Proceedings of the Technical Workshops

for the Hydraulic Fracturing Study:

Water Resources Management

U.S. Environmental Protection Agency

EPA 600/R-11/048 | May 2011 | www.epa.gov
EPA 600/R-11/048 

 May 2011 

Proceedings of the Technical Workshops 

for the Hydraulic Fracturing Study: 

Water Resources Management

Office of Research and Development 

US Environmental Protection Agency 

Washington, DC
i 

List of Figures ........................................................................................................................ ii

List of Tables ........................................................................................................................ iii

Introduction .......................................................................................................................... 1

Workshop Participants .......................................................................................................... 1

Agenda .................................................................................................................................. 3

Summary and Abstracts from Theme 1: Water Use & Sustainability ....................................... 6

Summary of Presentations for Theme 1: Water Use & Sustainability ....................................... 7

Summary of Discussions Following Theme 1: Water Use & Sustainability Presentations ......... 9

Abstracts for Theme 1: Water Use & Sustainability ................................................................. 13

How are Appropriate Water Sources for Hydraulic Fracturing Determined? Predevelopment Conditions and Management of Development Phase Water Usage ............. 14

Water Management Analysis of Hydraulic Fracturing using System Dynamic Models ....... 16

Water Requirements and Sustainable Sources in the Barnett Shale ................................... 23

An Overview of Current and Projected Shale and Tight-Gas Water Use in Texas: Implication 

for Local Water Resources .................................................................................................... 31

Enabling Fracturing Operations with Zero Fresh Water Withdrawals ................................. 35

Sustaining Louisiana’s Fresh Water Aquifers – A Case Study in Bringing Community and 

Industry Together ................................................................................................................. 39

Summary and Abstracts from Theme 2: Flowback Recovery & Water Reuse ......................... 40

Summary of Presentations for Theme 2: Flowback Recovery & Water Reuse ........................ 41

Summary of Discussions Following Theme 2: Flowback Recovery and Water Reuse 

Presentations ............................................................................................................................ 43

Abstracts for Theme 2: Flowback Recovery & Water Reuse .................................................... 48

Produced Water Reuse and Recycling Challenges and Opportunities Across Major Shale 

Plays ...................................................................................................................................... 49

A Water Chemistry Perspective on Flowback Reuse with Several Case Studies .................. 58

Shale Frac Sequential Flowback Analysis and Reuse Implications ....................................... 63

Characterization of Marcellus Shale and Barnett Shale Flowback Waters and Technology 

Development for Water Reuse ............................................................................................. 67

Mid-Continent Water Management for Stimulation Operations ......................................... 71

Toolbox Available to Treat Flowback and Produced Waters ................................................ 75

A Closed Loop System Using a Brine Reservoir to Replace Fresh Water as the Frac Fluid 

Source ................................................................................................................................... 76

Summary and Abstracts from Theme 3: Disposal Practices ................................................... 81

Summary of Presentations from Theme 3: Disposal Practices ................................................. 82

Summary of Discussions Following Theme 3: Disposal Practices Presentations ..................... 84

Abstracts for Theme 3: Disposal Practices................................................................................ 86

Novel and Emerging Technologies for Produced Water Treatment .................................... 87

Simple Modeling of the Disposition of Fluids On-Site in a Pit .............................................. 93

Underground Injection Wells f or Produced Water Disposal ............................................... 97

Wastewater from Gas Development: Chemical Signatures in the Monongahela Basin .... 103

Revisiting the Major Discussion Points of the Technical Presentation Sessions ................... 104

Table of Contents 
ii 

Poster Abstracts................................................................................................................ 106

Chemical Transformations of 2, 2-Dibromo-3-nitrilopropiamide ...................................... 107

Shale Gas Development and Related Water-Resource Investigations in New York State –

Cooperative Projects to Promote Public Understanding.................................................... 112

Glossary of Terms .............................................................................................................. 114
ii 

List of Figures 

Figure 1. New oil and gas wells drilled in Pennsylvania by year. Green line is represents nonMarcellus Shale, Purple line represents Marcellus Shale wells. 2011 data is projected from 

January-February 2011 values. ..................................................................................................... 16

Figure 2. Location map of oil and gas drilling activities in Pennsylvania in 2010 (from PA Dept of 

Environmental Protection web page). .......................................................................................... 17

Figure 3. Potential components of System Dynamic Model for Hydraulic Fracturing to better 

understand the water cycle. ......................................................................................................... 18

Figure 4. Model Interface of an in situ-oil shale development .................................................... 19

Figure 5. Construction phase model component of the in-situ oil shale example. ...................... 20

Figure 6. Operation phase model component of the in-situ oil shale example. .......................... 21

Figure 7. 2008 Barnett Shale Water Use Summary Estimates ..................................................... 27

Figure 8. Trinity Aquifer ................................................................................................................ 28

Figure 9. MVR Evaporator Recovery Based on Feed Gravity for NaCl Brine ................................ 29

Figure 10. Barnett Flowback Analysis ........................................................................................... 30

Figure 11. Estimated hydraulic fracturing water use in 2008 and 2010 in the state of Texas. .... 32

Figure 12. Projected oil and gas water use 2010–2060. ............................................................... 33

Figure 13. Saline Aquifers in the US .............................................................................................. 37

Figure 14. Hydrolytic Degradation Pathway for DBNPA (Williams et al., 2010) ......................... 108

Figure 15. Reaction with DBNPA with nucleophiles and sunlight (Williams et al., 2010) .......... 109

Figure 16. pH profile for the hydrolysis of DBNPA at 25° ........................................................... 109
iii 

List of Tables 

Table 1. Number of wells completed in the Barnett Shale during the past four years by industry 

and specific to Devon's operations ............................................................................................... 23

Table 2. Typical Marcellus Salt Levels (ppm). Source: Blauch et al. SPE Paper 125740, 2009 ..... 36

Table 3. Water use in major shale plays ....................................................................................... 49

Table 4. Water vapor combustion and hydrologic cycle volume recovery by major shale play .. 55

Table 5. Source: SPE 138222 ......................................................................................................... 77

Table 6. The Debolt Process Flow Diagram (SPE 138222) ............................................................ 78

Table 7. UIC well classifications .................................................................................................... 98

Table 8. Rates of Hydrolysis of DBNPA ....................................................................................... 110
1 

Introduction 

The Hydraulic Fracturing Study 

In its Fiscal Year 2010 budget report, the U.S. House of Representatives Appropriation 

Conference Committee identified the need for a study of the potential impacts of hydraulic 

fracturing (HF) on drinking water resources. The Committee directed EPA scientists to 

undertake a study of HF to better understand any potential impacts of hydraulic fracturing on 

drinking water and ground water. The EPA produced a draft study plan, which focuses on the 

key stages of the HF water lifecycle: water acquisition, chemical mixing, well injection, flowback 

and produced water, and wastewater treatment and waste disposal. This plan was submitted to 

the Science Advisory Board (SAB) in February 2011 and the peer review of the plan was held on 

March 7 and 8, 2011. At the time these technical workshop proceedings were developed, the 

SAB had not given its official review to EPA. 

EPA has included stakeholder concerns in the planning process of the study from its inception, 

engaging stakeholders in a dialogue about the study through a series of webinars and facilitated 

public meetings held between May and September 2010. EPA also held four technical 

workshops in February and March 2011 to explore the following focus areas: Chemical & 

Analytical Methods (February 24-25), Well Construction & Operations (March 10-11), Fate & 

Transport (March 28-29) and Water Resource Management (March 29-30). 

The technical workshops centered around three goals: (1) inform EPA of the current technology 

and practices being used in hydraulic fracturing, (2) identify research related to the potential 

impacts of hydraulic fracturing on drinking water resources, and (3) provide an opportunity for 

EPA scientists to interact with technical experts. EPA invited technical experts from the oil and 

natural gas industry, consulting firms, laboratories, state and federal agencies, and 

environmental organizations to participate in the workshops. EPA will use the information 

presented in this document to inform research that effectively evaluates the relationship 

between HF and drinking water. 

An initial report of results from the EPA’s study is expected by late 2012, with an additional 

report expected in 2014. 

About the Proceedings 

These proceedings provide an overview of the twenty-two presentations and two posters given 

on water resources management at the Technical Workshop for the U.S. EPA Hydraulic 

Fracturing Study held on March 29 and 30, 2011. This workshop consisted of three themes: 

Theme 1– Water Use & Sustainability; Theme 2– Flowback Recovery & Water Reuse; and 

Theme 3– Disposal Practices. The proceedings include abstracts of the presentations and 

posters and a summary of the discussions that took place during the workshop. The 
2 

presentations from this workshop are not part of the proceedings document, but may be 

accessed at http://epa.gov/hydraulicfracturing. 

This is the fourth of four technical workshops on topics relating to the EPA Hydraulic Fracturing 

Study. The other three workshops are: Chemical and Analytical Methods (Feb. 24–25), Well 

Construction and Operations (Mar. 10–11), and Fate and Transport (Mar. 28–29). Proceedings 

will be available separately for the other three workshops. 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 

Editorial Team for the Proceedings

The attendees at the Water Resources Management workshop were selected based on 

information submitted to EPA during the attendee nomination process. Presenters, a workshop 

lead, and theme leads were selected from the pool of attendees based on the information 

submitted to EPA during the attendee nomination process. The workshop lead, John Veil of Veil 

Environmental, LLC, assisted EPA in finalizing details for the workshop and served as the lead 

editor of the proceedings document. The theme leads—Gary Hanson of Louisiana State 

University - Shreveport, Tom Hayes of the Gas Technology Institute, and Matthew Mantell of 

Chesapeake Energy Corporation —served as editors for Themes 1, 2, and 3, respectively. 
1 

Workshop Participants 

Name Affiliation 

David Alleman ALL Consulting 

James Arnold Water Remediation Technology, LLC 

Mike Baker Ohio Environmental Protection Agency 

Doug Beak US Environmental Protection Agency 

Chrystal Beasley US Environmental Protection Agency 

Amy Bergdale US Environmental Protection Agency 

Matthew Blauch Superior Well Services 

Jeanne Briskin US Environmental Protection Agency 

Susan Burden US Environmental Protection Agency 

Cal Cooper Apache Corporation 

Jill Cooper EnCana Oil & Gas (USA) Inc. 

Robin Costas US Environmental Protection Agency 

Brian D'Amico US Environmental Protection Agency 

Robin Danesi US Environmental Protection Agency 

Jill Dean US Environmental Protection Agency 

Natenna Dobson U.S. Department of Energy 

Eric Engle Delaware River Basin Commission 

Bill Godsey Geo Logic Environmental Services, LLC 

Johanna Haggstrom Halliburton Energy Services 

Richard Hammack National Energy Technology Lab 

Gary Hanson Louisiana State University - Shreveport 

Fred Hauchman US Environmental Protection Agency 

Andrew Havics pH2, LLC 

Tom Hayes Gas Technology Institute 

Stephen Jester ConocoPhillips 

Bill Kappel US Geological Survey, New York Water Science 

Center 

George King Apache Corporation 

Steve Kraemer US Environmental Protection Agency 

Joseph Lee PA Dept. of Env. Protection 

Matthew Mantell Chesapeake Energy Corporation 

Jan Matuszko US Environmental Protection Agency 

Rick McCurdy Chesapeake Energy Corporation 

Martin Medina Shell Exploration & Production Co. 

Pete Miller Range Resources 

Keith Minnich Talisman Energy Inc. 

Thomas Muilenberg MIOX Corporation 

Jean-Philippe "JP" Nicot The University of Texas at Austin 
2 

Name Affiliation 

Carl Palmer Idaho National Laboratory 

Tricia Pfeiffer US Environmental Protection Agency 

Steve Platt US Environmental Protection Agency 

Robert Puls US Environmental Protection Agency 

Vikram Rao Research Triangle Energy Consortium 

Harry Schurr III CNX Gas/CONSOL Energy

Khin-Cho Thaung US Environmental Protection Agency 

D. Steven Tipton Newfield Exploration Mic-Continent Inc. 

Robert Vagnetti National Energy Technology Laboratory 

John Veil Argonne National Laboratory 

Conrad Volz University of Pittsburgh 

Jim Weaver US Environmental Protection Agency 

James (Jim) H. Welsh Louisiana Office of Conservation 

James Werline Devon Energy Corporation 

Stevie Wilding US Environmental Protection Agency 

Ron Wilhelm US Environmental Protection Agency 

Nathan Wiser US Environmental Protection Agency 

Brian Woodard Devon Energy 

Mike Worden US Department of the Interior, Bureau of Land 

Management 

David Wunsch National Ground Water Association 

Pei Xu Colorado School of Mines 

Paul Ziemkiewicz West Virginia University 
3 

Agenda 

Technical Workshops for the Hydraulic Fracturing Study

Water Resources Management  March 29-30, 2011 

US EPA Conference Center 

One Potomac Yard (South Building) 

2777 S. Crystal Drive 

Arlington, VA 22202 Room S-4370 and 4380 

March 29, 2011 

12:30 pm Registration 

1:00 pm Welcome 

Fred Hauchman, Director of the Office of Science Policy, EPA Office of Research and 

Development 

John Veil, Workshop Lead, Veil Environmental, LLC 

Pat Field, Facilitator, Consensus Building Institute 

Theme 1: Water Use & Sustainability 

1:15 pm Technical Presentation Session 1: Determinations of Appropriate Water Sources for 

Hydraulic Fracturing 

How are Appropriate Water Sources for Hydraulic Fracturing Determined? Predevelopment Conditions and Management of Development Phase Water Usage, Gary 

Hanson, Louisiana State University – Shreveport 

Fresh, Brackish or Saline Water for Hydraulic Fracturing? What are the Options?, Bill 

Godsey, Geo Logic Environmental Services, LLC 

Water Management Analysis of Hydraulic Fracturing using System Dynamic Models, Carl 

Palmer, Idaho National Laboratory 

Water Requirements and Sustainable Sources in the Barnett Shale, James Werline, Devon 

Energy Corporation 

2:45 pm Break 
4 

2:55 pm Technical Presentation Session 2: Water Quantities used for Hydraulic Fracturing and 

Sharing of Water Resources 

An Overview of Current and Projected Shale and Tight Gas Water Use in Texas: Implication 

for Local Water Resources, JP Nicot, The University of Texas at Austin 

Water Demand and Supply in the Eagle Ford Shale, Stephen Jester, ConocoPhillips

Enabling Fracturing Operations with Zero Fresh Water Withdrawals, Vikram Rao, Research 

Triangle Energy Consortium 

Sustaining Louisiana’s Fresh Water Aquifers -- A Case Study in Bringing Community and 

Industry Together, James Welsh, Louisiana Office of Conservation 

4:25 pm Revisit the Major Discussion Points of the Technical Presentation Sessions 

John Veil, Workshop Lead, Veil Environmental, LLC 

Gary Hanson, Theme 1 Lead, Louisiana State University - Shreveport 

4:45 pm Adjourn for the Day 

March 30, 2011 

Theme 2: Flowback Recovery & Water Reuse 

8:00 am Technical Presentation Session 3: Case Studies from Around the US 

Produced Water Reuse and Recycling Challenges and Opportunities Across Major Shale 

Plays, Matthew Mantell, Chesapeake Energy Corporation 

A Water Chemistry Perspective on Flowback Reuse with Several Case Studies, Keith 

Minnich, Talisman Energy Inc. 

9:15 am Break 

9:25 am Technical Presentation Session 4: Flowback Characteristics 

Shale Frac Sequential Flowback Analyses and Reuse Implications, Matthew Blauch, 

Superior Well Services 

Characterization of Marcellus Shale and Barnett Shale Flowback Waters and Technology 

Development for Water Reuse, Tom Hayes, Gas Technology Institute 

10:25 am Break 
5 

Theme 3: Disposal Practices 

10:35 am Technical Presentation Session 5: Reclamation Systems 

Mid-Continent Water Management for Stimulation Operations, D. Steven Tipton, Newfield 

Exploration Mid-Continent, Inc. 

Toolbox Available to Treat Flowback and Produced Waters, Johanna Haggstrom, 

Halliburton Energy Services 

A Closed Loop System Using a Brine Reservoir to Replace Fresh Water as the Frac Fluid 

Source, George King, Apache Corporation 

Williams Ford, Piceance Basin: Flowback Water Reuse – Quality and Quantity, Jill Cooper, 

EnCana Oil & Gas (USA), Inc. 

12:05 pm Lunch 

1:00 pm Technical Presentation Session 6: Treatment Technologies and Processes Prior to 

Disposal 

Treatment of Shale Gas Produced Water for Discharge, David Alleman, ALL Consulting 

Novel and Emerging Technologies for Produced Water Treatment, Pei Xu, Colorado School 

of Mines 

2:00 pm Break 

2:10 pm Technical Presentation Session 7: Disposal Practices and Potential Impacts 

Water Quality in the Development Area of the Marcellus Shale Gas in Pennsylvania and the 

Implications on Discerning Impacts from Hydraulic Fracturing, Joseph Lee, Pennsylvania 

Department of Environmental Protection 

Simple Modeling of the Disposition of Fluids On-Site in a Pit, Andrew Havics, pH2, 

LLC/QEPA 

Underground Injection Wells for Produced Water Disposal, Rick McCurdy, Chesapeake 

Energy Corporation 

Wastewater from Gas Development: Chemical Signatures in the Monongahela Basin, Paul 

Ziemkiewicz, West Virginia University 

3:25 pm Revisit the Major Discussion Points of the Technical Presentation Sessions 

John Veil, Workshop Lead, Veil Environmental, LLC 

Tom Hayes, Theme 2 Lead, Gas Technology Institute 

Matthew Mantell, Theme 3 Lead, Chesapeake Energy Corporation 

4:30 pm Closing Discussions 

John Veil, Workshop Lead, Veil Environmental, LLC 

Jeanne Briskin, Hydraulic Fracturing Research Task Force Leader, EPA Office of Research 

and Development 
6 

Summary and Abstracts from Theme 1: Water Use & 

Sustainability
7 

Summary of Presentations for Theme 1: Water Use & Sustainability 

The statements made during the workshop do not represent the views or opinions of EPA. The

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 

Technical Presentations 

The first set of technical presentations in this theme addressed determinations of appropriate 

water sources for HF. 

John Veil, Veil Environmental, LLC, provided some opening remarks. He presented estimates of 

water requirements for shale gas activities in the Marcellus and Fayetteville Shales. Based on 

his calculations, water demand for wells in the Marcellus Shale could range from 2,255 million 

gallons per year (MG/year) to 11,275 MG/year, or 6.2–31 MG per day (MGD). In the Fayetteville 

Shale, he approximated that water needs could be approximately 13.7 MGD. Mr. Veil noted 

that these estimates account for less than 1% of actual water withdrawals in these areas, and 

he thus concluded that, while local conditions may restrict water availability in some areas or in 

some parts of the year, sufficient water does exist to support natural gas development and 

other water use needs. 

Gary Hanson, Louisiana State University -- Shreveport, discussed potential ground and surface 

water sources to be used to support HF operations. He described the history, mission, and 

accomplishments of the Red River Water Management Institute and other partnership groups 

with regard to HF water resources management in Louisiana. Mr. Hanson noted that the 

establishment of the Water Energy Working Group (WEWG) was critical in moving industry 

from ground water to surface water sources for HF. He noted that appropriate water sources 

for HF can change through time explaining that ground water had been a viable source until 

numerous Haynesville Shale wells were drilled and hydraulically fractured. He also pointed out 

one example of an operator who is currently using treated wastewater from a paper mill. Mr. 

Hanson also presented a set of preliminary water quality data from the Wilcox Aquifer in 

Louisiana and, from this data, concluded that there was no evidence of direct impact from HF 

or drilling, though there may be some impact from water withdrawals. Mr. Hanson also 

described an aquifer management initiative in the Sparta Aquifer in southern Arkansas, which 

he suggested as an excellent model for ground water resource sustainability.

Bill Godsey, Geo Logic Environmental Services, LLC, explored the potential benefits and 

negative impacts due to the use of fresh, brackish, saline, or blended waters for HF operations. 

He provided general information on aquifers in the Marcellus Shale area and the Potomac 

Aquifer in Maryland and Virginia, and then described differences in ground water quality as it 

relates to differences in aquifer depth and extent. 
8 

Carl Palmer, Idaho National Laboratory, described the use of system dynamic models to track 

HF water usage. He demonstrated how to build a model and presented an example of a system 

dynamics reservoir model that could be used within a geographic information system (GIS) 

framework. He explained that this type of modeling tool could relate to all three of the themes 

of this technical workshop, as it can integrate other modeling work and data collection 

initiatives while acting as a single predictive tool for water management decisions.

James Werline, Devon Energy Corporation, presented a case study of Devon’s water 

requirements, sources, management, and use in the Barnett Shale in Texas. He described the 

different end uses of water in Texas and in the area underlain by the Barnett Shale as well as 

the proportions of ground water, surface water, and recycled water used by Devon for their HF 

operations in the Barnett. Mr. Werline also described Devon’s water recycling processes using 

mechanical vapor recompression (MVR) units. He explained that MVR units vaporize saline 

fluids, allowing the operator to collect the resulting distilled water for reuse and dispose of the 

concentrated brine. Mr. Werline concluded by summarizing Devon’s water reuse statistics to 

date.

The second set of technical presentations addressed water quantities used for HF and sharing 

of water resources. 

JP Nicot, University of Texas at Austin, provided an overview of water use for shale gas and 

tight gas development in Texas. He presented water use data for several different types of oil 

and gas use, particularly for the main shale and tight gas formations in Texas and the horizontal 

and vertical wells in the Barnett. Dr. Nicot described historical and projected drawdown 

patterns for several aquifers in Texas. He noted that recycling can be a viable water 

management option, but that using alternative sources (collected rainwater, treated municipal 

wastewater, brackish water) or less water-intensive techniques may be more effective in areas 

with little produced water (where recycling opportunities are limited).

Stephen Jester, ConocoPhillips, addressed water demand and supply in the Eagle Ford Shale 

area in southern Texas. He presented estimated values for HF water demand in the Eagle Ford 

and compared them to water demand for other end uses. He also compared demand to supply 

volumes that were estimated using ground water availability models for the Gulf Coast and 

Carrizo-Wilcox Aquifers. Mr. Jester concluded that, on the large scale, evidence indicates that 

water demand for HF and other uses can be met by the available supply. However, he 

cautioned that local conditions should be monitored to avoid impacts such as methane 

migration.

Vikram Rao, Research Triangle Energy Consortium, discussed the possibility of HF with zero 

fresh water withdrawals and the associated benefits and challenges. Dr. Rao noted that 

industry has already responded to the challenge of recycling flowback water by using more 

saline water, and that, in some cases, use of saline water for HF has advantages over use of 

fresh water. However, Dr. Rao explained that increased use of saline water requires addressing 

issues such as scaling, chemical incompatibilities with additives, a need for better reservoir 
characterization, and desalination and other treatment concerns. Dr. Rao also recommended 

further investigations and mapping of saline aquifers.

James Welsh, Louisiana Office of Conservation, presented a case study from Louisiana’s 

Haynesville Shale area. Mr. Welsh explained that, initially, water for HF was withdrawn from 

the fresh water Carrizo-Wilcox Aquifer; however, increasing ground water withdrawals quickly 

began to conflict with other water use needs in the area. Working with operators, the state 

implemented policy changes and encouraged operators to use alternative water sources (e.g., 

surface water, non-potable ground water). Mr. Welsh noted that Louisiana continues to work 

with stakeholders on water management issues -- for example, Louisiana adopted regulations 

allowing the reuse of flowback water for HF. Mr. Welsh is of the opinion that state regulators 

are in the best position to implement solutions in their states and he cautioned against 

nationwide HF regulations. 

9 

Summary of Discussions Following Theme 1: Water Use & Sustainability 

Presentations

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 

Clarification of items in the presentations. Regarding the modeled aquifer depression and 

rebound in Dr. Nicot’s presentation, a participant asked whether irrigation water use declined 

during the recovery period. The presenter clarified that water use for irrigation was highest in 

the 1940s and 1950s and has decreased since then, allowing the aquifer to recover; the 

presenter noted that these results suggest that the aquifer can recover from extensive 

pumping. However, Dr. Nicot emphasized that local impacts do need to be considered. He 

indicated that the water use figures in his presentation represented well completion 

information only, not necessarily total fresh water use. Dr. Nicot noted that operators are not 

required to report water use for other steps in the well construction and operation process. In 

response to Dr. Rao’s presentation, a participant noted that some shallow aquifers do host 

bacteria; however, the presenter noted that more research is required in this area.

Using high-TDS water for HF operations. A participant asked if saline water can be used for both 

slickwater and gel fracture jobs. The presenters clarified that saline water can be used in gel 

systems, though compatibility tests are necessary and water handling is very important. A 

participant asked about corrosion effects from using high-TDS water. The presenters agreed 

that high salinity increases the amount of equipment loss and turnover. The presenters also 

noted that in some situations, matching the salinity of the injected fluids to the salinity of the 

reservoir improves production. Another participant asked for more information on using highly 

saline waters in fracturing fluids. One participant explained that using high-saline water can 

mitigate clay swelling issues in the shales. Participants agreed that industry has made significant 
10

advances in the use of brines and that, in some situations, using highly saline waters could have 

a positive impact on production. Participants also emphasized the importance for operators to 

have choices for water sources and disposal options, and noted that potential local impacts and 

public opinions can play a large role in this process. 

Recycling and disposal. A participant asked about the barium chloride content of produced 

water from operations using high-salinity water. The presenters agreed that barium could pose 

a problem and that characterizing the mineral content of the saline water is important, but 

noted that not much work has been done on adequately detailed characterizations of saline 

water resources in the United States. They mentioned, however, an ongoing USGS study that is 

currently working to map brackish aquifers. A participant stated that publicly-owned treatment 

works (POTWs) are not appropriate for the disposal of any kind of flowback fluids due to the 

high levels of strontium, barium, bromide, and other chemicals.

MVR treatment units. A participant asked about treating high-TDS water with MVR units. The 

presenter clarified that it is possible to treat water containing greater than 79,000 mg/L TDS, 

but these higher TDS levels decrease the efficiency of the units. The presenter added that deep 

well injection is the preferred disposal method for these types of fluids. The presenter indicated 

that the concentrate produced by the MVR units have TDS levels of approximately 140,000–

150,000 mg/L. The presenter explained that this concentrate is injected into the Ellenburger 

Formation, where the native brines have TDS levels of approximately 180,000–190,000 mg/L. 

The presenter noted that, depending on transportation costs, MVR treatment costs 

approximately $2.85–$5.00 per barrel; in the Barnett Shale area, it costs approximately $1.00–

$1.50 per barrel for deep well injection (including transportation costs). He explained that the 

MVR units are centrally located, and water is transported to and from the units by pipe. Finally, 

he noted that the Texas Railroad Commission (RRC) issues discharge permits for water treated 

by the MVR technique. Several participants emphasized that deep well injection is the 

preferred disposal method where it is available.

Water withdrawals. A participant asked if there are rate limitations for withdrawing ground 

water in Texas. A presenter responded that pumping rate is determined based on the aquifer 

and would be limited based on the permeability and conductivity of the formation. Tests 

conducted while drilling a water well would provide the relevant information. The presenters

noted that water wells are registered with the county water districts, which monitor spacing, 

cones of influence, property setbacks, etc., to ensure that aquifer drawdown is not excessive. 

According to the presenters, operators also work with surface land owners when drilling water 

wells, and surface water withdrawals are regulated by the Texas Commission on Environmental 

Quality (TCEQ). The presenters explained that TCEQ permits one-time withdrawals of 10 acrefeet, after which a study must be conducted to investigate any impacts on upstream and 

downstream flows. These studies can take up to two years to complete. The presenters noted 

that availability is the primary concern when identifying water sources, and it is closely related 

to cost. One participant indicated that his company looks first for surface water sources; if 

these are not available, ground water sources are the second choice. 
11

Aquifer recharge rates and aquifer storage. A participant asked about the recharge rates of 

aquifers used for HF. A presenter responded that, in Louisiana, the Wilcox Aquifer has a very 

low recharge rate and is exposed over a large uplift area with poor recharge characteristics 

including channelized sands with mineral precipitation. The presenter stated that the overlying 

terrace deposits also have low infiltration rates; however, the presenter indicated that the Red 

River can supply adequate water for HF operations in that area. A participant asked about 

aquifer storage of HF water. One presenter noted that he has experience with aquifer storage 

for drinking water, but not for other fluids. Another presenter described a situation in the Horn 

River Basin in British Columbia where brine is extracted, used, treated, and reinjected. A 

participant speculated that an injection well for produced water storage would likely be 

regulated as a Class V well.

Storage and transportation issues. One participant indicated that his company stores treated 

produced water in earthen ponds and that the low TDS levels (approximately 100 mg/L) of the 

water simplify storage concerns. Other operators stated that they do not discharge treated 

water but reuse it in their HF operations. A participant asked about on-site management of 

highly saline waters. One participant stores all waters with TDS levels above 2,000 mg/L in 

tanks, and other participants use lined pits with leak detection equipment. One participant 

avoids using pipe to transport brines due to the risk of ruptured pipelines. 

Water use terminology. A participant asked for clarification on what “available” water means. A 

presenter responded that this generally refers to surplus water that is not being used for other 

purposes. Another participant noted that unused ground water might be considered “lost” due 

to rejected recharge, but other participants disagreed, arguing that all water is used by local 

industries and residents, though in some cases that use may be indirect.

The importance of flexibility. Participants noted that there are a variety of water source and 

disposal options, and individual options may not be appropriate or available for all situations. 

Participants indicated that in the Eagle Ford play, recycling options can be beneficial to industry 

and the environment are not always desired by landowners, who would prefer to sell water to 

operators instead of encouraging water reuse. One participant noted that Louisiana is an 

excellent example of cooperation between regulatory agencies and industry since the state has 

updated its regulations to include options for water reuse.

Water management coordination groups. A participant described a consortium of operators 

who coordinate water management issues in a basin in Utah. Similar consortia are forming in 

the Barnett (the Barnett Shale Water Conservation and Management Committee, or BSWCMC) 

and the Eagle Ford areas; in addition, a water-energy working group has been formed in 

Louisiana. The groups generally address water source issues and technology development for 

reclamation/reuse. Another participant noted that in the area of the Haynesville shale play, 

there is no formal consortium, but several operators are coordinating to develop a pipeline 

from the Toledo Bend Reservoir. One participant cautioned that water rights laws in Western 

states might complicate coordination efforts among operators.
12

Surface and ground water regulations in Louisiana and Texas. A participant stated that in 

Louisiana, the state owns the rights to running water (e.g., rivers, streams, lakes fed by streams) 

and has developed a protocol for pricing the water. Companies can buy the water outright, or 

they can provide a service to the state instead. The participant indicated that the state is 

considering a tiered pricing structure that would account for the greater value of some water 

sources (e.g., headwaters). Ground water is not priced and may be withdrawn as long as the 

use does not damage a neighboring property or well. Louisiana has a process for evaluating 

water wells with eight-inch or larger casings. According to the participant, a model is used to 

determine the zone of influence, cone of depression, and other factors. Another participant 

stated that Texas has 16 Ground Water Management Areas that are responsible for setting 

“desired future conditions” for their aquifers. Participants discussed whether withdrawals for 

drilling/production are exempt from the process of setting these “desired future conditions.” 

Ground water monitoring. A participant asked about existing ground water monitoring 

programs. The presenter noted that some municipalities in Texas monitor ground water levels 

very closely. For example, in San Antonio ground water information is regularly published in a 

local newspaper. The presenters also stated that Texas has a statewide program at the state 

level to monitor ground water levels and quality, and it maintains a database with this 

information. The USGS also monitors ground water, but the presenter noted that some states 

have only a few participating monitoring wells. A participant noted that there is currently a 

movement to establish a more complete nationwide ground water monitoring network.

Other comments. Citing a review published in Nature, a participant noted that shale gas 

production is less water-intensive than several other types of energy production, including 

producing ethanol from corn. Another participant noted that water withdrawn during the three 

to four weeks required to drill a well can be used to fill water impoundments. Another 

participant noted that water withdrawals for HF are generally one-time withdrawals, compared 

to agricultural withdrawals that occur year after year. 
13

Abstracts for Theme 1: Water Use & Sustainability 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 
14

How are Appropriate Water Sources for Hydraulic Fracturing 

Determined? Pre-development Conditions and Management of 

Development Phase Water Usage 

Gary Hanson 

Louisiana State University Shreveport 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Historically the determination of water sources for hydraulic fracturing has typically been left 

up to the oil or gas operator or their drilling contractor. Fresh water, although only one 

component of frac fluids in tight gas sand stimulation, was the source of choice and ease of 

access would determine whether surface or groundwater was used. Prior to multistage 

horizontal fracing of gas shales, use of ponds or nearby streams provided sufficient water to 

drill and frac a typical tight sand well in most areas of the country. However as the 

unconventional shale plays arrived on the scene using “slick-water” fracing technique and 

horizontally drilled wells that required multiple stages in order to effectively stimulate the 

reservoir, water demands increased dramatically. Groundwater, which had been only used 

periodically in the past, became the source of choice in many areas. Groundwater use for 

fracing increased in northwest Louisiana after the discovery of the massive Haynesville Shale. 

The public and rural water utilities saw this activity as a threat to “their” source of water, so 

from their perspective a water source (groundwater) that was previously considered an 

appropriate source for fracing, became an inappropriate source, as drilling and fracing 

continued. 

Prior to the onset of the Haynesville Shale gas boom in northwest Louisiana, two critical actions 

were taken by local government and a university. First, a voluntary water committee called the 

Water Resources Committee of Northwest Louisiana (WRCNL) was formed and second, one of 

the member parishes (counties) worked with the local LSU Shreveport University to set up a 

groundwater monitoring system. Both actions were taken prior to the Haynesville Shale 

discovery and because there was a perceived need that groundwater and surface water 

resources were in jeopardy. In some cases, as operators moved into the area multiple Wilcox 

aquifer water wells were drilled to not only supply water for drilling, but also for fracing. Rig 

supply wells are considered exempt wells (no notification to Office of Conservation prior to 

developing) in Louisiana, but groundwater wells used for fracing are considered industrial wells 

and there is a 60-day pre-drilling notice required. Groundwater use for fracing is not specifically 

deemed unlawful. As stated earlier, operators have always used groundwater as an appropriate 

water source for fracing, but with the onset of the Haynesville high volume (5 million gallons), 

multistage, horizontal well development program, other groundwater users (district water 

systems, domestic & agriculture) became concerned. For them, groundwater was not an 

appropriate water source for fracing. The Office of Conservation stepped in and advised that 

surface water or non-potable aquifer alternatives should be used as a source of water. 
15

In 2001, the Red River Watershed Management Institute (Institute) was formed at LSU 

Shreveport and the Red River Education & Research Park (RRERP) was developed adjacent to 

the campus in the floodplain of the Red River. Faculty and students developed monitoring wells 

in the Red River Alluvial Aquifer (RRAA), an aquifer that had been studied historically by the 

USGS and other agencies. The RRAA is considered non-potable, but exhibits high deliverability 

due to its’ high porosity and high hydraulic conductivity and was a good candidate for 

alternative groundwater supply for fracing. The RRAA became an appropriate water source for 

fracing, and although there exists some competition from agriculture, it is deemed sustainable 

because it is sourced by the overlying Red River which has been impounded for navigation. 

In the early stages of the Haynesville development, a sub-committee of the WRCNL was formed 

and met at the Institute. Co-chaired by the Director of the Institute and the Executive Director 

of the Red River Waterway Commission, the Water Energy Working Group (WEWG) was 

comprised of federal and state regulators, operators and water transfer specialists. Although 

many Haynesville Shale operators had become convinced that they needed to reduce their 

dependence on the Wilcox Aquifer, appropriate alternatives could not be used without some 

kind of approval process. The WEWG worked to establish USACE permits for access to the Red 

River. Following formal opinions by the Louisiana Attorney General and legislation that would 

allow for the states “running” surface water, including the Red River, to be withdrawn legally, 

operators were given surface water alternative. Private ponds became an easy and appropriate 

source of surface water in areas remote from large waterbodies. If landowners filled the ponds 

using groundwater wells, however, the pond is not considered an appropriate water source for 

fracing by the state. 

Has the Wilcox aquifer been changed by Haynesville Shale drilling activity in northwest 

Louisiana? A study of up to 1000 domestic wells located in the areas of gas shale development, 

was undertaken by the Louisiana Geological Survey /LSU in cooperation with the watershed 

Institute at LSU Shreveport. Over one-third of the wells have been sampled and analyzed. 

About 75 domestic wells that were used in a previous study have been included (re-sampled 

and analyzed). No significant change in water quality has been observed at this point in the 

project. 

A project in nearby south Arkansas has been challenged to develop a recovery plan for Sparta 

Aquifer, historically the main source of water for pubic and industrial use. This successful 

project, which funded the construction of a 20-mile pipeline to a large river in order to supply 

water for industrial needs, allowed industry to stop drawing water from the aquifer and should 

be a model for the nation. A potential unconventional gas play is in the early stages of 

development in South Arkansas/North Louisiana and the Union County Water Conservation 

Board has the potential to supply about 20 million gallons of surface water as an appropriate 

water source for fracing.
Water Management Analysis of Hydraulic Fracturing using System 

Dynamic Models 

Earl Mattson, Carl Palmer, and Kara Cafferty 

Idaho National Laboratory 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Introduction 

The recent increased production of natural gas from tight gas reservoirs has lead to public 

concern of the protection and use of subsurface water resources. Although the water 

consumption to perform hydraulic fracturing of these tight reservoirs often accounts for a small 

percentage of the total water consumption of the region, the rate of water consumption is 

rising, leading towards potential conflicts of water availability even in the “water abundant” 

eastern states associated with the Marcellus Shale. 

The amount of water needed is directly tied to the increase in the amount of natural gas 

production and hence to the number of wells that are hydraulically fractured. Hydraulic 

fracturing for the Marcellus requires approximately 4,000,000 gallons of water for each well 

that is fractured (GWPC, 2009). Drilling in Pennsylvania Marcellus Shale has been increasing by 

16

Figure 1. New oil and gas wells drilled in Pennsylvania by year. Green line is 

represents non-Marcellus Shale, Purple line represents Marcellus Shale wells. 2011 

data is projected from January-February 2011 values.

4500

4000

del

3500

lirD 

3000

slle

2500

W of 

2000

rbe

1500

umN

1000

500

0

2008 2009 2010 2011

Year
17

about 500 wells per year (Pennsylvania Department of Environmental Protection, 2011) (Figure 

1). The resulting water demand for hydraulic fracturing of these wells requires approximately 

6000 acre feet of water each year. 

Furthermore, the location of the Marcellus gas drilling activity is not uniformly distributed. This 

drilling activity tends to be concentrated along available leasing, access to distribution 

pipelines, and overall profitability. Using Pennsylvania as an example, the most active areas 

tend to be near Bradford County in the north and Washington County in the Southwest, (e.g., 

Figure 2). These areas have been the focus of drilling in the Marcellus Shale since 2008, and will 

likely be the preferred areas for some time. 

Figure 2. Location map of oil and gas drilling activities in 

Pennsylvania in 2010 (from PA Dept of Environmental Protection 

web page).

At some point in the future, the increase in hydraulic fracturing activity and the concentration 

of these activities in certain geographic locations could lead to over-allocation of the local water 

supply. The ability to understand, predict and minimize the impact of shale gas energy resource 

development on water supply within the local watersheds needs to be addressed. 

System dynamic modeling is a potential tool that can provide a better understanding of the 

present and future water consumption for a diverse set of stakeholders (the multiple energy 

development operators, federal and state regulators, and the surrounding communities). This 

model is a dynamic non-linear simulation model with the capability to integrate “soft” and 

“hard” system components in a single tool. System dynamic modeling has been used to better 
understand river basin models, fuel cycles, and population dynamics on resources. Although the 

connection of this set of information can be accomplished through the use of multiple software 

packages, one great advantage of system dynamic modeling package is that it provides a visual 

model of the system that allows non-technical stakeholders a better understanding of the 

complex system. 

To develop a system dynamic model for hydraulic fracturing, the water cycle is first broken up 

into a number of sub-models that describe the potential water flows. Figure 3 illustrates a 

potential structure for a system dynamic model. The source water may be from surface water 

sources, shallow groundwater and other recycle/reuse sources. Due to the nature of hydraulic 

fracturing, this water is typically stored on-site in tankers, or storage lagoons. The fracture 

design module would either use data from the operators or from idealized fracture geometries 

(e.g. PKN planer fracture models) to determine water use for the fracture. Water distribution 

from the injection could be segregated into that contained in the fracture, leakoff volume, pretreatment water use volumes. Finally, flowback and produced water could be accounted for via 

numerical approximations of physical phenomena or via operators’ best judgment information 

on a specific location. Produced and flowback water returned to the surface can to examined 

for quantity (and potentially quality) allowing for decisions of treatment options and reuse. 

Researchers at the Idaho National Laboratory are currently conducting an assessment for 

another unconventional fossil energy resource, oil shale. The following example describes how 

an in-situ oil shale retorting operation was modeled and used as input data for a GIS based 

groundwater consumption model of the Piceance Basin in Colorado. 

18

Figure 3. Potential components of System Dynamic Model for 

Hydraulic Fracturing to better understand the water cycle.

Source

Groundwater

Surface water

Reuse

Pre-fracture Storage

Ponds

Pipelines

Tankers

Operation

Operating pressure

Fracture rinse

Flow back water

Produced water Water in matrix

Fracture Design

Injection rate

Injection pressure

Youngs Modulas

Possion ration

Stress conditions

# of fractures

Leakoff rate

Water Injected

Fracture volume

Leakoff volume Waste volume

Post-fracture Storage

Volume

Treatment
19

 

Oil Shale Water Model Example 

The use of oil shale as a supplemental energy source is rapidly emerging as an answer to 

increasing energy demand and cost. Oil shale is a sedimentary rock which contains a high 

content of kerogen. When subjected to high temperatures in an anoxic environment, oil shale 

decomposes into a mixture of liquid and gaseous substances similar to petroleum fuels (Brandt,

2007).Oil shale energy conversion is achieved by two basic methodologies: ex-situ retorting and 

in-situ retorting. Ex-situ processes involve mining oil shale in large open pits or subsurface 

mines, then applying heat in an above ground or surface retort. In-situ retorting process use 

subsurface heaters or steam to apply heat below ground. While still under development, an

advantage of in-situ retorting is the reduction of environmental impacts caused by eliminating 

the mining process. Both processes are water intensive and consume large quantities of water 

for construction, operation, and remediation (Lee, 1991). Accurately modeling water 

requirements and consumption will greatly aid in the assessment of water availability and the 

potential to utilize oil shale deposits as a viable energy source in a region. 

To assess the impact of water availability as a limiting factor for in situ oil shale conversion, a 

PowerSimTM,system dynamic, model was developed. A pilot study conducted by Shell Oil 

Company, was used as a template for the theoretical model since in situ retorting is highly 

developmental. Patents, literature, and engineering principles were referenced where 

appropriate. 

Model architecture for an in situ oil shale development was developed in three stages: 

construction, operation and remediation. Figure 4 illustrates the model interface and the three 

stage design architecture. 

Figure 4. Model Interface of an in situ-oil shale development 
20

Each oil shale stage has a system dynamic model that describes the water use during each 

stage. For example, the construction stage of the in situ retorting process was assumed to 

consist of any site preparation and development prior to oil production (Figure 5). An average 

well drilling rate of 8 ft/hr was estimated from average limestone and sandstone drilling rates. 

Drilling mud and seepage losses were estimated to be 30 barrels/hr and 1.5 barrels/hr

(Devereux, 1999). Pilot study saturated porosities and effective porosities of 10.7% and 3.8% 

were assumed (Brandt, 2007). 

While the construction phase of the in-situ retorting process is controlled by physical activities 

like well drilling and site preparation, the operation phase involves the complex interaction of 

heat transfer, chemical reactions, and material conversion (Figure 6). A non-uniform heat 

transfer rate assuming cylindrical geometries was used to model the in-situ heat transport 

(Hendersen, 1997). An initial oil shale temperature of 20 °C and a pyrolysis temperature of 

400°C were used to calculate heat transfer rates (Brandt, 2007). Homogenous material 

properties were assumed to simplify calculations. Important oil shale material parameters 

include: thermal conductivity (1.2 W/m°C), density (1.75g/cm3), heat capacity (1.25J/g°C) (Lee, 

1991). 

The operation phase includes a process to describe the rate of oil production using kinetic 

factors for pyrolysis oil production published by Shell. Water synthesized during the pyrolytic 

conversion was modeled from chemical reactions, and kinetic factors published in patents and 

literature. An empirical formula for kerogen of C421H638O44S4NCl was assumed. Modification of 

the in-situ porosity was accounted for due to the retorting of the kerogen. 

Figure 5. Construction phase model component of the in-situ oil shale example.
21

Summary 

In many areas of the country shale gas development is rapidly growing. Hydraulic fracturing of 

shale typically injects two to four million gallons of water per well into the subsurface. Of this 

water, 10 to 70 percent is returned to the surface via flowback and produced water 

mechanisms. A predictive method is needed to assess the impact of the projected shale gas 

development on the local water resources in both quantity needed for the fracturing process 

and to develop adequate treatment plans for water to the surface. 

System dynamic models offer a potential tool to assess water needs of the shale gas industry 

and allow its development to coexist with communities needs. The model components can be 

as simple or as sophisticated as necessary and tailored to the complexities of the development 

region. Some components will be based on operators’ judgment. Other components will be 

based from engineering standards, thermodynamics, pilot scale tests, and the results from 

other processes models. These components when combined together, can describe the water 

consumption, losses, and returns to the surface for each hydraulic fracture as a function of time 

and scale. The model should be designed with the intent to be able to connect to GIS databases 

and other state regulatory management tools. Connecting to a GIS database will allow the 

models to access regional spatial data to support the model and allow its output to be 

effectively used in other tools to make water management decisions. 

Figure 6. Operation phase model component of the in-situ oil shale example. 
22

References 

Brandt, Adam R., Converting Oil Shale to Liquid Fuels: Energy Inputs and Greenhouse Gas 

Emissions of the Shell in Situ Conversion Process. Environmental Science Technology 

2008, 42(7489-7495). 

Brandt, Adam R., Converting Green River Oil Shale to Liquid Fuels with the Shell in-situ 

Conversion Process: Energy Inputs and Greenhouse Gas Emissions. 2007. 2-31.

Hendersen, Perry, and Young. Principles of Process Engineering. ASAE. 1997. 150-201. 

 Devereux, Steve. Drilling Technology in Nontechincal Language. Pennwell. 1999. 1(54-

56). 

Ground Water Protection Council and All Consulting, 2009, Modern Shale Gas Development in 

the United States: A Primer, Report to the USDOE, April 

Oil Shale Test Project, Oil Shale Research and Development Project. Plan of operation. 

Submitted to Bureau of Land Management, Shell Frontier oil and Gas, Inc., 2006. 

Lee, Sunggyu, James G. Speight, Sudarashan K.Loyalka. Handbook of Alternative Fuel 

Technologies. CRC Press. 2007. 

Lee, Sunggyu, Robert Iredell, Oil Shale Technology.CRC Press 1991. 

Pennsylvania Department of Environmental Protection, 

http://www.dep.state.pa.us/dep/deputate/minres/oilgas/new_forms/marcellus/marcel

lus.htm, 2011 
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23

Water Requirements and Sustainable Sources in the Barnett Shale 

James “Rusty” Werline, PE

Devon Energy 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

This paper will focus on the water requirements and sustainable sources in the Barnett Shale. 

Devon Energy Corporation understands that water is a needed resource for its business as well 

as an essential part of the ecosystem. Water is vital to the health, social and economic wellbeing of communities in which we live and operate. Our success relies on executing a 

sustainable water management strategy that balances ecological, economic, operational and 

social criteria. Devon is committed to the principles of water conservation and reuse where 

feasible in its operations. 

Background

The Barnett Shale is located in the Fort Worth Basin in North Texas. This paper will focus on 

Devon’s water requirements, water use and water sources in the Barnett Shale. This paper also 

will discuss Devon’s water management and sustainability initiatives in the Barnett Shale. This 

paper focuses on an area covering six counties in North Texas. Devon operates more than 4,500 

wells in the basin and produces approximately 1.2 billion cubic feet (Bcf) of natural gas per day. 

Devon is the largest producer of natural gas in the Barnett Shale and one of the largest 

producers of natural gas in Texas. 

Devon’s Water Requirements in the Barnett Shale

Devon currently is drilling with 13 rigs in the Barnett Shale. Each well requires approximately 

4.3 million gallons of water for the drilling and completion process. Ninety-six percent of the 

total water required for a Barnett Shale well is used for fracture stimulation. Generally, fracture 

stimulations in the Barnett Shale for horizontal wells are performed in six to 10 stages. Peak 

drilling activity for Devon was in 2008, when 584 wells were completed. The following table 

shows the number of wells completed in the Barnett Shale during the past four years by the 

industry and specific to Devon’s operations (Table 1).

2007 2008 2009 2010

Industry wells 2,536 3,084 1,627 1,876

Devon wells 469 584 298 420

% Devon 18.5% 18.4% 18.3% 22.4%

Table 1. Number of wells completed in the Barnett Shale during the past four years by industry 

and specific to Devon's operations 
.08 

In 2010, Devon completed 420 horizontal wells requiring 41.3 million barrels of water and 

refractured 150 vertical wells requiring 4.5 million barrels of water. Of the water used, 11.5 

million barrels were obtained from surface water sources, 32.3 million barrels were derived 

from groundwater sources and 2 million barrels came from Devon’s recycling initiatives. As 

horizontal drilling technology has improved, Devon is drilling longer laterals in the Barnett Shale 

resulting in an increase in the number of fracture stimulation stages required to complete each 

well. The increase in stages requires additional water used on a per well basis; however, fewer 

wells will now be needed to develop equivalent gas reserves in the field. This should result in 

more efficient water use. 

24

Water Use in Texas and the Barnett Shale 

Mining water use in Texas, in which oil and gas activity is included, represents only a small 

fraction of total water use in the state. Mining water use in the Texas Water Development 

Board (TWDB) annual 2008 water use compilation for the entire state resulted in only 0.5 

percent relative to the total of the other water use categories including municipal, 

manufacturing, steam electric, irrigation and livestock. Overall, in 2008 the mining industry in 

Texas used approximately 139,000 acre-feet, including 35,800 acre-feet for fracture stimulating 

wells (mostly in the Barnett Shale/North Texas area). Water use in the Barnett Shale was 

approximately 25,000 acre-feet.1 Figure 7 represents the water usage in the Barnett Shale in 

2008 as per the TWDB. 

The 2007 TWDB Water Plan that utilized water-demand surveys and projections estimated 0.27 

million acre-feet as the demand for mining, compared to about 17.60 million acre-feet of total 

water use in 2010, equating to about 1.5 percent of the state water demand. Combining all 

water uses in the state, projections suggest that peak mining water use will occur in the 2020-

2030 decade at approximately 250,000 acre-feet. Total mining use percentage is never 

expected to exceed 1.5 percent relative to total water use and oil and gas use is never expected 

to exceed 0.6 percent for any of the decades from 2010-2060.1 

The basin-wide fraction of total fresh water resources used by Barnett natural gas producers in 

2005 was estimated to be approximately 0.5 percent in comparison with all other users and 

uses. This was projected by TWDB to rise to approximately 2 percent during the year of peak 

Barnett drilling activity.2 

 

1

TWDB, 2011, Current and Projected Water Use in the Texas Mining and Oil and Gas Industry, Draft

2

Galusky, Jr. L.P. 2009. Fort Worth Basin/Barnett Shale Natural Gas Play: An Update and Prognosis on the Use of 

Fresh Water Resources in the Development of Fort Worth Basin Barnett Shale Natural Gas Reserves
.08 

25

Water Sources Available to Barnett Shale Operators

Groundwater Sources 

Devon produces groundwater from permitted water wells in the Trinity Aquifer. In many cases, 

these water wells are available for use by landowners. The Trinity ranges in depth from 600-

1,400 feet. The Trinity Aquifer outcrops in the western part of the basin and the subcrop is from 

the west to east (Figure 8). The production volume from a single water well may range from 50-

250 gallons per minute. Devon stores the groundwater in centralized earthen containments 

prior to fracturing a well. The basin-wide fraction of groundwater resources used by Barnett 

natural gas producers in 2005 was estimated to be approximately 2.5 percent in comparison 

with all other users and uses. 

Surface Water Sources 

Devon also utilizes surface waters for development of the Barnett Shale. These surface waters 

are obtained with surface-use agreements from local landowners, permitted withdrawals from 

river authorities, purchase agreements with municipal water suppliers and permitted 

withdrawals from local streams and impoundments regulated by the Texas Commission on 

Environmental Quality. The basin-wide fraction of surface water resources used by Barnett 

natural gas producers in 2005 was estimated to be approximately 0.2 percent in comparison 

with all other users and uses. 

Recycled Water

Devon also utilizes recycled water processed with mechanical vapor recompression (MVR) units 

operated by Fountain Quail Water Management. Fountain Quail currently has four units 

operating for Devon with a capacity to process 8,000 to 10,000 barrels of water per day. 

Water Management and Sustainability Initiatives in the Barnett Shale

Devon recycles flowback water with a MVR evaporation process developed by Fountain Quail. 

MVR evaporation is an energy-efficient process that produces distilled water from flowback 

water that contains dissolved solids. The dissolved solids remain in solution and are removed 

from the system as a concentrate and disposed in permitted deep wells. The distillate recovery 

is based on the feed water’s TDS (Total Dissolved Solids) (Figure 9). 

This recycling initiative was implemented in the Barnett Shale in 2005. Fountain Quail currently 

has four units operating for Devon, with capacity to process approximately 8,000 to 10,000 

barrels per day. Each MVR unit has a 2,500 barrel per day capacity. Devon utilized up to nine 

units during peak drilling activity in 2008, with the capability of processing 22,500 barrels per 

day. Devon has generated a total of 10.8 million barrels (454 million gallons) of distilled water, 

which is enough water to fracture stimulate more than 100 wells. With TDS removal, the water 

can be stored in centralized earthen containments and pumped via temporary piping to nearby 

fracture stimulation jobs with little environmental risk. 

Flowback water composition dictates the volume an operator can economically recycle and 

what type of recycling methods may be technically feasible for use. Figure 10 illustrates how 

the TDS values change as a well is produced after fracture stimulation. As the TDS values 
.08 

26

increase, the opportunities to efficiently recycle may decrease. Figure 10 also shows how 

flowback composition changes in different areas of a shale play. With the MVR process that 

Devon utilizes, the best efficiencies are realized when the TDS value is 70,000 parts per million 

or less. 

There are several challenges in implementing a water sustainability and management program 

within a shale gas play. A few of these include technology limitations, maintaining an adequate 

supply of flowback water for treatment, sustained demand for recycled water, transportation, 

logistics and costs, construction of storage facilities, regulatory barriers in permitting and public 

education. Because the Barnett Shale area has several low-cost Class II saltwater disposal 

opportunities that allow operators to efficiently dispose of flowback and produced water, 

developing and implementing a cost-competitive sustainability program using recycling proves 

challenging. 

Devon is constantly working at this challenge and researching new ideas to recycle water from 

natural gas shale development. 
.08 

Municipal - 86%

Manufacturing - 3%

Mining/O&G drilling - 3%

Steam electric - 1%

Irrigation - 4%

Livestock - 3%

Figure 7. 2008 Barnett Shale Water Use Summary Estimates 

27
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28

Figure 8. Trinity Aquifer 
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29

Figure 9. MVR Evaporator Recovery Based on Feed Gravity for NaCl Brine
.08 

30

Barnett Flowback Analysis

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

100000

0 5000 10000 15000 20000 25000

Cumulative Flowback (bbls)

TDS (PPM)

Denton County South Denton County North Johnson County

Figure 10. Barnett Flowback Analysis
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31

An Overview of Current and Projected Shale and Tight-Gas Water 

Use in Texas: Implication for Local Water Resources 

Jean-Philippe Nicot 

Bureau of Economic Geology, The University of Texas at Austin 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

In the middle of 2009, we undertook a study of water use in the state of Texas in the upstream 

segment of the oil and gas industry (that is, water used to extract the commodity until it leaves 

the wellhead), both current and projected for the next 50 years (Nicot et al., 2011). The 

objective of the study was to determine the amount of water used for different purposes (well 

drilling, completion, and secondary and tertiary recovery processes of conventional resources) 

across the state. With tens of thousands of wells having been hydraulically fractured in the past 

few years, the state water agency (TWDB) called for a study to assess hydraulic fracturing (HF) 

water use. Secondary objectives were (1) to collect information on the source of the water 

(groundwater, surface water, or another source) and the quality of the water (fresh or brackish) 

and (2) to understand the extent of recycling/reuse across the industry. We were able to gather 

relatively accurate data from the stimulation stage (HF), as a well is being readied for 

production. Operators have to report the amount of water used in the process, and tabulated 

data are available in a format easy to process from private vendors (IHS Energy). The data were 

not without typos, but they and other issues were resolved by ensuring consistency between 

amount of water, number of stages, and proppant loading. We assigned median values to those 

wells with no usable data. The split between surface water, groundwater, and other sources 

(waste water) was much harder to determine. It seems that neither groundwater nor surface 

water dominates in most plays, and both are used across the state. To the best of our 

knowledge, alternative water sources are still marginal in Texas. The amount of reuse/recycling 

was also difficult to discern. We estimated it at ~5% of the amount injected for shale-gas plays. 

We are more uncertain about water use for drilling wells and waterfloods, although it is clearly 

nonnegligible. 

Overall, in 2010, we estimate that the oil and gas industry used (preliminary numbers) ~45,000

acre-feet (AF) for fracturing wells (Figure 11) and ~18,000 AF for other purposes more 

widespread across the state. These figures do not show a large departure from water volume 

used in previous decades, in which a similar amount of fresh/brackish water was used mostly 

for waterfloods in the western half of the state. Currently hydraulic fracturing is being used in 

many plays across the state, primarily in shale-gas plays, including the Barnett Shale play in the 

Fort Worth area, which is responsible for ~50% of the HF water use (22,500 AF). Other 

important shale plays include the Haynesville/Bossier play in East Texas straddling the Louisiana 

state line (~3,000 AF in Texas) and the Eagle Ford play in South Texas (6,500 AF). The Eagle Ford 

play also contains a significant oil section, which is the focus of current exploration and 
.08 

production. The Permian Basin, a major oil-producing area, has also seen a recent revival, 

thanks to HF of long vertical wells (the “Wolfberry” play). In 2010, Permian Basin plays used 

~7,000 AF for the hydraulic fracturing of many formations (including >3,500 AF in the 

“Wolfberry” play). Tight-gas plays, which, unlike shale plays, are conventional reservoirs or 

sections of conventional reservoirs with a very low permeability, have been receiving hydraulic 

fracturing treatment for decades in Texas. They too have seen a significant increase in interest, 

HF operations, and gas production. East Texas gas plays used ~2,000 AF for HF, whereas the 

Texas section of the Anadarko Basin in the Texas Panhandle used >25,000 AF. The south Gulf 

Coast gas province may be the only basin that has not seen an increase in the number of large 

HF jobs (~1,000 AF over a large area). 

32

To put these figures in perspective, Texas has been projected to have consumed ~18.3 million

AF of water in 2010, according the most recent 2007 state water plan, including >10 and ~4.8

million AF for irrigation and municipal use, respectively. HF water use composes a small fraction 

of the state water use (0.4%). 

Projections for the oil and gas industry were made with the help of various sources by 

estimating the amount of oil and gas (including shale gas) to be produced in the state in the 

0

5

10

15

20

25

30

Barnett Sh

Haynesville Sh

Eagle Ford Sh

oodford/BarnettPB/Pearsall Sh

Anadarko T

East Texas T

Permian Basin TG/T

South Texas / Gulf Coast TG

.

.

.

W .

G

G

O

Water Use (Thousand AF)

Work in progress, preliminary 

results 

Figure 11. Estimated hydraulic fracturing water use in 2008 and 

2010 in the state of Texas. 
.08 

33

next few decades and by distributing it through time (Figure 12). Given the volatility of the price 

of oil and gas, the figures provided clearly indicate only a possible future. We project that state 

overall water use in the oil and gas industry will peak in the 2020–2030 decade at ~<150,000 

AF, thanks to the oil and gas unconventional resources that “will start” to decrease in terms of 

water use around that time. 

In Texas, only one thorough study (Bene et al., 2007) in the public domain and performed in 

2007 addresses the regional impact of shale-gas water use on an aquifer (the Barnett Shale and 

the Trinity aquifer). The conclusion of the study was that the aquifer as a whole was not in 

danger of being depleted and that gas operators use only a relatively small fraction of the total 

demand. However, some rural counties, typically relying on groundwater for domestic use, are 

seeing a relatively large increase in groundwater pumping. A similar situation exists in the 

Carrizo aquifer overlying the Eagle Ford Shale in South Texas. Local recovery following the large 

decrease in irrigation-water demand could be slowed because of HF. In some other areas of the 

aquifer, HF water demand could increase stress to the aquifer. In both these aquifers, note that 

historical pumping stresses were much higher than could be generated by HF and that water 

levels rebounded relatively quickly. However, healthy aquifers do not necessarily mean an 

absence of local water-resource issues. If an HF water supply well is located close to a domestic 

well, pumps may have to be lowered and/or the well deepened, and pumping rates may be 

reduced. 

0

50

100

150

2010 2020 2030 2040 2050 2060

Calendar Year

Water Use (thousand AF)

O&G Shale Gas Tight Fm. Waterflood Drilling

Work in progress, 

preliminary results 

Figure 12. Projected oil and gas water use 2010–2060. 
.08 

34

Reference 

Bene, P.G., B. Harden, S.W. Griffin, and J.-P. Nicot. 2007. Northern Trinity/Woodbine Aquifer 

Groundwater Availability Model: Assessment of Groundwater Use in the Northern 

Trinity Aquifer Due to Urban Growth and Barnett Shale Development. Texas Water 

Development Board. TWDB Contract No. 0604830613. 

Nicot, J.-P., A. K. Hebel, S. M. Ritter, S. Walden, R. Baier, P. Galusky, J. Beach, R. Kyle, L. Symank,

and C. Breton. 2011. Current and Projected Water Use in the Texas Mining and Oil and

Gas Industry, report prepared by the Bureau of Economic Geology. The University of 

Texas at Austin, in review for the Texas Water Development Board, Austin, TX. 
.08 

35

Enabling Fracturing Operations with Zero Fresh Water Withdrawals 

Vikram Rao

Research Triangle Energy Consortium

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Abstract 

Water withdrawals represent an issue in some parts of the country where shale gas operations 

are active. Attempts to use surface water instead of ground water, and in some cases gray 

water, are worthwhile and should be pursued. However, the industry should be challenged to 

do without these. Industry has already responded to the challenge of recycling flowback water 

by becoming more salt tolerant. The ability to use saline waters of convenience should be 

seriously investigated. The primary candidates are sea water, saline aquifer water and 

produced water. Removal of some constituents such as solids, divalent ions and bacteria will 

likely be necessary. 

Principal Issues 

Of the water issues facing shale gas operations, the two demanding the greatest attention are 

fresh water withdrawals and discharges of contaminated water. The latter can largely be 

addressed through re-use of flowback water, albeit with some treatment. But shale gas 

formations are such that only about a quarter to a third of the fracturing fluid returns. This 

causes a need for makeup water. The gel frac operations of the early Barnett are in the past 

except in some instances such as the Haynesville. These days most operations run slick that is 

with less than half of one percent of chemicals. This causes the volumes to go up, and up to 5 

million gallons are used per well. Consequently, makeup water will run up to 3.5 million gallons. 

To date makeup water has been sourced from ground water primarily, but also surface water. 

Schemes to use other sources with low utility, such as gray water, are also being executed. We 

suggest here a discourse on the proposition that all makeup water comprise produced water, 

saline aquifer water or sea water, whichever of these are the saline waters of convenience. 

Handling Salinity 

Fracturing operations have become increasing salt tolerant. To some degree, this has been 

driven by the need to re-use flowback water with a minimum of processing, but once the 

industry approached the problem, it became obvious that in many instances the salinity had 

advantages. In the ternary diagram of carbonate, silica and clay, the preferred compositions are 

those with a higher proportion of the first two constituents. Nevertheless, there is enough clay 

to cause water absorption and swelling. This can be minimized at higher salinities. So a measure 

of salinity is actually a net benefit. In the limit one may want to match the salinity of the 

connate water in order to create a chemical potential balance. 
.08 

Even if salinity is tolerable to about 80,000 ppm TDS, we know that flowback water can exceed 

that number. Table 2 shows some data for the Marcellus. In this particular study TDS topped 

out at around 220,000 ppm, but instances of 350,000 ppm are not completely uncommon in 

the Marcellus. 

36

Table 2. Typical Marcellus Salt Levels (ppm). Source: Blauch et al. SPE Paper 125740, 2009 

Total Dissolved Solids 

(ppm) 

Mg (ppm) Ca (ppm) 

Average 47,364 175 1750 

Range 16,000 – 220,000 10-927 400-8600 

It is possible that these are due to evaporite sequences or from accidentally allowing fractures 

to penetrate the highly saline Onandaga below the reservoirs. Assuming these are unavoidable 

in the main, one must be prepared to handle high numbers. This means that some level of 

desalination may be necessary although clearly not the levels dictated by the old paradigm of 

fresh water as base fluid. All desalination methods leave a residue that needs disposal, and in 

the case of reverse osmosis, the residue from sea water desalination has TDS of around 75,000 

ppm. This may be usable, but in general one needs to be prepared to dispose of these residues. 

An option would be the saline aquifers, even if they were the source of water. Regulations 

allowing this would need to be studied. Produced water is currently being reinjected in some 

locations. This would not be that different. 

Saline Aquifers 

Since ground water tends to get saltier with depth, one can reasonably assume that saline 

aquifers are ubiquitous. Deep saline aquifers have been studied as repositories for captured 

carbon dioxide, and the Frio is the largest in the country. The last map was published around 

1960 and one assumes the lack of updating is due to not enough importance being attached to 

these water bodies. (Figure 13 shows the available map of saline aquifers in the US.) Even this 

map demonstrates the existence of such water over much of the shale production areas. It also 

shows the depths to be low to moderate. This likely equates to modest salinity, which is good 

for hydraulic fracturing. The actual figures are almost certainly available in many instances. If 

the viability of use of this sort of water is confirmed, a mapping of location and composition 

would be of value. 

Divalent Ions 

Divalent ions, in particular Mg and Ca, cause issues with some the ingredients of fracturing 

fluid. The affected chemicals include surfactants, breakers and friction reducers. All of this can 

be traversed through substitution. The worst actor is likely the formation of scale. In of itself it 

can be deleterious, but the propensity of scale to concentrate the very low concentration of 

radioactive elements sometimes present is a concern. Absent scaling, the divalent ions would 
.08 

37

likely be returned to the formation through reuse of the flowback water therefore removal of 

these species is probably for the best. Technology for removal of divalent ions is very 

straightforward but the practicality of doing so at every site may be daunting. One fairly recent 

trend that could increase the use of treatment technology is the practice of pad drilling, which 

involves drilling up to 20 wells from a single location. This allows for aggregation of facilities of 

all types and has other environmental benefits.

Bacteria 

Bacteria are known to be bad actors in reservoirs because they cause the formation of various 

undesirables such as sulfates that plug pores and cause the formation of H2S. Therefore, any 

frac fluid must be free of bacteria. The bacterial content of saline aquifers is not known 

systematically. A 1975 study (Willis, et al., 1975) determined that three shallow unpolluted 

saline aquifers in the southeast contained various species, mostly anaerobic. Methanogenic 

bacteria were also found in each case. One can reasonably expect that biocidal treatment will 

be necessary. 

Discussion 

The workshop participants should debate the advisability of using saline waters of convenience 

as makeup water. Saline aquifers are likely the most viable targets. These would need to be 

more completely mapped for the benefit of the industry. Economic considerations would 

Figure 13. Saline Aquifers in the US
.08 

38

include the levels of processing required and the practicality of moving this water over 

distances. 

Reference 

Willis, CJ, GH Elkan, E Horvath, and KR Dail. 1975. Bacterial flora of saline aquifers. Ground 

Water 13(5): 406-409.
39

Sustaining Louisiana’s Fresh Water Aquifers – A Case Study in 

Bringing Community and Industry Together 

James H. "Jim" Welsh 

Louisiana Office of Conservation 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

 

The Haynesville Shale Natural Gas Play in Louisiana lies more than 10,000 feet below the 

surface. It is a consistent 500-foot thick layer underlying an area approximately 80 miles south 

to north by 60 miles east to west across the north Louisiana/east Texas border. In order to 

commercially produce the wells in the Haynesville Shale, operators use the technique known as 

“Hydraulic Fracturing”. Fracking, as it is referred to, requires large volumes of water - up to 5 

million gallons per well. Ground water had been the usual source for this drilling technique over 

the years, but as development in the Shale heightened, the potential for impacts on local 

domestic water use had become a real concern. 

 

Recognizing that the extensive water demand could pose a stress on nearby fresh water 

aquifers, the Louisiana Office of Conservation (the state’s regulatory authority) began to pursue 

alternatives to satisfy industry’s need for water for this type of exploration and production 

(E&P) activity, while trying to avert impacts to the immediate source of water for area 

neighborhoods and the local community. 

 

The Conservation Office wasted no time in researching and finding ample yield in several 

surface water sources. By combining this course of action with a few other water management 

procedures, and with amendments to the existing regulations, the office provided a successful 

and manageable solution. In this case, the outcome included appropriate use and protection of 

surface water, ground water and domestic water supply. Collectively, all stakeholders would 

share in the effort to conserve, protect, and sustain the state’s fresh water aquifers.
40

Summary and Abstracts from Theme 2: Flowback Recovery & 

Water Reuse 
41

Summary of Presentations for Theme 2: Flowback Recovery & Water Reuse 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 

Technical Presentations 

The first set of technical presentations in this theme addressed case studies from around the 

United States. 

Matthew Mantell, Chesapeake Energy Corporation, discussed the feasibility of produced water 

reuse in various shale formations. Mr. Mantell noted that this feasibility is influenced by initial 

and long-term produced water volumes as well as the quality of the produced water. He also 

described produced water management options, including disposal by deep well injection and 

simple and advanced methods for treatment and reuse. Mr. Mantell noted that natural gas 

combustion results in the release of water, replacing the water HF processes remove from the 

hydrologic cycle. He also emphasized that industry is working to improve the efficiency of fresh 

water use. 

Keith Minnich, Talisman Energy Inc., provided information on produced water reuse from a 

water treatment and water chemistry perspective and presented case studies highlighting key 

water reuse issues. Mr. Minnich noted that, in some cases, produced water can be reused after 

simple settling of suspended solids and does not require other treatment techniques. In 

addition, he suggested that blending of produced water and fresh water might be effective for 

reducing the scaling potential of the HF water. He noted that the addition of barite “seed” 

crystals can be used to precipitate barite out of supersaturated waters. Mr. Minnich also 

discussed logistical considerations for water reuse and emphasized that treatment and reuse 

activities must be site specific. 

The second set of technical presentations addressed flowback characteristics. 

Matthew Blauch, Superior Well Services, described the results of sequential flowback analyses 

in the Marcellus and their implications for produced water reuse. He presented water 

chemistry results for TDS, chloride, hardness (calcium carbonate), and barium, as well as these 

components’ relationships to flowback volume and location. Mr. Blauch discussed evidence 

suggesting that salt content in produced water is due to primary dissolution of thin salt lenses 

within the Marcellus. Mr. Blauch concluded that formation water variations require ongoing 

chemical analysis of produced waters; however, these analyses can also provide a basis for 

predicting the chemical composition of produced waters in new development areas.
.08 

42

Tom Hayes, Gas Technology Institute, presented data on produced water chemistry from the 

Marcellus and the Barnett. The analyses included TDS levels in produced water over time and 

concentrations of chemicals of concern, including volatile and semi-volatile organics, pesticides, 

polychlorinated biphenyls (PCBs), metals, and radionuclides. Based on these results, Dr. Hayes 

identified possible treatment needs for reused water and described two broad treatment 

options (demineralization and conditioning without demineralization) that could achieve these 

objectives. Dr. Hayes also described examples of specific treatment methods currently in use in 

HF operations.

The third set of technical presentations in this theme addressed reclamation systems. 

Jill Cooper, EnCana Oil & Gas (USA), described EnCana’s water reclamation system in the 

Piceance basin of Colorado. Ms. Cooper explained that the target formations there have several 

properties that make the reuse of flowback water attractive, such as the presence of natural 

fractures and permeability. These properties allow EnCana to minimize use of proppant, 

reducing the amount of additives needed in fracturing fluid as well as the amount and cost of 

treatment necessary to prepare produced water for reuse. Ms. Cooper closed by 

recommending a regional approach to regulation because of the variation between different 

formations. 

D. Steven Tipton, Newfield Exploration Mid-Continent, presented Newfield’s flowback water 

recycling program. Mr. Tipton stated that water treatment, transport, and disposal are a huge 

cost for operators, and in the Granite Wash formation, Newfield can recycle up to 80% of 

produced water with no treatment. He explained that the water is transported to recycle pits 

via poly lines. He also explained that in the Woodford Shale, produced water has high chloride 

content and a small amount (6%) is reused as a brine source after treatment at a recycling 

facility, replacing the addition of potassium chloride (KCl) to the fracture fluid.

Johanna Haggstrom, Halliburton Energy Services, presented a “toolbox” of treatment options 

available for produced water recycling. Categories of treatment techniques she presented 

include clarification (removal of suspended solids and some metals and organics) and 

demineralization (removal of dissolved solids). Ms. Haggstrom emphasized that choosing a 

treatment option should be done on a case-by-case basis due to the unique makeup of 

produced waters from different formations and the different goals for the end-use of this 

water. Halliburton does not provide operators with specifications for final water quality of 

produced water on particular projects.

George King, Apache Corporation, described Apache’s reuse of water in the Horn River play in 

British Columbia. Mr. King explained that the drilling operation is a closed-loop system that 

withdraws a 35,000 ppm brine from a nearby reservoir, uses it in the fracturing fluid, performs 

some minor treatment on the produced water, and then returns it to the original formation. He 

explained that the brine reservoir has other properties including high temperature and low 
.08 

levels of solids and other suspended materials that make it an ideal component of the fracture 

fluid, require minimal additional chemicals, and facilitate reuse. The chemicals used in this 

system are commonly available in many household products. This closed-loop reuse system 

reduces the environmental impact of the drilling operation, freshwater use, and operator costs. 

43

Summary of Discussions Following Theme 2: Flowback Recovery and 

Water Reuse Presentations 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 

Clarification of items in the presentations. A participant asked about the Marcellus Shale core 

shown in Mr. Blauch’s presentation. The presenter clarified that both cuttings and standard 

core were taken; he noted that cuttings are easier to obtain, but cores allow a researcher to 

pinpoint the location of salt striations. A participant asked about the fluctuating produced 

water TDS levels shown on a graph in Dr. Hayes’s presentation. The presenter explained that, 

generally, TDS levels steadily increase with time; however, individual cases may differ from this 

pattern. A participant asked about barium analysis in the second set of technical presentations. 

Both presenters indicated that the analyte was soluble barium, not total barium. A participant 

asked what kind of liner is used in Newfield’s pits. The presenter clarified that Newfield uses a 

geo-membrane liner in their pits. For freshwater pits they use a 20 mil liner, and for flowback 

water, Newfield uses a 30 mil liner. The presenter explained that these liners are used because 

the water has a low TDS (17,000 mg/L) that meets Oklahoma agricultural use standards.

Water treatment techniques. A participant asked about testing recycled water before reuse. In 

the Marcellus Shale, one operator uses a centralized pad for filtration. According to this 

participant, water is analyzed on site for a few parameters, such as bacteria and scaling 

properties, and a titration method is used to analyze for chloride. A presenter asked if the 

settling tanks or effluent inlets are designed for swirling or other accelerated settling 

techniques. The presenter clarified that standard tanks have been used to date, with the inlets 

and outlets arranged in the optimum fashion. A participant noted that Amoco conducted 

research on settling tanks in the 1970s and 1980s. Another participant asked if on-site 

treatment techniques can be powered by the gas that is produced at the site. The presenters

agreed that while this is possible, it is more economical to sell the gas. However, they noted 

that treatment techniques are sometimes powered by waste heat from the compressors. 

Use of surface water. A participant asked if it is more economical to use surface water rather 

than recycled produced water in areas with sufficient supplies of surface water. The presenters

indicated that this is generally the case, especially in the Haynesville where water chemistry is 

poorly suited to reuse. The presenters added that water quality in the Haynesville is generally 
.08 

consistent across the shale play. However, they noted that the larger Marcellus Shale has 

variations in water quality from Pennsylvania to West Virginia.

Biocides. A participant asked about the use of biocides in recycled water. The presenters stated 

that they use standard biocides, such as glutaraldehyde or a glutaraldehyde quaternary amine 

blend, and that there are not special biocide treatments for recycled water. However, they 

noted that ongoing experiments are investigating the use of chlorine dioxide, similar to the 

techniques used by municipal water systems. The presenters of the third set of technical 

presentations indicated that use of biocides may not be necessary in some slickwater 

operations with high bottomhole temperature. However, they clarified that biocides are 

necessary if polymers for a gel are being mixed with surface waters.

Economic drivers of water reuse. A participant asked if reusing water is economical. The 

presenters indicated that reusing water is very cost-effective in the Marcellus because of the 

otherwise high disposal costs of produced water. They stated that operators try to reuse 100% 

of their water, including initial flowback and long-term flowback, especially in the northern 

parts of the Marcellus play. They noted that southern parts of the Marcellus are closer to 

disposal wells; according to the presenters, reuse is not as prevalent in these areas but it is 

increasing. The presenters noted that in the Fayetteville, recycling is also attractive because 

produced water does not have to be treated before it is reused. Some participants added that 

water reuse will likely become more economical as technologies develop and improve.

On-site water management and multi-well pads. A participant asked about environmental 

management and oversight at HF sites. Participants explained that once the well completion 

activities are set up, water managers ensure that the completions team is properly supported. 

A participant stated that a host of environmental and safety standards support these activities, 

and operators closely monitor the amounts of water and hydrocarbons produced. Another 

participant stated that large operators can dedicate staff to on-site water management 

activities. A participant pointed out that multi-well pads can reduce the risks and concerns 

associated with transporting produced water, since water may be able to be reused on site. 

Another participant noted that multi-well pads will likely become more prevalent once initial 

drilling is completed to maintain individual leases. A participant asked which party at a drill site 

is responsible for handling produced water. A presenter explained that the operator is 

ultimately responsible for the produced water (as well as for any individuals on the site). 

However, the presenter added that operators usually contract to a third party who specializes 

in flowback management.

Removal of solids. A participant asked about techniques for the removal of solids from 

produced water. The presenter clarified that there are two goals to this process: reducing the 

overall amount of solids in the water and reducing the particle size of the remaining solids. The 

presenter stated that, generally, nothing is added during this solids removal process. The 

resulting solids are inert compounds: a mix of sand, clay, rock cuttings, and some precipitated 

barite. The presenter noted that barium chloride is much more soluble and will not settle out. 

44
.08 

45

The presenter commented that after settling, the material is removed from the tanks and a 

third party transports it to a licensed landfill. As far as the presenter is aware, the landfills have 

not encountered any issues with radioactive material in the removed solids. He also noted that 

naturally-occurring radioactive material (NORM) is generally present as soluble radium, which 

stays in the produced water and does not filter or settle out. A participant noted that in 

Colorado, data suggest that gross alpha/beta levels are high in produced pit liquids.

Pipelines. A participant asked about transporting fresh and produced water through pipes and 

how these used pipes are flushed and transported when they need to be moved. One 

participant transports flowback by truck but uses irrigation-based pipe for temporary fresh 

water pipeline. The participant noted that this irrigation pipe often allows water to seep out 

once it is pressurized. Another operator transports both fresh water and brine by pipe. The 

participant explained that the fresh water pipe is ten-inch aluminum irrigation pipe, while 

brines of high TDS levels can be conveyed with a pipeline of higher integrity of construction to 

eliminate leakage. The participant stated that pipes transporting flowback are “pigged” and 

flushed to ensure none of the water leaks out when the pipe is dismantled. Other participants 

do not use irrigation pipe for fresh water because of public perception issues. One participant 

avoids making 90 degree angles with the pipe and contracts a third party to conduct pressure 

tests to ensure the pipe’s integrity. 

Well pad reclamation. A participant asked about the final steps for reclaiming a well pad, 

specifically whether reclamation is different when produced water is managed on site. A 

participant noted that on-site protocols for handling flowback are similar regardless if the water 

is destined for disposal or for reuse. However, a participant added that performing more 

extensive treatment on site can impact reclamation and this is one reason why operators might 

choose to treat water for recycling in a central location or to only treat water by settling. A 

participant noted that at the well pad, operators try to avoid any long-term remediation needs 

by installing liners, ensuring proper materials handling, etc.

Research and development. A participant asked if operators develop in-house methods to 

improve water quality for reuse. The presenters explained that operators both develop new 

methods and use established methods. They added that some operators are coordinating to 

evaluate different ways of managing chemical additives, especially in areas where fresh water 

aquifers underlie multiple leases. One participant noted that coordination happens best in the 

field, not on the management level. The participant suggested that, in the future, third-party 

firms might act as water brokers, treating and redistributing excess flowback. One participant 

noted that knowledge sharing is a key factor in water management. Another participant 

pointed attendees to the BSWMC’s Web site (http://www.barnettshalewater.org/) to find more 

information on coordinated water management efforts. The participant noted that there is an 

established structure for research, development, evaluation, and identification of best practices 

in this rapidly developing field. 
.08 

Chemical analyses of flowback. A participant asked if the chemical components of flowback 

from the Marcellus and the Barnett are similar. The presenter explained that five-day flowback 

samples from both formations have similar general chemistries. In general, the Barnett seems 

to have a higher alkalinity. He noted that total organic carbon (TOC) is low and oil and grease 

levels are in the tens of mg/L for both formations. A participant asked about 2-butoxyethanol 

(2-BE) in flowback fluids. Dr. Hayes clarified that the study in his presentation analyzed for four 

alcohols. He explained that TOC levels indicate the order of magnitude of the alcohols and 

other organic compounds is low. In general, his study found that flowback fluids have very low 

TOC levels (tens of mg/L). A participant asked if future investigations of flowback fluid should 

include additional or different analytes. A presenter indicated that effective studies can include 

fewer analytes and that Dr. Hayes’ study included a large list of the potential chemicals of 

concern, including some that are not used in HF. In addition, this study originally included 

radionuclides, but that analysis was postponed due to issues with salt interference. Participants 

added that data collection and analysis of flowback is very important and that other operators 

have been collecting similar data.

Salt striations in the Marcellus Shale. A participant asked about salt striations in Marcellus Shale 

core. The presenter explained that these salt deposits were analyzed by direct sampling and by 

leaching under surface/atmospheric conditions. A participant noted that the source of the salt 

deposits has not been extensively described in the geologic literature, but there is evidence 

showing that they may be evaporative. Another participant added that a presentation in 

Workshop 1 (Chemical and Analytical Methods) contained compelling evidence that the salt 

originates in evaporative sequences in the formation.3 

A water balance approach for monitoring. A participant asked about using a water balance 

approach to determine whether fractures have grown into other zones: if long-term produced 

water volumes are greater than injected volumes, would that be evidence that fractures have 

broken into other formations? Another participant noted that this might be a useful approach, 

though long-term data on this subject are not available and it seems that the variability of 

subsurface properties would complicate any water balance approach. One participant noted 

that some shale plays have only been in production for a few years, limiting the availability of 

long-term flowback data. Multiple participants stated that, in general, the Barnett is the only 

shale play that will return more water than originally injected.

Chemical partitioning. A participant asked about the effect of condensate production on TOC 

levels in flowback. This would be relevant to the southwestern section of the Marcellus Shale. 

Other participants noted that samples from this area do not show elevated TOC levels, likely 

 

46

3

EPA believes the presenter was referencing the presentation by Jennifer McIntosh (University of Arizona) on 

Chemical and Isotopic Tracers of Natural Gas and Formation Waters in Fractured Shales. The abstract that 

corresponds to the presentation is included in the Proceedings of the Technical Workshops for the Hydraulic 

Fracturing Study: Chemical & Analytical Methods (EPA 600/R-11/066).
.08 

due to partitioning between the gas and the condensate. A participant described air quality 

results from condensate tanks in southwestern Pennsylvania, claiming that high levels of 

naphthalene, benzene, toluene, and xylene were present. The participant asked why these 

materials are not found in the water. Another participant suggested that this is likely also due 

to partitioning. 

Regulation and permitting. In Colorado, drilling on federal lands is overseen by the Bureau of 

Land Management (BLM). BLM has a Memorandum of Understanding (MOU) with the Colorado 

Oil and Gas Conservation Commission (COGCC) regarding production activities on federal lands. 

A participant noted that obtaining a permit for produced water recycling in Texas requires the 

certification of a registered engineer, among other requirements. Oklahoma is in the process of 

permitting the first recycling pit. In Texas, one participant drains pits annually, inspects the 

liners, and makes repairs if necessary.

Disclosure of fracture fluid additives. Halliburton provides the composition of their fracture 

fluids in many of their areas of operation, available on their Web site. Apache and other 

operators have also made this information available and it will be included on the 

http://fracfocus.org Web site. Participants indicated that the main components of fracture fluid 

will be disclosed, although there will most likely always be some that remain confidential as 

trade secrets. Other participants added that some companies are developing more 

environmentally-friendly alternatives to fracture fluid components, dependent on demand for 

green alternatives from operators.

Well siting. The presenters of the third set of technical presentations clarified that a number of 

factors are taken into consideration when siting wells to minimize environmental impact, 

including, for example, proximity to drinking water system well fields. The presenters explained 

that directional drilling technology has advanced so that gas reserves can be reached by a well 

some distance away. 

Reusing other fluid types. The presenters of the third set of technical presentations noted that 

while slickwater fracture fluids are generally the best candidates for reuse, linear gels have 

been reused in some regions. The presenters explained that the higher number of additives in 

gel systems generally makes them less attractive for reuse.

47
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48

Abstracts for Theme 2: Flowback Recovery & Water Reuse 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 
.08 

49

Produced Water Reuse and Recycling Challenges and Opportunities 

Across Major Shale Plays 

Matthew E. Mantell, P.E. 

Chesapeake Energy Corporation 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Water Use in Shale Development 

Water is an essential component of shale development. Operators use water for drilling, where 

a mixture of clay and water is used to carry rock cuttings to the surface, as well as to cool and 

lubricate the drillbit. Drilling a typical Chesapeake shale well requires between 65,000 and 

600,000 gallons of water. Water is also used in hydraulic fracturing, where a mixture of water 

and sand is injected into the shale at high pressure to create small cracks in the rock and allows 

gas to freely flow to the surface. Hydraulically fracturing a typical Chesapeake shale well 

requires an average of 5 million gallons of water. The water supply requirements of shale oil 

and gas development are isolated in that the water needs for each well are limited to drilling 

and development, and the placement of shale wells are spread over the entire shale play. 

Subsequent fracturing treatments of wells to re-stimulate production are possible, but unlikely, 

and re-stimulation is dependent upon the particular characteristics of the producing formation 

and the spacing of wells within the field. A breakdown of approximate water use for drilling and 

fracturing by shale play is provided below: 

Table 3. Water use in major shale plays
.08 

Produced Water Management 

50

Produced water plays a key role in the environmental and economic viability of shale oil and gas 

development. Produced water is a byproduct of all oil and natural gas (energy) development. In 

order to successfully develop these resources, produced water has to be effectively managed. 

For the purposes of this discussion, produced water is all water that is returned to the surface 

through a well borehole and is made up of water injected during the fracture stimulation 

process, as well as natural formation water. Produced water is typically produced for the 

lifespan of a well, although quantities may vary significantly by play. Produced water quality can 

also vary tremendously from brackish (not fresh, but less saline than seawater) to saline (similar 

salinity to seawater) to brine (which can have salinity levels multiple times higher than 

seawater). Furthermore, the term flowback refers to the process of excess fluids and sand 

returning through the borehole to the surface. For this discussion, the water produced during 

flowback operations is considered produced water. 

The feasibility of produced water reuse is dependent on three major factors. First is the 

quantity of the produced water generated, including the initial volume of produced water 

generated (typically during the first few weeks after stimulation). The second factor is the 

duration in time of produced water generation, including the rate at which water is generated 

and how it declines over time. Wells that produce significant volumes of produced water during 

the initial time period are preferred for reuse due to the logistics involved in storing and 

transporting the water for reuse. A continuous volume can keep tanks and trucks moving, 

increasing the economic efficiency of reusing the produced water from one wellsite to another. 

The Barnett, Fayetteville, and Marcellus Shales all produce a significant volume of initial 

produced water enabling the effectiveness of reuse. These three major shale plays produce 

approximately 500,000 to 600,000 gallons of water per well in the first 10 days after 

completion. This volume is sufficient to provide approximately 10% to 15% of the total water 

needed to fracture a new well (see Table 3 above). The Haynesville Shale produces less water, 

approximately 250,000 gallons per well in the first 10 days after completion. This is 

approximately 5% of the total water needed to fracture a new well. 

Long-term produced water production is also important because wells that produce large 

volumes of produced water for long periods of time will require a disposal or reuse option that 

is located in close proximity to the wellsite in order to retain the economic viability of the 

operation. The unit of measurement used for comparison of long term produced water is 

gallons of water per million cubic feet (MMCF) of gas or hydrocarbon liquid equivalent. This unit 

of measurement for comparing volumes is exclusive to shales because there appears to be a 

direct correlation between hydrocarbon production and long term produced water generation 

in the major shale plays. Barnett Shale wells generate by far the largest volume of produced 

water of any major shale play at greater than 1,000 gallons per MMCF. The Barnett Shale is 

believed to contain larger volumes of natural formation water present in, and in close proximity 

to the shale. The Eagle Ford, Haynesville, and Fayetteville Shale are moderate produced water 

generating plays at approximately 200 to 1,000 gallons per MMCF. These shale formations are 

relatively desiccated and allow less fluid production per MMCF. The lowest long term produced 
.08 

51

water volumes come from the Marcellus Shale. The Marcellus is a highly desiccated formation 

that tends to trap fluids in the shale through physical / chemical interactions. Water production 

is less than 200 gallons per MMCF in the southern portion of the play in West Virginia, and 

closer to 25 gallons per MMCF in northern portion of Pennsylvania. 

The third major factor in produced water reuse is the quality of the produced water. Total 

dissolved solids (TDS), also known as the salinity, total suspended solids (TSS), the larger 

suspended particulates in water, scale-causing compounds (calcium, magnesium, barium, 

sulfate) and bacteria growth all have a major effect on the feasibility of reusing produced 

water. TDS can be managed in the reuse process by blending with freshwater to reduce the 

TDS. Blending is necessary because high TDS can increase friction in the fluid which is 

problematic in the hydraulic fracturing process. TSS can be managed with relatively inexpensive 

filtration systems. Filtration of TSS is necessary because elevated solids can cause well plugging 

and also decreases biocide effectiveness. Scale and bacteria causing compounds can be 

managed with chemical treatments or advanced filtration, but each additional treatment step 

reduces the economic efficiency of the process. The ideal produced water for reuse has low 

TDS, low TSS and little to no scale or bacteria-causing compounds. (Chesapeake Energy 2010d) 

Produced Water Management Options 

While produced water is generated with the production of oil and gas (energy) as stated above, 

energy also plays a key role in determining the best way to manage produced water. Most 

produced water is of very poor quality and may contain very high levels of natural salts and 

minerals that have dissociated from the target hydrocarbon reservoir. 

Two classifications of treatment technologies are available for treatment and reuse of produced 

water: conventional treatment and advanced treatment technology. Both classifications have 

energy, environmental, and economic impacts that are directly impacted by produced water 

quality. Conventional treatment includes flocculation, coagulation, sedimentation, filtration, 

and lime softening water treatment processes. These treatment processes are generally 

effective in removing water quality parameters such as suspended solids, oil and grease, 

hardness compounds, and other nondissolved parameters. These conventional water 

treatment processes can be energy intensive, but are typically much less energy intensive than 

the salt separation treatments listed below. Conventional processes such as flocculation, 

coagulation, and lime softening utilize chemicals (sometimes in large volumes) which may have 

a significant energy input in the development of these chemicals used in the treatment process. 

However, simple filtration methods with little to no chemical inputs have a much lower energy, 

environmental, and economic impact. 

Advanced treatment technology includes reverse osmosis membranes, thermal distillation, 

evaporation and/or crystallization processes. These technologies are used to treat dissolved 

solids, primarily consisting of chlorides and salts, but also including dissolved barium, strontium 

and some dissolved radionuclides. These dissolved parameters are much more difficult and 

energy intensive to treat and can only be separated with these advanced membrane and 

thermal technologies. Treating dissolved solids is a very energy intensive process. These 
.08 

processes are the “second level” or more advanced form of treatment because similar 

conventional processes listed above are typically needed upfront to ensure that most of the 

non-dissolved parameters listed above are removed prior to the dissolved solids treatment 

process. 

Outside of treatment for reuse, disposal is the other produced water management option. 

Outside of the Marcellus Shale, salt water disposal wells are by far the most common method 

of disposing of produced fluids from shale operations. Surface discharge via wastewater 

treatment plants has historically been a common treatment technique in the northeast United 

States, but has been generally phased out due to stricter discharge regulations and natural 

evolution of the industry due to the Marcellus Shale development. As a note, Chesapeake 

Energy does not currently discharge any produced water either directly, or via wastewater 

treatment plants in any shale play. 

Energy, environmental and economic considerations must be carefully considered when 

discussing possible reuse and disposal options for produced water. Much discussion and 

technology development has focused on treatment technologies that can treat produced water 

so it is suitable for some form of reuse. These options include reuse in oil and gas operations, 

municipal, agricultural, and/or industrial operations. Lower dissolved solids produced water 

(<30,000 ppm TDS) may be feasible for treatment to reuse outside of oil and gas operations. 

Higher dissolved solid produced waters (> 30,000 ppm TDS) should only be reused where the 

high salt/salinity content can be kept in solution (to avoid the intense energy input to separate 

salts). Operators have successfully demonstrated this ability by using conventional treatment 

processes on high TDS waters, then managing the TDS by blending the fluids in hydraulic 

fracturing operations. The feasibility of relying on high TDS produced waters for potential 

municipal or agricultural water supply doesn’t make sense from an energy, economic, or 

environmental perspective due to the availability of alternative low quality water resources 

that could be treated to acceptable standards with far lower energy inputs. This includes 

municipal wastewater, brackish groundwater, and even seawater when logistically feasible. 

Based on this same logic, environmental and economic benefits may directly correlate when 

evaluating reuse versus disposal. For example, in areas with extensive salt water disposal well 

infrastructure like the Barnett Shale, salt water disposal wells are in close proximity to 

operations, and are a low cost, low energy, safe, and effective alternative to advanced reuse. 

The energy requirements needed to treat Barnett Shale produced water (outside of direct 

filtration and blending) is significant. Since all energy sources result in some form of air 

emissions, water use, and/or waste generation; reusing produced water in this area using an 

advanced treatment technology may have greater negative environmental impacts than salt 

water disposal. Furthermore, oil and gas operations that keep dissolved solids in solution and 

use the fluid in completion operations for subsequent wells can effectively reduce the volume 

of fresh water needed for future operations by significant amounts. The onshore shale oil and 

gas industry has recently been very successful in utilizing conventional, low energy treatment 

systems to remove suspended solids from produced water and in using this water in hydraulic 

52
.08 

fracturing operations. From an energy efficiency standpoint, this is a much more efficient use of 

energy and water than treating produced water to drinking water standards. 

53

Produced Water Reuse and Recycling: The Chesapeake Energy Experience 

Over the past three years, Chesapeake has developed and implemented a highly successful 

produced water reuse program in its Marcellus Shale operating area, and has extended this 

program to all its shale operating areas. Chesapeake is not alone as many other onshore shale 

oil and gas companies have also been working to continue to reduce the volume of freshwater 

utilized in operations and thereby reducing the need to compete with other traditional users of 

freshwater. 

Barnett Shale Reuse 

Reuse of produced water in the Barnett Shale is limited by the high volumes of water produced 

and the corresponding availability of Class II saltwater disposal wells (SWDs) in close proximity 

to well sites. Barnett Shale produced water generally has higher levels of TDS, low TSS and 

moderate scaling tendency. Chesapeake is currently treating and reusing approximately 6% of 

the total water needed to drill and fracture Barnett Shale wells in the southern portion of the 

play. Currently, logistics and economics are the main limiting factors in preventing higher levels 

of reuse in this area. These factors (logistics and economics) as well as urban curfew limitations 

(limited 24 hour operations in urban Ft Worth areas) currently prevent the feasibility of reuse in 

Chesapeake’s northern Barnett Shale operational areas. However, in the northern (urban) 

portion of the Barnett Shale, Chesapeake is pioneering the use of evaporative technologies that 

utilize waste heat from gas compressors to reduce the volume of water injected into salt water 

disposal wells. The benefit of this technology is the prolonged lifespan of the salt water disposal 

well (heavier concentrated brines may actually be better for disposal wells) and also the ability 

to manage fluids with fewer disposal wells. 

Fayetteville Shale Reuse 

Fayetteville Shale produced water is generally of excellent quality for reuse and the volumes of 

water generated are typically sufficient. Fayetteville Shale produced water has very low TDS, 

low TSS and low scaling tendency. Chesapeake is currently meeting approximately 6% of 

drilling and fracturing needs in the Fayetteville Shale with produced water reuse with a target 

goal of 20% reuse in the play. Since TSS levels are low, very limited treatment (filtration) is 

needed prior to reuse. As with the Barnett Shale, logistics and economics are currently the main 

limiting factor in preventing higher levels of reuse in the Fayetteville Shale. 

Haynesville Shale Reuse 

The Haynesville Shale produces a smaller volume of produced water initially (compared to the 

other major plays) and has very poor quality produced water. TDS levels are high immediately, 

TSS is high and the produced water has high scaling tendency. The quality and volume factors 

combined with an adequate SWD infrastructure make produced water reuse in the Haynesville 

very challenging. Chesapeake has looked into produced water reuse in the Haynesville, but low 

produced water volumes, poor produced water quality and the resulting economics have 

prevented successful reuse of produced water in the Haynesville Shale to date. However, due 

to the large volumes of higher quality drilling wastewater generated during the drilling process, 
.08 

Chesapeake is actively exploring options to reuse this wastewater in subsequent drilling and 

fracturing operations. 

54

Marcellus Shale Reuse 

In terms of produced water generation, the Marcellus Shale is ideal in that it produces a 

significant volume of produced water within the first few weeks and then the water 

production generally falls off very quickly. The quality of Marcellus Shale produced water is 

good with moderate to high TDS, low TSS and moderate scaling tendency. The TDS is managed 

with precise blending of produced water with freshwater during a subsequent fracture 

treatment and the TSS is managed with a simple particle filtration system consisting of a 100-

micron filter followed by a 20-micron filter. Scaling and bacteria are managed through a very 

precise monitoring and testing program to ensure the compatibility of the produced water with 

the freshwater when blended for use during fracture stimulation. 

Chesapeake’s Marcellus Shale reuse program has been tremendously successful. In 

Chesapeake’s core operating area of the northern Marcellus in north-central Pennsylvania, 

Chesapeake is reusing nearly 100% of all produced water and drilling wastewater. This reuse 

can reduce the volume of freshwater needed to drill and hydraulically fracture subsequent 

Marcellus Shale wells by 10% to 30%. Resulting benefits include the need for less fresh water 

for hydraulic fracturing operations (which reduces the impact on local supplies) and also 

reduces truck traffic on public roads because less fresh water is hauled (resulting in less wear 

and tear on roads, reduced noise and air quality impacts). From an operational perspective, the 

reuse program is attractive because it helps reduce the cost of operations including wastewater 

disposal costs, water supply costs, and transportation costs. Note that only a fraction of the 

water utilized in the drilling and fracturing process is returned to the surface as produced water 

(Chesapeake Energy 2010b). Furthermore, Chesapeake has moved to a closed loop synthetic oil 

based mud system for drilling operations, which significantly reduces wastewater 

generated from the drilling process. 

Criticisms of Shale Gas Water Use: Removal of Water from the Effective Hydrologic 

Cycle 

One of the major criticisms to the use of water in the development of oil and natural gas 

supplies, particularly in the hydraulic fracturing of shale plays, is the so-called “permanent 

removal” of water from the surface and near sub-surface (effective) hydrologic cycle. While the 

focus of this abstract and presentation is on produced water management, it is important to 

address this criticism about the loss of water as it directly relates to salt water disposal well 

practices, produced water generation volumes, and shale water management in general. 

Regardless of the shale play, since the majority of produced water either remains in the 

formation or is disposed of in another suitable geologic formation (via Class II SWDs), this water 

is indeed removed from the effective hydrologic cycle. This may lead some to criticize and treat 

oil and natural gas water use differently than other major water users like power plants who 

consume water during the cooling process. The argument is the power plant type of 

consumption is evaporation and the volume of water evaporated is simply released to the 

atmosphere as water vapor and is still in the effective hydrologic cycle. These concerns about 
.08 

the permanent loss of water from the effective hydrologic cycle can easily be addressed with a 

simple explanation of natural gas combustion. When natural gas is combusted with oxygen (air) 

it forms two by-products, carbon dioxide and water vapor. The balanced combustion reaction is 

shown below: 

It is the generation of water vapor that ultimately offsets the removal of water from the 

effective hydrologic cycle. Based on some common assumptions about natural gas and natural 

gas combustion, approximately 10,675 gallons of water vapor are produced with the 

combustion of one MMCF of natural gas. (These calculations are shown in detail along with all 

assumptions in Appendix A.) This volume of water vapor generation was applied to determine 

approximately how much natural gas needs to be generated and combusted to offset the 

volume of water used in the development of a typical shale well in each major shale play. The 

results are calculated and shown in Table 4 including the average amount of time needed for a 

typical Chesapeake well to produce the volume of natural gas needed to offset the water used 

to develop (drill and fracture) the well. 

55

As shown above, a well in any of the four major shale plays produces enough natural gas in less 

than nine months, that when combusted, offsets the entire volume of water used in the 

development of that well with wells in the Barnett, Marcellus and Haynesville generally 

producing enough gas in less than six months of production. Please note that these wells are 

anticipated to produce natural gas for more than 20 years. (Chesapeake Energy 2010b) 

Major Conclusions 

1. The U.S. Onshore Oil and Natural Gas Industry is reducing the volume of freshwater 

utilized in operations, thereby reducing the need to compete with other traditional 

users of freshwater 

2. Feasibility of produced water reuse is dependent on three major factors: quantity, 

duration, and quality of produced water generated 

Table 4. Water vapor combustion and hydrologic cycle volume recovery by major shale play 
.08 

56

3. Produced water quantity, duration, and quality can all vary considerably between shale 

plays and can even vary geographically within the same play 

4. Environmental and economic benefits may directly correlate when evaluating reuse 

versus disposal options 

5. The volume of water “removed” from the effective hydrologic cycle during hydraulic 

fracturing OR produced water disposal via salt water disposal wells is more than offset 

during the combustion of the hydrocarbon fuels produced 

Appendix A: Water Vapor from the Combustion of Natural Gas Calculations 

Assumptions 

 Typical natural gas makeup assumptions: 

Methane (CH4) ~ 95% 

Ethane (C2H6) 

Propane (C3H8) 

n-Butane (C4H10) ~5% combined 

Carbon Dioxide (CO2) 

Nitrogen (N) 

Sulfur (S) 

 Due to variations in natural gas makeup (above), take conservative approach and only 

use 

 methane to calculate water vapor production, although ethane (C2H6), propane (C3H8) 

and nbutane

 (C4H10) when combusted will also produce water vapor. 

 Balanced Equation for Methane Combustion: CH4 + 2O2 → CO2 + 2H2O

 Assume normal temperature and pressure (68F and 1 atm) 

 Volume of 1 mole of CH4 at 68F is 0.0026 lb mole/ft3

 Molecular weight of water is 18 lb/lb mole 

 Liquid water density at 68F is 8.33 lbs/gallon 

Calculations 

Step One: Determine how much methane is in one million cubic feet (MMCF) of natural gas: 

1. 1,000,000 cu-ft of natural gas x 0.95 (methane component) = 950,000 cu-ft of CH4

Step Two: Determine the number of pound mol of CH4 using the assumption above for the 

volume of one mole of CH4. 

2. 950,000 cu-ft of CH4 x (0.0026 lb mol CH4 / ft3 of CH4) = 2,470 lb mol CH4

Step Three: Using the balanced equation above, determine how many pounds of mols of water 

vapor are produced in the combustion process. 

3. 2,470 lb mol CH4 x (2 lb mol H2O / 1 lb mol CH4) = 4,940 lb mol H2O 
.08 

57

Step Four: Using the molecular weight of water, determine how many pounds of water vapor 

areproduced in the combustion process. 

4. 4,940 lb mol H2O x (18 lb H2O/1 lb mol H2O) = 88,920 lb H2O 

Step Five: Using the liquid water density, determine the volume of water vapor produced. 

5. 88,920 lb H2O x (1 gal H2O/8.33 lb H2O) = 10,675 gals H2O (as vapor) per MMCF

Note: Not all natural gas that is consumed is combusted. According to a 1995 DOE Topical 

Report on “Economic Evaluation and Market Analysis for Natural Gas Utilization,” 

approximately 3.5% (relatively negligible) of natural gas is used as feedstock for ammonia, 

methanol, ethylene and hydrogen production. 

References 

Chesapeake Energy. 2010b. Operational Data. 

Chesapeake Energy. 2010c. Investor Presentation. 

http://www.chk.com/Investors/Pages/Presentation.aspx

Chesapeake Energy. 2010d. Operational Experience. 

USDOE, 1995. U.S. Department of Energy: Economic Evaluation and Market Analysis for Natural 

Gas Utilization – Topical Report – 1995. 

http://www.osti.gov/bridge/purl.cover.jsp?purl=/211345-iEUh0M/webviewable/
58

A Water Chemistry Perspective on Flowback Reuse with Several 

Case Studies 

Keith Minnich, P.Eng., PE 

Talisman Energy USA Inc. 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Summary 

Operators have tested the feasibility of using frac flowback water that has received only a 

minimum level of treatment. Successful fracture operations have been reported using frac 

solutions with total dissolved solids (TDS) in excess of 50,000 mg/l. 

Any discussion on reuse must emphasize the differences between the North American 

(Western Canada, Eastern Canada, Eastern USA, and Southern USA) shale gas formations and 

differences between locations in the same formation make reuse decisions and logistics site 

specific. Operations must be conducted in compliance with applicable local laws and 

regulations. 

This abstract discusses the reuse of frac flowback from a water chemistry perspective. Two 

examples of flowback reuse, where a minimal water treatment has been used, describe the 

rationale for why the practice is considered acceptable. Associated logistics considerations are 

also presented. 

Introduction 

Hydraulic fracturing is essential to the production of natural gas from tight shale. Fracture fluids 

are predominantly a water and sand mixture with a small percentage of other chemicals with 

specific functions. Fracturing requires high pressure. Friction reducers are used to decrease the 

frictional force in the pumped water allowing the pumping pressure to reach the formation. A 

mild acid prepares the stimulated area to accept the fracture treatment, biocide kills any 

bacteria collected in the water prior to pumping, scale inhibitors prevent mineral buildup from 

the water produced from the well, and corrosion inhibitors are added to protect equipment. 

Breakers to reduce the viscosity of friction reducers, clay stabilizers, and surfactants might also 

be used. 

Approximately 10% to 50% of the water used for hydraulic fracturing may be returned quickly 

to the surface as frac flowback. Reuse of frac flowback has multiple benefits: 







Reduces demand for fresh water 

Reduces water disposed 

Reduces truck hauling to offsite disposal 
59

Frac Flowback Reuse by Creating Near Fresh Water Quality 

Until recently it was believed that near fresh quality water, or water with most metals and 

hardness removed, was required for use in fracturing fluid. Historically, most shale gas fracture 

flowback was disposed of by deep well injection. Deep injection wells are not always available 

and offsite disposal costs can be quite large relative to other water related costs. 

Various technologies have been proposed to achieve near fresh quality standards by removing 

suspended solids, heavy metals, hardness, organics, and dissolved solids. In some cases, a 

relaxed requirement of specifying only the removal of heavy metals and hardness was 

considered acceptable. 

These technologies are usually expensive, add operational complexity, increase environmental 

and safety risks, and generate by-products which require disposal in compliance with applicable 

laws and regulations. 

 

There are clear advantages to reuse of frac flowback which requires only a minimum amount of 

treatment for removing suspended or dissolved solids. Several operators, including Talisman 

Energy, are routinely using frac flowback which has had a minimum amount of treatment. 

Talisman Energy USA Goals for Flowback Reuse 

Data collected from recent drilling in the Marcellus shale formations by Talisman Energy 

indicates initial flowback ranging between 10% and 25% of the injected volume. The initial 

flowback has lower dissolved solids than later flowback. The maximum concentration of Total 

Dissolved Solids (TDS) in the blended flowback is less than 200,000 mg/l. To consistently reuse 

virtually all of the flowback by blending with fresh water, frac fluids need to function effectively 

with a maximum TDS of 50,000 mg/l. 

Water Chemistry Perspective on the Water Quality Requirements for Frac Flowback 

Reuse 

The typical constituents in shale gas frac flowback water have been identified through various 

sampling programs. While the relative proportions of these constituents vary depending on the 

formation, there are some consistencies in the types of constituents present. Typically, the 

range of Total Dissolved Solids (TDS) is between 25,000 mg/l to 250,000 mg/l. The constituents 

which might impact the performance of the chemical additives to a frac fluid or impact the 

formation include:













Suspended Solids – fine clay (could also include biosolids)

Organics – both added and naturally occurring

Scaling ions – barium, strontium, calcium, and magnesium along with alkalinity and 

sulfates

Chlorides and oxygen – accelerate corrosion

Residual friction reducers – interfere with constituents in the frac fluid

Microbes – souring of the formation and microbiologically enhanced corrosion
60

The recommended functional performance considerations for reuse are: 















Friction reducer effectiveness

Scale formation

Microbiology control

Corrosion

Breaker

Clay stabilization

Long term impact on formation

Friction reducers with salinity tolerance of 90,000 mg/l or more have been advertised by 

several companies. Friction loop tests were performed for Talisman Energy and the 

acceptability of using a blend of flowback and fresh water with a TDS of 50,000 mg/l was 

demonstrated. Talisman’s service providers were confident that the other functions could also 

be addressed. The two functional performance considerations which generated the most 

discussion were suspended solids and scale control. 

Two case studies -- one for suspended solids and one for scale control -- are discussed below. 

Water Chemistry Perspective; Case Study 1 - Suspended Solids 

The recommendation for water used to prepare frac fluids is that it should be substantially free 

of suspended solids. There are various specifications to define what total amount of suspended 

solids and what particle size range meet the expectation of substantially free. 

Talisman Energy conducted filtration of flowback tests for removing suspended solids but 

commonly experienced filter plugging. Thus the requirement to filter the flowback created an 

obstacle to reuse. 

All of Talisman Energy’s fracture operations include flowback storage. Application of Stoke’s law 

to the various storage configurations suggested that under ideal conditions all particles greater 

than 30 micron in diameter would be removed from the frac flowback. 

Samples were collected from several frac operations to determine the effectiveness of unaided 

gravity settling in flowback tanks whose primary purpose is surge control and storage. 

 Slide 7 shows the sampling arrangement and the location of the filter recommended by 

water treatment companies. 





An investigation was made to compare a Stoke’s law prediction to actual removal. The 

prediction indicated that under ideal conditions solids > 30 microns would be removed. 

It was understood that particle size and inlet/outlet configuration of the tanks were not 

ideal. 

Slides 8 and 9 show the particle size distribution of suspended solids before and after 

flowback holding tanks. The inlet and outlet of the surge and holding tanks were 

arranged to facilitate site set-up, not suspended solids removal, and the configuration 

was not ideal for settling. As a result, suspended solids removal was less than predicted. 

Side 10 summarizes the solids distribution before and after the holding tanks. 
61









Slide 11 show that most of the sand and clays are removed by settling, leaving primarily 

barite. 

Slide 12 shows the configuration of tanks to achieve performance which is closer to 

what is predicted by Stoke’s law.

The reuse of flowback with 50 mg/l or less of suspended solids, with a particle size range 

of greater than 30 microns and less than 100 microns, has not had a noticeable effect on 

well performance. No long term studies have been made. 

Talisman Energy has not observed interference from biomass. 

Settled solids are periodically removed from the tanks by vacuum trucks and disposed in 

licensed landfills in compliance with applicable laws and regulations. 

Water Chemistry Perspective Case; Study 2 – Scale Control 

The scaling potential of barium, calcium, and iron with sulfate and carbonate ions has been 

discussed at length in the literature and there are both ongoing and new studies. There are 

many public and proprietary computer programs available to calculate scaling potential. 

For the purpose of this case study a flowback chemistry for Northeast Central Pennsylvania 

chemistry is presented in Slide 14. 

Slide 15 highlights that the chemistry is a high ionic strength, chloride based system with very 

high concentrations of the scale forming cations and very low concentrations of sulfate and 

carbonate. 

When the ions are matched with each other the extent to which the salts are chloride based 

becomes more clear (refer to Slide 16). 

Slide 17 shows the extent to which ionic strength has an impact on the total and relative 

solubility of salts. 

It was recommended to Talisman Energy that metals and hardness be removed from the 

flowback before reuse. The open literature has examples of similar recommendations. Due to 

the high concentration of barium, strontium, calcium, and magnesium large amounts of sodium 

sulfate, soda ash, and lime are required. 

In many cases the source of sulfate and carbonate alkalinity is the fresh make-up water. Since 

the high concentration of scaling cations are in the formation, it is best to remove the sulfate 

and carbonate alkalinity from the frac fluid before injection. 

An alternative is to settle out the gross suspended solids, as described in Case 1 and then take 

advantage of the remaining barium sulfate “seeds” to quickly de-supersaturate sulfate. The 

chemistry of this approach is well established (refer to Slide 20). There are also literature 

references to co-precipitation of other scaling salts on seed crystals. 
62

Talisman has reused flowback with only settling and no chemical addition for metals and 

hardness reduction for blend TDS of approximately 50,000 mg/l with no apparent negative 

impact on the formation or gas production. 

Several hypotheses have been put forth for why blending of flowback and fresh water might be 

effective at reduced scaling potential of the blend: 







Iron is likely oxidized and precipitated as Fe(OH)3 in surface tanks

Reduction in ionic strength reduces BaSO4 solubility by 50%. SO4 from surface water 

reacts with excess Ba and likely precipitates on seeds

Some CaCO3 and SrCO3 precipitation will occur. However, at this time scale control is 

indicated because of inverse solubility with respect to temperature and lack of definite 

information on co-precipitation

There are questions about the impact of flowback reuse on the formation: 









The presence of barite “seeds” should reduce down hole and formation scaling due to 

preferential precipitation on the seeds

Caution is recommended for formations with soluble sulfate. However, barite “seeds” 

might be useful in such situations

In principle, fewer salts should be solubilized from the formation with higher TDS frac 

fluid

The impact of increased frac fluid density has not been investigated

Logistics Considerations for Frac Flowback Reuse 

There are differences between the North American (Western Canada, Eastern Canada, Eastern 

USA, and Southern USA) shale gas formations and differences between locations in the same 

formation. Reuse decisions and logistics will be site specific. Operations must be conducted in 

compliance with applicable local laws and regulations. 

The logistics of transporting and handling flowback to minimize environmental and public 

health risks must take the following into consideration: 











Number of wells per pad - flowback reuse on multi-well (refer to Slide 24) pads reduces 

movement of flowback off the pad

Timing - storage required to deal with when flowback is available and when it is 

required

Variations in the amount of flowback – flowback ranges from 10% to 50% of the injected 

frac fluid, which impacts the choice and style of storage (refer to Slides 25 and 26)

Location of fresh makeup

Contiguousness of leases

In general, reusing flowback on site with Multi-Well pads will reduce the amount of fresh water 

required at the pads and significantly reduce the movement of flowback from the pad.
63

Shale Frac Sequential Flowback Analysis and Reuse Implications 

Matt Blauch 

Superior Well Services, a Nabors Company 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Water re-use challenges and solutions have direct and indirect influences in the design of 

hydraulic fracturing fluid systems and products used in High Volume, High Rate (HVHR) 

hydraulic fracturing of shale wells (1,2). In general, effectively engineered water reuse solutions 

should: provide effective fracture development, allow practical application and economic 

performance, be non-damaging to well production, extend microbiological control, minimize 

environmental impact and reduce environmental risk. 

 

Until relatively recently, HVHR fracturing required the use of fresh water as the base fluid due 

to the sensitivity of polymeric friction reducers to high TDS waters and concerns that the 

interaction of the frac fluid constituents with the formation would result in adverse 

precipitation of geochemical mineral species often referred to as “scale”(3). 

Significant lessons learned from early HVHR fracturing and flowback analysis from the Marcellus 

shale has led to the development of products that have a higher degree of compatibility with 

the inorganic constituents in flowback waters as well as better understanding of the impacts of 

recycled flowback water on well performance (1). In general, much higher salinity fluids are 

now used than during initial development. However, much still remains to be learned from 

geospatial variations both within the Marcellus and other shale plays (2). 

Exploration into the geochemical variations and implications of high TDS flowback fluids for 

recycling and re-use in closed system fracturing applications is provided through ongoing 

flowback water analysis. To date, over 500 flowback samples obtained following HVHR 

fracturing operations have been catalogued. Sequential flowback studies involve time and 

volume dependent analysis of the flowback samples. The study presented includes results 

obtained from 25 sequential flowback studies representing discrete well site locations 

throughout the Marcellus shale play. 

In this case study, flowback analysis locations trend from the northeast to the southwest. A 

number of significant trends are observed. 

TDS and Chloride Content 

There is an exceptionally good correlation between chlorides and total dissolved solids (TDS) 

(i.e., R

2

 = 0.995). This would be expected since chlorides are the predominant anion in flowback 

waters. TDS levels range from approximately 200 mg/L to nearly 145,000 mg/L and 

concentration increases with time and flowback volume. Regional distribution of the TDS levels 
64

appear to vary significantly. Well sites representing a cross section of Marcellus region were 

from the following counties; 1) Susquehanna; 2) Jefferson; 3) Armstrong and 4) Fayette. The 

highest salinity (TDS) content appears in the Jefferson data with TDS approaching 145,000 

mg/L. The lowest TDS levels were observed in Armstrong County with values reaching 

approximately 30,000 mg/L. 

Hardness vs. Marcellus Flowback Volume by Region

Total hardness, represented as CaCO3 shows a similar trend to the TDS on a distribution basis 

for each of the four regions. The significance of total hardness relates to both compatibility of 

the fracturing fluid chemical package and the geochemical propensity to precipitate potential 

production impairing minerals(3). The highest level of total hardness is represented in the 

Jefferson data set with values exceeding 30,000 mg/L in the late stage flowback. 

Barium Content vs. Marcellus Flowback Volume by Region 

Barium content is of particular interest during reuse due to the susceptibility of barium to form 

barium scales such as barium sulfate. Barium trends in the sequential flowback data show three 

primary geospatial signatures. In the Fayette and Armstrong signatures, very little barium is 

observed. In the Jefferson trend, barium levels are relatively low (approximately 50 to 400 

mg/L) up to approximately 7,000 bbls recovered after which the levels rise to approximately 

1,700 mg/L. The Susquehanna trend curve shows a relatively constant linear trend showing 

higher early uptake. 

Geospatial Variation of Flowback Geochemistry 

Correlation of water geochemistry to physical location (both latitude and longitude) provides 

insight into the potential to predict key water chemistry values for geochemical simulation 

purposes. One example is illustrated in the calcium trend versus longitude and latitude. With 

the exception of one anomalous point, when compared on a fixed volume basis, it appears that 

calcium content increases from west to east. However, there appears to be some very high 

brine content wells in the mid-state region. Such information can be utilized as a predictive tool 

in planning development of future well sites, with improved water management strategies, 

better scale prediction and more convergent reuse strategy. 

Post-Frac Water Load Recovery 

Load recovery following fracturing operations is a key aspect of any water reuse program since 

the load recovery volumes may vary across operating locations and the amount of water that 

can be recycled is dependent upon the final water chemistry. In many cases, significant dilution 

of flowback water with fresh water is applied to new completions. However, reuse consisting of 

100% flowback water with no fresh water dilution is possible when augmented with treatment4 

to remove all or a portion of the detrimental constituents. The load recovery from selected well 

sites indicates a range from less than 10% to nearly 60%. The dataset includes both vertical and 

horizontal wells. Geospatial variation shows weak, but positive correlation to latitude and 

longitude with the higher load recovery percentages occurring in the southern operating 

regions. 
65

Geochemistry and Source of Salts

Interaction between shale and fracturing fluids has been the subject of a number of studies (1,

3, 5, 6). Providing both a predictive method and preventative measure to controlling 

geochemical precipitates, scale, microbially induced deposits and other rock/fluid interactions 

is important for enabling sustained reuse of flowback waters and for optimization of production 

performance. A geochemical simulation method has been developed to help predict potential 

mineral species that have a tendency to form insitu based on inputs from flowback water 

analyses3. Based on a study conducted to address the question of the origin of salts observed in 

the Marcellus shale flowbacks, the authors present hypotheses regarding the origin of dissolved 

salts observed in the flowback waters (1). Geologic interpretation of the genesis of shale basins 

such as the Marcellus provides insights into the origin of the salts. Potential mechanisms for the 

observed salinity in the flowbacks include: 

1. Primary dissolution of Autochthonous salt 

2. Primary dissolution of Allochthonous salt 

3. Encroachment of Basinal brines 

4. Mobilization of Hypersaline connate fluids 

5. A combination of the above

Experiments using drilled cuttings and cores show some evidence for the Autochthonous origin. 

In summary, it cannot be assumed that observed flowback geochemistry is simply due to 

“fracturing” into brine water within subjacent wet formations, as previously assumed. Piper 

analysis appears to be a potentially useful tool for characterizing the water “genetics” and 

determining pathways for mixing with various compositions of water types. Additional work is 

suggested in this area including “water fingerprinting”.

Comparison of Marcellus flowback geochemical results with limited studies from other shale 

plays such as the Haynesville appears to show similar trends regarding soluble salts. In one 

study, Haynesville flowback waters show higher levels of TDS than observed in the Marcellus 

study with values exceeding 120,000 mg/L after 7,500 bbls flowback volume. These flowback 

waters also show higher initial salt uptake. 

Reuse Implications

Water reuse has been enabled and is now a reality for HVHR shale fracturing operations in a 

wide range of geologic settings. Insights obtained from analysis of flowback waters provide a 

basis for chemical additive package design, treatment options, geochemical implication and 

environmental risk assessment. Inherent variations in downhole geochemistry and the 

equilibration of injected frac water with the subsurface rock environment provide a technical 

need for continued analysis of flowback waters. Analysis and interpretation of the geospatial 

variation of inorganic dissolved species can provide a basis for future prediction of geochemical 

composition anticipated in new development areas. Such prediction could enable better 

planning, development of water management strategies and hydraulic fracturing fluid design. 
66

References

1. Blauch, et. Al., 2009. Marcellus Shale Post-frac Flowback Waters – Where is All the Salt 

Coming from and What are the Implications?. Presented at the SPE Eastern Regional 

Meeting held in Charleston, West Virginia, USA, 23-25 September, 2009. 

2. Houston, et. Al., “Fracture-stimulation in the Marcellus Shale: Lessons learned in fluid 

selection and execution,” SPE 125987 presented at the SPE Eastern Regional Meeting, 

Charleston, W.V., Sept. 23-25, 2009. 

3. Blauch, 2010. Geochemical fixes boost shale completion efficiency. World Oil, July 2010, 

pp. D121-D124. 

4. Papso, J., et. Al., 2010. Gas Well Treated with 100% reused Frac Fluid. August 2010, 

Harts E&P. 

5. Lash, Gary G. 2009. Overview of the Tectonic and Eustatic Framework of Yager, Kappel, 

and Plummer. Devonian Black Shale, Appalachian Basin. Presented at the SPE 

Cooperstown Applied Technology Workshop, Cooperstown, New York. 

6. Dresel, P.E. 1985. The Geochemistry of Oilfield Brines From Western Pennsylvania. MS 

Thesis, The Pennsylvania State University Department of Geochemistry and Mineralogy. 
67

Characterization of Marcellus Shale and Barnett Shale Flowback 

Waters and Technology Development for Water Reuse 

Tom Hayes 

Gas Technology Institute 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

The Barnett and Appalachian Shales are among the largest and most active natural gas plays in 

the U.S. that geographically covers all or part of 20 counties in North Texas and large areas of 

Pennsylvania and West Virginia. The Barnett area is proven to have approximately 2.5 trillion 

cubic feet (59 km3) of natural gas reserves and is widely estimated to contain up to 27 trillion 

cubic feet (700 km3) of technically recoverable natural gas (USGS, 2004; Clouser, 2006). The 

Marcellus Play of the Appalachian Shale Region is considered to be larger in size and capacity in 

comparison to the Barnett. Both shale plays are considered to be unconventional gas 

formations; each of these plays depend upon the economical utilization and environmentallyresponsible management of large volumes of water for continued sustainable development. 

Hydraulic fracturing (fracing) is a necessary step for initiating economical well performance, 

requiring between 1 and 4 million gallons of water for successful well completion. Vertical wells 

require approximately 1 million gallons and horizontal wells require 3-4 million gallons 

according to Barnett Shale Producers. These per-well levels of water production also apply to 

the wells installed and completed in the Marcellus Shale. In both plays, horizontal wells 

comprise more than 90% of the total wells that are constructed. Of the total water used by the 

industry, completions using hydraulic fracturing represent more than 94% and drilling 

represents 5% as see in Slide 6 (Galusky, 2007). During years when more than 2,000 wells are 

constructed in a shale gas play, approximately 2 billion gallons will be used for new 

completions. This level of water demand poses a number of challenges for industry in the 

course of developing the Barnett and Appalachian Shales for natural gas production. In 

recognition of this need, the natural gas industry has supported efforts to characterize flowback 

water and evaluate water reuse approaches that significantly reduce freshwater demand while 

providing environmentally acceptable options for flowback water management. 

Flowback Water Characteristics 

Effective management of flowback water requires some level of knowledge of the 

characteristics of the water; a breakdown of categories of constituents found in many flowback 

and produced waters is depicted in Slide 8. Flowback water contains salts, metals and organic 

compounds from the formation as well as many of the compounds that were introduced as 

additives to the influent stream. Discussions between the industry and regulatory agencies of 

Pennsylvania and West Virginia have pointed to the need for an information base on the 

composition and properties of flowback water and on the influent water streams that are used 
68

to perform frac jobs. The objective of this effort was to conduct the initial sampling and analysis 

of water streams associated with shale gas development in the Marcellus Shale. 

In recognition of the importance of this effort, 17 member companies of the Marcellus Shale 

Coalition (MSC) volunteered 19 locations where shale gas wells were scheduled to be 

hydraulically fractured. The Field Sampling and Analysis Plan and the Quality Assurance Project 

Plan were developed, reviewed, and finalized for the effort by the companies of the 

Appalachian Shale Water Conservation and Management Committee (ASWCMC), PA-DEP and 

WV-DEP. At each of the host sites, samples of influent water streams at Day 0 and the flowback 

water streams at 1, 5, 14, and 90 days following the frac job event were collected by a single 

engineering subcontractor, URS. All samples were sent to Test America (a PA-DEP certified 

environmental testing laboratory) for analysis. The list of constituents recommended for the 

characterization study was developed from comments received from the PADEP, the WVDEP

and members of the Appalachian Shale Water Conservation and Management Committee 

(ASWCMC). Categories of determinations that were conducted included: 1) General Chemistry, 

2) Organic Compounds, and, 3) Metals. Once reviewed and qualified, data from these analyses 

were organized and tabulated in a source blind manner into an Excel spreadsheet that currently 

represents the information base. 

Results from this effort indicate that values for pH, alkalinity, total dissolved solids, total organic 

carbon, oils and greases and other parameters from general water characterization are within 

the normal ranges reported for conventional produced waters by the USGS. General 

characteristics of Marcellus Shale waters (influent and 5-day flowback) are shown in Slide 13. 

Comparisons of characteristics of 14-day flowback waters with conventional produced waters 

are shown in Slide 14. Flowback water concentrations of total dissolved solids ranged from 

3,000 to 260,000 mg/l; typical profiles show an increase in total dissolved solids in flowback 

water with time following a frac job event (as shown in Slides 16-18). Anions and cations of 

influent and 5-day flowback water are shown in Slide 15; as with conventional produced water, 

shale gas flowback water cations are dominated by sodium and calcium; the main anion is 

chloride. 

Metals normally seen in conventional produced waters, such as iron, calcium, magnesium, and 

boron, are at levels in flowback waters that are well within known ranges for normal produced 

waters. Heavy metals that are of concern in urban industrial wastewaters and POTW sludges --- 

such as chromium, copper, nickel, zinc, cadmium, lead, arsenic and mercury --- are at very low 

levels in flowback and produced waters (as shown in Slide 34). 

Among volatile organic constituents, more than 93% of all constituent determinations were at 

non-detectable levels and less than 1% of the determinations (mainly volatile constituents that 

are a natural part of formation waters) were above 1 ppm (as shown in Slide 23). Virtually all 

man-made halogenated solvents were at non-detect levels; volatile constituents that are 

measureable, are those that are normally found in conventional produced waters. 

Regarding semivolatile organic constituents, more than 96% of all determinations were at 

nondetectable levels and less than 0.1% of all constituents were above 1 ppm; the remainder of 
69

constituents were at low trace levels – usually below 10 ppb (as seen in Slide 27). All 

chlorinated pesticides, organophosphorus pesticides and polychlorinated biphenyls in all 

samples were determined to be at non-detect levels. The results of this shale gas water 

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

semivolatile constituents should be considered to be unnecessary for the sampling and analysis 

of flowback waters in the future. 

Recently, characterization of shale gas waters has been completed for five locations in the 

Barnett using the same procedures employed in the Marcellus Shale Project; general 

characteristics of the 5-day flowback waters are compared between the two plays. For the 

limited number of sites sampled, the Barnett Shale waters appear to be significantly lower in 

total dissolved solids -- about half of the TDS levels of the Marcellus Shale waters that range 

from 38,000 to 238,000 mg/l TDS. Alkalinities of the Barnett waters at 238 to 1630 mg/l (as 

CaCO3) are relatively higher than the Marcellus waters -- perhaps four times higher -- due to the 

greater presence of bicarbonate concentrations in the Barnett waters. Marcellus shale water, 

however, showed significantly higher levels of TOC than Barnett waters though most samples 

from both plays had TOC levels below 70 mg/l (modest TOC levels). 

Water Reuse Technology Evaluations and Development 

Information on water flows in the shale gas industry indicate that although each well 

completion represents a potential significant flowback water output equivalent to 5-35% of the 

influent water, it is also true that future hydraulic fractures represent substantial opportunities 

for the reuse of these waters, especially during the growth phase of each shale gas 

development area. The median flowback water volume collected from 19 locations in the 

Marcellus Shale was approximately 24 percent of the influent water volumes used for each 

completion operation. 

Predominantly, the industry prefers to dispose of flowback and produced waters using Class II

deep well injection if such disposal capacity is locally available and economically accessible. In 

areas of the U.S. where Class II wells are sparse (the Marcellus Shale has only 7 Class II wells 

which represents a very low capacity to accept produced waters and flowback), water reuse has 

been a logical alternative to pursue as is done in the Pennsylvania portion of the Marcellus 

Shale. In areas of the U.S. where severe limitations of water availability can arise from frequent 

occurrences of drought, shale gas developers have considered water reuse as a means of 

significantly reducing demands on sources of fresh water that compete with community water 

supplies. 

Where flowback and produced water reuse are being pursued aggressively, there are mainly 

two schools of thought that exist in the shale gas industry. Approach A is comprised of 

conditioning the brines for the removal of suspended solids, oils and greases, bacteria, and 

scale forming ions (i.e. constituents that potentially interfere with equipment and infrastructure 

maintenance) with no demineralization (desalination) prior to reuse. Currently, this approach is 

being used within the Marcellus Shale as the predominant shale gas water management 

practice. A more rigorous treatment (“Approach B”) is comprised of treating shale gas water all 
70

the way to the recovery of distilled or demineralized water with the concomitant generation of 

a small volume of concentrated brine; this rigorous treatment approach is usually capable of 

recovering demineralized water equivalent to 70-80% of the original flowback/produced water 

stream. A general flowsheet that encompasses water reuse options available to the industry 

are shown in Slides 40-42. 

Since 2005, the shale gas developers have evaluated a number of processes capable of 

demineralization and brine volume reductions. The most capable demineralization approach 

that has been demonstrated in the treatment of shale gas waters -- in terms of reliability and 

performance -- is the mechanical vapor recompression thermal distillation (MVR) process. This 

process is capable of handling a very wide range of brines (from less than 10,000 mg/l to more 

than 120,000 mg/l TDS) while achieving over 70 percent efficiencies in water recovery. This 

process is commercially applied to shale gas water stream management in the Barnett and in 

some shale gas fields of the Western U.S. Another demineralization process that has been 

tested on shale gas waters in the field is reverse osmosis (RO), though to a much lesser extent 

than the MVR process. Tests with RO on shale gas waters have verified the ability of the process 

to recover about 60% of highly demineralized water as long as the influent water did not 

exceed 40,000 mg/l of TDS. Photos of MVR and RO field demonstration units (located in the 

Barnett Shale) are shown in Slides 43 and 44. Demineralization with either process comes with 

a significant cost that must be evaluated and understood to achieve effective deployment. In 

the shale gas industry, demonstrations involving both processes are continuing. 
71

Mid-Continent Water Management for Stimulation Operations 

The Case for Recycling Frac Water 

D. Steven Tipton, P.E. 

Newfield Exploration Mid-Continent, Inc. 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Introduction 

Water use and management is critical to the petroleum industry. It is the most common and 

heavily used fluid in our business. In every jurisdiction in this country its use is regulated in 

some manner. The regulations and ownership of water is different in each area in which the 

industry works. In many areas of the country the use and handling of water have become 

emotionally charged. For this presentation, I will be concentrating on the water use and 

reclamation for the stimulation of the Granite Wash tight gas reservoirs in the Anadarko Basin 

and the shale gas reservoirs of the Woodford Shale in the Arkoma Basin. Both areas have 

evolved as the drilling activity increased and changed. In each area an infrastructure has been 

created to support Newfield’s completion operations and the need for water. 

The Life of a Barrel of Frac Water 

Source Ground water for the Granite Wash

Surface ponds built to store run off from rain for the Woodford Shale

Storage Fresh water is stored in ponds or large pits

 Recycled water is stored in lined pits or frac tanks

Transfer to well for stimulation Fresh water is pumped through aluminum 

irrigation or poly pipe to the well site

Recycled water is either trucked to the well site or 

pumped through poly pipe

Water is transferred from the storage facilities to 

the well being completed at up to 100 BPM

Fracturing operation Halliburton, Schlumberger, BJ or other companies mix the 

water with proppant and other chemicals and pump it into 

the well

Flow back water The flow back water is separated from any hydrocarbons at 

the well’s test or production facilities and then pumped to a 

recycle pit for reuse or trucked to a processing facility for 
72

clean up and reuse. The water that is not reused will be 

taken to a disposal well. 

NFX Granite Wash Operations 

Newfield’s Britt Ranch and Briscoe fields were originally drilled for deep Morrow gas which is a 

conventional reservoir. Since 2001, Newfield has drilled over 150 vertical Granite Wash tight 

gas wells. Initially, frac pits were built at each well site. It soon became apparent that having 

central water supply pits was more economical and as the amount of water being used 

increased it made sense to begin recycling it. When Newfield started drilling and completing 

horizontal wells in this area the water usage went from approximately 80,000 barrels per 

completion for vertical wells to over 250,000 barrels per completion for horizontal wells. 

Fresh water is generally transported from the pits to the well being completed through 10” 

aluminum irrigation pipe. The recycled water is transported through 8” HDPE (high density 

polyethylene) pipe. Newfield owns 38 miles of 8” poly and 10 miles of 4” poly to move water 

from pit to pit and from the pits to the wells being stimulated. Generally three or four lines are 

used to deliver water from the frac pits to the well being completed. Once the completion is 

finished and the well is being flowed back one poly line is left in place to pump the water back 

to the pit. The company also owns 6 water transfer pumps to move water from the flow back or 

production tanks to the recycle pits. 

The water being produced into the recycle pits contains approximately the same TDS as the 

water used during the completion operation (15,000 to 17,000 mg/l) and is relatively clean. Any 

solids produced with the water drop out in the flow back pits. By reusing the water Newfield 

saves over $8 million per year in reduced requirement for potassium chloride and another $1 

million a year in purchasing additional fresh water. The hydrocarbons not caught in the 

production equipment (less than 500 mg/l) are skimmed from the pits as is necessary and 

recycled through our disposal facilities. 

Currently Newfield recycles approximately 80% of the water it uses. The company would 

recycle more however not all of the wells produce back their entire load. In addition, the pits 

are permitted only for fresh or flow back water so once the entire load is recovered the 

produced water must be trucked to a SWD well. In the Britt Ranch area, the company has seven 

recycle pits with a total capacity of 2.4 million barrels and ten fresh water pits with a total 

capacity of 1.3 million barrels. In the Briscoe area there are two recycle pits with a total 

capacity of 900,000 barrels. Due to the soil conditions and to protect the environment all of the 

pits are lined with geomembrane liners. 

Each of the recycle pits is permitted by the Texas Railroad Commission. They are inspected 

before they are used and then drained at least once a year and re-inspected. Some of the pits 

have been in use for more than five years without a leak or failure. 
73

As stated above Newfield has a long history of drilling vertical wells in the Granite Wash. Since 

the Granite Wash has multiple pay zones the focus had been on drilling vertical wells and 

completing all of the zones using multiple frac stages. Using this approach the best vertical well 

in the area had an initial production rate of 9.2 MMCFD and 48 BOPD with over a 90% initial 

decline rate when completing eight of the zones. An average vertical well initially produced at a 

rate of approximately 5 MMCFD with multiple zones completed. After much work, a horizontal 

well was drilled and completed in the upper member of the Granite Wash during the fall of 

2008. That well initially produced at a rate of 25 MMCFD and 1500 BOPD and produced 2 BCF

and 100,000 BO in its first four months. Since that time eleven individual zones have been 

tested in the Granite Wash with horizontal completions with the average initial production of 

17 MMCFD with much lower decline rates than the vertical wells. As can be seen with these 

numbers, horizontal wells have substantially improved both the initial productivity and reserves 

from the Granite Wash. 

With the horizontal wells has come the demand for much more water. The average vertical well 

was completed using 80,000 to 100,000 barrels of water. The average horizontal well is using 

250,000 barrels of water or 25,000 barrels per frac stage. Experiments have been conducted 

using different perforating schemes, water volumes (from 5,000 barrels to up to 55,000 barrels 

per stage) and pumping rates (from 60 to over 100 barrels per minute). Since some of the zones 

are up to 600 feet thick attempts have been made to see if the zones could be drilled with just 

one lateral and get sufficient height from the frac to recover the reserves efficiently. Based on 

the frac mapping, we have not been able to achieve the frac height desired. (As an aside, these 

attempts to intentionally increase the frac height have proven to us that in most cases getting 

more than 250 feet of height growth is very difficult. So it the probability of fracturing into a 

USDW zone more than 10,000 feet above the reservoirs we are stimulating is very low.) 

Due to the large amount of water required to complete some of the wells, the pits have been 

“daisy chained” together using poly pipe so that water can be moved from pit to pit. Using this 

approach two wells were recently completed on the same pad using over 800,000 barrels of 

water with the fracs being pumped at over 100 barrels per minute and water moved up to nine 

miles. 

The approach Newfield has taken in its Granite Wash water management is being used as the 

model for new projects in Western Oklahoma, the Eagle Ford in South Texas, the Wasatch in 

Eastern Utah and the Marcellus. It is also being copied by other operators in the area. 

NFX Woodford Shale Operations 

Newfield’s Woodford Shale operations are conducted over a 900 square mile area in the 

Arkoma Basin. The Woodford Shale was initially developed with vertical wells with the best 

initial production being 1,600 MCFD and the average well’s initial production ranged from 300 

to 400 MCFD. Newfield began drilling and completing horizontal Woodford wells during the 

spring of 2005. During the last six years the lateral lengths have increased from 2500 feet to 

over 10,000 feet with corresponding increases in initial production rates. The average initial 

producing rate for Newfield’s Woodford wells is 7.0 MMCFD.
74

Fracturing volumes on the vertical wells was generally small (less than 10,000 bbl) and could be 

done from frac tanks or a small fresh water pond. To achieve higher producing rates from the 

Woodford wells, much larger fracture stimulations with volumes increasing up to 300,000 

barrels per well were required. Some of Newfield’s four well pads have used up 1.2 million 

barrels of water during the completion operations. 

As the horizontal play developed Newfield build over 60 fresh water ponds to collect run off 

from rain water. The ponds ranged in size from 50,000 to over 750,000 bbls with a total 

capacity of over 8 million barrels. Fresh water is transferred from the pond to the well sites 

through 10” aluminum irrigation pipe. In cases where there is not enough fresh water in one 

pond they may be connected together using irrigation pipe and the water moved from pond to 

pond. Fresh water has been moved up to 2.5 miles during the frac operations. Recycled high 

chloride water is trucked from our Ecosphere water treatment facility to the well site where it is 

stored in frac tanks. Fresh water is then mixed with the recycled water through the frac blender 

to make an equivalent of 1 percent chloride water. 

Ecosphere is a technology Newfield uses to clean up its recycled high chloride water for use as a 

potassium chloride substitute. The technology is provided by Ecosphere Energy Services LLC 

which uses ozone to oxidize hydrocarbons, residual chemicals and heavy metals. This process 

also kills any bacteria in the water, reduces the surface tension of the water and reduces sulfate 

and carbonate scaling tendencies. Their process also uses hydrodynamic cavitation, electro 

chemistry, acoustic cavitation and various types of filtration. Should it be desired to reduce the 

salinity the unit is equipped with reverse osmosis units. Newfield saves over $13 million per 

year in reduced chemical usage by using Ecosphere to clean up its recycled water. 

Once the completion is finished and the well is flowing back, the produced water is trucked to a 

salt water disposal facility. The Ecosphere equipment is located at one of Newfield’s salt water 

disposal wells and uses the water there as its source. The processed water is stored in in frac 

tanks until it is needed. At this time only six percent of the frac water is recycled. 

Newfield is working on locating a place for recycle pits and being able to use higher chloride 

water as a frac fluid so that more water can be recycled. 

Conclusion 

Newfield’s Granite Wash operation is a prime example of where recycling frac water is 

environmentally responsible and makes the company money at the same time. This is a win-win 

for the landowners, the community, and the company. 
75

Johanna Haggstrom, Ph.D. 

Halliburton Energy Services 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Increased demands on freshwater sources, stricter local legislation on the use of municipal 

waters in industry, and the unpredictability of drought conditions all conspire to make the use 

of non-freshwater-based stimulation technologies, as well as the ability to recycle flowback and 

produced waters an important objective in today's oilfield. The advantages of using these nonfreshwater sources include the reduction or elimination of disposal costs and the 

environmental benefit gained by recycling non-freshwater sources (as opposed to the largescale consumption of freshwater required by current technologies). Water produced from the 

formation (produced water), as well as treatment flowback water, is becoming more costly for 

disposal due to increasing trucking costs and disposal fees and hence, the demands for water 

conditioning and reuse have increased dramatically this past decade. Furthermore, the 

complexity of global water management is significantly magnified when contemplating the local 

challenges concerned with government regulations, water volumes, water quality, and the like. 

Conventional means of waste water regeneration include, for example, water softening, 

distillation, ion exchange, reverse osmosis (RO), ozonation, and a wide range of filtration 

technologies. Flowback and produced water vary in composition tremendously depending on 

several factors, including location of the formation, chemicals used during stimulation, and age 

of the well. Total Dissolved Solids (TDS) vary tremendously and can reach up to saturation levels 

(around 300,000 mg/L). In addition, the water can contain a variety of different salts, making 

one field’s water very different from the next. This variability makes no "one-treatment 

method" suitable for all waters. For example, during distillation of salt water, the amount of 

distilled water generated depends on how much salt is in the water; in other words, the overall 

throughput decreases with increasing salt content. The cost effectiveness decreases with 

increased salt concentration and is hence not cost effective for produced waters very high in 

salt. 

When deciding between water treatment methods to treat flowback and produced waters, it is 

important to consider the end use and its specific requirements, as well as composition of the 

water. With water treatment processes, the cost of treatment chemicals, type of equipment, 

and maintenance of the equipment, ease of process mobility, personnel, and disposal of 

treatment waste should all be considered, and as the end use and incoming water quality will 

vary, the treatment processes have to be selected accordingly. 

Toolbox Available to Treat Flowback and Produced Waters 
76

A Closed Loop System Using a Brine Reservoir to Replace Fresh 

Water as the Frac Fluid Source 

Minimization of Fresh Water Use: The Use and Reuse of 35,000 ppm Brine from a 

Dedicated Deep Reservoir as a Fracture Fluid for Shale

George E. King 

Apache Corporation 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

A non-fresh water source has been proposed and tested in the laboratory and field for 

application as a fracturing fluid in shale gas formations, with potential to replace a very high 

percentage of the fresh water used in the Encana and Apache area of the Horn River Basin in 

British Colombia, Canada (Pond, 2010; DeMong, 2011). The water source is the Debolt 

formation, which overlies the Horn River Play gas zones by several thousand feet. The Debolt 

formation in the EnCana/Apache area of the Horn River Basin contains a moderately saline 

water (35,000 ppm TDS), in a high strength, high permeability rock matrix capable of supplying 

thousands of barrels of water per hour. The intent of the project is to sharply reduce the 

amount of fresh water used in fracturing and to form a closed loop system that will reduce 

storage of water at the surface. Additional benefits include reduction of air emissions (pumps 

and heaters), reduction in chemicals (oxygen scavengers and biocides) and overall reduction in 

surface pipe lines and truck traffic. The project equipment involves dedicated water supply 

wells, large electric submersible pumps (ESP), a stand-alone water treating plant (to remove 

hydrogen sulfide gas (H2S), and equipment to recover the after-frac produced water from the 

wells and reinject the fluids into the Debolt formation. 

Shale gas developments in North America have centered on using fresh water as a fracturing 

base fluid since about year 2000, when the C.W. Slay well in the Barnett shale was refractured 

after foam fracture treatment and gelled fracture treatments were found to be expensive and 

created substandard well performance (Steinsberger, 2009; Grieser, 2003; Palisch, 2008; 

Schein, 2004; Arthur, 2009). The slick water re-fracture on this well (slick water contains 0.25 

gallons of polyacrylamide polymer friction reducer per 1000 gallons of water, plus smaller 

amounts of scale inhibitor, biocide and oxygen scavenger (Authur, 2009)) provided gas rates 

above even the initial rates from the well when it was first stimulated in 1983. The ability of 

slick water fracturing to enhance the productivity of shale well from the unfractured initial 

flows of 0 to less than 100 scf/d, to fracture stimulated average initial flows of 1,000,000 to 

10,000,0000+ scf/d, has been shown to be controlled by penetration of the low viscosity water 

(water at 0.6 to 1.0 centipoises) into the natural fractures of the shales, providing ability for the 

increasing pressure to widen the natural fractures, opening up flow paths to the natural gas 

trapped within the shale. Previous fracture fluids were less effective in the shales due to higher 

viscosity preventing fluids from invading and opening the natural fracture systems and the high 
77

cost of gelled and foam fracturing fluids with accompanying large amounts of expensive 

additives. Well performance has been directly linked to larger amounts of water, larger 

amounts of proppant and higher injection rates (Coulter, 2004; 2006, King 2008, 2010). 

Objections to fresh water use for hydraulic fracturing have risen in several places and, while the 

quantity of fresh water is lower in these shale developments than many local industries, 

agriculture and municipal uses, the returning water is often highly saline, making water 

recovery to the fresh water supply more technologically difficult (Gaudlip, 2008; Blauch, 2009). 

This presentation focuses on a joint project by EnCana and Apache to use the moderately saline 

water from the Debolt formation as a primary source for fracturing fluid for the Horn River 

Basin (HRB) Shales in the northern British Columbia (BC) Province of Canada. The pilot projects 

and initial fracturing operations from multi-well pads in the HRB area was accomplished with 

fresh water from municipal water sources and finally from the local lakes within the guidelines 

set up by the BC Oil and Gas Commission (OGC). For larger scale operations, the companies 

sought a source of water that was more stable and less environmentally intrusive, settling on 

the Debolt formation brine. 

Laboratory testing (Pond, 2010) identified the water treatment necessary to address H2S (60 to 

80 ppm in water phase and up to a few thousand in the water vapor phase) and several other 

considerations. The following chart from SPE 138222 summarizes the EnCana work. 

General water treating steps and rational behind the operation was as follows: 





Dilute HCl with corrosion inhibitor injected downstream of supply wellhead to lower pH 

and prevent scaling. 

Inject high pressure natural gas to strip H2S and CO2. Second step was low pressure gas 

stripping of water. 

Table 5. Source: SPE 138222 
78









Collect water in a tank and flash off gas and vapor for treatment and recovery or 

incineration. 

Monitoring water flow rate accomplished by inline measurement. 

Small storage of water was accomplished in positive pressure tanks with a propane 

atmosphere. 

Final “polishing” step with a chemical scavenger reduced H2S in the frac water to zero. 

The process was brought to a commercial, high rate level with twenty-one total potential steps 

and optional steps (Table 6). The testing met objectives of 0 ppm H2S with no unfavorable byproducts. Detailed water monitoring checked on bicarbonate concentrations, scale potential, 

barium concentration and iron sulfide content. Other testing on biocides, scale inhibitors and 

general shale impact of the Debolt water showed minimum impact. The salinity of the water 

did require re-engineering of some additives. 

The Debolt water source is provided by two ESP pumped wells. Each ESP has an operating 

envelope in the range of 31,250 to 50,000 barrels per day (5000 to 8000 m

3

/d). The water 

treatment plant is designed for 100,000 barrels per day (16,000 m

3

/d), which is sufficient for 3 

to 4 fracs per day. 

 There are two tanks, each with a volume of 9375 bbls (1500 m

3

) for storage of processed water 

(sweet). A frac spread may only draw from a full tank, eliminating the possibility of an upset in 

the treating system supplying out-of-spec water to the pumping equipment. 

Table 6. The Debolt Process Flow Diagram (SPE 138222) 
79

Post-frac produced water flow from the wells will be processed with a minimum of treatment 

except to remove solids and gas, and then re-injected into the Debolt formation. On-going 

studies will monitor both the supply and the disposal. 

Conclusions 







The Debolt water source is a regional sour aquifer with a TDS level unsuitable for either 

agriculture or drinking water. 

Use of the Debolt water required a series of tests focused on water treatment, 

formation interaction and disposal potential. 

Environmental impact improvements are seen in a number of areas: 

o

o

o

o

o

o

Minimization of water heater emissions by using the hot water from the Debolt 

(approximately 140 F/60 C) instead of heating lake water to prevent freezing 

in the -20C operations. 

Minimization of fresh water usage. Fresh water still used for surface drilling and 

cementing. 

Possible reduction of biocides and elimination of several other chemicals by 

keeping oxygen out of the water. 

Reduction of surface frac water storage to less than 5% of total needed 

Reduction of surface pipe from lakes. 

Reduction of truck traffic and roads by using the closed-loop system. 

References 

Arthur, J.D., Bohm, B., Coughlin, B.J., Layne, M.: “Evaluating Implications of Hydraulic Fracturing 

in Shale Gas Reservoirs,” Paper SPE 121038, presented at the 2009 SPE Americas 

Environmental and Safety Conference, San Antonio, TX USA, 23-25 March. 

Arthur, J.D., Bohm, B, Cornue, D.: “Environmental Considerations of Modern Shale 

Developments,” Paper SPE 122931, presented at 2009 SPE Annual Technical Meeting, 

New Orleans, LA, USA, 4-7 October. 

Blauch, M.E., Myers, R.R., Moore, T.R., Houston, N.A.: “Marcellus Shale Post-Frac Flowback 

Waters – Where is All the Salt Coming From and What are the Implications?,” Paper SPE 

125740, presented at the 2009 SPE Regional Meeting, Charleston, WVA, USA, 23-25 

September. 

Coulter, G.R., Benton, E.G., Thomson, C.L.: “Water Fracs and Sand Quality: A Barnett Shale 

Example,” Paper SPE 90891, presented at the 2004 SPE Annual Technical Conference 

and Exhibition, Houston, Sept 26-29.

Coulter, G.R., Gross, B.C., Benton, E.G., Thomson, C.L.: “Barnett Shale Hybrid Fracs – One 

Operator’s Design, Application and Results, “Paper SPE 102063, presented at 2006 SPE 

Annual Technical Conference and Exhibition, San Antonio, TX, USA, 24-27 September. 

DeMong, K., Hands, R., Affleck, B.: “Advances in Efficiency in Horn River Shale Stimulation,” SPE 

140654, SPE Hydraulic Fracturing Technology Conference, 24-26 Jan 2011, The 

Woodlands, TX, USA. 
80

Ferguson, M.L.: Comparing Friction Reducers’ Performance in Produced Water From Tight Gas 

Shales,” SPE Technology Update, J.P.T., November 2009, pp 24-27.

Gaudlip, A.W., Paugh, L.O., Hayes, T.D.: “Marcellus Water Management Challenges in 

Pennsylvania,” Paper SPE 119898, presented at the 2008 SPE Shale Gas Production 

Conference, Ft. Worth, TX, USA, 16-18 November. 

Grieser, B, Hobbs, J., Hunter, J., Ables, J.: “The Rocket Science Behind Water Frac Design,” Paper 

SPE 80933, presented at 2003 SPE Production Operations Symposium, OK City, OK, USA, 

22-25 March. 

King, G. E.: “Thirty Years of Gas Shale Fracturing: What Have We Learned?”, SPE 133456, SPE 

Annual Technical Meeting and Exhibition, Spet 20-22, 2010, Florence, Italy. 

King, G.E., Lee, R.M.: “Adsorption and Chlorination of Mutual Solvents Used in Acidizing,” SPE 

Production Engineering, Cvol.3, No. 2, May 1988, pp 205-209. 

King, G.E., Warden, S.L.: “Introductory Work in Scale Inhibitor Squeeze Performance: Core Tests 

and Field Results,”Paper SPE 18485, presented at 1989 SPE International Symposium on 

Oilfield Chemistry, Houston, TX, USA, 8-10 February. 

Palisch, T.T., Vincent, M.C., Handren, P.T.: “ Slickwater Fracturing-Food For Thought,” Paper 

SPE115766, presented at 2008 SPE Annual Technical Meeting, Denver, CO, USA, 21-24 

September. 

Pond, J., Zerbe, T., Odland, K.: “Horn River Frac: Past, Present, and Future,” SPE 138222, 2010 

Canadian Unconventional Resources & International Petroleum Conf., 19-21 October, 

Calgary, Alberta, Canada. 

Schein, G.: “The Application and Technology of Slickwater Fracturing,” Distinguished Lecturer 

Presentation, SPE 108807, presented 2004-2005. 

Steinsberger, N.: “The Barnett Shale and the Evolution of North American Shale Plays,” 

Presentation and Slides, presented at 2009 SPE GCS Westside Study Group. 
81

Summary and Abstracts from Theme 3: Disposal Practices
82

Summary of Presentations from Theme 3: Disposal Practices 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 

Technical Presentations 

The first set of technical presentations in this theme addressed treatment technologies and 

processes prior to disposal. 

David Alleman, ALL Consulting, described three potential options for managing produced 

water: deep injection, treatment and disposal via surface discharge or beneficial use, and reuse 

in HF activities. He explained that there are a number of treatment challenges including the 

variation in produced water characteristics, generally high TDS concentrations, makeup of the 

waste stream after treatment, and differences between treatment in the laboratory and in the 

field. He explained that the high TDS concentrations effectively limit the technologies that are 

capable of treating shale gas produced water for discharge to reverse osmosis and thermal 

distillation. He noted that while there are a number of vendors who offer such treatment 

technologies, only a few have demonstrated the capability to treat shale gas produced water, 

and, among those, most do not have facilities and experience in all of the active shale gas plays. 

Thus, the availability of effective treatment technologies in any given location is limited. ALL 

Consulting has developed a mixing and scale affinity model with DOE that allows operators to 

model the chemical reactions taking place downhole and identify potential scaling issues. He 

stated that this model has helped smaller operators in particular design the appropriate 

fracture fluid for their water base.

Pei Xu, Colorado School of Mines, presented on her research team’s recent literature review 

and technical assessment of a number of different emerging treatment technologies for 

produced water. She stated that factors such as the particular water chemistry of the produced 

water and the pressure and thermal resources of the formation should be taken into account 

when selecting treatment technologies. She suggested that a good treatment technology 

should fulfill a number of requirements including low chemical and energy demand, flexibility, 

robustness, low maintenance, high rejection of contaminants, and high recovery.

The final set of technical presentations addressed disposal practices and potential impacts. 

Joseph Lee, Pennsylvania Department of Environmental Protection, stressed that much more 

water monitoring is needed in Pennsylvania. He commented that there are a number of causes 

of water pollution in the state, including large numbers of coal mines and orphaned and 

abandoned extraction wells, but there has not yet been any evidence of HF directly impacting 

underground sources of drinking water (USDWs). He noted that it is known that surface and 

ground waters in the Marcellus Shale area are already stressed by the legacy of past mineral 

extraction. Mr. Lee concluded that Pennsylvania has recently updated state well construction 
83

regulations and he emphasized that these and other oil and gas regulations are adequate to 

protect water resources.

Andrew Havics, pH2, LLC, presented a risk assessment of the chemicals present in pit fluids on 

site at drilling operations in Colorado. The selection of chemicals in the assessment was driven 

by what was present and the risk factors associated with fate and transport for those 

chemicals. Benzene, toluene, ethylbenzene, and xylene (BTEX) were the most important 

chemicals investigated. The study found that there was no significant risk to human health from 

these chemicals based on the potential for exposure. The presenter emphasized that, when 

conducting a similar assessment elsewhere, the local geologic and hydrogeologic conditions 

should be thoroughly characterized.

Rick McCurdy, Chesapeake Energy Corporation, presented an overview of the Underground 

Injection Control (UIC) program, outlining the different well classes and discussing the 

particulars of Class II injection wells. Of approximately 144,000 Class II wells in the United 

States, 80% are used for enhanced oil recovery and 20% are used for disposal. Brine disposal in 

Class II wells is safe and environmentally sound, and is the most economic solution in many 

areas. He stated in some areas, However, these benefits are offset by high transportation costs 

if a Class II disposal well is not located near drilling operations. In these cases, he commented 

that other options for disposal such as treatment and reuse may become more viable. He 

provided an example from Chesapeake, which has developed their reuse program (AquaRenew) 

in areas such as Pennsylvania where the local geology is not conducive to constructing Class II

wells.

Paul Ziemkiewicz, West Virginia University, presented a study investigating the sources of TDS

loads in the Monongahela River following the high loads measured in 2008. He explained that 

the major sources of TDS in the Monongahela watershed are coal mines (including acid mine 

drainage), coalbed methane wells, and wells in the Marcellus Shale. Brine from the Marcellus 

and mine water have different chemical signatures, with the Marcellus water dominated by 

sodium chloride and mine water by sodium sulfate. In the Youghiogheny River (a large tributary 

to the Monongahela), the study found that sodium chloride was much more dominant during 

the winter wet season and the average TDS increased greatly compared to the summer. The 

study did not find TDS concentrations over 500 mg/L since 2009. Dr. Ziemkiewicz noted that a 

mass balance approach can be useful for evaluating the effectiveness of TDS control options. 
84

Summary of Discussions Following Theme 3: Disposal Practices 

Presentations 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use.

Emerging technologies literature review. Dr. Xu clarified that for well-understood technologies, 

the research team was able to consider a variety of factors that affect the cost of the 

technology including chemical and energy demand and depreciation. For an assessment of a 

new technology, the team was only able to look at the cost of acquiring the technology. When 

assessing general water quality after treatment, they looked only at whole effluent toxicity. 

However, the research group did try to cover constituents of concern for beneficial use, and 

considered indirect potable water use as an option.

Colorado pit fluids modeling study. Mr. Havics clarified that his study found no difference in 

arsenic concentration between soil samples taken at the study sites and background soil 

concentrations obtained from USGS data. In addition to soil concentrations, he suggested that 

ground water concentrations of arsenic be measured at increasing pH, simulating the chemistry 

of the pit fluids. The presenter added that the concentration of arsenic found in the soil at the 

Colorado study sites was an order of magnitude lower than what would be considered a risk.

Clarification on items in the other technical presentations. The mixing model described by Mr. 

Alleman is based on USGS’s PHREEQC model and is available to the public free of charge. Mr. 

Lee clarified that chloride and bromide ratios in the Monongahela study were also used to 

fingerprint the different brines in the study, and matched the other results of the study. Mr. Lee 

also clarified that when he called for additional monitoring in Pennsylvania, he specifically 

meant ground water monitoring.

Well construction and casing. A participant asked why the casing of some wells is not cemented 

to the surface. The presenters answered that the feasibility of cementing to the top of the well 

depends on local conditions. In some areas, there is a zone above which the well cannot be 

cemented. The presenters also noted that mud logging can be used to identify shallow gas 

zones and cement the problem areas without cementing the entire sequence from top to 

bottom. Some participants recommended referring to the meeting summary from Workshop 2 

for further information.

Disposal wells in the Marcellus. Some participants stated that it is currently more economic for 

many operators to reuse produced water in the Marcellus than to inject it for underground 

disposal. A participant suggested that the reason underground disposal is not common in the 

Marcellus is due less to geologic concerns and more to past and present practices in the state 

which give operators opportunities to dispose of fluid much more easily than through injection. 

One participant asked if injection wells are even needed in the Marcellus, given the trend 

toward exploring reuse options and the low water volume output of the play. A participant 
85

recommended that if there is a need for the development of injection capacity in the Marcellus, 

operators should cooperate to find suitable zones. The presenters emphasized that the decision 

of how to dispose of produced water is a practical and economic one: they stated that in some 

cases, underground injection is the safest and most cost-effective and in other cases reuse is 

safer and more cost-effective. 

Conventional plays. A participant suggested that, while the technical workshops have focused 

on tight shales, the participants and presenters keep conventional plays in mind. The 

participant suggested that the emphasis has been on tight plays because of the volume of 

water used in slickwater operations. Participants noted that conventional wells are fractured 

with much less fluid but use higher concentrations of chemicals, so they belong in a different 

discussion. 
86

Abstracts for Theme 3: Disposal Practices 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 
87

Pei Xu, Tzahi Cath and Jörg E. Drewes 

AQWATEC, Environmental Science and Engineering Division, Colorado School of Mines 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Introduction 

Development of unconventional gas resources, including coalbed methane (CBM), shale gas, 

and tight sand is currently one of the most rapidly growing trends in domestic oil and gas 

exploration and production. The U.S. Energy Information Administration (EIA) projects that 

shale gas and CBM will make up 34% of total U.S. production in 2035, doubling their 17% share 

in 2008 [1]. Shale gas is the largest contributor to the growth natural gas production, while 

production from CBM deposits remains relatively stable from 2008 to 2035. 

The rapid rise in production from shale formations is in large part attributed to the advances in 

horizontal drilling and hydraulic fracturing techniques. Hydraulic fracturing is the most 

significant technique that has enhanced the commercial shale gas production. Shale formation 

commonly has low permeability; therefore the wells need to be stimulated by hydraulic 

fracturing techniques. Hydraulic fracturing involves pumping fluids and proppant (i.e., grains of 

sand or other material used to hold the cracks open) down the wellbore under high pressure so 

that the gas can flow to the wellbore. A general estimate of water requirement for multi-stage 

fracture treatment of a horizontal well varies between 2.3 and 6 million gallons of water [2-4]. 

Development of shale gas resources also requires significant quantities of water for drilling and 

plant operations. Additionally, the majority of the frac water, from lower than 15% to as much 

as nearly 80%, returns to the surface [2, 5]. The flowback water typically contains sand, 

chemical additives, hydrocarbons, salts, and occasionally low level of naturally occurring 

radioactive materials (NORM) that are found in many geological formations. In addition to frac 

flowback water, large volumes of produced water are generated in the early stages of gas 

production to reduce pressure in the formation before the gas can be produced. Produced 

water is typically salty and often requires treatment prior to discharge. 

Water usage, water quality, and disposal are the pressing issues that may potentially inhibit the 

projected growth in unconventional gas production, in particular considering new 

environmental legislation and public perception [6]. Operators must manage flowback and 

produced waters in a cost-effective manner that complies with regulatory requirements. This 

requires the treatment processes to be robust, mobile and modular, sustainable, inexpensive, 

and to have low energy demand. Furthermore, technologies should be versatile and flexible 

and can be used to treat water with variable quantity and quality containing different 

contaminants and having different characteristics. 

Novel and Emerging Technologies for Produced Water Treatment 
88

Various treatment technologies have been used or under development to address water supply 

and disposal issues during oil and gas development. Funded by the DOE/RPSEA program, we 

conducted a literature review and technical assessment to evaluate existing and emerging 

technologies that have been used for treatment of produced water and novel technologies that 

could be tested and considered in the future. The evaluation criteria for technical assessment 

include commercial status of technology and applications; applicable feed and expected 

product water quality; removal efficiencies of key constituents; infrastructure considerations 

(modularity, mobility, etc); energy use and consumption; chemical demand; life cycle and costs; 

operation and maintenance considerations (ease of operation, reliability, etc); pre- and posttreatment; and waste disposal. Laboratory and field testing were conducted to explore the 

most appropriate and cost-efficient technologies for treatment of CBM produced waters that 

will allow beneficial use of the treated water. A modeling framework was developed to 

evaluate the technical aspects, institutional complexity, and economic viability of multiple 

beneficial use and discharge options. The decision making framework is comprised of four 

modules: 1) Water Quality Module (WQM); 2) Treatment Selection Module (TSM); 3) Beneficial 

Use Screening Module (BSM); and 4) Beneficial Use Economic Module (BEM). The detailed 

description of this RPSEA project and the downloadable tools and technology factsheets can be 

found at the website “Produced Water Treatment and Beneficial Use Information Center” 

(http://aqwatec.mines.edu/produced_water/index.htm).

This paper will summarize briefly the technical assessment and testing results of novel and 

emerging technologies for produced water treatment. 

Electrochemical Charge Driven Separation Processes 

Electrochemical charge driven separation processes separate dissolved ions from water through 

ion permeable membranes or conductive adsorbers under the influence of an electrical 

potential gradient. These processes include electrodialysis (ED), electrodialysis reversal (EDR), 

electrodeionization (EDI), and capacitive deionization (CDI). An ED stack consists of a series of 

anion exchange membranes (AEM) and cation exchange membranes (CEM) arranged in an 

alternating mode between anode and cathode. The positively charged cations migrate toward 

the cathode, pass the cation exchange membrane, and rejected by the anion-exchange 

membrane. The opposite occurs when the negatively charged anions migrate to the anode. This 

results in an alternating increasing ion concentration in one compartment (concentrate) and 

decreasing concentration in the other (diluate). The EDR process is similar to the ED process, 

except that it also uses periodic reversal of polarity to effectively reduce and minimize 

membrane scaling and fouling, thus allowing the system to operate at relatively higher water 

recoveries. 

Electrodeionization (EDI) is a commercial desalination technology that combines ED and 

conventional ion exchange (IX) technologies. A mixed-bed ion exchange resin or fiber is placed 

into the diluate cell of a conventional electrodialysis cell unit to increase the conductivity in the 

substantially non-conductive water. The IX resins are regenerated via water splitting under 

current. The process can be performed continuously without chemical regeneration of the IX 

resin, and reduce the energy consumption when treating low salt solutions. 
89

Capacitive deionization (CDI) is an emerging desalination technology. In CDI, ions are adsorbed 

onto the surface of porous electrodes (e.g., activated carbon, carbon aerogel, carbon fibers, 

etc) by applying a low voltage electric field, producing deionized water. 

Electrochemical charge driven separation processes are typically used in desalination of 

brackish water (up to about 8,000 mg/L TDS for EDR) and not highly saline water. This is 

because the cost of these processes and energy consumption increase substantially with 

increasing salinity or TDS concentration. ED and EDR have been successfully used at a number 

of municipal water and wastewater treatment plants to desalinate brackish water and 

reclaimed water. Laboratory experiments and pilot scale testing have been conducted to 

investigate the feasibility of these technologies to treat produced water. Although these 

processes are less prone to fouling as compared to reverse osmosis (RO) and nanofiltration (NF) 

membranes, the efficiency of ED, EDR and EDI is degraded by fouling/scaling. Sparingly soluble 

inorganic salts (e.g., CaSO4, CaCO3) and multivalent ions (e.g., iron and manganese) can still 

scale the IX membranes by precipitation and fixation. This can be controlled by pretreatment of 

the feedwater with processes such as filtration for suspended solids, softening or pH lowering, 

and addition of antiscalant into the concentrate compartments. A disadvantage of these 

processes is the limited removal of non-charged constituents, including organics molecules, 

silica, boron, and microorganisms. 

Ceramic MF/UF membrane 

Ceramic ultrafiltration and microfiltration membranes are made from oxides, nitrides, or 

carbides of metals such as aluminum, titanium, or zirconium. Ceramic membranes are much 

more resilient than polymeric membranes and are mechanically strong, chemically and 

thermally stable, and can achieve high flux rates. Typically, a tubular configuration is used with 

an inside-out flow path, where the feed water flows inside the membrane channels and 

permeates through the support structure to the outside of the module. 

Ceramic membranes are capable of removing particulates, organic matter, oil and grease, and 

metal oxides. Ceramic MF/UF membranes alone cannot remove dissolved ions and dissolved 

organics. Pre-coagulation, injection of a chemical coagulant upstream from the membrane, 

improves removal efficiencies of dissolved organic carbon and smaller particulates. As with 

conventional ultrafiltration and microfiltration, a strainer or cartridge filter is necessary as 

pretreatment for ceramic membranes. Numerous research studies have been conducted on 

using ceramic membranes to treat oil-containing wastewater and produced water [7-8]. These 

research studies have shown that ceramic membranes perform better than polymeric 

membranes on oil-containing waters. Ceramic membranes have also been employed 

commercially as part of a large treatment train consisting of multiple unit process at the 

Wellington Water Works to treat oilfield produced water [9]. 

Energy requirements for ceramic membranes are lower than those required for polymeric 

membranes. Ceramic membranes have a higher capital cost than polymeric membranes. The 
90

application of ceramic membranes for produced water treatment may increase as more 

research and pilot studies are conducted. 

Membrane Distillation 

Membrane distillation (MD) is a novel thermally driven membrane separation process that 

utilizes a low-grade heat source to facilitate mass transport through a hydrophobic, 

microporous membrane [10-11]. The driving force for mass transfer is a vapor pressure 

gradient between a feed solution and the distillate, and is the only membrane process that can 

maintain process performance (i.e., water flux and solute rejection) almost independently of 

feed solution TDS concentration. MD is most likely capable of producing ultra-pure water at a 

lower cost compared to conventionally distillation processes; however, compounds with higher 

volatility than water, such as BTEX and other organic compounds, will diffuse preferentially 

faster through the membrane. Membrane materials commonly employed for MD include 

polytetrafluorethylene (PTFE), polypropylene (PP), and polyvinylidenedifluoride (PVDF). MD 

membranes may be packaged in either flat-sheet or hollow-fiber configurations. For 

pretreatment, MD processes require a pre-filter to screen out large particles and the complete 

removal of any surfactants present in the feed stream. If surfactants are present in the MD feed 

stream they will wet the hydrophobic pores of the MD membrane and cause pore flooding, 

which results in a substantial reduction in membrane solute rejection. 

MD is flexible for most variations in feed water quality and quantity. It may become a potential 

technology for produced water treatment with the improvement in MD membranes and 

system design. 

Osmotically Driven Membrane Processes 

Forward osmosis (FO) is an osmotically driven membrane process. During FO, water diffuses 

spontaneously from a stream of low osmotic pressure (the feed solution) to a hypertonic (draw) 

solution having a very high osmotic pressure. Unlike RO and NF, FO systems operate without 

the need for applying hydraulic pressure. The membranes used for this process are dense, nonporous barriers similar to RO and NF membranes, but are composed of a hydrophilic, cellulose 

acetate active layer cast onto either a woven polyester mesh or a micro-porous support 

structure. 

Typically, the FO draw solution is composed of NaCl, but other draw solutions composed of 

NH4HCO3, sucrose, and MgCl2 have been proposed. During FO the feed solution is concentrated 

while the draw solution becomes more dilute. FO requires the continuous reconcentration of 

the draw solution for sustainable system operation. One option is the use of RO for 

reconcentrating the draw solution and producing fresh product water for beneficial use or 

discharge. 

FO membranes are capable of operating with feed TDS ranging from 500 mg/L to more than 

35,000 mg/L, and rejecting all particulate matter and almost all dissolved constituents (greater 

than 95% rejection of TDS). These attributes also allow FO to achieve very high theoretical 
91

recoveries while minimizing energy and chemical demands. An additional benefit of FO is that 

the process occurs spontaneously, without the need of applied hydraulic pressure. Therefore 

fouling layers that accumulate on FO membranes may be readily removed with cleaning (e.g., 

increasing cross-flow velocity, osmotic backwashing) or with chemicals, and irreversible flux 

decline is minimized [12]. FO membranes may be packaged in flat sheet or spiral-wound 

configurations. These packages allow for relatively small process footprints, but are still not 

optimized to the extent of pressure driven processes. 

The testing results of FO process for produced water treatment at laboratory and field are 

promising. With the development of more suitable draw solution and appropriate semipermeable membrane, FO process can become a potentially industrial technology to address 

the challenges of shale gas flowback and produced water treatment. 

References 

[1]U.S. Energy Information Administration, Annual Energy Outlook 2010 with Projections to 

2035. Report #:DOE/EIA-0383(2010). Release Date: May 11, 2010. Available at: 

<http://www.eia.doe.gov/oiaf/aeo/gas.html>. [cited October 16, 2010]. 

[2]GWPC and ALL, Modern Shale Gas Development in the United States: A Primer. Prepared for 

the U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory 

(NETL). Prepared by the Ground Water Protection Council and ALL Consulting. April 2009. 

Available at: <http://www.oilandgasinvestor.com/Files/DOEShaleGasPrimer.4.14.09.pdf>. 

[3]Railroad Commission of Texas web site: June 4, 2007. “Water Use in the Barnett Shale.” 

Available at: <http://www.rrc.state.tx.us/divisions/og/wateruse_barnettshale.html>. [Cited October 

16, 2010], 

[4]D.B. Burnett and C.J. Vavra, Desalination of Oil Field Brine - Texas A&M Produced Water 

Treatment. Available at: <http://www.pe.tamu.edu/gprinew/home/BrineDesal/MembraneWkshpAug06/Burnett8-06.pdf>. [Cited October 16, 2010]. 

[5]J. Veil, Water Management Technologies Used by Marcellus Shale Gas Producers. Prepared 

for: United States Department of Energy National Energy Technology Laboratory. Final Report 

July 2010. 

[6]PADEP, Notice of Final Rulemaking Department of Environmental Protection Environmental 

Quality Board [25 PA. CODE CH. 95]. Wastewater Treatment Requirements. Available at: 

<http://files.dep.state.pa.us/PublicParticipation/Advisory%20Committees/AdvCommPortalFiles/WRAC/

Preamble%20TDS%20Final%20Rulemaking%20to%20WRAC.pdf>. [cited October 16, 2010]. 

[7]R.S. Faibish, and Y. Cohen, Fouling and rejection behavior of ceramic and polymer-modified 

ceramic membranes for ultrafiltration of oil-in-water emulsions and microemulsions, Colloids 

and Surfaces A: Physicochemical and Engineering Aspects 191 (2001) 27-40.

[8]G. Gutierrez, A. Lobo, D. Allende, A. Cambiella, C. Pazos, J. Coca, and J.M. Benito, Influence of 

Coagulant Salt Addition on the Treatment of Oil-in-Water Emulsions by Centrifugation, 

Ultrafiltration, and Vacuum Evaporation, Separation Science and Technology 43 (2008) 1884 - 

1895.

[9] D.R. Stewart, Developing a new water resource from production water. Available at: 

http://www.crwcd.org/media/uploads/Dave_Steward.pdf. [cited October 1, 2010] 
92

[10] T.Y. Cath, V.D. Adams, and A.E. Childress, Experimental study of desalination using direct 

contact membrane distillation: A new approach to flux enhancement, Journal of Membrane 

Science 228 (2004) 5-16.

[11] K.K. Sirkar, and B. Li, Novel membrane and device for direct contact membrane distillationbased desalination process: phase II, 2003, Bureau of Reclamation, Denver, Colorado. 

[12] T.Y. Cath, A.E. Childress, and M. Elimelech, Forward osmosis: principles, applications, and 

recent developments, Journal of Membrane Science 281 (2006) 70-87.
93

Simple Modeling of the Disposition of Fluids On-Site in a Pit 

Andrew A Havics1, CHMM, CIH, PE, and Dollis Wright2

1

pH2, LLC, Avon, IN

2QEPA, Denver, CO

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

The fracing process begins with wellpad siting, proceeds through completion and ends with 

production (and the eventually decommissioning or abandonment). The steps in the process 

include: site selection, well pad development, drilling, fracing, and production. Using the term 

waste to mean any disposal, whether in use or afterwards, one realizes that there are a number 

of waste materials produced during these steps including: drilling fluids, pit solids, pit liquids, 

frac fluids, flowback fluids, and produced water. An investigation involving sampling and 

analysis of these materials was conducted along with a followup risk assessment (RA) to assess 

the impact of fracing in four energy basins in Colorado which was completed in the spring of 

2008 [URS, 2008; QEPA, 2008]. The focus of this presentation will be on three media: flowback 

fluids, frac fluids, and produced waters, although other media (e.g., pit solids as waste) and 

subsequent pathways were considered and were evaluated in both the sampling and analysis 

[URS, 2008] and in the RA [QEPA, 2008]. 

Chemical Analysis

In 2008, in a project funded by the Colorado Oil and Gas Association (COGA), QEPA, pH2 

through QEPA, and URS were contracted to devise a sampling and analytical plan as part of a 

risk assessment for proposed changes in the Oil & Gas (O&G) regulations in Colorado [COGCC, 

2008]. This first necessitated the identification of chemicals for analytical evaluation (CAE) and 

eventual selection of the chemicals [URS, 2008]. A list of chemicals was prepared that included 

data suggested by a review of Material Safety Data Sheets (MSDS) from COGA member 

companies. It also included standard chemicals of interest in the O&G industry such as Benzene, 

Toluene, Ethyl Benzene, Xylenes (BTEX), Polnuclear Aromatic Hydrocarbons (PAHs), Boron, 

Chloride, Total Extractable Petroleum Hydrocarbons (TEPH), etc. [CDPHE, 2007; COGCC, 2008]. 

Primary metals (and metalloid) included were the 8 Resource Conservation and Recovery Act 

(RCRA) metals consisting of arsenic, barium, cadmium, chromium, lead, mercury, silver, and 

selenium; and an additional 15 target analyte list (TAL) metals were added from EPA Method 

6020A which included Aluminum, Antimony, Beryllium, Calcium, Cobalt, Copper, Iron, 

Magnesium, Manganese, Nickel, Potassium, Sodium, Thallium, Vanadium & Zinc. Based on a 

review of potential agents associated with raw material derived from subsurface deposits, gross 

alpha and gross beta were selected for analysis. A small subset of samples from pit wastes was 

analyzed by EPA’s Toxic Characteristic Leaching Procedure (TCLP) for 8 RCRA metals in addition 

to pH, reactive sulfides, and reactive cyanides to evaluate waste disposal considerations. 

However, this presentation will only cover flowback fluids, frac fluids, and produced waters, of 

which there are 32, 3, and 16 sample data points, respectively, including duplicates. 
94

Chemical Selection for Disposition Modeling 

Based on the analytical results, measurable values of the 173 analytes were narrowed. 

Although a number of PAHs were present, their fate-transport and subsequent risk were not 

shown to be significant human health risks; however, some were modeled. A few chemicals 

were removed from the modeling of liquid waste disposition based on previous modeling of 

solid wastes (our scenarios 1 to 8) indicating minimal opportunity for significant risk given basic 

maximum concentration as well as subsequent fate and transport. Chloride and boron were not 

selected for modeling as these had Colorado regulatory limits not tied to human health and 

these limits were not expected to be exceeded in these materials once accounting for dilution, 

fate, and transport. For instance, the boron maximum was 7.6 mg/L versus a limit of 2 mg/L

limit, not including any dilution from transport. 

The glycols were initially considered but dismissed based on the risk assessor’s qualitative 

order-of-magnitude assessment with regard to having a defacto dilution attenuation factor 

(DAF) under the modeled circumstances of an initial 4-100 dilution before significant transport. 

This diluted value when compared to drinking water standards and in consideration of fate and 

transport resulted in their de-selection from the liquid disposition modeling. For instance, only 

5 of 33 data points in the flowback fluids and none of the produced water samples detected 

glycols. The maximum in any medium was 120,000 ug/L, and with a 100 fold dilution (DAF) the 

result would be 1,200 ug/L. Using a 300-fold safety factor to calculate an acceptable limit based 

on the more toxic of the glycols (ethylene) [Blood, 1965] would result in 0.14 mg/kg/day 

acceptable exposure rate. For a 70 kg man consuming 2 L/day, that would be a drinking water 

limit of 4,900 u/L, higher than any suspect concentration at the point of exposure (POE). 

Similarly, data for 2-butoxyethanol (2-BE) revealed several detects in pit solids (as solids), pit 

fluids, flowback fluids, and drilling fluids. The highest of these was 7.1 mg/L in flowback flow 

fluids. A total of 5 additional hits were noted as tentatively identified compounds (TICs) with 

suspect validity, the highest estimated concentration from these was 20 mg/L. The ATSDR MRLS 

for 2-BE are 0.4 mg/kg/day and 0.07 mg/kg/day for intermediate and chronic exposure [ATSDR, 

1998]. These were converted to surrogate drinking water limits assuming 55-70 kg female or 

male humans and using a reasonable maximum likelihood estimate of water intake of 2 liters 

per day [EPA, 1989]. This results in intermediate surrogate drinking water limits of 11-14 mg/L, 

and chronic limits of 1.925-2.45 mg/L. One also notes that these limits have uncertainty/safety 

factors of 90 and 1000, respectively. Using the 20 mg/L and presuming typical DAFs of 100+, 2-

BE would not present a significant risk. 

Although gross alpha and gross beta were present, a set of appropriate phys-chem properties is 

not available for modeling their fate and transport within the model chosen for the other 

components. Furthermore, the effect of the anticipated DAF (100+) of disposing of a liquid in a 

waste pit on-site [where reserve pits at closure tend to be about 75x20 ft to 100x50 ft at depths 

of 8-10 ft], suggests that in these geologic settings, gross alpha and beta (maximums 274 and 

4,030 pCi/L, respectively) would not result in exceedances of 15 and 30 pCi/L EPA suggested 

levels in absence of isotope data at the anticipated conservatively estimated POE of 72 meters. 

The flowback fluids in general produced the highest levels of constituents of concern. The 
95 

produced water at the highest levels, for conservatism, were used in the modeling. Maximum 

values for each constituent were used as opposed to means or upper confidence limits (UCLs). 

Soil leaching was run simultaneously with the liquid and thus results include both, but are 

driven by the liquids in the off-site scenarios. 

Fate & Transport 

In the study in Colorado, the hypothetical practice of releasing flowback or produced water 

back into waste pits was modeled using a standard fate & transport model used in the ASTM 

RBCA standard [ASTM, 2002]. The modeling performed assumed a standard pit had an infinite 

source of flowback fluid and assumed no liner was present. We chose characteristics of the 

chemicals based on data from the two basins qualitatively considered more risky in setting, and 

the hydrogeologic characteristics for these basins as well. The model for transport is a standard 

Domenico model [Domenico, 1985, 1987] for solute transport with a modification for decaybased attenuation. For no decay, the decay constant in the equation, λ, was set to zero. Other 

parameters were set to limit errors, and apply a certain level of conservancy while still using 

more regional/local maximum likelihood estimators (MLEs) for hydrogeologic parameters. The 

hydraulic conductivity (Kha) was selected as 3.63E-3 cm/sec, driven by regulatory concerns 

[CDPHE, 2007], although the range tends to be lower. The depth to groundwater was varied 

from 1-3 meters (3.3-9.8 feet) in the 4 scenarios modeled, two with 1 meter and two with 3 

meters. The lower range of constituent retardation values from ASTM [ASTM, 2002] was used 

in the model. The POE for ground water was set at 10-72 meters (33-236 feet), where 72 

meters was the nearest well in a survey of 28 sites from the two basins (out the 55 sites from 

which the full study was conducted). The POE for surface water was also set at 10-72 meters, 

recognizing that the minimum and 5% quantile values for surface water distance to drilling well 

at the 28 sites investigated were 15 and 59 meters (49 & 194 feet), respectively. Of the 4 

scenarios modeled, two used 10 meters and two used 72 meters; and two assumed decay and 

two did not. Decay rates were set by chemical by selecting on the lower end of published data. 

Exposure

Several assumptions go into the exposure assessment process and a number of limitations also 

arise from this. In the study in Colorado the fluids released back into waste pits was modeled 

using a standard fate & transport model used in the ASTM RBCA standard [ASTM, 2002]. As part 

of this ASTM process, pathways from soils, groundwater and vaporization were considered. 

Scenarios that were accounted for included fishing, swimming, well water consumption, 

inhalation of air and dust downwind, etc. Exposures for commercial building occupancy and a 

construction worker scenario were modeled and are in the RA (QEPA, 2008), but are not 

presented here. Because multiple pathways, and thus exposures and doses, were modeled on 

the same population (e.g., person), an overestimate of real exposure is likely to arise. The RA

was completed using a variety of assumptions, details of which are provided in the RA [QEPA, 

2008]. 

The results indicate that benzene is driving the carcinogenic risk with all other agents (e.g., 

PAHs, phthalates, etc.) having little influence. There was an effect from arsenic, but this would 

already be seen from background levels present in soils already. The results also indicate that 
96

the non-cancer risk is driven by toluene, followed by xylenes and then ethylbenzene, with all 

other agents having little influence. The groundwater pathway is clearly more important. Based 

on the 4 scenarios, with scenarios 10 & 11 the most likely, it does not appear that the fluids 

present the significant risk that might have been anticipated had the fate, transport, and RA not 

been performed. 

Acknowledgments 

The study upon which a portion of this presentation is based was funded by the Colorado Oil 

and Gas Association (COGA). I would also like to acknowledge Mark Leverson, PG, Principal 

Hydrogeologist with URS for his work and assistance on the hydrogeology aspects. 

References 

ASTM: E1739-95(2002), Standard Guide for Risk-Based Corrective Action Applied at Petroleum 

Release Sites. ASTM, Conshohocken, PA. 2002. 

ATSDR: Toxicological Profile for 2-Butoxyethanol and 2-Butoxyethanol Acetate. August 1998. 

ATSDR: Toxicological Profile for Ethylene Glycol. 2010. 

ATSDR: Toxicological Profile for Propylene Glycol. 1997. 

Blood, FR: Chronic toxicity of ethylene glycol in the rat. Food Cosmet Toxicol 3:229-234. 1965. 

Colorado Department of Public Health and Environment (CDPHE), Hazardous Materials and 

Waste Management Division, Table 1 Colorado Soil Evaluation Values (CSEV) –

December 2007

Colorado Oil and Gas Conservation Commission (COGCC), Draft Rules for Oil and Gas 

Development in Colorado, (HB 1298 & HB 1341), March 31, 200. 

Domenico, P.A.: An Analytical Model for Multidimensional Transport of a Decaying 

Contaminant Species. J Hydrology 91: 49–58, 1987. 

Domenico, P.A. and G.A. Robbins: A New Method of Contaminant Plume Analysis. Ground 

Water 23(4): 476–485. 1985. 

QEPA: Pathway Analysis and Risk assessment (PARA) For Solids and Fluids Used In Oil and Gas 

Exploration and Production in Colorado, pp. 1-930, June 2008. 

URS: Field Activities Report for Characterization of Exploration and Production Pit Solids and 

Fluids in Colorado Energy Basins, June 4, 2008. 

US EPA: Exposure Factors Handbook, Volume I - General Factors. EPA 600/8-89/043. USEPA: 

Washington, DC. May, 1989. 
97

Underground Injection Wells f or Produced Water Disposal 

Rick McCurdy 

Chesapeake Energy Corporation 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Introduction 

The Oil and Gas Industry first utilized underground injection as a means of disposing of the 

naturally occurring brine that was often produced along with crude oil and / or natural gas in 

the 1930’s. In 1974, the Safe Drinking Water Act required the U.S. Environmental Protection

Agency (EPA) to set minimum requirements for the brine injection wells utilized by the Oil and 

Gas Industry along with numerous other wells used for disposal of various hazardous and 

nonhazardous wastes. These requirements are generally referred to as the Underground 

Injection Control (UIC) program. Since inception of the UIC program, Class II wells (those wells 

classified for injection of oil and gas liquids including oilfield brine disposal wells) have safely 

injected over 33 trillion gallons of oilfield brine without endangering underground sources of 

drinking water (USDW). 

History of Underground Injection 

During the 1930’s, oil producers first began disposing of the brine produced in conjunction with

crude oil back into the same formation from which it had been extracted. In this same decade, 

the practice of injecting produced brine into a formation in order to push crude oil to an 

adjacent producing well was initiated, thus starting the practice of enhanced oil recovery (EOR). 

In the 1940’s, oil refineries began using deep well injection for disposal of refinery waste and 

several chemical plants followed this trend a decade later. As the practice of brine disposal 

using deep well injection continued to grow, many states began implementing regulations for 

disposal of oilfield brine in the 1950’s. In the 1960’s, documented cases of groundwater 

contamination associated with the underground injection of waste began to surface. Most 

notably, a waste injection well at the Hammermill Paper Company in Erie, Pennsylvania 

suffered a casing failure and pulping liquor escaped into the surrounding ground and into Lake 

Erie. Though never conclusively determined, a black liquid found to be flowing from an 

abandoned oil well approximately five miles from the Hammermill well was believed to be 

pulping liquor from the Hammermill well. 

In response to this and other cases, the U.S. Congress passed the Safe Drinking Water Act in 

1974 and gave the EPA the authority to regulate the underground injection of all wastes in 

order to protect USDW’s. In the following decade, Federal UIC regulations were passed 

establishing five classes of wells that fall under the UIC program and requirements for States or 

tribes to have primary enforcement, or primacy, on their lands. Since its creation, the UIC 

program has been amended to allow for stricter regulations for deep well injection of 
98

hazardous waste and to create a sixth well classification for wells that will be used for geologic 

sequestration of carbon dioxide (CO2).

Primary Enforcement (Primacy) 

As mentioned above, the Federal UIC regulations established the requirements necessary for a 

State or tribe to enforce the program on their lands. In order to assume primacy, the States or 

tribes had to demonstrate their program for UIC enforcement met the minimum requirements 

established by the EPA’s UIC program. Currently, 33 States and three U.S. Territories have 

primacy for all of the UIC wells in their jurisdiction. Seven States, but none of the U.S. 

Territories, share primacy with the EPA, often with a State handling one or more classifications 

of wells and the EPA overseeing the remaining classifications. The EPA maintains primary 

enforcement of the UIC programs in the remaining ten States and three US Territories. 

Well Classification 

Under the Federal UIC regulations, there are currently six different well classifications. 

Class II Wells 

At present, there are approximately 144,000 Class II injection wells in the U.S. Of these, 

roughly 80% are wells used for enhanced oil recovery (EOR). Most prominent of this group are 

water injection wells that re-inject brine taken from a producing formation back into that 

formation in an effort to pressure more crude oil to the producing wells. This subset of Class II

wells also includes wells used to inject steam into formations containing viscous crude and 

wells used to inject various mixtures of gas and / or brine to improve crude production. The 

smallest subset of Class II wells is the wells that are used to inject liquid hydrocarbons into 

underground storage caverns. Most recognizable of this set of wells are those utilized for the 

U.S. Strategic Petroleum Reserve. The remaining Class II wells, approximately 20% of the total, 

are those wells that are used to dispose of the fluids associated with oil and gas production, 

more commonly referred to as saltwater disposal wells. 

Table 7. UIC well classifications 
99

Saltwater Disposal Wells (SWD) 

This special subset of the Class II UIC wells has allowed for the safe disposal of fluids 

associated with oil and gas production since the 1930’s and has a long track record of 

protecting USDW’s under the UIC program. Oil and Gas Companies have come to rely on the 

safe and economic operation of these wells for disposal of the naturally occurring brine that 

often accompanies the production of oil and / or gas. Whenever an Oil and Gas Company or a 

commercial SWD Operator decides to establish a SWD in a new area, the first consideration is 

site selection. 

The surface location of an SWD well is important as it needs to be an area where it is easily 

accessible by Operators who need to dispose of brine from their oil and gas production efforts; 

however, surface location is not the only consideration when selecting a site for the SWD well. 

Additionally, the SWD Operator needs to understand the geology beneath the surface location. 

The first consideration is for a porous and permeable, non-hydrocarbon bearing zone that is not 

considered an aquifer under the UIC program. A previously productive oil and gas zone that is 

now depleted and is porous and permeable is also suitable for brine disposal. In either of these 

options, there must be a clear barrier between the zone of interest and all USDW’s and the area

to be drilled must be relatively clear of any geologic faults. Once the site selection is complete, 

the well may be drilled and completed provided certain minimum requirements in the UIC 

program are adhered to. 

Once drilling commences on the well, the first requirement under the UIC program for the area 

is the depth at which surface casing must be run. Usually, surface casing is run from surface to 

a depth that is several hundred feet beyond the deepest know aquifer in an area. Once surface 

casing is set, cement is circulated into the void between the steel casing and the bored hole, 

forming an impermeable seal across any aquifers. The well is then drilled to the desired depth 

for the zone targeted for disposal. Again, steel casing is run from surface to the total depth of 

the well and cement is circulated into the area between the casing and the borehole from the

bottom of the well to surface, forming another dual layer of protection to isolate the injected 

fluids from any USDW. A cement bond or evaluation log is usually run at this point. The 

cement evaluation log is a sonic tool that can give a 360° interpretation of the quality of the 

cement bond to the casing’s outside diameter. At this point, a special tool is used to open holes

in (or perforate) the casing and cement across the disposal zone. 

Injection tubing (usually internally plastic coated to protect the pipe from corrosion) and a 

packer are run into the well. The packer is a device that seals the annular space between the 

casing and tubing and prevents the fluid being injected via the tubing from coming back up 

hole. The UIC program often dictates the depth at which the packer must be located, but it is 

usually somewhere between 50’and 100’ above the uppermost perforation. After running the 

packer and tubing into the well, a packer fluid is circulated through the tubing and back up the 

annular space to surface before the packer is “set” or activated. Packer fluids serve three 

primary purposes: 1) protect the casing inside diameter and tubing outside diameter from 

corrosive agents, 2) provide a hydraulic fluid to allow for instantaneous notification on the 

surface should the packer leak injection fluid into the annular space and 3) provide hydrostatic 
100

head pressure to help offset the pressure on the bottom of the packer from the injection fluid. 

After the packer is set, UIC regulations require that the mechanical integrity of the injection 

casing and packer seal be tested and verified. This is usually done by applying pressure to the 

annular fluid and using a chart recorder to document that the pressure remains constant in a 

static condition for a period of time (e.g. 30 minutes). Once a well has been placed in service, 

the UIC regulations require that, as a minimum, the wellbore integrity be verified via a recorded 

pressure test once every five years and the normal operating annular pressure be observed and 

recorded once per month. Many of the oil and gas regulating divisions in States with primacy 

have more stringent requirements. In Texas, for example, a recorded pressure test for casing 

integrity (H5 test) must be performed annually on each Class II well. 

The next required step in the UIC process is a step rate test to determine maximum surface 

injection pressure. In a step rate test, a fluid similar to that expected to be injected into the well 

once it is in service is pumped into the well at gradually increasing rates. Each rate is 

maintained for a required period of time, usually either 30 or 60 minutes. Bottomhole pressure 

is recorded during this period. When plotting the dynamic bottomhole pressures for each 

injection rate, the point at which the fracture gradient for the targeted formation is exceeded 

will be seen as an inflection in the slope of the line through the pressure points. After noting 

that the formation has “broken down” or indicated that fracture formation has initiated, 

pumping may be stopped and the instantaneous shut in pressure (ISIP) recorded. Maximum 

surface injection pressure is often set at or just below the ISIP, allowing for hydrostatic head of 

the injected fluid and friction loss in the injection tubing. In the event that formation 

breakdown is not noted in the test, maximum surface injection pressure is usually set to reflect 

the highest pressure seen during the step rate test. UIC regulations generally require that all 

step rate tests be witnessed by a representative for the local UIC administrator. 

After a saltwater disposal well has been properly constructed, the economics of operation often 

complement this time-proven method of brine disposal. For a saltwater disposal well that is 

operated by an Oil and Gas Company for disposal of the brine produced during normal 

operations, the average cost of disposal is often less than $0.25 per barrel of fluid disposed. A 

commercial SWD well will typically charge between $0.50 and $2.50 per barrel of fluid. As with 

most things in life, this price disparity is usually related to supply and demand. In areas where 

disposal wells are plentiful and generally operate below capacity, competition drives the price 

down. In areas where there is a strong demand for brine disposal, but the disposal 

infrastructure has not been developed or the subsurface geology is not conducive to 

underground injection of oil and gas fluids, the commercial operators can receive a premium 

for their services. 

A second cost associated with disposal of oilfield brine is transportation of the brine from 

where it is gathered and stored at the well site to the disposal well. On average, the 

transportation of brine will cost an Operator $1.00 per barrel of brine per hour of 

transportation time. In an area such as the Barnett Shale in North Texas where SWD wells are 

plentiful, brine transportation may only add $0.50 per barrel to the cost of brine disposal. 

Conversely, in northern Pennsylvania, where the nearest commercial disposal well may be in 
101

Ohio or West Virginia, the cost of transportation can easily add $4.00 to $6.00 per barrel to the 

cost of disposal. 

Lastly, in addition to the cost of transportation in this area, an Operator needs to consider the 

wear and tear on local roads from the long distance transportation of the brine along with 

contribution of carbon dioxide emissions from the trucks required to transport the brine. 

Consideration of these three items led Chesapeake Energy to develop our unique Aqua 

RenewTM program to allow for reuse of produced brine from our Marcellus wells. By filtering

and reusing the brine in an upcoming completion, Chesapeake not only reduces the amount of 

fresh water required for the completion, but we can also eliminate seven hours of truck time 

that would have been used to transport brine to an out of State disposal well. This reduction in 

truck transportation of brine will also reduce 52,500 road miles of wear per well and eliminate 

88 metric tons of carbon dioxide emissions per well. 

The subsurface geology in Pennsylvania has not proven to be conducive to brine disposal. To 

date, there are only eight permitted Class II wells devoted to saltwater disposal in the entire 

state. Of these eight, three utilize the Oriskany formation for disposal and two use a 

combination of the Oriskany and Huntersville formations. One well injects into the Balltown 

formation and another the Gatesburg zone. Lastly, the highest disposal volume of the set 

injects into a mine void. As a group, the eight wells account for 8,667 barrels per day of brine 

disposal capacity. By comparison, the Mann #1 SWD well operated by Chesapeake near 

Cleburne, Texas (Barnett Shale) averages 26,000 barrels per day of brine disposed. The Mann 

#1 injects brine into the Ellenburger Formation, a porous strata located 1 1⁄2 miles beneath all 

known aquifers in the area. Tarrant County, of which Fort Worth, Texas is the county seat, has 

more saltwater disposal wells (ten) than the entire State of Pennsylvania. Overall, the State of 

Texas has approximately 12,000 Class II saltwater disposal wells. 

While the overall subsurface geology in Pennsylvania may not be ideally suited to subsurface 

brine injection, Chesapeake did attempt to drill and complete a Class II well in the Trenton / 

Black River formations. Originally budgeted for three million dollars, ultimate capital spent on 

this well was just under seven million dollars and numerous tests indicated very limited brine 

uptake capacity. A permanent bridge plug was set above the targeted formations and the well 

was temporarily abandoned. 

Reclamation / Disposal Combinations 

In areas where disposal opportunities are limited or disposal capacity in a given well is less than 

plentiful, it may be advantageous to utilize some form of water reclamation upstream of the 

disposal well. Of the reclamation systems available to the industry, all have differing costs and 

efficiencies associated with brine concentration and some are limited in consideration by 

organics or the total dissolved solids concentration of the fluid to be treated. To an Operator, 

another key consideration is whether the unit produces a distilled water or water vapor. If it is 

distilled water and the unit is east of the 98thMeridian, the distilled water must be trucked 

back to a completion location to be used in an upcoming stimulation. A provision of the Clean 
102

Water Act allows Operators to request permission from the EPA to surface discharge treated 

produced fluids for the beneficial use of agriculture or for wildlife propagation – provided the 

discharge location is west of the 98th Meridian. If discharge of treated water is not allowable 

and available water resources are abundant, a reclamation system that produces water vapor 

while concentrating the brine for disposal will save road wear and reduce carbon dioxide 

emissions from truck traffic. 

By concentrating the brine prior to disposal, these units may make economic sense in area 

where disposal capacity is limited. If the produced brine chemistry allows for recovery of 75% of 

the treated water volume as vapor, the remaining brine volume will be reduced by a factor of 

four. Reclaiming this fluid prior to disposal allows for a disposal site that has a maximum daily 

capacity of 500 barrels of water to process 2,000 barrels of fluid per day. Of the processed 

2,000 barrels, 1,500 are returned to the water cycle as vapor and the remaining 500 barrels of 

concentrated brine are sent down the Class II disposal well. 

Chesapeake Energy is trialing such a unit at our Brentwood disposal site just east of downtown 

Fort Worth. Two EVRAS (evaporative reduction and solidification system) units manufactured 

by Layne Christensen’s Intevras Division utilize waste heat from the Ark Park compressor site to 

treat 1,200 barrels per day of produced water. Of these 1,200 barrels, roughly 700 are 

evaporated as water vapor. The result is that the initial 1,200 barrels are concentrated down to 

500 barrels before injection into the Brentwood SWD well. Though not economically 

favorable to the standard Barnett Shale practice of straight disposal of oilfield brine, the 

Brentwood application allows us to properly test out application of the technology for other 

areas. 

Conclusions 

 The Oil and Gas Industry has utilized underground injection of brine since the 1930’s 

and Class II UIC wells currently inject two billion gallons of fluid per day for enhanced oil 

recovery, disposal and storage. 

 Wells used exclusively to dispose of fluids from oil and gas production account for 20% 

of the 144,000 Class II Wells in the U.S. 

 Brine disposal in Class II wells is safe, environmentally sound and is the most 

economically viable option in most areas. 

 In areas of limited disposal capacity or where water resources are stressed, reuse of 

produced brine is proving to be an effective alternative to underground injection. 
103

Wastewater from Gas Development: Chemical Signatures in the 

Monongahela Basin 

Paul Ziemkiewicz, PhD 

West Virginia University 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

The West Virginia Water Research Institute began monitoring the Monongahela River and its 

major tributaries in July 2009 after reports of increasingly high dissolved solids concentrations 

in the River near Pittsburgh in the late summer of 2008. A sampling network of sixteen stations 

was established extending from mile 23 at Elizabeth PA to the Rivers two major sources, the 

Tygart and West Fork Rivers. Based on earlier surveys by the Pittsburgh District, US Army Corps 

of Engineers and PaDEP, the chemical constituents of interest were determined to be: sodium, 

sulfate, chloride, calcium, magnesium and alkalinity. Total dissolved solids (TDS), iron, 

aluminum and manganese were also determined in the laboratory. Field parameters including 

pH and electrical conductivity were also measured. It was decided that loadings were needed in 

order to identify significance of the various ion sources so sampling stations were located near 

gauges where possible and flows were estimated in non-gauged streams. Sampling took place 

every two weeks, data were compiled and results placed on a publicly available website: 

monWQ.net. 

While sampling made no assumptions as to the sources of the high TDS readings we suspected 

that two sources would predominate: treated coal mine discharges and brines from the gas 

industry. The former were easy to characterize as the coal mine discharges are regulated under 

the NPDES program of the Clean Water Act. Brines are not. Streams dominated by coal mine 

discharge were characterized by sodium sulfate as the dominant ions. Brines are characterized 

by sodium chloride and three streams in Pennsylvania: the Youghiogheny, Ten Mile Creek and 

Whiteley Creek show a distinct sodium chloride signature suggesting heavy brine loadings. So, 

after 20 months it is possible to identify the major sources of TDS and their chemical signatures. 

The results also indicate seasonality with respect to higher TDS concentrations during low flow 

periods. This has led to a successful program with the coal industry whereby pumping rates are 

restricted during sensitive, low flow periods in late summer and fall with corresponding, higher 

discharges during high flow periods. As a result, the data show substantially reduced TDS

concentrations on the Monongahela River since adoption of the managed discharge program in 

December 2009 and our data show no instances of TDS concentrations exceeding 500 mg/L on 

the Monongahela since December 2009. 

The presentation focuses on major ion loadings and concentrations in the Monongahela River 

and its tributaries, the relative contributions of the major ions to TDS and their proportional 

contribution per tributary. 
104

Revisiting the Major Discussion Points of the Technical 

Presentation Sessions

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use. 

John Veil of Veil Environmental, the workshop lead noted that local issues may be more 

important than overall water availability in most shale plays. He suggested that with 

appropriate planning, the available water can accommodate most needs. In addition, he 

suggested saline ground water, surface water, and reused water are often viable alternative 

options to fresh ground water, and as technologies advance, some of these options will become 

more widely adopted. He emphasized that technology is also allowing HF to become more 

water efficient; operators are using larger well pads with more wells and more stages, resulting 

in less required water per unit of gas produced. Mr. Veil noted that it is important for all parties 

to be aware of the actual costs and prices of procuring, treating, recycling and disposing of 

water. Mr. Veil mentioned the success story of operators switching to surface water in 

Louisiana, as well as the challenges posed by landowner relations in the Eagle Ford. He 

encouraged all of the participants to continue to participate in the discussion and noted that 

regulatory and policy issues will continue to affect energy production and water use. 

Gary Hanson of Louisiana State University – Shreveport, the Water Use and Sustainability 

theme lead, described his experience working in multiple sectors and noted that even agreeing 

upon common units for water use (e.g., acre feet, gallons) can be a challenge. He also noted 

that while the oil and gas industry is a business with financial incentives, the last two years have 

seen significant improvements in the way the industry addresses water use issues on a stateby-state basis. In addition, he noted that the industry has been rapidly adapting and improving 

their technologies, recognizing the potential benefits of using high-saline water in fracturing 

fluids. Mr. Hanson concluded that water will be a very important issue in the future and there 

will continue to be advances in technologies using reclaimed or recycled water. 

Tom Hayes of the Gas Technology Institute, the Flowback Recovery and Water Reuse theme 

lead, reiterated the definitions of flowback and produced water, and he summarized the main 

points of the presentations and discussions. The presentaters emphasized the variability of 

different plays and the necessity of tailoring water management to the specific characteristics 

and challenges of each unique play. He stated that many operators are currently streamlining 

and simplifying approaches to water management as new industry standards are developed. He 

concluded by noting that a number of innovations are facilitating the development of new 

concepts in water management, including continuing adaptation of water treatment 

technologies, new well pad design options, pipeline conveyance, and a variety of water storage 

options.
105

Matthew Mantell of Chesapeake Energy Corporation, the Disposal Practices theme lead,

summarized the main discussion points from the Theme 3 technical presentations. He noted 

that treatment involves moving contaminants from one phase to another and introducing 

different disposal issues. He stated that a number of innovative technologies have been 

developed, but availability is still a limiting factor. He suggested that Underground injection 

wells are currently the most popular disposal method due to economic and practical 

considerations. Mr. Mantell also noted that in areas such as Pennsylvania, where there are 

large numbers of abandoned wells and mines, ground water monitoring is essential. He stated 

that the example of high TDS levels in the Monongahela River in 2008 and the subsequent 

study tracing the source of salinity underscores the need for monitoring. He remarked that the 

study’s perspective on Dunkard Creek and other tributaries to the Monongahela illustrates that 

what may become the focus of the news media is not always the real issue. 

Bob Puls of U.S. EPA, the Hydraulic Fracturing Study Technical Lead, thanked the participants in 

the workshop for their contributions. The presentations and discussion were very useful to EPA 

and will inform the way that the study is developed. Dr. Puls summarized key points made by 

the presenters. First, he noted that it is important to understand how water availability in 

different regions may affect the potential impacts of water withdrawal. Second, he noticed that 

there were many presentations on reuse of produced water. He noted that the field has 

changed in this area in just one year and that more meetings on this issue could be a good idea 

due to the quick changes in industry and concern for environmental protection. Dr. Puls noted 

that some presentations suggested that the salts in produced water might be beneficial for 

injection, and using recycled water for injection could reduce costs with little to no impact on 

production efficiency. He also noted that some presentations advised that there are significant 

differences between regions in that some formations are more consistent regarding volume 

and quality of produced water, and other formations are more variable. It was also noticed in 

the presentations that there are differences in formation chemistry, in treatment and disposal 

options, and in the regulations in different states. Dr. Puls observed that some of the presenters 

expressed concern that reusing produced water is potentially not only an issue of water 

availability and cost considerations, but also of community and public concerns. Dr. Puls 

concluded by thanking the leaders and organizers of the workshops. 
106

Poster Abstracts 

Posters were submitted to US EPA for display during the technical workshops. Authors also 

submitted poster abstracts for use in this proceedings document. 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA. Any mention of trade 

names or commercial products does not constitute endorsement or recommendation for use.
107

Chemical Transformations of 2, 2-Dibromo-3-nitrilopropiamide 

Uni Blake

MajiTox for Gastem USA 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

Introduction 

As a part of determining the potential extent of the impact of a chemical on a target receptor, 

exposure pathways and the environmental fate of the contaminant of concern (COC) need to 

be addressed. Predictive modeling of the exposure pathways can be used to determine how the 

anthropogenic chemical moves through the environment and how the chemical would 

effectively avail itself to receptor response. Potential COC that result from chemical 

transformations are also used in the modeling process. 

This abstract briefly describes the various potential chemical transformations of 2, 2-Dibromo3-nitrilopropiamide (DBNPA) during the well stimulation process to determine if other COC can 

result from the chemical transformation of the biocide and also potentially act contiguously 

with DBNPA. 

Background 

2, 2-Dibromo-3-nitrilopropiamide has been used commonly as a non-oxidizing biocide; mostly 

in cooling water systems. In this known use, it has been regulated safely under the National 

Pollution Discharge Elimination System. The biocide is used commonly because of its ability to 

hydrolyze completely into benign components. In modeling systems of 2, 2-Dibromo-3-

nitrilopropiamide reactions, the pH and temperature effect, down-hole resident time, bacteria 

kill rate, exposure to microbial time and the original biocide concentration can all be shown to 

have an impact on the concentration of biocide at discharge. Therefore, to understand 2, 2-

Dibromo-3-nitrilopropiamide reactions during the hydraulic fracturing process, different 

potential reaction scenarios that can affect discharge concentrations are looked at. 

Down hole 

Conditions: 







elevated temperatures of 120-150 °F 

high pressure 

potential of presence of unspent acid 

Under the above conditions, DBNPA will be expected to undergo complete hydrolysis. 
108

Transformation in the Environment 

Reactions in Soil 

These types of reactions would be the result of potential surface spill. 

Reactions: 









Biodegradation by microorganisms in the soil 

Adsorption 

Chemical degradation 

Hydrolysis

DBNPA is expected to disappear faster in soil than in surface water mostly due to chemical or 

microbial degradation (note: if DBNPA is available in concentrations below the inhibitory levels 

of the microbes). Chemical degradation may also be due to reactions with natural occurring 

sulfites or bisulfites. Degradates found include dibromoacetic acid and 2-cyanoacetamide which 

will most likely be biodegraded within 30 days. 

Reactions in Surface Water 

This scenario would be based on a potential surface water spill. 

Reactions: 





Photolysis 

hydrolysis 

Potential degradates include cyanoacetic acid, cyanoacetoamide, malonic acid and oxalic acid. 

Having relatively short half-lives, most of these products will disappear. The most stable is 

dibromoacetic acid (1/2 life of 300 days at 25°C days). However, DBAA is less toxic on aquatic 

life than DBNPA. Oxalic acid will decarboxylate to carbon dioxide. 

Figure 14. Hydrolytic Degradation Pathway for DBNPA (Williams et al., 2010)
109

Reactions During Flowback Storage 

Potential reaction in the storage tank of unspent DBNPA would be pH and resident dependent. 

Figure 15. Reaction with DBNPA with nucleophiles and sunlight (Williams et al., 2010)

Figure 16. pH profile for the hydrolysis of DBNPA at 

25°
110

pH r1/2 Temp °C 

3.9 2,140 23

6 155 25

6.7 37.0 25

7.3 8.8 25

7.7 5.8 25

7.7 145 0 

8.0 2.0 25

8.9 0.34 25

9.7 0.11 25

9.7 1.5 0 

Table 8. Rates of Hydrolysis of DBNPA 

Potential products of the incomplete hydrolysis of the biocide in water include 

dibromoacetnitrile, dibromoacetic acid, tribromoacetonitrile, and tribromoacetoamide. 

Wastewater Treatment 

Unspent biocide can be deactivated prior to treatment using a reducing agent, however 

according to literature (Tamblin, 2010), flowback waters from the Marcellus Shale were tested 

for toxicity prior to the POTWs acceptance of flowback and it was determined that the flowback 

did not have significant biocide concentrations to impact the function of the wastewater 

treatment plant. 

Conclusion 

According to this evaluation of the reactions and the chemical transformations of DBNPA during 

and after the process of the well stimulation, it does not appear that the biocide will persist in 

the soil after a potential spill or aquifer communication with flowback fluids. This can be 

concluded by 2, 2-Dibromo-3-nitrilopropiamide’s ability to hydrolyze and biodegrade rapidly in 

the soil. 

In the event of a potential spill on surface water, at the lower concentrations of DBNPA found 

in flowback, it can be expected that the biocide would degrade rapidly (half-life of less than 5 

hours) due to hydrolysis and photolysis. 

The next step of the assessment would be to perform a toxicity assessment to determine 

carcinogenicity on some of the more persistent biocide degradates and then determine their 

exposure. 

References 

Exner J. H., Burk G. A. and Kyriacou D. “Rates and products of decomposition of 2,2-dibromo-3- 

nitrilopropionamide” , 1973 J. agric. Fd Chem. 21, 838- 842

Terry M. Williams, “Deactivation of Industrial Water Treatment Biocides”. The Dow 

Chemical Company; Heather R. McGinley, The Dow Chemical
111

Stephen Klaine, George Kobb, Richard Dickerson, Kenneth Dixon, Ronald Kendall, Ernest Smith, 

Keith Solomon “An ecological risk assessment for the use of the biocide, DBNPA, in 

industrial cooling towers”. 1996. Environmental. Toxicology and Chemistry 15: 21-30

Michael E. Tamblin. One POTW's Acceptance of Hydrofractured Water Clear Water, Winter 

2010, Vol. 40, No. 4 pgs. 40-43

Kargbo D. M, Wilhelm R. G, Campbell D. J. “Natural gas plays in the Marcellus Shale: challenges 

and potential opportunities.” Environ Sci Technol. 2010 Aug 1;44(15):5679-84.
112

Shale Gas Development and Related Water-Resource Investigations 

in New York State –Cooperative Projects to Promote Public 

Understanding 

William Kappel 

US Geological Survey, New York Water Science Center 

The statements made during the workshop do not represent the views or opinions of EPA. The 

claims made by participants have not been verified or endorsed by EPA.

The U.S. Geological Survey (USGS), in cooperation with various partners, is performing water 

resource studies and continue to develop projects to collect, analyze, and provide waterresource information to New York State agencies, the residents of the State, the gas industry, 

and others to understand, protect, and promote the transparent and sustainable use of the 

Nation’s water resources.

Current projects include valley-fill aquifer mapping and hydrogeologic characterization in the 

Southern Tier counties of New York and recurring ambient ground-water quality assessments 

throughout the State as part of the USEPA/New York State Department of Environmental 

Conservations (NYSDEC) 305-(b) water quality program. USGS has also assisted the 

Susquehanna River Basin Commission (SRBC) in their implementation of a real-time stream 

water-quality program in the Upper Susquehanna River Basin in both New York and 

Pennsylvania. These programs build on over 100 years of unbiased geologic and hydrologic data 

collection and interpretation by the USGS. 

Two USGS reports have recently been released which are quite useful to State regulators, the 

gas industry, and the general public in understanding surface water characteristics and 

estimating availability of low-flow in the Susquehanna River Basin in New York - “Low flow of 

streams in the Susquehanna River basin of New York” by A. D. Randall, 2010, U.S. Geological 

Survey Scientific Investigations Report 2010-5063, 57 p. Relating to groundwater quality and 

the Marcellus shale, the location of the fresh water/ salt water interface in the Southern Tier of 

New York was reported in – “Evaluation of well logs for determining the presence of freshwater, 

saltwater, and gas above the Marcellus Shale in Chemung, Tioga, and Broome Counties, New 

York, by J.H. Williams, 2010, U.S. Geological Survey Scientific Investigations Report 2010-5224, 

27 p. 

Pending projects include “Hydrogeologic Characterization and Water-Quality Assessment in 

Relation to Marcellus and Utica Shale Gas Development in Otsego County, New York”. This 

project will involve the gas industry, Otsego County agencies, one or more local universities, 

several State agencies, and the USGS to characterize the surface and groundwater resources of 

Otsego County through the sharing, compilation, and distribution of several sources of 

information from existing and newly-collected water quality and geologic data. This pilot study 
113

will serve as the basis for an anticipated state-wide, shared database of information available 

for all to utilize during and following the production of shale gas resources in New York State. 

The project would utilize 1.) water well and gas well information collected by the State and the 

gas industry, 2.) geologic information mapped by the New York State Geological Survey which 

would be enhanced by the collection of new geologic data during the drilling of gas wells and 

water wells throughout the County, 3.) the evaluation of surface and ground water-quality data 

that currently exist and the addition of new water-quality data collected before, during, and 

following gas well drilling, hydrofracking, and long-term gas production, and 4.) the collection 

and utilization of natural gas ‘fingerprinting’ (isotopic gas analysis), to identify thermogenic 

sources of natural gas (old gas) that exist in the bedrock of New York, as well as other (newer) 

sources of natural gas, such as “swamp gas”, landfill gas, and gas found in unconsolidated 

glacial deposits “drift gas”.

Another project would document historic water-quality data collected by the USGS to serve as a 

retrospective assessment of stream water-quality parameters – primarily specific conductance 

and total dissolved solids and chloride data, where available, from the USGS National Water 

Information System (NWIS) database. The specific conductance data would serve as a baseline 

to compare current and future surface-water conditions. This study would be enhanced by 

targeted programs to collect current specific conductance data in New York streams to confirm 

and update the previous dataset, as well as studies being carried out by other agencies, for 

instance, the Susquehanna River Basin Commission. The SRBC currently provides near-real-time 

water quality data for about 40 selected small and large watersheds throughout the shale-gas 

region of New York and Pennsylvania within the Susquehanna River watershed. 

All of these projects provide various water and geologic resource information which is critical in 

understanding existing hydrogeologic conditions in New York. These projects would serve 

numerous water-resource agencies, regulators, the gas industry, and the residents of New York 

by providing this information to understand and properly protect and manage the use of these 

resources, as well as increase our ability to evaluate impacts during the long-term development 

and production of shale gas in New York State. Without these data, stakeholders are missing 

key information required for the clear understanding and proper management of New York’s 

surface and groundwater resources, and how shale gas development may or may not impact 

these resources. 
114

Glossary of Terms 

The sources of the definitions found in this glossary are noted at the end of each definition. 

Sources include the following: 

 

Abbreviated Source Full Source Name 

SPE Society of Petroleum Engineers Exploration & Production 

Glossary (http://www.spe.org/glossary/wiki/doku.php/) 

Schlumberger Schlumberger Oilfield Glossary 

(http://www.glossary.oilfield.slb.com/default.cfm) 

ABBREVIATIONS

2-BE 2-butoxyethanol 

AEM anion exchange membranes 

AF acre-feet 

ASTM American Society for Testing and Materials 

ASWCMC Appalachian Shale Water Conservation and Management Committee 

ATSDR Agency for Toxic Substances and Disease Registry 

bbls barrels 

Bcf billion cubic feet 

BCF billion cubic feet 

BEM beneficial use economic module 

BLM Bureau of Land Management

BOPD barrels of oil per day

BPM barrels per minute 

BSM beneficial use screening module 

BSWCMC Barnett Shale Water Conservation and Management Committee 

BSWMC Barnett Shale Water Conservation and Management Committee 

BTEX benzene, toluene, ethylbenzene, and xylene 

CAE chemicals for analytical evaluation 

CDI capacitive deionization

CEM cation exchange membrane 

COC contaminant of concern 

COGA Colorado Oil and Gas Association 

COGCC Colorado Oil and Gas Conservation Commission 

DAF dilution attenuation factor 

DBNPA 2, 2-dibromo-3-nitrilopropiamide 

DOE US Department of Energy

E&P exploration and production

ED electrodialysis 

EDI electrodeionization

EDR electrodialysis reversal 

ESP electric submersible pumps 

EVRAS evaporation reduction and solidification system 

FO forward osmosis 

GIS geographic information system 

HDPE high density polyethylene 
115

HF hydraulic fracturing 

HRB Horn River Basin 

ISIP instantaneous shut in pressure 

IX ion exchange 

LSU Louisiana State University 

MD membrane distillation 

MF microfiltration 

MGD million gallons per day 

MLE maxiimum likelihood estimator 

MMCF million cubic feet 

MMCFD million cubic feet per day 

MSC Marcellus Shale Coalition 

MSDS Material Safety Data Sheets 

MVR mechanical vapor recompression

NORM naturally occurring radioactive material 

O&G oil and gas 

PADEP Pennsylvania Department of Environmental Protection 

PAH polynuclear aromatic hydrocarbons 

PCB polychlorinated biphenyls 

POTW publicly-owned treatment works 

PP polypropylene 

PTFE polytetrafluorethylene 

PVDF polyvinylidenedifluoride 

RBCA risk-based corrective action 

RCRA Resource Conservation and Recovery Act 

RO reverse osmosis

RPSEA Research Partnership to Secure Energy for America 

RRAA Red River Alluvial Aquifer 

RRC Texas Railroad Commission 

RRERP Red River Education & Research Park 

SAB Science Advisory Board

scf/d standard cubic foot per day 

SRBC Susquehanna River Basin Commission 

SWD saltwater disposal well 

TAL target analyte list 

TCEQ Texas Commission on Environmental Quality 

TCLP toxic characteristic leaching procedure 

TDS total dissolved solids 

TEPH total extractable petroleum hydrocarbons 

TIC tentatively identified compound 

TOC total organic carbon 

TSM treatment selection module 

TSS total suspended solids 

TWDB Texas Water Development Board 

UF ultrafiltration 

UIC Underground Injection Control 

USACE United States Army Corps of Engineers 

USGS United States Geological Survey 

WEWG Water Energy Working Group 

WQM water quality module 

WRCNL Water Resources Committee of Northwest Louisiana 

WVDEP West Virginia Department of Environmental Protection
116

GLOSSARY

acre-foot 1 acre-foot of water = 325,851.4 gallons or 10,344.5 barrels 

connate water the natural brine occupying the pore spaces. Usually this water is at equilibrium with the minerals 

in the formation. (SPE) 

evaporite a formation formed by the evaporation of water from shallow seas. Very low permeability. (SPE) 

flowback The process of allowing fluids to flow from the well following a treatment, either in preparation for a 

subsequent phase of treatment or in preparation for cleanup and returning the well to production. 

(Schlumberger) 

kerogen An initial stage of oil that never developed completely into crude. Typical of oil shales. (SPE) 

pig a flow line clearing device, pumped through the line with normal flow. (SPE) 

produced water A term used to describe water produced from a wellbore that is not a treatment fluid. The 

characteristics of produced water vary and use of the term often implies an inexact or unknown composition. It 

is generally accepted that water within the pores of shale reservoirs is not produced due to its low relative 

permeability and its mobility being lower than that of gas. (Schlumberger) 

Note: The term produced water is sometimes used synonymously or interchangeably with flowback. 

slick water a water base fluid with only a very small amount of a polymer added to give friction reduction benefit. 

(SPE) 

sweet absence of hydrogen sulfide, H2S. (SPE) 
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