MEMORANDUM

TO: Brian D’Amico, EPA/EAD

Lisa Biddle, EPA/EAD

FROM: Meghan Camp, ERG

Brent Ruminski, ERG

DATE: 20 April 2012

SUBJECT: Notes for Shale Gas Industry Meeting Held on 29 February 2012

On 29 February 2012, EPA held a meeting with members of the oil and gas industry and 

discussed economic and engineering topics for the Shale Gas Extraction (SGE) rulemaking. The 

main discussion topics included shale gas economics and engineering.

Attachment 1 lists all of the meeting participants. The names of organizations 

participating on the call included:

• QEP Resources, Inc. (QEP);

• Apache Corporation (Apache);

• Anadarko Petroleum Company (Anadarko);

• American Petroleum Institute (API);

• American Natural Gas Alliance (ANGA);

• U.S. EPA;

• Abt Associates (Abt);

• Westat; and

• Eastern Research Group, Inc (ERG).

Shale Gas Economics (Sarah Banaszak, ANGA)

Sarah Banaszak, a representative from the American Natural Gas Alliance (ANGA), led 

the first discussion on economics, which covered historic gas prices, projected gas prices, and the 

long- and short-term factors that affect gas prices. Attachment 3 provides slides that Ms. 

Banaszak presented for this discussion.

Historic Gas Prices

Ms. Banaszak described overall trends in oil and gas prices. Until 2009, oil and gas prices 

tracked closely with each other. This was because the U.S. imported a majority of its oil and gas 

from other countries. However, since 2009, a major increase in domestic gas production from 

shale and tight sands formations has caused gas prices to decrease while oil prices continue to 
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rise. The increase in domestic gas production results from advancements in hydraulic fracturing 

and horizontal drilling technologies. Ms. Banaszak described these trends as long-term factors of 

natural gas prices. In general, long-term factors occur when industry moves from one technology 

to another or from one type of basin to another. Ms. Banaszak also pointed to a short-term 

divergence in oil and gas prices during 2005 and 2006, which was the result of hurricanes 

disrupting Gulf of Mexico natural gas supplies.

Projected Gas Prices 

Ms. Banaszak presented a chart from the EIA preliminary 2012 outcome, which shows 

the historic and projected U.S. dry gas production from resources including shale gas, tight gas, 

coalbed methane, and other onshore and offshore resources. The chart shows the expansion of 

shale gas production starting around 2005. The projections predict that shale gas and tight gas 

will account for 70 percent of the U.S. natural gas supply by 2035. Mark Himmelstein pointed 

out that CBM production has decreased by 2 percent since 2010, and stated that he expects CBM 

production to continue to decline.

Ms. Banaszak described how the increase in shale and tight gas supply impacted the EIA 

outlooks between 2005 and 2011. The 2005 projections show the U.S. as a net importer of LNG 

and natural gas at an increasing rate. The 2011 projections show the U.S. as a net importer of 

LNG and natural gas at a decreasing rate. Ms. Banaszak stated that the prediction is that the U.S. 

will become an exporter of LNG and potentially an exporter of natural gas. The U.S. exports 

natural gas via pipeline to Mexico and receives natural gas via pipeline from Canada. The net 

natural gas imports are around 10 to 15 percent. On the LNG side, the U.S. currently operates six 

or seven LNG terminals around the country and exports LNG from Alaska. LNG imports can 

come from Trinidad, Tobago, West Africa, Nigeria, Angola, the Middle East, Qatar, and some 

Asian cargos.

Ms. Banaszak compared natural gas price forecasts from EIA 2011, ICF, and IHS. The 

EIA 2011 and ICF projections show shale gas prices gradually increasing from $4.38/MMBtu in 

2010 to around $5.00/MMBtu in 2020 and $7.00/MMBtu by 2035. Ms. Banaszak explained that 

the gradual price increases are due to inflation and increasing natural gas demand. The ICF 

model assumed higher natural gas demand in the power sector than the EIA model; however, the 

ICF price forecast for 2035 ($7.15/MMBtu) was slightly lower than the EIA 2035 price forecast 

($7.21/MMBtu). The HIS price view with constrained shale gas production predicted 

$15.00/MMBtu by 2035.

Long-term Factors of Gas Prices

Ms. Banaszak shifted the discussion to the long-term factors that affect current gas prices 

and price outlooks. The EIA and other outlook models require many long-term assumptions and 

it is important to understand what the model assumes before comparing results from two 

different models. One major long-term factor is investments to support industry growth (2012 

EIA projects $5.7 billion per year through 2025). Pipeline investments have been $8 billion over 

the last 3 out of 4 years. Some other long-term drivers of gas prices on a large scale include:

• Oil prices;

• Technology development;

• Economic growth;
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• Storage; and

• Electricity growth and demand.

Short-term Factors of Gas Prices and Risk

On the project level, several risk factors affect natural gas prices. These risk factors are 

the same factors that companies consider when deciding whether to develop a project:

• Drilling a well will not always be successful. Sometimes the well production will 

be significantly less than expected or the composition of the gas itself will be 

different than expected1

. 

• Connection of pipelines is critical for economical transportation of products. 

Delays in pipeline construction can prevent projects from becoming economical.

• Permit acquisition delays may push the well’s peak production to a lower market 

when prices are lower.

• Unseasonably warm weather will put downward pressure on prices due to the lack 

of demand.

Because all of these factors vary by play, basin, state, and time it is very difficult for 

companies to define a single minimal return of investment for all projects. Mr. Himmelstein

suggested that EPA should assume this number on a basin or lower level. He also described how 

projects on federal lands would have higher risk due to more stringent regulations. A general rule 

of thumb is that companies will always move assets (e.g. drilling rigs) to projects with less risk. 

For example, Pioneer, who is the biggest producer in the Raton Basin, recently moved all of their 

rigs to Texas and Louisiana. In addition, smaller companies will have lower minimal return of 

investment for projects compared to larger companies. 

Current Structure of the Shale Gas Industry

Several speakers provided statistics on the profile of the U.S. gas extraction industry in 

terms of company sizes. It was unclear if these numbers were specific to the shale gas industry or 

the gas industry as a whole.

• Ninety to 98 percent of the companies with interest in shale gas extraction are 

larger corporations. 

• Independent producers (i.e., not companies like Exxon mobile or Shell) drill 70 

percent of wells.

• Independent producers produce 82 percent of natural gas.

• Sixty percent or more of the independent producers are pass-through entities (e.g. 

LLPs, LLCs, or INCs). 

• Shale gas wells are more costly than CBM wells. Therefore, shale gas producing 

companies are larger than CBM producing companies.

• Most gas production is done on private land, and companies are starting to 

produce more liquid-rich gas. Budgets are moving toward oil.

 

1 Wellhead gas is composed of methane, carbon dioxide, hydrogen sulfide, and other gases. The composition affects 

the cost for gas processing and may be difficult to predict. 
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• Many smaller companies that started production in the Marcellus have been 

bought by larger corporations. In addition, some foreign companies are starting to 

buy the American company wells.

Shale Gas Engineering

The second part of the discussion covered engineering practices of shale gas extraction. 

Speakers from two organizations led this part of the discussion: George King of Apache 

Corporation (Apache) discussed hydraulic fracturing and Rebecca Thingelstad of Anadarko

Petroleum Company (Anadarko) discussed wastewater handling.

Hydraulic Fracturing (George King, Apache)

George King, a representative from the Apache Corporation, led the first discussion held 

on shale gas engineering. In general, Mr. King discussed technical details of hydraulic fracturing. 

Mr. King has 40 years of experience in hydraulic fracturing. Mr. King broke down the 

production of oil and gas into drilling (well construction) and fracturing. Fracturing begins when

the operator hauls equipment and materials on site and ends when the operator is selling gas. The 

majority of Mr. King’s discussion focused on drilling and fracturing.

Apache Projects

To describe the benefits of using horizontal wells, Mr. King provided some background 

on Apache’s shale gas project in the Horn River Basin, British Columbia Canada. Table 1 shows 

infrastructure requirements to drain 6,000 acres of gas play (9 square miles) in the Horn River 

using horizontal wells and vertical wells. Attachment 2 provides an image of a well pad in the 

Horn River Basin using horizontal wells.

Table 1. Infrastructure Requirements for Horizontal and Vertical 

Wells

Component Horizontal Wells Vertical Wells

Gas Play Drained (acres) 6,000 6,000

Wells 12 75

Well Pads 1 8

Total Surface Footprint (Acres) 6 150

Oil/Gas Pipelines (miles) 4 30

Trucking Miles (miles) 36,000 (or 1,400 with 

water pipeline)

45,000
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Fresh Water Monitoring Zone 

Size (Acres)

8 6,000

Mr. King also described the closed loop fracturing technique that Apache uses in the 

Horn River Basin. For fresh water, Apache pays between $2.12 per barrel in the summertime and 

over $3 per barrel in the wintertime due to freezing problems. Once Apache implemented the 

closed loop fracturing process, the fresh water price decreased to $0.72 per barrel. Mr. King 

described the closed loop process in terms of a typical scenario in the Horn River basin of 

Canada. 

• Hydraulically fracturing a horizontal well requires 12 million gallons of makeup 

water.

• A local salt water well will provide 90 percent of this makeup water (this water is 

not usable as potable water).

• Fresh water makes up the additional 10 percent of makeup water.

• When the operator recovers water after fracturing, they send it back down the salt 

water well. 

Mr. King noted that this technique is more economical than traditional methods but is not 

commonly used. Currently, Apache is looking at potential closed loop fracturing projects in the 

Eagle Ford and Barnett shale plays of Texas. In these areas, third parties drill water wells to 

supply fresh water for municipalities. However, some water wells are unsuccessful and result in 

the production of salt water. Apache is working on an arrangement with the companies that drill 

these wells where Apache would purchase this salt water. Apache is also working on deals with 

local municipalities using the concentrated brine waste stream from reverse osmosis units in their 

fracturing operations. 

Well Construction

Mr. King related the well casing to as a pressure vessel, which must keep high-pressure 

fluids contained early in its life and keep out salt water in the later stages of its life. Well casing 

usually includes 3 to 5 barriers of steel and cement. Well casing regulations used to be flexible 

but states have done a thorough job on strengthening them. For example, early operators in the 

Marcellus did not enclose the annular space around the well with cement. This is especially 

critical when the surrounding rock is methane rich (e.g., shales and coal beds). Through years of 

experience and research, Mr. King found that when operators make this mistake (less than 1 

percent of wells he has researched) there is a one-to-one correlation to elevated methane in 

surrounding water aquifers. Attachment 2 shows a slide from Mr. King’s website that illustrates 

proper well construction. 

Hydraulic Fracturing of Conventional and Unconventional Wells

Hydraulic fracturing in unconventional formations requires 50 to 60 percent of the 

hydraulic pressure required to fracture conventional formations due to the direction the fractures 

occur. In vertical wells, “planer” fracturing occurs, which are in the direction out of the sides of 

the well. In these fractures, the force must overcome tectonic pressures. In horizontal wells, the 
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fractures occur up and down and with less tectonic pressure. In addition, unconventional 

formations contain more natural fractures. As a result, unconventional wells can have up to 10 to 

100 million square feet of contact area, which is much higher than conventionally fractured 

wells.

The differences in conventional and unconventional hydraulic fracturing fluids and 

wastewater include:

• Conventional wells require less fracturing fluid but a higher percentage will return 

as flowback or produced water;

• Conventional wells require less chemicals overall and there is more potential for 

the use of greener chemical;

• Conventional wells may require more polymer crosslink chemicals; and

• Wastewater from conventional wells will have lower concentration of trace 

pollutants.

Hydraulic Fracturing of Shale Gas and Tight Sands

According to Mr. King, hydraulic fracturing in tight sands and shale is very similar. 

However, a few minor differences include:

• Tight sands fracturing fluids may require more clay control additives than shale 

fracturing fluids.

• Tight sands fracturing fluids may not need the same viscosity as shale fracturing 

fluids.

Hydraulic Fracturing Process Description

Operators typically develop a new unconventional field by drilling vertical wells in order 

to find productive areas. After the productive areas are located, they focus on drilling horizontal 

wells. Horizontal wells are fractured in multiple stages. Typical horizontal wells require 8 to 10 

stages; however, some wells may require up to 14 or 16 stages. In terms of refracturing 

completed wells, operators typically refracture less than 5 percent of wells per year. It would not 

be beneficial to refracture a well in 3 years. Operators are more likely to go back to conventional

wells that have already been producing (but not fractured) and fracture them to enhance 

production. 

Fracturing Fluid 

Operators’ criteria for makeup water quality have shifted over the last few years. 

Historically, most operators required that all makeup water be fresh water (approximately 500 

mg/L TDS). The current criteria for makeup water is between 30,000 to 50,000 mg/L TDS but 

up to 70,000 mg/L is possible due to advancements in friction reducers and other chemical 

additives. Iron is also a critical pollutant that must be less than 10 mg/L to prevent downhole 

scaling. 

Mr. King described how service providers typically add all chemicals possible to a fluid 

to “cover their bases.” However, a good way for operators to reduce cost is to look into 
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eliminating unnecessary chemicals. He said it is possible to save on the order $30,000 to 

$100,0002 per hydraulic fracture by eliminating the use of unnecessary chemical additives. 

Attachment 2 provides a slide from Mr. King’s website that shows common additives that are 

require versus generally unnecessary additives.

Wastewater and Gas Production over Time

Mr. King described a typical wastewater production decline curve for hydraulically 

fractured wells. After the shut in period, wastewater will flow an initial rate of 3 to 6 barrels per 

minute (equivalent to 4,300 to 8,600 bbl/day). Within 5 to 6 days, this flow rate will drop off

significantly. Within 2 to 6 weeks, 5 to 55 percent of the fracturing fluid will return as flowback

(typically 40 to 50 percent in the Devonian and more like 5 to 10 percent in the Eagle Ford). 

Over the lifetime of a well, wastewater will only flow at a rate of 10 barrels per day. However, 

these numbers may vary by well and play. 

Mr. King also described typical natural gas production decline curve for hydraulically 

fractured wells. Over the first year, a well’s gas production will decrease by 45 percent alone 

followed by 20 percent decline over the second and third year. Over the remaining life of the 

well, gas production will decrease at a rate of 4 percent per year. A productive well will produce 

2 to 3 BCF of gas in its lifetime. Again, these numbers will vary by well and play. Mr. King 

noted that the 40 percent decline over the first year use to be 70 percent. This improvement is

due to advancements in hydraulic fracturing. It is possible that shale wells may only produce for 

10 years but the latest estimate is a 15 to 20 year lifespan. There is always a possibility a wells 

will last for a much longer period. Mr. King provided an example of a 150-year-old well in PA 

still producing oil today.

Wastewater Handling and Management (Rebecca Thingelstad, Anadarko)

The second discussion of engineering practices of the shale gas industry focused on 

wastewater handling practices. Rebecca Thingelstad of Anadarko led this discussion. Ms. 

Thingelstad mentioned that best practices vary from basin to basin, play to play, operator to 

operator, and well to well. Throughout this discussion, the speakers provided several 

explanations for these variations, including: 

• Regulations vary by state and region;

• UIC disposal capacity varies by region; and

• New plays have less infrastructure in place for centralized management options.

Types of Wastes from Hydraulic Fracturing

Ms. Thinglestad began by describing the different types of waste streams found on oil 

and gas well sites. These include stormwater, drilling water, and wastewater. Operators manage 

stormwater, drilling fluids, and wastewater separately. This discussion only includes 

management of wastewater. For the purpose of this discussion, wastewater is all water produced

by the well after hydraulically fracturing. This includes both the commonly used terms 

 

2 Mr. King also described these savings as 3 to 10 percent of the total cost of fracturing.
Page 8 of 15

“flowback”3 and “produced”4 water. The meaning of flowback is actually a process and not the 

water itself that immediately flows out of the well after fracturing. 

Wastewater Handling

Wastewater is usually stored in closed tanks or lined pits for a short period but the 

method used depends on regulations in the area. In some cases, regulations may restrict the 

transportation of water. For example, federal regulations sometimes prohibit the transportation of 

water from private land to federal land. Unless the operator intends to use the wastewater in

additional fracturing, they will haul the wastewater off site quickly. The wastewater is hauled 

offsite by truck or pipeline. According to Mr. King, pipelines can result in 70 percent reduced

transportation costs. Operators may use temporary pipelines on various landscapes and reuse 

them repeatedly. Temporary piping is often made of polypropylene, which is available in 5,000-

foot long reels and does not include joints. 

Wastewater Management

A large portion of the discussion focused on current trends of wastewater management in 

the industry. Representatives who spoke mentioned several wastewater management options 

including:

• Haul to CWT;

• Haul to POTW;

• Evaporation in impoundments;

• Haul to UIC; and

• Reuse.

Craig Brown from QEP Resources Inc. (QEP) suggested that operators manage 90 to 98

percent of wastewater through underground injection and less than 1 percent through POTWs.

However, he did not explain if this number is nationwide, specific to QEP, or specific to one 

basin or play. No matter how the wastewater is managed (e.g., reuse, UIC, CWT, and POTW);

there are always contractual limitations (e.g., quality and quantity). In addition, all current 

wastewater management options require operators to comply with some local, state, or federal 

regulations. Producers may hire subcontractors who specialize in wastewater management but 

this is more common for larger companies than for smaller companies.

Reuse

When possible, operators will truck or pipe wastewater to another site for use in 

additional fracturing jobs. Previously, wastewater reuse was uncommon due to concerns that the 

high TDS levels would decrease the effectiveness of friction reducers and the fluid would require 

too much horsepower during fracturing. New chemicals now allow TDS concentrations to be as 

high as 70,000 mg/L making reuse more popular.

 

3 Flowback is commonly referred to as the wastewater that flows immediately after hydraulic fracturing takes place 

until the well begins producing gas. This fluid usually resembles the fracturing fluid used to fracture the well.

4 Produced water is commonly referred to as the wastewater that flows after flowback water for the remaining life of 

the well. This fluid usually resembles the formation water
Page 9 of 15

Craig Brown from QEP Resources provided an example of how operators in the Pinedale 

area of southwest Wyoming pipe wastewater directly to a reverse osmosis facility. All 

wastewater is transferred via pipeline to a third party recycler. The third party recycler treats 

wastewater and returns it to the operator to use in additional fracturing jobs. Wastewater that is 

not of sufficient quality is treated and discharged under a WY NPDES permit into the upper 

Green River Basin. QEP and Anadarko did not provide details on the recycler contract. 

Treatment 

Operators may decide to treat wastewater for reuse or disposal but the ultimate decision 

always comes back to economics. In parts of Wyoming, it is more economic for operators to 

build gathering pipelines to pipe wastewater to CWTs for treatment because large volumes of 

wastewater can be managed increasing the economies of scale. However, a newly developed 

play will not have that kind of infrastructure in place resulting in less attractive economics for 

centralized treatment.

According to Mr. King, treatment of wastewater to reduce certain ions will start at $3 per 

barrel. More intense treatment such as evaporation and condensation may cost between $12 and 

$15 per barrel (not including transportation or solids disposal). In Texas, operators pay between 

$1.5 and $2.0 per barrel for UIC disposal, which makes economic sense. On the other hand, 

operators in the Marcellus will not have access to as many UIC disposal wells and treatment 

options may be more economical.
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Attachment 1: List of Meeting Participants

Name Affiliation

Rob Wood U.S. EPA, Acting Director of EAD

January Matuszko U.S. EPA, Branch Chief

Erik Helm U.S. EPA, SGE Economist

Tom Borne U.S. EPA, CBM EA

Jan Pickerel U.S. EPA, Pretreatment Program

Kim Petro U.S. EPA, Pretreatment Program

James Covington U.S. EPA, CBM Economist

Marla Smith U.S. EPA, CBM Lead

Brian D’Amico U.S. EPA, SGE Lead

Lisa Biddle U.S. EPA, SGE Engineer

Ahmar Siddiqui U.S. EPA, CBM Engineer

Cuc Schroeder U.S. EPA, SGE Statistician

Maria Gomez-Taylor U.S. EPA

Richard Mark Unknown

Jill Dean U.S. EPA, OGWDW

Lee Fuller IPPA

Stephanie Meadows API

Jason Smith API

Sarah Banaszak ANGA, Chief Economist

Amy Farrell ANGA

Marc Himmelstein CBM lobbyist

Rebecca Thingelstad Anadarko

George King Apache 

Craig Brown QEP

Matt Kellogg IPPA

Jan Gilbreath U.S. EPA, OP

Richard Witt U.S. EPA, OGC

Telephone Participants:

Brian Schumacher U.S. EPA, ORD

Chris Impelliteri U.S. EPA, ORD

David Marker Westat

Erik Edgar Abt

Mike Fisher Abt
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Attachment 1: List of Meeting Participants

Name Affiliation

Tatiana Melnikova Abt

Betsy Bicknell ERG

Meghan Camp ERG

Brent Ruminski ERG
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Attachment 2: George King Slides

Figure 1. Proper well casing example

Source: George King’s Website 5

 

5

Available online at: 

http://gekengineering.com/Downloads/Free_Downloads/Avoiding_Shale_Investment_Pitfalls_Pitfalls_23_January_

2012.pdf
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Table 1. Common versus Uncommon Chemical Additives

Source: George King’s Website 6

 

6 Available online at: 

http://gekengineering.com/Downloads/Free_Downloads/A_Guide_to_Chemicals_in_Fracturing_10_Aug_2010.pdf
Page 14 of 15

Figure 2. Horn River Basin 6 acre well pad draining 5,000 acres.

Source: George King’s Website 7

 

7 Available online at: 

http://gekengineering.com/Downloads/Free_Downloads/Alternate_Water_Sources_for_Fracturing_17_Jan_2012.pd

f
Page 15 of 15

Attachment 3: American Natural Gas Alliance (ANGA) Presentation