final report png 580

HYDRAULIC FRACTURING: THE UP-STATE NEW YORK DEBATE

4/24/13 Feasibility of environmentally safe shale gas production in upstate New York

“A review of the potential environmental impact and the economics of environmentally safe production”

Prepared By: Ibrahim Bukhamseen, Maxian Seales, Kojo C. Yeboa & Egbadon Udegbe

Hydraulic Fracturing: The Up-State New York Debate

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TABLE OF CONTENTS

LIST OF FIGURES .................................................................................................................................................. 3

EXECUTIVE SUMMARY ........................................................................................................................................ 5

CHAPTER 1 | INTRODUCTION ............................................................................................................................ 9 SECTION 1.1: UNCONVENTIONAL NATURAL GAS .............................................................................................................. 9

1.1.1 Deep Gas ..................................................................................................................................................................... 9 1.1.2 Tight Gas .................................................................................................................................................................. 10 1.1.3 Coal Bed Methane ................................................................................................................................................... 10 1.1.4 Geo Pressurized Zones ........................................................................................................................................... 11 1.1.5 Methane Hydrates/ Clathrates .............................................................................................................................. 11 1.1.6 Shale Gas ................................................................................................................................................................. 12

SECTION 1.2 – SHALE GAS OUTLOOK ................................................................................................................................ 13 SECTION 1.3: ESTIMATED WORLDWIDE GAS QUANTITIES ............................................................................................. 14 SECTION 1.4:!SHALE GAS IN THE UNITED STATES ............................................................................................................. 16

1.4.1 The United Sates Shale Gas Deposits ................................................................................................................... 16 1.4.2 Marcellus shale Gas Play ....................................................................................................................................... 19

SECTION 1.5 – HYDRAULIC FRACTURING & THE NEW YORK STATE SHALE GAS DEBATE ........................................ 21 1.5.1 Hydraulic Fracturing ............................................................................................................................................... 21 1.5.2 The History of the New York State Shale Gas Debate - Events that shaped the Debate .............................. 22 1.5.3 Current status of the Shale Gas Debate in New York State .............................................................................. 24

CHAPTER 2 | ENVIRONMENTAL CONCERNS OF HYDRAULIC FRACTURING .................................................. 27 2.1 WATER REQUIREMENT .................................................................................................................................................. 27 2.2 WATER CONTAMINATION .......................................................................................................................................... 28 2.3 FLOW BACK WATER MANAGEMENT ........................................................................................................................ 28

CHAPTER 3 | POLICY CONSIDERATIONS FOR HYDRAULIC FRACTURING ...................................................... 30 3.1 FEDERAL REGULATION OF HYDRAULIC FRACTURING ............................................................................................... 30 3.2 NEW YORK STATE REGULATION OF HYDRAULIC FRACTURING ............................................................................. 33

CHAPTER 4 | ENGINEERING ASSESSMENT 1 .................................................................................................... 35

Hydraulic fracturing propagation and threat to underground sources of drinking water .................................. 35 4.1 FRACTURE PROPAGATION .......................................................................................................................................... 35 4.2 SEEPAGE OF METHANE GAS ....................................................................................................................................... 37 4.3 CASE STUDIES ................................................................................................................................................................. 38

4.3.1 Case 1: Natural Gas Content in Water Well (Weatherford, Texas) ............................................................. 38 4.3.1 Case 2: Chemical Additives in Water Well (Pavillion, Wyoming) ................................................................. 39

CHAPTER 5| ENGINEERING ASSESSMENT 2 ..................................................................................................... 40

Flowback water treatment options for Up-state New York Shale Gas Production ............................................. 40 5.1 COMPOSITION OF FRACTURING FLUIDS ................................................................................................................. 40 5.2 PURPOSE OF FRACTURING FLUID COMPONENTS ................................................................................................. 40 5.3 HYDRAULIC FRACTURING FLOWBACK WATER ...................................................................................................... 44


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5.3.1 Flowback water volume ............................................................................................................................................. 44 5.3.2 Potential impact on public health and the environment ......................................................................................... 45 5.2.3 Treatment and Disposal Options for Hydraulic Fracturing wastewater .............................................................. 47

5.4 TREATMENT PROCESSES IN POTWS & CWTS ............................................................................................................. 52 5.5 ON-SITE TREATMENT OF HYDRAULIC FRACTURING WASTE WATER ..................................................................... 56 5.6 TREATMENT OPTIONS FOR UPSTATE NEW YORK ...................................................................................................... 62 5.7 REQUIRED TREATMENT PROCESSES & COST OF TREATMENT OPTIONS ............................................................... 66

CHAPTER 6| ENGINEERING ASSESSMENT 3 ..................................................................................................... 68

Proppant Selection for Gas Production in the Marcellus Shale in Up-state New York ....................................... 68 6.1 PURPOSE AND TYPES OF PROPPANTS ......................................................................................................................... 68 6.2 PROPPANT SELECTION ..................................................................................................................................................... 70 6.3 ECONOMICS OF PROPPANT SELECTION ................................................................................................................. 75 6.4 PROPPANT SELECTION: UPSTATE NEW YORK MARCELLUS SHALE ..................................................................... 79

6.4.1 Closure stress Calculation .......................................................................................................................................... 79 6.4.2 Proppant Type Selection ............................................................................................................................................ 80

CHAPTER 7 | ECONOMIC ASSESSMENT ........................................................................................................... 81 7.1 DEVELOPMENT OF CASH FLOW MODEL AND PRODUCTION MODEL .................................................................. 81

7.1.1 Field Size & Well Development ............................................................................................................................ 81 7.1.2 Decline Curve Analysis ............................................................................................................................................ 83 7.1.2 Gas Price .................................................................................................................................................................. 88

7.2 ECONOMIC MODELING OF PRODUCTION VIABILITY ............................................................................................... 90 7.2.1 Metrics of Profitability ............................................................................................................................................ 90 7.2.2 Baseline Cash Flow Model ...................................................................................................................................... 91 7.2.3 Cost of Flowback Treatment Options ................................................................................................................... 98 7.2.4 Cash Flow Analysis of Flowback Treatment Alternatives ................................................................................. 100 7.2.5 Summary of Cash Flow Analysis ......................................................................................................................... 104

CHAPTER 8 | SOCIO-ECONOMIC IMPACT ON UP-STATE NEW YORK ........................................................... 106 8.1 EMPLOYMENT ............................................................................................................................................................... 108 8.2 ECONOMY .................................................................................................................................................................... 110 8.3 STATE REVENUES AND EXPENDITURES .................................................................................................................... 111

APPENDIX ........................................................................................................................................................ 112

BIBLIOGRAPHY ................................................................................................................................................ 113


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LIST OF FIGURES

Figure 1.1: Shale gas offsets declines in other U.S. supply to meet consumption growth and lower import needs ____________ 13 Figure 1.2: 30% domestic gas production outpaces 16% consumption growth, leading to declining imports _______________ 15 Figure 1.3: Location of shale gas and shale oil plays in the US (Source: http://abhilashchalakuzhy.blogspot.com) ___________ 17 Figure 1.4: Technically recoverable shale oil in the US (EIA 2011) _______________________________________________ 17 Figure 1.5: Technically recoverable shale gas in the US (EIA 2011) ______________________________________________ 18 Figure 1.6: Location of the Marcellus Shale Play (EPA 2012) ___________________________________________________ 19 Figure 1.7: Schematic detailing the process of Hydraulic Fracturing (source: Shale Gas: Applying Technology to solve Americas Energy Challenges) (EPA 2011) _________________________________________________________________________ 21 Figure 3.1: Federal Regulation of Hydraulic Fracturing by the EPA _______________________________________________ 32 Figure 3.2: New York State Regulation of Hydraulic Fracturing by the DEC ________________________________________ 34 Figure 4.1 - Barnett Shale Mapped Fracture Treatments (Fisher). ________________________________________________ 35 Figure 4.2 - Marcellus Shale Mapped Fracture Treatments (Fisher). ______________________________________________ 36 Figure 4.3 – Scenarios For Seepage of Hydrocarbon Into Aquifer (EPA, 2012). ____________________________________ 37 Figure 5.1: Schematic detailing the fracture fluid composition in Fayetteville Shale (Arthur, Bohm et al. 2009) _____________ 43 Figure 5.2: Schematic detailing the fracture fluid composition in Marcellus Shale (NYSDEC 2011) _______________________ 43 Figure 5.3: Chemicals identified as carcinogens, possible carcinogens and hazardous air pollutants (EPA 2012) ____________ 46 Figure 5.4: Fracturing fluid composition inclusive of recycled flowback water (NY SGEIS) _____________________________ 49 Figure 5.5 – Disposal methods for Hydraulic fracturing wastewater - Source - (EPA 2012) ____________________________ 53 Figure 5.6 – Generalized flow diagram for treatment processes in a conventional POTW- (EPA 2012) ___________________ 54 Figure 5.7 – Maximum allowbale water quality requirements after onsite treamtent and prior to reuse (NYSDEC 2011) ______ 58 Figure 5.8– Comparison of Electrodialysis Reversal and Reserve Osmosis (NYSDEC 2011) ____________________________ 60 Figure 5.9 - Comparison of treatment options (NYSDEC 2011) _________________________________________________ 61 Figure 5.10 – Disinfection byproducts regulated by the National Primary Drinking water Regulations (EPA 2012) __________ 63 Figure 5.11 – Typical process arrangement to treat hydraulic fracturing flowback water. ______________________________ 66 Figure 5.12 – Cost for various hydraulic fracturing flowback water management options ______________________________ 67 Figure 6.1 – Proppant Application Rang (LaFollette 2010) ____________________________________________________ 69 Figure 6.2: Effect of Fracture Length and Conductivity on Reservoir Productivity (Gidley 1989) _________________________ 71 Figure 6.3– Effect of Depth on fracture conductivity as a function of proppant type (Gidley 1989) ______________________ 71 Figure 6.4 – Effect of Closure stress on Fracture conductivity for Various Proppant Types (Economides and Martin 2007) _____ 72 Figure 6.5: Effect of proppant size (sand) on fracture permeability (Gidley 1989) __________________________________ 72 Figure 6.5: Approximate Depth to the Marcellus Shale ________________________________________________________ 73 Figure 6.6 – Generalized procedure for proppant selection ____________________________________________________ 74 Figure 6.7 – Cumulative Gas Production as a Function of Fracture Conductivity _____________________________________ 75 Figure 6.8 – Cost per unit fracture area per unit of conductivity versus closure stress (Phillip and Anderson) _______________ 77 Figure 6.9 – Net Present Value vs. Fracture Length (after Britt and Veatch) ________________________________________ 77 Figure 6.10 – Incremental present worth vs fracture conductivit (Gidley 1989) _____________________________________ 78 Figure 6.11– Incremental present worth vs fracture half-length (Gidley 1989) ______________________________________ 78 Figure 7.1: Northern Pennsylvania Marcellus Drilling and New York State _________________________________________ 82 Figure 7.2: Hypothetical Reservoir Field Description __________________________________________________________ 83 Figure 7.3: Optimistic decline curve based on P20 initial production ______________________________________________ 86 Figure 7.4: Moderate decline curve based on P50 initial production ______________________________________________ 86 Figure 7.5: Conservative decline curve based on P80 initial production ___________________________________________ 87 Figure 7.6: Yearly shale gas production rate predicted by moderate decline curve ___________________________________ 87 Figure 7.7: Total proposed annual Shale Gas production ______________________________________________________ 88 Figure 7.8: Summary of Costs __________________________________________________________________________ 94 Figure 7.9: Seven-year MACRS Depreciation Schedule ________________________________________________________ 94 Figure 7.10: 2012 US Federal Income Tax Rate Schedule (Durman, 2012) ________________________________________ 97


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Figure 7.11: Baseline Cash Flow Model ___________________________________________________________________ 97 Figure 7.12: Cash Flow with Flowback Treatment Option 1 ___________________________________________________ 101 Figure 7.13: Cash Flow with Flowback Treatment Option 2 ___________________________________________________ 102 Figure 7.14: Cash Flow with Flowback Treatment Option 3 ___________________________________________________ 103 Figure 7.15: Cash Flow with Flowback Treatment Option 4 ___________________________________________________ 104 Figure 7.16: Comparison of Results of Cash Flow Analysis ____________________________________________________ 105 Figure 8.1 – Estimates of low and average rate of development scenarios. ________________________________________ 107 Figure 8.2 – Projected Total Employment in New York State From Each Development Scenario (NYSDEC 2011). __________ 109 Figure 8.3 – Projected Total Employment in New York State During Development (NYSDEC 2011). ____________________ 110


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Hydraulic Fracturing: The Up-State New York Debate F E A S I B I L I T Y O F E N V I R O N M E N T A L L Y S A F E S H A L E G A S P R O D U C T I O N I N U P S T A T E N E W Y O R K

EXECUTIVE SUMMARY

Natural gas is one of the main energy sources used in many aspects of everyday life worldwide.

This fossil fuel is cleaner burning and emits lower levels of harmful airborne emissions than other fossil fuel

types. The demand for energy from natural gas is unwavering; new sources for this ever important

resource must be discovered and capitalized on. Natural gas has historically been produced from

conventional deposits as these provided the easiest, most cost effective, and practical production options.

With new technology, unconventional gas sources, which may have been too costly or logistically

impossible to produce, have now become available. With the advent of horizontal drilling and hydraulic

fracturing, shale gas in particular has come to the forefront as an unconventional gas source, which could

largely impact both the United States and worldwide energy and gas markets. The future of shale gas in

the United States appears to be extremely promising when one considers the quantity of the deposits; it

is therefor clear that shale gas is an unconventional gas source that merits thorough discussion.

However, this seemingly ideal source of energy supply is not without its fair share of controversy.

New York is currently the battleground for the debate on hydraulic fracturing (the method by which shale

gas is extracted). Most agree that the debate in New York started in February 2008 when Chesapeake

and Fortuna/Talisman formally revealed their Marcellus shale intentions via public filing with the New

York State Department of Energy Conversation (DEC). In July of the same year, amidst public outcry over

the potential detrimental effects of hydraulic fracturing, the then governor (David Paterson) directed the

DEC to update the generic oil and gas environmental impact statement to reflect all current technologies

related to shale gas recovery. This directive ultimately halted all hydraulic fracturing, and by extension

shale gas recovery in the New York portion of the Marcellus Shale. Since this moratorium, two (2) draft

environmental impact statements have been issued by the DEC for public comment, Chesapeake Energy


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withdrew their application with the DEC, and the DEC, in November 2012, formally requested a 90 day

extension to their rule making process in regards to hydraulic fracturing. Five years has pass since the

moratorium, and the DEC is yet to make a formal decision on the issue of hydraulic fracturing in the New

York State. In the meantime approximately fifty (50) applications for permits to use hydraulic fracturing

to recover shale gas in the Marcellus shale are pending review in the offices of the DEC, and the debate

among New Yorkers rages on; the detractors of hydraulic fracturing are concerned with the potential

detrimental environmental impact, where as the proponents of the process are enticed by the positive

socio-economic impacts of shale gas recovery in New York State.

Some officials and many residents of New York believe that drilling gas wells, and using

hydraulic fracturing technologies will cause severe pollution to the air, water, and soil. However, both

industrial research, and engineering design show that following specific preventive procedures and safety

requirements while performing high volume hydraulic fracturing of gas wells in New York State would

significantly reduce the chances of environmental pollution, and permanent environmental damage. When

the flipside of the debate is considered, one cannot deny that the development of natural gas reservoirs

in Marcellus shale formations using high-volume hydraulic fracturing will have a positive socio-economic

impact on the upstate New York region, and New York State in general. Permitting high-volume hydraulic

fracturing would create thousands of job opportunities in up-state New York; both regional and state

economic activities would increase due to the expansion of secondary and tertiary suppliers to the natural

gas industry, and this will significantly increase the revenue stream to New York State as a result of both

direct and indirect payments to local and state governments.

In order to understand the New York Marcellus Shale debate from a regulatory standpoint, we

have investigated the major policy considerations surrounding gas prospecting activities at both Federal

and State level. At state level, the New York Department of Environmental Conservation (DEC) oversees

shale gas operations by means of an ongoing, so-far successful regulatory program. Federal regulation

of hydraulic fracturing by the EPA, on the other hand, is a more controversial issue. The EPA oversees

operations through the Safe Drinking Water Act (SDWA) Underground Injection Control (UIC) program,

and the Clean Water and Clean Air Acts. Parties opposed to hydraulic fracturing argue that it is

incompletely regulated through the SDWA UIC program, and the Emergency Planning and Community

Right to Know Act. The Fracturing Responsibility and Awareness of Chemicals (FRAC) Act has been


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proposed in Congress to enable more strict control of hydraulic fracturing activities at Federal level, and

has the potential to impact the cost of operations in the future.

In order to gain a comprehensive understanding of the issues being debated and the feasibility of safely producing shale gas in upstate New York, three major engineering assessments were conducted; these assessments and the respective objectives are outlined below:

1. Hydraulic Fracture Propagation & Threat to underground sources of drinking water

a. Determine the possibility/likelihood that either fracturing fluid, or the produced gas can contaminate underground sources of drinking water.

2. Flowback water treatment

a. Assess the capability of publicly owned water treatment plants to effectively treat flowback water.

b. Determine the processes required to effectively treat flowback water c. Determine the cost implication of effectively managing hydraulic fracturing flowback

water and the effect of this cost of the feasibility of producing shale gas in the Marcellus Shale in Up-State New York.

3. Proppant Selection

a. Assess the potential environmental impact of different proppants b. Assess the impact of different proppants on flowback water treatment requirement c. Determine categories of proppant that can effectively function in the Marcellus Shale in

Up-State New York.

Our research, as previously stated, found that it was highly unlikely for hydraulic fracturing

processes to contaminate underground sources of drinking water. From the standpoint of flowback water

treatment, our findings show that publicly owned water treatment plants (POTWs) are specifically

designed to treat sewer waste and are not effective in the treatment of hydraulic fracturing flowback

water. Two of the major issues in the inability of POTWS to treat flowback water are the high level of

bromide, which contribute to the formation of disinfection byproducts (DBPs), and the total dissolve solids,

which can reach levels as high as 200,000 ppm. The processes required to effectively treat flowback

water include physical separation, chemical precipitation, bioreactor and some form of advance

treatment (such as forward osmosis, reverse osmosis, ion-exchange, crystallization, electro-dialysis), which

must be selected based on the specific composition of the water to be treated. The four potentially most

effective methods of managing flowback water in Up-State New York include injection into class II wells,

mobile and stationary onsite treatment, and industrial wastewater treatment facilities. The cost for these


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options ranges from $0.045 per barrel to $2.00 per barrel not including the cost for transportation,

which ranges from $75 to $90 per hour.

The effect proppant has on the environment, and the impact they have on the required treatment

processes for flowback water was found to be negligible. Proppants are solid material that are

nonreactive and do not dissolve in the fracturing fluid; proppants are easily removed from fracturing

fluid flowback water by means of physical separation such as filtration, and chemical precipitation. The

ease of removal of proppant from flowback water is demonstrated by the fact the POWTs are capable

of removing the proppant, but these plants are ineffective in reducing the total dissolve solids (TDS) in the

flowback water. The most effective type of proppants for use in the Marcellus shale in Up-State New

York have been identified as frac sand and lightweight proppant for closure stresses lower than 4000 psi

and resin coated sand, ceramic and ISP for closure stresses between 4000 psi and 9000psi.

Finally, an economic analysis was conducted, which aimed to characterize the inflows and outflows

typically associated with shale gas production in the New York Marcellus Shale, in order to evaluate how

the additional cost of implementing less environmentally impactful production methods affect economic

viability of shale gas production. This process entailed defining a hypothetical field size, predicting the

rate of production of gas over a set time period and the price of gas during this time frame. A cash flow

analysis has been developed to characterize the costs experienced by this hypothetical filed, and to

estimate revenues from the production model; this approach allowed us to predict the net cash flow each

year during production. Using this framework, the effect of the additional cost of enhanced flowback

treatment options was evaluated. The results of this cash flow analysis suggest that implementing the

proposed flowback water treatment improvements would have a limited impact on the economic viability

of shale gas exploration in the New York Marcellus Shale.

When all the engineering assessment findings, and the outputs of the economic models are

considered, it can be stated that shale gas can be produced safely and profitably using the process of

massive hydraulic fracturing from the Marcellus shale in the upstate region of New York State without

fear of permanent environmental damage.


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CHAPTER 1 | INTRODUCTION

SECTION 1.1: UNCONVENTIONAL NATURAL GAS !

Natural gas is defined as a mixture of hydrocarbons, primarily methane, which can undergo

combustion in order to provide energy, energy which represents a staple of US and worldwide energy

consumption. In comparison to other fossil fuels namely oil and coal, natural gas can be considered to be

amongst the cleanest burning and environmentally safest energy sources to produce, releasing 23.9% of

the Carbon dioxide emissions, 14.2% of the carbon monoxide emissions, 9.2% of the nitrogen oxide

emissions, and less than a percent of sulfur dioxide and particulates emissions released in lbs per Billion

Btu of energy input produced according to reports by the Environmental Informational Administration

(EIA). As natural gas is a non-renewable fossil fuel the amount of natural gas resources can be quantified

to determine total gas resources, however this amount of gas may not be commercially recoverable for a

number of reasons. As technologies further develop and gas stores previously commercially unviable to

produce become available, these unconventional gas resources now become potential natural gas

reserves which could impact and redefine the US an global natural gas markets. Currently there are six

major forms of natural gas which may be characterized as unconventional; deep natural gas, tight gas,

coal-bed methane, geopressurized gas, methane hydrates and shale gas. These unconventional sources

vary in regards to the amount of focus being devoted to each in terms of their respective current

production and future developmental outlook. While the technology is available to cost effectively

produce some of these gas sources there is still yet a ways to go in developing the means with which to

fully produce, transport or even utilize others. (Naturalgas.org, 2011)

1.1.1 Deep Gas

While conventional natural gas deposits are found at all different geologic depths and

stratigraphic locations the majority of conventional deposits are found at depths no deeper than 10,000


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feet underground. Deep gas then represents an unconventional source in that it exists at depths of

15,000 feet and greater which poses various technical problems. Not enough pertinent drilling

information exists on the geologic environments found at such great depths. At depths this great hostile

drilling environments are encountered including but not limited to high temperatures and acidic gas

compositions. These deep wells often require advanced initial well stimulation and well completion

procedures in order to produce adding to the costs of production. While the cost of average well

completion is estimated at $160,000 for wells drilled up to 5,000 feet and $579,000 for wells drilled

between 5,000 and 10,000 feet, the cost for wells drilled at the depths greater than 15,000 feet the

average cost is $5,373,000, almost ten times greater than the average cost of a conventional well (T. S.

Dyman, 2003).

1.1.2 Tight Gas

Tight natural gas is sometimes lumped together with shale gas and named tight shale gas leading

to some confusion however the two do represent different unconventional gas stores. Tight gas refers to

natural gas reservoirs trapped in extremely low permeability geographical locations making production

without any form of stimulation economically unfeasible, often sandstone and limestone plays. While

conventional gas reservoirs exhibit permeability’s as low as .01 darcy, tight gas reservoirs can display

permeability values in the range of milidarcy and even nanodarcy (Naturalgas.org, 2011). As of 2009

tight gas represented a significant portion of the US dry gas consumption 28% which could be viewed

largely as a result of early federal incentives and tax credits which made this gas source attractive to

produce. Incentives for tight gas are heavily dependent on the current and projected gas market prices

and thus tight gas can be projected to take a production decline as predicted by the EIA. (Energy

Information Administration, 1993)

1.1.3 Coal Bed Methane

Coal bed methanes utilize the current production of another fossil fuel by accessing the natural

methane stored within coalbed seams underground. The natural gas may be stored in the coal seams


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themselves or within the rock layers which surround the coal deposits and is released during commercial

coal mine production. A significant amount of coal associated methane is estimated to exist in the United

States with the Potential Gas Committee estimating almost 163 Tcf of technically recoverable resources

available, 7.8% of the recoverable United States gas reserves. This methane gas previously posed both

health and technical risks when released in the coal mines and was thus vented into the atmosphere

however it is now possible to extract and inject the free gas into natural gas pipelines for commercial

sale and use (Naturalgas.org, 2011).

1.1.4 Geo Pressurized Zones

Geo pressurized zones can best be described as natural gas deposits located in areas under

unusually high pressures for the geologic depth. Natural gas in these deposits is found trapped in a sand

or silt layer due to the compression of a clay layer underneath, from which the gas migrated. The rapid

clay compaction leaves this gas under extreme pressures making this gas source unpredictable and quite

dangerous to produce with current drilling technology. It is estimated that the 1,110 Tcf of technically

recoverable gas this gas source holds represents the greatest potential amount of technically recoverable

natural gas besides that of methane hydrates. Although there is the technology available to tap into this

vast gas resource there are no viable production options or techniques to date which make this gas source

commercially feasible to produce. (Teledyne Isco, 2011)

1.1.5 Methane Hydrates/ Clathrates

Methane hydrates stand the most newly discovered and thus underdeveloped of the

unconventional gas sources however this potential gas source boasts the greatest possible potential in

terms of estimated natural gas resources with estimates ranging between 7,000 Tcf and over 73,000

Tcf. These methane hydrates are formed as water freezes around methane molecules forming a

crystalline lattice structure which traps the methane within it. This unconventional source is as of yet still in

its infant stages and further research must be done in order to better understand the structure and


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properties of these hydrates before any effort can be put towards developing ways of producing and

marketing the natural gas trapped within the hydrates (Naturalgas.org, 2011).

1.1.6 Shale Gas

Tight gas shales currently represent the greatest potentially economically profitable form of

unconventional gas recovery and could in future years change the way the US as well as global markets

view natural gas consumption and export. Shale gas comprises the stores of natural gas confined within

shale formations. Due to the very low permeability of shale it was previously economically unfeasible to

attempt to produce from these formations. With the advent of better technologies in the areas integral to

shale gas formation production, namely hydraulic fracturing in conjunction with horizontal drilling,

previously untapped stores of natural gas have suddenly become economically available for production.

(Naturalgas.org, 2011)


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SECTION 1.2 – SHALE GAS OUTLOOK

Since major shale gas production took off in the 1980’s in the Barnett shale play its consumption

has steadily increased with each passing year in the United States.

Figure 1.1: Shale gas offsets declines in other U.S. supply to meet consumption growth and lower import needs

According to Figure 1.1, EIA projections from the 2011 Annual Energy Outlook, shale gas is

expected to increase from the 14% of U.S. dry gas consumption per year it represented in 2009 up to

45% in the year 2035 (U.S. Energy Information Administration, 2011). This represents a nearly 300%

increase, an increase which comes at the expense of all other gas sources but largely at the expense of

U.S. gas imports. (Teledyne Isco, 2011)


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SECTION 1.3: ESTIMATED WORLDWIDE GAS QUANTITIES

The potential for shale gas to impact the global gas market looms large with the possibility of

shifting the ranks of those traditionally considered to be global gas giants in terms of gas exports. In the

Energy Information Administration’s (EIA) 2011 revised World report on world shale gas resources.

Almost 61% of conventional natural gas reserves are located in the Middle East and Eurasia while only

4% or nearly 283 trillion cubic feet are found in the United States. In contrast when one factors in

technically recoverable unconventional gas sources North America is found to have the largest amount of

gas reserves [Teledyne Isco 2011]. In terms of shale gas alone North America currently holds almost 29%

of the technically recoverable world shale gas reserves with the US itself holding 13% of the world

reserves by itself or an estimated 862 Tcf of shale gas. The United States 862 Tcf of shale gas is over

300% of its proved conventional dry gas quantities according to the EIA report emphasizing the greater

importance shale gas will play in the near future as conventional resources continue to be depleted. (U.S.

Energy Information Administration, 2011)

Countries who previously found themselves dependent to whatever degree on foreign gas

imports sit on recoverable stores of domestic unconventional gas reserves which could decrease their

dependence on foreign gas imports and even potentially turn them into gas exporters. The United States

with its gas transport methods and necessary infrastructure in place to handle natural gas liquefaction

stands to gain a strong foothold in the global natural gas market, further bolstering the national

economy. This economic potential can be evidenced by Figure 1.2 , the EIA projected decline of the

percent of US natural gas consumption US foreign gas imports from 11% as of 2009 to 1% by the year

2035 (U.S. Energy Information Administration, 2011).


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Figure 1.2: 30% domestic gas production outpaces 16% consumption growth, leading to declining imports


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SECTION 1.4: !SHALE GAS IN THE UNITED STATES !

1.4.1 The United Sates Shale Gas Deposits

The United States Shale Gas and shale oil deposits can be subdivided into six (6) major areas; the

areas include the Northeast, Gulf Coast, Mid-Continent, Southwest, Rocky Mountain, and West Coast

Region. Combined, these areas are home to approximately twenty-three (23) shale gas and shale oil

plays. The names and locations of these plays are as outlined below (EIA 2011) and the geographic

locations are as shown in Figure 1.3:

1. The Northeast Region includes the Marcellus, Devonian Big Sandy, Devonian Low Thermal

Maturity, Devonian Greater Siltstone, New Albany and the Antrim shale gas plays.

2. The Gulf Coast Region includes the Haynesville, Eagle Ford and the Floyd- Neal/Conasauga

shale gas and shale oil plays.

3. The Mid-Continent Region includes the Fayetteville, Woodford and the Cana Woodford shale

gas plays.

4. The Southwest Region includes the Barnett, Barnett-Woodford, and the Avalon and Bone Springs


5. The Rocky Mountain Region includes the Hilliard-Baxter-Mancos, Lewis, Mancos and the Bakken


6. The West Coast Region includes the Monterey/Santos shale oil play.

These deposits have a combined total of 750 Tcf of technically recoverable shale gas and 23 Billion

bbl of shale oil; total conventional recoverable gas and oil in the US are in the region of 272.5 Tcf gas

and 26 billion bbl of oil. These figures show that the recoverable shale gas in the country dwarfs

conventional gas resources in the United States. Recoverable shale gas and shale oil by shale gas basin is

outlined in Figures 1.4 and 1.5.


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Figure 1.3: Location of shale gas and shale oil plays in the US (Source: http://abhilashchalakuzhy.blogspot.com)

!

!Figure 1.4: Technically recoverable shale oil in the US (EIA 2011)

Review of Emerging U.S. Shale Gas and Shale Oil Plays x

Shale Oil In addition to the gas produced in the shale plays, condensate and plant liquids may also be produced. Four shale oil plays were also identified and reviewed during this analysis. As seen in the following Table, the majority of these resources are located in the Monterey/Santos shales currently under development by OXY. The technically recoverable resource for these four plays is approximately 24 Billion barrels of oil (BBO) across nearly 13,000 square miles. The average EUR for the plays is approximately 460 thousand barrels of oil (MBO).

Table ii U.S. Technically Recoverable Shale Oil Resources Summary

Play

Technically Recoverable

Resource Area (sq. miles)

Average EUR

Gas (Tcf)

Oil (BBO)

Leased Unleased Gas (Bcf/ well)

Oil (MBO/ well)

Eagle Ford … 3.35 3,323 … 300 Total Gulf Coast … 3.35 3,323 … 300 Avalon & Bone Springs … 1.58 1,313 … 300 Total Southwest … 1.58 1,313 … 300 Bakken … 3.59 6,522 … 550 Total Rocky Mountain … 3.59 6,522 … 550 Monterey/Santos … 15.42 1,752 … 550 Total West Coast … 15.42 1,752 … 550 Total Lower 48 U.S. … 23.94 12,910 … 460

References 1. Department of Energy, Energy Information Administration. Annual Energy Outlook

2010. April 2010. 2. Department of Energy, Energy Information Administration. Modified by INTEK Inc. 3. Congressional Research Services. Unconventional Gas Shales: Development,

Technology, and Policy Issues. October 2009. 4. NRG & Associates and HPDI Data.

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Figure 1.5: Technically recoverable shale gas in the US (EIA 2011)

Review of Emerging U.S. Shale Gas and Shale Oil Plays viii

unproved discovered technically recoverable resources (TRR) is provided in the following Table.

Table i U.S. Shale Gas Unproved Discovered Technically Recoverable Resources Summary

Play

Technically Recoverable

Resource Area (sq. miles)

Average EUR

Gas (Tcf)

Oil (BBO)

Leased Unleased Gas (Bcf/ well)

Oil (MBO/ well)

Marcellus 410.34 … 10,622 84,271 1.18 … Big Sandy 7.40 … 8,675 1,994 0.33 … Low Thermal Maturity 13.53 … 45,844 0.30 … Greater Siltstone 8.46 … 22,914 0.19 … New Albany 10.95 … 1,600 41,900 1.10 … Antrim 19.93 … 12,000 0.28 … Cincinnati Arch* 1.44 ... NA 0.12 ... Total Northeast 472.05 … 101,655 128,272 0.74 … Haynesville 74.71 … 3,574 5,426 3.57 … Eagle Ford 20.81 … 1,090 5.00 … Floyd-Neal & Conasauga 4.37 … 2,429 0.90 … Total Gulf Coast 99.99 … 7,093 5,426 2.99 … Fayetteville 31.96 … 9,000 2.07 … Woodford 22.21 … 4,700 2.98 … Cana Woodford 5.72 … 688 5.20 … Total Mid-Continent 59.88 … 14,388 2.45 … Barnett 43.38 … 4,075 2,383 1.42 … Barnett Woodford 32.15 … 2,691 3.07 … Total Southwest 75.52 … 6,766 2,383 1.85 … Hilliard-Baxter-Mancos 3.77 … 16,416 0.18 … Lewis 11.63 … 7,506 1.30 … Williston-Shallow Niobraran* 6.61 … NA 0.45 … Mancos 21.02 … 6,589 1.00 … Total Rocky Mountain 43.03 … 30,511 0.69 … Total Lower 48 U.S. 750.38 … 160,413 136,081 1.02 …

*Cincinnati Arch and Williston-Shallow Niobraran were not assessed in this report.

The 750 trillion cubic feet of shale gas resources in the INTEK shale report is a subset of the AEO2011 onshore lower 48 natural gas shale resource estimate of 862 trillion cubic feet. The AEO2011 includes 35 trillion cubic feet of “proved reserves” reported to the Securities and Exchange Commission (SEC) and the EIA1, 20 trillion cubic feet of inferred reserves not 1 Additional information and comparisons of the SEC and EIA reserves can be found in the EIA report “U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves, 2009”

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1.4.2 Marcellus shale Gas Play

The Marcellus shale play is located in the Appalachian Basin across the Eastern Part of the United

States. It covers an area of approximately 95,000 square miles and intersects the states of New York,

Pennsylvania, Maryland, Ohio, Virginia and West Virginia; refer to Figure 1.6. Of the six (6) states,

beneath which this shale deposits lies, Pennsylvania has claim to the largest section (35.35 %), followed

by West Virginia (21.33 %), then New York (20.06 %).

!

!!

Figure 1.6: Location of the Marcellus Shale Play (EPA 2012)

!

Figure 4 shows that the Marcellus shale gas deposits accounts for 410 Tcf or 55% of the total

750 Tcf of technically recoverable shale gas in the United States. The Marcellus shale was first produced

in 2006; today the shale deposit produces approximately 4 BCF/D of gas or 6% of the United States

total daily natural gas production. At todays gas price of approximately $4/MScf, gas production can

represent a significant portion of any state revenue stream. The proponents of shale gas recovery in

New York State are driven by the fact that New York has claim to approximately 21% of the Marcellus

Figure 32. Extent of the Marcellus Shale, which underlies large portions of New York, Ohio, Pennsylvania, and West Virginia ( The case study focuses on reported changes in drinking water quality in Bradford County, Pennsylvania, with a few water samples taken in neighboring Susquehanna County.

US EIA, 2011d; USCB, 2012a, c).

Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report December 2012

7.4. Bradford County, Pennsylvania

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much of New York, Pennsylvania, Ohio, and West Virginia. Recently, natural gas drilling in thhre ough

Marcellus Shale has increased significantly in northeastern Pennsylvania, including Bradford County.

142


Page 20

Shale deposits, and this claim has enormous potential economic benefits in the form of jobs, tax revenues,

and improved services. However to recover this gas, hydraulic fracturing must be employed. Detractors

of the technology are staunchly against this process and by extension gas recovery in the New York State

section of the Marcellus shale because they believe hydraulic fracturing has the potential to pollute the

underground sources of drinking water. Herein then lies the bases of the Shale gas debate in New York

State.

Some will argue that the New York State shale gas debate began in February 2008 when the

New York State Department of Environmental Conservation (DEC) received the first applications for shale

gas extraction from the New York portion of the Marcellus Shale formation. Others argue that the

debate actually commenced on July 23, 2008, when then New York Governor David Paterson directed

the DEC to update the oil and gas environmental impact statement to reflect all new technologies

involved in the controversial practice of high-volume hydraulic fracturing, also referred to as fracking.

Whichever side of this argument anyone chooses to support, it is undeniable that the debate is about the

process of hydraulic fracturing and it’s potential adverse effects on the environment.


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SECTION 1.5 – HYDRAULIC FRACTURING & THE NEW YORK STATE SHALE GAS DEBATE

1.5.1 Hydraulic Fracturing

Traditional oil bearing formations typically possess small connected passageways in the rock

formation that allow the relatively easy movement on oil and gas from the rock pores to the wellbore;

this movement is achieved by creating a pressure difference between the wellbore and the hydrocarbon

bearing formation. The formation rock ability to transmit fluid is referred to as the rock or the formation

permeability; the easier it is for the rock to transmit fluid the higher rock permeability.

Unfortunately, there are hydrocarbon bearing formations, such as the Marcellus Shale, whose

permeability is too low to allow the natural movement of hydrocarbon fluids from the reservoir rock to

the wellbore. Hydraulic fracturing is a process by which the reservoir rock permeability is artificially

increase to allow the flow of reservoir fluids from deep in the rock formation to the well bore. The

process of hydraulic fracturing therefore allows the production of oil and gas from rock formations, which

could not be produced by conventional means.

!Figure 1.7: Schematic detailing the process of Hydraulic Fracturing (source: Shale Gas: Applying Technology to solve Americas Energy Challenges) (EPA 2011)


Page 22

The size of a hydraulic fracture project may vary widely by but typically involves the injection of

between 10,000 to 60,000 barrels (0.5 to 3 million gallons) of high pressure water mixed with chemicals

and proppants to create fractures in the gas or oil bearing formation. The created fractures then become

the pathway by which the gas or oil flow to the wellbore and is extracted. Hydraulic fracturing my take

place in several stages but the basic objective of the operation remains the same. The process is used to

create fractures in the formation and allow the hydrocarbons to flow; the proppants is used to keep these

fractures open and the chemicals, though they may serve several purpose, one of the most important is to

reduce friction thereby improving fluid flow through the reservoir rock. Figure 7 above provides an

illustration of this process.

1.5.2 The History of the New York State Shale Gas Debate - Events that shaped the Debate

The first recorded hydraulic fracturing recorded in the United States history was in 1903 at which

time the process was used for granite mining. Hydraulic fracturing was later used for commercial oil and

gas extraction in the 1940s; the first recorded hydraulic fracture of this nature was recorded in 1949.

Strikingly, prior to 1997 there existed no regulations in the United States and control hydraulic fracturing

in any context, whether for granite mining or commercial oil and gas extraction.

Prior to 1997, the EPA had considered hydraulic fracturing a well stimulation technique used for

hydrocarbon production. This definition of the hydraulic fracturing therefore excluded this activity from

the regulations stipulated by the Underground Injection Control program (UIC). The UIC is a subsidiary of

the Environmental Protection agency (EPA) and is one of the action arms of the safe drinking water act

(SDWA); the program is charge with the responsibility of regulating the construction and operation of

injection wells in an attempt to prevent ground water contamination.

In 1994, the legal Environmental assistance foundation (LEAF) challenged the EPA’s position or

rather their definition of hydraulic fracturing by stating that the process involves the injection of foreign

substances underground and should therefore be subject to the SDWA, and the regulation of the UIC.

Three years later, in 1997, the 11th Circuit Court of Appeal ruled in favor of LEAF; hydraulic fracturing of

coalbed methane wells was from then onwards subject to the SDWA and the UIC program. This, it can be


Page 23

said, was the beginning of the hoopla surround hydraulic fracturing, ground water contamination, and

environmental control.

Following the circuit court ruling on hydraulic fracturing, the EPA instructed that research be

undertaken to investigate the potential of water contamination due to hydraulic fracturing in coalbed

methane reservoirs. The research commenced in 1999 and the final report entitled “Evaluation of Impacts

to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs Study

“ was published in 2004. In this report, the EPA explicitly stated there was little to no risk of fracturing

fluid contaminating underground sources of drinking water during hydraulic fracturing of coalbed

methane production wells. This statement can be taken as the EPAs first official position on the potential

impact hydraulic fracturing may have on underground sources of drinking water. The statement is even

more striking when we compare the distance between coalbed methane reservoir and underground

sources of drinking water (USDW) with the distance between conventional and unconventional natural gas

reservoir and UGSDs; coalbed methane reservoir are much closer to the surface and are in closer

proximity to UGSDs than are conventional and unconventional gas reservoirs. The question can therefore

be put forward: If coalbed methane reservoirs are much closer to USDWs than are conventional and

unconventional gas reservoirs, and hydraulic fracturing in coalbed methane poses little to no risk of

contaminating USDWs, what is then the likelihood that hydraulic fracturing of unconventional gas reservoirs

contamination underground sources of drinking water (USDWs).

In 2005, the Energy Policy ACT amended the Safe Drinking Water Act (SDWA) definition of

“Underground injection” to exclude the injection of fluids or propping agents other than diesel fuels, in

hydraulic fracturing activities. This, it can be said, is a solidification of the EPAs position on the potential

risk of hydraulic fracturing, and further emphasizes the EPA belief that the threat hydraulic fracturing

operations poses to USDWs is negligible. Three years later, in February 2008, the New York state

debate on hydraulic fracturing was born; in February 2008 the New York Department of Environmental

Control (DEC) received the first set of public filing for permission to produce natural gas from the New

York State Section of the Marcellus Shale. Chesapeake and Fortuna/Talisman were the first two

companies to express formally via public filings to the DEC, their intention to produce natural gas from

the New York state section of the Marcellus shale.

In July 2008, we see for the first time, federal regulations and the shale gas production in New

York meeting head-on. On July 21, 2008 the shale gas well spacing regulation came into effect. One


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day later on July 22, ProPublica published the first newspaper article staunchly against shale gas

production in New York State; the article was entitled “New York's Gas Rush Poses Environmental Threat”.

One after the article was published and during the signing of the new shale well spacing bill, David

Paterson, then Governor of New York State, called for a review of the potential impact shale gas

recovery may have on the environment. He directed the DEC to update the generic oil and gas

environmental impact statement; this review was intended to thoroughly cover and capture all the new

technologies involved in high-volume hydraulic fracturing within shale gas reservoir rocks.

Since July 22, 2008 there has been a moratorium on drilling, and by extension, hydraulic

fracturing in the New York State section of the Marcellus Shale to recover gas. Meanwhile, joint bills

introduced in the house and senate in June 2009, are being discussed and pending vote. If these Bills are

approved, they will repeal the exemption granted to hydraulic fracturing operations and will require oil

and gas companies to disclose the chemicals used in these operations.

1.5.3 Current status of the Shale Gas Debate in New York State!

Since July 2008, after the directive given by Governor David Paterson, the New York

Department of Environmental Conservation (DEC) has published two drafts of the Supplemental Generic

Environmental Impact Statement (SGEIS) for potential natural gas drilling activities in the Marcellus Shale;

the first draft was issued on September 30th, 2009. The Draft SGEIS supplements the existing Generic

Environmental Impact Statement (GEIS) and analyzes the range of potential impacts of shale gas

development using horizontal drilling and high-volume hydraulic fracturing. It outlines safety measures,

protection standards and mitigation strategies that operators would have to follow to obtain permits.

Noticeable, one month after this draft report was published, Chesapeake Energy Corporation

issued a news release (October 28, 2009) in which they announced their decision to cancel their plans to

pursue shale gas recovery in the New York State Marcellus Shale; the company cited concerns raised in

the draft SGEIS about drilling in the watershed area as the reason for their decision.

The second draft Supplemental Generic Environmental Impact Statement (SGEIS) was issued on

September 11, 2011; the revised documents addressed concerns and incorporated appropriate


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additions suggested in public comments on the first draft. The second draft document, prior the closure of

the public comment period, received in excess of 66,000 public comments.

In November 2012, after approaching the one-year deadline outlined under Section 202 of the

State Administrative Procedures Act (“SAPA”), the DEC submitted a request to the New York Department

of State (DOS) for a 90-day extension on its rule making process for its proposed regulation that will

govern natural gas recovery via high-volume hydraulic fracturing. Sec 202 of the SAPA allows the DEC

one year from the date of the last public hearing to adopt the proposed rules in regards to natural gas

recovery viz a vie hydraulic fracturing after which time the rule making process expires. To avoid this

situation and keep the rule making process valid, the DEC submitted a notice of revised rule making to

the New York DOS stating the process had to be delayed due to the ongoing New York State

Department of Health (DOH) review of the of the health impacts of the proposed regulations. The request

for revised rule making requires the DEC to hold another public comment period on the revised rules; the

comment period commenced on December 12, 2012 and closed on January 11, 2013. In addition, SAPA

requires the DEC to submit an assessment of all public comments received on the revised proposed rule

and an analysis of the issues highlighted by the comments, and significant alternatives that may have

been suggested. If there are regulatory changes from the DOH for which substantial revision to the

DSGEIS is required, the DEC will have to issue another notice of revised ruling making and therefore host

another comments period. Such a situation will undoubtedly further extend the final regulations into 2013.

The New York State Shale gas debate has again peeked the Federal government interest in the

impact hydraulic fracturing may have on the environment. The acting Under Secretary of Energy, Arun

Majumdar, on April 13, 2012, directed the Department of Energy (DOE), Department of the Interior

(DOI) and the Environmental Protection Agency (EPA) to develop “A multi-agency program directed toward

a focused collaborative Federal interagency effort to address the highest priority challenges associated with

safely and prudently developing unconventional shale gas and tight oil resources”. In addition the EPA is

also undertaking a national study to understand the potential impact of fracturing on drinking water

resources. The first progress report was released in December 2012; the final draft report for peer

review and comment is expected in 2014. These are just two examples, which highlight the Federal

government focus on the topic hydraulic fracturing; this renewed focused, some have suggested, is due to

the massive public feedback on New York drafts Supplemental Generic Environmental Impact Statement

(SGEIS).


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Finally, four (4) years into the moratorium on shale gas production in New York, neither side of

the shale gas debate is closer to knowing who will prevail in the end. It is now left to be seen whether the

proponents of tax revenues and jobs from shale gas production will prevail or the critics of hydraulic

fracturing, and supporters of environmental protection will be the victors. Whatever position the DEC

takes in the end, one can only hope it is not influenced by the utterings of either side but is based on

sound research and scientific data. Nonetheless, for completeness, the current state of the shale gas

debate can be summarized as follows:

• The refiled rule does not reflect current DEC policy with respect to whether or not hydraulic

fracturing can be done safely in New York. That determination will be based on the findings of

the environmental impact statement and the DOH review of that document.

• The DEC will not take any final action or make any decision regarding hydraulic fracturing until

after Dr. Shah's (commissioner of New York state DOH) health review is completed and the DEC,

through the environmental impact statement, is satisfied that this activity can be done safely in

New York State.

• If DEC decides that hydraulic fracturing cannot be safely done in New York, these regulations will

not have any practical effect and the process will not go forward. If DEC decides that the process

can be done safely, these regulations would be adjusted in accordance with the health and safety

requirements and issues addressed in the Supplemental Generic Environmental Impact Statement.

• Currently there are approximately fifty(50) applications pending review and approval for shale

gas recovery in the New York State section of the Marcellus shale play.


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CHAPTER 2 | ENVIRONMENTAL CONCERNS OF HYDRAULIC FRACTURING

The major concerns in New York State in regards with hydraulic fracturing process are its

environmental impact. Officials and residents of New York think drilling gas wells and using hydraulic

fracturing technologies would have severe damage on natural elements such as air, water, and soil.

Recent debates and discussions in the Northeastern state were focused on the threats imposed by drilling

and high volume hydraulic fracturing on the safety of the water resources available. Residents are

concerned about depletion of surface or underground water sources due the high volumes needed to

perform a hydraulic fracture in a gas well. In addition, the public think that high volume hydraulic

fracturing would lead to water contamination due to seepage of methane gas and fracturing fluids to

underground fresh water aquifers or due to improper treatment and disposal of flow back fracture fluid.

Both industrial research and engineering design show that following specific preventive procedures and

safety requirements while performing high volume hydraulic fracturing of gas wells in New York State

would prevent any environmental damages from happening.

!

2.1 WATER REQUIREMENT

High volume hydraulic fracturing treatments require large amount of water to be performed. The

water needs to be source in an environment friendly and cost effective way. Two to four millions of

gallons of water are required for a single fracture treatment in shale gas reservoirs to initiate gas

production (Cooly and Donnelly, 2012). It is very important to protect the water quality and quantity

from water sources that are used for hydraulic fracturing treatments. The sources of water for such

treatments vary between surface and subsurface water bodies such as rivers, lakes, private and

municipal water supplies, and ground water aquifers. The key factor in supplying water for high volume

hydraulic fracturing treatment is supply rate. Withdraw of water from its source should be done at rates

that does not disturb the quantity or the quality of water in that source. In addition, to natural sources,

flow backwater from a fracture treatment can be reused in future job after proper recycling process.


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Current recycling technology enable reuse of 80% of flow back water which forms 20-25% of a new

fracture treatment water requirement (Smith, 2012). Reusing flow back water mitigate the environmental

effect resulting from withdrawing water from its natural source and air emission resulting from

transporting water to wellhead location.

! !

2.2 WATER CONTAMINATION

The highest concern against high volume hydraulic fracturing is drinking water contamination.

Number of people around the United States has claimed that a hydraulic fracturing treatment of a

horizontal gas well would extend to an underground water aquifer causing fracturing fluid or

hydrocarbons to mix it leading to contamination of fresh drinking water. However, analysis of the

geological nature of the shale gas fields across the United states show that the pay zones or the reservoir

rock that holds the hydrocarbon gas are situated at very low zones in depths as compared to

underground water aquifers. Underground water aquifers in Marcellus shale area are typically located

less than 1000 ft deep from earth’s surface. Meanwhile, the reservoir rock of shale gas is sitting at depth

range between 4000 ft to 8500 ft. A fracture created by a fracturing treatment extends vertically for

several hundred feet only which is significantly far from reaching an underground fresh water aquifer

(Smith, 2012).

2.3 FLOW BACK WATER MANAGEMENT

! !After the completion of a hydraulic fracturing treatment of a gas a well and putting the well on

production again, some of the fracturing fluid along with naturally occurring water in the shale reservoir

flows back to surface. Quantities of flowback water depend on the characteristics of the shale formation

that was treated and on the properties of the fracturing fluid itself. Often, the flowback water has very

high levels of TDS (total dissolved solids) up to three times the amount in sea water. The total dissolved

solids are formed from naturally occurring material from the shale reservoirs such as radioactive

materials, metals and salts. Therefore, the recovered fracture fluid should be disposed in environmentally

safe methods to prevent surface water contamination. The fracturing fluid could be injected in a disposal


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well, treated in private or municipal water treatment plants, or even used for another hydraulic fracturing

treatment.

The primary method for disposing flow back water is to be injected in designated water disposal

wells that are designed for injecting water mixed with oil/gas production wastes which eliminate the

need to treat the water and prevent surface water contamination. Flow back water could also be

treated and recycled in municipal or private wastewater treatment plants. However, due to the high

content of total dissolved solids in water, most plants cannot remove the hazardous wastes efficiently.

Therefore, the new regulations passed in 2010 restrict the monthly discharge rates of treated water into

a natural water body to prevent contamination (Cooly and Donnelly). Finally, onsite recycling and

treatment of flowback water allows reusing around 80% of it forming 20-25% of the water requirement

another fracturing treatment (Smith).

Adopting industry standards and following sound engineering practices can mitigate the

environmental effect of high volume hydraulic fracturing in Marcellus shale in New York State. The

combination of engineering design and correct measurements would lead to a safer operation and a

cleaner environment which encourage the progress into developing such attractive energy source.

!


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CHAPTER 3 | POLICY CONSIDERATIONS FOR HYDRAULIC FRACTURING

The regulation of hydraulic fracturing plays a pivotal role in shale gas prospecting in the New

York Marcellus Shale. The effectiveness of the present regulation framework in protecting the environment

and holding involved parties accountable, has divided opinions in the ensuing debate. This section

presents the national and state-level policy and regulation landscape of the practice, as they pertain to

the New York Marcellus Shale debate, in both current and future contexts.

3.1 FEDERAL REGULATION OF HYDRAULIC FRACTURING

At the federal level, the U.S. Environmental Protection Agency (EPA) is the most important

regulatory body for hydrofracking, and consequently most interwoven in the New York debate. The EPA

administers laws either directly or by delegating authority to the states. Other federal entities with

varying degrees of influence on natural gas prospecting and operations include the Bureau of Land

Management of the Department of the Interior and the U.S. Forest Service of the U.S. Department of

Agriculture (Independent Oil and Gas Association of New York).

Federal regulation of hydrofracking by the EPA is carried out under a set of policies. Firstly,

under the Safe Water Drinking Act (SWDA) Underground Injection Control (UIC) program, requirements

are spelled out for proper well siting, construction and operation in order to minimize the risk to

underground drinking water. The SDWA was passed by the US Congress in 1974. These regulation

measures cover the case where diesel fuels are used as additives in the hydrofracking process. (United

States Environmental Protection Agency, 2012).

Secondly, the EPA regulates wastewater discharges to the treatment facilities under the Clean

Water Act (CWA) (1972) effluent guidelines program, which sets national standards for industrial

wastewater discharges, based on economically feasible best available technologies. On-site discharge of

water from shale gas extraction into U.S. waters is prohibited. The EPA also imposes requirements for


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reporting impaired waters. The EPA is currently developing a set of standards under the CWA, to be

finalized in 2014. These include standards for wastewater discharges produced from shale natural gas

extraction and chloride water quality criteria to protect aquatic life (United States Environmental

Protection Agency, 2012).

Thirdly, the EPA administers the Clean Air Act (1990) regulations for the oil and gas industry to

address air quality impacts associated with hydraulic fracturing. Some of these impacts include emissions

of methane, volatile organic compounds and hazardous air pollutants. The EPA has promoted the Natural

Gas STAR and Clean Construction USA programs to foster technologies and practices congruent with air

quality impact minimization (United States Environmental Protection Agency, 2012). Figure 3.1

summarizes federal regulation of hydraulic fracturing by the EPA

The EPA is currently undertaking a congressionally recommended study of hydraulic fracturing

and its potential impact on drinking water resources. A progress report was released in 2012, pending a

final draft report in 2014 for peer review and commentary (United States Environmental Protection

Agency, 2013). The results of this study have the potential shape the future landscape of federal

hydrofracking operations and regulation.

Parties opposed to hydraulic fracturing in New York have leveled criticism against the federal

regulation of hydraulic fracturing by the EPA, claiming an insufficient degree of control over

hydrofracking operations, relative to comparable industries (Spence, 2011). This notion is predicated on

two key regulatory issues. Firstly, the Energy Policy Act (2005) exempted hydraulic fracturing from

regulation under the UIC program except in the case of diesel fuel usage in additives. The Act amended

the definition of the SDWA’s UIC to exclude “the underground injection of fluids or propping agents

(other than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal

production activities” (Arthur, Hochheiser, & Coughlin, 2011). Secondly, hydrofracking is not covered

under the Emergency Planning and Community Right to Know Act, which requires annual reporting of toxic

chemical usage in industrial operations (Spence, 2011).


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Figure 3.1: Federal Regulation of Hydraulic Fracturing by the EPA

In attempt to alleviate these concerns, the Fracturing Responsibility and Awareness of Chemicals

(FRAC) Act was introduced by Congress in 2009. This act would amend the SDWA to include regulation

of hydrofracking under the UIC and require disclosure of chemical additives in hydrofracking operations.

The Act has yet to be passed, because undecided members of Congress are believed to be awaiting the

results of the aforementioned EPA study on hydrofracking (Spence, 2011). Needless to say, this Act would

have a telling impact on the federal hydrofraking regulatory framework. If implemented, industry

research projects a potential addition of approximately $100,000 to the cost of each new well, in

compliance with the FRAC Act (Arthur, Hochheiser, & Coughlin, 2011).

Federal Regulation (EPA)

Safe Drinking Water Act (SDWA) Underground Injection Control (UIC)

program (1974)

Sets requirements for proper well siting, construction and

operation (in the case of diesel fuel usage)

Clean Water Act (1972)

Regulates discharge of pollutants into U.S. waters and quality standards for

surface waters

Prohibits on-site discharge of water from shale gas

extraction into U.S. waters

Requires reporting of impaired waters, as described by quality

standards

Clean Air Act (1990)

Prescribes standards for oil and natural gas

production regarding gas emissions and greenhouse

gas reporting


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3.2 NEW YORK STATE REGULATION OF HYDRAULIC FRACTURING

Regulation of hydraulic fracturing in New York Marcellus Shale is mainly overseen by the

Department of Environmental Conservation (DEC). Key features of the DEC’s hydrofracking regulatory

program include review of drilling applications for environmental compliance through screening of

proposed well locations and review of proposed well designs. The DEC also performs on-site inspection

of drilling operations and enforces strict restoration rules upon completion of these activities. Proponents

of hydrofracking in the New York debate would point to the fact that these regulations have prevented

any previously known occurrences of groundwater contamination in the state (Department of

Environmental Conservation). Figure 3.2 summarizes New York State’s regulation of hydraulic fracturing.

Other agencies with influence on hydrofracking in the New York Marcellus Shale are the

Susquehanna River Basin Commission (SRBC) and the Delaware River Basin Commission (DRBC). These

bodies regulate the rate and volume of water withdrawal from their respective basins, as well as review

and approve water usage for hydrofracking in the New York Marcellus Shale (Department of

Environmental Conservation).

In accordance with the State Environmental Quality Review Act and the state Environmental

Conservation Law, the DEC has been charged with preparing the aforementioned Supplementary

Generic Environmental Impact Statement (SGEIS), which provides a comprehensive review of potential

environmental impacts and preventive measures associated with hydrofracking. The results of the

document will invariably influence the outcome of the New York debate.


Page 34

!

Figure 3.2: New York State Regulation of Hydraulic Fracturing by the DEC

State Rgulation (DEC)

Review of drilling applications for compliance

Screening of well locations and review of well design

On-site inspection of drilling operation

Enforcement of strict post-completion restoration rules


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CHAPTER 4 | ENGINEERING ASSESSMENT 1

Hydraulic fracturing propagation and threat to underground sources of drinking water

4.1 FRACTURE PROPAGATION

Microseismic and tiltmeter technologies are intensively used since 2001 to map the geometries of

hydraulic fractures in unconventional shale gas reservoirs in North America.

Figures 4.1 and 4.2 show data of hydraulic fracturing treatments in both Barnett and Marcellus shale,

which are the major shale gas, plays in the United Sates.

!

!

Figure 4.1 - Barnett Shale Mapped Fracture Treatments (Fisher).


Page 36

!

Figure 4.2 - Marcellus Shale Mapped Fracture Treatments (Fisher).

The graph shows the true vertical depth of the top and bottom of the hydraulic fracture

treatments performed in Barnett Shale. The depths are colored according to the county that the

treatments were performed in. Also, it illustrates the depth of the deepest water wells in the each county

where a fracture treatment has been mapped by the blue shaded bars at the top of the figure. As the

data show, the largest mapped vertical growth of a fracture top is still several thousands feet bellow the

deepest well in a water aquifer in each county.

Similarly, Figure 4.2 shows a large distance between the largest top of fracture in the Marcellus

shale and the bottom of the deepest water aquifer. As seen from the graph, the fractures in Marcellus

shale grow a little bit higher than in the Barnett. However, the shallowest fracture top is still around 4500

ft below the aquifers in those areas (Fisher).

As a result, it is clear that that there is a large distances rock layers separating between the

water aquifers and producing zones of shale gas reservoirs which works as a barrier against migration

of hydrocarbon gas or fracturing fluid and hence prevent underground water contamination.


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4.2 SEEPAGE OF METHANE GAS

Another public concern about hydraulic fracturing is seepage of methane gas from existing wells

or from the fractures themselves into a drinking water aquifer (Figure 4.3). During the drilling process of

any oil and gas wells, multiple layers of steel casings are set to isolate the well from the surrounding rock

formation. In addition, these casings are cemented together to close any gaps in between and hence

confine all hydrocarbons inside the well. Regular corrosion logging and pressure testing is performed to

ensure the integrity of the casing and detect any leakage from the well into the surrounding formation.

On the other hand, as explained in the figures above, all hydraulic fractures vertical growth stops several

thousands feet below potable water aquifers. Therefore, hydrocarbon gas cannot move vertically in the

impermeable rocks towards the aquifer above it, as the low permeability is the reason for performing a

fracture treatment to recover the gas from the shale formation in the first place.

!

Figure 4.3 – Scenarios For Seepage of Hydrocarbon Into Aquifer (EPA, 2012).

!


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4.3 CASE STUDIES

Engineering studies and drilling requirement demonstrated that it is not likely that hydraulic

fracturing fluid or hydrocarbons in shale formations would migrate from the treated zones up to the

shallow water aquifers. Yet several incidents and cases of drinking water aquifer contamination were

linked to high-volume hydraulic fracturing technology. Therefore, laboratory tests and chemical analysis

of the contaminated water samples were done to confirm whether the contamination resulted is linked to

natural gas development or not. This section will discuss the observations that lead to the assumption that

water contamination was caused by hydraulic fracturing of shale formations along with results of

investigations about these incidents.

4.3.1 Case 1: Natural Gas Content in Water Well (Weatherford, Texas)

In 2010, traces of gas were found in water well drawing from the Trinity water aquifer in a small

town near Weatherford, Texas. The owner believed that the gas originated a gas well located near. He

then filed a claim to EPA against the company who owns the gas well, which is called Range Resources

Inc. Testing of the contaminated fluid samples confirmed the presence of methane gas that is of

thermogenic nature. A thermogenic gas is formed under high temperature and pressures that cause a

conversion of organic material to natural gas. The EPA suggested that it had originated from a deep

source such as one developed by Range Resource Inc. and hence issued and endangerment notice against

the natural gas operator. One of the claims that were under investigation is whether if gas migrated from

the reservoir rock through thousands of rock layers or is that it leaked from the wellbore itself due to

poor well integrity. However, pressure surveys proved that there was no possibility for gas to migrate

through the thick rock layer and confirmed the integrity of the well. Analysis of the chemical composition

found that based on the nitrogen content of methane found in water sample, the source of gas is actually

the Strawn formation, which underlay the Trinity water aquifer at 400 ft deep and not the Barnett shale

of which Range Resources Inc. produces natural gas from (Smith, 2012).


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4.3.1 Case 2: Chemical Additives in Water Well (Pavillion, Wyoming)

In 2011, EPA conducted a investigation after receiving complaints about foul taste and odor of

some water wells in town of Pavillion, Wyoming. The study conducted along with chemical analysis of

contaminated water samples have linked between hydraulic fracture activities and the chemical additives

found in it. The water samples had synthetic chemicals along with benzene concentration that was higher

than the safe limit according to the Safe Drinking Water Act. Among the hazardous chemical substances

found in water samples of concern was 2-butoxyethyl phosphate that which is indicated by the Petroleum

Association of Wyoming as a fire retardant used in plastic components in water wells. Moreover, the

benzene concentration found in the contaminated sample is neither an additive in hydraulic fracturing

fluid nor a fluid produced from gas reservoirs. It is worth to mention that there was not a solid link

between hydraulic fracturing activities and underground water contamination in the town of Pavillion until

this point of time (Smith, 2012).


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CHAPTER 5| ENGINEERING ASSESSMENT 2

Flowback water treatment options for Up-state New York Shale Gas Production

5.1 COMPOSITION OF FRACTURING FLUIDS

Over the last two (2) decades the chemicals that comprise the hydraulic fracturing fluid morphed

into a complex system of over 2500 distinctly named industrial components each with a unique mix of

chemicals and chemical concentrations. However, what has remained the same is the general purpose of

each major component of the frac fluid. The frac fluid can be divided into three major categories: the

pad or base fluid, proppant, and additives (Economides and Martin 2007). The pad fluid, which is

normally water, constitutes approximately 90% of frac fluid composition, the proppant accounts for

about 9%, and the remaining 1% is subdivided between the different chemical additives. This basic

makeup is relatively the same between fracturing projects but may vary slight due to geological changes

between the formations. A comparison of the fracture fluid composition for the Fayetteville and

Marcellus Shale deposit is illustrated in Figures 5.1 and 5.2. Even though there is some change in the

percentage of the components, the general makeup of the frac fluid remains the same; there is a pad

fluid, proppant and chemical additives.

5.2 PURPOSE OF FRACTURING FLUID COMPONENTS

Each component in the frac fluid has a unique role; the pad fluid transmit the energy required to

fracture the formation and also transport the proppant which is used to keep the created fractures open,

allowing gas to flow, after the fracturing pressure has been released. The proppant used in many

hydraulic fracturing projects is usually sand but may vary depending on the formation geology; other

proppants typically employed are low density ceramic beads, sintered bauxite and resin-coated sand

among many others (LaFollette 2010).


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Like proppants, chemical additives are just as varied and even more so if we were to consider their

type, chemical composition and purpose. Nonetheless, frac fluid additives fall into fix categories as

outlined below:

1) Acid

2) Corrosion Inhibitor

3) Bactericide/Biocide

4) Friction Reducer

5) Iron Control

6) Scale Inhibitors

7) Clay stabilizers

8) Viscosity modifiers

a. Gelling agents

b. Cross Linker

c. Breaker

9) Surfactant

10) PH Adjusting Agent

The acid, typically Hydrochloric acid, is used as a stimulator; it cleans up the wellbore perforations of

cement and other debris after the fracturing fluid is pump and in so doing it provides an unhindered path

for gas to flow. The use of acid treatment as a stimulant subjects the steel tubing, well casing, tools and

tanks to rapid corrosion; rapid corrosion is halted by adding a corrosion inhibitor, such as Dimethyl

Formamide, to the frac fluid.

In shale formations there are clay particles that swell or migrate when exposed to frac fluid; clay

particle swelling and/or migration blocks the pore throats in the formation and reduces the formation

permeability and therefore the ability of gas to flow easily through the formation. Clay stabilizing

additives can either be temporary or permanent; temporary clay stabilizers are usually salts such as

potassium chloride (KCl) or sodium chloride (NaCl) and permanannet clay stabilizers, which are used in

conjunction with temperorary clay stabilizers, are cationic organic polymers that tighly bond to the clay

surfaces thereby neutralizing the negatively charged clay particles. Due to the negative charge on clay

particles, they attract water molecules and swell; the negative charge also aids clay particle migration in


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the formation when the ionic concentration of the formation changes due to addition of the fracturing

fluid.

Similar to the effect that clay has on the formation, scale formation in the rock pore throat, and

wellbore perforations hinder the flow of gas; the scale inhibitors are therefore added to reduce such

deposits from occurring. The same is true for biocides, which prevent the growth of bacteria and other

biological organism that also blocks pore throats and perforations and in so doing reduces the

permeability of the formation. Biocides are also used to minimize the bacterial corrosion in the wellbore

and prevent the adverse effect bacteria have on the viscosity of the frac fluid. Fracture fluids typically

contain gels that are organic, which provides an ideal medium for bacterial growth, reducing viscosity

and the ability of the fluid to effectively carry proppant (Arthur, Bohm et al. 2009).

Friction reducers, as the name implies, reduces the effect that tubing and formation friction will have

on fracture fluid pressure; the less friction there is the less the energy loss (in the form of pressure

reduction) between the surface where the frac fluid is being pumped and the formation, where the frac

fluid is expected to fracture the rock. Viscosity modifiers either increases or decreases the viscosity of the

frac fluid; the greater the viscosity of frac fluid, the easier it is for the fluid to transport proppant but the

more difficult it is to pump and flow back the fluid post fracturing. Also higher viscosity fluids limit the

fracture length and ultimately reduce productivity and ultimate recovery. Therefore a balance must

therefore be attained; during the fracturing process one may want a relatively higher viscosity frac fluid

to transport the proppant but not too high that it begins to limit fracture length growth and it becomes

difficulty to flowback. which ultimately blocks the flow path and damages the formation.


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Figure 5.1: Schematic detailing the fracture fluid composition in Fayetteville Shale (Arthur, Bohm et al. 2009)

Figure 5.2: Schematic detailing the fracture fluid composition in Marcellus Shale (NYSDEC 2011)


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5.3 HYDRAULIC FRACTURING FLOWBACK WATER

5.3.1 Flowback water volume

In a survey conducted in 1995 by the American Petroleum Institute (API), it was found that the U.S

exploration and production segment of the oil and gas industry generated almost 18 billion bbl of

produced water (Puder and Veil 2006). Noting the significant increase in hydraulically fractured wells

between 1995 and 2012, one can easily conceive the impact this has had on the volume of produced

water (flowback water or waste water) especially when we consider the average volume of water used

in hydraulic fracturing.

Before going further, one must first understand the difference between flowback water and

produced water, even though the difference is very subtle. Fracturing flowback water is fluid that was

initially used to fracture the formation and contains proppants, different chemical additives and some

soluble and insoluble deposits from the formation. This type of wastewater is usually returned in the first

few days following hydraulic fracturing but is progressively replaced by produced water. Produced

water is fluid that was displaced by the movement of the gas through the formation and can contain some

of the chemicals used in hydraulic fracturing but contains progressively more of the reservoir soluble and

insoluble components such as salts, gases (e.g. methane, ethane), trace metals, naturally occurring

radioactive elements (e.g. radium, uranium), and organic compounds (Foster 2012). Both type of

wastewater fall under the same category referred to as hydraulic fracturing wastewater.

The volume of fracturing fluid used in the life of a field has been estimated to be in the range

from 500 gallons for mini-fracturing treatment (Gidley 1989) to as much as 2 million to 7million gallons

for massive hydraulic fracturing projects, which use in excess of 3million lbm of proppant per frac job

(Gidley 1989; Moss 2008; Foster 2012). In a report published by the EPA in 2012, it was estimated that

flowback water volume ranges from 10% to 70% of the volume of the injected fluid; the percentage of

flowback water is most significantly affected by the geology of the formation. Flowback water

recoveries reported from horizontal Marcellus wells in the northern tier of Pennsylvania range between 9

and 35 percent of the fracturing fluid pumped (NYSDEC 2011) . The potential volume of flowback water

an operator will have to manage can easily be illustrated by considering a frac job that used 5 million


Page 45

gallons of fracturing fluid; the flowback water from this treatment will be in the range of 500,000 to 3.5

million gallons of fluids (EPA 2012).

5.3.2 Potential impact on public health and the environment

The additives mixed with the fracturing fluid are essential to the success of the fracturing

procedure but they are also one of the main reasons for the concerns raised about the potential impact

of flowback water on human health and the environment. The other three (3) reasons are the excessive

amounts of dissolve salts, heavy metals, and naturally occurring radioactive material (NORM) that are

brought back to the surface with the flowback water.

According to a 2012 published report by Environmental Protection Agency (EPA), more than 2500

different fracturing products (additives) has been recorded as being used between 2005 and 2009;

many of these additives contained one more of the 27 chemicals identified as known or suspected

carcinogens, or classified as hazardous air pollutants (EPA 2012). See Figure 5.3. Apart from their impact

as direct carcinogens and hazardous air pollutants, the concern was recently raised that flowback water

may contribute to the formation of disinfection byproducts such as brominated byproducts during the

treatment of drinking water; these byproducts are detrimental to human health at high exposure levels

(EPA 2012). The US House of Representatives’ Committee on Energy and Commerce Minority Staff

released a report (2011) noting that more than 650 products (i.e., chemical mixtures) used in hydraulic

fracturing contain 29 chemicals that are either known or possible human carcinogens or are currently

regulated under the SDWA (EPA 2012).

For the above reasons, it is crucial that hydraulic fracturing wastewater be handed safely and be

treated and disposed properly in a controlled manner. Many operators who currently invest in hydraulic

fracturing transport their flowback water to either publicly or privately owned wastewater facility for

treatment and deposal. However a concerned has been voiced about the efficacy of these treatment

facilities in regards to flowback water. The question has been asked whether these facilities can, with

currently installed technology, effectively remove selected contaminants from the fracturing wastewater,

including radium and other metals.


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Since these concerns have been raised, it is prudent they are thoroughly addressed and some consensus

reached on the best option for flowback water treatment in Upstate New York. Is publicly owned

treatment works (POTW) and commercial treatment systems the best option for the shale gas industry in

Update New York or are there other feasible methods for flowback water treatment that can be

employed? These are the questions that must be answered.

Figure 5.3: Chemicals identified as carcinogens, possible carcinogens and hazardous air pollutants (EPA 2012)


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5.2.3 Treatment and Disposal Options for Hydraulic Fracturing wastewater

Even though many operators send flowback water to either POTWs or centralized waste

treatment facilities (CWT) and there are advantages to the operators for doing so, there are many other

options currently available, some of which are more frequently employed than wastewater treatment

facilities. The methods currently practiced in several states for the disposal or treatment (Puder and Veil

2006; Arthur, Bohm et al. 2009) of flowback water include:

1) Evaporation 2) Land application 3) Treatment 4) Injection into Class II wells 5) Recycling 6) Publicly Owned Treatment Works (POTW) 7) Off-site Centralized/Commercial Water Treatment (CWT) 8) Onsite Water Treatment 9) Bioremediation

Evaporation is a process that is most suitable for semiarid regions; the evaporation technology

involves the use of ponds, generally referred to as evaporation ponds. These ponds are lined to prevent

wastewater from seeping into the ground; in semiarid regions, hot dry air moving across the land surface

results in the evaporation of the liquid portion of the waste. The remaining solids are then disposed of in

approved landfills. Base on the report published by Argonne National Laboratory for the US Department

of Energy, the process of evaporation is practiced in Colorado, New Mexico, Utah, and Wyoming(Puder

and Veil 2006).

Land application refers to the application of drilling waste to the land and allowing the soils

naturally occurring microbial population to metabolize, transform, and assimilate waster constituents in

place. Land application is a form of bioremediation and is normally considered both wastewater

treatment and disposal, and is broken down into two main categories: land farming and land spreading

or land treatment. Land farming is the repeated disposal of wastewater to the soil surface and land

treatment is the one-time application of waste with low levels of hydrocarbons and salts to the soil

surface. Land application as a treatment and disposal method for flowback water is currently practiced

in Arkansas, New Mexico, Texas, Utah and Wyoming (Puder and Veil 2006).


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Recycling as the terms suggest involves the reuse of hydraulic fracturing wastewater for future

hydraulic fracturing projects by removing certain components that may adversely affect the fracturing

process and the productivity of the reservoir. However achieving the required, or an acceptable, treated

water quality is a major challenge facing reuse technology; controlling the TDS, calcium and hardness of

treated water is essential as these play a major role in scale formation, which severely affects the

productivity of wells.

The SRBC’s reporting system for water usage within the Susquehanna River Basin (SRB) has

provided a partial snapshot of flowback water reuse specific to Marcellus development. For the period

June 1, 2008 to June 1, 2011, operators in the SRB in Pennsylvania reused approximately 311 million

gallons of the approximately 2.14 billion gallons withdrawn and delivered to Marcellus well pads. The

SRBC data indicate that an average of 4.27 million gallons of water were used per well; this figure

reflects an average of 3.84 million gallons of fresh water and 0.43 million gallons of reused flowback

water per well. The current limiting factors on flowback water reuse are the volume of flowback water

recovered and the timing of upcoming fracture treatments. Treatment and reuse of flowback water on the

same well pad reduces the number of truck trips needed to haul flowback water to another destination

(NYSDEC 2011).

Recycling is done both on site and at offsite recycling facilities depending on the relative distance

of these facilities to the project site since transportation cost can greatly increase the cost of this process.

For this same reason, recycled water is typically reused at the site because the cost of transporting the

water to new site limits the feasibility of this process. Recycling is done for several waste streams ranging

from water and oil based muds and cuttings to contaminated soils. However, commercial facilities that

recycled produced water could only be found in Oklahoma and California (Puder and Veil 2006).

Recycling as a hydraulic fracturing wastewater management tool is quickly gaining ground; gas

producers are striving to reduce the cost associated with procuring fresh water, wastewater

transportation, and offsite treatment and disposal. However from a report issued by the EPA, which was

based on information collected from 62 operators in the Marcellus shale play, we see that the reuse

treatment technologies are similar, if not the same, to those used by wastewater treatment facilities

(WWTF) or publicly owned treatment works (POTWs). The processes typically included direct reuse,

onsite treatment (e.g., bag filtration, weir/settling tanks, thirdparty mobile treatment systems) and offsite

treatment. However, from the foregoing we see that onsite treatment, though it reduces the volume of


Page 49

fresh water required, and the volume of wastewater produced, the treatment processes involved are still

not suited for the removal of many of the chemical additives in hydraulic fracturing wastewater and

therefore there will still be need to treat and properly dispose of the final concentrated volumes of

wastewater and residuals remaining at the end of operations (end of field life).

Offsite treatment, based on the research findings, consisted predominantly of some form of

stabilization, primary clarification, precipitation and secondary clarification and/or filtration; the specifics

of offsite treatment methods were lacking in the data recovered as these procedures are considered

proprietary (EPA 2012). From the foregoing, what we see is that onsite treatment, though it reduces the

volume of fresh water required and wastewater produced, the treatment processes involved are still not

suited for the removal of many of the chemical additives in hydraulic fracturing wastewater before the

treated effluent is disposed of into surface stream.

Figure 5.4: Fracturing fluid composition inclusive of recycled flowback water (NY SGEIS)

Treatment is also a popular means of managing not only produced water but also other waster

streams from the oil and gas industry. In this context treatment refers to use of cells,

solidification/stabilization, and separation but not to treatment in POWTs, CWTs or thermal treatment.


Page 50

Some companies use earthen cells where free oil is removed and salvaged for resale, salty water is

stored and later injected into a commercial saltwater injection well, and finally any remaining solid waste

is processed to remove organic contamination through biological degradation.

Other companies use separation; this process involves dewatering of liquid waste streams to

separate solids from liquid waste streams by using desanders and decanter centrifuges. The liquid phase

is further treated and sent to a POWT or injected into a commercial saltwater injection well. The solids

are stabilized with fly ash, cement, wood chips or similar material and trucked to landfills to be used as

daily cover material. The use of treatment of manage produced water has been identified in only two

states; Texas and Alabama currently practice treatment as a produced water management

method(Puder and Veil 2006).

The process of solidification/stabilization is more used for sludge or solid waste; the process

encapsulates the solid waste or sludge and transforms it into an inert dirt-like substance that will not leach

hydrocarbons or heavy metals into the environment.

Injection of flowback water into class II injection wells is the most popular means of disposing this

type of wastewater; the EPA estimates that more than 2 billion gallons of brine from oil and gas

operations are injected daily. The process involves the collection and transportation of the flowback

water to a commercially licensed disposal well where the wastewater is injected into the formation. Many

states currently poses commercial injection wells; states that posses such facilities include Oklahoma,

Alabama, Arkansas, Texas, Louisiana, North Dakota, New Mexico and many others.

Publicly owned treatment works (POTWs) and Commercial water treatment (CWTs) facilities is

a favorite option for operators involved in hydraulic fracturing and are seeking an offsite flowback

water treatment method. The use of POTWs and CWTs is thought to be favored because it is deemed an

easy means of complying with regulatory requirements and it is though to be more cost effective than

self-treatment. Other operators may see it as a means of shifting the burden of responsibility and

liability to a third party, which is not necessarily the case since the company that originally generates the

waste maintains liability indefinitely under the U.S. Superfund Law (Comprehensive Environmental

Response, Compensation, and Liability Act).

In a report published in 2006 on behalf of the US Department of Energy(Puder and Veil 2006),

the authors reported that only eight(8) of the thirty(30) oil and gas producing states had a dedicated


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industry-specific network of offsite commercial disposal and companies and facilities; states with such a

network includes Arkansas, Colorado, New Mexico, Oklahoma, Texas, Utah and Wyoming. Seven of the

thirty (30) states investigated had few offsite facilities; Pennsylvania was highlighted as one of these

states. More surprisingly however, fifteen (15) of the (30) oil and gas producing states investigated were

without industry specific offsite commercial disposal facilities and companies; noteworthy is that Ohio and

New York fell under this category. For this reason, it is reasonable to question the efficacy of treatment

processes at POTWs and CWTs, since discharge of treated wastewater to surface waters provides an

opportunity for chemicals found in the effluent to be transported to downstream PWS intakes (EPA 2012).


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5.4 TREATMENT PROCESSES IN POTWS & CWTS

POWTs collect wastewater from private and commercial sources; the sewerage is treated to

remove harmful organisms so that the end product can be discharged safely into surface streams. As part

of the service POWTs provide, they also accept and treat wastewater from industrial sources. The Clean

Water Act (CWA) regulates wastewater that has been treated and is to be discharged into a surface

stream; regulation is done through the National Pollutant Discharge Elimination System (NPDES) permit

program. Consequently CWTs must obtain permits if their discharge goes directly to surface waters.

Industries who transport waste to POTWs for treatment are subject to the general pretreatment

regulation under the CWA; this outlines the responsibilities of industries and the public to implement

pretreatment standards to control pollutants, which may pass through or interfere with POTW treatment

processes (Puder and Veil 2006). Hydraulic fracturing wastewater is treated both at publicly owned

treatment works (POTWs) and centralized waste treatment facilities; the wastewater may be treated on

or off site after which time it is deposed of into surface rivers. Figure 5.5 illustrates this process.

Some states allow hydraulic fracturing wastewater to be treated at POTWs with subsequent

discharge to rivers but the exact number of POTWs currently accepting hydraulic fracturing wastewater

is not known (EPA 2012). In December 2012, the EPA published a report that indicated that up until May

2011, approximately 15 POTWs in Pennsylvania where accepting hydraulic fracturing wastewater from

the Marcellus shale play; In April 2011 the Pennsylvania Department of Environmental Protection

requested that the Marcellus Shale natural gas operators voluntarily cease delivering their wastewater to

the fifteen (15) mentioned POTWs; in April 2011, the Pennsylvania Department of Environmental

Protection announced a request for Marcellus Shale natural gas drillers to voluntarily cease delivering

their wastewater to the 15 POTWs (EPA 2012). Soon thereafter, in November 2011, the state put in

place more stringent regulations that limit monthly average values as follows:

1) 500 milligrams per liter TDS, 2) 250 milligrams per liter chloride, 3) 10 milligrams per liter total barium 4) 10 milligrams per liter total strontium


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These limits however don’t apply to the fifteen POTWs mentioned above or other grandfather treatment

plants (EPA 2012).

Figure 5.5 – Disposal methods for Hydraulic fracturing wastewater - Source - (EPA 2012)

Conventional POTW treatment processes are categorized into four (4) groups: primary,

secondary, tertiary and advanced treatment. Most POTW are designed to filter and flocculate solids, as

well as consume biodegradable organic species associated with human and some commercial waste. Very

few facilities are designed to manage the organic and inorganic chemical compounds contained in

hydraulic fracturing wastewater (EPA 2012). A generalized flow diagram for the treatment process in

POTWs is presented in Figure 5.6.

The conventional POTW treatment process starts with primary treatment where large solids and

other wastewater constituents that either float or sink is removed by screens or weirs by means of grit

removal processes, and/or sedimentation and flotation. Secondary treatment involves the removal of

biodegradable organics by means of microbial processes (e.g., “bioreactor” in Figure 5.6), in fixed


Page 54

media (e.g., trickling filters) or in the water column (e.g., aeration basins) (EPA 2012). Secondary

treatment is immediately followed by a second settling stage, which removes suspended solids generated

in the aeration basins; this process takes place in the secondary clarify shown in Figure 5.6. The

treatment process is concluded with filtration and or UV disinfection to achieve a particular end use

quality (e.g. irrigation). If no end use is intended, the treated effluent is discharged to surface waters; the

solids residuals, formed as byproducts of the treatment processes, and which may contain metals,

organics, and radionuclides, are de-watered and disposed of at landfills, by land application or

incineration.

Figure 5.6 – Generalized flow diagram for treatment processes in a conventional POTW- (EPA 2012)

Unlike publicly owned treatment works (POTWs), which are not specifically designed to handle

the chemical additives in frac water, commercial treatment facilities designed for this purpose comprise

much more advance treatment methods, which are capable of removing the unwanted chemical additives

from the treated effluent. Commercail processes for treating hydraulic fracturing wastewater include

crystallization (zero liquid discharge), thermal distillation/evaporation, electrodialysis, reverse osmosis,


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ion exchange, and coagulation/flocculation followed by settling and/or filtration (EPA 2012). However

there are tradeoff that has to be managed when selecting a process to treat fracturing wastewater;

hydraulic fracturing wastewater has high-TDS and will require a process that can manage this type of

wastewater composition. Thermal processes are best suited to effectively treat high-TDS wastewater and

are capable of treating hydraulic fracturing wastewater with zero liquid discharge, leaving only residual

salts but these processes are energy-intensive. Electrodialysis and reverse osmosis may be less energy

intensive but are feasible only for the treatment of lower-TDS wastewaters. These technologies are not

able to treat highTDS waters (>45,000 milligrams per liter) and may require pretreatment (e.g.,

coagulation and filtration) to minimize membrane fouling (EPA 2012). Consequently, they are not the

most suitable methods to treat hydraulic fracturing wastewater if pretreatment is not an option. One of

the main advantages of centralized waste treatment facilities is that they can be used as pre-treatment

prior to a POTW; this approach allows the operator to meet the Clean Water Act pretreatment

regulation, which outlines industries responsibilities to implement pretreatment standards to control

pollutants, which may pass through or interfere with POTW treatment processes. Additionally this option

provides the operator with the option of self-managing waste disposal by means of an approved NPDES

permit, which allows the operator to discharged treated effluent directly to surface water.


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5.5 ON-SITE TREATMENT OF HYDRAULIC FRACTURING WASTE WATER

The decision to use on-site treatment and the selection of the treatment options is based on the following

factors (NYSDEC 2011):

Operational

• Flowback fluid characteristics, including scaling and fouling tendencies; • On-site space availability; • Processing capacity needed; • Solids concentration in flowback fluid, and solids reduction required; • Concentrations of hydrocarbons in flowback fluid, and targeted reduction in hydrocarbons; • Species and levels of radioactivity in flowback; • Access to freshwater sources; • Targeted recovery rate; • Impact of treated water on efficacy of additives; and • Availability of residuals disposal options.

Cost

• Capital costs associated with treatment system; • Transportation costs associated with freshwater; and • Increase or decrease in fluid additives from using treated flowback fluid.

Environmental

• On-site topography; • Density of neighboring population; • Proximity to freshwater sources; • Other demands on freshwater in the vicinity; and • Regulatory environment.

On-site treatment facilities will typically include the following processes:

1) Physical and/or Chemical separation

This process is required for the removal of oil, grease and suspended matter from the flowback


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water and is typically employed as a pretreatment step in a multistep on-site treatment process. Physical

separation technologies include hydrocyclones, filters, and centrifuges; however, filtration appears to be

the preferred physical separation technology. Microfiltration has been shown to be effective in lab-scale

research, nanofiltration has been used to treat production brine from off-shore oil rigs, and modular

filtration units have been used in the Barnett Shale and Powder River Basin. Nanofiltration has also been

used in Marcellus development in Pennsylvania, though early experience there indicates that the fouling

of filter packs has been a limiting constraint on its use (NYSDEC 2011).

Chemical separation is a two part process: coagulants and flocculants are used to break emulsions

(dissolved oil) and to remove suspended particles and precipitation is achieved by manipulating

flowback water chemistry such that the constituents (e.g. metals) will precipitate out of solution.

Precipitation is usually done sequentially, so that several chemicals will precipitate, resulting in cleaner

flowback water. Chemical separation units have been used in the Barnett Shale and Powder River Basin

plays, and some vendors have proprietary designs for sequential precipitation of metals for potential use

in the Marcellus Shale play (NYSDEC 2011) .

If the on-site treatment process was installed primarily for the purpose treating flowback water

for blending and reuse, chemical precipitation may be the only step needed. Chemical precipitation will

remove the scale forming metals such as barium, strontium, calcium and magnesium; upon removal of

these metals, no further treatment may be required. Figure 5.7 illustrates the allowable water quality

requirements for reuse after on-site treatment and prior to potential additional dilution with fresh water

(NYSDEC 2011).

2) Dilution

Even after on-site physical and/or chemical separation the concentration of some flowback water

constituents may still be too high and therefore adversely affect the fracturing fluid desired properties.

For example, the demand for friction reducers increases when the chloride concentration increases; the

demand for scale inhibitors increases when concentrations of calcium, magnesium, barium, carbonates, or

sulfates increase; biocide requirements increase when the concentration of microbes increases(NYSDEC

2011). This problem can be overcome by blending the treated flowback water with fresh water thereby


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reducing the concentration of the unwanted constituent and in so doing dilution reduces the impact amount

of fracturing fluid additives required for recycled flowback water.

Figure 5.7 – Maximum allowbale water quality requirements after onsite treamtent and prior to reuse (NYSDEC 2011)

3) Advance Treatment

Membranes/Reverse Osmosis

Membranes are an example of an advanced filtration techniques used to treat TDS in flowback

water. The membrane technology allows the water (permeate) to pass through the membrane but blocks

suspended or dissolved particles larger than the membrane pore size. This method of treatment is

capable of treating TDS concentrations up to approximately 45, 00 mg/L and can produce and effluent

with TDS in the range of 200 to 500 mg/L but the recovery rate for this technology is only

approximately 50-75% . On the downside, this type of technology may be impacted by scaling and/or

microbial fouling and therefore the flowback water may require pre-treatment before membrane

filtration (NYSDEC 2011).

Reverse osmosis (RO) used osmotic pressure to push clean water through the membrane; the

process produces a highly concentrated brine effluent that will require further treatment and disposal.

The RO process is however less efficient with high TDS inflows such as flowback water. Consequently in a

multistage treatment process, RO is used as primary treatment (with suitable prior pre-treatment) and

must be followed by secondary treatment method, either onsite or off-site, that is capable of treating the

concentrated brine solution.


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Modular membrane technology units have been used in different regions for many different

projects, including the Barnett Shale. Some firms have developed modular RO treatment units, which could

potentially be used in the Marcellus (NYSDEC 2011).

Thermal Distillation

Thermal distillation is a process that employs evaporation and crystallization techniques that

integrate a multi-stage distillation column. The process is fouling and scaling resistant and is capable of

treating flowback water with a wide range of parameter concentration. For example, thermal distillation

may be able to treat TDS concentrations from 5,000 to over 150,000 mg/L, and produce water with TDS

concentrations between 50 and 150 mg/L (NYSDEC 2011). However the process is very energy intensive,

it has a large footprint, and the produced salts still require safe disposal.

Modular thermal distillation units have been used in the Barnett Shale, and have begun to be used in the

Marcellus Shale in Pennsylvania. In addition to the units that are already in use, several vendors have

designs ready for testing; potentially further decreasing costs in the near future(NYSDEC 2011) .

Ion Exchange

Ion exchange as its name implies is a technology that allows specific ions to be exchange from the

flowback. The process involves the use of different types of resins, that are selected on the basis of the

type of ion you will like to remove; in the case of flowback water the resin are selected to preferentially

remove sodium ions. The volume of the resin used and the size of the ion exchange vessel depend on the

salt concentration and the volume of the flowback water to be treated. Modular ion exchange units have

been used in the Barnett Shale (NYSDEC 2011).

Electrodialysis/Electrodialysis Reversal

This process uses alternating stacks of cation and anion membranes; the application of a current to

the membranes as the flowback water passes causes the cations and anions to migrate in different

directions. Electrodialysis reversal (EDR) is the same process except the electric current polarity can be

reversed, implementing a backwash cycle, which cleans the stacks and reduces membrane scaling. EDR

consumes much less energy than standard reverse osmosis systems and can reduce salt concentration in


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treated water to less than 200mg/L. A comparison of Electrodialysis Reversal and Reserve Osmosis

technologies is presented in Figure 5.8.

Figure 5.8– Comparison of Electrodialysis Reversal and Reserve Osmosis (NYSDEC 2011)

Ozone/Ultrasonic/Ultraviolet

The process involves the oxidation and separation of hydrocarbons and heavy metals; the process

also oxidizes biological films and bacteria from flowback water. The microscopic air bubbles in

supersaturated ozonated water and/or ultrasonic transducers cause oils and suspended solids to float

(NYSDEC 2011). The process is typically used as a one step in a multistep flowback water treatment

process where flowback water is treated for blending or re-use in drilling new wells. Systems

incorporating ozone technology have been successfully used and analyzed in the Barnett Shale (NYSDEC

2011).

Crystallization/Zero Liquid Discharge

Zero liquid discharge (ZLD) is probably one of the most effective means of treating flowback

water but it is also probably the most expensive means of doing so. The ZLD process ensures that all

liquid effluent is of reusable or dischargeable quality and concentrate from the treatment process will be

crystallized and will either reusable onsite, offered for sale as a secondary byproduct, or will be treated

sufficiently that it meets regulations for disposal at a landfill (NYSDEC 2011). The ZLD technology uses

the same principles as physical and chemical separation (precipitation, centrifuges etc) and evaporation

but because of the cost of the system its use as a treatment is rare and the economic feasibility of using

the technology to treat flowback water is yet to be proven (NYSDEC 2011).


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Figure 5.9 summarizes the typical processes used in the US for onsite flowback water treatment

and provides a comparison between these processes.

Figure 5.9 - Comparison of treatment options (NYSDEC 2011)


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5.6 TREATMENT OPTIONS FOR UPSTATE NEW YORK

One of the leading issues in the hydraulic fracturing debate in New York is the potential impact

hydraulic fracturing wastewater can have on the environment and especially human health. Hydraulic

fracturing wastewater typically contains high concentration of TDS and significant concentrations of

Chloride and bromide. These halogens are difficult to remove from wastewater and most conventional

POTWs are ill-equipped to handle these pollutants. Consequently, since drinking water intakes can be

located downstream of discharge points, frac water that is disposed of into surface streams, either by

POTWs or onsite treatment facilities, has the potential to elevate chloride and bromide concentrations in

drinking water. When the contaminated drinking water is chlorinated at the water treatment facility, the

chloride and bromide reacts with natural occurring organic matter (NOM) in the water and produces

disinfection byproducts (DBP). DBPs are carcinogenic and have detrimental developmental and

reproductive effects; for this reason the maximum contaminant levels (MCLs) of the DBPs bromate,

chlorite, haloacetic acids, and total THMs (Trihalomethanes) in finished drinking water are regulated by

the National Primary Drinking Water Regulations (EPA 2012).

Additionally, increased bromide concentrations in drinking water resources can lead to greater

total THM concentrations on a mass basis and may make it difficult for some PWSs to meet the

regulatory limits of total THM listing in Figure 5.10 in finished drinking water. The high level of bromine in

fracturing wastewater is due to the brominated biocides that are often used in fracturing fluids to

minimize biofilm growth. The regulated DBP and their corresponding MCLs are outlined in Figure 5.10;

the EPA has identified elevated bromide and chloride levels in surface water from hydraulic fracturing

wastewater as a priority for protection of public water supplies but it is important to note that hydraulic

fracturing wastewater can potentially contain other contaminants in significant concentrations that could

affect human health (EPA 2012).


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Figure 5.10 – Disinfection byproducts regulated by the National Primary Drinking water Regulations (EPA 2012)

Considering all that has been presented thus far, a summary of the treatment procedures that are

feasible, not feasible and the reason for the decision is as follows:

1) Evaporation – Not a feasible option for upstate New York as the process requires that the rate of

evaporation be much more than the rate of precipitation; the process is more suited for arid or

semi-arid areas where ward dry air moving across the land surface rapidly evaporates the water

in frac waste leaving a solid that can be safely disposed of at an approved landfill.

2) Treatment – Semi-feasible Option for upstate New York. The process is more geared towards

the treatment of slurry waste such as drilling mud and other waste material such as contaminated

soil. The process is also used to treat produced water before injection into class II wells but

additional treatment will be required to meet the Clean Water Act requirement on effluent water

quality (e.g. TDS).

3) Land Application – Not a feasible option for Up-State New York. Given the already

environmentally sensitive nature of hydraulic fracturing wastewater disposal, this option will only

serve to further aggravate the situation.


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4) Recycling – Both onsite and offsite recycling is a feasible option for Up-State New York. Recycling

has the potential to drastically reduce both the need for fresh water and the volume of

generated hydraulic fracturing wastewater. However, one has to be cognizant of the fact that

there will still be need to treat and properly dispose of the final concentrated volumes of

wastewater and residuals remaining at the end of operations (end of field life) and this

wastewater will have to be treated to an acceptable level if they are to be disposed of into

surface streams. The other downside to this option is that commercial facilities recycling produced

water could only be found in California and Oklahoma.

5) Injection into Class II wells – Feasible option for upstate New York. The only downside to this

approach is that there are not many saltwater injection wells in New York (Puder and Veil 2006)

and the cost of transporting the hydraulic fracturing wastewater may or may not have a severe

impact on the feasibility of this approach, which will depend on the injection wells locations

relative to the production site. Puder et al in their report published in 2006 found that companies

will not be inclined to transport wastewater beyond 50 to 75 miles of the operations unless no

other alternatives are available because the transportation cost can affect the feasibility of

offsite treatment (Puder and Veil 2006).

6) Publicly Owned Treatment Works (POTW) – Not a feasible option for Up-State New York. It is

obvious from literature available on these facilities that they were not designed to tackle the

treatment of hydraulic fracturing wastewater. Wastewater from the fracturing process has too

many known and unknown chemical constituents for a POTW to effectively managed and cost and

practicality of updating such facilities to treat hydraulic fracturing wastewater renders this option

more infeasible. e.g The technology needed to effectively treat hydraulic fracturing wastewater is

not aptly suited to treating sewer waste.

7) Centralized/Commercial Water Treatment (CWT) – Feasible option but investment and/or waste

transport cost will be a limiting factor. Unlike POTWs, CWTs are specifically designed to handle

multiple types of industrial wastewater. The shortcoming in this proposed option is that New York

state has no dedicated produced water treatment network for the oil and gas industry (Puder

and Veil 2006) and in 2006 the Division of Mineral Resources of the New York Department of


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Environmental Conservation does not permit or license commercial disposal facilities, nor does it

officially track disposal of E&P wastes that are removed from well sites(Puder and Veil 2006). One

may consider out of state commercial treatment facilities in places such as Pennsylvania but there

will be feasibility implication due additional transportation cost.

8) On-Site Treatment Plants – Feasible Option but will feasible checks will have to be done on a site

by site basis taking in consideration the points outlined in previously such as onsite space

availability, flowback water composition, access to fresh water, cost of treatment facility,

regulatory environment etc.


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5.7 REQUIRED TREATMENT PROCESSES & COST OF TREATMENT OPTIONS

Having assessed the composition of flowback water and the capability of the different

wastewater treatment processes, the flowchart illustrated in Figure 5.11 was developed to depict a

typical series of processes required to effectively treat hydraulic fracturing flowback water. The overall

treatment process typically involves some form of physical separation, chemical precipitation, a

bioreactor, and one of the many forms of advance treatment, which includes forward osmosis, reverse

osmosis, thermal distillation, eletro-dialysis, ion exchange, or zero liquid discharge (crystallization). The

advance treatment option must be chosen based on the specific composition of the field flowback water

and the economics of the processes. As Figure 5.9 showed, the capability/effectiveness of each process is

not identical and the cost of each process differ significantly, as discussed previously in this chapter.

Figure 5.11 – Typical process arrangement to treat hydraulic fracturing flowback water.


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The research into hydraulic fracturing flowback water was taken one step further, as discussed

previously, to evaluate the methods employed by other states in the management of hydraulic fracturing

flowback water. Section 5.6 in discussed the management options that we have deemed feasible for use

in the Marcellus Shale (Up-State New York); Figure 5.12 illustrates the cost of these options. The four most

feasible options selected were onsite stationary treatment, onsite mobile treatment, industrial/commercial

wastewater treatment facility, and disposal into class II injection wells; the cost for each of these options

were inputted into our economic model to determine the overall feasible of producing shale gas using the

respective wastewater treatment method.

Figure 5.12 – Cost for various hydraulic fracturing flowback water management options


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CHAPTER 6| ENGINEERING ASSESSMENT 3

Proppant Selection for Gas Production in the Marcellus Shale in Up-state New York

6.1 PURPOSE AND TYPES OF PROPPANTS

Proppants function, as would have been discusses briefly previously in this document, is keep open

or prop open the fractures created by the hydraulic fracturing process after the fracturing fluid is

removed. This is essential because it then maintains an open pathway through which the fluids can move

from reservoir matric to the wellbore. Many different types of proppant are available but each

proppant can be placed in one of the following categories: silica sand, resin-coated sand and ceramics

or composites. Silica sand typically includes Ottawa, Jordan, England and Brady sand; resin coated

includes curable and pre-cured; ceramics includes sintered bauxite, intermediate strength proppant (ISP)

and lightweight proppant (LWP)

No one proppant can be universally used in every reservoir; the type of proppant selected

depends on the characteristics of the formations (formation pressure being the most significant) and

fracture design (fracture width, conductivity tc.). In terms of types available, under the sand catergory

two of the most popular are Ottawa sand and brady sand. Because of the relatively low cost and

readily availability of good quality sand, silica sand is one of the most popular proppants used in the

industry today. However as previously stated, no one proppant is universal; sand is typically used in

shallower reservoirs where the closer stresses are smaller where as ceramics are used in intermediate

depth reservoirs and sintered bauixite, having the strongest compressive strength of all are used in the

deepest reservoirs. Figure 6.1 illustrates the typical application range for the different categories and

some of the typical types of Proppants being used today.

Each proppant type has its advantages and limits; outside of these the proppants are adversely

affects the hydraulic fracture design. For example, silica sand is very poplular because good quality

sand is readily available but high closure stresses crush the sand and ultimate reduces the fracture

permeability to almost nil. Resin coated proppant (ie sand coated with a polymeric material) can


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withstand higher closure stresses by means of the coating which reduces high grain to grain stress; the

coating also aids in improving the fracture conductivity as causes the proppants to clump together

increases the proppant density in the fracture. Nonetheless there are limits to the closure stress these resin

coated proppants can withstand and they are much more expensive than pure silica sand.

Ceramics have a higher compressive strength than sand and resin coated proppants AND

therefore can withstand higher closure stresses but they tend to be much more expensive and still cannot

be used at extreme depths (>12,000ft) where they are also crushed. Lightweight ceramics and ultra light

weight proppants such as resin coated porous ceramics and plastic composites (Economides and Martin

2007) are some of the newer versions of proppants being used; the low specific gravity of this type of

proppant allows the fracturing fluid to transport the proppant further into the fracture thus improve the

fracture effective length (conductive length) and ultimate the productivity and ultimate recovery of the

reservoir.

In very deep reservoirs, (ie 14,000ft and greater) sintered bauxite is normally the proppant of

choice because of it high compressive strength. However one of the shortcomings of this material is high

specific gravity; the property causes the proppant to settle out of the fracturing fluid quickly thereby

limiting the distance the proppant can be transported into the fracture. This reduces the effective length

of the fracture and thus the productivity and ultimate recovery of the reservoir.

Figure 6.1 – Proppant Application Rang (LaFollette 2010)


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6.2 PROPPANT SELECTION

As previously stated, the type of proppant selected depends on the reservoir properties

especially the depth and by extension the closure stress in the fracture. However, apart from this, fracture

design and economics are the other two driving forces behind the type of proppant selected. Proppant

selection as a function of fracture engineering design will be presented in this section and proppant

selection as a function of economics will be presented in section 6.3.

From the engineering design standpoint, the proppant selected is a function of the following:

1. Fracture closure stress (function of reservoir geology)

2. Desired Fracture width

3. Desired Fracture Length

4. Desired fracture conductivity

The ultimate goal in all hydraulic design, apart from minimizing the cost of the actual fracture job,

is to maximize the fracture conductivity. By improving the fracture conductivity, the fracture job efficiency

improves and the productivity of the reservoir. i.e. A greater rate of oil and or/gas can be produced

daily and monies invested in the reservoir can be recouped sooner. The change in productivity as a

function of fracture length and conductivity is illustrated in Figure 6.2. The effect of depth (ie closure

stress) on the two extremes of proppant types that being sand and sintered bauxite is illustrated in Figure

6.3; Figure 6.4 illustrated the effect closure stress has on the conductivity of various typically used

proppants.

The fracture conductivity is a function of the fracture width and the permeability proppant pack.

The wider the fracture and/or the more permeable the fracture packs the greater is the fracture

conductivity. On the same note, the ronder and larger the proppant the greater is the proppant pack

permeability. However there are trade offs that hae to be made between fracture width and length, and

proppant pack permeability and the effective fracture length. Reservoir productivity is a direct function

of fracture width and permeability; the reservoir recovery factor or the percent of the total hydrocarbon

present in the reservoir that is recovered is a function of the effective fracture length. In order to increase

the fracture width one must increase the fracture fluid viscosity which ultimate limits the length of the


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fracture. Fracture permeability can be increase by increasing the proppant size but larger proppants

are heavier and cannot be transported as far as smaller proppants and as fracture width reduces futher

in the reservoir to proppants are to big to pass and thus this limits the effective fracture length. The effect

of proppant size on permeability is illustrated in Figure 6.4

Figure 6.2: Effect of Fracture Length and Conductivity on Reservoir Productivity (Gidley 1989)

Figure 6.3– Effect of Depth on fracture conductivity as a function of proppant type (Gidley 1989)


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Figure 6.4 – Effect of Closure stress on Fracture conductivity for Various Proppant Types (Economides and Martin 2007)

Figure 6.5: Effect of proppant size (sand) on fracture permeability (Gidley 1989)


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In the Marcellus shale, proppant selection can be narrowed by first determining the anticipated

closure stress in the Upstate New York portion of the of the Marcellus shale and then eliminating those

Proppants whose compressive strength cannot withstand the closure stress. Figure 6.5 illustrate the

approximate depth from the surface to the Marcellus shale formation; in New York the depth to the

Marcellus shale ranges from just below 3000ft to just above 7000ft. Joel Star in his paper “Closure Stress

Gradient Estimation of the Marcellus Shale from Seismic Data” estimated the closure stress gradient in the

Marcellus shale to be approximately around 1.166 psi/ft (Starr 2011); variation in this value is

expected but based on the researchers findings most of the calculated closure stress gradient fell around

this value. Using this gradient, the anticipated closure stress in the Marcellus shale will range from

approximately 3500psi to 8500 psi (for the approximated depth of 3000 to 7000ft).

Figure 6.5: Approximate Depth to the Marcellus Shale

Using Figure 6.1 we see that the applicable categories of proppant are silica sand, resin coated

sand and ceramic proppants; sintered bauxite is not necessary as the closure stresses are well below the

recommended closure stress of 10,000 psi used for sintered bauxite. From the same figure it can noted


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that most of the silica sand proppant will be applicable for the closure stresses below 4000spi (ie depths

below 3430ft) whereas for closure stresses greater than 4000 psi (depths greater than 3430ft)

proppant selection will have to be in the categories of resin coated sand or ceramic proppant of which

there are numerous types to choose. Ultimately, when the final selection of the proppant is made, either

for the lower stress portions of the Marcellus shale (closure stresses less than 4000psi) or the high stress

regions (closure stress greater than 4000 psi), the selection will be made based on a compromise

between the fracture design (desired fracture width and effective length) and the cost of proppant and

anticipated return in reservoir performance (Economics of Proppant Selection). A generalized procedure

for proppant selection is presented in Figure 6.6.

Figure 6.6 – Generalized procedure for proppant selection


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6.3 ECONOMICS OF PROPPANT SELECTION

Optimizing fracture conductivity designs and by extension reservoir engineering economics is a

complex, intricate, and iterative process involving not only fracture propagation simulation but also

reservoir flow simulation. To achieve this goal, a comprehensive fracture-conductivity/reservoir-

performance study, which addresses the issue of fracture conductivity optimization and the resulting rate

of recovery and ultimate recoverable reserves and the economics of the different options must be

conducted. As is the case with proppant selection, no one approach is universal, hence such as analysis

will have to be done on a field-by-field basis if the formation properties and the economics of the

location vary widely.

Figure 6.7 illustrates the changes in cumulative gas production as a function of fracture

conductivity. However fracture conductivity is not limited to simply the fracture width and permeability of

the proppant pack; there are other numerous ancillary forces affecting these parameters. These include

but are not limited to the closure stress, physical properties of the proppant (grain size and size

distribution, roundness and sphericity, density), proppant concentration, movement of formation fines,

proppant embedment, proppant settling, gel residue plugging etc.

Figure 6.7 – Cumulative Gas Production as a Function of Fracture Conductivity


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The conductivity of a fracture and in turn the productivity of the reservoir is not merely based on

the proppant type selected. The factors affecting these system properties are numerous and interrelated;

the only plausible method of optimizing your fracture design by ensuring maximum conductivity at

minimum cost id to complete a fracture propagation and reservoir simulation modeling. The economics of

each design choice is then incorporated with these models ensuring the overall system is optimized. Over

the last couple of years, some researches have provided methods for design selection that incorporates

economics of the solution. A few of these approaches are presented below:

1. Cost efficiency (as a function of proppant type) versus closure stress. This is a modification of the

traditional conductivity-closure stress data that captures the cost of the proppant. This approach

was developed by Phillip and Anderson; the generated chart is presented in Figure 6.8.

2. Britt and Veatch presented an approach that plotted Net Present Value (as a function of matrix

permeability) Versus fracture penetration (Fracture length). This approach is illustrated in Figure

6.9.

3. Incremental present worth versus fracture conductivity and fracture half-length, which are the two

main factors that ultimately affect the performance of the reservoir. This approach is illustrated in

Figures 6.10 and 6.11. These curves are the output of a comprehensive fracture-

conductivity/reservoir-performance study; they are the tools needed to determine an appropriate

fracture-conductivity/length relationship required to maximize economic returns for a given

reservoir (Gidley 1989).


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Figure 6.8 – Cost per unit fracture area per unit of conductivity versus closure stress (Phillip and Anderson)

Figure 6.9 – Net Present Value vs. Fracture Length (after Britt and Veatch)


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Figure 6.10 – Incremental present worth vs fracture conductivit (Gidley 1989)

Figure 6.11– Incremental present worth vs fracture half-length (Gidley 1989)


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6.4 PROPPANT SELECTION: UPSTATE NEW YORK MARCELLUS SHALE

The output of this engineering assessment of the proppant type most suitable for the Marcellus

Shale in Up-State New York was based on the determination of the closure stress in the formation. The

calculated closure stresses range from approximately 3500 psi to 8500 psi. Using this information the

formation was divided into two major categories: portions of the formation with closure stresses greater

than 4000psi and portions of the formation with closure stresses less than 4000psi. The respective

categories of proppant that can function effectively in these environments were then identified. The

calculations, in addition to the selected proppants, are outlined below. However it must be stressed that

the proppants selected do not represent the required proppants for an optimized fracture design (from

both a productivity and economics standpoint), they merely represent the type/category of proppants

that can function effectively within the magnitude of closure stress identified; optimized designs are

reservoir specific and can only be effectively done through the analysis of the output of a combined

fracture propagation-reservoir flow simulation and economic model.

6.4.1 Closure stress Calculation

Closure stress Gradient = 1.166 psi/ft (Starr 2011)

Depth to top of formation = 3000 ft to 7500 ft

Formation thickness = 50ft to 150ft

Depth to center of formation = 3075ft to 7075

Closure stress = Depth x stress gradient

Closure stress = 3585 psi to 8453psi


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6.4.2 Proppant Type Selection

Using the calculated fracture closure stress data, the following proppant selection was made:

For closure stress below 4000 psi :

1. Frac sand - $0.08 - 0.10/lb

2. Lightweight proppant - $0.20/lb

Closure stresses (>4000psi & < 9000psi):

1. Resin coated sand – $0.35/lb

2. Ceramic - $0.40/lb

3. ISP – $0.45/lb

It must be mentioned again that the proppants selected do not represent the required proppants

for an optimized fracture design (from both a productivity and economics standpoint); the selection

merely represent the type/category of proppants that can function effectively within the magnitude of

closure stress identified The fracture design can only be optimized viz a vie tradeoffs between the cost

for fracture design (which is a function of the fracture fluid, treatment size, volume of proppant used and

type of proppant selected) and the resulting reservoir performance; optimization is not merely based on

the type of proppant used in the fracturing process.


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CHAPTER 7 | ECONOMIC ASSESSMENT

7.1 DEVELOPMENT OF CASH FLOW MODEL AND PRODUCTION MODEL

In order to assess the potential for profitable shale gas production in New York a cash flow

model was applied to the proposed shale gas production from a hypothetical shale reservoir. This

hypothetical simulation served the purpose of displaying the potential profit a gas producer could expect

to receive were the moratorium on drilling lifted and production allowed in the portion of Marcellus shale

extending into New York. In the development of the cash flow model a trend of conservatism was

followed in assumption made so as not to overstate the economic feasibility of our proposed

environmentally safe production options. The economic assessment can thus be broken down into distinct

stages. The first stage was comprised of the development of a proposed reservoir consisting of a

designated number of production wells. The field size could then be based off of the assumed number of

wells in a manner which would stay in line with the conservative nature of the model. The potential

revenue could thus be generated from a determination of the gas production and an assignment of the

cost of gas for the period of time in which the model is run. This represents the inflow and ultimately

determines the total revenues expected from the producers investment in the field

7.1.1 Field Size & Well Development

The region of interest through which the Marcellus Shale extends into upstate New York shares a

border with a region in northern Pennsylvania which has substantial shale gas development and

production, particularly the northeastern region. The proximity of our region of interest to this area in

Pennsylvania allows for some comparisons and predictions to be made based on the similarity in region

topography, reservoir characteristics, and land use. During 2008 52 Marcellus wells were drilled in five

counties in northern Pennsylvania: McKean, Potter, Tioga, Bradford, and Susquehanna, counties which all

share a direct border with New York. The following year in 2009, 296 wells were drilled within the same

aforementioned counties. The rapid growth of shale gas development in the region which is depicted in


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Figure 7.1 can be used as an indicator for the potential rate of well development in the upstate New

York region.[ Considine, Watson & Considine]

Figure 7.1: Northern Pennsylvania Marcellus Drilling and New York State

Initial drilling in the upstate New York region would be limited for various environmentally,

politically, and logistically driven reasons. As the Marcellus shale play extends northward into New York,

the geologic total vertical depth to bottom decreases. This decrease in reservoir depth indicates that the

depths to the shale gas pay zones a producer would need to drill to in New York State are closer to the

surface than in other regions of the Marcellus. A desire to avoid the New York City watershed is another

contributing factor in determining the extent of well development and growth. Chesapeake Energy, a

major producer in the Marcellus shale play, for instance declared in 2010 that it has no intent to drill in

Delaware County due to the fact that this county contains a portion of the water shed. New York State's

Department of Environmental Protection predicts, the maximum number of wells drilled in the region of

the Marcellus extending into New York in any single year would be 500 for the aforementioned reasons.

Based on the trajectory of well development in northern Pennsylvania, and the observed ratio of vertical

to horizontal wells it is predicted that 14 horizontal wells could be drilled within the first year of the lift

on the moratorium on drilling in New York. For the sake of simplicity this designated number of wells

could be assumed to be attributed to a single hypothetical producer in the region. Vertical wells were not

accounted for as the focus of this model is to predict the economic impact from the hydraulic fracturing

procedure associated with horizontal drilled wells.


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In most states including New York rig spacing is regulated and enforced in order to satisfy

environmental concerns and to protect land owners collectively leasing land to producers. Often no single

land owner owns the sufficient land necessary for a producer to fully develop a reservoir and thus

multiple land owners are often involved in the negotiation of land leasing for the proposed drilling

venture. The minimum rig spacing enforced in most states is 640 acres and thus this value was used for the

purpose of determining a prospective reservoir field size. New York enforces compulsory integration and

utilization in regards to land ownership. Thus the minimum 640 acre rig spacing can be assumed to be

applied regardless of specific gas leasing agreements with individual owners, and owners who choose to

holdout on leasing land. [http://www.dec.ny.gov/energy/1590.html]. Although up to 3.5 wells on

average are drilled per operating rig in the Marcellus, our model assumed 1 well per rig in order to

maintain a conservative evaluation of the costs associated with land leasing by overestimating the

proposed acreage of land leased. [ Considine, Watson, Blumsack]. These parameters would lead to our

proposed field size of 8,960 acres; a value which must be restated is conservative in nature. The

summary of our proposed reservoir field can be found displayed in Figure 7.2.

Figure 7.2: Hypothetical Reservoir Field Description

7.1.2 Decline Curve Analysis

Quite possibly the most significant step in determining the economic feasibility for shale gas

production in our hypothetical reservoir, was the prediction of the amount of natural gas which could be

produced over time. Historical data on well production for horizontal wells active in the Marcellus shale

are difficult to come by as this information would be considered proprietary. Despite this lack of

production information it is known that all wells will experience significant declines in productivity over

Vertical Horizontal

No.$of$Drilling$Rigs 14

Total$Field$Size(Acres) 8960

Hypothetical$Reservoir$Field$Description

0 14

No.$Wells$per$Rig

No.$of$Wells

Acres$per$Rig

1

640


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time. Shale gas wells experience production declines due to the low permeability characteristics of shale

deposits and the low concentration of gas, spread over large areas. Wells typically found in the

Marcellus Shale will experience a production decline rate of approximately 65-85 percent within the first

twelve months with subsequent declines in production throughout the remaining life of the well (Considine

2010). Although there is a lack of tangible data relating to the long-term performance of shale gas

wells, data is available on initial rates of production, annual well decline rates, and the type of reservoir

decline characteristics observed in the Marcellus. The available data allows for decline curve analysis to

be performed allowing for a curve capable of predicting production decline over time to be fitted to

initial production values.

Decline curve analysis is widely used in industry in order to evaluate the potential of either

producing wells or even reservoirs, particularly when there is not much information available. The

prediction of future well/reservoir performance based and modeled off of the trend of declining past

production serves as the fundamental basis behind the analytical technique. Three equations

representative of exponential, hyperbolic, and harmonic production declines developed by Arps are the

most commonly used in industry today. A hyperbolic decline equation was chosen in order to assess the

potential gas production over a period of 15 years for the cash flow model. The equation used is

presented below.

!! = !!!

1 + !×!!×!! !

!! = production!at!time!!!(!!"#!"# )!

!! = initial!production!rate!(!!"#!"# )!

!! = initial!decline!rate!(!"#$!!)!!! = b!exponent!term!!!! = time!(!"#$)

Production at any time can be calculated given that the initial production rate, initial production decline

rate, and b exponent term are known for the well of interest. The b exponent term is defined as the time

rate change of the reciprocal of the decline rate and must maintain a constant value between 0 and 1 in

order for the curves to hold any practical sense and for the resulting predicted production rate to hold


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any meaningful value. This b exponent term, unlike the !! !&!!! ! terms, is not dependent on the initial shale

gas production and instead is an independently determined variable which characterizes the severity of

the production decline in the curve. Larger values of the b exponent term characterize curves with more

aggressive downward slopes while lower values indicate a curve with a moderate downward slope

[Poston and Poe].

Shale gas wells are most effectively represented by hyperbolic curves for the following reasons.

[Engelder, Terry]

! Horizontal well has access to the unbounded reservoir in the vertical direction

! Formation fractures allow access to large reservoir volume

! Drainage is more complete in the naturally fractured Marcellus shale

The chosen values for the initial annual decline rate and b exponent term were selected based off

of the decline curve analyses performed by various producers in the Marcellus Shale including

Chesapeake Energy and Range Resources. The value of .9 selected reflects the steep production declines

observed in wells in the Marcellus shale. The initial production rate of wells coming on production in the

Marcellus shale is quite variable and thus three different production decline curves were created

representing a optimistic, average, and conservative estimation for our proposed shale gas production.

The values used represented the P20, P50, and P80 30 day initial production rate. The P20 initial

production rate represents the rate equaled or exceeded by 20% of wells completed in 2009 in the

Marcellus shale while the P50 and P80 production rates equal the production equaled or exceeded by

50% of wells and 80% of wells respectively. The resulting decline curves can be seen below as Figure

7.3, Figure 7.4, and Figure 7.5 respectively


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Figure 7.3: Optimistic decline curve based on P20 initial production

Figure 7.4: Moderate decline curve based on P50 initial production


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Figure 7.5: Conservative decline curve based on P80 initial production

Based on these decline curves the yearly gas production for the 15 year time frame of interest was

modeled after the moderate decline curve. The yearly shale gas production rate per year can be seen

below in Figure 7.6

Figure 7.6: Yearly shale gas production rate predicted by moderate decline curve

Year Production-(MMcf/D)1 3.5002 2.0343 1.4154 1.0765 0.8656 0.7207 0.6158 0.5369 0.475

10 0.42511 0.38412 0.35113 0.32214 0.29815 0.277


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The total gas production in a given year could thus be calculated by assuming year round production and

accounting for the fact that the predicted production applies to all 14 wells in the proposed reservoir.

The total gas production is depicted below in Figure 7.7

Figure 7.7: Total proposed annual Shale Gas production

7.1.2 Gas Price

The wellhead price of gas which represents the price per volumetric unit of natural gas a

producer charges before costs associated with gathering, transportation and refinement are included has

seen a marked drop from the high prices observed in the year 2008 and before. (Federal Energy

Regulatory Commission, 2010) From 2008 to 2009 average wellhead gas prices from the lower 48

average dropped more than 50%, falling from the price of $8.18 per Mcf seen in 2008 to $3.71 per

Mcf in 2009. (EIA, 2013) This decline was spurred by the downturn in the US economy and although gas

prices along with other energy related commodity prices dropped, gas prices have been on the steady

rebound. The EIA projects that gas prices will continue to increase gradually over the next 15 years to

$5.73. For our cash flow model a blanket natural gas price of $4.15 per Mcf, the current natural gas

price, was assessed for the determination of our predicted yearly revenues from the proposed shale gas

production. When the gas price outlook as predicted by the EIA is factored in, this value of $4.15 per

Year Total)Annual)Gas)Production)(MMcf)1 17885.002 10392.623 7228.284 5500.225 4417.936 3679.337 3144.638 2740.479 2424.77

10 2171.6711 1964.4512 1791.8313 1645.9114 1521.0315 1413.00


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Mcf, can be considered conservative and would be expected to underestimate the revenues a producer

could expect to see.


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7.2 ECONOMIC MODELING OF PRODUCTION VIABILITY

This section presents a profitability analysis of hydraulic fracturing operations in New York.

Having obtained a characterization of the rate of gas production, field size characteristics, gas prices,

and costs associated with various flowback water treatment methods, the primary objective of this

analysis is to ascertain the degree to which hydofracking ventures in New York may be profitably

pursued. This is achieved through a twofold approach:

• Economic modeling of the baseline operation of a typical shale gas prospecting firm,

without implementing flowback water treatment enhancements.

• Viability assessment of shale gas prospecting operations, in the presence of more costly

flowback treatment options.

The results of this analysis will provide information as to whether shale gas development in New York is

practicable on a feasible basis, with implementation of less environmentally impactful production

techniques.

7.2.1 Metrics of Profitability

This analysis primarily utilizes cash flow analysis in assessing the profitability of hydrofracking

operations. The development of this cash flow model involves evaluating the cumulative difference

between “in-flow” and “out-flow” of cash experience by the typical firm, which is discounted annually to

account for inflation.

Cash flow modeling proves a suitable metric in this feasibility analysis because in addition to

providing information on the expected cash in hand each year, it allows for the determination of other

profitability indices used to compare across different scenarios. These include

• Payout time: The number of years required for the firm to break even, i.e. accrue positive

profit.


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• Net Present Value (NPV): The net cash-in-hand obtained by the firm at the end of

operations, valued in current monetary terms.

• Profit-to-Investment Ratio: The ratio of capital investments to the NPV at the end of

operations.

The analysis will utilize these metrics in comparing across the aforementioned production scenarios

to assess the degree to which they are economically viable.

7.2.2 Baseline Cash Flow Model

This cash flow analysis evaluates the baseline in-flow and out-flow characteristics of the typical

shale gas producing firm by drawing from estimates of operation economics currently experienced by

similar firms in the Marcellus Shale. This characterization excludes the proposed flowback treatment

enhancement options.

The following characteristics are taken into account in the development of the cash flow model:

• Net Receipts

• Operating Costs

• Tax Allowances

• Taxes

A. NET RECEIPTS

The first step in the development of the cash flow model is to determine the net cash receipts after

sales each year. This value is simply the difference between the annual gross receipts obtained, and the

royalty payments made to the landowner.

The gross receipts represent the product of the total gas production and the prevailing well head

gas prices each year. It is the initial revenue obtained through the sale of produced gas.

Royalty payments are defined as “reservations to the lessor (landowner) of a certain portion of

the oil or gas found and extracted, or of the proceeds from the sale, at no cost to the lessor” (Kergel,


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2011). They are paid in addition to the lease acquisition costs, to be discussed in the next section. In New

York, royalties are typically assessed at 12.5% of gross receipts (Kergel, 2011).

B. OPERATING COSTS

After determining the net receipts, the next step in the cash flow analysis is to determine the baseline

operating costs incurred by the typical shale gas prospecting firm at various yearly intervals. For

simplicity, the analysis assumes that all the wells are drilled within the first year. These costs are discussed

as follows,

• Lease Acquisition and Bonus: In addition to royalties, the firm must incentivize the

landowner by offering a signing bonus. In the Marcellus Shale leases typically last for

five-year periods (Durman, 2012). Also, lease bonus payments in the Marcellus usually

range between a few hundreds and $10,000 per acre, with an average of $2700 per

acre (Hefley & Seydor, 2011).

For our predetermined hypothetical field size of 8960 acres, this leads to an estimated

baseline lease bonus cost of $24.19m. This cost occur three times during the 15-year field

lifetime, at the aforementioned five-year intervals.

• Site Preparation and Permitting: Drilling activities in the Marcellus Shale generally

require purchasing permits and posting bonds for each well drilled, as a means for the

state to monitor drilling activities and environmental impacts. On average these costs

would amount to about $5,000 per well (Durman, 2012).

After obtaining these, additional steps are usually taken to prepare the site for drilling.

These include construction of roads, stripping and leveling of the land, laying of rocks for

drilling pads, and making provisions for erosion control. These preparation measures

typically cost about $400,000 per well (Durman, 2012).

In the case of our hypothetical 14-well field, site preparation and permitting fees sum up

to $5.6m. These costs are incurred only once during operations.

• Drilling Costs: These costs are incurred during drilling and completion processes involved

in shale gas prospecting. On average, they sum up to approximately $2.4m per well, as

observed in Marcellus Shale (Considine, Watson, & Blumsack, 2010).


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Drilling costs may be classified into intangible and tangible drilling costs. Tangible drilling

costs, like drilling equipment, are known to offer salvage value. On the other hand,

intangible drilling costs do not offer salvage value. Examples include labor, cost of

chemicals and proppants. Tangible and intangible drilling costs typically amount to about

25% and 75% of drilling costs, respectively (Durman, 2012).

Based on this estimate, our hypothetical 14-well field would incur total drilling costs of

approximately $33.6m, which would also be a one-time cost. Therefore, tangible and

intangible drilling costs would amount to $8.4m and $25.2m, respectively.

• Capital Investment: Capital investments pertaining to shale gas exploration in the

Marcellus Shale would include pipeline infrastructure, facilities development and

equipment. These typically cost about $980,000 per well (Considine, Watson, & Blumsack,

2010).

Again, in the case of our hypothetical field, this would yield an estimated one-time

payment of $13.72m.

• Lease Operating Costs: These costs are those incurred in the day-to-day production of

natural gas, following drilling and completion activities, including labor, well maintenance,

materials and supplies, administrative costs, among others. They represent the primary

recurring annual cost incurred throughout the lifetime of the well. Lease operating costs

are often denoted in terms of per-unit production, with an average of $0.7 per Mcf of

production in the Marcellus Shale (Durman, 2012).

In the baseline scenario, the cash flow analysis applies this value to the gas production, as

characterized by the aforementioned decline curve model, in order to estimate the annual

lease operating costs. These yearly outflows are shown in Appendix i

Figure 7.8 summarizes the baseline costs accounted for by the cash flow analysis and how frequently they

occur.


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Cost/Rate Frequency Royalties 12.5 % of Gross Receipts Annual Lease Acquisition & Bonus $24.19m 5 years Site Preparation & Permitting $405,000 Once Intangible Drilling Costs $25.2m Once Tangible Drilling Costs $8.4m Once Capital Investments $13.72m Once Lease Operating Costs $0.7/Mcf of Production Annual

Figure 7.8: Summary of Costs

C. TAX ALLOWANCES

Having characterized costs typically incurred by a shale gas prospecting firm, the next pivotal

step is to determine what portion of the net income would be available for taxation. These non-cash costs

are then subtracted out from the net income before applying state and federal income tax rates. Natural

gas prospecting industries usually benefit from the following tax allowances (Durman, 2012):

• Depreciation: Tangible drilling costs are allowed to be depreciated over a seven-year

period, based on Modified Accelerated Cost Recovery System (MACRS) from the US

Internal Revenue Service (IRS) (Internal Revenue Service, 2012). This entails subtracting a

predetermined percentage of tangible drilling costs from the taxable income from the first

year to the eighth year of production. The baseline yearly depreciation deductions

pertaining to our hypothetical field are tabulated in Figure 7.9

Year 1 2 3 4 5 6 7 8 Percentage 14.29% 24.49% 17.49% 12.49% 8.93% 8.93% 8.93% 4.46% Depreciation $1,200,360 $2,057,160 $1,469,160 $1,049,160 $750,120 $749,280 $750,120 $374,640

Figure 7.9: Seven-year MACRS Depreciation Schedule

• Depletion: Tax allowances are typically provided to natural gas prospecting firms in the

Marcellus Shale, to account for the depletion of lease-related costs, including lease

acquisition expenses and lease operating costs. There are two methods of calculating

depletion: statutory and cost-based depletion. The latter has been applied to this cash flow


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analysis, with the assumption that the firm is an integrated energy company, considering

that statutory depletion is only available to independent producers (Durman, 2012).

The cost-based method determines how much depletion may be accounted for on a per-

unit basis of gas production. It takes into account the following factors (Durman, 2012):

o Number of units of gas produced each year, as predetermined from the previously

discussed production decline model;

o Unrecoverable depletable costs at the end of the year, which is defined as the

“original leasehold cost, plus lease operating costs, less the value at the end of

operations, less the cumulative depletion deducted in previous years” (Durman,

2012).

o Remaining units of gas available at the beginning of the year, which is obtained as

the difference between the total estimated gas and the cumulative production to

each year.

Based on these parameters, cost-based depletion is calculated based on the following

expression,

!"#$!!"#$"%&'( =

!""#$%!!"#$%!!"#$ ∗ !"#$%&'$#()*$!!"#$"%&'$"!!"#$#!!"!!ℎ!!!"#!!"!!ℎ!!!"#$(!"#$%&#'(!!"#$%&%&'!!"#$%!!"!!ℎ!!!"#$"!!"!!ℎ!!!"#$)

The results of this cost-based depletion analysis for each year throughout our the economic

lifetime of hypothetical field are shown in Appendix i

D. TAXES

Having determined the cost incurred during the economic lifetime of the field, as well as the tax

allowances typical firm would be eligible for, the final outflows accounted for by the cash flow model

are state- and federal-level annual taxes.


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• New York State Taxes: At state and municipality level, natural gas prospecting firms in

New York are accountable for real property tax, sales tax and corporation income tax

(Kent, 2011).

o Real Property Tax: New York State employs the unique Unit Production Value

(UPV) system in assessing real property taxes. This system is based on economic

profiles reflecting average income, expenses, and operating data for the five

calendar years preceding the year in which the UPVs are to be certified.

Production costs and revenues are compiled in each of the four natural gas

producing regions in the state, including dry hole costs, depreciation, tangible

capital investments, overriding royalty interests and depletion (Kergel, 2011).

These figures are used in setting the UPV to determine the assessed value of

production. Finally, this assessed value receives the per-unit of production tax rate.

The average UPV for all four regions in New York in the 2011 has been

determined to be $11.19/Mcf, with an average tax rate of $29.40/1000 cubic

feet of production (Ecology and Environment, Inc., 2011). These figures have been

applied to the cash flow analysis in each year of production, based on postulated

gas produced, with the assumption that it remains approximately constant through

the life of our hypothetical field.

o Sales Tax: In addition to real property tax, a 4% rate is applied annually to the

gross receipts in form of sales taxes (Kent, 2011).

o Corporation Income Tax: Also, a state corporation income tax rate of 6.5% is

typically experienced by natural gas producing firms in New York, which is

applied annually to the firm’s taxable income (Kent, 2011).

• Federal Income Tax: This is determined based on the federal income tax schedule from

the IRS, displayed in Figure 7.10. Income taxes applied to the taxable income are

determined based on the following formula (Durman, 2012):

!"#"$%&!!"#$"#%&'!!"#$%&!!"# =

!"#$!!"# + !"#!!"#$ ∗ (!"#"$%&!!"#$%& − !"#$%!!"#$%!!"!!"#!!"#$%&')

The annual taxes assessed in our baseline cash flow analysis are presented in Appendix i


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Figure 7.10: 2012 US Federal Income Tax Rate Schedule (Durman, 2012)

The cash flow analysis consolidates all theses factors by deducting the above listed costs and

taxes incurred each year from the net receipts, in order to determine the net cash flow. This annual net

cash flow is discounted at a common rate of 17.5%, which is based on statutory factor intended to

account for variables such as risk, non-liquidity, intangibles, and taxation (Kergel, 2011). Finally, a

cumulative cash flow characterization of our hypothetical natural gas prospecting firm in New York is

obtained by iteratively summing the cumulative net cash each year. Figure 7.11 shows the results of the

cash flow analysis of the field under study, in the baseline operation scenario.

Figure 7.11: Baseline Cash Flow Model

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Appendix i contains spreadsheets characterizing this operation for the lifetime of the field. It is

important to note that the “dips” in cumulative cash at five-year intervals correspond to the cost of

renewing the land lease, as previously discussed. This baseline cash flow analysis yields the following

metrics of profitability:

• Payout time: 3 years

• Net Present Value (NPV): $18.25m

• Profit-to-Investment Ratio: 1.33

These figures represent our estimates of the production economics associated with shale gas

prospecting in New York for a typical firm, without including the potential cost of implementing less

environmentally impactful production techniques. In the next phase of our economic analysis, these results

will be compared to four cases featuring the implementation of alternate flowback water treatment

methods, in order to assess the effect of their added costs on the viability of operations.

7.2.3 Cost of Flowback Treatment Options

In assessing the effects of different flow back water treatment options on the economic potential

of our proposed reservoir the same uniform assumptions were made and applied to each of the 14 wells.

Upper and lower limit boundaries were established for flow back volume metrics given the variable

nature from well to well. Given that the number of stages of treatment varies in the Marcellus shale

anywhere from 8 to 13 fracturing stages and the volume of fluid per stage ranges from 300,000 to

600,000 gallons the total volume for full hydraulic treatment can be said to range between 2.4 million to

7.8 million gallons. In the Marcellus Shale anywhere from 9% to 35% of the volume of water used for the

treatment is recovered as flow back water indicating that the total volume of flow back water a

producer could expect from a well producing in the Marcellus Shale would fall in the range of 216,000

to 2.7 million gallons. EPA (2012) The arithmetic mean of these two values was then calculated and

applied as the value for our proposed flow back volume. Similar to gas an oil production, the volume of

flow back water produced follows a decline which can be modeled however this decline is far more

rapid than the annual decline experienced by the concurrent gas production. In addition the decline can


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be observed to level off to a constant value fairly quickly after the initial rapid decline. For this reason a

decline in flow back of 50% was assessed for each well after the first year of production, and a flat

flow back rate assigned to each year after. The costs for the different options were calculated and

assessed. (Galusky & Hayes, 2011)

• Option 1: Disposal into Injection wells

$.3 -$10.00 per barrel with average costs falling below $1.00

Average price of $1.00 per barrel flowback water assigned per well

• Option 2: Centralized Water Treatment

$0.045/gal to $0.055/gal

Average price of $.050 per Gallon of flow back water assigned per well

• Transportation Cost

Transport Truck capacity: 110 barrels assigned

Average transportation time: 3.5 to 4.5 hours, 4.0 hours assigned

Transportation Cost: $75-$90 per hour, $82.5 per hour assigned

With the first two treatment options transportation costs associated with the transport of the flow

back water from the well either to the injection well site or to the necessary water treatment needed to

be accounted for as the costs associated with relocating the flow back water exceed the actual cost

associated with treating the flow back volume. The number of trucks required to handle the annual flow

back volume was determined based on the truck capacity. The average time for transportation was then

applied to calculate the required man hours necessary to transport the water. The total cost was then

calculated as the cost for each option was then calculated as the combined cost for transportation and

treatment of the volume of flow back water for each year of the model. (Puder & Veil, 2006)

• Option 3: Mobile on-site Treatment

$1.25- $2.00 per barrel

Average Price of $1.62 per barrel of flow back water assigned per well

• Option 4: Stationary on-site Treatment and Recycling

Cost for physical separation unit - $300,000


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Cost of chemical separation unit - $450,000

Proposed system capacity is 1041 gallons/Hour

Ion exchange – $60 K/1000 gallon/Hour

Reverse Osmosis - $71K/1000 gallons/Hour

Total cost for facility development assessed in first year- $823,900

The advanced treatment cost associated with reverse osmosis was selected as this cost provided the more

conservative option for our cash flow model by exaggerating the potential cost associated with this

treatment option.

7.2.4 Cash Flow Analysis of Flowback Treatment Alternatives

In this section, the cash flow analysis framework developed for the baseline production case will

be utilized in assessing the effect of earlier discussed flowback treatment options. This will involve

observing the impact of previously delineated costs associated with these treatment options on the cost

categories in Figure 7.8 and how they ultimately affect the baseline production economics.

A. TREAMENT OPTION 1: INJECTION INTO WELLS

With this treatment option, based on earlier discussed associated costs, the additional cost per

well will amount to approximately $46,300 per well, yielding a total $648,200 over the lifetime of the

field. Also, total transportation costs of approximately $138,900 per well sum up to $1.94m in

transportation costs. Therefore the final cost of this treatment option over the lifetime of the field is

estimated at $2.59m.

This cost will be incurred annually throughout the operation, and thus would add to the lease

operating cost. Therefore, it would also be accounted for in the depletion accounting. Figure 7.12 shows

the cash flow characteristics resulting from this additional cost of flowback treatment by injection into

wells.


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Figure 7.12: Cash Flow with Flowback Treatment Option 1

The profitability metrics from this analysis are:




Though we observe a slight decline in NPV and profit-to-investment ratio from the baseline case,

the payout time remains the same. The full analysis is tabulated in Appendix ii

B. TREAMENT OPTION 2: CENTRALIZED WATER TREATMENT

This case is similar to that of the option in terms of the pertinent cost categories considered. Firstly,

the standalone cost of this treatment option per well as previously been estimated at $72,900 per well

and $1.02m for our 14-well hypothetical field. Assuming similar total transportation costs as derived in

option 1 above, the additional cost of centralized water treatment over the operation period amounts to

approximately $2.96m.

As is the case with option 1, this additional cost will be experienced annually and would thus be

considered as a lease operation cost. Figure 7.13 shows the cash flow after considering cost of

centralized flowback treatment.

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The profitability metrics resulting from this cash flow model are:




Again, we observe relatively insignificant drops in NPV and profit-to-investment ratio from the

baseline production scenario, with no change in payout time. The full analysis is tabulated in Appendix iii

C. TREAMENT OPTION 3: MOBILE ON-SITE TREATMENT

In the case of mobile on-site flowback water treatment, no transportation costs are incurred. The

additional costs associated with this option have been estimated to be $74,980 per well, which leads to

a total lifetime cost of approximately $1.05m for the field under study.

Once again, this cost will be spread out annually. Thus, they will be considered as lease operating

costs. The cash flow model Figure 7.14 takes into account the cost of mobile on-site flowback water

treatment.

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The following profitability metrics have resulted from this analysis:




As observed in the above cases, the cost of water treatment has no significant impact on the

production economics. The full analysis is tabulated in Appendix iv

D. TREAMENT OPTION 4: STATIONARY ON-SITE TREATMENT

In this case, the bulk of the costs are incurred on the first year as addition capital investments. As

earlier discussed, these costs would be composed of physical and chemical separator costs of $300,000

and $450,000 respectively, as well as an estimated cost of $73,900 for the reverse osmosis bioreactor.

This yields a total additional capital investment cost of approximately $823,900.

The cash flow model Figure 7.15 takes into account the cost of mobile on-site flowback water

treatment.

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The profitability indices in this case are:




This case follows the trend observed with the previous three options, whereby the additional cost

incurred has no significant impact on the NPV and profit-to-investment ratio, with the payout time

remaining unchanged. The full analysis is tabulated in Appendix v

7.2.5 Summary of Cash Flow Analysis

The above cash flow models have been proposed as means to characterize the production

economics that would be observed by a typical gas prospecting firm in the New York Marcellus Shale,

and also to evaluate the effect of the cost of various environmentally-friendly flowback treatment options

on the viability of operations.

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From the results of the cash flow analysis, as summarized in Figure 7.16, we observe that none of

the proposed flowback treatment options displays significant impacts on the viability of the venture. This

is apparent in the constant expected payback period in each case and the generally limited variations in

NPV and profit-to-investment ratio.

Baseline Option 1 Option 2 Option 3 Option 4 Payout time (yrs) 3 3 3 3 3

NPV ($) 18.25m 17.50m 17.39m 17.95m 17.74m Profit-to-Investment Ratio 1.33 1.28 1.27 1.31 1.22

% Difference Option 1 Option 2 Option 3 Option 4 NPV -4.29 -4.95 -1.67 -2.87

Profit-to-Investment Ratio -3.91 -4.72 -1.53 -9.02

Figure 7.16: Comparison of Results of Cash Flow Analysis


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CHAPTER 8 | SOCIO-ECONOMIC IMPACT ON UP-STATE NEW YORK

This chapter will discuss the socio-economic impact of high-volume hydraulic fracturing on New

York State. The socio-economic assessment will describe the impact of hydraulic fracturing of natural gas

horizontal wells on three aspects, which are, employment, economy, and government or state revenue and

expenditure. Three major assumptions were taken into consideration by the New York State Department

of Environmental Conservation to evaluate the impact of the above-mentioned technology on each of

these aspects. The assumption are related to volume and rate of development, time period needed to

complete development and produce the reservoirs, and finally, distribution of hydraulically fractured

natural gas well in the state of New York.

For the purpose of this evaluation, the rate of development is measured by the annual rate of

well construction. Based on information provided by the Independent Oil & Gas Association of New York

(IOGA-NY) , the DEC developed three different development scenarios which are low rate development

scenario, average rate development scenario, and high rate development scenario. In all of these

scenarios, it is assumed that 90% of wells drilled would be horizontal wells compared to 10% of

conventional vertical well. Also it is assumed that the low rate development is equal to 25% of the

estimated average rate development. In addition, all development is assumed to be done in 30 years at

which a rapid increase of development rate is observed during the first ten years compared to years 10

to 30 during which construction rate of natural gas wells becomes steady. As shown in figure 8.1 below,

by the end of year 30, a total of 9,461 horizontal wells and 1,071 vertical wells are assumed to be

constructed under the low development scenario. Moreover, a total of 37,842 horizontal wells and 4,284

vertical wells are assumed to be constructed in 30 years under the average development scenario.

Finally, based on the high development scenario, a total of 56,508 horizontal and 6,273 vertical wells

are assumed to be constructed by the end of the development time period. However, due to the

increasing costs of drilling natural gas horizontal well with high-volume hydraulic fractures further from

their ideal locations, and the drilling and fracturing restrictions around specific sensitive locations, the high

rate development scenario is unlikely to be achieved and hence not used in this assessment.


Page 107

Figure 8.1 – Estimates of low and average rate of development scenarios.

As stated earlier, both development scenarios would take a total of 20 years to be completed.

The number of constructed wells would grow annually during the first 10 years until it reaches a peak at

which the same number of wells is constructed in all years from year 11 to year 30. As shown in the

figure above, the estimated number of wells to be completed in the years 10 to 30 is a total of 371

horizontal and 42 vertical wells under the low scenario, and a total of 1,484 horizontal and 168 vertical

wells under the average development scenario.

It is also assumed the production life of each well is 30 years. With the first well drilled in year

one and the last one drilled in year 30, a typical shale gas field in New York State would produce of a

total of 60 years. After completion of the development by year 30, production rate of shale gas

reservoir would gradually decrease until year 60 at which all wells are assumed to seize to produce.

Finally, the DEC considered three specific regions were within possible areas of natural gas

development to measure the impact of high-volume hydraulic fracturing. The main factors for selection of

these three regions high, moderate, and low production potential, whether any forms of natural gas

development existed in the area or not, and differences in land use patterns. It is important to mention

that results of analysis is not restricted within these three regions, rather it is extrapolated on all regions

of New York State where it is possible to perform high-volume hydraulic fracturing of natural gas

development purposes. The areas selected are:

Region A: Broome County, Chemung County, and Tioga County

Region B: Delaware County, Otsego County; and Sullivan County

Region C: Cattaraugus County and Chautauqua County


Page 108

8.1 EMPLOYMENT

Development of natural gas reservoir in Marcellus Shale is expected to increase employment

rates by creating more job opportunities. As natural gas developers start drilling new vertical and

horizontal gas wells and perform high-volume hydraulic fracture treatments, the need for construction

workers and operating crew will rise significantly to accommodate the expected development scenarios

mentioned above. According to statistics collected and calculations made by the Marcellus Shale

Education and Training Center in Pennsylvania, construction of an average natural gas well using the

high-volume hydraulic fracturing requires 410 individuals working in 150 different occupations. The

amount of construction workers needed to construct one well is equal to 11.53 full-time equivalent (FTE)

workers. A FTE is defined as an employee working for eight hours a day for 260 days a year. Typically,

construction of a horizontal gas well with high-volume fracturing treatment would take between 3 to 4

months per well. In addition, operating such well requires approximately 354 person hours per year or

the equivalent of 0.17 FTE workers. On the other hand, the labor requirement to drill a vertical well with

fracturing treatment is calculated based on the ratio of depth of the vertical well compared to high-

volume hydraulic fracturing horizontal well. As a result, a ratio of 0.2777 was applied to the 11.53 FTE

labor requirement to estimate the overall labor requirements to construct a hydraulically fractured

vertical well in Marcellus Shale (NYSDEC 2011).

Based on the figures calculated by the Marcellus Shale Education and Training Center in

Pennsylvania, the volume of employment opportunities or job positions created by high-volume hydraulic

fracturing is projected on the entire State of New York. It is worth mentioning that the amount of

employment is directly linked to the annual rate of development (well construction). As shown in Figure

8.2 the US Bureau of Economic Analysis and New York State Department of Labor (NYSDOL) calculated

that the total numbers of construction jobs that will be created is 4,408 FTE workers and 17,634 FTE

workers to drill a total of 413 wells under the low rate development scenario and 1,652 wells under the

average rate development scenario. Similarly, the maximum labor requirements to operate the total

number of wells drilled under each development scenario are calculated to be 1,790 FTE and 7,161 FTE

under the low rate development and average rate development respectively. These figures correspond

to peak production period at year 30 before any of the wells stop producing by the end of its


Page 109

production life. As natural gas development increase, the secondary and tertiary support business

expand to meet the increased demand by the gas operators. Therefore, in addition to the direct

employment, high-volume hydraulic fracturing would also indirectly create additional employment in

additional sectors of the economy. The maximum numbers of indirect employment were calculated using

Regional Input-Output Modeling System. To calculate the total numbers, multipliers to the direct

employment figures for the natural gas industry from the US Bureau of Economic were used. The

proposed drilling is expected to generate a total of 7,293 FTE under the low rate development scenario

and 29,174 FTE under the average development scenario. As a result, high-volume hydraulic fracturing in

the State of New York would generate a total of 13,491 and 53,939 direct and indirect full-time jobs

under low development and average development scenarios respectively which represent 0.2% and

0.7% of New York’s labor force in 2010.

Figure 8.2 – Projected Total Employment in New York State From Each Development Scenario (NYSDEC 2011).

As stated earlier, development of natural gas with high-volume hydraulic fracturing would occur

on multiple stages. The rate of well construction would increase rapidly during the first ten years after

granting the lift of the ban until it reaches the maximum rate in year 10. However, years 10 to 30 would

observe a constant number of newly drilled wells per year. And finally, no construction would occur in

year 30 to 60 as all natural gas development would be completely done by year 30 and only operation

requirements have to be met. Therefore, total levels of employment would be highest between years 10

to years 30. Also, as shown in Figure 8.3 below, the level of direct and indirect employment would

decrease significantly as all construction is completed (NYSDEC 2011).


Page 110

Figure 8.3 – Projected Total Employment in New York State During Development (NYSDEC 2011).

8.2 ECONOMY

The increase of high-volume hydraulic fracturing operations, would not only affect the natural gas

industry in New York State, but would also have a substantial affect on other industries too. As

construction and operation of natural gas wells start, the demand for equipment, supplies, and personnel

increase significantly in shale gas regions. Therefore, industries that supply natural gas operators and

support the regions where natural gas development takes place would face a considerable increase in

demands for the products and services they provide. Furthermore, tertiary suppliers or industries that

supply and support the natural gas industry suppliers would experience a similar increase in demand for

their products. Therefore, high-volume hydraulic fracturing operations in the State of New York would

lead to a positive impact on the regional economies in the areas of natural gas development in specific

and New York State in general as a result of the expansion required to accommodate the increase in

demand for products and services of different business. It is worth to mention that the industries that


Page 111

would observe the highest increase in economic activity are real estate, scientific and technical services,

construction, and manufacturing industries. On the other hand, several industries will experience some set

backs due the natural gas development by high-volume hydraulic fracturing. Agriculture may decrease in

volume, as natural gas development would take productive agriculture land to be developed as well sites

or required infrastructure.

8.3 STATE REVENUES AND EXPENDITURES

In similarity to regional and state economy, high-volume hydraulic fracture would also lead to an

increase in state revenues. The expansion of natural gas development under state-owned land would

translate into a direct increase in revenue incurred by New York State in the form of lease payments. In

addition, the growth of income tax of natural gas developers and the increased economic activity

mentioned earlier would also boost state revenue. Also, royalty payments worth of 12.5% of for any

natural gas reserves extracted from under state-owned lands would be payable to the State of New

York.

Yet, expansion of high volume hydraulic fracturing has adverse effect on government or state

expenditures. Drilling natural gas wells throughout the Marcellus Shale region would have a substantial

affect on traffic. High volume hydraulic fracturing drilling would increase truck traffic to haul in

equipment and supplies in and out of well sites. Therefore, New York State would need to increase the

budget of road maintenance in order to minimize the deterioration of its road systems as a result of

increased traffic and hence insure road quality throughout their projected life. In addition, more firm

monitoring, oversight, and permitting procedures would also require the state to spend substantial funds

in order to protect human health and the environmental safety.

It is important to mention that the exact amount of state revenue and expenditures was not

calculated for the purpose of this study. At this point, the exact location of each well is not determined

and therefore, it is not possible to determine the exact figures of lease payments or royalties as natural

gas development might occur under private or state owned land (NYSDEC 2011).


Page 112

APPENDIX


Page 1

Appendix i: Baseline Cashflow Model

YEAR 1 2 3 4 5 6 7 8

2013 2014 2015 2016 2017 2018 2019 2020

Production Data Gas Rate (MMcf/D) 3.500 2.034 1.415 1.076 0.865 0.720 0.615 0.536

Annual Gas Production Rate (MMcf) 17,885.00 10,392.62 7,228.28 5,500.22 4,417.93 3,679.33 3,144.63 2,740.47 Price

Gas Price ($/mcf) $4.15 $4.15 $4.15 $4.15 $4.15 $4.15 $4.15 $4.15 Net Receipts

Gross Receipts $74,222,750 $43,129,362 $29,997,373 $22,825,922 $18,334,430 $15,269,223 $13,050,200 $11,372,957 Royalties (12.5%) $9,277,844 $5,391,170 $3,749,672 $2,853,240 $2,291,804 $1,908,653 $1,631,275 $1,421,620

Net Receipts After Royalties $64,944,906 $37,738,192 $26,247,701 $19,972,682 $16,042,626 $13,360,570 $11,418,925 $9,951,338 Costs

Lease Acqusition & Bonus $24,192,000

$24,192,000 Site Prep & Permit fees $5,600,000

Drilling & Completion Cost $33,600,000 Intangible Drilling Cost $25,200,000 Capital Investments $13,720,000 Lease Operating Costs (US $.70/mcf) 12,519,500.00 $7,274,832 $5,059,797 $3,850,155 $3,092,554 $2,575,531 $2,201,238 $1,918,330

Flowback Option Total Lease Operating Costs $12,519,500 $7,274,832 $5,059,798 $3,850,156 $3,092,554 $2,575,532 $2,201,238 $1,918,330

Tax Allowances Depreciation $1,200,360 $2,057,160 $1,469,160 $1,049,160 $750,120 $749,280 $750,120 $374,640

Depletion $6,370,238 $4,790,948 $5,062,510 $4,916,018 $4,705,021 $4,508,756 $4,346,458 $4,222,198 Net Taxable Income -$23,857,192 $23,615,252 $14,656,233 $10,157,348 $7,494,931 -$18,664,997 $4,121,109 $3,436,170

NY State Tax Assessed Value $200,133,150 $116,293,389 $80,884,482 $61,547,486 $49,436,692 $41,171,712 $35,188,370 $30,665,878

Real Property Tax $5,883,915 $3,419,026 $2,378,004 $1,809,496 $1,453,439 $1,210,448 $1,034,538 $901,577 Sales Tax $2,968,910 $1,725,174 $1,199,895 $913,037 $733,377 $610,769 $522,008 $454,918

Corporate Income Tax -$1,550,717 $1,534,991 $952,655 $660,228 $487,171 -$1,213,225 $267,872 $223,351 Net Cash Flow after NY State Tax -$31,159,299 $16,936,061 $10,125,679 $6,774,587 $4,820,945 -$19,272,990 $2,296,690 $1,856,324

Federal Income Tax -$10,594,162 $5,758,261 $3,442,731 $2,303,360 $1,639,121 -$6,552,817 $780,875 $631,150 Net Cash Flow after Federal Tax -$20,565,138 $11,177,800 $6,682,948 $4,471,228 $3,181,824 -$12,720,173 $1,515,816 $1,225,174

Tangible Drilling Cost $8,400,000 Non Cash Charges

Depreciation $1,200,360 $2,057,160 $1,469,160 $1,049,160 $750,120 $749,280 $750,120 $374,640 Depletion $6,370,238 $4,790,948 $5,062,510 $4,916,018 $4,705,021 $4,508,756 $4,346,458 $4,222,198 Discount

Final Net Cash Flow -$21,394,539 $18,025,908 $13,214,618 $10,436,406 $8,636,964 -$7,462,137 $6,612,393 $5,822,011 Cumulative Net Cash Flow -$21,394,539 -$3,368,631 $9,845,987 $20,282,393 $28,919,357 $21,457,220 $28,069,613 $33,891,624

Discount Rate

0.175 0.175 0.175 0.175 0.175 0.175 0.175 Discount Factor (1/(1+i)n)

0.85 0.72 0.62 0.52 0.45 0.38 0.32

Discounted Cash Flow -$21,394,539 $15,341,198 $9,571,476 $6,433,353 $4,531,163 -$3,331,762 $2,512,647 $1,882,816 Cumulative Discounted Cash Flow -$21,394,539 -$6,053,341 $3,518,134 $9,951,487 $14,482,650 $11,150,888 $13,663,535 $15,546,352


Page 2

YEAR 9 10 11 12 13 14 15

2021 2022 2023 2024 2025 2026 2027

Production Data Gas Rate (MMcf/D) 0.475 0.425 0.384 0.351 0.322 0.298 0.277

Annual Gas Production Rate (MMcf) 2,424.77 2,171.67 1,964.45 1,791.83 1,645.91 1,521.03 1,413.00 Price

Gas Price ($/mcf) $4.15 $4.15 $4.15 $4.15 $4.15 $4.15 $4.15 Net Receipts

Gross Receipts $10,062,786 $9,012,425 $8,152,474 $7,436,090 $6,830,541 $6,312,283 $5,863,959 Royalties (12.5%) $1,257,848 $1,126,553 $1,019,059 $929,511 $853,818 $789,035 $732,995

Net Receipts After Royalties $8,804,937 $7,885,872 $7,133,415 $6,506,578 $5,976,723 $5,523,248 $5,130,964 Costs

Lease Acqusition & Bonus

$24,192,000 Site Prep & Permit fees

Drilling & Completion Cost Intangible Drilling Cost Capital Investments Lease Operating Costs (US $.70/mcf) $1,697,337 $1,520,168 $1,375,116 $1,254,280 $1,152,139 $1,064,722 $989,102

Flowback Option Total Lease Operating Costs $1,697,337 $1,520,168 $1,375,116 $1,254,280 $1,152,139 $1,064,722 $989,102

Tax Allowances Depreciation Depletion $4,136,903 $4,092,495 $4,094,409 $4,155,301 $4,304,382 $4,620,391 $5,432,575

Net Taxable Income $2,970,697 $2,273,209 -$22,528,110 $1,096,997 $520,202 -$161,866 -$1,290,713 NY State Tax

Assessed Value $27,133,150 $24,300,973 $21,982,213 $20,050,564 $18,417,771 $17,020,349 $15,811,495 Real Property Tax $797,715 $714,449 $646,277 $589,487 $541,482 $500,398 $464,858

Sales Tax $402,511 $360,497 $326,099 $297,444 $273,222 $252,491 $234,558 Corporate Income Tax $193,095 $147,759 -$1,464,327 $71,305 $33,813 -$10,521 -$83,896

Net Cash Flow after NY State Tax $1,577,376 $1,050,505 -$22,036,159 $138,762 -$328,315 -$904,234 -$1,906,233 Federal Income Tax $536,308 $357,172 -$7,492,294 $47,179 -$111,627 -$307,440 -$648,119

Net Cash Flow after Federal Tax $1,041,068 $693,333 -$14,543,865 $91,583 -$216,688 -$596,794 -$1,258,114 Tangible Drilling Cost

Non Cash Charges Depreciation Depletion $4,136,903 $4,092,495 $4,094,409 $4,155,301 $4,304,382 $4,620,391 $5,432,575

Discount Final Net Cash Flow $5,177,971 $4,785,828 -$10,449,456 $4,246,884 $4,087,694 $4,023,597 $4,174,462

Cumulative Net Cash Flow $39,069,595 $43,855,423 $33,405,967 $37,652,851 $41,740,545 $45,764,142 $49,938,603 Discount Rate 0.175 0.175 0.175 0.175 0.175 0.175 0.175

Discount Factor (1/(1+i)n) 0.28 0.23 0.20 0.17 0.14 0.12 0.10 Discounted Cash Flow $1,425,137 $1,121,028 -$2,083,124 $720,533 $590,234 $494,450 $436,587

Cumulative Discounted Cash Flow $16,971,489 $18,092,517 $16,009,393 $16,729,926 $17,320,160 $17,814,609 $18,251,196


Page 3

Appendix ii: Cashflow Model for Treatment Option 1

YEAR 1 2 3 4 5 6 7 8 2013 2014 2015 2016 2017 2018 2019 2020






Lease Acqusition & Bonus $24,192,000 $24,192,000 Site Prep & Permit fees $5,600,000

Drilling & Completion Cost $33,600,000 Intangible Drilling Cost $25,200,000

Capital Investments $13,720,000 Lease Operating Costs (US $.70/mcf) 12,519,500.00 $7,274,832.19 $5,059,797.82 $3,850,155.50 $3,092,554.47 $2,575,531.57 $2,201,238.50 $1,918,330.17

Flowback Option 1 1,296,000.00 $92,571 $92,571 $92,571 $92,571 $92,571 $92,571 $92,571 Total Lease Operating Costs $13,815,500 $7,367,404 $5,152,369 $3,942,727 $3,185,126 $2,668,103 $2,293,810 $2,010,902

Tax Allowances

Depreciation $1,200,360 $2,057,160 $1,469,160 $1,049,160 $750,120 $749,280 $750,120 $374,640









Discount Rate 0.175 0.175 0.175 0.175 0.175 0.175 0.175 Discount Factor (1/(1+i)n) 0.85 0.72 0.62 0.52 0.45 0.38 0.32

Discounted Cash Flow -$22,194,301 $15,374,034 $9,582,995 $6,436,101 $4,530,197 -$3,334,122 $2,510,026 $1,880,503

Cumulative Discounted Cash Flow -$22,194,301 -$6,820,267 $2,762,728 $9,198,829 $13,729,026 $10,394,904 $12,904,930 $14,785,433


Page 4

YEAR 9 10 11 12 13 14 15 2021 2022 2023 2024 2025 2026 2027






Lease Acqusition & Bonus $24,192,000 Site Prep & Permit fees Intangible Drilling Cost Tangible Drilling Cost

Capital Investments Lease Operating Costs (US $.70/mcf) $1,697,337.33 $1,520,168.10 $1,375,116.09 $1,254,280.16 $1,152,139.39 $1,064,722.46 $989,101.56

Flowback Option 1 $92,571 $92,571 $92,571 $92,571 $92,571 $92,571 $92,571.43 Total Lease Operating Costs $1,789,909 $1,612,740 $1,467,688 $1,346,852 $1,244,711 $1,157,294 $1,081,673

Tax Allowances

Depreciation

Depletion $4,269,732 $4,230,591 $4,241,142 $4,315,173 $4,484,502 $4,834,835 $5,724,360 Net Taxable Income $2,745,297 $2,042,542 -$22,767,415 $844,554 $247,510 -$468,881 -$1,675,069

NY State Tax Assessed Value $27,133,150 $24,300,973 $21,982,213 $20,050,564 $18,417,771 $17,020,349 $15,811,495

Real Property Tax $797,715 $714,449 $646,277 $589,487 $541,482 $500,398 $464,858 Sales Tax $402,511 $360,497 $326,099 $297,444 $273,222 $252,491 $234,558

Corporate Income Tax $178,444 $132,765 -$1,479,882 $54,896 $16,088 -$30,477 -$108,879 Net Cash Flow after NY State Tax $1,366,626 $834,831 -$22,259,909 -$97,273 -$583,282 -$1,191,294 -$2,265,606

Federal Income Tax $464,653 $283,843 -$7,568,369 -$33,073 -$198,316 -$405,040 -$770,306 Net Cash Flow after Federal Tax $901,973 $550,988 -$14,691,540 -$64,200 -$384,966 -$786,254 -$1,495,300

Tangible Drilling Cost Non Cash Charges

Depreciation Depletion $4,269,732 $4,230,591 $4,241,142 $4,315,173 $4,484,502 $4,834,835 $5,724,360 Discount

Final Net Cash Flow $5,171,705 $4,781,579 -$10,450,398 $4,250,973 $4,099,536 $4,048,581 $4,229,061 Cumulative Net Cash Flow $38,301,333 $43,082,912 $32,632,515 $36,883,488 $40,983,024 $45,031,605 $49,260,666


Discounted Cash Flow $1,423,413 $1,120,032 -$2,083,311 $721,227 $591,944 $497,520 $442,297 Cumulative Discounted Cash Flow $16,208,846 $17,328,878 $15,245,567 $15,966,793 $16,558,737 $17,056,257 $17,498,554


Page 5

Appendix iii: Cashflow Model for Treatment Option 2

YEAR 1 2 3 4 5 6 7 8 2013 2014 2015 2016 2017 2018 2019 2020






Lease Acqusition & Bonus $24,192,000 $24,192,000 Site Prep & Permit fees $5,600,000 Intangible Drilling Cost $25,200,000 Tangible Drilling Cost $8,400,000


Flowback Option 2 1,482,300.00 $105,879 $105,879 $105,879 $105,879 $105,879 $105,879 $105,879 Total Lease Operating Costs $14,001,800 $7,380,711 $5,165,676 $3,956,034 $3,198,433 $2,681,410 $2,307,117 $2,024,209

Tax Allowances

Depreciation $1,200,360 $2,057,160 $1,469,160 $1,049,160 $750,120 $749,280 $750,120 $374,640












Page 6

YEAR 9 10 11 12 13 14 15 2021 2022 2023 2024 2025 2026 2027






Lease Acqusition & Bonus $24,192,000 Site Prep & Permit fees Intangible Drilling Cost Tangible Drilling Cost



Tax Allowances

Depreciation




Corporate Income Tax $176,338 $130,610 -$1,482,118 $52,537 $13,540 -$33,346 -$112,471 Net Cash Flow after NY State Tax $1,336,331 $803,828 -$22,292,073 -$131,203 -$619,934 -$1,232,558 -$2,317,266

Federal Income Tax $454,353 $273,301 -$7,579,305 -$44,609 -$210,777 -$419,070 -$787,870 Net Cash Flow after Federal Tax $881,979 $530,526 -$14,712,768 -$86,594 -$409,156 -$813,489 -$1,529,395







Page 7

Appendix iv: Cashflow Model for Treatment Option 3

YEAR 1 2 3 4 5 6 7 8 2013 2014 2015 2016 2017 2018 2019 2020









Flowback Option 3 524,880.00 $37,491 $37,491 $37,491 $37,491 $37,491 $37,491 $37,491 Total Lease Operating Costs $13,044,380 $7,312,324 $5,097,289 $3,887,647 $3,130,046 $2,613,023 $2,238,730 $1,955,822

Tax Allowances

Depreciation $1,200,360 $2,057,160 $1,469,160 $1,049,160 $750,120 $749,280 $750,120 $374,640












Page 8

YEAR 9 10 11 12 13 14 15 2021 2022 2023 2024 2025 2026 2027






Lease Acqusition & Bonus $24,192,000 Site Prep & Permit fees

Drilling & Completion Cost Intangible Drilling Cost



Tax Allowances

Depreciation




Corporate Income Tax $187,162 $141,686 -$1,470,627 $64,659 $26,635 -$18,603 -$94,015 Net Cash Flow after NY State Tax $1,492,022 $963,157 -$22,126,778 $43,168 -$431,577 -$1,020,493 -$2,051,779

Federal Income Tax $507,288 $327,473 -$7,523,104 $14,677 -$146,736 -$346,968 -$697,605 Net Cash Flow after Federal Tax $984,735 $635,684 -$14,603,673 $28,491 -$284,841 -$673,525 -$1,354,174







Page 9

Appendix v: Cashflow Model for Treatment Option 4

YEAR 1 2 3 4 5 6 7 8 2013 2014 2015 2016 2017 2018 2019 2020









Flowback Option 4 $823,911 Total Lease Operating Costs $12,519,500 $7,274,832 $5,059,798 $3,850,156 $3,092,554 $2,575,532 $2,201,238 $1,918,330

Tax Allowances

Depreciation $1,200,360 $2,057,160 $1,469,160 $1,049,160 $750,120 $749,280 $750,120 $374,640




Corportate Income Tax -$1,604,272 $1,534,991 $952,655 $660,228 $487,171 -$1,213,225 $267,872 $223,351 Net Cash Flow after NY State Tax -$31,929,656 $16,936,061 $10,125,679 $6,774,587 $4,820,945 -$19,272,990 $2,296,690 $1,856,324








Page 10

YEAR 9 10 11 12 13 14 15 2021 2022 2023 2024 2025 2026 2027






Lease Acqusition & Bonus $24,192,000 Site Prep & Permit fees

Drilling & Completion Cost Intangible Drilling Cost


Flowback Option 4 Total Lease Operating Costs $1,697,337 $1,520,168 $1,375,116 $1,254,280 $1,152,139 $1,064,722 $989,102

Tax Allowances

Depreciation

Depletion $4,136,903 $4,092,495 $4,094,409 $4,155,301 $4,304,382 $4,620,391 $5,432,575 Net Taxable Income $2,970,697 $2,273,209 -$22,528,110 $1,096,997 $520,202 -$161,866 -$1,290,713



Corportate Income Tax $193,095 $147,759 -$1,464,327 $71,305 $33,813 -$10,521 -$83,896 Net Cash Flow after NY State Tax $1,577,376 $1,050,505 -$22,036,159 $138,762 -$328,315 -$904,234 -$1,906,233

Federal Income Tax $536,308 $357,172 -$7,492,294 $47,179 -$111,627 -$307,440 -$648,119 Net Cash Flow after Federal Tax $1,041,068 $693,333 -$14,543,865 $91,583 -$216,688 -$596,794 -$1,258,114







Page 113

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