1. DEPARTMENT OF ENVIRONMENTAL PROTECTION
      2. Office of Oil and Gas Management
      3. TABLE OF CONTENTS
      4. I. INTRODUCTION
      5. II. DEFINITIONS
      6. III. AOR GEOMETRY
      7. A. AOR Geometry Selection Table
      8. Table 1. AOR Geometry Table.
      9. IV. REFERENCE MATERIAL REVIEW
      10. A. Reference Material Requirements Checklist
      11. Table 2. List of Publicly Available Reference Materials
      12. Table 3: List of Pay-for-Service Reference Materials
      13. V. LANDOWNER COORDINATION/SURFACE ACCESS
      14. A. Use of DEP Landowner Survey Form
      15. B. Use of Development Plan Form
      16. C. Land Management Agency/Commission Contacts
      17. D. Landowner Coordination Requirements Checklist
      18. E. Other Considerations
      19. VI. ADJACENT OPERATOR COORDINATION
      20. A. Wells Within the AOR
      21. B. Adjacent Operator Coordination Requirements Checklist
      22. C. Other Considerations
      23. VII. WELL MONITORING
      24. A. Hydraulic Fracturing Communication Risks and Monitoring Levels
      25. Figure 1: Conceptual Model of Impact Potential
      26. Impact Potential Continuum
      27. High Low
      28. Increasing Reservoir Thickness (Higher
      29. Treatment Volume ) →
      30. Increasing Lateral Offset from Well (Energy Dissipates) →
      31. Figure 2: Risk Characterization at Offset Wells
      32. B. Standard Monitoring Plans
      33. Figure 4: Standard Monitoring Plan for Unconventional Well
      34. C. Well Monitoring Requirements Checklist
      35. D. Other Considerations
      36. VIII. AOR REPORT DELIVERABLES
      37. A. Standard AOR Report Electronic Summary Table
      38. B. Site-specific AOR Report
      39. C. AOR Report Deliverables Requirements Checklist
      40. D. Other Considerations
      41. Figure 5: AOR Summary Table Report Parameters
      42. Figure 5 Continued
      43. IX. WELL ADOPTION
      44. A. Other Considerations
      45. X. INCIDENT REPORTING AND RESOLUTION
      46. C. Incident Resolution
      47. D. Other Considerations
      48. Figure 6: Standard Follow-up Incident Report
      49. APPENDIX A - AOR GEOMETRY
      50. APPENDIX B - MAP INDICES OF GEOGRAPHIC AREAS COVERED BY VARIOUS
      51. STANDARD REFERENCE MATERIALS
      52. APPENDIX C - SUPPORTING TECHNICAL INFORMATION
      53. Treatment Pressure and Volume Monitoring
      54. APPENDIX D - DEP EMERGENCY RESPONSE CONTACT INFORMATION

800-0810-001 / Interim Final October 8, 2016 / Page i
DEPARTMENT OF ENVIRONMENTAL PROTECTION
Office of Oil and Gas Management
DOCUMENT NUMBER:
800-0810-001
TITLE:
Guidelines for Implementing Area of Review (AOR) Regulatory
Requirement for Unconventional Wells
EFFECTIVE DATE:
October 8, 2016
AUTHORITY:
2012 Oil and Gas Act (58 Pa. C.S. § 3201
et seq.
), Clean Streams Law
(35 P.S. § 691.1
et seq.
), 25 Pa. Code §§ 78a.52a and 78a.73
POLICY:
Unconventional well operators
conducting
hydraulic fracturing
activities
should follow this policy to minimize the likelihood of
communication
incidents
and to ensure protection of public health, public safety and the
environment.
PURPOSE:
The purpose of this guidance is to inform those engaged in
hydraulic
fracturing
activities how to comply with the requirements of The Clean
Streams Law, the 2012 Oil and Gas Act, 25 Pa. Code Chapter 78a, and
other applicable laws. This policy is developed to facilitate appropriate
risk mitigation for
unconventional well operators
and includes a risk-
based classification scheme for
offset well
locations and commensurate
levels of monitoring; sections addressing
communication incident
management, reporting, and resolution; and operational alternatives and
technical considerations for different anticipated scenarios. This policy
also provides an outline of the Department of Environment Protection’s
(Department or DEP) well adoption permitting process.
APPLICABILITY:
This Policy applies to
operators
conducting
hydraulic fracturing
activities
at
unconventional wells
in the Commonwealth of Pennsylvania.
DISCLAIMER:
The policies and procedures outlined in this guidance document are
intended to supplement existing requirements. Nothing in the policies or
procedures will affect regulatory requirements.
The policies and procedures herein are not an adjudication or a regulation.
There is no intent on the part of the Department to give these rules that
weight or deference. This document establishes the framework, within
which DEP will exercise its administrative discretion in the future. DEP
reserves the discretion to deviate from this policy statement if
circumstances warrant.
PAGE LENGTH:
48

800-0810-001 / Interim Final October 8, 2016 / Page ii
TABLE OF CONTENTS
I.
Introduction......................................................................................................................................1
II.
Definitions........................................................................................................................................1
III.
AOR Geometry ................................................................................................................................4
A.
AOR Geometry Selection Table..........................................................................................4
Table 1. AOR Geometry Table...........................................................................................4
IV.
Reference Material Review..............................................................................................................4
A.
Reference Material Requirements Checklist .......................................................................5
Table 2. List of Publicly Available Reference Materials....................................................6
Table 3: List of Pay-for-Service Reference Materials........................................................9
V.
Landowner Coordination/Surface Access......................................................................................10
A.
Use of DEP Landowner Survey Form ...............................................................................10
B.
Use of Development Plan Form.........................................................................................11
C.
Land Management Agency/Commission Contacts............................................................12
D.
Landowner Coordination Requirements Checklist............................................................13
E.
Other Considerations .........................................................................................................13
VI.
Adjacent Operator Coordination....................................................................................................13
A.
Wells Within the AOR.......................................................................................................13
B.
Adjacent Operator Coordination Requirements Checklist ................................................14
C.
Other Considerations .........................................................................................................14
VII.
Well Monitoring.............................................................................................................................15
A.
Hydraulic Fracturing Communication Risks and Monitoring Levels................................15
Figure 1: Conceptual Model of Impact Potential..............................................................16
Figure 2: Risk Characterization at Offset Wells...............................................................17
Figure 3: Suggested Monitoring Levels, Notification Responsibilities, and
Monitoring/Risk Mitigation Options.................................................................18
B.
Standard Monitoring Plans ................................................................................................19
Figure 4: Standard Monitoring Plan for Unconventional Well ........................................20
C.
Well Monitoring Requirements Checklist.........................................................................21
D.
Other Considerations .........................................................................................................21
VIII.
AOR Report Deliverables..............................................................................................................21
A.
Standard AOR Report Electronic Summary Table............................................................21
B.
Site-specific AOR Report ..................................................................................................22
C.
AOR Report Deliverables Requirements Checklist...........................................................22
D.
Other Considerations .........................................................................................................22
Figure 5: AOR Summary Table Report Parameters .........................................................23
IX.
Well Adoption................................................................................................................................25
A.
Other Considerations .........................................................................................................25
X.
Incident Reporting And Resolution ...............................................................................................25
A.
Incidents Requiring 2-Hour Notification and 3-Day Follow-up Incident Report..............26
B.
Incidents Requiring 24-Hour Notification and 30-Day Follow-up Incident Report..........27
C.
Incident Resolution............................................................................................................28
D.
Other Considerations .........................................................................................................29
Figure 6: Standard Follow-up Incident Report .................................................................30

800-0810-001 / Interim Final October 8, 2016 / Page iii
Appendix A - AOR Geometry .................................................................................................................. 32
Appendix B - Map Indices Of Geographic Areas Covered By Various Standard Reference
Materials............................................................................................................................. 34
Appendix C - Supporting Technical Information ..................................................................................... 42
Appendix D - DEP Emergency Response Contact Information ............................................................... 44
Appendix E - AOR Process Flow Diagram .............................................................................................. 45

800-0810-001 / Interim Final October 8, 2016 / Page 1
I.
INTRODUCTION
Hydraulic fracturing
is a technical procedure utilized by the oil and gas industry to break down
rock and extend and prop open fractures in hydrocarbon reservoirs in order to increase oil and
gas recovery. It involves the application of surface and hydrostatic pressures that combine to
generate bottom hole pressures in excess of rock strength and, thus, fracture the rock.
Subsequent to this, emplacement of materials known as proppants occurs to prevent fracture
closure after treatment pressure is reduced. Due to the character of the oil and gas reservoirs in
Pennsylvania,
hydraulic fracturing
is necessary at most wells to produce commercial quantities
of hydrocarbons.
When oil- or gas-bearing reservoirs are vertically isolated from shallower, freshwater aquifers
serving as sources of drinking water by adequate intervening rock layers,
hydraulic fracturing
can be utilized with negligible risk to waters of the Commonwealth. However, when other wells
penetrate the
zone of hydraulic fracturing influence
, they increase risk by serving as potential
conduits to the surface and shallow subsurface. Properly plugged or equipped operating wells
notably lessen this risk.
The Area of Review (AOR) regulations of Chapter 78a, found in sections 78a.52a and 78a.73,
provide the assessment, reporting, monitoring and incident resolution requirements established to
appropriately address risks associated with
hydraulic fracturing
communications. This
document provides further clarification related to those sections of the regulations. Wherever
possible, materials are sequenced chronologically from an operational perspective.
II.
DEFINITIONS
This section of the document provides the Department of Environmental Protection’s (DEP)
interpretations of terms used in sections 78a.52a and 78a.73 and utilized throughout the
document. Many of these terms have context-specific meanings and the definitions are,
therefore, provided for clarity related to specific regulatory requirements. This section also
includes definitions from the 2012 Oil and Gas Act and 25 Pa. Code Chapter 78a for reference.
Note that the terms defined in this section are italicized throughout the document.
Abandoned well
– As defined in 2012 Oil and Gas Act (58 Pa.C.S. § 3201
et seq.
).
Active well
– For the purposes of this policy, a well:
(1)
That is designed to be capable of flowing or producing hydrocarbons into a metered
gathering system, for commercial purposes; or one which is designed to provide natural
gas for the purposes of supplying a domestic or commercial property. Both uses defined
may apply at a single well.
(2)
That has been assigned a permit or registration number by the state of Pennsylvania and
has not been designated a status of
Inactive
,
Orphan, Abandoned
, or Plugged and
Abandoned.
(3)
That for the purposes of notification of adjacent
operators
, is being drilled or stimulated
if it is determined that it penetrates or is likely to penetrate the zone of influence of the
hydraulic fracturing
activity.
(4)
That penetrates below the typically recognized freshwater zone, including gas storage
wells, injection wells used for secondary recovery and disposal wells.

800-0810-001 / Interim Final October 8, 2016 / Page 2
(5)
That meet criteria (1), (2) or (3) and has not been permitted or registered by the state of
Pennsylvania.
Bottom hole location
GPS coordinates
of the deepest penetration of the well (decimal degrees)
for a vertical well, i.e.,
GPS coordinates
of surface hole location; and depth below the last
measured
GPS coordinate
pair equivalent surface location for an intentionally deviated or
horizontal well. All coordinate data must reference the NAD 83 geodetic reference system.
Closest approach
– The point or points along the length of a lateral (horizontal) well bore that
potentially fall within the AOR radius (1,000 feet) of an
offset well
.
Communication incident
– A transfer of measurable pressure or fluid flow from a well
undergoing
hydraulic fracturing
to an
offset well
that is reportable in accordance with this policy.
In certain cases, the referenced transfer of pressure or fluid may be evidenced at the well
undergoing
hydraulic fracturing
.
GPS (global positioning system) coordinates
– A satellite-based positioning system that provides
detailed coordinate data, i.e., latitude and longitude. It is composed of user, control, and satellite
segments, and allows precise position location quickly and with high accuracy (adapted from
Bolstad, 2008). GPS utilizes a worldwide common grid that is easily converted to any local grid,
is passive in all-weather operations, gives continuous real-time information, and is capable of
supporting an unlimited number of users and areas (adapted from U.S. Air Force, 2016). The
accuracy of coordinates provided by any GPS must be compliant with DEP’s “Oil and Gas
Locational Guidance” (Document Number: 550-2100-009) (+/- 10m) for wells that require
visual monitoring
at the
offset well
location as part of the AOR regulation. It is acceptable to
collect locational information using standard surveying techniques. For wells in the area of
review depicted on the submitted plat,
GPS coordinates
may be derived from a separate source
such as on-file permits or available databases and do not need to be field-verified or compliant
with DEP’s “Oil and Gas Locational Guidance”. All coordinate data must reference the NAD 83
geodetic reference system.
Hydraulic fracturing/hydraulically fractured
– Injecting fracturing fluids into the target
formation at a force exceeding the parting pressure of the rock, thus inducing fractures through
which oil or gas can flow to the well bore (adapted from API Guidance Document HF3, 2011).
Inactive well
– A well granted Inactive Status by DEP pursuant to the 2012 Oil and Gas Act
(58 Pa.C.S. § 3214).
Landowner
– For the purposes of this policy, any owner that has a right or interest in a surface
estate. In certain cases, this owner may also have rights or interests in the mineral estate or oil
and gas rights.
Offset well
– Any
Active, Inactive, Orphan, Abandoned
or Plugged and Abandoned well
surrounding a well that is undergoing
hydraulic fracturing
.
Orphan well
– As defined in 2012 Oil and Gas Act (58 Pa.C.S. § 3201
et seq.
).
Owner (of a well)
– An
owner
per Pennsylvania’s Oil and Gas Act, 2012 (58 Pa.C.S. § 3203) is
defined to be person who owns, manages, leases, controls or possesses an oil or gas well.
Owner

800-0810-001 / Interim Final October 8, 2016 / Page 3
does not include owners or possessors of surface real estate property on which an
abandoned
well
is located who did not participate or incur costs in the drilling/extraction operation of the
abandoned well
and has no right of control over the drilling/extraction operation of the
abandoned well
. An
owner
is not necessarily the same individual as the
Responsible
Party/Operator
(see definition that follows), but is understood to be the person who has legal
access to the well, and legal rights to any economic benefit, i.e. production, from the well.
Responsible Party/Operator
– The person designated as the well
operator
or
operator
on the
permit application or well registration per Pennsylvania’s Oil and Gas Act (58 Pa.C.S. § 3203),
i.e., the permit holder. Where a permit or registration was not issued, the term shall mean any
person who locates, drills, operates, alters or plugs any well or reconditions any well with the
purpose of production therefrom. In cases where a well is used in connection with the
underground storage of gas, the term also means a “storage
operator
.” Simply “locating” a well
without the purpose of producing it does not assign
responsible party
status to an
operator
developing an area. The
responsible party
for the condition and maintenance of a well is
assumed to be equivalent to the
operator
, but could also be the
owner
in the case where the two
are not the same.
True vertical depth/True bottom hole depth
– For the purposes of the AOR regulations, these
terms should be considered to be equivalent.
True bottom hole depth
is defined to be the best
available estimate of the depth in feet below the surface hole location for the deepest penetration
point of the well. This shall be either as reported in available records, or represent a best
technical estimate provided by the
operator
in consideration of development history in the state
in the area of activity. For an intentionally deviated well, this is the depth below the
x-y equivalent surface location of the deepest penetration point.
Unconventional formation
– As defined in Oil and Gas Act of 2012 (58 Pa.C.S. § 3201
et seq.
).
Unconventional well
– A bore hole drilled or being drilled for the purpose of or to be used for the
production of natural gas from an
unconventional formation
(as defined in the Oil and Gas Act of
2012 (58 Pa.C.S. § 3201
et seq.
).
Visual monitoring
– Verification at the location on the ground that is the identified site of a well
bore requiring monitoring or some other feature that would require such monitoring. Eye contact
or instrumentation are both suitable mechanisms for completing
visual monitoring
and “visual”
inspections may be completed at a time interval that is respective of how well the site requiring
monitoring is secured and the risk the monitored site poses.
Well control incident/loss of well control
– A scenario where the treatment pressure, producing
pressure, and/or annular pressure of the well being treated or any
offset well
deviates from
anticipated pressures in a manner that indicates mechanical integrity has been compromised and
continued operations pose a risk to personnel safety, equipment integrity, or the environment
(adapted from API RP 100-1, 9.4.5, 2015). This definition also includes any situations where a
communication incident
requires mobilization of specialized equipment to enter an
offset well
under pressure in order to circulate out a kick.
Zone of hydraulic fracturing influence
– A vertical buffer distance referencing upward or
downward offsets from notch or perforation elevations in order to define what
offset wells
falling
in the AOR have the highest potential to be communicated with during
hydraulic fracturing

800-0810-001 / Interim Final October 8, 2016 / Page 4
activities. The
zone of hydraulic fracturing influence
is defined as a function of perforation
elevation and is set at +/- 1,500 feet for all
unconventional wells
.
III.
AOR GEOMETRY
Sections 78a.52a. and 78a.73 require an
operator
of
unconventional
wells to identify wells
within a specific area, execute monitoring at a subset of those wells having certain penetration
depths, and submit a report and accompanying plat to DEP containing the information required
by section 78a.52a(c) prior to drilling the well. These areas and penetration depths are a function
of the well attributes that is the subject of the area of review, i.e., the well that will be stimulated
using
hydraulic fracturing
.
For horizontal and vertical
unconventional wells
, survey distances reference the plan view
projection of the well bore path and are set at 1,000 feet in all directions surrounding it. The well
bore path in plan view for vertical wells is the surface hole location.
See
§ 78a.52a(a).
True vertical depths
of
offset wells
determine notification responsibilities and whether or not
wells located within the AOR must be visually monitored during
hydraulic fracturing
activities.
Vertical buffer distances, referencing perforation elevations for cased hole completions are
established at +/- 1,500 feet for all
unconventional wells
.
See
§ 78a.73(c).
Schematics depicting AOR geometries are included in Appendix A.
A.
AOR Geometry Selection Table
Select the characteristics that describe the well that is the subject of the AOR:
Table 1. AOR Geometry Table.
Well Type
Orientation
AOR
Distance (ft)
Wells Requiring Monitoring
Unconventional
Vertical
1,000
all that penetrate within +/- 1,500 feet of
uppermost and lowermost perforations
Unconventional
Horizontal
1,000
all that penetrate within +/- 1,500 feet of
uppermost and lowermost perforations
IV.
REFERENCE MATERIAL REVIEW
Section 78a.52a(b)(1)–(2) provides that
operators
must identify
offset wells
by (1) conducting a
review of DEP’s well databases and other available well databases and (2) conduct a review of
historical sources of information, such as applicable farmline maps, where accessible. Numerous
sources of information are available for determining the locations of
offset wells
falling within
the AOR.
DEP has identified several well databases and historical sources of information to ensure
compliance with the identification requirements in section 78a.52a(b)(1)-(2). In addition to a
desktop review of databases and historical sources, a thorough field survey may, in many cases,
be a superior way to identify offset wells. Additionally, as
operators
field locate
offset wells
included the AOR report deliverables package, DEP will review and verify this information, as

800-0810-001 / Interim Final October 8, 2016 / Page 5
resources allow; make necessary corrections; and add previously unidentified wells to its own
databases.
Table 2 lists required sources to be used for completing the AOR survey as well as other
potentially useful sources. With the exception of the required sources, discretion may be applied
by the
operator
to arrive at a final conclusion regarding which reference sources may be most
useful for assessing their site. Required sources are shaded in red.
Table 3 provides additional pay-for-service sources that may be useful when completing the
AOR survey. Note that accessing these additional reference materials is not a regulatory
requirement and that the compilation is provided for informational purposes only.
A.
Reference Material Requirements Checklist
Review list of reference materials in Table 1 and the associated Map Indices in
Appendix B. Apply professional discretion to determine which reference
materials should be used to locate
offset wells
at your site, keeping in mind that
the DEP Oil and Gas Map (or associated databases) and DCNR Open File Report
OFOG 15 01.2 (Map 10) must always be consulted for any portions of the AOR
not surveyed on foot – these sources are shaded in red.
Construct a table of well locations by status and list the reference material source
used to identify each well.
Determine which wells will require monitoring, i.e., which wells penetrate the
zone of hydraulic fracturing influence
?
Indicate which wells in the AOR will require notification of adjacent
operators
.

800-0810-001 / Interim Final October 8, 2016 / Page 6
Table 2. List of Publicly Available Reference Materials
Note that not all sources provide statewide coverage and professional judgment should be applied to determine which sources are appropriate
for the site being assessed. A thorough field survey is recommended in certain cases.
Source
Geographic
Area of
Applicability
Location
Comments
Instructions for Use
County/Local
Historical
Societies
Statewide
Establish local contacts through
various mechanisms
These organizations often
archive historical maps which
may be inclusive of oil and gas
well locations
Find contact information and call
organization to determine if any
sources are available for review.
DCNR BTGS
Reports and
Publications
Limited
Geographic
Extent
http://www.gis.dcnr.state.pa.us/ge
ology/index.html
Also see Map Index in
Appendix B
Reports and other publications
with maps depicting oil and
gas well locations associated
with different fields throughout
the commonwealth
Navigate to PaGEODE website and
search for reports by quadrangle.
Compare to Appendix B to determine
which reports cover oil and gas topics
and download applicable reports for
review or visit BTGS in Pittsburgh to
review report.
DCNR BTGS
Farmline Maps
Limited
Geographic
Extent
See Map Index in Appendix B
Farmline map collection willed
to Bureau of Topographic and
Geologic Survey by Equitable
Reference Appendix B to determine if
maps are available that cover drilling
site and consult BTGS to review
maps.
DEP Oil and
Gas Map
1
Statewide
http://www.depgis.state.pa.us/Pa
OilAndGasMapping/
Web-based GIS for mapping
wells throughout the state
Navigate to area of operation and
select well by status to view locations.
Note that this information can also be
downloaded in tabular format from
DEP’s website:
http://www.dep.pa.gov/Business/Ener
gy/OilandGasPrograms/OilandGasMg
mt/Oil-and-Gas-Reports/Pages

800-0810-001 / Interim Final October 8, 2016 / Page 7
Source
Geographic
Area of
Applicability
Location
Comments
Instructions for Use
DEP
Production
Reporting
Statewide
https://www.paoilandgasreporting
.state.pa.us/publicreports/Module
s/Welcome/Agreement.aspx
Most useful in situations where
adjacent
operator
cannot be
successfully contacted using
available DEP address, as
sometimes other companies
report production on behalf of
the
operator
and may be able
to provide updated contact
information
Search for well using API #. Contact
DEP (717.772.2199) to determine who
reported production for the well in
question.
DEP Spud
Report
1
Statewide
http://www.depreportingservices.
state.pa.us/ReportServer/Pages/R
eportViewer.aspx?/Oil_Gas/Spud
_External_Data
For wells in process of being
drilled that have not yet been
input in eFACTS or EDWIN
Use option for querying by location,
i.e., query by municipality to
determine what wells may be in
process of being drilled or what wells
have been drilled but not entered into
eFACTS.
PASDA
Historic Wells
and Mine Map
Atlas
Limited
Geographic
Extent
http://www.pasda.psu.edu/
This currently includes wells
that were digitized from analog
source maps (WPA and
K-sheet/H-sheet mine map
series) by DEP and wells
located in the footprint of
historic coal mines (Mine Map
Atlas); this is not a
comprehensive compilation
and is subject to updates
In the “Data Search” box in the upper
right corner of the main website,
search for “historic wells.” Click on
the title and then click preview data to
see locations in map form or to
download a scanned map. The mine
Map Atlas link is on main PASDA
Page.
Penn Pilot
Statewide
http://www.pennpilot.psu.edu/
Archive of historical aerial
imagery
Input address or coordinates to
download associated aerial images.
Options include filtering on location
and image era. Images from the 1930s
to 1970s are available.
The National
Map
Statewide
http://viewer.nationalmap.gov/vie
wer/
Archive of current USGS
topographic maps
Input address or coordinates and select
“Other Featured Data” to view
available topographic maps.

800-0810-001 / Interim Final October 8, 2016 / Page 8
Source
Geographic
Area of
Applicability
Location
Comments
Instructions for Use
USGS
Historical
Topographic
Map Explorer
Statewide
http://historicalmaps.arcgis.com/u
sgs/
Archive of current and historic
USGS topographic maps
Input address or coordinates to review
available historical topographic maps
for the site. Maps from late 1800s to
1980s are available.
Google Earth
Pro
Statewide
https://www.google.com/earth/
Aerial imagery dating back
1990s
After downloading free software,
input address or coordinates to review
available historical aerial imagery for
the site.
USGS Reports
and
Publications
Limited
Geographic
Extent
http://energy.usgs.gov/RegionalSt
udies/AppalachianBasin.aspx
Archive of open-file reports
discussing development
histories in various portions of
Appalachian basin
Compare to Appendix B to determine
which reports cover oil and gas topics
and visit BTGS in Pittsburgh to
review report.
Industry
Historic Map
Inventory
Limited
Geographic
Extent
Various
Any maps in the possession of
the
operator
completing
hydraulic fracturing
Review available maps.
DCNR Open
File Report
OFOG 15-01.2
(Map 10)
Statewide
http://www.dcnr.state.pa.us/topog
eo/publications/digitaldata/index.
htm#oil
GIS layer that provides
comprehensive compilation of
oil and gas well depths in
Pennsylvania
Download Open File Report files from
DCNR website and import shapefiles
into GIS
1
Indicates mandatory reference source (shaded red).

800-0810-001 / Interim Final October 8, 2016 / Page 9
Table 3: List of Pay-for-Service Reference Materials
Note: May have additional information useful for completing the AOR survey.
Source
Location
Comments
Core Lab Consortia
http://corelab.com/
None
DrillingInfo
http://drillinginfo.com/
None
EDWIN (formerly
PAIRIS/WIS)
https://edwin.onbaseonline.com/1500AppNet/
Login.aspx
Database containing well records/completion
reports for oil and gas wells drilled in Pennsylvania
ENERDEQ
https://www.ihs.com/products/oil-gas-tools-
enerdeq-browser.html
An IHS service
IHS
https://www.ihs.com/products/us-well-
data.html
None
ITG
www.ITG.com
Analysis of data
Natural Gas
Intelligence
http://www.naturalgasintel.com.newsletters/2-
shaledaily
Analysis of data
TGS Well Log Data
https://llp.tgsnopec.com/llp/index.aspx
None
Woodmac
http://www/woodmac.com
Analysis of data

800-0810-001 / Interim Final October 8, 2016 / Page 10
V.
LANDOWNER COORDINATION/SURFACE ACCESS
In addition to reviewing databases and historical sources to identify
offset wells
in
section 78a.52a(1)–(2), section 78a.52a(b)(3) requires the
operator
to submit a questionnaire by
certified mail on forms provided by DEP to
landowners
whose property is within the AOR. The
intent of this questionnaire is to solicit information regarding the precise location of
offset wells
on their property. Section 78a.52a(c) requires the
operator
to provide proof of notification that
the
operator
submitted questionnaires to those applicable landowners. This regulatory process
defined is also critical for coordinating surface access to locate any wells in the field that the
operator
is responsible for monitoring.
All information gathered as part of
landowner
surveys conducted in accordance with
section 78a.52a(b)(3) may be cataloged for reuse by the
operator
for up to three (3) years from
the date surveying of the parcel was completed. With approval from DEP, information gathered
using the development plan option described below may be referenced for an additional two (2)
years for a total of five (5) years from the date of collection. Information collected is
transferrable to other
operators
who may acquire a lease in situations when the original,
documented survey results are provided to the new
operator
.
A.
Use of DEP Landowner Survey Form
In accordance with section 78a.52a(b)(3), DEP developed a form for completing the
required
landowner
surveys: 8000-PM-OOGM0148U. This form must be sent via
certified mail, as defined in 25 Pa. Code § 78a.1, to all
landowners
occupying parcels
within the established AOR. It is recommended that a reference map be included with
the form to best assist the
landowner
in determining whether or not wells they are aware
of fall within the AOR. The form must be mailed to the person identified in courthouse
records of the county who is designated to receive tax notices for the surface tax parcel,
although this person may appoint a local designee. If more than one tax parcel within the
prescribed AOR radius is registered to the same individual, multiple tax parcels can be
included on a single form. Multiple proposed
unconventional
drilling locations may also
be referenced on a single form. This is most relevant in situations where a
landowner
owns are large parcel or when a single parcel contains a multi-well pad.
The instructions accompanying the form specify that a
landowner
or the landowner’s
designee should complete and return the form to the
operator
within ten (10) business
days of receipt. It is not required that certified mail receipts or completed forms be sent
to DEP along with the AOR deliverables package, but the process must be verified by the
operator
completing the AOR report form. It is recommended, but not required, that all
certified mail receipts and completed questionnaires be retained by the
operator
for
five (5) years following the completion of
hydraulic fracturing
activities as
documentation that the regulatory requirements were satisfied. This may also facilitate
the transfer of
landowner
survey information to other
operators
.
As part of the survey,
landowners
are asked to provide documentation of any wells they
are aware of on their property. Documentation may be in the form of pictures (physical
evidence) or records (historic maps, well records, etc.).
Landowners
are also asked if
they would be willing to share documentation concerning any wells with
operators
and
allow the
operator
access to their property to evaluate any identified wells, including

800-0810-001 / Interim Final October 8, 2016 / Page 11
those known by the
landowner
and any wells the
operator
may have become aware of
through analysis of available reference materials.
There is no expectation that
operators
access wells under any of the following scenarios:
(1)
The
landowner
does not complete the questionnaire within a reasonable
timeframe or at all.
(2)
The
landowner
does not acknowledge that any physical evidence of a well’s
presence exists nor do they indicate that they have any official records
documenting the presence of a well.
(3)
The
landowner
claims they have physical evidence or official records
documenting the presence of wells on their property but is unwilling to share such
information with the
operator
.
(4)
The
landowner
will not grant access to the
operator
.
(5)
Research completed by the
operator
and documented along with the AOR report
deliverables indicates that any wells that may be present on the
landowner’s
property are not likely to penetrate within the
zone of hydraulic fracturing
influence
and the
landowner
has not provided any information that would call into
question the validity of this determination.
B.
Use of Development Plan Form
Many
operators
have lease agreements with state agencies or coordinate with land
management agencies when oil and gas rights are severed from surface rights. Private
landowners
may also own significant acreage in rural areas. It is more common in these
situations for development to take place on large tracts of land. Additionally,
operators
may wish to evaluate many smaller tracts of land at one time to prepare for well pad
development. An operator may fulfill the requirements in section 78a.52a(b)(3) by
coordinating with
landowners
to identify
offset wells
as presented in this section of the
document.
Use of the
Development Plan form
, which is designed to enable efficiency measures, may
be appropriate in the following scenarios:
(1)
An
operator
has a lease agreement with a state or federal agency or a working
access agreement with the agency in cases where oil and gas rights are severed
from surface rights, e.g., DCNR, USFS, PGC, etc.).
(2)
An
operator
is dealing with one or several large
landowners
.
(3)
An
operator
is looking to evaluate large tracts of land (possibly with numerous
surface
landowners
) in preparation for significant exploration efforts and to
complete due-diligence assessments prior to finalizing site construction, drilling,
and
hydraulic fracturing
.
The
Development Plan form
and accompanying instructions (8000-PM-OOGM0147U)
are accessible from DEP’s website and may be utilized for coordinating with landowners
and identifying
offset wells
under the development plan option. The form allows the
operator
to maintain an electronic tabular summary of parcels associated with multiple
well locations. Because this process potentially covers much larger areas of
development, it necessarily requires more lead time/earlier coordination with
landowners

800-0810-001 / Interim Final October 8, 2016 / Page 12
and it should not be used in situations where information must be gathered within
ten (10) business days, although the forms associated with the 10-day process must be
used to facilitate the collection of information needed under the development plan option
per the regulatory requirements of section 78a.52a(b)(3).
Operators
choosing the
development plan option should allow for up to 30 business days for receipt of responses
and may request approval from DEP to extend the reference period up to a maximum of
five (5) years for any single well location.
It is recommended, but not required, that information used to complete the
landowner
survey (questionnaires, certified mail receipts, etc.) be retained by the
operator
for
five (5) years following the completion of
hydraulic fracturing
activities as
documentation that the regulatory requirements of section 78a.52a(b)(3) were satisfied.
This may also facilitate the transfer of survey information to other
operators
.
C.
Land Management Agency/Commission Contacts
In situations where a government agency or commission serves as the
landowner
,
operators
should use the following contact information to best coordinate
landowner
surveying activities.
(1)
PA Fish & Boat Commission
Property Services Chief/Real Estate Chief
450 Robinson Lane
Bellefonte, PA 16827
814-359-5221 or 814-359-5108
RA-fbpropertyservice@pa.gov
(2)
Forest Service/Allegheny National Forest
Supervisor’s Office
4 Farm Colony Drive
Warren, PA 16365
Attention: Colleen Kelly
(3)
DCNR Bureau of Forestry
Minerals Division
P.O. Box 8552
Harrisburg, PA 17105-8552
Attention: Chief, Oil and Gas
(4)
DCNR Bureau of State Parks
P.O. Box 8551
Harrisburg, PA 17150-8851
Attention: Chief, Park Operations and Maintenance Division
(5)
PA Game Commission
BWHM - Environmental Planning and Habitat Protection Division
OGM Section
2001 Elmerton Avenue
Harrisburg, PA 17110-9797

800-0810-001 / Interim Final October 8, 2016 / Page 13
D.
Landowner Coordination Requirements Checklist
?
Have all parcels in the AOR been identified and have addresses been determined
for each
landowner
?
?
Have
landowner
questionnaires been submitted to each property owner in the
AOR?
?
Were
landowner
questionnaires submitted via certified mail?
?
Is it necessary to schedule site visits to inspect any alleged wells or wells
identified by the
operator
through the database or historic source review?
The
landowner
has completed and returned the questionnaire within a
reasonable time.
The
landowner
has acknowledged that physical evidence of a well’s
presence exists or indicated that they have official records documenting
the presence of a well and is willing to share this information.
The
landowner
has agreed to grant access to the
operator
.
Research completed by the
operator
and documented along with the AOR
report deliverables indicates that at least one well present on the
landowner’s
property is likely to penetrate within the
zone of hydraulic
fracturing influence
or the
landowner
has provided information that at
least one well on their property is likely to penetrate the
zone of hydraulic
fracturing influence
E.
Other Considerations
?
Were site maps included with each
landowner
questionnaire?
?
Have returned questionnaires, certified mailing receipts, and other forms of
documentation been placed in a file that has a retention schedule of five (5) years
following the completion of
hydraulic fracturing
activities?
?
Has the
operator
determined that it will be important to document conditions at
wells on a
landowner’s
property prior to
hydraulic fracturing
activities even in a
situation where communication risks are low, i.e., is there concern that a false
claim regarding a
communication incident
may be filed?
?
Is a plan in place for attempting to re-contact unresponsive
landowners
in areas
where communication risks are elevated?
VI.
ADJACENT OPERATOR COORDINATION
Section 78a.73(c) requires
operators
completing
hydraulic fracturing
activities to notify adjacent
operators
with
offset wells
that penetrate the
zone of hydraulic fracturing influence
. The intent
of this section is to facilitate the necessary level of coordination between
operators
in order to
mitigate risk and ensure the integrity, safety, and continued viability of assets.
A.
Wells Within the AOR
After defining the AOR and prior to drilling, the
operator
shall contact all adjacent
operators
who are responsible for
active
,
inactive
,
abandoned
, and plugged and
abandoned wells in situations when the intended zone of completion (proposed

800-0810-001 / Interim Final October 8, 2016 / Page 14
perforation elevations) for the planned well is within +/-1,500 feet of any portion of any
offset well
bore path intersecting the AOR.
For recently plugged wells identified within the AOR that intercept the
zone of hydraulic
fracturing influence
, i.e., those plugged within the preceding 12 months, the
operator
who plugged the well is considered the
responsible party
and during coordination this
should be clearly established. Such wells include those where the final site restoration
has not yet been completed/approved and/or the bond has not yet been released. The
operator
intending to complete
hydraulic fracturing
activities may request that DEP
complete an inspection of the well prior to stimulation. Such inspections will be
completed at the agency’s discretion. Note that this assignment of responsibility for
recently plugged
offset wells
is exclusive to the AOR regulation and shall not be
interpreted to apply in other contexts, unless directed by DEP.
In accordance with section 78a.73(c), adjacent
operators
whose wells fall within the
AOR shall be notified of intended operations at least 30 days in advance of the
anticipated spud date, or at the time the well drilling permit is submitted if it is expected
that the well will be spud within 30 days of permit issuance. Wells in the process of
being drilled or stimulated are classified as
active
if the definition in this policy is
satisfied and must be considered during the analysis.
Operators
are also expected to
coordinate notification and monitoring activities within different business units of their
own companies.
DEP’s Well Inventory Report serves as the resource identifying the most up-to-date
contact information for
operators
in the state and can be accessed from the agency’s
reporting page.
Operators
intending to complete
hydraulic fracturing
activities should
maintain documentation of attempts to contact adjacent
operators
for up to five (5) years
following well completion.
B.
Adjacent Operator Coordination Requirements Checklist
?
Has notification been provided to
operators
with
offset wells
, including recently
plugged wells (within the last 12 months), within the AOR at least 30 days prior
to anticipated well spud?
?
Has notification to different business units, e.g., drilling, completions, operations
been provided within the company intending to conduct
hydraulic fracturing
activities?
?
Has the
hydraulic fracturing
operations team been briefed about actions that must
be taken when notified by an adjacent
operator
about a confirmed
communication
incident
?
C.
Other Considerations
?
Are coordinated monitoring efforts with the adjacent
operator
needed in
consideration of the communication risk at the location?
?
Have communication protocols for implementation during
hydraulic fracturing
activities, including timely notification in the event of an unintended
communication, been established with the adjacent
operator
?

800-0810-001 / Interim Final October 8, 2016 / Page 15
?
Has the subject of workover procedures been discussed with the adjacent
operator
, including scenarios where well work may be necessary to ensure
mechanical integrity and/or environmental protection standards? Has it been
determined who may assume financial responsibility for such work and the legal
mechanisms for moving forward with adequate liability protection?
?
Have risk mitigation strategies been fully evaluated in situations where an
adjacent
operator
has not been cooperative? Such strategies may include
revising/eliminating
hydraulic fracturing
stages or redirecting the targeted well
bore path for horizontal
unconventional wells
, moving the well location an
appropriate distance from the
offset well
, and/or completing visual observations
from a distance.
?
Have all correspondence or attempts to communicate with the adjacent
operator
been adequately documented and archived in a file with a retention schedule of
five (5) years?
VII.
WELL MONITORING
A.
Hydraulic Fracturing Communication Risks and Monitoring Levels
Section 78a.73(c) requires
operators
to visually monitor
offset wells
during stimulation
activities that penetrate within 1,500 feet measured vertically from the stimulation
perforations or have an unknown true vertical depth. Not all
offset wells
penetrating the
zone of hydraulic fracturing influence
pose the same level of risk. An assessment of
historical data and
communication incidents
supports the concept that communication
risks are a function of several different variables including
offset well
location, depth,
construction details, age, and status. Several of these variables are interrelated, making it
possible to further simplify the risk-characterization model. For this reason, there are
several options available for the
operator
to meet the monitoring requirements in
section 78a.73(c) based on the risk-classification criteria described below.
Key risk-classification criteria are:
(1)
Character of the
hydraulic fracturing
activity.
(2)
Character and location of wells in the AOR.
A generalized risk-classification scheme is presented in the figures that follow. Figure 1
categorizes the potential for impact as a function of reservoir thickness and offset
distance between the stimulated wells and surrounding wells falling within the AOR.
Figure 2 considers the character of the wells within the AOR.

800-0810-001 / Interim Final October 8, 2016 / Page 16
Figure 1: Conceptual Model of Impact Potential
Impact Potential Continuum
High
Low
Conceptual model characterizing impact potential based on treatment volume (reservoir thickness) and
offset distance for wells within the AOR.
Relatively Thin
Reservoir
Hydraulically
Fractured/Offset
Well Distant
(LOWER
POTENTIAL FOR
IMPACTS)
Relatively Thick
Reservoir
Hydraulically
Fractured/Offset
Well Near
(HIGHER
POTENTIAL FOR
IMPACTS)
Increasing Reservoir Thickness (Higher
Treatment Volume ) →
Increasing Lateral Offset from Well (Energy Dissipates) →

800-0810-001 / Interim Final October 8, 2016 / Page 17
Figure 2: Risk Characterization at Offset Wells
Description
General Risk Level
Wells within AOR which do not penetrate the
zone of hydraulic fracturing
influence
NEGLIGIBLE
Wells inside AOR which penetrate the zone
of hydraulic fracturing influence
Active wells
being drilled
LOWER
Active wells
in production/
inactive wells
Zone of hydraulic fracturing influence
/pressure isolation is verified
LOWER
Lack of
zone of hydraulic fracturing influence
/pressure isolation
HIGHER
Plugged and/or
abandoned wells
Well plugged in accordance with current regulations and laws
LOWER
Well plugged prior to passage of Act 223 (1984 Oil and Gas Act)
MODERATE
Well plugged prior to permitting era (1956)
HIGHER
Well on DEP's orphan and abandoned list
HIGHER
Abandoned well
for which plugging status is unknown
HIGHER
Characterization of risk associated with
offset wells
within the AOR that penetrate the
zone of hydraulic
fracturing influence
and
offset wells
within the AOR which do not penetrate the
zone of hydraulic
fracturing influence
. Note that site-specific well plugging methodologies may have significant influence
on the portion of the classification scheme related to
abandoned wells
.
Suggested levels of monitoring are established in Figure 3. Scenarios requiring adjacent
operator
notification, as specified in section 78a.73(c), are also summarized for
reference. Finally, general monitoring/risk mitigation options are described. It is
important to note that no accurate historical records of
hydraulic fracturing
communication incidents
have been kept. Because of this, the suggested monitoring
levels are not quantitative and instead represent relative levels of perceived risk.

800-0810-001 / Interim Final October 8, 2016 / Page 18
Figure 3: Suggested Monitoring Levels, Notification Responsibilities, and Monitoring/Risk Mitigation Options
Description
General Risk Level or
Suggested Monitoring
Level
Monitoring/Risk Mitigation
Options
Wells within AOR which do not penetrate the
zone of hydraulic fracturing influence
(NEGLIGIBLE)
NONE
Wells inside AOR which penetrate the
zone of hydraulic fracturing influence
Active wells
being drilled
(LOW)
NOTIFICATION ONLY
Active wells
in production/
inactive wells
Zone of hydraulic fracturing influence
/pressure isolation is verified
(LOW)
NOTIFICATION ONLY
Lack of
zone of hydraulic fracturing influence
/pressure isolation
(HIGH)
NOTIFICATION ONLY
Active wells
in production or being drilled/
inactive wells
(adjacent
operator
)
(LOW)
NOTIFICATION ONLY
Plugged and/or
abandoned wells
Abandoned well
or well plugged within preceding 12 months (adjacent
operator
)
(LOW)
NOTIFICATION ONLY
Well plugged in accordance with current regulations and laws
LOW
CHECK POST-COMPLETION
Well plugged prior to passage of Act 223 (1984 Oil and Gas Act)
MEDIUM
CHECK PRE- AND POST-
COMPLETION
Well plugged prior to well permitting era (1956)
HIGH
CONTINUOUS MONITORING
OR ENSURE CONTAINMENT
Well on DEP's orphan and abandoned list
HIGH
CONTINUOUS MONITORING
OR ENSURE CONTAINMENT
Abandoned well
for which plugging status is unknown
HIGH
CONTINUOUS MONITORING
OR ENSURE CONTAINMENT
Summary table of
offset well
characteristics, general risk level (in parentheses for wells requiring notification only) or suggested monitoring
levels, notification responsibilities, and monitoring/risk mitigation alternatives. Note that time intervals over which continuous monitoring is
required is dependent upon the character of the
hydraulic fracturing
operation and is further refined in Figure 4.

800-0810-001 / Interim Final October 8, 2016 / Page 19
B.
Standard Monitoring Plans
After locating all wells known to fall within the AOR, the
operator
must identify the
subset of those wells that require monitoring in accordance with section 78a.73(c):
intended zone of completion (proposed perforation elevations) for the planned well is
within +/-1,500 feet of any portion of any
offset well
bore path intersecting the AOR.
Suggested options for both
visual monitoring
and ensuring containment are provided
below. The operator may employ one or more of the listed techniques based on the
operator’s evaluation of the AOR. This list may not be comprehensive, i.e., there may be
other techniques that satisfy the regulatory requirements related to monitoring. In all
cases, it is essential that the
operator
coordinate with DEP prior to connecting any
equipment to an
offset well
with no
responsible party
, as repercussions related to
ownership responsibilities are at stake.
Monitoring/Containment techniques:
(1)
Employ RTU/continuous monitoring/automatic shut-in devices at producing wells
(monitoring/containment)
(2)
Empty tanks at producing wells for optimum capacity (containment)
(3)
With prior DEP authorization, equip
abandoned wells
with pressure gauges
(monitoring)
(4)
With prior DEP authorization, equip
abandoned wells
with tanks (containment)
(5)
Plug or re-plug
abandoned wells
(containment)
(6)
Install continuous gas meters/flow meters or employ hand-held gas meters at
abandoned wells
(monitoring)
(7)
Appoint field personnel with radio contact to observe adjacent wells (monitoring)
(8)
Install chart gauge(s) at producing wells for a permanent pressure record
(monitoring)
(9)
Use flagging tape and maintain clear observation pathways for
abandoned wells
that can be viewed from the rig operations area (monitoring)
Section 78a.52a requires the operator to submit a monitoring plan for wells that must be
monitored under section 78a.73(c), including the methods the operator will use to
monitor these wells. A standard monitoring plan is provided for
unconventional wells
in
the table that follows (Figure 4). The plan does not cover incident response, as that
subject is covered in Section X (Incident Reporting and Resolution). Monitoring
protocols are based on relative, perceived risk levels.
Operators
also have the option of
developing site-specific monitoring protocols that consider
communication incident
risks
identified in this policy. Such an approach may rely on well-field geometries/preferred
fracture propagation orientations and the character of the
hydraulic fracturing
activity
e.g., treatment volumes and pressures used. In such situations, the site-specific
assessment must be submitted as part of the AOR summary report. It is strongly
recommended that the details of site-specific monitoring plans also be discussed with
DEP prior to implementation. Under no circumstances may a monitoring plan be
proposed that does not involve the
operator
confirming whether or not a
communication
incident
has taken place through
visual monitoring
.

800-0810-001 / Interim Final October 8, 2016 / Page 20
Figure 4: Standard Monitoring Plan for Unconventional Well
Well Type
Orientation
Depth
(ft)
Pre-
Hydraulic Fracturing
/During
Hydraulic
Fracturing
Actions Based on Established
Monitoring Level
Post-
Hydraulic Fracturing
Actions Based on Established
Monitoring Level
Low
Medium
High
Low
Medium
High
Unconventional
Any
Any
No pre-
hydraulic
fracturing
requirements
Visually
observe pre-
hydraulic
fracturing
Ensure
containment
At conclusion of
hydraulic
fracturing
, check all identified
offset wells
requiring monitoring
within AOR
Visually observe
offset well
continuously
during
closest
approach
Note: The plan does not cover incident response, as that subject is covered in Section X (Incident Reporting and Resolution).

800-0810-001 / Interim Final October 8, 2016 / Page 21
C.
Well Monitoring Requirements Checklist
?
Have the construction characteristics, age, and status of the
offset wells
in the
AOR been determined and used to assign the appropriate monitoring level
(Figure 3)?
?
For
offset wells
in the AOR requiring monitoring, has well integrity been assessed
based on surface observations and a review of available records?
?
Has a risk-based monitoring plan been developed for
offset wells
within the AOR?
D.
Other Considerations
?
Has the character of the
hydraulic fracturing
activity been defined in terms of
anticipated treatment pressures, volumes, and pump durations and compared to
the information in Appendix C?
?
Has the expected type of fracture plane orientation, e.g., vertical or horizontal,
been determined for the interval(s) being targeted for production?
?
Does the risk change as a function of what activity is being completed at the well
undergoing
hydraulic fracturing
, i.e., multi-zone or multi-stage completions?
?
Have the standard monitoring protocols been considered (Figures 4 through 8)?
?
Has a plan for securing high-risk
offset wells
in the AOR been executed to
minimize the potential for environmental impacts?
VIII. AOR REPORT DELIVERABLES
Section 78a.52a(c) requires the
operator
to submit a report summarizing the AOR review,
including (1) a plat, (2) proof of submitting questionnaires to landowners, (3) a monitoring plan,
and (4) the true vertical depth of offset wells in the AOR, if known. The
AOR report
consists of
standard components that will be useful for creating a database detailing
operator
activities
associated with the regulation. The
AOR report
also consists of site-specific analyses and plans
that are not easily transferable to a tracking system, but are nonetheless important for
recognizing and addressing variability throughout the different oil and gas producing areas of the
state. This section of the guidance provides a tabular summary of the standard AOR
deliverables, as well as a discussion of considerations related to the composition of the
accompanying site-specific report. Note that an electronic plat must also be filed in conjunction
with each
AOR report
. The
AOR report
must be submitted electronically to DEP at least 30 days
in advance of well spud, or in cases where a well will be spud within 30 days of permit issuance,
along with the well permit package in accordance with section 78a.52a(d).
A.
Standard AOR Report Electronic Summary Table
In accordance with section 78a.52a(d), each
AOR report
must be submitted electronically
using the standard form available on DEP’s website. Instructions have been developed
for completion of the report (8000-FM-OOGM146U). Figure 5 is a tabular summary of
the standard components that must accompany each submittal. Note that not all
parameters listed apply for each report developed. Those that are not relevant should be
left blank. Each tabular report shall cross-reference a plat using the designated well ID.
The plat must consist of an electronically rendered map, drawing, or print that is
accurately drawn to scale and depicts all wells listed in the
AOR report
along with other
relevant features.

800-0810-001 / Interim Final October 8, 2016 / Page 22
Additional information concerning the well that is the subject of the AOR must also be
provided. This information shall be inclusive of anticipated surface and
bottom hole GPS
coordinates
for the well that will be stimulated by way of
hydraulic fracturing
and the
API number, or the farm name and number for a well that has not yet been permitted.
Finally,
operators
must indicate if all
landowners
within the AOR have been notified and
whether or not proof of notification is on file.
B.
Site-specific AOR Report
In certain cases, the
operator
completing the AOR survey may develop a site-specific
narrative report to accompany the electronic summary table. Information in the report
may consist of the following:
(1)
The specifics of the risk assessment completed to determine appropriate levels of
monitoring at applicable wells and details related to the type of monitoring
activities that will be implemented
(2)
Any historical well drilling analysis completed to estimate well
true vertical
depths
(3)
Any geologic evaluation used to modify the AOR geometry beyond the
dimensions prescribed in the regulations
(4)
Coordination/monitoring agreements between adjacent
operators
(5)
Documentation of identified well ownership and access issues
(6)
Bibliography of reference materials used to compile information on wells falling
within the AOR
Whenever a written accompanying report is deemed necessary, it shall be submitted to
DEP electronically in pdf format. Written reports are recommended by DEP in cases
where significant supplemental analyses were used to arrive at conclusions related to
assigning risk and implementing monitoring activities, as they will be critical in
determining what may have gone wrong when unanticipated
communication incidents
occur and also useful for resolving compliance matters in such cases.
C.
AOR Report Deliverables Requirements Checklist
?
Has the Standard
AOR Summary Table Report
been downloaded and completed
for the well that is the subject of the AOR?
?
Has an accompanying AOR well plat that references all wells in the AOR Report
Electronic Summary Table been prepared and submitted along with the AOR
Report Electronic Summary Table?
?
Do submitted
GPS coordinates
for all field-verified wells within the AOR meet
DEP accuracy requirements, i.e., +/-10 m?
D.
Other Considerations
?
Has the need for an accompanying narrative report been evaluated in
consideration of information that is most likely to be included in such a report
(see items (1)-(6) in subsection B above)?

800-0810-001 / Interim Final October 8, 2016 / Page 23
Figure 5: AOR Summary Table Report Parameters
Field Heading
Description of Report Parameter
Operator ID/OG Number
DEP ID or OGO number for the
operator
planning to conduct hydraulic fracturing.
Landowner
Notification
Documentation
"Y" to certify that all
landowners
with parcels in the area of review were notified per the regulatory requirements,
otherwise enter "N."
Were Any Wells Identified Within
the AOR?
“Y” if offset wells were identified within the AOR, otherwise enter “N.”
US Well No. (API
No.)/Authorization ID for Well
that is Subject of Area of Review
If the well has been permitted, provide the US Well No. (API No.) using the following format: CCC-XXXXX. CCC
represents the three-digit county code and XXXXX represents the unique, 5-digit county ID. The sections of the US
Well No. (API No.) must be separated by a dash (-). If the well has not been permitted, the GreenPort authorization
ID should be provided along with the county and municipality in the appropriate fields.
Municipality
Municipality that well will be drilled in if no US Well No./API No. has been assigned.
County
County that well will be drilled in if no US Well No./API No. has been assigned.
Surface Hole Latitude for Well
that is Subject of Area of Review
(decimal degrees)
The anticipated surface location latitude and longitude, in decimal degrees, for the well that is the subject of the area
of review. This must reference NAD 83 datum.
Surface Hole Longitude for Well
that is Subject of Area of Review
(decimal degrees)
Bottom Hole
Latitude for Well that
is Subject of Area of Review
(decimal degrees)
For horizontal wells, the anticipated
bottom hole
location latitude and longitude in decimal degrees for the well that
is the subject of the area of review. This must reference NAD 83 datum.
Bottom Hole
Longitude for Well
that is Subject of Area of Review
(decimal degrees)
Note: Information for
AOR Report
pertaining to well that will be hydraulically fractured.
Figure 5 Continued
ld Heading
Description of Report Parameter
US Well No. (API No.)/Alternate
Well ID
The US Well (API No.) assigned to the well using the following format: CCC-XXXXX. CCC represents the three-
digit county code and XXXXX represents the unique, 5-digit county ID. The sections of the US Well No. (API No.)
must be separated by a dash (-). If a US Well No. (API No.) has not been assigned, use the following numbering
system: “U1”, “U2”, “U3”, etc. The identifiers used in the report must be identical to those used on the site plat for
cross-referencing purposes.
Reference Material/Source
The source that used to identify the
offset well
from the list of available options: “DEP Database”, “Other Database”,
“Historical Source”, “
Operator
Map”, “
Landowner
Survey”, “Aerial Image”, or “Field Inspection.”
Well Status
The status used to classify the
offset well
from the list of available options: “
Active
”, “
Inactive
”, “
Orphan
”,
Abandoned
”, “Plugged & Abandoned”, or “Undetermined.” If the offset well has been field verified, the status
should reflect what was observed during the inspection.
Adjacent
Operator
ID/
OGO Number
If the
offset well
included in the summary report is the responsibility of an adjacent
operator
, please provide the DEP
ID or OGO number for that
operator
. Leave this space blank if neither notification nor monitoring at the offset well is
required. Indicate "No RP" if well does not have an
operator
associated with it.
Adjacent
Operator
Notification
“Y” if the adjacent
operator
was notified or “N” if the delivery service failed. This space should be left blank if the
well is the responsibility of the
operator
intending to conduct hydraulic fracturing activities at the well indicated in the
first section of Figure 5 or if the well does not require notification in advance of well spud

800-0810-001 / Interim Final October 8, 2016 / Page 24
ld Heading
Description of Report Parameter
Surface Location Latitude
(decimal degrees)
The true latitude and longitude in decimal degrees of the surface location of the well. This should be North American
Datum of 1983 (NAD 83) and must meet or exceed the current DEP policy regarding locational accuracy (+/- 10 m)
for any wells surveyed in the field by the operator.
Surface Location Longitude
(decimal degrees)
Bottom Hole Latitude (decimal
degrees)
The true latitude and longitude in decimal degrees of the bottom hole location of all intentionally deviated wells based
on a review of available records. This should be North American Datum of 1983 (NAD 83).
Bottom Hole Longitude (decimal
degrees)
Survey Accuracy (+/- meters)
For any well coordinates referenced in DEP/Department of Conservation and Natural Resources (DCNR) databases, or
anything digitized from a historical map or a map from a published report that has not been field verified, leave this
column blank. If the offset well has been field verified and surveyed with a hand-held GPS or other surveying
equipment, accuracy must be reported as a numerical value in meters in the space provided and meet the current DEP
accuracy policy: +/- 10 meters or better.
Access
"Y" if
landowner
consent for access has been granted or "N" if
landowner
consent for access has not been granted.
Property Tax ID #
The tax parcel ID for the tract of land where the
offset well
is located.
TVD (feet)
The
true vertical depth
(TVD) in feet for the
offset well
. This shall either be as reported in available records, or
represent a best technical estimate provided by the
operator
in consideration of development history in the state in the
area of activity. For an intentionally deviated well, this is the depth below the latitude-longitude equivalent surface
location of the deepest penetration point.
Information Source for TVD
Information regarding how the
offset well
TVD was determined from a list of available options: “DEP Well Record”,
“Publication Well Depth”, “Private Source Well Record”, “Study of Regional Drilling History”, or “Other”. A
separate written report may be necessary to explain measures undertaken by the
operator
to investigate drilling history
in an area.
Well Integrity Assessment
For
offset wells
in the monitoring plan that are observed in the field, the
operator
must assess the well's ability to
contain fluids based on a surface visual inspection. Please choose from the following codes for each
offset well
inspected in the field: "1" if the well appears to have integrity based on field observation and any well construction
details gleaned from a file review; "2" if the well appears to have compromised integrity or may experience
compromised integrity during
hydraulic fracturing
based on any well construction details gleaned from a file review;
and "3" if the integrity status cannot be determined with reasonable confidence. For wells not observed in the field,
this parameter should be left blank.
Monitored Site
If the
offset well
is included in monitoring plan, indicate "Y", otherwise indicate "N.”
Monitoring Level
Indicate the monitoring level from the list of available options: "High", "Medium", and "Low." Leave this field blank
if the well does not require monitoring.
Monitoring Plan Notes
This field is optional and is designed to contain specific notes explaining monitoring or mitigation plans for each well.
Entries are limited to 255 characters or less.
Engineered Communication
The engineered communications field is for use if an operator has planned a controlled communication event in
association with well efficiency testing. If such an event is planned, indicate "Y,” otherwise indicate "N." This space
should be left blank if the well does not require notification in advance of spud.
Text Comment
This field is optional and intended for use in cases when further clarification may be necessary. Entries are limited to
255 characters or less.
Standard report parameters for tabular component of
AOR Report
and accompanying Monitoring Plan
.

800-0810-001 / Interim Final October 8, 2016 / Page 25
IX.
WELL ADOPTION
In section 78a.73(d), the AOR regulation has provisions for adopting
offset wells
that have been
communicated with. Although a discussion of the details of the well adoption permit (Permit
Application to Adopt an Oil or Gas Well) is beyond the scope of this document, several
recommendations and general guidelines are provided for reference.
If an
operator
identifies an
abandoned
or
orphan well
within the AOR that they are interested in
adopting, it is recommended that this activity be pursued prior to commencement of
hydraulic
fracturing
, as it may be one way to effectively mitigate risk ahead of stimulation. Establishing
well ownership and identifying whether or not there is some operating interest in an
abandoned
well
is essential to manage liability in such situations. For wells already on DEP’s
orphan
and
abandoned
list, due diligence has been completed in this regard and an interested party need only
perform additional measures if they believe it is legally advisable to do so. For wells that are not
listed on DEP’s
orphan
and
abandoned
list, conducting due diligence related to well ownership
and operating interests is a critical step.
In all cases, it is essential to establish an updated lease agreement addressing operating/royalty-
disbursement conditions, and to secure ongoing access to rehabilitate and operate the well. DEP
does not regulate the details of lease agreements and does not intend to evaluate any processes
that were undertaken by the
operator
to bring the well back in to legal production aside from
those aimed at assuring that necessary environmental protection standards are in place.
For any wells that were communicated with during
hydraulic fracturing
activities, a site-specific
integrity assessment protocol or workover plan, potentially involving downhole analysis
procedures, must be submitted to DEP along with the adoption permit.
A.
Other Considerations
?
Have the well adoption permit and accompanying instructions been reviewed?
?
Have
abandoned
and
orphan wells
in the AOR been considered for adoption prior
to
hydraulic fracturing
activities?
?
For any wells on the adoption permit, have all potential
responsible parties
been
considered and has a thorough assessment of potential operating interests been
completed?
?
Has a lease agreement been established that provides ongoing access and the
ability to operate the well that is being considered for adoption?
X.
INCIDENT REPORTING AND RESOLUTION
Section 78a.73(c)-(d) provides notification and incident response requirements for certain
communication incidents
. Accordingly, to clearly define a protocol for incident resolution, it is
first essential to indicate what constitutes a reportable
communication incident
. Reportable
communication incidents
include, in accordance with section 78a.73(c): (1) any change in a well
required to be monitored, (2) any treatment pressure or volume changes indicative or abnormal
fracture propagation at the well being stimulated, or (3) confirmed well communication incidents
associated with the well’s stimulation activities. Inter-well communication intentionally
executed by the
operator
and communication incidents below the reporting thresholds defined in
this policy are not reportable
communication incidents
under section 78a.73(c). Please note,

800-0810-001 / Interim Final October 8, 2016 / Page 26
operators are required to maintain a safe operating environment.
See
58 Pa.C.S. § 3259(2);
25 Pa. Code § 78a.81. When a reportable
communication incident
occurs, the operator must
notify DEP, cease stimulation activities and prevent any pollution to waters of the
Commonwealth or discharges to the surface. This section of this document outlines the
operator’s obligations under different circumstances.
Please note that the notification and reporting requirements included in this regulation do not
necessarily satisfy other regulatory obligations under sections 78.73/78a.73 pertaining to the
over-pressuring of the surface casing seat, sections 78.86/78a.86 pertaining to defective casing
and cement, sections 78.88/78a.88 pertaining the mechanical integrity of operating wells, or
sections 78.89/78a.89 pertaining to the investigation of stray gas migration incidents; or any
other statutory or regulatory investigative and reporting requirements. Further, all environmental
releases of regulated substances must be reported and remediated in accordance with the Clean
Streams Law, section 91.33, section 78a.66, and/or applicable law.
A.
Incidents Requiring 2-Hour Notification and 3-Day Follow-up Incident Report
In cases where certain reportable incidents are identified, the
operator
must immediately
cease
hydraulic fracturing
and notify DEP via the electronic reporting notification
service on the DEP website. This notice must be filed within two (2) hours of when the
operator
first becomes aware of the incident. Note that established standards and
timelines must be followed for any
communication incidents
that also violate
section 91.33 or the provisions of section 78a.66. If, and only if, an emergency develops,
the operator should contact DEP Emergency Response by telephone immediately (see
Appendix D).
Hydraulic fracturing
may not commence again until DEP is satisfied that
the situation is under control and measures have been developed to prevent any further
anticipated risk. Part of this process includes submission of the standard electronic
follow-up
incident report
available for download on DEP’s website and described in
Figure 6 and the accompanying instructions for the incident report
(8000-PM-OOGM0145U).
Immediate activity cessation and notification is essential to begin the process of risk
mitigation and reduce the potential for compounding environmental impacts as soon as
possible. It is also critical for initiating conversations between the
operator
and DEP;
and coordination with the public, as necessary. A
communication
incident
report
must be
filed with the agency within three (3) days of when the
operator
first becomes aware of
the incident.
Communication incidents
that must be reported to DEP within two (2) hours and
followed up with a standard
incident report
within three (3) days include:
(1)
Any
communication incident
evidenced by downhole pressure or volume changes
during
hydraulic fracturing
in the well being completed when the specific event
observed indicates a loss of mechanical integrity, i.e., containment, and that could
pose a specific risk to the environment (surface or subsurface fluid release), safety
or is indicative of
loss of well control
. This would amount to a sudden loss of
pressure or a volume change that is clearly, statistically beyond the normal
variability that a job has.

800-0810-001 / Interim Final October 8, 2016 / Page 27
(2)
Any
communication incident
with an
abandoned
,
orphan
or plugged well; as the
ability for containment and pressure control at such wells is significantly limited.
Immediate reporting applies even in the case where an
operator
has established
temporary containment measures at the surface that appear to have been
implemented with success. A plan for permanently plugging the affected well
must be developed and executed by the
operator
as soon as practicable, unless the
operator
plans to adopt the well and place it into production. The plan may be
implemented without filing a notice of intent to plug the well, provided DEP
approval is received.
(3)
Any
communication incident
with any other well that the
operator
completing the
stimulation has been made aware of and that threatens or jeopardizes the integrity
of the surface or near surface environment as a result of a breach/loss of
containment, a release of pollution-causing substances to the environment, or
some other occurrence that has the potential to impact the waters of the
Commonwealth.
(4)
Any
communication incident
that results in a
well control incident/loss of well
control
as defined in this guidance.
(5)
Any
communication incident
that results in site safety risks as a result of
equipment malfunction or other events within the AOR.
B.
Incidents Requiring 24-Hour Notification and 30-Day Follow-up Incident Report
A subset of
communication incidents
may occur that were either anticipated and coupled
with measures introduced by the
operator
to maintain control of the situation, but were
not intentionally implemented or engineered; or that do not otherwise result in any
environmental, safety, or
well control incidents
by virtue of the
offset well’s
construction
and operating characteristics. The
operator
conducting
hydraulic fracturing
is not
required to cease
hydraulic fracturing
if: (1) any releases to the environment are
prevented, (2) safe site conditions are maintained at all times, (3) it is ensured that
offset
well
construction components and all appurtenances are adequately rated to contain fluid
pressure and volume, (4) DEP is notified within 24 hours of when the
operator
first
became aware of the incident via the electronic reporting notification service on the DEP
website, and (5) an
incident report
is filed with DEP within 30 days of when the
operator
first becomes aware of the incident.
Information associated with these
communication incidents
will help determine what
risk-mitigation measures are appropriate in the future, e.g., size of tank that should be
installed, allow DEP to complete follow-up work as needed with regard to any potential
well integrity problem(s), and enable DEP and the industry to continue to evaluate the
geometry of the AOR in a more comprehensive sense and update this guidance from a
risk-mitigation standpoint, as needed.
Communication incidents
that must be reported to DEP within 24 hours and followed up
with a standard
incident report
within 30 days include:
(1)
Any
communication incident
with any
active
or
inactive well
that the
operator
conducting the stimulation has become aware of that does not result in an
environmental, safety, or
well control incident
, but does result in a breach/loss of
containment that is not coupled to a release, e.g., release to a tank. A breach/loss

800-0810-001 / Interim Final October 8, 2016 / Page 28
of containment includes the observation of any flowing fluids in sections of the
well where they were previously not noted, provided these observations are not in
association with the outer annular spaces of surface or coal casing. The reporting
threshold is characterized by a significant increase in the volume of such fluids or
annular pressures respective of baseline conditions, as judged by the
operator
completing
hydraulic fracturing
and/or responsible for the
offset well
.
(2)
Any
communication incident
that results in significant production pressure
deviations at any
active
or
inactive well
that the operator conducting the
stimulation has become aware of. For wells that produce gas inside of surface or
coal casing strings, reportable conditions include any surface-measured
production pressures in excess of 80% but less than 100% of the hydrostatic
pressure at the casing seat depth (assume 0.433 psi/ft gradient). For all wells, any
pressure increases that are within 10% of the containment rating for the lowest
rated barrier element subjected to production pressure must be reported. For
example, if a well head valve is rated for 5,000 psi and production pressures
increase to 4,500 psi as a result of a
communication incident
, this constitutes a
reportable incident.
There is no expectation that adjacent
operators
notify an
operator
conducting
hydraulic
fracturing
when
communication incidents
below the thresholds for completing a 30-day
follow-up incident report described in this policy are noted at an
offset well
that is the
responsibility of the adjacent
operator
. However, in cases when the adjacent
operator
does make the
operator
conducting
hydraulic fracturing
aware of a
communication
incident
below these thresholds, the
operator
conducting
hydraulic fracturing
is not
required to cease
hydraulic fracturing
if: (1) the adjacent
operator
documents in writing
that none of the applicable thresholds for reporting in subsections A and B of this section
have been exceeded, (2) DEP is notified within 24 hours of when the
operator
first
became aware of the incident via the electronic reporting notification service on the DEP
website, and (3) an incident report is filed with DEP within 30 days of when the
operator
first becomes aware of the incident. In this case, the follow-up incident report is the
aforementioned written documentation provided by the adjacent
operator
in (1) above.
Notification and follow-up reporting is required one time only if subsequent
communication incidents
occur at the
offset well
during later
hydraulic fracturing
stages
provided the incidents remain below the thresholds requiring a 30-day follow-up incident
report.
C.
Incident Resolution
For reportable
communication incidents
under subsection A of this section,
hydraulic
fracturing
may only recommence after DEP has provided authorization in accordance
with § 78a.73(c). In instances where a
communication incident
alters a nearby
abandoned
or
orphan well
that is on DEP’s list, or any previously plugged well for which
no further regulatory obligations exist for another
operator/responsible party
,
plugging/re-plugging or well adoption (Permit Application to Adopt an Oil or Gas Well)
is required. Provided the
operator
is able to stabilize conditions at the affected well,
plugging does not necessarily need to be completed prior to recommencement of
hydraulic fracturing
.

800-0810-001 / Interim Final October 8, 2016 / Page 29
The
operator
may choose to file a Good Samaritan Law proposal for plugging the well or
may proceed with the project outside of the liability protection afforded under that law.
All Good Samaritan Law filings will be reviewed and judged on individual merit and the
circumstances which led to the
communication incident
. Because the regulation requires
plugging if the well is not going to be adopted, DEP may decide that the protections
afforded under the Good Samaritan Law are not appropriate. Note that it is not necessary
to first adopt the well in instances where plugging will be implemented.
When plugging is necessary to resolve an issue at a well that is not covered under the
previous paragraph, i.e., a well for which some other
operator/responsible party
exists,
environmental and safety issues must be mitigated as soon as possible, even if under an
Order from DEP. After resolution of these matters, it is up to both
operators/responsible
parties
involved to make the necessary arrangements for plugging of the well in
accordance with all applicable laws and regulations. Some of these matters are discussed
in more detail under Section V of the guidance addressing coordination between adjacent
operators
.
Plugging may not always be necessary to resolve
communication incidents
, and in certain
cases there may be disputes between adjacent
operators
that must be resolved.
Resolution of such matters is beyond the scope of this document or regulatory program.
In all cases, the
operators/responsible parties
must demonstrate that all environmental
and safety matters are mitigated with diligence and that the plan to move forward with
hydraulic fracturing
activities can be implemented in a manner that appropriately
mitigates previously revealed or reasonably anticipated risks.
D.
Other Considerations
?
Prior to commencement of
hydraulic fracturing
activities, have the subsections of
this section detailing incidents requiring suspension of
hydraulic fracturing
activity and 2-hour notification (subsection A above) and 24-hour notification
(subsection B above) been reviewed and are they understood by operations staff?
?
Has the necessary coordination with adjacent
operators
and
landowners
been
implemented to ensure that environmental and safety risks can be addressed
expeditiously in the event of an unanticipated
communication incident
?
?
Are company personnel responsible for interfacing between operations staff and
DEP familiar with the immediate notification and follow-up incident reporting
deadlines and where appropriate forms and instructions for notification and
follow-up incident reporting can be accessed?
?
Have operations staff been in communication with DEP field inspection staff to
discuss the timeline for commencement of the
hydraulic fracturing
activities and
any aspects of the monitoring plan that may require close coordination with the
agency?
?
Has the Good Samaritan Law and project proposal template been reviewed and
evaluated for future consideration?

800-0810-001 / Interim Final October 8, 2016 / Page 30
Figure 6: Standard Follow-up Incident Report
Field Heading
Description of Report Parameter
API No. (US Well No.) of
Hydraulically
Fractured
Well
The US Well No. (API No.) assigned to the well that was undergoing
hydraulic fracturing
at the time of the
communication incident
. Use the following format: CCC-XXXXX. CCC represents the three-digit county code and
XXXXX represents the unique, 5-digit county ID. The sections of the API No. must be separated by a dash (-).
API No. (US Well No.)/ID of Well Where
Communication Incident
Was Observed
If a US Well Number or API number has been assigned to the well where the
communication incident
was observed, enter
it in the space provided using the format described above. If no API number has been assigned to the well, either enter the
ID from the Area of Review Report Summary Table that was previously submitted or, if the well was not identified as part
of the area of review survey and does not have an API number, use the following nomenclature: (C1, C2, C3, etc.).
Adjacent
Operator
ID/
OGO Number
If an adjacent
operator’s
well was involved in the communication incident, this is the OGO No. for that
operator
. Leave
blank if same as the
operator
who was conducting
hydraulic fracturing
activities. Indicate "No RP" if well does not have
an
operator
associated with it.
Start Date
The date that the
communication incident
was first observed in MM/DD/YYYY format.
End Date
The date incident control was established at the well where
communication incident
was observed, i.e., environmental or
safety concerns mitigated. Use MM/DD/YYYY format. Leave blank if incident has not yet been resolved when the report
is submitted.
Environmental/Safety/Well Control
Incident
"Y" if a surface release, water supply impact, other environmental impacts, or a
well control
or other safety incident has
occurred, otherwise indicate "N."
Communication Type
The type of
hydraulic fracturing communication incident
from the list of available options: "Stimulation to Operating
Well", "Stimulation to Well Being Drilled", Stimulation to
Abandoned
/
Orphan Well
", "Stimulation to
Inactive
Well",
"Stimulation to Plugged Well", or "Other."
Adjacent Lateral Effects
"Y" if
communication incident
originated at horizontal well and intervening horizontal wells fall between the source of the
communication and the well where the
communication incident
was observed, otherwise indicate "N."
Latitude of Stage Midpoint for Well
Undergoing
Hydraulic Fracturing
(decimal degrees)
The midpoint latitude and longitude, in decimal degrees, of the stage being
hydraulically fractured
when the
communication incident
occurred. If a vertical well was being
hydraulically fractured
, provide the surface hole location.
This must reference NAD 83 datum and, if a vertical well was being
hydraulically fractured
, the locational information
provided must meet the DEP policy regarding locational accuracy (+/- 10 m).
Longitude of Stage Midpoint for Well
Undergoing
Hydraulic Fracturing
(decimal degrees)
Latitude of Receiving Well (decimal
degrees)
The latitude and longitude, in decimal degrees, representing the surface hole location of the well where the
communication
incident
was observed. This applies for vertical wells or when the vertical section of an intentionally deviated is the point
of entry for pressure/fluids associated with the well undergoing
hydraulic fracturing
. This must reference NAD 83 datum
and meet the DEP policy regarding locational accuracy (+/- 10 m).
Longitude of Receiving Well (decimal
degrees)

800-0810-001 / Interim Final October 8, 2016 / Page 31
Field Heading
Description of Report Parameter
Bottom Hole
/Bit Location Latitude of
Receiving Well (decimal degrees)
The latitude and longitude, in decimal degrees, of the well where the
communication incident
was observed. If being
drilled, indicate the bit location, otherwise indicate the
bottom hole location
. This field applies for intentionally deviated
wells only when the point of entry for pressure/fluids associated with the well undergoing
hydraulic fracturing
occurred
along the deviated portion of the production hole section. This must reference NAD 83 datum. This field should be left
blank if the
communication incident
is associated with a vertical well or the vertical section of an intentionally deviated
well.
Bottom Hole
/Bit Location Longitude of
Receiving Well (decimal degrees)
Landing Point Latitude of Receiving Well
(decimal degrees)
The landing point latitude and longitude, in decimal degrees, of the well where the
communication incident
was observed.
This field applies for intentionally deviated wells only when the point of entry for pressure/fluids associated with the well
undergoing
hydraulic fracturing
occurred along the deviated portion of the production hole section. This must reference
NAD 83 datum. This field should be left blank if the
communication incident
is associated with a vertical well or the
vertical section of an intentionally deviated well.
Landing Point Longitude of Receiving
Well (decimal degrees)
Kick Volume (bbls)
The volume of the kick circulated out, in barrels (bbls), at the well where the
communication incident
was observed. This
field only applies to offset drilling scenarios when a reportable kick was detected in association with the
hydraulic
fracturing communication incident
.
Stage Fluid Volume (bbls)
The volume of the stage, in bbls, that was being
hydraulically fractured
at the time of the
communication incident
.
Maximum Treatment Pressure (psi)
The maximum treatment pressure, in pounds per square inch (psi), of the stage that was being
hydraulically fractured
at
the time of the
communication incident
.
Average Treatment Pressure (psi)
The average treatment pressure, in psi, of the stage that was being
hydraulically fractured
at the time of the
communication
incident
.
Abnormal Treatment Volumes Noted
Indicate "Y" if the treatment volume of the stage being
hydraulically fractured
at the time of the
communication incident
was significantly higher compared to adjacent stages; otherwise indicate "N."
Abnormal Treatment Pressures Noted
Indicate "Y" if the treatment pressure of the stage being
hydraulically fractured
at the time of the
communication incident
was significantly higher compared to adjacent stages; otherwise indicate "N."
Faults Present or Geologic Anomalies
Noted
Indicate "Y" if the presence of faults or other geologic anomalies was noted in the intervening area between the well that
was being hydraulically fractured and the well that was communicated with, otherwise indicate "N."
Orientation of Fault/Geologic Anomaly in
Horizontal Plane
If faults or geologic anomalies were noted, provide the azimuth of the dominant orientation of the fault/geologic anomaly
in horizontal plane (0 to 360 degrees). If no faults or geologic anomalies were noted, this space should be left blank.
Brief Description
Additional details related to incident, as needed. Limit description to 255 characters or less.
Figure 6 is for
unconventional well hydraulic fracturing communication incident
.

800-0810-001 / Interim Final October 8, 2016 / Page 32
APPENDIX A - AOR GEOMETRY
EXAMPLE 1 - UNCONVENTIONAL GAS WELL WITH NO NEARBY PROSPECTIVE SHALE GAS UNITS
Notes: Yellow (identify); Red (identify and visually monitor); and Blue (no requirements); HF (well that is subject of area of review that will be
hydraulically fractured
)

800-0810-001 / Interim Final October 8, 2016 / Page 33
EXAMPLE 2 - UNCONVENTIONAL GAS WELL WITH UNDERLYING PROSPECTIVE SHALE GAS UNIT
Notes: Yellow (identify); Red (identify and visually monitor); and Blue (no requirements); HF (well that is subject of area of review that will be
hydraulically fractured
)

800-0810-001 / Interim Final October 8, 2016 / Page 34
APPENDIX B - MAP INDICES OF GEOGRAPHIC AREAS COVERED BY VARIOUS
STANDARD REFERENCE MATERIALS
Historical Oil and Gas Reports by Series
Coverage for Bureau of Topographic and Geologic Survey Reports
Source: DCNR, accessed December 2015
Notes: Publication M39 (Summarized Records of Deep Wells in Pennsylvania, 1950-1954)
supplements Publication M30 and provides information for wells in Armstrong, Bedford, Bradford,
Cameron, Centre, Clearfield, Clinton, Crawford, Elk, Erie, Fayette, Indiana, Juniata, Luzerne,
Lycoming, McKean, Mercer, Northumberland, Potter, Somerset, Sullivan, Tioga, Union, Warren,
Washington, Westmoreland, and Wyoming counties.

800-0810-001 / Interim Final October 8, 2016 / Page 35
Coverage for Bureau of Topographic and Geologic Survey Progress Reports
Source: DCNR, accessed December 2015

800-0810-001 / Interim Final October 8, 2016 / Page 36
Coverage for Bureau of Topographic and Geologic Survey Special Bulletin Reports
Source: DCNR, accessed December 2015

800-0810-001 / Interim Final October 8, 2016 / Page 37
Coverage for Bureau of Topographic and Geologic Survey Farmline Maps
Source: DCNR, accessed December 2015
Disclaimer: The information presented on this map is provided “as is” without representation or
warranty of any kind – as to suitability, reliability, applicability, merchantability, fitness, non-
infringement, result, outcome, or any other matter. The Department of Conservation and Natural
Resources does not represent or warrant that such information is or will be always up-to-date, complete,
or accurate. Any representation or warranty that might be otherwise implied is expressly disclaimed.

800-0810-001 / Interim Final October 8, 2016 / Page 38
Coverage for United States Geological Survey Folio Reports
Source: DCNR, accessed December 2015

800-0810-001 / Interim Final October 8, 2016 / Page 39
Tabular Summary of United States Geological Survey Folio Reports
Report No.
Quadrangle
82
Masontown-Uniontown
92
Gaines
93
Elkland-Tioga
94
Brownsville-Connellsville
102
Indiana
110
Latrobe
115
Kittanning
121
Waynesburg
123
Elders Ridge
125
Rural Valley
133
Ebensburg
134
Beaver
144
Amity
146
Rogersville
160
Accident-Grantsville
170
Mercersburg-Chambersburg
172
Warren
174
Johnstown
176
Sewickley
177
Burgettstown-Carnegie
178
Foxburg-Clarion
179
Pawpaw-Hancock
180
Claysville
189
Barnsboro-Patton
224
Somerset-Windber
225
Fairfield-Gettysburg
227
Hollidaysburg-Huntingdon

800-0810-001 / Interim Final October 8, 2016 / Page 40
Coverage for United States Geological Survey Bulletins
Source: DCNR, accessed December 2015

800-0810-001 / Interim Final October 8, 2016 / Page 41
Tabular Summary of United States Geological Survey Bulletins
Publication No.
Quadrangle
256
Elders Ridge
279
Kittanning & Rural Valley
286
Beaver
300
Amity
304
Greene County (Rogersville, Waynesburg, Masontown)
318
Steubenville, Burgettstown & Claysville
454
Foxburg
456
Carnegie
829
New Kensington
873
Butler & Zelienople

800-0810-001 / Interim Final October 8, 2016 / Page 42
APPENDIX C - SUPPORTING TECHNICAL INFORMATION
Treatment Pressure and Volume Monitoring
Treatment pressure and volume monitoring are discussed in the AOR regulations of Chapter 78a in
section 78a.73(c). The following discussion considers the role of treatment pressure and/or volume
monitoring as a direct surrogate for
offset well
monitoring in circumstances where either access cannot
be secured or more efficient monitoring strategies may occur at the well that is the subject of the AOR.
Describing, to any reasonable approximation, the theoretical mechanism for
hydraulic fracturing
, is
beyond the scope of the regulation and depends greatly on the local lateral and vertical stress fields,
depths/pressures, and lithologies of the objective reservoir. Many competing models exist to describe
fracture propagation and experts in the field are not aligned on a “standard” model. However, in
general, the following statements can be made with some degree of certainty:
(1)
It is important to distinguish between shallow-reservoir
hydraulic fracturing
models and deep-
reservoir
hydraulic fracturing
models. In shallow reservoirs, horizontal “pancake” fractures
propagate along bedding planes. In deeper reservoirs, tensile vertical fractures are generated
when the overburden stress is no longer the least principal stress, i.e., the weight of overburden
exceeds the “lift” generated by the hydraulic fracture pressure, causing the fracture to propagate
vertically through the rock and laterally away from the well bore, rather than along a bedding
plane. Transition from shallow-reservoir to deep-reservoir propagation types typically occurs at
1,000 to 3,000 feet below surface. Deep-reservoir models are generally assumed to be associated
with the development of
unconventional
reservoirs at depths greater than 2,000 feet below
surface.
(2)
In the simplest deep-reservoir model, two vertical “wing” fractures (180 degrees apart) are
generated from the perforation point that extend away from the well bore. Azimuth orientation
of the vertical fracture depends on the azimuths of the minimum and maximum horizontal
stresses in the rock. However, this assumes a homogeneous reservoir (uniform stresses and rock
properties through the volume of rock being stimulated by the hydraulic fracture). Any deviation
from this, e.g., natural fractures, layering of rock with very different geomechanical
characteristics, etc., would lead to a much more complex three-dimensional set of fractures.
(3)
In the deep-reservoir case, hydraulic fractures may extend out hundreds of feet beyond the well
bore in height and lateral extent, but probably not much more than a thousand feet beyond in
most circumstances. The only exception may be scenarios where a pre-existing zone of
weakness occurs, such as a fault. This is supported by microseismic data, which is the industry’s
standard tool for monitoring the extent of fracture propagation in the subsurface.
(4)
Modern
hydraulic fracturing
is most often used in reservoirs with low porosity and permeability,
e.g., porosity <10%, permeability < 1000 nD, referred to as a “tight” or
unconventional
reservoirs that cannot be otherwise developed with standard stimulation techniques. Typical
examples include gas-bearing shales and siltstones.
During a
hydraulic fracturing
operation, variations in pressure and volume are common. A measurable
treatment pressure or volume change that indicates a communication event with another well bore would
be so small, relatively speaking, that it would not be possible to distinguish it from the normal variability
in any event for high-volume,
hydraulic fracturing
treatments. Therefore, it is not appropriate to
recommend a specific requirement for pressure or volume monitoring during an
unconventional
completion job.

800-0810-001 / Interim Final October 8, 2016 / Page 43
Pressure and fluid communication with an adjacent producing well bore is relatively common, and
indeed is often by design in the industry. The communication effects are usually detected in the adjacent
well bore; however, not in pressure or volume changes in the well being completed. Communication
effects can include pressure “spikes” and subsequent drops, changes in production rate, and the detection
of chemical tracers, when used. The industry deliberately designs tests, e.g., downspacing trials, to see
when inter-well communication starts to occur to optimally develop the hydrocarbon resource in an area.
In such trials, adjacent producing wells are designed to handle moderate fluctuations in pressure and
volume. These industry-standard trials and variations are not the target of the AOR regulation and are
not considered reportable incidents.
Any reporting of downhole pressure or volume changes during an
unconventional
completion job either
in the well being completed or in adjacent, producing wells should be done only when a specific event
occurs that could indicate a loss of mechanical integrity, i.e., containment, and that could pose a specific
risk to the environment (surface or subsurface fluid release) or safety (
loss of well control
). This would
amount to a sudden loss of pressure or a volume change that is clearly, statistically beyond the normal
variability that a job has. However, these particular guidelines (“normal variability”) cannot be
quantified as a standard rule, as each completion job is unique. Therefore, action in these cases is left to
the discretion and experience of the
operator
.

800-0810-001 / Interim Final October 8, 2016 / Page 44
APPENDIX D - DEP EMERGENCY RESPONSE CONTACT INFORMATION

800-0810-001 / Interim Final October 8, 2016 / Page 45
APPENDIX E - AOR PROCESS FLOW DIAGRAM

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