Jflfc United States
Environmental Protection
Lai I mm Agency
Supplemental Technical Support
Document for the Effluent Limitations
Guidelines and Standards for
Unconventional Oil and Gas Operations
EPA-821-R-19-004
June 6, 2019
U.S. Environmental Protection Agency
Office of Water (4303T)
Washington, D.C. 20460
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Acknowledgements and Disclaimer
This document was prepared by the Environmental Protection Agency. Neither the United States
Government nor any of its employees, contractors, subcontractors, or their employees make any
warrant, expressed or implied, or assume any legal liability or responsibility for any third party's
use of or the results of such use of any information, apparatus, products, or process discussed in
this report, or represents that its use by such party would not infringe on privately owned rights.
Questions regarding this document should be directed to:
U.S. EPA Engineering and Analysis Division (4303T)
1200 Pennsylvania Avenue NW
Washington, DC 20460
(202) 566-1000
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Contents
CONTENTS
1. Executive Summary and purpose of this document vn
2. Re-evaluation of oil and gas Extraction Entities potentially
SUBJECT TO THE UOG RULE AND SUMMARY OF DATA SOURCES 2-1
2.1 Scope of Analysis 2-1
2.2 Overview of Data Sources for New BAT Analysis 2-8
2.2.1 Databases 2-8
2.2.2 Detailed Study of CWT Category for Facilities Managing Oil and
Gas Extraction Wastes 2-8
2.2.3 Clean Water Act Section 308 Letters 2-8
2.2.3.1 Entity Selection Criteria 2-9
1.2.2.2 Engineering, Cost, and Production Information 2-10
1.2.2.3 Entity Financial Information 2-10
2.2.4 Locational Analysis 2-11
2.2.5 Oil and Gas Prices, and Other General Financial Information 2-11
3. Alternative Wastewater Management Analysis 3-1
3.1 Alternative Wastewater Management Analysis 3-1
3.1.1 Step 1 - PA DEP Waste and Production Reports 3-2
3.1.2 Step 2 - Prepare PA DEP Waste and Production Report
Development Databases 3-2
3.1.3 Steps 3 and 4 - Prepare PA DEP and DI Cross-Reference Database
and Identify Wells/Entities that Will Likely Incur Costs 3-2
3.1.4 Step 5 - Develop List of Wastewater Management Alternatives to
POTW Discharge 3-5
3.1.5 Step 6 - GIS Analysis 3-8
3.1.6 Step 7 - Cost Data Compilation 3-11
3.1.7 Step 8 - UOG Alternative Wastewater Management Analysis -
Baseline Costs 3-12
3.1.8 Step 9 - UOG Alternative Wastewater Management Analysis -
Incremental Costs 3-16
3.1.9 Step 10 - Identify and Remove Stripper Wells 3-20
3.2 Alternative Wastewater Management Analysis Results 3-20
3.3 Cost Analysis Uncertainties and Limitations 3-21
4. Economic Impact Analysis 4-1
4.1 Overview of Discounted Cash Flow Analysis 4-1
4.1.1 Analysis Period and Dollar Year 4-1
4.1.2 Baseline Analysis Methodology 4-1
4.1.3 Post-Compliance Analysis Methodology 4-3
4.2 Assumptions for Projecting Over the Ten-Year Analysis Period for
Surveyed Facilities 4-4
4.2.1 Projecting Crude Oil and Natural Gas Prices 4-5
4.2.2 Projecting Crude Oil, Natural Gas, and Condensate Production 4-5
4.2.3 Projecting Revenue 4-6
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Supplemental Technical Support Document for the ELGs
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4.2.4 Projecting Operating Costs 4-6
4.2.5 Proj ecting Quantity of Wastewater 4-6
4.2.6 Projecting Wastewater Management and Transportation Costs 4-7
4.2.7 Projecting Impact Fees, Other Costs, Depreciation, and Interest 4-7
4.2.8 Projecting Federal and State Taxes 4-8
4.3 Assumptions for Modeling Non-Surveyed Facilities 4-8
4.4 Baseline Analysis Results 4-10
4.5 Post-Compliance Analysis Results 4-10
4.6 Uncertainties and Limitations 4-10
5. Cost to Revenue 5-1
5.1 Analysis Approach 5-1
5.2 Results 5-2
6. Non-Water Quality Environmental Impacts 6-3
6.1 Air Pollution 6-3
6.2 Solid waste 6-3
6.3 Energy Requirements 6-4
7. Water quality Parameters in Shale, Tight, and Conventional Oil
AND GAS WASTEWATER 7-1
7.1 Analysis Approach 7-1
7.2 Results 7-2
7.3 Uncertainties and Limitations 7-7
8. Preliminary Conclusion 8-1
9. References 9-1
Appendix A. ALTERNATIVE WASTEWATER MANAGEMENT ANALYSIS
DATABASE AND SPREADSHEET STRUCTURES 1
A-l. PA DEP Waste and Production Reports Table Field Descriptions (Step 1) 1
A-2. PA DEP Waste Report and Production Report Development Databases
(Step 2) 3
PA DEP Waste Report Development Database 3
PA DEP Production Report Development Database 4
A-3. PA DEP and DI Desktop® Cross-reference Database (Steps 3 and 4) DI
Desktop® 5
DI Desktop® 6
PA DEP and DI Desktop® Cross-Reference Database Queries 7
Additional PA DEP Data 10
A-4. GIS Analysis Output Results File (Step 6) 10
A-5. UOG Alternative Wastewater Management Analysis (Step 8, 9, and 10) 11
A-6. Stripper Well Analysis for Table 2-3 and Figure 2-3 12
Appendix B COST SENSITIVITY ANALYSIS 1
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List of Tables
LIST OF TABLES
Page
Table 2-1. UOG Resource Potential: Shale as of January 1, 2013, EIA East Region,
Appalachian Basin 2-5
Table 2-2. UOG Resource Potential: Tight as of January 1, 2013, EIA East Region,
Appalachian Basin 2-5
Table 2-3. PA DEP Waste Data for Oil and Gas Wells in 2016 2-8
Table 3-1. Example Crosswalk of PA DEP Waste Facility Record Standardization 3-3
Table 3-2. Available CWT Facilities 3-6
Table 3-3. Available Disposal Wells 3-7
Table 3-4. Alternative Wastewater Management Analysis Results 3-20
Table 4-1. Results of Baseline and Post-Compliance Analysis 4-10
Table 5-1: Entity Annualized Cost-to-Revenue (CTR) Results 5-2
Table 7-1. Select Pollutants in Produced Water from Conventional, Shale, and Tight Oil
and Gas Operations in the Appalachian Basin 7-3
Table 7-2. Select Pollutants in Produced Water from Conventional and Unconventional
Oil and Gas Operations Across the United States 7-4
Table 7-3. Naturally Occurring Radium Isotope Concentrations 7-5
Table 7-4. TDS Concentrations in Produced Water from Pennsylvania Tight Oil
and Gas Formations 7-5
Table 7-5. Naturally Occurring Radium Isotope Concentrations 7-6
Table 6. Reference List 9-1
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List of Figures
LIST OF FIGURES
Page
Figure 2-1. Major U.S. Tight Plays (Updated June 6, 2010) 2-3
Figure 2-2. Major U.S. Shale Plays (Updated June 6, 2010) 2-4
Figure 2-3. Map of Wells Generating Oil and Gas Wastewater in Pennsylvania,
Excluding Stripper Wells (2016) 2-7
Figure 3-1. UOG Alternative Wastewater Management Analysis Work Flow Diagram 3-1
Figure 3-2. Wastewater Management Alternatives Used in EPA's Analysis and EPA-
defined UOG Wells Discharging to POTWs in Pennsylvania in 2016 3-10
Figure 3-3. Example GIS Analysis Trucking Routes from Wells to Reynoldsville POTW 3-11
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Executive Summary
1. EXECUTIVE SUMMARY AND PURPOSE OF THIS DOCUMENT
The EPA promulgated the rule, Effluent Limitations Guidelines and Standards for the Oil
and Gas Extraction Point Source Category (the unconventional oil and gas or UOG rule), on June
28, 2016. 81 FR 41845. The UOG rule is a national rule which prohibits unconventional oil and
gas operations from discharging pollutants in wastewater to POTWs, in other words, a "zero
discharge" requirement. The UOG rule defines the term "unconventional oil and gas operations"
to include operations involving "crude oil and natural gas produced by a well drilled into a shale
and/or tight formation (including, but not limited to, shale gas, shale oil, tight gas, and tight oil)."
See 40 CFR 435.33(a)(2)(i). The UOG rule does not include those entities covered under 40
CFR Part 435, Subpart F, the Stripper well category. In promulgating the UOG rule, EPA
explained that UOG wastewaters are not typical of POTW influent wastewater, and as a result
some UOG extraction wastewater constituents: can be discharged, untreated, from the POTW to
the receiving stream; can disrupt the operation of the POTW (e.g., by inhibiting biological
treatment); can accumulate in biosolids, limiting their use; and can facilitate the formation of
harmful disinfection by-products.
EPA concluded at the time of promulgation of the UOG rule that the zero discharge
requirement was technologically available, economically achievable, and had acceptable non-
water quality environmental impacts for the industry as a whole, and thus BAT for this industry,
because all UOG operators were already meeting this requirement. EPA's record at issuance of
the final rule reflected that no unconventional oil and gas operations were discharging to a
POTW. Rather, EPA's record indicated that all UOG operations across the country were reusing
their wastewater or sending wastewater elsewhere, such as to centralized waste treatment
operations (privately-owned facilities that treat industrial waste) or to Class II underground
injection control wells (disposal wells). See the Technical Development Document for the
Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source
Category (EPA-820-R-16-003, June, 2016).
After the UOG rule was promulgated, several interested parties notified EPA that a
number of oil and gas operations in Pennsylvania covered by the rule were in fact discharging
wastewater to POTWs at the time of the rulemaking. These parties stated their operations are
"conventional" under Pennsylvania law and appear to meet the definition of "unconventional" in
the UOG rule. Pennsylvania defines an unconventional formation as: "a geological shale
formation existing below the base of the Elk Sandstone or its geologic equivalent stratigraphic
interval where natural gas generally cannot be produced at economic flow rates or in economic
volumes except by vertical or horizontal well bores stimulated by hydraulic fracture treatments
or by using multilateral well bores or other techniques to expose more of the formation to the
well bore" (DCN SGE01486). As Pennsylvania's definition of an unconventional formation is
narrower than the definition used in the UOG rule, EPA concluded that there were, indeed, some
operators in Pennsylvania that sent their wastewater to POTWs that would be subject to the UOG
rule.
Based on this post-promulgation information, the EPA extended the compliance date for
existing sources that were lawfully discharging to POTWs on or between April 7, 2015 and June
28, 2016, to three years from the effective date of the rule—to August 29, 2019 (compliance date
postponement rule). See 81 FR 88126-88127. That rule did not change the compliance date for
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Supplemental Technical Support Document for the ELGs
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Executive Summary
all other facilities subject to the final onshore UOG extraction pretreatment standards rule. As it
did for the proposal for the UOG rule, in the proposal for the postponement rule, EPA requested
information regarding any existing onshore UOG extraction facilities that currently discharge
UOG extraction wastewater to POTWs in the U.S. EPA did not receive any information in
response to that request.
Pennsylvania Grade Crude Oil Coalition (PGCC) also filed a petition for review of the
rule regarding this matter. PGCC indicated that the EPA did not conduct the necessary analyses
of Pennsylvania defined conventional facilities that meet the definition of "unconventional" in
the UOG rule and that they should not be subject to the UOG requirements. In response, the EPA
filed a motion (unopposed by PGCC) for voluntary remand without vacatur on August 31, 2017,
which was granted by the Court in October, 2017. In the motion, EPA discussed the post-
promulgation information referenced above, acknowledging that this information is inconsistent
with the record for the rule. Further, the motion explained that EPA requested the remand to
consider any additional evidence relevant to the UOG rule, develop the record, and take any
follow-up action as appropriate.
The EPA recently gathered new data and information and performed supporting analyses
to update the UOG rulemaking record. Much of the new data is for calendar year 2016 as that
was the most recent year with the most complete data to inform these new analyses. This
supplemental Technical Support Document describes the new data, methodology, analysis, and
results. First, this document describes how EPA re-evaluated oil and gas facilities that discharge
to POTWs and that may generate wastewater from wells defined as unconventional under the
UOG rule. In particular, it describes how EPA used information reported by oil and gas
extraction facilities to Pennsylvania for 2016 and well formation information from multiple
sources to identify those oil and gas extraction facilities that discharged any wastewater to
POTWs and that are defined as conventional under Pennsylvania's definition, but are defined as
unconventional according to the 2016 UOG rule's definition. The UOG rule is not applicable to
activities regulated under the Stripper Subcategory (40 CFR 435 Subpart F). The UOG rule
applies to onshore unconventional oil and gas extraction facilities regulated under Subpart C.
Subpart C excludes facilities regulated under Subpart F.1 EPA determined that out of 879 oil and
gas extraction entities reporting to Pennsylvania in 2016 (and over 6,000 nationwide), 22 entities
discharged at least some portion of their wastewater to a POTW from UOG operations as defined
by the 2016 UOG rule. Based on the 2016 data, this is the subset of entities that likely need to
make changes to comply with the 2016 UOG rule (and incur any associated costs).
For those 22 entities, this document then describes how EPA evaluated alternative
wastewater management alternatives to discharge to POTWs and the associated incremental
costs to these entities and the industry as a whole. EPA found that wastewater management
alternatives were available to all of these entities as many of them reported using another
wastewater management alternative in addition to a POTW in 2016. To estimate the potential
1 Under 40 CFR part 435 subpart F, the definition of a stripper wells is "onshore facilities which produce 10 barrels
per well per calendar day or less of crude oil and which are operating at the maximum feasible rate of production
and in accordance with recognized conservation practices." Specialized definitions 40 CFR §435.61 (c) "The term
"well" shall means crude oil producing wells and shall not include gas wells or wells injecting water for disposal or
for enhanced recovery of oil or gas", "(d) The term "gas well" shall mean any well which produces natural gas in a
ratio to the petroleum liquids produced greater than 15,000 cubic feet of gas per 1 barrel (42 gallons) of petroleum
liquids."
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Supplemental Technical Support Document for the ELGs
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Executive Summary
incremental costs of this rule to these facilities (which represent the only entities in the U.S. that
may incur costs associated with the nationally applicable rule), EPA calculated any incremental
wastewater management costs for these operators to send their wastewater to the nearest
alternative technology as well as any associated incremental transportation costs. For each entity,
EPA added incremental wastewater management and transportation costs to get the total
incremental costs to operators across all UOG wells.
EPA also evaluated incremental non-water quality environmental impacts associated with
alternative wastewater management approaches. This includes changes in air emissions, solid
waste generation, and energy consumption. The incremental change depends on the alternative
wastewater management approach. For example, sludge generation would likely decrease if a
UOG facility sends its wastewater to a UIC well and would likely increase if it sends its
wastewater to a CWT facility. Even if each operator that currently sends its wastewater to a
POTW elected to use a wastewater management approach that incrementally increased air
emissions, sludge generation, or energy usage, these changes would be small relative to U.S.
totals.
The EPA then estimated potential financial impacts for these entities by conducting a
discounted cash flow analysis (modeled future revenue and operation costs) over 10 years on an
after-tax basis. Based on this analysis, the EPA found that seven of the 22 entities would have
negative profits irrespective of the UOG rule's incremental costs. For the remaining entities,
when adding in the incremental costs of the rule, the EPA's analysis shows that none of the 15
entities would be at risk of closure as a result of complying with the UOG rule.
Historically, in conducting ELG analyses, the EPA considers entities with negative
profits before the addition of costs to comply with any new ELGs to be baseline closures and
removes them from any further analysis (e.g., total costs, total benefits). However, in this case,
the seven entities that the data indicate have negative profits in 2016 continued to report
wastewater discharge to Pennsylvania in 2017 demonstrating they remain in business. Therefore,
the EPA is reporting cost information as a range with the lower value representing EPA's typical
approach and the upper value assuming all 22 facilities continue to operate. The EPA's analysis
shows that for 2016, the median incremental costs would be between $131 and $279 per entity
and the total costs of the UOG rule for 2016 would be approximately $33,000 -$65,000.
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Supplemental Technical Support Document for the ELGs
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Introduction
2. RE-EVALUATION OF OIL AND GAS EXTRACTION ENTITIES
POTENTIALLY SUBJECT TO THE UOG RULE AND SUMMARY OF DATA
SOURCES
2.1 Scope of Analysis
Nationally, United States Census Bureau Statistics of U.S. Businesses (SUSB, 2015)
estimates over 6,000 firms that meet the NAICS code 2111 for Oil and Gas Extraction: primarily
engaged in operating and/or developing oil and gas field properties and establishments primarily
engaged in recovering liquid hydrocarbons from oil and gas field gases (DCN SGE01449).
As explained in the Executive Summary, EPA received notification post-promulgation
that, indeed, some oil and gas entities in Pennsylvania that drilled into shale or tight formations
were sending wastewater to POTWs (DCN SGE01431; DCN SGE01482). In light of this new
information, EPA reviewed its record on operators that discharged any type of oil and gas
wastewater to POTWs. In addition to Pennsylvania, some operators in California and Colorado
had historically managed oil and gas extraction wastewater at POTWs. EPA re-evaluated the
information on the formations into which these operators drilled wells and continued to
determine that these wells were not drilled into tight or shale formations and therefore were not
subject to the UOG rule (DCN SGE01397; DCN SGE01399). EPA also contacted California and
Colorada to confirm its determination. Therefore, EPA has limited the scope of this supplemental
analyses to oil and gas extraction operations in Pennsylvania.
The Commonwealth of Pennsylvania requires oil and gas operators to report information
on wells located in Pennsylvania. See Pennsylvania Department of Environmental Protection
(PA DEP) Title 25, Chapter 78, Subchapter E (well reporting). This data includes: "the amount
and type of waste produced and the method of waste disposal or reuse", and "Drillers log that
includes the name and depth of formations from the surface to total depth, depth of oil and gas
producing zone, depth of fresh water and brines and source of information." During development
of the UOG rule, the EPA used this data as compiled by Pennsylvania to support its finding that
there were no UOG extraction facilities discharging wastewater to POTWs. Since EPA now has
a better understanding that the definition of UOG in the 2016 rule is broader than Pennsylvania's
definition, EPA has re-evaluated the available data. To determine which facilities are potentially
subject to the UOG rule, in addition to the PA DEP data, EPA used the following datasets and
sources, which are briefly described below, with more details provided in Appendix A and
Section 2:
• PA DEP Production and Waste Reports. Oil, gas, and condensate production
quantities. Waste quantity, waste type and waste management practices used.
• PA DEP Formation Database. This database identifies the oldest, target and/or
producing formations for all Pennsylvania oil and gas wells.
• DI Desktop® Database. Compiled by the firm Drillinglnfo, DI Desktop® lists all
known2 oil and gas wells in the United States, including well API number, location,
2 For more detail on what wells may or may not be included in DI Desktop®, see Section A-3 and DI's Data
Coverage (DCN SGE01171).
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Supplemental Technical Support Document for the ELGs
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Introduction
operator, well trajectory, and annual oil and gas production and produced water
generation.
• EDWIN Database. The EDWIN database is maintained by the Pennsylvania
Department of Conservation and Natural Resources, Bureau of topographic and
Geological Survey, providing records for oil and gas wells drilled in Pennsylvania,
including scanned oil and gas well documents and associated digital and interpreted
data.
• PA PEP SPUD Database. This database compiles Pennsylvania oil and gas SPUD
data, including well location.
• EIA listings of known tight and shale formations. This includes two maps published
by EIA: Major Tight Gas Plays, Lower 48 States (Figure 2-1) and Shale Gas Plays,
Lower 48 States (Figure 2-2), and EIA's Assumptions to the Annual Energy Outlook
2015 (Table 2-1 and Table 2-2). Tight and Shale formations identified by EIA in
these figures and tables include: Berea-Murrysville, Bradford-Venango-Elk, Medina/
Clinton-Tuscarora, Marcellus, Utica, Clinton-Medina, Tuscarora, and Devonian.
EPA combined these data sources together via well API numbers to have comprehensive
information on oil and gas wells in Pennsylvania.
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Supplemental Technical Support Document for the ELGs
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Introduction
Bowdoin-
Greenhorn
WiHston
Basin
Ncrlh-Cential
Montana Area
Judith River-
Bi^om Basin
t Cretaceous
VWnd Ri/er Basin
Cretaceous-Lower Tertiary
Grea:er Green t-
River Basin ' .
Mesaverde-
Lance-Lewis
Denver Basin
'K Sussex-Shannon"
\ Cod ell-Niobrara
y) Muddy J
/ [[Niobrara Chalk
.-J Berba-Murryfeville
Bradford-^fenango-Elk
Mediriai'Ciirjton-Tuscarora
Wasatch-
Mesa verde
JJrta Basin
Man cos
Dakota
C le vetand
Red Fork
Granite Wash
Mtsavercte
Pictured CI
Dakota q,r
Anafiarko
5 Basin
Travis Pi
Bossier
Cotton V
Gilmer L
Permian
E-as.n
Texas-Louisiana-
Mississppi
¦ Salt Basin
Penrr-Perm Carbonate
_ Morrow
Ft Worth
Basin
Thirty -J
One
Austin Chalk
1 Eastern
Sheff-'"
Miles
'—r~
i 1 i 1 i
D 100 330 300 400
Wilcoxlobo V'-y-/
01 mosY j! / .
Stuart Cityldwa'rds > i j
¦
Vicksburn
I I Tight Gas Plays
Stacked Plays
Shallowest / Youngest
Basils
e a
DeepestOldest
Inter-Basin Areas
Source: DCN SGE00155.
Figure 2-1. Major U.S. Tight Plays (Updated June 6, 2010)
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Supplemental Technical Support Document for the ELGs
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Introduction
Bakken'
Wiliiston
Basin
Three
Forks
Powder
River Basin
Mowry-k
Antrim
Greater
Green River
Basin
Niobran
Forest City
Basin
Unita Basin
Maricos
Illinois Bgsin
Park
Basin'
Marcellus
Mannlni
Piceance
Basin
.Appalachian
Basin
Hermosa
New
Albany
Cherokee Platform
Pierre
Anadarko Basir
Fayetteville
Chattanooga
Woodford
s \\
Black Warrior
Basin
Arkoma Basin
Conasauga
Ardmore Basin
Valley & Ridge
Province
Ft Worth
Basin
Barnett
Haynesville-
Bossier
TX-LA-MS Sat Basin
Western
Gulf f
San Joaquin
Basin
Monterey-
Temblor
Monterey-—-»
*
Santa Maria-^
Ventura-Los
Angeles Basins
Montana
Thrust
Belt
Cody
o
Niobrara*
Heath**
Maneos
Canyon
garado* Basin
Lewis
San Juan
Basin
Raton
Basin
Abo-Veso""
Gloneta-Yeso*,"' ^
Pab Dure
Basin Bend
CL>
Bone Spring
Delaware
Spraberry****
Per irian Basin
Current play - Oldest stacked play , , . 6 .
*^r K 7 Mixed shale & chalk play
Current play -1 intermediate depth/age stacked play "Mixed shale & limestone play
""Mixed stiaie & dolostone-
Current play - Shallowest/youngest stacked play siitstone-sandstone play
. ""Mixed shale & limestone-
Prospective play atoone-awstone p.»y
Basin
evoman
(Ohio)
Source: DCN SGE01191.
Figure 2-2. Major U.S. Shale Plays (Updated June 6, 2010)
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Introduction
Table 2-1. UOG Resource Potential: Shale as of January 1, 2013, EIA East Region, Appalachian Basin
EIA Region
EIA Basin
UOG Formation
Name
Resource
Type
Oil EUR
(MMbls per Well)
Gas EUR
(Bcf per Well)
Oil TRR
(MMbls)
Gas TRR
(Bcf)
New Well
Potential
(Number of
wells)
1—East
Appalachian
Devonian
Shale Gas
0.000
0.061
0
23,700
388,500
Marcellus
Shale Gas
0.003
1.581
300
148,700
94,000
Utica
Shale Gas
0.002
0.470
200
53,100
112,900
Shale Oil
0.043
0.092
700
1,500
16,300
Sources: DCN SGE01179.
Abbreviations: UOG - unconventional oil and gas; EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf—billion cubic feet of gas;
TRR—technically recoverable resources
Table 2-2. UOG Resource Potential: Tight as of January 1, 2013, EIA East Region, Appalachian Basin
EIA Region
EIA Basin
UOG Formation
Name
Resource
Type
Oil EUR
(MMbls per Well)
Gas EUR
(Bcf per Well)
Oil TRR
(MMbls)
Gas TRR
(Bcf)
New Well
Potential
(Number of
wells)
1—East
Appalachian
Clinton-Medina
Tight Gas
0.002
0.058
400
12,400
213,800
Tuscarora
Tight Gas
0.000
0.724
0
4,400
6,100
Sources: DCN SGE01179.
Abbreviations: UOG - unconventional oil and gas; EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf—billion cubic feet of gas;
TRR—technically recoverable resources
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Supplemental Technical Support Document for the ELGs
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Introduction
Section 2 provides step-by-step descriptions of how EPA used the information in the
above sources to identify wells that discharged to POTWs in 2016, which EPA then used
formation and location data to classify each well reported to Pennsylvania in 2016 as
unconventional or conventional as defined by the 2016 UOG rule. Since wells classified by
Pennsylvania as unconventional also meet the UOG rule's definition, EPA classified any well
categorized as unconventional by Pennsylvania3 to be similarly unconventional for the UOG
rule. For wells classified as conventional by Pennsylvania, EPA reviewed operator reported
information on the formation into which the well was drilled in combination with the other data
sources identified above to determine if it was a shale or tight formation.
After reviewing all available database records from Pennsylvania, 680 wells that
discharged wastewater to POTWs in 2016 did not have formation names reported. EPA searched
completion reports for these wells in Pennsylvania's Exploration and Development Wells
Information Network (EDWIN) database (DCN SGE01420) to look for the missing information
but was unable to determine the formation these wells were drilled into for the majority of the
680 wells 4. These wells' formations therefore were labeled as "not reported" in EPA's analysis.
To be conservative, for purposes of this analysis only, EPA included all 680 "not reported"
formation name wells as unconventional.
EPA also reviewed all wells active in 2016 and removed from the analysis wells that met
the definition of 40 CFR part 435 Subpart F, the Stripper Well category because these wells are
not subject to the UOG rule. 40 CFR §435.60 defines stripper wells as "onshore facilities which
produce 10 barrels per well per calendar day or less of crude oil and which are operating at the
maximum feasible rate of production and in accordance with recognized conservation practices."
These wells cannot be gas wells, as seen in the specialized definitions 40 CFR §435.61 (c) "The
term "well" shall means crude oil producing wells and shall not include gas wells or wells
injecting water for disposal or for enhanced recovery of oil or gas" and, "(d) The term "gas well"
shall mean any well which produces natural gas in a ratio to the petroleum liquids produced
greater than 15,000 cubic feet of gas per 1 barrel (42 gallons) of petroleum liquids." Therefore,
given the format of the data, EPA reviewed the 2016 oil and gas production data contained in PA
DEP's database and excluded any well from the analysis that had less than a ratio of 15,000
cubic feet of gas per 1 barrel of oil, and had less than an average of 10 barrels per day of oil over
the year's reported production and number of producing days (note: because these operators
report data on an annual basis to Pennsylvania, EPA was limited in determining barrels of oil per
day at a finer detail).
3 The 2016 UOG rule's definition of unconventional is broader than Pennsylvania's definition and therefore
inclusive of all Pennsylvania-defined UOG wells.
4 During a review of well completion reports in the EDWIN database, EPA identified approximately 70 percent of
the 680 wells did not have formation names reported in Pennsylvania's database or DI Desktop records. For the
majority of the remaining wells, EPA only identified generic formation information. For example, some of the
record completion reports included the type of rock (e.g., sandstone), but no formation name. Based on a cursory
review of the available well completion reports, EPA only identified UOG formations names for less than 5 percent
of the 680 wells. EPA determined this was not sufficient information for purposes of this analysis to identify if the
well was drilled into an unconventional formation, as defined by EPA, and therefore decided to report all 680
remaining wells as "not reported", and subsequently, conservatively considered all "not reported" wells as
"unconventional wells" for purposes of the analysis..
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Figure 2-3 depicts oil and gas wells generating wastewater in 2016 in Pennsylvania,
excluding stripper wells, and whether this analysis classifies them as UOG, COG, or not
reported. Appendix A-5 describes the database EPA created to identify stripper wells.
EPA Resource Type
A Not Reported (910)
• Conventional (1,439)
• Unconventional (14.1S9)
Source: PA DEP Databases, see Section 2.2.1.
Figure 2-3. Map of Wells Generating Oil and Gas Wastewater in Pennsylvania, Excluding
Stripper Wells (2016)
Table 2-3 summarizes data primarily for wastewater production and discharge to
POTWs for the same wells depicted in Figure 2-3 (excludes stripper wells). Table 2-3 breaks out
the data by EPA resource type, with "COG" representing wells that are conventional according
to the 2016 UOG rule's definitions; "UOG" representing wells that are unconventional according
to the 2016 UOG rule's definitions; and "Not Reported" representing those wells where the
resource type was not reported by operators but were considered unconventional for purposes of
EPA's analysis. Out of the 879 operators producing oil and gas in Pennsylvania in 2016, 22
reported discharging UOG wastewater and/or "Not Reported" wastewater to POTWs.3 Since
these are the operators that would potentially incur costs to comply with the UOG rule (including
the "Not Reported" category, because EPA, at this time, cannot determine if it is unconventional
or conventional and so conservatively categorized it as unconventional for purposes of this
analysis), EPA's additional analyses focused on these 22 operators.
5 12 out of the 13 operators that reported discharging "Not Reported" wastewater also discharged UOG wastewater.
The 2 operators that reported discharging COG wastewater to POTWs in 2016 also reported discharging UOG
wastewater from their wells to POTWs in 2016.
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Table 2-3. PA DEP Waste Data for Oil and Gas Wells in 2016
EPA
Resource
Type
Operators Producing Oil and Gas
Operators Generating
Wastewater (excludes stripper
wells)
Discharges
to POTWs (excludes stripper wells)
Number of
Operators
Number of
Wells
Producing
Oil and Gas
Wastewater
Volume
Generated
(bbls)
Number of
Operators
Number of
Wells that
Generated
Wastewater a
Wastewater
Volume
Generated
(bbls)
Number of
Operators
Discharging
to POTWs
Number of
Wells
Discharging
to POTWs a
Wastewater
Sent to
POTWs
(bbls)
COG
Not analyzed by EPA
68
1,439
591,255
2
4
200
UOG
191
14,159
25,555,262
21
795
53,361
Not
Reported
84
910
114,165
13
164
7,882
Totals
879
80,658
30,580,866
209 b
16,508
26,260,681
22 b
(10.5%)c
963
(5.8%)c
61,443
(0.2%)c
Source: PA DEP Databases, see Section 2.2.1.
a—These wells are shown as dots in Figure 2-3.
b—Totals do not equal the sum of operators as operators generate more than one type of wastewater,
c—Percentages based on the operators generating wastewater in 2016 (middle section of table).
2.2 Overview of Data Sources for New BAT Analysis
Once EPA determined the entities that may incur cost to comply with the UOG rule, EPA
used the following additional sources to re-analyze whether the zero discharge requirements in
the UOG rule are technologically available, economic achievable, and have acceptable non-water
quality impacts within the meaning of the CWA.
2.2.1 Databases
EPA also used the PA DEP Production and Waste Reports in combination with the DI
cross-reference database described above to create a master database (PA DEP and DI cross-
reference database - DCN SGE01418) to use for production data, formation data (where
available, see section above), and wastewater management information. For details on how EPA
refined the data sources, see Appendix A. This information was particularly helpful in
identifying the wastewater management practices currently used by wells in Pennsylvania
(POTWs, CWT facilities, disposal wells, etc.)
2.2.2 Detailed Study of CWT Category for Facilities Managing Oil and Gas Extraction
Wastes
EPA conducted a study of CWT facilities accepting oil and gas extraction wastewater
from 2014 to 2017, which included information on CWT facilities in Pennsylvania that accept
such wastewater and their associated costs.
2.2.3 Clean Water Act Section 308 Letters
EPA used information from selected operators on wastewater management costs and their
ftnancials to assess the financial impacts of the final rule on entities that likely need to make
changes to comply with the 2016 UOG rule (affected entities). EPA requested information from
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nine Pennsylvania oil and gas operators through an information request pursuant to Section 308
of the Clean Water Act to augment data available from publicly available sources.
2.2.3.1 Entity Selection Criteria
As described above, EPA identified entities that operated UOG wells and discharged
wastewater to POTWs in 2016 and therefore may experience financial impacts from the UOG
rule. EPA evaluated if a census of all entities would be necessary to assess those impacts. EPA
reviewed information about the entities and found that there was enough similar about these
entities a census was not needed. For example, since all of the entities are small businesses (less
than 1,250 employees), there would be enough similarity in their financial portfolios, that a
response from some of the entities could be extrapolated to all of the entities reasonably so (i.e.,
an entity with 1,300 employees has a different corporate structure than an entity with 10
employees). Another example is that all of the entities were located in Pennsylvania, and so a
response from some of the entities could be extrapolated to all of the entities reasonably so (i.e.,
if the entities were located in different states, they may need to meet different state fees or
different tax structures and so EPA would need a census of the entities to accommodate the
differing tax structures in order to best understand financial impacts of the UOG rule). Using this
reasoning, that entities were similar enough that with only information from some entities, EPA
could use that to model the other entities appropriately for purposes of this analysis, in addition
to EPA's desire to minimize burden on the industry (and thereby, request only the information
that is needed), EPA determined it did not need a census. Rather, EPA elected to use its authority
under Section 308 of the CWA to collect information from nine or fewer entities to support its
current analyses
To obtain information across a diverse set of entities and to capture enough costing
information for wastewater management, EPA ranked the entities based on several factors, with
equal weight given to each factor (DCN SGE01433):
• Number of wells discharging to POTW.
• Volume of wastewater being sent to POTWs.
• Estimated Revenue of all wells.
• Estimated Revenue of wells discharging to POTWs.
• Estimated incremental costs.
• Volume of wastewater being sent to CWT facilities.
EPA sent letters, including data requests, to the nine top ranked entities based on these
factors. Since the entities ranked in the top nine category had wastewater volumes an order of
magnitude higher than entities ranked lower, EPA wanted to capture any wastewater
management decisions that may differ because of significant wastewater volume differences
across the entities (e.g., EPA didn't know if an entity with higher wastewater volume may have
longer term contracts with trucking entities than an entity with lower wastewater volume, thereby
having an effect on their business decisions that may warrant a different modelling structure in
EPA's analysis), so EPA substituted two of the top entities with two lower ranked entities to
make the data more representative of all entities.
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To reduce the response burden, EPA asked a limited number of questions (six). Also,
EPA followed up with the recipients to answer any questions or provide further data, as needed
(DCN SGE01434). Eight of the nine entities responded.
1.2.2.2 Engineering, Cost, and Production Information
In order to assess the incremental cost of the rule, EPA requested recipients to report
wastewater volumes generated, wastewater management employed, and associated costs. To
reduce burden to respond to this request, EPA summarized the quantity of oil and gas wastewater
generated from wells and transferred to POTWs, CWT facilities, or disposal wells as reported to
PA DEP (described above) for reporting periods 2013 through 2016. EPA asked entities to verify
this information and to also provide information on associated costs for 2013-2016. EPA
requested the following information related to wastewater management costs from those entities
that received EPA's data request:
• Any payment to any wastewater management facility (e.g., payment to a
POTW, CWT facility, or disposal well) for wastewater management cost
(overall cost and $ per barrel).
• Transportation costs to any wastewater management facility.
• Metric upon which the facility is billed for transportation costs (e.g., $ per
mile, $ per hour).
EPA did not request costs for all aspects of wastewater management because (1) EPA
was minimizing respondent burden, and (2) EPA found it reasonable to make assumptions on
certain wastewater management baseline costs (i.e., EPA already had cost information on some
aspects of wastewater management (e.g., renting tanks for temporary storage) from site visits and
call records from the 2016 UOG rule record and the 2017 CWT study record), further described
below. This production, wastewater management, and cost data provide key information for the
baseline and post-compliance cost analysis presented in Section 2.
To further verify the datasets from Pennsylvania with more current information, EPA
requested each entity provide the total number of wells nationwide and in Pennsylvania as of
January 1, 2018. Three of the eight facilities provided corrected information on the quantity of
wastewater they had reported in Pennsylvania's datasets. EPA used this corrected quantity of
wastewater in its analyses. Once EPA was made aware of these corrections, EPA noted two other
entities that may have misreported their data to Pennsylvania. EPA contacted PA DEP regarding
these two entities' wastewater data, who followed up with both, confirming the need to correct
the quantity of wastewater reported. These two entities subsequently resubmitted corrected 2016
data to PA DEP database (DCN SGE01450; DCN SGE01451). Those corrections are reflected in
the PA DEP online database and in EPA's analyses.
1.2.2.3 Entity Financial Information
EPA collected financial information to assess economic achievability of the rule. EPA
solicited the following financial data for the year 2016:
• Revenue attributable to oil operations.
• Revenue attributable to gas operations.
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• Other revenue.
• Operating costs attributable to oil operations (not including wastewater
management costs).
• Operating costs attributable to gas operations (not including wastewater
management costs).
• Depreciation.
• Impact fees paid to Pennsylvania Public Utility Commission.
• Other costs.
• Interest.
• Federal and state income taxes.
Six entities responded with these data items; the remaining two provided their federal tax
return for 2016 instead. In addition, EPA requested total employment to confirm if the small
business threshold is met, and oil and gas threshold prices, if they existed, below which the
facility would cease oil or gas operations.
The financial data listed above provide key information for the baseline and post-
compliance financial analysis presented in Section 4. In addition, EPA used this data to model
the non-surveyed entities that are expected to incur compliance costs under the rule.
2.2.4 Locational A nalysis
In order to determine the closest wastewater management alternative (for purposes of this
analyses: CWT facility or disposal well) instead of a POTW, EPA used the well locations to
conduct a GIS analysis for each 2016 UOG rule defined UOG well discharging to POTWs in
2016. Specifically, EPA used ArcGIS Online to calculate the driving distances and times from
the well locations to the POTWs as a baseline. Next, EPA used ArcGIS Online to calculate
driving distances and times from the wells to the nearest CWT facilities and disposal wells using
the "Find Nearest" tool, optimized using the "Trucking Time" function. EPA used the driving
distances and times generated by the GIS Analysis to calculate the transportation cost component
of the Alternative Wastewater Management Analysis.
2.2.5 Oil and Gas Prices, and Other General Financial Information
In addition to the financial data received in the response to EPA's data request, EPA also
used EIA data on historical West Texas Intermediate (WTI) crude oil spot prices (DCN
SGE01439), Pennsylvania crude oil first purchase prices (DCN SGE01441), and Henry Hub
natural gas spot prices (DCN SGE01440); EIA Annual Energy Outlook WTI (DCN SGE01438)
and Henry Hub price projections (DCN SGE01437); and the Bureau of Economic Analysis GDP
price deflator index (DCN SGE01436). The use of these data is discussed in more detail in
Sections 4.2 and 4.3.
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3.
ALTERNATIVE WASTEWATER MANAGEMENT ANALYSIS
This section describes in detail the methodology EPA used to determine the facilities that
will likely need to make changes to comply with the 2016 UOG rule, the available alternatives,
and the incremental costs associated with those alternatives.
3.1 Alternative Wastewater Management Analysis
Figure 3-1 illustrates the steps EPA used to conduct the Alternative Wastewater
Management Analysis using the data sources described in Section 2.2. Each of these steps is
described below with additional detail.
©
©
©
©
O&G Production Data
Waste Data
Formation information
and location
Facility
Locations
Facility Names
Nearest Waste
Facility Alternative
Management
and
Transportation
Costs
(10)
Analysis
Data Source
Legend:
DCN SGE01420
EDWIN
Cost Data from 308 Letters
DCN SGE01407 - SGE01415
Access Database
DCN SGE01170
Dl Desktop1
Cost Data from Other
Sources
PA DEP Formation
Database and Spud Data
Excel Files
DCN SGE01375
DCN SGE01246
List of Aiternative Waste
Facilities-CWT Facilities
and Disposal Wells
PA DEP Waste Reports and
PA DEP Production Reports
CSVfiles
DCN SGE01421
DCN SGE01422
Generated from ArcGIS Online
GIS Analysis
UOG Alternative
Wastewater Management
Cost Analysis
Excel File
DCN SGE01419
PA DEP and Dl Cross-
Reference Database
Access Database
DCN SGE01418
PA DEP Waste Reports and
O&G Production
Development Databases
Access Databases
DCN SGE01416
DCN SGE01417
Figure 3-1. UOG Alternative Wastewater Management Analysis Work Flow Diagram
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3.1.1 Step 1 — PA DEP Waste and Production Reports
EPA downloaded individual PA DEP Waste Reports and PA DEP Production Reports in
comma separated values (CSV) files for 2004 through 2016 on February 12, 2018 and January 8,
2018, respectively. Table A-l in Appendix A lists and describes the report fields.
3.1.2 Step 2 — Prepare PA DEP Waste and Production Report Development Databases
EPA developed Access databases to compile and store the individual PA DEP Waste and
Production Report CSV files downloaded from PA DEP's website (Step 1), and to prepare the
data for subsequent analyses. EPA developed and populated the databases using a series of
Access queries described in Tables A-2 and A-3 in Appendix A for the PA DEP Waste and
Production Reports, respectively.
The PA DEP Waste Reports include a variety of naming conventions, spelling errors, and
missing information. Two of the database development queries function to correct and
standardize the Waste Type, Waste Disposal Method, Waste Facility Name, and Waste Facility
Permit Number fields to facilitate subsequent data analysis. EPA created two consolidation
crosswalk tables to execute the data standardization queries. Table 3-1 shows a small subset of
the >2,000 entries from the crosswalk tables to illustrate the data standardization. For example,
reported waste types such as "Drilling Fluid" and "Drilling" were standardized in the
Consolidated Waste Type field as "Drilling wastewater," and reported facilities names such as
"Mccutcheon Enterprise," "Mccutcheon Enterprises Inc," and "Mccutcheon Enterprises, Inc."
were standardized in the Consolidated Waste Facility Name field as "Mccutcheon Enterprise." In
some cases, EPA used best professional judgment to standardize the data fields. For example,
one of the records in Table 3-1 reports "Municipal Sewage Treatment Plant" as Disposal Method
and "Mccutcheon Enterprises, Inc." (a known CWT facility) as Waste Facility Name. In this
example, EPA populated the Consolidated Disposal Method as "CWT Facility" for this record.
EPA included the complete consolidation crosswalk tables within the PA DEP Waste
Development Database (DCN SGE01416).
3.1.3 Steps 3 and 4 — Prepare PA DEP and DI Cross-Reference Database and Identify
Wells/Entities that Will Likely Incur Costs
EPA developed the PA DEP and DI Desktop® Cross-reference Database (Step 4) to
identify the subset of wells that likely need to make changes to comply with the 2016 UOG rule
(those discharging to POTWs in 2016 and that meet the 2016 UOG rule's definition of UOG).
Specifically, the database links the waste and production data from the PA DEP Waste and
Production Report Development Databases, which are used to identify those wells that
discharged to POTWs in 2016, with formation and location data from other data sources (Step
3), which are used to identify those wells that meet the 2016 UOG rule's definition of UOG.
The PA DEP and DI Desktop® Cross-reference Database (DCN SGE01418) also
prepares the well data that EPA included in the industry data requests (discussed in Section 0)
and to populate well location data used in the GIS Analysis (Step 6).
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Table 3-1. Example Crosswalk of PA DEP Waste Facility Record Standardization
Report Fields, As Reported by Operators
Report Fields, As Standardized by EPA
Reported
Waste Type
Reported Management
Method
Reported Waste
Facility Name
Reported Waste
Facility Permit
Number
Consolidated
Waste Type
Consolidated
Management
Method
Consolidated Waste
Facility Name
Consolidated
Waste Facility
Permit Number
Drilling Fluid
Centralized Treatment Plant
For Recycle
Mccutcheon
Enterprise
PADO13 826847
Drilling
wastewater
CWT Facility
Mccutcheon Enterprise
PAD013826847
Drilling
Centralized Treatment Plant
For Recycle
Mccutcheon
Enterprises Inc
PAD013826847
Drilling
wastewater
CWT Facility
Mccutcheon Enterprise
PAD013826847
Frac Flowback
Residual Waste Transfer
Facility
Mccutcheon
Enterprises Inc
PAD013826847
Flowback
CWT Facility
Mccutcheon Enterprise
PAD013826847
Fracking Fluid
Municipal Sewage
Treatment Plant
Mccutcheon
Enterprises, Inc.
a
Flowback
CWT Facility
Mccutcheon Enterprise
PAD013826847
Drilling Fluid
Public Sewage Treatment
Plant
Dornick Point
Wwtp
PA0026034
Drilling
wastewater
POTW
Johnstown STP
PA0026034
Drilling Fluid
Public Sewage Treatment
Plant
Johnstown Sewage
Treatment Plant
PA0026034
Drilling
wastewater
POTW
Johnstown STP
PA0026034
Drilling
Brine Or Industrial Waste
Treatment Pit
Johnstown Stp
a
Drilling
wastewater
POTW
Johnstown STP
PA0026034
Brine
Municipal Sewage
Treatment Plant
Johnstown Stp
a
Long-term
produced water
POTW
Johnstown STP
PA0026034
Produced Fluid
Reuse Other Than Road
Spreading
Johnstown Stp
a
Long-term
produced water
POTW
Johnstown STP
PA0026034
Drilling Fluid
Brine Or Industrial Waste
Treatment Pit
Ridgeway Borough
a
Drilling
wastewater
POTW
Ridgeway Borough STP
PA0023213
Drilling Fluid
Centralized Treatment Plant
For Recycle
Ridgway Borough
Sewage Plant
PA0023213
Drilling
wastewater
POTW
Ridgeway Borough STP
PA0023213
Drilling Fluid
Public Sewage Treatment
Plant
Ridgway Borough
Sewage Treatment
Plant
PA0023213
Drilling
wastewater
POTW
Ridgeway Borough STP
PA0023213
Brine
Injection Disposal Well
Carper Well Svc
Biyane Smith 1
34-121-23390
Long-term
produced water
Underground
Injection
N/A
N/A
Produced Fluid
Centralized Treatment Plant
For Recycle
Carper Well Svc
Biyane Smith 1
34-121-23390
Long-term
produced water
Underground
Injection
N/A
N/A
N/A - Not applicable; EPA did not standardize disposal well facility names or permit numbers.
a—No permit number was reported for these records. EPA assigned the correct permit number during data consolidation.
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EPA's primary data source for formation data is DI Desktop®; Table A-4 in Appendix A
lists and describes the DI Desktop® fields. Where formation data are unavailable from DI
Desktop®, EPA supplemented with formation data from PA DEP's Formation and EDWIN
Databases. Data sources for well location include the PA DEP Waste and Production Reports, DI
Desktop®, and PA DEP SPUD data.
EPA developed and populated PA DEP and DI Desktop® Cross-reference Database
using a series of Access queries described in Table A-5 in Appendix A. In summary, the queries
perform the following actions:
1. Compiles data from applicable data sources (PA DEP Waste and Production
Report Development Databases, DI Desktop®, PA DEP Formation Database, PA
DEP SPUD Data, EDWIN) using Well API number as the link.
2. Populates well formation names using formation names from DI Desktop®.
Where well formation names are blank in DI Desktop®, populates well formation
names using formations names from the PA DEP Formation Database.
3. Identifies those formations that are "Tight" or "Shale" using publications by EIA
listing known tight and shale formations. This includes two maps published be
EIA: Major Tight Gas Plays, Lower 48 States (Figure 2-1) and Shale Gas Plays,
Lower 48 States (Figure 2-2), and EIA's Assumptions to the Annual Energy
Outlook 2015 (Table 2-1 and Table 2-2).
4. Determines and identifies UOG, COG, and Unreported wells based on the 2016
UOG rule's definitions of these terms. Specifically:
a. The 2016 UOG rule defined Unconventional Wells
The 2016 UOG rule defined UOG wells are those that PA DEP
categorized as UOG, as well as those with a reported formation name that
identified as Tight or Shale (even if PA DEP categorized them as
conventional).
b. The 2016 UOG rule defined Conventional Wells
The 2016 UOG rule defined COG wells are those that PA DEP did not
define as UOG and that were not identified as either Tight or Shale based
on formation name.
c. Not Reported Wells
Not reported wells are those that PA DEP did not define as UOG and that
lack formation names from DI Desktop®, PA DEP Formation, and
EDWIN Databases. EPA considered these wells as UOG wells in its
analysis to be conservative. This assumption could result in over-
estimation of the incremental compliance costs attributable to these wells,
as some may not be 2016 UOG rule defined UOG wells.
5. Populates well location (latitudes and longitudes) using the following hierarchy of
data sources:
a. PA DEP Waste and Production Report data. These reports provided
latitude and longitudes for approximately 95% of wells generating
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wastewater in 2016. It is EPA's preferred data source because it's publicly
available.
b. DI Desktop®. This supplemental data source provided locations for
approximately 2% of wells generating wastewater in 2016.
c. PA DEP SPUD Data. This supplemental data source provided locations
for less than 1% of wells generating wastewater in 2016.
d. Average Farm location. For those wells that lacked location data from the
previous data sources, EPA calculated and populated the average location
of all wells located within the same farm as identified by the PA DEP
Waste Reports (see Appendix A for data fields). EPA used this
methodology to maximize that number of wells modeled by the GIS
Analysis (Step 5) and ultimately included in its analysis. EPA estimated
locations for less than 1% of wells generating wastewater in 2016 using
this methodology.
e. Average Municipality location. For those wells that lacked location data
from the previous data sources, EPA calculated and populated the average
location of all wells located within the same municipality and county,
regardless of the operator, as identified by the PA DEP Waste Reports (see
Appendix A for data fields). EPA used this methodology to maximize that
number of wells modeled by the GIS Analysis (Step 5) and ultimately
included in its analyses. EPA estimated locations for approximately 2% of
wells generating wastewater in 2016 using this methodology.
6. Identifies the oil and gas operators and wells in Pennsylvania that discharged to
POTWs in 2016 and that meet the 2016 UOG rule's definition of UOG in 40 CFR
435 Subpart C. Collates summary information about these operators such as
number of active wells, other wastewater management practices, and oil and gas
production.
3.1.4 Step 5 — Develop List of Wastewater Management Alternatives to POTWDischarge
EPA prepared an initial list of CWT facilities and disposal wells6 accepting all oil and
gas extraction wastewater by reviewing the Disposal Method and Waste Facility Name fields in
the PA DEP Waste Reports for 2016 and 2017 (i.e., EPA started with a list of only CWT
facilities and disposal wells that all operators in Pennsylvania reported themselves as using in
2016 and 2017). EPA developed the final list of alternative wastewater management facilities by
removing those known to have shut down, accept only small volumes of wastewater, or that
otherwise lack capacity to receive additional wastewater. For example, EPA conservatively
removed all Pennsylvania disposal wells from the list of available alternative facilities because
6 In addition to CWT facilities and disposal wells, the 2016 UOG rule listed recycle/reuse as one of the wastewater
management alternatives to POTWs. EPA did not analyze the costs for recycle/reuse as an alternative to
management at POTWs because EPA would need to know information such as the future exploration and
production plans for operators and the associated wastewater demand for activities such as drilling. EPA expects that
the cost of recycle/reuse would be less than or comparable to management at POTWs, particularly if water is reused
close to where it is produced. In addition, recycle/reuse offsets the need to purchase fresh water resulting in potential
additional savings for operators. Also, to a certain extent recycle/reuse is captured within the CWT facility option as
some portion of wastewater managed at some CWTs is reused by other operators.
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they may not have capacity to accept additional UOG wastewater. EPA made these adjustments
to ensure that wastewater management alternatives are available. Finally, EPA reviewed the cost
model outputs to confirm that reception facilities have enough capacity to receive the modeled
wastewater volumes (see correspondence with facilities for capacity questions: DCN SGE01452
and DCN SGE01453). EPA received information from PGCC noting that some specific
wastewater management facilities were unavailable to at least some portion of the operators that
likely need to make changes to comply with the UOG rule (DCN SGE01494). In response, EPA
reviewed again the 2016, 2017 and newly available 2018 data and identified several operators,
categorized as conventional under Pennsylvania's definition and categorized as unconventional
under the 2016 UOG rule's definition, that were sending their wastewater to said facilities (DCN
SGE01494). Table 3-2 and Table 3-3 list the CWT facilities and disposal wells, respectively, that
EPA used in this analysis (DCN SGE01419).
Table 3-2. Available CWT Facilities
Waste Facility Name or Operator
Permit Number
Facility
City
Facility
State
Latitude
Longitude
CARES McKean (Now Highland Field
Services)
4212201;
WMGR123NW005
McKean
County
PA
41.661944
-78.636667
Fluid Recovery Service, Josephine
PA0095273
Josephine
PA
40.482583
-79.171882
Hydro Recovery (Burgettstown)
WMGR123SW019
Burgettsto
wn
PA
40.420084
-80.418137
Fluid Recovery Service, Franklin
PA0101508
Franklin
PA
41.37292
-79.798357
Mccutcheon Enterprise
PAD013826847
Apollo
PA
40.588989
-79.61189
Green County Water Treatment, LLC
WMGR123SW010
Telford
PA
39.908288
-80.141133
Reserved Environmental Services (Butler)
WMGR123NW009
Renfrew
PA
40.813222
-79.936506
Hydro Recovery (Antrim)
WMGR123NC010
Wellsboro
PA
41.644016
-77.285987
4K Martins Ferry Facility
OH0011339
Martins
Ferry
OH
40.100216
-80.712527
Reserved Enviromnental Services (Mount
Pleasant)
WMGR123SW005
PA0254185
Mount
Pleasant
PA
40.160788
-79.55889
Cleannont Storage Facility
WMGR123NW011
PA
41.619444
-78.426389
Riverside Park Recycling Facility (Buckeye
Brine)
ORDER 2014-04
UHRICHS
VILLE
OH
40.38616
-81.394476
PETTA Enterprises - Cambridge Facility
ODNR 2015-29
Cambridge
OH
40.035077
-81.599078
Fairmont Brine
WVR000521948
wv
39.507345
-80.126338
Appalachian Water Services Lie (also
Shallenberger Construction/Ronco Facility)
PA0253723;
WMGR123SW001
Masontown
PA
39.853611
-79.924722
Eureka Resources (Standing Stone)
WMGR123NC018
Standing
Stone
PA
41.745748
4
-76.350338
Eureka Resources (Williamsport 1)
WMGR123NC005;
WMGR119
Williamspo
rt
PA
41.237689
-77.008517
Fluid Recovery Service, Kingsley
WMGR123NE004
PA
41.701128
-75.674304
Hydro Recovery (Blossburg)
WMGR123
Blossburg
PA
41.671495
-77.073048
Source: DCN SGE01419.
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Alternative Wastewater Management Analysis
Table 3-3. Available Disposal Wells
Waste Facility Name or Operator
Permit
Number
Facility City
Facility
State
Latitude
Longitude
MONROE #1
34-007-24523
WOOSTER
OH
41.8200300
-80.5445400
KLEESE #1 (SWIW #18)
34-155-21438
VIENNA
OH
41.2392500
-80.6385600
NORTHSTAR LUCKY #4 (SWIW #12)
34-099-23158
NORTH
LIMA
OH
40.9627400
-80.6636300
CLEARWATER 111 (SWIW #15)
34-059-2-3986
CAMBRIDGE
OH
40.0273000
-81.5111700
RE-HYDRO #1 (SWIW #10)
34-157-25506
DENNISON
OH
40.4084240
-81.2953570
RITCHIE HUNTER WATER
DISPOSAL (GREEN HUNTER)
2D0859721
ELLENBORO
wv
39.2584280
-81.0999970
PETROWATER INC.
3192
JEFFERSON
OH
41.6808130
-80.7222390
RENSHAW / BRADNAN #1 (B&R)
DISPOSAL WELL
34-007-20919
PIERPOINT
OH
41.7678570
-80.5696940
RHOA #3 (SWIW #8)
34-007-21847
JEFFERSON
OH
41.6132130
-80.7828350
CLINTON OIL CO UNIT 1-973
(SWIW #30)
34-007-2-3097
GARRETTSV
ILLE
OH
41.5615100
-80.9932300
CLINTON OIL #2 (SWIW #21)
34-007-23262
GARRETSVI
LLE
OH
41.2878680
-81.0960960
MILLER & CO #1 (SWIW #32)
34-007-2-3692
GARRETTSV
ILLE
OH
41.5540600
-80.9903000
MILLER & CO #3 (SWIW #28)
34-007-24355
GARRETTSV
ILLE
OH
41.5532790
-80.9914540
K & H PARTNERS LLC #1 (SWIW #8)
34-009-23821
COOLVILLE
OH
39.2260800
-81.7614000
ADAMS #1 (SWIW #10)
34-031-27177
COSHOCTON
OH
40.3008300
-81.8481800
DEVCO UNIT #1 (SWIW #11)
34-059-24067
CAMBRIDGE
OH
39.9412800
-81.6737900
SOS-D #1 (SWIW #12)
34-059-24202
CAMBRIDGE
OH
39.9936100
-81.5729700
ROSCOE MILLS #1 (SWIW #19)
34-105-23619
MEIGS
OH
38.9404800
-81.7875900
GOFF #1 (SWIW #27)
34-119-28776
NORWICH
OH
39.9773700
-81.8069000
KEMBLE #1-D (SWIW #28)
34-119-28780
NORWICH
OH
39.9749500
-81.8453900
PATTISON TRUST # 1-D (SWIW #30)
34-119-28803
NORWICH
OH
39.9736400
-81.8257300
WARREN DRILLING CO #1 (SWIW
#6)
34-121-23995
DEXTER
CITY
OH
39.6538100
-81.4753100
WILCOX #1
34-133-20114
ROOTSTOW
N
OH
41.0960300
-81.1995400
BLAZF.K #2 SWIW
34-133-20525
HIRAM
OH
41.3312000
-81.1842300
MYERS #1 UNIT (SWIW #31)
34-133-21076
ATWATER
OH
41.0762170
-81.1392560
MILLER #1 DISP WELL
34-133-22523
WINDHAM
OH
41.2522200
-81.0204700
PLUM CREEK #1 DISPOSAL WELL
34-133-23614
KENT
OH
41.1050900
-81.3584000
GROSELLE INECTION WELL # 2
34-133-24096
GARRETTSV
ILLE
OH
41.3458800
-81.0897800
MEYERS #2 (SWIW #33)
34-133-24189
ATWATER
OH
41.0756000
-81.1429400
SOINSKI #1 (SWIW # 37)
34-133-24462
WINDHAM
OH
41.2586300
-81.0246000
BELDEN & BLAKE WELL # 2
34-151-23420
HARTVILLE
OH
40.9502500
-81.2488500
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Alternative Wastewater Management Analysis
Table 3-3. Available Disposal Wells
Waste Facility Name or Operator
Permit
Number
Facility City
Facility
State
Latitude
Longitude
WOLF #1 DISP WELL
34-155-21893
NEWTON
FALLS
OH
41.2025900
-80.9989800
WOLF #2 DISPOSAL WELL
34-155-21894
NEWTON
FALLS
OH
41.1985200
-81.0006400
ANNAROCK D-l
34-155-22403
FOWLER
OH
41.3156900
-80.6184900
NATALE #1 (SWIW #28)
34-155-23196
WARREN
OH
41.2683500
-80.8915300
WOLF #4 DISPOSAL WELL
34-155-23203
NEWTON
FALLS
OH
41.2022380
-81.0023580
NATALE #2 (SWIW #29)
34-155-23223
VIENNA
OH
41.2649100
-80.8914300
PANDER R & P #2 (SWIW #16)
34-155-2-3794
NEWTON
FALLS
OH
41.1987700
-80.9940800
PANDER #1 (SWIW #15)
34-155-23795
NEWTON
FALLS
OH
41.2003850
-80.9917880
JOHNSON DISPOSAL #1
34-155-24063
NORTH
BLOOMFIEL
D
OH
41.4623100
-80.7219800
B & J NO 1 INJECTION (SWIW #33)
34-155-24079
VIENNA
OH
41.2492080
-80.6649740
DENNISON DISPOSAL 1 (SWIW #11)
34-157-25507
DENNISON
OH
40.4075400
-81.3117100
MOZENA #1 (SWIW #13)
34-157-25511
NEWCOMER
STOWN
OH
40.2832900
-81.5780700
NICHOLS #1 (SWIW #13)
[HECKMAN WATER RES(CVR)INC]
34-167-23862
BELPRE
OH
39.3478700
-81.5906800
VOCATIONAL SCHOOL #2 (SWIW
#20)
34-167-29543
MARIETTA
OH
39.4262780
-81.5023790
VOCATIONAL SCHOOL UNIT #2
(SWIW#20)
34-167-2-9543
MARIETTA
OH
39.4262800
-81.5023800
Source: DCN SGE01419.
3.1.5 Step 6 — GIS Analysis
EPA conducted an analysis to determine the proximity of each of the UOG wells that
discharged to POTWs (developed in Step 4) to alternative wastewater management practices
consisting of CWT facilities and disposal wells. EPA conducted this analysis using ESRI ArcGis
Online and used ESRI's built-in analysis tools for calculating distance and travel time between
locations. The analysis components are as follows:
1. EPA created GIS layers containing the latitude/longitude of the analysis entities:
2016 UOG rule defined UOG wells discharging to POTWs; POTWs receiving
wastewater from UOG wells; disposal wells, and CWT facilities.
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Alternative Wastewater Management Analysis
2. Using the "Proximity" analysis tool, and the "Find Nearest7" function, EPA
determined the shortest trucking time, and the associated trucking distance,
between each UOG well and the POTW that accepted wastewater from that well.
3. EPA repeated this process for each well to determine the closest (measured by
trucking time) CWT facility and the closest disposal well.
4. EPA generated and exported Results files containing the closest alternative
management options to Excel for further analysis in Step 8 (see Table A-6 in
Appendix A for a list of results files generated).8
Figure 3-2 shows the location of the UOG wells of interest (in orange), the four POTWs
that received wastewater from these wells (in blue), available CWT facilities (in green) and
available Class II disposal wells (in black). EPA notes that eight entities used only a POTW to
manage their wastewater in 2016; the remaining 14 entities used alternative wastewater
management approaches in addition to POTWs in 2016.
As an example of one of the steps of the analysis, Figure 3-3 shows the trucking routes
from each UOG well (in orange) to the Reynoldsville POTW for the subset of wells that
discharge to the Reynoldsville POTW.
7 This function: "Models basic truck travel by preferring designated truck routes and finds solutions that optimize
travel time. Routes must obey one-way roads, avoid illegal turns, and so on. When you specify a start time, dynamic
travel speeds based on traffic are used where it is available, up to the legal truck speed limit. Follows rules
applicable to heavy trucks." (DCN SGE01485)
8 The analysis toolkit using ArgGIS online is limited to 1,000 entities per run, so the Ridgeway dataset was broken
into three subsets for GIS analysis purposes.
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Alternative Wastewater Management Analysis
m
A
Legend
it potw
~ CWT Facility
¦ Disposal Well
Discharging UOG Wells
25
50
100
Miles
Source: PA DEP Databases, see Section 2.2.1
Figure 3-2. Wastewater Management Alternatives Used in EPA's Analysis and EPA-
defined UOG Wells Discharging to POTWs in Pennsylvania in 2016
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Supplemental Technical Support Document for the ELGs
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Alternative Wastewater Management Analysis
ojriuy !«(.'
Suniivfciyllts
Knox T«vp
Rockton
Cbote-pflpQ"
Bloofo Tap
.mawrey
3UK.
kmNlMI
m&a
Glen Campbell
Center
Cl»es1 Twp
Hilfcdale
Legend
~ POTW
Home
0^ch».*ging UOG W«lts
Trucking Routes
Figure 3-3. Example GIS Analysis Trucking Routes from Wells to Reynoldsville POTW
3.1.6 Step 7 - Cost Data Compilation
Wastewater Management Cost ($ bhl) Compilation
Oil and gas operators provided their wastewater management costs for POTWs, CWT
facilities, and disposal wells in their responses to EPA's data request. Operators typically
reported these costs in units of dollars per barrel ($/bbl). EPA also extracted available
information on costs that CWT facilities charge to treat oil and gas wastewater (cost data) from
reports EPA prepared from meetings or site visits to CWT facilities and oil and gas operators
from the Detailed Study of the CWT Category for Facilities Managing Oil and Gas Extraction
Wastes (2017) and the UOG final rule (2016). The sources of all wastewater management cost
data used in the analysis are identified within Step 8 and these sources are available in the UOG
rulemaking record. EPA calculated the average wastewater management cost ($/bbl) for each
POTW, CWT facility and disposal well, using available site-specific cost data. For facilities that
lacked site-specific cost data, EPA used the average cost for all facilities of the same type. For
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Alternative Wastewater Management Analysis
example, if EPA lacked cost data for a specific CWT facility, then EPA used the average cost for
all CWT facilities.
Transportation Cost Data Compilation
Oil and gas operators provided their wastewater transportation costs in their responses to
EPA's data requests. EPA used the components defined below the equations to calculate a
trucking cost factor in units of $/bbl/hr. EPA used Equation 1 to calculate Truck Load Hours
(hours), assuming a Truckload Capacity of 100 bbl of wastewater per truck. EPA completed a
GIS analysis to determine the Estimated Driving Time (min) (See Step 6 for more detail). EPA
used these data (i.e., weighted average of 2013 - 2017 data for all 7 operators who responded to
data request letters) and Equation 2 to develop a trucking cost factor of $3.35 $/bbl/hr. EPA used
this trucking cost factor for EPA's analysis. A step-by-step description of the transportation cost
assumptions and calculations can be found in the "Cost Assumptions and Calcs." worksheet in
the Alterative Wastewater Management Analysis (DCN SGE01419).
Equation 1
Truck Load Hours = Estimated Driving Time (min) x (1 hr / 60 min) / (Vol WW (bbl) / Truckload
Capacity)
Equation 2
Trucking Cost Factor = Annual Transp Cost / Vol WW / Truck Load Hours x
Total Number Truck Loads
where:
Annual Transp Cost
($)
Vol WW (bbl)
Truck Load Hours
(hours)
Total Number Truck
Loads (trucks)
Annual transportation cost reported by an operator for a
specific waste facility (e.g., a POTW, a CWT facility, or a
disposal well) they used between 2013 to 2017.
Volume of wastewater generated by a specific well and
sent to a specific waste facility (e.g., a POTW, a CWT
facility, or a disposal well) between 2013 and 2017.
Number of driving hours per truck required by an operator
to send wastewater to a specific waste facility (e.g., a
POTW, a CWT facility, or a disposal wells) (2013-2017).
Vol WW (bbl) divided by Truckload Capacity, which EPA
assumed to be 100 bbl of wastewater per truck.
3.1.7 Step 8— UOG Alternative Wastewater Management Analysis - Baseline Costs
In order to model all operating costs for each entity for the economic analysis (Section 4),
EPA chose to estimate all costs for an entity, even those costs not associated with wastewater
going to a POTW. Therefore, if an entity was identified as sending any of their 2016 UOG rule
defined UOG wastewater to a POTW, EPA chose to estimate all of the costs that entity incurred
for all of their wastewater management portfolio, including all wastewater management
approaches used (e.g., storage). As can be seen in the UOG Alternative Wastewater Management
Analysis (DCN SGE01419), many entities sent their wastewater to more than just POTWs. EPA
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Alternative Wastewater Management Analysis
prepared the UOG Alternative Wastewater Management Analysis spreadsheet (DCN SGE01419)
to estimate the baseline costs incurred by the entity identified in Step 4 to manage all of their
wastewater generated in 2016, regardless of management method. EPA developed and populated
the spreadsheet as described in Table A-7 in Appendix A. The assumptions are described below:
Baseline Transportation Costs
EPA estimated transportation costs for all 2016 wastewater managed by an operator who
discharged at least some portion of their wastewater to POTWs in 2016. As applicable, this
included transportation costs to POTWs, CWT facilities, disposal wells, reuse/recycle, storage
pending disposal or reuse, road spreading, and landfills. In general, EPA used Equation 3 below
to calculate baseline transportation costs for each wastewater management approach employed
for each well by an entity and then summed the transportation costs for all wells operated by
each entity.
Equation 3
Baseline Transp Cost = Baseline Transp Time x lhr. /60 min x Trucking Cost Factor x
Vol WW
where:
Baseline Transp Cost = Baseline transportation cost for 2016 for a specific record9
($)
Baseline Transp Time = GIS calculated trucking time to transport generated
(min) wastewater from a specific well to a specific waste facility in
2016.
Trucking Cost Factor = Fee paid by operators for trucking wastewater. Calculated in
($/bbl/hr) Equation 2.
Vol WW (bbl) = Volume of wastewater generated by a specific well and sent
to a specific waste facility in 2016.
EPA used slightly different assumptions for the "Baseline Transp Time" variable in
Equation 3 above depending on the baseline management approach.
• POTWs, CWT Facilities, and Disposal Wells - EPA calculated the transport
time using ArcGIS (see Step 6) with the well and waste facility latitude and
longitudes reported in the PA DEP waste reports as inputs.
• Reuse/Recycle - For wells where generated wastewater is reported as
reuse/recycle, the location for wastewater reuse/recycle is not reported. In lieu
of well-specific reuse/recycle location, EPA calculated trucking times from
the well that generated the wastewater to the average latitude and longitude
9 A "record" refers to a waste record in PA DEP's Oil & Gas Waste Reports. A specific waste report provides a
listing of waste produced by a given well for a specific waste stream and waste facility. This information is reported
to PA DEP by oil and gas operators.
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for all the wells owned by the operator. This methodology assumes that
wastewater is not shared with other operators.
• Road spreading - Some road spreading records included exact latitude and
longitudes for the road spreading location, which EPA used to estimate
trucking times. For those that did not, EPA estimated latitudes and longitudes
for trucking using the county and municipality name that accepted the
wastewater for road spreading.
• Storage Pending Disposal or Reuse - EPA assumed zero transportation costs
based on the assumption that wastewater is stored at the well pad.
• Landfill - Since some operators reported sending waste to landfills, EPA
included these costs in calculating their baseline costs. Wastes managed at
landfills include materials such as drill cuttings. EPA calculated the transport
time using ArcGIS (see Step 6) and the well and landfill latitudes and
longitudes reported in the PA DEP waste reports as inputs. Because all waste
sent to landfills was solid, reported in units of tons, EPA converted the
trucking cost factor from units of $/bbl/hr to $/ton/hr by multiplying by a
factor of 10 barrels/ton. This methodology assumes that the hourly rate for
trucks hauling solid waste are the same as those for trucks hauling wastewater,
and that each truck can haul 10 tons of solid waste.
Baseline Management Costs
For each record, EPA used Equation 4 to calculate the baseline management costs paid
for wastewater management (e.g., to a CWT facility for treatment) by entity in 2016. EPA
summed the baseline management costs for all wells operated by each entity.
Baseline Mgmt Costs = Vol WW x Mgmt Fee
Equation 4
where:
Baseline Mgmt
Cost ($)
Vol WW (bbl)
Mgmt Fee ($/bbl)
= Baseline management cost for 2016 for a specific record.
= Volume of wastewater generated by a specific well and sent
to a specific waste facility in 2016.
= $ per barrel fee charged to an operator for a specific waste
facility or wastewater management approach.
EPA used slightly different assumptions for the "Mgmt Fee" in Equation 4 above
depending on the baseline wastewater management approach.
• POTWs, CWT Facilities, Disposal Wells - EPA used the wastewater
management costs determined in Step 7.
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Alternative Wastewater Management Analysis
• Reuse/Recycle - All reuse/recycle records from PA DEP in EPA's 2016
baseline analysis included the comment "REUSE WITHOUT PROCESSING
AT A PERMITTED FACILITY" indicating that these wastewaters were not
treated prior to reuse in exploration and production activities. However, EPA
conservatively assumed that operators did treat a portion of this wastewater
using non-TDS removal treatment technologies (i.e., relatively low-cost
physical/chemical technologies that are incapable of removing total dissolved
solids) because literature reports that such treatment is frequently done prior
to reuse (DCN SGE00575; DCN SGE00635; DCN SGE00275; DCN
SGE00625; DCN SGE00636; DCN SGE00276). EPA obtained costs for non-
TDS removal treatment from EPA's report Unconventional Oil & Gas
Extraction Wastewater Treatment Technologies (DCN SGE01186). EPA
assumed that 50 percent of wastewater was treated, and that 50 percent was
not treated. This assumption is based on citations in literature and EPA site
visits to UOG operators, including Petroleum Equipment & Services
Association's 2012 survey (DCN SGE00575), where UOG operators reported
that 54 percent of produced water reused/recycled by the UOG industry in
2012 for fracturing requires minimal or no treatment. In addition, the EPA
conducted several site visits and conference calls with operators that have
increasingly reused/recycled wastewater with no treatment (DCN SGE00635;
DCN SGE00275; DCN SGE00625; DCN SGE00636; DCN SGE00276).
• Storage Pending Disposal or Reuse - EPA assumed zero management cost
because this wastewater was not yet transferred to a management location in
2016. Instead, EPA estimated a cost that operators paid to store the
wastewater (see Baseline Storage section).
• Road spreading - EPA assumed zero management cost as there is no
treatment cost associated with road spreading.
• Landfill - EPA assumed an average management fee of $47.10 per ton of
solid waste that was sent to landfills in 2016. This assumption is based on
values reported for landfills accepting drilling solid waste in an Argonne
National Laboratory report (DCN SGE00139).
Baseline Storage
For each record where reuse/recycle or storage pending disposal management approaches
were used, EPA used Equation 5 to calculate the baseline storage costs. EPA used storage costs
associated with renting tanks to store wastewater before it is reused within the oil and gas
extraction industry. EPA obtained tank rental fee and tank capacity values during site visits and
conference calls with UOG operators for the UOG final rule (2016). EPA assumed storage costs
to be zero for all other baseline management approaches (CWT facilities, POTW, landfill, road
spreading) based on the assumption that wastewater is stored in permanent storage tanks located
on each well pad. EPA assumed the costs for these permanent storage tanks are attributed to well
development investment prior to 2016, and there is no current cost in 2016. This assumption is
reasonable given that most of the wells have spud dates prior to 2010, and capital costs for
permanent storage tanks would have been paid off in less than 5 years.
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Alternative Wastewater Management Analysis
Rental costs for storage tanks are dependent on the number of days storage is required.
EPA assumed that storage tanks would be required for 30 days.
Equation 5
Baseline Storage Cost = Vol WW/ Storage Tank Capacity x Storage Tank Rental Fee x
Number of Days
where:
Baseline Storage Cost
($)
Vol WW (bbl)
Storage Tank
Capacity (bbl/tank)
Frack Tank Rental
Fee ($/tank/day)
Number of Days
= Baseline storage cost for 2016 for a specific record.
= Volume of wastewater generated by a specific well and
reported as re-used and/or stored by an operator in 2016.
= Average tank volume reported by operators during EPA site
visits and conference calls.
= Average $ per tank per day rental fee charged to an operator
for renting a storage tank, reported by operators during EPA
site visits and conference calls.
= Number of days wastewater must be stored.
Total Baseline Costs
For each record, EPA used Equation 6 to calculate total baseline costs by entity in 2016.
Equation 6
Total Baseline Costs = Baseline Mgmt Cost + Baseline Transp Costs
Baseline Storage Costs
where:
Total Baseline
Cost ($)
Baseline Mgmt
Cost ($)
Baseline Transp
Cost ($)
Baseline Storage
Cost ($)
= Total baseline cost for 2016 for a specific record in 2016.
= Baseline management costs for 2016 for a specific record,
calculated in Equation 4.
= Baseline transportation costs for 2016 for a specific record,
calculated in Equation 3.
= Baseline storage costs for 2016 for a specific record,
calculated in Equation 5.
3.1.8 Step 9 —UOG Alternative Wastewater Management Analysis - Incremental Costs
EPA prepared the UOG Alternative Wastewater Management Analysis spreadsheet to
estimate the incremental costs that would be incurred by the operators identified in Step 4 to
eliminate discharging UOG wastewater to POTWs and instead send their wastewater to the
closest available CWT facilities or disposal wells. EPA developed and populated the spreadsheet
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as described in Table A-7 in Appendix A. The remainder of this section provides a brief
overview of these activities.
EPA estimated incremental costs as the difference in cost between the baseline
wastewater transportation and management for UOG discharges to POTWs compared to an
alternative management approach (i.e., CWT facility or disposal well). All remaining cost
components (e.g., onsite storage) are not expected to vary post-compliance, because for purposes
of this analysis EPA assumes that wastewater sent to a POTW would be replaced only by
sending wastewater to a CWT facility or disposal well, and therefore the other cost components
are not expected to contribute to the incremental costs. EPA used the following steps:
Incremental Transportation Costs
EPA used the following steps to calculate incremental transportation costs. EPA
performed these steps for both the nearest alternative CWT facility and disposal well determined
in step 6.
1. For each record, EPA used Equation 7 to calculate the incremental transport time
as the difference between the time to truck the wastewater to the POTW
(baseline) and the time to truck the wastewater to the alternative wastewater
management approach (i.e., the nearest CWT facility and nearest disposal well
determined in Step 6). Note that the incremental transport time can be positive or
negative, depending on whether the closest alternative CWT facility or disposal
well is closer or further away from the well than the POTW.
2. For each record, EPA calculated the incremental transportation cost ($) by
multiplying the incremental transport time by the trucking cost factor, and then
multiplying by the volume of wastewater discharged to a POTW in 2016.
Equation 7
Incr Transp Time = Alt Transp Time - Baseline Transp Time to POTW
Equation 8
Incr Transp Cost = Incr Transp Time x 1 hr /60 min x Trucking Cost Factor x
Vol WW POTW
where:
Incr Transp Time
(+/- min)
Time difference between transporting generated wastewater
to an alternative waste treatment site (CWT facility or
disposal well) versus POTW, can be + or -.
GIS calculated time per well to transport generated
wastewater to alternative treatment site.
Alt Transp Time
(min)
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Baseline Transp
Time to POTW
(min)
Incr Transp Cost
(+/- $)
Trucking Cost
Factor ($/bbl/hr)
Vol WW POTW
(bbl)
GIS calculated time per well to transport generated
wastewater to POTW.
Difference in transportation cost per well between alternative
(CWT facility/disposal well) and POTW.
Weighted average fee paid by operators for trucking
wastewater. Calculated in Equation 1
Truck Load Hours = Estimated Driving Time (min) x (1 hr /
60 min) / (Vol WW (bbl) / Truckload Capacity)
Equation 2 of Step 7.
Reported volume of wastewater per well discharged to a
POTW in 2016.
Incremental Wastewater Management Costs
EPA used the following steps to estimate incremental wastewater management costs
charged by CWT facilities and disposal wells. EPA performed these steps for both the nearest
alternative CWT facility and disposal well determined in Step 6.
1. For each record, EPA identified the management fee, in $/bbl, for the alternative
waste facility (i.e., nearest CWT facility and disposal wells) identified in Step 6.
However, EPA did not have facility-specific management prices for 12 out of 24
CWT facilities and for 37 out of 48 disposal wells. Instead, EPA used an average
of all CWT facility cost data when estimating costs for these CWT facilities
without specific management costs, and EPA used an average of all disposal well
cost data when estimating costs for these disposal wells without specific costs(i.e.,
for CWTs without specific management fees, an average of all CWT facility fees
is used instead for that CWT facility fee, and for disposal wells without a specific
managment fee, an average of all disposal well fees is used instead for that
disposal well management fee).
2. For each record, EPA used Equation 9 to calculate the difference between this
alternative management fee and the baseline management fee (i.e., the $/bbl
charge from the POTW).
3. For each record, EPA used Equation 10 to calculate the incremental wastewater
management costs ($) for the nearest alternative CWT facility and nearest
disposal well. This excludes transportation costs.
Equation 9
Incr Mgmt Fee = Alt Mgmt Fee - Baseline Mgmt Fee
Equation 10
Incr Mgmt Costs = Incr Mgmt Fee x Vol WWpotw
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where:
= Difference in price charged by POTW compared to the
alternative CWT facility and disposal well.
= Price charged to operators for sending wastewater to
the alternative CWT facility and disposal well.
= Price charged to operators for sending wastewater to
the POTW in 2016.
= Incremental management cost for sending wastewater
to the nearest CWT facility and disposal well instead
of a POTW.
= Reported volume of wastewater per well discharged to
a POTW in 2016.
Final Incremental Costs
1. For each record, EPA calculated the total incremental wastewater management
cost for wastewater management alternatives ($) by summing the incremental
transportation and incremental management costs to alternatively send the
wastewater to the nearest CWT facility and to the nearest disposal well as shown
in Equation 11.
2. For each record, using the results from step 1 above, EPA selected the least
expensive wastewater management alternative for each well by comparing the
total incremental wastewater management costs for each alternative (i.e., CWT
facility versus disposal well). See Equation 12.
Equation 11
CWT Cost = Incr CWT Transp Cost + Incr CWTMgmt Cost
Disposal Well Cost = Incr Disposal Well Transp Cost + Incr Disposal Well Mgmt Cost
Equation 12
If CWT Cost > Disposal Well Cost, choose Disposal Well
If CWT Cost < Disposal Well Cost, choose CWT
where:
CWT Cost ($)
Incr CWT Transp Cost
(+/- $)
Incr CWT Mgmt
Costs (+/- $)
3-19
Incr Mgmt Fee (+/- $)
Alt Mgmt Fee ($/bbl)
Baseline Mgmt Fee
($/bbl)
Incr Mgmt Costs (+/-
$)
Vol WW POTW (bbl)
= Total cost per well to dispose of wastewater at CWT
facilities.
= Difference in transportation cost per well between
CWT facility and POTW.
= Incremental management cost for sending wastewater
to the nearest CWT facility instead of a POTW.
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Disposal Well Cost ($)
Incr Disposal Well
Transp Cost (+/- $)
Incr Disposal Well
Mgmt Costs (+/- $)
Total cost per well to dispose of wastewater at
disposal wells.
Difference in transportation cost per well between
disposal well and POTW.
Incremental management cost for sending wastewater
to the nearest disposal well instead of a POTW.
3.1.9 Step 10 — Identify and Remove Stripper Wells
EPA added 2016 oil and gas production data to the Alterative Wastewater Management
Cost Analysis spreadsheet (DCN SGE01419) to identify and remove stripper wells from the cost
analysis because stripper wells (as defined at 40 CFR 435.60) are not subject to the UOG rule.
Oil and gas production data include separate production data fields for each well including oil
quantity (bbl), oil production days (days), gas quantity (MCF), gas production days (days),
condensate production (bbl), and condensate production days (days). EPA used these fields to
identify stripper wells using the following steps:
1. Calculated the average quantity of oil produced per day in 2016 by dividing oil
quantity by the oil production days.
2. Calculated the average gas to oil ratio in 2016 by dividing gas quantity by the oil
quantity in 2016.
3. Identified wells as stripper wells if they generated less than 10 barrels per day of oil
(Step 1) and had a gas to oil ratio less than 15,000 cubic feet to barrels (Step 2).
4. Removed the identified stripper wells from the overall cost analysis because they
would not be subject to the UOG rule.
3.2 Alternative Wastewater Management Analysis Results
Table 3-4 presents summary statistics of the results of the Alternative Wastewater
Management Analysis. Outputs from the Alternative Wastewater Management Analysis are key
inputs to EPA's economic achievability analysis described in Section 4.
Table 3-4. Alternative Wastewater Management Analysis Results
Cost Output
Result
Baseline Costs
A. Operators Discharging 2016 UOG Rule Defined UOG Wastewater to POTWs
22
B. Total Oil and Gas Wells (UOG and COG) Producing Oil or Gas Owned by (A) Operators
18,136
C. Total Oil and Gas Wells (UOG and COG) Generating Wastewater Owned by (A) Operators
5,863
D. Total Baseline Costs for (B) Wells
$6,043,000
Incremental Costs
A. Total Wells with Incremental Costs
959
B. Total Incremental Transportation Cost ($)
$21,109
C. Total Incremental Management Cost ($)
$43,798
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Table 3-4. Alternative Wastewater Management Analysis Results
Cost Output
Result
D. Total Incremental Transportation and Management Cost ($) (B+C=D)
$64,907
Source: DCNSGE01419.
3.3 Cost Analysis Uncertainties and Limitations
EPA identified uncertainties and limitations in the Alternative Wastewater Management
Analysis:
• As described in Section 3.1.4, some operators incorrectly reported wastewater
volumes to PA DEP. Where EPA had updated information, it incorporated
that information in its analyses. Other entities may have similar errors;
however, a review of the data did not indicate any obvious errors.
• As described in Section 3.1.3, EPA assumed wells with formation information
"not reported" are UOG and estimated incremental costs for these wells if
they discharged to POTWs in 2016. This would lead to an overestimation of
costs to the extent that these unknown facilities are not UOG under the 2016
UOG rule's definition of UOG. Seven percent of the total costs to comply
(Table 3-4) are attributed to unknown formations.
• EPA used GIS analysis to estimate real world driving distances and times.
Real world driving distances and times may be greater or fewer.
• EPA assumed the closest CWT facility or disposal well would be used as an
alternative to discharging to POTWs. While EPA has no data to indicate that
these alternatives are not available, EPA performed a sensitivity analysis to
estimate the cost impact or transporting to the second closest CWT
facility/disposal well instead (see Appendix B). This analysis demonstrated
that while total costs to would increase under this scenario, economic impacts
as described in Section 4 would remain the same.
• One CWT facility (Clearmont Storage Facility) was not identified by the GIS
analysis as the closest alternative management approach for any UOG wells,
even though it is located closest to a number of these wells. This is likely due
to a factor such as an incomplete GIS layer, as this facility was recently
constructed, and therefore the map layer used at the time of the analysis may
not have contained a viable trucking route to the facility. This may lead to an
overestimation of the incremental compliance costs for some undetermined
number UOG wells.
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4. ECONOMIC IMPACT ANALYSIS
4.1 Overview of Discounted Cash Flow Analysis
EPA used a discounted cash flow (DCF)-based analysis to assess the economic
achievability of the rule. This analysis tests the effects of the costs of compliance on the financial
performance and business value of the regulated entities, based on changes in after-tax cash flow
(ATCF) and the discounted present value of ATCF. The discounted present value of cash flow
provides a measure of business value. Reduction in business value, specifically when business
value would become negative because of incremental compliance costs, is an indicator of
potential adverse financial impact of the rule's requirements.
EPA performed the impact analysis in two steps:
1. Baseline analysis, to assess business condition and value before changes in
regulatory requirements. A key purpose of this analysis is to identify entities that
appear to have negative profits independent of increased regulatory costs.
2. Post-compliance analysis, to asses change in business value due to regulatory
requirements. This analysis assesses the reduction in business value from
compliance costs, focusing on whether some entities' business value is positive in
the baseline but turns negative because of compliance requirements.
4.1.1 Analysis Period and Dollar Year
EPA relied on financial data reported for 2016 in its data requests to 9 entities (described
in Section 2) to analyze the financial health of the entities that will likely need to make changes
to comply with the UOG rule (regulated entities). For this analysis, EPA adjusted this financial
data, and all financial data values used in the analysis, to 2017 dollars using the Gross Domestic
Product (GDP) price deflator index (DCN SGE01436). EPA analyzed each entity over a ten-year
analysis period.
4.1.2 Baseline Analysis Methodology
EPA performed the business value analysis on the basis of after-tax cash flow (ATCF),
including an allowance for ongoing capital outlays, that is available to an entities' providers of
capital - i.e., its creditors and equity owners.10 When discounted over an analysis period using an
appropriate cost of capital for calculating present value, this metric yields an estimate of business
value based on accepted financial analysis conventions.
A key component of the ATCF calculation is operating cash flow, which is the cash, on
an after-tax basis, provided by a business' ongoing operations and before payments to providers
of capital. The provision for ongoing capital outlays is then subtracted from operating cash flow
to yield the after-tax cash flow measure that is used in analyzing business value. EPA calculated
operating cash flow (OPCF) for each entity in each year of the analysis period as follows:
10 This metric of after-tax cash flow, when defined to include an allowance for ongoing capital outlays, is often
referred to as free cash flow.
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Equation 13
OPCF = Rev — FclCost — Tax
where:
OPCF = Operating cash flow (defined as pre-interest, but after-tax).
Rev = Total revenue.
FclCost = Total facility costs, excluding depreciation and interest.
Tax = Federal and state corporate income taxes.
In this calculation, depreciation is excluded to account for the fact that depreciation is a
non-cash charge.
Because a business needs to replace and/or refurbish its capital equipment to maintain
operations, the operating cash flow value described above will generally overstate the cash flow
that is available to providers of capital - creditors and equity owners - and that would be the
basis for estimating business value as a going-concern. Accordingly, for assessing business
value, it is appropriate to adjust operating cash flow for ongoing capital expenditures. One
approach is to estimate the ongoing capital outlay as equal to depreciation; EPA used this
approach for this analysis. EPA finds this reasonable because depreciation is meant to reflect the
cost over time from consumption - i.e., using up - of capital equipment and even though
depreciation would still reflect historical purchase values, which could be quite old, the value is
close in concept to the value needed as a replacement/refurbishment value, on a steady state basis
(i.e., ongoing capital outlay). Using this approach, EPA estimated ATCF, with allowance for
ongoing capital replacement (i.e., depreciation, in this approach) for each facility using the
following equation:
ATCF = Rev — FclCost — Tax — Depr
Equation 14
where:
ATCF = After-tax cash flow.
Rev = Total revenue.
FclCost = Total facility costs, excluding depreciation and interest.
Tax = Federal and state corporate income taxes.
Depr = Depreciation as a proxy for capital replacement.
EPA used the resulting ATCF values in the DCF-based analysis of business value. EPA
calculated the ATCF for each year of the analysis period,11 then calculated the baseline present
value of after-tax cash flow (DCFbl) by taking the present value of the ATCF time series. In
performing the discounted present value analysis, EPA used the OMB recommended real
discount rate of 7 percent to discount the 10-year cash flow series. EPA calculated the present
value of the cash flow series as follows:
11 A description of how EPA projected costs and revenues over the analysis period can be found in Section 4.2.
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Equation 15
(v ATCFi \
where:
DCFbl = Baseline present value of after-tax cash flow.
ATCFi = After-tax cash flow for year i.
i = The given year in the 10-year analysis period beginning with the year
of compliance (i=0).
r = The OMB recommended real discount rate of 7 percent (DCN
S GEO 1444).
EPA recorded the results for each entity and did not carry forward entities with negative
DCF value in the baseline to the post-compliance impact analysis because those entities are
shown to be negative in profit without any post-compliance incremental costs, and so the effect
of the incremental costs affecting an entity's profits from positive to negative cannot be
demonstrated.
4.1.3 Post-Compliance Analysis Methodology
EPA performed an analysis of compliance impact on regulated entities using a DCF-
based analysis of the change in business value of facilities resulting from an occurrence of
compliance costs. EPA considers entities with a positive business value in the baseline, but that
turns negative after accounting for compliance costs, as potential closures due to the regulation.
As described in Section 3, EPA developed incremental cost estimates for complying with
the UOG rule for all entities for non-surveyed entities and surveyed entities. To estimate the
impact these costs may have on regulated entities, EPA estimated the after-tax present value of
compliance costs on a constant dollar basis. To adjust the entity compliance costs from a pre-tax
basis to an after-tax basis, EPA determined the tax reduction associated with the annual
compliance expense. EPA used the following equation to calculate the combined tax rate (rc) for
each entity in order to adjust compliance costs to an after-tax basis:
Equation 16
tc zy + ts zy * ts
where:
Tc = Combined tax rate.
if = Federal corporate income tax rate12.
Ts = State of Pennsylvania corporate income tax rate13.
12 The federal corporate income tax rate is 21 percent (https://www. irs. go v/pub/irs-pdf/i 1120 .pdf).
13 Pennsylvania's corporate income tax rate is 9.99 percent
fhttp://www.revenue.pa.gov/GeneralTaxInformation/News%20and%20Statistics/ReportsStats/TaxCompendium/Do
cuments/2017 tax compendium.pdf).
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EPA then calculated the present value of after-tax compliance costs (CmplCpv) over the
analysis period as follows:
Equation 17
„ (V 0Mi - Tc * 0Mi\
CmplCpv = ^2, (1 + ry j
where:
CmplCpv = Present value of after-tax compliance costs.
OM; = O&M costs in year i.
i = The given year in the 10-year analysis period beginning with the year
of compliance (i=0).
xc = Combined tax rate.
r = The OMB recommended real discount rate of 7 percent (DCN
S GEO 1444).
EPA subtracted the present value of after-tax compliance costs {CmplCpv) from the
baseline present value of after-tax cash flow (DCFbl) to estimate the post-compliance business
value of the facility (DCFpc):
Equation 18
DCFpC = DCFbl — CmplCpv
where:
DCFpc = Post-compliance business value of the entity.
DCFbl = Baseline present value of after-tax cash flow.
CmplCpv = Present value of after-tax compliance costs.
EPA then evaluated each entity's post compliance DCF: a post-compliance DCF of zero
or less would indicate a possible post-compliance closure while a positive value would indicate
that the entity would continue to operate after compliance.
4.2 Assumptions for Projecting Over the Ten-Year Analysis Period for Surveyed
Facilities
EPA conducted the DCF analysis over a ten-year analysis period, beginning in 2016, by
projecting data over the analysis period based on data provided by entities in response to EPA's
data request. As described in Section 2, EPA requested data from a subset of entities that will
likely incur costs to comply with the UOG rule. This section describes how EPA projected each
data item over the analysis period for the eight entities that responded to EPA's data request.
Section 4.3 describes how EPA modeled the non-surveyed entities, and how these projections
differ for non-surveyed entities.
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4.2.1 Projecting Crude Oil and Natural Gas Prices
A key consideration in this analysis is the expected price for crude oil and natural gas.
Since the WTI oil price peak of 2008-2014 and Henry Hub gas price peak of 2005-2009, prices
have been lower in more recent years, reaching their lowest values in the first year of the
analysis, 2016. However, since 2016, prices have increased and are expected to continue to
increase over the analysis period, according to EIA. Using publicly available data, EPA
accounted for this expected increase in oil and gas prices over time by developing oil and natural
gas price projections based on analyses from EIA's 2018 Annual Energy Outlook reference case.
EPA used the following data to calculate crude oil and natural gas price projections:
• Historical Pennsylvania crude oil first purchase prices14 (DCN SGE01441).
• Historical Henry Hub natural gas spot prices (DCN SGE01440).
• Henry Hub and WTI Reference case price projections, for the period 2016-
2050, from 2018 Annual Energy Outlook (DCN SGE01439).
EPA began the crude oil price projection from EIA's reported 2016 and 2017
Pennsylvania crude oil first purchase price. EPA then applied the projected year-to-year
percentage change in WTI prices from Annual Energy Outlook's reference case to estimate
crude oil prices in years 3-10 of the analysis period.
An appropriate basis for modeling the price facilities will receive for their natural gas
would be wellhead prices in Pennsylvania. However, because EIA only publishes Henry Hub
natural gas prices, which are downstream from the wellhead and thus not the appropriate price
concept for modeling the price at the facility, EPA relied on natural gas production and revenue
from natural gas operations as reported in responses to EPA's data requests. EPA estimated an
average natural gas price from these data and used this estimate as a starting point for the first
year of the analysis.15 EPA then applied the projected year-to-year percentage change in Henry
Hub prices from Annual Energy Outlook's reference case to estimated natural gas prices in years
2-10 of the analysis period.
4.2.2 Projecting Crude Oil, Natural Gas, and Condensate Production
EPA used reported production levels for 2016 and 2017 as production in the first two
years of the analysis period. Production in years 3-10 was assumed to be on a constant trend,
equal to 2017 production. EPA decided to assume constant production after testing several
models using historical 2006-2016 PA oil production and PA crude oil first purchase prices for
all impacted entities. These models used historical price and production data to estimate price-
production models that could be used to estimate future production given future prices. EPA
developed the following price-production models based on historical 2006-2016 data:
• Entity-specific linear trend line.
14 EIA defines first purchase price as "the price for domestic crude oil reported by the entity that owns the crude oil
the first time it is removed from the least boundary" (https://www.eia.gov/tools/glossarv/index.php?id=F').
15 EPA excluded one outlier data point from the estimated average natural gas price received by surveyed entities in
2016.
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• Entity-specific quadratic trend line.
• Entity-specific constant production based on 2016 production.
• Entity-specific linear trend line assuming averaged prices.16
• Linear fit using average production per entity.
In order to determine which price-production model was the most appropriate to use,
EPA used each model to estimate 2017 oil production (as an example of all factors) and
compared the estimate to the actual 2017 production value. The constant production model
resulted in the lowest total error (i.e., difference between estimated and actual oil production)
across all entities. The model with the second lowest total error (i.e., difference between
estimated and actual oil production) was the entity-specific linear trend line. EPA tested these
two models using natural gas production and prices as well, and, again, the constant production
model resulted in the smallest error when predicting 2017 natural gas production. EPA therefore
assumed constant 2017 oil, gas, and condensate production over the remainder of the analysis
period (years 3-10).
4.2.3 Projecting Revenue
Revenue in the first year of the analysis period was as reported in EPA's data request.
EPA calculated oil and gas revenue in years 2-10 of the analysis period as the product of
projected oil prices and oil production, and gas prices and gas production. EPA estimated
revenue from condensate production would be equal to the product of projected condensate
production and price of oil.17 EPA assumed all other non-oil, non-gas, and non-condensate
revenue would remain constant over the analysis period because EPA had no basis/data to
increase or decrease it, and given that, assuming this other revenue was constant seemed more
reasonable than changing it.
4.2.4 Projecting Operating Costs
EPA received data on operating costs attributable to oil operations and to gas operations
in responses to EPA's data request. EPA used operating costs in year 1 as reported. Together
with oil and gas production data, EPA used reported oil and gas operating costs to calculate unit
operating costs ($/bbl oil, and $/Mcf gas). EPA assumed a constant unit operating cost over the
analysis period since most of these wells have been operating for years (if not decades) with
nearly a 'steady-state' currently in place for costs. In years 2-10 of the analysis period, EPA
calculated oil and gas operating costs as the product of the unit operating cost and projected
production.
4.2.5 Projecting Quantity of Wastewater
EPA assumed that production of wastewater per unit of oil or natural gas would remain
constant over the analysis period. This is an appropriate assumption because (1) EPA had no
other data, and (2) it is reasonable to assume operators will continue to generate a similar amount
16 EPA averaged prices between each local minimum and maximum. Prices in 2006-2008 were set equal to the
average over the same period; the 2009 price was set equal to the 2008-2009 average; prices in 2010-2013 were set
equal to the 2009-2013 average; and prices in 2014-2016 were set equal to the 2013-2016 average.
17 Condensate removed from natural gas is classified as crude oil by regulatory agencies, and refiners pay almost as
much for condensate as crude oil (DCN SGE01445).
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of wastewater relative to oil over the life of the well. EPA made this assumption for all oil and
gas wells (UOG and COG), based on EPA's review of PA DEP Production and Waste Report
data over a 5-year time period (DCN SGE01419). Using 2016 oil production, gas production,
and wastewater production, EPA calculated unit wastewater production based on both oil and gas
production for each facility (i.e., barrels of wastewater per barrel of oil, barrels of wastewater per
Mcf of gas). EPA calculated wastewater production in years 2-10 as unit wastewater production
times oil or gas production. To estimate the quantity of wastewater generated at facilities that
produce both oil and gas, EPA conservatively used the unit wastewater production that resulted
in the highest wastewater quantity (and thus the highest wastewater management and
transportation costs).
4.2.6 Projecting Wastewater Management and Transportation Costs
EPA received 2016 data on wastewater management and transportation costs for
wastewater sent to a POTW, CWT facility, or disposal well by the 8 respondents to EPA's data
request. EPA calculated the costs per barrel of wastewater and assumed this unit cost remained
constant over the analysis period (in years 2 through 10) given that EPA had no other data or
basis to assume it would increase or decrease. For example, a CWT may increase its price to
accept wastewater if it sees oil and gas entities are receiving a higher price for selling their oil
and gas product (assuming a cost pass through) over time or it may decrease its price to accept
wastewater if the oil price decreases and entities decide not to bring their wastewater to the CWT
because of prices that do not take into account the lower oil prices. Since EPA does not have
knowledge of business decisions from CWTs, EPA assumed it was more reasonable to assume a
constant unit cost than to increase or decrease it. Furthermore, SGE01452 does document that in
the past, some CWTs have maintained prices for oil and gas entities in order to keep their
business, even when costs for the CWT increased. EPA calculated total wastewater management
and transportation costs as the product of this unit cost and project wastewater quantity, as
described above.
4.2.7 Projecting Impact Fees, Other Costs, Depreciation, and Interest
Impact fees, other (non-oil and gas operating) costs, deprecation, and interest in year 1 of
the analysis period were as reported in the response to EPA's data request. EPA assumed each
would remain constant over years 2 through 10 of the analysis period. It is appropriate to assume
impact fees will remain constant since this is Pennsylvania law. It is appropriate to assume non-
oil and gas operating costs are constant because EPA had no basis to increase or decrease it, and
assuming this other cost was constant seemed more reasonable than changing it (e.g., personnel
costs). It is appropriate to assume depreciation is constant in this approach because depreciation
is meant to reflect the cost over time from consumption - i.e., using up - of capital equipment
and even though depreciation would still reflect historical purchase values, which could be quite
old, the value is close in concept to the value needed as a replacement/refurbishment value, on a
steady state basis (i.e., ongoing capital outlay). It is appropriate to assume interest in year 1 is
constant because generally a loan is negotiated as a long-term contract with the interest rate
locked in for the life of the loan.
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4.2.8 Projecting Federal and State Taxes
EPA received data on 2016 federal and state taxes paid by surveyed entities. In some
cases, entities reported taxes of zero. EPA assumed these facilities are S-corporations that do not
pay corporate income taxes and would therefore have zero taxes over the analysis period.18 If an
entity reported paying taxes in 2016, EPA calculated taxes in years 2-10 as the product of
earnings before taxes (EBT) and the combined tax rate (unless EBT is less than zero, in which
case taxes are zero).
4.3 Assumptions for Modeling Non-Surveyed Facilities
EPA performed a baseline and post-compliance DCF analysis on entities that are
expected to incur compliance costs but that did not receive a data request (non-surveyed entities).
To do so, EPA modeled each non-surveyed entity using known production data and by assigning
a model facility from among the surveyed entities. EPA assigned a model facility to each non-
surveyed entity as follows:
• Compiled existing data on 2016 oil and natural gas production data for all
survey and non-surveyed entities that likely need to make changes to comply
with the 2016 UOG rule pulled from Pennsylvania datasets.
• Estimated 2016 revenue for non-surveyed entities as the product of production
and price.
• Compiled existing data on revenue as reported for eight surveyed entities.
• Calculated the production mix for all entities as the ratio of oil production to
gas production.
• Matched each non-surveyed entity to the closest surveyed entity based on
estimated revenue and production (oil and gas) mix, because those factors
would be fundamental to determining similarity across entities. In order to
match on two variables, EPA minimized the sum of squared errors between
the non-surveyed entity and each surveyed entity. First, EPA scaled revenue
and production mix by that metric's average value across surveyed and non-
surveyed entities to ensure that each metric contributed equally to the sum of
squared errors. EPA then calculated the sum of squared errors for the two
scaled metrics between each non-surveyed entity and each surveyed entity.
The surveyed entity that resulted in the minimum sum of squared errors is that
non-surveyed entity's "model facility".
Similar to how EPA analyzed impacts for surveyed entities that reported their
information, EPA performed a DCF-based analysis on each non-surveyed entity. However, since
EPA did not have specific financial information on the non-surveyed entities, EPA used financial
18 EPA performed a sensitivity analysis to determine what impact, if any, this assumption had on the results of the
DCF closure analysis. EPA determined the assumption has no impact on the results - assuming all facilities paid
corporate income taxes resulted in the same number of baseline and post-compliance closures.
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information from a surveyed entity that most closely matched it, which we call its model facility.
To adjust the model facility's data to reflect the non-surveyed entity, EPA calculated a model
adjustment factor as the non-surveyed entity's estimated 2016 revenue (product of production
and price) divided by the model facility's reported 2016 revenue. EPA used the model
adjustment factor to scale several data items, as described below.
To analyze non-surveyed entities, EPA used the same DCF analysis and assumptions
described in the previous sections, with the following exceptions:
• Revenue in year 1 calculated as price times actual (2016) production (because
EPA had 2016 production, a modeled adjustment factor wasn't needed).
• Oil and gas operating costs calculated as the model facility's unit operating
cost ($/bbl, $/Mcf) times production at the non-surveyed entity (because EPA
had 2016 production, a modeled adjustment factor wasn't needed).
• Impact fees in year 1 calculated as the model facility's reported impact fees
times the model adjustment factor (because EPA did not have actual data for
this factor of the modeled entity, the model adjustment factor is used).
• Other (non-oil and gas operating) costs in year 1 calculated as the model
facility's reported other costs times the model adjustment factor (because EPA
did not have actual data for this factor of the modeled entity, the model
adjustment factor is used).
• Depreciation in year 1 calculated as the average ratio of depreciation to total
revenue among all surveyed entities times the total revenue of the analysis
entity.19
• Interest in year 1 calculated as the average ratio of interest to total revenue
among all surveyed entities times the total revenue of the non-surveyed
entity.19
• Federal and state taxes in year 1 calculated as the model entity's reported
taxes times the model adjustment factor (because EPA did not have actual
data for this factor of the modeled entity, the model adjustment factor is used).
In year 2-10, if the analysis facility has positive EBT and the model entity
reported paying taxes, taxes are calculated as the non-surveyed entity's EBT
times the combined tax rate.
19 Relative to other line items that are more closely related to the scale of production at a facility (e.g. operating
costs), there is a much weaker relationship between depreciation and revenue, or interest and revenue. Model facility
depreciation-to-revenue (and interest-to-revenue) is therefore not likely to be a reasonable metric for calculating
depreciation at non-surveyed entities. As such, EPA did not adjust these items according to the model adjustment
factor. Instead, EPA used an average value over the set of modeled entities as an approximation of the depreciation
and interest relative to the size of UOG facilities.
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for Unconventional Oil and Gas Operations
Economic Impact Analysis
4.4 Baseline Analysis Results
EPA performed the DCF baseline analysis for all entities. Based on the baseline analysis,
seven entities are shown to be negative in profit without any post-compliance incremental costs,
and so the effect of the incremental costs affecting an entity's profits from positive to negative
cannot be demonstrated. EPA did not carry these entities forward to the post-compliance closure
analysis, leaving 15 entities expected to incur compliance costs for the post-compliance analysis.
4.5 Post-Compliance Analysis Results
EPA found that none of the 15 entities expected to incur compliance costs would be at
risk of closure because all continue to have positive profit after incurring the costs to comply.
Table 4-1 summarizes the results of the DCF baseline and post-compliance closure analysis.
Table 4-1. Results of Baseline and Post-Compliance Analysis
Tilk-
Title
Baseline Closures
7 of 22 Entities
Post-Compliance Closures
0 of 15 Entities
Source: DCN SGE01484.
4.6 Uncertainties and Limitations
• EPA based all oil and gas price projections on the price projections provided by the EIA.
These price projections may be higher or lower over a 10-year period and given that the
oil and gas market is a cyclical market, the prices may actually go down, as opposed to
how EIA projected the prices as going up, over a 10-year period. While uncertain, EPA
assesses the price projections based on EIA modelling to be reasonable because EIA's
Annual Energy Outlook is a publicly published documentation of future price modelling.
EIA includes the following documentation of EIA projections: "[1] Projections in the
Annual Energy Outlook 2018 (AEO2018) are not predictions of what will happen, but
rather modeled projections of what may happen given certain assumptions and
methodologies. [2] The AEO is developed using the National Energy Modeling System
(NEMS), an integrated model that captures interactions of economic changes and energy
supply, demand, and prices. [3] Energy market projections are subject to much
uncertainty, as many of the events that shape energy markets and future developments in
technologies, demographics, and resources cannot be foreseen with certainty." (DCN
SGE01438)
• EPA assumed a constant trend in modelling out 10 years for several elements of the
model: oil, gas, and condensate production; operation costs; and unit costs of water. Over
a 10-year timeframe, several factors may influence deviations from a constant trend for
each of these elements. EPA does not have any future data to determine if any of these
elements may change and found it more reasonable, for purposes of this analysis, that
when in doubt, to keep factors constant if there is no other source to tell EPA if it will
increase or decrease. As is discussed in EIA's projections, energy market projections are
subject to much uncertainty, as many of the events that shape energy markets and future
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for Unconventional Oil and Gas Operations Economic Impact Analysis
developments in technologies, demographics, and resources cannot be foreseen with
certainty.
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Cost to Revenue
5. COST TO REVENUE
The Regulatory Flexibility Act (RFA) requires federal agencies to consider the impact of
their rules on small entities. The RFA describes the regulatory flexibility analyses and
procedures that must be completed by federal agencies unless they certify that the rule, if
promulgated, would not have a significant economic impact on a substantial number of small
entities. This certification must be supported by a statement of factual basis, e.g., addressing the
number of small entities affected by the proposed action, expected cost impacts on these entities,
and evaluation of the economic impacts. Although this notice is not a proposal rulemaking, since
EPA has consistently done a cost-to-revenue analysis in developing effluent limitations
guidelines and standards EPA is providing an analysis in this notice as to whether the UOG rule
would have "a significant impact on a substantial number of small entities" (SISNOSE) for this
impact analysis. This assessment involved the following steps:
• Determining which of those entities are small entities, based on Small Business
Administration (SBA) size criteria.
• Assessing the potential impact of the regulatory requirements on those small entities
by comparing the estimated annualized compliance cost to revenue; the cost-to-
revenue ratio indicates the magnitude of economic impacts. EPA used threshold
compliance costs of 1 percent or 3 percent of revenue to categorize the degree of
significance of the economic impacts on small entities.
• Assessing whether those small entities incurring potentially significant impacts
represent a substantial number of small entities. EPA determined whether the number
of small entities impacted is substantial based on (1) the estimated absolute numbers
of small entities incurring potentially significant impacts according to the two cost
impact criteria, and (2) the percentage of small entities in the relevant entity
categories that are estimated to incur these impacts.
5.1 Analysis Approach
EPA identified the Small Business Administration (SBA) size threshold
(https://www.sba.gov/document/support—table-size-standards) guidelines (2017). For the NAICs
codes under Subsector 211 - Oil and Gas Extraction, employee size of 1,250 is considered a
small business. EPA reviewed the employee count of the facilities that responded to its data
request and found an average of 10 employees per entity. Given that the other entities reviewed
for this analysis are also likely to have employee size below 1,250 (PGCC self-identified entities
considered COG under Pennsylvania's definition as small businesses, DCN SGE01494), the
other entities don't have 125X the oil or gas production that the surveyed entities have, so likely
don't have 125X the employees the surveyed entities have, making them meet the SBA
threshold, and over 99% of the oil and gas industry is considered small businesses according to
Census, DCN SGE01449), all entities analyzed in this impact analysis are considered small
businesses under the SBA guidelines.
As outlined in the introduction to this chapter, two criteria are assessed in determining
whether a regulation would qualify for a no-SISNOSE finding:
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for Unconventional Oil and Gas Operations
Cost to Revenue
• Is the absolute number of small entities estimated to incur a potentially
significant impact, substantial?
• Do these significant impact entities represent a substantial fraction of small
entities in the industry that could potentially be within the scope of a
regulation?
A measure of the potential impact of a regulation on small entities is the fraction of small
entities that have the potential to incur a significant impact. For example, if a high percentage of
potentially small entities incur significant impacts even though the absolute number of
significant impact entities is low, then the rule could represent a substantial burden on small
entities. To assess the extent of economic/financial impact of a regulation on small entities, EPA
compares estimated compliance costs to estimated entity revenue (also referred to as the "sales
test"). The analysis is based on the ratio of estimated annualized after-tax compliance costs to
annual revenue of the entity. EPA categorizes entities according to the magnitude of economic
impacts they may incur as a result of the rule. EPA identifies entities for which annualized
compliance costs are at least 1 percent and 3 percent of revenue. EPA then evaluated the absolute
number. The Agency assumes that entities incurring costs below 1 percent of revenue are
unlikely to face significant economic impacts, while entities with costs of at least 1 percent of
revenue have a higher chance of facing significant economic impacts, and entities incurring costs
of at least 3 percent of revenue have a still higher probability of significant economic impacts.
For this analysis, EPA assumed that oil and gas entities would not be able to pass any of the
increase in their production costs to consumers (zero cost pass-through). This assumption is used
for analytic convenience and provides a worst-case scenario of regulatory impacts to oil and gas
entities.
5.2 Results
Table 5-1 summarizes the results of the analysis for the UOG rule. EPA estimates that 1 small
entity would incur costs exceeding 1 percent of revenue, and 0 small entities would incur costs of
at least 3 percent of revenue. On the basis of percentage of small entities in the oil and gas
extraction industry, given that there are over 6,000 entities in the oil and gas industry meet the
SBA size standard for small business in this industry, the analysis shows a small fraction of
small businesses of 0 percent incurring an impact at the 1 percent of revenue levels (DCN
SGE01449).
Table 5-1: Entity Annualized Cost-to-Revenue (CTR) Results
Number of I'.ulilics
with (IK 3" i.
Revenue - Year 1
21
1
0
Source: DCN SGE01484.
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Cost to Revenue
6. NON-WATER QUALITY ENVIRONMENTAL IMPACTS
EPA also evaluated the potential change in non-water quality environmental impacts that
may occur when oil and gas entities eliminate discharging UOG wastewater to POTWs in
Pennsylvania. For these analyses, EPA looked at the potential incremental effect on air pollution,
solid waste generation, and energy consumption.
6.1 Air Pollution
Oil and Gas wastewaters contain organic compounds. When these wastewaters are treated
at a POTW, they often pass through a series of collection and treatment units. These units are
typically open to the atmosphere and allow wastewater containing organic compounds to contact
ambient air. Atmospheric exposure of the organic-containing wastewater may result in
significant water-to-air transfers of volatile organic compounds (VOCs). In general, POTWs
have not installed air or wastewater treatment technologies designed to control the release of
VOCs to the atmosphere. Additionally, POTWs do not typically employ best management
practices designed to control VOC emissions (such as covering their treatment tanks). Therefore,
as soon as these VOC- containing wastewaters contact ambient air, volatilization will begin to
occur. Thus, volatilization of VOCs from oil and gas wastewater may begin immediately on
receipt, or as the wastewater is treated.
The wastewater management alternatives that form the basis of the pretreatment
standards are sending the wastewater to a CWT facility, underground injection, or recycle/re-use.
EPA does not project incremental increases in air emissions for these alternatives. As is the case
for POTWs, as soon as these VOC-containing wastewaters contact ambient air, volatilization
will begin to occur. As a result, any wastewater management approach that include contact with
ambient air, will similarly lead to air emissions. To the extent that produced water disposed of in
underground injection results in less contact with ambient air than at POTWs, incremental VOC
emissions may decrease.
6.2 Solid waste
Solid waste will be generated due to a number of treatment technologies that may be in
place at POTWs such as gravity separators and biological treatment systems. The incremental
quantity of solid waste generated from an alternative method, depends on the method. For
example, UIC would likely lead to a decrease in sludge generation. Similarly, as most oil and gas
wastewater that is re-used within the industry undergoes minimal treatment, sludge generation
would likely decrease or remain the same. CWT facilities will likely generate additional solid
waste over and above what would be generated at a POTW. The actual amount of sludge
generation is dependent on the treatment processes in place. For example, chemical precipitation
would likely result in additional sludge. However, even if all of the UOG wastewater currently
sent to POTWs is alternatively managed by a CWT facility, because the volume of UOG
wastewater is relatively small compared to the total volume of wastewater treated at CWT
facilities, any additional sludge generated would similarly be small. When EPA promulgated the
CWT rule in 2000, it estimated that the additional solid waste disposed in landfills would be less
than 0.19% of the annual tonnage of waste currently disposed in landfills. See Development
Document for Effluent Limitations Guidelines and Standards for the Centralized Waste
Treatment Industry (EPA-821-R-00-020, August 2000).
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for Unconventional Oil and Gas Operations
Cost to Revenue
6.3 Energy Requirements
As is the case for solid waste generation, the incremental change in energy requirements
depends on the alternative wastewater management approach as well as the location of that
alternative. Energy is required in transporting UOG wastewater to a POTW and also in operating
the wastewater treatment systems at a POTW. To the extent that transportation distances increase
or decrease for a non-POTW management approach, fuel usage will similarly be affected. EPA
estimates the total incremental miles as a result of the alternative wastewater management
approach are 3,700 miles, which correlates to approximately 600 gallons of fuel (DCN
SGE01419). According to EIA, on-highway vehicles consumed approximately 40 billion gallons
of distillate fuel in 2016 (DCN SGE01523). Regarding energy needed for treatment, whether
energy needs increase or decrease depend on the alternative wastewater management method.
For example, as most oil and gas wastewater that is re-used within the industry undergoes
minimal treatment, energy usage for treatment may decrease. CWT facilities will likely require
additional energy for treatment over and above what would be needed at a POTW. The actual
incremental amount of energy depends on the treatment processes in place at the CWT. For
example, chemical precipitation would likely result in additional energy requirements. However,
even if all UOG wastewater currently sent to POTWs is alternatively managed by a CWT
facility, because the volume of UOG wastewater is relatively small compared to the total volume
of wastewater treated at CWT facilities, any additional energy requirements would similarly be
small. When EPA promulgated the CWT rule in 2000, it estimated that the additional energy
requirements associated with treatment would equate to 4,210 barrels of oil per day while overall
consumption of oil in the United States at the time was 18.3 million barrels of oil per day. See
Development Document for Effluent Limitations Guidelines and Standards for the Centralized
Waste Treatment Industry (DCN SGE01534).
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
7. WATER QUALITY PARAMETERS IN SHALE, TIGHT, AND CONVENTIONAL
OIL AND GAS WASTEWATER
To better understand why EPA included oil and gas wastewater extracted from tight and
shale in the definition of unconventional, EPA is including this section to describe characteristics
of these wastewaters. EPA analyzed produced water characterization data from the U.S.
Geological Survey (USGS) National Produced Waters Geochemical Database v2.3 (DCN
SGE01447; DCN SGE01446) to compare the concentrations of pollutants in wastewater
generated by conventional, shale, and tight oil and gas well operations. EPA reviewed a subset of
the formation and basin combinations reported in the USGS data20 and assigned an EPA resource
type based on EPA's definition of UOG. EPA also incorporated national and state water quality
standards (WQS) data and POTW performance data to provide context to the produced water
characterization data (DCN SGE01454).
7.1 Analysis Approach
The USGS Produced Water Geochemical Database v. 2.3 (USGS database) contains
geochemical and other information for produced waters from oil and gas wells (DCN
SGE01447; DCN SGE01446). The database contains over 114,000 records where each record
represents a well for which produced water was sampled and analyzed. Each record includes
basic well identification information such as API number, basin, and geological formation and
includes up to 130 pollutant concentration measurements. While the database contains some
records for produced water generated by geothermal and injection wells, over 113,000 of the
114,000 records are for produced water from oil and gas extraction wells. Some oil and gas
extraction wells were sampled multiple times such that they have more than one record.
There are approximately 9,000 formation and basin combinations reported in the USGS
data. EPA reviewed these formation and basin names to determine whether they meet the 2016
UOG rule's definition of UOG (i.e., tight gas, tight oil, shale gas, shale oil), but limited the
review to the subset of formation and basin combinations with the greatest number of associated
records. EPA's review included approximately 70 percent of the total well records from 600
different formations/basins. To conduct this review, EPA assigned an EPA resource type by
searching for the basin and formation combination in EIA's Annual Energy Outlook (DCN
SGE01190), shale map (DCN SGE01191), and tight map (DCN SGE00155). If the combination
was listed by EIA as tight or shale, EPA assigned it a tight or shale resource type, respectively.
The "EPA Resource Type Crosswalk" tab in the USGS Produced Water Characterization
Analysis Spreadsheet (DCN SGE01446) includes details on which formation and basin
combinations EPA reviewed. Table 7-1 summarizes these resource type assignments. Well types
reported by USGS as "Geothermal", "Injection", or "Undefined" were all given an EPA resource
type "Indeterminate". In addition, for well types reported by USGS as "Conventional
Hydrocarbon", EPA assigned a "Conventional Hydrocarbon" resource type if the formation
name was complete (e.g., not reported as an acronym or number or blank) and if it was not found
in any list of tight or shale formations reported by EIA. For well types reported by USGS as
20 EPA reviewed over 600 out of approximately 9,000 formation and basin combinations, representing
approximately 70% of the total USGS well records throughout the United States.
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for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
"Conventional Hydrocarbon", EPA assigned an "Indeterminate" resource type if the formation
name was incomplete.
A number of concentration values in the USGS database were reported as "MDL" or
"PQL". In the past for the effluent guidelines program, EPA has used one-half of the MDL in
calculating summary statistics for data. However, since EPA did not know the MDL for data
reported in the USGS database EPA instead excluded these results when preparing the tables in
Section 7.2 as there is no feasible way to include the data. The number of MDL or PQL values
reported in the database for each pollutant are indicated in the oil and gas wastewater
characterization summary tables in Section 7.2.
7.2 Results
Table 7-1 presents data and statistics on select constituents in produced water from
conventional, shale, and tight oil and gas operations in the Appalachian basin alongside relevant
WQS data and typical POTW removal efficiencies. The shale formations in the Appalachian
basin include the Marcellus. The tight formations in the Appalachian basin include the Bradford,
Berea, Clinton, Medina, Tuscarora, and Venango. As shown in Table 7-1, the median values of
concentrations of select pollutants found in produced water generated by conventional, shale, and
tight oil and gas wells, exceed the maximum WQS.
POTW performance data indicate that POTWs do not effectively treat the pollutants
shown in Table 7-1 (as well as other pollutants). Typical concentrations of untreated domestic
wastewater are approximately 900 mg/L for TDS and approximately 100 mg/L for chloride
(DCN SGE00167). Table 7-1 shows that TDS concentrations in samples of produced water from
conventional, shale, and tight oil and gas wells in the Appalachian basin are orders of magnitude
higher than these typical POTW influent concentrations, which could interfere with POTW
operations or result in pass-through and discharge to the environment.
Table 7-2 presents the concentrations (excluding MDL/PQL values) of select constituents
in produced water from conventional and unconventional oil and gas operations across the entire
United States (as defined by the UOG rule). TDS in UOG produced water consists of dissolved
matter including salts (e.g., sodium, chloride, nitrate, bromide), group II alkaline earth metals
(e.g., calcium, strontium, barium), and other minerals and organic material. Table 7-2 shows that
concentrations of TDS and its constituents are found in similar ranges in conventional and
unconventional produced water.
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
Table 7-1. Select Pollutants in Produced Water from Conventional, Shale, and Tight Oil and Gas Operations in the Appalachian Basin
Parameter
Units
Conventional3
Shale"
Tight0
Range
of Water
Quality
Standards'
POTW
Percent
Removal
(%)a
Ranged
Median
Number
of Data
Points
Number of
Data Points
Reported as
Below
MDLs/PQLse
Ranged
Median
Number
of Data
Points
Number of
Data Points
Reported as
Below
MDLs/PQLse
Ranged
Median
Number
of Data
Points
Number of
Data Points
Reported as
Below
MDLs/PQLse
TDS
mg/L
6,690 -
353,000
153,000
949
0
1,410-
273,000
107,000
337
0
69,000 -
385,000
273,000
455
0
250- 1,000
8
Bromide
mg/L
20 - 2,240
615
671
25
10-2,470
608
281
5
429-
2,920
1,670
377
0
N/A
N/A
Calcium
mg/L
79-
46,400
11,400
900
1
124 -
24,000
8,070
382
0
4,670 -
51,100
28,300
453
2
N/A
9
Chloride
mg/L
3,970 -
205,000
92,000
908
1
168 -
158,000
64,400
325
0
44,200 -
208,000
149,000
471
0
250
57
Sodium
mg/L
2,130-
82,300
37,300
884
2
239-
57,900
28,000
353
0
20,500 -
75,600
55,400
443
2
N/A
3
Barium
mg/L
7-1,870
342
395
70
1 - 9,320
1,060
323
0
1 -864
10
45
7
1.00-2.00
16
Boron
mg/L
10-135
41
8
1
0-37
13
136
0
17-119
39
69
0
N/A
30
Strontium
mg/L
7-2,030
176
386
56
6-5,330
1,380
364
0
118 -
1,480
959
424
5
N/A
N/A
Gross alpha
pCi/L
N/A
N/A
0
0
56-
20,600
5,700
103
2
N/A
10,400
1
0
N/A
N/A
Gross beta
pCi/L
N/A
N/A
0
0
64 - 7,940
1,630
101
2
N/A
11,600
1
0
1,000
N/A
Radium-226
pCi/L
124 -
4,840
690
11
0
12 -
10,300
1,270
98
3
59-
1,360
370
43
2
N/A
N/A
Radium -
228
pCi/L
129 -
2,080
1,170
10
0
1 -1,110
143
94
5
54-
6,170
500
27
2
N/A
N/A
Source: EPA analysis (DCN SGE01446) of USGS National Produced Waters Geochemical Database v2.3 (DCN SGE01447).
N/A - Not Available.
a—Conventional oil and gas in the Appalachian basin represented in this table includes over 20 different formations,
b—Shale formations in the Appalachian basin represented in this table include the Marcellus.
c—Tight formations in the Appalachian basin represented in this table include the Bradford, Berea, Clinton. Medina, Tuscarora, and Venango,
d—The lower range represents the 5th percentile and the upper range represents the 95th percentile.
e—EPA excluded these data from statistics presented in this table because EPA did not know the MDL for data contained in the USGS database and therefore cannot calculate
statistics that include consideration of these data (i.e., the "number of data points" columns do not include the "number of data points reported as below MDLs/PQLs").
f—Data source: State Water Quality- Human Health Standards for Pollutants of Concern in Oil and Gas Wastewater (DCN SGE01454). Where the Water Quality Standard is
reported as "N/A", criteria for these pollutants may not have been developed and therefore no standards may exist,
g—Typical percent removal capabilities from POTWs with secondary treatment (DCN SGE00600).
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
Table 7-2. Select Pollutants in Produced Water from Conventional and Unconventional Oil and Gas Operations Across
the United States
Conventional3
Unconventionalb
Number of
Number of Data
Data Points
Number
Points Reported
Number
Reported as
of Data
as Below
of Data
Below
Parameter
Units
Range0
Median
Points
MDLs/PQLsd
Range0
Median
Points
MDLs/PQLsd
Total Dissolved Solids (TDS) and Primary Anions and Cations Contributing to TDS
TDS
mg/L
2,730 - 323,000
62,300
42,943
0
2,390 - 262,000
21,900
14,270
0
Bromide
mg/L
19-4,890
300
1,639
155
10-2,410
535
1,212
38
Calcium
mg/L
21 -28,700
2,280
40,747
135
12-21,800
222
15,645
30
Chloride
mg/L
190 - 197,000
36,300
41,266
17
472 - 152,000
9,000
15,663
0
Sodium
mg/L
458 - 103,000
19,800
35,269
13
730 - 68,200
6,440
13,251
2
Metals
Barium
mg/L
0.1-682
20
2,761
2,682
0.33 - 1,410
10.6
2,903
630
Boron
mg/L
3-204
43
745
15
0.7 - 118
18.8
548
12
Strontium
mg/L
3 - 2,080
109
2,425
182
6 - 2,870
680
1,526
50
Radioactives
Gross alpha
pCi/L
N/A
N/A
0
0
57 - 20,500
5,740
104
2
Gross beta
pCi/L
N/A
N/A
0
0
65 - 7,940
1,650
102
2
Radium-226
pCi/L
3 -4,010
194
26
0
17-6,950
562
149
5
Radium-228
pCi/L
134-2,070
930
11
0
2 - 1,620
215
128
7
Source: EPA analysis (DCN SGE01446) of USGS National Produced Waters Geocheinical Database v2.3 (DCN SGE01447).
N/A - Not available because no data were reported for this pollutant and resource type in the USGS database based on EPA's review,
a—Conventional oil and gas represented in this table includes over 130 different formations,
b—Unconventional formations represented in this table includes over 160 different formations,
c—The lower range represents the 5th percentile and the upper range represents the 95th percentile.
d—EPA excluded these data from statistics presented in this table because EPA did not know the MDL for data contained in the USGS database and therefore cannot
calculate statistics that include consideration of these data (i.e., the "number of data points" columns do not include the "number of data points reported as below
MDLs/PQLs").
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
According to Pennsylvania Code 95.1021, oil and gas produced water may be discharged
to a POTW if the discharges are first treated by a CWT facility and do not exceed specified
monthly average concentrations developed to maintain receiving water quality (DCN
SGE00187). As shown in Table 7-3, the median concentrations for TDS, chloride, barium, and
strontium in tight oil and gas produced water in the Appalachian Basin (excluding MDL/PQL
values) are at or above the monthly average limits in the Pennsylvania Code.
Table 7-3. Naturally Occurring Radium Isotope Concentrations
Constituent
Appalachian Basin Tight Oil and Gas Wastewater Concentrations"
Monthly Average
Pretreatment
Standard set by PA
Code 95.10 (mg/L)c
Range (pCi/L)b
Median (mg/L)
Number of Data
Points
Number of
MDLs/PQLs
Excluded from
Analysis
TDS
69,000 - 385,000
273,000
455
0
500
Chloride
44,200 - 208,000
149,000
471
0
250
Barium
1-864
10
45
7
10
Strontium
118 - 1,480
959
424
3
10
a—EPA analysis (DCN SGE01446) of USGS National Produced Waters Geochemical Database v2.3 (DCN
SGE01447).'
b—The lower range represents the 5th percentile and the upper range represents the 95th percentile,
c—PA Code Chapter 95 DCN SGE00187.
The constituents and concentrations of constituents in unconventional produced water
varies based on geographic location. For example, Table 7-4 shows median TDS concentrations
ranging from approximately 100,000 to 300,000 mg/L for specific tight oil and gas formations
found in Pennsylvania. These median concentrations exceed the conventional and
unconventional produced water median concentrations of 62,300 mg/L and 21,900 mg/L,
respectively, shown in Table 7-2 and are within the range presented for conventional, shale and
tight oil and gas produced water in Table 7-1.
Table 7-4. TDS Concentrations in Produced Water from Pennsylvania Tight Oil
and Gas Formations
Median TDS
Number of MDLs/PQLs
Tight Formation3
Concentration (mg/L)b
Number of Data Points
Excluded from Analysis
Clinton
285,000
326
0
Berea
94,000
49
0
Medina
297,000
47
0
Bradford
108,000
16
0
Venango
120,000
14
0
Tuscarora
286,000
3
0
21 PA Code 95.10 is titled, "Treatment requirements for new and expanding mass loadings of Total Dissolved Solids
(TDS)".
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
Table 7-4. TDS Concentrations in Produced Water from Pennsylvania Tight Oil
and Gas Formations
Tight Formation3
Median TDS
Concentration (mg/L)b
Number of Data Points
Number of MDLs/PQLs
Excluded from Analysis
All Formations
272,500
455
0
Source: Source: EPA analysis (DCN SGE01446) of USGS National Produced Waters Geocheinical Database v2.3
(DCN SGE01447).
a—These formations are classified as tight by EIA and meet the 2016 UOG rule's definition of UOG (DCN
SGE00155).
b—No MDL results were reported in the USGS database for TDS in tight formations in the Appalachian Basin.
Metals such as boron and strontium and radioactive constituents are also found in oil and
gas produced water (see Table 7-1 and Table 7-2). As shown in Table 7-1, POTWs with
secondary treatment are typically able to remove only thirty percent of boron, the remainder of
which would likely be discharged into surface waters by the POTW.
Oil and gas formations contain varying levels of naturally occurring radioactive material
(NORM) resulting from uranium and thorium decay, which can be transferred to oil and gas
produced water. In Table 7-5, EPA compared tight oil and gas produced water data from Table
7-1 for radium-226 and radium-228 to data from a 2014 International Atomic Energy Agency
(IAEA) report that included radium isotope concentrations in rivers, lakes, groundwater, and
drinking water from public water systems (DCN SGE00769). Except for two MDL values, all
the concentrations of radium-226 and radium-228 reported in the USGS Database for tight oil
and gas produced water in the Appalachian basin were above the naturally occurring
concentrations. Refer to "Radioactive Materials in the Unconventional Oil and Gas (UOG)
Industry" (DCN SGE01185) for more information about concerns with radioactive materials in
UOG produced water.
Table 7-5. Naturally Occurring Radium Isotope Concentrations
Constituent
Appalachian Basin Tight Oil and Gas Wastewater
Concentrations"
Naturally Occurring Radium Isotope
Concentrations in Groundwaterb
Range0
(pCi/L)
Median
(pCi/L)
Number
of Data
Points
Number of
MDLs/PQLs
Excluded
from
Analysis
Range
(pCi/L)
Maximu
m
(pCi/L)
Maximum
Sample
Location
Radium-226
59 - 1,362
370
43
2
0.032 -6.5
170
Texas
groundwater
Radium-228
54-6,167
500
27
2
N/A°
12
South Carolina
well water
a—Source: EPA analysis (DCN SGE01446) of USGS National Produced Waters Geocheinical Database v2.3 (DCN
SGE01447).
b—Source: IAEA, 2014 (DCN SGE00769).
c— The lower range represents the 5th percentile and the upper range represents the 95th percentile,
d—IAEA, 2014 (DCN SGE00769) did not report any average concentration data for radium-228.
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
7.3 Uncertainties and Limitations
• Fewer data points were available for shale and tight produced water
concentrations than were available for conventional hydrocarbon produced
water concentrations for most constituents.
• The USGS data did not contain readily available information about the
analytical method used for each sample analysis. Therefore, EPA excluded
results reported as "MDL" or "PQL" in the USGS database when calculating
summary statistics as it is uncertain as to what value to assign to such results.
• The USGS data had limited available data for radioactive constituents. For
example, the USGS data lacked gross alpha and gross beta data for
conventional hydrocarbon produced water and contained only one data point
for gross alpha and gross beta for tight oil and gas produced water.
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
8. PRELIMINARY CONCLUSION
At the time EPA promulgated the 2016 rule, it established zero discharge pretreatment
standards for UOG extraction facilities based on alternative wastewater management approaches.
Consistent with the factors identified in the Clean Water Act and described in the preamble to the
2016 rule, EPA found these alternatives to be technologically available, have acceptable non-
water quality environmental impacts, and be economically achievable. Further, such standards
would prevent some UOG extraction wastewater constituents largely from "passing through" the
POTW untreated and discharged from the POTW to the receiving stream. Further, EPA
concluded that no existing UOG facilities were discharging pollutants to POTWs at the time of
the 2016 rule.
As described in this document, EPA has supplemented the rulemaking record to account
for the UOG facilities in Pennsylvania, that were in fact, discharging wastewater to POTWs at
the time of the rulemaking. The UOG rule is not applicable to activities regulated under the
Stripper Subcategory (40 CFR 435 Subpart F). The UOG rule applies to onshore unconventional
oil and gas extraction facilities regulated under Subpart C. Subpart C excludes facilities regulated
under Subpart F. This analysis indicates that there are 22 entities that discharged at least some
portion of their wastewater to a POTW from UOG extraction operations as defined by the UOG
rule in 2016. As is described in the UOG final rule and supplemented by this analysis, all of
these entities have a portfolio of wastewater management approaches currently available other
than POTWs.
EPA calculated the incremental wastewater management costs for these operators to send
their wastewater to the nearest alternative technology as well as any associated incremental
transportation costs.
EPA evaluated the economic impacts of the UOG rule. The 22 entities in Pennsylvania
that may incur costs associated with this rule is less than 0.1% of oil and gas extraction nation-
wide entities. The EPA then estimated potential financial impacts for these entities by conducting
a discounted cash flow analysis (modeled future revenue and operation costs) over 10 years on
an after-tax basis. Based on this analysis, the EPA found that seven of the 22 entities would have
negative profits irrespective of the UOG rule's incremental costs. For the remaining entities,
when adding in the incremental costs of the rule, the EPA's analysis shows that none of the 15
entities would be at risk of closure as a result of complying with the UOG rule.
Historically, in conducting ELG analyses, the EPA considers entities with negative
profits before the addition of costs to comply with any new ELGs to be baseline closures and
removes them from any further analysis (e.g., total costs, total benefits). However, in this case,
the seven entities that the data indicate have negative profits in 2016 continued to report
wastewater discharge to Pennsylvania in 2017 demonstrating they remain in business. Therefore,
the EPA is reporting cost information as a range with the lower value representing EPA's typical
approach and the upper value assuming all 22 facilities continue to operate. The EPA's analysis
shows that for 2016, the median incremental costs would be between $131 and $279 per entity
and the total costs of the UOG rule for 2016 would be approximately $33,000 -$65,000.
EPA also evaluated incremental non-water quality environmental impacts associated with
alternative wastewater management approaches. This includes changes in air emissions, solid
8-1
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Water Quality Parameters in Shale, Tight,
and Conventional Oil and Gas Wastewater
waste generation, and energy consumption. The incremental change depends on the alternative
wastewater management approach. For example, sludge generation would likely decrease if a
UOG facility sends its wastewater to a UIC well and would likely increase if it sends its
wastewater to a CWT facility. Even if each operator that currently sends its wastewater to a
POTW elected to use a wastewater management approach that incrementally increased air
emissions, sludge generation, or energy usage, these changes would be small relative to U.S.
totals.
Lastly, EPA reviewed available data on the concentration of pollutants in wastewater
generated from shale, tight, and conventional oil and gas formations as well as POTW
performance in removing these pollutants. This data demonstrates that all of these wastewaters
can generate concentrations of pollutants that are not typically received by POTWs. POTW
performance data continue to indicate that POTWs do not effectively treat some of these
pollutants and that they will pass through untreated and be discharged from the POTW.
After accounting for the new information and analyses described above, EPA concludes
that the zero discharge of pollutants standard is technologically available, economically
achievable and has acceptable non-water quality environmental impacts. EPA also notes that the
rule would prevent some UOG extraction wastewater constituents from being discharged,
untreated, from the POTW to the receiving stream. Based on this information, the EPA will not
revise the 2016 rule.
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
References
9. REFERENCES
Table 6. Reference List
DCN
Reference
SGE00139
Puder, M.G. and Veil, J. A. 2006. Offsite Commercial Disposal of Oil and Gas
Exploration and Production Waste: Availability, Options, and Costs
SGE00155
United States Department of Energy (U.S. DOE). 2010. United States Energy
Information Administration (EIA). Major Tight Gas Plays, Lower 48 States. Available
electronically at: https://www.eia.gov/oil gas/rpd/tight gas.pdf
SGE00167
Metcalf & Eddy. 2003. Wastewater Engineering: Treatment and Reuse
SGE00187
Pennsylvania Department of Environmental Protection. 2010. 25 PA Code Chapter 95
40 PA.B.4835
SGE00275
United States Environmental Protection Agency (U.S. EPA). 2012. Site Visit Report for
Citrus Energy Corporation Marcellus Shale Gas Operations
SGE00276
United States Environmental Protection Agency (U.S. EPA). 2012. Meeting with
XTO Energy, Inc. about Unconventional Oil and Gas Sanitized
SGE00575
Petroleum Equipment Suppliers Association. 2012. Outlook for Domestic
Unconventional Resources
SGE00600
United States Environmental Protection Agency (U.S. EPA). 2003. Development
Document for the Final Effluent Limitations Guidelines and Standards for the Metal
Products and Machinery Point Source Category
SGE00625
United States Environmental Protection Agency (U.S. EPA). 2015. Site Visit Report for
Southwestern Energy Fayetteville Shale Gas Operations
SGE00635
United States Environmental Protection Agency (U.S. EPA). 2012. Site Visit Report
Chesapeake Energy Corporation Marcellus Shale Gas Operations Sanitized
SGE00636
United States Environmental Protection Agency (U.S. EPA). 2012. Talisman Marcellus
Operations Overview
SGE00763
Pennsylvania Department of Environmental Protection (PA DEP). 2014. Oil and Gas
Reporting - Electronic (OGRE) Public Reporting Data Dictionary, vl.O
SGE00769
International Atomic Energy Agency (IAEA). 2014. The Environmental Behavior of
Radium: Revised Edition
SGE01170
Drillinglnfo, Inc. 2015. DI Desktop®. Downloaded on March 30, 2015
SGE01171
Drillinglnfo, Inc. 2015. DI Desktop® Data Coverage
SGE01179
Eastern Research Group, Inc. (ERG). 2016. Data Compilation Memorandum forthe
Technical Development Document (TDD)
SGE01185
Eastern Research Group, Inc. (ERG). 2016. Radioactive Elements in the
Unconventional Oil and Gas (UOG) Industry
SGE01186
United States Environmental Protection Agency (U.S. EPA). 2016. Unconventional Oil
and Gas Wastewater Treatment Technologies
SGE01188
United States Environmental Protection Agency (U.S. EPA). 2016. Technical
Development Document forthe Effluent Limitations Guidelines and Standards forthe
Oil and Gas Extraction Point Source Category. EPA-820-R-16-003. Available
electronically at: https://www.epa.gov/sites/production/files/2016-
06/documents/uog oil-and-gas-extraction tdd 2016.pdf
SGE01190
United States Department of Energy (U.S. DOE). 2015. United States Energy
Information Administration (EIA). Assumptions to the Annual Energy Outlook 2015
9-1
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
References
Table 6. Reference List
DCN
Reference
SGE01191
United States Department of Energy (U.S. DOE). 2015. United States Energy
Information Administration (EIA). Shale Gas Plays, Lower 48 States
SGE01246
Pennsylvania Department of Environmental Protection (PA DEP). 2015. Spud Data
Report
SGE01375
Pennsylvania Department of Environmental Protection (PA DEP). 2016. Pennsylvania
Oil and Gas Well Formations. Downloaded on August 8, 2016
SGE01397
Eastern Research Group, Inc. (ERG). 2016. POTWs Accepting Oil and Gas Wastewater
in Los Angeles County
SGE01399
Eastern Research Group, Inc. (ERG). 2016. POTWs Accepting Oil and Gas Wastewater
in Colorado
SGE01407
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - Catalyst Energy
SGE01408
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - Mead Oil
SGE01409
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - MSL Oil & Gas
SGE01410
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - New Century Energy
SGE01411
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - PVE Oil
SGE01412
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - Snyder Brothers
SGE01413
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - Alliance Petroleum
SGE01414
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - Fairman Corporation
SGE01415
United States Environmental Protection Agency (U.S. EPA). 2018. Final
Unconventional Oil and Gas Data Gathering Letter - Dannie Energy
SGE01416
Eastern Research Group, Inc. (ERG). 2018. PA DEP Waste Reports Development
Database
SGE01417
Eastern Research Group, Inc. (ERG). 2018. PA DEP O&G Production Development
Database
SGE01418
Eastern Research Group, Inc. (ERG). 2018. PA DEP and DI Desktop Cross-Reference
Database
SGE01419
Eastern Research Group, Inc. (ERG). 2018. UOG Alternative Waste Management Cost
Analysis - Sanitized
SGE01420
Pennsylvania Department of Conservation and Natural Resources (PA DCNR). 2018.
Bureau of Topographic and Geologic Survey. Exploration and Development Wells
Information Network (EDWIN). Downloaded on June 5, 2018
SGE01421
Eastern Research Group, Inc. (ERG). 2018. Pennsylvania Department of Environmental
Protection's (PA DEP) Statewide Oil and Gas Waste Reports Memorandum.
SGE01421.
A01
Pennsylvania Department of Environmental Protection (PA DEP). Statewide Oil and
Gas Waste Reports. WasteExport2004-2009 COG and UOG.
SGE01421.
A02
Pennsylvania Department of Environmental Protection (PA DEP). Statewide Oil and
Gas Waste Reports. WasteExport2010-2016 Conventional.
SGE01421.
A03
Pennsylvania Department of Environmental Protection (PA DEP). Statewide Oil and
Gas Waste Reports. WasteExport2010-2016 Unconventional
9-2
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
References
Table 6. Reference List
DCN
Reference
SGE01422
Eastern Research Group, Inc. (ERG). 2018. Pennsylvania Department of Environmental
Protection's (PA DEP) Statewide Oil and Gas Production Reports Memorandum.
SGE01422.
A01
Pennsylvania Department of Environmental Protection (PA DEP). Statewide Oil and
Gas Production Reports. 1-Oil Gas Well Production 2016
SGE01422.
A02
Pennsylvania Department of Environmental Protection (PA DEP). Statewide Oil and
Gas Production Reports. 2-Oil Gas Well Production 2015
SGE01422.
A03
Pennsylvania Department of Environmental Protection (PA DEP). Statewide Oil and
Gas Production Reports. 3-Oil Gas Well Production 2010-2014
SGE01422.
A04
Pennsylvania Department of Environmental Protection (PA DEP). Statewide Oil and
Gas Production Reports. 4-Oil Gas Well Production 2017
SGE01431
Thompson G. 2016. Letter from U.S. Congress to Administrator McCarthy
SGE01433
United States Environmental Protection Agency (U.S. EPA). 2018. Well Production and
Waste Summary by Producer
SGE01434
United States Environmental Protection Agency (U.S. EPA). 2018. EPA follow up letter
to Catalyst
SGE01436
United States Bureau of Economic Analysis (U.S. BEA). 2018. Table 1.1.9 Implicit
Price Deflators for Gross Domestic Product (GDP Deflator). Accessed on May 25,
2018. Available online at:
https ://apps .bea.gov/iT able/iTable .cfm?reqid= 19&step=2#reqid= 19&step=3 &isuri=1 &
1921=sur. vey& 1903=13
SGE01437
United States Energy Information Administration (EIA). 2018. Annual Energy Outlook
2018 with Projections to 2050: Natural Gas Production: Dry Gas Production
SGE01438
United States Energy Information Administration (EIA). 2018. Annual Energy Outlook
2018 with Projections to 2050: Petroleum and Other Liquids Prices: Crude Oil -
Reference Case
SGE01439
United States Energy Information Administration (EIA). 2018. Cushing, OK WTI Spot
Price FOB (Dollars per Barrel). Accessed May 25, 2018. Available electronically at:
https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=rwtc&f=a
SGE01440
United States Energy Information Administration (EIA). 2018. Henry Hub Natural Gas
Spot Price: Annual. Accessed May 29, 2018. Available electronically at:
https://www.eia.gov/dnav/ng/hist/rngwhhdA.htm
SGE01441
United States Energy Information Administration (EIA). 2018. Pennsylvania Crude Oil
First Purchase Price (Dollars per Barrel). Accessed May 25, 2018. Available
electronically at: https://www.eia.gov/dnav/pet/pet pri dfpl k a.htm
SGE01443
United States Environmental Protection Agency (U.S. EPA). 2018. Detailed Study of
the Centralized Waste Treatment Point Source Category for Facilities Managing Oil and
Gas Extraction Wastes
SGE01444
United States Office of Management and Budget (OMB). 2003. Circular A-4.
September 17, 2003. Available online at:
https://www.whitehouse.gov/sites/whitehouse.gov/files/omb/circulars/A4/a-4.pdf
SGE01445
Hyne, Norman J. 2012. Nontechnical Guide to Petroleum Geology, Exploration,
Drilling & Production: Third Edition. Tulsa, OK: PennWell Corporation
SGE01446
Eastern Research Group, Inc. (ERG). 2018. USGS Produced Water Characterization
Analysis
SGE01447
United States Geological Survey (USGS). 2018. U.S. Geological Survey National
Produced Waters Geochemical Database v2.3
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
References
Table 6. Reference List
DCN
Reference
SGE01449
U.S. Census Bureau. 2018. U.S. Census Bureau, Number of Firms, Number of
Establishments, Employment, and Annual Payroll by Enterprise Employment Size for
the United States, All Industries: 2015
SGE01450
Pennsylvania Department of Environmental Protection (PA DEP). 2016. Revised 2016
PA DEP Waste Reports - Mover
SGE01451
Pennsylvania Department of Environmental Protection (PA DEP). 2016. Revised 2016
PA DEP Waste Reports - HighPoint
SGE01452
Mittal D. 2018. FRS Facilities Capacities
SGE01453
Kepler D. 2018. Question on Kane Facility
SGE01454
Eastern Research Group, Inc. (ERG). 2018. Water Quality Standards relevant to the
Appalachian Basin
SGE01461
Eastern Research Group, Inc. (ERG). 2019. Stripper Well Analysis database 2016
SGE01462
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
To Alcosan - Trucking Time to POTWs
SGE01463
United States Environmental Protection Agency (U.S. EPA). 2018. Nearest CWTs to all
wells
SGE01464
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Alcosan - Trucking Time to UICs
SGE01465
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Brockway - Trucking Time to POTWs
SGE01466
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Brockway - Trucking Time to UICs
SGE01467
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Reynoldsville - Trucking Time to POTWs
SGE01468
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Reynoldsville - Trucking Time to UICs
SGE01469
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Ridgeway 1 - Trucking Time to Ridgeway
SGE01470
United States Environmental Protection Agency (U.S. EPA). 2018. Wells to Ridgeway
1 - Trucking Time to UICs
SGE01471
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Ridgewav 2 - Trucking Time to Ridgewav
SGE01472
United States Environmental Protection Agency (U.S. EPA). 2018. Wells to Ridgeway
2 - Trucking Time to UICs
SGE01473
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Ridgewav 3 - Trucking Time to Ridgewav
SGE01474
United States Environmental Protection Agency (U.S. EPA). 2018. Wells to Ridgeway
3 - Trucking time to UICs
SGE01475
United States Environmental Protection Agency (U.S. EPA). 2018. 0817 origins 1 to
0817 destinations 1
SGE01476
United States Environmental Protection Agency (U.S. EPA). 2018. 0817 origins 2 to
0817 destinations 2
SGE01477
United States Environmental Protection Agency (U.S. EPA). 2018. Origins 1 to
Destinations 1
9-4
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
References
Table 6. Reference List
DCN
Reference
SGE01478
United States Environmental Protection Agency (U.S. EPA). 2018. Origins 2 to
Destinations 2
SGE01479
United States Environmental Protection Agency (U.S. EPA). 2018. Origins 3 to
Destinations 3
SGE01480
United States Environmental Protection Agency (U.S. EPA). 2018. 0824 Last GIS data
for EPA Results (003)
SGE01481
United States Environmental Protection Agency (U.S. EPA). 2018. Wells Discharging
to Brockway - Trucking Time to Nearest CWTs
SGE01482
Oberlander D. 2016. Letter from Commonwealth of PA House of Representatives Oil
and Gas Caucus to Administrator McCarthy
SGE01484
United States Environmental Protection Agency (U.S. EPA). 2019. EPA UOG Financial
Impact Analysis - Sanitized.
SGE01485
ESRI. 2019. Find Nearest - ArcGIS Online Help, https://doc.arcgis.com/en/arcgis-
online/analvze/find-nearest.htm. Accessed on February 6, 2019
SGE01486
Common Wealth of Pennsylvania. 1987. Pennsylvania Code CHAPTER 78. OIL AND
GAS WELLS
SGE01494
United States Environmental Protection Agency (U.S. EPA). 2019. Response to
Handouts from EPA Site Visit.
SGE01523
U.S. EIA. 2019. Distillate Fuel Oil and Kerosene Sales by End Use.
SGE01534
U.S. EPA. 2000. Development Document for Final Effluent Limitations Guidelines and
Standards for the Centralized Waste Treatment Industry. EPA-821-R-00-020.
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APPENDIX A
Alternative Wastewater Management Analysis Database and Spreadsheet Structures
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Appendix A
APPENDIX A. ALTERNATIVE WASTEWATER MANAGEMENT ANALYSIS
DATABASE AND SPREADSHEET STRUCTURES
The following subsections describe the structures and contents of the underlying data
files used to perform the Alternative Wastewater Management Analysis described in Section 3.
A-l. PA PEP Waste and Production Reports Table Field Descriptions (Step 1)
PA DEP requires all operators to report oil, gas, and waste generation for oil and gas
wells, including waste generated at wells in Pennsylvania that is transferred to another state. For
waste generation, operators must report waste quantity, waste type, and waste management
information for each well they operate. For production, operators must report oil, gas, and
condensate production quantities for each well they operate. Both the production and waste
reports include other identifying information such as well API number, production period, well
configuration (horizontal, vertical), and resource type (UOG or COG) as defined by PA DEP. PA
DEP periodically publishes aggregated reports containing these waste and production data
henceforth referred to as PA DEP Waste Reports22 and PA DEP Production Reports23,
respectively.
Table A-l describes the report data fields from PA DEP, which are used in all the
databases and spreadsheets EPA created for this cost analysis.
Table A-l. PA DEP Waste Reports Table Field Descriptions
Field Name
Description
Well Permit #
The number of the permit that was issued to the oil and gas operator for this well by
the PA DEP. This is equivalent to well API number.
Period Id
A code value indicating the 4-digit reporting year and a number indicating the report
period, where: 0=Annual; l=Marcellus 6-month from Jan-June; 2=Marcellus 6-
month from July-December; and 3=Initial Marcellus 12-month reporting period from
7/1/2009 through 6/30/2010.
Well Status
An indicator of the well's current status, where: Inactive=not drilled yet and
Active=producing. Other acceptable values for this field are "Plugged" and
"Abandoned."
Farm Name
The name given to a well by the well operator. Name usually corresponds with the
landowner at the time of permitting, which does not change. The farm name and well
# normally produce a unique identifier for the well.
Well#
The number of the well assigned by the well operator. Usually follows the farm name
(above).
Waste Type
The type of waste that was generated at the well.
Waste Quantity
The amount of the waste product that was generated at the well.
Units
The unit of measure that was used for the generated waste.
Disposal Method
The method used to dispose of the waste generated at the well.
22 EPA downloaded these reports on 2/12/2018 (see DCN SGE01421).
23 EPA downloaded 2006 through 2016 production data on 1/3/2018 and downloaded 2017 production data on
6/15/2018 (see DCN SGE01422).
A-l
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Appendix A
Table A-l. PA DEP Waste Reports Table Field Descriptions
Field Name
Description
Averaged
This Y/N field indicates whether the production and waste amounts were averaged
(Y) or not (N). If Y, they were averaged based on the group of wells to which the
belongs. If N, the reported amounts are specific to the well.
Operator Name
The organizational name of the well operator reporting well production during all or
a portion of the reporting period. Several operators may report during the reporting
period based on their period of control.
OGO#
The oil and gas operator (OGO) Id of the operator of the well during the report
period. Several operators may report during the reporting period based on their period
of control.
Well County
The County in which the well is located.
Well Municipality
The Municipality in which the well is located.
Well Latitude
The latitude value, in decimal degrees, for the permitted well location.
Well Longitude
The longitude value, in decimal degrees, for the permitted well location.
Unconventional
A yes or no indicator that identifies a bore hole drilled or being drilled to be used to
produce natural gas from an unconventional formation as defined by PA. Note: see
Section 2.1 for discussion of the differences between PA DEP's and the 2016
UOG rule's definitions of UOG.
Well Configuration Code
An indicator code that describes whether a well is horizontal, vertical, or
intentionally deviated. A value of "HORIZ" indicates that the well is a horizontal
well, meaning a well is initially drilled vertically then curved to become horizontal
(or near horizontal) to parallel a particular geologic formation. Intentionally deviated
wells are indicated by a value of "DEVIA", whereas vertical wells are indicated by a
value of "VERTI".
Home Use
A yes or no indicator that represents whether the well has been identified as a home
use well or not. Home use wells have no commercial production and the product is
used entirely on the property.
Waste Facility Permit #
The permit number of the waste facility that the waste product was taken to if the
facility was permitted by DEP.
Waste Facility Name
Name of the facility that accepted and treated the waste products from the well.
Facility Address 1
The primary address of the waste facility.
Facility Address 2
The optional second line of the address of the waste facility.
Facility City
The municipality in which the waste facility is located.
Facility State
The state in which the waste facility is located.
Facility Zip Code
The zip code of the waste facility.
Facility Phone
The phone number of the waste facility.
Facility Latitude
The latitude value, in decimal degrees, for the waste facility location.
Facility Longitude
The longitude value, in decimal degrees, for the waste facility location.
Reporting Period
The date range of the production or waste report that is being reviewed.
Comment Reason
Well operator comment on the well or group of wells, typically indicating why no
production data were reported.
Comment Text
Well operator comment on a well or group of wells, typically indicating why no
production data were reported.
Formation
A name assigned to a geological section of the earth crust.
Parent Formation
A higher classification of a rock formation.
Source: DCN SGE00763.
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A-2. PA PEP Waste Report and Production Report Development Databases (Step 2)
EPA used the PA DEP reports to identify oil and gas wells in Pennsylvania that
discharged wastewater to POTWs in 2016 and to extract their relevant characteristics such as
production quantities, wastewater quantities, and whether the well meets the 2016 UOG rule's
definition of UOG.
For both the PA DEP Waste and Production Reports, the information is collected directly
from operators and contains a variety of naming conventions, spelling errors, and some missing
or inaccurate information. In addition, PA DEP periodically updates the Waste and Production
Reports to incorporate new and/or corrected data reported by operators. These updates are not
scheduled or announced, which means that new or updated data may have been added after
EPA's download dates of January 3 and February 12, 2018 for the Production and Waste reports,
respectively.
EPA conducted data clean-up activities for information contained in certain data fields
that are key to this cost analysis. These activities included standardizing certain naming
conventions (e.g., waste type, management method, waste facility name), confirming production
data and resolving inconsistent production data (for operators that received data requests), and
filling data gaps in well latitude and longitude and resource type to the extent possible using
other data sources. Data clean-up activities are described and documented in Section 3 and
Appendix A of this report and in supporting documentation in the UOG rulemaking record. For
example, EPA verified that all latitude and longitudes reported by PA DEP fell inside the state of
Pennsylvania before using them for the GIS analysis. Most data were used as downloaded and
assumed accurate because they are reported directly by the operators.
PA DEP Waste Report Development Database
Table A-2 lists and describes the Access queries used to develop and populate the PA
DEP Waste Report Development Database and to format the data for use in future analyses. The
queries perform two primary functions that ultimately create the final database:
1. Combine all waste reports from PA DEP's website (2004 through 2016) into a
single table titled "PA DEP Waste Data" and format the data by removing dashes
from the reported years (queries 000 through 114 in Table A-2).
2. Standardize data reported by operators in select fields using the crosswalk
database tables described below (queries 200 and 201 in Table A-2).
Table A-2. PA DEP Waste Report Development Database Queries
Query Name
Description
000 - Create PA DEP Waste Table
Creates the shell of the final PA DEP Waste Data.
001 - Append Waste 2004-
2009 A11
Appends the 2004 through 2009 waste reports for all oil and gas wells to the
PA DEP Waste Data table (DCN SGE01421.A01).
002 - Append Waste 2010-
2016COG
Appends the 2010 through 2016 waste report for COG wells to the PA DEP
Waste Data table (DCN SGE01421.A02).
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Table A-2. PA DEP Waste Report Development Database Queries
Query Name
Description
003 - Append Waste 2011-
2016UOG
Appends the 2011 through 2016 waste report for UOG wells to the PA DEP
Waste Data table (DCN SGE01421.A03).
100 - Fix 2010 Waste Period ID
Fixes the error associated with the Period ID for 2010 reports (the query
changes values where the period was reported as "#NUM!" to 2010).
101 - Remove Waste dashes-2004
Changes "2004-0" to "2004" in the Period ID field.
102 - Remove Waste dashes-2005
Changes "2005-0" to "2005" in the Period ID field.
103 - Remove Waste dashes-2006
Changes "2006-0" to "2006" in the Period ID field.
104 - Remove Waste dashes-2007
Changes "2007-0" to "2007" in the Period ID field.
105 - Remove Waste dashes-2008
Changes "2008-0" to "2008" in the Period ID field.
106 - Remove Waste dashes-2009
Changes "2009-0" to "2009" in the Period ID field.
107 - Remove Waste dashes-2010
Changes "2010-0", "2010-1", and "2010-2" to "2010" in the Period ID field.
108 - Remove Waste dashes-2011
Changes "2011-0", "2011-1", and "2011-2" to "2011" in the Period ID field.
109 - Remove Waste dashes-2012
Changes "2012-0", "2012-1", and "2012-2" to "2012" in the Period ID field.
110 - Remove Waste dashes-2013
Changes "2013-0", "2013-1", and "2013-2" to "2013" in the Period ID field.
111 - Remove Waste dashes-2014
Changes "2014-0", "2014-1", and "2014-2" to "2014" in the Period ID field.
112 - Remove Waste dashes-2015
Changes "2015-0", "2015-1", and "2015-2" to "2015" in the Period ID field.
113 - Remove Waste dashes-2016
Changes "2016-0", "2016-1", and "2016-2" to "2016" in the Period ID field.
114 - Delete blank Rows
Removes records with a blank permit number from the PA DEP Waste Data
table.
200 - Update Consolidated Waste
Type
Uses the Waste Type Consolidation crosswalk table developed by EPA to
standardize and populate the Consolidated Waste Type data field.
201 - Update Consolidated
Disposal Method and Facility
Uses the Facility Type Consolidation crosswalk table developed by EPA to
standardize and populate the Consolidated Disposal Method, Consolidated
Waste Facility Name and Consolidated Waste Facility Permit Number data
fields.
PA DEP Production Report Development Database
Table A-3 lists and describes the Access queries used to develop and populate the PA
DEP Production Report Development Database (DCN SGE01417) and to format the data for use
in future analyses. The queries perform two primary functions that ultimately create the final
database:
1. Combine all production reports from PA DEP's website (2006 through 2016) into
a single table titled "PA O&G Production Raw Combined" and format the data by
removing dashes from the reported years (queries 001 through 111 in Table A-3).
2. Consolidate data reported by operators to remove any wells producing zero oil,
gas, and condensate (query 200 in Table A-3).
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Table A-3. PA DEP Production Report Development Database Queries
Query Name
Description
001 - Make Raw Combined
Table and Add Download 1
Creates the shell of the PA O&G Production Raw Combined table using the 2016
production report (DCN SGE01422.A01).
002 - Append Download 2
Appends the 2015 production report to the PA O&G Production Raw Combined
table (DCN SGE01422.A02).
003 - Append Download 3
Appends the 2010 through 2014 production reports to the PA O&G Production
Raw Combined table (DCN SGE01422.A03).
004 - Append Download 4
Appends the 2006 through 2010 production reports to the PA O&G Production
Raw Combined table.
005 - Append Download 5
Appends the 2017 production reports to the PA O&G Production Raw Combined
table (DCN SGE01422.A04).
100 - Update Report ID 2016
Changes "2016-0", "2016-1", and "2016-2" to "2016" in the Period ID field.
101 - Update Report ID 2015
Changes "2015-0", "2015-1", and "2015-2" to "2015" in the Period ID field.
102 - Update Report ID 2014
Changes "2014-0", "2014-1", and "2014-2" to "2014" in the Period ID field.
103 - Update Report ID 2013
Changes "2013-0", "2013-1", and "2013-2" to "2013" in the Period ID field.
104 - Update Report ID 2012
Changes "2012-0", "2012-1", and "2012-2" to "2012" in the Period ID field.
105 - Update Report ID 2011
Changes "2011-0", "2011-1", and "2011-2" to "2011" in the Period ID field.
106 - Update Report ID 2010
Changes "2010-0", "2010-1", and "2010-2" to "2010" in the Period ID field.
107 - Update Report ID 2009
Changes "2009-0" to "2009" in the Period ID field.
108 - Update Report ID 2008
Changes "2008-0" to "2008" in the Period ID field.
109 - Update Report ID 2007
Changes "2007-0" to "2007" in the Period ID field.
110 - Update Report ID 2006
Changes "2006-0" to "2006" in the Period ID field.
111 - Update Report ID 2017a
Changes "2017-0", "2017-1", and "2017-2" to "2017" in the Period ID field.
200 - PA DEP O&G
Production by Well
Creates final PA DEP O&G Production Cleaned Up table by removing wells with
zero oil, gas, and condensate production.
a—2017 data were only partially complete for the year at the time EPA downloaded the data.
A-3. PA DEP and DI Desktop® Cross-reference Database (Steps 3 and 4) DI
Pesktop®
Drillinginfo is an oil and gas research firm located in Austin, Texas. DI Desktop® is a
comprehensive database generated by Drillinginfo that contains a record for each oil and gas
well drilled in the United States. Basic well data contained in DI Desktop® for each well
includes: well API number, latitude, longitude, operator, and well trajectory. DI Desktop® also
includes annual oil, gas, and produced water production per well. DI Desktop® includes records
for wells that are no longer active (i.e., shut in), disposal wells, COG wells, coal bed methane
(CBM) wells, and UOG wells. It does not contain a field that indicates if wells are COG or
UOG.
Drillinginfo uses oil and gas databases maintained by individual state oil and gas
agencies to create DI Desktop®. For this analysis, EPA downloaded DI Desktop® on
March 30, 2015. For the most part, the downloaded database that EPA used reflects wells drilled
as of 2014, but it varies by state. State-level information such as the oil and gas agency names,
last production date, production start date, and update frequency (e.g., monthly, quarterly) is
provided by Drillinginfo (DCN).
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EPA used this data source to capture the geological formation in which wells discharging
to POTWs were completed. The geological formation information was subsequently used to
determine whether wells in PA DEP's Waste Reports are defined as UOG by the 2016 UOG
rule's definition of UOG.
EPA assumed that geological formations reported in DI Desktop® were accurate, albeit
incomplete for some wells. EPA spot checked geological formations using EDWIN (EDWIN
data source discussed below); note, however, that EDWIN is the foundation of DI Desktop® for
Pennsylvania oil and gas extraction wells and not an independent data source.
EPA also used DI Desktop® as a supplemental data source to fill data gaps in well
latitude and longitude when not available from other PA DEP data sources, thereby improving
the completeness of 2016 UOG rule defined UOG wells included in EPA's cost analysis.
DI Desktop®
Table A-4 lists the fields in DI Desktop® along with their descriptions.
Table A-4. DI Desktop® Field Descriptions
Field Name
Description
ENTITYID
DI assigned ID unique to a given property. A well is referred to as a "property" in
DI Desktop®.
APINO
API assigned number of a well on the property.
PROPERTYTYPE
Property type (e.g., lease, unit, well, completion, other, unknown).
PRODU CTIONT YPE
Production type (e.g., oil, gas, injection).
PRODTYPECLASS
Classification of production type into D&A (drilled and abandoned), gas,
injection O&G (oil and gas), oil, and other.
PRODFLAG
Production flag to indicate whether the well should be producing liquids. This is
'Yes" for "Gas," "Oil," and "O&G" production type classification.
LIQUIDPRODTYPE
Liquid production type (i.e., unknown condensate, or oil) based on the
production type classification and well test data.
WELL_NAME
Operator assigned well/lease name of the property.
FIELD
Field name the property is reporting from.
CURROPERNAME
Current operator name.
SPUDDATE
Date drilling commenced on property.
COMMONOPERNAME
Corporate entity that is determined by DI to own the current operator.
LATITUDENAD27
Surface latitude the property is located in; for multi-well properties DI Desktop®
picked a well to designate the location of the property, in NAD27 format.
LONGITUDENAD27
Surface longitude the property is located in; for multi-well properties DI
Desktop® picked a well to designate the location of the property, in NAD27
format.
LATITUDENAD83
Surface latitude the property is located in; for multi-well properties DI Desktop®
picked a well to designate the location of the property, in NAD83 format.
LONGITUDENAD83
Surface longitude the property is located in; for multi-well properties DI
Desktop® picked a well to designate the location of the property, in NAD83
format.
COUNTY
County the property is located in.
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Table A-4. DI Desktop® Field Descriptions
Field Name
Description
FIPSCODE
Federal Information Processing Standard (FIPS) county code based on county or
GIS analysis using latitude and longitude.
DISTRICT
District within a given state the property is assigned.
STATE
State the property is located in.
EPAREGION
EPA region the property is located in.
OFFSHORE
Offshore waters indicator.
RESERVOIR
Reservoir, formation, zone, or pool that the property is reported as producing
from.
BASIN
The basin the property is located in.
FORMATION
Formation that the property is reported as producing from.
STATUS
Current status of the well (e.g., active, inactive, shut in).
TOTALDEPTH
Total depth the well was drilled to.
PLUGDATE
Date the well was plugged. Note: for instances where duplicate API numbers
were combined, the maximum value was selected.
COMPLETIONDATE
Most recent completion date of the well.
COMPLETIONYEAR
Year of the completion date.
Well Trajectory
This is the configuration of the wellbore. Options include: H - Horizontal; D -
Directional; V - Vertical; U - Unknown.
FIRSTPRODDATE
First date of reported production for the property. Note: for instances where
duplicate API numbers were combined, the minimum value was selected.
LASTPRODDATE
Last date production was reported for the property.
LATITUDEBOTM
Bottom hole latitude of the property.
LONGITUDEBOTM
Bottom hole longitude of the property.
SumOfLIQ[xx]
Annual oil production in barrels. A separate column is provided for each year
from 2000 (i.e., "SUMOFLIQOO") through 2014 (i.e., "SUMOFLIQ14").
SumOfGAS[xx]
Annual Gas production in thousand cubic feet. A separate column is provided for
each year from 2000 (i.e., "SUMOFGAS00") through 2014 (i.e.,
" SUMOF GAS 14").
SumOfWTR[xx]
Annual produced water production in barrels. A separate column is provided for
each year from 2000 (i.e., "SUMOFWTR00") through 2014 (i.e.,
" SUMOF WTR14").
PROD [xx] FLAG
Yes/No flag indicating if oil and/or gas production was greater than zero for a
given year. A separate column is provided for each year from 2000 (i.e.,
"PROD00 FLAG") through 2014 (i.e., "PROD 14 FLAG").
ACTIVEFLAG
Yes/No flag indicating whether or not a well is active based on production.
ACTIVEPRODFLAG
Yes/No flag indicating whether the entity (i.e., property) is active (using the
ACTIVE FLAG field) and had production in 2014 (using the PROD14 FLAG
field).
PA DEP and DI Desktop® Cross-Reference Database Queries
Table A-5 lists and describes the Access queries used to develop and populate the PA
DEP and DI Desktop® Cross-reference Database and to format the data for use in future
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analyses. The queries perform three primary functions key to creating the final database for use
in the Alternative Wastewater Management Analysis:
1. Identify the subset of wells that are the subject of this Alternative Wastewater
Management Analysis (i.e., those discharging to POTWs in 2016 and that meet
the 2016 UOG rule's definition of UOG) (queries 000a through 108c in Table A-
5).
2. Populate well location data for use in the GIS analysis (Step 5) (queries 110a
through 115c in Table A-5).
3. Collate summary information about the operators of the wells subject to the
Alternative Wastewater Management Analysis, such as number of active wells,
other wastewater management practices, and oil and gas production from 2006 to
2016 (queries 200 through 203 in Table A-5).
Table A-5. PA DEP and DI Desktop® Cross-Reference Database Queries
Query Name
Description
000a - Make PA DEP Waste Data
Table
Creates the shell of the PA DEP Waste Data table using the PA DEP
Waste Data table from the PA DEP Waste Reports Development
Database (DCN SGE01416).
000b-Update API
Adds the Well API number to the PA DEP Waste Data table using the
Well Permit Number listed in that table.
000c - delete empty row
Removes records with a blank permit number from the PA DEP Waste
Data table.
001 - Update No to N for PA DEP
UOG Flag
Revises the PA DEP UOG Flag field to "N" where it says "No."
002 - Update Yes to Y for PA DEP
UOG Flag
Revises the PA DEP UOG Flag field to "Y" where it says "Yes."
100 - Update with DI Desktop® Info
Adds DI Desktop® data to the PA DEP Waste Data table using the Well
API number as the link (DCN SGE01170).
101 - Update with PA DEP Formation
Info
Adds PA DEP Formation data to the PA DEP Waste Data table using the
Well API number as the link (DCN SGE01375).
102a - Update EDWIN for Tight
Adds tight flag to EDWIN formation records that are listed as tight by
EIA.
102b - Update EDWIN for Shale
Adds shale flag to EDWIN formation records that are listed as shale by
EIA.
102c - Update EDWIN for COG
Adds COG flag to all EDWIN formation records that are not listed as
shale or tight by EIA.
102d - Find EDWIN UOG Wells
Finds wells identified as tight or shale and assigns them as UOG.
102e - Find EDWIN COG Wells
Finds wells not identified as UOG and assigns them as COG.
102f - Update PA DEP Table with
EDWIN UOG
Updates PA DEP Waste Data table with wells in EDWIN identified as
UOG
102g - Update PA DEP Table with
EDWIN COG
Updates PA DEP Waste Data table with wells in EDWIN identified as
COG
103a - Update Consolidated Formation
- Step 1
Updates the formation name to the formation name listed in the DI
Desktop® data.
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Table A-5. PA DEP and DI Desktop® Cross-Reference Database Queries
Query Name
Description
103b - Update Consolidated Formation
Where the formation name is blank in the DI Desktop® data, updates the
formation name to the formation name listed in the PA DEP Formation
Database (DCN SGE01375).
103c - Update Consolidated Formation
Where the formation name is blank in the DI Desktop® data, updates the
formation name to the formation name listed in EDWIN, if reported.
105 - Update Tight Flag
Updates the EIA Tight/Shale Flag to "Tight" when the formation name
contains a known tight formation. A list of known tight formations is
provided in the query design table.
106 - Update Shale Flag
Updates the EIA Tight/Shale Flag to "Shale" when the formation name
contains a known shale formation, or the PA DEP Waste Data
Unconventional Flag is "Y." A list of known shale formations is provided
in the query design table.
107 - Update Unknown Formations
Updates the EIA Tight/Shale Flag to "Unknown" when the formation
name is blank or listed as unnamed.
108a - Update UOG resource Flag
Updates the EPA Resource Type field to "UOG" when the PA DEP
Waste Data Unconventional Flag is "Y," or the EIA Tight/Shale Flag is
"Shale" or "Tight."
108b - Update Unknown resource Flag
Updates the EPA Resource Type field to "Unknown" when the PA DEP
Waste Data Unconventional Flag is "N," and the EIA Tight/Shale Flag is
"Unknown."
108c - Update COG resource Flag
Updates the EPA Resource Type field to "COG" when the PA DEP
Waste Data Unconventional Flag is "N," and the EIA Tight/Shale Flag is
blank.
109 - Update 308 Letter Flag
Adds a flag to operators that were selected to receive 308 letters.
110a - Update Bad Lat Longs
Removes latitudes and longitudes that are outside of Pennsylvania.
110b - Update Lat Long Source
Changes the source blank latitudes and longitudes to PA DEP Waste
Reports.
11 la - Update Missing Lat Longs
Using PA DEP Prod Data
Updates blank latitudes and longitudes to latitudes and longitudes listed
in the PA DEP Production Reports (DCN SGE01422).
11 lb - Update Bad Lat Longs
Removes latitudes and longitudes that are outside of Pennsylvania.
112a - Update Missing Lat Longs
Using PA DEP Spud Data
Updates blank latitudes and longitudes to latitudes and longitudes listed
in the PA DEP Spud Data (DCN SGE01246).
112b - Update Bad Lat Longs
Removes latitudes and longitudes that are outside of Pennsylvania.
113a - Update Missing Lat Longs
Using DI Desktop®
Updates blank latitudes and longitudes to latitudes and longitudes listed
inDI Desktop® (DCN SGE01170).
113b - Update Bad Lat Longs
Removes latitudes and longitudes that are outside of Pennsylvania.
114a - Avg lat long by farm name
Averages all latitudes and longitudes for a given farm name.
114b - Update Missing Lat Longs
Using Farm Values
Updates blank latitudes and longitudes to the average latitude and
longitude determined using farm name.
114c - Update Bad Lat Longs
Removes latitudes and longitudes that are outside of Pennsylvania.
115a - Avg lat long by municipality
Averages all latitudes and longitudes for a given municipality.
115b - Update Missing Lat Longs
Using Municipality Values
Updates blank latitudes and longitudes to average latitude and longitude
determined using municipality name.
115c - Update Bad Lat Longs
Removes latitudes and longitudes that are outside of Pennsylvania.
200 - List of Operators Discharging to
POTWs in 2016
Finds operators discharging wastewater to POTWs in 2016 using their oil
and gas operator number.
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Table A-5. PA DEP and DI Desktop® Cross-Reference Database Queries
Query Name
Description
201 - Discharging Operators - All
Waste Data
Groups the data from the PA DEP Waste Data table to show all waste
data consolidated in the POTW-Dischargers - All Waste Data table.
202 - Discharging Operators - 2016
POTW Waste Data
Groups the data from the POTW-Dischargers - All Waste Data table to
show 2016 data in the POTW-Dischargers - 2016 POTW Waste Records
table.
203 - Discharging Operators - All
O&G Production
Groups the data from the PA DEP Production Reports based on operators
discharging in 2016 to make the POTW-Dischargers - All O&G
Production table.
Additional PA DEP Data
The PA DEP Oil and Gas Well Formations Report (DCN SGE01375)24 lists all oil and
gas wells and the oldest, target, and/or the producing formations. EPA used this data source to
fill data gaps in formation names provided by DI Desktop® (DI Desktop® data source discussed
below). EPA considers the PA DEP Oil and Gas Well Formations Report the best available
alternative data source to fill data gaps, thereby improving the completeness of 2016 UOG rule
defined UOG wells included in EPA's cost analysis.
Exploration and Development Well Information Network (EDWIN) (DCN SGE01420) is
maintained by the Pennsylvania Department of Conservation and Natural Resources, Bureau of
topographic and Geological Survey, providing records for more than 104,000 oil and gas wells
drilled in Pennsylvania. EDWIN provides access to both scanned oil and gas well documents and
associated digital and interpreted data through a single web-based application. EPA considers
EDWIN to be the best available data source to fill remaining formation data gaps, thereby
improving the completeness of 2016 UOG rule defined UOG wells included in EPA's cost
analysis.
The PA DEP SPUD Data Report (DCN SGE01246)25 is a database that contains
Pennsylvania oil and gas SPUD data through December 2018. EPA used this data source to
replace inaccurate (i.e., outside Pennsylvania) and missing well latitudes and longitudes in the
PA DEP Production and Waste Reports for this analysis. EPA considers the PA DEP SPUD Data
Report to be the best available data source to fill location data gaps, thereby improving the
completeness of 2016 UOG rule defined UOG wells included in EPA's cost analysis.
A-4. GIS Analysis Output Results File (Step 6)
Table A-6 lists the GIS analysis output results file which are contained in the docket.
Each record in these files contains a starting location (e.g., discharging UOG well), ending
location (e.g., POTW, CWT), and the resulting travel distance and time estimated by EPA using
ArcGIS Online.
24 Downloaded on 8/8/2016 from
www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx?/Oil Gas/OG Well Formations.
25 Downloaded on 1/2/2018.
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Table A-6. Analysis Output Results Files
Destination(s)
Filename
DCN#
POTWs Receiving
Wastewater
WellsDischargingT o_Alcosan_-_T rackingT imetoPOT Ws. xlsx
SGE01462
CWT Facilities
Nearest October 02 2018 CWTs to October 02 2018 wells all.xlsx
SGE01463
Disposal Wells
Wells_Discharging_to_Alcosan_-_Trucking_Time_to_UICs.xlsx
SGE01464
POTWs Receiving
Wastewater
Wells_Discharging_to_Brockway_-_Trucking_Time_to_POTWs.xlsx
SGE01465
Disposal Wells
Wells_Discharging_to_Brockway_-_Trucking_Time_to_UICs.xlsx
SGE01466
POTWs Receiving
Wastewater
Wells_Discharging_to_Reynoldsville_-_Trucking_Time_to_POTWs.xlsx
SGE01467
Disposal Wells
Wells_Discharging_to_Reynoldsville_-_Trucking_Time_to_UICs.xlsx
SGE01468
Ridgeway POTW
Wells_Discharging_to_to_Ridgeway_l_-
_T rackingT imetoRidgeway .xlsx
SGE01469
Disposal Wells
Wells_to_Ridgeway_l_-_Trucking_Time_to_UICs.xlsx
SGE01470
Ridgeway POTW
Wells_Discharging_to_Ridgeway_2_-
_T rackingT imetoRidgeway .xlsx
SGE01471
Disposal Wells
Wells_to_Ridgeway_2_-_Trucking_Time_to_UICs.xlsx
SGE01472
Ridgeway POTW
Wells_Discharging_to_Ridgeway_3_-
_T rackingT imetoRidgeway .xlsx
SGE01473
Disposal Wells
Wells_to_Ridgeway_3_-_Trucking_time_to_UICs.xlsx
SGE01474
All Disposal Methods
0817origins l_to_0817destinations 1 .xlsx
SGE01475
All Disposal Methods
0817origins2_to_0817destinations2.xlsx
SGE01476
CWT, POTW, or
Disposal Wells
OriginsltoDestinationsl .xlsx
SGE01477
CWT, POTW, or
Disposal Wells
Origins_2_to_Destinations_2.xlsx
SGE01478
CWT, POTW, or
Disposal Wells
Origins_3_to_Destinations_3 .xlsx
SGE01479
Townships for road
spreading
0824 Last GIS data for EPA Results (003).xlsx
SGE01480
CWT Facilities
WellsDischargingtoBrockway-
_Trucking_Time_to_Nearest_CWTs.xlsx
SGE01481
A-5. UOG Alternative Wastewater Management Analysis (Step 8, 9, and 10)
EPA's primary data source for transportation and management costs are the responses
completed by the eight facilities that responded to EPA's data request. EPA also used
management costs obtained during EPA site visits and conference calls with oil and gas, CWT
facility, and disposal well operators. These site visits and conference calls were conducted by
EPA in support of the UOG rulemaking (DCN SGE01188) and CWT Study (DCN SGE01443).
The management costs reported by these operators are often reported in general ranges because
management costs vary by other factors that are determined on a case-by-case scenario. EPA
assumes that cost information provided in responses to EPA's data request and collected during
site visits and conference calls are accurate because they are reported directly by the operators
and wastewater management facilities.
The "Cost Assumptions and Calcs." worksheet in the Alterative Wastewater Management
Analysis (DCN SGE01419) describes the origin of data and assumptions used throughout this
A-ll
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Appendix A
analysis. Specifically, it provides a description of the data used to develop baseline costs for
operators who discharged UOG wastewater to POTWs in 2016 and the data used to estimate
incremental costs for these operators to eliminate UOG wastewater discharges to POTWs.
A-6. Stripper Well Analysis for Table 2-3 and Figure 2-3
Table A-7 lists and describes the Access queries in EPA's Stripper Well Analysis
database (DCN SGE01461) used to identify and flag stripper wells oil and gas wells in PA
DEP's waste and production reports. EPA created this database to create Table 2-3. The queries
perform two primary functions:
1.
Identify stripper wells in PA DEP's 2016 waste and production databases (queries
00 through 03). Section 3.1.9 also describes the detailed criteria used to identify
stripper wells.
2.
Calculate summary statistics for Table 2-3 (queries 04 through 23).
Table A-7. Stripper Well Database Query Descriptions
Query
Description
00
Filters PA DEP's O&G Production well data to only include wells producing in 2016 and creates the
"2016 O&G Producing Wells" table.
01
For each well in the in "2016 O&G Producing Wells" table, this query calculates gas to oil ratio for
each well by dividing 2016 gas quantity (cubic feet) by 2016 oil production quantity (barrels).
02
For each well in the in "2016 O&G Producing Wells" table, this query calculates oil production per day
for each well by dividing 2016 oil quantity (barrels) by 2016 number of oil production days.
03
For each well in the in "2016 O&G Producing Wells" table, this query populates the "stripper well"
column using EPA's stripper well criteria: wells that produce less than 10 barrels per day and do not
have a gas to oil production ratio greater than 15,000 cubic feet per day.
04
This query finds the unique number of operators producing oil and gas in 2016.
05
This query finds the unique number of operators producing oil and gas in 2016, excluding stripper
wells.
10
Filters "PA DEP Waste Data" for 2016 records and sums wastewater volume by well. All wells are
included.
11
Groups query 10 results by operator by summing the wastewater volume by operator and by well
resource type and counting the number of wells.
12
Groups query 11 results by counting the number of operators, summing the number of wells, and
summing the wastewater volume by well resource type.
13
Groups query 11 results by OGO number (i.e., operator ID) to identify the number of operators
producing wastewater in 2016.
20
Filters "PA DEP Waste Data" for 2016 records and sums wastewater volume by well (stripper wells
excluded).
21
Groups query 20 results by operator by summing the wastewater volume by operator and by well
resource type and counting the number of wells (stripper wells excluded).
22
Groups query 21 results by counting the number of operators, summing the number of wells, and
summing the wastewater volume by well resource type (stripper wells excluded).
23
Groups query 11 results by OGO number (i.e., operator ID) to identify the number of operators
producing wastewater in 2016 (stripper wells excluded).
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations Appendix B
APPENDIX B
Cost Sensitivity Analysis
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Appendix B
APPENDIX B COST SENSITIVITY ANALYSIS
Sensitivity analysis is an important component in the production of robust cost analysis
results. These sensitivity analyses assess the effects of alternative assumptions regarding the
effects of the UOG final rule under an alternative scenario. For this cost analysis, EPA
performed a sensitivity analysis on choosing the second rather than the first closest alternative
CWT facility or disposal well. All other cost analysis methodologies and assumptions remain the
same as those described in Section 3.
Table B-l presents summary statistics of the cost results from the sensitivity analysis,
together with the change as compared to the original cost results. Conducting the Alternative
Wastewater Management Analysis by mapping wells to send wastewater to the second nearest
CWT facility or disposal well, instead of the nearest, increases transportation costs by $128,000
and decreases management costs by $8,300. Overall, managing wastewater using the second
closest facility versus the closest resulted in total incremental costs of $184,619 as compared to
$64,907, respectively.
Table B-l. Sensitivity Scenario (Second Closest CWT Facility/Disposal Well) Alternative
Wastewater Management Analysis Results (2016)
Cost Output
Result
Sensitivity
Analysis Result
Change
(+/-)
Baseline Costs
A. Operators Discharging 2016 UOG Rule Defined UOG
Wastewater to POTWs
22
22
0
B. Total Oil and Gas Wells (UOG and COG) Producing Oil or
Gas Owned by (A) Operators
18,136
18,136
0
C. Total Oil and Gas Wells (UOG and COG) Generating
Wastewater Owned by (A) Operators
5,863
5,863
0
D. Total Baseline Costs for (B) Wells
$6,043,304
$6,043,304
0
Incremental Costs
A. Total Wells with Incremental Costs
959
959
0
B. Total Incremental Transportation Cost ($)
$21,109
$149,120
+$128,011
C. Total Incremental Management Cost ($)
$43,798
$35,499
-$8,299
D. Total Incremental Transportation and Management Cost ($)
(B+C=D)
$64,907
$184,619
+$119,712
Source: DCN SGE01419.
For the impacts analysis, results of the sensitivity analysis show 7 entities will be baseline
closures, and 0 of the remaining 15 will close because of incremental compliance costs.
Therefore, the sensitivity analysis shows no change in entity closures as compared to the original
analysis.
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Supplemental Technical Support Document for the ELGs
for Unconventional Oil and Gas Operations
Appendix B
Table B-2. Sensitivity Scenario (Second Closest CWT Facility/Disposal Well): Results of
Baseline and Post-Compliance Analysis (2016)
Results of Baseline and Post-Compliance Analysis
Baseline Closures
7 of 22 Entities
Post-Compliance Closures
0 of 15 Entities
Source: DCN SGE01484.
Table B-3 summarizes the results of the sensitivity scenario on the cost-to-revenue
analysis. EPA estimates that 7 small entities would incur costs exceeding 1 percent of revenue
but less than 3 percent of revenue, and 1 small entity would incur costs of at least 3 percent of
revenue.
Table B-3. Sensitivity Scenario (Second Closest CWT Facility/Disposal Well): Entity
Annualized Cost-to-Revenue (CTR) Results
Number of Entities
with CTR <1%
Number of Entities
with CTR 1-3%
Number of Entities
with CTR >3%
Revenue - Year 1
14
7
1
Source: DCN SGE01484.
B-2
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