U.S.-China Shale Gas Training Program
Environmental Policy and Technology for Shale Gas Development
December 3-4, 2015, Beijing, China
U.S. Environmental Standards and
Regulations for Shale Gas Development
David L. Wochner, Partner
K&L Gates LLP – Washington, DC
Tel. +1.202.778.9014
david.wochner@klgates.com
© Copyright 2015 by K&L Gates LLP. All rights reserved.
Global Oil and Gas Counsel Across Five Continents
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US REGULATORY CONSIDERATIONS
 Natural gas activities impacted
 Environmental issues in the upstream natural gas sector
 Federal role in US shale gas regulation and
management
 Current issues impacting shale gas development
 Lessons learned from U.S. shale gas development
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OIL & GAS INDUSTRY ACTIVITIES IMPACTED BY
ENVIRONMENTAL REGULATION
 Upstream – extraction and production
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Facility siting
Facility design
Drilling and development activities
Long-term operations
 Midstream – gathering, processing, and transportation
 Facility siting and design (pipelines, compressor stations,
dehydration stations, etc.)
 Long-term operations
 Downstream – exports, end uses, electric generation,
petrochemical facilities
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ENVIRONMENTAL ISSUES IN THE OIL AND GAS E&P
SECTOR
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Environmental assessment and planning
Well pad siting and design / support facility siting and design
Well construction – casing and cementing standards
Hydraulic fracturing fluid chemical composition & disclosure
Water withdrawal – location, amount & conditions
Flowback and produced water management (storage, treatment &
disposal)
Drill cutting and waste management
Surface management of chemicals
Emergency and contingency planning / training / response
Air emissions (during construction, operations, transportation)
Liability issues – for pre-existing conditions on land, releases during
development & operations; stray gas
Response to community & environmental group concerns
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FEDERAL ROLE IN US SHALE GAS REGULATION
 Most oil and natural gas well regulation in the United
States is focused at state agency level
 Substantial experience accumulated over many decades in state
environmental and oil & gas management agencies
 Historically, there has been relatively limited US federal
agency involvement in regulation of upstream oil and gas
production
 Over the last few years the US federal government is
increasingly involved, incrementally regulating and
investigating various aspects of unconventional
production activities
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THE AGENCIES – US EPA
 Assessment of the Potential Impacts of Hydraulic Fracturing on
Drinking Water Resources – July 2015 Draft Study
 Indicates that EPA “did not find evidence [of] widespread, systemic
impacts on drinking water resources” from hydraulic fracturing
 Draft is currently undergoing peer review by the agency’s scientific
advisory board hydraulic fracturing panel
 The panel has held a series of public teleconferences and meetings next one is scheduled for December 3, 2015
 Proposed rules/draft guidance regulating air emissions, including
methane and VOCs, from oil and gas sources – August 18, 2015
 Establish control techniques guidelines (CTGs) for VOC emissions from
existing oil and gas sources in ozone nonattainment areas
 Amend the definition of “adjacent” for the purpose of EPA’s
determination whether to aggregate emissions from interconnected oil
and gas sources.
 Public comment period is scheduled to close on December 4, 2015
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THE AGENCIES – US EPA
 Amendments to EPA GHG reporting program for oil and
gas sources
 On October 22, 2015, EPA finalized amendments to its GHG
reporting program rules for oil and gas sources
 Expands the scope of the GHG reporting program to gathering
and boosting systems, completions and workovers of oil wells
with hydraulic fracturing, and blowdowns of natural gas
transmission pipelines
 EPA’s “Waters of the United States” (WOTUS) rule
 EPA released the final WOTUS rule on May 27, 2015
 Industry’s position is that it dramatically expands the definition of
the Clean Water Act jurisdiction to areas that are often dry
 Highly political and currently subject to significant litigation in
multiple federal trial and appellate courts
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THE AGENCIES – US EPA
 Effluent Limitation Guidelines (ELGs) for the Oil and Gas
Extraction Point Source Category
 On March 31, 2015, EPA released a proposed rule that would
prohibit the discharge of oil and gas wastewater to POTWs
(which is generally consistent with current industry practice)
 EPA Response to Environmental Integrity Project (EIP)
Petition to add upstream oil and gas operations to Toxic
Release Inventory (TRI) under EPCRA
 EPA’s October 22, 2015 response indicates that it plans to
propose a rule that would make natural gas processing facilities
subject to the TRI reporting program, but not other upstream oil
and gas sources
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THE AGENCIES – US EPA
 EPA Inspector General Evaluation of EPA and State
Regulation of Hydraulic Fracturing – July 16, 2015
 Office of Inspector General’s final report identifies two issues in
need of improvement by EPA: (1) oversight of permit issuance
for hydraulic fracturing using diesel fuels; and (2) a plan for
responding to comments on a proposed rule regarding regulation
of hydraulic fracturing chemicals
 Permitting Guidance for oil and gas hydraulic fracturing
activities using diesel fuels
 Final guidance released on February 11, 2014
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THE AGENCIES – US EPA
 Study of induced seismicity related to underground
injection disposal wells – February 6, 2015
 EPA announced in January 2012 it was preparing a
“considerations document” of induced seismicity issues, focusing
on well sites in West Virginia, Arkansas, and Texas
 EPA Inspector General Evaluation of Efforts to Address
Methane Emissions From Natural Gas Distribution
Pipelines – July 25, 2014
 Final report evaluates what actions EPA has taken to reduce
methane emissions from leaking distribution pipelines and
recommends the agency consider whether further regulations are
needed
 Also suggests EPA work with the PHMSA to deal with methane
leaks
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THE AGENCIES – US DEPARTMENT OF ENERGY
 "Blueprint for a Secure Energy Future" – Spring 2011
 President Obama directed the DOE Secretary of Energy Advisory Board
(SEAB) Natural Gas Subcommittee to make recommendations to
improve the safety and environmental performance of natural gas
hydraulic fracturing
 The Subcommittee issued a report on August 18, 2011, recommending
actions that federal and state agencies and industry should be taking to
ensure safer operating practices
 SEAB Task Force on FracFocus 2.0 – March 2014
 Major recommendations include modifying FracFocus to accept
“systems” disclosure and commissioning a third party audit
 FracFocus accommodated many of the recommendations and
FracFocus 3.0 was announced on February 26, 2015
 DOE consideration of unconventional production in LNG export
proceedings
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THE AGENCIES – US DEPARTMENT OF THE INTERIOR
 BLM Rules on Hydraulic Fracturing on Federal Lands
 BLM’s final rules regulating hydraulic fracturing on federal lands were
published in the federal register on March 26, 2015
 Focus is on disclosure of chemicals used in the fracturing process,
wellbore integrity and water use and disposal of flow back water
 On September 30, 2015, the U.S. District Court for the District of
Wyoming issued an order preliminarily enjoining BLM’s rules
 On November 27, 2015, Environmental groups appealed the court’s
order issuing the injunction to the 10th Circuit Court of Appeals
 Participation of U.S. Geological Survey in the interagency hydraulic
fracturing coordinating programs with DOE and EPA
 Venting and flaring
 BLM has announced plans to develop new regulations on the conditions
under which venting and flaring of gas production may be authorized
during drilling or production operations on federal lands
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THE AGENCIES – FERC
 FERC has jurisdiction over the construction and operation of
interstate natural gas pipelines and LNG import and export facilities
 The Sierra Club and several national and local environmental
organizations have challenged repeatedly FERC’s failure to
consider alleged impacts of upstream hydraulic fracturing activities
when it is conducting an environmental review of midstream
(pipelines) and downstream (LNG terminals) infrastructure
 They allege that FERC improperly failed to consider upstream “induced”
environmental impacts of hydraulic fracturing due to increased demand
for natural gas for shipping on pipelines or exports through coastal
facility
 More generally, NGOs have increasingly targeted FERC with
protests and letter-writing campaigns
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THE AGENCIES – MISCELLANEOUS AGENCIES
 Department of Homeland Security
 Evaluating whether to allow barges carrying wastewater from hydraulic
fracturing on U.S. rivers
 Department of Health and Human Services
 Centers for Disease Control and Prevention (CDC) has called for a
wider study of potential public health effects of natural gas development
 Agency for Toxic Substances and Disease Registry (ATSDR)
participated in the analysis of groundwater samples from oil and gas
incidents Wyoming and Pennsylvania and issued health consultations
for the sites
 Department of Agriculture
 George Washington National Forest included in its draft Forest Plan a
ban on horizontal drilling
 Securities and Exchange Commission
 In August 2011, the SEC began requesting information from publiclytraded natural gas companies regarding hydraulic fracturing chemicals
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CONTINUING AND EVOLVING ISSUES
 What is appropriate role of federal vs state government?
 What issues warrant uniformity or a floor of regulatory standards?
 What issues require flexibility to address differing conditions across
nation and geologic regions?
 What is appropriate role of local vs. state government?
 What is role of government standards vs. industry best practice
development?
 The long process for statutory and regulatory enactments
 Legal challenges to authority of agencies to consider and regulate
shale gas-related issues
 Nexus between shale gas development and need for infrastructure
to take that gas to market
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LESSONS FROM NORTH AMERICA & OTHER REGIONS
 Shale gas development is a progressive learning / adaptive
management process
 No regulations are perfect
 Environmental analysis / risk management require application of
both common sense and cumulative experience
 The public is a major stakeholder
 Industry’s reputation rests on the performance of every player –
embracing best practices is essential
 Integrated, comprehensive, and predictable environmental
regulations are critical to successful and environmentally beneficial
development
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Questions?
ADDITIONAL REGULATORY MATERIALS
Well Pad & Support Facility Siting
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TYPICAL WELLPAD
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WELL PAD SITING FOR UNCONVENTIONAL OIL AND
GAS
 Average well pad = ~5 acres
(2000 m²), 2-3 acres after
drilling
 Multiple wells – 4-8+ per
well pad
 State regulated
 Laterals = 1.6-2.5 km
 Surface area impact is small
fraction of area tapped
 Lateral location, direction and
distance depend on formation
characteristics
 Horizontal drilling design gives
some flexibility in well pad siting
and impact avoidance
 Access roads, gathering lines
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SITING CONSTRAINTS
 Federal law constraints
 Wetlands & “waters of the United States” - Clean Water Act §404
 Endangered Species Act – designated habitats and avoidance of “takes”
 States:
 Most establish siting constraints and setbacks from sensitive uses, with
provision for variances and exceptions under certain circumstances
 Examples:
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1000 ft. from a water well, surface water intake, reservoir
200 ft. from a public park, forest, game land or wildlife area
Areas that will impact threatened or endangered species
100 ft. from wetland > 1 acre in size
Not in floodplain without variance and special designs
200/500 ft. from a building, absent landowner consent
 Other issues
 Identification of closed / abandoned wells in area
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Facility Design and Construction
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WELL CONSTRUCTION STANDARDS
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Casing & cementing – the most
critical element
Example of modern standards = PA:
25 Pa. Code §§78.81-78.87
 Casing and cementing plan for
every well
 Casing pipe standards
 Surface hole drilled on air,
freshwater, or freshwater based
drilling fluid
 Multi-string casing: conductor
pipe; surface casing;
intermediate casing; production
casing
 Surface casing to 50 ft. below
fresh groundwater, cemented
back to surface
 Centralizers required every 150
ft.
 Where cement circulation lost,
additional casing strings
required
 Cement compressive strength
standards (1200 psi in 72 hrs.)
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WELL PAD DESIGN & CONSTRUCTION
 Requirements for erosion & sedimentation control plans and permits
 Partial exemption in Federal Clean Water Act § 402(l)(2) for discharges
composed entirely of stormwater from oil and gas exploration,
production, processing and transmission operations which “are not
contaminated by contract with, and do not come into contact with, ay
overburden, raw material, intermediate products, finished product,
byproduct or waste products ….”
 State permitting mandates exceed CWA (E.g., 25 Pa. Code Ch. 102)
 State regulations
 Impoundment design and lining systems
 Containment for tanks and chemical storage
 Federal regulations
 Mandates of Federal Clean Air Act §112(r) “general duty” clause
 Oil Pollution Control Act – requirements for SPCC plans and
containment around tanks storing “oil”
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Chemical Use & Disclosure
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CHEMICAL DISCLOSURE REQUIREMENTS IN U.S.
 Chemical disclosure requirements
 Hydraulic fracturing chemical disclosure primarily governed by state
laws
 Federal Emergency Planning & Community Right to Know Law
rules for hazardous chemicals present at sites > certain quantities
 EPA Toxic Substances Control Act
 EPA granted and denied in part an NGO petition under TSCA
 May 2014 ANPRM – range of options under §8 re disclosure of chemicals used
in hydraulic fracturing
 Balancing competing concerns:
 Public trust and disclosure of risks
 Information needs of environmental agencies and medical
professionals to manage and address risks or release events
 Service company concerns for protection of intellectual property
(proprietary recipes and practices)
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EVOLVING STATE CHEMICAL DISCLOSURE LAWS
 Some states (e.g., Colorado, North Dakota, Pennsylvania, Texas)
require chemical information disclosure to public via
www.FracFocus.org Chemical Disclosure Registry or similar
website
 Pennsylvania plans to transition away from FracFocus to a new staterun online database by June 2016
 Other states – information submitted only to state regulatory agency
 What must be disclosed:
 Most: list of chemical ingredients in hydraulic fracturing fluid
(CAS #)
 Some: submission of material safety data sheets
 Some: maximum concentration or range of concentrations
 Exceptions: chemicals not disclosed to operator by mfg, vendor
or service providers, chemicals not intentionally added,
chemicals that occur incidentally or unintentionally present in
trace amounts
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CHEMICAL DISCLOSURE (CON’T)
 When disclosures required:
 Before fracturing treatment, planned chemical use (a few states)
 After treatment, actual chemical use – 20-60 days after
completion (majority of states)
 But: emergency planning rule may separately require certain
disclosures to state and local emergency agencies
 Trade secret protections:
 May limit disclosure to agency
 May require disclosure to agency but limit disclosure to public
(with exceptions for disclosure to medical personnel)
 Useful reference: Congressional Research Services, Hydraulic
Fracturing: Chemical Disclosure Requirements (June 2012)
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Chemical disclosure requirements in eastern states
Pennsylvania
West Virginia
Ohio
information (trade
name, CAS#, max
concentration, volume
of base fluid)
Before: list of
anticipated additives
After: list of additives
actually used, max
concentrations, etc.
with completion report
Trade name, supplier,
and total volume of all
substances, including
max concentration and
CAS# of chemical
additives
When
Within 30 days of well
completion, with
completion report
Within “reasonable
time” of completion,
with completion report
Within 60 days of
completion, with well
log / completion report
Public disclosure
Must submit chemical
disclosure registry
form on FracFocus
within 60 days of HF
Disclosure through
FracFocus
Disclosure through
FracFocus
Trade secret /
proprietary information
protection
Need not be disclosed
except for limited
disclosure to health
professionals and
persons responding to
spill or release
Need not be disclosed
except for limited
disclosure to health
professionals and
WVDEP during
investigation
Trade secrets need not
be disclosed except for
limited disclosure to
health professionals
References
58 Pa.C.S.
§3222(b.1), 3222.1;
25 Pa. Code §78.122
W.Va. Code §22-6A7(e)(5); WVCSR 35-8.
Ohio Rev. Code
§1509.10
What must be disclosed Chemical additive
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Water Withdrawal & Consumption
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WATER RESOURCE REQUIREMENTS FOR SHALE
DEVELOPMENT
 1-5+ million gallons for each well
 25-30% of water emerges as flowback water (much of that in
relatively short time period)
 Water withdrawn and staged; not drawn all at one time
 Opportunity to reuse return flow
 In NE US, ~ 80% of flowback reported to be reused
 Still, significant supplemental water required for makeup
 From an overall perspective, water requirements for shale gas
development are comparatively modest
 Total of all wells < 1 major power plant; < ½ use of golf courses
 But concerns regarding –
 Impacts to small local streams
 Cumulative impacts of many withdrawals in a watershed
 Maintaining a baseline low flow (seasonal impacts)
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APPROACHES TO WATER RIGHTS AND
WITHDRAWALS
 Combination of common law (riparian rights in East, prior appropriation
in West) with increasing shift to regulatory approaches
 Example: Pennsylvania - requirement for Water Management Plan
approval by PA Dept. of Environmental Protection
 Identification of sources (by sub-basin)
 Specific impact questions for each type of source (streams,
groundwater, treated effluent, etc.)
 Monitoring plan and water withdrawal reporting requirements
 Regional regulation in some basins
 Example: Susquehanna River Basin Commission
 Project approval for all shale gas wells
 Review of both withdrawal and consumptive use
 Pass-by flow policy based on seasonal stream flow patterns
and % exceedance flow values.
 Encouragement of shared use and recycling
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KEY ISSUES IN WATER WITHDRAWAL MANAGEMENT
 Cumulative impact considerations – coordination of withdrawals by
multiple operators potentially impacting same waterbody or
watershed
 Pass-by flows – when should withdrawals be suspended during low
flow periods in order to preserve water for downstream users and
in-stream needs (wastewater assimilation and aquatic life)
 SRBC passby flow policy
 West Virginia Water Withdrawal Guidance Tool
 Policies and practices to encourage use of “non-fresh” water
sources (such as treated wastewater effluent)
 Policies and practices to encourage flowback and produced water
reuse and recycling
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PENNSYLVANIA WATER WITHDRAWAL REGULATION
 Pennsylvania water management plans (58 Pa.C.S. §3211(m))
 Oil & gas operator must submit to PaDEP showing sources to be used,
and measures to protect environment and other uses
 PaDEP review considers quantity, withdrawal rate, timing and passby
flow conditions to determine that plan (1) will avoid adverse impact
upon quantity and quality of water available to other users; (2) maintain
existing uses of water source; (3) not cause adverse impact to water
quality in watershed as a whole; and (4) include a reuse plan for fluids
used to fracture wells
 SRBC, DRBC approved withdrawals are presumed to meet criteria
 Section 3211(m)(4) declares that compliance with a DEP-approved
water management plan “shall be deemed to satisfy the laws of this
Commonwealth.” (Signal – common law restrictions on place of use
may be trumped)
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WEST VIRGINIA & OHIO WATER WITHDRAWAL
REGULATION
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West Virginia water management approach (W.Va.CSR 35-8-1 et seq.)
 Water management plan required if withdrawals for drilling, fracturing or
stimulation of a well will exceed 210,000 gallons in any month
 Identify source, location and amount of anticipated withdrawals & downstream uses
 Demonstrate sufficient in-stream flow will be available downstream of withdrawal.
Sufficient in-stream flow is maintained when pass-by flow protective of identified
stream use is preserved
 WVA Water Withdrawal Guidance Tool – provides real-time data to
determine suitability of conditions for withdrawal
 Ohio water withdrawal regulation (Ohio Rev. Code §1501.32 et seq.)
 New requirement for ground and surface water source identification in gas well
applications (Ohio Rev. Code §1509.06(A)(8)(a))
 Withdrawal permit program administered by ODNR for Diversions out of Ohio
Basin > 100,000 gpd
 Withdrawals statewide that would result in a new or increased consumptive use
> 2 mgd averaged over any 30-day period
 New or increased capacity for withdrawal in Lake Erie watershed ≥ 1 mgd;
withdrawal capacity in high quality waters in Lake Erie watershed ≥ 100,000 gpd
(Ohio Rev. Code §1522.12)
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SUSQUEHANNA RIVER BASIN COMMISSION (SRBC)
 Project review (18 CFR §§ 806.1-806.16, 806.22)
 Any withdrawal or consumptive water use for shale gas well
 Any import of water into basin or export of water from basin
 Approval by rule process for consumptive uses
 Streamlined process for water sharing
 Recent developments
 New approach to low flow protection / setting passby flow
conditions
 Proposed rule restricting withdrawals in headwater streams
(watersheds < 10 sq. mi.) (77 Fed. Reg. 75915 (Dec. 26, 2012))
 Basinwide consumptive use study launched to evaluate
cumulative water use and availability by subbasin, targeted for
completion in December 2015
(http://www.srbc.net/planning/cwuas.htm)
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SRBC’s low flow protection policy & technical guidance1
 Old approach – use of Pennsylvania Instream Flow Model for most cold
water fish streams; 20% of average daily flow for other streams
 New approach – tiered arrangement, with watersheds classified into aquatic
resource class (ARC) based on area, with monthly exceedance values
ARC
1
Description
1
Headwaters
2
Creeks
3
Small rivers
4
Medium tributary rivers
5
Medium mainstem rivers
6
Large Rivers
Drainage
Area (mi2)
De minimis
threshold
Passby flow
None
Monthly P70
10-50
5% monthly P95
Monthly P75
50-200
5% monthly P95
Monthly P80
200-1000
5% monthly P95
Monthly P85
1000-5000
10% monthly P95
Monthly P90
≥5000
10% monthly P95
Monthly P95
≤ 10
http://www.srbc.net/policies/lowflowpolicy.htm
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Wastewater Management
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THE FLOWBACK/WASTEWATER CHALLENGE
 ~ 1-5 million gallons required for a frac job; 25-30% of water emerges
as flowback water (much of that in relatively short time period)
 Need to develop representative characterization of flowback and
produced waters
 Example: Marcellus Shale flowback water contains 4-25% salts
(TDS typically exceeds 100,000 mg/l)
 Other constituents: barium, strontium, naturally occurring radioactive
materials (NORM), oil and gas, trace amounts of chemicals added
during hydraulic fracturing
 Some flowback (wet gas areas) contains condensate / natural gas
liquids
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WASTEWATER MANAGEMENT CHALLENGE (CON’T)
 Need to store and manage to avoid releases
 Lined impoundments
 Frac tanks
 Types of secondary containment
 TDS is hard to remove economically
 Streams have limited assimilative capacity
 Options:
 Evaporation (in dry areas, such as Texas)
 Reverse osmosis (lower TDS water) or evaporation/crystallization
(higher TDS water)
 Underground injection of brine
 Industry’s rapidly evolving solution => recycling and reuse of flowback
and produced water in subsequent operations
 Requires provisions for storage, treatment, blending and
coordinated operations
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A MATRIX OF WASTEWATER MANAGEMENT
REGULATIONS
 Water quality laws and regulations
 Federal Clean Water Act
 State counterpart water quality laws
 “Solid waste” laws and regulations
 Resource Conservation and Recovery Act (RCRA) – hazardous
waste regulation under Subtitle C; other waste regulation under
Subtitle D
 State waste laws – e.g., Pa. Solid Waste Management Act
 Safe Drinking Water Act – underground injection control program
 State oil and gas laws
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FEDERAL CLEAN WATER ACT
 Structure:
 Regulates discharge of “pollutants” via a “point source” to “navigable
waters of the United States” through the NPDES permit system
 Under CWA §§ 301, 306, 307, EPA sets national technology based
treatment standards (referred to as “effluent limitation guidelines)
 Under CWA § 303, states must designate protected uses of streams
and establish instream water quality criteria to protect such uses
 States (or EPA) issue permits for discharges from point sources,
establishing effluent limits based on the more stringent of technologybased limits or limits to protect instream water quality (“water quality
based effluent limits”)
 Standards:
 Produced water and drilling fluids may not be discharged to navigable
waters from a well site (EPA ELG, 40 C.F.R. Part 435)
 Off-site disposal through centralized treatment works allowed – treatment
standards set
 EPA proposed rule would prohibit discharge of oil and gas waste water to
POTWs (80 Fed. Reg. 18557 (Apr. 7, 2015))
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EXAMPLE OF RECENT STATE REGULATION –
PENNSYLVANIA
 TDS Discharge Limitations: 25 Pa. Code §95.10 (published Aug.
21, 2010)
 Treatment requirements for new and expanding loadings of total
dissolved solids (TDS)
 Wastewater source reduction strategy (maximizing reuse) required for
natural gas operations by 8/22/2011
 New discharges from natural gas operations allowed only through
centralized treatment facilities with strict discharge limits (500 mg/l
TDS, 250 mg/l Chlorides, 10 mg/l Barium and Strontium)
 Continuing debate concerning potential Ch. 93 instream water
quality criteria for Chlorides for aquatic life protection
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Underground injection of flowback or treatment residuals
 Safe Drinking Water Act – Underground Injection
Control (UIC) program
 Federal Energy Policy Act amendment excludes
from definition of “underground injection” the
“underground injection of fluids or propping agents
… pursuant to hydraulic fracturing operations
related to oil, gas or geothermal production
activities.” 42 U.S.C. §300h(d).
 But wells used for disposal of brine or waste
require UIC permits
 Permit program administered by EPA or by
authorized state (holding “primacy”)
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UIC (CON’T)
 Federal standards (40 C.F.R. Part 146)
 Class II UIC wells = wells used for disposal of fluid brought to
surface from conventional oil and gas production
 Requires evaluation of potential impacts within area of endangering
influence (§146.6)
 Plan for corrective action to prevent fluid movement into drinking
water sources (§144.55, 146.7)
 Identification of all wells within area of review penetrating formations
affected by pressure increase
 Demonstration of mechanical integrity
 Specific construction standards (casing, cementing, logging,
testing) (§146.22)
 Detailed monitoring requirements (§146.23)
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UIC (CON’T)
 Pennsylvania
 Regulated under 25 Pa. Code §78.18 – provides for permitting of
disposal or enhanced recovery wells via Oil & Gas Act well permit
 Must submit to DEP a copy of UIC permit and application submitted to
EPA under Part 146
 Requires control and disposal plan meeting requirements of 25 Pa.
Code §91.34
 West Virginia
 Class II permit required under W.Va. Code R. §47-13-13.3
 New York
 Div. of Mineral Resources regulates drilling, operation of brine disposal
wells under NY Envtl. Conservation Law §23-0305(14)
 DRBC
 DRBC invokes project review jurisdiction over UIC wells in the
Delaware Basin
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Waste Management
FEDERAL VS. STATE “WASTE” REGULATION
 Federal RCRA: Produced water and drilling fluids are exempt
from regulation as “hazardous waste” (unused fracturing fluids
and hydraulic fluids are not exempt)
 State waste management:
 Typically applies to both hazardous and non-hazardous waste
 Definition of “solid waste” – includes solid, liquid and
contained gaseous material that is discarded
 Drill cuttings / wastes subject to state management and
disposal standards
 Example:
 PA oil and gas regulations – requirements for waste
management plan
 PA residual waste management regulations
 Current issues: appropriate methods of waste management /
TENORM concerns
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AIR EMISSIONS
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AIR EMISSIONS
 Sources:
 Fugitive emissions from piping or tank leaks – VOCs, BTEX
(controlled by flares and vapor recovery units)
 Tanks, pits or ponds (condensate separation) - VOCs
 Drilling rig engines (diesel engines) – NOx, CO
 Compressor station engines – NOx, formaldehyde (controlled
by ultra lean burn engines and oxidizers)
 Dehydration facilities – small quantities of ethylene glycol
 Regulations
 Complex interplay between federal and state rules
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AIR EMISSION ISSUES
 Emission regulation depends on total emissions from facility, and
whether facility qualifies as a “major source”
 “Major source” definition refers to any source or group of
stationary sources “within a contiguous area” and “under
common control” 42 U.S.C. §7661(2) (See Pa. definition of
“facility” - §121.1)
 “Major source” emission thresholds differ depending upon the pollutant,
the nature of the source, the area’s attainment status, and the
regulatory program at issue
 Implication: When will natural gas production / processing
facilities (including compressor stations) be considered a single
“facility” for determining “major source” status?
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AIR EMISSION ISSUES – “AGGREGATION”
 Current EPA Regulations – 3 requirements:
(1) Same industrial grouping (same two digit SIC code)
(2) Under common control of same entity
(3) Contiguous or adjacent properties
 EPA Guidance:
 Consider both distance and “functional interrelatedness” / “functional
interdependence” to determine adjacency (no formula or bright lines)
 Sixth Circuit Court of Appeals – Summit Petroleum v. EPA (2012):
 Do not consider “functional interrelatedness” – only distance
 EPA attempted to limit the effect of Summit Petroleum to the Sixth
Circuit (KY, MI, OH, TN), but this position was rejected by the D.C.
Circuit in NEDACAP v. EPA (May 2014)
 In response, EPA has proposed new rules defining “adjacency”
specifically for the oil and gas sector – two “co-proposals”:
(1) Adjacent if on sites located within ¼ mile of one another
(2) Adjacent if separated by less than a ¼ or “if there is an exclusive
functional interrelatedness”
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NEW SOURCE REVIEW (NSR)
 Pre-construction permit requirements that apply to “major
stationary sources” of “regulated NSR pollutants”
 New major sources
 “Major modifications” to “major stationary sources”
 Regulated NSR pollutants include:
 The 6 criteria pollutants (PM, ground-level ozone, carbon
monoxide, sulfur oxides, nitrogen oxides, lead)
 Other pollutants “subject to regulation” under the CAA
 Supreme Court in UARG v. EPA (2014):
 GHG emissions alone cannot trigger major source permitting
requirements, but are subject to best available control
technology (BACT) requirements if emissions of another
pollutant exceeds major source thresholds
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NSR IN NON-ATTAINMENT AREAS
 Applies to sources that exceed major source thresholds for one or
more of the 6 criteria pollutants, if the source is in an area that is in
non-attainment for that pollutant
 Major source = potential to emit ≥100 tpy of a regulated NSR pollutant; 50
tpy of VOCs or 100 tpy of NOx in most areas of PA (25 tpy of VOC or NOx
in SE PA) [more stringent in portions of NE corridor]
 Must implement Lowest Achievable Emission Rate (LAER) + obtain
offsets for VOC or NOx emissions
 Permit required before commencement of any construction
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NSR IN ATTAINMENT AREAS - PREVENTION OF
SIGNIFICANT DETERIORATION (PSD)
 Pre-construction permit required for major sources
 Emissions impact analysis
 May well require ambient monitoring for up to 1 year
 Modeling to show cumulative emissions will not cause
NAAQS exceedance
 Class 1 area impact analysis
 Mandate for use of best available control technology (BACT)
 Not quite as stringent as LAER
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OPERATING PERMITS
 Major stationary sources must also apply for and maintain Title V
operating permits
 Compiles all requirements that apply to a facility in one federally
enforceable permit
 More onerous recordkeeping than otherwise would apply
 Must be renewed every five years
 No new substantive emissions controls
 Biennial certification required
 Minor sources still must comply with state requirements
 State technology standards
 PA Best Available Technology (25 Pa. Code §127.12(a)(5))
 Some states require pre-construction and/or operating permits
for oil and gas facilities as well
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AIR STANDARDS
 National Emission Standards for Hazardous Air Pollutants
(NESHAP)
 EPA also regulates hazardous air pollutants (HAPs)
 Examples: BTEX (benzene, toluene, ethyl benze, xylene);
formaldehyde
 National Emissions Standards for HAPs (NESHAPs) apply to
specific categories of sources
 Both new and existing sources
 Area sources v. major sources
 HAP emissions are not aggregated – CAA § 112(n)(4)
 Maximum Achievable Control Technology (MACT)
 New Source Performance Standards (NSPS)
 EPA promulgates NSPS that apply to categories of sources
imder CAA § 111(b)
 NSPS apply only to new, modified, and reconstructed
sources
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NESHAPS AND NSPS FOR THE OIL AND GAS SECTOR
 Issued in 2012, minor amendments in 2013, 2014, and
2015
 Directly regulates VOCs, achieves reductions in GHGs as
a co-benefit
 NSPS – 40 C.F.R. Part 60 Subpart OOOO (“Quad O”)
 Requires “green completions” at natural gas wells beginning January 1,
2015
 Also regulates emissions of VOCs from:
 Compressors and pneumatic controllers in the production & processing
segments
 Storage vessels in the production, processing, transmission, and storage
segments
 Leaking components (and SO2 emissions) at processing plants
 NESHAPs (Part 63 Subpart HH & HHH) apply to glycol dehydrators,
storage vessels, and equipment leaks at processing plants
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NEW EPA METHANE AND VOC PROPOSALS
 Proposed NSPS for Methane and VOCs
 Update to 40 CFR Part 60, Subpart OOOO (“Quad-O”)
 Would directly regulate methane emissions
 Would impose requirements on new categories of sources, including
hydraulically fractured oil wells and natural gas compressor stations
 Would impose leak detection and repair (“LDAR”) requirements on well
sites, gathering/boosting stations and compressor stations
 Would apply only to new/modified/reconstructed sources
 Draft Control Techniques Guidelines (CTGs)
 Would apply to existing oil and gas sources in ozone non-attainment
areas (including all of Pennsylvania)
 Includes Reasonable Available Control Technology (RACT)
recommendations for controlling VOCs from covered sources
 Once finalized, states would be required to develop rules imposing
RACT on existing oil and gas facilities
 Potential future regulation under CAA §111(d)(1)
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GREENHOUSE GAS (GHG) REPORTING RULES
 40 C.F.R. Part 98, Subpart W
 Reports due annually on March 31
 Applies to “facilities” that emit 25,000 metric tons of CO2e / year
 25,000 metric ton threshold includes emissions from stationary fuel
combustion, equipment leaks, vented sources, and flares
 Should not aggregate emissions from compressor stations along a
single transmission pipeline (40 C.F.R. §98.6)
 But should aggregate emissions from all well pads owned or operated
by same entity in a single hydrocarbon basin (40 C.F.R. §98.238)
 EPA finalized revisions to Subpart W in October 2015 that add
reporting requirements for gathering and boosting systems, oil
wells, and transmission pipeline blowdowns
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Thank You
David L. Wochner, Partner
K&L Gates LLP
1601 K Street, NW
Washington, DC 20006
202.778.9014
david.wochner@klgates.com
klgates.com
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