### MEMORANDUM

TO: Lisa Biddle, U.S. EPA

FROM: Brent Ruminski, ERG

Sarah Yates, ERG

DATE: March 31

, 201 5

SUBJECT: Data Compilation Memorandum for the Technical Development Document

(TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction (DCN SGE 00693)

This memorandum describes how ERG developed various tables and figures presented in EPA’s Technical Development Document for Proposed Effluent Limit ations Guidelines and Standards for Oil and Gas Extraction (DCN SGE00704) . Specifically, this memorandum focuses

on the tables and figures listed in Table 1 of this m emorandum all of which are specific to unconventional oil and gas (UOG)

. T ables and figures that are presented in the TDD not listed in Table 1 either did not require calculations and/or analyses by ERG or are described in separate, supporting memoranda. Appendix F of the TDD contains a crosswalk of all tables and figures in the TDD and the name of the relevant supporting memorandum , where applicable. The subsections of this memorandum are parallel to the Chapters in the TDD :

 Section 1.0 discusses tables and figures in the TDD Chapter B, Backgrou nd on Unconventional Oil and Gas Extraction ;

 Section 2.0 discusses tables and figures in the TDD Chapter C, Unconventional Oil and Gas Extraction Wa stewater Volumes and Characteristics ; and

 Section 3.0 discusses tables and figures in the TDD Chapter D, Unconventional Oil and Gas Extraction Wastewater Management and Disposal Practices

.

The following list of Microsoft Excel attachments to this memorandum contain the underlying data and calculations used to create the figures and tables in the TDD that are described in this memorandum. Table 1 present s the relevant attachment to this memorandum that contain s the underlying data and analysis for each figure and table.

 Attachment 1

– Onshore Oil and Gas Drilling Activity

- DCN SGE 00693 .A01

 Attachment 2

– EIA UOG R esource Potential

- DCN SGE00693 .A02

 Att achment 3

– TDD Data Compilation

- DCN SGE00693 .A03Memorandum

M arch 31 , 2015 Page 2

Table 1

. List of Tables and Figures Discussed in this Memorandum

TDD Chapter TDD Table

or Figure Number TDD Table or Figure Title Memo

. Section Memo

.

Attachment Number

B Figure B

- 7 Length of Time to Drill a Well in Various UOG

Formations as Reported for the First Quarter of 2012 through the Third Quarter of 2013 1.1 SGE00693 .A01

Figure B

- 13 Number of Active U.S. Onshore Rigs by Trajectory and

Product Type over Time 1.2 SGE00693 .A01

Table B

- 2 Active Onshore Oil and Gas Drilling Rigs by Well

Trajectory and Product Type (as of November 8, 2013) 1.2 SGE00693 .A01

Table B

- 3 a UOG Potential by Resource Type as of January 1, 201 2 1.3 SGE00693 .A02

Table F

- 3 b UOG Resource Potential: Shale as of January 1, 201 2 1.3 SGE00693 .A02

Table F

- 4 b UO G Resource Potential: Tight as of January 1, 201 2 1.3 SGE00693 .A02 Figure B

- 14 Projections of UOG Well Completions 1.4 SGE00693 .A03

C Table C

- 1 Sources for Base Fluid in Hydraulic Fracturing 2.1 SGE00693 .A03

Table C

- 3 Most Frequently Reported Additive Ingredients Used in

Fracturing Fluid in Gas and Oil Wells from FracFocus (2011

- 2013) 2.2 SGE00693 .A03

D Table D

- 1 UOG Produced Water Management Practices 3.1 SGE00693 .A03

Table D

- 4 Reported Reuse/Recycle Criteria 3.2.1 SGE00693 .A03

Table D

- 5 Reported Reuse/Recycle Practices as a Percentage of Total

Fracturing Volume 3.2.2 SGE00693 .A03

Figure D

- 6 Hypothetical UOG Produced Water Generation and Base

Fracturing Fluid Demand over Time 3.2.3 SGE00693 .A03

a

— This table in the TDD also includes some data from a separate ERG analysis (DCN SGE00963). b

— These tables are related to the discussion about Table B

- 3 in Chapter B of the TDD

. This memorandum will refer to the following terms used throughout the TDD, the supporting memoranda, and memoranda attachments:

 Unconventional oil and gas (UOG) resources

- crude oil and natural gas 1 produced by wells drilled 2 into low porosity, low pe rmeability formations.

 UOG extraction wastewater

- sources associated with production, field exploration, drilling, well completion, or well treatment for unconventional oil and gas extraction (e.g.

, drilling muds, drill cuttings, produced sand, produced water)

. 3

 Drilling wastewater

– the liquid waste stream separated from recovered drilling fluid (mud) and drill cuttings during the drilling process

.

1 Natural gas can include “natural gas liquids,” components that are liquid at ambient temperature and pressure.

2 UOG wells may be drilled using horizontal, vertical, or directional well trajectories. Literature sometimes refers to well trajectory as “dril l type”.
3 Stormwater is not considered a source of UOG extraction wastewater. In general, no NPDES permit is required for discharges of stormwater from any field activities or operations associated with oil and gas production, except as specified in 40 C .F.R. 122.26(c)(1)(iii) for discharges of a reportable quantity or that contribute to a violation of a water quality standard . States may impose additional requirements for management of drilling site stormwater.Memorandum

M arch 31 , 2015 Page 3

 P roduced water

– the water (brine) brought up from the hydrocarbon

- bearing

strata during the extraction of oil and gas. This can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process . Based on the stage of completion and production the well is in, produced water can be further broken down into the following components:

 Flowback

– the produced water generated in the initial period after hydraulic fracturing (i.e., fracturing fluid, injection water, any chemicals added downhole, and varying amounts of formation water)

.

 Long

- term produced water (LTPW)

– the produced water generated during the production phase of the well after the initial flowback process (includes increasing amounts of formation water)

.

1.0 C OMPILATION OF D ATA FOR TDD C HAPTER B

The following subsections discuss the data and methods used to d evelop the tables and figures listed in Table 1 and presented in TDD Chapter B.

1.1 TDD Chapter B, Section 3.1 UOG Well Drilling and Construction (Figure B

- 7)

Figur e B

- 7 “ Length of T ime to Drill a Well in Various UOG Formation s” shows the number of days required to drill a well for various UOG formations

. Attachment 1 ( DCN SGE00693 .A01 ) contains the underlying data in the tabs called “Drilling Days Data ” and “Drilling Da y s Figure” . For this analysis, ERG obtained data from Baker Hughes ’ U.S. Onshore Well Count (DCN SGE00503)

. This data set is a quarterly census of the number of new onshore oil and gas wells that were spud 4 in the U.S., and includes counts of th e number of land wells, the number of land rigs, and the number of land wells per rig that were spud in each major U.S. basin /formation 5 . These counts are available from first quarter 2012 t hrough third quarter 2013

, and are representative of all U.S. oilf ield activities.

To calculate the average time to drill a well in each formation presented in TDD Figure B

- 7, ERG divide d the number days in each quarter (typically 9 1 or 92 days) by the number of wells per rig for that quarter to calculate drilling effic iency, or the average number of drilling days per well per rig in a given UOG basin/ formation.

For simplicity, ERG combined the well counts for the three different Woodford shale formations ( i.e., Ardmore Woodford, Arkoma Woodford, Cana Woodford) to represent the Woodford shale formation. ERG accomplished this by summing the well count s and rig counts respectively for each quarter for the three different Woodford shale formations . ERG then perform ed the final calculation described above using the new, combined Woodford shale totals to get the number of drilling days per rig

.

4 The term “spud” means to initiate the dr illing of a well.
5 Baker Hughes reported a mixture of basins (e.g., Williston, Permian) and formations (e.g., Marcellus, Utica) in all of their rig counts datasets.Memorandum

M arch 31 , 2015 Page 4

1.2 TDD Chapter B, Section 4.1 Historical and Current Drilling Activity for Unconventional Oil and Gas (Figure B

- 13 and Table B

- 2)

Baker Hughes periodically publishes the two active rig count data sets 6 listed below that provide different and more detailed information on active wells than the Baker Hughes U.S. Onshore Well Count data set (DCN SGE00503) described in Section 1.1

. ERG downloaded the se two additional rig count datasets listed below in November 2013 and used them as the basis for Figure B

- 13 and Table B

- 2 in the TDD. Attachment 1 ( DCN SGE00693 .A01 ) contains the downloaded rig counts and ERG’s analys e s. Information contained in these two Baker Hughes datasets are described below.

 North America Rotary Rig Count (Jan 2000 7

- Current) ( DCN SGE 00504 ) : tabulates the total number of active rigs in the U.S. and Canada for each week dating back to January 1991 and indicates product type ( i.e., oil

, gas , mis 8 ) and well trajectory ( i.e., horizontal, directional, vertical). The dataset includes the following fields :

 Well T rajectory

 Number of rigs drilling horizontal wells

 Number of rigs drilling directional wells

 Number of rigs drilling vertical wells

 Total number of active rigs

 Product Type;

 N umber of rigs drilling for oil

 Number of rigs drilling for gas

 Number of rigs drilling for “miscellaneous”

 Total number of active rigs (equals the total number of active rigs in the trajectory category above)

 North America Rotary Rig Count Pivot Table ( DCN SGE 00502 ) : presents a record for each active rig in North American on a weekly basis beginning in February 2011 . The dataset include s the following for each rig :

 Country ( i.e., Canada

, U nited S tates ) ;

 County;

 Basin 9 ;

 Drill For ( i.e., gas, oil , miscellaneous ) ;

 Location (i.e., land, offshore, inland waters);

 Trajectory ( i.e., directional, horizontal, vertical) ;

 Well Type;

 Well Depth;

 Date (both publish date and the date the data represents ) ; and

 Rig count (i.e., number of rigs)

.

6 Baker Hughes’s rig count datasets serve as an indicator of demand for products used in dr illing, completing, producing, and processing hydrocarbons in the petroleum industry.

7 Although this source title includes the phrase “Jan 2000

– Current”, it includes data back to January 1991.
8 Baker lists some wells as “Mis” which stands for miscellan eous. ERG added these types of rigs to oil rig counts for all analyses assuming that they represent wells that produce a mixture of oil and gas (i.e., wet gas).
9 Baker Hughes reported a mixture of basins (e.g., Williston, Permian) and formations (e.g., Marcellus, Utica) in all of their rig counts datasets.Memorandum

M arch 31 , 2015 Page 5

The following two subsections describe how ERG used these Baker Hughes datasets to generate Figure B

- 13 and Table B

- 2 in the TDD.

1.2.1 Figure B

- 13 “Number of Act ive U.S. Onshore Rigs by Trajectory and Product Type over Time”

Figure B

- 13 “Number of Active U.S. Onshore Rigs by Trajectory and Product Type over Time” shows the estimated total number of active drilling rigs between January 2000 and November 2013

. The f

igure also plots the number of drilling rigs by trajectory type (i.e., directional, horizontal, vertical) and by well type (i.e., oil, gas). To prepare this figure, E RG graphed the relevant U.S. data as reported in the Baker Hughes North America Rotary Rig Count dataset (Jan 2000

- Current) 10 (DCN SGE 00504). Attachment 1 (DCN SGE00693 .A01 ) contains the underlying data and analysis for Figure B

- 13 in the tabs called “Drill O ver Time Data ” and “Drill over Time Figure ”.

1.2.2 Table B

- 2 “ Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of November 8, 2013) ”

Table B

- 2 “ Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of November 8, 2013) ” shows the number of active drilling rigs in the U.S. by basin and/ or formation 11 . The rig counts are further broken down by trajectory (i.e., directional, horizontal, vertical) and by well type (i.e., oil, gas)

. To develop Table B

- 2, ERG used the most
recent rig counts from the Baker Hughes North American Rotary Rig Count Pivot Table dataset downloaded on November 11 , 2013. Attachment 1 (DCN SGE00693 .A01 ) contains the underlying data and analysis for Table B

- 2 in the tabs called “Rigs by Basin Data ” and “Rigs by Basin Table ”.

ERG used the following steps to summarize the rig counts :

1. Filtered the “Rigs by Basin data ” tab for:

a. “U nited States ” rigs in the Country field b. “ land” ( onshore ) rigs in the Location field

c. “11/8/201 3 ” in the PublishDate field (as downloaded on November 11, 2013). 2. In the Rigs by Basin Table, ERG summe d the total number of rigs, number of gas rigs, and number of oil rigs for each reported basin/ formation with the filters in S tep 1

. For each type (i.e., oil, gas), ERG further categorized the number of oil or gas wells by trajectory (i.e., directional, ho rizontal, vertical). Most data provided by Baker Hughes is on a basin/formation basis. Baker Hughes reported a mixture of basins (e.g., Williston, Permian) and formations (e.g., Marcellus, Utica) in all of their rig counts datasets. For Woodford formations , Baker Hughes published sub

- formation data for the Woodford shale: Cana Woodford, Arkoma Woodford, and Ardmore Woodford

. ERG combined th e number of rigs for these into one common formation called “Woodford”.

10 This document published by Baker Hughes includes drill rig counts for the entire North America but also pro vide separate counts for the United States. ERG used the data reported for the United States which is in the “ US Oil & Gas Split ” tab in SGE00504.

11 Baker Hughes reported a mixture of basins (e.g., Williston, Permian) and formations (e.g., Marcellus, Utica) in all of their rig counts datasets.Memorandum

M arch 31 , 2015 Page 6

1.3 TDD Chapter B, Section 4. 2 Unconventional Oil and Gas Resource Potential ( Table

B

- 3 , Table F

- 3 Table F

- 4 )

The following tables in the TDD summariz e the total new well potential , estimated ultimate recover y (EUR), and technically recoverable resource (TRR) for the four resource types (i.e., shale gas, shale oil, tight gas, tight oil) and for each known formation (e.g., Marcellus, Barnett) :

 Table B

- 3

- “UOG Resource Potential by Type as of January 1, 201 2 ” ;

 Table F

- 3

- “UOG Resource Potential: Shale as of January 1, 201 2 ” ; and

 Table F

- 4

- “UOG Resource Potent ial: Tight as of January 1, 2012 ”

. 12

To create these tables

, ERG used the data reported in Table 9.3 of the U.S. Energy Information Administration ’s (EIA) Assumptions to the Annual Energy Outlook 201 4 (DCN SGE00988 )

. Attachment 2 ( DCN SGE00693 .A02 ) contains the underlying data and analysis

. In the assumptions to each Annual Energy Outlook (AEO) document

, EIA reports the total resource potential for each active and prospective UOG formation. EIA bases these estimates on studies completed by the United States Geological Survey (USGS) , historical oil and gas production, and expected future advances in drilling technology

. The two r esource estimate s reported by EIA tha t ERG used in our analysis are described below. 13 The “Raw EIA Data” tab in Attachment 2 contains the estimates as reported by EIA

.

 Technically R ecoverable R esource ( TRR )

– TRR is the total oil 14 and/or gas that is believed to be extractable from a formation based on current technology disregarding economics

. In EIA’s 2014 report, TRR estimates are reported as of January 1, 2012. EIA reports natural gas TRR in units of billion cubic feet (BCF) and crude oil TRR in units of billion barrels ( B bls). ERG converte d the crude oil TRR from B bls to million barrels (MMbbls) in the “Raw EIA Data” tab in Attachment 2 (DCN SGE00693 .A02 ).

 Estimated U ltimate R ecovery ( EUR )

– Lifetime recovery of oil

, and/or gas per well based on existing production data and current/expected drilling practices in each formation (e.g., vertical or horizontal drilling). These estimates are averages across all wells; actual production may vary significant ly from well to well

. EIA reports nat ural gas EUR in units of BCF per well a nd crude oil EUR in units MMb b l s per well.

ERG used EIA’s TRR and EUR estimates to calculate new well potential by formation (e.g., Marcellus) and by resource type (e.g., shale gas, tight oil)

. ERG calculated the new well potential based on EIA’s TRR estimates which assume current oil and gas extraction technology (e.g. hydraulic fracturing, horizontal drilling). These estimates do not factor in future changes to

12 Tables F

- 3 and F

- 4 are located in Chapter F of the TDD but support Chapter B.
13 EIA also publishes the foll owing statistics for each UOG formation: total land area (square miles), percent of land area that may be developed (%), and maximum well spacing (wells/square mile). Multiplying these values for a given formation provides an estimate of new well potential

. 14 EIA also provides TRR estimates for natural gas plant liquids (NGPLs) but they were not the focus of ERG’s analysis. EIA defines NGPLs production as the extraction of gas plant liquids constituents such as ethane

, propane , normal butane, isobutane

, and natural gasoline , sometimes referred to as extraction loss

.Memorandum

M arch 31 , 2015 Page 7

TRR estimates, advances in drilling technology, or econ omic conditions that ultimately determine how many wells industry drills.

Specifically, E RG used the following procedures for this analysis:

1. In the “Raw EIA Data” tab in Attachment 2 (DCN SGE00693 .A02 ), ERG calculated new well potential for each formatio n or sub

- formation (e.g., Central Fayetteville, West Fayetteville) reported by EIA using Equation 1

. 15 The natural gas and crude oil TRR and EUR can be used interchangeably to find the same new well potential for each formation. A f ew unconventional oil formations have zero natural gas TRR. For these, ERG used the crude oil TRR and EUR to calculate new well potential

. Equation 1

2. In the “Raw EIA Data” tab in Attachment 2 (DCN SGE00693 .A02 ), ERG assigned each formation and sub

- formation (reported b y EIA) a common formation name. For example, EIA reported resource potential separately for “Fayettevil le

- Central” and “Fayetteville

West. ” ERG consolidated these formation names into “Fayetteville.” 3. In the “Raw EIA Data” tab in Attachment 2 (DCN SGE00693 .A02 ), ERG classified each formation and sub

- formation into one of four resource types: shale gas, shale oil, tight gas, or tight oil. For most formations, ERG used the resource types assigned to formations by EIA in the Assumptions to the Annual Energy Ou tlook 201 3 (DCN SGE00486)

. 16 However, a ll unconventional oil formations were combined by EIA in this report i nto the group called “tight oil ” which includes both shale and tight formations

, as defined by ERG. Therefore, ERG assigned each unconventional oil play to either the shale oil or tight oil category as shown in EIA’s shale and tight maps (DCN SGE00153 and DCN SGE00155). 17
4. In the “Potential Data by Formation” tab in Attachment 2 (DCN SG E00693 .A02 ), ERG used Equation 2 and Equation 3 below to recalculate total ne w well potential and TRR for each consolidated formation in order to eliminate sub

- formations from the list

. ERG calculated the average EUR for each consolidated formation using Equation 4 and the results from Equation 2 and Equation 3 . The results of this step generate Table F

- 3 and F

4 in the TDD

. Equation 2

15 ERG calculated the total new well potential using the same method EIA presented in EIA’s Assumptions to the Annual Energ y Outlook 2014 (DCN SGE00988).
16 EIA’s 2014 assumptions report (DCN SGE00986) did not organize the list of UOG formations by resource type like EIA’s 2013 assumptions report (DCN SGE00486).
17 A few formations did not appear in EIA’s 2013 assumptions repor t or in the EIA shale and tight maps. ERG used assessment reports completed by the USGS to assign the appropriate resource type to these formations.Memorandum

M arch 31 , 2015 Page 8

Equation 3

Equation 4

5. In the “Potential Data by Resource Type ” tab in Attachment 2 (DCN SGE00693 .A02 ), ERG used Equation 5 and Equation 6 below to recalculate total new well potential and total TRR for each of the four resource types that were assigned by ERG in Step 3

, above

. Next, ERG calculated the weighted average EUR for each resource type using Equation 7 and the results from Equation 5 and Equation 6

. The results of this step generate Table B

- 3 in the TDD

. Equation 5

Equation 6

Equation 7

Table B

- 3 also shows estimates of active UOG wells during 2010

– 2011. ERG obtained these estimates using data from Drilling i nfo’s (DI) Desktop® well database described in a separate memorandum (DCN SGE00963 )

.

1.4 TDD Chapter B, Section 4.3 Current and Projections of Future UOG Well Completions (Figure B

- 14)

Figure B

- 14 “Projections of UOG Well Completions” shows the projected number of UOG wells completed annually and cumulatively using information from the October 2012 IHS Report, America’s New Energy Future: The Unconventional Oil and Gas Revolution and the US Economy (DCN SGE 00 864 )

. Attachment 3 ( DCN SGE00693 .A03 ) contains the underlying data and analysis in the tabs called “ IHS Well Projections” and “ IHS Well Projections Figure ”

.

IHS estimated annual well completion s for 2012, 2015, 2020, 2025, 2030, and 2035. IHS

e stimates are provided for unconventional oil wells and unconventional gas wells. 18 For gas wells, IHS estimates are further broken down by resource type (i.e., shale

, tight )

. ERG extrapolated the number of well completions between the years reported by IHS. For example, IHS reported 7,179 unconventional oil well completions in 2012 and 8,472 completions in 2015, or an increase of 1,293 unconventional oil wells over this three

- year period. Therefore, ERG

assume d that 431 unconventional oil wells are completed each year from 2012 to 2015.

18 IHS uses the same definition of UOG as defined in this memorandum.Memorandum

M arch 31 , 2015 Page 9

Using the number of wells completed each year (either reported by IHS or extrapolated from IHS data) ; ERG calculated the cumulative well completions by summing the number of completed wells for that year and all preceding years starting in 2012

.

2.0 C OMPILATION OF D ATA FOR TDD C HAPTER C

The following subsections discuss the data and methods used to develop t he tables and figures listed in Table 1 and presented in TDD Chapter C.

2.1 TDD Chapter C, Section 1.1 Base Fluid Composition (Table C

- 1)

Table C

- 1 “Source s for Base Fluid in Hydraulic Fracturing” shows the composition of base fluid used for hydraulic fracturing across major basins and various UOG formations. Attachment 3 ( DCN SGE00693 .A03 ) contains the underlying data references and analysis in the tab call ed “Base Fluid Data ”

. For some basins/formations, ERG identified data from multiple references and/or projected 19 data in addition to historic year data . Therefore, each formation may have multiple rows in this tab where each row represents the various references and types of data (i.e., historic or projected)

. In addition, literature reported various types of sources that are used for base fluid. ERG categorized the reported data from the source into one of three categories in the “Base Fluid Data ” tab:

 Fresh water

– Naturally occurring water on the Earth 's surface . Examples include ponds

, lakes

, rivers and streams , and certain underground aquifers . Fresh water is generally characterized by having low concentrations of dissolved salts and other total dis solved solids (TDS)

.

 Brackish water

– W ater that has more salinity than fresh water , but not as much as
seawater

. Example sources include certain underground aquifers

, effluent from publicly owned treatment plants (POTWs)

, and wastewater from other industr i es

.

 Reuse/recycle water

– This is any UOG extraction wastewater (i.e., flowback, long

term produced water, drilling wastewater).

To populate Table C

- 1 in the TDD, ERG compiled percentages from the “Base Fluid Data ” tab in the “Base Fluid Summary” tab on a basins/formations basis

. For basins/formations where ERG identified projected data in addition to historic data

, ERG created a separate set of columns for each basin/formation combination in the tab

. Table C

- 1 presents t hese projected data parenthetical ly.

2.2 TDD Chapter C, Section 1.2 Additives (Table C

- 3)

Table C

- 3 “ Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in Gas and Oil Wells from FracFocus (2011

- 2013) ” shows concentrations of chemicals common ly used in the hydraulic fractu ring of gas and oil wells. 20 Data are presented in terms of percent by

mass. ERG obtained data as reported in Table 8 and 9 of EPA ORD’s FracFocus Summary Report (DCN SGE 00721). However, ERG reorganize d the data by combining the two ORD tables into one

. ERG reordered the chemicals by highest to lowest weighted average median

19 ERG identified one report that proje cted base fluid composition for “low water use”, “most likely”, and “high water use” scenarios for 2020 and 2060. ERG used the “most likely” scenario for 2020 (DCN SGE00639).Memorandum

M arch 31 , 2015 Page 10

concentration. Attachment 3 ( DCN SGE00693 .A03 ) contains the un derlying data and ordering
process in the tab “ORD FF Chemicals”

.

3.0 C OMPILATION OF D ATA FOR TDD C HAPTER D

The following sub sections discuss the data and methods used to d evelop tables and figures listed in Table 1 and presented in TDD Chapter D

.

3.1 TDD Chapter D, Intro duction (Table D

- 1)

Table D

- 1 “UOG Produced Water Management Practices” presents information about how UOG operators manage produced water across basins containing major UOG formations. ERG reviewed existing literature sources for information about wastewater management pract ices . Some sources only contain ed qualitative produced water management information, while others also report ed the percentage of produced water disposed of via each management practice. Because quantitative data were not available across all formations, E RG categorized management practices in each formation as follows :

 X

– A small (<10 percent) or unknown portion of UOG produced water was managed with this management practice;

 XX

– A moderate portion (>10 and <50 percent) of UOG produced water was managed with this management practice; or

 XXX

– A majority (>50 percent) of UOG produced water was managed with this management practice.

The “ UOG PW Management ” tab in Attachment 3 ( DCN SGE00693 .A03 ) contains the underlying data references used to create Table D

- 1 . The attachment includes additional information that is not included in the TDD about how ERG designated the “X” categories

. The “Additional Comments” column provides further explanation about the type of information reported in the underlying reference that ERG used to assign the “X” category.

3.2 TDD Chapter D, Section 3 .2 Reuse/Recycle Drivers (Table D

- 4 , Table D

- 5 , and Figure D

- 6 )

The following subsections describe how ERG used existing literature t o generate T able D

- 4, Table D

- 5 and Figure D

- 6 in the TDD

.

3.2.1 Reuse Criteria

Table D

- 4 “Reported Reuse/Recycle Criteria” shows ranges of observed or recommended constituent concentration s for use in fracturing base fluid (i.e., mixture of wastewater and other

20 FracFocus is a national hydraulic fracturing chemical registry managed by the G round Water Protection Council (GWPC) and the Interstate Oil and Gas Compact Commission (IOGCC) . Its stated goal is to provide a publicly accessible site for operators to disclose information about the chemicals used in the hydraulic fracturing of oil and gas wells. The registry includes information for wells fractured after January 1, 2011. As of November 2013, more than 55,000 wells have been registered. The registry is easily searchable by county, state, operator, American Petroleum Institute (API) well number, date of fracturing, or well name, and information is returned as individual PDF files for specific wells. Entries for specific wells on specific dates are referred to in the FracFocus report as “disclosures”.Memorandum

M arch 31 , 2015 Page 11

source water) . It also shows the associated potential issue that the fluid or well may experience with concentrations in excess of that concentration

. Attachment 3 ( DCN SGE00693 .A03 ) contains the underlying data and analysis in the tabs called “Reuse Crit eria Data” and “Reuse Criteria Summary”

.

E RG compiled the reported criteria (in units of mg/L, c/mL, or S

. U

. ) for each constituent from existing literature . From these compiled values, ERG calculated the minimum and maximum reported criteria (i.e., concentrations) for each constituent

. In addition to the concentration criteria, ERG presented the associated potential issue that the fluid or well may experience, as reported in Acharya et al., 2011 ( DCN SGE 00070 ) , in Table D

- 4 in the TDD

.

3.2.2 Reuse Drivers at the Well Level

Table D

- 5 “ Reported Reuse/Recycle Practices as a Percentage of Total Fracturing Volume” presents the volume of reused/recycled wastewater as a percent of the total base fluid volume used to fracture a specific well , or the blending ratio, for several different formations. Table D

- 5 reports the actual blending ratio and /or the estimated maximum potential blending ratio reported in literature (e.g., technical presentation from an industry conference). To generate this table, ERG only used literature where UOG operators or industry experts were the author. The estimated maximum potential blending ratio was described in literature as the typical flowback volume per well compared to the typical fracturing volume per well

.

Attachm ent 3 ( DCN SGE00693 .A03 ) contains the underlying data and analysis in the “Reuse Blending Ratios Data” and “Reuse Blending Ratios Summary” tabs

. In the “Reuse Blending Ratios Data” tab, ERG tabulated actual reuse percentages and estimated maximum

reuse potential on a basin and formation basis based on values reported in ex isting literature. ERG calculated the minimum and maximum values within each category (i.e., actual blending ratio and estimated potential blending ratio) by basin and formation and pre sented the resulting
range in the “Reuse Blending Ratio Summary” tab and Table D

- 5 in the TDD

.

3.2.3 Reuse Drivers at the Formation Level

Figure D

- 6 “Hypothetical UOG Produced Water Generation and Base Fracturing Fluid Demand o ver Time” illustrates a hypothetic al scenario for UOG produced water generation. This figure indicates that

, as a formation matures, the volume of base fluid needed to fracture subsequent wells may be less than the volume of produced water generated by producing wells in the area. This fig ure was regenerated from a wastewater disposal figure presented in Shell Canada Limited ’s October 29, 2012 presentation, “ Identifying the Recycling and Treatment Criteria that M

ust be Met to Avoid Scaling and Enable Successful Re

- Use ” (DCN SGE 0030 5.A 0 3)

. The scenario is for one operator in a particular formation based on a hypothetical drilling program. ERG regenerated this figure by interpreting values of “wastewater generation” and “demand for fracturing” from the figure in the Shell presentation

. Attach ment 3 ( DCN SGE00693 .A03 ) contains the estimated volumes derived from the Shell presentation, which were used as the underlying data for Figure D

- 6 in the TDD

, in the “Hypothetical Scenario Data” and “Hypothetical Scenario Figure ” tabs

.Memorandum

M arch 31 , 2015 Page 12

4.0 Q UALITY C ONTROL P RO CEDURES

All of the analyses presented in this memorandum adhered to the Environmental Engineering Support for Clean Water Regulations Programmatic Quality Assurance Project Plan (PQAPP) (DCN SGE00957) and the Unconventional Oil and Gas (UOG) Supplemental Q uality Assurance Project Plan (SQAPP) (DCN SGE00 958 ), including collecting, evaluating, and analyzing existing data and information

. Specifically, ERG used the procedures described in Section 4 of the PQAPP to gather and manage existing data in support of the UOG proposed rulemaking. ERG staff entered reference information for relevant sources into the UOG Literature Review database. The ERG index keeper reviewed all reference information, assigned each reference a Document Control Number (DCN ), imported th e reference information into the UOG Project File Index database, and saved referenced files in the Electronic Project File folder.

ERG also used the procedures described in Section 3 of the SQAPP when collecting existing data for use in the UOG proposed r ulemaking. ERG used a combination of sources, including reports, papers, and online databases from state regulatory agencies such as departments of environmental protection and oil and gas commissions. As shown in Table 2 in this memorandum, ERG assigned a source flag (A, B, C or D ) to all references used in these analyses. ERG defines each source flag as follows:

 Source Flag A

- J ournal articl es and documents prepared by or for a government agency (e.g., site visit reports, industry meeting notes);

 Source Flag B

- Documents prepared by a verified source 21 that include citation information (e.g., operator reports, vendor documents, conference presentations, university publications);

 Source Flag C

- Documents prepared by a verified source that do not include citation information (e.g., operator reports, vendor documents, conference presentations); and

 Source Flag D

- Documents prepa red by a source that could not be verified and that do not include citation information

. EPA and ERG followed the procedures described in Section 7.0 of the PQAPP to generate, evaluate, and analyze data using a spreadsheet. ERG conducted the following QA

c hecks during the analyses:

 ERG created the three Microsoft Excel spreadsheets provided in Attachment s 1 through 3 to track useful data and to document analyses. ERG performed a 100 percent check of all data entry, manipulations and calculations, and docume nted these in an internal version of the spreadsheet.

 ERG had a senior staff member familiar with ELGs and the UOG proposed rulemaking review the results from the three Microsoft Excel spreadsheets provided in Attachments 1 through 3.

21 ERG considered sources as “verified” if we were able to find information about the author outside of the reference document. ERG primarily verified information by looking for company/organization websites that confirmed the author’s affiliation with the UOG industryMemorandum

M arch 31 , 2015 Page 13

5.0 R EFERENCES

Table 2 provides DCNs, citations , and source flags for references used in the s e analyses

. The references in Table 2 are sorted by DCN.

Table 2 . References

DCN Source Citation Source Flag a

SGE00007 .A1 0 Mantell, Matthew. 2011. Produced Water Reuse and Recycling Challenges and

Opportunities Across Major Shale Plays. Prepared by Chesapeake Energy Corporation. Presented at EPA Technical Workshops for the Hydraulic Fracturing Study

– Water Resources Management March 29

- 30, 2011. (March). B

SGE00070 Acharya , Harish R.. 2011. Cost Effective Recovery of Low

- TDS Frac Flowback

Water for Reuse. GE Global Research. A

SGE00090 NYSGEIS; Leff, Eugene. 2011. Supplemental Generic Environmental Impact

Statement (SGEIS) on the Oil, Gas, and Solution Mining Regulatory Program. New York State Department of Environmental Conservation (NYSDEC). A

SGE00153 U.S. Energy Information Administration (EIA). 2011. Shale Gas Plays, Lower 48

States. Prepared by EIA Office of Oil and Gas. (May). A

SGE00155 U.S. Energy Information Administration (EIA). 201 0 . Tight Sands Gas Plays, Lower

48 States. Prepared by EIA Office of Oil and Gas. ( June ). A

SGE00188 O'Connell, James, ERG.2014. Pennsylvania Department of Environmental

Protection’s (PA DEP) Statewide Oil and Gas Waste Reports. ( December)

. A

SGE00254 Michigan Department of Environmental Quality (MI DEQ). 2006. Michigan Oil and

Gas Regulations. Natural Resources and Environmental Protection Act

— Act No. 451 of the Public Acts of 1994, as amended. Office of Geological Survey. (April). A

SGE00275 U.S. EPA. 2012. Site Visit Report Citrus Energy Corporation Marcellus Shale Gas

Operations. A

SGE00276 U.S. EPA. 2012. Meeting with XTO Energy, Inc. about Unconventional Oil and Gas

Sanitized. A

SGE00284 Hayes, Thomas et al. 2012. Barnett and Appalachian Shale Water Management and

Reuse Technologies. Research Partnership to Secure Energy for America (RPSEA). A

SGE00298 .A2 3 Cathey, Robie. 2012. Ecosphere. Ecosphere Technology. Technical Presentation at

the 2012 3rd Water Management for Shale Plays. B

SGE00305.A03 Cheung, Timothy. 2012. Identifying the Recycling a nd Treatment Criteria That Must

be Met to Avoid Scaling and Enable Successful Reuse. Shell. C

SGE00311.A 0 3 Horn, Aaron. 2012. Examining Techniques and Chemistries For Managing Bacteria,

Scaling And Corrosion. Technical Presentation at the 2012 Shale Gas Water Management Conference. C

SGE00311.A 0 7 Dunkel, Michael. 2012. The Economics of Water Management. Technical

Presentation at the 2012 Shale Gas Water Management Conf erence. C

SGE00311 .A1 2 Mazoch, Mark. 2012. Fayetteville Shale. Southwestern Energy. Technical

Presentation at the 2012 Shale Gas Water Management Conference. B

SGE00339 Susquehanna River Basin. Marcellus & Utica Occurrence. 2011. (October 18).

Available online at: http://www.srbc.net/programs/docs/10

- 20

- 11%20T.%20Beauduy%20Testimony%20Attachments%201

- 5.pdf A

SGE00341 Veil, John. 2011. Water Management Practices Used by Fayetteville Shale Gas

Producers. United States Department of Energy National Energy Technology Laboratory. AMemorandum

M arch 31 , 2015 Page 14

Table 2 . References

DCN Source Citation Source Flag a

SGE00379 Hill, David A. 2012. The Future Is NOW for Water Recycling in the Niobrara.

Wyoming Energy News. C

SGE00422 Werline, James. 2011. Water Requirements and Sustainable Sources in the Barnett

Shale. EPA HF Technical Workshop. B

SGE00442.A 0 3 Dees, John. 2013. Reeder Energy. Mississippi Lime Production & Produced Water

Congress 2013

– Re

- Using Produced Water. Technical Presentation at the 2013 Mississippi Lime Conference. C

SGE00480 Luedecke, Richard. 2012. Energy Water Conservation & Recycling. C

SGE00486 U.S. Energy Information Administration (EIA). 2013. Assumptions to the Annual

Energy Outlook 2013. A

SGE00502 Baker Hughes. 2013. North America Rotary Rig Count Pivot Table (Feb 2011

-

Current). Last updated 11/8/2013. Downloaded on 11/11/2013. Available online at: http://phx.corporate

- ir.net/phoenix.zhtml?c=79687&p=irol

- reportsother B

SGE00503 Baker Hughes. 2013. U.S. Onshore Well Count. Last updated 10/11/2013.

Downloaded on 11/11/2013. Available online at: http://phx.corporate

ir.net/phoenix.zhtml?c=79687&p=irol

- wellcountus#. B

SGE00504 Baker Hughes. 2013. North America Rotary Rig Count (Jan 2000

- Current). Last

updated 11/15/2013. Downloaded on 11/20/2013. Available online at: http://phx.corporate

- ir.net/phoenix.zhtml?c=79687&p=irol

- reportsother B

SGE00507 Boschee, Pam. 2012. Handling Produced Water from Hydraulic Fracturing. Oil &

Gas Facilities. B

SGE00521 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes for Shale Gas Industry Meeting

Held on 29 February 2012. (April 20). A

SGE00532 Hansen et al. 2013. Water Resource Reporting and Water Footprint from Marcellus

Shale Development in West Virginia and Pennsylvania. San Jose State University. (October 30). B

SGE00556 Nicot, Jean

- Philippe. 2011. Current and Projected Water Use in the Texas Mining and

Oil and Gas Industry. Texas Water Development Board. Bureau of Economic Geology. (January). A

SGE00575 Petroleum Equipment Suppliers Association (PESA). 2012. Outlook for Domestic

Unconventional Resources. PESA Annual Meeting Presentation. B

SGE00596 ERG

. 201 5 . Analysis of Centralized Waste Treatment Facilities (CWTs) Accepting

UOG Wastewater. A

SGE00616 U.S. EPA. 2013. Summary of the Technical Workshop on Wastewater Treatment and

Related Modeling. April 18. A

SGE00625 U.S. EPA. 201 5 . Site Visit Report Southwestern Energy (SWN) Fayetteville Shale

Gas Operations Sanitized. A

SGE00637.A 0 3 Yoxtheimer, David. 2013. Produced Fluid Generation and Injection Well Disposal

Considerations. Technical Presentation at the Shale Gas Water Management Initiative. B

SGE00637.A05 Vidic, Radisav. 2013. Reuse of Produced Water For Hydraulic Fracturing.

Department of Civil and Environmental Engineering University of Pittsburgh. Technical Presentation at the 3rd Shale Play Water Management Marcellus and Utica Conference. B

SGE00639 Nicot et al. 2012. Oil & Gas Water Use in Texas: Update to the 2011 Mining Water

Use Report. (September). Bureau of Economic Geology. AMemorandum

M arch 31 , 2015 Page 15

Table 2 . References

DCN Source Citation Source Flag a

SGE00691 U.S. EPA. 2013. Summary of the Technical Workshop on Water Acquisition

Modeling: Assessing Impacts Through Modeling and Other Means. September. A

SGE00693 ERG . 201 5 . Data Compilation Memorandum for the UOG Technical Development

Document. A

SGE00705 ERG. 2014. Ruminski, Brent. Notes on Call with Hydrozonix, LLC on 7 February

2014. (March 7.) A

SGE00721 U.S. EPA. 2015. Analysis of Hydraulic Fracturing Fluid Data from the FracFocus

Chemical Disclosure Registry 1.0. (March). A

SGE00738 Livingston, Doug. 2013. Water Recycling: The Cure for Drillers' Drinking Problem?

Shale Magazine. B

SGE00739 E RG . 201 5 . Analysis of Pennsylvania Department of Environmental Protection’s Oil

and Gas Waste Reports. A

SGE00 864 IHS. 2012. America’s New Energy Future: The Unconventional Oil and Gas

Revolution and the US Economy. Volume 1: National Economic Contributions. B

SGE00963 ERG. 2015. Analysis of DI Desktop® Database. A

SGE00966 California Council on Science and Technology (CCST). 2014. Advanced Well

Stimulation Technologies in California: An Independent Review of Scientific and Technical Information. Sacramento, CA. A

SGE00988 Energy Information Administration. 2014. Assumptions to the Annual Energy

Outlook 2014. A

SGE00989 U.S. Energy Information Administration (EIA). 2014. Annual Energy Outlook 201 4

with Projections to 2040. A

SGE00991 United States Geological Survey. 2008. Assessment of Undiscovered Oil and Gas

Resources of the Permian Basin Province of West Texas and Southeast New Mexico, 2007. A

SGE00992 United States Geological Survey. Unknown. Woodbine Formation. Accessed on

10/21/2014. A

SGE00993 United States Geological Survey. Unknown. Buda Formation. Accessed on

10/21/2014. A

a

– Source Flag A

- J ournal articles and documents prepared by or for a government agency (e.g., site visit reports, industry meeting notes); Source Flag B

- Documents prepared by a verified source that include citation information (e.g., operator reports,

v endor documents, conference presentations, university publications); Source Flag C

- Documents prepared by a verified source that do not include citation information (e.g., operator reports, vendor documents, conference presentations); and Source Flag D

- Documents prepared by a source that could not be verified and that do not include citation information.A TTACHMENT 1 : O NSHORE O IL AND G AS D RILLING A CTIVITY E XCEL F ILE ( DCN SGE00693 .A01 )A TTACHMENT 2 : EIA UOG P OTENTIAL E XCEL F ILE ( DCN SGE00693 .A02 )A TTACHMENT 3: TDD D ATA C OMPILATION E XCEL F ILE ( DCN SGE00693 .A03 )