L07440-62-2Vanadium24 1 40.4 40.4 40.4mg/LTotal Kjeldahl Nitrogen25 25 37.5 122 585mg/LTotal Organic Carbon3128 23 69.2 449 1080mg/LTotal Suspended Solids43 43 16 129 2080mg/LXylenes38 15 15.3 444 2670μg/L07440-66-6 Zinc43 18 0.011 0.036 8570mg/LZinc, Dissolved22 1 0.07 0.07 0.07 mg/LFluid Density145 145 8.39004 8.7 9.2 lb/galHardness by Calculation170 170 203 11354 98000mgCaCO3/LSalt %145 145 0.9 5.8 13.9 %Specific Conductivity15 15 1030 110000 165000 pmhos/cmSpecific Gravity150 154 0 1.04 1.201Temperature31 31 0 15.3 32 °CTemperature145 145 24.9 68 76.1 °F30Regulated under foaming agents.31Regulated via BOD, COD and the different classes/compounds of organic carbon.

### 4-41

Table 4-7 - Typical concentrations of parameters th at 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 method s are enabling the recovery of valuable onshore natural gas reserves. These new methods al so 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 TD S, and low concentrations of several
parameters.

Reasonably good quality water is typically needed t o harness the full benefit of fracturing fluid
additives. Freshwater is therefore an obvious choic e. But use of freshwater in hydraulic fracturing operations imposes an additional constra int 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-sta te industrial treatment plants, or underground injection wells 32 

### are the disposal options utilized. However, treati ng flowback fluid at POTWs can cause potential excursion of POTW perm it limits; also, trucking the water is costly. Underground injection removes the water fro m the natural water cycle.

On-site treatment (with off-site disposal of the co ntaminants removed) or recycling is seen as the more environmentally sound method for managing flow back. This section surveys on-site treatment or recycling options currently used; prov ides a preliminary evaluation of the extent and conditions of such use; and assesses the general ap plicability of these technologies at hydraulic fracturing sites in New York State.

5.2 Flowback Recycling

Recycling flowback in hydraulic fracturing operatio ns presently entails primary treatment (i.e. settling) and then blending known amounts of flowba ck with freshwater [3]. Recycling the flowback reduces freshwater needs. However, high co ncentrations of different parameters adversely affect the desired fracturing fluid prope rties. Concentrations of chlorides, calcium, magnesium, barium, carbonates, sulfates, solids, mi crobes, etc. in the flowback are too high to use as-is [1]. The demand for friction reducers inc reases when the chloride concentration increases [1]; the demand for scale inhibitors incr eases when concentrations of calcium, magnesium, barium, carbonates, or sulfates increase [ 1]; biocide requirements increase when the concentration of microbes increases [6]. The curren t recycling practice of blending flowback

32 It should be noted that while three fully permitte d 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 (d iscussed later) is typically needed prior to recycling flowback.

One operator who shared analytical results after us ing 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 pr ior 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 y ear to assess potential seasonal variations and their impact on bacterial activity and water qualit y. 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 treat ment technologies are:

1. Influent [i.e. flowback] parameters and their conce ntrations

2. Parameters and their concentrations allowable in th e 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 l ikely 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. Theref ore, a series of on-site treatment technologies is needed to produce a usable treated flowback stre am. Stringing together several treatment units is costly. However, treating the flowback on-site w ould 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 th e effluent

All experts and operators agree that freshwater mee ts 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 minimu m allowable water quality for a fracturing operation: different experts suggest different limi ts 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 fo r 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 flo wback in the Barnett Shale due to economic infeasibility. However, based on feedback from a fe w operators, when on-site treatment is provided, the residuals (or concentrates) are injec ted into deep and stable strata (UIC wells). The regulatory framework for disposal of these residual s 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 uti lize on-site treatment and the selection of specific treatment options. These include:

Operational

 

### Flowback fluid characteristics, including scaling a nd fouling tendencies

 

### On-site space availability

 

### Processing capacity needed

 

### Solids concentration in flowback fluid, and solids reduction required

 

### Concentrations of hydrocarbons in flowback fluid, a nd targeted reduction in hydrocarbon 33

 

### 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 re siduals

 

### 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 con figurations is illustrated in Figure 5-1 34 

### . 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 t able 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 p articular characteristics of flowback would determine the spe cific steps.

### 5-5

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

Some form of physical and/or chemical separation wi ll be required as a part of on-site treatment. Physical and chemical separation technologies typic ally 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 sys tems.

The efficiency of filtration technologies is contro lled 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 $300,00 0; 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 l ab-scale research, nanofiltration has been used to treat produced water from off-shore oil rigs, an d modular filtration units have been used in the Barnett Shale and Powder River Basin [21, 22, 23, 2 4].

5.4.2 Chemical Separation and Precipitation

Chemical separation utilizes coagulants and floccul ants to break emulsions (dissolved oil) and to remove suspended particles. Precipitation is accom plished by manipulating flowback chemistry such that constituents within the flowback (in part icular, metals) will precipitate out of solution. This can also be performed sequentially, so that se veral chemicals will precipitate, resulting in
cleaner flowback.

Separation and precipitation are used as pre-treatm ent steps within multi-step on-site treatment processes. Chemical separation units have been use d in the Barnett Shale and Powder River Basin, and some vendors have proprietary designs fo r sequential precipitation of metals for potential use in the Marcellus Shale [25, 26, 27].

If flowback is to be treated solely for blending an d 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 exc ess treatment may be required. Prices for chemical precipitation systems are dependent upon t he cost of the treatment chemicals; one vendor quoted a 15 gallon per minute (gpm) system f or $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 m ay be used to treat TDS in flowback. The technology allows water, the permeate, to pass thro ugh 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 appro ximately 45,000 mg/L, and produce an
effluent with TDS concentrations between 200 and 50 0 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 scali ng 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 u sed in various desalination projects, in both modular and permanent configurations.

RO is a well-proven technology, though it is less e fficient 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 w ill 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 secondar y 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. S ome 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 pref erentially remove certain ions. When treating flowback, the resin would be selected to preferenti ally remove sodium ions. The required resin volume and size of the ion exchange vessel would de pend on the salt concentration and flowback
volume treated.

The Higgins Loop is one version of ion exchange tha t has been successfully used in Midwest coal bed methane applications. The Higgins Loop us es 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 s ystem [33].

Modular ion exchange units have been used in the Ba rnett Shale.

5.4.5 Electrodialysis

These treatment units are configured with alternati ng stacks of cation and anion membranes that allow passage of flowback fluid. The electric curr ent applied to the stacks forces anions and cations to migrate in different directions [32].

Electrodialysis Reversal (EDR) is similar to electr odialysis, 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 ele ctricity usage than standard RO systems and can potentially reduce salt concentrations in t he 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 Sy stems

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 (SD I) < 12 SDI < 5

Operating Pressure <50 psi > 100 psi

Power Consumption Lower for <2,500 mg/L TDS Lower f or >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 produc e 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 effe ctive at higher TDS concentrations (>150,000 mg/L) than other treatment technologies.

Traditionally energy and space intensive, recent in dustry advancements have produced modular distillation/evaporation units that are less cost-p rohibitive than older models. Some systems have been designed with the option to utilize natur al gas that may be available from the well pad 35 

### , while others use recycled waste heat (primarily f rom gas compressors at the well pad) as
the sole heat source. In addition to new sources o f thermal energy for distillation systems, some vendors have designed systems that require signific antly 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 effe ctive on highly concentrated wastewaters, thus minimizing the amount of water needed to be ev aporated. Due to these limitations, some vendors suggest that thermal distillation/evaporati on be used as a secondary treatment; further concentrating the wastewater concentrate from a fil tration or reverse osmosis treatment system.

Modular thermal distillation units have been used i n the Barnett Shale, and have begun to be used in the Marcellus Shale in Pennsylvania. In ad dition to the units that are already in use, several vendors have designs ready for testing, pot entially further decreasing costs in the nearfuture [23, 24, 30, 34, 35, 36, 37, 38].

Due to the high TDS concentrations found in Marcell us flowback samples, mobile evaporation treatment systems appear to be the most feasible sy stem 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 princi ples 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 use d in some capacity on site, will be offered for

35 During initial exploration and production phases, natural gas would likely not be readily available a t the well pad.

### 5-9

sale as a secondary product if radiological paramet ers are below an acceptable threshold, or will be treated in such a way that it will meet regulati ons for disposal within a landfill.

ZLD treatment is a relatively rare, expensive treat ment 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 t he systems’ byproducts. In addition to the crystallized salts produced by ZLD, treated effluen t water and/or steam will also be a product that can be used by a third party in some industria l or agricultural setting.

ZLD treatment systems are in use in a variety of in dustries, but none have been implemented in a natural gas production setting yet. Some technolog y vendors have advertized ZLD as a treatment option in the Marcellus, but the economic al 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 sepa rate most hydrocarbons and heavy metals, and oxidize biological films and bacteria from flow back fluid. The microscopic air bubbles in supersaturated ozonated water and/or ultrasonic tra nsducers cause oils and suspended solids to
float.

Multiple vendors include ozone treatment technologi es as one step in their flowback treatment process, including treatment for blending and re-us e of water in drilling new wells. Systems utilizing ozone technology have been successfully u sed and analyzed in the Barnett Shale [31, 39].

5.4.9 Comparison of potential on-site treatment technolog ies

A comparison of performance characteristics associa ted with on-site treatment technologies is provided in Table 5-3.

Table 5-3 - Summary of Characteristics of On-site F lowback 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 w aste streams are typically governed by the type (classification) of waste. The following secti ons discuss the available containment vessels, and the regulations that could potentially apply to flowback.

Due to the large volumes of water required for hydr aulic fracturing operations and the limited quantities of water that can be withdrawn and trans ported 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 combina tion of impoundments and frac tanks.

5.5.1 Frac tanks

Frac tanks are available from many different vendor s 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-bot tom, rectangular tank with a single axle. These tanks are designed to be pulled by any semi-t ruck 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 previ ous one, however instead of a V-bottom, these tanks have a cylindrical bottom. Functionally, the re is not much difference between these two tank designs.

The third frac tank design is a skid-mounted cylind rical 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. W hile tank transport may be more challenging for these tanks, they are available in volumes larger t han the 21,000-gallon rectangular tanks.

Most frac tanks are designed to have at least one m an-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, interi or epoxy coating to minimize corrosion, volume gauges, and various adjustable piping and drainage configurations. Many manufacturers also supply geomembrane containment berms that are desig ned 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; thes e tanks typically offer less capacity than the 21,000, single-walled tanks.

Each frac tank is capable of holding only a small p ortion of the frac fluid or flowback at any given time. To account for this, operators use hos es 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 capacit y of the water storage system, a feature not available if using only an on-site impoundment, how ever this could prove to be a costly and space-consuming approach to on-site fluid containme nt.

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 t o holding water for fracturing and storing flowback, impoundments are commonly used by driller s to hold water and drilling mud, as well as by producers to hold produced water and other wa stewaters and brines created at the well-site. The use of these impoundments, as well as their des ign, is typically controlled by various state regulations. While many states have such regulatio ns, 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 Y ork state regulations.

Many aspects of Texas’ and Pennsylvania’s impoundme nt 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 ga s operator is permitted to use an on-site impoundment [40]. The Commission has published a g uidance manual specifying design criteria which are deemed appropriate [41]. Pennsylvania, o n the other hand, incorporated the design criteria into the actual regulations [42].

The most significant difference between these two s tates’ 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 com pacted 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 pe rmeability requirement. Although not applicable for many pits, this potentially gives Te xas gas operators, upon regulatory approval, the ability to utilize unlined, compacted soil cont ainment 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. Texa s regulation requires leak detection systems for brine containment pits that use a synthetic lin er. 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). Pe nnsylvania, 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 th ere is no regulation requiring an earlydetection system for leaks from on-site containment ponds in Pennsylvania.

Table 5-4 - Design specifications for containment p onds 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 jag ged

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 require ments 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 o r hardpan, and constructed and maintained so as to prevent escape of brine or salt water[43]. See S ection 4.7.2 for additional information. The GEIS further requires use of a plastic liner for al l pits and specifies pit design and construction procedures [18].

The regulated design criteria for solid waste dispo sal 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 le ak 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 flow back) 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 regul ations 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 regulat ions

On-site treatment and containment of drilling mud a nd flowback fluids requires compliance with federal and state regulations. However, this indust ry is presently exempt from some of the more stringent federal regulations. The Resource Conser vation Recovery Act (RCRA) governs how waste materials are handled and disposed of, includ ing a subcategory of solid wastes that are defined as hazardous. Depending on the specific co nstituents in flowback from a particular site/location, as defined by the RCRA, flowback flu id may be considered a solid waste [45]; however, regardless of the fluid’s Toxicity Charact eristics, because of its exemption from RCRA, flowback will be exempt from federal classifi cation as a hazardous waste [46, 47].

The USEPA reviewed existing regulations prior to pr eparing its 1988 regulatory determination resulting in the exemption of oil and gas explorati on and production wastes from federal hazardous waste regulations [48]. That review resu lted in the following conclusions:

 

### Many samples of oil and gas exploration and product ion wastes exhibited toxic characteristics, although these characteristics alo ne do not indicate the actual threat to human or environmental health. Location and manage ment practices, among other factors, help to reduce risks from these wastes.

 

### Categorizing these wastes as hazardous under RCRA w ould have a large (multi-billion dollar) economic impact upon the oil and gas indust ry, 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 provi de effective regulation of oil and gas wastes, without requiring the stringent RCRA hazard ous 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-rel ated 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 excee d) the regulatory toxicity level. It is important to note that, per 40 CFR 261.24, toxic co ncentrations need to be determined using specifically prescribed analytical methods; these m ethods 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 wou ld therefore be present in flowback. The maximum concentration of barium for the Toxicity Ch aracteristic, as provided in 40 CFR 261.24, is 100 mg/L. The median concentration of ba rium 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 Character istic, 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 conc entration 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 explorati on and production wastes may indeed have toxic characteristics, the EPA concluded that the e conomic burden imparted on operators if these wastes were regulated under RCRA hazardous waste ru les 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 prote ct surface water (National Pollutant Discharge Elimination System – NPDES; SPDES in New York) and groundwater (Underground Injection Control - UIC) from pollution would regul ate 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. R adium-226 has a 1,600 year half-life, is commonly occurring, and undergoes alpha decay. Rad ium-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 s amples 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 indicat ors of the concentration of radium isotopes may be limited due to the variability in the correl ation 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 a nalyticals 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 flow back samples are relatively low. Limited data from PA and WV has indicated higher NORM conce ntrations in later flowback water than
in the initial flowback water. Based on limited dat a, it appears that NORM concentrations in production brine are higher than in flowback water.

Treatment of flowback water or production brine cou ld 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, jurisdiction al agencies may include the USEPA, the Nuclear Regulatory Commission (NRC), Occupational S afety and Health Administration (OSHA), and Pipeline and Hazardous Materials Safety Administration (PHMSA). In the absence of any delegated state authority, these age ncies would have regulatory jurisdiction at various points throughout the waste treatment, tran sportation and disposal processes [50].

Various individual states have introduced regulatio ns related to NORM and TENORM, including regulatory frameworks for NORM disposal, as describ ed below. In New York, many NORMrelated regulatory responsibilities lie with the NY S Departments of Environmental Conservation (NYSDEC) and Health (NYSDOH). The NYSDEC has radio logical regulatory authority as well as waste regulatory authority, and NYSDOH has regul atory authority over worker and public health protection from radiation along with the aut hority 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 t reat flowback for one or more constituents, at present, there is no practical and cost-effective m ethod to selectively remove NORM or processed and concentrated NORM. Therefore the impa ct of concentrating waste streams that could potentially contain NORM must be considered b y 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 fr equently mentioned methods of disposal

are:

 

### On-site injection into oil/gas well once production has ceased.

 

### On-site spreading of waste on land (incorporation i nto 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 r epositories (this is a last resort disposal method).

 

### Off-site brine treatment facilities (permitted to t reat produced waters and brines – potentially limited influent NORM levels).

Note that not all these methods are allowed or impl emented in all states with oil and gas production. In particular, New York’s Part 380 reg ulations 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 beco me contaminated with built-up radioactive material. To address this issue, some states with significant oil and gas production have also implemented regulations governing the decontaminati on 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 commercia lly used 36 

### treatment method that selectively treats/removes radium from flowback or production b rine. Chemical precipitation, for example, is based on the chemical’s solubility constant/prod uct. The solubility of radium and its compounds is similar to the solubility of several o ther metals and their compounds. Therefore isolating it via precipitation, when treating large volumes of waste streams, would be challenging.

Treatment techniques, such as chemical precipitatio n, ion-exchange or activated carbon that
remove radium also remove other metals. The treatme nt 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 handl ing 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 c ontamination of subsequent treatment units.

Because of the potential challenges with handling w aste streams that may contain processed and concentrated NORM, treating flowback with appreciab le amounts of NORM would be difficult.

36 Here ‘Commercial Use’ encompasses wastewater treat ment 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 m ay offer many advantages to Marcellus gas operators. Treatment and re-use of flowback will r educe the quantity of fresh water required for fracturing operations, which will in turn reduce wi thdrawal and trucking costs. On-site treatment may also potentially reduce disposal cost of flowba ck fluids, by decreasing volumes that must be trucked to a centralized treatment facility or disp osal site.

On-site treatment technology is not necessarily wid ely available, although an increasing number of producers are beginning to use such systems with in 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 suc cessfully 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 s hale formations are all potential issues that
must be addressed.

In addition to the above uncertainties, storage, ha ndling, and ultimate disposal of flowback concentrates could become further complicated by it s 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 pr oposed and tested in the last few years. Treatment capability will likely continue to improv e and treatment costs will likely decline as the oil and gas industry begins to utilize treatment te chnologies more extensively.5-19Table 5-6 - Select characteristics of various treatment technologies currently offered or under design37Vendor Processes used Flowrate/unitAllowableInfluent TDS% Recovered asEffluentEffluentqualityFootprint/ unit Energy UsageApproximatePriceDescription ofconcentrateConcentratedisposal methodOperational StatusA & BThermal Distillation/Evaporation720,000 gpd10,000 mg/L >95%<5 mg/L TDSOnsite/ modular in additionto a centralized plantHigh - - -Rock salts orconcentrated brineRock salt can besold - concentratedbrine must betreatedPortable unit is designed -centralized treatment facilityis being designedCrystallization 150,000 mg/L 50%BBrine concentration - - - - - - >95% <10 mg/L TDSOnsite/ modular units orcentralized treatment plantModerate to high$50M-$100M forcentralizedtreatment plantConcentrated brine orcrystallized solidsBrine must betreated or - solidscan be re-used, sold,or disposedVendor has extensiveexperience with centralizedtreatment plantsEvaporation - - - - - - - - - - - -Crystallization - - - - - - - - - - - -Reverse Osmosis 662,400 gpd 45,000 mg/L 35-45% - --C & DChemical Precipitation100,000 gpd custom custom - - - Onsite/ modular Low- - - - - - - - -Designed, not yetimplementedOxidationEOxidation- - -40,000 mg/Lchloride- - - on-site reuseOnsite/ modular -contained in frac tanksModerateContracted priceper barrel- - - - - - Field testedReverse OsmosisF & GFiltration126,000 gpd/unit - - - 90-95%distilled water(<200 mg/L TDS)Onsite/ portable High $3-$4 per barrelConcentrated brineInjection well orfurther treatmentUsed by many industries -starting to be used in field forflowback - contains process toseparate VOCs for useThermal Distillation/EvaporationMethanolOnsite use or saleOxidationVOCsHNanofiltration w/ vibration 316,800 gpd discharge or reuse 80% injection well 4’x4’x16’H Low to moderate$300,000 for a25,000 gpd unit5% total solidsInjection well orfurther treatmentIn use in Marcellus and onoffshore oil rigsIThermal Distillation/Evaporation72,000 gpd - - - - - -for blending andreuseOnsite/ modular Moderate to high$4 per barrelConcentrated brineInjection well orfurther treatmentReady to be builtReverse Osmosis 1,008,000 gpd - - - 75%- - - ModerateJThermal Distillation/Evaporation330 gpd/unit150,000 mg/L(41,700 mg/L in testresults)90%< 500 mg/L TDS(106 mg/L TDSin test results)~ 10 ft2/unitModerate (lowenergy evap)- - - - - - - - -In use in western US and inPA for treating producedwater - also buildingcentralized plantKReverse Osmosis 4,500 gpd/unit 45,000 mg/L - - - drinking quality 36' x 7' - modular Moderate - - - Concentrated brine - - - Tested - for saleLEvaporation &Crystallization- - - - - - 95% reuse/ dischargeOnsite/ modular units orcentralized treatment plantHigh - - - Solid cakeApproved forlandfill disposalCustom design - notimplemented in Marcellus yetMFiltration~20,000 gpd/unit no limit 90% steam 20’ x 40’ Low (waste heat) $3-$4 per barrelConcentrated brine orchemicalcrystallizationBrine treatmentplant or landfill forthe crystalsIn use in Marcellus in PAEvaporationCrystallization37This table contains data obtained from flowback treatment system vendors. This information may change at anytime and its inclusion in this table by nomeans indicates a preference or an endorsement of any one technology (vendor names have been omitted).Vendors providing different types of treatment units sometimes collaborate in order to provide a complete treatment system.5-20Vendor Processes used Flowrate/unitAllowableInfluent TDS% Recovered asEffluentEffluentqualityFootprint/ unit Energy UsageApproximatePriceDescription ofconcentrateConcentratedisposal methodOperational StatusNDistillation (Mobile VaporRecompression)105,000 gpd/unit 80,000 mg/L 60-90% <10 mg/L TDS 50' x 50' Moderate $4.50 per barrel Concentrated brineCentralizedtreatment or reuseas a kill fluidIn use in western USMechanical/ chemicalseparationOChemical Precipitation 300,000 gpd - - - - - -re-use asfracturing fluid25,000 ft2Low$0.50 - $3 perbarrelSludge cakeLandfill if barium isremoved fromsludge - otherwise,hazardous wasteProcess designed - notimplemented yet

### 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, w hich potentially could have an adverse impact on the environment if not properly controlle d. The recognition of potential hazards has motivated investigation into environmentally-fr iendly alternatives for hydraulic fracturing technologies and chemical additives.

It is important to note that use of ‘environmentall y friendly’ or ‘green’ alternatives may reduce, but not entirely eliminate, adverse environ mental impacts. Therefore, further research into each alternative is warranted to fully underst and the potential environmental impacts and benefits of using any of the alternatives. In addit ion, the ‘greenness’ needs to be evaluated in a holistic manner, considering the full lifecycle i mpact of the technology or chemical.

6.2 Environmentally-Friendly Fracturing Technology Alte rnatives

The following environmentally-friendly technology a lternatives have been identified as being in use in the Marcellus Shale, with other fracturin g/stimulation applications or under investigation for possible use in Marcellus Shale o perations:

 

### Liquid carbon dioxide alternative – The use of a li quid carbon dioxide and proppant mixture reduces the use of other additives [51]. Ca rbon dioxide vaporizes leaving only the proppant in the fractures. The use of this tech nique in the US has been limited to demonstrations [93].

 

### Nitrogen-based foam alternative – Nitrogen-based fo am 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 nitro gen foam was found to introduce liquid components that can cause formation damage [ 88].

 

### Liquefied Petroleum Gas (LPG) – The use of LPG, con sisting primarily of propane, has the advantages of carbon dioxide and nitrogen c ited above; additionally, LPG is known to be a good carrier of proppant due to the h igher viscosity of propane gel [83]. Further, mixing LPG with natural gas does not ‘cont aminate’ natural gas; and the mixture may be separated at the gas plant and recyc led [83]. LPG’s high volatility, low weight, and high recovery potential make it a g ood fracturing agent. This technology is in limited use in Canada, and no info rmation 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 beca use 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. sl imhole drilling, coiled tubing, multilateral drilling, and dual-well configuration 38 

### ) 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 thei r use at shale plays similar to the
Marcellus.

Locating multiple wells in a single pad, particular ly 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 chang e made to date in shale fracturing operations in the United States has been the switch ing from a diesel- (also called oil- or synthetic-) based fluid to water based fluid. In 20 03, BJ Services Company, Halliburton Energy Services, Inc., and Schlumberger Technology Corporation and the USEPA signed a voluntary Memorandum of Agreement by which diesel f uel use in hydraulic fracturing fluids injected into underground sources of drinking water during hydraulic fracturing of coalbed methane wells was eliminated [59, 60]. Diesel cont ains benzene, naphthalene, toluene, ethylbenzene, xylenes, and other potentially harmfu l compounds. While this agreement was limited to shallow coalbed methane wells, diesel wa s not among the listed constituents used for hydraulic fracturing by operators or their serv ice providers who shared data with NYSDEC, and its use as a primary component of hydra ulic fracturing fluid is not within the scope of the SGEIS. While chemical additives are st ill involved, the fluid used in hydraulic fracturing operations is now water-based.

There are several US-based chemical suppliers who a dvertise ‘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]; Eco surf EH surfactants by Dow Chemicals;
or ‘Green’ Chemicals for the North Sea from BASF. U SEPA has published the twelve principles of green chemistry and a sustainable che mistry hierarchy [62], listed below, yet these do not provide a common measure of environmen tal-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 an d intersecting horizontal wellbore systems to acces s greater extents of gas resources with a single well site. This has been applied in low-medium permeabi lity
formations.

### 6-3

2. Design safer chemicals and products: Design chemica l products to be fully effective, yet have little or no toxicity.

3. Design less hazardous chemical syntheses: Design sy ntheses to use and generate substances with little or no toxicity to humans and the environment.

4. Use renewable feedstocks: Use raw materials and fee dstocks that are renewable rather than depleting. Renewable feedstocks are often made from agricultural products or are the wastes of other processes; depleting feedst ocks are made from fossil fuels (petroleum, natural gas, or coal) or are mined.

5. Use catalysts, not stoichiometric reagents: Minimiz e 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 r eagents, 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 us e 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 u sing solvents, separation agents, or other auxiliary chemicals. If these chemicals ar e 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 tha t 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 t he formation of byproducts.

12. Minimize the potential for accidents: Design chemic als and their forms (solid, liquid, or gas) to minimize the potential for chemical acci dents including explosions, fires,
and releases to the environment.

While these twelve principles of green chemistry an d a sustainable chemistry hierarchy set general characteristics of an environmentally-frien dly chemical or technique, they do not provide an objective metric for evaluating the envi ronmentally-friendliness. Presently, environmentally-friendliness of chemicals used in h ydraulic fracturing in the US has been measured only subjectively. Vendors/suppliers indic ate their products are environmentallyfriendly, but presently, there is no established me thod in the US to assess the life-cycle

### 6-4

impact or impact on all relevant media of these che micals. 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-fri endly 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 ma y be discharged into the North Sea. Two
of the initiatives are:

 

### The Offshore Chemical Notification Scheme (OCNS) th at manages chemical use and discharge by the United Kingdom (UK) and Netherland s offshore petroleum industries.

 

### The European Union legislation regarding the Enviro nmental Impact Assessment (EIA) that requires a comprehensive assessment of the eff ects of projects on the environment.

An outcome of these initiatives was a regulation th at prohibited the discharge of cuttings generated from drilling with synthetic- (i.e. oil/d iesel) based drilling fluids where the synthetic oil on the cuttings is greater than 1% [6 3]. Additionally, the UK government proposed to phase out the discharge of cuttings con taminated 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 trans ported 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 publishe d 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 wa ters of the United States.

6.3.2 Environmental Coordination in Europe

The Convention for the Protection of the Marine Env ironment 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 fi fteen 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 c over land-based sources and the offshore industry. These two conventions were unified, updat ed 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 practi ce or best available techniques to prevent pollution [65]. The OSPAR list of substances that m ay be used or discharged offshore which are considered by OSPAR to Pose Little or No Risk t o the Environment (PLONOR) contains substances whose use or discharge offshore are subj ect 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/agreem ents/04- 10_plonor%202008%20revision.doc

.

### 6-5

The “main environmental acceptability criterion” fo r the UK government’s decision was biodegradation [64], which is consistent with Princ iple 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 product s must pass biodegradation, bioaccumulation, toxicity, and taint tests in order to be permitted for use [67]. Organisation for Economic Co-Operation and Development (OECD) No rth Sea countries require chemicals to be tested for ecotoxicity, biodegradat ion, and bioconcentration/bioaccumulation [64, 65].

6.3.2.1 Offshore Chemical Notification Scheme (OCNS )

The Offshore Chemical Notification Scheme (OCNS) ma nages chemical use and discharge by the UK and Netherlands offshore petroleum indust ries [68]. OCNS classifies chemicals using test protocols approved by OSPAR Harmonised O ffshore Chemical Notification Format (HOCNF) coordinates the testing requirements for oilfield chemicals throughout the
Northeast Atlantic sector.

To assess the potential environmental hazard associ ated with chemical products that may be used in offshore drilling operations, OCNS uses tox icity, 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 produ cts. Several lists of approved products that may be used for Production, Completion / Worko ver, Drilling or Cementing, ranked by their HQ may be found at http://www.cefas.co.uk/off shore-chemical-notification-scheme- (ocns)/hazard-assessment.aspx.

In the UK, OCNS is regulated by the Department of E nergy and Climate Change (DECC) with scientific and environmental input from the Ce ntre for Environment, Fisheries and Aquaculture Science (Cefas) and the Fisheries Resea rch Services (FRS). In the Netherlands, OCNS is regulated by the State Supervision of Mines (SSM) with scientific and environmental advice from Cefas and Netherlands gov ernment 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 (le ast hazardous), and HQ color from purple (most hazardous), through orange, blue, whit e, and silver, to gold (least hazardous) [70].

### 6-6

Table 6-1 - Cefas Chemicals Categories based on Haz ard 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-notificati on-scheme-(ocns)/hazardassessment.aspx. OCNS-approved products that were a lso 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 reg ulatory environment among the OSPAR countries. Norwegian State Pollution Control Author ity (SFT) also regulates the use of drilling muds through discharge permits. SFT assess es water-based fluids using data on bioaccumulation potential and bio-degradability. SFT e ncourages limiting use and discharges of even these approved products. Discharge of unused c hemicals 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 Selectio n Guidelines for Drilling & Production
Activities on Frontier Lands. C-NLOPB follows the O CNS to a great extent.

6.4 Summary

The ‘environmentally-friendly’ aspect of hydraulic fracturing of deep shale formations presently stem from drilling techniques, like horiz ontal drilling and mutli-well pads with smaller overall footprint, and from the use of envi ronmentally-friendly chemicals.

Several US-based chemicals suppliers advertise ‘gre en’ 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 estab lished criteria that define environmentalfriendliness, and utilize models and databases to t rack chemicals’ overall hazardousness against those criteria. Similar to NYSDEC, the regu latory authorities in Europe request proprietary information from chemicals suppliers, a nd 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 th e criteria used in Europe or the US might choose to set up an independent scientific entity t o evaluate all chemicals proposed for use within US territories. However, at this time, it ma y not be feasible to require the use of ‘green’ chemicals because presently there is no met ric 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 s etting up a metric that provides a comprehensive evaluation is difficult.

It is important to note that several products manuf actured by US-based companies, and used or proposed for use in the Marcellus Shale in New Y ork, may be found in the European approved chemicals lists.

### 7-1



## 7 ALTERNATE W ATER 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 us age 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 withdrawa l at the rate needed at all times, may be subject to restrictions on interbasin transfers, an d 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 s hould be considered, where available,
include:

 

### Effluent from municipal or industrial wastewater tr eatment plants

 

### Partial re-use of fracturing water (discussed in Se ction 5)

 

### Non-contact cooling water discharges from industria l plants

 

### Saline aquifers

 

### Stormwater ponds

 

### Impoundments (lakes, reservoirs, quarries)

 

### Mine discharges

 

### Deep mine pools

Alternate water sources need to meet a number of cr iteria before they may be considered for hydraulic fracturing, as discussed below.

7.3 Factors that Affect Usability of Alternate Water So urces

Operators should consider several factors when eval uating 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 b e 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 decreas es when longer distances and travel times are involved. Also, the selected routes need to con sider roadway wear, bridge weight limits, local zoning limits, impacts on residents, and rela ted traffic concerns.

Available quantity – Fewer larger water sources avo ids 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 an d less steady source.

Accessibility –Water from deep mines and saline aqu ifers may be more difficult to access than a surface water source unless adequate infrast ructure is in place. Access to a municipal or industrial plant or reservoir may be inconvenien t due to security or other concerns. Access to a stream may be difficult due to terrain, compet ing land uses, or other issues.

Quality of water – The fracturing fluid serves a ve ry specific purpose at different stages of the fracturing process. The composition of the wate r could affect the efficacy of the additives and equipment used. The water may require pre-treat ment or additional additives may be needed to overcome problematic characteristics.

Potential concerns with water quality include scali ng from precipitation of barium sulfate and calcium sulfate [1]; high concentrations of chlorid es, 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 potentia lly plug fractures [1]; microbes that can accelerate corrosion, scaling or other gas producti on [6]; and high concentrations of sulfur (e.g. water from flue gas desulfurization impoundme nts), which could contaminate natural gas. In addition, water sources of variable quality could present difficulties.

Similar to reusing or recycling flowback for hydrau lic fracturing, experts on hydraulic fracturing agree that high quality water is easy an d convenient to use, and that somewhat lower quality water may also be utilizable for hydr aulic fracturing [1]. Perhaps due to the additional cost and inconvenience of withdrawing an d transporting alternate water sources, expectations of water quality are higher of alterna te water sources than of recycled flowback. Based on the applicable water quality specification s, 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 treatme nt.

Permittability – Applicable permits and approvals w ould need to be identified and assessed as to feasibility and schedule for obtaining approv als, conditions and limitations on approval that could impact the activity or require mitigatio n, 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 hydraul ic fracturing will be necessary, or appropriate treatment for re-use provided. Utilizin g an alternate source with sub-standard quality water could add to treatment and disposal c osts.

Cost – Sources that have a higher associated cost t o acquire, treat, transport, permit, access or dispose, typically will be less desirable by indust ry.

7.4 Summary

Theoretically, any water source may be utilized for hydraulic fracturing. But in practice, several factors could affect the usability and suit ability 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 wat er treatment, regulations, and costs. Each service company and operation would need to evaluat e local conditions to determine the availability of alternate water sources to a partic ular gas well.

### 8-1



## 8 WATER WELL SAMPLING NEEDS

8.1 Introduction

Based on experiences in other states, there is conc ern that high-volume hydraulic fracturing operations may impact private water wells in the St ate of New York (the State) by contaminating the water well or depleting the resou rce [72, 73, 75]. However, the USEPA found no threat to water sources from hydraulic fra cturing [75, 76]. Additionally, Interstate Oil and Gas Compact Commission (IOGCC) member state s have all stated that there have been no cases where hydraulic fracturing has been v erified to have contaminated drinking water [76]. This section summarizes available infor mation on private water well sampling, testing, and monitoring activities performed in a n umber of states in conjunction with hydraulic fracturing of deep shale formations. The desktop research identified relevant information for New York, Pennsylvania, Ohio, Kentu cky and Texas.

This section also proposes ‘indicator’ compounds/el ements to monitor before and after drilling/fracturing to indicate whether there may b e a connection between private water well contamination and hydraulic fracturing operations. These indicators have been selected using limited analytical results of flowback from the Mar cellus 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 - Pro tection 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 alte rnate 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 a ny 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 mon itoring of water wells within 1,000 feet of the gas well may, therefore, be driven by both t he 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 P ennsylvania. While the drinking water well owner may use a ‘Do-it-yourself’ sampling kit, a st ate-certified laboratory needs to perform the analyses if legal action were later required ba sed on the analytical results.

8.3 Water Well Sampling Requirements in Ohio

The Ohio Department of Natural Resources administer s a pre-drilling water sampling program in Ohio. This program requires gas well ope rators to prepare a sampling plan; the actual sampling requirements are determined on a ca se-by-case basis and may be contingent on a variety of factors, including hydrology, geolo gy, 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 va ries by operation.

### 8-2

The State of Ohio requires analyses of the followin g parameters to characterize pre-drilling water quality: alkalinity, barium, calcium, chlorid e, conductivity, iron, magnesium, pH, potassium, sodium, sulfate, and total dissolved sol ids (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 inf ormation 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]. Kentu cky Administrative Regulations have general requirements and guidelines for groundwater protection, but the desktop search did not find any specific water supply monitoring requi rements 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 Conservati on Law (ECL) authorizes the New York State Department of Environmental Conservation (NYS DEC) 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 o ut 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 E nvironmental Impact Statement if the proposed oil or gas well is within 1,000 feet. Stri ct 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 p lace 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 i ts 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 ope rators a succinct list of parameters

### 8-3 to monitor, at the producer’s expense, in private w ater wells within a certain distance of a proposed gas well, before and after a fracturi ng operation.

 

### NYSDEC could draw from Pennsylvania’s requirements and require any gas well operator who affects the quantity or quality of a p rivate water supply to restore or replace, within a reasonable timeframe, the affecte d private water supply with an alternate source of water similar in quantity and q uality to the original supply.

8.8 Indicator Compounds/Elements of Potential Contamina tion due to Hydraulic Fracturing

Limited time-series data of flowback from Marcellus Shale gas wells in Pennsylvania show that concentrations of several parameters in flowba ck increased over the 2 to 3 week period. These parameters include: TDS, hardness, calcium, m agnesium, bromide, chloride, fluoride, chemical oxygen demand, barium, and manganese. Conc entrations of sulfates, bicarbonates, total Kjeldahl nitrogen, 5-day biological oxygen de mand, 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 d ata 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 mat erials in the shale formation or due to fracturing fluids, there is insufficient data at th is time to make a definitive determination that these other parameters would always be found primar ily/exclusively due to fracturing operations in the Marcellus Shale area.

In order to determine if a private water supply wel l has been contaminated due to hydraulic fracturing operations, comprehensive pre- and post- drilling water quality monitoring may be
warranted 39 

### . Such monitoring may be costly, though.

Monitoring for parameters such as barium, TDS and p H could indicate if the private water well has been contaminated due to the fracturing op eration. Monitoring for strontium, sodium, chloride, hardness (calcium and magnesium), surfactants, total suspended solids (TSS), iron, carbonates and bicarbonates could prov ide 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 shal e formations. Based on NYSDEC’s experience with investigating water well complaints, pre-drilling p rivate water well quality may vary due to impact of even an undeveloped shale.

### 8-4

Monitoring for methane would alert potential uncont rolled emissions due to damaged casings, etc. It has also been suggested that an is otopic analysis of carbon in methane could determine if the gas is from a shallow source or fr om a deep reservoir.

8.9 Summary

There is concern among the public, particularly amo ng property owners and private water supply well owners near hydraulic fracturing operat ions, about potential well water contamination due to fracturing operations. This se ction surveyed existing private water well sampling, testing and monitoring requirements in Ne w York, Pennsylvania, Ohio, Kentucky
and Texas.

Barium and TDS are recommended as indicator substan ces to monitor for, at a minimum, in private water supply wells, before and after gas we ll drilling/fracturing to determine potential contamination from the operation. Private water wel l quality depends on a number of factors, including water well construction, potential pre-ex isting contamination, and natural water quantity variations. Therefore, establishing pre-dr illing well water conditions is important to determine the potential impact of the fracturing op eration.

The frequency and length of monitoring would likely depend on the specific location; but may be pre-drilling, then once per month from the s tart 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 frequ ency 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 pote ntial 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 addi tives to assist and enhance drilling and fracturing. A portion of the fracturing fluids ret urns to the surface as flowback. This fluid contains variations of additives, parameters that w ere 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 accordan ce with their designated use classifications. This study addresses this issue, subject to the lim ited 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 inf ormation 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 propose d for use in hydraulic fracturing operations in New York.

Section 3 discusses volumes and composition of flow back 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 pre sents a list of compounds and elements based on analytical results of flowback from the Ma rcellus Shale.

Section 4 surveys the sufficiency of federal and Ne w 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 dr inking water standards, the SPDES program, NYSDOH’s POC and UOC Standards, or which h ave guidance through TOGS111. Nearly all the parameters detected in laboratory an alyses provided by industry appear to be addressed in Federal or State regulations or guidan ces.

Section 5 is a preliminary survey of flowback recyc ling and on-site treatment technologies currently used to a limited extent for other drilli ng/fracturing operations. On-site treatment of flowback is costly, and technology is not widely av ailable for use in the Marcellus Shale. However, these technologies are evolving to meet in dustry needs and regulatory requirements. At the present time, operators appear to recycle flowback more than treat it.

Section 6 surveyed ‘environmentally-friendly’ hydra ulic fracturing technologies and chemicals. It appears that environmentally-friendly technologies are in experimental phases or have only been used under conditions different f rom the Marcellus. The ‘environmentally-

### 9-2

friendly’ aspect of hydraulic fracturing of deep sh ale formations presently stems from drilling techniques, such as horizontal drilling and multi-w ell 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 regard ing oil and gas drilling in the North Sea. This study did not evaluate the robustness or effic acy of European efforts, but suggests that
the OSPAR Convention and the Offshore Chemical Noti fication Scheme (OCNS) serve as the starting point for setting up a framework in Ne w York State (or the US 40 

### ) to promote environmentally-conscious hydraulic fracturing oper ations. The specific concerns associated with onshore vs. offshore operations would likely b e 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 th at may be utilized for hydraulic fracturing operations. Several alternate sources might potenti ally 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 coolin g water discharge from industrial facilities may presently be a significant component of a waterbody 41 

### , and its use would likely require approvals and permit modifications from wat erbody commissions or other agencies. Water from saline aquifers, quarries, or mines woul d likely require significant treatment. These sources already contain high concentrations o f TDS – the parameter likely of greatest operational concern in flowback. Treatment is costl y. 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 avail ability, 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 compl ete life-cycle) of water used in hydraulic fracturing.

There is concern that hydraulic fracturing operatio ns may contaminate private water wells in the vicinity. Section 8 surveys efforts in Pennsyl vania 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 pro gram to protect municipal water wells. Section 8 draws from experiences and guidelines in Pennsylvania and Ohio to suggest enhancements to water resource protection (particul arly 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 sugge sts 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 fract uring.

41 Particularly during low flow period, the relativel y 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 associat ed with hydraulic fracturing within a very short period of time. The information is based on l imited interactions with service companies, telephone interviews and articles from i ndustry experts, or information published on websites, and is not based exclusively on peer-r eviewed published literature. Composition of additives and analytical results of flowback are from service companies and operators who voluntarily shared proprietary information with NYS DEC. 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 the se 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 chemi cal additives used in fracturing operations. As additional service companies, operators and chem icals suppliers share more information, the table with basic constituents in additives (Tab le 3-1) may be further expanded.

Except for the analytical results provided by the M SC, the different analyses of flowback data tested for different sets of parameters. In ad dition, 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 c omprehensive list of parameters, guidelines on allowable detection methods under dif ferent conditions, along with the composition and quantity of water and additives use d would provide a better understanding of constituents in flowback. Flowback composition c hanges 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 innovat e and share information would help understand the industry’s progress in on-site treat ment and recycling.

Some US-based companies advertise ‘green’ chemicals . But there does not appear to be a common metric in place to evaluate environmental-fr iendliness 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 environmenta l 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 impera tive that these regulations and requirements
continue to be administered at the state-level. Int erstate collaboration with respect to shale development similar to riverbasin commissions would likely be beneficial.

This study suggests a few parameters to test and mo nitor 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 perc eived need for a State-wide private well testing program.

### 9-4

9.3 Closing

The oil and gas industry has developed innovative t echnologies to harness natural gas from the low-permeability Marcellus Shale formation at d epths of several thousand feet. Adequate safeguards are necessary to carry out these drillin g and fracturing operations in an environmentally sensitive manner. The industry has shared proprietary information and experiences regarding hydraulic fracturing operatio ns which have been utilized in this report.

As with other states in the core Marcellus Shale re gion, 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 impo rtant 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 pro vides an opportunity for agencies, industry and the public to work together to develop one resource while protecting and preserving other resources and respecting the compe ting public demands on the State.

### 10-1



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### 10-2

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### 10-5

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