DEP Regulatory Requirements
Chapter 78 Subchapter D
Dave English
Division of Compliance and Data Management
Bureau of Oil and Gas Management
Focus
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Significant changes to
Subchapter D.
Relevant revisions to
Subchapters A, C, and E
Oil and Gas Wells and the Middle Devonian Marcellus Formation
Chapter 78 Subchapter D addresses:
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New well drilling,
casing, cementing,
completion and
operational practices
Chapter 78 Subchapter D addresses:
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Currently
operating oil and
gas wells
Chapter 78 Subchapter D addresses:
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Plugging
abandoned wells
Rationale for Proposed Rulemaking:
Needs Assessment
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New drilling and completion practices used to
develop Marcellus and other “unconventional”
formations
Stray gas migration incidents (Marcellus and
shallow oil and gas wells)
Well control incidents (e.g. EOG incident June 3,
2010 in Clearfield County)
Hydraulic fracturing additive disclosure
Mandatory production reporting – Act 15
Final Rulemaking 25 Pa. Code Chapter 78
Background
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Initial draft presented to TAB September 17, 2009
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DEP met with TAB and subcommittee four additional times
(10/28/09, 1/14/10, 1/21/10, 3/25/10)
Advanced Notice of Proposed Rulemaking: Public
comment period January 30, 2010 – March 2, 2010
Notice of Final Rulemaking: Public comment period
July 10, 2010 – August 9, 2010
Approval by EQB, IRRC, Attorney General’s Office.
Final Regulations approved on publication in the
Pennsylvania Bulletin February 5, 2011
Final Rulemaking 25 Pa. Code Chapter 78:
Significant Revisions
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Well Control
Well Construction (casing and cementing operations)
Mechanical Integrity of Existing Wells
Gas Migration Response
Well Reporting
Future Rulemaking: Next Regulatory
Package
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Revisions to Plugging regulations: 78.91-78.98
Revisions to Subchapter C: Environmental Protection
Performance Standards
Other revisions and modifications, i.e., “tweaks” to
Subchapter D
Chapter 78. Oil and Gas Wells
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Subchapter A: General Provisions
Chapter 78. Oil and Gas Wells
Subchapter A: General Provisions – new definitions added
 Conductor pipe
 Intermediate casing
 L.E.L. (lower explosive limit)
 Unconventional formations
Chapter 78. Oil and Gas Wells
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Subchapter C: Environmental Protection
Performance Standards
78.55. Control and Disposal Plan
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Plan must include operator’s
pressure barrier policy that
identifies barriers to be used
during specific operations
Plan must be available at the well
site for review during drilling and
completion activities
List of emergency contact phone
numbers for the area in which
the site is located must be
prominently displayed at the well
site during drilling, completion,
and workover activities
Chapter 78. Oil and Gas Wells
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Subchapter D: Well
Drilling, Operation
and Plugging
78.72 Use of Safety Devices – BOP Equipment
(New language in italics)
BOP equipment to be used:
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When drilling well intended to
produce natural gas from an
unconventional formation
When drilling out frac plugs
Where pressures are anticipated
at the well site that may result in
a loss of well control
Where operator is drilling in an
area where there is no prior
knowledge of pressure or natural
open flow
When drilling conservation wells
When drilling within 200 feet of a
building
78.72 Use of Safety Devices – BOP Equipment
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Controls for the blow-out
preventer must be accessible to
allow actuation of the
equipment
Additional controls for the BOP
with a pressure rating of 3000
psi, not associated with the rig
hydraulic system, must be
located at least 50 ft. away
from the drilling rig such that
the BOP can be activated if
control of the well is lost
78.72 Use of Safety Devices – BOP Equipment
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Remote Accumulator for BOP Actuation
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Close-up of BOP Controls
78.72 (d) BOP Equipment Testing
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Annular-type: must test
according to the
manufacturer’s
instructions, or by a
professional engineer,
before placing in service
Equipment failing test
must not be used until it
is repaired/replaced and
passes the test
78.72(d) BOP Equipment Testing
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Ram-type: must test for
both pressure and ram
operation before placing
in service on the well
Testing in accordance
with API RP53
If not in good working
order, drilling must cease
until BOP equipment is
repaired/replaced and retested
78.72 BOP: Additional requirements
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All lines, valves and fittings between the closing unit and the BOP
stack must be flame resistant and have a rated working pressure
that meets or exceeds the requirements of the BOP system
When BOP is installed or required, an individual must be present at
the well site with a current certification from a well control course
accredited by the International Association of Drilling Contractors or
other organization approved by DEP
Pressure barriers identified in drilling and completions operations
requiring two mechanical barriers must be capable of being tested.
This does not mean that all operations utilizing BOP equipment must
employ two mechanical barriers
A stripper barrier or stripper heads are not considered adequate
barriers
A coiled tubing rig or hydraulic workover unit with appropriate BOP
equipment must be utilized during post-completion cleanout
operations in unconventional formations penetrated by a horizontal
wellbore
DEP will be developing pressure barrier policy
Chapter 78 Major Changes to Well Construction and
Cementing and Other Changes to Subchapter D
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Revised casing standards
New requirement for
casing and cementing plan
New Section on lost
circulation
Revised cement standards
New Section on
mechanical integrity of
existing wells
78.73 General Provisions: Revised language
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Operator must construct well in accordance with this Chapter and
ensure that the integrity of the well is maintained and health,
safety, environment and property are protected
Operator must prevent gas, oil, brine, completion and servicing
fluids, and any other fluids or materials from below the casing seat
from entering fresh groundwater, and shall otherwise prevent
pollution or diminution of fresh groundwater
Reduced pressure at surface or coal protective casing seat may not
exceed 80% of the hydrostatic pressure of the surrounding fresh
groundwater (0.8 X 0.433) X casing length (ft)
78.73 General Provisions: New Language
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Excess gas encountered
during drilling, completion
or stimulation must be
flared, captured or
diverted from the drilling
rig in a manner that does
not create a hazard to
public health or safety
Wells must be equipped
with a check valve to
prevent backflow from
pipelines into well (except
gas storage wells)
78.75a. New Section: Area of Alternative Methods
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DEP may designate an area of alternative methods if it
determines that well drilling and operating requirements
beyond those provided in this Chapter are necessary
Notice of proposed area of alternative methods will be
published in PA Bulletin
Wells drilled within this area must meet the
requirements specified by the Department unless the
operator obtains DEP approval to drill, operate or plug
the well in a different manner that is at least as safe and
protective of the environment as the requirements in the
area of alternative methods
78.76. Drilling within a Gas Storage
Reservoir
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An operator proposing to drill in
a gas storage area (or the
surrounding reservoir protective
area….normally 2000 ft) must
send a copy of the location plat,
the drilling/casing/cementing
plan, and the anticipated date
drilling will commence to the gas
storage reservoir operator
New language requires that
information above also be sent
to the Department along with
proof of notification to the gas
storage reservoir operator; DEP
must approve the proposal prior
to drilling
78.81-78.87. Casing and Cementing
78.81 General Provisions
Casing and cementing must:
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Allow effective control of the well at all times
Prevent the migration of gas and other fluids into
fresh groundwater
Prevent the pollution or diminution of fresh
groundwater
Prevent the migration of gas or other fluids into
coal seams
78.82. Use of Conductor Pipe
New rulemaking additions:
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Conductor pipe shall be installed in a manner that
prevents the subsurface infiltration of surface water
or fluids
Conductor pipe shall be made of steel
78.83. Surface and Coal Protective Casing and
Cementing Procedures: New Language
Wells drilled, altered, reconditioned or recompleted after final
regulations may not utilize surface casing, or any casing
functioning as water protection casing, unless:
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The well is an oil well where the operator does not produce any gas
generated by the well and the annulus between the surface casing
and the production pipe is left open
The operator demonstrates that the pressure in the wellbore at the
casing seat is no greater than the pressure allowed by (new)
78.73(c): (0.8 X 0.433 psi/ft X casing length (ft). Operator must
install a working pressure gauge that can be inspected by the
Department
Determination may be with a pressure test to 80% of the calculated
hydrostatic pressure at the surface casing seat
78.83. Surface and Coal Protective Casing and
Cementing Procedures: New Language
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Surface casing may not be set more than 200 feet below the
deepest fresh groundwater except as necessary to set the casing
in consolidated rock
Surface casing hole must be drilled using air, freshwater, or
freshwater-based drilling fluid
Wellbore must be conditioned to ensure an adequate cement
bond between the casing and formation prior to cementing
Centralizers: at least one within 50 ft. of the surface casing seat,
then in intervals no greater than every 150 ft. above the first
centralizer
78.83. Surface and Coal Protective Casing and
Cementing Procedures: New Language
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Operator must document the depth of the fresh groundwater zone
in the well and record if additional fresh groundwater is encountered
below the surface casing
Coal protective string must have at least two centralizers, one within
50 ft. of the casing seat and the second within 100 ft. of the surface
When cementing in lost circulation zones, using a pour string/tremie
pipe to cement above the cement basket does not constitute
“permanently cementing” the surface or coal protective casing
pursuant to new Section 78.78b (relating to Casing and Cementing
– Lost Circulation)
78.83a. Casing and Cementing Plan: New Section
Operator must prepare a casing and cementing plan showing how the
well will be drilled and completed
Plan must include:
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Anticipated depth and thickness of any producing formation, expected
pressures and anticipated fresh groundwater zones, and the method or
information by which the depth of the deepest fresh groundwater was
determined (discussed later)
Diameter of the borehole
Casing type, depth, diameter, wall thickness, and burst pressure rating
Cement type, additives, and estimated amount
Estimated location of centralizers
Proposed borehole conditioning procedures
Alternative methods or materials as required by DEP as a condition of the well
permit
Plan must be available at the well site for review, may be required by the
Department for review and approval (for permit issuance), and any
revisions to the plan made as a result of on-site modifications must be
documented by the operator, initialed and dated, and available for DEP
review
Section 78.83a.(a)(1): Methodology for
Determining Deepest Fresh Groundwater
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Regulatory definition of “deepest fresh
groundwater”
“The deepest fresh groundwater bearing formation penetrated by the wellbore as
determined from drillers logs from the well or from other wells in the area
surrounding the well or from historical records of the normal surface casing seat
depths in the area surrounding the well, whichever is deeper. “
Buckwalter & Moore (2006)
Section 78.83a.(a)(1): Methodology for
Determining Deepest Fresh Groundwater
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Standard groundwater quality classification
schemes
Fetter (1994)
Fresh
Brackish
Saline
Brine
0 to 1,000 mg/l TDS
1,000 to 10,000 mg/l TDS
10,000 to 100,000 mg/l TDS
>100,000 mg/l TDS
Quiñones-Aponte & Wexler (1995)
Fresh
Slightly Saline (brackish)
Moderately Saline (brackish)
Very Saline (saltwater)
Brine
<1,000 mg/l TDS
1,000 to 3,000 mg/l TDS
3,000 to 10,000 mg/l TDS
10,000 to 35,000 mg/l TDS
>35,000 mg/l TDS
Olsthoorn (2008)
Section 78.83a.(a)(1): Methodology for
Determining Deepest Fresh Groundwater
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Some numerical considerations in Pennsylvania
Delaware River Basin Commission (DRBC)
Freshwater is “water containing less than 1,000 mg/l of dissolved solids, most often salt.”
40 CFR 144.3 – United States EPA
“Underground source of drinking water (USDW) means an aquifer or its portion: (a)(1)
Which supplies any public water system; or (2) Which contains a sufficient quantity of
ground water to supply a public water system; and (i) Currently supplies drinking water for
human consumption; or (ii) Contains fewer than 10,000 mg/l total dissolved solids; and (b)
Which is not an exempted aquifer.”
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“10,000 mg/l is FAR TOO SALINE for drinking
water supplies in this Commonwealth”
Section 78.83a.(a)(1): Methodology for
Determining Deepest Fresh Groundwater
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Numerical considerations elsewhere
Texas: 3000 mg/l TDS
Oklahoma: 10,000 mg/l TDS
Illinois: 10,000 mg/l TDS
New York: 1,000 mg/l TDS
Alberta: 4,000 mg/l TDS to a depth not to exceed 600 meters
Section 78.83a.(a)(1): Methodology for
Determining Deepest Fresh Groundwater
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Numerical considerations
(31 states surveyed)
GWPC (2009)
Section 78.83a.(a)(1): Methodology for
Determining Deepest Fresh Groundwater
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Numerical considerations
(15 states with quantitative definition)
GWPC (2009)
Section 78.83a.(a)(1): Methodology for
Determining Deepest Fresh Groundwater
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Techniques for defining base of deepest
fresh groundwater aquifer
Estimating fracture zone yield and measuring specific
conductance using a calibrated meter during drilling
Standard water well geophysical logging of tophole –
specific conductance critical, but other logs may help
corroborate water-bearing zones
More sophisticated geophysical logging of tophole per
EPA UIC recommendations (SP log or resistivity/porosity
log)
Installation of monitoring wells at well pad and
groundwater testing
Information from offset wells including water well
testing, geophysical log data, and surface casing set
depths; considering water well offsets alone
will typically not be enough
Williams (2010)
78.83b. Casing and Cementing – Lost Circulation:
New Section
If cement used to permanently cement the surface or coal
protective casing cannot be circulated to the surface due to lost
circulation, the operator shall determine the top of cement, notify
the Department and meet one of the following:
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Run additional string 50 deeper than where circulation was lost,
cement back to lost circulation string casing seat, vent the annulus,
meet pressure requirements of 78.73(c)
Run production casing and set on packer, vent the annulus
Run production casing to formation being produced, cement to
surface
Run intermediate and production casing and cement both strings to
surface
May also emplace supplemental cement in addition to the above
78.83b. Casing and Cementing – Lost Circulation:
New Section- continued
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Policy: cement returns to surface followed by cement drop may
be considered to be permanently cemented if the DEP inspector
determines an adequate amount of surface casing cement was
placed above the seat.
Top of cement determination must be made and notification given
to the DEP inspector for evaluation of casing cement adequacy
and subsequent approval for remedial casing options. Must be
done prior to continuation of drilling (e.g. no TOC determination
after well drilled/completed to TD).
In addition to remedial casing options, the minimum amount of
surface casing cement above seat and corresponding maximum
amount of uncemented surface casing will be made on a case-bycase basis by DEP. In certain cases, the well may need to be
plugged and abandoned if only a minimal amount of cement
exists above the surface casing seat (a “catastrophic” loss of
cement).
DEP may require remedial cementing from surface and/or
pressure-testing of the casing string to determine integrity of the
well and ensure protection of the surface casing seat.
78.83c. Intermediate and Production Casing: New
Section
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Prior to cementing intermediate and production casing, the
borehole, mud, and cement must be conditioned to ensure an
adequate cement bond between the casing and the formation
If a well is to be equipped with intermediate casing, centralizers
must be used and the casing must be cemented to the surface by
the displacement method; gas may be produced off the
intermediate casing if a shoe test demonstrates that all gas will be
contained within the well and a relief valve is installed at the surface
that is set at less than the shoe test pressure (this pressure must be
recorded in the completion report)
Except as provided by 78.83, each well must be equipped with
production casing; centralizers must be used; the production string
may be set on a packer or cemented in place; annular space must
be cemented to a point at least 500 ft. above the TVD or at least
200 ft. above the uppermost perforations, whichever is greater.
78.84. Casing Standards: Original Language
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Casing must withstand the effects of tension, and
prevent burst and collapse during its installation,
cementing, and subsequent drilling and producing
operations
Casing must be equipped with appropriate equipment to
center the casing through the hole in fresh groundwater
zones
Coal protective casing must have a minimum wall
thickness of 0.23 inches
78.84. Casing Standards: New Language
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All casing must be a string of new pipe with a pressure rating at least 20%
greater than the anticipated maximum pressure
Used casing may be approved but must be pressure tested after cementing
and before continuation of drilling; a passing pressure test is holding the
maximum anticipated pressure for 30 minutes with no more than a 10%
change in pressure. Pressure testing should be done before significant gel
strength has developed in the cement. API RP65 Part 2
New or used plain end casing that is welded must be pressure tested and hold
the maximum anticipated pressure for 30 minutes with no more than a 10%
change in pressure
Welded casing must be welded using at least
three passes with the joint cleaned between
each pass
Welder must be trained and certified in the
applicable API, ASME, AWS or equivalent
standard for welding casing and pipe or an
equivalent training and certification program; a
person with 10 or more years of experience
welding casing does not need to be certified
Note that the certification requirements do not
kick in until August 5, 2011
78.85. Cement Standards: Original Requirements
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Cement must resist degradation
by chemical and physical
conditions in the well
Minimum compressive strength
of 350 psi in accordance with
API spec 10; cement must set
for a minimum period of eight
(8) hours prior to the
resumption of actual drilling
Operator may request approval
from DEP to reduce the cement
setting time when special
cement or additives are used
Chapter 78.85: New Cement Standards
Revised cement standards:
 Cement must protect casing from corrosion and geochemical,
lithologic and physical conditions of the surrounding wellbore
 Gas-block additives and low fluid-loss slurries in areas of known
shallow gas-producing zones are required
 Zone of critical cement around surface casing seat
 True eight-hour WOC (wait on cement) before casing may be
disturbed
 One-day notification to DEP prior to cementing of surface
casing
 Cement job log must be prepared and available at the well site
during drilling operations and maintained for at least five years
Chapter 78.85: New Cement Standards
Zone of Critical Cement:
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Applies to bottom 300 ft. of surface casing cement,
or entire cemented string if the surface casing string
is less than 300 ft
Cement must achieve a 72-hour compressive
strength of 1200 psi
Cement must achieve a free-water separation of no
more than 6 milliliters of water per 250 milliliters of
cement
Chapter 78.85: New Cement Standards
Eight-hour WOC (wait on cement) – casing may be not
be disturbed by:
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Releasing pressure on the cement head; if check
valves on float shoe are secure, the pressure may be
released at a continuous, gradual rate after four
hours
Nippling up on or in conjunction to the casing
Slacking off by the rig supporting the casing in the
cement sheath
Running drill pipe or other mechanical devices into
or out of the wellbore with the exception of a
wireline used to determine the top of cement
Chapter 78.85: New Cement Standards
Cement job log – required components:
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Mix water temperature and pH
Type of cement with listing and quantity of additives
Volume, yield, and density in ppg of the cement
Amount of cement returned to the surface
Cementing procedural information including a description of the
pumping rates in bbl/min, pressure in psi, time in min, and the
sequence of events during the cementing operations
Logs must be available for all cement jobs done after 2/5/2011.
Section 78.88: Mechanical Integrity of
Operating Wells
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Quarterly monitoring program will begin first quarter after the
Department develops a standard form for collecting mechanical
integrity data
Key monitoring/testing provisions
Pressure monitoring associated with production casing
Pressure monitoring in annular space associated with production casing
Pressure monitoring at relevant casing seat
Checking well fluid level in production casing
Corrosion and equipment deterioration survey
Monitoring for leaking gas
Clear methodology for addressing over-pressured wells
Flexibility for Department to require additional testing
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Report detailing results of quarterly inspections must be submitted to
Department annually by January 31 of year following inspections
Operating Wells 78.88 Mechanical Integrity
of Operating Wells
For wells not in compliance, the operator must immediately notify
DEP and take corrective action to mitigate the excess pressure on
the surface casing seat, coal protective casing seat, or
intermediate casing seat when the intermediate casing seat is
used in conjunction with the surface casing seat to isolate fresh
groundwater
Corrective action occurs in the following hierarchy:
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Operator must reduce the shut-in or producing back pressure to
achieve compliance with 78.73(c)
Operator must retrofit the well by installing production casing to
reduce pressure on the casing seat to achieve compliance with
78.73(c); the annular space surrounding the production casing must
be open to the atmosphere; production casing must either be
cemented in place or installed on a permanent packer
Operator must notify DEP 7 days prior to initiating corrective action
Section 78.88: Mechanical Integrity of
Operating Wells
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Potential well problems
Section 78.88: Mechanical Integrity of
Operating Wells
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Potential well problems: overpressuring
Harrison (1985)
Section 78.88: Mechanical Integrity of
Operating Wells
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Potential well problems: overpressuring (continued)
Harrison (1985)
Section 78.88: Mechanical Integrity of
Operating Wells
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Potential well problems: overpressuring (continued)
Harrison (1985)
Section 78.88: Mechanical Integrity of
Operating Wells
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Potential well problems: cement failures and inadequate casing/tubing
Section 78.88: Mechanical Integrity of
Operating Wells
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Some notable items
Operators will not be required to
retrofit older wells for pressure
monitoring
Overpressured conditions or problems
noted during well corrosion/equipment
deterioration survey must be reported
immediately
7-day notification for wells that will
be retrofitted with production casing
Section 78.88: Mechanical Integrity of
Operating Wells
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Some notable items (continued)
Water protection depth will apply in
older wells where fluid levels can be
determined
Pressure monitoring locations will vary
as a function of well construction
Section 78.88: Mechanical Integrity of
Operating Wells
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Department projects underway or being
considered to assist the industry
Development of comprehensive technical
guidance/instructions to accompany form to
ensure consistency and ease of
implementation
Development of tracking system for problems
noted to help identify what well maintenance
procedures are critical during various points
throughout operational history
M.I.C.S.(2011)
78.89. Stray Gas Mitigation Response
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Establishes protocol for operator, DEP, and local emergency response
agencies to determine the nature of a gas migration incident, assess the
potential for hazards to public health and safety, and mitigate any hazard
posed by the release of natural gas
Operator, in conjunction with the Department and local emergency
response agencies, must take measures necessary to ensure public health
and safety
Section 78.89: Gas Migration Response
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Stray gas migration incidents continue to represent one of the most
significant problems associated with oil and gas development in the
Commonwealth
Previous discussion on well integrity highlighted some problems that
result in stray gas migration incidents
Other contributing factor in Pennsylvania is the number of
legacy/abandoned wells that were never properly plugged and whose
locations remain unknown
Stray gas migration associated with Marcellus Shale development has
been geographically isolated
Section 78.89: Gas Migration Response
Physical properties of methane
The simplest of all paraffin
hydrocarbon gas
Flammable, colorless, and odorless
Specific gravity: 0.555
Explosive range: 5-15%
Maximum solubility in water: 26-32
mg/l at standard temperature and
pressure, but higher at depth due to
pressure regime
Baldassare (2009)
Section 78.89: Gas Migration Response
Factors influencing stray gas migration
Changes in barometric pressure
Soil and bedrock
porosity/permeability
Pore water
Temperature contrasts
Other meteorological conditions
including precipitation (rain vs.
snow) and ground cover (layer of
snow or frozen ground)
Figure courtesy of John Harper, PA
Topographic and Geologic Survey
Section 78.89: Gas Migration Response
Types of gas and isotopic signatures
(Baldassare, 2009)
Subsurface microbial gas (deepsea sediments and drift gas)
Near-surface microbial gas (marsh
gas and landfill gas)
Thermogenic gas (natural gas and
coalbed gas)
Baldassare (2009)
Section 78.89: Gas Migration Response
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Locations: total number of stray gas cases since 1987 compared to all
permitted drilling activity
Section 78.89: Gas Migration Response
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Location: of Marcellus Shale stray gas cases since 2008 compared to
Marcellus Shale drilling activity between 2008 and 2010
Section 78.89: Gas Migration Response

Recent trends in stray gas incidents: Marcellus Shale versus nonMarcellus Shale wells
Section 78.89: Gas Migration Response
Key components of stray gas regulations
Operators notified about a potential stray gas migration incident must
immediately conduct an investigation to determine nature of incident,
assess potential hazards, and mitigate hazards as needed
Response actions are tiered based on the severity of the incident
Investigation closure dependent upon Department approval
Section 78.89: Gas Migration Response
 A three-tiered approach
Category 1 (Immediate Threat): detectable concentrations equal to or
greater than 10% of the lower explosive limit (LEL) or combustible gas
in a building or structure(s), or otherwise deemed Category 1 by the
Department.
Category 2 (Potential Threat): detectable concentrations less than
10% of the LEL of combustible gas in a building or structure(s), and/or
combustible gas greater than 50% of the LEL in the headspace of a
water well, and/or visual or audible evidence of stray gas bubbling
through a water well column or surface body, and/or detectable
concentrations of stray gas in the soils, and/or concentrations of
dissolved methane in water at or above 25% of the lower solubility limit
for methane (7 mg/l).
Category 3 (No Apparent Threat): none of the above conditions were
met. If conditions indicate methane in groundwater at concentrations
above 0.5 mg/l, but below 7 mg/l, continued monitoring is necessary to
ensure that concentrations do not trend to a Category 2 potential
threat.
Section 78.89: Gas Migration Response

Department projects underway or being considered to assist the
industry
Development of stray gas migration technical guidance document to
compliment new regulations
NCRO Stray Gas Prevention Program
Series of joint technical guidance and public outreach documents
with Emergency Response staff
Plugging: 78.91 – 78.98
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Second attempt to remove production casing after
cutting, ripping, shooting or other method approved by
the Department.
Cement plug now to be placed across oil or gas-bearing
strata (rather than gel).
Next regulatory package will significantly revise plugging
regulations.
Chapter 78. Oil and Gas Wells

Subchapter E: Well Reporting
Chapter 78. Oil and Gas Wells
Subchapter E: Well Reporting – Revisions
 78.121. Production reporting: Incorporates the requirements of Act
15 of 2010 which mandates semi-annual reporting of production of
Marcellus Shale wells (8/15 & 2/15); Non-Marcellus wells report
annually (2/15); Information is posted on DEP’s website
 78.122. Well record and completion report: Completion report to
include: descriptive list of chemical additives used in the stimulation
fluid; the percent by volume of those additives; a list of hazardous
chemicals used in the stimulation fluid (MSDS/CAS #); the percent
by volume of those hazardous chemicals; the total volume of water
used; a list of water sources used pursuant to an approved water
management plan; the total volume of recycled water used; and the
pump rate and pressure used in completing the well
 Operator must designate separate sheet as confidential or a trade
secret; DEP will prevent disclosure of confidential information to the
extent provided by the Right-To-Know Law
 Well record adds certification by operator that well has been
constructed in accordance with this Subchapter and any permit
conditions imposed by DEP
Thank you
daenglish@state.pa.us
(717) 772-2199