MEMORANDUM

TO: Lisa Biddle, EPA

FROM: James K. O’Connell, ERG 

Brent Ruminski, ERG

Jason Sese, ERG

Sarah Yates, ERG

DATE: March 31, 2015

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

Characterization Data Compilation – DCN SGE00724

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 (TDD) for Proposed Effluent Limitations Guidelines and Standards for 

Oil and Gas Extraction (DCN SGE00704). Specifically, this memorandum focuses on 

information included in Chapter C in the TDD and covers the following:

 Data sources used

 Preparation and analysis of data

 Compilation of summary data

This memorandum is organized into the following sections:

 Section 1.0 focuses on how ERG compiled UOG produced water volume data to 

create Table C-6, Table C-7, and Table C-8 in the TDD.

 Section 2.0 describes how ERG compiled UOG produced water rates over time to 

create Figure C-2 in the TDD.

 Section 3.0 describes the 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 ERG’s quality control (QC) procedures.

 Section 6.0 lists the references used for this memorandum and its attachments.

 Section 7.0 contains the Microsoft Excel spreadsheet and Microsoft Access 

database attachments to this memorandum and their Document Control Numbers 

(DCNs). These spreadsheets and databases contain the underlying data and 
Memorandum

March 31, 2015

Page 2

calculations used to support the information presented in the TDD and to create 

the TDD tables and figures discussed 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. 

Appendix F of the TDD contains a crosswalk of all tables and figures in the TDD and the name 

of the relevant supporting memorandum, if applicable. Table 1 provides an index of the tables 

and figures explained in more detail in this memorandum.

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 SGE00724.A01

Figure C-3

Anions and Cations Contributing to TDS Concentrations 

in Shale and Tight Oil and Gas Formations 3.3 SGE00724.A013

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 SGE00724.A013

Figure C-5

Barium Concentrations in UOG Produced Water from 

Shale and Tight Oil and Gas Formations 3.3 SGE00724.A013

Table C-6

UOG Well Flowback Recovery by Resource and Drill 

Type 1.0 SGE00724.A01

Table C-7

UOG Well Long-Term Produced Water Generation Rates 

by Resource and Drill Type 1.0 SGE00724.A01

Table C-8 UOG Well Produced Water Volumes by Formation 1.0 SGE00724.A01

Table C-11 Concentrations of Select Classical and Conventional 

Constituents in UOG Produced Water 3.3 SGE00724.A013

Table C-13 Concentrations of Select Anions and Cations 

Contributing to TDS in UOG Produced Water 3.3 SGE00724.A013

Table C-15 Concentrations of Select Organic Constituents in UOG 

Produced Water 3.3 SGE00724.A013

Table C-17 Concentrations of Select Metal Constituents in UOG 

Produced Water 3.3 SGE00724.A013

Table C-19 Concentrations of Select Radioactive Constituents in 

UOG Produced Water 3.3 SGE00724.A013
Memorandum

March 31, 2015

Page 3

This memorandum will refer to the following terms, which are also used throughout the 

TDD, the supporting memoranda, and memoranda attachments:

 Unconventional oil and gas (UOG) resources

1

– crude oil and natural gas2

produced by a well drilled3into a low porosity, low permeability formation 

(including, but not limited to, shale gas, shale oil, tight gas, tight oil).

 UOG extraction wastewater – sources of wastewater pollutants associated with 

production, field exploration, drilling, well completion, or well treatment for 

unconventional oil and gas extraction.

4 UOG extraction wastewater includes 

produced water, drilling wastewater, and produced sand5.

 Produced water – the water (brine) brought up from the hydrocarbon-bearing 

strata during the extraction of oil and gas. This can include formation water, 

injection water, and any chemicals added downhole or during the oil/water 

separation process. Based on the stage of completion and production the well is 

in, produced water can be further broken down into the following components:

o Flowback – the produced water generated by UOG wells in the initial period 

after hydraulic fracturing prior to production (i.e., fracturing fluid, injection 

water, any chemicals added downhole, and varying amounts of formation 

water). After the hydraulic fracturing procedure is completed and pressure is 

released, the direction of fluid flow reverses, and the fluid flows up through 

the wellbore to the surface. The water that returns to the surface is commonly 

referred to as “flowback.” Flowback is typically reported as a percentage of 

fracturing fluid volume in literature and by industry.6

o Long-term produced water (LTPW) – the produced water generated by UOG 

wells during the production phase, after the initial flowback process. Longterm produced water includes increasing percentages of formation water that 

make up the total volume of long-term produced water. Long-term produced 

water continues to be produced throughout the lifetime of the well and is 

usually reported in terms of flow rates in literature and by industry.7

 

1 UOG resource types are categorized into shale and tight formations.

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

3 UOG wells may be drilled using horizontal, vertical, or directional well trajectories. Literature sometimes refers to 

well trajectory as “drill type”.

4

Stormwater is not considered a source of UOG extraction wastewater. In general, no NPDES permit is required for 

discharges of stormwater from any field activities or operations associated with oil and gas production, except as 

specified in 40 C.F.R. 122.26(c)(1)(iii) for discharges of a reportable quantity or that contribute to a violation of a 

water quality standard. States may impose additional requirements for management of drilling site stormwater. 

5 Drilling wastewater and produced sand are not discussed in this memorandum. Additional information about 

drilling wastewater can be found in ERG’s Unconventional Oil and Gas (UOG) Drilling Wastewater memorandum 

(DCN SGE00740).

6 ERG also expressed flowback as a percent of fracturing fluid volume in its analyses. Flow rate changes rapidly 

during flowback, making it difficult to summarize. 

7 ERG analyzed LTPW in terms of flow rates because these rates do not vary significantly over time. In addition, 

LTPW is generated over the entire life of the well. Because well life varies significantly between wells, ERG did not 

convert LTPW flow rates to a total volume.
Memorandum

March 31, 2015

Page 4

 Drilling wastewater – the liquid waste stream separated from recovered drilling 

fluid (mud) and drill cuttings during the drilling process.

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:

 Fracturing fluid volume (million gallons per well, Mgal/well)8

 Flowback recovery (percent of fracturing fluid volume)

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

Table C-8, “UOG Well Produced Water Volumes by Formation,” contains these data 

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

C-6 and C-7 in the TDD, both of which are higher-level aggregations of the data presented in 

Table C-8. Table C-6, “UOG Flowback Recovery by Resource and Drill Type,” presents

flowback recovery at the resource type level, and Table C-7, “UOG Well Long-Term Produced 

Water Generation Rates by Resource and Drill Type,” 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 Table C-6, Table C-7, and Table C-8 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®. The structure of 

these datasets required ERG to conduct an analysis to calculate the lower range, median, and 

upper range values from a given dataset9. 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 SGE00520)

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. The underlying data in the 

 

8

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.

9

In most cases, ERG calculated the 10th and 90th percentiles to estimate lower and upper ranges and to eliminate 

outliers.
Memorandum

March 31, 2015

Page 5

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

all oil and gas wells ever drilled.

10 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 2007 through 2011. The version of the DI 

Desktop®database that ERG used for this analysis was downloaded in January 2012, 

representing, for the most part, data from 2011. The raw data are contained in the “Active Oil 

and Gas Wells” table in Attachment 3 (DCN SGE00724.A03). 

1.1.1.2 FracFocus® Database (DCN SGE00585)

In March 2015, EPA’s Office of Research and Development (ORD) released a database 

they developed from public disclosures to FracFocus®(DCN SGE00585). 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.

11 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. FracFocus®publishes reports for individual 

wells in portable document file (PDF) format. EPA’s ORD converted these PDF files into a 

Microsoft Access database to conduct a national-level analysis of chemical additives. ORD’s 

FracFocus®raw database is contained in the “ORD FF DB (DCN SGE00585)” table in 

Attachment 5 (DCN SGE00724.A05).

1.1.2 State-level Datasets

To perform select analyses to estimate typical produced water volumes and rates, ERG 

used databases from Ohio, Colorado, New Mexico, North Dakota, and Wyoming. 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 

4.9; attachments 6 through 12 contain the data and ERG’s calculations (DCN SGE00724.A06-

12). A more detailed description of each data source is provided in the “Data Source” 

subsections in Sections 4.3 through 4.9.

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 9 at the end of this memorandum, and are also listed in the “Source” 

column in the “PW Data” tab in Attachment 1 (DCN SGE00724.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 specifically reported that a typical 

horizontal Barnett well requires approximately 1,000,000 to 7,300,000 gallons of fracturing 

 

10 The exact year recordkeeping began varies by state, but the majority of states go back to 1900.

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

coalbed methane formations.
Memorandum

March 31, 2015

Page 6

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,

12

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-6, C-7, and C-8 in the TDD. Each of 

these steps corresponds to a specific tab in Attachment 1 (DCN SGE00724.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 4.9) 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 the weighted average as explained in Step 2 (Equation 1) 

and Step 3 (Equation 2).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)13

◦ Upper range (barrels/well)

◦ Number of data points

◦ Formation Level Weighted Average Fracturing Volume 

◦ Resource Level Weighted Average Fracturing Volume 

 Flowback recovery (% of fracturing fluid injected)

◦ Lower range (%)

◦ Median/average (%)13

◦ Upper range (%)

◦ Number of data points

◦ Formation Level Weighted Average Flowback Recovery

◦ Resource Level Weighted Average Flowback Recovery

 Long-term produced water

 

12 The upper and lower ranges represent either the 10th and 90th percentiles from analyses of comprehensive 

databases ERG analyzed or the typical minimum and maximum values reported by industry. In order to exclude 

outliers, these ranges do not include absolute minimum and maximum values that are possible.

13 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. 
Memorandum

March 31, 2015

Page 7

◦ Lower range (barrels/day/well)

◦ Median/average (barrels/day/well)13

◦ Upper range (barrels/day/well)

◦ Number of data points

◦ Formation Level Weighted Average LTPW Rate

◦ Resource Level Weighted Average LTPW Rate

 Source Flag (A, B, C, or D)14

 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 SGE00724.A01).

Step 2: Generation of PW Data by Formation tab (TDD Table C-8)

To create TDD Table C-8, ERG aggregated the data in the PW Data tab by formation and 

well trajectory (e.g., horizontal Barnett wells, vertical Marcellus wells). Table C-8 

presents the following three different types of produced water data: fracturing fluid

volume, flowback recovery (percent of fracturing fluid), 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:

 

14 For a discussion on the source flags, please see Section 5.0.
Memorandum

March 31, 2015

Page 8

 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 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 

 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

 

 

 

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 “Calculated Numbers by 

Formation and Well Trajectory (from the PW Data tab)” in the PW Data by Formation 

tab. ERG rounded these values to two significant 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 the 

quality of information. For more information about source flags, see Section 5.0

Step 3: Generation of PW Data by Resource tab (TDD Table C-6 and Table C-7)

To create TDD Tables C-6 and C-7, ERG aggregated data in the PW Data tab by resource 

type and well trajectory (e.g., horizontal shale wells, vertical tight wells). Table C-6 

presents fracturing fluid volume and flowback recovery by UOG resource type and well 

trajectory. Table C-7 shows long-term 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 of the average/median values reported in the PW Data tab for each 

resource type and well trajectory combination using Equation 2 below.
Memorandum

March 31, 2015

Page 9

 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.

Equation 2

 

 

 

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 SGE00724.A01). Most of these references were studies of flowback rates

and characteristics over time after fracturing.

15

2.2 Methods and Procedures

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

following steps:

 

15 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. 
Memorandum

March 31, 2015

Page 10

Step 1:

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

in Attachment 1 (DCN SGE00724.A01):

 Basin

 Formation

 Well Trajectory (horizontal, vertical)

 Reported Flow Rate (barrels per day, bpd)

16

 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 

SGE00724.A01).

Step 3:

The FB Data Summary tab in Attachment 1 (DCN SGE00724.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.

 

16 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.
Memorandum

March 31, 2015

Page 11

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 14 (DCN SGE00724.A014). 

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 SGE00740). 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. 

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 2014 United States Geological Survey (USGS) 

Produced Water Geochemical Database v. 2.0 (PROVISIONAL) (USGS database) by well, as 

described in Section 4.10 and shown in Attachments 15 and 16 (DCN SGE00724.A015-A16). 

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

17 well 

operator data, as described in Section 4.11 and shown in Attachment 17 (DCN 

SGE00724.A017).

Table 9 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 5.0 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 (DCN SGE00724.A014) 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

 

17 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.
Memorandum

March 31, 2015

Page 12

 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,

18

maximum value)

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 

SGE00724.A014).

3.2.1 Data Preparation

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

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

national-level produced water characterization data from EPA’s ORD. The general “Pollutant 

Concentrations” summary table was compiled from the various sources listed in Table 9, 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 4.10 and 4.11, 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. 

 

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

uncharacterized single values.
Memorandum

March 31, 2015

Page 13

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. 

3.2.3 Minimum, Median,

19 and Maximum Data

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

the minimum, median,

19 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 in the UOG Wastewater Characterization 

database. 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 

 

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

uncharacterized single values.
Memorandum

March 31, 2015

Page 14

referencing EIA documents and using engineering judgment (DCN SGE00988, DCN SGE00153, 

DCN SGE00155). 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 2014 Assumptions to the Annual Energy Outlook (DCN 

SGE00988). 

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 “Drill Type 

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:

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

wastewater21; and unknown. These were standardized using the “WW Description Crosswalk” in 

the UOG Wastewater Characterization database (DCN SGE00724.A014). 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. 

 

20 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 memo).

21 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.
Memorandum

March 31, 2015

Page 15

The list comprised 19 classical and conventional constituents, 31 metals, 21 organics, 2 others, 

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

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 13 (DCN SGE00724.A013) 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 13 

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; 

ranges were defined using the lowest and highest median values (i.e., the minimum value 

corresponds to the minimum median value and the maximum value corresponds to the highest 

median value).

22 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 

SGE00724.A014): flowback, UOG wastewater, and produced water.

The majority of the tables presented in Section C.3 (UOG Extraction Wastewater 

Characterization) of the TDD were compiled by filtering the final dataset by specific constituent 

categories (e.g., classical and conventional, metals, organics) and tabulating the minimum of the 

median data field, median of the median data field, maximum of the median data field, number 

of data points, and number of detects23 for each constituent. ERG also sometimes organized the 

produced water characterization data by formation name. The analyses used to generate drilling 

wastewater characterization tables are discussed in the Unconventional Oil and Gas (UOG) 

Drilling Wastewater memorandum (DCN SGE00740).

 

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

values.

23 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. 
Memorandum

March 31, 2015

Page 16

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 

TDS Contrib Ions w Form Summary tab in Attachment 13, DCN SGE00724.A013). ERG listed 

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

the “Other Dissolved Constituents” category.

24

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 13 (DCN SGE00724.A013). 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 13, DCN SGE00724.A013).

4.0 ADDITIONAL UOG PRODUCED WATER VOLUME AND CHARACTERIZATION 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.

The following subsections describe analyses that ERG completed using national-level 

datasets to generate data inputs to the PW Data tab in Attachment 1 (DCN SGE00724.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 Database to calculate typical long-term 

produced water generation rates for specific UOG formations on a per well basis and by well 

trajectory. ERG entered the results of this analysis into the PW Data tab in Attachment 1 (DCN 

SGE00724.A01). Attachment 2 (DCN SGE00724.A02) contains the Microsoft Excel portion of 

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

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

the raw DI-Desktop®data 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. 

4.1.1 Data Source

ERG used the list of active oil and gas wells in the DI Desktop®database (shown in the 

“Active Oil and Gas Wells” table in Attachment 3, DCN SGE00724.A03). ERG identified the 

list of active oil and gas wells in a separate analysis described in ERG’s Analysis of DI Desktop® 

memorandum (DCN SGE00963). The version of the DI Desktop®database that ERG analyzed 

 

24 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 13, 

DCN SGE00724.A013).
Memorandum

March 31, 2015

Page 17

was last downloaded in 2012 and contains data from 2011. The DI Desktop®database reports the 

following data that ERG used in this analysis: 25

 Formation26

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

 Well completion date (DD/MM/YYYY)

 2007 produced water production (barrels)27

 2008 produced water production (barrels)

 2009 produced water production (barrels)

 2010 produced water production (barrels)

 2011 produced water production (barrels)

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 the 

DI Desktop®database by UOG formation name and by well completion year. In each 

query, ERG also summed the total annual produced water volume for each well 

completion year. The query descriptions are provided in Section 4.1.3. An example 

matrix resulting from these queries (for horizontal Barnett shale wells) is shown in Figure 

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

2 (DCN SGE00724.A02). ERG only pulled records with sufficient data for this analysis, 

which, at a minimum included, the following:

 Well completion date: Not null

 Annual produced water volume: Not null28

 Well trajectory: Not null and not “unknown”

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

Year

In the Detailed Results tab of Attachment 2 (DCN SGE00724.A02), ERG calculated the 

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

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 completion year (i.e., 

WCY+1) 29 through 2011, and divides by the number of wells, 365 days, and number of 

 

25 Some of these data fields may be missing in the DI Desktop® database. ERG excluded records that were missing 

one or more of these data fields from this analysis.

26 For this analysis, ERG specifically used the “Common Formation Name” field created by ERG in a separate 

analysis of the DI Desktop® dataset (DCN SGE00963).

27 The DI Desktop®

database includes annual produced water volumes but does not specify whether it is flowback or 

long-term produced water.

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

water production data (e.g., OK, AR).

29 This excludes flowback volumes for wells that were fractured during the well completion year.
Memorandum

March 31, 2015

Page 18

production years.

30 Figure 1 shows the resulting calculations for the Barnett Shale 

example. As previously explained, the DI Desktop®database 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. ERG chose the number of 

completion years to include for a given formation based on drilling activity and 

engineering judgment. For example, the number of Bakken wells drilled per year was 

minimal until the 2000's, but Cotton Valley well drilling began ramping up in the late 

1990's.

Equation 3

 

 

 

 

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 SGE00724.A02) contains the final 

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

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

and 90th percentile of the “daily average long-term produced water rate (bbl/day/well)” 

 

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

year. 

Horizontal Wells

2007 2008 2009 2010 2011

Barnett 2003 78 571,851 570,827 498,664 547,037 511,815 19.0

Barnett 2004 260 1,760,227 1,772,633 1,686,449 1,562,233 1,047,994 16.5

Barnett 2005 640 9,728,591 12,083,421 14,116,598 12,337,711 8,353,219 48.5

Barnett 2006 1,156 39,433,230 20,873,337 17,189,776 13,799,108 10,565,114 48.3

Barnett 2007 2,180 58,017,111 34,970,374 26,592,199 17,525,438 43.1

Barnett 2008 2,617 46,861,850 26,143,390 19,049,956 32.1

Barnett 2009 1,520 56,865,362 32,393,917 80.4

Barnett 2010 1,887 17,052,449 24.8

10th percentile (bpd per well): 17.4

Median (bpd per well): 37.6

90th percentile (bpd per well): 58.1

Annual Long-term Produced Water Volume (barrels)

Daily Average 

Long-term 

Produced Water 

Formation (bbl/day/well)

Completion 

Year

Number 

of Wells

No Production
Memorandum

March 31, 2015

Page 19

column in the Detailed Results tab.31 ERG calculated the 10th percentile and 90th

percentile (as opposed to minimum and maximum) to remove outlying data points. The 

total number of data points (i.e., number of wells) is also calculated for each UOG 

formation and well trajectory. ERG entered these results into the PW Data tab of 

Attachment 1 (DCN SGE00724.A01).

4.1.3 Attachment 3 – Query Descriptions

Table 3 describes the queries performed in Attachment 3 (DCN SGE00724.A03).

Table 3. Query Descriptions for DI Desktop® Database (Attachment 3, DCN 

SGE00724.A03)

Attachment 3 Query Query Description

Applicable Tabs in 

Attachment 2

00 - Available 

Formations with Data

Sums the produced water volume for UOG formations by state.

ERG used this list to determine which UOG formations could 

be analyzed in this analysis and to determine which states 

should be excluded from this analysis because they did not 

report water production data to DI Desktop®.

No applicable tab

01a

This query creates a new table called “Results” and sums 

annual produced water volumes for each year 2007-2010 for 

the horizontal Bakken shale wells by: 

 Completion year

 Number of wells completed during that year

Detailed Results tab

01b through 01x

These queries sum annual produced water volumes for each 

year 2007-2010 for each UOG formation and by: 

 Completion year

 Number of wells completed during that year

 Drill type (horizontal + directional or vertical).

The results of these queries are appended to the Results table 

created by query “01a”.

Detailed Results tab

Note: DI Desktop was formerly known as HPDI, Inc.

4.2 Attachments 4 and 5 FracFocus®Fracturing Fluid Volumes

ERG analyzed the FracFocus®database published by EPA’s Office of Research and 

Development (ORD) in March 2015 (DCN SGE00585) 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 SGE00724.A01). 

Attachment 4 (DCN SGE00724.A04) contains the Microsoft Excel portion of the analysis. 

Attachment 5 (DCN SGE00724.A05) contains the Microsoft Access database portion of the 

analysis, including the queries that link ORD’s FracFocus®data to other oil and gas databases, 

which are described in more detail in Section 4.2.3.

 

31 DI Desktop® reports well trajectory as “drill type.” Therefore, all raw databases and query results in Attachment 3 

describe well trajectories using the term “drill type”.
Memorandum

March 31, 2015

Page 20

4.2.1 Data Sources

ORD’s FracFocus®database (DCN SGE00585) (see Section 1.1.1.1) contains underlying 

fracturing fluid volume data and well 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’s® Well database (DCN SGE00520) and various state databases to provide these 

additional data fields in this analysis.32 As shown in 

Figure 2, the common data field in FracFocus®, DI Desktop®, and various state databases 

is the well API number. Only well API numbers that were contained in both the FracFocus®

database (DCN SGE00585) and the other databases were included in the results of this analysis.

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

date contained in the version of DI Desktop®that ERG used. These FracFocus®records were 

excluded from the analysis. 

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

formation and well trajectory information. However, some state agencies publish databases of 

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

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

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

databases instead of the DI Desktop®database to maximize the number of usable results. For 

example, DI Desktop® contained no Utica shale wells because Utica well drilling ramped up in 

2012, after the last update to the version of the DI Desktop®data that ERG is using, in late 2011. 

However, the Ohio Department of Natural Resources publishes a running list of horizontal Utica 

shale wells, 140 of which matched up with FracFocus®records. ERG used databases published 

by the following state agencies in this analysis:

 Ohio Department of Natural Resources (OH DNR) (DCN SGE00561)

 Oklahoma Geological Survey (OGS) (DCN SGE00694)

 Kansas Geological Survey (KGS) (DCN SGE00720)

 North Dakota Industrial Commission (NDIC) (DCN SGE00557)

 Louisiana Department of Natural Resources (LA DNR) (DCN SGE01024) 

 Arkansas Oil and Gas Commission (AOGC) (DCN SGE01021)

 

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

analysis of the DI Desktop® dataset (DCN SGE00963). The version of the DI Desktop® database analyzed was last 

updated in 2012 and referred to data from 2011.
Memorandum

March 31, 2015

Page 21

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

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 the FracFocus®database (DCN 

SGE00724.A05) with the DI Desktop®database using well API number. ERG excluded 

wells with “unknown” or blank well trajectories in the DI Desktop®database from the 

results. The resulting table contains the data fields listed below and can be found in the 

Query Results from SGE00724.A05 tab in Attachment 4 (DCN SGE00724.A04). The 

Query Results from SGE00724.A05 tab is the output from the Microsoft Access 

database. 

 API Number

 Formation

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

 Fracturing fluid volume (gallons)

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

ERG identified six state agency databases with more up-to-date data than the version of 

the DI Desktop®database that ERG used for this analysis. Using queries in the 

FracFocus®database (DCN SGE00724.A05), ERG cross-linked the FracFocus®database 

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)
Memorandum

March 31, 2015

Page 22

with these state agency databases using well API number. The results 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 the DI Desktop®database. The Data Sources by State tab in Attachment 4 

(DCN SGE00724.A04) indicates the states for which ERG used a state agency database

instead of, or in combination with, the DI Desktop®database. Table 4 contains more 

detail about the data contained in each state agency database.

Step 3: Summary of Results

The Query Results from SGE00724.A05 tab in Attachment 4 (DCN SGE00724.A04)

contains the resulting records from the database portion of this analysis. These are the 

FracFocus®database records with fracturing fluid volumes that ERG was able to link to 

UOG formation and well trajectory data from another database. On a UOG formation and 

well trajectory basis, ERG calculated the 10th percentile, 50th percentile (i.e., median), 

and 90th percentile statistics of fracturing fluid volumes (gallons). ERG calculated the 10th

percentile and 90th percentile (as opposed to the minimum and maximum) to remove 

outlying data points. The results for these calculations are shown in the Summary of 

Results tab in Attachment 4 (DCN SGE00724.A04). ERG converted the volumes from 

gallons to barrels by dividing by 42 gallons per barrel. The total number of data points

(i.e., number of wells)

33 is also shown in this tab. ERG entered these results into the PW 

Data tab of Attachment 1 (DCN SGE00724.A01).

4.2.3 Attachment 5 – Query Descriptions

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

Attachment 5 (DCN SGE00724.A05). The results of the analysis are documented in Attachment 

4 (DCN SGE00724.A04).

The following are the tables found in Attachment 5:

 ORD FF DB (DCN SGE00585) – This is the raw FracFocus database published 

by ORD (DCN SGE00585).

 ORD FF DB - Manipulated – This is a version of the FracFocus database 

published by ORD that ERG created by processing the queries listed in Table 4. 

 ORD FF DB - Final – This is the final version of the FracFocus database that 

ERG generated by processing the queries listed in Table 4. This table is copied 

into the Query Results from SGE00724.A05 tab in Attachment 4.

 Consolidated Formation Crosswalk – Crosswalk of known basin and formation 

combinations in the DI Desktop® database from ERG’s analysis of that database 

(DCN SGE00963).

 

33 In this analysis, the number of data points equals the number of wells.
Memorandum

March 31, 2015

Page 23

 HPDI_EXPORT_011012 – The raw DI Desktop® database (DCN SGE00520).

DI Desktop was formerly known as HPDI, Inc.

 KS Horizontal Wells (DCN SGE00720) – List of wells published by the Kansas 

Geological Survey (KGS) that contains formation and well trajectory information 

by API number. 

 ND Wells (DCN SGE00557) – List of wells published by NDIC that contains 

formation and well trajectory information by API number.

 OGS Woodford Permits (DCN SGE00694) – This is a list of permitted Woodford 

shale wells published by OGS.

 Fayetteville Wells (DCN SGE01021) – This is a list of permitted Fayetteville 

shale wells published by AOGC.

 Haynesville Wells (DCN SGE01024) – This is a list of permitted Haynesville 

shale wells published by LA DNR.

 Utica Well Permits (DCN SGE00561) – This is a list of permitted Utica wells 

published by OHDNR.

Table 4. FracFocus®Fracturing Fluid Volumes Query Descriptions

Query Query Description

000

This query makes a new table called "ORD FF DB - Manipulated" and populates it with all records in 

EPA ORD’s FracFocus®(DCN SGE00585) database flagged as "OK" in the field called 

"VolumeFFflag". When creating this new table, this query also creates a blank field named API_ERG

that is populated in subsequent queries.

100

This query updates the API_ERG field in the "ORD FF DB - Manipulated" table to match the API field 

reported in FracFocus®database (DCN SGE00585). The API_ERG field is manipulated by queries 101 

through 110 to a format that matches DI Desktop®(DCN SGE00520). For example, all API numbers in 

FracFrocus are in the format: "##-###-#####", but DI Desktop®reports Arkansas API numbers with "-

00-00" at the end. States that are not included in queries 101 through 110 report API number in the 

same format as FracFocus®.

101 Adds "-00-00" to end of the API_ERG field for AR wells in the "ORD FF DB - Manipulated" table.

102 Adds "-00" to end of the API_ERG field for AL wells in the "ORD FF DB - Manipulated" table.

103 Adds "-00" to end of the API_ERG field for CO wells in the "ORD FF DB - Manipulated" table.

104 Adds "-00" to end of the API_ERG field for LA wells in the "ORD FF DB - Manipulated" table.

105 Adds "-00" to end of the API_ERG field for MS wells in the "ORD FF DB - Manipulated" table.

106 Adds "-00-00" to end of the API_ERG field for MT wells in the "ORD FF DB - Manipulated" table.

107 Adds "-00" to end of the API_ERG field for UT wells in the "ORD FF DB - Manipulated" table.

108 Adds "-00" to end of the API_ERG field for TX wells in the "ORD FF DB - Manipulated" table.

109 Adds "-00" to end of the API_ERG field for WV wells in the "ORD FF DB - Manipulated" table.

110 Adds "-00" to end of the API_ERG field for NM wells in the "ORD FF DB - Manipulated" table.

200 This query makes a new table called "ORD FF DB - Final" and cross-references all API numbers in 

FracFocus®(DCN SGE00585) against the raw DI Desktop®database. The resulting table includes all 
Memorandum

March 31, 2015

Page 24

Table 4. FracFocus®Fracturing Fluid Volumes Query Descriptions

Query Query Description

of the FracFocus® database fields in addition to the following fields from the DI Desktop® database if 

a matching API number was found: Basin_DI, Formation_DI, and Drill_Type_DI. Wells without 

matches are still included in the new table but these fields are left blank. Empty fields are also created 

for Formation_ERG and Resource Type_ERG, which are populated in subsequent queries.

201

This query cross references the Basin_DI and Formation_DI fields in the "ORD FF DB - Final" table 

against the “Consolidated Formation Crosswalk” tablea. For those records with matching basin and 

formations, this query updates the “Formation_ERG” field in the "ORD FF DB - Final" with the 

common formation name in the “Consolidated Formation Crosswalk” table.

202

This query cross references the API numbers in the "ORD FF DB - Final" table against a list of 

horizontal Utica shale wells published by OH DNR (DCN SGE00561). If the API numbers in 

FracFocus®(DCN SGE00585) match API numbers in OH DNR (DCN SGE00561), this query updates 

the Formation_ERG, Drill Type_DI, and Recourse Type_ERG fields in the “ORD FF DB - Final” table 

to "Utica", "H" (based on OH DNR's file name, which is a list of horizontal wells), and "shale" 

respectively.

203

This query cross references the API numbers in the "ORD FF DB - Final" against a list of permitted 

Oklahoma shale wells published by OGS (DCN SGE00694). If the API numbers in FracFocus® (DCN 

SGE00585) match API numbers in OGS's shale list (DCN SGE00694), this query updates the 

Formation name, Drill Type, and Resource Type fields in the “ORD FF DB - Final” table to 

"Woodford", "H", and "shale" respectively. This query only pulls wells from OGS's shale well list 

where the reported formation name includes "Woodford" and the lateral length is greater than zero.

204

This query cross references the API numbers in the "ORD FF DB - Final" against a list of permitted 

horizontal Kansas wells published by the KGS (DCN SGE00720). If the API numbers in FracFocus®

(DCN SGE00585) match API numbers in KGS's list (DCN SGE00720), this query updates the 

Formation_ERG, Drill Type_DI, and Resource Type_ERG fields in the "ORD FF DB - Final" table to 

"Mississippi Lime", "H" (based on KGS's file name, which is a list of horizontal wells), and "shale" 

respectively. This query only pulls wells from KGS's horizontal well list where the reported formation 

name includes "Mississippi".

205

This query cross references the API numbers in the "ORD FF DB - Final" against a list of oil and gas 

wells in North Dakota published by NDIC (DCN SGE00557). If the API numbers in FracFocus®(DCN 

SGE00585) match API numbers in NDIC's list (DCN SGE00557) this query updates the 

Formation_ERG and Resource Type_ERG fields in the "ORD FF DB - Final" 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 Drill Type_ERG field in the “ORD FF DB -

Final” table to the reported value in the wellbore field (i.e., drill type) in NDIC's list.

206

This query cross references the API numbers in the "ORD FF DB - Final" against a list of oil and gas 

wells in Arkansas published by AOGC (DCN SGE01021) (see the “Fayetteville Wells” table). This 

query updates the Formation name and Resource Type fields in the "ORD FF DB - Final" table to 

"Fayetteville" and "shale" respectively if the API numbers in FracFocus®(DCN SGE00585) match API 

numbers in DCN SGE01021 and if the existing formation field in “ORD FF DB - Final” was blank.

207

This query cross references the API numbers in the "ORD FF DB - Final" against a list of oil and gas 

wells in Louisiana published by LA DNR (DCN SGE01024) (see the “Haynesville Wells” table). This 

query updates the Formation name and Resource Type fields in the "ORD FF DB - Final" table to 

"Haynesville" and "shale" respectively if the API numbers in FracFocus®(DCN SGE00585) match API 

numbers in DCN SGE01024 and if the existing formation field in “ORD FF DB - Final” was blank.

208

This query updates all null values in the “Drill Type_DI” field of the “ORD FF DB - Final” table to 

“U” (i.e., unknown).

209

This query updates all null values in the “Formation_ERG” field of the “ORD FF DB - Final” table to 

“Unknown”.

210

This query updates all null values in the “Resource Type_ERG” field of the “ORD FF DB - Final” 

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

formation name, COG wells, or CMB wells. 
Memorandum

March 31, 2015

Page 25

Table 4. FracFocus®Fracturing Fluid Volumes Query Descriptions

Query Query Description

211

This query summarizes the final results. It includes counts of wells by Formation_ERG, Drill Type_DI, 

and Resource Type_ERG. 

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 SGE00963).

The following subsections 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 

SGE00724.A01) (see Section 1.2). 

4.3 Attachment 6 – Bakken Flowback Recovery

ERG analyzed flowback recovery for UOG wells completed in the Bakken formation in 

North Dakota using data published by the NDIC (DCN SGE00557) and the results from ERG’s 

analysis of ORD’s FracFocus®data (DCN SGE00724.A04, DCN SGE00724.A05). ERG entered 

the results of this analysis as inputs to the PW Data tab in Attachment 1 (DCN SGE00724.A01). 

Attachment 6 (DCN SGE00724.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 SGE00557). 

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 month34

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 SGE00724.A04, 

DCN SGE00724.A05). Relevant data provided in the FracFocus results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)

 Fracture Date (DD/MM/YYYY)

 Fracturing fluid volume (gallons)

 

34 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.
Memorandum

March 31, 2015

Page 26

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

database.

4.3.2 Methods and Procedures

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

Step 1: Identify Bakken Wells from FracFocus® Analysis

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

horizontal Bakken shale wells located in North Dakota (DCN SGE00724.A04-.A5). ERG 

excluded vertical and directional wells from this analysis that were identified in 

FracFocus because there were a limited number of records. 

Step 2: Identify Bakken Flowback Volumes in NDIC’s Production Data

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

from ERG’s Analysis of FracFocus®Fracturing Fluid Volumes (DCN SGE00724.A04-

A5). For each well, ERG located the production data in the NDIC database for the given 

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

recorded the produced water volume and production days35 in the “Estimated Flowback 

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

Attachment 6 (DCN SGE00724.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.36 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 SGE00724.A06).

Step 3: Calculate Flowback Recovery

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

using Equation 4 below. The flowback volume was obtained in Step 2 from the NDIC 

database. The total fracturing fluid volume was obtained from ERG’s Analysis of 

FracFocus®Fracturing Fluid Volumes (DCN SGE00724.A04-A5).

 

35 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.

36 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.
Memorandum

March 31, 2015

Page 27

Equation 4

 

 

 

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

Step 4: Summary of Results

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

flowback recovery for horizontal Bakken wells. ERG calculated the 10th percentile and 

90th percentile as opposed to the minimum and maximum to remove outlying data points. 

The resulting statistics and total number of wells are shown in the Results tab of 

Attachment 6 (DCN SGE00724.A06). ERG entered these results into the PW Data tab of 

Attachment 1 (DCN SGE00724.A01). 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 analyzed UOG flowback recovery for UOG wells completed in the Avalon and

Bone Spring, Wolfcamp, and Dakota formations 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 SGE00724.A04-A5). ERG entered the results of this analysis as inputs to the PW Data tab 

in Attachment 1 (DCN SGE00724.A01). Attachment 7 (DCN SGE00724.A07) contains the 

underlying Microsoft Excel file.

4.4.1 Data Source

ERG obtained data from NMEMNRD Oil Conservation Division (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. 

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 SGE00724.A04-

A5). Relevant data in these results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)
Memorandum

March 31, 2015

Page 28

 Fracture Date (DD/MM/YYYY) 

 Fracturing fluid volume (gallons)

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

NMEMNRD’s database.

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 wells 

located in New Mexico (DCN SGE00724.A04-A5). This only included directional wells 

for the Avalon and Bone Spring, Wolfcamp, and Dakota formations. There were no

vertical and horizontal wells in this analysis because there were only directional UOG 

wells in New Mexico that were contained in the results of ERG’s FracFocus®Fracturing 

Fluid Volumes analysis (DCN SGE00724.A04-A5). 

Step 2: Identify NMEMNRD Flowback Water Volumes

For each well identified in Step 1, ERG searched produced water volumes in the 

NMEMNRD database for the month in which the well was completed according to the 

FracFocus®database. ERG recorded the produced water volume and production days into 

the “Flowback Volume (barrels)” and “Flowback Days” fields respectively in the 

Analysis tab of Attachment 7 (DCN SGE00724.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.37 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 7 (DCN SGE00724.A07). 

Step 3: Calculate Flowback Recovery

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

using Equation 4. The flowback volume was obtained in Step 2 from the NMEMNRD 

 

37 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.
Memorandum

March 31, 2015

Page 29

database. The total fracturing fluid volume was obtained from ERG’s Analysis of 

FracFocus®Fracturing Fluid Volumes (DCN SGE00724.A04-A5).

Step 4: Summary of Results

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

flowback recovery for New Mexico wells. ERG calculated the 10th percentile and 90th

percentile as opposed to the minimum and maximum to remove outlying data points. The 

results are shown in the Results tab of Attachment 7 (DCN SGE00724.A07). The total 

number of wells is also shown in this tab. ERG entered these results into the PW Data tab 

of Attachment 1 (DCN SGE00724.A01). 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 analyzed flowback recovery and long-term produced water generation rates for 

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

along with ORD’s FracFocus®database (DCN SGE00585).38 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 of this analysis as inputs to the PW Data 

tab in Attachment 1 (DCN SGE00724.A01). Attachment 8 (DCN SGE00724.A08) contains the 

underlying Microsoft Excel file for this analysis.

4.5.1 Data Source

ERG obtained data from the OH DNR Quarterly Production Archive (DCN SGE00559 

and DCN SGE00560) for shale production. ERG downloaded Microsoft Excel files from OH 

DNR’s website that contain oil, gas, and produced water production on a quarterly or annual 

basis.39 ERG downloaded the following files:

 

38 Section 4.5.1 explains why ERG used the raw ORD FracFocus database instead of ERG’s analysis of ORD’s 

FracFocus database.

39 Production data for 2013 and 2014 (i.e., previous and current years) is provided in quarterly files; production data 

for 2011 and 2012 (i.e., historic data) is provided for the entire year.
Memorandum

March 31, 2015

Page 30

 2011 Utica Shale Production – DCN SGE00559 (2011 Prod (SGE00559) tab in 

Attachment 8, DCN SGE00724.A08).

 2012 Utica Shale Production – DCN SGE00560 (2012 Prod (SGE00560) tab in 

Attachment 8, DCN SGE00724.A08).

 2013 Quarterly Horizontal Shale Production: 1st Quarter – DCN SGE00694 

(2013 Prod 1Q (SGE00694) tab in Attachment 8, DCN SGE00724.A08).

 2013 Quarterly Horizontal Shale Production: 2nd Quarter – DCN SGE00695

(2013 Prod 2Q (SGE00695) tab in Attachment 8, DCN SGE00724.A08).

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

(2013 Prod 3Q (SGE00727) tab in Attachment 8, DCN SGE00724.A08).

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

(2013 4Q Prod (SGE00737) tab in Attachment 8, DCN SGE00724.A08).

Each file reports the following data:

 Well API number

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

water production (barrels) 40

 Number of production days in each quarter or year. 

To obtain fracturing fluid volumes for this analysis, ERG used ORD’s FracFocus®

database described in Section 1.1 (DCN SGE00585). Relevant data from these results included

the following:

 Well API number

 State

 Fracture Date (DD/MM/YYYY) 

 Fracturing fluid volume (gallons)

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

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

all Utica wells listed 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:

 

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

produced water.
Memorandum

March 31, 2015

Page 31

Step 1: Identify Ohio Wells from FracFocus® Analysis

ERG filtered ORD’s FracFocus®database (DCN SGE00585) for all well records in Ohio. 

Step 2: Identify OH DNR Flowback Volumes 

For each well identified in Step 1, ERG searched produced water volumes in the OH 

DNR data for the first month of production. ERG recorded the produced water volume 

and production days into the “Flowback Volume (barrels)” and “Flowback Days” fields 

respectively in the Analysis tab of Attachment 8 (DCN SGE00724.A08). 

Table 5 explains in more detail how ERG identified flowback volumes; this method 

varied by the completion year and/or by the quarter the well first produced oil or gas, or 

generated produced water. 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.41 Further, some wells may have produced for less than 2 

weeks in the first production period, so the flowback recovery (calculated in next step)

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

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

brine production by the fracturing fluid volume.a

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

brine production by the fracturing fluid volume. a

2013 – 1

st Quarter If the number of 1

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

the 1

st quarter 2013 brine production by the fracturing fluid volume. a

2013 – 2

nd Quarter If the number of 2

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

the 2

nd quarter 2013 brine production by the fracturing fluid volume. a

2013 – 3

rd Quarter If the number of 3

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

the 3

rd quarter 2013 brine production by the fracturing fluid volume. a

2013 – 4

th Quarter If the number of 4

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

the 4

th quarter 2013 brine production by the fracturing fluid volume. a

a— If the production days was 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 flowback recovery as a percentage of total fracturing fluid volume 

using Equation 4. The flowback volume was obtained in Step 2 from the OH DNR data. 

The total fracturing fluid volume was obtained from ORD’s FracFocus®database (DCN 

SGE00585) for all well records in Ohio.

 

41 ERG used a slightly different approach from other analyses in Section 4.0 because the data published by OHDNR 

is organized on a quarterly basis, not monthly.
Memorandum

March 31, 2015

Page 32

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

Long-Term Produced Water Rates

ERG calculated long-term produced water rates using Equation 5; all inputs were from 

OH DNR’s production data. Table 6 explains in more detail how ERG identified and 

calculated long-term produced water volumes, which varied by the year and/or quarter 

the well first produced oil, gas, or produced water. In addition, ERG did not calculate 

long-term produced water rates for wells that had intermittent production.

Equation 5

 

 

 

Where:

LTPW – long term produced water

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

First 

Production 

Period for 

Well

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 in 2012 and 

2013 and only generated long-term produced water in 2012 and 2013. ERG divided the total 2012 

and 2013 brine production by the total 2012 and 2013 production days. a

2012

ERG assumed that wells that first produced in 2012 were in the production phase by the 2

nd

quarter of 2013 and only generated long-term produced water in the 2

nd

, 3rd and 4th quarter of 

2013. ERG divided the total 2

nd

, 3rd and 4th quarter 2013 brine production by the total 2

nd, 3rd and 

4

th 2013 production days.

2013 – 1

st

Quarter

ERG assumed that wells that first produced in 1

st quarter 2013 were in the production phase

during 3rd and 4th quarter 2013. ERG divided the total 3

rd and 4th quarter 2013 brine production by 

the total 3

rd and 4th quarter 2013 production days.

2013 – 2

nd

Quarter

ERG assumed that wells that first produced in 2

nd quarter 2013 were in the production phase

during 4th quarter 2013. ERG divided the total 4

th quarter 2013 brine production by the total 4th

quarter 2013 production days.

2013 – 3

rd

Quarter

ERG did not calculate long-term produced water rates for wells that first produced in 3rd quarter 

2013 because we did not have the produced water volume data for the time period in which these 

wells were producing (i.e., 2014 – 1

st Quarter).

2013 – 4

th

Quarter

ERG did not calculate long-term produced water rates for wells that first produced in 4th quarter 

2013 because we did not have the produced water volume data for the time period in which these 

wells were producing (i.e., 2014 – 2

nd Quarter).

a—unlike the procedures for 2012, ERG used the 2012 annual volumes here because quarterly data are not available 

for 2012.

Step 5: Summary of Results

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

flowback recovery and long-term produced water. ERG calculated the 10th percentile and 

90th percentile, as opposed to the minimum and maximum, to remove outlying data 

points. The results are shown in the Results tab of Attachment 8 (DCN SGE00724.A08). 

ERG entered these results into the PW Data tab of Attachment 1 under the horizontal 
Memorandum

March 31, 2015

Page 33

Utica well category42 (DCN SGE00724.A01). 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 16 days of production, which falls within the general ranges of flowback 

process length reported in literature.

4.6 Attachment 9 – Niobrara Long-term Produced Water Rates

ERG analyzed long-term produced water rates generated by UOG wells completed in the 

Niobrara formation in Colorado using data published by the Colorado Oil and Gas Conservation 

Commission (COGCC) (DCN SGE00518). ERG used this analysis to estimate long-term 

produced water generation rates because there were limited Niobrara 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 of this analysis as inputs to the PW Data tab in 

Attachment 1 (DCN SGE00724.A01). Attachment 9 (DCN SGE00724.A09) contains the 

underlying Microsoft Excel file.

4.6.1 Data Source

ERG obtained the following data from COGCC Production Data Inquiry (DCN 

SGE00518). The website allows users to query annual oil, gas, and produced water production 

data in several different ways. 

 Well API number

 Production year

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

4.6.2 Methods and Procedures

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

Step 1: Identify Niobrara Wells from COGCC

ERG queried COGCC’s production database “by well” with the following criteria:

 Production from 2000 to 2014

 Geological field number 16950 (i.e., Niobrara horizontal)

ERG assumed all production data in the results were from wells drilled horizontally due 

to the naming convention of the geological field by COGCC (i.e., Niobrara horizontal).

 

42 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 wells completed in the Utica formation for the purpose 

of this analysis.
Memorandum

March 31, 2015

Page 34

Step 2: Assign Well Completion Years

ERG copied the raw data from the search in Step 1 into the Raw Data tab in Attachment 9 

(DCN DGE00724.A9) and performed the following analyses:

 Sorted well records by ascending API number and then by year.

 Flagged all wells as “inactive” in the “Production Year_ERG” column if the well 

produced zero gas, oil, and/or water during that year.

 Assigned each well a completion year equal to the smallest value in the 

“Production Year_ERG” column.43 ERG did not include years that were flagged 

as inactive as a completion year.

Step 3: Calculate Niobrara Produced Water Volumes

In the Analysis and Results tab in Attachment 9 (DCN SGE00724.A09), ERG summed 

produced water volumes for each completion year. ERG also counted the number of 

wells represented in each completion year. 

Step 4: Calculate Niobrara Long-term Produced Water Rate

In the Analysis and Results tab in Attachment 9 (DCN SGE00724.A09), ERG calculated

long-term produced water rates for each completion year using Equation 6 below, where 

the annual LTPW volume excludes the produced water generated during the well 

completion year (WCY) and the number of years does not include the well completion 

year (in order to exclude flowback volumes). Further, ERG assumed that all wells 

generated long-term produced water for 365 days per year after the well completion year.

Equation 6

 

 

 

 

Where:

LTPW – long term produced water

WCY – well completion year

Step 5: Summary of Results

ERG calculated the 10th percentile, 50th percentile, and 90th percentile statistics for longterm produced water rates in the Analysis and Results tab of Attachment 9 (DCN 

SGE00724.A09). ERG calculated the 10th percentile and 90th percentile (as opposed to 

the minimum and maximum) to remove outlying data points. ERG also compiled the total 

 

43 The COGCC requires all operators to report monthly oil, gas, and water production beginning in 1999. Therefore, 

assuming that the first year a well reported production is equivalent to the well completion year is appropriate for 

this analysis.
Memorandum

March 31, 2015

Page 35

number of wells (i.e., data points) in this tab. ERG entered these results into the PW Data 

tab of Attachment 1 (DCN SGE00724.A01).

4.7 Attachment 10 – Wyoming Flowback Recovery

ERG analyzed UOG flowback recovery for UOG wells completed in the Niobrara, 

Mesaverde, and Lance formations 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® Data (DCN SGE00724.A04-A5). ERG entered the results of this analysis 

into the PW Data tab in Attachment 1 (DCN SGE00724.A01). Attachment 10 (DCN 

SGE00724.A010) contains the underlying Microsoft Excel file.

4.7.1 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 SGE00724.A04-

A5). Relevant data in these results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)

 Fracture Date (DD/MM/YYYY)

 Fracturing fluid volume (gallons)

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

WOGCC’s database.

4.7.2 Methods and Procedures

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

Step 1: Identify UOG Wells in the FracFocus® Database

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

UOG wells located in Wyoming (DCN SGE00724.A04-A5). ERG searched the WOGCC 

database for this list of well API numbers using the “Download Production” feature on

the WOGCC website. ERG downloaded the results in Microsoft Excel format and copied 

them into the Analysis tab of Attachment 10 (DCN SGE00724.A010).
Memorandum

March 31, 2015

Page 36

Step 2: Identify Flowback Water Volumes in WOGCC’s Production Data

For each well identified in Step 1, ERG located the production data in the WOGCC 

database for the month that well was completed according to the FracFocus®database. 

ERG identified the produced water volume and production days during flowback in the 

Raw Data tab and recorded them in the “Flowback Volume (barrels)” and “Flowback

Days” fields respectively in the Analysis tab of Attachment 10 (DCN SGE00724.A010). 

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.44 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 10 (DCN SGE00724.A010). 

Step 3: Calculate Flowback Recovery

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

using Equation 4. The flowback volume was obtained in Step 2 above from the WOGCC 

database. The total fracturing fluid volume was obtained from ERG’s Analysis of 

FracFocus®Fracturing Fluid Volumes (DCN SGE00724.A04-A5).

Step 2: Summary of Results

ERG calculated 10th percentile, 50th percentile (i.e., median), and 90th percentile statistics 

of the flowback recovery by Wyoming wells. ERG calculated the 10th percentile and 90th

percentile as opposed to the minimum and maximum to remove outlying data points. The 

results are shown in the Results tab of Attachment 10 (DCN SGE00724.A010). The total 

number of wells is also shown in this tab. ERG entered these results into the PW Data tab 

of Attachment 1 (DCN SGE00724.A01). 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 26 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.

 

44 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.
Memorandum

March 31, 2015

Page 37

4.8 Attachment 11 – Wattenberg Flowback Recovery and Long-term Produced Water 

Rates

ERG analyzed produced water volumes and rates for UOG wells completed in the 

Wattenberg field (i.e., primarily Codell-Niobrara formation) using data generated by Bing Bai in 

2013 (DCN SGE00501). The underlying data and results are shown in the Analysis tab of 

Attachment 11 (DCN SGE00724.A011). ERG entered the results of this analysis into the PW 

Data tab of Attachment 1 (DCN SGE00724.A01).

4.8.1 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 assumed these to be the "Codell-Niobrara" formation. 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.

4.8.2 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 7 (shown as Equation 2 in DCN SGE00501). As reported 

by Bai, 2013, Equation 7 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 7

 

 

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 8 below (shown as Equation 3 in DCN SGE00501). As 

reported by Bai, Equation 8 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).
Memorandum

March 31, 2015

Page 38

Equation 8

 

 

 

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 9 below (shown as Equation 1 in DCN SGE00501). As 

reported by Bai, Equation 9 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 9

 

 

Where:

q = flow rate, barrels per day

t = time since completion, days

Step 4: Summary of Results

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 (as opposed to the minimum and maximum) to 

remove outlying data points. For horizontal wells only,

45 ERG also calculated the 

flowback rates over the first 30 days of production to estimate total flowback volume.

46

ERG presents the results in the Results tab in Attachment 11 (DCN SGE00724.A011). 

ERG also presents the total number of wells in this tab. ERG entered these results into the 

PW Data tab of Attachment 1 (DCN SGE00724.A01).

4.9 Attachment 12 – Niobrara Flowback Recovery

ERG estimated flowback recovery for UOG wells completed in the Niobrara formation 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 SGE00724.A04-A5). ERG entered the results of this analysis as inputs to 

the PW Data tab in Attachment 1 (DCN SGE00724.A01). Attachment 12 (DCN SGE00724.12) 

contains the underlying Microsoft Excel file.

 

45 Bai (2013) only provided an equation for flowback for horizontal wells.

46 Literature reports that the flowback process lasts anywhere between 14 and 60 days. (DCN SGE00951).
Memorandum

March 31, 2015

Page 39

4.9.1 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 SGE00724.A04-

A5). Relevant data in these results included the following:

 Well API number

 Formation

 State

 Well trajectory (horizontal, vertical, or directional)

 Fracture Date (DD/MM/YYYY)

 Fracturing fluid volume (gallons)

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

COGCC’s database.

4.9.2 Methods and Procedures

Step 1: Identify Colorado Wells from FracFocus® Analysis

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

UOG wells located in Colorado (DCN SGE00724.A04-A5). 

Step 2: Identify UOG Flowback Volumes in COGCC’s Production Data

ERG searched COGCC’s production database for individual UOG wells listed in the 

filtered results (from Step 1) in ERG’s Analysis of FracFocus®Fracturing Fluid Volumes

(DCN SGE00724.A04-A5). For each well, ERG located the production data in the 

COGCC database for the month that well was completed, according to the FracFocus®

database. ERG recorded the produced water volume and production days into the 

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

the Analysis tab of Attachment 12 (DCN SGE00724.A012). 

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 
Memorandum

March 31, 2015

Page 40

volumes 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 “Estimated Flowback Volume 

(barrels)” and “Production Days” fields respectively in the Analysis tab of Attachment 12

(DCN SGE00724.A012). 

Step 3 : Calculate Flowback Recovery

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

using Equation 4. The flowback volume was obtained in Step 2 above from the COGCC 

database. The total fracturing fluid volume was obtained from ERG’s Analysis of 

FracFocus®Fracturing Fluid Volumes (DCN SGE00724.A04-A5).

Step 4: Summary of Results

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

flowback recovery by formation and well trajectory. ERG calculated the 10th percentile 

and 90th percentile (as opposed to the minimum and maximum) to remove outlying data 

points. The results are shown in the Results tab of Attachment 12 (DCN 

SGE00724.A012). The total number of wells is also shown in this tab. ERG entered these 

results into the PW Data tab of Attachment 1 (DCN SGE00724.A01). 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 well trajectory, which falls within the ranges of flowback process length reported in 

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

NATIONAL LEVEL UOG PRODUCED WATER CHARACTERIZATION ANALYSES

The following subsections describe analyses that ERG completed using national-level 

datasets to generate data inputs to the UOG Wastewater Characterization Database in 

Attachment 14 (DCN SGE00724.A014) (see Section 3.0). 

4.10 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 15 and 16 (DCN SGE00724.A015-.A16).

4.10.1 Data Source

The USGS Produced Water Geochemical Database v. 2.0 (PROVISIONAL) (USGS 

database) contains geochemical and other information for produced waters from both 

 

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.
Memorandum

March 31, 2015

Page 41

conventional and unconventional well types (DCN SGE00956). 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 14 (DCN SGE00724.A014).

ERG obtained data from the USGS database from the USGS website on August 8, 2014 

and aggregated the data for inclusion in the “Raw Data 3 - USGS Data” table in the “UOG 

Wastewater Characterization” database in Attachment 14 (DCN SGE00724.A014). The “USGS 

National Produced Waters Geochemical Database v. 2.0 (PROVISIONAL) – Documentation” 

file (DCN SGE00956) provides additional background about this database and defines all of the 

fields within the tables in the database.

4.10.2 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 16 (DCN SGE00724.A016), 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 16 (DCN SGE00724.A016) into the USGS Data tab 

in Attachment 15 (DCN SGE00724.A015). Within Attachment 15, ERG first removed 

any negative values48 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 15. Finally, ERG manually 

removed any Parameters that did not have values for any of the wells in the Median 

Summary_Del Blank Col tab.

 

48 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 their exclusion should not have an impact on the results.
Memorandum

March 31, 2015

Page 42

Step 4: “Un-Crosstab” Data

ERG exported the results of the Median Summary_Del Blank Col tab from Attachment 

15 (DCN SGE00724.A015) into the “USGS Median Summary Data (from Excel)” table 

in Attachment 16 (DCN SGE00724.A016). Because the Excel results were in a crosstabtype format where the parameter names were stored in the column headings, ERG created 

union queries49 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”50 process on the “USGS_Temp” table in Attachment 16 (DCN 

SGE00724.A016) to make the data more usable in Step 5.

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. 

4.10.3 Attachments 15 and 16 – Query Descriptions

Table 7 describes the queries and their results used to perform the analyses in 

Attachments 15 and 16 (DCN SGE00724.A015 and A16).

Table 7. USGS Produced Water Database: Query Descriptions

Query(s) Query Description

Relevant 

Memorandum 

Attachment

000 Initialized [USGS_Temp] table.

16

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). 15

51

 

49 Union queries combine the results of several similar select queries.

50 The “un-crosstab” process refers to the process of translating data from columns into rows.

51 Attachment 15 (DCN SGE00724.A015) is an Excel attachment in which ERG completes the median calculations 

that cannot be performed in the Access database in Attachment 16 (DCN SGE00724.A016). Attachment 16 lists 

Query 200 as a placeholder entry for the step in which ERG exports the data to Excel to perform these median 

calculations.
Memorandum

March 31, 2015

Page 43

Table 7. USGS Produced Water Database: Query Descriptions

Query(s) Query Description

Relevant 

Memorandum 

Attachment

“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.

16

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 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.

4.11 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 17 (DCN SGE00724.A017) and the QC procedures 

are described in Section 5.0.
Memorandum

March 31, 2015

Page 44

4.11.1 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).

52 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 5.0. 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 14 (DCN SGE00724.A014). 

ERG received a non-CBI53 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 14 (DCN SGE00724.A014). 

4.11.2 Methods and Procedures

ERG’s analysis of the ORD data is shown in Attachment 17 (DCN SGE00724.A017). 

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 17, DCN SGE00724.A017), 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 17 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 17 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 

SGE00963).

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 

17, DCN SGE00724.A017). ERG also deleted any data where the associated formation 

 

52 These data are referred to as source ORD, 2014 in the relevant attachments.

53 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.
Memorandum

March 31, 2015

Page 45

name was blank (see Query 12 in Attachment 17, DCN SGE00724.A017). 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 17, DCN SGE00724.A017). 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 17, DCN SGE00724.A017).

Step 4: Generate Final Table

ERG imported the final table (“All_Data_Final” table in Attachment 17, DCN 

SGE00724.A017) into the Wastewater Characterization database in Attachment 14 (DCN 

SGE00724.A014) and standardized the data using the methods described in Section 3.2

of this memorandum.

4.11.3 Attachment 17 – Query Descriptions

Table 8 describes the queries used for the analyses performed in Attachment 17 (DCN 

SGE00724.A017).

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”

5.0 QUALITY CONTROL (QC) 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 proposed rulemaking. ERG staff entered reference 

information for relevant sources into the UOG Literature Review database. The ERG index 

keeper reviewed all reference information, assigned each reference a Document Control Number 
Memorandum

March 31, 2015

Page 46

(DCN), imported the reference information into the UOG Project File Index database, and saved 

referenced files in the Electronic Project File folder.

ERG also used the procedures described in Section 3 of the SQAPP when collecting 

existing data for use in the UOG proposed rulemaking. ERG used a combination of sources, 

including reports, papers, and online databases from state regulatory agencies, such as 

departments of environmental protection and oil and gas commissions. As shown in Table 9, 

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 verified54 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.

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 proposed 

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 4.11):

 

54 ERG considered sources as verified if we were able to find information about the author outside of the reference 

document. ERG primarily verified information by looking for company/organization websites that confirmed the 

author’s affiliation with the UOG industry.
Memorandum

March 31, 2015

Page 47

 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 14 (DCN SGE00724.A014).

 ERG found data discrepancies in less than two percent of the files that were 

checked.

6.0 REFERENCES

Table 9 lists the sources ERG used along with their DCN and source flag (see Section 5.0

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 9. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00002

Volz, Conrad, Ferrar, Kyle, and Michanowicz, D. 2011. 

Contaminant Characterization of Effluent from PA Brine 

Treatment Josephine Facility. A X

SGE00004.A06

Coleman, Nancy. Chesapeake Energy. Produced Formation 

Water Sample Results from Shale Plays. B X

SGE00006.A03

Havics, Andrew. 2011. pH2, LLC/QEPA. Fracing & 

Associated Media Composition in Colorado. A X

SGE00006.A04

McElreath, Debra. 2011. Chesapeake Energy Corp. 

Comparison of Hydraulic Fracture Fluid Composition with 

Produced Formation Water Quality Following Fracturing: 

Implications for Fate and Transport. C X

SGE00007.A10

Mantell, Matthew. Chesapeake Energy Corp. Produced 

Water Reuse and Recycling Challenges and Opportunities 

Across Major Shale Plays. C X

SGE00007.A13

Hayes, Tom. Gas Technology Institute. 2011. 

Characterization of Marcellus Shale and Barnett Shale 

Flowback Waters and Technology Development for Water 

Reuse. A X

SGE00007.A14

Tipton, Steven. 2011. Newfield Exploration. Mid-Continent 

Water Management for Stimulation Operations. B

SGE00007.A18

Alleman, David. 2011. ALL Consulting. Treatment of Shale 

Gas Produced Water for Discharge. D X

SGE00011

Veil, John. Argonne National Laboratory: E. 2010. Water 

Management Technologies Used by Marcellus Shale Gas 

Producers. A X

SGE00064

Williams, John. 2011. Marcellus Shale Gas Development 

and Water Resource Issues. USGS. A X
Memorandum

March 31, 2015

Page 48

Table 9. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00070

Acharya, Harish R. 2011. Cost Effective Recovery of LowTDS Frac Flowback Water for Reuse. GE Global Research. A X X

SGE00091

Rimassa, Shawn, Paul Howard, Kristel Blow, 

Schlumberger. 2009. Optimizing Fracturing Fluids from 

Flowback Water. Society of Petroleum Engineers. A X

SGE00110

Bruff, Mathew 2011. An Integrated Water Treatment 

Technology Solution for Sustainable Water Resource 

Management in the Marcellus Shale. Alteta Inc. Argonne 

National Laboratory. BLX, Inc. CWM Environmental, Inc. A X

SGE00153

Energy Information Administration. 2011. Shale Gas Play, 

Lower 48 States. Prepared by EIA Office of Oil and Gas. 

(May). A X

SGE00155

Energy Information Administration. 2010. Tight Gas Plays, 

Lower 48 States. Prepared by EIA Office of Oil and Gas. 

(June). A X

SGE00241

Rowan, E.L., et al. Radium content of oil- and gas-field 

produced waters in the northern Appalachian Basin (USA)—

Summary and discussion of data. U.S. Geological Survey 

Scientific Investigations Report 2011–5135, 31 p A X

SGE00275

US EPA. 2012. Site Visit Report Citrus Energy Corporation 

Marcellus Shale Gas Operations. A X

SGE00276

US EPA. 2012. Meeting with XTO Energy, Inc. about 

Unconventional Oil and Gas Sanitized. A X

SGE00280

US 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, Tom. 2012. Barnett and Appalachian Shale Water 

Management and Reuse Technologies A X

SGE00286

Hammer, 2012. In Fracking's Wake: New Rules are Needed 

to Protect Our Health and Environment from Contaminated 

Wastewater. (May). 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. B 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 Publicly-Owned Treatment Works (POTWs). Prepared for 

Halliburton Energy Services, Inc. C X

SGE00332

Kent, Perry. New Albany Shale Gas Research Project. Gas 

Technology Institute. B X
Memorandum

March 31, 2015

Page 49

Table 9. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00333

Horn, Aaron D. 2009. Breakthrough Mobile Water 

Treatment Converts 75% of Fracturing Flowback Fluid to 

Fresh Water and Lowers CO2 Emissions. Society of 

Petroleum Engineering. 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

Welsh, James. Hydraulic Fracturing Regulatory Processes in 

Louisiana. Louisiana Department of Natural Resources. A X

SGE00344

Haluszczak, Lara O.. 2012. Geochemical evaluation of 

flowback brine from Marcellus gas wells in Pennsylvania, 

USA. Department of Geosciences, Pennsylvania State 

University. A X

SGE00345

Lewis, Aurana. 2012. Wastewater Generation and Disposal 

from Natural Gas Wells in Pennsylvania. Nicholas School 

Of The Environment. Duke University. B X

SGE00350

Stepan, Daniel, et al.. 2010. Bakken Water Opportunities 

Assessment - Phase 1. Energy & Environmental Research 

Center, University of North Dakota. Prepared for National 

Energy Technology Laboratory. A X X

SGE00358

Ecolotron Water Recovery Systems. 2011. Treatment of 

Flow Back and Produced Water from the Hydraulic 

Fracturing of Oil – Shale. A X

SGE00359

Kimball, Robert. 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. Research Partnership to Secure 

Energy for America (RPSEA). A X X

SGE00442.A02

Colwell, Cecil. 2013. Development of Cost Effective 

Systems for Handling Produced Water. Source Energy. C X

SGE00442.A06

Murray, Kyle E.. 2013. Examining Water Production 

Volumes and Produced Water Quality in the Mississippi 

Lime to Develop Appropriate Management Strategies.

Mississippi Lime Production and Produced Water. B X X

SGE00465

Nicot, Jean-Philippe and Scanlon, Bridget. 2012. Water Use 

for Shale-Gas Production in Texas, U.S.. University of Texas 

at Austin. A X

SGE00480

Luedecke, Richard. 2012. Energy Water Conservation & 

Recycling 33rd Annual Governor's Water Conference. 

Devon Energy. C X

SGE00486

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. Department of Civil and 

Environmental Engineering, Colorado State University. A X

SGE00507

Boschee, Pam. 2012. Handling Produced Water from 

Hydraulic Fracturing. Oil & Gas Facilities. B X
Memorandum

March 31, 2015

Page 50

Table 9. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00511

Casey, Greg. 2013. The evolution of Class II Salt Water 

Disposal (SWD) Wells as Part of the Shale Revolution. 

Technical Presentation presented at Ground Water Protection 

Council's Annual UIC Conference. (January). B X

SGE00518

Colorado Oil and Gas Conservation Commission (COGCC). 

COGIS - Production Data Inquiry. A X

SGE00520

Drillinginfo. 2011. DI Desktop® December 2011 Download. 

Drillinginfo, Inc. B X

SGE00532

Hansen, et al. 2013. Water Resource Reporting and Water 

Footprint from Marcellus Shale Development in West 

Virginia and Pennsylvania. San Jose State University. 

(October 30). B X X

SGE00555

New York State Department of Environmental Control 

(NYSDEC). 2009. New Discharge Notification: SPDES

Permit NY 002 5984 to Watertown, NY POTW. 

(December). A X

SGE00556

Nicot, Jean-Philippe. 2011. Current and Projected Water Use 

in the Texas Mining and Oil and Gas Industry. Texas Water 

Development Board. Bureau of Economic Geology. 

(January). A X

SGE00557

North Dakota Industrial Commission (NDIC). 2014. Basic 

Subscription Services - Well Index. Department of Mineral 

Resources, Oil and Gas Division. Last Accessed on 

1/27/2014. 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

SGE00561

Ohio Department of Natural Resources (OH DNR). 2013. 

Utica/Point Pleasant Shale Cumulative Permitting Activity 

through 12/07/2013. Downloaded on 12/12/2013. Last 

updated on 12/6/2013. A X

SGE00585

U.S. Environmental Protection Agency (U.S. EPA). 2014. 

FracFocus®Database. Office of Research and Development 

(ORD). A X

SGE00592

U.S. Department of Energy (U.S. DOE). 2013. Oil & Natural 

Gas Program Newsletter (E&P Focus): Water Issues 

Dominate Oil and Gas Production. Fall. A X

SGE00607

U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Conference Call with Quicksilver Resources, Inc. About 

Shale Gas Operations Sanitized. (October 11). A X

SGE00616

U.S. Environmental Protection Agency (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 

(SWN) Fayetteville Shale Gas Operations Sanitized A X
Memorandum

March 31, 2015

Page 51

Table 9. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00629

Warner, Nathaniel, Cidney Christie, Robert Jackson, Avner 

Vengosh. 2013. Impacts of Shale Gas Wastewater Disposal 

on Water Quality in Western Pennsylvania. Environmental 

Science and Technology. September 10. A X

SGE00632

Williams, John. Unknown. The Marcellus Shale Gas Play: 

Geology, Development, and Water Resource Impact 

Mitigation. USGS: New York Water Science Center. A X

SGE00635

U.S. Environmental Protection Agency (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. (September). Bureau of 

Economic Geology. A X

SGE00640

Mingazetdinov, Ildus. 2012. Predictions Of Produced Water 

Quality And Quantity For Spatially-Distributed Wells In 

Niobrara Formation. Department of Civil and Environmental 

Engineering. Colorado State University. B X

SGE00641

Nicot, Jean-Philippe. 2013. Geographical, Geological, and 

Hydrogeological Attributes of Formations in the Footprint of 

the Eagle Ford Shale. Bureau of Economic Geology. 

(February). A X

SGE00642

Goodwin, Stephan, et al. 2012. Life Cycle Analysis of Water 

Use and Intensity of Oil and Gas Recovery in Wattenberg 

field, Colo. Oil & Gas Journal. (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

SGE00691

U.S. Environmental Protection Agency (U.S. EPA). 2013. 

Summary of the Technical Workshop on Water Acquisition 

Modeling: Assessing Impacts Through Modeling and Other 

Means. September. A X

SGE00693

ERG. 2015. Data Compilation Memorandum for the 

Technical Development Document (TDD) for Proposed 

Effluent Limitations Guidelines and Standards for Oil and 

Gas Extraction. Office of Water Engineering and Analysis 

Division. A X

SGE00694

Oklahoma Geological Survey. 2014. Gas Shale Database. 

Accessed January 29, 2014. A X

SGE00695

U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Conference Call with ConocoPhilips About Shale Gas 

Operations. A X

SGE00704

U.S. Environmental Protection Agency (U.S. EPA). 2015. 

Technical Development Document for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction. A X X

SGE00710

Slutz, James, et al. 2012. Key Shale Gas Water Management 

Strategies: An Economic Assessment Tool SPE 157532. 

Society of Petroleum Engineers. (September 11). B X
Memorandum

March 31, 2015

Page 52

Table 9. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00719

Agrawal, Archna. 2009. A Technical and Economical Study 

of Completion Techniques in Five Emerging U.S. Shale 

Plays. Office of Graduate Studies of Texas A&M University. 

(December) B X

SGE00720

Kansas Geological Survey. 2014. Horizontal or Slant Wells 

in Kansas. Last updated 2/8/2014. Accessed on 3/17/2014. A X

SGE00727

Ohio Department of Natural Resources (OH DNR). 2014. 

2013 Quarterly Horizontal Shale Production: 3rd Quarter. A X

SGE00731

Silva, James. 2013. Pretreatment Targets for Salt Recovery 

from Marcellus Shale Gas Produced Water. GE Global 

Research Center. IWC-13-38. (November 17). A X

SGE00734

Boschee, Pam. 2014. Produced and Flowback Water 

Recycling and Reuse: Economics, Limitations, and 

Technology. Oil and Gas Facilities Magazine. (February). A X

SGE00737

Ohio Department of Natural Resources (OH DNR). 2014. 

2013 Quarterly Horizontal Shale Production: 4th Quarter. A X

SGE00739.A03

ERG. 2015. Analysis of Pennsylvania Department of 

Environmental Protection’s (PA DEP) Oil and Gas Waste 

Reports – Attachment 3 – Data Calculations. A X

SGE00740

ERG. 2015. Unconventional Oil and Gas (UOG) Drilling 

Wastewater Memorandum. A X

SGE00773

Helmer, Stephen. 2014. RE: Public Records Request - Frack

Waste - Solids and Fluids - Norm. (January 14).

Tenorm A X

SGE00774

Ziemkiewicz, Paul. 2013. Water Quality Literature Review 

and Field Monitoring of Active Shale Gas Wells. Phase I: 

Assessing Environmental Impacts of Horizontal Gas Well 

Drilling Operations. West Virginia Department of 

Environmental Protection. (Feb. 15). A X

SGE00777

Johnson, Tommy and Harry, David. 2014. Uinta Water 

Management. Water Management for Shale Plays 

Conference. (May 28). C X

SGE00779.A25

RETTEW. 2014. Water Treatment - Oil and Gas 

Environment Compliance Conference Appalachian Basin -

Washington, PA May 13 – 14 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

Division of Solid and Hazardous Materials. 1999. An 

Investigation of Naturally Occurring Radioactive Materials 

(NORM) in Oil and Gas Wells in New York State. DEC 

Publication. (April). A X

SGE00950

EERC Northern Great Plains Water Consortium (NGPWC). 

2009. Bakken Water Opportunities Assessment. North 

Dakota Petroleum Council Annual Meeting. C X
Memorandum

March 31, 2015

Page 53

Table 9. UOG Extraction Wastewater Characteristics Data Sources

DCN Source Citation 

Source 

Flaga

WW 

Volumes

WW 

Char.

SGE00951

NYSDEC. 2011. Supplemental Generic Environmental 

Impact Statement (SGEIS) on the Oil, Gas, and Solution 

Mining Regulatory Program: Information Requests. Prepared 

by: ALL Consulting. A X

SGE00953

Gastem, Aaron Sulkey. Unknown. Otsego County, Utica 

Water Analysis. USA A X

SGE00954

Palacios, Virginia. 2012. Baseline Groundwater Quality 

Testing Needs in the Eagle Ford Shale Region April 2012 A X

SGE00955

USGS. 2013. USGS Produced Water Database Accessed on 

November 25, 2013. A X

SGE00956

Blondes, Madalyn S., Kathleen D. Gans, James J. Thordson, 

Mark E Reidy, Burt Thomas, Mark A Engle, Yousif K 

Kharaka, Elizabeth L Rowan. 2014. U.S. Geological Survey 

(USGS) National Produced Waters Geochemical Database 

v2.0 (PROVISIONAL) 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

SGE00963 ERG. 2015. Analysis of DI Desktop® Memorandum. A X

SGE00988

Energy Information Administration. 2014. Assumptions to 

the Annual Energy Outlook 2014. A X

SGE01021

Arkansas Oil and Gas Commission (AOGC). 2014. B-43 

Field - Well Completions. Downloaded 1/5/2014. A X

SGE01022

Energy Information Administration (EIA). 2011. 

Distribution and Production of Oil and Gas Wells by State. 

(January 7). A X

SGE01024

Louisiana Department of Natural Resources. 2014.

Haynesville Shale Wells. Last updated 1/5/2014. 

Downloaded 1/7/2014. A X

SGE01028

Pennsylvania Department of Environmental Protection. 

2015. Technologically Enhanced Naturally Occurring 

Radioactive Materials (TENORM) Study Report. A X

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.

7.0 ATTACHMENTS
ATTACHMENT 1: UOG PW DATA COMPILATION (DCN SGE00724.A01)
ATTACHMENT 2: DI DESKTOP LONG-TERM PRODUCED WATER GENERATION RATES

(DCN SGE00724.A02)
ATTACHMENT 3: DI DESKTOP LONG-TERM PRODUCED WATER GENERATION RATES

(DCN SGE00724.A03)
ATTACHMENT 4: FRACFOCUS FRACTURING FLUID VOLUMES (DCN SGE00724.A04)
ATTACHMENT 5: FRACFOCUS FRACTURING FLUID VOLUMES (DCN SGE00724.A05)
ATTACHMENT 6: BAKKEN FLOWBACK RECOVERY (DCN SGE00724.A06)
ATTACHMENT 7: NEW MEXICO FLOWBACK RECOVERY (DCN SGE00724.A07)
ATTACHMENT 8: UTICA FLOWBACK RECOVERY AND LONG-TERM PRODUCED WATER RATES

(DCN SGE00724.A08)
ATTACHMENT 9: NIOBRARA LONG-TERM PRODUCED WATER RATES (DCN SGE00724.A09)
ATTACHMENT 10: WYOMING FLOWBACK RECOVERY (DCN SGE00724.A010)
ATTACHMENT 11: WATTENBERG FLOWBACK RECOVERY AND LONG-TERM PRODUCED 

WATER RATES (DCN SGE00724.A011)
ATTACHMENT 12: NIOBRARA FLOWBACK RECOVERY (DCN SGE00724.A012)
ATTACHMENT 13: UOG WASTEWATER CHARACTERIZATION ANALYSIS

(DCN SGE00724.A013)
ATTACHMENT 14: UOG WASTEWATER CHARACTERIZATION DATABASE

(DCN SGE00724.A014)
ATTACHMENT 15: USGS PRODUCED WATER DATABASE (DCN SGE00724.A015)
ATTACHMENT 16: USGS PRODUCED WATER DATABASE (DCN SGE00724.A016)
ATTACHMENT 17: ORD NON-CBI OPERATOR DATA (DCN SGE00724.A017)