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 a ll presentations ERG downloaded from an FTP site

.Memorandum

27 November 2012

Page 2 of 14

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

Reference A ttachment 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 Uti ca

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 & U t i ca 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

, 2012 a 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

DevelopmentMemorandum

27 November 2012

Page 3 of 14

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

Reference A ttachment 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, 2012 b 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 Altela Rain: Pressure

- less, Multiple

- Effect Thermal Distillation

Cathey, 2012 SGE00310.A17 Robie Cathey, Eco sphere 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.Memorandum

27 November 2012

Page 4 of 14

4 1. General Information on Wast ewater 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 t o 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 l iquid 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, t he use o f gels

requires higher quality base fluid (McGinns, 2012).

o Lucey (2012) argue d 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 w ater and wastewater m anagement 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

27 November 2012

Page 5 of 14

5

through reuse strategies. However, the presenters did not break do wn 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

assumpt ions 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 h ypothetical pipeline located

in Southwest North Dakota servici ng 80 wells and 10 miles long.

 Breakdown of capital costs

o 10” pipeline with a 25 bbl/min capacity co sts

approximately $17/ foot

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

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

o Booster pumps: $300,000

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

o Total u pfront 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 capacit y).Memorandum

27 November 2012

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6 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

pro prietary activated carbon f ilter to remove soluble organic and inorganic

constituents.

 E stimated treatment cos t of $5.0 0 /bbl

.

 Only conducted pilot testing in Marcellus.

 P erformance 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 rever se 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.htmlMemorandum

27 November 2012

Page 7 of 14

7 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 (Col orado

, 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 s ource water and wastewater prior to fracturing a new

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

eliminating the need for bioc ide.

 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):

 CARES 5 : 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 i s also equipped to chemically treat up to 10,000

bpd.

 CAES 6 : 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 (Mer il, 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

Page 8 of 14

8

 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/conde nsation 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 es timated

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

 Concentrated solar c rystallization

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 20 12 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 Osm osis (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

Page 9 of 14

9

 Provided one example of a m obile forward osmo sis treatment unit with an

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

3 . Current a nd 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)

 W astewater Management

o Reuse

 PA (Hughes, 2012)

 R e use: 80 to 90%

 Underground Injection or treated for TDS removal and disposal :

10 to 20%

 WV (Heath, 2012)

 R euse : 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 wel ls but two comm ercial

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

27 November 2012

Page 10 of 14

10

Table 3

. Marcellus Underground Injection Well s

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.

U t i ca

 Shale Gas Development

o Activity ( Wilson, 2012 )

 As of 2011 there were 382 permits issued

, 144 horizontal wells drilled

, and 17 producing wells 7

 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)

 C urrently 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 f eet 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 c osts: at least $2 million per well

 Number of stages: average of 30 stages in 2012

7 Up

- to

- date informat ion available online at: http://www.ohiodnr.com/oil/shale/tabid/23174/Default.aspxMemorandum

27 November 2012

Page 11 of 14

11

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

 Produce d 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 R iver 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 be en approved

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

to permitting approval, not availability of source water.

 Groundwater : Increasing ly more popular

 Municipal: Is used but is li mited due to lack of population. POTWs ar e

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

 Wastewater Management (Landenberger, 2012)

o Evaporation in open p its: 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 Ha ndling (Landenberger, 2012)

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

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

going projects

.

o Trucking: A t ypical 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/oilga s/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

Page 12 of 14

12 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 pla ce 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 t reatment process (mobile/batch treatment) (Zamora, 2012)Memorandum

27 November 2012

Page 13 of 14

13

 Treatment cost: $2.35/bbl

 Treated 26 5,000 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 ox idation 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

Page 14 of 14

14 Attachment 1

Power Point Presentations