MEMORANDUM

TO: Lisa Biddle, EPA

Karen Milam, EPA

FROM: James K. O’Connell, ERG 

Brent Ruminski, ERG

Jason Sese, ERG

Sarah Yates, ERG

DATE: June 7, 2016

SUBJECT: Unconventional Oil and Gas (UOG) Produced Water Volumes and 

Characterization Data Compilation – DCN SGE01184

This memorandum describes the data and methods used to compile unconventional oil 

and gas (UOG) produced water volumes and characterization data for the Technical 

Development Document for Effluent Limitations Guidelines and Standards for Oil and Gas 

Extraction (TDD) (DCN SGE01188). Specifically, this memorandum focuses on information 

included in Chapter C in the TDD; it covers: data sources used, preparation and analysis of data, 

and compilation of summary data. Table 1, below, provides an index of the tables and figures 

explained in more detail in this memorandum. Tables and figures in the TDD that are not 

described in this memorandum either did not require calculations or analysis by ERG, or are 

described in separate, supporting memoranda. The Crosswalk Memorandum between Proposed 

and Final Technical Development Document for Effluent Limitations Guidelines and Standards 

for Oil and Gas Extraction: Tables and Figures (DCN SGE01334) contains a crosswalk of all 

tables and figures in the TDD. Appendix F of the TDD contains the name of the relevant 

supporting memorandum for each TDD table and figure, where applicable. This memorandum is 

organized into the following sections:

 Section 1.0 Compilation of UOG produced water volume data (TDD Table C-7, 

Table C-8, and Table C-9)

 Section 2.0 Compilation of UOG produced water rates over time (TDD Figure C2).

 Section 3.0 UOG produced water characterization database and its related 

analyses.

 Section 4.0 describes individual analyses ERG performed to obtain produced 

water volume and characterization data.

 Section 5.0 describes additional UOG produced water characterization data 

analyses using national and state-level datasets.

 Section 6.0 describes ERG’s quality assurance procedures.

 Section 7.0 lists the references used for this memorandum and its attachments.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 2

The 16 attachments to this memorandum contain the underlying data and calculations 

used to support the information presented in the TDD and to create the TDD tables and figures

discussed in this memorandum. These attachments are listed in Section 8.0 below.

For the tables/figures explained in more detail in this memorandum, Table 1 provides the 

TDD chapter, memorandum section, and attachment information. 

Table 1. List of Tables and Figures Discussed in this Memorandum

TDD Table or 

Figure Number TDD Table or Figure Title

Memo.

Section

Memo. Attachment 

Number

Figure C-2

Ranges of Typical Produced Water Generation Rates 

Over Time After Fracturing 2.0 SGE01184.A01

Figure C-3

Anions and Cations Contributing to TDS Concentrations 

in Shale and Tight Oil and Gas Formations 3.3 SGE01184.A12

Figure C-4

Chloride, Sodium, and Calcium Concentrations in 

Flowback and Long-Term Produced Water (LTPW) from 

Shale and Tight Oil and Gas Formations

3.3 SGE01184.A12

Figure C-5

Barium Concentrations in UOG Produced Water from 

Shale and Tight Oil and Gas Formations 3.3 SGE01184.A12

Table C-7

UOG Well Flowback Recovery by Resource and Well 

Trajectory 1.0 SGE01184.A01

Table C-8

Long-Term Produced Water Generation Rates by 

Resource Type and Well Trajectory 1.0 SGE01184.A01

Table C-9 Produced Water Volume Generation by UOG Formation 1.0 SGE01184.A01

Table C-11 Concentrations of Select Classical and Conventional 

Constituents in UOG Produced Water 3.3 SGE01184.A12

Table C-13 Concentrations of Select Anions and Cations 

Contributing to TDS in UOG Produced Water 3.3 SGE01184.A12

Table C-15 Concentrations of Select Organic Constituents in UOG 

Produced Water 3.3 SGE01184.A12

Table C-17 Concentrations of Select Metal Constituents in UOG 

Produced Water 3.3 SGE01184.A12

Table C-19 Concentrations of Select Radioactive Constituents in 

UOG Produced Water 3.3 SGE01184.A12

For definitions of common terms used throughout the TDD, the supporting memoranda, 

and memoranda attachments, please refer to the Glossary in the introduction of the TDD. 

1.0 COMPILATION OF UOG PRODUCED WATER VOLUME DATA

ERG compiled data to characterize typical volumes of water used for fracturing fluid and

the rate at which wastewater is generated during UOG extraction on a per well basis. 

Specifically, ERG compiled the following data:
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

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 Fracturing fluid volume (million gallons per well, Mgal/well)1

 Flowback recovery (percent of fracturing fluid volume)

 Long-term produced water rates (gallons per day per well, gpd/well)

Table C-9, “Produced Water Volume Generation by UOG Formation,” contains these

data listed above by UOG formation (e.g., Marcellus) and well trajectory. ERG also generated 

Tables C-6 and C-8 in the TDD, both of which are higher-level aggregations of the data 

presented in Table C-9. Table C-7, “UOG Well Flowback Recovery by Resource and Well 

Trajectory,” presents flowback recovery at the resource type level, and Table C-8, “Long-Term 

Produced Water Generation Rates by Resource Type and Well Trajectory,” presents long-term 

produced water rates at the resource type level. The following subsections provide more 

information about the data sources and methods used to generate Tables C-7, C-8 and C-9 in the

TDD.

1.1 Key Data Sources

ERG used three general categories of datasets for this analysis: 

 National-level datasets (Drillinginfo, Inc. (DI) Desktop®, FracFocus®)

 State-level datasets (e.g., state oil and gas databases)

 Available literature

The specific data fields that ERG used from each of these sources are explained in the 

individual example analyses presented in Section 4.0.

1.1.1 National-level Datasets

ERG used two national-level datasets, DI Desktop® and FracFocus®. ERG conducted an 

analysis to calculate the median, as well as to illustrate the range of values contained 

within a given dataset2. The DI Desktop® and FracFocus® analyses are explained in 

Sections 4.1 and 4.2 of this memorandum, respectively. 

1.1.1.1 DI Desktop® Well File Database (DCN SGE01170)

DI Desktop® is a comprehensive well file database compiled and maintained by DI that 

provides a record for all oil and gas wells drilled in the United States.3 The underlying data in the 

DI Desktop® database comes from individual state oil and gas agencies and contains a record for 

all oil and gas wells ever drilled.

4 Data for each well include: well API number, well completion

date, well depth, latitude, longitude, and well trajectory. DI Desktop® also includes annual oil, 

gas, and produced water production per well from 2000 through 2014. The version of the DI 

Desktop® database that ERG used for this analysis was downloaded in March 2015, representing, 

 

1 Flowback volumes can be estimated by multiplying the total fracturing fluid volume by the percent of fracturing 

fluid returned as flowback. However, ERG does not perform this calculation.

2

In most cases, ERG calculated the 10th percentile and 90th percentile values to represent the typical range of the 

data.

3 The database is subject to restrictions on its use and dissemination. Based on the license agreement discussions, 

access to the raw data in the database is limited to ERG and EPA personnel only; although summary data developed 

using queries can be disseminated more widely. Wholesale “data dumps” cannot be disseminated electronically. All 

disseminations of such summary data, however, should cite Drillinginfo as the source of the information.

4 The exact year recordkeeping began varies by state, with the majority of records dating back to 1900.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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for the most part, data from 2014 but this varies by state. State-level information such as the oil 

and gas agency names, last production date5, production start date6, and update frequency (e.g., 

monthly, quarterly) is provided in Drillinginfo’s Data Coverage table (DCN SGE01171). The 

raw data are contained in the “DI Desktop Wells (SGE01170)” table in Attachment 3 (DCN 

SGE01184.A03). 

1.1.1.2 FracFocus® Database (DCN SGE01169)

FracFocus® is an industry-managed national registry of chemicals used in hydraulic 

fracturing. Operators submit disclosures to FracFocus® for individual wells that they 

hydraulically fracture.

7 Historically, submitting disclosures has been voluntary, but some states 

are beginning to mandate reporting to FracFocus®. Each record includes the well completion 

date, well type (oil or gas), total fracturing fluid volume (in gallons), well API number, well 

depth, latitude, longitude, and the concentrations of additives in the fracturing fluid.

In June 2015, FracFocus® published a Microsoft Access database (FracFocus® 2.0)

containing all of the public disclosures submitted to the organization through June 2015. It 

contains over 102,000 well records. In July 2015, ERG downloaded FracFocus® 2.0 directly 

from the FracFocus® website (https://fracfocus.org/data-download). The raw data from

FracFocus® 2.0 is contained in the “FF V2 (SGE01169)” table in Attachment 5 (DCN 

SGE01184.A05).

1.1.2 State-level Datasets

To estimate typical produced water volumes and rates in some states, ERG used 

databases from Ohio, Colorado, New Mexico, North Dakota, and Wyoming state agencies. ERG 

included these states because they have significant UOG activity and their state oil and gas 

agencies publish comprehensive databases that contain monthly or annual produced water 

volumes per well (depending on the state), and include well API number, formation name, well 

completion date, and/or well trajectory. The analyses ERG performed are described in Sections 

4.3 through 4.8; Attachments 6 through 11 contain the data and ERG’s calculations (DCN 

SGE01184.A06-11). A more detailed description of each data source is provided in the “Data 

Source” subsections in Sections 4.3 through 4.8.

1.1.3 Available Literature

ERG also used other literature that reported UOG produced water volumes or rates, such 

as detailed reports, site visit reports, and technical presentations from conferences. These 

data sources appear in Table 10 at the end of this memorandum, and are also listed in the

“Source” column in the “PW Data” tab in Attachment 1 (DCN SGE01184.A01). Many of 

the references that ERG used reported produced water volumes and rates in terms of 

lower range, median or average, and/or upper range. For example, one reference

 

5 This is the date that the state last updated the data that Drillinginfo included in ERG’s version of the DI Desktop®

database downloaded on March 30, 2015.

6 First year that the state agency maintained records for oil and gas wells. 

7 These reports represent wells completed in UOG formations, conventional oil and gas (COG) formations, and 

coalbed methane formations.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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specifically reported that a typical horizontal Barnett well requires approximately 

1,000,000 to 7,300,000 gallons of fracturing fluid, with a median of 3,700,000 gallons,

based on data for 14,000 wells (DCN SGE00465). ERG entered these values into the PW 

Data tab as the lower range,

8

upper range, median/average, and number of data points.

This data compilation procedure is further described in Section 1.2.

1.2 General Data Compilation Procedures

ERG took the following steps to generate Tables C-7, C-8, and C-9 in the TDD. Each of 

these steps corresponds to a specific tab in Attachment 1 (DCN SGE01184.A01), as noted in the 

headings below.

Step 1: Data input into PW Data tab

The PW Data tab contains the fracturing fluid volume and produced water volume data

generated by the individual analyses that ERG performed (described in Sections 4.1

through 4.8) and reported in other available literature. ERG initiated a new record item 

(i.e., row) in this tab only when the existing data source reported the UOG formation and 

well trajectory. ERG calculated weighted averages of fracturing fluid volume, flowback 

recovery, and long-term produced water generation rates using the Equations in Step 2 

(Equation 1) and Step 3 (Equation 2) below. These averages were weighted by the 

number of data points contained in each formation/trajectory and resource/trajectory 

combination (i.e., combinations with more data points were given more weight in 

calculating the averages than those with fewer data points). The PW Data tab contains the 

following data fields:

 Basin

 Formation

 Resource type (shale, tight)

 Well trajectory (horizontal, directional, vertical)

 Fracturing fluid volume

◦ Lower range (barrels/well)

◦ Median/average (barrels/well)9

◦ Upper range (barrels/well)

◦ Number of data points

 Flowback recovery (% of fracturing fluid injected)

◦ Lower range

◦ Median/average9

◦ Upper range

◦ Number of data points

 Long-term produced water generation rates

◦ Lower range (barrels/day/well)

 

8 The lower and upper ranges represent the 10th and 90th percentile values, respectively, of the data ERG analyzed. 

Percentile values were chosen to represent the range of data instead of the minimum and maximum values reported, 

as the minimum and maximum values may not be representative of the typical range.

9

In some cases, ERG’s individual analyses produced median values that would be entered into this field. In other 

cases, values from literature were reported as an average. Therefore, a value in this field could represent a median, 

an average, or an uncharacterized single value. 
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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◦ Median/average (barrels/day/well)9

◦ Upper range (barrels/day/well)

◦ Number of data points

 Source Flag (A, B, C, or D)10

 Data Quality Justification

 Notes

 Source (i.e., DCN number)

ERG followed the procedures listed below for entering data into the PW Data tab:

 Where data were available for input, but the number of data points was not reported, 

ERG assigned the number of data points equal to 1. 

 Where data were only available in the form of a range (e.g., 100 to 150 gpd/well), ERG 

assigned these two values to the lower and upper range fields, respectively. ERG

assigned no value to the median/average field and assigned a 2 to the number of data 

points field.

 ERG only considered non-null values in the analysis. Note that values reported as zero 

were not considered null values. Values reported as zeros were counted as zeros in all 

calculations.

 Where a data point was reported only as a minimum or maximum, ERG assigned this 

value to the lower or upper range field, as appropriate. ERG assigned no value to the 

median/average field and assigned the number of data points equal to 1.

 In most cases, ERG used literature that specifically reported flowback in terms of 

percent of fracturing fluid volume, and long-term produced water in terms of flow rate 

(e.g., gallons per day, barrels per day, gallons per year, barrels per year). If the 

literature did not report the data on these bases, ERG’s alternative 

approaches/assumptions are described in the “Notes” column in the PW Data tab in 

Attachment 1 (DCN SGE01184.A01).

Step 2: Generation of PW Data by Formation tab (TDD Table C-9)

To create TDD Table C-9, ERG aggregated the data in the PW Data tab in Attachment 1 

(DCN SGE01184.A01) by formation and well trajectory (e.g., horizontal Barnett wells, 

vertical Marcellus wells). Table C-9 presents the following three different types of 

produced water data: fracturing fluid volume, flowback recovery (percent of fracturing 

fluid returned), and long-term produced water generation rate. For each formation and 

well trajectory combination, and for each of these three types of produced water data, 

ERG calculated the following:

 Minimum of the lower range – Identified the minimum value in the lower range 

reported in the PW Data tab for each formation and well trajectory combination.

 Weighted average of the median/average values – Calculated the weighted average of 

the average/median values (based on the number of data points) reported in the PW 

Data tab for each formation and well trajectory combination, using Equation 1 below.

 Maximum of the upper range – Identified the maximum value in the upper range 

reported in the PW Data tab for each formation and well trajectory combination.

 

10 For a discussion on the source flags, please see Section 6.0.
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 Number of data points – Summed the total number of data points reported in the PW 

Data tab for each formation and well trajectory combination.

Equation 1

Weighted AverageForm,i = ∑ Voli ×

Ni

Formi NFormi

Where,

Formi = Each formation and trajectory combination

NForm,i = Number of total data points for each formation and trajectory combination

Ni = Number of data points for line item entered into the PW Data tab

Voli = Volume data point (i.e., fracturing fluid volume, flowback recovery, or long-term produced 

water rate)

The calculated values are listed in the columns marked “Data from the PW Data tab” in 

the PW Data by Formation tab. ERG rounded these values to two significant11 figures for 

the TDD; these rounded numbers are listed in the columns marked “Sig Figs for TDD” in 

the PW Data by Formation tab.

This tab also includes columns indicating the number of data points that came from 

sources with a specified source flag. This information is presented to demonstrate both 

the quantity of data available, as well as the relative quality of the underlying 

information. For more information about source flags, see Section 6.0.

Step 3: Generation of PW Data by Resource tab (TDD Table C-7 and Table C-8)

To create TDD Tables C-7 and C-8, ERG aggregated data in the PW Data tab in 

Attachment 1 (DCN SGE01184.A01) by resource type and well trajectory (e.g., 

horizontal shale wells, vertical tight wells). Table C-7 presents fracturing fluid volume 

and flowback recovery by UOG resource type and well trajectory. Table C-8 shows longterm produced water rates by UOG resource type and well trajectory. ERG calculated the 

following for each of these types of volume data:

 Minimum of the lower range – Identified the minimum value in the lower range 

reported in the PW Data tab for each resource type and well trajectory combination.

 Weighted average of the median/average values – Calculated the weighted average 

(based on the number of data points) of the average/median values reported in the PW 

Data tab for each resource type and well trajectory combination using Equation 2

below.

 Maximum of the upper range – Identified the maximum value in the upper range 

reported in the PW Data tab for each resource type and well trajectory combination.

 Number of data points – Summed the total number of data points reported in the PW 

Data tab for each resource type and well trajectory combination.

 

11 Since the number of significant figures contained in the source material varies and in some cases is unknown, it 

would be impractical to maintain significant figures throughout all calculations.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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Equation 2

Weighted AverageRes,i = ∑ Voli ×

Ni

Resi NResi

Where,

Resi = Each resource type and trajectory combination

NRes,i = Number of total data points for the resource type and trajectory combination

Ni = Number of data points for the specific data point/range entered

Voli = Volume data point (i.e., fracturing fluid volume, flowback recovery, or long-term produced 

water rate)

ERG rounded the calculated values to two significant figures for the TDD; these rounded 

numbers are listed below the row marked “Sig Figs for TDD Tables” in the PW Data by 

Resource tab.

2.0 COMPILATION OF UOG PRODUCED WATER RATES OVER TIME AFTER FRACTURING

ERG compiled produced water rates (e.g., gallons per day) over time after fracturing 

from available literature to generate Figure C-2 in the TDD. This graph shows that flowback 

rates after fracturing are initially high and decrease rapidly over time before gradually leveling 

off to long-term produced water rates.

2.1 Data Sources

ERG used numerous literature sources that reported produced water rates over time after 

hydraulic fracturing. ERG only included data points from sources reporting the associated well 

trajectory, number of days after fracture, and associated UOG formation. These data sources are 

identified by DCN number for each data point in the “Source” column in the FB Data tab in 

Attachment 1 (DCN SGE01184.A01). Most of these references were studies of flowback rates

and characteristics over time after fracturing.

12

2.2 Methods and Procedures

To compile typical produced water flow rates over time after fracturing, ERG took the 

following steps:

Step 1:

ERG entered data from literature into the following data fields in the FB Data tab 

in Attachment 1 (DCN SGE01184.A01):

 Basin

 Formation

 Well Trajectory (horizontal, vertical)

 Reported Flow Rate (barrels per day, bpd)

13

 

12 Most of these studies specifically reported flowback rates, as opposed to produced water, long-term produced 

water, or a more vague description of UOG wastewater. 

13 References reported flowback rates in units of barrels per day. Step 3 shows how ERG converted these rates from 

barrels per day to gallons per day.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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 Number of Days after Fracturing

 Number of Data Points

 Source Flag

 Notes

 Source (DCN number)

Step 2:

Next, ERG categorized each data point based on how long after fracturing the 

reported flow rate was measured. The categories were 1–5 days, 6–14 days, and 15–90 

days. For example, if a source reported the flow rate three days after the fracture, ERG 

assigned it to the “1-5 days” category. The appropriate category was listed for each data 

point in the “Day Category_ERG” column in the FB Data tab in Attachment 1 (DCN 

SGE01184.A01).

Step 3:

The FB Data Summary tab in Attachment 1 (DCN SGE01184.A01) shows ERG’s

calculations of the 10th percentile, median (i.e., 50th percentile), and 90th percentile flow 

rates, and the number of data points for each UOG formation, well trajectory, and day 

category (e.g., 1-5 days). ERG converted values from barrels per day to gallons per day 

by multiplying by 42 (gallons/barrel) and rounding the results to two significant figures.

This tab also shows the list of sources that ERG used to calculate flow rates for each 

formation and well trajectory, and a list of the corresponding source flags.

ERG also calculated the same results for all basins and formations combined in 

the last row in the FB Data Summary tab in Attachment 1 and summed the total number 

of data points. The results for all basins and formations are shown graphically in the FB 

Rates Graph tab, which is also Figure C-2 “Typical UOG Well Produced Water 

Generation Rates” in the TDD. In the FB Rates Graph tab, ERG obtained the “Well Life

(~10 – 30 years)” data points from the “Weighted Average LTPW Rate” column in the 

PW Data by Resource tab in Attachment 1.

3.0 UOG PRODUCED WATER CHARACTERIZATION DATA

ERG developed the UOG Wastewater Characterization database to collect information 

about the constituents in UOG extraction wastewater. The database compiles information about 

each well (e.g., location), the type of wastewater sampled (e.g., flowback), measured 

constituents, and the range of concentrations measured and recorded. The UOG Wastewater 

Characterization database is included in Attachment 13 (DCN SGE01184.A13). 

While the database compiles information on various types of wastewater, this 

memorandum only discusses the wastewater characterization data associated with UOG 

produced water. Additionally, wastewater characterization data associated with drilling 

wastewater is discussed in the Unconventional Oil and Gas (UOG) Drilling Wastewater

memorandum (DCN SGE01181). Sources of information included in the UOG Wastewater 

Characterization database and analyses of the collected data are described in detail in the 

following sections of this memorandum. 
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3.1 Data Sources

ERG compiled characterization data from approximately 50 sources, including publicly 

available databases, industry reports, and numerous journal articles and technical papers. ERG 

also analyzed and aggregated data from the 2015 United States Geological Survey (USGS) 

Produced Water Geochemical Database v. 2.1 (PROVISIONAL) (USGS database) by well, as 

described in Section 5.1 and shown in Attachments 14 and 15 (DCN SGE01184.A14-A15). ERG 

standardized the data from ORD’s non-confidential business information (CBI)

14 well operator 

data, as described in Section 5.2 and shown in Attachment 16 (DCN SGE01184.A16). ERG also 

analyzed and aggregated data from the Wyoming Oil and Gas Conservation Commission (WY 

OGCC) by well, as described in Section 5.3 and shown in Attachment 17 (DCN 

SGE01184.A17).

Table 10 lists all data sources that ERG used to develop the UOG Wastewater 

Characterization database (specifically flagged with an “X” in the “WW Char.” column), 

including the document control numbers (DCNs), source citations, and source quality flags (A, 

B, C, or D). The source quality flags are described further in the TDD and in Section 6.0 in this 

memorandum. In some cases, multiple sources reference the same original data source; therefore, 

ERG reviewed the content of each source to identify duplicated data. When ERG found 

duplicated data, ERG selected data from only one source.

3.2 Key Database Fields and Standardization Procedures

The UOG Wastewater Characterization database in Attachment 13 (DCN 

SGE01184.A13) was designed to incorporate information from different data sources and to 

identify key wastewater characterization information, including: 

 Measured constituent

 Constituent category (e.g., metal)

 Location/region

 Basin

 Formation

 Resource type (shale, tight)

 Well type (gas or oil)

 Well trajectory (horizontal, directional, vertical)

 Wastewater description (e.g., flowback, long-term produced water, UOG wastewater)

 Sample information (e.g., number of samples, units, analytical methods)

 Concentration values (e.g., detection limit minimum value, median value,

15 maximum 

value)

 

14 ORD removed all of the data flagged as confidential business information (CBI) under the Toxic Substances 

Control Act of 1976 (TSCA) before providing this subset of data to ERG.

15 The “median” field in the UOG Wastewater Characterization database can represent medians, averages, or other 

uncharacterized single values.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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ERG extracted the information listed above from each data source, where available. Missing data 

elements were marked as “unknown.” 

Because naming conventions, terminology, and measured units differed by data source, 

ERG standardized each data field to allow for comparison and summary of data across the entire 

database. The following sections provide details on how ERG standardized the overall dataset to 

facilitate comparison of data across all data sources. All of the data, crosswalks, and analyses 

described below are contained within the UOG Wastewater Characterization database (DCN 

SGE01184.A13).

3.2.1 Data Preparation

ERG used four main raw data tables in the UOG Wastewater Characterization database: a 

general “Pollutant Concentrations” summary table, data imported from the USGS database, 

national-level produced water characterization data from EPA’s ORD, and data provided by WY 

OGCC. The general “Pollutant Concentrations” summary table was compiled from the various 

sources listed in Table 10, but excluded the USGS and ORD data. The methods that ERG used to 

standardize the data from the USGS and ORD datasets are discussed in Sections 5.1 and 5.2, 

respectively. These three data tables were then compiled into a single data table in the UOG 

Wastewater Characterization database. 

When extracting data that were expressed as a range by a data source, ERG assigned the 

two range values to the lower and upper range fields. Where only a single measurement was 

reported, that value was entered into the median field; therefore, a data point in the median field 

could be a median, an average, or some other uncharacterized single value.

ERG placed data related to the measured constituent, basin, formation, resource type, 

well type, well trajectory, and wastewater description into raw data fields, capturing the data as 

they were reported by the source. Before performing any analyses of the dataset, ERG removed 

all leading and trailing spaces from the raw data fields. 

3.2.2 Constituent Standardization and Constituent Category Assignments

ERG created a list of all constituents included in the various sources and created a 

“Pollutant Parameter Crosswalk” to standardize constituent names. For example, “Co” and 

“Cobalt” were standardized to “Cobalt.” 

In a separate “Pollutant Categories Crosswalk,” ERG assigned primary and secondary 

(optional) categories for each standard constituent name to allow for grouping and analysis of 

certain constituents. For example, aluminum was placed in the “Metals” category. All crosswalks 

used in the data standardization and analyses are contained in the database. 
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3.2.3 Minimum, Median,

16 and Maximum Data

For each set of reported constituent concentrations from a given source, ERG compared 

the minimum, median,

16 and maximum values, where available, to ensure regularity in the data. 

If the reported values did not reflect the correct relative sequence (minimum value < median 

value < maximum value), ERG reviewed the values to determine the source of error, and if 

appropriate, corrected the values so that the correct relative sequence was maintained. ERG 

completed this correction in queries 101 through 121 of UOG Wastewater Characterization 

database in Attachment 13 (DCN SGE01184.A13). ERG only considered non-null values in the 

analysis. (Note that values reported as zero were not considered null values.)

In some cases, data sources indicated that certain values were not measured because they 

did not exceed the limit of detection. Where a source reported a non-detect value but listed the 

associated limit of detection, ERG used the limit of detection as the measured value. Where a 

source reported a non-detect value but did not report the associated limit of detection, ERG did 

not assign a value.

3.2.4 Formation Name Standardization

ERG compiled a list of reported formation names and created a “Raw Formation Name 

Crosswalk” to standardize formation names. For example, data sources that reported variations 

of the Bakken formation (e.g., Bakken MT, Bakken, ND Core, etc.) were standardized and 

updated to Bakken. Formation names that were not reported within the reference and that ERG 

could not associate with an existing formation, or that were reported as being associated with a 

conventional well, were designated as “NA–Unknown” or “NA–Conventional,” respectively. 

3.2.5 Basin Name Standardization and Location/Region Assignment

Similar to the formation name standardization method discussed above, ERG created a 

separate “Raw Basin Name Crosswalk,” to standardize and update basin names. 

However, in some instances, data sources did not report a specific basin, but did report 

the associated formation. ERG generated a “Basin-Formation Crosswalk” of known basins and 

formations to infer basin names based on the formation names. ERG devised the crosswalk by 

referencing EIA documents and using engineering judgment (DCN SGE01190, DCN 

SGE01191). Basin names that were not reported within the reference, that ERG could not 

associate with an existing basin, or that were reported as being associated with a conventional oil 

and gas well were designated as NA–Unknown or NA–Conventional, as appropriate. 

ERG also created a “Basin-Region Crosswalk,” assigning each basin to its appropriate 

region (Northeast, Gulf Coast, Midcontinent, Southwest, Rocky Mountain, or West Coast), as 

identified by the U.S. EIA in their 2015 Assumptions to the Annual Energy Outlook (DCN 

SGE01190).

 

16 The “median” field in the UOG Wastewater Characterization database can represent medians, averages, or other 

uncharacterized single values.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 13

3.2.6 Well Trajectory, Resource Type, and Well Type Standardization

Based on the information available within each data source, ERG assigned well 

trajectory, resource type, and well type for each set of data points, using the “Well Trajectory 

Crosswalk” and “Well Type –Resource Type Crosswalk.” ERG identified well trajectory as 

horizontal, vertical, directional, or unknown. ERG defined resource type as conventional, NA 

(unknown), shale and/or tight, and ERG defined well type as NA (unknown or conventional), or 

oil and/or gas.

3.2.7 Wastewater Description Standardization

ERG standardized wastewater descriptions provided in each data source into the 

following categories:

17 fracturing fluid, base fluid, flowback, produced water; UOG 

wastewater18; and unknown. These were standardized using the “WW Description Crosswalk” in 

the UOG Wastewater Characterization database (DCN SGE01184.A13). ERG captured 

wastewater descriptions as reported in the existing data source and did not reclassify any 

wastewater descriptions. ERG only standardized names (e.g., “flowback” and “fracturing fluid 

flowback” were consolidated into “flowback”).

3.2.8 Units of Measure Standardization

ERG converted reported constituent concentrations to standardized units of measure 

appropriate for each constituent. ERG established a “Unit Definition Crosswalk,” in the database 

to list units and conversion factors. 

3.3 Data Summary Analysis for TDD

Once ERG standardized all of the data and compiled them into a single summary table in 

the database, ERG queried produced water data for 79 specific constituents of interest for the 

TDD. ERG compiled the list of constituents of interest based on the presence and relevance of 

the given constituent in the UOG industry, as indicated by data provided in existing literature. 

The list comprised 21 classical and conventional constituents19, 31 metals, 21 organics, 2 others, 

and 4 radioactive constituents, as listed in Table 2 below. 

 

17 These terms (fracturing fluid, base fluid, flowback, produced water, UOG wastewater, and unknown) refer to the 

wastewater descriptions reported in the underlying data sources and do not always correspond with the definitions of 

these terms as used throughout the TDD, the supporting memoranda, and memoranda attachments (defined at the 

beginning of this memorandum).

18 ERG assigned the “UOG wastewater” category to any data source that reported data associated with wastewater 

generated from the well after fracture, but that did not specify flowback or produced water.

19 Section 304(a)(4) of the that Clean Water Act (CWA) designates the following as "conventional" pollutants: 

biochemical oxygen demand (BOD5), total suspended solids (TSS), fecal coliform, pH, and any additional pollutants 

EPA defines as conventional. The Agency designated "oil and grease" as an additional conventional pollutant on 

July 30, 1979 (see 44 FR 44501). The CWA does not define “classical” pollutant. Rather, pollutants that are not 

designated as either conventional or toxic are considered nonconventional pollutants. An example would be TDS. In 

the discussion of pollutants in UOG wastewaters in this memorandum, ERG has organized the discussion according 

to the categories in Table 2, which includes the category “Classical and conventional”. In this context, “Classical 

and conventional” refers to a range of parameters that are determined via classical wet chemistry analytical methods, 

including some CWA 304(a)(4) conventional pollutants as well as other parameters such as nutrients, alkalinity, 

hardness, COD, etc.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 14

Table 2. Constituents of Interest for the TDD, by Constituent Category

Constituent Category Constituent

Classicals and Conventionals

Alkalinity, Ammonia, Bicarbonate, BOD, Bromide, Carbonate, Chloride, COD, 

Fluoride, Hardness, Hardness as CaCO3, Nitrate, Nitrite, Oil and Grease, pH, 

Phosphate, Specific Conductivity, Sulfate, TDS, TOC, TSS

Metals

Aluminum, Antimony, Arsenic, Barium, Beryllium, Boron, Cadmium, Calcium, 

Chromium, Cobalt, Copper, Fluorine, Iron, Lead, Lithium, Magnesium, 

Manganese, Mercury, Molybdenum, Nickel, Phosphorus, Potassium, Selenium, 

Silver, Sodium, Strontium, Thallium, Tin, Titanium, Vanadium, Zinc

Organics

1,2,4-Trimethylbenzene, 1,3,5-Trimethylbenzene, 2-Butoxyethanol, Acetone, 

Benzene, BTEX, Carbon Disulfide, Chlorobenzene, Chloroform, Ethanol,

Ethylbenzene, Isopropylbenzene, Methanol, Methyl Chloride, Naphthalene, 

Phenol, Pyridine, Tert-butylacetate, Tetrachloroethylene, Toluene, Xylenes

Other Sulfate Reducing Bacteria, Sulfide

Radioactives Gross Alpha, Gross Beta, Radium 226, Radium 228

ERG exported data for the selected constituents from the database to Excel to generate 

summary tables and figures for the TDD. Attachment 12 (DCN SGE01184.A12) includes the 

Excel file with the exported data and all of the analyses that ERG conducted to generate 

summary tables and figures for the TDD. The Table of Contents (TOC) in Attachment 12

indicates the specific tabs with data and calculations for each TDD figure and table.

ERG did not use actual minimum and maximum reported values for the summary tables; 

lower and upper ranges were defined using the 10th and 90th percentiles of the median values

(i.e., the lower range corresponds to the 10th percentile of the median value and the upper range

corresponds to the 90th percentile of the median value).

20 ERG further reduced the dataset by 

removing data that were related to conventional or unknown wells, and limited the wastewaters 

of interest to the following types of wastewater, as reported in the UOG Wastewater 

Characterization database (DCN SGE01184.A13): flowback, UOG wastewater, and produced 

water. To create TDD Table C-11, Table C-13, Table C-15, Table C-17, and Table C-19 

presented in Section C.3 (UOG Extraction Wastewater Characterization), ERG filtered the final 

dataset by specific constituent categories (e.g., classical and conventional19, metals, organics) 

and tabulated the 10th percentile of the median data field, 50th percentile (median) of the median 

data field, 90th percentile of the median data field, number of data points, and number of detects21

for each constituent. ERG also sometimes organized the produced water characterization data by 

formation name. The analyses used to generate the drilling wastewater characterization tables 

(i.e., TDD Table C-10, Table C-12, Table C-14, Table C-16, and Table C-18) are discussed in 

the Unconventional Oil and Gas (UOG) Drilling Wastewater memorandum (DCN SGE01181).

ERG generated Figure C-3 in the TDD by first tabulating the median concentration for 

each ionic contributor to TDS (e.g., chloride, calcium, potassium, barium) by formation (see the 

 

20 As discussed previously, the “median” values may represent medians, averages, or other uncharacterized single 

values.

21 Number of data points was based on the total number of samples taken; number of detects was based on the 

number of data points with valid measurements. 
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 15

TDS Contrib Ions w Form Summary tab in Attachment 12, DCN SGE01184.A12). ERG listed 

the primary ionic contributors as individual constituents; minor contributors were combined into 

the “Other Dissolved Constituents” category.

22

ERG generated Figure C-4 and Figure C-5 in the TDD using built-in Excel functions 

(e.g., percentile, median) to calculate the concentration quartiles for each specific data subset of 

interest. The underlying data used to generate Figure C-4 are shown in the Cl, Na, and Ca 

Summary Data tab, and the underlying data used to generate Figure C-5 are shown in the Barium 

Data tab in Attachment 12 (DCN SGE01184.A12). ERG used these underlying data sets to 

illustrate the data using box and whisker plots (see the Ca, Na, and Ca Figure and Barium Figure

tabs in Attachment 12, DCN SGE01184.A12).

4.0 ADDITIONAL UOG PRODUCED WATER VOLUME DATA: ANALYSES USING NATIONAL 

AND STATE-LEVEL DATASETS

The following subsections describe analyses that ERG performed on individual datasets 

that contained UOG produced water volumes and characteristics data. Each of these individual 

analyses is contained in a separate attachment. The results of these analyses were used as inputs 

to the compilation analyses described in Sections 1.0 through 3.0 of this memorandum. The 

attachments are identified in the following subsections, along with the analyses descriptions.

Subsections 4.1 and 4.2 describe analyses that ERG completed using national-level 

datasets to generate data inputs to the PW Data tab in Attachment 1 (DCN SGE01184.A01) (see 

Section 1.2). 

4.1 Attachments 2 and 3 DI Desktop® Long-term Produced Water Generation Rates

ERG analyzed Drillinginfo’s (DI) Desktop® Well File Database (hereafter referred to as 

DI Desktop®) (DCN SGE01170) to calculate typical long-term produced water generation rates 

for specific UOG formations on a per well basis and by well trajectory. ERG converted the raw 

DI-Desktop® data (DCN SGE01170) into a more useful format for calculating long-term 

produced water generation rates in Microsoft Excel. This process is described in more detail in 

Section 4.1.2. Attachment 2 (DCN SGE01184.A02) contains the Microsoft Excel portion of the 

DI Desktop® analysis. Attachment 3 contains the Microsoft Access database portion of the DI 

Desktop® analysis; the queries performed in this attachment are described in Section 4.1.3. ERG 

entered the results of this analysis into the PW Data tab in Attachment 1 (DCN SGE01184.A01). 

4.1.1 Data Source

ERG developed a list of active oil and gas wells from DI Desktop® in a separate analysis

described in ERG’s Analysis of DI Desktop® memorandum23 (DCN SGE01180). ERG used this

 

22 ERG used engineering judgment to determine the “primary” versus “minor” ionic contributors based on 

availability of data and reported measured values (see “TDS Contrib Ions w Form Summary” tab in Attachment 12, 

DCN SGE01184.A12).

23 The version of the DI Desktop® database that ERG analyzed was last downloaded in 2015 and contains data 

mostly from 2014 but it varies by state. State-level information such as the oil and gas agency names, last production 

date, production start date, and update frequency (e.g., monthly, quarterly) is provided in Drillinginfo’s Data 

Coverage table (DCN SGE01171).
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 16

list of active oil and gas wells (shown in the “Active Oil and Gas Wells” table in Attachment 3, 

DCN SGE01184.A03) to calculate long-term produced water generation rates. DI Desktop®

reports the following data that ERG used in this analysis: 24

 Formation25

 Well trajectory (horizontal, directional, vertical, unknown)

 Well completion date (DD/MM/YYYY)

 2000 to 2014 produced water production (separate column for each year in barrels, 

bbl)

26

4.1.2 Methods and Procedures

To estimate typical long-term produced water rates, ERG used the following procedures:

Step 1: Summarize Data by UOG Formation

Using the queries described in Section 4.1.3, ERG compiled UOG well counts from DI 

Desktop® by UOG formation name, well completion year, and well trajectory. For each 

one of these groupings, ERG counted the number of wells completed that year and 

summed the total annual produced water volume for those wells for each year from 2000 

through 2014. An example for horizontal Barnett shale wells is shown in Figure 1. ERG 

only included wells that were completed between 2000 and 2013.27 Additionally, ERG 

only included records with sufficient data for this analysis, which included the following:

 Well completion date: Not null

 Annual long-term produced water volume: Not null28

 Well trajectory: Not null and not “unknown”

Results for all UOG formations are contained in the Detailed Results tab in Attachment 2 

(DCN SGE01184.A02).

Step 2: Calculation of Annual Long-term Produced Water Rates by Completion 

Year

In the Detailed Results tab of Attachment 2 (DCN SGE01184.A02), ERG calculated the 

daily average long-term produced water rate (bbl/day/well) for each completion year (i.e., 

 

24 Some of these data fields may be missing in DI Desktop®. ERG excluded records that were missing one or more 

of these data fields from this analysis.

25 For this analysis, ERG used the “Common Formation Name” field generated by ERG in a separate analysis of DI 

Desktop® described in ERG’s Analysis of DI Desktop® memorandum (DCN SGE01180).

26 DI Desktop® includes annual produced water volumes but does not specify whether it is flowback or long-term 

produced water.

27 ERG used the 2000 year as a cutoff based on engineering judgement and when hydraulic fracturing became more 

common. ERG used the 2013 year as a cutoff because DI Desktop® included produced water volume through 2014. 

However, wells that were completed in 2014 may have produced flowback in 2014 which should not be included in 

long-term produced water calculations.

28 Some states did not report water production to DI Desktop®. ERG did not include wells for states that have no 

water production data (i.e., KS, KY, MO, OH, OK, OR, PA, TN, UT). Information included or not included at the 

state-level is provided in Drillinginfo’s Data Coverage table (DCN SGE01171). For AR, ERG only excluded 

Fayetteville wells because none of the Fayetteville wells had water data, but other wells in AR did.
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June 7, 2016

Page 17

across the rows). ERG used Equation 3 to calculate this average, which sums the annual 

long-term produced water volumes starting with the year after the completion year (i.e., 

WCY+1)through 2014, and divides by the number of wells, 365 days, and the number of 

production years (i.e., 2014 – WCY).

29 Figure 1 shows the resulting calculations for the 

Barnett Shale example. As previously explained, DI Desktop® contains annual produced 

water volumes, but does not specify whether it is flowback and/or long-term produced 

water. Excluding the produced water volumes during the well completion year in 

Equation 3 ensures that the calculated long-term produced water rates do not include 

flowback volumes, as shown by the black cells in Figure 1.

Equation 3

LTPW per day per well =

∑2014

WCY+1 Annual LTPW

# of Wells × (2014 − WCY) × 365

Where:

LTPW – long term produced water

WCY – well completion year

Figure 1. Example Calculation of Daily Average Long-Term Produced Water Rate 

(Horizontal Barnett Shale Wells)

Step 3: Summary of Results

The Summary of Results tab of Attachment 2 (DCN SGE01184.A02) contains the final 

results of this analysis which include a row for each UOG formation and well trajectory 

combination30. For each combination, ERG calculated the 10th percentile, 50th percentile

(i.e., median), and 90th percentile of the “daily average long-term produced water rate 

(bbl/day/well)” column in the Detailed Results tab. ERG calculated the 10th percentile 

and 90th percentile values to represent the typical range of the data. ERG also calculated 

the total number of wells for each UOG formation and well trajectory. ERG entered these 

results into the PW Data tab of Attachment 1 (DCN SGE01184.A01).

 

29 ERG assumed that all wells generated long-term produced water for 365 days per year after the well completion 

year. 

30 The associated basin and resource type of the UOG formation is also included in the results.
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Page 18

4.1.3 Attachment 3 – Query Descriptions

Table 3 describes the queries in Attachment 3 (DCN SGE01184.A03).

Table 3. Query Descriptions for ERG’s Long-Term Produce Water Analysis of DI 

Desktop® Database (Attachment 3, DCN SGE01184.A03)

Attachment 

3 Query # Query Description

Applicable Tabs in 

Attachment 2

100

This query creates a new table called [Results]. To make this table, the 

query groups well records in the [Active Oil and Gas Wells] table by:

 UOG formation name;

 Well completion year; 

 Resource type (shale or tight); and

 Well trajectory (horizontal, directional or vertical).

For each of these combination groupings of UOG formation, completion 

year, resource type, and well trajectory, the query:

 Counts the number of wells that fit into that grouping; and

 Sums the annual produced water volumes for each year from 2000 to 

2014 for all the wells that fit into that grouping.

ERG excluded the following records from the “Results” table:

 Wells completed in 2014;

 Wells completed before the year 2000;

 Wells that don’t belong to any UOG formation; and

 Wells with an unknown well trajectory.

ERG also excluded states that did not report water production data to DI 

Desktop®. Information included or not included at the state-level is 

provided in Drillinginfo’s Data Coverage table (DCN SGE01171).

Detailed Results tab

4.2 Attachments 4 and 5 FracFocus® Fracturing Fluid Volumes

ERG analyzed a database published by FracFocus® in June 2015 (DCN SGE01169) to

calculate typical fracturing fluid volumes for specific UOG formations on a per well basis and by 

well trajectory. The results of this analysis were entered into the PW Data tab in Attachment 1 

(DCN SGE01184.A01). Attachment 4 (DCN SGE01184.A04) contains the Microsoft Excel 

portion of the analysis. Attachment 5 (DCN SGE01184.A05) contains the Microsoft Access 

database portion of the analysis, including the queries that link the FracFocus® data to other oil 

and gas databases, which are described in more detail in Section 4.2.3.

4.2.1 Data Sources

The FracFocus®database (DCN SGE01169) (see Section 1.1.1.1) contains fracturing 

fluid volume data for individual wells identified by API number. It does not contain UOG 

formation names or well trajectories, both of which are necessary for this analysis. Therefore, 

ERG used DI Desktop® (DCN SGE01170) and various databases published by state oil and gas 

agencies to identify these additional data fields for this analysis.31 As shown in Figure 2, the 

 

31 ERG used the list of active oil and gas wells in DI Desktop® as identified by ERG in a separate analysis of DI 

Desktop® described in ERG’s Analysis of DI Desktop® memorandum (DCN SGE01180). The version of the DI 

Desktop® database analyzed was last updated in 2015 and referred to data from 2014 but it varies by state. Statelevel information such as the oil and gas agency names, last production date, production start date, and update 

frequency (e.g., monthly, quarterly) is provided in Drillinginfo’s Data Coverage table (DCN SGE01171).
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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Page 19

common data field in the FracFocus® database, DI Desktop®, and the state oil and gas databases 

is the well API number. ERG only included well API numbers that were contained in both the 

FracFocus® database (DCN SGE01169) and the other databases in the results of this analysis.

For example, the FracFocus® database contains records for wells that were completed after the 

most recent date contained in DI Desktop®; these FracFocus® records were excluded from the

analysis. 

For most states, ERG linked the FracFocus® database records to DI Desktop® to obtain 

the UOG formation and well trajectory information. However, some state oil and gas agencies 

publish databases of UOG wells that contain the same type of data as DI Desktop® (e.g., well 

API number, formation, well trajectory), but are more up-to-date than the version of DI 

Desktop® that ERG used in this analysis. For these states, ERG used the published state agency 

databases instead of DI Desktop® to maximize the number of usable results. For example, ERG 

identified less than one hundred UOG wells drilled into the Utica shale formation (in Ohio) in DI 

Desktop®, resulting in limited results that matched up with FracFocus® records. However, the 

Ohio Department of Natural Resources (OH DNR) publishes a running list of Utica shale wells

(updated weekly), over a thousand wells of which matched up with a FracFocus® records. 

Therefore, ERG linked the FracFocus® data to the OH DNR data, as opposed to DI Desktop®, to 

obtain the UOG formation and well trajectory information for the Utica shale wells. ERG used 

databases published by the following state agencies in this analysis:

 Ohio Department of Natural Resources (OH DNR) (DCN SGE01172)

 Kansas Geological Survey (KGS) (DCN SGE01175)

 North Dakota Industrial Commission (NDIC) (DCN SGE01189)

Figure 2. Overview of Sources Used for FracFocus® Fracturing Fluid Volume Analysis

FracFocus

•Fracturing fluid volume 

(gallons)

• Volume data quality 

flag assigned by ORD

•API Number

DI Desktop®

•UOG formation

•Well trajectory 

(horizontal, vertical, 

directional)

Various State 

Databases

•UOG formation

•Well trajectory 

(horizontal, vertical, 

directional)
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Page 20

4.2.2 Methods and Procedures

To estimate typical fracturing fluid volumes, ERG used the following procedures:

Step 1: Cross Reference FracFocus® against DI Desktop®

Using the queries described in Section 4.2.3, ERG linked well records in the FracFocus®

database to well records in DI Desktop® using well API number (DCN SGE01184.A05). 

The resulting table, FF DB – Manipulated, contains the data fields listed below for each 

well API number:

 From the FracFocus®database (DCN SGE001169):

o Well Name

o Well location (state, county, latitude, longitude)

o Operator name

o Fracturing fluid volume (gallons)32

o Fracture date (start and end dates)

 From DI Desktop® (DCN SGE01170):

o Resource type

o Formation

o Well trajectory (i.e., horizontal, directional, vertical)

If ERG did not find a match in DI Desktop®, the resource type, formation, and well 

trajectory fields were left blank in the final table, but ERG still included the well API 

number and relevant data from the FracFocus® database.

Step 2: Cross Reference FracFocus® Database against State Agency Databases

ERG identified state agency databases with more up-to-date data than the data in the 

version of DI Desktop® that ERG used for this analysis. Using the queries described in 

Section 4.2.3, ERG linked the FracFocus® database with these state agency databases 

using well API number (similar to Step 1 above). The results (i.e., resource type, 

formation, and well trajectory) of this cross reference override the results of the cross 

reference in Step 1 because, as explained in Section 4.2.1, ERG determined that these 

state agency databases have more up-to-date data than DI Desktop®. ERG used a state 

agency database instead of DI Desktop® for North Dakota, Ohio, and Kansas. Table 4

contains more detail about the data contained in each state agency database.

The FF DB - Manipulated tab in Attachment 4 (DCN SGE01184.A04) contains the 

resulting records from Steps 1 and 2.

Step 3: Summary of Results

The Summary of Results tab in Attachment 4 (DCN SGE01184.A04) provides summary 

statistics of the data in the FF DB – Manipulated tab. ERG calculated the 10th percentile, 

 

32 The fracturing fluid volume is noted in Attachment 4 (DCN SGE01184.A04) as “TotalBaseWaterVolume”.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

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Page 21

50th percentile (i.e., median), and 90th percentile33 statistics of fracturing fluid volumes 

(gallons) reported in the FF DB - Manipulated tab. ERG converted the volumes from 

gallons to barrels by dividing by 42 gallons per barrel. These statistics were calculated for 

each UOG formation and well trajectory basis34. The Summary of Results tab also sums

the total number of data points (i.e., number of wells)35. ERG entered these results into 

the PW Data tab of Attachment 1 (DCN SGE01184.A01).

4.2.3 Attachment 5 – Query Descriptions

Table 4 describes the queries ERG used to analyze the FracFocus® database in 

Attachment 5 (DCN SGE01184.A05). The results of the analysis are documented in Attachment 

4 (DCN SGE01184.A04).

The following is a list of tables found in Attachment 5 (DCN SGE01184.A05) with a 

brief description of the data contained in each:

 DI Desktop Wells (SGE01170) – The raw DI Desktop® database (DCN SGE001170).

 FF DB - Manipulated – This is a version of the FracFocus® database that ERG created by 

processing the queries listed in Table 4. This table is copied into the FF DB -

Manipulated tab in Attachment 4.

 FF V2 (SGE01169) – This is version 2 of the raw FracFocus® database published by 

FracFocus® in June 2015 (DCN SGE01169).

 Formation Consolidation Crosswalk – Crosswalk of known basin and formation 

combinations in DI Desktop® developed during ERG’s analysis of DI Desktop® (DCN 

SGE01170).

 KS Horizontal Wells (SGE01175) – List of wells published by the KGS that contains 

formation and well trajectory information by API number. 

 ND Wells (SGE01189) – List of wells published by NDIC that contains formation and 

well trajectory information by API number.

 OH Horizontal Utica Wells (SGE01172) – List of permitted Utica wells published by OH

DNR.

 

33 ERG calculated the 10th percentile and 90th percentile values to represent the typical range of the data.

34 ERG added the basin for each formation in the Summary of Results tab.

35 In this analysis, the number of data points equals the number of wells.
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Page 22

Table 4. FracFocus® Fracturing Fluid Volumes Query Descriptions

Attachment 

5 Query #

Query Description

100

This query makes a new table called [FF DB – Manipulated] and populates it with all records 

from the FracFocus® database (DCN SGE01169) that meet the following criteria:

 The field “TotalBaseWaterVolume” is greater than 0. 

 The field “State” is not "beaver" and not "beckham" and not "harper" and not "hemphill" 

and not “red river" and not “roosevelt" and not "rusk" and not “state" and not "ward". 

ERG identified data quality issues with these entries in the FracFocus® database. These 

exclusions corresponded to a small number of total records.

200

This query cross references the API numbers in the [FF DB – Manipulated] table against the [DI 

Desktop Wells (SGE01170)] table. When an API match is found, this query populates the Well 

Trajectory field in the [FF DB – Manipulated] table with the well trajectory reported in DI 

Desktop®. Wells without a match are still included in the [FF DB – Manipulated] table, but the 

“Well Trajectory” field is left blank.

201

This query performs the following two cross references simultaneously:

 The [FF DB – Manipulated] table is cross referenced against the [DI Desktop Wells 

(SGE01170)] table via API number; and

 The [DI Desktop Wells (SGE01170)] table is cross referenced against the [Consolidated 

Formation Crosswalk] tablea via “Basin,” “Reservoir,” and “Formation” fields. 

If a match is found, this query updates the “Consolidated Formation” and “Resource Type” fields 

in the [FF DB – Manipulated] table with the “Consolidated Formation” and “Resource Type”

fields reported in the [Formation Consolidation Crosswalk] table. Wells without a match are still 

included in the [FF DB – Manipulated] table, but the “Resource Type” and “Formation” fields are 

left blank.

300

This query cross references the API numbers in the [FF DB – Manipulated] table against a list of 

horizontal Utica shale wells published by OH DNR (DCN SGE01172). If the API numbers in 

FracFocus® (DCN SGE01169) match API numbers in OH DNR (DCN SGE01172), this query 

updates the “Formation,” “Well Trajectory,” and “Resource Type” fields in the [FF DB –

Manipulated] table to "Utica", "H" (based on OH DNR's file name, which is a list of horizontal 

wells), and "shale,” respectively.

301

This query cross references the API numbers in the [FF DB – Manipulated] table against a list of 

permitted horizontal Kansas wells published by the KGS (DCN SGE01175). If the API numbers 

in FracFocus® (DCN SGE01169) match API numbers in KGS's list (DCN SGE01175), this query 

updates the “Consolidated Formation,” “Well Trajectory,” and “Resource Type” fields in the [FF 

DB – Manipulated] table to "Mississippi Lime", "H" (based on KGS's file name, which is a list of 

horizontal wells), and "tight," respectively. This query only pulls wells from KGS's horizontal 

well list where the reported formation name includes "Mississippi.”

302

This query cross references the API numbers in the [FF DB – Manipulated] against a list of oil 

and gas wells in North Dakota published by NDIC (DCN SGE01189). If the API numbers in 

FracFocus® (DCN SGE01169) match API numbers in NDIC's list (DCN SGE01189) this query 

updates the “Consolidated Formation” and “Resource Type” fields in the [FF DB – Manipulated]

table to "Bakken" and "shale" respectively. This query only pulls wells from NDIC's well list 

where the reported formation name includes "Bakken". This query also updates the Well 

Trajectory field in the [FF DB – Manipulated] table to the reported value in the wellbore field 

(i.e., Well Trajectory) in NDIC's list.

400 This query updates all null values in the “Well Trajectory” field of the [FF DB – Manipulated]

table to “U” (i.e., unknown).

401 This query updates all null values in the “Consolidated Formation” field of the [FF DB –

Manipulated] table to “Unknown”.

402

This query updates all null values in the “Resource Type” field of the [FF DB – Manipulated]

table to “Unknown”. These wells could be UOG wells, where ERG could not identify a common 

formation name, COG wells, or CBM wells. 
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 23

Table 4. FracFocus® Fracturing Fluid Volumes Query Descriptions

Attachment 

5 Query #

Query Description

500 This query summarizes the final results of the [FF DB – Manipulated] table. It includes counts of 

wells by Consolidated Formation, State, and Well Trajectory. 

a—ERG created this crosswalk in a separate analysis where ERG assigned consolidated formation names to 

combinations of basins and formations reported in DI Desktop®. More information about this analysis can be found 

in ERG’s Analysis of DI Desktop® memorandum (DCN SGE01180).

Subsections 4.3 through 4.8 describe analyses that ERG completed using state or 

formation level data sets to generate data inputs to the PW Data tab in Attachment 1 (DCN 

SGE01184.A01) (see Section 1.2). 

4.3 Attachment 6 – Bakken Flowback Recovery

ERG estimated flowback recovery for UOG wells completed in the Bakken shale 

formation in North Dakota using data published by the NDIC (DCN SGE01189) and the results 

from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes (DCN SGE01184.A04-A05). 

ERG entered the results of this analysis as inputs to the PW Data tab in Attachment 1 (DCN 

SGE01184.A01). Attachment 6 (DCN SGE01184.A06) contains the underlying Microsoft Excel 

file for this analysis.

4.3.1 Data Source

ERG obtained a subscription to NDIC’s Basic Subscription Services (DCN SGE01189). 

Relevant data for this analysis that were provided in the NDIC dataset include the following:

 Well API number

 NDIC assigned “well file #” (used to search for wells in the NDIC database, see 

Section 4.3.2)

 Monthly production of oil (barrels), gas (million cubic feet, MCF), and produced water 

(barrels)

 Number of production days in each month36

To obtain fracturing fluid volumes for this analysis, ERG used the results from the 

FracFocus® Fracturing Fluid Volume analysis described in Section 4.1.3 (DCN SGE01184.A04-

A05). Relevant data provided in the FracFocus® results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)

 Fracture date (start and end dates)

 Fracturing fluid volume (gallons)

 

36 The number of production days reported by NDIC is the number of days that the given well was producing any 

combination of oil, gas, and/or water in the given month.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 24

The well API number is the field ERG used to link the FracFocus® database to the NDIC 

data.

4.3.2 Methods and Procedures

To estimate typical flowback recovery, ERG used the following procedures:

Step 1: Identify Bakken Wells in North Dakota from FracFocus® Analysis

ERG filtered the results from the FracFocus® Fracturing Fluid Volume analysis for 

Bakken shale wells located in North Dakota (DCN SGE01184.A04-.A05), excluding 

wells with unknown well trajectories. These well records are contained in the Analysis 

tab of Attachment 6 (DCN SGE01184.A06).

Step 2: Estimate Flowback Volumes in NDIC’s Production Data

ERG searched the NDIC production database for Bakken shale wells listed in the 

Analysis tab (from Step 1). For each well, ERG located the production data for the given 

month in which the well was completed, according to the FracFocus® database. ERG 

recorded the produced water volume and production days37 in the “Estimated Flowback 

Volume (barrels)” and “Production Days” fields, respectively, in the Analysis tab in

Attachment 6 (DCN SGE01184.A06). 

Literature reports that the flowback process lasts anywhere between 14 and 60 days 

(DCN SGE00951). During this analysis, ERG encountered some wells that produced 

water for fewer days than the general flowback process length reported in literature (e.g., 

3 days) in the month the well was completed. For all wells where the number of 

production days was less than 14 in the completion month, ERG recorded the volume for 

these days in addition to the volumes for the entire next month of production.38 For 

example, a well completed at the end of July 2011 only produced 1,000 barrels of 

produced water during 3 days of production by the end of the month. In August 2011, this 

well produced 5,000 barrels of produced water during 31 days of production. ERG 

recorded 6,000 and 34 into the “Estimated Flowback Volume (barrels)” and “Production 

Days” fields, respectively, in the Analysis tab of Attachment 6 (DCN SGE01184.A06).

Step 3: Calculate Flowback Recovery

ERG calculated the estimated flowback recovery as a percentage of total fracturing fluid 

volume using Equation 4 below. ERG performed this calculation in the “Estimated 

Flowback Recovery” field in the Analysis tab in Attachment 6 (DCN SGE01184.A06) 

for each well record with an estimated flowback volume from Step 2 above. The total 

 

37 The number of production days reported by NDIC is the number of days that the given well was producing any 

combination of oil, gas, and/or water in the given month.

38 ERG made this assumption in order to make the available data in literature useful for estimating flowback 

recovery for different UOG formations. The actual flowback recovery for individual wells may have been lower or 

higher than the recovery ERG estimated.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 25

fracturing fluid volume was obtained from ERG’s Analysis of FracFocus® Fracturing 

Fluid Volumes (DCN SGE01184.A04-A05).

Equation 4

Flowback Recovery (%) =

Flowback volume

Total Fracturing Fluid Volume × 100

Note: ERG converted flowback volume units from barrels to gallons using 42 gallons per barrel.

Step 4: Calculate Summary Statistics

ERG calculated 10th percentile, 50th percentile, and 90th percentile statistics for the 

estimated flowback recovery for Bakken shale wells. The results are shown in the Results 

tab of Attachment 6 (DCN SGE01184.A06), which also includes the number of wells 

analyzed. ERG excluded vertical and directional Bakken wells from the results because 

there were a limited number of records (less than 10). 

ERG calculated the 10th percentile and 90th percentile values to represent the typical 

range of the data. ERG also calculated the median number of production days associated 

with the flowback recovery statistics to verify it agrees with typical flowback process 

lengths reported in literature (i.e., between 14 and 60 days) (DCN SGE00951). The 

calculated flowback recovery statistics in this analysis represent a median of 30 days of 

production, which falls within the general ranges of flowback process length reported in 

literature, and thus verifies the methods and procedures for this analysis.

4.4 Attachment 7 – New Mexico Flowback Recovery

ERG estimated flowback recovery for UOG wells in New Mexico using data published 

by the New Mexico Energy, Minerals, and Natural Resources Department (NMEMNRD) (DCN 

SGE00644) along with results from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes

(DCN SGE01184.A04-A05). This included UOG wells completed in the Avalon and Bone 

Spring, Wolfcamp, Delaware, and Dakota formations.39 ERG entered the results of this analysis 

as inputs to the PW Data tab in Attachment 1 (DCN SGE01184.A01). Attachment 7 (DCN 

SGE01184.A07) contains the underlying Microsoft Excel file.

4.4.1 Data Source

ERG obtained well production data from NMEMNRD (DCN SGE00644). The online 

well search application allows users to obtain the following information for a specified well 

using the well API number:

 Monthly production of oil (barrels), gas (MCF), and produced water (barrels); and

 Number of production days in each month. 

 

39 Other UOG formations (i.e., Morrow, Mesaverde) were also identified from ERG’s analysis of FracFocusTM but 

were not included in the results because there were less than 10 wells.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 26

To obtain fracturing fluid volumes for this analysis, ERG used the results from the 

FracFocus® Fracturing Fluid Volume analysis described in Section 4.1.3 (DCN SGE01184.A04-

A05). Relevant data in these results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)

 Fracture date (start and end dates)

 Fracturing fluid volume (gallons)

The well API number is the common field ERG used to link the FracFocus® database to 

the NMEMNRD data.

4.4.2 Methods and Procedures

To estimate typical flowback recovery, ERG used the following procedures:

Step 1: Identify New Mexico Wells from FracFocus® Analysis

ERG filtered the results from the FracFocus® Fracturing Fluid Volume analysis for UOG 

wells located in New Mexico (DCN SGE01184.A04-A05), excluding wells with 

unknown well trajectories. These well records are contained in the Analysis tab of 

Attachment 7 (DCN SGE01184.A07).

Step 2: Identify Flowback Volumes in NMEMNRD’s Production Data

ERG searched the NMEMNRD production database for wells listed in the Analysis tab 

(from Step 1). For each well, ERG located the production data for the given month in 

which the well was completed, according to the FracFocus® database. ERG recorded the 

produced water volume and production days in the “Estimated Flowback Volume 

(barrels)” and “Production Days” fields, respectively, in the Analysis tab in Attachment 7 

(DCN SGE01184.A07). 

Literature reports that the flowback process lasts anywhere between 14 and 60 days 

(DCN SGE00951). During this analysis, ERG encountered some wells that produced for

fewer days than the general flowback process length reported in literature (e.g., 3 days) in 

the month the well was completed. For all wells where the number of production days 

was less than 14 in the completion month, ERG recorded the volume for these days in 

addition to the volumes for the entire next month of production.40 For example, a well 

completed at the end of July 2011 only produced 1,000 barrels during 3 days of 

production by the end of the month. In August 2011, this well produced 5,000 barrels of 

produced water during 31 days of production. ERG recorded 6,000 and 34 into the 

 

40 ERG made this assumption in order to make the available data in literature useful for estimating flowback 

recovery for different UOG formations. The actual flowback recovery for individual wells may have been lower or 

higher than the recovery ERG estimated.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 27

“Estimated Flowback Volume (barrels)” and “Production Days” fields, respectively, in 

the Analysis tab of Attachment 7 (DCN SGE01184.A07). 

Step 3: Calculate Flowback Recovery

ERG calculated the estimated flowback recovery as a percentage of total fracturing fluid 

volume using Equation 4. ERG performed this calculation in the “Estimated Flowback 

Recovery” field in the Analysis tab in Attachment 7 (DCN SGE01184.A06) for each well 

with an estimated flowback volume from Step 2 above. The total fracturing fluid volume 

was obtained from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes (DCN 

SGE01184.A04-A05).

Step 4: Calculate Summary Statistics

ERG calculated 10th percentile, 50th percentile, and 90th percentile statistics for the 

estimated flowback recovery for UOG wells in New Mexico. The results are shown in the 

Results tab of Attachment 7 (DCN SGE01184.A07), which also includes the number of 

wells analyzed. ERG excluded well trajectory and formation combinations from the 

results if they had less than 10 wells (e.g., directional wells in the Delaware formation). 

ERG calculated the 10th percentile and 90th percentile to values to represent the typical 

range of the data. ERG also calculated the median number of production days associated 

with the flowback recovery statistics to verify it agrees with typical flowback process 

lengths reported in literature (i.e., between 14 and 60 days) (DCN SGE00951). The 

calculated flowback recovery statistics in this analysis represent a median of 30 to 31

days of production, depending on the formation, which falls within the general ranges of 

flowback process length reported in literature, and thus verifies the methods and 

procedures for this analysis.

4.5 Attachment 8 – Utica Flowback Recovery and Long-term Produced Water Rates

ERG estimated flowback recovery and long-term produced water generation rates for 

UOG wells completed in the Utica shale formation in Ohio using data published by the OH DNR 

along with results from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes (DCN 

SGE01184.A04-A05). ERG used this analysis to estimate long-term produced water generation 

rates because there were limited Utica wells in the DI Desktop® database, which is the database 

ERG used to estimate long-term produced water for most other UOG formations. ERG entered 

the results from this analysis into the PW Data tab of Attachment 1 (DCN SGE01184.A01) under 

the horizontal Utica shale well category.41 Attachment 8 (DCN SGE SGE01184.A08) contains 

the underlying Microsoft Excel file for this analysis.

 

41 OH DNR named some of the published production files “Utica” production and others “horizontal shale” 

production. ERG assumed that all of the wells are horizontal shale wells completed in the Utica formation for the 

purpose of this analysis.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 28

4.5.1 Data Source

ERG downloaded Microsoft Excel files from the OH DNR website containing oil, gas, 

and produced water production on a quarterly or annual basis.42 ERG downloaded the following 

files and compiled all of the data in the Raw Sate Data tab in Attachment 8 (DCN 

SGE01184.A08):

 2011 Utica Shale Production – DCN SGE00559

 2012 Utica Shale Production – DCN SGE00560

 2013 Quarterly Horizontal Shale Production: 1st Quarter – DCN SGE00964

 2013 Quarterly Horizontal Shale Production: 2nd Quarter – DCN SGE00965

 2013 Quarterly Horizontal Shale Production: 3rd Quarter – DCN SGE00727

 2013 Quarterly Horizontal Shale Production: 4th Quarter – DCN SGE00737

 2014 Quarterly Horizontal Shale Production: 1st Quarter – DCN SGE01237

 2014 Quarterly Horizontal Shale Production: 2nd Quarter – DCN SGE01238

 2014 Quarterly Horizontal Shale Production: 3rd Quarter – DCN SGE01239

 2014 Quarterly Horizontal Shale Production: 4th Quarter – DCN SGE01240

 2015 Quarterly Horizontal Shale Production: 1st Quarter – DCN SGE01241

 2015 Quarterly Horizontal Shale Production: 2nd Quarter – DCN SGE01242

Each file reports the following data:

 Well API number

 Year and, where applicable, quarter of production data

 Other identifier information (e.g., Owner, Well Name)

 Quarterly or annual production of oil (barrels), gas (thousand cubic feet), and produced 

water (barrels) 43

 Number of production days in each quarter or year. 

To obtain fracturing fluid volumes for this analysis, ERG used the FracFocus® database 

described in Section 1.1 (DCN SGE01169). Relevant data from these results included the 

following:

 Well API number

 State

 Fracture date (start and end dates)

 Fracturing fluid volume (gallons)

 

42 Production data for 2013, 2014, and 2015 is provided in quarterly files; production data for 2011 and 2012 is 

provided for the entire year.

43 In these reports, OH DNR refers to produced water as "brine" which includes both flowback and long-term 

produced water.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 29

The well API number is the common field ERG used to link the FracFocus® database to

the OH DNR production data. Note that the production files published by OH DNR indicate that 

all Utica wells are horizontally drilled.

4.5.2 Methods and Procedures

To estimate typical flowback recovery and long-term produced water rates, ERG used the 

following procedures:

Step 1: Identify Utica Shale Wells in Ohio from FracFocus® Analysis

ERG filtered the results from the FracFocus® Fracturing Fluid Volume analysis for Utica 

shale wells located in Ohio (DCN SGE01184.A04-A05), excluding wells with unknown 

well trajectories. These well records are contained in the FB Analysis tab of Attachment 

8 (DCN SGE01184.A08).

Step 2: Identify Flowback Volumes in OH DNR’s Production Data

For each well listed in the FB Analysis tab (from Step 1) in Attachment 8 (DCN 

SGE01184.A08), ERG looked up the total produced water and production days in the OH 

DNR production data contained in the Raw State Data tab for each of the production 

periods listed in Table 5 (e.g., 2011, 2012, 2013 - 1

st quarter). Next, ERG identified the 

first production period in which each well produced oil, gas, and/or water and recorded 

the period in the “First Production Period” field in the FB Analysis tab. Lastly, using the 

calculation methods described in Table 5, ERG recorded the produced water volume and 

production days in the “Estimated Flowback Volume (barrels)” and “Production Days” 

fields, respectively, in the FB Analysis tab. As shown in Table 5, the method ERG used 

to identify flowback volumes varied depending on the first production period for each

well.

Literature reports that the flowback process lasts between 14 and 60 days (DCN 

SGE00951). For the purpose of this analysis, ERG assumed a maximum of 60 days of 

production to identify wells in the flowback phase. If there were more than 60 production 

days during the first reporting period, ERG did not calculate flowback recovery for the 

well.44 Further, some wells may have produced for less than 14 days in the first 

production period, so the flowback recovery (calculated in Step 3) may be an 

underestimate.

Table 5. Calculation Methods Used for Each “First Production Period”

First Production 

Period for Well Calculation of Flowback Recovery (% of Fracturing Fluid Volume)

a

2011 If the number of production days in 2011 was less than 60 days, ERG divided the 

2011 brine production by the fracturing fluid volume.

2012 If the number of 2012 production days was less than 60 days, ERG divided the 2012 

brine production by the fracturing fluid volume.

 

44 ERG used a slightly different approach from other analyses in Section 4.0 because the data published by OH DNR 

is organized on a quarterly basis, not on a monthly basis.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 30

Table 5. Calculation Methods Used for Each “First Production Period”

First Production 

Period for Well Calculation of Flowback Recovery (% of Fracturing Fluid Volume)

a

2013 – 1

st Quarter If the number of 1

st quarter 2013 production days was less than 60 days, ERG divided 

the 1

st quarter 2013 brine production by the fracturing fluid volume.

2013 – 2

nd Quarter If the number of 2

nd quarter 2013 production days was less than 60 days, ERG divided 

the 2

nd quarter 2013 brine production by the fracturing fluid volume.

2013 – 3

rd Quarter If the number of 3

rd quarter 2013 production days was less than 60 days, ERG divided 

the 3

rd quarter 2013 brine production by the fracturing fluid volume.

2013 – 4

th Quarter If the number of 4

th quarter 2013 production days was less than 60 days, ERG divided 

the 4

th quarter 2013 brine production by the fracturing fluid volume.

2014 – 1

st Quarter If the number of 1

st quarter 2014 production days was less than 60 days, ERG divided 

the 1

st quarter 2014 brine production by the fracturing fluid volume.

2014 – 2

nd Quarter If the number of 2

nd quarter 2014 production days was less than 60 days, ERG divided 

the 2

nd quarter 2014 brine production by the fracturing fluid volume.

2014 – 3

rd Quarter If the number of 3

rd quarter 2014 production days was less than 60 days, ERG divided 

the 3

rd quarter 2014 brine production by the fracturing fluid volume.

2014 – 4

th Quarter If the number of 4

th quarter 2014 production days was less than 60 days, ERG divided 

the 4

th quarter 2014 brine production by the fracturing fluid volume.

2015 – 1

st Quarter If the number of 1

st quarter 2015 production days was less than 60 days, ERG divided 

the 1

st quarter 2015 brine production by the fracturing fluid volume.

2015 – 2

nd Quarter If the number of 2

nd quarter 2015 production days was less than 60 days, ERG divided 

the 2

nd quarter 2015 brine production by the fracturing fluid volume.

a— If the production days were reported as greater than 60 days during the first reporting period, ERG did not 

calculate flowback recovery for the well.

Step 3: Calculate Flowback Recovery

ERG calculated the estimated flowback recovery as a percentage of total fracturing fluid 

volume using Equation 4. ERG performed this calculation in the “Estimated Flowback 

Recovery” field in the Analysis tab in Attachment 8 (DCN SGE01184.A08) for each well 

with an estimated flowback volume from Step 2 above. The total fracturing fluid volume 

was obtained from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes (DCN 

SGE01184.A04-A05).

Step 4: Identify OH DNR Long-Term Produced Water Volumes and Calculate 

Long-Term Produced Water Rates

Next, ERG calculated long-term produced water rates using a similar methodology as 

described in Section 4.1.2 (DI Desktop® long-term produced water analysis); all inputs 

were from OH DNR’s production data. The relevant calculations are contained in the 

“LTPW Analysis” tab. For each production period listed in Table 6, ERG counted the 

total number of wells that produced oil, gas, and/or water in that period and summed the 

total produced water volume for those wells for all subsequent production periods. ERG 

calculated long-term produced water rates separately for each production period group.

Table 6 provides more detail about how ERG identified and calculated long-term 

produced water rates, which varied by the year and/or quarter the well first produced oil, 

gas, or produced water.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 31

Table 6. Calculation Methods Used for Each “First Production Period”

First Prod. 

Period Calculation of Long-term Produced Water (barrels per day per well)

2011

ERG assumed that wells that first produced in 2011 were in the production phase beginning with the 

1

st quarter 2013.a ERG divided the total 2013, 2014, and 2015 (1st and 2nd quarters only) produced 

water volume by the number of calendar daysb over the same period (900 days)band by the number 

of wells that first produced in 2011.

2012

ERG assumed that wells that first produced in 2012 were in the production phase beginning with the 

2

nd quarter 2013.a ERG divided the total 2013 (2nd, 3rd and 4th quarters only), 2014, and 2015 (1st and 

2

nd quarters only) produced water volume by the number of calendar daysb over the same period (810 

days)band by the number of wells that first produced in 2012.

2013 – 1

st

Quarter

ERG assumed that wells that first produced in the 1st quarter 2013 were in the production phase 

beginning with the 3rd quarter 2013.

a ERG divided the total 2013 (3rd and 4th quarters only), 2014, and 

2015 (1st and 2nd quarters only) produced water volume by the number of calendar daysb over the 

same period (720 days)band by the number of wells that first produced in 1

st quarter 2013.

2013 – 2

nd

Quarter

ERG assumed that wells that first produced in the 2nd quarter 2013 were in the production phase 

beginning with the 4th quarter 2013.

a ERG divided the total 2013 (4th quarter only), 2014, and 2015 

(1st and 2nd quarters only) produced water volume by the number of calendar daysb over the same 

period (630 days)band by the number of wells that first produced in 2nd quarter 2013.

2013 – 3

rd

Quarter

ERG assumed that wells that first produced in the 3rd quarter 2013 were in the production phase 

beginning with the 1st quarter 2014.

a ERG divided the total 2014 and 2015 (1st and 2nd quarters only)

produced water volume by the number of calendar daysb over the same period (approximately 540 

days)band by the number of wells that first produced in 3rd quarter 2013.

2013 – 4

th

Quarter

ERG assumed that wells that first produced in the 4th quarter 2013 were in the production phase 

beginning with the 2

nd quarter 2014.a ERG divided the total 2014 (2nd, 3rd, and 4th quarters only) and 

2015 (1st and 2nd quarters only) produced water volume by the number of calendar daysb over the 

same period (450 days)band by the number of wells that first produced in 4th quarter 2013.

2014 – 1

st

Quarter

ERG assumed that wells that first produced in the 1st quarter 2014 were in the production phase 

beginning with the 3rd quarter 2014.

a ERG divided the total 2014 (3rd and 4th quarters only) and 2015 

(1st and 2nd quarters only) produced water volume by the number of calendar daysb over the same 

period (360 days)band by the number of wells that first produced in 1st quarter 2014.

2014 – 2

nd

Quarter

ERG assumed that wells that first produced in the 2nd quarter 2014 were in the production phase 

beginning with the 4th quarter 2014.

a ERG divided the total 2014 (4th quarter only) and 2015 (1st and 

2

nd quarters only) produced water volume by the number of calendar days over the same period (270 

days)band by the number of wells that first produced in 2nd quarter 2014.

2014 – 3

rd

Quarter

ERG assumed that wells that first produced in the 3rd quarter 2014 were in the production phase 

beginning with the 1st quarter 2015.

a ERG divided the total 2015 (1st and 2nd quarters only) produced 

water volume by the number of calendar daysb over the same period (180 days)band by the number 

of wells that first produced in 3rd quarter 2014.

2014 – 4

th

Quarter

ERG assumed that wells that first produced in the 4th quarter 2014 were in the production phase 

beginning with the 2nd quarter 2015.

a ERG divided the total 2015 (2nd quarter only) produced water 

volume by the number of calendar daysb over the same period (90 days)band by the number of wells 

that first produced in 4th quarter 2014.

2015 – 1

st

and 2nd

Quarter

ERG assumed wells that first produced in the 1st quarter 2015 and later were not in the production 

phase until the 3rd quarter 2015. Because no data from OH DNR was available after the 2nd quarter 

2015, ERG did not calculated long-term produced water rates for these wells.

a— ERG also skipped the entire reporting period that immediately followed the period the well was completed to 

avoid inadvertently including flowback volumes in the long-term produced water calculation. ERG assumed that 

wells only produce long-term produced water (i.e., not flowback) when they are in the production phase.

b— ERG used the number of calendar days instead of the production days reported by OH DNR to be consistent 

with ERG’s analysis of DI Desktop® (see Section 4.1.2). The production days reported by OH DNR factor in down 

time required for maintenance that is experienced by most wells. ERG assumed 90 calendar days per quarter.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 32

Step 5: Calculate Summary Statistics

ERG calculated 10th percentile, 50th percentile, and 90th percentile statistics for the 

estimated flowback recovery and long-term produced water rates for horizontal Utica 

wells in Ohio. The results are shown in the Results tab of Attachment 8 (DCN 

SGE01184.A08), which also includes the number of wells analyzed (i.e., number of data 

points) and the number of flowback days (relevant only to the flowback recovery data). 

ERG calculated the 10th percentile and 90th percentile values to represent the typical 

range of the data. ERG also calculated the median number of production days associated 

with the flowback recovery statistics to verify it agrees with typical flowback process 

lengths reported in literature (i.e., between 14 and 60 days) (DCN SGE00951). The 

calculated flowback recovery statistics in this analysis represent a median of 24 days of 

production, which falls within the general ranges of flowback process length reported in 

literature, and thus verifies the methods and procedures for this analysis.

4.6 Attachment 9 – Wyoming Flowback Recovery

ERG estimated UOG flowback recovery for UOG wells completed in Wyoming using 

data published by the Wyoming Oil and Gas Conservation Commission (WOGCC) (DCN 

SGE00643) along with results from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes

(DCN SGE01184.A04-A05). This included UOG wells completed in the Mesaverde, Lance, 

Niobrara, Codell, and Mowry formations. 45 ERG entered the results of this analysis into the PW 

Data tab in Attachment 1 (DCN SGE01184.A01). Attachment 9 (DCN SGE01184.A09) contains 

the underlying Microsoft Excel file for this analysis.

4.6.1 Data Source

ERG obtained data from the WOGCC Download Production tool (DCN SGE00643). 

This tool allows users to download the following information for a group of API numbers in 

Microsoft Excel format: 

 Monthly production of oil (barrels), gas (MCF), and produced water (barrels)

 Number of production days in each month

To obtain fracturing fluid volumes for this analysis, ERG used the results from the 

FracFocus® Fracturing Fluid Volume analysis described in Section 4.1.3 (DCN SGE01184.A04-

A05). Relevant data in these results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)

 Fracture date (start and end dates)

 

45 Other UOG formations (i.e., Muddy J) were also identified from ERG’s analysis of FracFocusTM but were not 

included in the results because there were less than 10 wells.
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 Fracturing fluid volume (gallons)

The well API number is the common field ERG used to link the FracFocus® database and 

the WOGCC data.

4.6.2 Methods and Procedures

To estimate typical flowback recovery, ERG used the following procedures:

Step 1: Identify WY UOG Wells in the FracFocus® Database

ERG filtered the results from the FracFocus® Fracturing Fluid Volume analysis for UOG 

wells located in Wyoming (DCN SGE01184.A04-A05), excluding wells with unknown 

well trajectories. The well records are contained in the Analysis tab of Attachment 9 

(DCN SGE01184.A09).

Step 2: Download WOGCC’s Production Data

ERG searched the WOGCC database for the list of well API numbers identified in step 1 

using the “Download Production” feature on the WOGCC website. ERG downloaded the 

results in Microsoft Excel format and copied them into the Raw State Data tab of 

Attachment 9 (DCN SGE01184.A09).

Step 3: Identify Flowback Volumes in WOGCC’s Production Data

ERG searched the WOGCC production data in the Raw State Data tab for wells listed in 

the Analysis tab (from Step 1). For each well, ERG located the production data for the 

given month in which the well was completed, according to the FracFocus® database. 46

ERG recorded the produced water volume and production days in the “Estimated 

Flowback Volume (barrels)” and “Production Days” fields, respectively, in the Analysis 

tab in Attachment 9 (DCN SGE01184.A09). 

Literature reports that the flowback process lasts anywhere between 14 and 60 days 

(DCN SGE00951). During this analysis, ERG encountered some wells that produced for 

fewer days than the general flowback process length reported in literature (e.g., 3 days) in 

the month the well was completed. For all wells, where the number of production days 

was less than 14 in the completion month, ERG recorded the volume for these days in 

addition to the volume for the entire next month of production.47 For example, a well 

completed at the end of July 2011 only produced 1,000 barrels during 3 days of 

production by the end of the month. In August 2011, this well produced 5,000 barrels of 

produced water during 31 days of production. ERG recorded 6,000 and 34 into the 

 

46 In the Raw State Data tab, the “Flowback Indicator_ERG” field is flagged as “flowback” during periods of 

potential flowback. Flowback periods were identified by searching for the month and year that the well was 

fractured according to FracFocsTM.

47 ERG made this assumption in order to make the available data in literature useful for estimating flowback 

recovery for different UOG formations. The actual flowback recovery for individual wells may have been lower or 

higher than the recovery ERG estimated.
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“Estimated Flowback Volume (barrels)” and “Production Days” fields respectively in the 

Analysis tab of Attachment 9 (DCN SGE01184.A09). 

Step 4: Calculate Flowback Recovery

ERG calculated the estimated flowback recovery as a percentage of total fracturing fluid 

volume using Equation 4. ERG performed this calculation in the “Estimated Flowback 

Recovery” field in the Analysis tab in Attachment 9 (DCN SGE01184.A09) for each well 

with an estimated flowback volume from Step 3 above. The total fracturing fluid volume 

was obtained from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes (DCN 

SGE01184.A04-A05).

Step 5: Calculate Summary Statistics

ERG calculated 10th percentile, 50th percentile, and 90th percentile statistics for the 

estimated flowback recovery for UOG wells in Wyoming. The results are shown in the 

“Results” tab of Attachment 9 (DCN SGE01184.A09), which also includes the number of 

wells analyzed and the total number of wells. ERG excluded well trajectory and 

formation combinations from the results if they had less than 10 total wells (i.e., Column 

I) (e.g., vertical wells in the Niobrara formation).

ERG calculated the 10th percentile and 90th percentile values to represent the typical 

range of the data. ERG also calculated the median number of production days associated 

with the flowback recovery statistics to verify it agrees with typical flowback process 

lengths reported in literature (i.e., between 14 and 60 days) (DCN SGE00951). The 

calculated flowback recovery statistics in this analysis represent a median of 27 to 31

days of production, depending on the formation, which falls within the general ranges of 

flowback process length reported in literature, and thus verifies the methods and 

procedures for this analysis.

4.7 Attachment 10 – Codell-Niobrara Flowback Recovery and Long-term Produced 

Water Rates

ERG estimated produced water volumes and rates for UOG wells completed in the 

Wattenberg field (i.e., primarily Codell-Niobrara formation located in the Denver Basin) using 

data generated by Bing Bai in 2013 (DCN SGE00501). The underlying data and results are 

shown in the Analysis tab of Attachment 10 (DCN SGE01184.A10). ERG entered the results of 

this analysis into the PW Data tab of Attachment 1 (DCN SGE01184.A01).

4.7.1 Data Source

ERG used data from an article published in the Journal of Petroleum Science and 

Engineering by Colorado State University researcher Bing Bai in 2013 (DCN SGE00501) to 

estimate flowback recovery and long-term produced water rates for the Codell-Niobrara tight gas 

formation in the Denver Basin (DCN SGE00501). This article summarizes production data 

trends for wells completed in the J Sandstone, Codell Sandstone, Niobrara, Hygiene Sandstone, 

and Terry Sandstone formations. Based on engineering judgment and EIA’s tight gas map (DCN 

SGE00155), ERG consolidated all of these formations into the "Codell-Niobrara" formation for 
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the purpose of this analysis. More specifically, the article provides equations that estimate 

produced water rates as a function of time after completion based on production data from 1,677 

vertical wells and 32 horizontal wells.

4.7.2 Methods and Procedures

ERG performed the following steps to estimate flowback recovery and long-term 

produced water rates using the equations provided in Bai (2013) (DCN SGE00501). 

Step 1: Flowback Rates for Horizontal Wells

ERG calculated flowback rates over the first 60 days of production for a typical 

horizontal well using Equation 5 (shown as Equation 2 in DCN SGE00501). As reported 

by Bai, 2013, Equation 5 estimates produced water flow rate as a function of days after 

completion and is only valid for the first 60 days of production (DCN SGE00501).

Equation 5

q = 264.4e

−0.043t

Where:

q = flow rate, barrels per day

t = time since completion, days

Step 2: LTPW Rates for Horizontal Wells

ERG calculated long-term produced water rates over 13 years of production for a typical 

horizontal well using Equation 6 below (shown as Equation 3 in DCN SGE00501). As 

reported by Bai, Equation 6 calculates produced water flow rate as a function of days 

after completion and is only valid after the first 60 days of production, up to 13 years of

production (DCN SGE00501).

Equation 6

q =

88.86

(1 + 0.0447t)

Where:

q = flow rate, barrels per day

t = time since completion, days

Step 3: LTPW Rates for Vertical Wells

ERG calculated long-term produced water rates over 13 years of production for a typical 

vertical well using Equation 7 below (shown as Equation 1 in DCN SGE00501). As 

reported by Bai, Equation 7 calculates produced water flow rate for vertical wells as a 

function of days after completion and is only valid after the first 60 days of production,

up to 13 years of production (DCN SGE00501).

Equation 7

q = 1.981e

−0.1614t
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Where:

q = flow rate, barrels per day

t = time since completion, days

Step 4: Calculate Summary Statistics

ERG calculated 10th percentile, 50th percentile, and 90th percentile statistics of the longterm produced water rates separately for horizontal and vertical wells. ERG calculated 

the 10th percentile and 90th percentile values to represent the typical range of the data. For 

horizontal wells only,

48 ERG also calculated the flowback rates over the first 30 days of 

production, based on engineering judgement, to estimate total flowback volume.

49 ERG 

presents the results in the Results tab in Attachment 10 (DCN SGE01184.A10). ERG also 

presents the total number of wells in this tab. ERG entered these results into the PW Data 

tab of Attachment 1 (DCN SGE01184.A01).

4.8 Attachment 11 – Colorado Flowback Recovery

ERG estimated flowback recovery for UOG wells completed in Colorado using data 

published by the Colorado Oil and Gas Conservation Commission (COGCC) (DCN SGE00518) 

along with results from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes (DCN 

SGE01184.A04-A05). This included UOG wells completed in the Niobrara, Codell, CodellNiobrara, Mancos, and Muddy J UOG formations. ERG entered the results of this analysis as 

inputs to the PW Data tab in Attachment 1 (DCN SGE01184.A01). Attachment 11 (DCN 

SGE01184.A11) contains the underlying Microsoft Excel file.

4.8.1 Data Sources

ERG obtained data from COGCC (DCN SGE00518). The online well search application 

allows users to obtain the following information for a specified well using the well API number:

 Monthly production of oil (barrels), gas (MCF), and produced water (barrels)

 Number of production days in each month

To obtain fracturing fluid volumes for this analysis, ERG used the results from the 

FracFocus® Fracturing Fluid Volume analysis described in Section 4.1.3 (DCN SGE01184.A04-

A05). Relevant data in these results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)

 Fracture date (start and end dates)

 Fracturing fluid volume (gallons)

 

48 Bai (2013) only provided an equation to calculate flowback rates for horizontal wells.

49 Literature reports that the flowback process lasts anywhere between 14 and 60 days. (DCN SGE00951).
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The well API number is the common field ERG used to link the FracFocus® database and 

the COGCC data.

4.8.2 Methods and Procedures

Step 1: Identify Colorado Wells from FracFocus® Analysis

ERG filtered the results from the FracFocus® Fracturing Fluid Volume analysis for UOG 

wells located in Colorado (DCN SGE01184.A04-A05), excluding wells with unknown 

well trajectories. The well records are contained in the Analysis tab of Attachment 11 

(DCN SGE01184.A11).

Step 2: Identify Flowback Volumes in COGCC’s Production Data

ERG searched the COGCC production database for the wells listed in the Analysis tab 

(from Step 1). For each well, ERG located the production data for the given month in 

which the well was completed, according to the FracFocus® database. ERG recorded the 

produced water volume and production days in the “Estimated Flowback Volume 

(barrels)” and “Production Days” fields, respectively, in the Analysis tab in Attachment 

11 (DCN SGE01184.A11). 

Literature reports that the flowback process lasts anywhere between 14 and 60 days 

(DCN SGE00951). During this analysis, ERG encountered some wells that produced for 

fewer days than the general flowback process length reported in literature (e.g., 3 days) in 

the month the well was completed. For all wells that had fewer than 14 production days

in the completion month, ERG recorded the volume for these days in addition to the 

volumes for the entire next month of production.50 For example, a well completed at the 

end of July 2011 only produced 1,000 barrels during 3 days of production by the end of 

the month. In August 2011, this well produced 5,000 barrels of produced water during 31 

days of production. ERG recorded 6,000 and 34 into the “Estimated Flowback Volume 

(barrels)” and “Production Days” fields respectively in the Analysis tab of Attachment 11

(DCN SGE01184.A11). 

Step 3: Calculate Flowback Recovery

ERG calculated the estimated flowback recovery as a percentage of total fracturing fluid 

volume using Equation 4. ERG performed this calculation in the “Estimated Flowback 

Recovery” field in the Analysis tab in Attachment 11 (DCN SGE01184.A11) for each 

well with an estimated flowback volume from Step 2 above. The total fracturing fluid 

volume was obtained from ERG’s Analysis of FracFocus® Fracturing Fluid Volumes

(DCN SGE01184.A04-A05).

 

50 ERG made this assumption in order to make the available data in literature useful for estimating flowback 

recovery for different UOG formations. The actual flowback recovery for individual wells may have been lower or 

higher than the recovery ERG estimated.
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Step 4: Calculate Summary Statistics

ERG calculated 10th percentile, 50th percentile, and 90th percentile statistics for the 

estimated flowback recovery for UOG wells in Colorado. The results are shown in the 

Results tab of Attachment 11 (DCN SGE01184.A11), which also includes the number of 

wells analyzed and the total number of wells. ERG excluded well trajectory and 

formation combinations from the results if they had less than 10 wells (e.g., horizontal 

wells in the Codell-Niobrara formation).

ERG calculated the 10th percentile and 90th percentile values to represent the typical 

range of the data. ERG also calculated the median number of production days associated 

with the flowback recovery statistics to verify it agrees with typical flowback process 

lengths reported in literature (i.e., between 14 and 60 days) (DCN SGE00951). The 

calculated flowback recovery statistics in this analysis represent a median of 29 to 30

days of production, depending on the formation, which falls within the general ranges of 

flowback process length reported in literature, and thus verifies the methods and 

procedures for this analysis.

5.0 ADDITIONAL UOG PRODUCED WATER CHARACTERIZATION DATA: ANALYSES USING 

NATIONAL AND STATE-LEVEL DATASETS

The following subsections describe analyses that ERG completed using national- and 

state-level datasets to generate data inputs to the UOG Wastewater Characterization Database in 

Attachment 13 (DCN SGE01184.A13) (see Section 3.0). 

5.1 USGS Data Used for UOG Produced Water Constituent Characterization

The following subsections describe the analysis that ERG completed using a nationallevel produced water characterization dataset published by USGS. The analyses and underlying 

data appear in Attachments 14 and 15 (DCN SGE01184.A14-.A15).

5.1.1 Data Source

The USGS Produced Water Geochemical Database v. 2.1 (PROVISIONAL) (USGS 

database) contains geochemical and other information for produced waters from both 

conventional and unconventional well types (DCN SGE01260). The database is a compilation of 

25 individual databases, publications, or reports. ERG used the USGS database to obtain 

produced water constituent data to include in the UOG Wastewater Characterization Database in 

Attachment 13 (DCN SGE01184.A13).

ERG obtained data from the USGS database from the USGS website on August 24, 2015

and aggregated the data for inclusion in the “Raw Data 3 - USGS Data” table in the “UOG 

Wastewater Characterization” database in Attachment 13 (DCN SGE01184.A13). The “USGS 

National Produced Waters Geochemical Database v. 2.1 (PROVISIONAL) – Documentation” 

file (DCN SGE01260) provides additional background about this database and defines all of the 

fields within the tables in the database.
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5.1.2 Methods and Procedures

ERG performed the following steps to analyze the USGS data:

Step 1: Extract Relevant Data

ERG imported the USGS data into the “USGS Raw Data” table in ERG’s USGS 

Produced Waters database in Attachment 15 (DCN SGE01184.A15), extracted entries 

where the well type was shale and/or tight, then deleted entries from references that were 

already included in the UOG Wastewater Characterization database, based on the 

citations listed for each entry in the USGS database. 

Step 2: Compile Unique List of Wells and Assign Well IDs

ERG compiled a list of unique wells, based on the following USGS database fields: 

original database/reference, basin, formation, well name, and well type. ERG assigned 

each unique well in the extracted dataset from Step 1 a “Well ID” that was used to 

aggregate constituent data by well. 

Step 3: Calculate Medians

Because Microsoft Access does not support median calculations, ERG exported the 

“USGS Temp” table in Attachment 15 (DCN SGE01184.A15) into the USGS Data tab in

Attachment 14 (DCN SGE01184.A14). Within Attachment 14, ERG first removed any 

negative values51 in the USGS Data_Neg Values Removed tab. ERG then used Excel 

functions to calculate the median values for each unique Well ID and Parameter in a 

crosstab format on the Median Summary tab in Attachment 14. Finally, ERG manually 

removed any Parameters that did not have values for any of the wells in the Median 

Summary_Del Blank Col tab.

Step 4: “Un-Crosstab” Data

ERG exported the results of the Median Summary_Del Blank Col tab from Attachment 

14 (DCN SGE01184.A14) into the “USGS Median Summary Data (from Excel)” table in

Attachment 15 (DCN SGE01184.A15). Because the Excel results were in a crosstab-type 

format where the parameter names were stored in the column headings, ERG created 

union queries52 to pull the results of each column into a single table with three columns

containing Well ID, Parameter, and Median Value. ERG also performed a similar type of 

“un-crosstab”53 process on the “USGS_Temp” table in Attachment 15 (DCN 

SGE01184.A15) to make the data more usable in Step 5.

 

51 ERG identified some negative values in the data that referred to numeric codes (e.g., “-3=NA, not analyzed, 

unknown”). ERG also identified non-coded negative values in the data that referred to actual data values. ERG was 

unable to find an explanation of these values. These non-coded negative values only accounted for 0.2 percent of the 

full dataset; ERG excluded these non-coded negative values from the analysis because they were difficult to 

interpret and ERG would not expect a concentration value below zero.

52 Union queries combine the results of several similar select queries.

53 The “un-crosstab” process refers to the process of translating data from columns into rows.
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Step 5: Compile Min, Max, and Median Data 

From the “un-crosstabbed” full data set, ERG queried the true (non-median) minimum

and maximum values for each unique Well ID and Parameter and added them to a final 

table. ERG added the median values based on the data in the “un-crosstabbed” median 

table. Lastly, the final table was formatted for export into the UOG Wastewater 

Characterization database. 

5.1.3 Attachments 14 and 15 – Query Descriptions

Table 7 describes the queries and their results used to perform the analyses in 

Attachments 14 and 15 (DCN SGE01184.A14 and A15).

Table 7. USGS Produced Water Database: Query Descriptions

Query(s) Query Description

Relevant 

Memorandum 

Attachment

000 Initialized [USGS_Temp] table.

15

001 Appended the entries from the entire set of [USGS Raw Data] into [USGS_Temp], 

where the well type was “shale gas” or “tight”.

002 Removed entries from [USGS_Temp] (Hayes and NYSDEC), which were already 

included in the TDD database.

100 Initialized [List of Wells] table.

101 Extracted all unique combinations of IDDB, REFERENCE, BASIN, 

FORMATION, DFORM, WELL, and WELLTYPE and appended to [List of 

Wells]. WellID was auto numbered to create a list of all unique wells. 

102 Linked [USGS_Temp] table to [List of Wells] table by IDDB, REFERENCE, 

BASIN, FORMATION, DFORM, WELL, and WELLTYPE, and updated

[USGS_Temp].[WellID] to be equal to [List of Wells].[WellID]. This query 

assigned WellID values in the [USGS_Temp] table.

200 Exported [USGS_Temp] to Excel (USGS_Median Data.xlsx, USGS Data tab).

14

54

“USGS_Data_Neg Values Removed” tab: Referenced “USGS Data” tab and only 

pulled non-negative values.

“Median Summary” tab: Created a table with WellID row headers and Parameter 

column headers. Array equations calculate the median value for each combination 

of WellID and Parameter. 

“Median Summary_Del Blank Col” tab: Manually removed Parameter columns 

with no data, for easier handling in the Access file. 

Imported “Median Summary_Del Blank Col” tab into Access as [USGS Median 

Data (from Excel)].

300 Initialized [Median Summary] table.

15

301a, 302a Created a union query to pull [WellID] and median value for each Parameter. The 

text for the union query was created by making a list of Parameters in Excel, and 

then creating an equation template to create each line of text. A single union query 

was too large for Access to handle; therefore it was split into two separate queries. 

This query converts the data from a crosstab type query (WellID row headers and 

 

54 Attachment 14 (DCN SGE01184.A14) is an Excel attachment in which ERG completes the median calculations 

that cannot be performed in the Access database in Attachment 15 (DCN SGE01184.A15). Attachment 15 lists 

Query 200 as a placeholder entry for the step in which ERG exports the data to Excel to perform these median 

calculations.
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Table 7. USGS Produced Water Database: Query Descriptions

Query(s) Query Description

Relevant 

Memorandum 

Attachment

Parameter column headers) into a table with individual line entries for each Well 

ID, Parameter, and Median Value.

301b, 302b Appended the results of 301a and 302a into [Median Summary] table.

400 Initialized [All Parameter Data] table.

401a, 402a,

403a, 404a

Similar to 301a and 302b above, except it uses all data from [USGS_Temp].

401b, 402b Appended the results of 401a through 404a into [All Parameter Data] table.

500 Initialized [USGS Data for Export] table.

501a Summarized Min, Max, and Number of Data Points for all values in [All Parameter 

Data] table.

501b Appended well information and results of 501a into [USGS Data for Export] table.

502 Updated query to update [USGS Data for Export] with median data from [Median 

Summary].

503 Deleted min and max in [USGS Data for Export] if there is only one data point.

504 Standardized the format for easy import in to a separate TDD database: Added

reference to USGS, 2014; set all WW Descriptions to “Produced”, etc.

5.2 ORD Data Used for UOG Wastewater Constituent Characterization

The following subsections describe the analysis that ERG completed using a nationallevel produced water characterization dataset from EPA that was compiled from the public 

docket for EPA ORD’s Study of the Potential Impacts of Hydraulic Fracturing on Drinking 

Water Resources: Progress Report (Docket ID: EPA-HQ-ORD-2010-0674). The analyses and 

underlying data are contained in Attachment 16 (DCN SGE01184.A16) and the QC procedures 

are described in Section 5.3.

5.2.1 Data Source

As part of ORD’s Study of Hydraulic Fracturing for Oil and Gas and its Potential Impact 

on Drinking Water Resources, ORD obtained data from nine UOG well operators, randomly 

selected to obtain a stratified statistical representation of the industry. A portion of the data that 

ORD received from operators included concentrations of constituents found in their produced 

water. These data are available through the public docket for EPA’s Study of the Potential 

Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report (Docket ID: 

EPA-HQ-ORD-2010-0674).

55 EPA compiled these concentration data into a spreadsheet and 

provided it to ERG. ERG performed QC checks on the concentration data; a description of these 

QC checks is included in Section 5.3. ERG imported the concentration data from EPA’s 

spreadsheet into the “Raw Data 2 - ORD_All_Data_Manipulated” table in the “UOG Wastewater 

Characterization” database in Attachment 13 (DCN SGE01184.A13). 

 

55 These data are referred to by the relevant Docket ID instead of by DCN in the relevant attachments.
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ERG received a non-CBI56 subset of the national concentration data from EPA and 

analyzed the produced water data for inclusion in the Wastewater Characterization database, 

which is shown in Attachment 13 (DCN SGE01184.A13). 

5.2.2 Methods and Procedures

ERG’s analysis of the ORD data is shown in Attachment 16 (DCN SGE01184.A16). 

ERG performed the following steps to compile the constituent concentration data from ORD’s 

dataset:

Step 1: Standardize API Numbers

Using ORD’s dataset “Raw Data_NonCBI Operator Data from ORD” table in 

Attachment 16 (DCN SGE01184.A16), ERG first standardized the API numbers for TX, 

ND, NM, AR, and LA to the format used by other states. Queries 00 through 05 in 

Attachment 16 show this standardization.

Step 2: Make Table with ORD and DI Desktop® Data

The API number standardization (Step 1) allowed ERG to link the ORD dataset to the DI 

Desktop® dataset to pull additional data fields into the analysis (i.e., state, basin, 

formation, resource type, well trajectory, spud date, completion date). Query 10 in 

Attachment 16 shows this step in the analysis. More information about the DI Desktop®

database can be found in ERG’s Analysis of DI Desktop® memorandum (DCN 

SGE01180).

Step 3: Update Data

ERG manually updated the “Resource Type_ERG” field to “tight” for the Spraberry 

formation, based on existing literature (DCN SGE00486) (see Query 11 in Attachment 

16, DCN SGE01184.A16). ERG also deleted any data where the associated formation 

name was blank (see Query 12 in Attachment 16, DCN SGE01184.A16). ERG used 

Microsoft Access functions to calculate the number of days since fracturing, based on the 

date reported in the ORD dataset and the completion date reported in the DI Desktop®

dataset (see Query 13 in Attachment 16, DCN SGE01184.A16). Finally, ERG updated 

the wastewater type to “UOG wastewater” for all data because the ORD dataset did not 

identify wastewater as flowback or long-term produced water (see Query 14 in 

Attachment 16, DCN SGE01184.A16).

Step 4: Generate Final Table

ERG imported the final table (“All_Data_Final” table in Attachment 16, DCN 

SGE01184.A16) into the Wastewater Characterization database in Attachment 13 (DCN 

SGE01184.A13) and standardized the data using the methods described in Section 3.2 of

this memorandum.

 

56 EPA removed all of the data flagged as confidential business information (CBI) under the Toxic Substances 

Control Act of 1976 (TSCA) before providing this subset of data to ERG.
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5.2.3 Attachment 16 – Query Descriptions

Table 8 describes the queries used for the analyses performed in Attachment 16 (DCN 

SGE01184.A16).

Table 8. Analysis of ORD Non-CBI Operator Data: Query Descriptions

Query(s) Query Description

00 Copied “API No” to “API_ERG”.

01, 02, 03, 04, 05 Updated the “API_ERG” numbers for TX, ND, NM, AR, and LA to standardize the format of 

the API number across all of the states represented in the data.

10 Linked the ORD dataset to the DI Desktop® dataset to pull additional data fields into the 

analysis (i.e., state, basin, formation, resource type, well trajectory, spud date, completion 

date).

11 Updated “Formation” and “Resource Type” for Spraberry. 

12 Removed records with null or blank dates. 

13 Calculated “Days Since Fracturing” by finding the differential between the sample date and 

well completion date. 

14 Set “Wastewater Type” to “UOG Wastewater”.

5.3 WY OGCC Data Used for UOG Wastewater Constituent Characterization 

The following subsections describe the analysis that ERG completed using a state-level 

produced water characterization dataset published by the Wyoming Oil and Gas Conservation 

Commission (WY OGCC). The analyses and underlying data appear in Attachment 17 (DCN 

SGE01184.A17).

5.3.1 Data Source

EPA requested data from WY OGCC and received a dataset output on September 3, 2015 

containing the raw data found in the “WY OGCC Raw Data” table in Attachment 17 (DCN 

SGE01184.A17)57. The raw WY OGCC dataset contains wastewater characterization data at the 

well level for wastewater from both conventional and unconventional well types (DCN 

SGE01244.A01). ERG used the WY OGCC data to obtain produced water constituent data to 

include in the UOG Wastewater Characterization Database in Attachment 13 (DCN 

SGE01184.A13).

5.3.2 Methods and Procedures

ERG performed the following steps to analyze the WY OGCC data:

 

57 ERG excluded some of the raw data from WY OGCC due to data quality concerns. The WYOGCC Water Data 

Memorandum (DCN SGE01244) provides more detail about the data quality concerns in the underlying, raw data 

from WY OGCC.
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Step 1: Remove Duplicates

ERG reviewed the WY OGCC dataset and determined that some of the data were 

duplicative with data from the USGS Produced Water database version 2.1 (DCN 

SGE01260) that was also reviewed and analyzed in this memorandum (see Section 5.1). 

In an effort to eliminate duplicates, ERG compared the WY OGCC data to the USGS 

data. ERG compared the following five data fields, and if the data in all five fields were 

exact duplicates, ERG excluded the WY OGCC data from the UOG Wastewater 

Characterization Database in Attachment 13 (DCN SGE01184.A13):

 API number

 pH

 Total dissolved solids (TDS)

 Calcium (Ca)

 Chloride (Cl)

Step 2: Compile Unique List of Wells and Assign Well IDs

ERG compiled a list of unique wells, based on the following WY OGCC database fields: 

API number, well name, field name, formation name, and sample location. ERG assigned 

each unique well in the extracted dataset a “Well ID” that was used to aggregate 

constituent data by well. 

Step 3: “Un-Crosstab” Data

Next, because the raw WY OGCC constituent data were in a crosstab-type format where 

the parameter names were stored in the column headings, ERG created a union query58 to 

pull the results of each column into a single table with three columns containing Well ID, 

Parameter, and Value. This query created one row for each measurement, which is the 

format that Microsoft Access typically requires to aggregate data.

Step 4: Extract Relevant Data

ERG compared the WY OGCC data to the DI Desktop® data (DCN SGE01180.A01) to 

identify the wastewater characterization data associated with UOG wells. ERG cross 

referenced the data in the WY OGCC dataset to the “Active Oil and Gas Wells” table in 

the DI Desktop® dataset by API number to get a list of UOG wells. ERG used the 

“Resource Type” (e.g., shale, tight) and “Consolidated Formation” (e.g., Fayetteville) 

fields in the DI Desktop® dataset to determine the list of UOG wells. Where the 

“Resource Type” and/or “Consolidated Formation” fields were blank, ERG excluded the 

wells from the UOG Wastewater Characterization Database in Attachment 13 (DCN 

SGE01184.A13) because we could not determine if the data were associated with UOG 

or COG wells.

 

58 Union queries combine the results of several similar select queries.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 45

Step 5: Import Relevant Data into UOG Wastewater Characterization Database

The final table was formatted for import into the UOG Wastewater Characterization 

database in Attachment 13 (DCN SGE01184.A13). ERG imported the table as “Raw 

Data - WY OGCC - Not Final”.

Step 6: Summarize Data by Basin, Formation, and Parameter

In an effort to equally weigh the available data for all basins and formations in the United 

States59, ERG collapsed the data from WY OGCC into one median value for each basin, 

formation, and parameter. Because Microsoft Access does not support median 

calculations, ERG exported the “Raw Data - WY OGCC - Not Final” table in Attachment 

17 (DCN SGE01184.A17) into the Raw Data - WY OGCC - Not Final tab in Attachment 

18 (DCN SGE01184.A18). Within Attachment 18, ERG used Excel functions to calculate 

the median values and number of samples for each unique Basin, Formation, and 

Parameter on the Import_Raw Data 4 - WY OGCC tab in Attachment 18.

Step 7: Import Summarized Data into UOG Wastewater Characterization Database

ERG imported the Import_Raw Data 4 - WY OGCC tab into the UOG Wastewater

Characterization database in Attachment 13 (DCN SGE01184.A13). ERG named the 

table “Raw Data 4 - WY OGCC”.

5.3.3 Attachment 17 – Query Descriptions

Table 9 describes the queries and their results used to perform the analyses in Attachment 

17 (DCN SGE01184.A17).

Table 9. WY OGCC Database: Query Descriptions

Query(s) Query Description

000 Initialized [WY OGCC Data Without Dups] table.

001 Compared [WY OGCC Raw Data] with [USGS Raw Data] using API No, Ca, Cl, TDS, and pH 

values to find duplicate data.

002 Appended non-duplicate WY OGCC data to [WY OGCC Data Without Dups] table.

003 Created a union query to pull “WellID” and value for each Parameter. This query converts the data 

from a crosstab type query (WellID row headers and Parameter column headers) into a table with 

individual line entries for each Well ID, Parameter, and Value.

004 Combined the results of query 003 with the well data (API No, Well Name, Formation), using the 

“WellID”.

005 Queried the [Active Oil and Gas Wells] table from the DI Desktop® Well File Database (DCN 

SGE01170) to summarize unique API Nos. with associated [Consolidated Formation] names. Note: 

only entries with a valid [Consolidated Formation] and/or [Resource Type] were assumed to be UOG 

wells. 

 

59 The other large data sets that ERG used for the UOG wastewater characterization analyses represented data for the 

entire United States. Since the WY OGCC data only represented data from basins/formations in WY, including each 

data point as a unique value in ERG’s analysis caused unintentional weight to be given to the data from these 

basins/formations.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 46

Table 9. WY OGCC Database: Query Descriptions

Query(s) Query Description

006 Combined the results of queries 004 and 005 using API No.

007 Appended the results of 006 into [WY OGCC Data – for Export] table.

008 Assigned unique “SGE_ID” values to [WY OGCC Data – for Export] entries for use in the UOG 

Wastewater Characterization database (DCN SGE01184.A13)

6.0 QUALITY ASSURANCE (QA) PROCEDURES

All of the analyses presented 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 about produced water volumes and constituent characteristics.

Specifically, ERG used the procedures described in Section 4 of the PQAPP to gather and 

manage existing data in support of the UOG 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 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 10, 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., EPA site visit reports, industry meeting notes).

 Source Flag B - Documents prepared by a verified60 source that include citation 

information (e.g., operator reports, vendor documents, 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).

 Source Flag D - Documents prepared by a source that could not be verified and that do 

not include citation information.

 

60 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.
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 47

ERG followed the procedures described in the PQAPP to generate, evaluate, and analyze 

data using spreadsheets (Section 7.0) and databases (Section 8.0). ERG conducted the following 

QA checks during the analyses:

 ERG performed a 20 percent check of all data manually entered.

 ERG performed a 100 percent check of all analyses and calculations, and documented 

these checks in internal versions of the spreadsheets and databases.

 For all analyses performed in state-specific Access databases, one team member created 

queries and another team member reviewed the design and logic of the queries. ERG 

documented these checks in the internal versions of spreadsheets and databases.

 ERG had a senior staff member familiar with ELGs and the UOG rulemaking review 

the results from each analysis.

ERG performed the following, specific QC checks on the data collected as part of ORD’s 

Study of Hydraulic Fracturing for Oil and Gas and its Potential Impact on Drinking Water 

Resources (discussed in Section 5.2):

 ERG performed a 20 percent check of the data entry from the raw UOG well operator 

data to the compiled spreadsheet. If ERG identified a discrepancy between the two 

files, ERG checked all of the relevant data from the file (i.e., not just a 20 percent 

check), where it was reasonable to do so (i.e., the number of data points in the file was 

less than 50).

 Where ERG identified a discrepancy between the data, ERG corrected the data in the 

“Raw Data 2 - ORD_All_Data_Manipulated” table in the “UOG Wastewater 

Characterization” database in Attachment 13 (DCN SGE01184.A13).

 ERG found data discrepancies in less than two percent of the files that were checked.

7.0 REFERENCES

Table 10 lists the sources ERG used along with their DCN and source flag (see Section 

6.0 for a description of source flags). The type of information extracted from each source is 

noted with an X in the “WW Volumes” (wastewater volumes) and/or “WW Char.” (wastewater 

characterization) columns.

Table 10. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00002

Volz, Conrad; Ferrar, Kyle; Michanowicz, Drew et. al. 2011. 

Contaminant Characterization of Effluent from PA Brine 

Treatment Josephine Facility

A X

SGE00006.A03 Havics, Andrew, pH2, LLC/QEPA. 2011. Fracking & 

Associated Media Composition in Colorado B X

SGE00006.A04

McElreath, D. 2011. Comparison of Hydraulic Fracturing 

Fluids Composition with Produced Formation Water Quality 

Following Fracturing.

C X

SGE00007.A13

Hayes, T. 2011. Characterization of Marcellus Shale and 

Barnett Shale Flowback Waters and Technology 

Development for Water Reuse

C X
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 48

Table 10. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00007.A14 Tipton, Steven, Newfield Exploration. 2011. Mid-Continent 

Water Management for Stimulation Operations B

SGE00011

Veil, John A. 2010. Water Mgmt Technologies Used by 

Marcellus Shale Gas Producers. Prepared by Argonne 

National Lab. Prepared for U.S. DOE NETL.

A X

SGE00064

Williams, John. 2011. Marcellus Shale-Gas Development 

and Water-Resource Issues. USGS: New York Water 

Science Center.

A X

SGE00070

Acharya, Harish; Matis, Hope; Kommepalli, Hareesh; 

Moore, Brian; Wang, Hua. 2011. Cost Effective Recovery of 

Low-TDS Frac Flowback Water for Re-use. 

A X X

SGE00090 NYSDEC. 2011. Suppl. Generic Env. Imp. Statement on Oil, 

Gas, & Soln. Mining Reg. Prgm. Prelim. Rev. Draft. A X

SGE00091

Rimassa, Shawn; Howard, Paul; Blow, Kristel; 

Schlumberger. 2009. Optimizing Fracturing Fluids from 

Flowback Water. Society of Petroleum Engineers.

A X

SGE00110

Bruff, Matthew. 2011. An Integrated Water Treatment 

Technology Solution for Sustainable Water Resource 

Management in the Marcellus Shale.

A X

SGE00155

U.S. Energy Information Administration. 2010. Tight Sands 

Gas Plays, Lower 48 States. Prepared by EIA Office of Oil 

and Gas. (June).

A X

SGE00241

Rowan, E.L., et al. 2011. Radium content of oil and gas field 

production waters in the northern App Basin. USGS 

Scientific Investigations Report 2011–5135.

A X

SGE00275 U.S. EPA. 2012. Site Visit Report: Citrus Energy 

Corporation Marcellus Shale Gas Operations. (January 22). A X

SGE00276 U.S. EPA. 2012. Meeting with XTO Energy, Inc. about 

Unconventional Oil and Gas Sanitized. A X

SGE00280 U.S. EPA. 2013. Site Visit Report: Anadarko Petroleum 

Corporation Marcellus Shale Gas Operations. (January 9). A X

SGE00283 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes on 

Conference Call with BLX, Inc on 15 May 2012. (June 11). A X

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

Water Management and Reuse Technologies. RPSEA A X

SGE00298.A05 Ashwin Dhanasekar. 2012. Assessing Specific Shale Plays -

Niobrara. Colorado State University. B X

SGE00305.A05

Dave Yoxtheimer. 2012. Flowback Treatment and Reuse 

Strategies for Tight Oil Formations. Penn State Marcellus 

Center for Outreach and Research.

B X

SGE00311.A07 Michael Dunkel. 2012. The Economics of Water 

Management. Pioneer Natural Resources. C X

SGE00311.A12 Mark Mazoch. 2012. Fayetteville Shale. Southwestern 

Energy. B X X

SGE00313

Gradient. 2009. Evaluation of Potential Impacts of Hydraulic 

Fracturing Flowback Fluid Additives on Microbial Processes 

in POTWs

C X
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 49

Table 10. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00332 Kent Perry. New Albany Shale Gas Research Project. Gas 

Technology Institute. B X

SGE00333

Horn, A. 2009. Breakthrough Mobile Water Treatment 

Converts 75% of Fracturing Flowback Fluid to Fresh Water 

and Lowers CO2 Emissions. SPE-121104-PP

B X X

SGE00339

Susquehanna River Basin Commission (SRBC). 2011. 

Susquehanna River Basin Commission: Water Withdrawals 

& Consumptive Use for Natural Gas Industry.

A X

SGE00343 James Welsh. Hydraulic Fracturing Regulatory Processes in 

Louisiana. Louisiana Department of Natural Resources. A X

SGE00344

Haluszczak, L.O.; Rose, A.W.; Kump, L.R. 2012. 

Geochemical Evaluation of Flowback Brine from Marcellus 

Gas Wells in Pennsylvania, USA.

A X

SGE00345 Lewis, Aurana. 2012. Wastewater Generation and Disposal 

from Natural Gas Wells in Pennsylvania. Duke University. B X

SGE00350

Stepan, D.J., et. al. 2010. Bakken Water Opportunities 

Assessment -Phase 1. Energy & Env Research Cntr, Univ of 

ND. Prepared for Nat'l Energy Tech Lab

A X X

SGE00359

Robert Kimball. 2012. Key Considerations for Frac

Flowback / Produced Water Reuse and Treatment. CDM 

Smith.

C X

SGE00414

Hayes, Thomas, et.al. 2012. Characterization of Flowback 

Waters from the Marcellus and the Barnett Shale Regions 

Report No. 08122-05.09. RPSEA

A X X

SGE00442.A02 Cecil Colwell. 2013. Development of Cost Effective 

Systems for Handling Produced Water. Source Energy. C X

SGE00442.A06

Murray, K.E. 2013. Examining Water Production Volumes 

and Produced Water Quality in the Mississippi Lime to 

Develop Appropriate Management Strategies.

B X X

SGE00465

Jean-Philippe Nicot and Bridget Scanlon. 2012. Water Use 

for Shale-Gas Production in Texas, U.S. University of Texas 

at Austin.

A X

SGE00480

Richard Luedecke. 2012. Energy Water Conservation & 

Recycling 33rd Annual Governor's Water Conference. 

Devon Energy.

C X

SGE00486 U.S. Energy Information Administration. 2013. Assumptions 

to the Annual Energy Outlook 2013. A X

SGE00501

Bai, Bing. 2013. Modeling of Frac flowback and produced 

water volume from Wattenberg oil and gas field. Journal of 

Petroleum Science and Engineering. 

A X

SGE00507 Boschee, Pam. 2012. Handling Produced Water from 

Hydraulic Fracturing. Oil & Gas Facilities. B X

SGE00511 Casey, Greg. 2013. The evolution of Class II Salt Water 

Disposal (SWD) Wells as Part of the Shale Revolution. B X

SGE00518 Colorado Oil and Gas Conservation Commission (COGCC). 

COGIS - Production Data Inquiry. A X
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 50

Table 10. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00532

Hansen, E; Mulvaney, D; Betcher, M. 2013. Water Resource 

Reporting and Water Footprint from Marcellus Shale 

Development in WV and PA. (October 30).

B X X

SGE00555

New York State Department of Environmental Control 

(NYSDEC). 2009. New Discharge Notification: SPDES 

Permit NY 002 5984 to Watertown, NY POTW.

A X

SGE00556 Nicot, Jean-Philippe, et al. 2011. Current and Projected 

Water Use in the Texas Mining and Oil and Gas Industry. A X

SGE00558 Office of Geological Survey (OGS). 2011. Hydraulic 

Fracturing of Natural Gas Wells in Michigan. (May 31). A X

SGE00559 Ohio Department of Natural Resources (OH DNR). 2012. 

2011 Utica Shale Production. A X

SGE00560 Ohio Department of Natural Resources (OH DNR). 2013. 

2012 Utica Shale Production. A X

SGE00592 U.S. DOE. 2013. Water Issues Dominate Oil and Gas 

Production. E&P Focus. (Fall). A X

SGE00607

U.S. EPA. 2012. Conference Call with Quicksilver 

Resources, Inc. About Shale Gas Operations Sanitized. 

(October 11)

A X

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

Wastewater Treatment and Related Modeling. (April 18) A X

SGE00625 U.S. EPA. 2015. Site Visit Report: Southwestern Energy 

Fayetteville Shale Gas Operations. Sanitized. A X

SGE00629

Warner et al. 2013. Impacts of Shale Gas Wastewater 

Disposal on Water Quality in Western PA. Environmental 

Science & Technology 47(20):11849–11857

A X

SGE00632

Williams, John. n.d. The Marcellus Shale Gas Play: 

Geology, Development, and Water-Resource Impact 

Mitigation. USGS: New York Water Science Center.

A X

SGE00635 U.S. EPA. 2012. Site Visit Report Chesapeake Energy 

Corporation Marcellus Shale Gas Operations Sanitized. A X

SGE00639

Nicot et al. 2012. Oil & Gas Water Use in Texas: Update to 

the 2011 Mining Water Use Report. Univ of TX at Austin. 

(September)

A X

SGE00640

Mingazetdinov, Ildus. 2012. Predictions Of Produced Water 

Quality And Quantity For Spatially-Distributed Wells In 

Niobrara Formation

B X

SGE00641

Nicot, Jean-Philippe. 2013. Geographical, Geological, and 

Hydrogeological Attributes of Formations in the Footprint of 

the Eagle Ford Shale.

A X

SGE00642

Goodwin, S., et al. 2012. Life Cycle Analysis of Water Use 

and Intensity of Oil and Gas Recovery in Wattenberg field. 

(May 7).

B X

SGE00643 Wyoming Oil and Gas Conservation Commission. 2013. 

Download Production. A X

SGE00644

New Mexico Energy, Minerals and Natural Resources 

Department (NMEMND). 2014. OCD Permitting: Well 

Search.

A X
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 51

Table 10. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00691

U.S. EPA. 2013. Summary of the Technical Workshop on 

Water Acquisition Modeling: Assessing Impacts Through 

Modeling and Other Means. (September).

A X

SGE00710

Slutz, J; Anderson, J; Broderick, R; Horner, P. 2012. Key 

Shale Gas Water Management Strategies: An Economic 

Assessment Tool. (September 11).

B X

SGE00719

Agrawal, Archna. 2009. A Technical and Economical Study 

of Completion Techniques in Five Emerging U.S. Shale 

Plays. (December).

B X

SGE00727 Ohio Department of Natural Resources (OH DNR). 2014. 

2013 Quarterly Horizontal Shale Production: 3rd Quarter. A X

SGE00731

Silva, J; Gettings, R; Kostedt, W; Watkins, V. 2013. 

Pretreatment Targets for Salt Recovery from Marcellus 

Shale Gas Produced Water. 

A X

SGE00737 Ohio Department of Natural Resources (OH DNR). 2014. 

2013 Quarterly Horizontal Shale Production: 4th Quarter. X

SGE00774 Ziemkiewicz, P. 2013. Water Quality Literature Review and 

Field Monitoring of Active Shale Gas Wells. (February 15). A X

SGE00777

Johnson, Tommy and Harry, David. 2014. Uinta Water 

Management. Water Management for Shale Plays 

Conference. (May 28).

C X

SGE00788

NYSDEC. 2009. Supplemental Generic Environmental 

Impact Statement (SGEIS) on the Oil, Gas, and Solution 

Mining Regulatory Program.

C X

SGE00948

Chapman. 2012. Geochemical and Strontium Isotope 

Characterization of Produced Waters from Marcellus Shale 

Natural Gas Extraction.

A X

SGE00949

NYSDEC. 1999. An Investigation of Naturally Occurring 

Radioactive Materials (NORM) in Oil and Gas Wells in New 

York State. DEC Publication.

A X

SGE00950

EERC (NGPWC) Bakken Water Opportunities Assessment 

North Dakota Petroleum Council Annual Meeting September 

2009.

C X

SGE00951

NYSDEC. 2011. Supplemental Generic Environmental 

Impact Statement (SGEIS) on the Oil, Gas, and Solution 

Mining Regulatory Program: Info Requests. 

A X

SGE00954 Palacios, Virginia. 2012. Baseline Groundwater Quality 

Testing Needs in the Eagle Ford Shale Region April 2012 A X

SGE00957

ERG. 2013. Environmental Engineering Support for Clean 

Water Regulations Programmatic Quality Assurance Project 

Plan (PQAPP).

A X X

SGE00958 ERG. 2014. Unconventional Oil and Gas (UOG) 

Supplemental Quality Assurance Project Plan (SQAPP). A X X

SGE00964 Ohio Department of Natural Resources (OH DNR). 2014. 

2013 Quarterly Horizontal Shale Production: 1st Quarter. X

SGE00965 Ohio Department of Natural Resources (OH DNR). 2014. 

2013 Quarterly Horizontal Shale Production: 2nd Quarter. X

SGE01028 PA DEP. 2015. Technologically Enhanced Naturally 

Occurring Radioactive Materials (TENORM) Study Report. A X
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 52

Table 10. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE01165

Maguire-Boyle, S.J. and Barron, A.R. 2014. Organic 

compounds in produced waters from shale gas wells. Royal 

Society of Chemistry.

A X

SGE01169 FracFocus. 2015. FracFocus Database. Accessed on July 22. A X

SGE01170 DrillingInfo, Inc. 2015. DI Desktop® March 2015 

Download_CBI. B X

SGE01171 DrillingInfo, Inc. 2015. HPDI Data Coverage. (March 30). B X

SGE01172

OH DNR. 2015. Utica/Point Pleasant Shale Cumulative 

Permitting Activity through 12/07/2013. Downloaded on 

9/6/2015. Last updated on 8/29/2015.

A X

SGE01175 Kansas Geological Survey. 2015. Horizontal or Slant Wells 

in Kansas. Accessed on 9/9/2015. A X

SGE01180 ERG. 2016. Analysis of DI Desktop® Database. A X

SGE01181 ERG. 2016. Unconventional Oil and Gas (UOG) Drilling 

Wastewater Memorandum A X

SGE01182.A03

ERG. 2016. Analysis of Pennsylvania Department of 

Environmental Protection’s Oil and Gas Waste Reports -

Attachment 3 - Data Calculations.

A X

SGE01188

U.S. EPA. 2016. Technical Development Document for 

Effluent Limitations Guidelines and Standards for Oil and 

Gas Extraction.

A X X

SGE01189

NDIC. 2015. Basic Subscription Services Well Index. 

Department of Mineral Resources, Oil and Gas Division. 

Last Accessed on 9/15/2015.

A X

SGE01190 U.S. Energy Information Administration. 2015. Assumptions 

to the Annual Energy Outlook 2015. A X

SGE01191

U.S. Energy Information Administration. 2015. Lower 48 

States Shale Plays. Prepared by EIA Office of Oil and Gas. 

(April).

A X

SGE01237 Ohio Department of Natural Resources (OH DNR). 2015. 

2014 Quarterly Horizontal Shale Production: 1st Quarter. A X

SGE01238 Ohio Department of Natural Resources (OH DNR). 2015. 

2014 Quarterly Horizontal Shale Production: 2nd Quarter. A X

SGE01239 Ohio Department of Natural Resources (OH DNR). 2015. 

2014 Quarterly Horizontal Shale Production: 3rd Quarter. A X

SGE01240 Ohio Department of Natural Resources (OH DNR). 2015. 

2014 Quarterly Horizontal Shale Production: 4th Quarter. A X

SGE01241 Ohio Department of Natural Resources (OH DNR). 2015. 

2015 Quarterly Horizontal Shale Production: 1st Quarter. A X

SGE01242 Ohio Department of Natural Resources (OH DNR). 2015. 

2015 Quarterly Horizontal Shale Production: 2nd Quarter. A X

SGE01259 USGS. 2015. USGS Produced Water Database Accessed in 

September 2015.

A X

SGE01260 U.S. Geological Survey (USGS). 2014. National Produced 

Waters Geochemical Database v2.1 (Provisional). A X

SGE01262 Earthworks. 2015. Gaps in Water and Waste Reporting for 

Oil and Gas Production: A Five State Review. B X
UOG Produced Water Volumes and Characterization Data Compilation Memorandum

June 7, 2016

Page 53

Table 10. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE01334

ERG. 2016. Memorandum Providing a Crosswalk between 

Tables and Figures in the Proposed and Final Technical 

Development Document for Effluent Limitations Guidelines 

and Standards for Oil and Gas Extraction.

A -- --

a—Source Flag A—Journal articles and documents prepared by or for a government agency (e.g., EPA 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, 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).

Source Flag D—Documents prepared by a source that could not be verified and that do not include citation 

information.

8.0 ATTACHMENTS
ATTACHMENT 1: UOG PW DATA COMPILATION (DCN SGE01184.A01)
ATTACHMENT 2: DI DESKTOP LONG-TERM PRODUCED WATER GENERATION RATES

(DCN SGE01184.A02)
ATTACHMENT 3: DI DESKTOP LONG-TERM PRODUCED WATER GENERATION RATES

(DCN SGE01184.A03)
ATTACHMENT 4: FRACFOCUS FRACTURING FLUID VOLUMES (DCN SGE01184.A04)
ATTACHMENT 5: FRACFOCUS FRACTURING FLUID VOLUMES (DCN SGE01184.A05)
ATTACHMENT 6: BAKKEN FLOWBACK RECOVERY (DCN SGE01184.A06)
ATTACHMENT 7: NEW MEXICO FLOWBACK RECOVERY (DCN SGE01184.A07)
ATTACHMENT 8: UTICA FLOWBACK RECOVERY AND LONG-TERM PRODUCED WATER RATES

(DCN SGE01184.A08)
ATTACHMENT 9: WYOMING FLOWBACK RECOVERY (DCN SGE01184.A09)
ATTACHMENT 10: CODELL-NIOBRARA FLOWBACK RECOVERY AND LONG-TERM PRODUCED 

WATER RATES (DCN SGE01184.A10)
ATTACHMENT 11: COLORADO FLOWBACK RECOVERY (DCN SGE01184.A11)
ATTACHMENT 12: UOG WASTEWATER CHARACTERIZATION ANALYSIS

(DCN SGE01184.A12)
ATTACHMENT 13: UOG WASTEWATER CHARACTERIZATION DATABASE

(DCN SGE01184.A13)
ATTACHMENT 14: USGS PRODUCED WATER EXCEL FILE (DCN SGE01184.A14)
ATTACHMENT 15: USGS PRODUCED WATER DATABASE (DCN SGE01184.A15)
ATTACHMENT 16: ORD NON-CBI OPERATOR DATA (DCN SGE01184.A16)
ATTACHMENT 17: WY OGCC CHARACTERIZATION DATA (DCN SGE01184.A17)
ATTACHMENT 18: WY OGCC EXCEL CALCULATIONS (DCN SGE01184.A18)