MEMORANDUM

TO: Lisa Biddle, US EPA/OW/EAD

FROM: Sarah Yates, ERG

DATE: 09 July 2014

SUBJECT: 2014 A&WMA Oil and Gas Environmental Compliance Conference Notes

On May 13 through 14, ERG attended the 2014 Air and Waste Management Association 

(A&WMA) Oil and Gas Environmental Compliance Conference in Washington, PA. This 

memorandum summarizes relevant information presented at the conference. In general, the 

conference had three concurrent sessions (A, B, and C). Session A focused on air permitting and

compliance. ERG did not attend any of the Session A presentations and, therefore, does not 

summarize these presentations in this memorandum. ERG attended select presentations from 

Sessions B and C, which are summarized in this memorandum. This memorandum includes 

notes on the following:

• Section 1 describes general information on unconventional oil and gas (UOG) and 

hydraulic fracturing;

• Section 2 describes UOG waste stream management options;

• Section 3 describes emerging trends in Marcellus shale gas development; and

• Section 4 describes general information that is not directly relevant to the UOG 

proposed rulemaking. 

Table 1 lists all of the presentations from the A&WMA Oil and Gas Environmental 

Compliance conference. Attachment 1 provides all presentations that A&WMA provided to 

attendees after the conference. Attachment 2 provides contact information for all of the 

presenters at the A&WMA Oil and Gas Environmental Compliance conference.
Memorandum

11 July 2014

Page 2 of 21

Table 1. Presentations from the 2014 A&WMA Oil and Gas Environmental Compliance Conference

Presentation DCN Presenter Name and Affiliation Presentation Title

SGE00779.A2 Hopkins, Michael; Ohio EPA Air Permitting for Oil & Gas Facilities in Ohio

SGE00779.A3 Jennings, Laura; WV DEP, Division of Air Quality West Virginia's Air Quality General Permit for Oil and Natural Gas 

Production Facilities (G70-A)

SGE00779.A4 Pennsylvania Department of Environmental Protection Air Quality Permitting of Natural Gas Drilling, Compression and 

Processing Facilities in Pennsylvania

SGE00779.A5 Bosquez, Ted; Morgan, Lewis & Bockius LLP Update on ORSANCO Water Quality Programs

SGE00779.A6 Powell, Beth; New Pig Energy Secondary Containment: Regulations & BMPs

SGE00779.A7 Slagel, Gary; Steptoe & Johnson Pennsylvania Act 13 Issues & Concerns

SGE00779.A8 Bosquez, Ted; Morgan, Lewis & Bockius LLP Management of TENORM Practical Assessment

SGE00779.A9 Maher, Thomas; Civil & Environmental Consultants, Inc. Oil & Gas Exploration and Production Waste Regulations in Ohio

SGE00779.A10 Socash, Stephen; Bureau of Waste Management PADEP Management of Oil and Gas Waste in Pennsylvania

SGE00779.A11 Muscenti, Tom; Trinity Consultants Evaluating Well Pad Permitting in the Appalachian Basin

SGE00779.A12 Schmelzle, John; RETTEW GP 12.1/12.2 Air Permitting of Oil and Gas Well Site Production 

Operations in Ohio

SGE00779.A13 Woerner, Andy; ERM NSPS Subpart OOOO Lessons Learned... and a Look Ahead

SGE00779.A14 Daley, Jim; NGE Site Planning, Design & Restoration to Support Desired Land Use

SGE00779.A15 Parker, Lauren; Civil and Environmental Consultants, Inc. Erosion and Sediment Control for natural gas pipeline projects

SGE00779.A16 Rinde, Jonathan; Manko, Gold, Katcher & Fox, LLP Successful Wetland Permitting for Oil and Gas Pipelines

SGE00779.A17 Allison, Megan; TETRA TECH Decreasing Costs of Waste Stream Analysis by Implementing a 

Testing Reduction Program and Utilizing Generator Knowledge

SGE00779.A18 Costa, Brenda; Moody and Associates Act 2 and the PA DEP Spill Policy

SGE00779.A19 Silverman, Thomas; EHS Support LLC Drilling Mud Evaluation

SGE00779.A20 Hennessey, Yvonne; Hiscock & Barclay Aggregation of Air Emissions - What Does Adjacency Really Mean

SGE00779.A21 Hunt, Gary;TRC Corporation Why Methane Matters

SGE00779.A22 Kantorczyk, Todd; Manko, Gold, Katcher & Fox, LLP OSHA and EPA Regulation of Release Prevention Programs for Oil 

and Gas Operations: A Primer and Update
Memorandum

11 July 2014

Page 3 of 21

Presentation DCN Presenter Name and Affiliation Presentation Title

SGE00779.A23 Poffenberger, Clara; Bingham Air Permit Issues for Oil and Gas Operations: Unresolved EPA Rules 

and Recent Court Cases Affecting Air Permits

SGE00779.A24 Mastowski, Ryan; RETTEW Disposal - Oil and Gas Environmental Compliance Conference

SGE00779.A25 Mastowski, Ryan; RETTEW Water Treatment - Oil and Gas Environmental Compliance Conference

SGE00779.A26 Silverman, Thomas; EHS Support LLC Managed Aquifer recharge Using Treated Coal Seam Gas Water

SGE00779.A27 Silverman, Thomas; EHS Support LLC Risk Assessment of Aquifer Connectivity Associated with Well and 

Bore Integrity

SGE00779.A28 Biksey, Tom; EHS Support LLC PBT Assessment of Hydraulic Fracturing Fluids from Coal Seam Gas 

Fields in Australia

SGE00779.A29 Meloy, Michael; Manko, Gold, Katcher & Fox, LLP Pennsylvania’s Oil & Gas and Residual Waste Programs: Negotiating 

the Maze

SGE00779.A30 Render, Jo; ERM The More Things Change. . . Assessing Social Risks in Industry Swing 

Periods

SGE00779.A31 Wilson, Brad; Environmental Resources Management The Phase 0 Approach Best Practices – Building Blocks and Roadmap 

for an EMIS Strategy

SGE00779.A32 Keatley, Robert; DEP – Division of Air Quality NSPS OOOO & Fracking Air Quality Rule Updates

SGE00779.A33 Kuntz, Timothy; Pennsylvania Department of Environmental 

Protection

Inspecting Natural Gas Compressor Stations in Pennsylvania

SGE00779.A34 McCall, Duke; Bingham Hydraulic Fracturing (Fracking): Litigation Trends

SGE00779.A35 Smith, Stephen; Steptoe & Johnson PLLC Perspectives on Enforcement & Compliance

SGE00779.A36 Stewart, Andrew; EPA EPA's Energy Extraction National Enforcement Initiative

SGE00779.A37 Yoxtheimer, Dave; Penn State Marcellus Center Emerging Trends in Shale Energy Development

SGE00779.A38 Blinn, Leah; Air & Waste Association Oil and Gas Environmental Compliance Conference Welcome and 

Introduction

Not Availablea Garland, Bob; TETRA Technologies, Inc. Hydraulic Fracturing Primer

a—This presenter did not upload a presentation to the FTP site.
Memorandum

11 July 2014

Page 4 of 21

4

1. General Information on Unconventional Oil & Gas (UOG) and Hydraulic 

Fracturing

Garland, 2012 (DCN not available)

• Oil is currently a higher demand commodity than gas because of supply/demand

• Unconventional oil and gas (UOG) is classified as “unconventional” rather than 

“conventional” because of the permeability of the formation

o The Devonian Sands (formation with oil and gas on top of each other) used to be 

considered an unconventional formation, but now is considered conventional

• Hydraulic Fracturing dates back to the 1860’s

• UOG Production

1. Drilling

a. Well developers can now develop up to twelve wells with one wellhead 

because of horizontal drilling practices

2. Production Casing

a. Casing is used to prevent gas intrusion and/or water transfer

b. 25 PA Code, Chapter 78 – Casing Requirements

i. Casing requirements for vertical and horizontal wells are the same 

until the kick-off point

3. Perforation

a. Perforation gun (i.e., hollow steel carrier) carries the shape charge down into 

the formation with the goal of creating a “line of communication” between the 

cased wellbore and the producing reservoir

4. Enhanced Production (i.e., Hydraulic Fracturing)

a. Shale formations have nanodarcy permeability that holds natural gas in the 

rock formation

b. Operators use the following stepwise process to enhance production of gas 

from a well (after completing steps #1 through #3):

i. Pump acid/additives to perforation zone

ii. Pump water to perforation zone

iii. Add sand incrementally (2 to 2.5 lb of sand/gallon of water)

iv. Stop pumping after adding sufficient sand

v. Insert (fiberglass, steel, or rubber) plug to maintain pressure in that 

specific “stage” of the well

c. Operators hydraulically fracture wells using ~99.5% water/sand and ~0.5% 

chemical additives:

i. Friction reducers – allow easier pumping downhole

ii. Acid – removes drilling mud from the wellbore

iii. Biocide – prevents microbial growth

iv. Corrosion inhibitor – prevents metal pipe corrosion

v. Surfactants – promote flowback return
Memorandum

11 July 2014

Page 5 of 21

5

d. In total, operators use between 65,000 and 120,000 barrels of water per well 

for hydraulic fracturing

e. Marcellus shale gas operators often do not use gels

f. Operators complete wells in stages. One well may have up to 60 stages, where 

each stage is 150 to 300 feet long

g. At the fractured well, there are working tanks, pump trucks, wellhead, and a 

manifold, all of which have to work in tandem with each other to complete the 

fracture

h. Energy use

i. Operators that use diesel fuel burn through a lot of fuel. For example, 

if you assume 100 gallons of diesel/hour/truck and 16 hydraulic 

fracturing trucks are used, that requires 1,600 gallons of diesel 

fuel/hour

ii. However, a lot of operators are moving to dual fuel (diesel and natural 

gas) to reduce consumption. Operators can also use liquefied natural 

gas (LNG) and compressed natural gas (CNG)

5. Drill out plugs

6. Produce oil and/or gas

a. The Marcellus and Utica formations are over-pressured, so gas flows back 

naturally with flowback and/or produced water

b. Separate oil and gas from production stream

• Formations:

o Genusao Shale (shallowest)

o Tully Limestone

o Hamilton Shale

o Marcellus Shale (thickest; production accelerated in 2007)

o Utica Shale (deepest; wet gas and oil)

• Number of Wells Drilled:

Formation State Approximate Number of Wells

Marcellus PA >5,000

OH 20

Utica PA 29

OH 500

Upper Devonian PA 50

OH 2,000

•

Q: Are there other applications for hydraulic fracturing?

Question and Answer Session:

A: In 2004, EPA found no problem with hydraulically fracturing coalbed methane wells 

in Pennsylvania. The only requirement was that no diesel was used.
Memorandum

11 July 2014

Page 6 of 21

6

Q: How has communication evolved over time between all of the different companies 

involved in well development?

A: There are a lot of different players speaking a lot of different “languages” on the well 

site. They have SOPs, safety meetings, and managers present onsite to ensure correct 

practices.

Q: What are alternative materials for fracturing?

A: CO2, nitrogen, and propane. 

CO2 fractures – freezing is a problem; expensive; comes from eastern PA.

Nitrogen fractures – used in WV because the shale formations are under-pressure; 

nitrogen returns as part of the gas stream and you have to wait for it to dissipate out of the 

gas stream.

Propane fractures – have been tried but not repeated.

Q: Has there been enough production in the Utica formation to compare decline curves to 

the Marcellus formation?

A: No, we don’t yet have enough information on the Utica formation. In the Utica, 

they’re just now defining where to drill.

Q: Are companies looking at green fracturing techniques?

A: Yes, companies are constantly looking at “greener” methods. For example, there is 

ongoing biocides research being conducted by Halliburton and various universities.

Q: Do well companies use technology to know where the fracture goes?

A: Yes, they use microseismic technology. They also use chemical tagging of different 

areas and flowback water monitoring.

Q: In southern CA, there are subsidence issues. Have you seen subsidence issues in the 

Marcellus shale formation?

A: No, it’s not an issue with the Marcellus shale because proppant holds fractures open.

Q: Can you discuss OSHA’s crystallite silicate requirements?

A: Silica dust on location used to be a bigger issue. Now, vacuum trucks on location 

address the issue by sucking sand dust out of the air. Employees are also wearing 

personal protective equipment (PPE, e.g., breathing apparatus).

•

Duquesne University is conducting a research study called “Three Rivers Quest” in 

which they are sampling the Allegheny River, Monongahela River, and Pine Creek. 

Researchers from Duquesne University and West Virginia University’s Water Resource 

Institute will collect bi-weekly samples from January 2013 through at least April 2015. 

They will engage Pace laboratories to analyze the samples in order to draw conclusions 

about the impacts on rivers from shale gas development.

Ongoing Research:
Memorandum

11 July 2014

Page 7 of 21

7

2. Management Options for UOG Waste Streams (e.g., Treatment, Reuse, Disposal)

2.1 Wastewater Management Options

Mastowski, 2012 (SGE00779.A24, SGE00779.A25)

• Discussion of general practices for hydraulically fracturing a shale gas well

• Flowback characteristics

o Flowback characteristics for various wells differ within a formation

o Flowback water is typically basic (pH = 8.5 to 9.0 SU)

o General flowback characteristics are listed on slide 13

 Utica range of TDS concentrations: 50,000 to 300,000 mg/L

 Marcellus range of TDS concentrations: 38,500 to 230,000 mg/L

 Barnett range of TDS concentrations: 23,600 to 98,900 mg/L

• Wastewater generation 

o Rates vary between flowback (~100 bbl/hr or ~100,800 gal/day) and produced 

water (~5 gal/day)

o Characteristics also vary between flowback (smaller concentrations) and produced 

water (larger concentrations because longer contact time with the formation)

• Wastewater management options include: disposal wells and reuse for future fracturing 

jobs (with or without treatment). Treatment methods include:

o Chemical/physical treatment with pH adjust is used for removal of heavy metals 

and solids

o Reverse osmosis, not typically needed because no operators are currently 

managing their wastewater through surface discharge

o Operators used to want very clean water for reuse, but are lowering reuse quality 

requirements

• Treatment Options:

o Bag Filters

 4 canister filters

 Remove SRBs

 Gross solids typically <25 μm, but some operators want solids <10 μm

 Don’t need drinking water standard effluent when reusing

 Test used bag filters for NORM because they are typically disposed of in 

landfills

• 50 pCi/L – PA discharge limit

• 5 pCi/L – EPA drinking water standard

o RETTEW Mobile Treatment Unit (Chemical/Physical Treatment)

 Chemical treatment removes iron, sulfate, bacteria, and adjusts pH

 Physical treatment removes solids

o Fountain Quail Rover (Chemical/Physical Treatment)

 Similar treatment to RETTEW mobile treatment unit, plus solids handling 

filter press on trailer
Memorandum

11 July 2014

Page 8 of 21

8

o Mobile Physical Chemical Treatment

 Actively adjusts pH and removes particulates

 Physical/chemical treatment used for blending ratios of 15 to 20: 1

o Electrocoagulation

 Removes heavy metals

 Con: requires electricity

o Chlorine Dioxide

 More advanced treatment than physical/chemical treatment

 Chlorine is generated on location

 Treatment requires small footprint

o Aquatech Mobile Evaporator

 End product is distilled water

 Con: high energy demand 

o Fixed Facilities

 Examples of facilities that RETTEW helped to design: TerrAqua, Eureka, 

HydroRecovery

 Most facilities include the following treatment: oil/water separator, 

primary clarification, physical/chemical treatment, and (some facilities 

also include) filter press

 WMGR 123 – PA DEP surface discharge permit

 Facilities can accept up to 200,000 gallons/day and treat influent based on 

the TDS concentration (e.g., TDS <=50,000 mg/L go on one treatment 

train, TDS >50,000 go on a different treatment train; TDS >150,000 mg/L 

go on a third treatment train)

 RETTEW has staff on-site to run facilities 24 hours/day

o Aquatech Modular Zero Liquid Discharge

 Typically used for larger volumes of water due to economic reasons

o Evaporation

 Removes heavy metals (e.g., barium) for beneficial reuse

• Treatment Costs (excluding transportation costs):

o Filtration: $0.5/bbl to $1.35/bbl

o Chemical/Physical: $4/bbl to $10/bbl

o Injection Wells: $4/bbl to $15/bbl

o Evaporation: $9/bbl to $15/bbl (could be higher depending on availability of 

power source)

• Transportation:

o Assumption for general trucking costs: ~100 bbl water truck costs $100/hour 

($1/bbl/hr)

o When distance to disposal is >500 miles, train transport is more cost effective 

than trucking. Train transport is used occasionally in the western U.S.

• Class II injection for disposal wells
Memorandum

11 July 2014

Page 9 of 21

9

o Injection well program: look for geology where the rock is like a sponge; 

pressurize water into the well and allow water to diffuse outward through the rock 

to keep the space/capacity of the well

o Monitor for TDS in injection wells because if you pack too many solids into the 

well, fissures through which water escapes will be plugged and UIC capacity will 

be limited

o Approximate number of Class II injection for disposal wells by state:

 PA: 7

• Pennsylvania has many privately owned wells that are not 

available to public (or all operators)

 OH: 191

• Ohio had an injection well program long before the UOG boom

• New Ohio regulations require a well to be immediately shut down 

if a rictor scale reading of 1 or greater is measured

 WV: 70

• Trucking costs make WV disposal wells less attractive to operators

 TX: 50,000

o Injection rate: 500 to 2,000 bbl/day

• Evaporation ponds

o Shallow, usually lined ponds with leak detection systems and groundwater 

monitoring

o Periodically, ponds have to be dredged and dredged materials may be used as road 

salt, if they meet regulatory requirements

o Evaporation ponds may have bird netting installed over ponds to keep out birds 

that would otherwise land on the ponds and potentially transport pollutants from 

the oil and gas industry to other areas

o Not prevalent in eastern U.S. (e.g., PA, OH), but they are used in western U.S. 

where climate is more ideal for evaporation (e.g., Wyoming can have up to 1” of 

evaporation per day)

• Question and Answer Session:

Q: What influent and effluent sampling is done by RETTEW at fixed facilities?

A: Every truck into a facility has a grab sample taken to make sure there are not major 

outliers in the pH, iron, sulfate (should be <200 mg/L), or surfactant concentrations.

The same suite of parameters is measured in effluent to make sure they are meeting the 

required effluent criteria.

The sulfate concentration is limited to mitigate the risk of barium sulfate scaling 

downhole. RETTEW used Halliburton’s standards to develop acceptable effluent 

characteristics.

Q: What management options are being used in Texas?
Memorandum

11 July 2014

Page 10 of 21

10

A: Texas is different in that injection wells are the primary management methods. Texas 

operators are exploring recycling wastewater and are moving towards beneficial reuse 

(instead of disposal).

Q: Do operators pre-treat wastewater before injection for disposal?

A: The weight of the water is important (e.g., rain water doesn’t weigh enough to 

facilitate efficient injection and therefore would likely be rejected). Typically, <0.5% 

solids is accepted, which can be achieved with grit/centrifuge treatment or solids settling. 

Suspended solids remain in the wastewater. In Ohio, TENORM limits exist. The ongoing 

PA DEP NORM study may change NORM limits in PA.

Q: Do injection wells reject wastewater with odor?

A: Yes, all the time. Odor may indicate high solids content.

2.2 Drilling Mud and Cuttings Management (related to CBM)

Silverman, 2012 (SGE00779.A19)

• Discussion of drilling mud and cuttings management options for a coalbed methane 

(CBM) project in Australia

o Drilling mud primarily includes base fluid, weighting agent (barite), and biocide. 

Researchers often saw high pH and high concentrations of NaCl and KCl, which 

are not good for beneficial reuse involving plants

o 200 to 250 cubic yards of drilling muds/cuttings (60%) disposed of onsite via 

burial and the remainder of drilling liquids (40%) treated offsite

o Liquid management options include reuse, reuse after treatment, and beneficial 

reuse. The following provide more detailed descriptions of options:

 Direct burial – isolate salts and limit impacts

 Landspreading – apply drilling cuttings to fields; cuttings have macro and 

micro nutrients, but salinity can be harmful, need to manage salt 

concentrations

 Dust suppression

 Road construction

 Compost

• Question and Answer Session:

Q: Are regulators in the U.S. okay with burying waste? What are alternatives?

A: Operators are looking for beneficial uses because landfills are costly. However, they 

need to check salt content before considering beneficial reuse.

Q: What was the regulator feedback from this study?
Memorandum

11 July 2014

Page 11 of 21

11

A: Regulators wanted to know that beneficial reuse was low risk. They were happy with 

documentation of constituents in drilling muds.

3. Emerging Trends in the Marcellus Shale Play

Yoxtheimer, 2012 (SGE00779.A37)

• Formation overview:

o Upper Devonian Shale is shallow (~5,000 to 6,000 feet deep) and is being 

developed in western PA

o The Marcellus Shale ranges from ~2,000 to 9,000 feet deep

o The Utica Shale ranges from ~2,000 to 14,000 feet deep and is typically 2,000 to 

5,000 feet below the Marcellus shale

• Approximately 10,000 UOG wells have been drilled in PA, OH, and WV through 

November 19, 2013

• Waste stream generation:

o Approximately 1,000 tons of drilling cuttings are generated per well and most are 

disposed of at landfills

 Potential for beneficial reuse – in building materials and/or proppants?

o Approximately 100 tons of sand are used per well and sand is mostly disposed of 

at landfills

 Potential for beneficial reuse?

o Approximately 10 barrels of water are used per 1 MMCF of gas produced

o Approximately 1.6 MM barrels of drilling fluid were generated in 2013, the 

majority of which were recycled

• Wastewater management options:

o There are ~20 CWTs in the Pennsylvania area. CWTs have WMGR 123 permits

o There are ~18 landfills in Pennsylvania that handle solids (e.g., drilling cuttings)

o Reuse

 Contamination concerns with downhole plugging/scale formation (from 

barium, strontium, calcium, magnesium, and TDS)

o Very little Marcellus shale wastewater is disposed of at underground injection 

wells in PA

 Likely, as Utica well development progresses, there will be more UIC 

capacity developed in OH

• Miscellaneous information:

o Approximately two square miles of shale reservoir can be tapped from one UOG 

wellpad

o Quick well completion is important because the longer it takes to complete a well, 

the more resources are used and the less efficient it is

o Water based drilling fluids are typically used for the upper wellbore
Memorandum

11 July 2014

Page 12 of 21

12

o Operators are more commonly using natural gas fired drilling and fracturing rigs 

because it costs less. For example, one gallon of diesel costs ~$3.60 and one 

gallon of natural gas costs ~$1.20

4. General Information Not Relevant to UOG Proposed Rulemaking

4.1 Information on Solid Waste and Wastewater Management and Handling Practices in 

PA and OH

Socash, 2012 (SGE00779.A10)

• PA Solid Waste Management Act (SWMA)

o Solid waste definition excludes drill cuttings managed at the well site. Therefore, drill 

cuttings are not included in the solid waste definition under SWMA if disposed of at 

the well site. When there’s no opportunity for drill cutting management at the well 

site, drill cuttings are hauled off site and then fall under the SWMA

• Reuse of oil and gas waste

o Coproducts are materials applied to land, used to produce products applied to land or 

burned for energy. To determine a coproduct, need to demonstrate that the material is 

physically and chemically similar to the commercial product (25 PA Code 287.9)

o General Permit for Beneficial Use

 Issued by PA DEP

 If unsure about coproduct determination, submit request for general permit

• Residual waste generators must keep records of: type and quantity of waste, date, 

transport method, and final destination (facility)

• Compliance with PA Act 90 is required prior to disposing of residual waste at a landfill.

The following requirements are relevant to PA Act 90:

o Annual Chemical Analysis – operators must characterize every 2,200 lbs of residual 

waste at one location over one month on Form 26R

 Form 26R is submitted to the disposal facility and to PA DEP

 Form 26R is designed for consistent waste types and can be recertified every 

five years, if the company provides good baseline information showing 

consistent characterization data

o Form U – facility waste acceptance plan (WAP) submitted electronically to PA DEP 

by landfill/processing facility taking the waste (includes TENORM data, among other 

information)

 PA landfills are not allowed to take hazardous waste

 If facility doesn’t hear approval/denial of Form U within 15 days, they can 

accept whatever waste was in question on their Form U
Memorandum

11 July 2014

Page 13 of 21

13

 Facility (e.g., landfill) has to determine that waste acceptance won’t cause 

negative impacts

 Many landfills have installed radioactivity monitors (since 2002)

 Form U requires radioactivity analyses of waste streams in pCi/g, but 

landfills measure radioactivity in μg/hr. PA DEP ongoing study is 

working on standardizing this

• Ongoing Studies

o PA DEP O&G Radioactivity Study – sampling at landfills, wells, cuttings, tanks

 Proposed final report date: Fall 2014

 Current status: compiling and analyzing data

Maher, 2012 (SGE00779.A9)

• The state of Ohio is a net importer of waste from PA

• Oil and gas E&P waste is managed by EPA, ODNR, OEPA, and ODH

• In July 2013, House Bill 59 passed and attempted to create better coordination between 

OH agencies

• EPA regulations (40 CFR 261)

• ODNR regulations

o Regulate the following:

 O&G E&P operations in Ohio

 Wastewater and drilling cuttings management at drill site

 Frac water pits/lagoons

 TENORM determination in wastes

 Frac water disposal at UIC wells

 Frac water hauling

o If drill cuttings are managed on site, they’re exempt from solid waste definition. 

Drilling cuttings that are air or water based muds are also exempt

o Ohio does not allow POTW discharge for frac water, flowback, or produced 

water. The only disposal method for produced waters in Ohio is UIC wells, so 

determination of earthquake causes (that’s in much of the media lately) is an 

important issue for O&G waste management in Ohio

o Testing for TENORM is not required if operator is reusing waste downhole, 

sending waste to Class II UIC, or disposing of waste out of state

• OEPA regulations

o OEPA has the smallest role of all the agencies regarding oil and gas operations

o OEPA follows federal exemption

o Drilling cuttings that contact other contaminated solutions are not exempt

• ODH regulations

o Regulate TENORM

o Determined list of TENORM materials (e.g., pipe scale, recycled mud)
Memorandum

11 July 2014

Page 14 of 21

14

o Specifies methods to use for radium 226 and radium 228 (must be detection of at 

least 5 pCi/L). The only acceptable method to-date for radium 226 and radium

228 is EPA Method 901.1M (2009)

o In-situ gamma spectroscopy of another method for radium measurement

o Landfills can’t accept drilling cuttings with free liquids; liquids need to be dried 

and stabilized (which may occur at off-site facilities and/or at the well site) prior 

to landfill. Ohio landfills don’t require radioactivity monitors like PA landfills

o Reference Document

• Mr. Maher stated that he is not aware of beneficial reuse of waste in Ohio

: Guidance for Sampling Waste Containing TENORM 

(February 20, 2014)

• Generator Waste Profile – reviewed by landfill and approved/denied directly by landfill 

(state of OH is not involved)

4.2 Information on Spill Response

Costa and Bennett, 2012 (SGE00779.A18)

• PA DEP’s spill policy is not consistent; there are different requirements for reporting 

depending on how much is spilled, when, and where

• Options: Act 2 or Alternative Method

o Act 2 Pros: get formal liability release from spill

o Act 2 Cons: public notice that operator has to submit to DEP that becomes part of 

public record (this prevents most operators from wanting to go through Act 2)

o Alternative Method Pros: no public notice, not as much reporting as Act 2

o Alternative Method Cons: can’t use site-specific standards, must use background 

standards; no liability release

• Act 2 incorporation into 25 PA Code, Chapter 78

o Spill policy – permittee is responsible

o Brine chlorides are one of main concerns with spills on oil and gas sites. PA DEP 

stated that they aren’t interested in creating statewide chloride standard

o Act 2 can’t be made mandatory because there are no statewide chloride health 

standards

• Question and Answer Session:

Q: Is there a push for landowners to require Act 2 remediation because without Act 2, 

they have no liability coverage?

A: Landowners don’t want to rock the boat with the operators because the operators are 

paying the landowners.

Q: Do operators refuse to comply?

A: No, but sometimes an operator is not proactive and waits for PA DEP to tell them 

what to do.
Memorandum

11 July 2014

Page 15 of 21

15

Q: What quantity of spill qualifies for Act 2?

A: Approximately 1 barrel.

Q: What is the status of the Chapter 78 revisions?

A: They’re not yet final. Inclusion of Act 2 in Chapter 78 will make “voluntary” 

requirements (of Act 2) “mandatory”.

Q: Are there concerns other than chlorides in spills (e.g., bromide)?

A: Bromide has a standard. The release of liability from select constituents is possible, 

but there will not be a release for chloride without a standard.

4.3 Information about Generator Knowledge and Testing

Allison, 2012 (SGE00779.A17)

• Generator knowledge – underutilized in PA; Form 26R contains laboratory data used for 

waste evaluations

• Testing reduction – characterize all generated waste streams and variance in streams; 

certify generator knowledge for five years if similar waste can be proven; reduced 

sampling costs for operators (~$30,000/wellpad in staging costs are eliminated)

o Data validation is very important, especially for liability protection

• Goal: reduce sample collection through testing reduction

• Question and Answer Session:

Q: Did you get feedback from PA DEP and/or others?

A: PA DEP and landfills met with Tetra Tech during this effort. Tetra Tech met with 

DEP beforehand to discuss the program.

4.4 Information on Aquifer Recharge

Silverman, 2012 (SGE00779.A26)

• Converting coal seam gas (CSG) to liquefied natural gas in Australia generates 

wastewater with approximately 3,000 mg/L salt content. The Australian government said 

they can’t evaporate this brackish water

• Looked at “managed aquifer recharge” to replenish aquifers using treated brackish water

• The Surat basin contains the beneficial use aquifer that’s being recharged in this study

• Before using CSG wastewater (~3,000 mg/L TDS), treat to lower TDS. The treatment is 

primarily done with RO units and then ions are re-amended into water to get wastewater 

to be characteristic of the drinking water aquifer (i.e., between 500 and 900 mg/L TDS)
Memorandum

11 July 2014

Page 16 of 21

16

• Conducted a risk assessment to look at human and environmental impacts of untreated 

CSG wastewater

• During the study, the injection rate decreased quickly over ten days, ending at ~2 L/sec 

injection, which is very low

o Researchers found that the reason for the low injection rates was because the TDS 

was too low in the water. Once revised, the injection rate increased again, but not

enough – the low TDS wastewater had clogged the aquifer as well as caused clay 

swelling

 TDS: 19 mg/L

 SAR: 60

 Rusted casing 

• Question and Answer Session:

Q: Did the Australian government have concerns with the presence of fracking 

chemicals in the recharge water?

A: The water that was being used for recharge was not frack water. The government 

did not do a risk assessment because fracking companies disclosed the chemicals used 

and there was no concern.

Q: What are the depths of the CSG versus the beneficial use aquifer?

A: CSG depth = 500 to 800 m and beneficial use aquifer depth = 100 to 200 m.

Q: What was done with the remaining water that was not able to be injected for 

aquifer recharge?

A: Water was collected in a dam nearby and researchers took quantities to inject for 

testing purposes. They didn’t have to inject it – it was simply for testing purposes.

4.5 Information on Non-Technical and Social Risks Related to UOG Development

Render, 2012 (SGE00779.A30)

• ERM focuses on the non-technical (e.g., social) risks associated with UOG development

• Media analyses presented the following concerns from the public:

o Crime rates

o Economic trends

o Communication and transparency

o Social risks
Memorandum

11 July 2014

Page 17 of 21

17

4.6 Inspection and Enforcement Panel

4.6.1 Inspection and Enforcement Panel Presentations

McCall, 2012 (SGE00779.A34)

• Hydraulic fracturing litigation trends are difficult to describe because few decisions have 

been made

• Major factors in litigation:

o Location – close proximity to people not used to the disturbance

o Public perception

o Media attention – encourages advocacy groups

o Water scarcity (e.g., Monterey Shale in CA)

• Litigation to date:

o >300 lawsuits regarding hydraulic fracturing and related to seismic activity, 

medical issues, enforcement of regulations, and property damage

• Trends in litigation:

o Traditional court procedures apply (i.e., no special actions for hydraulic 

fracturing)

o Potential for jury appeal – guided by what’s “fair,” not by science

o Litigation to force disclosure – trend toward disclosure (e.g., Baker Hughes)

o Litigation to force regulation

• Things the operator can do to avoid litigation:

o Give location weight in deciding where to drill

o Outreach to public before drilling

o Counter negative press/media

Kuntz and Norris, 2012 (SGE00779.A33)

• Field inspections require the following:

o File review (determine what version of the GP5 permit applies – 8/2006, 3/2011, 

or 2/2013)

o Review GP5 with facility

o Request additional reports/paperwork

o Inspect facility (for fugitive emissions, opacity, odor)

• PA DEP sent a letter to GP5 permitted UOG facilities requesting information for an

Emissions Inventory Report. In the future, this may pertain to conventional oil and gas 

facilities too

Keatley, 2012 (SGE00779.A32)

• Discussion of NSPS Subpart OOOO and other regulatory changes
Memorandum

11 July 2014

Page 18 of 21

18

• Regions 3, 5, 6 and 8 collaborated and concluded that any wells that are hydraulically 

fractured should comply with reduced emissions completions

• Options for emissions:

o Flare – usually portable flares on trailers

 EPA hasn’t certified control devices (e.g., flares), so within 180 days they 

need to be tested

o Green completions – recover gas with no release to atmosphere

• Electronic reporting:

o Daily logs for well completions and digital photographs

Stewart, 2012 (SGE00779.A36)

• Reason for EPA involvement – litigation with shale gas, concerns related to hydraulic 

fracturing, with focus on onshore natural gas production

• EPA’s National Initiative – across 10 EPA regions

o EPA is looking at all exploration and production, not just hydraulic fracturing

o EPA is also looking at the full life cycle of natural gas wells because different 

stages of development require different BMPs and/or injunctive relief

o Companies are reaching out to EPA about new green completion technologies

• Discussed “NextGen” – next generation compliance.

o Involving electronic reporting (required through regulations and/or enforcement 

settlements)

 CWA NPDES e-reporting

 Expanding ECHO website to link data to enforcement actions

o Technology

 GMAP – geospatial measurement of air pollution (e.g., methane, BTEX)

 FLIR cameras

o Innovative Enforcement

 Geoplatform

 Target inspections based on source location near human health issues

• Settlements to-date:

o XTO – CWA (2013)

o Fluid Recovery Services – CWA (2013)

o Atlas Resources – CAA, EPCRA (2012)

Smith, 2012 (SGE00779.A35)

• Examples of Enforcement Issues:

o Donora Smog

o Cuyahoga River (CWA)

o Toxic Waste at Love Canal (Superfund)

o Robinson Township, PA (Oil and Gas Act 13)

o Chemical Spill into Elk River, WV (WV Tank Act)
Memorandum

11 July 2014

Page 19 of 21

19

• Trade Groups

o API

o Marcellus Shale Coalition

o PIOGA

o OOGA

o WVONGA

• Professional Networks

o A&WMA

o Consultants

o Counsel

o Operators

o NGOs (e.g., Environmental Defense Fund)

4.6.2 Inspection and Enforcement Panel Question and Answer Session

Q: Are federal regulations going to be put in place?

A: Federal regulations are in development and depend on what scientific studies show as 

to whether or not additional regulations are needed.

In an industry such as this, the federal government strongly relies on states. Federal 

government does targeting and inspection of a few target sites and/or communicates with 

states about bad actors. Then, the states often have the option of taking the cases before 

federal action (depending on authority delegation).

Q: How does SLPD work with WED, AED, and Waste and Chemical Enforcement?

A: They all work very closely with each other. SLPD oversees national initiative and 

discusses ongoing enforcement issues across offices.
Memorandum

11 July 2014

Page 20 of 21

20

Attachment 1

Power Point Presentations
Memorandum

11 July 2014

Page 21 of 21

21

Attachment 2

Presenter Contact Information