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Water Resource Reporting and Water Footprint  R

from Marcellus Shale Development 

in West Virginia and Pennsylvania

Prepared by

Evan Hansenθ

Dustin Mulvaneyπ

Meghan Betcherθ

θ

Downstream Strategies

295 High Street

Suite 3

Morgantown, WV 26505

www.downstreamstrategies.com

π

San Jose State University

1 Washington Square

San Jose, CA 95112

Prepared for

Earthworks Oil & Gas

Accountability Project

PO Box 1102

Durango, CO 81302

Final Report

October 30, 2013
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Water Resource Reporting and Water Footprint 

from Marcellus Shale Development

in West Virginia and Pennsylvania

Evan Hansen, Dustin Mulvaney, and Meghan Betcher

Restate the title here

List the authors again here

ABOUT THE AUTHORS

Evan Hansen, M.S., Principal, Water Program, Downstream Strategies. Mr. Hansen founded Downstream 

Strategies, an environmental consulting company in West Virginia, in 1997. He explores resource and 

environmental problems and solutions in three areas: water, energy, and land. He manages interdisciplinary 

research teams, performs quantitative and qualitative policy and scientific analyses, provides expert 

testimony, facilitates stakeholder meetings, and performs field monitoring.

Dustin Mulvaney, Ph.D., Assistant Professor of Sustainable Energy Resources, Department of 

Environmental Studies, San Jose State University. Dr. Mulvaney is an interdisciplinary researcher with 

expertise in social science research methodologies as well as life-cycle analysis, with a focus on solar energy 

technologies, biofuels, and natural gas. He is a life cycle analysis consultant to biofuel companies and has 

provided expert testimony in numerous cases before the California Public Utilities Commission on the 

impacts of electricity prices on solar energy deployment and energy efficiency. Dr Mulvaney is a peer 

reviewer for the National Science Foundation, as well as eight research journals including Environmental 

Science & Technology, Solar Energy, and the Journal of Integrative Environmental Sciences. 

Meghan Betcher, M.S., Environmental Scientist, Downstream Strategies. Ms. Betcher offers expertise in 

environmental science and is experienced in project design, field sampling, data analysis, and presentation of 

complex scientific findings to academics, students, and community groups.
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ACKNOWLEDGEMENTS

We thank the Robert & Patricia Switzer Foundation for funding this project through its Network Innovation 

Grant Program, and we especially thank Executive Director Lissa Widoff, Program Officer Erin Lloyd, and 

Communications Manager Lauren Hertel for their support and assistance.

This project also would not have been possible without the support and assistance from the Earthworks Oil & 

Gas Accountability Project. In particular, we thank Bruce Baizel, Director and Nadia Steinzor, Eastern Program 

Coordinator.

At San Jose State University, Brian Rosa compiled and analyzed a considerable amount of gas production 

data. At Downstream Strategies, Marc Glass, Principal, Monitoring and Remediation provided valuable 

feedback and ideas.

We also thank Brian Lutz, Assistant Professor, Department of Biological Sciences, Center for Ecology and 

Natural Resources Sustainability, Kent State University for providing data upon which his previous 

Pennsylvania study was based.

Skytruth Communications Director David Manthos helped facilitate the use of Skytruth’s Chemical Database 

Download, which compiles FracFocus data into a searchable database.

At the West Virginia Department of Environmental Protection, we thank Henry (Jason) Harmon for providing 

withdrawal and waste data and for reviewing and explaining the data. We also thank Mike Shank at the West 

Virginia Department of Environmental Protection for his assistance.

Paula Ballaron at Susquehanna River Basin Commission helpfully provided data and explanations related to 

water withdrawals, fluid injection, and fluid recovery within the Susquehanna River Basin.

Finally, we thank our external reviewers for their valuable feedback (job titles and organizations are provided 

for identification purposes only and do not imply endorsement): Dr. Arjen Y. Hoekstra (Professor in Water 

Management, Department of Water Engineering & Management, University of Twente, The Netherlands), Dr. 

Alan Krupnick (Senior Fellow and Director, Center for Energy Economics and Policy, Resources for the Future), 

Dr. P.W. Gerbens-Leenes (Assistant Professor, Department of Water Engineering & Management, University 

of Twente, The Netherlands), Dr. Brian Lutz (Assistant Professor, Department of Biological Sciences, Kent 

State University), Dr. William Niemann (Associate Professor and Chair of Geology, Marshall University), Daniel 

Soeder (Research Physical Scientist, National Energy Technology Laboratory), and one anonymous reviewer.
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TABLE OF CONTENTS

EXECUTIVE SUMMARY........................................................................................................................................VIII

1. INTRODUCTION .............................................................................................................................................1

2. THE SHALE GAS BOOM AND THE ENERGY-WATER NEXUS..............................................................................4

2.1 THE FRACKING PROCESS: FROM PERMITS TO PRODUCTION..........................................................................................5

2.2 IMPACTS OF SHALE GAS EXTRACTION ON WATER RESOURCES.......................................................................................6

2.3 MARCELLUS WASTE DISPOSAL OPTIONS ..................................................................................................................7

2.4 SHALE FOSSIL FUELS AND WATER USE .....................................................................................................................9

2.5 MARCELLUS SHALE GAS AND WATER USE ................................................................................................................9

3. DATA COLLECTION AND REPORTING REQUIREMENTS ................................................................................. 11

3.1 WEST VIRGINIA ...............................................................................................................................................11

3.2 PENNSYLVANIA................................................................................................................................................13

4. INJECTION, RECOVERY, AND DISPOSAL OF FLUIDS IN WEST VIRGINIA ......................................................... 15

4.1 DRILLING PROGRESS IN THE MARCELLUS SHALE......................................................................................................15

4.2 WITHDRAWALS ...............................................................................................................................................16

4.3 QUALITY CONTROL AND COMPLETENESS OF THE INJECTION, RECOVERY, AND DISPOSAL DATASET ......................................18

4.4 INJECTIONS .....................................................................................................................................................19

4.5 RECOVERY AND DISPOSAL ..................................................................................................................................20

4.6 WATER REMOVED FROM THE HYDROLOGIC CYCLE ...................................................................................................25

5. INJECTION, RECOVERY, AND DISPOSAL OF FLUIDS IN PENNSYLVANIA ......................................................... 27

5.1 DRILLING PROGRESS IN THE MARCELLUS SHALE......................................................................................................27

5.2 WITHDRAWALS ...............................................................................................................................................28

5.3 INJECTIONS .....................................................................................................................................................30

5.4 RECOVERY AND DISPOSAL ..................................................................................................................................31

5.5 WATER REMOVED FROM THE HYDROLOGIC CYCLE ...................................................................................................37

6. WATER FOOTPRINT OF MARCELLUS SHALE GAS PRODUCTION.................................................................... 39

6.1 THE WATER FOOTPRINT APPROACH......................................................................................................................39

6.2 WATER FOOTPRINT PER UNIT ENERGY...................................................................................................................40

6.3 BLUE WATER FOOTPRINT ...................................................................................................................................42

6.4 GREY WATER FOOTPRINT ...................................................................................................................................46

7. CONCLUSIONS AND RECOMMENDATIONS................................................................................................... 51

7.1 WEST VIRGINIA ...............................................................................................................................................51

7.2 PENNSYLVANIA................................................................................................................................................56

7.3 SUMMARY......................................................................................................................................................60

REFERENCES......................................................................................................................................................... 62

APPENDIX A: DETAILED DATA COLLECTION AND REPORTING REQUIREMENTS IN WEST VIRGINIA ...................... 71

APPENDIX B: DETAILED DATA COLLECTION AND REPORTING REQUIREMENTS IN PENNSYLVANIA ...................... 74

APPENDIX C: QUALITY CONTROL FOR WEST VIRGINIA DATA ............................................................................... 77

APPENDIX D: QUALITY CONTROL FOR PENNSYLVANIA DATA............................................................................... 78
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TABLE OF TABLES

Table 1: Horizontal Marcellus gas well permits in West Virginia and Pennsylvania.............................................3

Table 2: Shale gas production in the United States and the Marcellus play (TCF, 2010-2011)............................4

Table 3: Shale gas reserves in the United States and the Marcellus play (TCF, 2010-2011)................................4

Table 4: Water requirements per well for fracking by shale play (million gallons)............................................10

Table 5: Range of estimates of water used per well in the Marcellus Shale (million gallons)............................10

Table 6: West Virginia withdrawal data summary (2009-2012).........................................................................16

Table 7: Reported water withdrawals for Marcellus wells in West Virginia (million gallons, % of total 

withdrawals, 2010-2012)....................................................................................................................................17

Table 8: West Virginia wells with reporting data and remaining after quality control (2010-2012)..................18

Table 9: Completeness of West Virginia Frac Water Reporting Database (2010-2011).....................................19

Table 10: Injection volumes for horizontal Marcellus wells in West Virginia (million gallons, 2010-2012).......20

Table 11: Flowback fluid disposal volumes by method in West Virginia (gallons, % of total, 2010-2012).........21

Table 12: Discrepancies related to recycled and reused flowback fluid reporting (million gallons, 2010-2012)

............................................................................................................................................................................23

Table 13: Interstate transport of flowback fluid from West Virginia Marcellus wells (2010-2012)...................25

Table 14: Water removed from the hydrologic cycle by Marcellus wells in West Virginia (million gallons, 2010-

2012)...................................................................................................................................................................26

Table 15: Marcellus wells hydraulically fractured within the Susquehanna River Basin....................................28

Table 16: Water withdrawals by Marcellus wells in the Susquehanna River Basin (million gallons, %, 2009-

2012)...................................................................................................................................................................29

Table 17: Reporting rate for Pennsylvania Marcellus wells reported to FracFocus (2009-2012).......................30

Table 18: Injection volumes for Pennsylvania Marcellus wells reported to FracFocus (million gallons, 2009-

2012)...................................................................................................................................................................30

Table 19: Injection volumes for Marcellus wells in the Susquehanna River Basin (million gallons, 2009-2012)31

Table 20: Fluid recovery in the Susquehanna River Basin ..................................................................................31

Table 21: Waste disposal method in Pennsylvania (gallons, % of total, 2008-2011) .........................................33

Table 22: Interstate transport of waste from Pennsylvania Marcellus wells (2008-2011).................................37

Table 23: Water removed from the hydrologic cycle by Marcellus wells in Pennsylvania (million gallons, 2009-

2011)...................................................................................................................................................................38

Table 24: Thirty-year production estimates and water use per unit energy for shale gas.................................41

Table 25: Estimates for volumes of water consumed per unit of energy...........................................................41

Table 26: One estimate of annual production and decline over four years for Pennsylvania Marcellus wells 

(Mcf)....................................................................................................................................................................42

Table 27: Derivation of first-year production proxy for West Virginia wells (2010-2012) .................................43

Table 28: West Virginia production volumes (Mcf, 2010-2012).........................................................................43

Table 29: Blue water footprint for Marcellus wells in West Virginia (gallons/Mcf) ...........................................44

Table 30: Initial blue water footprint calculations for Marcellus wells in Pennsylvania (2009-2011)................45

Table 31: Blue water footprint for Marcellus wells in Pennsylvania (gallons/Mcf)............................................46

Table 32: Contaminants and thresholds screened in this research (mg/L) ........................................................47

Table 33: Marcellus flowback water data used to calculate grey water footprint (mg/L unless otherwise 

specified).............................................................................................................................................................48

Table 34: Primary contaminants, thresholds, and volume ranges for grey water footprint..............................49

Table 35: Grey water footprint for Marcellus wells in West Virginia (2010-2012).............................................49

Table 36: Grey water footprint for Marcellus wells in Pennsylvania (2009-2011).............................................49

Table 37: West Virginia data reporting...............................................................................................................54

Table 38: Pennsylvania data reporting ...............................................................................................................59
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TABLE OF FIGURES

Figure 1: Horizontal Marcellus gas well permits in West Virginia and Pennsylvania ...........................................3

Figure 2: West Virginia reporting forms .............................................................................................................11

Figure 3: Pennsylvania reporting forms..............................................................................................................13

Figure 4: Currently active horizontal Marcellus wells in West Virginia, by permit year.....................................15

Figure 5: Reported water withdrawals for Marcellus wells in West Virginia (% of total withdrawals, 2010-

2012)...................................................................................................................................................................17

Figure 6: Percent of injected fluid that is recovered for Marcellus wells in West Virginia (2010-2012)............20

Figure 7: Flowback fluid disposal by method over time in West Virginia (2010-2012)......................................22

Figure 8: Flowback fluid disposal by method in West Virginia (average, 2010-2012)........................................22

Figure 9: Destination of flowback fluid from West Virginia Marcellus wells (2010-2012) .................................24

Figure 10: Pennsylvania Marcellus wells that commenced drilling in specified year.........................................27

Figure 11: Water withdrawals by Marcellus wells in the Susquehanna River Basin ..........................................29

Figure 12: Waste generated from Pennsylvania wells by fluid type (2008-2011)..............................................32

Figure 13: Total waste generated from Pennsylvania Marcellus wells, by type (2008-2011)............................32

Figure 14: Waste disposal by method over time in Pennsylvania (2008-2011) .................................................34

Figure 15: Waste disposal by method in Pennsylvania (average, 2008-2011) ...................................................34

Figure 16: Flowback fluid disposal by method over time in Pennsylvania (2008-2011).....................................35

Figure 17: Destination of waste from Pennsylvania Marcellus wells (2008-2011).............................................36

Figure 18: Summary of key West Virginia water and fluid flows........................................................................52

Figure 19: Summary of key Pennsylvania water and fluid flows........................................................................57
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ABBREVIATIONS

API American Petroleum Institute

ATSDR Agency for Toxic Substances & Disease Registry

BOGM Bureau of Oil and Gas Management (Pennsylvania)

BTEX benzene, toluene, ethylbenzene, and xylene

CFR Code of Federal Regulations

CSR Code of State Rules

DOE Department of Energy

EIA Energy Information Administration

ISO International Organization for Standardization

Mcf thousand cubic feet

mcm million cubic meters

MWh megawatt-hour

NPDES National Pollutant Discharge Elimination System

NYSDEC New York State Department of Environmental Conservation

PADEP Pennsylvania Department of Environmental Protection

PASDA Pennsylvania Spatial Data Access

POTW publicly owned treatment works

SRB Susquehanna River Basin

SRBC Susquehanna River Basin Commission

STRONGER State Review of Oil and Natural Gas Environmental Regulations, Inc.

TCF trillion cubic feet

TDS total dissolved solids

TSS total suspended solids

UIC underground injection control

US United States

USEPA United States Environmental Protection Agency

USGS United States Geological Survey

WVDEP West Virginia Department of Environmental Protection
viii | P a g e

EXECUTIVE SUMMARY

Freshwater resources around the world are under threat from fossil fuel development, and these threats are 

emerging in new places with the rapid growth in recent years of natural gas extraction from shale using 

horizontal drilling and hydraulic fracturing. This technique has been criticized for its environmental impacts, 

including dewatering streams and surface- and groundwater pollution. Many specific instances of water 

impacts remain under scientific investigation, and in Pennsylvania and West Virginia, a number of researchers 

have documented the potential impacts of fracking on water resources.

This report focuses on the extraction of natural gas from the Marcellus Shale in Pennsylvania and West 

Virginia. While conventional gas production has been conducted here for decades, unconventional wells that 

utilize advances in horizontal drilling have grown considerably more common in the past decade. Nearly nine 

thousand horizontal Marcellus Shale natural gas wells have been permitted in these two states from 2005 to 

2012, and more than eleven thousand such wells will likely be permitted by the end of 2013.

As permitted wells have been developed and started production, they have drastically increased gas 

production in these two states. These wells have also made an important contribution by growing the 

regional workforce and contributing to state taxes, a significant economic benefit during a time of economic 

stagnation. 

In recent years, West Virginia and Pennsylvania have improved their regulation and oversight of water use 

and pollution from natural gas extraction. Both states now require recordkeeping and public reporting of key 

water quality and quantity information. In this report, we use these databases to document water 

withdrawals, fluid injections, and waste recovery and disposal, including the transport of waste to 

neighboring states. We also apply the concept of life cycle analysis to calculate the water footprint of the 

extraction phase of natural gas from Marcellus Shale. 

In addition, we provide recommendations for improving data collection and reporting requirements to 

appropriately inform future management decisions by policy makers, regulators, and operators. More 

broadly, these recommendations will help regulators—and the industry itself—ensure that water 

withdrawals, fluid injection, and waste disposal are undertaken in such a manner as to protect the region’s 

groundwater and surface water resources.

Key West Virginia findings

 Approximately 5 million gallons of fluid are injected per fractured well. 

 Surface water taken directly from rivers and streams makes up over 80% of the water used in 

hydraulic fracturing and is by far the largest source of water for operators. Because most water used 

in Marcellus operations is withdrawn from surface waters, timing is important, and withdrawals 

during low flow periods can result in dewatering and severe impacts on small streams and aquatic 

life.

 Reused flowback fluid accounts for approximately 8% of water used in hydraulic fracturing.

 On average, only 8% of injected fluid is recaptured. The remaining 92% remains underground, 

completely removed from the hydrologic cycle.

 The flowback fluid reported as waste in West Virginia represents only approximately 38% of total 

waste volume. Because of inadequate state reporting requirements, the fate of 62% of fracking 

waste is unknown. 
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 At present, the three-state region—West Virginia, Pennsylvania, and Ohio—is tightly connected in 

terms of waste disposal. Almost one-half of flowback fluid recovered in West Virginia is transported 

out of state. Between 2010 and 2012, 22% of recovered flowback fluid was sent to Pennsylvania, 

primarily to be reused in other Marcellus operations, and 21% was sent to Ohio, primarily for 

disposal via underground injection control wells.

 The amount of water used per well is higher than previously estimated for Marcellus Shale wells. The

blue water footprint of wells started in West Virginia from 2010 to 2012, which represents the 

volume of water removed from the hydrologic cycle per unit of gas produced, ranges from 1.6 to 2.2 

gallons/Mcf. When considering the sensitivity of these results to higher gas production estimates, 

the range dropped to 1.2 to 2.0. Previous estimates of water use ranged from 0.677 to 1.2. 

Key Pennsylvania findings

 Approximately 4.3 million gallons of fluid are injected per fractured well. 

 On average, only 6% of injected fluid is recaptured. The remaining 94% remains underground, 

permanently removed from the hydrologic cycle.

 In Pennsylvania, three primary waste categories are tracked: flowback fluid, brine, and drilling waste, 

with flowback fluid representing approximately 38% of the total. 

 As Marcellus development has expanded, waste generation has increased. In Pennsylvania, 

operators reported an almost 70% increase in waste generated from 2010 to 2011—rising to a 

reported 613 million gallons of waste in 2011. 

 More than 50% of waste generated by Pennsylvania Marcellus wells is treated and discharged to 

surface waters—either through brine/industrial waste treatment plants or municipal sewage 

treatment plants. This stands in stark contrast to West Virginia, where virtually no flowback fluid is 

reported to be discharged to surface waters. 

 In Pennsylvania, approximately one-third of total waste is reused, although data are not available to 

determine whether it is reused in Pennsylvania or elsewhere. Approximately 5% of total 

Pennsylvania Marcellus waste is injected in UIC wells, mostly in Ohio.

 There is significant potential for Marcellus development in Pennsylvania to impact water quality 

because a large percentage of waste is treated at plants that discharge to the state’s rivers and 

streams. 

 At present, the three-state region— West Virginia, Pennsylvania, and Ohio—is tightly connected in 

terms of waste disposal. While most Pennsylvania waste remains in-state, a significant amount of 

waste is shipped to UIC wells in Ohio, and Pennsylvania reuses flowback fluid received from West 

Virginia.

 In Pennsylvania, the blue water footprint, which represents the volume of water removed from the 

hydrologic cycle per unit of gas produced, ranges from 3.2 to 4.2 gallons per Mcf from 2009 to 2011 

on a 4-year production basis. When considering the sensitivity of these results to higher natural gas 

estimates, the range dropped to 1.2 to 3.9. Previous estimates of water use ranged from 0.677 to 

1.2.
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Recommendations 

 Modify reporting systems so that operators report withdrawals by individual well, not by well site. 

 Fix mistakes in databases, make data entry less error-prone, and provide searchable online datasets.

 Unify the two units within the West Virginia Department of Environmental Protection with 

responsibilities related to oil and gas. Currently, staff at one office may not be fully cognizant of 

other aspects of reporting requirements, and it may also lead to inconsistencies between databases 

that are being maintained for the same gas wells.

 In Pennsylvania, make Marcellus-specific withdrawal data fully and freely available across the entire 

state.

 Require operators to report all aspects of water use and waste production, treatment, and disposal

along the entire life cycle of shale gas extraction. 

 Effectively enforce new rules governing surface water withdrawals and increase oversight of industry 

surface water withdrawals in order to protect rivers and streams.

 Develop new methods to reduce water and waste at all stages of shale gas production.

Summary

The findings of this report suggest that the volumes of water used to fracture Marcellus Shale gas wells are 

substantial and the quantities of waste generated are significant. While West Virginia and Pennsylvania have 

recently taken steps to improve data collection and reporting related to gas development, critical gaps persist 

that prevent researchers, policymakers, and the public from attaining a full picture of trends. Given this, it is 

highly likely that much more water is being withdrawn and more waste is being generated than is known. 

While a considerable amount of flowback fluid is now being reused and recycled, the data suggest that it still 

displaces only a small percentage of freshwater withdrawals, which will limit its benefits except in times of 

drought where small percentages could be important. While West Virginia and Pennsylvania are generally 

water-rich states, these findings indicate that horizontal drilling and hydraulic fracturing operations could 

have significant impacts on water resources in more arid areas of the country. However, if existing 

techniques are applied to the much deeper and thicker Utica Shale that lies below the Marcellus, than even 

water-rich regions could find that shale gas operations make water supplies vulnerable. 

In short, the true scale of water impacts can still only be estimated, and considerable improvements in 

industry reporting, data collection and sharing, and regulatory enforcement are needed. The challenge of 

appropriately handling a growing volume of waste to avoid environmental harm will continue to loom large 

unless such steps are taken. 
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1. INTRODUCTION

It is widely agreed that the freshwater resources around the world are under threat from fossil fuel 

development (Gleick 1994; McMahon and Price 2011). These threats are emerging in new places 

with the rapid growth in recent years of natural gas extraction from shale using horizontal drilling 

and hydraulic fracturing (”fracking”). This technique has been criticized for its environmental 

impacts, including dewatering streams (Entrekin et al. 2011) and surface- and groundwater pollution 

(Olmstead et al. 2013). Many specific instances of water impacts remain under scientific 

investigation (USEPA 2012; USEPA 2011a; USEPA 2011b), and in Pennsylvania and West Virginia, a 

number of researchers have documented the potential impacts of fracking on water resources

(Abdalla 2010; Lutz et al. 2013; Quaranta et al. 2012; WVDEP 2013d; West Virginia Water Research 

Institute 2013; Ziemkiewicz et al. 2013; Kargbo 2010; Lavelle 2010). 

This report focuses on the extraction of natural gas from the Marcellus Shale in Pennsylvania and 

West Virginia.1 While conventional gas production has been conducted here for decades, 

unconventional wells that utilize advances in horizontal drilling have grown considerably more 

common in the past decade. Nearly nine thousand horizontal Marcellus Shale natural gas wells have 

been permitted in these two states from 2005 to 2012: 7,081 in Pennsylvania and 1,680 in West 

Virginia (See Figure 1 and Table 1) (PADEP 2013h, WVDEP 2013c). Including the estimated number of 

permitted wells in 2013, more than eleven thousand such wells will likely be permitted by the end of 

2013.

Most of the recent permits have been issued in northern West Virginia, southwestern Pennsylvania, 

and northeastern Pennsylvania.2As permitted wells have been developed and started production, 

they have drastically increased gas production in these two states. These wells have also made an 

important contribution by growing the regional workforce, with an estimated 29,320 people 

employed in core industries for shale gas extraction (Marcellus Shale Coalition 2013). Companies 

developing these shale resources have paid more than $1.6 billion in state taxes from 2006 to 2012

(Marcellus Shale Coalition 2013), a significant economic benefit during a time of economic 

stagnation.

In recent years, West Virginia and Pennsylvania have improved their regulation and oversight of 

water use and pollution from natural gas extraction. Both states now require recordkeeping and 

public reporting of key water quality and quantity information related to water withdrawal, fluid 

injection, and waste disposal. 

While these data collection and reporting requirements provide a key backdrop, the core of this 

report is our use of these databases to document water withdrawals, fluid injections, and waste 

recovery and disposal, including the transport of waste to neighboring states.3 We also apply the 

concept of life cycle analysis to calculate the water footprint of the extraction phase of natural gas 

from Marcellus Shale.

 

1 When reviewing data collection and reporting requirements, it is important to clarify how each state distinguishes between Marcellus and other 

wells, unconventional and conventional wells, and vertical and horizontal wells. In this report, we use the term “unconventional” interchangeably with 

“Marcellus.” In the Pennsylvania reporting systems, the term “unconventional” is used to distinguish Marcellus wells from wells in other formations, 

and the systems therefore include both vertical and horizontal wells. However, the West Virginia Frac Water Reporting Database contains data for 

horizontal wells only. As of now, this database only includes wells in the Marcellus formation. Now that drilling in the Utica formation has begun, this 

database will soon also contain data for horizontally drilled Utica wells. Vertical wells are not included in this West Virginia database because these 

wells require much smaller volumes of water for drilling, and reporting is only required if a well used more than 750,000 gallons of water.

2

In neighboring Ohio, the pace of shale gas development has been much slower and has focused on the Utica Shale, which is beneath the 

Marcellus.

3 Freshwater is sometimes also transported across state lines; however, we do not distinguish between instate and out-of-state freshwater 

withdrawals.
2 | P a g e

Water footprints are indicators that represent impacts to water resources by estimating water 

quantities in addition to impacts on water quality (Hoekstra et al. 2011). The approach divides water 

use into three components. First, the blue water footprint estimates the volume of surface and 

groundwater withdrawn, consumed, or removed from the hydrologic cycle to produce a product.4

Second, the grey water footprint is an indicator of water pollution, and is defined as the amount of 

water required to assimilate water pollution to an acceptable threshold or standard. Finally, the 

green water footprint “refers to the human use of the evaporative flow from the land surface” 

(Hoekstra et al. 2011, p. 20). Because the green water footprint largely applies to products produced 

in agriculture or forestry, it was not considered relevant to the water footprint approach used here. 

Through the process of collecting and analyzing the West Virginia and Pennsylvania data, we found 

that the data reported by operators are sometimes incomplete, inaccurate, unavailable to the public, 

or inconvenient to query. Despite these challenges, these datasets represent the best information 

currently available with which to characterize impacts of Marcellus wells on water resources. As the 

datasets become more complete and accurate, we expect the estimates in this report to be refined. 

Our analysis allows us to draw conclusions about patterns of water withdrawals, fluid injections, 

waste disposal, and water footprints. We also provide recommendations for improving data 

collection and reporting requirements to appropriately inform future management decisions by 

policy makers, regulators, and operators. More broadly, these recommendations will help 

regulators—and the industry itself—ensure that water withdrawals, fluid injection, and waste 

disposal are undertaken in such a manner as to protect the region’s groundwater and surface water 

resources. 

 

4 Deciding to use withdrawals, consumption, or removal from the hydrologic cycle would depend on what is deemed most important about the 

product system. 
3 | P a g e

Figure 1: Horizontal Marcellus gas well permits in West Virginia and Pennsylvania

Sources: Well data from WVDEP (2013c) and PADEP (2013h). Susquehanna River Basin boundary from PASDA (2013). Note: The number of 

permitted wells is greater than the number actually drilled.

Table 1: Horizontal Marcellus gas well permits in West Virginia and Pennsylvania

Year West Virginia Pennsylvania Total

2005-2007 6 34 40

2008 60 156 216

2009 261 1,064 1,325

2010 288 1,958 2,246

2011 477 2,067 2,544

2012 588 1,802 2,390

2013 (estimate) 624 2,244 2,868

Total 2,304 9,325 11,629

Sources: WVDEP (2013c) and PADEP (2013h). Note: The number of permitted wells is greater than the number actually drilled. The 2013 

estimates were calculated by doubling the number of wells permitted from January through June 2013.
4 | P a g e

2. THE SHALE GAS BOOM AND THE ENERGY-WATER NEXUS

In the United States (US), about 30% of electricity was produced from natural gas in 2012, up from 

23% just a decade ago (EIA 2011; EIA 2012). This growth in natural gas use for electricity has tracked 

increases in domestic production, which has been aided by developments in hydraulic fracturing and 

horizontal drilling that have made recovery of shale gas resources economically feasible. By 2010, 

shale gas approached 25% of US gas production (EIA 2012), and it continues to grow rapidly. One of 

the fastest areas of shale gas growth is the Marcellus Shale play, where gas production more than 

doubled from 2010 to 2011 (Table 2).

Table 2: Shale gas production in the United States and the Marcellus play (TCF, 2010-2011)

Area 2010 2011

United States 5.4 8.0

Marcellus play 0.5 1.4

West Virginia Marcellus play 0.1 0.2

Pennsylvania Marcellus play 0.4 1.1

Source: EIA (2013b).

In the future, shale gas is anticipated to gain a greater share of overall natural gas production and is 

poised to grow to 13.6 trillion cubic feet (TCF) in 2035 (EIA 2013a). For comparison, overall US 

natural gas demand is estimated at 25.5 TCF in 2012 (EIA 2013a). As technological development 

drives down the costs of extraction, shale gas reserves have grown, and are likely to continue to 

grow (Table 3). 

Table 3: Shale gas reserves in the United States and the Marcellus play (TCF, 2010-2011)

Area 2010 2011

United States 97.4 131.6

Marcellus play 13.2 31.9

West Virginia play 2.5 6.0

Pennsylvania play 10.7 23.6

Source: EIA (2013b). Note: Shale gas reserves are as of December 31 of the given year. The Energy 

Information Administration (EIA) reports proven reserves, which are conservative estimates. 

However, natural gas extraction from shale has renewed attention to the impacts of fossil fuel 

extraction on water resources. Accessing shale gas resources via current technologies requires 

significant quantities of freshwater compared to historical practices and has raised numerous water 

quality concerns. As natural gas production from shale continues to expand with the potential 

unlocked by high-volume hydraulic fracturing combined with horizontal drilling, there will be 

increasing attention to this energy-water nexus (Scown et al. 2011). Electricity and compressed 

natural gas are poised to gain a greater share of energy resources for transportation (EIA 2013c), and 

shale gas will make up an increasing portion of the natural gas portfolio. Hence, if the potential 

water impacts of shale gas development are not properly managed, freshwater impacts can be 

expected to become more widespread and appear in new regions over time as resource 

development proceeds.
5 | P a g e

2.1 The fracking process: From permits to production

As we describe in this report, the growth of fracking has raised numerous questions about impacts to 

water resources. These impacts can occur because of the large water quantities needed for 

production, as well as faulty engineering, poor decisions, accidents, or poor processing practices at 

several points along the life of a well. Well development proceeds through the following stages:

 Permitting. Well permits are generally required by state regulatory agencies before 

construction can begin. State laws and regulations for well permits differ. For example, 

setbacks from structures or sensitive landscape features vary among states, and data 

collection and reporting requirements are also different.

 Site development. If a well is being developed at an undeveloped site, a “pad” must be 

constructed before drilling can begin. Pads provide a level working surface free of 

obstructions. As enabled by horizontal drilling methods, multiple wells or horizontal legs 

may be advanced from a single pad. In addition to the well pad, site development may be 

required for areas associated with pipelines or other supporting infrastructure.

 Water acquisition. Water is acquired via direct extraction by the operator from surface or 

groundwater, by purchasing water, or by reusing fluid from previously drilled and fractured

Marcellus sites. 

 Drilling and casing. Once proper permits are approved and the site is prepared, drilling can 

commence. Starting the drilling process is sometimes referred to as “spudding” a well. 

Unconventional Marcellus Shale wells begin with a vertical borehole. The vertical segments 

of the boreholes are then lined with a surface casing composed of steel that is sealed into 

place with cement to a depth of up to one thousand feet (Soeder 2012). Properly installed, 

casing protects fresh groundwater, and it is common to extend the surface casing several 

hundred feet below any aquifers. With a surface casing in place, the borehole begins to 

curve and an intermediate casing to prevent fluid migration and prevent borehole collapse is 

installed up to a point known as the kickoff (Soeder 2012). From here, the borehole is 

deviated laterally to run within the shale bed. A production casing is installed that runs 

inside the surface and intermediate casings, all the way through the end of the borehole. 

 Hydraulic fracturing. After the well is drilled, explosive charges are used to perforate the 

production casing. This puts the production casing in contact with the shale production 

zone. After a brief cleaning with hydrofluoric acid, it is hydraulically fractured with a fluid 

composed of water, sand, and chemicals. This fluid is injected under steadily increasing 

pressure, and the sand or other proppant material holds the fractures open after pressure is 

released. This process is known as “completion.”

Once the fracking process is completed, fluid that returns to the surface is referred to as 

“flowback” and is directed to temporary onsite storage where it is ultimately disposed of or 

reused. This flowback water typically returns to the surface within the first seven to 14 days 

(American Petroleum Institute 2010), but can continue for months. In addition to flowback, 

naturally present brine fluid also returns to the surface. 

 Production. Once a well begins producing gas, it can continue to produce for decades, 

although annual production volumes decrease rapidly. 
6 | P a g e

As documented in this report, different types of data are collected and reported at different stages. 

For example, in both Pennsylvania and West Virginia, completion reports with information on 

chemicals used in the fracking fluid must be submitted. And in both states, production reports must 

be submitted that periodically document the volume of natural gas that was produced. See Chapter 

3 and Appendix A and B for more detail on these and other data collection and reporting 

requirements.

2.2 Impacts of shale gas extraction on water resources 

The well development process described above has the potential to generate numerous impacts to 

water resources. Researchers have investigated potential impacts to both water quantity and quality, 

which can vary across different geologic basins. Research on the impacts to water from shale gas 

extraction can broadly be categorized into research on water quality indicators and research on 

water and wastewater quantities. Many of these studies attempt to characterize ecosystem and 

habitat effects, both aquatic and terrestrial, and human health impacts, but a number simply seek to 

understand water use and pollution in general. 

Research on water resource impacts has been performed at universities (Lutz et al. 2013; Jackson et 

al. 2013); by government agencies (USEPA 2012; USEPA 2011a; USEPA 2011b; USGS Powell Center 

for Analysis and Synthesis 2012; Soeder and Kappel 2009); and by non-governmental organizations 

such as the Pacific Institute (Cooley and Donnelly 2012), Environmental Working Group (Horwitt 

2011), Environment America (2013), and National Ground Water Association (National Ground 

Water Association 2011). 

Despite the important information revealed about impacts to water quality and quantity from this 

body of research, it remains challenging to interpret the results and/or assess the tradeoffs between 

concerns about water quantity and those about water quality. Key questions remain: Are the 

concerns for one greater than the other? Do regulations need to be adjusted for water withdrawals, 

waste disposal, or both? 

While water quality and quantity are inextricably linked, the local context may influence public 

perceptions. Water footprint indicators can help understand how industry trends and practices may 

change impacts to water over time. In this section, we survey prior research to understand the 

breadth of methods, data, and assumptions used to understand the impacts of natural gas extraction 

from shale. We review the published literature on impacts from fracking and related activities with 

the goal of identifying gaps in the literature, noting critical research needs, and informing our data 

analysis.

2.2.1 Groundwater quality

Fracking for natural gas can put groundwater in and around the well site at risk. Impacts to 

groundwater quality include methane migration (Osborn et al. 2011), shale formation brine and 

associated metals migration (Saiers and Barth 2012; Warner et al. 2012), and contamination of 

groundwater from drilling or flowback fluids (USEPA 2011). Groundwater that is close to the surface 

is often relied upon as drinking water, while deeper groundwater usually is not. There is much 

debate and ongoing scientific research to determine the hydraulic connectivity between deep and 

shallow groundwater (Warner et al. 2012). Arguably the most probable way to contaminate shallow 

groundwater is through poor onsite management of flowback and drilling fluids (Holloway and Rudd 

2013; Howarth and Ingraffea 2011). Poorly managed and sited waste pits can also impair water 

quality via mechanical failure, such as when liners rupture and create direct contact with 

groundwater (Folger et al. 2012; Rich and Crosby 2013; USGS 2012). Buried waste also poses water 

quality risks. Obviously, intentional dumping—which has been found to happen (USEPA 2013a)—will
7 | P a g e

impact water quality. Though it has not been documented with certainty to date, damage to wells 

that occurs close to the surface might lead to the direct contamination of groundwater as fracking or 

flowback fluid can be introduced to the subsurface, and possibly to groundwater resources, from the 

site of well failure (Folger et al. 2012).

2.2.2 Surface water

Similarly, shale gas extraction can impact surface water by above-ground land management and offsite waste treatment. Spills, leaks, and other releases of flowback fluid can directly impair surface 

water because these fluids contain low-level radiation (Rowan et al. 2011), heavy metals, and other 

contaminants. Olmstead et al. (2013) examined how surface water in Pennsylvania was impacted by

the permitted release of treated shale gas waste. They looked at the impacts of land use change and 

the release of treated shale gas waste on total suspended solids (TSS) and chloride concentrations. 

Increased TSS concentrations would occur from runoff associate with well pads, pipelines, and roads. 

The source of chloride is brine and flowback fluid. They found that chloride concentrations did 

impact downstream water quality, but were not able to detect increased TSS concentrations

(Olmstead et al. 2013). Numerous other studies are ongoing or underway. 

2.3 Marcellus waste disposal options

A variety of types of wastes are generated when Marcellus wells are drilled and hydraulically 

fractured. Between 2004 and 2011, the volume of waste disposed in Pennsylvania has increased by 

570% (Lutz et al. 2013). 

Fluids that are recovered soon after fracking are referred to as flowback fluid. Arthur et al. (2008) 

estimate that 10% to 30% of initial volume of water is recovered as flowback from Marcellus Shale

wells. The Susquehanna River Basin Commission (SRBC) estimates that 8% to 12% is recovered as 

flowback (Richenderfer 2010). A public presentation by Penn State Extension (Yoxtheimer 2012) puts 

this range from approximately 8% to 10%. 

The data analyzed in this report found a value similar to the low values, at approximately 8% in West 

Virginia and 6% in the Susquehanna River Basin (SRB) in Pennsylvania based on the methodology we 

document later. If not disposed of properly, this waste can impair water quality—both groundwater 

and surface water. But even industry best practices for disposal can have water quality implications 

(Olmstead et al. 2013). 

There are limited options for managing waste that returns to the surface after fracking, which 

includes flowback fluid, brine generated from within the target formation, and other types of waste. 

Generally, the best option is to reuse flowback fluids to perform fracturing at another Marcellus well. 

This option eliminates the need to locate a disposal site and lessens the water withdrawal 

requirements for future fracturing efforts. As discussed below, our analysis shows that, as a 

percentage of total waste disposal, the reuse of flowback fluids has increased dramatically in

Pennsylvania (Table 21) but has actually decreased in recent years in West Virginia (Table 11). While 

reuse is an appealing alternative, recycled flowback fluid must be treated and diluted with 

freshwater, and another well must be available at which to use it again.

In recent years, the most common option in many regions of the US is to pump waste fluids 

underground via underground injection control (UIC) wells. These wells are intended to dispose of 

waste far below ground, and the Safe Drinking Water Act regulates UIC use and operation. There are 

five types of UIC wells. Class II wells are specifically built to inject fluids to enhance recovery or to 
8 | P a g e

dispose of flowback fluid, brine, and other residual waste generated by oil and gas operations 

(USEPA 2013).5

According to West Virginia Department of Environmental Protection (WVDEP), there are 62 active

Class II UIC wells in West Virginia (WVDEP 2013e). Most of these wells are owned by drillers and used 

to dispose of fluids produced in their own operations; however, 14 are commercial wells (WVDEP 

2013e) and accept fluids from more than one oil and gas operation. In West Virginia, WVDEP has 

primacy over its UIC program and therefore administers permits for Class II UIC wells.

In Pennsylvania, there are seven Class II UIC wells (Platt n.d.). The Pennsylvania Department of 

Environmental Protection (PADEP) has not been granted primacy over the program; therefore, the 

United States Environmental Protection Agency (USEPA) administers the Class II UIC well program in 

Pennsylvania.

Much of the waste generated by wells in Pennsylvania and West Virginia is disposed of in UIC wells in 

Ohio (See Table 13 and Table 22). Ohio has almost two hundred Class II UIC wells available for drilling 

waste disposal (Adgate 2013).

Treatment and discharge to surface water is a third option. Especially when the Marcellus play began 

to be developed, waste was trucked to publicly owned treatment works (POTWs) in both West 

Virginia and Pennsylvania. These plants eventually discharge to surface waters. However, over time, 

it became clear that POTWs were not effectively treating natural gas fluids before discharging to 

receiving streams (Olmstead et al. 2013; Volz 2011). Flowback fluid with significant levels of sodium 

and chloride can raise total dissolved solids (TDS) levels in the POTW’s effluent (USEPA 2011). They 

are also not equipped to treat fluids that contain radium, a contaminant commonly found in 

flowback water (Rowan et al. 2011). When high levels of bromide and chloride are present, as is 

common in the Marcellus Shale, POTWs can synthesize brominated and chlorinated constituents in 

the effluent. These compounds can include brominated and chlorinated trihalomethanes, which 

have been linked to human cancers and birth defects (USEPA 2005). 

With the high volumes of flowback fluid being generated, there are also questions about whether 

POTWs are over capacity. Riha and Rahm (2010) modeled the impacts to water resources in New 

York’s undeveloped section of the SRB using hypothetical withdrawal and disposal data and found 

that POTWs could be over capacity without investments in private industrial waste treatment plants

specifically outfitted to treat hydraulic fracturing waste.

As regulators have increasingly frowned upon sending these fluids to POTWs, their use has stayed 

negligible in West Virginia (Table 11) and has become less common in Pennsylvania (Table 21). Brine 

or industrial waste treatment plants present another option for treating hydraulic fracturing waste 

before discharging to surface waters. While these plants are prevalent in Pennsylvania (Table 21), 

they are not currently used in West Virginia (Table 11).

Disposing of brine, which returns to the surface over a longer time period than flowback fluid, also 

presents water quality concerns. Ohio regulators are considering whether to allow solidified brine to 

be disposed of in its 40 landfills (Downing 2013).

 

5 While UIC permits are required for the disposal of fluids related to Marcellus gas production, they are not needed for Marcellus wells themselves.
9 | P a g e

2.4 Shale fossil fuels and water use

It was known early in the evolution of shale gas extraction that hydraulic fracturing requires

substantial quantities of water. By 2006, an estimated 35,000 wells were already fractured across the 

US (Halliburton, 2008; cited in USEPA 2011a), requiring an estimated 70 to 140 billion gallons per 

year (USEPA 2011). According to USEPA at the time, “this is equivalent to the total amount of water 

withdrawn from drinking water resources each year in roughly 40 to 80 cities with a population of 

50,000 or about one to two cities of 2.5 million people” (2011, p. 22a). With the boom in shale gas 

production not starting in earnest until 2008, the volume of water required to frack for natural gas 

has increased by an order of magnitude or more. 

The amount of water used per shale gas well varies, but hydraulic fracturing at a single horizontal 

well can require 1.9–9.1 million gallons of water-based fracturing fluids (Sutherland et al. 2011). The 

US Department of Energy (DOE) puts the input requirements for hydraulic fracturing between 2.9 to 

5.0 million gallons of water, 1,300–2,300 kilograms of sand, and 29,000–50,000 gallons of chemicals 

on average per well (DOE 2009; cited in Lewis 2012). 

Nicot and Scanlon (2012) estimated net water use in shale-gas production in Texas based on wellcompletion data. They found that cumulative water use in the Barnett Shale play totaled 145 million 

m

3

(38 billion gallons), roughly 9% of the water use of Dallas’ population of 1.3 million. They found 

that these water withdrawals were less than 1% of overall water use for entire state of Texas, but 

could have important local impacts in times of low water availability. Because a large portion of the 

water injected is removed from the hydrologic cycle, there could be long-term impacts to water 

availability in arid areas of Texas. Formation characteristics suggest that more of the initial volume of 

water returns to the surface in the Barnett than the Marcellus; however, in 2011, there were no 

published estimates of the volume of water withdrawals that return to the surface for the Barnett 

Shale (Mantell 2011).

Water use varies across different basins. Annual estimates of total water use across the Barnett 

Shale ranged from 2.6 to 5.3 billion gallons per year from 2005 through 2007 (Bene et al. 2007; cited

in Galusky 2007). Estimates for North Dakota’s Bakken Shale project water use at nearly 5.5 billion 

gallons of water per year for oil and gas production (Kellman and Schneider 2010).

2.5 Marcellus Shale gas and water use

Drilling and fracking Marcellus Shale wells likewise require millions of gallons of water per well. 

SRBC—the interstate commission that manages one of the largest river basins atop the Marcellus 

Shale—“projects 30 million gallons a day of consumptive use associated with full development of just 

the Marcellus play” within the SRB (Drohan et al. 2012, p. 395). In fact, on a per-well basis, the 

Marcellus Shale appears to require more water—between 4.1 and 5.6 million gallons—than the 

Fayetteville, Haynesville, and Barnett Shale plays (Table 4). The variability can be attributed to 

differences in shale formation geology, depth, and well type, which vary over space and time. 
10 | P a g e

Table 4: Water requirements per well for fracking by shale play (million gallons)

Shale play Typical range

Barnett 2.3–3.8

Fayetteville 2.9–4.2

Haynesville 2.7–5.0

Marcellus 4.0–5.6

Sources: Groundwater Protection Council & ALL Consulting (2009) and Clark et al. (2011), 

which cites Mantell (2010). These values assume one frack per well. Per-well water 

requirements will be higher if re-stimulation occurs, but there is a dearth of information about

water use from re-stimulation.

Estimates of water requirements for Marcellus wells vary but fit within the range noted above. 

Drohan et al. (2012) note that SRBC estimates an average of 4.4 million gallons per well. Range 

Resources (2010) finds the water volume per well to be over 4.6 million gallons. Using operational 

data from Chesapeake Energy, Mantell (2010; 2011) finds water use requirements to be 4.1 and 5.6 

million gallons respectively.6Researchers at Argonne National Laboratory estimate water use in the 

Marcellus Shale to be approximately 4.0 million gallons per well (Clark et al. 2013). 

Table 5: Range of estimates of water used per well in the Marcellus Shale (million gallons)

Water volume Research team

4.4 SRBC; cited in Drohan et al. 2012

4.6 Range Resources 2010

5.6 Mantell 2011

4.1 Mantell 2010

4.0 Clark et al. 2013

To put these values into a similar context that USEPA used in 2011, the Pittsburgh Water & Sewer 

Authority produces 70 million gallons of water per day to serve its 83,000 customers (Pittsburgh 

Water & Sewer Authority 2010). The approximately 6,000 Marcellus wells in Pennsylvania have 

injected about as much water as Pittsburgh supplies to its customers in one year. 

Put another way, the entire flow of the Susquehanna River contributes 26 billion gallons of water per 

day to the Chesapeake Bay (Drohan et al. 2012). The cumulative volume of water used by all wells in 

Pennsylvania is roughly equal to the daily flow from the entire river basin. These cumulative impacts 

are especially important because such a large percentage of the water injected does not return to 

the surface and is lost to the hydrologic cycle. The volume of water injected to date in Pennsylvania 

is also roughly 1% of the 2.5 trillion gallons of total surface water in Pennsylvania alone (Abdalla 

2010). While overall, 1% might be seen as only a marginal impact, these volumes could be critical in 

times of drought. Also, as drilling expands, the cumulative impacts are likely to grow proportional to 

water use. The development of the deeper and thicker Utica Shale that underlies the Marcellus with 

similar techniques will require substantially more water. 

 

6 Mantell (2010) uses 2009 operational data from Chesapeake Energy. The increase in volume in Mantell 2011 in Table 5 is likely due to deeper 

wells. 
11 | P a g e

3. DATA COLLECTION AND REPORTING REQUIREMENTS

3.1 West Virginia

Data collection and reporting requirements have evolved rapidly in recent years in West Virginia as 

new laws, regulations, and policies have been enacted. In West Virginia, water withdrawals, water 

used in development of horizontal Marcellus wells, and disposal of flowback fluid are regulated by 

two acts and their associated rules: the Natural Gas Horizontal Well Control Act and the Water 

Resources Protection and Management Act. The Natural Gas Horizontal Well Control Act,7passed by 

the West Virginia Legislature in 2011, recognized that advanced natural gas drilling practices require 

use and disposal of unprecedented quantities of water. Existing oil and gas regulations, which 

focused on conventional drilling techniques, were not adequate for the increased number of wells 

drilled and the copious volumes of water used and waste produced as a result of hydraulic fracturing 

and horizontal drilling. This Act created a regulatory framework to address the large volumes of 

water injected during drilling and fracturing and the disposal of flowback fluid. However, as 

described below, many of the reporting requirements stem from a previous law, the Water 

Resources Protection and Management Act,8 which was updated in 2008.

As illustrated in Figure 2, a variety of water, waste, and production data must be collected and 

reported to WVDEP, starting with the water management plan submitted with the permit, and 

ending with annual production reports. Appendix A provides detailed descriptions of each of these 

forms and reports.

Figure 2: West Virginia reporting forms

Permitting

Site 

development Drilling

Hydraulic 

fracturing

Completion

Production

Production 

reports 

(March 31 

each year)

Well completion 

report 

(90 days after completion)

Frac water 

reporting form

(1 year after conclusion of 

hydraulic fracturing)

Large water user 

registration

(Before withdrawals 

begin)

Water management 

plan

(With permit)

Water 

acquisition

Source: Appendix A.

 

7 W.Va. Code §22- 6A.

8 W.Va. Code §22-26.
12 | P a g e

FRACFOCUS AND SKYTRUTH

FracFocus is an online chemical disclosure registry for the oil and gas industry maintained by 

two non-profit organizations: the Interstate Oil and Gas Compact Commission and the 

Groundwater Protection Council. All data uploaded to the online database is self-reported by 

well operators. The online database contains the volume of fracking fluid injected into each well 

and the chemical additives present in the fracking fluid, with the exception of chemical 

components determined to be proprietary. All information contained in this database is 

searchable online and free to the public; however, search results are only provided for single 

wells.

Until recently, all information contained in the FracFocus database was voluntarily disclosed by 

well operators. According to a recent Harvard Law School study, 11 states direct or allow well 

operators to use FracFocus; Pennsylvania is one of these states (Konschnik et al. 2013). More 

recently, the West Virginia Legislature changed state rules to require additive reporting to the 

WVDEP Office of Oil and Gas and to FracFocus (35 CSR 8-10). This change took effect on July 1, 

2013.

SkyTruth is a nonprofit organization that uses remote sensing, digital mapping, and other 

techniques to monitor mining, oil and gas drilling, deforestation, fishing, and other human 

activities. One service provided by this organization is its FracFocus Chemical Database 

Download, which compiles FracFocus data into a downloadable, searchable database (SkyTruth 

2013). This source was used to compile certain information from FracFocus for this report.

For this analysis, only the fluid injection volumes in FracFocus were used. Even for this 

parameter, FracFocus does not compile data into a searchable database. As such, FracFocus is 

of limited usefulness for researchers who desire data for numerous wells. SkyTruth’s FracFocus 

Chemical Database Download, however, turns the FracFocus data into a searchable database 

that is publicly available, thereby drastically increasing the usefulness of data collected by 

FracFocus.
13 | P a g e

3.2 Pennsylvania

In Pennsylvania, several statutes and regulations govern Marcellus Shale gas exploration and 

production, and a series of policies and manuals provide further guidance (PADEP 2013a; STRONGER 

2013). As in West Virginia, data collection and reporting requirements for Marcellus operations have 

also evolved in recent years in Pennsylvania, particularly with the passage of the Oil and Gas Act, also 

known as Act 13, in 2012. As illustrated in Figure 3, PADEP, like WVDEP, requires operators to collect 

and report a variety of water, waste, and production data in a set of plans, forms, and reports.

Certain of these reporting requirements are similar to those in West Virginia: water management 

plans submitted with permit applications, completion reports filed after well completion, and gas 

production reports filed periodically after wells begin producing. However, many of the reporting 

requirements are different. For example, Pennsylvania requires operators to submit waste disposal 

information for a wide variety of waste types in well site restoration reports and along with the 

production reports, while waste reporting in West Virginia is limited to flowback fluid and is 

submitted only once. Appendix B provides detailed descriptions of each of these forms and reports.

Figure 3: Pennsylvania reporting forms

Permitting

Site 

development Drilling

Hydraulic 

fracturing

Completion

Production

Water management 

plan

(With permit)

Water 

acquisition

Well record

(30 days after cessation of 

drilling or altering a well)

Completion report 

(30 days after well is 

capable of production)

Well site 

restoration report

(60 days after restoration 

of well site)

Chemical 

disclosure form

(60 days after conclusion 

of hydraulic fracturing)

Production 

(and waste) reports 

(Feb. 15 and Aug. 15 

each year)

Source: Appendix B.
14 | P a g e

SUSQUEHANNA RIVER BASIN COMMISSION 

SRBC plans for the conservation, utilization, development, management, and control of the water 

and related natural resources of the SRB, which includes part of New York, Pennsylvania, and 

Maryland (18 CFR §801.0). SRBC regulates all withdrawals of surface water and groundwater and 

consumptive water uses within the basin for natural gas development in the Marcellus Shale 

(SRBC 2013a).

Prior approval from SRBC through an application process is required for water withdrawals and 

consumptive uses for natural gas development. Consumptive water uses at natural gas drilling 

pads are handled through an administrative general permit process, known as Approval by Rule, 

and are reviewed and acted on by SRBC’s Executive Director. SRBC does not, however, regulate 

water quality. (SRBC 2013a)

SRBC does not directly regulate the capture, storage, transport, treatment, recycling, or disposal 

of fluid recovered from Marcellus wells from drilling or fracking. However, the injection of water 

for fracking is regulated as a consumptive use by SRBC. SRBC therefore approves the consumptive 

use of water at drilling pads and requires natural gas companies to abide by all other agencies’ 

water quality and waste management requirements. SRBC also requires natural gas companies to 

report post-hydrofracking information. These reports allow SRBC to track the quantities of 

freshwater, recycled flowback fluids, and all other water used, the sources or origin of all 

freshwater/wastewater used, and destinations of wastewater and unused freshwater whether it 

be to a permitted treatment facility or reuse at another drilling pad. (SRBC 2013a)

SRBC withdrawal and consumption data, as well as SRBC post-hydrofracking information, are 

relevant for the current analysis.
15 | P a g e

4. INJECTION, RECOVERY, AND DISPOSAL OF FLUIDS IN WEST 

VIRGINIA

4.1 Drilling progress in the Marcellus Shale

The first Marcellus wells in West Virginia were drilled vertically, but with the advent of horizontal 

drilling techniques, the number of permitted Marcellus wells has grown dramatically. Since 2007, 

WVDEP issued more permits each year for horizontal Marcellus wells, reaching almost 600 newlyissued permits in 2012 (See Table 1, above). As of August 9, 2013 2,064 horizontal Marcellus gas

wells had been permitted in West Virginia. Figure 4 illustrates the number of currently active 

horizontal Marcellus wells among those permitted in a given year. As of August 9, 2013, 698 

horizontal Marcellus wells were active in West Virginia (WVDEP 2013c).

Figure 4: Currently active horizontal Marcellus wells in West Virginia, by permit year

0

50

100

150

200

250

2006 2007 2008 2009 2010 2011 2012 Number of active wells

Source: WVDEP (2013c). Note: The number of active wells represents the number of wells permitted each year that 

were active as of August 9, 2013. On this date, no wells permitted in 2013 were active.
16 | P a g e

4.2 Withdrawals

Withdrawal data were obtained from the WVDEP Water Use Section through a Freedom of 

Information Act request. Water withdrawal volumes in West Virginia are reported by extraction 

event and by well site—not by individual well.9In most cases, a well site contains more than one 

well, and water may be stockpiled in a single pond for fracturing multiple wells at that site or on 

entirely different pads. Further complicating the reporting of withdrawals, water used at a single site 

may be withdrawn from multiple sources at different times. It is therefore not possible to determine 

the volume of water withdrawn for use at any individual well. 

Still, WVDEP collects a variety of useful information about withdrawals, including withdrawal source 

name, location, watershed, and volume withdrawn. This information is reported to WVDEP through 

the online Frac Water Reporting Form.

As shown in Table 6, the number of withdrawals and well sites included in this database has 

increased substantially between 2009 and 2012. In 2009, data for 13 withdrawals for seven different 

well sites were reported. By 2011, the dataset included 355 total withdrawals for 112 different well 

sites. The 2012 dataset is not yet complete.

Table 6: West Virginia withdrawal data summary (2009-2012)

Data 2009 2010 2011

2012 

(partial year)

Number of withdrawals 13 184 355 169

Number of well sites 7 58 112 59

Source: WVDEP (2013a). The number of withdrawals refers to the number of withdrawals with a withdrawal “begin date” in each year.

Our analysis of the West Virginia water withdrawal data focuses on the three years with the most 

data: 2010 through 2012 (See Table 6 and Figure 5). During this time, water for use in drilling and 

hydraulic fracturing was withdrawn from groundwater and surface water—lakes, ponds, rivers, and 

streams. Water was also purchased from public and private water providers. In addition, reused 

flowback fluid captured at wells following injection was transferred to other wells and used again.

From 2010 through 2012, almost 2 billion gallons of water withdrawals were reported for Marcellus 

wells in West Virginia. As the number of horizontal wells in the Marcellus climbed from 2010 through 

2011, the volume of fluid required to service these wells increased by almost 200 million gallons. 

During all years, surface water was the most widely utilized source of water used in Marcellus well 

development—81% of the total from 2010 through 2012. Since 2010, more than 1.6 billion gallons of 

water have been withdrawn from West Virginia’s surface waters for injection into horizontal wells in 

the Marcellus. 

When flowback fluid is reused, it lessens demands for withdrawals from groundwater and surface 

water. Reuse as a percent of total withdrawals has increased somewhat, from 6% in 2010 to 10% in 

2012.10 As described later in this report, the percentage has been somewhat higher in the SRB in 

Pennsylvania, where it increased from 10% in 2010 to 18% in 2012 (See Table 19).11

 

9 While withdrawals per well are not known, the volume of fluid injected per well is known, and is reported below in Table 10.

10 The reuse percentages in Table 7 represent the percentage of total withdrawals that come from reused flowback fluid. This is different from the 

percent of flowback fluid that is recycled and reused, which is shown in Table 11. While Table 11 suggests that most flowback fluid is recycled and 

reused, Table 7 clarifies that this reused flowback fluid still represents a small percentage of total withdrawals.

11 In Pennsylvania, we calculate the percentage of injection volumes from that come from reused flowback fluid. In West Virginia, we calculate the 

percentage of withdrawals (including reused flowback fluid) that come from reused flowback fluid. These calculations, while not exactly the same, 

convey a similar result.
17 | P a g e

Table 7: Reported water withdrawals for Marcellus wells in West Virginia (million gallons, % of total 

withdrawals, 2010-2012)

Source 2010 2011

2012

(partial year) Total

Groundwater 0

0%

21.2

3%

1.5 

<1%

22.7

1%

Surface water 476.8

77%

662.2 

81% 

466.9

83%

1,605.8

81%

Purchased water 104.0

17% 

70.0

9%

34.7

6%

208.6

10%

Reused flowback fluid 35.1

6%

60.0

7%

57.2

10%

152.2

8%

Total 615.8

100%

813.4

100%

560.2

100%

1,989.3

100%

Source: WVDEP (2013a). Note: Surface water includes lakes, ponds, streams, and rivers. The dataset does not specify whether purchased water originates 

from surface or groundwater. As of August 14, 2013, the Frac Water Reporting Database did not contain any well sites with a withdrawal “begin date” later 

than October 17, 2012. Given that operators have one year to report to this database, the 2012 data are likely very incomplete.

Figure 5: Reported water withdrawals for Marcellus wells in West Virginia (% of total withdrawals, 

2010-2012)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

2010 2011 2012 Percent of total water withdrawals

Year of water withdrawal begin date

Ground water

Surface water

Reused water

Purchased water

Source: WVDEP (2013a).
18 | P a g e

4.3 Quality control and completeness of the injection, recovery, and disposal

dataset

Injection, recovery, and disposal data were obtained from the WVDEP Water Use Section through a 

Freedom of Information Act request. The dataset provided by WVDEP includes total injection 

volume, injection “begin dates” and “end dates,” recovery amount, and recovery “begin dates” and 

“end dates” by American Petroleum Institute (API) number for horizontal wells targeting the 

Marcellus formation. It also includes volume reused, volume disposed of in UIC wells, and volume 

disposed of at POTWs for each API number or West Virginia well ID.12 These data were self-reported 

by well operators to WVDEP using the online Frac Water Reporting Form.

Prior to performing data analysis, the data were reviewed and quality control methods were 

implemented to ensure that only representative data were included in our analysis. Appendix C 

describes the quality control steps that were taken, and Table 8 summarizes the number of West 

Virginia wells with reporting data and remaining after quality control.

To assess trends in water use and disposal over time, wells were separated by the year that injection 

began. As shown in Table 8, a significant number of wells were removed from the West Virginia 

dataset before performing calculations. Of the 398 wells for which injection began in 2010, 2011, or 

2012, just over two-thirds remain after quality control.

Table 8: West Virginia wells with reporting data and remaining after quality control (2010-2012)

2010 2011

2012 

(partial year) Total

With reporting data 109 159 130 398

Remaining after quality control 84 140 46 270

Percent of data eliminated 23% 12% 65% 32%

Source: WVDEP (2013a). Note: Years represent the year that injection began.

WVDEP provided the well and injection data separately from the waste data. The WVDEP well ID was 

used to join the disposal data to the injection data so that injection volume, recovery volume, total 

disposal volume, and disposal volume by method were available for each API number and 

corresponding well ID.

13 This joined dataset was used for further analysis.

To assess the completeness of this dataset, we calculate a reporting rate for each year. WVDEP’s Gas 

Well Permit Database (WVDEP 2013c) was obtained from the WVDEP Technical Applications & 

Geographic Information System Unit and was used to calculate the total number of wells for each 

year that should have been required to report water data. This database was filtered to show only 

wells targeting the Marcellus formation that are also horizontal wells. Assuming that water has been 

used at all active wells, the data was further filtered to wells with an active status. These wells were 

then separated according to the year in which they were permitted. 

We then searched the entire Frac Water Reporting Database for the API numbers that correspond to 

the wells that were legally required to report water data.

14 The reporting rate we calculate is not 

meant to measure the accuracy of the data reported, but the percentage of required reports that 

exist in the database; therefore, we searched the entire Frac Water Reporting Database for each API 

 

12 These West Virginia well IDs, while different from API numbers, were unique and could be cross-referenced against the API numbers.

13 The disposal year for reuse is not included in the Frac Water Reporting Database; thus, the year for reuse was determined by joining the well ID 

for the reuse waste volume to the well ID in the well information database. All waste data are tied to the injection date of the well that produced the 

waste.

14 The Frac Water Reporting Database contained numerous wells that did not exist in the Well Permit Database.
19 | P a g e

number identified as described in the previous paragraph, and not just the wells remaining after 

quality control in Table 8. 

To estimate reporting rates for the Frac Water Reporting Database, we divided the number of wells 

that reported to this database (WVDEP 2013a) by the total number of active horizontal Marcellus 

wells from the Gas Well Permit Database (WVDEP 2013c). Reporting rates, shown in Table 9, were 

only calculated for 2010 and 2011. The Frac Water Reporting system was not established prior to 

2010, so reporting rates for earlier years were not estimated. Even though 91 horizontal Marcellus 

wells with a permit date in 2012 are listed as active in the permit database, we assume that the 

reporting rate calculated using this method for these wells would not be accurate due to the oneyear lag time in reporting following water injection.

Only 35% of the wells permitted in 2010 and 2011, on average, have reported to the Frac Water 

Reporting Database. This combined reporting rate was applied, as described below, to the total 

reported volume injected, total reported volume disposed, and total reported volume removed from 

the hydrologic cycle to obtain an estimated statewide total for each category. The estimated totals 

were calculated by dividing the reported total by the average reporting rate of 35%. Even though the 

combined reporting rate is based on 2010 and 2011 alone, it was applied to 2010, 2011, and 2012.

Table 9: Completeness of West Virginia Frac Water Reporting Database (2010-2011)

Year of permit issuance

Active, horizontal, 

Marcellus wells

Wells that reported to the 

Frac Water Database

Percent of wells that 

reported to the 

Frac Water Database

2010 166 71 43%

2011 242 70 29%

Total 408 141 35%

Sources: Active, horizontal, Marcellus wells from WVDEP (2013c). Wells that reported to the Frac Water Database from WVDEP (2013a). Note: Even 

though 91 horizontal Marcellus wells with a permit date in 2012 are listed as active in the permit database, we assume that the reporting rate 

calculated using this method for these wells would not be accurate due to the one-year lag time in reporting following water injection.

4.4 Injections

The total reported volume of water injected for 2010, 2011, and 2012 was calculated by summing 

the injection amounts reported for all wells with injection “begin dates” in each year. The per-well

average in Table 10 was calculated by dividing the total reported volume by the number of active 

wells as represented by the dataset. Because the Frac Water Reporting Database does not contain 

data for all wells in West Virginia, we calculated an estimated total volume to represent all active 

horizontal Marcellus wells in the state. As described above, the estimated total was calculated by 

dividing the total reported volume by the average reporting rate of 35%. 

A total of 1.4 billion gallons of fluid were reported to have been injected into horizontal wells in the 

Marcellus since 2010. Given that the Frac Water Reporting Database is incomplete, we calculate that 

the actual total may be estimated at 3.9 billion gallons during this period.
20 | P a g e

Table 10: Injection volumes for horizontal Marcellus wells in West Virginia (million gallons, 2010-2012)

Injection volume 2010 2011

2012

(partial year) Total

Average per well 5.0 4.7 6.0 5.0

Total, reported wells 423 661 275 1,359

Total, estimated 1,209 1,889 786 3,884

Note: As of August 14, 2013, the WVDEP Frac Water Reporting Database did not contain any wells with an injection “begin date” later than October 25, 

2012. Given that operators have one year to report to this database, the 2012 data are likely very incomplete.

4.5 Recovery and disposal

As opposed to Pennsylvania where all waste types are reported, West Virginia rules only require that 

operators report flowback fluid, defined as all fluid recovered in 30 days following injection or 50% of 

the injected volume, whichever occurs first. Therefore, recovery and disposal data analyzed in this 

chapter are for flowback fluid only.

A large portion—greater than 90%—of the water injected into Marcellus wells does not return to the 

surface in the time frame captured by the reporting requirements. After injection, this water remains 

deep underground and, thus, is lost to the hydrologic cycle. As illustrated in Figure 6, most wells 

recovered 7% or less.

During 2010 through 2012, an average of 8% of the total injected volume was recovered at 

horizontal wells in the Marcellus. In 2010, recovery averaged approximately 12%, and in 2011 and 

2012, the percentages recovered were even lower: 6% and 8%, respectively.

Figure 6: Percent of injected fluid that is recovered for Marcellus wells in West Virginia (2010-2012)

0

5

10

15

20

25

30

35

40 Number of wells

Percent recovered

Source: WVDEP (2013a). Note: One well reported that 98% of the fluid injected was recovered; this outlier is not 

included in the chart.
21 | P a g e

Following injection, flowback fluid along with naturally occurring brine returns to the surface. Well 

operators must collect this waste and properly dispose of it. As shown in Table 11, Figure 7, and 

Figure 8, most flowback fluid has been recycled and reused in other wells in each of the three years 

included in this study. The percent of total flowback that was reused has gradually decreased from 

2010 through 2012, however, from 88% to 65%.

15 During this time, the portion of total flowback 

disposed of in UIC wells has gradually increased. In 2010, UIC wells accepted only 12% of flowback 

fluids, but by 2012, they accepted 35% of flowback fluids from Marcellus wells in West Virginia. 

Disposal at POTWs was utilized only in 2010 and 2011, and even then, POTWs only received 1% or 

less of total waste.

Table 11: Flowback fluid disposal volumes by method in West Virginia (gallons, % of total, 2010-2012)

Disposal method 2010 2011

2012 

(partial year) Total

POTW

Average per well 1,365 3,363 0 2,168

Total, reported wells 114,660 470,834 0 585,494

Total, estimated 327,600 1,345,240 0 1,672,840

Percent of total <1% 1% 0% 1%

UIC

Average per well 60,145 74,515 155,861 83,903 

Total, reported wells 5,052,207 10,432,040 7,169,624 22,653,871 

Total, estimated 14,434,877 29,805,829 20,484,640 64,725,346

Percent of total 12% 26% 35% 22%

Reuse

Average per well 457,824 206,818 292,057 299,431 

Total, reported wells 38,457,186 28,954,545 13,434,604 80,846,335 

Total, estimated 109,877,674 82,727,271 38,384,583 230,989,528 

Percent of total 88% 73% 65% 78%

Total disposed

Average per well 519,334 284,696 437,235 385,503 

Total, reported wells 43,624,053 39,857,419 20,604,228 104,085,700

Total, estimated 124,640,151 113,878,340 58,869,223 297,387,714

Percent of total 100% 100% 100% 100%

WVDEP (2013a). Note: As of August 14, 2013, the WVDEP Frac Water Reporting Database did not contain any wells with an injection “begin date”

later than October 25, 2012. Given that operators have one year to report to this database, the 2012 data are likely very incomplete.

 

15 The reuse percentages in Table 11 represent the percent of flowback fluid that is recycled and reused. This is different from the percentage of total 

withdrawals that come from reused flowback fluid in Table 7. While Table 11 suggests that most flowback fluid is recycled and reused, Table 7

clarifies that this reused flowback fluid still represents a small percentage of total withdrawals.
22 | P a g e

Figure 7: Flowback fluid disposal by method over time in West Virginia (2010-2012)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2010 2011 2012 Percent of total fluid disposed

Year of injection begin date

Reuse

POTW

UIC

WVDEP (2013a). Note: As of August 14, 2013, the WVDEP Frac Water Reporting Database did not contain any wells 

with an injection “begin date” later than October 25, 2012. Given that operators have one year to report to this

database, the 2012 data are likely very incomplete.

Figure 8: Flowback fluid disposal by method in West Virginia (average, 2010-2012)

Reuse

78%

POTW

1%

UIC

22%

WVDEP (2013a). Note: As of August 14, 2013, the WVDEP Frac Water Reporting Database did not contain any wells 

with an injection “begin date” later than October 25, 2012. Given that operators have one year to report to this

database, the 2012 data are likely very incomplete.
23 | P a g e

Both the disposal dataset (Table 11) and the withdrawal dataset (Table 7) document flowback fluid 

that, rather than being disposed, was instead recycled and reused. However, as documented in Table 

12, these two datasets do not agree well, particularly in 2011 and 2012. In 2011, the disposal dataset 

suggests that 29 million gallons of flowback fluid was recycled and reused, but the withdrawal 

dataset suggests that twice that volume—approximately 60 million gallons—was recycled and 

reused. The discrepancy in 2012 is even greater; however, reporting has not been completed for 

wells for which injection began in 2012. 

It is possible that these discrepancies can be explained by time lags between when fluids are recycled 

and reused, operators that report one but not the other value, fluid captured at wells in West 

Virginia or Pennsylvania that is reused at wells in the other state, or other explanations. At the 

current time, they remain unexplained.

Table 12: Discrepancies related to recycled and reused flowback fluid reporting (million gallons, 2010-

2012)

Reported recycled and reused 

flowback fluid 2010 2011

2012

(partial year) Total

In disposal dataset 38 29 13 81

In withdrawal dataset 35 60 57 152

Sources: Recycled and reused flowback fluid reported in disposal dataset from Table 11, and reused flowback fluid reported in withdrawal dataset from

Table 7.

As shown in Figure 9, while much of the flowback fluid generated by West Virginia’s horizontal 

Marcellus wells stayed in West Virginia, a significant amount was shipped to the neighboring states 

of Ohio and Pennsylvania.16 In fact, from 2010 through 2012, only 57% of flowback fluid from 

horizontal Marcellus wells in West Virginia actually stayed in West Virginia. As illustrated in the 

bottom section of Table 13, 21% was shipped to Ohio and 22% was shipped to Pennsylvania.

Of all flowback fluid generated in these years, one-half was reused at wells in West Virginia, and 21% 

was reused at wells in Pennsylvania. An additional 21% was sent to UIC wells in Ohio. Together, these 

three destinations account for more than 90% of the flowback fluid generated at Marcellus wells in 

West Virginia.

Of the flowback fluid disposed of in UIC wells, approximately three-quarters was shipped to Ohio in 

2010 through 2012; the remaining one-quarter was sent to UIC wells within West Virginia (Table 13).

Fluids were also sent to POTWs in all three states; however, the total amount of fluids sent to POTWs 

is extremely small as compared to the other disposal options.

 

16 Obvious errors in the dataset related to locations of UIC wells and POTWs were corrected.
24 | P a g e

Figure 9: Destination of flowback fluid from West Virginia Marcellus wells (2010-2012)

Sources: WVDEP (2013a and c). Note: Marcellus wells that reuse flowback fluid from West Virginia wells are not distinguished from other wells in 

this map. Only those UIC wells in this dataset are displayed.
25 | P a g e

Table 13: Interstate transport of flowback fluid from West Virginia Marcellus wells (2010-2012)

Destination state Percent of total disposed Percent of disposal type total

UIC

West Virginia 6% 24%

Ohio 21% 76%

Pennsylvania 0% 0%

Subtotal, UIC 27% 100%

POTW

West Virginia <1% <1%

Ohio <1% 46%

Pennsylvania <1% 54%

Subtotal, POTW 1% 100%

Reuse

West Virginia 50% 70%

Ohio 1% 1%

Pennsylvania 21% 30%

Subtotal, reuse 72% 100%

Total

West Virginia 57%

Ohio 21%

Pennsylvania 22%

Source: WVDEP (2013a). Note: As of August 14, 2013, the WVDEP Frac Water Reporting Database did not contain any 

wells with an injection “begin date” later than October 25, 2012. Given that operators have one year to report to this 

database, the 2012 data are likely very incomplete. The percentages in the middle column of this table are similar to, but 

not exactly the same as, those reported in the final column of Table 11 and charted in Figure 8. This is because some data 

included in Table 11 and Figure 8 were omitted from this table due to insufficient disposal site location information.

4.6 Water removed from the hydrologic cycle

During hydraulic fracturing, water is injected deep below the Earth’s surface. As described above, 

only 8% of this water injected between 2010 and 2012 has returned to the surface where it is 

recovered by well operators. The water that is injected but not recovered is removed from the 

hydrologic cycle. In addition, the flowback fluid injected into UIC wells is also removed from the 

hydrologic cycle. Therefore, the total volume of water removed from the hydrologic cycle was 

calculated by adding the volume of water that was injected but not recovered to the volume of 

water disposed of in UIC wells. 

As shown in Table 14, Marcellus wells in West Virginia, on average, removed about 4.7 million 

gallons from the hydrologic cycle in recent years. In total, according to the database of operatorreported water use, more than 1.2 billion gallons were removed from the hydrologic cycle from 2010 

through 2012. When accounting for the fact that this database is incomplete, the true total for the 

state may be closer to an estimated 3.7 billion gallons during this time period.

In 2012, the average per-well volume removed from the hydrologic cycle increased by more than 

one million gallons per well, as compared with 2010 and 2011. On average, proportionately more 

waste was disposed of in UIC wells in 2012 than in previous years (See Table 11); however, the 

increase in water removed from the hydrologic cycle is primarily explained by the large increase in 

injection volume between 2011 and 2012 (See Table 10).
26 | P a g e

Table 14: Water removed from the hydrologic cycle by Marcellus wells in West Virginia (million gallons, 

2010-2012)

2010 2011

2012

(partial year) Total

Average per well 4.6 4.5 5.7 4.7

Total, reported wells 385 632 262 1,280

Total, estimated 1,101 1,806 749 3,657

Source: WVDEP (2013a). Note: As of August 14, 2013, the WVDEP Frac Water Reporting Database did not contain any wells with an injection “begin date”

later than October 25, 2012. Given that operators have one year to report to this database, the 2012 data are likely very incomplete.
27 | P a g e

5. INJECTION, RECOVERY, AND DISPOSAL OF FLUIDS IN

PENNSYLVANIA

5.1 Drilling progress in the Marcellus Shale

The development of Marcellus wells in Pennsylvania began in 2005 when the first Marcellus well, a 

Range Resources vertical well, was completed (Soeder 2012). During that same year, drilling 

commenced for three additional Marcellus wells. 

Since 2009, PADEP has issued more than one thousand permits each year for horizontal Marcellus 

wells, and more than two thousand such permits were issued in 2011 (See Table 1). As of August 8, 

2013 8,418 horizontal Marcellus gas wells had been permitted in Pennsylvania.

As illustrated in Figure 10, drilling has increased rapidly in recent years. In 2010, drilling commenced 

for 1,594 Marcellus wells, and in 2011 that figure increased again to 1,959. Based on the number of 

wells reported for the first half of 2013, it is estimated that more than 1,200 Marcellus wells may be 

drilled in 2013. 

The issuance of Marcellus well permits has outstripped the actual drilling of wells. This has resulted 

in a backlog of permitted wells. This backlog, however, is being addressed. At the end of 2011, only 

49% of active wells were producing. By the end of 2012, this percentage reached 63%, and by June 

30, 2013, it reached 67% (Henderson 2013).

Figure 10: Pennsylvania Marcellus wells that commenced drilling in specified year

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 Number of wells where drilling has commenced

Source: PADEP (2013d). Note: 2013 values estimated by doubling the reported values for January through June 2013.

This figure contains data for all Marcellus gas wells in Pennsylvania. Table 1, Figure 1, and Figure 4 show data for 

horizontal Marcellus wells only. 
28 | P a g e

Statewide data are not available on the number of wells that have been hydraulically fractured. 

However, within the SRB watershed, SRBC reports that 778 wells were hydraulically fractured in 

2011, and 806 were hydraulically fractured in 2012 (See Table 15).

Table 15: Marcellus wells hydraulically fractured within the Susquehanna River Basin

Year Number of wells

2008 10

2009 147

2010 449

2011 778

2012 806

2013 (partial year) 221

Source: SRBC (2013b). Note: 2013 includes first and second quarters only.

5.2 Withdrawals

In West Virginia, a single statewide database is available to track water withdrawals, fluid injections, 

flowback fluid recovery, and flowback fluid disposal. In Pennsylvania, however, no such database is 

available. Instead, data analyzed in this chapter is collected from multiple sources—some data for 

Pennsylvania as a whole and other data for the SRB only. 

One database of interest is PADEP’s database of all water acquisitions by water users that withdraw 

greater than 10,000 gallons per day in any given 30-day period in all Pennsylvania river basins except 

the SRB (PADEP 2013g). While this database tracks water withdrawals by individual withdrawal 

points and purchases, it is not possible to relate this data to individual wells or well pads. It can be 

filtered to acquisitions for use by the oil and gas industry, but it is not possible to filter for 

withdrawals for drilling and fracturing in the Marcellus formation. Therefore, the database is not 

used in this report.

Without these data, we are left with withdrawal and consumption data from Marcellus wells within 

the SRB, which is collected by SRBC As shown in Table 16, SRBC separates withdrawals into nondocketed and docketed categories. Docketed withdrawals are from surface and groundwater, while 

non-docketed sources are mainly comprised of public water systems, but can include sources such as 

abandoned mine discharges, industrial and municipal wastewaters, and pad stormwater.

In the SRB, more than 8.3 billion gallons of water were withdrawn for use at Marcellus wells between 

2008 and the first quarter of 2013. Of this total, 6.0 billion gallons were withdrawn from surface and 

groundwater. In 2010 and 2011, docketed surface and groundwater withdrawals made up a much 

larger percentage of total water consumed than other sources. 
29 | P a g e

Table 16: Water withdrawals by Marcellus wells in the Susquehanna River Basin (million gallons, %, 

2009-2012)

Source type 2009 2010 2011 2012 Total

Docketed

Average per well 1.9 4.1 3.8 1.2 2.7 

Total, reported 283 1,856 2,925 927 5,991 

Percent of total 60% 81% 77% 53% 72%

Non-docketed

Average per well 1.3 1.0 1.1 1.0 1.1 

Total, reported 191 438 873 826 2,328 

Percent of total 40% 19% 23% 47% 28%

Total

Average per well 3.2 5.1 4.9 2.2 3.8 

Total, reported 475 2,293 3,798 1,754 8,320 

Percent of total 100% 100% 100% 100% 100%

Source: SRBC (2013c). Note: Docketed withdrawals are from surface and groundwater. Non-docketed sources are mainly comprised of public water systems, 

but can include sources such as abandoned mine discharges, industrial and municipal wastewaters, and pad stormwater. Average values were calculated by 

dividing the total volumes by the total number of wells in the SRB that have been hydraulically fractured, as reported in Table 15. Consumptive use may not 

equal the sum of docketed and non-docketed withdrawals due to rounding in original data source. Docketed water withdrawals in fourth quarter 2010 were 

adjusted from 753 to 556 million gallons to correct an apparent mistake in the original data source.

Figure 11: Water withdrawals by Marcellus wells in the Susquehanna River Basin

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2008 2009 2010 2011 2012 Million gallons

Non-Docketed Water Sources

Docketed Water Withdrawals 

Source: SRBC (2013c).
30 | P a g e

5.3 Injections

Since April 2012, operators in Pennsylvania have been required to submit reports to FracFocus that 

include, among other things, injection volumes. Before then, many well operators voluntarily 

disclosed water injection volumes to FracFocus. As described above, the FracFocus data analyzed 

here was obtained from SkyTruth (2013).

For each year, the rate at which Pennsylvania operators report to FracFocus was estimated by 

dividing the number of Pennsylvania wells in the FracFocus database that began fracturing in that 

year by the number of wells that commenced drilling that year, as reported to PADEP (See Figure 10, 

above).17

While the FracFocus database is still not complete, the percentage of operators reporting to 

FracFocus has increased significantly in recent years. As shown in Table 17, in 2010, just 3% of drilled 

Pennsylvania wells reported to FracFocus, but two years later, 85% of wells were reported to this 

database. This coincides with the implementation of Act 13, which requires well operators to 

disclose chemical additives and injection volumes to FracFocus.

Table 17: Reporting rate for Pennsylvania Marcellus wells reported to FracFocus (2009-2012)

2009 2010 2011 2012 Total

Number of wells reported to FracFocus 16 55 1,147 1,135 2,353

Reporting rate 2% 3% 59% 85% 41%

Sources: Number of wells in FracFocus from SkyTruth (2013). Number of wells drilled from PADEP (2013d).

As illustrated in Table 18, 4.3 million gallons of fluid, on average were injected into each 

Pennsylvania Marcellus well in recent years. A total of 10 billion gallons have been reported via 

FracFocus, and this corresponds to an estimated total of approximately 24 billion gallons, after taking 

into account the reporting rates shown in Table 17.

Table 18: Injection volumes for Pennsylvania Marcellus wells reported to FracFocus (million gallons, 

2009-2012)

2009 2010 2011 2012 Total

Average per well 2.8 3.9 4.5 4.1 4.3 

Total, reported 44 220 5,118 4,666 10,051 

Total, estimated 2,245 6,373 8,740 5,513 24,366

Source: SkyTruth (2013).

In addition to injection data available from FracFocus via SkyTruth, additional injection data are 

available for Marcellus wells in the SRB from SRBC. As shown in Table 19, from 2009 through 2011, 

the total injection volume in the SRB steadily rose to 3.6 billion gallons annually. In 2012, the total 

volume injected decreased slightly to 3.4 billion gallons. 

In each year since 2010, recycled flowback fluid has made up a larger percentage of total injection 

volumes. In 2012, reuse rose to 18% of the total volume injected. For comparison, the percentage of 

West Virginia withdrawals made up of reused flowback fluid has also increased, but only reached 

10% in 2012 (Table 7).

18

 

17 These percentages do not reflect the possibility that a well may have been drilled the year before it was fractured; therefore, the year-by-year 

percentages should be treated as rough estimates. The total percentage, however, more accurately represents the percentage of drilled wells that 

have reported to FracFocus within this time period.

18 Injection volumes of freshwater and recycled flowback fluid are reported separately to SRBC. In West Virginia, the volume of recycled flowback 

fluid is reported as a withdrawal. Although the terminology is different, the percentages convey similar results.
31 | P a g e

Table 19: Injection volumes for Marcellus wells in the Susquehanna River Basin (million gallons, 2009-

2012)

2009 2010 2011 2012 Total

Freshwater injected 486 

90%

1,732 

90%

3,064 

86%

2,796 

82%

8,078

86%

Flowback injected 55 

10%

189

10%

492 

14%

627 

18%

1,363

14%

Total 541

100%

1,921 

100%

3,556

100%

3,423

100%

9,440

100%

Average per well 3.7 4.3 4.6 4.2 4.3

Source: SRBC (2013b). Note: Data presented in this table and in Table 16 are from SRBC; however, the percentage of freshwater is significantly different. 

Some portion of the non-docketed withdrawal volumes in Table 16 represent fresh water from public water systems, but this portion is not known. Further, 

withdrawal volumes in Table 16 are reported for well sites, but injection volumes in this table are reported for individual wells. Assuming that water withdrawn 

is injected, the percentage of each source type should be similar.

5.4 Recovery and disposal

A significant portion of the water injected during hydraulic fracturing does not return to the surface. 

Statewide electronic data are not publicly available for injection and recovery volumes for Marcellus 

wells across Pennsylvania; however, SRBC reports recovery percentages for wells within the SRB. 

Between 2009 and 2012, an average of 6% of the fluid injected into Marcellus wells in the SRB was 

captured at the surface (See Table 20). This is similar to, but slightly less than, the average of 8% for 

West Virginia Marcellus wells between 2010 and 2012 (See Section 4.5 and Figure 6).

Table 20: Fluid recovery in the Susquehanna River Basin

Year Percent recovered

2009 9%

2010 5%

2011 4%

2012 5%

Total 6%

Source: SRBC (2013b).

While fluid recovery data are not available statewide, flowback disposal data are. These data are 

reported to PADEP together with other waste disposal volumes. These data are available for 

download from PADEP for the years 2000-2012 (PADEP 2013f). Lutz et al. (2013) and Lewis (2012) 

analyzed these data and found several inaccuracies that required editing. Rather than downloading 

the raw data and performing the same edits, we instead started with the peer-reviewed data set

provided by Lutz. All waste disposal data reported here are from this edited dataset, which was 

originally sourced from PADEP (Lutz 2013a). Appendix D describes the quality control steps taken by 

Lutz, which are incorporated into this edited dataset.

Pennsylvania rules require operators to report total volumes of waste produced every six months 

along with production data for the life of the well.19 In contrast, West Virginia rules only require that 

operators report flowback fluid, defined as all fluid recovered in 30 days following injection or 50% of 

the injected volume, whichever occurs first. As illustrated in Figure 12 and Figure 13, flowback fluid 

 

19 The rectified Pennsylvania dataset, originally obtained from PADEP, includes information for many types of waste: drilling waste, brine, basic 

sediment, fracking fluid, servicing fluid, and spent lubricant (Lutz et al. 2013). These categories are slightly different from the current PADEP 

categories: basic sediment, produced fluid, drill cuttings, flowback fluid, drilling fluid, flowback fracturing sand, servicing fluid, and spent lubricant

(PADEP 2013f).
32 | P a g e

constitutes only approximately 38% of the total volume of waste generated by Marcellus wells in 

Pennsylvania.20

Figure 12: Waste generated from Pennsylvania wells by fluid type (2008-2011)

Source: Lutz et al. (2013). Note: The category “other” includes basic sediment, servicing fluid, and spent lubricant.

Figure 13: Total waste generated from Pennsylvania Marcellus wells, by type (2008-2011)

Source: Lutz et al. (2013). Note: The category “other” includes basic sediment, servicing fluid, and spent lubricant.

 

20 Of the 1,363 million gallons of waste reported from 2008 through 2010, 514 million gallons of flowback fluid were reported (Lutz et al. 2013).
33 | P a g e

Table 21 presents a full breakdown of waste disposal for Marcellus wells in Pennsylvania by method: 

brine/industrial waste treatment plant, UIC well, municipal sewage treatment plant, other, and 

reuse. The total volume of wastewater generated by Marcellus wells has continued to increase each 

year. From 2010 to 2011, the volume increased by almost 70%.

Table 21: Waste disposal method in Pennsylvania (gallons, % of total, 2008-2011)

Disposal method 2008 2009 2010 2011 Total

Brine/industrial waste treatment plant

Average per well 93,690 375,088 130,343 58,647 113,202 

Total, reported 25,296,280 214,175,137 220,931,766 186,321,692 646,724,875 

Percent of total 32% 70% 61% 30% 47%

UIC

Average per well 706 2,962 6,865 21,444 14,291 

Total, reported 190,726 1,691,220 11,636,441 68,126,753 81,645,140 

Percent of total <1% 1% 3% 11% 6%

Municipal sewage treatment plant

Average per well 127,889 44,275 8,004 465 13,102 

Total, reported 34,530,105 25,280,839 13,567,123 1,476,510 74,854,577 

Percent of total 43% 8% 4% <1% 5%

Other

Average per well 45,463 83,620 26,637 4,212 20,752 

Total, reported 12,275,088 47,747,056 45,149,889 13,382,541 118,554,574 

Percent of total 15% 16% 12% 2% 9%

Reuse

Average per well 26,559 32,982 42,165 108,211 77,238 

Total, reported 7,171,024 18,832,831 71,469,602 343,786,587 441,260,044 

Percent of total 9% 6% 20% 56% 32%

Total

Average per well 294,308 538,927 214,015 192,979 238,586 

Total, reported 79,463,223 307,727,083 362,754,821 613,094,083 1,363,039,210 

Source: Lutz et al. (2013). Note: Per-well averages refer to the volume of waste produced by an average well during each year. Older wells produce significantly 

less waste than newer wells. These averages include both new and old wells.21

 

21 Marcellus wells produce a large volume of waste during the first year of production, and then this volume decreases throughout the life of the well. 

Lutz et al. (2013) found that a Pennsylvania Marcellus well produced an average of 360,595 gallons of brine during the first year, which decreased to 

39,626 gallons of brine during the fourth year of production. On average, Pennsylvania Marcellus wells produced 759,230 gallons of brine during the 

first four years of production (Lutz et al. 2013). The per-well averages shown in Table 21 represent something different—the average amount of 

waste generated by the wells active in a single year, including both old and new wells.
34 | P a g e

Figure 14: Waste disposal by method over time in Pennsylvania (2008-2011)

Source: Lutz et al. (2013).

As illustrated in Figure 14, as the total volume of waste produced by Marcellus wells has increased,

an increasing proportion of this waste has been reused in other wells and sent to UIC wells for 

disposal. As both reuse and UIC wells have become more popular disposal methods, the volume 

treated at municipal sewage treatment plants and brine or industrial treatment plants has declined. 

Figure 15: Waste disposal by method in Pennsylvania (average, 2008-2011)

Source: Lutz et al. (2013).
35 | P a g e

On average, almost one-half of recent Marcellus waste in Pennsylvania was sent to brine or industrial 

treatment plants, and almost one-third was reused and recycled in other wells (Figure 15).

Figure 16: Flowback fluid disposal by method over time in Pennsylvania (2008-2011)

Source: Lutz et al. (2013).

For comparison with West Virginia results, an analysis of disposal method of flowback fluid alone was 

conducted. As illustrated in Figure 16, this analysis shows that flowback fluid shows similar trends as 

for all waste types combined. However, higher percentages of this waste type have been reused at 

other wells. In 2011, 74% of all flowback fluid in Pennsylvania was reused.

As shown in Figure 17, while much of the waste generated by Pennsylvania’s horizontal Marcellus 

wells stayed in Pennsylvania, a significant amount was shipped to the neighboring states of Ohio and 

West Virginia. From 2008 through 2011, 88% of waste from horizontal Marcellus wells in 

Pennsylvania actually stayed in Pennsylvania.22 As illustrated in the bottom section of Table 22, 9% 

was shipped to Ohio and 2% was shipped to West Virginia.

Most of the waste fluid generated in these years was kept in-state for treatment and discharge to 

surface waters: 39% was sent to brine or industrial waste treatment plants located in Pennsylvania 

and an additional 15% was sent to municipal sewage treatment plants in Pennsylvania (Table 22). 

Approximately 32% of wastes were reused, and 4% were sent to UIC wells in Ohio for disposal. All 

other combinations of treatment destination states and systems took only 1% or less of total wastes 

from Pennsylvania.

 

22 This percentage does not take into account waste fluid that was recycled and reused or disposed of in “other” category because locations are not 

available for these data.
36 | P a g e

Figure 17: Destination of waste from Pennsylvania Marcellus wells (2008-2011)

Sources: Lutz et al. (2013), PASDA (2013). Note: Marcellus wells that reuse flowback fluid from Pennsylvania wells are not distinguished from other 

wells in this map. Only those UIC wells in this dataset are displayed.
37 | P a g e

Table 22: Interstate transport of waste from Pennsylvania Marcellus wells (2008-2011)

Destination state

Percent of total 

disposed

Percent of disposal 

type total

Brine or industrial waste treatment

Pennsylvania 38% 96%

Ohio 1% 2%

West Virginia <1% 1%

Other <1% 0%

Subtotal, brine or industrial waste treatment 39% 100%

UIC

Pennsylvania <1% 4%

Ohio 4% 96%

West Virginia <1% <1%

Other 0% 0%

Subtotal, UIC 5% 100%

Municipal sewage treatment plant

Pennsylvania 15% 94%

Ohio <1% <1%

West Virginia 1% 6%

Other 0% 0%

Subtotal, municipal sewage treatment plant 15% 100%

Reuse 32% 100%

Other 9% 100%

Total (excluding reuse and other)

Pennsylvania 88%

Ohio 9%

West Virginia 2%

Other <1%

Source: Lutz et al. (2013). Note: Reuse and other volume is not separated by state because locations are not available for 

disposal data in these categories. The percentages in the middle column of this table are similar to, but not exactly the same 

as, those reported in the final column of Table 21 and charted in Figure 14 and Figure 15. This is because some data 

included in Table 21 and these figures were omitted from this table due to insufficient disposal site location information.

5.5 Water removed from the hydrologic cycle

During hydraulic fracturing, water is injected deep below the Earth’s surface. Some, but not all of this 

water eventually returns to the surface where it is recovered by well operators. 

Data are not available for the state as a whole, but between 2009 and 2012, an average of 6% of the 

fluid injected into Marcellus wells in the SRB was captured at the surface (See Table 20). Injected 

water that is not recovered is removed from the hydrologic cycle. Disposing of waste using UIC wells, 

which is becoming increasingly popular, also removes water from the hydrologic cycle. Therefore, 

the volume of water removed from the hydrologic cycle was calculated by adding the volume of fluid 

that was injected but not recovered from Marcellus wells to the volume of waste disposed of in UIC 

wells. 

In contrast to West Virginia, where a single dataset was available from which to estimate totals 

across the state, Pennsylvania calculations require a slightly different approach. The average volume 

of water disposed of at UIC wells as reported to PADEP (See Table 21) was added to the average 

volume that was not recovered according to the SRBC data (See Table 19 and Table 20). To generate 
38 | P a g e

a statewide estimate based on these per-well averages, we multiplied the averages by the total 

number of wells drilled in the state (See Figure 10, above). 

As shown in Table 23, approximately four million gallons of water was lost from the hydrologic cycle 

at each well during the years 2009 through 2011. This is close to the estimated 4.3 million gallons 

injected, on average, per well in Pennsylvania (See Table 18 and Table 19). Between 2009 and 2011, 

an estimated total of 17.8 billion gallons of water were removed from the hydrologic cycle across 

Pennsylvania. 

Table 23: Water removed from the hydrologic cycle by Marcellus wells in Pennsylvania (million gallons, 

2009-2011)

2009 2010 2011 Total

Average per well 3.4 4.1 4.4 4.1

Total, estimated 2,716 6,489 8,653 17,858

Source: Calculated in this report.
39 | P a g e

6. WATER FOOTPRINT OF MARCELLUS SHALE GAS PRODUCTION

6.1 The water footprint approach

The approach used to understand and represent impacts of shale gas extraction on water resources 

in West Virginia and Pennsylvania is a “virtual” or water footprint framework (Hoekstra et al. 2011). 

The water footprint approach aims to integrate dimensions of water withdrawals, consumptive use, 

and water quality impacts into representative metrics of water impact. The purpose of the water 

footprint is to understand impacts and trends, raise awareness, and develop policy that encourages 

best practices and the disclosure of water impacts.

Other studies have attempted to compare natural gas to other electricity sources or transportation 

fuels on a water per unit energy basis (Clark et al. 2011; Scown et al. 2011). The results of this body 

of research have several generalizable conclusions about the relationship between natural gas and 

water resources:

 Electricity from natural gas generally requires less water in the extraction phase than coal 

extraction (Gleick 1995; Fthenakis and Kim 2010); 

 More water is withdrawn for cooling natural gas powered thermoelectric power plants with 

open loop cooling than is used for conventional natural gas extraction (Younos et al. 2009); 

 Electricity from natural gas with open loop cooling requires fewer water withdrawals and 

lower water consumption than coal and nuclear, but has an order of magnitude lower water 

requirement than for geothermal (Dominguez-Faus et al. 2009); and

 Water withdrawal and consumption for solar, wind, and hydropower is negligible in 

comparison to natural gas (Fthenakis and Kim 2010). 

The purpose of a water footprint approach is to better understand how to represent the cumulative 

and relative significance of impacts caused by water use and water pollution. While it has been used 

to measure water impacts of products for some time, it has more recently been applied as an 

indicator of water use in the energy sectors—for example biofuels (Gerbens-Leenes et al. 2009) and 

hydroelectricity (Herath et al. 2011). New water footprint guidelines are available through the World 

Business Council for Sustainable Development (Hoekstra et al. 2011) and ISO 14046 (ISO 2013).

The basic framework for a water footprint analysis is to understand and represent impacts to water 

resources where there are impacts to both water quantity and water quality from producing a 

particular commodity. While an overall water footprint metric can be produced from this framework, 

there are three components. The blue water footprint refers to the volume of surface and 

groundwater consumed (or evaporated) as a result of the production of a commodity. The approach 

to the blue water footprint is similar to other efforts to understand the water use intensity of fossil 

fuel extraction from shale. The grey water footprint of a product refers to the volume of freshwater 

that is required to assimilate the load of pollutants to an acceptable threshold or standard. The 

green water footprint refers to the rainwater consumed and is typically reserved for agricultural 

commodities where a significant amount of water is lost through respiration. 

We use the water footprint approach as a framework to quantify water consumed and understand 

the relative significance compared to impacts to water quality. Water use is typically described as 

water withdrawals and water consumed. “Withdrawals” refer to any freshwater that is temporarily 

or permanently removed from its source, whereas “consumption” is limited to water that is not 
40 | P a g e

returned to its original watershed in the short term or permanently removed form the hydrologic 

cycle (Hoekstra et al. 2011; Scown et al. 2011). 

This water footprint analysis focuses on the fuel acquisition stage of the life cycle of natural gas 

production. The fuel acquisition stage is the point where natural gas is taken from its reservoirs in 

the shale rock formations. Other research has estimated the amount of both water withdrawals and 

water consumption for conventional natural gas extraction (Fthenakis and Kim 2010; Younos et al. 

2009). But for shale gas extraction, most prior studies of water use focused only on water 

withdrawals. In this research, our water footprint methodology focuses on water consumed, which 

we refer to as water removed from the hydrologic cycle.

Much of this research has been normalized based on electricity. Fthenakis and Kim (2010) put water 

withdrawals to extract natural gas at 34.3 gallons per megawatt-hour (MWh) for onshore and 0.2 

gallons per MWh offshore, estimated water consumption to be negligible, and estimated 

withdrawals onsite at 51.9 gallons per MWh for overall fuel extraction and acquisition.23 Inhaber 

(2010) reports that electricity from natural gas requires 20,605.4 gallons of water per MWh overall, 

but this is mostly withdrawals for cooling gas turbines. This water use is considered nonconsumptive, notwithstanding thermal pollution and evaporative losses. 

The scope of the water footprint is the blue and grey water footprint. Green water (evaporated 

rainwater) was determined to be not relevant for this project. The process we evaluated was natural 

gas extraction from Marcellus Shale and the unit of analysis was gallons of water per thousand cubic 

feet (Mcf) of natural gas. We base our analyses on statewide datasets from Pennsylvania and West 

Virginia in which the natural gas industry self-reports data on withdrawals, injections, recovery, and 

disposal. 

6.2 Water footprint per unit energy

Water volumes alone are not enough, however, to appreciate the relative impacts of different 

extraction techniques. A well that requires larger volumes of water may also produce significantly 

more energy over the life of the well. To assess water impacts it is important to look at water use 

and gas production over the life of a well because a large portion of water use comes in the first 

year, while the bulk of gas production occurs over longer time horizons (Lutz et al. 2013; Lewis 2012). 

Accurately assessing water impacts across shale basins or per well site requires normalizing water 

use and impact by unit of energy produced. It is therefore important to know the gas and oil 

production values per well. The normalization based on energy production is a key concept in the life 

cycle water footprint. 

There are several ways to estimate water use per unit energy. The first is to estimate the majority of 

gas production, which occurs in the first four years of production (Lutz et al. 2013). While Lutz et al. 

(2013) did not focus on water use, it is instructive to understand how they normalize wastewater per 

unit energy. Lutz et al. (2013) found that Marcellus wells produce approximately ten times more 

wastewater per well than conventional wells. Yet they point out that compared with conventional 

wells, Marcellus wells also produce over 28 times more gas in four years, on average (Lutz et al. 

2013). Thus Marcellus wells produce less wastewater per unit energy. However, they point out that,

“[d]espite Marcellus wells producing less wastewater per unit gas recovered, the Marcellus Shale is 

massive and the cumulative volume of wastewater generated in the region is growing dramatically” 

(Lutz et al. 2013, p. 6). 

 

23 Reporting water withdrawals in terms of electricity requires careful consideration because it assumes a certain efficiency of combustion to generate 

electricity. 
41 | P a g e

A second approach is to consider a much longer time horizon for gas production. Dale et al. (2013) 

estimated water use per unit energy in a life cycle analysis that also evaluated energy use and 

greenhouse gas emissions from extracting natural gas from the Marcellus Shale in Pennsylvania. 

They used a subset of the water use and waste data reported to Pennsylvania regulators, and they 

normalized these water data over a 30-year production interval to produce the data set for gas 

production shown in Table 24. They distinguished 728 wells started from 2008 to 2010 from wells

started in 2011. They found that wells started in 2011 required 0.677 gallons/Mcf, a 2% reduction in 

water use compared to wells started from 2007–10. 

Table 24: Thirty-year production estimates and water use per unit energy for shale gas

Gas production Water use per unit

Well start mcm Mcf energy (gallons/Mcf)

2008–10 72 2,754,237 0.694

2011 108 3,813,559 0.677

Source: Dale et al. (2013).

The Dale et al. (2013) study addresses the question of whether the industry is getting better at 

lowering the overall water impacts from shale gas extraction. They conclude, “although improved 

fracturing processes have reduced the amount of water on a per-stage basis, longer laterals and 

additional fracturing stages nullify these improvements in our results. However, changes to flowback management mean more water is reused and less is permanently disposed of in injection wells” 

(Dale et al. 2013, p. 5463). There have been improvements in water use efficiency per unit of energy 

produced, but the overall exploitation of the Marcellus play is swamping any efficiency or 

conservation gains. In other words, the per-well reductions in water use are far outpaced by the 

overall water use.

Dale et al. (2013) also conclude that, “with the rise of large-scale reuse of wastewater and more 

robust water pipeline and storage networks, high-level concerns over water consumption, at least in 

the relatively water-rich states that overlie the Marcellus, should be focused on excessive water 

withdrawals from specific bodies of water or during specific times rather than overall water quantity 

used for fracking” (p. 5465). In other words, some water bodies may leave communities or 

ecosystems more vulnerable than others during times of water stress, and efforts should focus on 

these areas instead of overall water use. 

Other studies also focus on the lifetime production of the well, but do not specify the number of 

years of gas production. Mielke et al. (2010) compiled findings from the US Geological Survey (USGS) 

(Soeder and Kappel 2009) and estimated the volume of water consumed per unit energy for 

Marcellus Shale gas extraction is 1.2 gallons/Mcf. Using values from Chesapeake Energy, Mantell 

(2011) estimates the water use efficiency from the fracking process to be 1.07 gallons/Mcf. The 

values are collectively reported in Table 25 below, which shows a range from 0.677 gallons/Mcf (Dale 

et al. 2013) to 1.2 (Mielke et al. 2010). Such a variation might be anticipated, as there is no 

conclusive information about the lifetime production of a shale gas well. 

Table 25: Estimates for volumes of water consumed per unit of energy

Water Use (gallons/Mcf) Timeframe evaluated Source

1.2 Not specified, life of well assumed Mielke et al. 2010

0.677–0.694 30 years (assumes no re-stimulation) Dale et al. 2013

1.07 Not specified, life of well assumed Mantell 2011
42 | P a g e

6.3 Blue water footprint

6.3.1 West Virginia

To understand the water footprint results it was important to establish the production of natural gas 

per well. Water use per well for natural gas from shale is significantly more than in conventional 

wells, but natural gas production is also much higher. Our goal was to use published estimates and 

their assumptions to characterize the gas production from Marcellus Shale gas wells.

24 Wells are 

most productive early in their lifetime unless re-stimulated, so the wells’ most productive years are 

the first four years (Lutz et al. 2013). King (2010; cited in Lewis 2012) suggests that well production 

declines exponentially over time, with five to ten years of viable production. These considerations 

helped justify using four-year production estimates to normalize the water use per well. 

There are no published data showing actual lifetime gas production from West Virginia horizontal 

Marcellus wells on a per-well basis. This is understandable, given that horizontal drilling began so 

recently. Per-well estimates of natural gas production from the Marcellus Shale do exist for 

Pennsylvania, but may have significant uncertainties because of the way the data were extrapolated. 

Lewis (2012) estimates that, in its first four years, a single Marcellus well will on average produce 

1,030,910 Mcf (See Table 26). Based on the four-year annual production and decline estimate shown 

in Table 26, approximately 40% of the four-year production total occurs in the first year. Lewis (2012) 

did not correct for the fact that the first year is typically not a full calendar year, and notes that this 

first year of production may be an underestimate. Nonetheless, this estimate of annual production 

and decline over four years were the most appropriate estimates to apply to West Virginia wells.25

Table 26: One estimate of annual production and decline over four years for Pennsylvania Marcellus 

wells (Mcf)

First

year

Second 

year

Third

Year

Fourth

year Total

Mean 396,100 439,600 138,700 56,510 1,030,910

Confidence interval26 25,900 35,100 17,900 14,600 --

Source: Lewis (2012).

Even though these values were produced for Pennsylvania wells, we assumed that the shale 

formations across the Marcellus have similar declines in gas production over four years and applied 

this first-year percentage to actual production data from West Virginia to estimate production for a 

given well. From Table 26, also note that the fourth year production is only approximately 5% of 

cumulative four-year production. 

Monthly production data were available for all wells that produced natural gas in West Virginia for 

each of the years of interest: 2010, 2011, and 2012. Only those 174 wells with both complete water 

 

24 Our approach did not consider any shale oil co-produced with natural gas. Many Marcellus Shale wells report oil production in addition to natural 

gas production, but these volumes are orders of magnitude smaller on a unit energy basis. The ISO 14040 (2006) framework and principles for life 

cycle analysis aim to prevent allocating impacts to co-products when they are not the primary economic driver of activities that cause the impacts. 

For this reason, we excluded any energy from oil from our normalization. Oil only constitutes a small fraction of the overall energy produced from 

these activities. A displacement approach could be used to credit natural gas production with the avoided burden of producing that volume of oil. But 

since other oil extraction techniques use far less water, it is not clear that these burdens could be avoided. In other words, any oil that is co-produced 

with natural gas does not displace any water use from oil extraction elsewhere. 

25 Another estimate of natural gas production over time demonstrated similar results. Duman (2012) estimated 10-year and 20-year production 

horizons, and this work suggested that 40.5% of the four-year production occurs in the first year. 

26 The confidence interval is used to estimate the uncertainty in the reported mean. The confidence intervals in Table 26 were estimated by Lewis 

(2012) because that study aimed to compare shale gas production to conventional gas production. Estimating confidence intervals allows one to 

ensure that any difference in the mean are not a result of uncertainty. Because we were not comparing this production curve to any other production 

curve, estimating an overall confidence interval was not necessary. 
43 | P a g e

and natural gas production data were analyzed. Ideally, natural gas production would be summed for 

an annual production rate. However, the data revealed that wells were not operating for the entire 

calendar year, with each beginning production during different months during the given year. Once a 

well started producing, it typically continued to produce through the end of the calendar year. 

To approximate a first-year production value, we took the reported monthly production in West 

Virginia for all wells with active production in our sample and estimated a monthly production 

average using all months with non-zero production. We summed the gas production for a given year 

and divided by the number of months. This monthly production average was extrapolated to 

approximate a value for 12 months of production. In other words, we aimed to estimate how much 

gas the well would have produced had it started producing gas on January 1st and continued through 

the end of the year. This was repeated for each year 2010, 2011, and 2012 and used as a first-year 

production proxy for all wells (See Table 27). An average per well was later obtained by dividing by 

the well count.

Table 27: Derivation of first-year production proxy for West Virginia wells (2010-2012)

Year Well count

Production 

from all sample wells (Mcf)

First-year production proxy

for all sample wells (Mcf)

2010 39 14,385,934 33,000,000

2011 93 35,158,685 77,000,000

2012 42 35,762,095 60,000,000

These proxy first-year production volumes were used in a model that projects a four-year production 

estimate. We chose a four-year total because Lutz et al. (2013) determined that the first four years 

are when the majority of gas is produced. As described above, approximately 40% of the well’s fouryear gas production occurs in the first year. Taking the annual estimates made above for each year, 

Table 28 provides the four-year production volumes. It is not clear what is driving the trend, but the 

2012 wells in our sample are projected to be significantly more productive per well. 

In the event that the 40% value underestimates gas production, we performed sensitivity analyses 

that assumed wells produced more gas than in the four-year period from the same water 

withdrawal. As described in Table 26, only about 5% of the cumulative gas production over four 

years occurs in that fourth year. For our sensitivity analysis we assumed that wells produce at the 

fourth year production rate for an additional two years (the six-year scenario) and six additional 

years (the ten-year scenario) before new water additions are required to re-stimulate production. In 

other words, we estimate that production over six years would be approximately 110% of the fouryear production estimate, and production over ten years would be approximately 130% of the fouryear production estimate. These per-well production values appear in Table 28 and were used to 

normalize the blue and grey water footprints. 

Table 28: West Virginia production volumes (Mcf, 2010-2012) 

All sample wells Per well

Year wells 

started

4 years of 

production

4 years of 

production

6 years of 

production

ten years of 

production

2010 82,500,000 2,100,000 2,310,000 2,730,000

2011 192,500,000 2,100,000 2,310,000 2,730,000

2012 150,000,000 3,600,000 3,960,000 4,680,000

Note: These calculations are based on annual production and the four-year production curve estimated by Lewis 2012, as well as 

sensitivity analyses based on six- and ten-years of production before need for additional water injection. Lutz et al. (2013) suggest that 

additional water withdrawals are required every five to ten years.
44 | P a g e

We also used a longer-range production value as a sensitivity. Dale et al. (2013) estimate that a 

single Marcellus well will produce 3,813,559 Mcf over 30 years. They used samples from PADEP 

production data collected in six-month periods, which contained both total production and days of 

production. A regression was performed on each well based on production per day to estimate a 

total production over 30 years. Well production may extend 30 years and perhaps even beyond;

however, Marcellus well production begins to decline significantly after the first or second year and 

requires re-stimulation with new water injections after five to ten years (King 2010). This increase in 

water use would be accompanied by an increase in gas production. Currently, there are no studies 

that estimate the relationship between well stimulation, water use, and gas production. Hence, if 

water use is normalized by the 30-year estimate of natural gas production, it is very likely 

underestimating water use—perhaps even significantly so. 

As illustrated in Table 29, the volume of water removed from the hydrologic cycle was divided by the 

amount of natural gas produced to provide a water footprint for shale gas extracted in West Virginia 

normalized by energy production. The “four years of gas production” scenario is based on the West 

Virginia production data as suggested above. The “30 years of gas production” scenario is based on 

values from Dale et al. (2013), which is likely an overestimate for gas production per water injection 

given the need to re-stimulate a well via water injection after five to ten years, though technological 

advances (so-called zipper frac technology, for example) may eliminate the need for re-stimulation. 

Hence, we interpret the 30-year scenario as the high range sensitivity to the analysis. Dale et al. 

(2013) found that wells started in 2010 would produce 2,754,237 Mcf and those started in 2011 

would produce 3,813,559 Mcf. The 2012 well-starts were assumed to have a similar profile as the 

wells started in 2011, but 2012 was not evaluated by Dale et al. (2013).27

Table 29: Blue water footprint for Marcellus wells in West Virginia (gallons/Mcf)

Basis 2010 2011 2012

Four years of gas production 2.2 2.2 1.6

Sensitivity to gas production estimates

Six years of gas production 2.0 2.0 1.4

Ten years of gas production 1.7 1.7 1.2

30 years of gas production 1.7 1.2 1.5

As Table 29 shows, the blue water footprint—the volume of surface and groundwater consumed—

ranges from 1.6 to 2.2 gallons of water per Mcf on a four-year production basis. If we assume the 

well will continue to produce gas at the rate found in year four for two additional years (six years 

total) the range is from 1.4 to 2.0 gallons of water per Mcf, and if we extend this rate out to ten 

years, the range is from 1.2 to 1.7 gallons of water per Mcf. On a 30-year basis, assuming no 

additional water injections, the blue water footprint ranges from 1.2 to 1.7 gallons of water per Mcf. 

These values are higher than the only other peer-reviewed estimate of water use per unit energy on 

the Marcellus Shale by Dale et al. (2013), which suggested that gas production from Marcellus Shale 

is only 0.7 gallons per Mcf. It is likely that this discrepancy is because Dale et al. (2013) used the 30-

year production horizon, but did not consider the volume of water that would be required to restimulate the well several times over the 30-year life of a well. Considering the four-year production 

scenario, and the sensitivity analyses, the range of 1.2 to 2.2 gallons of water per Mcf of natural gas

is narrow enough to suggest that these values are consistent. 

 

27 We applied the same Dale 30-year production estimates to both West Virginia (Table 29) and Pennsylvania (Table 31). Even though our data 

suggests different production estimates for West Virginia and Pennsylvania wells, we wanted a conservative estimate for gas production per water 

injection in our sensitivity analysis.
45 | P a g e

6.3.2 Pennsylvania

For Pennsylvania, we aimed to take a similar approach to the one used for West Virginia; however, 

there is a major difference in the way that the states report production. In Pennsylvania, production 

has been reported in six-month intervals since 2010, while West Virginia requires monthly 

production totals be reported. Therefore, the method of estimating gas production used for West 

Virginia could not be used for Pennsylvania. A lack of data for 2012 also meant we looked at a 

different time period for Pennsylvania (2009 to 2011) than West Virginia (2010 to 2012). 

Therefore, for Pennsylvania, we used per-well production values described by Lutz et al. (2013) that 

put per well production values at 1,062,000 Mcf over four years. Our preference would have been to 

modify these results based on the average increase is gas production per well as companies improve 

their extraction techniques, but our West Virginia sample of gas production show no significant 

change in gas production from 2010 to 2011 and a 44% increase from 2011 to 2012. Since 2012 was 

not in our Pennsylvania timeframe for analysis, we decided that the Lutz et al. (2013) estimate was 

most appropriate. 

The results below were normalized by natural gas production to give the total water removed from 

the hydrologic cycle per unit of natural gas produced. The total water removed from the hydrologic 

cycle by Marcellus wells in Pennsylvania was divided by the average production from a Marcellus gas 

well in Pennsylvania over a four-year period to provide the blue water footprint, which ranges from 

3.2 to 4.2 gallons per Mcf of natural gas production from Marcellus Shale. This is significantly higher 

than the results for West Virginia reported in Table 29, which suggested a range of 1.2 to 2.2 gallons 

of water per Mcf. 

Table 30: Initial blue water footprint calculations for Marcellus wells in Pennsylvania (2009-2011)

Well start year

Four-year gas production per 

average Marcellus well (Mcf)

Water removed from the 

hydrologic cycle (gallons)

Blue water footprint 

(gallons/Mcf)

2009 1,062,000 3,352,802 3.2

2010 1,062,000 4,071,156 3.8

2011 1,062,000 4,417,035 4.2

Sources: Gas production from Lutz et al. (2013). Water removed from the hydrologic cycle are un-rounded values from Table 23 of this report.

One explanation for the difference between the Pennsylvania and West Virginia results may be 

related to the waste reporting practices. In West Virginia, only flowback fluid is reported—not all of 

the waste produced. However, the major driver appears to be that the data used for average gas 

production per well is much lower in Pennsylvania, as compared with West Virginia. 

Using a similar approach to the water use data for West Virginia, we estimated the sensitivity of the 

water footprint per unit energy to overall gas production. We used the production estimates in Table 

26 and assumed that wells produce two additional years at the fourth year rate (the six year 

scenario), and an additional six years at the fourth year rate (the ten year scenario). We also 

estimated the sensitivity of the blue water footprint to the amount of gas produced by using the Dale 

et al. (2013) estimates for a 30-year time horizon. The Dale et al. (2013) analysis lumped 2008 

through 2010 into one average estimate, so we applied the same value to 2009 and 2010. The 

sensitivity of the blue water footprint to gas production is reported in Table 31.
46 | P a g e

Table 31: Blue water footprint for Marcellus wells in Pennsylvania (gallons/Mcf)

Basis 2009 2010 2011

Four years of gas production 3.2 3.8 4.2

Sensitivity to gas production estimates

Six years of gas production 2.9 3.6 3.9

Ten years of gas production 2.4 3.0 3.2

30 years of gas production 1.2 1.5 1.2

The results in Table 31 show a range of 3.2 to 4.2 gallons of water per Mcf from 2009 to 2011. This is 

in line with the 30-year blue water footprint in West Virginia, which ranged from 1.2 to 1.9 gallons 

per Mcf for the three years of analysis. These values are higher than the 0.7 gallons per Mcf estimate 

provided by Dale et al. (2013). As we describe above, the values used by Dale et al. (2013) appear to 

ignore water use associated with re-stimulating the well several times over the 30-year life of the 

well. While we do not question the Dale et al. (2013) methodology to estimate gas production over 

30-year life of the well, we do question the assumption that water withdrawals only occur once.

These blue water footprint metrics allow for a rough assessment of how much water is removed 

from the hydrologic cycle per unit of energy. In addition, coupled with the grey water footprint 

described in the following section, these blue water footprints serve as a basis for representing the 

cumulative impacts to water resources.

6.4 Grey water footprint

The grey water footprint of a product or process is “an indicator of the severity of water pollution, 

expressed in terms of the freshwater volume required to assimilate the existing load of pollutants” 

(Hoekstra et al. 2011). The dilution factor in a grey water footprint represents the number of times 

the effluent volume should be diluted to meet acceptable concentration thresholds. The basic 

premise behind the grey water footprint has been to understand how much water would be required 

to dilute polluted wastewater to some specified water quality standard. Research by Falkenmark and 

Lindh (1974) was one of the first attempts to make water pollution commensurate with water 

quantity, suggesting that a dilution factor of ten to fifty times the volume of wastewater flow is an 

adequate representation of pollution impacts on water resources. Research by Chapagain (2006) 

later distinguished dilution factors by type of pollutant and categories of emissions. This allowed for 

a better representation of impacts in the circumstances where the results would be sensitive to 

pollutants that are far above regulatory thresholds relative to other pollutants. Hoekstra and 

Chapagain (2008) introduced and linked the term grey water footprint to this approach.

The purpose of integrating this grey water footprint into the study is to understand the relative 

impacts of water pollution versus water consumption. Fracking can have impacts for both, but it 

becomes important to understand the relative magnitude of impacts to water quantity versus water 

quality. This may help policy makers and regulators focus on whether they should emphasize 

stronger rules on water use versus disposal, or both. Grey water footprints also can increase 

understanding of how pollutants are assimilated into the environment as well as the extent to which 

they stress existing municipal and industrial treatment plants. So long as grey water volumes remain 

below the surface and groundwater flows, any pollutants will be assimilated at concentrations below 

the selected standards. There are many caveats and assumptions that limit the applicability of these 

results, but a grey water footprint can provide an order-of-magnitude characterization of water 

pollution.
47 | P a g e

For this project we estimated the volumes of flowback water from natural gas wells and used 

published estimates for average concentrations of contaminants found in these waste streams. For 

thresholds, we used federal drinking water standards established by USEPA (2013b). These include 

the Maximum Contaminant Level Goal (the concentration at which there is no anticipated risk to 

health), the Maximum Contaminant Level (the highest permitted level for drinking water), and the 

Secondary Drinking Water Standard (a non-enforceable guideline). We also used contaminant 

thresholds developed by a special rule adopted in Pennsylvania that specified treatment standards 

for water treatment facilities receiving waste from oil and gas operations. It is also important to note 

that some contaminants do not have regulatory standards or recommended best practices. The 

absence of these thresholds does not necessarily imply absence of a water quality issue. 

The contaminants chosen for evaluation in the grey water footprint were ones that were both 

present in previous studies of the composition of flowback fluid and those that had drinking water 

standards or discharge standards particular to waste from shale gas operations. Table 32 lists these 

contaminants and the standards. Of all the standards in this table, we chose the most stringent to 

benchmark the dilution factor. Where standards are zero, such as the case with some metals such as 

lead, the threshold chosen was the actionable level (USEPA 2013c). The dilution factor is the amount 

of water required to dilute the average concentration found in flowback water to the most stringent 

threshold. Because the average concentrations as well as the regulatory thresholds differ by 

pollutant, this approach helps identify which contaminants have the largest relative potential 

impacts on water pollution. 

Table 32: Contaminants and thresholds screened in this research (mg/L)

Contaminant

USEPA Maximum 

Contaminant Level 

Goal

USEPA Maximum 

Contaminant 

Level

USEPA 

Secondary 

Standard

Pennsylvania rule 

adopted in 2010

Barium 2 2

Chloride 250 250

Bromide28 0.1 0.1

Sodium 2029

Sulfate 250

Lead 0 0.015

Iron 0.3

Manganese 0.05

Benzene 0 0.005

Toluene 1 1

Strontium 4

30

Alpha particles 0 15

Nitrate 10 10

TDS 500

Sources: Drinking water standards from USEPA (2013b). The supplemental information for Olmstead et al. 2013 describes the 

Pennsylvania rule adopted in 2010. Many of the contaminants in Table 33 did not have standards or recommended best practices that 

could be applied to this analysis.

Table 33 shows estimates of contaminant concentrations found in flowback water. Flowback water 

data came from various sources, including the permitting manual for oil and gas development in New

York (BOGM 2011) and a more recent draft environmental impact statement for revised permitting 

(NYSDEC 2001), which were reported as upper and lower ranges for effluent concentrations, as well 

as median and maximum discharges. Another important source was Hayes (2009), who provided a 

 

28 There is no standard for bromide, but USEPA says that pristine groundwater has a concentration of 0.1 mg/L. 

29 There is no standard for sodium, but concentrations above this level can be of concern to those on low sodium diets (USEPA 2013d; Penn State 

Extension 2013).

30 There is no standard for strontium, but USEPA has developed a lifetime health advisory aiming to keep strontium below 4 mg/L (ATSDR 2013). 
48 | P a g e

more extensive list of contaminants found in wastewater. Hayes (2009) reported upper and lower

ranges from both five days post-hydraulic fracturing and 14 days post-hydraulic fracturing based on

five samples of flowback water collected at each of 19 well sites. These two sources listed 28

contaminants and water quality criteria.31 But not all contaminants or water quality parameters 

known to be present in flowback fluid were surveyed because they did not all have drinking water 

standards or specific discharge standards for facilities treating flowback fluid.

Table 33: Marcellus flowback water data used to calculate grey water footprint (mg/L unless otherwise 

specified)

Averages

5 days post hydraulic 

fracturing

14 days post hydraulic 

fracturing

Contaminant

Lower 

Estimate

Upper 

Estimate

Median 

Estimate

Lower 

Estimate

Upper 

Estimate

Lower 

Estimate

Upper 

Estimate

Barium 0.553 15,700 1,450 21.4 13,900 43.9 13,600

Chloride 287 228,000 56,900 26,400 148,000 1,670 181,000

Bromide 185 1,190 15.8 1,600

Sodium 10,700 65,100 26,900 95,500

Sulfate 2.4 106 < 10 89.3

Lead Non-detect 0.606 Non-detect 0.349

Iron 0 810 29.2 21.4 180 13.8 242

Manganese 0.881 7.04 1.76 18.6

BTEX32 Non-detect 5.46

Strontium 0.501 5,841 1,115 345 4,830 163 3,580 J 

Nitrate < 0.1 1.2 < 0.1 0.92

TDS 1,530 337,000 63,800 38,500 238,000 3,010 261,000

Sources: Averages are from BOGM (2001) and NYSDEC (2011); The 5 days and 14 days post hydraulic fracturing estimates are from Hayes (2009). There are 

a number of contaminants here that did not have published values in the Marcellus Shale, but are believed to be constituent contaminants of waste. Unlike the 

rest of the parameters in his study, Hayes (2009) reported Alpha particles from a range of non-detect to an upper range, but also a median (Non-detect –

18,000 pCi/L; median 2,460 pCi/L).

The grey water footprint approach suggests representing the degree of water pollution as the 

volume of water required to assimilate the pollution to meet selected water standards. To estimate 

this grey water footprint, we chose the most stringent of the low and high ranges where multiple 

values were available. Using the contaminant concentration at each of the upper, median, and lower

values and dividing by the relevant threshold, we produced a dilution factor. The equation for the 

volume required to dilute the contaminant to the chosen threshold is: 

Dilution Factor = Contaminant Concentration / Water Quality Threshold

We did this separately for each contaminant with water quality parameters listed in Table 32. The 

dilution factor was multiplied by the total volume of water disposed to produce the grey water 

footprint. These data were from the same per well data used in the blue water footprint analysis 

where we aimed to use only wells with complete gas production and water use and disposal. The

grey water footprint aims to understand the indicator for water quality per unit energy, so the 

product of flowback water disposed per well and the dilution factor were divided by natural gas 

production per well. 

Grey Water Footprint = Water Disposed x Dilution Factor

 Natural Gas Production

 

31 Water quality criteria reported for flowback fluid in BOGM (2011), NYSDEC (2001), and Hayes (2009), but not used in the grey water footprint 

include oil and grease, pH, alkalinity, acidity, hardness, total Kjeldahl Nitrogen, ammonia, volatile and semi-volatile organic compounds, total organic 

carbon, dissolved organic carbon, chemical oxygen demand, biological oxygen demand, turbidity, and TSS. 

32 Benzene, toluene, ethylbenzene, and xylene (BTEX) was used as the proxy for the toluene and benzene dilution estimates.
49 | P a g e

Table 34: Primary contaminants, thresholds, and volume ranges for grey water footprint

Upper

(mg/L)

Median

(mg/L)

Lower

(mg/L)

Water quality 

threshold 

(mg/L)

Source for 

threshold

Dilution factor 

range

Barium 15,700 1,450 0.553 2.00 USEPA 7,850–0.3

Chloride 228,000 56,900 287 250.0 PA 2010 rule 912–1.1

Bromide 1,600 - 15.8 0.1 USEPA 16,000–158

Sodium 95,500 - 10,700 20.0 USEPA 4,775–535

Iron 810 29.2 non-detect 0.3 USEPA 2,700–0

Manganese 18.6 - 0.881 0.05 USEPA 372–17.6

Lead 0.606 - non-detect 0.0015 USEPA 404–0

Benzene 5.46 - non-detect 0.005 USEPA 1,092–0

Toluene 5.46 - non-detect 1.0 USEPA 5.5–0

Strontium 5,841 1,115 0.501 4.0 USEPA 1,460–0.1

TDS 337,000 63,800 1,530 500.0 PA 2010 rule 674–3.1

Sources: Upper, median, and lower concentrations from Table 33. Thresholds from Table 32.

6.4.1 West Virginia

The grey water footprint for West Virginia was based on the per-well data with complete gas 

production and flowback water disposal data. The flowback water was multiplied this maximum 

dilution factor. This volume required to dilute the flowback water was normalized per Mcf of natural 

gas production. The results are in Table 35, which also shows which contaminant drives the grey 

water footprint at the upper, median, and lower limits. These results suggest a declining grey water 

footprint from 2010 to 2012, which is due to a smaller volume of flowback fluid per unit energy. 

Table 35: Grey water footprint for Marcellus wells in West Virginia (2010-2012)

Well year Contaminant

Upper 

(gallons/Mcf) Contaminant

Median 

(gallons/Mcf) Contaminant

Lower 

(gallons/Mcf)

2010 Bromide 1,000 Barium 50 Sodium 40

2011 Bromide 600 Barium 30 Sodium 20

2012 Bromide 500 Barium 20 Sodium 20

6.4.2 Pennsylvania

A similar approach was used to estimate the grey water footprint for Pennsylvania wells. These 

estimates were based on wells with full flowback water and natural gas production data. As Table 36

suggests, there is no significant decline in the grey water footprint from 2009 to 2011, as there is in 

West Virginia. The same water quality data and thresholds were used for Pennsylvania, so the same 

contaminants drove the upper, median, and lower thresholds. 

Table 36: Grey water footprint for Marcellus wells in Pennsylvania (2009-2011)

Well year Contaminant

Upper 

(gallons/Mcf) Contaminant

Median 

(gallons/Mcf) Contaminant

Lower 

(gallons/Mcf)

2009 Bromide 900 Barium 40 Sodium 30

2010 Bromide 800 Barium 40 Sodium 30

2011 Bromide 1,000 Barium 40 Sodium 30
50 | P a g e

6.4.3 Summary of grey water footprint results

The results of the grey water footprints from West Virginia and Pennsylvania suggest a few trends. 

The contaminant in the upper thresholds that requires the largest volume of water to dilute is 

bromide, followed by barium, sodium, and iron. Sodium is the primary driver in the least 

contaminated water and the difference between the high and low thresholds for sodium are only 

one order of magnitude as opposed to two, three, or four orders of magnitude for the other 

contaminants. If not for the high levels of sodium in the lower range of representative samples, it 

would be much easier to dilute pollution from the “cleanest” flowback fluid.

Compared to the blue water footprints, the grey water footprints can be significant because of very 

high concentrations of contaminants. Even at the lower bound of contamination, the difference is 

two orders of magnitude, meaning that one-hundred times more water would be required to dilute 

the water pollution per Mcf than is removed from the hydrologic cycle. At the upper bounds the 

difference is four orders of magnitude per Mcf compared to water removed from the hydrologic 

cycle. 

The grey water footprint estimates here are used as an indicator to understand the relative 

magnitude of water pollution versus water use estimates. It is not a direct measure of water use. 

There are obvious limitations to grey water indicators, because water pollution is not being diluted in 

the way the indicator suggests. Most flowback fluid is being recycled or disposed of in UIC wells or at 

wastewater treatment facilities. However, at two orders of magnitude difference, we can get a 

better sense for how flowback water destined for disposal might stress water treatment facilities. In 

cases where there is illegal or improper disposal, we can also gain an order of magnitude assessment 

of how much this water pollution will impair freshwater sources. In sum, the grey water footprints 

represented here show that the water resource implications for hydraulic fracturing for natural gas 

are both an issue of water quantity and water quality, not one or the other as is often suggested. 
51 | P a g e

7. CONCLUSIONS AND RECOMMENDATIONS

Several teams of researchers are studying whether, and how, horizontally drilled, hydraulically 

fractured Marcellus wells impact water resources. In this report, we add to this body of literature by 

analyzing the self-reporting data collected in West Virginia and Pennsylvania related to water 

withdrawals and fluid injection, recovery, and disposal. We also calculate blue and grey water 

footprints and consider improvements to the data collection and reporting requirements that would 

facilitate even better data analysis in the future.

7.1 West Virginia

7.1.1 Water and fluid flows

As shown on the following page, our analysis of self-reporting data has resulted in a variety of 

estimates of water withdrawals and fluid injection, recovery, and disposal in recent years in West 

Virginia. Figure 18 summarizes several key results. 

On average, in recent years, approximately 5 million gallons of fracturing fluid has been injected per 

well. Surface water, by far, is the largest source of water, although reused flowback fluid has 

accounted for approximately 8% of total withdrawals.

Of the fluid injected underground, only 8%, on average, returns to the surface in the time frame 

captured by West Virginia reporting requirements; the rest remains underground. The water 

contained in the fracturing fluid that remains underground, together with that disposed of in UIC 

wells, is removed from the hydrologic cycle and is included in our blue water footprint calculations.

The flowback fluid reported as waste in West Virginia represents only approximately 38% of the total 

volume of Marcellus waste. This is because West Virginia only requires operators to report flowback 

fluid volumes once, in comparison to the Pennsylvania requirements to report of all types of waste 

every six months into the future.

Almost one-half of flowback fluid recovered in West Virginia is transported out of state. Between 

2010 and 2012, 22% of recovered flowback fluid was sent to Pennsylvania, primarily to be reused in 

other Marcellus operations, and 21% was sent to Ohio, primarily for injection in UIC wells.

Potential impacts to West Virginia’s surface waters are most likely to occur from water withdrawals, 

and not from waste disposal. Very little flowback fluid from West Virginia is sent to treatment plants 

that discharge to surface waters; however, most water used in Marcellus operations is withdrawn 

from surface waters. If these withdrawals are not timed appropriately, especially on small streams, 

aquatic life can be harmed if dewatering occurs. Pursuant to new rules, operators must now 

demonstrate that sufficient in-stream flow will be available immediately downstream from surface 

water withdrawal locations. Effective enforcement of these rules will be critical to protect the state’s 

surface waters.

The three-state region—which includes West Virginia, Pennsylvania, and Ohio—is tightly connected 

in terms of waste disposal. Flowback fluid from West Virginia wells is recycled and shipped to 

Marcellus wells in Pennsylvania, and flowback fluid is also shipped to UIC wells in Ohio for disposal.
52 | P a g e

Figure 18: Summary of key West Virginia water and fluid flows

Water 

Withdrawals

Mostly surface water

Injected 

fracturing fluid 

~5 million gallons/well

Flowback fluid

~38% of total waste

~8% of injected 

fracturing fluid

Most of 

remainder to 

Pa. wells

Remains 

underground

~92%

Injected in UIC 

wells (Ohio and 

W.Va.)

~27% of flowback fluid

Removed from hydrologic cycle

Reused

~72% of flowback fluid 

~8% of withdrawals

Most to 

W.Va. wells

Other waste

Data not reported in 

W.Va.

~62% of total waste

Source: All figures calculated in this report. 
53 | P a g e

KEY WEST VIRGINIA RESULTS

 From 2010 through 2012, approximately 2 billion gallons of water was withdrawn from 

surface and groundwater, purchased from public or private water suppliers, or obtained 

from other wells for use in Marcellus gas production in West Virginia (See Table 7).

 Surface water was the most widely utilized source of water used in Marcellus well 

development. Approximately 1.6 billion gallons of water have been withdrawn from West 

Virginia’s surface waters for injection in horizontal wells in the Marcellus, representing 81% 

of all withdrawals (See Table 7).

 Reuse as a percentage of total withdrawals has increased somewhat in West Virginia, but 

still only totaled 10% of withdrawals in 2012 (See Table 7).

 In West Virginia, an estimated 3.9 billion gallons of fluid have been injected into horizontal 

wells in the Marcellus since 2010. Horizontal Marcellus wells injected an average of 

approximately 5 million gallons during this period (See Table 10).

 Most fluid injected into Marcellus wells in West Virginia never returns to the surface (Figure 

6). Between 2010 and 2012, only 8% of injected fluid was recovered in the time frame 

captured by the reporting requirements.

 On average, horizontal Marcellus wells in West Virginia disposed of approximately 0.4 

million gallons of fluid per well (Table 11). 

 Between 2010 and 2012, 78% of recovered flowback fluid was reused; however, the 

percentage of recovered flowback fluid that is reused has dropped in recent years, from 

88% in 2010 to 73% in 2011 and 65% in 2012 (Table 11). While most recovered fluid is 

reused, the reused fluid still represents only a small percentage of total withdrawals used 

to service Marcellus wells in West Virginia.

 The percentage of flowback fluid disposed of at UIC wells increased from 12% in 2010 to 

26% in 2011 and 35% in 2012 (Table 11). 

 From 2010 through 2012, only 57% of recovered flowback fluid from horizontal Marcellus 

wells in West Virginia actually stayed in West Virginia, while 21% was shipped to Ohio 

(primarily to UIC wells) and 22% was shipped to Pennsylvania (primarily for reuse at other 

Marcellus wells) (Table 13).

 On average, about 4.7 million gallons per well were removed from the hydrologic cycle by 

horizontal Marcellus wells in West Virginia between 2010 and 2012 (Table 14). This totaled 

an estimated 3.7 billion gallons.

 In West Virginia, the blue water footprint, which represents the volume of water removed 

from the hydrologic cycle per unit of gas produced, ranged from 1.6 to 2.2 gallons per Mcf. 

When considering the sensitivity of these results to higher natural gas estimates, the range 

dropped to 1.2 to 2.0 (Table 29). 
54 | P a g e

7.1.2 Data collection and reporting

In the face of an unprecedented growth in the number of Marcellus wells that have been permitted, 

drilled, and hydraulically fractured in recent years, the West Virginia Legislature and WVDEP have 

taken steps to improve data collection and reporting. As summarized in Table 37, current West 

Virginia laws and regulations require operators to compile and report key information related to 

withdrawals, injections, recovery, and disposal. Although these data are not compiled into a formal 

database that is accessible online, Microsoft Excel spreadsheets with all submitted data are compiled 

by WVDEP and provided freely upon request. 

Table 37: West Virginia data reporting

Category of data

Form where data 

is reported

Required or 

voluntary?

Data reported by 

operators?

Reported data 

compiled into 

searchable 

database?

Searchable 

database publicly 

available?

Water withdrawals Frac Water 

Reporting Form Required Incomplete Yes Upon request

Fluid injection volume Frac Water 

Reporting Form Required Incomplete Yes Upon request

Chemicals in fluid

Well completion 

report and 

FracFocus

Required starting 

July 1, 2013 Unknown

FracFocus data 

searchable via 

SkyTruth

FracFocus data 

available via 

SkyTruth

Waste recovery Frac Water 

Reporting Form

Required for 

flowback only Incomplete Yes Upon request

Waste disposal Frac Water 

Reporting Form

Required for 

flowback only Incomplete Yes Upon request

Note: West Virginia operators have a one-year reporting deadline to report water withdrawals, fluid injection, waste recovery, and waste disposal volumes; however, it 

is not specified when the timeline begins, and this deadline is not enforced. Research presented in this report suggests that data reported to WVDEP for wells 

permitted in 2010 and 2011 is incomplete. The searchable databases referred to in this table are Excel spreadsheets available upon request from WVDEP.

However, additional steps can be taken to fine-tune these systems to make sure that regulators, the 

public, and researchers have accurate information that is provided in a convenient form and in a 

timely manner.

Two separate units within WVDEP—the Water Use Section and the Office of Oil and Gas—oversee 

different reporting requirements. The Water Use Section of the Division of Water and Waste 

Management oversees reporting of water volumes. The Office of Oil and Gas, however, handles 

permits and associated water management plans, the reporting of chemical additives, and other 

duties such as inspections and enforcement. This division of responsibility creates situations in which 

staff at one office may not be fully cognizant of other aspects of reporting requirements, and it may 

also lead to inconsistencies between databases that are being maintained for the same gas wells. It 

would be ideal if all Marcellus-related water reporting were managed within a single unit at WVDEP; 

however, absent such a reorganization, the Water Use Section and Office of Oil and Gas should 

closely integrate their data collection and reporting requirements and databases.

Withdrawal, injection, recovery, and waste disposal databases are not available online. WVDEP 

staff provided water-related data upon request, but these databases were actually copies of portions 

of Microsoft Excel databases. In addition, periodic requests were required in order to ensure that the 

most up-to-date data were provided. WVDEP already posts a considerable amount of data in 

searchable online databases, such as natural gas production data. WVDEP should implement an 

online database that provides free public access to its withdrawal, injection, recovery, and waste 

disposal data. This should be performed expeditiously to inform management decisions affecting 

environmental consequences as the rate of development increases.
55 | P a g e

Withdrawal, injection, recovery, and waste disposal datasets are incomplete. Based on the analysis 

conducted in this report, the Frac Water Reporting Database is only approximately 35% complete 

(See Table 9). While timelines are in place for certain types of reporting, it does not appear that 

WVDEP is monitoring the completeness of the data or enforcing the reporting of data within 

specified timelines. WVDEP should audit each database to determine what percentage of wells have 

reported. Methods similar to those used in this report could be employed, or WVDEP might have 

access to comparable or better methods. In addition, WVDEP should enforce its timelines to ensure 

that operators report on time.33 If necessary, the West Virginia Legislature should revise its laws 

and/or rules to set strict timelines and penalties for the reporting of water quality and quantity 

information. In the meantime, WVDEP should use all available resources to compel operators to 

report information required by West Virginia laws and regulations, even if this reporting is 

technically voluntary.

Withdrawal data are not available for individual wells. WVDEP requires water withdrawals to be 

reported by well site, and not by well. This makes it impossible to track withdrawals by well, because 

each well site may have multiple wells and because well sites may be used to stockpile water for use 

elsewhere. In contrast, the water management plans submitted with each well permit application 

include estimates of future withdrawals by well. WVDEP should implement a system whereby water 

withdrawals are reported for individual wells, and not by well site. This would allow better tracking 

of sources of water for each well, and it would also allow comparisons against the estimates of 

future withdrawals by well that are submitted in each water management plan.

Large quantities of waste remain unreported in West Virginia. In contrast to Pennsylvania, where 

waste disposal is reported for a wide variety of waste types (including, for example, drilling waste, 

brine, and spent lubricants), disposal data are only reported for flowback fluid in West Virginia. In 

addition to excluding these other categories of waste, the West Virginia system also misses flowback 

fluid that returns to the surface more than 30 days after fracking. This missing data can be quite 

substantial. According to Pennsylvania’s waste disposal data (See Section 5.4), flowback fluid 

constitutes approximately 38% of the total volume of waste generated by Marcellus wells in 

Pennsylvania. WVDEP should expand the scope of the recovery and disposal data reporting to 

include all waste types that are generated over time, and not just flowback generated in the first 30 

days. Rather than reporting data once, it should be reported periodically over time. This may require 

legislative changes to the relevant laws and/or rules.

Duplicate injection, recovery, and waste disposal volumes are often submitted. In the Frac Water 

Reporting Form, operators have often entered the same injection, recovery, and waste disposal 

volumes for multiple wells on the same pad or for multiple waste disposal events. This raises the 

question of whether the operator divided the volume before reporting or whether the volumes have 

been double- or triple-counted. WVDEP should ensure that the Frac Water Reporting Form clearly 

asks for well-by-well information. In addition, should an operator enter duplicate information for 

multiple wells on a single form, the Frac Water Reporting Form should automatically flag this and 

explain to the operator that well-by-well information should be entered.

Inconsistent waste and disposal data have been submitted. When processing the West Virginia data

for this report, many wells were removed from the analysis due to questions about data consistency. 

Wells were removed because recovery exceeds injection, a field had missing data, the recovery 

volume was negative, or disposal and recovery volumes differed by more than 10%. WVDEP should 

implement procedures to automatically check submitted data to ensure that it meets basic standards 

 

33 For example, just before completion of this report, it became apparent that the Frac Water Reporting Database provided by WVDEP (2013a) 

omitted 30 wells that began injection in 2011 but that had not reported until 2013. These wells were left out of our analysis; however, the discovery of 

these wells further underscores the importance of ensuring that operators report on time.
56 | P a g e

for data quality. At a minimum, this system should check for the types of questionable data 

documented here.

Well status data are missing. WVDEP provides an online Oil and Gas well search tool. Many entries 

in this database have a blank entry for “well status” field; therefore, it is not known whether these 

wells are active. WVDEP should institute a quality control procedure when data are reported to 

ensure that all necessary fields are filled in, before combining submitted data into its database.

No single data source provides the number of Marcellus wells drilled, fracked, and entering 

production in a given year. Despite the fact that operators must submit a variety of reports related 

to water, waste, and production volumes, none of the existing databases provide year-by-year 

accounting of the number of Marcellus wells drilled, fracked, and entering production in a given 

year. This is basic information that is known to WVDEP and is necessary to track the progress of the 

development of the Marcellus Shale; it should be easily and publicly available.

7.2 Pennsylvania

7.2.1 Water and fluid flows

As shown on the following page, our analysis of self-reporting data has resulted in a variety of 

estimates of water withdrawals and fluid injection, recovery, and disposal in recent years in 

Pennsylvania. Figure 19 summarizes the key results. On average, in recent years, approximately 4.3 

million gallons of fracturing fluid has been injected per well. This is comparable to, but less than, the 

5 million gallons reported in West Virginia.

Of the fluid injected underground, only approximately 6%, on average, returns to the surface; the 

rest remains underground. This percentage is also comparable to the 8% estimated for West Virginia. 

It is important to note that this figure represents the percentage of injected fracturing fluid that 

returns to the surface; the total amount of waste reported to PADEP is much higher. The water 

contained in the fracturing fluid that remains underground, together with that disposed of in UIC 

wells, is removed from the hydrologic cycle and is included in our blue water footprint calculations.

In Pennsylvania, three primary waste categories are tracked: flowback fluid, brine, and drilling waste, 

with flowback fluid representing approximately 38% of the total. 

In recent years, more than one-half of the waste generated by Marcellus wells in Pennsylvania is 

treated and discharged to surface waters—either through brine/industrial waste treatment plants or 

municipal sewage treatment plants. This stands in stark contrast to West Virginia, where virtually no 

flowback fluid is reported to be discharged to surface waters. In Pennsylvania, approximately onethird of total waste is reused, although data are not available to determine whether it is reused in 

Pennsylvania or elsewhere. Only approximately 5% of total waste is injected in UIC wells—mostly in 

Ohio.

In contrast to West Virginia, there is significant potential for Marcellus development in Pennsylvania

to impact its surface waters, because such a large percentage of waste is ultimately shipped to 

treatment plants that discharge to the state’s rivers and streams. While National Pollutant Discharge 

Elimination System (NPDES) permits are required for these sites, impacts could occur via spills, 

exceedances of permit limitations, or a lack of appropriate limitations for pollutants of concern.

The Pennsylvania data also confirm that the three-state region is tightly connected in terms of waste 

disposal. While most Pennsylvania waste remains in-state, a significant amount of waste is shipped 

to UIC wells in Ohio.
57 | P a g e

Figure 19: Summary of key Pennsylvania water and fluid flows

Water 

Withdrawals

Surface water, 

groundwater, 

purchased water

Injected 

fracturing fluid 

~4.3 million 

gallons/well

Waste: Flowback 

fluid, brine, 

drilling waste

~6% of injected 

fracturing fluid plus 

other waste

Data not available on 

destination state

Remains 

underground

~94%

Injected in UIC 

wells 

(Mostly Ohio)

~5% of total waste

Removed from hydrologic cycle

Reused

~32% of total waste

~14% of injection 

volume

Data not available 

on destination state

Brine/industrial 

waste treatment 

(Mostly Pa.)

~39% of total waste

Municipal 

sewage 

treatment 

(Mostly Pa.)

~15% of total waste

Surface water

Other

~9% of total waste

Source: All figures calculated in this report.
58 | P a g e

KEY PENNSYLVANIA RESULTS

 In Pennsylvania, no single database is available to document withdrawals by Marcellus 

wells statewide. SRBC data, however, documents that in the SRB, approximately 8.3 billion 

gallons of water were withdrawn for Marcellus wells from 2009 through 2012 (Table 16). 

 Of the total withdrawals for Marcellus wells in the SRB, about 6 billion gallons, or 72%, was 

withdrawn directly from surface and groundwater (Table 16). This figure provides a 

minimum percentage, because additional surface and groundwater is provided to 

Marcellus wells via public water systems, which are accounted for separately.

 Reused flowback fluid as a percentage of total injection volume is not available statewide; 

however, in the SRB, reused flowback fluid increased to 18% of total injection volume for 

Marcellus wells by 2012 (Table 19).

 According to data reported to FracFocus, Pennsylvania Marcellus wells injected 

approximately 10 billion gallons between 2009 and 2012; however, the reporting rate to 

FracFocus was only approximately 41% in this time period, so the true statewide injection 

volume was an estimated 24 billion gallons. An average of 4.3 million gallons have been 

injected into Marcellus wells during this time period (Table 17 and Table 18).

 According to data from SRBC, approximately 9.4 billion gallons of fluid were injected into 

Marcellus wells in the SRB—a subset of those in Pennsylvania—between 2009 and 2012 

and averaged 4.3 million gallons per well—the same as the statewide average for wells that 

reported to FracFocus (Table 18 and Table 19).

 During 2009 through 2012, an average of 6% of the fluid injected into Marcellus wells in the 

SRB was recovered (Table 20).

 Flowback fluid makes up only 38% of the total waste reported from Marcellus wells in 

Pennsylvania (Figure 13).

 The percentage of waste reused has increased substantially and reached 56% of total waste 

in 2012 (Table 21). 

 From 2008 through 2011, 88% of waste from horizontal Marcellus wells in Pennsylvania 

stayed in Pennsylvania, 9% was shipped to Ohio, and 2% was shipped to West Virginia

(Table 22).

 Most of the waste generated in 2008 through 2011 was kept in-state for treatment and

discharge to surface waters: 38% was sent to brine or industrial waste treatment plants 

located in Pennsylvania and an additional 15% was sent to municipal sewage treatment 

plants in Pennsylvania (Table 22).

 Horizontal Marcellus wells in Pennsylvania, on average, removed about 4.1 million gallons 

from the hydrologic cycle between 2009 and 2011 (Table 23). This totaled an estimated 

17.8 billion gallons.

 In Pennsylvania, the blue water footprint, which represents the volume of water removed 

from the hydrologic cycle per unit of gas produced, ranges from 3.2 to 4.2 gallons per Mcf 

from 2009 to 2011 on a 4-year production basis. When considering the sensitivity of these 

results to higher natural gas estimates, the range dropped to 1.2 to 3.9 (Table 31). The 

discrepancy appears to be because of different estimates for natural gas production. 
59 | P a g e

7.2.2 Data collection and reporting

As summarized in Table 38, current Pennsylvania laws and regulations require operators to compile 

and report key information related to withdrawals, injections, recovery, and disposal. However, 

water withdrawal data are only available in a format convenient for researchers within the SRB.

In addition, because fluid injection volumes and the chemicals in the fracking fluid are reported via 

FracFocus, they are not directly available in a searchable database that is available to the public, 

except via SkyTruth.

Waste recovery and disposal data, however, are compiled into Microsoft Excel spreadsheets and 

posted online for public use.

Table 38: Pennsylvania data reporting

Stage

Form where data 

is reported

Required or 

voluntary?

Data reported by 

operators?

Reported data 

compiled into 

searchable 

database?

Searchable 

database publicly 

available?

Water withdrawals Completion report Required Yes No No

Fluid injection volume FracFocus

Required via

FracFocus starting 

in 2012

Incomplete

FracFocus data 

searchable via 

SkyTruth

FracFocus data 

available via 

SkyTruth

Chemicals in fluid

Chemical 

disclosure form, 

completion 

report, FracFocus

Required via 

FracFocus starting 

in 2012

Incomplete

FracFocus data

searchable via 

SkyTruth

FracFocus data 

available via 

SkyTruth

Waste recovery Production (and 

waste) report Required Yes Yes Yes

Waste disposal

Well site 

restoration 

report, production 

(and waste) report

Required Yes Yes Yes

Note: Water withdrawals reported to Pennsylvania’s water acquisition database cannot be filtered for withdrawals for drilling and fracturing in the Marcellus formation; 

therefore, it is not considered to fulfill the criteria in this table. Completion reports are only available as paper copies and are not compiled into a searchable or publicly 

available database.

FracFocus is not searchable for multiple wells. The chemical disclosure data submitted to FracFocus 

is not searchable except for individual wells. If not for SkyTruth, the data would not be useable 

except on a well-by-well basis. Act 13 also provides that, by January 1, 2013, PADEP shall make a 

determination whether the registry allows the department and the public to search by various fields. 

As of mid-2013, PADEP had not made such a determination. PADEP should therefore create a webbased interface so that the public can search FracFocus by state, county, operator, year, or other 

useful search terms. This would obviate the need for a nonprofit organization such as SkyTruth to 

compile a separate database based on the contents of FracFocus. It would also allow such a search to 

use up-to-date entries in FracFocus. Now, SkyTruth only updates its datasets monthly.

Only summary data are available from SRBC without paying exorbitant fees. SRBC compiles 

informative data about water withdrawals, injections, and recovery, and these data are available 

online. However, this database is only available for a fee of $250 per quarter of data. Downloading 

data from 2010 to 2012 would then cost $3,000. For this report, free summary data were used 

because of the expense of accessing SRBC’s database. SRBC is a public entity and, therefore, should 

make these data freely available to the public. Marcellus data from PADEP and WVDEP are all freely 

available. If fees are necessary, then they should be greatly reduced.
60 | P a g e

In Pennsylvania, Marcellus-specific water withdrawal data are not available outside of the 

Susquehanna River Basin. PADEP maintains a database of all water acquisitions by water users that 

withdraw greater than 10,000 gallons per day in any given 30-day period in all Pennsylvania river 

basins except the SRB. It is possible to filter this database to acquisitions for use by the oil and gas 

industry, but it is not possible to filter for withdrawals for drilling and fracturing in the Marcellus 

formation. While it is laudable that PADEP’s water withdrawal database is freely available online, it 

should include fields such that data can be retrieved specifically for Marcellus wells. 

Withdrawal data are not available for individual wells. Outside of the SRB, PADEP’s water 

acquisition database tracks water withdrawals by individual withdrawal points and purchases. It is 

not possible to relate this data to individual wells or well pads. Within the SRB, SRBC’s withdrawal 

data also cannot be tracked to individual wells. PADEP and SRBC should implement systems whereby 

water withdrawals are reported for individual wells. This would allow better tracking of sources of 

water for each well, and it would also allow comparisons against the estimates of future withdrawals 

by well that are submitted in each water management plan.

Pennsylvania completion reports are only available as paper copies. These reports include data that 

well operators now report to FracFocus such as chemical additives in the stimulation fluids, but they 

also include information not reported to FracFocus, such as the total volume of recycled water used. 

All information submitted via completion reports should be publicly available in electronic form—not 

just the information that is submitted to FracFocus. This may require action by PADEP and/or the 

Pennsylvania Legislature.

Duplicate waste disposal volumes are often submitted. The same waste volume was reported for 

multiple waste disposal events for many wells in Pennsylvania. This raises the question of whether 

the operator divided the volume before reporting or whether the volumes have been double- or 

triple-counted. PADEP should ensure that its reporting system clearly asks for well-by-well 

information. In addition, if an operator enters duplicate information for multiple wells on a single 

form, the system should automatically flag this and explain to the operator that well-by-well 

information should be entered.

7.3 Summary

Recent laws and regulations in West Virginia and Pennsylvania have set in motion a significant 

amount of new data collection and reporting regarding the burgeoning Marcellus Shale industry. 

Today, publicly available information quantifies the volumes of water withdrawn; fluid injected; and 

waste recovered, disposed of, and recycled. However, as documented in this report, reporting is not 

complete, operators have entered inconsistent and erroneous data, and some data are not freely 

and publicly available. 

Given the holes in these datasets, it is likely that much more water is being withdrawn and more 

waste is being generated than is reported. In short, the true scale of water impacts can still only be 

estimated.

A considerable amount of flowback fluid is now being reused and recycled. This is commendable, and 

maximizing the amount of fluid recycled should continue to be a focus of the industry. However, the

data suggest that even as more waste is recycled, it is only displacing a small percentage of 

freshwater withdrawals. Therefore, as Marcellus development continues at a rapid pace, recycling 

and reuse cannot be the single solution to protect the region’s water resources from withdrawals.

The data suggest that, in recent years, approximately 4.7 million gallons per well in West Virginia and 

4.1 million gallons per well in Pennsylvania have been removed from the hydrologic cycle in recent 
61 | P a g e

years. While West Virginia and Pennsylvania are generally water-rich states, these results have 

potential impacts as similar horizontal drilling and hydraulic fracturing operations are developed in 

shale plays in more arid areas. The specific volumes of fluid injected and waste recovered will 

certainly vary in different plays based on the depth and thickness of the shale and other factors; 

however, these data suggest that the removal of water from the hydrologic cycle is an impact worth 

considering and mitigating.

A final key observation is that, as Marcellus development proceeds, waste generation is increasing. 

In Pennsylvania, operators reported an almost 70% increase in waste generated from 2010 to 2011—

rising to a reported 613 million gallons of waste in 2011. The question of how to appropriately 

handle this growing volume of waste will continue to loom large until the pace of well development 

slows. 

As these databases become more complete and accurate, we expect the estimates in this report to 

be refined. However, the estimates in this report represent the best available results that correspond 

to the data self-reported by Marcellus operators.

Overall, our findings suggest that the volumes of water used to fracture Marcellus Shale gas wells are

quite substantial, the quantities of waste generated are significant, and continual improvement and 

enforcement of data collection and reporting requirements will be necessary to minimize the 

potential impacts to water resources in West Virginia, Pennsylvania, and Ohio.
62 | P a g e

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http://www.pawaterplan.dep.state.pa.us/StateWaterPlan/WaterDataExportTool/WaterExp

ortTool.aspx Accessed March 26.

Pennsylvania Department of Environmental Protection (PADEP). 2013h, PA Operator permitted well 

inventory Excel spreadsheet. 

http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx?/Oil_

Gas/Operator_Permitted_Well_Inventory Accessed August 8.

Pennsylvania Spatial Data Access (PASDA). 2013. Susquehanna River Basin Boundary geographic 

information system data. 

http://www.pasda.psu.edu/uci/MetadataDisplay.aspx?entry=PASDA&file=srb_SRBC.xml&da

taset=504 . Downloaded October 14, 2013.

Penn State Extension. 2013, Common Water Test Parameters Related to Natural Gas Drilling. 

http://extension.psu.edu/natural-resources/water/marcellus-shale/drinkingwater/common-water-test-parameters-related-to-natural-gas-drilling/view

Pittsburgh Water & Sewer Authority. 2010, PGH2O, Pittsburgh’s Finest Water, 2010 Annual Report.

http://www.pgh2o.com/docs/annual_2010.pdf.

Platt, S. n.d. EPA’s Underground Injection Control Program- Brine Disposal Well Regulation in 

Pennsylvania. http://files.dep.state.pa.us/.../padep_advisory_council_uic_presentation.ppt

Accessed October 15, 2013.

Quaranta, J., Wise, T. and Darnell, A. 2012. Pits and Impoundments Final Report For Assessing 

Environmental Impacts of Horizontal Gas Well Drilling Operations (ETD-10 Project). Prepared 

for West Virginia Department of Environmental Protection Office of Oil and Gas. Submitted 

by Department of Civil and Environmental Engineering, West Virginia University. December 

17, 2013.

Rahm, B.G. & Riha, S.J. 2012. "Toward strategic management of shale gas development: Regional, 

collective impacts on water resources." Environmental Science & Policy 17: 12–23.

Rich, A. & Crosby, E. 2013. Analysis of Reserve Put Sludge from Unconventional Natural Gas 

Hydraulic Fracturing and Drilling Operations for the Presence of Technologically Enhanced 

Naturally Occurring Radioactive Material. New Solutions 23(1): 117–35. 

Richenderfer, J. 2010. Shale Gas Development in the Susquehanna River Basin. 

http://www.eia.gov/conference/2010/session10/richenderfer.pdf Accessed October 16, 

2013.

Riha, S. & Rahm, B.G. 2010. Framework for Assessing Water Resource Impacts from Shale 

Gas Drilling, Cornell University, City and Regional Planning, Ithaca, NY.

Rowan E., Engle, M., Kirby C., Kraemer, T. 2011. Radium content of oil- and gas-field produced waters 

in the northern Appalachian Basin (USA)—Summary and discussion of data. US Geological 

Survey Scientific Investigations Report 5135.

Scown, C.D., Horvath, A. & McKone, T.E. 2011. "Water Footprint of U.S. Transportation Fuels."

Environmental Science and Technology 45: 2541–53.

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68 | P a g e

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Shale, US Geological Survey West Trenton Publishing Service Center, Baltimore, MD.

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Natural Gas Technology. Intech, Croatia. 

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Role in Regulating Natural Gas Development. 

http://www.srbc.net/programs/natural_gas_development_faq.htm

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Hydrofrac Data Summary 8152013 (2).DOCX”. Emailed to author Hansen from Paula 

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Susquehanna River Basin Commission (SRBC). 2013c. Water Withdrawals & Consumptive Use for 

Natural Gas Industry: “Brf Mtg Item I Water Use Profile for Gas Industry 06-20-13.PDF”. 

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http://water.epa.gov/drink/contaminants/index.cfm Accessed October 22, 2013.

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Water. http://water.epa.gov/drink/contaminants/basicinformation/lead.cfm Accessed 

October 29, 2013.

US Environmental Protection Agency (USEPA). 2013d. Sodium in Drinking Water. 

http://water.epa.gov/scitech/drinkingwater/dws/ccl/sodium.cfm Accessed October 29, 

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Brominated trihalomethanes. EPA-822-R-05-011. Washington, DC. 

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of Unconventional Oil and Gas Development, Including Areas Where Hydraulic Fracturing 

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Environmental Impacts,” April 12, 2011.

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2012. “Geochemical evidence for possible natural migration of Marcellus formation brine to 

shallow aquifers in Pennsylvania.” Proceedings of the National Academy of Sciences 109(30): 

11961–6. 

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Reporting Instructions. 

http://www.dep.wv.gov/WWE/wateruse/Pages/FracWaterReportingForm.aspx Accessed 

June 6.

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permits database with geographical locations Excel spreadsheet.

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Pits and Impoundments Used in the Drilling of Horizontal Natural Gas Wells. Office of Oil and 

Gas. Pursuant to W.Va. Code §22-6A-23. March 7, 2013.

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containing WV Class II UIC well information. Public Information Office. Emailed to author 

Betcher October 17, 2013.

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Well Drilling Operations, AGM 064, Project Overview: Water and Waste Stream Study & Pits 

and Impoundments Study. Prepared for West Virginia Department of Environmental 

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Marcellus Center for Outreach and Research, Penn State University. 

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Systems, Virginia Water Resources Research Center. Special Report No. SR46-2009

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September 20, 2013.
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Ziemkiewicz, P., Hause, J. Gutta, B., Fillhart, J., Mack, B., and O’Neal, M. 2013. Final Report, Water 

Quality Literature Review and Field Monitoring of Active Shale Gas Wells, Phase I, For 

“Assessing Environmental Impacts of Horizontal Gas Well Drilling Operations.” Prepared for 

West Virginia Department of Environmental Protection Division of Air Quality. Prepared by 

West Virginia Water Research Institute, West Virginia University. February 15, 2013.
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APPENDIX A: DETAILED DATA COLLECTION AND REPORTING 

REQUIREMENTS IN WEST VIRGINIA

Water management plan

According to the Natural Gas Horizontal Well Control Act, a water management plan must be 

submitted along with a well work permit application for any well requiring the use of greater than 

210,000 gallons of water obtained by withdrawals from state waters during any 30-day period. This 

plan may be submitted on an individual well or watershed basis, and must include the following 

information:

 Type of water source, the county of each source to be used by the operation for water 

withdrawals, and the latitude and longitude of each anticipated withdrawal location;

 Anticipated volume of each water withdrawal;

 Anticipated months when water withdrawals will be made;

 Planned management and disposition of wastewater after completion from fracturing, 

refracturing, stimulation and production activities; and

 A listing of the anticipated additives that may be used in water utilized for fracturing or 

stimulating the well.34

For all surface water withdrawals, the water management plan must also include an identification of 

the current designated and existing water uses, including any public water intakes within 1 mile of 

the withdrawal location. The operator must also demonstrate that sufficient in-stream flow will be 

available immediately downstream of the withdrawal location, and include methods to be used to 

minimize adverse impacts to aquatic life. 

A well work permit will not be issued without a water management plan that has been approved by 

the Secretary.35

Large quantity water user registration

The Water Resources Protection and Management Act governs water use by large quantity water 

consumers—including Marcellus wells, other water-intensive industries, and public water supplies. 

Any entity that withdraws greater than 750,000 gallons of water during one calendar month is 

required to register with the WVDEP Water Use Section. These large-quantity users must update the 

WVDEP annually on their water use. If water use falls below this threshold, further reporting is not 

required.

Frac Water Reporting Form

All well operators who use greater than 750,000 gallons of water to fracture a well must register as a 

large-quantity user and report their water use and disposal through the online Frac Water Reporting 

Form. While the Act specifies that reporting is required for withdrawals of 750,000 gallons or more, 

instructions provided with the Frac Water Reporting Form requires reporting if a well uses 750,000 

gallons or more to frack a well (WVDEP 2013b). This form includes a variety of information related to 

withdrawals, injection, recovery, and disposal.

Withdrawal information is entered for each well site, and not by well. For example, six wells might 

be drilled from a single well pad; in this case, withdrawal information for all six wells would be 

 

34 W.Va. Code §22-6A-7.

35 W.Va. Code §22-6A-8.
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reported for a single “site.” Sometimes, a centralized impoundment is used as an intermediate 

holding pond for water that will be used at numerous well pads. Because water withdrawals are 

reported by site, situations where there are multiple wells at the site of withdrawal delivery, 

complicate efforts to use this database to track the volumes of withdrawals used at specific wells. 

For each well site, the Frac Water Reporting Form requires operators to enter the following 

information: 

 type and name of each water source, 

 latitude and longitude of each source, 

 total amount withdrawn from each source, and

 begin and end date of each withdrawal.

In contrast, water injection, recovery, and disposal volumes are reported for each well. Information 

reported includes:36

 API number;

 well location coordinates;

 producing formation and drill depth;

 amount of water injected and begin and end dates of injection;

 total amount of fluid recovered during the 30 days following injection or until half of the 

total volume injected is recovered, whichever occurs first;

 volume of waste water reused at another well and the API number of the well where the 

waste was reused;

 volume of water disposed of at a UIC well, permit number of the UIC well, begin and end 

date of disposal at the UIC well, and location coordinates of the UIC well; and

 volume of water disposed of at a POTW, permit number of the POTW, begin and end date of 

disposal, and location coordinates of the POTW.

Well operators are directed to complete a Frac Water Reporting Form within one year following 

fracturing. No system is currently in place for enforcing reporting compliance. As shown previously in

Table 9, only approximately 35% of 2010 and 2011 wells have reported water use to the Frac Water 

Reporting database.

For this report, flowback fluid in West Virginia is defined as the fluid that returns to the surface 

within 30 days of injection, or 50% of the total volume injected, because this is the fluid required to 

be reported by WVDEP. Brine continues to return to the surface for the duration of the life of the 

well. This fluid must be collected and disposed of by well operators; however, it is not reported in 

West Virginia.37

Based on an analysis of Pennsylvania waste disposal data (See Section 5.4), flowback fluid constitutes 

approximately 38% of the total volume of waste generated by Marcellus wells in Pennsylvania 

(Figure 12 and Figure 13). Thus, because well operators in West Virginia are only required to report 

flowback fluid, large quantities of waste—perhaps as much as 62%—remain unreported in West 

Virginia. This unreported waste is virtually entirely made up of brine and drilling waste (see Figure 

13).

 

36 The Natural Gas Horizontal Well Control Act requires operators to keep records of the information reported on the Frac Water Reporting Form 

onsite for three years, but does not mandate that operators report this data. Operators are also required to document the following information 

related to transportation of fluids to be used in hydraulic fracturing and recovered from wells: quantity of water transported, collection and delivery or 

disposal locations, and the name of the water hauling company. 

37 This requirement is inconsistent with Pennsylvania, in which a wide variety of waste types are reported: basic sediment, produced fluid, drill

cuttings, flowback fluid, drilling fluid, flowback fracturing sand, servicing fluid, and spent lubricant.(PADEP 2013f). 
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Well completion report

Operators are required to submit a well completion report to WVDEP and the West Virginia 

Geological and Economic Survey within 90 days following completion of well work. This report 

includes geological, drilling, and cementing information.38 The Natural Gas Horizontal Well Control 

Act and the Rules Governing Horizontal Well Development39 mandate that a list of all additives used 

during hydraulic fracturing and stimulation must be included in this report. Information required 

includes the following:

 the trade name, supplier, and purpose of each additive used in the hydraulic fracturing and 

stimulation process;

 a list of chemicals and additives intentionally added to a base fluid for the purpose of 

preparing a fracturing fluid;

 the Chemical Abstracts Service (CAS) registry number of each chemical;

 the maximum concentration of each chemical in the additive;

 the maximum concentration as added to the base fluid; and

 the volume of the base fluid to be used.

The operator may designate this information as a trade secret not to be disclosed to the agency; 

however, this information must be disclosed to health care professionals for use in treatment and 

diagnosis in the case of a medical emergency or to WVDEP in the case of an investigation by the 

agency.

Since July 1, 2013, the effective date of amendments to the Rules Governing Horizontal Well 

Development,40 the chemical additives reporting requirement may be fulfilled by reporting to 

WVDEP and to the FracFocus Chemical Disclosure Registry.41

Other requirements

In addition to the well completion report, the Natural Gas Horizontal Well Control Act includes a 

number of other provisions to address the large quantities of water required for fracking, including:

 identification of uses of surface waters from which withdrawals will be made,

 prior notification of WVDEP of the source of water from which withdrawals will be made,

 receipt of verification from WVDEP before withdrawal commences that streamflow is 

sufficient to protect uses, and

 appropriate signage at withdrawal points. 

Production reports

Production reports,

42 which include the quantity of oil and gas produced at each well for each 

month, must be submitted annually for the duration of production of a well. Data for the preceding 

year must be submitted by March 31 each year.43

 

38 35 CSR 4-12.

39 35 CSR 8.

40 35 CSR 8.

41 35 CSR 8-10.

42 Form WR-39E.

43 35 CSR 4-15.
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APPENDIX B: DETAILED DATA COLLECTION AND REPORTING 

REQUIREMENTS IN PENNSYLVANIA

Water management plan

Operators cannot withdraw or use water for drilling or hydraulic fracturing of Marcellus wells except 

in accordance with an approved water management plan. Compliance with approved water 

management plans is a condition of well permits issued for drilling and hydraulic fracturing of 

Marcellus wells.44

Water management plans are submitted to PADEP for review and approval...“based upon a 

determination that the proposed withdrawal, when operated in accordance with the proposed 

withdrawal operating conditions set forth in the plan, including conditions relating to quantity, 

withdrawal rate and timing and any passby flow conditions, will:

 not adversely affect the quantity or quality of water available to other users of the same 

water sources;

 protect and maintain the designated and existing uses of water sources;

 not cause adverse impact to water quality in the watershed considered as a whole; and

 include a reuse plan for fluids that will be used to hydraulically fracture wells.”45

For withdrawals within the SRB, these criteria are presumed to be achieved if the proposed water 

withdrawal has been approved by and is operated in accordance with conditions established by the 

SRBC. A similar presumption is included for withdrawals within the jurisdiction of the Delaware River 

Basin Commission or the Great Lakes Commission. However, PADEP still may establish additional 

requirements as necessary to comply with the laws of this Commonwealth.46

Well record

Although not used for this analysis, well records, which must be submitted to PADEP within 30 

calendar days of cessation of drilling or altering a well, include a variety of information such as 

contact information for the permittee, locational information for the well, the dates that drilling 

started and ended, the drilling method, information about casings and cement, elevation and depth 

of the well, drillers logs, and other information.47

Chemical disclosure form

A chemical disclosure form must be filed within 60 days following conclusion of hydraulic fracturing. 

According to Act 13, the form must be completed and posted on the chemical disclosure registry: 

FracFocus.48

Provisions are made for trade secrets and confidentiality; however, all information not determined 

to be a trade secret or confidential is available to the public.

Act 13 also provides that, by January 1, 2013, PADEP shall make a determination whether the 

registry allows the department and the public to search by various fields. If not, PADEP is to 

 

44 Act 13 Section 3211(m).

45 Act 13 Section 3211(m)(2).

46 Act 13 Section 3211(m)(3).

47 25 PA §78.122(a).

48 Act 13 Section 3222.1.b.2.
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investigate the feasibility of making the chemical disclosure information available on its Web site. As 

of mid-2013, PADEP had not made such a determination (Hanger 2013; Konschnik et al. 2013).

Completion report

Completion reports must be filed within 30 days after completion of a well (30 days after the well is 

capable of production). Completion reports must include a variety of information related to water 

quality and quantity:

 a descriptive list of the chemical additives in the stimulation fluids;

 the trade name, vendor and a brief descriptor of the intended use or function of each 

chemical additive in the stimulation fluid;

 a list of the chemicals intentionally added to the stimulation fluid, by name and chemical 

abstract service number;

 the maximum concentration of each chemical intentionally added to the stimulation fluid;

 the total volume of the base fluid;

 a list of water sources used under the approved water management plan and the volume of 

water used;

 the pump rates and pressure used in the well; and

 the total volume of recycled water used.49

These completion reports are only available in paper copies (Lutz 2013b).

Well site restoration report

Well site restoration reports must be submitted within 60 days after restoration of the well site.50

This report includes information about:

 land application of tophole water;

 the amount of off-site waste disposal of drilling fluid, fracking fluid, or other waste amounts; 

 the locations to which this waste is transferred (disposal well, landfill, sewage treatment 

plant, brine disposal plant, or other location, including permit number and hauler 

information);

 on-site disposal of drill cuttings or waste;

 pit disposal; 

 land application; and

 site restoration.

Information related to off-site waste disposal is a fundamental data source for this report. The well 

site restoration report is submitted only once and only reflects disposal of waste encountered soon 

after restoration of the well site. The production (and waste) reports described below are submitted 

every six months into the future and are our source for disposal data analysis.

 

49 Act 13 Section 3222.b.1.

50 25 Pa. Code §78.65(3). 
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Production (and waste) reports

Production (and waste) reports must be filed twice per year for Marcellus wells: on or before 

February 15 and August 15 of each year.

51 Each report must include gas production for the previous 

six-month period. For example, reports filed by February 15 provide six-month production figures for 

July through December of the previous year.52 PADEP posts production reports online as 

spreadsheets (PADEP 2013b). 

In addition to gas production, these reports must also include information on the amount and type 

of waste produced and the method of waste disposal or reuse.53 While the well site restoration 

report includes similar waste information, it is submitted only once, soon after restoration of the 

well site. The production (and waste) reports described in this section are submitted every six 

months into the future.

 

51 When this six-month reporting period was instituted, some Marcellus production data were reported twice (Lutz et al. 2013).

52 Act 13 Section 3222.a.1.

53 25 PA §78.121.
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APPENDIX C: QUALITY CONTROL FOR WEST VIRGINIA DATA

Any wells with missing total injection, total recovery, or total disposal volumes were removed. In one 

case, a well had a negative value entered for recovery volume; this well was removed from our 

dataset. Next, recovery amount and disposal amount (which includes reuse) for each well were 

compared. Because all recovered fluid should be disposed of or reused, wells with more than a 10% 

difference between amount disposed and amount recovered were removed from the dataset. 

In some instances, an identical volume of fluid injected was reported for two or more wells located 

at the same well site within the same year. We assumed that the total volume injected at a well site 

was reported for each well. Therefore, to avoid overestimating the total volume injected, the volume 

reported was divided by the number of times that it was reported, and this resulting volume was 

used in further analyses. 

In addition, for some wells, identical volumes were reported for disposal of one well’s waste at 

multiple facilities. Lutz et al. (2013) performed an extensive analysis of waste generated by 

Pennsylvania Marcellus gas wells (See Section 5.4). The PADEP data used in this analysis also 

contained numerous instances where the same waste volume was entered for multiple disposal 

events. The authors discussed this issue with PADEP employees familiar with the reporting system 

and determined that it was highly likely that identical volumes were errors and that the total volume 

was entered for each disposal event. Thus, to avoid over-estimation of fluid volumes, each identical 

volume was divided by the number of times that it occurred. We followed this method for the 

WVDEP data analyzed here to maintain consistency with the Pennsylvania method. It is possible that 

some of these identical volumes are true values; if so, we would be reporting conservative estimates 

for water use and disposal in West Virginia.
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APPENDIX D: QUALITY CONTROL FOR PENNSYLVANIA DATA

One issue with the PADEP wastewater data was that it showed that identical volumes of a given 

wastewater type were being taken from the same well to multiple treatment facilities within a given 

year. Through conversations with PADEP, it became clear that there was a problem with the way that 

the data was entered into the system. In reality, only a portion of the total was being delivered to 

each disposal facility. To remedy this issue, the total volume that was replicated was divided by the 

number of times that it was entered (Lutz et al. 2013).

Some wells lacked values for drilling fluid and for flowback fluid. As both fluids are essential for 

hydraulic fracturing, it was assumed that missing values resulted from a lack of reporting by well 

operators. Only wells with nonzero values for drilling fluid and flowback fluid were included in the 

dataset used for analysis (Lutz et al. 2013).

Wells generate brine for multiple years during production. In many instances, brine was not reported 

consistently for each year of production. Zero brine production values were assumed to be reporting 

errors, and these wells were removed from the dataset (Lutz et al. 2013).

Problems were also identified related to the geography of wastewater disposal facilities. Many of the 

names of wastewater treatment plants contained typos and were entered inconsistently by different 

operators. Typos were corrected by matching names to NPDES permits and using internet research. 

In addition, some disposal facilities were missing geographic coordinates. These data were also filled 

in. UICs with missing information were matched to a list of wells obtained from the Ohio Department 

of Natural Resources (Lutz et al. 2013).