Meeting Summary

Topic: Meeting with industry representatives about the unconventional oil and 

gas effluent guideline rulemaking

Meeting Date: 28 February 2013

Participants: Lisa Biddle, Jan Matuszko, Ahmar Siddiqui, Karen Milam, Pooja Parikh, 

Jesse Pritts, Cindy Roberts (EPA)

Amy Farrell (ANGA)

Lee Fuller, Matt Kellogg (IPAA)

Jason Smith (API)

Jeff Bull, Troy Jordan (Chesapeake)

Joe Cardenas (XTO Energy Inc.)

Michael Dunkle (Pioneer)

Greg Brown (QEP)

Brent Ruminski, Betsy Bicknell (ERG)

Erik Edgar, Ryan Stapler. (Abt)

On 28 February 2013, the U.S. Environmental Protection Agency (EPA) met with

members of the oil and gas industry to discuss EPA’s effluent guideline (ELG) rulemaking for 

the unconventional oil and gas extraction industry. 

Attachment 1 lists the meeting participants. Representatives of the following 

organizations participating in the call:

• U.S. EPA;

• Independent Petroleum Association of America (IPAA);

• America’s Natural Gas Alliance (ANGA);

• Chesapeake Energy, Inc. (Chesapeake);

• XTO Energy, Inc. (XTO);

• Pioneer Natural Resources Company (Pioneer);

• QEP Resources, Inc. (QEP);

• Abt Associates (Abt); and

• Eastern Research Group, Inc. (ERG).

Jeff Bull, a representative from Chesapeake, led the majority of the discussion. 

Attachment 2 provides slides that Mr. Bull presented. Discussion topics included exploration and 

production processes and wastewater management for both conventional and unconventional 

formations.
Meeting Summary

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Exploration and Production 

Mr. Bull described the typical well development process for the onshore sector of the oil 

and gas industry under the North American Industry Classification System (NAICS) code 

211111. This code identifies companies primarily engaged in operating onshore wells that 

extract:

• Crude oil;

• Condensate (i.e., hydrocarbons in the butane range that condense into liquids 

under high pressure); and

• Natural gas.

The following subsections describe the general well development processes for conventional and 

unconventional oil and gas wells.

Locating Hydrocarbons

Operators search for hydrocarbons within each play to locate potential sites for well 

development. This process can be as simple as analyzing existing production and drilling data or

as complex as conducting seismic surveys. In conventional formations, locating hydrocarbons

involves identifying pockets (i.e., bubbles) of oil and gas that occur at different depths below the 

surface. In unconventional formations, instead of pockets, oil and gas are trapped continuously 

within the source rock itself. Therefore, in unconventional formations, the exploration objective 

is to locate thick portions of source rock ideal for horizontal drilling and multistage fracturing.

Depending on available existing data, this process may take up to ten years to complete for a 

specific region within a play. 

Mineral and Property Rights Acquisition

Mineral and surface property rights must be acquired prior to construction at selected 

sites. Acquiring all the necessary rights may require up to five years. Operators must acquire 

mineral rights to all surface acreage from which they expect to drain oil and gas. Operators must 

also acquire property rights for the land on which they construct well pads and access roads. In 

most cases, the mineral rights owner and surface property owner are two different people which 

complicates the acquisition process. 

Permit Acquisition

Acquiring the necessary permits may require one half to three years depending on the 

total number of permits required. It is possible to permit multiple wells and well pads at one time 

but this would require more time to complete. Depending on location, the operator may need to 

obtain five to as many as 40 to 50 permits and approvals. Often, the operator must complete an 

environmental, wildlife, water resource, cultural/anthropological resource, and/or site 

engineering studies prior submitting permit applications. Wells installed on federal lands 

administered by the Bureau of Land Management (BLM) require an Environmental Impact 

Study, a process that typically takes several years to complete.
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Well Pad and Supporting Infrastructure Construction

After all permits and rights are obtained, operators may begin constructing the supporting 

infrastructure and well pad. Construction of one well pad and access road may take six months to 

two years depending on factors such as: distance to nearest existing access road, distance to 

nearest pipeline, and terrain. Construction of supporting infrastructure in areas with no previous 

oil and gas development takes much longer than in areas with existing development.

Well Drilling and Completion

Operators’ drilling and completion practices depend on the type of formation the 

hydrocarbons are trapped in. Operators develop most conventional formations using vertical and 

directional wells while in unconventional formations they use horizontal wells and multistage 

fracturing. Directional wells, which start off as a conventional well but then deviate from vertical 

until they reach a target area, are used in circumstances when an operator was unable to place the 

well pad directly above the oil and gas pocket in a conventional formation. Operators can 

typically drill and complete a single conventional or unconventional well in one to three months.

During the drilling process, operators circulate drilling fluids downhole to carry drill

cuttings to the surface, provide lubrication, and to cool the drill bit. Drilling fluids may be air, 

water, or synthetic oil-based depending on the part of the well being drilled. In general, the 

deeper the well is drilled, the heavier and more robust drilling fluid is required (i.e., water-based 

or synthetic oil-based). The heavy fluids, also called drilling muds, include additives to control 

pH and to increase specific gravity. When the circulated drilling fluid reaches the surface, 

operators remove the cuttings through a separation processes and haul them to landfill while the 

recovered drilling fluid is sent back down the well. At the end of the drilling process, operators 

may treat the drilling fluid and reuse it in drilling another well or dispose of it at landfills, 

underground injection wells, or centralized treatment facilities.

Well completion typically requires three to seven days, depending on the method and 

well properties. Most unconventional formations are completed using multistage hydraulic 

fracturing techniques. The hydraulic fracturing process involves injecting fluid under high 

pressure to create fractures in the formation and allow hydrocarbons to flow. The fluid typically 

consists of a water base fluid1

 1 EPA asked about the status of water-free hydraulic fracturing. Industry representatives acknowledged that wells 

have been fractured using propane with a sand proppant. They noted that the propane fracturing was used in watersensitive formations in Canada. They expressed concern about the safety of using propane-based fracturing fluids. 

, proppant, and chemical additives. Proppant allows the fractures to 

remain open after the initial fracture and chemical additives are used to promote the desired fluid 

characteristics (e.g., viscosity, density, reactivity). The water-based fracturing fluids are 

classified by the chemicals additives as slickwater (contains friction reducers), acids, or gels 

(contains high viscosity gels). Operators will choose between gel and slickwater recipes 

depending on the amount of proppant (sand) that must be carried into the formation. To date, 

slickwater chemistry is the most accommodating for using high TDS wastewater as part of the 

base fluid. Gel recipes are more complex, including components such as friction reducers and gel 

breakers that may not be as compatible with high TDS water base fluid. 
Meeting Summary

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Production and Enhanced Production

After the well is drilled and completed, produced water and hydrocarbons flow from the 

well. The produced fluids pass through a separator to recover hydrocarbons from the produced 

water. 

A well’s productive life depends on economics and ranges from 0 to 30 years. A 

successful well will generate enough revenue to recover capital costs within three to six years. 

Because production will have already significantly declined after three years, it is ideal for a well 

to produce for at least eight to ten years to generate a reasonable profit. If a well is completed 

and does not appear it will generate enough revenue to recover capital cost, operators will 

immediately shut in and abandon the well or sell it to another operator. For older wells whose 

production has declined to a point where the well does not generate enough revenue to cover 

operating costs, the operator may shut the well in, sell the well to another operator (usually small 

operators), or perform workover techniques to enhance recovery. 

Enhanced recovery techniques for conventional and unconventional wells are different 

due to their geological characteristics. To explain this, an industry representative cited Darcy’s 

Law shown in Equation 1, which describes fluid flow in a porous medium as it relates to fluid 

viscosity, medium permeability2

Equation 1 Fluid Flow ∝

Medium Permeability

Fluid Viscosity

× Medium Pressure Gradient

, and medium pressure gradient. This relationship is used to 

describe and understand hydrocarbon flow underground. 

Conventional formations inherently have high permeability and low formation pressures

while unconventional formations have relatively low permeability and higher formation pressure.

In order to allow hydrocarbons to flow to the well, the operator must create a pressure gradient

across the formation. In conventional formations, operators are able create a pressure gradient 

through water flooding. This process involves two vertical wells, one at each end of the target 

formation. Produced water is continuously injected at elevated pressures into one vertical forcing

the hydrocarbons to the second, lower pressure well (i.e., pressure gradient). For unconventional 

wells, it is not technically feasible to increase the formation pressure for an extended period of 

time because the formation is naturally at such high pressures. Since most unconventional 

formations have not been developed long enough to require enhanced production techniques, it is 

unknown what the typical technique will be if any. However, refracturing is probable. 

Another technique used to enhance production in unconventional formations is artificial 

lift in the well bore. When wells cannot produce liquids to the surface by their own pressure, rod 

pumps, electric submersible, and gas lift pumps are used. 

 2 Permeability is a fluid containing rock or substrate’s ability to allow fluids to flow through it.
Meeting Summary

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Wastewater Management

The second topic Mr. Bull discussed was wastewater management including wastewater 

characterization, underground injection, reuse, and treatment technology options for reuse. 

Figure 1 is a flow diagram describing current wastewater management options. The exact 

practice used depends on wastewater quality, volume, and location. The following subsections 

describe wastewater characterization and the commonly used wastewater management practices

by operators in unconventional formations: underground injection for disposal and reuse.

Figure 1. Oil and Gas Wastewater Management Options

Wastewater Characterization

Mr. Bull indicated that oil and gas wastewater may contain:

• Conventional pollutants (e.g., BOD, TSS, pH, oil and grease);

• Toxic priority pollutants (e.g., benzene, ethyl benzene, toluene, arsenic, 

beryllium, cadmium, chromium, copper, lead, mercury, selenium, thallium, zinc); 

and

• Non-conventional pollutants (e.g., TDS, COD, TOC).

Although TDS is not currently a regulated pollutant in the ELG program, it does impact 

technology viability and is a driver in wastewater management decisions. Flowback and 

produced water TDS concentrations vary by formation, within a formation, and over the life of 

the well. Table 1 provides typical TDS concentrations for different unknown formations. TDS 

concentrations are lowest immediately after the flowback process begins and increase after the 

flowback process is complete. 

Basic Treatment

Reuse

Discharge

Injection 

Disposal

Wastewater Advanced 

Treatment
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Table 1. Unconventional Wastewater TDS 

Concentrations

Formationa

TDS (mg/L)

Flowback 

(Initial Low)

Produced Water 

(Long-Term High)

A 150,000 225,000

B 50,000 300,000

C 50,000 150,000

D 30,000 180,000

E 15,000 100,000

F 10,000 80,000

G 10,000 50,000

a—The presentation did not provide specific formation names. 

Industry representatives confirmed that some EPA priority pollutants are present in oil 

and gas wastewater from unconventional formations. However, the industry does not generally 

conduct extensive chemical analysis when the typical management practice is underground 

injection. If an operator is reusing wastewater for fracturing, they would test only for constituents 

that may interact with fracturing base fluid chemicals or the formation and cause scaling or other 

problems. Prior to reuse, wastewater might be analyzed for: TDS, oil and grease, hardness, and 

certain heavy metals. In addition, this type of data collection does not typically go through 

rigorous data review for quality assurance.

Industry representatives briefly discussed the presence of radioactive materials in oil and 

gas wastewater. In general, radioactive materials are highly variable and are present in 

wastewater from both conventional and unconventional wells. A representative from Pioneer 

suggested that radioactive materials are not problematic in the Permian Basin but could not 

verify that Pioneer has conducted any analyses to demonstrate this. XTO suggested that 

radioactive materials are almost always present in produced water but may only be present in 

low concentration. Radioactive materials have not been a concern for the industry because the 

wastewater is typically hauled to underground injection wells for disposal. 

Underground Injection

Mr. Bull explained that most unconventional oil and gas wastewater is disposed of in

underground injection wells. There are approximately 150,000 Class II injection wells3

 3 Underground injection is regulated by the Safe Drinking Water Act (SDWA). Class II wells inject fluids associated 

with oil and natural gas production and include enhanced recovery wells, disposal wells, and hydrocarbon storage 

wells. 

in the 

country. Only 20,000 to 30,000 of these wells are classified as disposal wells while the 

remaining wells are designated for hydrocarbon storage or enhanced recovery. Disposal wells 

may either be commercially or non-commercially operated. The capacity of a single disposal 

well varies but it would be possible to estimate a typical capacity by analyzing state oil and gas 

agency data. There is no widespread discussion in the industry about lack of injection for 

disposal capacity but one area that tends to have lower capacity is the Marcellus region. This is 

because the states of Pennsylvania and West Virginia require produced water be disposed of in 
Meeting Summary

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the zone from which it was removed or deeper. Because of its depth, disposal into zones deeper 

than the Marcellus shale is not feasible. 

Reuse and Treatment Technology Options for Reuse

Mr. Bull focused the last part of the presentation on reuse of oil and gas wastewater in 

fracturing and available treatment technology options. Between 2009 and 2011, most companies 

argued that reuse was not technically feasible because the high TDS concentrations and 

adversely affected fracturing chemical additives and/or well geology. As a result, operators only 

used freshwater for base fluid in fracturing and disposed of all wastewater. This practice has 

changed dramatically in a short period of time as chemical suppliers developed additives that are

effective in high TDS matrixes. Today, many operators consider reuse as their first choice for 

managing shale gas wastewater. 

The biggest concerns for managing wastewater reuse are TDS concentrations and 

volumes. Operators must consider how much wastewater one well generates over time and its 

TDS concentration with respect to how many wells are planned to be fractured and how much 

dilution is necessary to maintain base fluid TDS criteria. If logistics are favorable for reusing 

wastewater in fracturing, the operator must decide the level of treatment. Some companies, such 

as XTO, reuse wastewater with no treatment at all when possible. Basic treatment options 

remove suspended solids, oil and grease, and select ions that are suspected to cause interference 

between chemical additives and the formation geology (e.g., iron, calcium, magnesium, and 

barium). Treatment options for reuse include:

• Sedimentation;

• Filtration;

• Chemical precipitation;

• Dissolved air flotation; and

• Biological treatment. 

Some advanced treatment technologies capable of removing TDS are technically viable 

for treating unconventional wastewater. These types of technologies may be used to treat prior to 

reuse or ultimate disposal (e.g., evaporation with no recovery, evaporation/condensation 

followed by discharge to POTW). Technically viable advanced treatment options for 

unconventional wastewater include:

• Reverse osmosis (RO);

• Forward osmosis (FO);

• Evaporation (no recovery);

• Evaporation/condensation;

• Membrane distillation; and

• Crystallization.

Table 2 provides general influent TDS concentrations, relative cost, and commercial availability 

of each of the advanced treatment technologies listed above. All advanced treatment 

technologies require some type of pretreatment to maximize efficiency and minimize scaling. In 
Meeting Summary

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addition, all of these technologies result in some type of liquid or solid waste stream that must be 

disposed of.

Table 2. Advanced Treatment Limitations

Formationa

Maximum Feed 

TDS (mg/L) Relative Cost

Commercially 

Available

RO 50,000 $ Yes

FO 100,000 $$ No

Evaporation 200,000 $$ Yes

Membrane Distillation 280,000 $$ No

Evaporation/Condensation 300,000 $$$ Yes

Crystallization 500,000 + $$$$$ Yes

The last part of the meeting covered expectations for future wastewater management. No 

one on the call was particularly optimistic about reducing wastewater generation using 

alternative base fluids for hydraulic fracturing (e.g., liquid propane, nitrogen). Instead, 

representatives suggested management of expected volume increase of wastewater generation 

from unconventional oil and gas will require a combination of two practices: the use of more 

advanced treatment technologies to treat wastewater for reuse and advancement in chemical 

additives to allow the use of higher TDS concentrations in base fluids. However, meeting 

participants suggested that TDS will always be a limiting factor for reuse in fracturing in order to 

protect the well integrity (i.e., prevent scaling, protect fracturing equipment). 
Attachment 1

Table A-1. List of Meeting Participants

Name Affiliation

January Matuszko US EPA

Lisa Biddle US EPA

Karen Milam US EPA

Jesse Pritts US EPA

Ahmar Siddiqui US EPA

Cindy Roberts US EPA

Pooja Parikh US EPA

Amy Farrell ANGA

Jason Smith API

Lee Fuller IPAA

Matt Kellogg IPAA

Jeff Bull Chesapeake

Troy Jordan Chesapeake

Joe Cardenas XTO

Michael Dunkle Pioneer

Craig Brown QEP

Brent Ruminski ERG

Betsy Bicknell ERG

Erik Edgar Abt Associates

Ryan Stapler Abt Associates
Meeting Summary

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Attachment 2

PowerPoint Presentation