MEMORANDUM

TO: Lisa Biddle, U.S. EPA

FROM: Brent Ruminski, ERG

Sarah Yates, ERG

DATE: March 31, 2015

SUBJECT: Data Compilation Memorandum for the Technical Development Document

(TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil 

and Gas Extraction (DCN SGE00693)

This memorandum describes how ERG developed various tables and figures presented in

EPA’s Technical Development Document for Proposed Effluent Limitations 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 memorandum all of which are specific to 

unconventional oil and gas (UOG). Tables 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, Background on 

Unconventional Oil and Gas Extraction;

 Section 2.0 discusses tables and figures in the TDD Chapter C, Unconventional Oil 

and Gas Extraction Wastewater 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 presents the relevant attachment to this memorandum 

that contains the underlying data and analysis for each figure and table.

 Attachment 1 – Onshore Oil and Gas Drilling Activity - DCN SGE00693.A01

 Attachment 2 – EIA UOG Resource Potential - DCN SGE00693.A02

 Attachment 3 – TDD Data Compilation - DCN SGE00693.A03
Memorandum

March 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, 2012 1.3 SGE00693.A02

Table F-3

b UOG Resource Potential: Shale as of January 1, 2012 1.3 SGE00693.A02

Table F-4

b UOG Resource Potential: Tight as of January 1, 2012 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 gas1

produced by wells drilled2into low porosity, low permeability 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 “drill 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

March 31, 2015

Page 3

 Produced 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 COMPILATION OF DATA FOR TDD CHAPTER B

The following subsections discuss the data and methods used to develop 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)

Figure B-7 “Length of Time to Drill a Well in Various UOG Formations” 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 Days Figure”. For this analysis, ERG obtained data from Baker Hughes’ U.S. Onshore 

Well Count (DCN SGE00503). This dataset is a quarterly census of the number of new onshore 

oil and gas wells that were spud4in the U.S., and includes counts of the 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/formation5. These counts are available from first quarter 2012 through third quarter 2013, 

and are representative of all U.S. oilfield activities. 

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

B-7, ERG divided the number days in each quarter (typically 91 or 92 days) by the number of 

wells per rig for that quarter to calculate drilling efficiency, 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 counts and rig counts 

respectively for each quarter for the three different Woodford shale formations. ERG then 

performed 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 drilling of a well.

5Baker Hughes reported a mixture of basins (e.g., Williston, Permian) and formations (e.g., Marcellus, Utica) in all 

of their rig counts datasets.
Memorandum

March 31, 2015

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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 sets6listed below that 

provide different and more detailed information on active wells than the Baker Hughes U.S. 

Onshore Well Count dataset (DCN SGE00503) described in Section 1.1. ERG downloaded these 

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 analyses. Information contained in these two Baker Hughes

datasets are described below. 

 North America Rotary Rig Count (Jan 20007- Current) (DCN SGE00504): 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, mis8) and well trajectory (i.e., horizontal, 

directional, vertical). The dataset includes the following fields:

 Well Trajectory

 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;

 Number 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 SGE00502): presents a record for 

each active rig in North American on a weekly basis beginning in February 2011. The 

dataset includes the following for each rig:

 Country (i.e., Canada, United States);

 County;

 Basin9;

 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 drilling, 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 miscellaneous. 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

March 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 Active 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 figure 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, ERG

graphed the relevant U.S. data as reported in the Baker Hughes North America Rotary Rig Count

dataset (Jan 2000 - Current)10 (DCN SGE00504). Attachment 1 (DCN SGE00693.A01) contains 

the underlying data and analysis for Figure B-13 in the tabs called “Drill Over 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 formation11. 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. “United States” rigs in the Country field

b. “land” (onshore) rigs in the Location field

c. “11/8/2013” in the PublishDate field (as downloaded on November 11, 

2013).

2. In the Rigs by Basin Table, ERG summed the total number of rigs, number of gas rigs, 

and number of oil rigs for each reported basin/formation with the filters in Step 1. For 

each type (i.e., oil, gas), ERG further categorized the number of oil or gas wells by 

trajectory (i.e., directional, horizontal, 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 the 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 provide 

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

March 31, 2015

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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 summarize the total new well potential, estimated 

ultimate recovery (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, 2012”;

 Table F-3 - “UOG Resource Potential: Shale as of January 1, 2012”; and

 Table F-4 - “UOG Resource Potential: 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 2014 (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 resource 

estimates reported by EIA that 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 Recoverable Resource (TRR) – TRR is the total oil14 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 (Bbls). ERG converted the crude oil TRR from Bbls to million barrels 

(MMbbls) in the “Raw EIA Data” tab in Attachment 2 (DCN SGE00693.A02). 

 Estimated Ultimate Recovery (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 significantly from well to well. EIA reports natural gas EUR in 

units of BCF per well and crude oil EUR in units MMbbls 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 following 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

March 31, 2015

Page 7

TRR estimates, advances in drilling technology, or economic conditions that ultimately 

determine how many wells industry drills. 

Specifically, ERG 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 formation 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 few 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 by EIA) a common formation name. For example, 

EIA reported resource potential separately for “Fayetteville-Central” and “FayettevilleWest.” 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 Outlook 2013 (DCN 

SGE00486).

16 However, all unconventional oil formations were combined by EIA in this 

report into 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 SGE00693.A02), ERG 

used Equation 2 and Equation 3 below to recalculate total new 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 F4 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 Energy 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 report 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

March 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 Drillinginfo’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 SGE00864). 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 completions for 2012, 2015, 2020, 2025, 2030, and 2035. IHS 

estimates 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

assumed 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

March 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 COMPILATION OF DATA FOR TDD CHAPTER C

The following subsections discuss the data and methods used to develop the 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 “Sources 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 called “Base Fluid Data”. For some basins/formations, ERG identified data from multiple 

references and/or projected19 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 dissolved solids (TDS).

 Brackish water – Water 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 industries.

 Reuse/recycle water – This is any UOG extraction wastewater (i.e., flowback, longterm 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 these projected data 

parenthetically. 

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 commonly

used in the hydraulic fracturing 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 SGE00721). However, ERG reorganized 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 projected 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

March 31, 2015

Page 10

concentration. Attachment 3 (DCN SGE00693.A03) contains the underlying data and ordering 

process in the tab “ORD FF Chemicals”.

3.0 COMPILATION OF DATA FOR TDD CHAPTER D

The following subsections discuss the data and methods used to develop tables and 

figures listed in Table 1 and presented in TDD Chapter D. 

3.1 TDD Chapter D, Introduction (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 

practices. Some sources only contained qualitative produced water management information, 

while others also reported the percentage of produced water disposed of via each management 

practice. Because quantitative data were not available across all formations, ERG 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 to generate Table 

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 concentrations 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 Ground 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

March 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 Criteria Data” and “Reuse 

Criteria Summary”.

ERG 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 SGE00070), 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.

Attachment 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 existing 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 presented 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 over Time” illustrates a hypothetical 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 figure was regenerated from a wastewater disposal figure presented in Shell 

Canada Limited’s October 29, 2012 presentation, “Identifying the Recycling and Treatment 

Criteria that Must be Met to Avoid Scaling and Enable Successful Re-Use” (DCN

SGE00305.A03). 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. Attachment 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

March 31, 2015

Page 12

4.0 QUALITY CONTROL PROCEDURES

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 

Quality Assurance Project Plan (SQAPP) (DCN SGE00958), 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 the 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 rulemaking. 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 - Journal 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 source21 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 prepared 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 

checks during the analyses:

 ERG created the three Microsoft Excel spreadsheets provided in Attachments 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 documented 

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 industry
Memorandum

March 31, 2015

Page 13

5.0 REFERENCES

Table 2 provides DCNs, citations, and source flags for references used in these analyses. 

The references in Table 2 are sorted by DCN.

Table 2. References

DCN Source Citation 

Source 

Flaga

SGE00007.A10 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). 2010. 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.A23 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 and Treatment Criteria That Must 

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

C

SGE00311.A03 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.A07 Dunkel, Michael. 2012. The Economics of Water Management. Technical 

Presentation at the 2012 Shale Gas Water Management Conference.

C

SGE00311.A12 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.

A
Memorandum

March 31, 2015

Page 14

Table 2. References

DCN Source Citation 

Source 

Flaga

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.A03 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.corporateir.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. 2015. 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. 2015. Site Visit Report Southwestern Energy (SWN) Fayetteville Shale 

Gas Operations Sanitized.

A

SGE00637.A03 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. 

A
Memorandum

March 31, 2015

Page 15

Table 2. References

DCN Source Citation 

Source 

Flaga

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. 2015. 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 ERG. 2015. Analysis of Pennsylvania Department of Environmental Protection’s Oil 

and Gas Waste Reports.

A

SGE00864 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 2014

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 - Journal 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, 

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 prepared by a source that could not be verified and that do not include citation 

information.
ATTACHMENT 1: ONSHORE OIL AND GAS DRILLING ACTIVITY EXCEL FILE (DCN

SGE00693.A01)
ATTACHMENT 2: EIA UOG POTENTIAL EXCEL FILE (DCN SGE00693.A02)
ATTACHMENT 3: TDD DATA COMPILATION EXCEL FILE (DCN SGE00693.A03)