MEMORANDUM

TO: Lisa Biddle, US EPA/OW/EAD

Brian D’Amico, US EPA/OW/EAD

FROM: Brent Ruminski, ERG

DATE: 27 November 2012

SUBJECT: 2012 Shale Gas Water Management Conference Notes

On October 29 through 31, ERG attended the 3

rd Water Management for Shale Gas Plays

Conference in Pittsburg, PA. This memorandum summarizes information presented at the 

conference. The remainder of this memorandum includes the following topics:

 Section 1 describes general information on wastewater management and handling 

practices;

 Section 2 describes emerging information on wastewater treatment technologies; and

 Section 3 describes current and emerging trends of shale gas development across 

various shale plays.

Table 1 lists the presentations that ERG referenced in this summary. Attachment 1 

provides all presentations ERG downloaded from an FTP site.
Memorandum

27 November 2012

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Table 1. Presentations Referenced at the 2012 Water Management for Shale Plays

Reference Attachment DCN Presenter Name and Affiliation Presentation Title

Day 1

Eichler, 2012 SGE00310.A01 Eichler, PA DEP Pennsylvania Department of Environmental Protection’s 

Perspective on Water Management in the Marcellus and Utica

Slagel, 2012 SGE00310.A02 Gary Slagel, Consol Energy Inc. Staturtory & Regulatory Review Pennsylvania, West Virginia, 

and Ohio

Heath, 2012 SGE00310.A03 Jason Heath, ORSANCO Marcellu & Utica Shale Plays: Water Issues in the Ohio River 

Basin

Lewis, 2012 SGE00310.A04 Tom Lewis, Lewis Environmental Services Production & Frac Water Recycling Trends and Future 

Requirements

Wilson, 2012 SGE00310.A05 Craig Wilson, KLGtest Water Acquisition and Wastewater Disposal in Ohio’s Utica 

Shale Play

Hughes, 2012 SGE00310.A06 Stephen Hughes, Tetra Tech, Inc. The Briefing Assessing Specific Shale Plays: Utica Play

Warlick, 2012a SGE00310.A07 Don Warlick, Warlick Energy Water Management for Shale Plays: An Overview of the 

Bakken Shale

Landenberger, 2012 SGE00310.A08 James Ladenberger, Barlett & West Water Issues Relative to the Bakken in North Dakota

Warlick, 2012b SGE00310.A09 Don Warlick, Warlick Energy Water Management for Shale Plays: An Overview of the 

Niobrara Shale

Carlson, 2012 SGE00310.A10 Kenneth Carlson, Colorado State University Assessing Specific Shale Plays: Niobrara

Sloan, 2012 SGE00310.A11 Robert Sloan, Greenhunter Energy, Inc. Eagle Ford, Barnett, and Permian Plays

Day 2

Lucey and McGinns, 

2012a

Not available John Lucey, Heckmann Corporation

Bob McGinnis, Bear Creek Engineering

Strategies for Minimizing the Amount of Water Needed On-site 

for Fracking

Meril, 2012 SGE00310.A12 Les Meril, 212 Resources 212 Resources

Pettengill, 2012 SGE00310.A13 Ron Pettengill, Epiphany Solar Systems

John Owisiany, Consol Energy, Inc.

Innovative Water Management Strategies for Future Marcellus 

Development
Memorandum

27 November 2012

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Table 1. Presentations Referenced at the 2012 Water Management for Shale Plays

Reference Attachment DCN Presenter Name and Affiliation Presentation Title

Zamora, 2012 SGE00310.A14 Frank Zamora, Trican Well Service How to Assess, Select and Develop the Optimal Water 

Management System

Tinto, 2012b Not available Joeseph Tinto, GE Water & Process 

Technologies

Using Mobile Water Treatment Systems to Process Frack 

Water

Hoopes, 2012 SGE00310.A15 Jonathan Hoopes, Greenhunter Energy, Inc. Storing Water On-site to Reduce Transportation Costs and 

Maximize Efficiencies

Bruff, 2012 SGE00310.A16 Matthew Bruff, Altela, Inc AltelaRain: Pressure-less, Multiple-Effect Thermal Distillation

Cathey, 2012 SGE00310.A17 Robie Cathey, Ecosphere Tech Ecosphere

Eltomi, 2012 SGE00310.A18 Sam Eltomi, Sabre Energy The Application of Chlorine Dioxide in Frac Water Treatment 

Using Multi Stream Reuse Water

Day 3

Ritts, 2012 SGE00310.A19 Dean Ritts, Worley Parsons Estimating Hazardous Air Pollutant (HAP) and VOC 

Emissions for a Flowback/Produced Water Treatment Plant

Kozora, 2012 SGE00310.A20 Chuck Kozora, Aquatech International 

Corporation

Treatment of Abandoned Mine Drainage (AMD) for Beneficial 

Reuse

Campana, 2012 Not available Edward Campana, Countryside Ventures, 

LLC

Energy Sources for Shale Wastewater Treatment in the 

Marcellus

Mastowski, 2012 SGE00310.A21 Ryan Mastowski Maximizing Efficiency and Safety When Moving Water

Themaat, 2012 SGE00310.A22 Johan Themaat, High Sierra Water Services Water Infrastructure Versus Mobile Options for Treating and 

Disposing Fracking and Produced Water

Skoff, 2012 SGE00310.A23 Dale Skoff, Tetra Tech Disposal Wells: An Assessment of Available Wells and 

Facilities

Poekes, 2012 SGE00310.A24 Drew Poeckes, West Dakota Water Developing the Infrastructure to Transport and Store Water 

Fracking

a—These presenters held an open discussion rather than providing a presentation.

b—This presenter did not upload a presentation to the FTP site.
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1. General Information on Wastewater Management and Handling

 Underground injection (Skoff, 2012)

o 30,000 injection for disposal wells nationwide.

o Difference between “disposal well” and “commercial disposal well” is that 

disposal wells are privately owned and are generally smaller in capacity. 

o Although operating disposal wells may be less expensive long term, there is 

higher risk involved compared to using a commercial disposal well (e.g., seismic 

activity, spills, blowouts). 

o Costs

 Commercial disposal: $3.50/bbl.

 Skoff (2012) provided general disposal well costs that were not specific to 

a one area but was discussed with other Marcellus topics. See Table 1.

Table 1. General Underground Injection Well Costs for 

Disposal Well Operators

Capital 

Costs

Operating Costs 

per Year

Approximate Cost per Barrel by 

Capacity

500 bbl/d

($/bbl)

1,000 bbl/d

($/bbl)

2,000 bbl/d

($/bbl)

500,000 150,000 1.41 0.71 0.35

1,000,000 150,000 1.67 0.83 0.42

1,500,000 150,000 1.92 0.96 0.48

2,000,000 150,000 2.18 1.09 0.54

Source: Skoff, 2012

 Reuse (Lucey and McGinns, 2012)1

o McGinns (2012) explained that liquid rich plays require more complicated 

chemistry in fracturing fluid including larger proppants. In order to carry larger 

proppant, the fluid requires gels to help with viscosity. In general, the use of gels 

requires higher quality base fluid (McGinns, 2012). 

o Lucey (2012) argued that gel fracturing fluids are starting to allow the use of 

“dirtier” water.2 He knows some operators who have successfully completed gel 

fracturing jobs with 40 percent wastewater as a base fluid.

o Source water and wastewater management is currently 10 to 13% of the total cost 

for the average shale well which creates a good opportunity for operators to save 

 

1 These presenters did not provide a presentation. 

2 The presenter explained that “dirtier” means higher TDS but with a more consistent quality. 
Memorandum

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through reuse strategies. However, the presenters did not break down what is 

included in “total cost.”

 Water Transportation 

o Trucking (Poekes, 2012)

 Truckers charger $120 per hour for 120 bbl load. 

 Estimated reconstruction costs for public roadways per mile traveled for 

each bbl of water trucked is $0.04/bbl/mile (see footnote for 

assumptions).

3 Operators pay these costs back through taxes.

 Storage 

o General cost of storing wastewater in 500 bbl fracturing tanks over the course of 

one fracturing job (Zamora, 2012). However, he did not provide the underlying 

assumptions such as cost per day per tank and the exact length of the fracturing 

job.

 8 tanks: $0.33/bbl

 9 tanks: $0.37/bbl

 20 tanks: $0.83/bbl

o Poekes (2012) provided a basic equation used to determine the capacity of storing 

freshwater onsite for fracturing when a pipeline is used to bring freshwater onsite. 

The inflow rate is the flow rate capacity of the pipeline (typically 25 bbl/min). 

 

 

 

o Freshwater pipeline (Poekes, 2012)

 Poekes (2012) presented on the design of a hypothetical pipeline located 

in Southwest North Dakota servicing 80 wells and 10 miles long.

 Breakdown of capital costs

o 10” pipeline with a 25 bbl/min capacity costs 

approximately $17/foot

o Right away for piping: $32,000/mile

o 10 miles of pipeline (52,800 feet): $897,600

o Booster pumps: $300,000

o 10 miles of right of way: $32,000

o Total upfront capital cost: $1,517,600

 Capital repayment costs depend on how many wells you can fit in 

the 10 miles, which varies on spacing requirements. Table 2

provides the economics of a hypothetical project as a function of 

the number of wells served with the capital costs described above.

 

3 Cost estimate based on reconstruction costs of a roadway with a rating of 750,000 Equivalent Single Axle Loads 

(ESAL) at a cost of $1,250,000 per mile according to North Dakota DOT. The average water truck uses 2.87 EASLs 

(40 ton truck for 100 bbl capacity). 
Memorandum

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Table 2. Freshwater Pipeline Economics

Parameter

1280 Acre 

Spacing

320 Acre 

Spacing

Number of wells services by pipeline 20 80

Capital repayment costs ($ per barrel) $0.95 $0.23

Estimated Operational costs ($ per barrel) $0.05 $0.05

Source: (Poekes, 2012)

2. Emerging Wastewater Treatment Technologies

 Chemical treatment and filtration

o Treatment vendor: Enviro-Shale Process (ESP) (Lewis, 2012)4

 Technology uses pretreatment to remove oil and grease followed by a 

proprietary activated carbon filter to remove soluble organic and inorganic 

constituents.

 Estimated treatment cost of $5.00/bbl. 

 Only conducted pilot testing in Marcellus.

 Performance data available for produced water with 138,000 to 306,000 

mg/L TDS (percent removal): 

 TDS: 14%

 Carbon Dioxide: 71.6%

 Iron: 99.9%

 Chloride: 18.5%

 Barium: 72.1%

 Strontium: 22.0 %

 Calcium: 6.2%

 TOC: 69.0%

o Treatment facilities: High Sierra Energy, LP (Themaat, 2012)

 Actively expanding operations in the Niobrara.

 Have two areas with activity

 Anticline (Wyoming, Pinedale tight gas)

o Treats oil and gas wastewater for reuse or surface water 

discharge using chemical treatment and reverse osmosis. 

Approximately 75% of influent is treated for reuse. 

Approximately 25% is discharged.

 

4 More information on Enviro-Shale is available online at: http://lesvc.weebly.com/enviro-shale-technology.html 
Memorandum

27 November 2012

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o 60,000 bpd reuse capacity

o 20,000 bpd discharge capacity

o 19 miles of pipeline for delivery from operators

o Also operate several disposal facilities

 DJ Basin (Colorado, Niobrara shale gas)

o Treats oil and gas wastewater for reuse only

o 10,000 bpd capacity

o Second plant constructed and opening soon

o Also operate several disposal facilities

 Advanced Oxidation

o Treatment vendor: Ozonix® (Cathey, 2012)

 Treats a mixture of source water and wastewater prior to fracturing a new 

well. Simplifies chemistry required on next fracturing job by reducing or 

eliminating the need for biocide.

 No waste stream

 Can continuously treat up to 3,360 gpm during fracturing. 

 Have treated 51 million bbls of flowback and produced water in the 

Fayetteville, Woodford, and Permian Basins from 610 wells.

 Evaporation/Condensation

o Treatment facilities: AltelaRain (Bruff, 2012)

 Bringing two new plants into the Marcellus (PA):

 CARES5: This plant is constructed at the McKean County (PA)

Landfill and uses landfill gas to power the evaporator. The 

concentrate is buried in the landfill instead of being hauled to an 

injection well. Facility may evaporate up to 2,400 bpd of 

wastewater but is also equipped to chemically treat up to 10,000 

bpd. 

 CAES6: This facility is located in Clarion County, PA and may 

evaporate up to 2,400 bpd of wastewater but is also equipped to 

chemically treat up to 10,000 bpd.

o Treatment facilities: 212 Resources (Meril, 2012)

 Currently treats tight gas wastewater in Colorado and discharges to surface 

water.

 

5 More information on the CARES plant available online at: http://www.caresforwater.com/. 

6 More information on the CAES plant available online at: http://caeswater.com/ . 
Memorandum

27 November 2012

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 Currently permitted in the state of ND to treat Bakken shale wastewater 

but does not have a contract in place with any operators.

 New centralized evaporation/condensation unit is almost permitted with 

PA DEP.

 Presentation includes detailed performance data for 19,000 mg/L TDS 

flowback from Colorado tight gas wastewater.

o GE mobile evaporator (Tinto, 2012)

 Treats approximately 1,700 bpd

 Treatment cost: $7 to $8/bbl estimated

 Two units have been sold and are operating in shale gas formations.

 Concentrated solar crystallization 

o Treatment vendor: Epiphany Solar (Pettengill, 2012)

 Converts produced water into solid waste and treated wastewater.

 Designed to work at remote locations requiring no onsite maintenance for 

30 to 45 days.

 Currently designed to treat produced water from one well (approximately 

10 bpd). Will scale up to treat an entire well pad (approximately 6 wells) 

after initial testing is complete in November 2012 at one of Consol 

Energy’s Marcellus wells.

 Influent streams (quantities represent totals over a year for one well)

 Produced water (100,000 gallons)

 Effluent streams

 Sludge/Metals from bio-filtration unit (7,000 lbs/10 bbls)

 Solid salt crystals (250,000 lbs)

 Treated wastewater (80,000 gallons)

 Treatment steps:

 Pretreated in a bio-filtration unit

 Preheated in a distillation unit (i.e., heat exchanger)

 Evaporated in concentrated solar units

 Condensed in a distillation unit (i.e., heat exchanger)

 Forward Osmosis (Zamora, 2012)

o Treatment technology

 Technology is similar to reverse osmosis in that it uses membranes to 

remove pollutants. Treats wastewater with TDS up to 35,000 mg/L and is 

subject to membrane fouling.
Memorandum

27 November 2012

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 Provided one example of a mobile forward osmosis treatment unit with an 

approximate cost of $4.5/bbl to treat drilling fluid for reuse in fracturing.

3. Current and Emerging Trends across Various Shale Plays

Marcellus

 Shale Gas Development 

o Activity (Hughes, 2012)

 Approximately 2,000 new wells expected per year through 2020

o Fracturing 

 Fracturing volume: 4 to 7.14 million gallons per well (Hughes, 2012)

 Flowback volume: 15 to 20% of injected fracturing fluid (Hughes, 2012)

o Production 

 Produced water volume: 4 to 10 bpd per well (Hughes, 2012)

 Wastewater Management

o Reuse

 PA (Hughes, 2012)

 Reuse: 80 to 90% 

 Underground Injection or treated for TDS removal and disposal: 

10 to 20% 

 WV (Heath, 2012)

 Reuse: 81%

 Underground injection: 18%

 Other: 1%

 OH (Heath, 2012)

 Underground injection: 98%

 Other: 2%

o Underground injection (Skoff, 2012)

 Approximately 250 disposal wells in Marcellus area.

 Table 3 breaks down current disposal well counts by state and provides 

estimated waiting period. All PA disposal wells are privately owned. 

There are no current commercial disposal wells but two commercial 

permits are pending, which are expected to be permitted for 1,000 bpd per 

well. There are approximately 20 existing oil and gas wells that have 

potential for conversion to disposal wells in Bear Creek Area of 

northwestern PA.
Memorandum

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Table 3. Marcellus Underground Injection Wells

State Primacy

Number of 

Wells Waiting Period

PA EPA 5

8 to 16 months

OH State 180 2 to 3 months

WV State 70 2 to 3 months

Source: Skoff, 2012.

Utica

 Shale Gas Development 

o Activity (Wilson, 2012)

 As of 2011 there were 382 permits issued, 144 horizontal wells drilled,

and 17 producing wells7

 Utica shale lies under Marcellus shale so there will likely be Utica 

development in both OH and PA. 

Bakken

 Shale Gas Development 

o Activity (Warlick, 2012a, Landenberger, 2012)

 Currently 190 rigs and 3,803 Bakken shale wells

 No slowdown expected on drilling in the next 15 to 20 years. At least 

2,000 new wells expected per year.

o Drilling (Warlick, 2012a)

 Well Depth: Typical true vertical depth (TVD) is 10,000 feet and true 

measured depth (TMD) is 20,000 feet

 Horizontal legs length: 5,000 to 9,000 feet

 Drilling Cost: $7 million per well

o Fracturing (Landenberger, 2012 unless otherwise noted)

 Requires use of gel in fracturing fluid in order to carry more proppant. Use 

of gels in fracturing requires more consistency and generally freshwater 

 Fracturing volume: 2 to 4 million gallons per well (3 million is typical)

 Flowback volume: 25% of injected fracturing volume per well within 30 

days (Warlick, 2012a)

 Fracturing costs: at least $2 million per well

 Number of stages: average of 30 stages in 2012

 

7 Up-to-date information available online at: http://www.ohiodnr.com/oil/shale/tabid/23174/Default.aspx
Memorandum

27 November 2012

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o Production (Warlick, 2012a)

 As much as 40 percent of associated gas produced is flared due to current 

lack of infrastructure. This is expected to decrease over time.8

 Produced water volume: 3 million gallons over lifetime of well assuming 

25 year lifetime equaling 7.8 bpd per well

 Source Water (Landenberger, 2012)

o Source water options (general acquisition costs: $10 to $20 per 1,000 gallons)

 Surface water: According to a study by North Dakota State Water 

Commission in 2010, the Missouri River and Lake Sakakawea are the only 

surface waters that have long term withdrawal capacity. These sources are 

located in the “sweet spot” of the Bakken play but have not been approved 

by the permitting authority. High cost of source water is actually attributed 

to permitting approval, not availability of source water.

 Groundwater: Increasingly more popular

 Municipal: Is used but is limited due to lack of population. POTWs are 

sporadic. Only 40,000 people live in the “sweet spot” of the Bakken play.

 Wastewater Management (Landenberger, 2012)

o Evaporation in open pits: 2 feet per year evaporates. The plan is to make large 

surface area ponds.

o Underground injection: Some operators will first evaporate as much water as 

possible and then haul it to an injection well.

o Reuse: currently limited to 20 to 40% of fracturing volume but new technologies 

are being evaluated and this practice may increase.

 Water and Wastewater Handling (Landenberger, 2012)

o New 2012 regulations allow fracturing fluid to be stored in open pits.

o Freshwater pipelines are becoming more popular. There are public and private ongoing projects.

o Trucking: A typical well requires 650 truck loads for source water. Each truck 

load is approximately 3 hours one way. Trucking rates: $110 per hour with 110 

bbl/load.

 

8

See https://www.dmr.nd.gov/oilgas/stats/2011gasprod.pdf for natural gas production quantity versus sales quantity 

in North Dakota by formation. Only 60 percent of gas produced in the Bakken during 2011 was sold to market, 

which accounts for 73 percent of the statewide gas production and 70 percent of the wells in the state.
Memorandum

27 November 2012

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Niobrara

 Shale Gas Development

o Activity (Warlick, 2012b)

 Currently 1,156 Niobrara shale wells

 Currently 520 to 690 wells drilled per year. Expected to increase to 800 to 

1,000 wells per year by 2015.

 Total cost for well development: $4 to 6 million per well (average of $5.2 

million)

o Drilling (Warlick, 2012b)

 Well Depth: Typical true vertical depth (TVD) is 4,500 to 7,500 feet and 

true measured depth (TMD) is 8,500 to 12,500 feet

 Horizontal legs length: 4,000 to 5,000 feet

o Fracturing 

 Fracturing volume: 2 to 4 million gallons per well (Warlick, 2012b); 2.72 

to 4 million gallons (Carlson, 2012) 

 Flowback volume: 25% of fracturing volume (Warlick, 2012b)

 Fracturing costs: at least $2 million per well (Warlick, 2012b)

o Production 

 Flaring of associated gas is minimal because there is already a lot of 

infrastructure in place from conventional wells (Warlick, 2012b).

 Produced water volume: approximately 60 bpd per well from end of 

flowback (31 days) decreasing to 20-30 bpd per well after 131 days after 

completion (Carlson, 2012).

Eagle Ford

 Shale Gas Development 

o Fracturing 

 Fracturing volume: Hybrid gel fracturing with 140,000 bbls (Zamora, 

2012)

 Source Water

o Groundwater: $0.50/bbl (Zamora, 2012)

 Wastewater Management

o Injection for disposal costs for flowback with 40,000 mg/L TDS: $2.00/bbl. 

(Zamora, 2012)

o Centralized treatment process (mobile/batch treatment) (Zamora, 2012)
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 Treatment cost: $2.35/bbl

 Treated 265,000 bbls

 Reclaimed 600 bbls of oil ($50,000)

 Water and Wastewater Handling

o Truck transport to disposal facility: $4.75/bbl (Zamora, 2012)

o In-ground pipe and pipeline for centralized treatment: $0.50/bbl. (Zamora, 2012)

Permian

 Wastewater Management

o Cathey (2012), an advanced oxidation treatment vendor, reported on one operator 

who successfully treated 80% freshwater and 20% of wastewater using their 

advanced oxidation treatment technology prior to using it for fracturing (Cathey, 

2012).

o Cathey (2012), an advanced oxidation treatment vendor, reported on one operator 

who is currently reusing approximately 20 to 40% of wastewater in fracturing 

using their advanced oxidation treatment technology based on data from 120 

wells (Cathey, 2012).
Memorandum

27 November 2012

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Attachment 1

Power Point Presentations