## Meeting Summary

T opic : M eeting with industry representatives a bout the unconventional oil and gas effluent g uideline rulemaking

Meeting D ate : 28 February 201 3

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 Edga r , Ryan S tapler

. (Abt )

On 28 February 201 3

, the U.S. Environmental Protection Agency (EPA) met with members of the oil and gas industry to discuss EPA’s effluent g uideline (ELG) rulemaking for

the u nconventional oil and g as 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 represe ntative from Chesapeake, led the majority of the discussion.

Attachment 2 provides slides that Mr. Bull presented. Discussion topics included e xploration and production processes and wastewater management for both conventional and unconventional

formations

.Meeting Summary Page 2 of 10

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 e ngaged in operating onshore wells that

extract :

**•** Crude oil;

**•** Condensate (i.e., h ydrocarbons in the butane range that condense into liquids under high pressure ) ; and

**•** Natural gas.

The following subsections describe the general well development processes for convention al 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 for mations, instead of pockets, oil and gas are trapped continuously

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

is to l ocat e thick portions of source rock ideal for horizontal drill ing and multistage frac turing

. Depending on available existing data, this process may take up to ten years to complete for a specific region within a play

.

M ineral and P roperty R ights Acquisition

M ineral 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 the y expect to drain oil and gas. Operators must
also acquire p roperty rights for the land on which they construct well pad s 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 man y 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

adm inistered by the Bureau of Land Management (BLM) require an Environmental Impact Study, a process that typically takes several years to complete.Meeting Summary Page 3 of 10

W

ell P ad and Supporting Infrastructure Construction

After all permits and rights are obtained, operators may b egin constructi ng the supporting

infrastructure and well pad. Construction of one well pad and access road m a y 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 a reas with no previous oil and gas development take s much longer than in areas with existing development

.

Well Drill ing and Completion

Operators’ drilling and completion practices depend on the type of formatio n the hydrocarbons are trapped in. Operators develop most conventional formations using vertical and

directional wells while i n un conventional formations they use horizontal wells and multi stage fracturing . Directional wells , which start off as a conventio nal 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 complet e 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. Dr illing 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 calle d 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 process es 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 drilli ng another well or dispose of it at landfills, underground injection wells, or centralized treatment facilities.

Well complet ion 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

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

consists of a water base fluid 1

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 water

sensitive formations in Canada. They expressed concern about the safety of using propane

- based fracturing fluids. , p roppant, 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 f racturing fluids are classified by the chemicals additives as slickwater ( contains friction reducers) , acids , or gels ( contains high viscosity g els )

. 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 us ing high TDS wastewater as part of the

base flu id . 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 Page 4 of 10

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 3 0 years. A

successful well will generate enough revenue to recover capital c osts within three to six years

. Because production will have already significantly declined after three years, i t 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 re cover capital cost, operators will immediately shut in and abandon the well or sell it to a nother operator. For older wells whose production has d eclined 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 recov ery 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 Equatio n 1

, which describes fluid flow in a porous medium as it relates to fluid viscosity, medium permeability 2

Equatio n 1 Fluid Flow ∝ Medium Permeability

Fluid Viscosity × Medium Pressure Gradient , and medium pressure gradient. T his relationship is used to describe and understand hydrocarbon flow underground

.

Conventional formations inherently have high permeability and low formation pressure s 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 ar e 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 sec ond , 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 pressure s

. Since most unconventio nal 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 format ions 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 Page 5 of 10

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:

**•** Con ventional pollutants (e.g., BOD, TSS, pH, oil and grease );

**•** Toxic priority pollutants (e.g., b enzene, ethyl benzene , toluene, arsenic, beryllium, cadmium, chromium, copper, lead, me rcury, 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 c oncentrations vary by formation, within a formati on, and over the life of

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

concentrations are lowest immedia tely after the flowback process begins and increase after the flowback process is complete. Basic Treatment

Reuse Discharge Injection Disposal

Wastewater Advanced

TreatmentMeeting Summary Page 6 of 10

Table 1

. Unconventional Wastewater TDS

Concentrations

Formation a 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 pri ority 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 material s in oil and

gas wastewater. In general, r adioa ctive material s are highly variable and are present in

wastewater from both conventional and unconventional wells. A representative from Pioneer suggested th at radioactive material s are not problematic in the Permian Basin but could not verify that Pioneer has conducted any analyses to demonstrate this

. XTO suggested that

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

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

w astewater 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 C lass II inj ection wells 3

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 t he industry about lack of injection for disposal capacity but o ne 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 inMeeting Summary Page 7 of 10

the zone from which it w as 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

frac turing 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 resul t, operators only

use d 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 treatmen t. 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)

. T reatment 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 vi able a dvanced 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 technologi es require some type of pretreatment to maximize efficiency and minimize scaling. InMeeting Summary Page 8 of 10

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

Table 2

. Advanced Treatment Limi tations

Formation a 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 technologi es to treat wastewater for reuse and advancement in chemical

additives to allow the use of higher TDS concentrations in base fluid s . 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 AssociatesMeeting Summary Page 10 of 10

Attachment 2

PowerPoint Presentation