Pipeline Safety: Class Location Change Requirements, 36861-36871 [2018-16376]
Download as PDF
<![CDATA[
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
Subpart C—Technical Standards
Brief Description: Part 101 prescribes
the manner in which portions of the
radio spectrum may be made available
for private operational, common carrier,
24 GHz Service, Local Multipoint
Distribution Service, and fixed,
microwave operations that require
transmitting facilities on land or in
specified offshore coastal areas within
the continental shelf. Subpart C sets
forth technical standards for
applications and licenses in the Fixed
Microwave Services.
Need: The revised rules provide the
interference protection criteria for fixed
stations subject to part 101 and requires
that transmitters used in the private
operational fixed and common carrier
fixed point-to-point microwave and
point-to-multipoint services under this
part must be a type that has been
verified for compliance. The need for
these rules is ongoing.
Legal Basis: 47 U.S.C. 154, and 303.
Section Number and Titles:
101.105(a)(5) and (6) Interference
protection criteria.
101.139(h) and (i) Authorization of
transmitters.
[FR Doc. 2018–16282 Filed 7–30–18; 8:45 am]
BILLING CODE 6712–01–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
49 CFR Part 192
[Docket ID: PHMSA–2017–0151]
RIN 2137–AF29
Pipeline Safety: Class Location
Change Requirements
Pipeline and Hazardous
Materials Safety Administration
(PHMSA), DOT.
ACTION: Advance notice of proposed
rulemaking (ANPRM).
AGENCY:
PHMSA is seeking public
comment on its existing class location
requirements for natural gas
transmission pipelines as they pertain to
actions operators are required to take
following class location changes due to
population growth near the pipeline.
Operators have suggested that
performing integrity management
measures on pipelines where class
locations have changed due to
population increases would be an
equally safe but less costly alternative to
the current requirements of either
reducing pressure, pressure testing, or
daltland on DSKBBV9HB2PROD with PROPOSALS
SUMMARY:
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
replacing pipe. This request for public
comment continues a line of discussion
from a Notice of Inquiry published in
2013 and a report to Congress in 2016
regarding whether expanding integrity
management requirements would
mitigate the need for class location
requirements.
DATES: Persons interested in submitting
written comments on this ANPRM must
do so by October 1, 2018.
ADDRESSES: You may submit comments
identified by the Docket: PHMSA–2017–
0151 by any of the following methods:
E-Gov website: https://
www.regulations.gov. This site allows
the public to enter comments on any
Federal Register notice issued by any
agency. Follow the online instructions
for submitting comments.
Fax: 1–202–493–2251.
Mail: Hand Delivery: U.S. DOT Docket
Management System, West Building
Ground Floor, Room W12–140, 1200
New Jersey Avenue SE, Washington, DC
20590–0001 between 9:00 a.m. and 5:00
p.m., Monday through Friday, except
Federal holidays.
Instructions: Identify the Docket ID at
the beginning of your comments. If you
submit your comments by mail, submit
two copies. If you wish to receive
confirmation that PHMSA has received
your comments, include a selfaddressed stamped postcard. Internet
users may submit comments at https://
www.regulations.gov/.
Note: Comments are posted without
changes or edits to https://
www.regulations.gov, including any
personal information provided. There is
a privacy statement published on
https://www.regulations.gov.
FOR FURTHER INFORMATION CONTACT:
Technical questions: Steve Nanney,
Project Manager, by telephone at 713–
272–2855 or by email at steve.nanney@
dot.gov.
General information: Robert Jagger,
Technical Writer, by telephone at 202–
366–4361 or by email at robert.jagger@
dot.gov.
SUPPLEMENTARY INFORMATION:
Outline of This Document
I. Class Location History and Purpose
A. Class Location Determinations
B. Class Location—‘‘Cluster Rule’’
Adjustments
II. Changes in Class Location Due to
Population Growth
III. Class Location Change Special Permits
A. Special Permit Conditions
IV. Pipeline Safety, Regulatory Certainty, and
Job Creation Act of 2011—Section 5
A. 2013 Notice of Inquiry: Class Location
Requirements
B. 2014 Pipeline Advisory Committee
Meeting, Class Location Workshop, and
Subsequent Comments
PO 00000
Frm 00070
Fmt 4702
Sfmt 4702
36861
C. 2016 Class Location Report
V. INGAA Submission on Regulatory
Reform—Proposal To Perform IM
Measures In-Lieu of Pipe Replacement
When Class Locations Change
VI. Questions for Consideration
VII. Regulatory Notices
Background
I. Class Location History and Purpose
The class location concept pre-dates
Federal regulation of gas transmission
pipelines 1 and was an early method of
differentiating areas and risks along
natural gas pipelines based on the
potential consequences of a
hypothetical pipeline failure. Class
location designations were previously
included in the American Standards
Association B31.8–1968 version of the
‘‘Gas Transmission and Distribution
Pipeline Systems’’ standard, which
eventually became the American
Society of Mechanical Engineers
(ASME) International Standard, ASME
B31.8 ‘‘Gas Transmission and
Distribution Pipeline Systems.’’ The
class location definitions incorporated
into title 49, Code of Federal
Regulations (CFR) § 192.5 were initially
derived from the designations in this
standard and were first codified on
April 19, 1970.2 These definitions were
like the original ASME B31.8 definitions
for Class 1 through 3 locations but
added an additional Class 4 definition
and, with some modifications, still
apply today.
Gas transmission pipelines are
divided into classes from 1 (rural areas)
to 4 (densely populated, high-rise areas)
that are based on the number of
buildings or dwellings for human
occupancy in the area. This concept is
to provide safety to people from the
effects of a high-pressure natural gas
pipeline leak or rupture that could
explode or catch on fire. PHMSA uses
class locations in 49 CFR part 192 to
implement a graded approach in many
areas that provides more conservative
safety margins and more stringent safety
standards commensurate with the
potential consequences based on
population density near the pipeline.
When crafting the natural gas
1 The Department of Transportation first proposed
class location regulations on March 24, 1970 (35 FR
5012). The proposal was part of a series of NPRMs
published in response to the Natural Gas Pipeline
Safety Act of 1968 (Pub. L. 90–481). The NPRMs
were directed at developing a comprehensive
system of Federal safety standards for gas pipeline
facilities and for the transportation of gas through
such pipelines. The class location rulemaking was
finalized on August 19, 1970, as part of a
consolidated rulemaking establishing the first
minimum Federal safety standards for the
transportation of natural gas by pipelines (35 FR
13248).
2 35 FR 13248.
E:\FR\FM\31JYP1.SGM
31JYP1
36862
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
daltland on DSKBBV9HB2PROD with PROPOSALS
regulations, DOT’s Office of Pipeline
Safety (OPS) determined that these more
stringent standards were necessary
because a greater number of people in
proximity to the pipeline substantially
increases the probabilities of personal
injury and property damage in the event
of an accident. At the same time, the
external stresses, the potential for
damage from third-parties, and other
factors that contribute to accidents
increase along with the population;
consequently, additional protective
measures are often needed in areas with
greater concentrations of population.
The most basic and earliest use of the
class location concept focused on the
design (safety) margin for the pipeline.
As pipelines are designed based, in part,
on the population along their pipeline
route and therefore the class location of
the area, it is important to decrease pipe
stresses in areas where there is the
potential for higher consequences or
where higher pipe stresses could affect
the safe operation of a pipeline in largerpopulated areas. Pipeline design factors
are derating factors that ensure
pipelines are operated below 100
percent of the maximum pipe yield
strength. From an engineering
standpoint, they were developed based
on risk to the public 3 and for piping
that may face additional operational
stresses.4 Pipeline design factors vary,
ranging from 0.72 in a Class 1 location
to 0.40 in a Class 4 location. They are
used in the pipeline design formula
(§ 192.105) to determine the design
pressure for steel pipe, and are generally
reflected in the maximum allowable
operating pressure (MAOP) based upon
a percentage of the specified minimum
yield strength (SMYS) at which the
pipeline can be operated.5 6 Design
factors are used along with pipe
characteristics in engineering
calculations (Barlow’s Formula) to
calculate the design pressure and MAOP
of a steel pipeline. More specifically, the
formula at § 192.105 is P = (2St/D) × F
× E × T, where P is the design pressure,
S is the pipe’s yield strength, t is the
wall thickness of the pipe, D is the
diameter of the pipe, F is the design
factor per the class location, E is the
3 For instance, the number of human dwellings
near the pipeline or the type of dwelling (hospital,
school, playground, nursing care facility, etc.).
4 This can include piping at compressor stations,
metering stations, fabrications, and road or railroad
crossings.
5 Design factors for steel pipe are listed in
§ 192.111. Class 1 locations have a 0.72 design
factor, Class 2 locations have a 0.60 factor, Class 3
locations have a 0.50 factor, and Class 4 locations
have a 0.40 design factor.
6 SMYS is an indication of the minimum stress a
pipe may experience that will cause plastic, or
permanent, deformation of the steel pipe.
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
longitudinal joint factor,7 and T is the
temperature derating factor.8 The
formula in § 192.105 can be used to
calculate the MAOP of a 1000 psig
pipeline with the same operating
parameters (diameter, wall thickness,
yield strength, seam type, and
temperature) but in different class
locations (and therefore different design
factors), and the MAOP of that pipeline
in the different class locations would be
as follows:
• No class location—design factor = 1.0
(none); MAOP = 1000 psig
• Class 1—design factor = 0.72; MAOP
= 720 psig
• Class 2—design factor = 0.60; MAOP
= 600 psig
• Class 3—design factor = 0.50; MAOP
= 500 psig
• Class 4—design factor = 0.40; MAOP
= 400 psig
As therefore evidenced, pipelines at
higher class locations will have lower
operating pressures and maximum
allowable operating pressures due to
more stringent design factors to protect
people near the pipeline.
As natural gas pipeline standards and
regulations evolved, the class location
concept was incorporated into many
other regulatory requirements, including
test pressures, mainline block valve
spacing, pipeline design and
construction, and operations and
maintenance (O&M) requirements, to
provide additional safety to populated
areas. In total, class location concepts
affect 12 of 16 subparts of part 192 and
a total of 28 individual sections.9
A. Class Location Determinations
Pipeline class locations for onshore
gas pipelines are determined as
specified in § 192.5(a) by using a
‘‘sliding mile.’’ The ‘‘sliding mile’’ is a
unit that is 1 mile in length, extends 220
yards on either side of the centerline of
a pipeline, and moves along the
7 The seam type of a pipeline, per this formula,
has a limiting effect on the MAOP of the pipeline.
While it is typically ‘‘1.00’’ and does not affect the
calculation, certain types of furnace butt-welded
pipe or pipe not manufactured to certain industry
standards will have factors of 0.60 or 0.80, which
will necessitate a reduction in design pressure.
8 The temperature derating factor ranges from
1.000 to 0.867 depending on the operating
temperature of the pipeline. Pipelines designed to
operate at 250 degrees Fahrenheit and lower have
a factor of 1.000, which does not affect the design
pressure calculation. Pipelines designed to operate
at higher temperatures, including up to 450 degrees
Fahrenheit, will have derating factors that will
lower the design pressure of the pipeline.
9 §§ 192.5, 192.8, 192.9, 192.65, 192.105, 192.111,
192.123, 192.150, 192.175, 192.179, 192.243,
192.327, 192.485, 192.503, 192.505, 192.609,
192.611, 192.613, 192.619, 192.620, 192.625,
192.705, 192.706, 192.707, 192.713, 192.903,
192.933, and 192.935.
PO 00000
Frm 00071
Fmt 4702
Sfmt 4702
pipeline. The number of buildings 10
within this sliding mile at any point
during the mile’s movement determines
the class location for the entire mile of
pipeline contained within the sliding
mile. Class locations are not determined
at any given point of a pipeline by
counting the number of dwellings in
static mile-long pipeline segments
stacked end-to-end.
When higher dwelling concentrations
are encountered during the continuous
sliding of this mile-long unit, the class
location of the pipeline rises
commensurately. As it pertains to
structure counts, a Class 1 location is a
class location unit along a continuous
mile containing 10 or fewer buildings
intended for human occupancy, a Class
2 location is a class location unit along
a continuous mile containing 11 to 45
buildings intended for human
occupancy, and a Class 3 location is a
class location unit along a continuous
mile containing 46 or more buildings
intended for human occupancy.11 Class
4 locations exist where buildings with
four or more stories above ground are
prevalent. Whenever there is a change
in class location that will cause an
apparent overlapping of class locations,
the higher-numbered class location
applies.
B. Class Location—‘‘Cluster Rule’’
Adjustments
After proposing the initial natural gas
safety regulations in 1970, OPS received
several comments stating that the
proposed class location definitions
could create 2-mile stretches of higher
class locations for the sole protection of
small clusters of buildings at crossroads
or road crossings. Because part 192
regulations become more stringent as
class locations increase from Class 1 to
4 locations, pipelines in higher class
location areas such as these can result
in increased expenditures to the
pipeline operator in areas where there is
no population. When finalizing the class
location definitions as a part of
establishing part 192 on August 19,
1970 (35 FR 13248), OPS added a new
paragraph to allow operators to adjust
the boundaries of Class 2, 3, and 4
10 Per the regulations, a ‘‘building’’ is a structure
intended for human occupancy, whether it is used
as a residence, for business, or for another purpose.
For the purposes of this rulemaking, a ‘‘building’’
may be interchangeably referred to as a ‘‘home,’’ a
‘‘house,’’ or a ‘‘dwelling.’’
11 Under § 192.5, Class 1 locations also include
offshore areas, and Class 3 locations contain areas
where the pipeline lies within 100 yards of a
building or a small, well-defined outside area
(including playgrounds, recreation areas, and
outdoor theaters) that is occupied by 20 or more
persons at least 5 days a week for 10 weeks in any
12-month period. The days and weeks need not be
consecutive.
E:\FR\FM\31JYP1.SGM
31JYP1
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
locations. Under this provision,
operators can choose to end Class 4
location boundaries 220 yards from the
furthest edges of a group of 4-story
buildings, and operators can choose to
end Class 2 and 3 boundaries up to 220
yards upstream and downstream from
the furthest edges of a group or
‘‘cluster’’ of buildings.12 ‘‘Clustering,’’
therefore, is a means of reducing the
length of a Class 2, 3, or 4 location in
a sliding mile unit that requires a Class
2, 3, or 4 location; in other words, it
allows operators to cluster or reduce the
amount of pipe that is subject to the
requirements of a higher class
location.13
It is important to note that while
clustering allows for the adjustment of
the length of class locations in certain
areas, it does not change the length of
class location units themselves nor the
method by which class location units
are determined. Further, clustering does
not exclude ‘‘buildings for human
occupancy’’ in a class location unit/
sliding mile, so all buildings within a
specified class location unit must be
protected by the maximum class
location level that was determined for
the entire class location unit. This
concept becomes especially important
when other buildings for human
occupancy are built within a class
location unit/sliding mile where a
cluster exists and an operator has
adjusted the class location length to
exclude certain lengths of pipe outside
of the cluster area.
For instance, assume there is a class
location unit/sliding mile containing 47
homes close to one another. The class
location unit would be a Class 3
location per the definition provided at
§ 192.5(b). An operator can consider
these homes a ‘‘cluster’’ and
appropriately apply the adjustment at
§ 192.5(c) so that the boundaries of the
Class 3 location are 220 yards upstream
and downstream from the furthest edges
of the clustered homes (buildings for
human occupancy). Therefore, while the
entirety of the pipeline is in a Class 3
class location unit, the only pipe subject
to Class 3 requirements is the length of
the cluster plus 220 yards on both sides
of the cluster. The remaining pipe in the
12 See
§ 192.5(c)(1) & (2).
example, if all buildings for human
occupancy in a sliding mile containing enough
buildings to require a Class 3 location were
clustered in the middle of that sliding mile, the
Class 3 area would end 220 yards from the nearest
building (on either side of the cluster through
which the pipeline passes) rather than at the end
of the 1-mile class location unit that would
otherwise be the basis for classification. Thus, if the
cluster were 200 yards in length, the total length of
the Class 3 area would be 640 yards (220 + 200 +
220).
daltland on DSKBBV9HB2PROD with PROPOSALS
13 For
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
class location unit/sliding mile, the pipe
that is outside of this clustered area,
could therefore be operated at Class 1
requirements rather than at the
otherwise-required Class 3
requirements.
However, what would happen if new
buildings were built within that sliding
mile but away from that single cluster?
If, per the example above, there is a
cluster of 47 homes at one end of a class
location unit/sliding mile, and 3 homes
are built at the other end of the class
location unit, the operator must count
and treat those 3 homes as a second
cluster, with the length of the cluster
plus 220 yards on both sides of the
cluster subject to Class 3 requirements.
The pipeline between these two clusters
would still be in a Class 3 location per
its class location unit, as there would be
50 homes within the sliding mile, but
the pipeline between the clusters could
be operated under Class 1 location
requirements. If the 220-yard extensions
of any two or more clusters intercept or
overlap, the separate clusters must be
considered a single cluster for purposes
of applying the adjustment.
An operator must use the clustering
method consistently to ensure that all
buildings for human occupancy within
a class location unit are covered by the
appropriately determined class location
requirements. Any new buildings for
human occupancy built in a class
location unit where clustering has been
used must also be clustered, whether
they form a new, independent cluster or
are added to the existing cluster. Note
that even a single house could form the
basis of a second cluster under this
requirement, as all buildings within a
specified class location unit must be
protected by the maximum class
location level that was determined for
the entire class location unit.
PHMSA’s interpretation to Air
Products and Chemicals, Inc., issued on
March 11, 2015,14 explains and
diagrams this concept further.
II. Changes in Class Location Due to
Population Growth
Class locations can change as the
population living or working near a
pipeline grows and, as outlined earlier,
are specifically determined based on the
density of dwellings within the 440yard-wide (quarter-mile-wide) sliding
mile down the pipeline centerline. Class
locations are used to determine a
pipeline’s design factor, which is a
component of the design formula
14 PHMSA Interpretation #PI–14–0017, available
at https://www.phmsa.dot.gov/sites/phmsa.dot.gov/
files/legacy/interpretations/Interpretation%20Files/
Pipeline/2015/Air_Products_PI_14_0017_10_01_
2014_Part_192.5.pdf.
PO 00000
Frm 00072
Fmt 4702
Sfmt 4702
36863
equation at § 192.105 and ultimately
factors into the pressure at which the
pipeline is operated. As population
around a pipeline increases and the
pipeline’s class location increases, the
numeric value of the design factor
decreases, which translates, via the
formula at § 192.105, into a lower
MAOP for the pipeline. To illustrate
this, a Class 4 location containing a
prevalence of 4-or-more-story buildings
has a safety factor of 0.4, whereas a
Class 2 location containing 11 to 45
dwellings has a safety factor of 0.6. If a
Class 2 location is very quickly
developed to a point where there is a
prevalence of 4-or-more story buildings,
the corresponding difference in safety
factor when the class location changes,
from a 0.6 to a 0.4, equates to a 33%
reduction in MAOP per the design
formula equation.
A change in class location requires
operators to confirm safety factors and
to recalculate the MAOP of a pipeline.
If the MAOP per the newly determined
class location is not commensurate with
the present class location, current
regulations require that pipeline
operators (1) reduce the pipe’s MAOP to
reduce stress levels in the pipe; (2)
replace the existing pipe with pipe that
has thicker walls or higher yield
strength to yield a lower operating stress
at the same MAOP; or (3) pressure test
at a higher test pressure if the pipeline
segment has not previously been tested
at the higher pressure and for a
minimum of 8 hours.15 Depending on
the pipeline’s test pressure and whether
it meets the requirements in §§ 192.609
and 192.611 (‘‘Change in class location:
Required study,’’ and ‘‘Change in class
location: Confirmation or revision of
maximum allowable operating
pressure,’’ respectively), an operator can
base the pipeline’s MAOP on a certain
safety factor times the test pressure for
the new class location as long as the
corresponding hoop stress of the
pipeline does not exceed certain
percentages of the specified minimum
yield strength (SMYS) of the pipe.16
15 See § 192.611 as appropriate to one-class
changes (e.g., Class 1 to 2 or Class 2 to 3 or Class
3 to 4). As an example, for a Class 1 to Class 2
location change, the pipeline segment would
require a pressure test to 1.25 times the MAOP for
8 hours. Following a successful pressure test, the
pipeline segment would not need to be replaced
with new pipe, but the existing design factor of 0.72
for a Class 1 location would be acceptable for a
Class 2 location.
16 See § 192.611. Specifically, if the applicable
segment has been hydrostatically tested for a period
of longer than 8 hours, the MAOP is 0.8 times the
test pressure in Class 2 locations, 0.667 times the
test pressure in Class 3 locations, or 0.555 times the
test pressure in Class 4 locations. The
corresponding hoop stress may not exceed 72% of
E:\FR\FM\31JYP1.SGM
Continued
31JYP1
36864
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
This is often referred to as a ‘‘one-class
bump,’’ as an operator can use this
method when class locations change
from a Class 1 to 2, a Class 2 to a 3, or
a Class 3 to a 4.
The §§ 192.5 and 192.611
requirements to change-out pipe, repressure test, or de-rate pipe to a lower
MAOP when population growth occurs
and requires a class location change are
the most significant reasons that
operators request that class locations be
revised or eliminated. Throughout the
process of considering class location
changes,17 comments PHMSA received
from the trade associations state that
reducing a pipeline’s operating pressure
below that at which the pipeline
historically operated may unacceptably
restrict deliveries to natural gas
customers. These same commenters
suggest that pressure testing pipelines
may be practicable in select cases, but
the test pressure required for higher
class locations may exceed what a
pipeline is designed to accommodate.
Operators also contend that they should
not have to change out pipe when a
class location change occurs if the
operator can prove that the pipe
segment is fit for service through
integrity assessments.18
daltland on DSKBBV9HB2PROD with PROPOSALS
III. Class Location Change Special
Permits
As population growth occurs around
pipelines that were formerly in rural
areas, some operators have applied for
special permits to prevent the need for
pipe replacement or pressure reduction
when the class location changes. A
SMYS of the pipe in Class 2 locations, 60% of
SMYS in Class 3 locations, or 50% of SMYS in
Class 4 locations.
17 See Section IV of this document. In the context
of this rulemaking, PHMSA has been considering
issues related to class location requirements since
publishing an ANPRM on the gas transmission
regulations in 2011. Following that, PHMSA
published a notice of inquiry soliciting comments
on expanding gas IM program requirements and
mitigating class location requirements (78 FR
46560; August 1, 2013) and held a public meeting
on the notice of inquiry topics on April 16, 2014
(both actions under Docket Number PHMSA–2013–
0161). PHMSA also received comments on the
issues discussed in this rulemaking in the docket
titled ‘‘Transportation Infrastructure: Notice of
Review of Policy, Guidance, and Regulations
Affecting Transportation Infrastructure Projects’’
which was noticed in the Federal Register on June
8, 2017 (82 FR 26734; Docket Number OST–2017–
0057).
18 Operators did not outline the type of integrity
assessments that would be appropriate from their
perspective nor the factors that should be
considered to determine whether a pipeline
segment is fit for service (such as pipe, pipe seam,
or coating conditions; O&M history; material
properties; pipe depth of cover; non-destructive
testing of girth welds; type pipe coatings used and
if they shield cathodic protection; seam type; failure
or leak history; and pressure testing or acceptance
criteria and any re-evaluation intervals).
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
special permit is an order issued under
§ 190.341 that waives or modifies
compliance with regulatory
requirements if the pipeline operator
requesting it demonstrates a need and
PHMSA determines that granting the
special permit would be consistent with
pipeline safety. PHMSA performs
extensive technical analysis on special
permit applications and typically grants
special permits on the condition that
operators will perform alternative
measures to provide an equal or greater
level of public safety. PHMSA publishes
a notice and request for comment in the
Federal Register for each special permit
application received and tracks issued,
denied, and expired special permits on
its website.
Since 2004, PHMSA has approved
over 15 class location special permits
based on operators adopting additional
conditions, including certain operating
safety criteria and periodic integrity
evaluations.19 20 Generally, the
additional conditions PHMSA requires
are designed to identify and mitigate
integrity issues that could threaten the
pipeline segment and cause failure,
especially given the fact that the
majority of class location special
permits it receives and reviews are for
older pipelines that may have
manufacturing, construction, or ongoing
maintenance issues, such as seam or
pipe body cracking, poor external
coating, insufficient soil cover, lack of
material records, dents, or repairs not
made to class location design safety
factors.
Typically, PHMSA requires operators
to incorporate the affected segments into
the company’s O&M procedures and
integrity management plan, perform
additional assessments for threats to the
pipeline segments identified during an
operator’s risk assessment, perform
additional cathodic protection 21 and
19 Special permit conditions are implemented to
mitigate the causes of gas transmission incidents
and are based on the type of threats pertinent to the
pipeline. The conditions are generally more heavily
weighted on identifying: Material, coating and
cathodic protection issues, pipe wall loss, pipe and
weld cracking, depth of pipe cover, third party
damage prevention, marking of the pipeline and
pipeline right-of-way patrols, pressure tests and
documentation, data integration of integrity issues,
and reassessment intervals.
20 Examples of PHMSA’s class location special
permit conditions can be found at: https://
primis.phmsa.dot.gov/classloc/docs/SpecialPermit_
ExampleClassLocSP_Conditions_090112_
draft1.pdf, and more information about PHMSA’s
special permit process for class location changes
can be found at: https://primis.phmsa.dot.gov/
classloc/documents.htm
21 Cathodic protection is a technique used to
control the corrosion of a metal surface by making
it the cathode of an electrochemical cell. This can
be achieved with a special coating on the external
surface of the pipeline along with an electrical
PO 00000
Frm 00073
Fmt 4702
Sfmt 4702
corrosion control measures, and repair
any discovered anomalies to a specified
schedule. Therefore, the additional
monitoring and maintenance
requirements PHMSA prescribes
through this process help to ensure the
integrity of the pipe and protection of
the population living near the pipeline
segment at a comparable margin of
safety and environmental protection
throughout the life of the pipe compared
to the regulations as written. The class
location change special permits that
PHMSA has granted have allowed
operators to continue operating the
pipeline segments identified under the
special permits at the current MAOP
based on the previous class locations.
PHMSA notes that it developed its class
location special permit process by
adapting Integrity Management (IM)
concepts and published the typical
considerations for class location change
special permit requests in the Federal
Register in 2004.22 Based on its
experiences when renewing some of the
earliest class location change special
permits, PHMSA has extended the
expiration date of its class location
change special permits from 5 years to
10 years. This extension should provide
additional regulatory certainty to
operators that apply for these permits.
Further, throughout the renewal process
of existing special permits, PHMSA has
not significantly changed the original
conditions imposed on individual
operators. While PHMSA can make
modifications to its special permit
conditions when it is in the interest of
safety and the public to do so, PHMSA
has determined that the present special
permit conditions and process are
consistent with public safety.
A. Special Permit Conditions
In the special permit conditions and
criteria PHMSA published in the
Federal Register on June 29, 2004,
PHMSA outlines several ‘‘threshold
conditions’’ pipelines must meet to be
considered for a special permit when
class locations change. For instance,
PHMSA does not consider any pipeline
segments for a special permit where the
class location those segments are in
changes to a Class 4 location. Typically,
PHMSA receives special permit requests
system and anodes buried in the ground or with a
‘‘sacrificial’’ or galvanic metal acting as an anode.
In these systems, the anode will corrode before the
protected metal will.
22 Federal Register (69 FR 38948, June 29, 2004).
Additional guidance is provided online at: https://
primis.phmsa.dot.gov/classloc/index.htm. Public
notices were published in Federal Register: 69 FR
22115 and 69 FR 38948, dated April 23, 2004 and
June 29, 2004: Docket No. RSPA–2004–17401—
Pipeline Safety: Development of Class Location
Change Waiver (Special Permit).
E:\FR\FM\31JYP1.SGM
31JYP1
daltland on DSKBBV9HB2PROD with PROPOSALS
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
for pipeline segments where the class
location is changing from Class 1 to
Class 3. PHMSA also does not consider
for class location change special permits
any segments that have bare pipe or
wrinkle bends. Other manufacturingand construction-related items PHMSA
considers include whether the
applicable segments have certain seam
types that may be more prone to defects
and failures, whether the pipe has
certain coating types that provide an
adequate level of cathodic protection,
and the design strength of the pipe.
There are also operation and
maintenance factors that PHMSA
considers when evaluating pipeline
segments for class location change
special permit feasibility. For example,
PHMSA doesn’t consider for a Class 1
to Class 3 location change special
permit any pipe segments that operate
above 72 percent SMYS. Operators also
need to produce a hydrostatic test
record showing the segment was tested
to 1.25 times the MAOP. Also, operators
are required to have pipe material
records to document the pipelines
diameter, wall thickness, strength, seam
type and coating type. For operators
who do not have these records, PHMSA
requires they make these records per the
special permit conditions. PHMSA often
requires operators to operate each
applicable segment at or below its
existing MAOP as well.
As part of the special permit
conditions, operators are required by
PHMSA to incorporate the applicable
pipeline segments into their IM program
and inspect them on a regular basis
according to the operator’s procedures.
As an extension of this requirement,
operators must perform in-line
inspections on the applicable segments,
and the segments must not have any
significant anomalies that would
indicate any systemic problems.
Additionally, PHMSA’s published
special permit criteria defines a ‘‘waiver
inspection area,’’ also known as a
‘‘special permit inspection area,’’ as up
to 25 miles of pipe on either side of the
applicable segment. Operators must
incorporate these areas into their IM
programs as well and inspect and repair
them per the operator’s IM program
procedures. Some of the factors PHMSA
uses when deciding the length of special
permit inspection areas are based on
factors including what class location the
surrounding pipe is in and whether
class location ‘‘clustering’’ has been
used. For both the special permit
segments and the special permit
inspection areas, PHMSA also typically
requires operators to perform
assessments and surveys to identify
pipe that may be susceptible to certain
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
issues, especially seam or cracking
issues in the pipe seam or pipe body,
based on the coating type, vintage, or
manufacturing of the pipe. Pipelines in
the special permit segments or in the
special permit inspection areas that
have had a leak or failure history are
also taken into consideration when
PHMSA develops an individual special
permit’s conditions so as to prevent
similar issues in the future. Further,
PHMSA looks at the enforcement
history of an operator applying for a
special permit as a benchmark for how
the operator has followed the Federal
Pipeline Safety Regulations when
developing the conditions following a
special permit request.
In class location change special
permit requests, PHMSA also ensures
that integrity threats to pipelines in
special permit segments and special
permit inspection areas are addressed in
operator operations and management
plans, including a systematic, ongoing
program to review and remediate
pipeline safety concerns. Some of the
typical integrity and safety threats
PHMSA would expect operators to
address include pipe coating quality,
cathodic protection effectiveness, stress
corrosion and seam cracking, and any
long-term pipeline system flow
reversals. To this end, PHMSA often
requires coating condition surveys, the
remediation of coating, and cathodic
protection systems for pipelines where
the operator has requested a class
location change special permit. Any
data gathered on the special permit area
and special permit inspection area
would have to be incorporated into the
operator’s greater IM program.
PHMSA incorporates these conditions
into class location change special permit
requests to ensure that operators meet or
exceed the threshold requirements with
equivalent safety to the provisions in
the Federal Pipeline Safety Regulations
that are being waived and ensure that
granting the special permit will not be
inconsistent with safety.
IV. Pipeline Safety, Regulatory
Certainty, and Job Creation Act of
2011—Section 5
On January 3, 2012, the Pipeline
Safety, Regulatory Certainty, and Job
Creation Act of 2011 (Pub. L. 112–90)
was enacted. Among the many
provisions of the Act, Section 5 required
PHMSA to evaluate whether IM system
requirements, or elements thereof,
should be expanded beyond highconsequence areas (HCA) and, with
respect to gas transmission pipeline
facilities, whether applying IM program
requirements, or elements thereof, to
additional areas would mitigate the
PO 00000
Frm 00074
Fmt 4702
Sfmt 4702
36865
need for class location requirements.
PHMSA was required to report the
findings of this evaluation to Congress
and was authorized to issue regulations
pursuant to the findings of the report
following a prescribed review period.
A. 2013 Notice of Inquiry: Class
Location Requirements
In August 2013, through a Notice of
Inquiry, PHMSA solicited comments on
whether expanding IM requirements
would mitigate the need for class
locations in line with the Section 5
mandate of the 2011 Pipeline Safety
Act.23 Several topics were discussed,
including whether class locations
should be eliminated and a single
design factor used, whether design
factors should be increased for higher
class locations, and whether pipelines
without complete material records
should be allowed to use a single design
factor if class locations were to be
eliminated.24
There was broad consensus among
PHMSA’s stakeholders that eliminating
class locations entirely would not lead
to improvement to pipeline safety.
Further, commenters noted that
establishing a single design factor in
lieu of class location designations might
be too complicated to implement. Many
commenters noted that any changes in
class location requirements would
impact not only the classifications of
many pipelines but would also possibly
create several unintended consequences
within part 192, as the class location
requirements are referenced or built
upon throughout the natural gas
regulations.
Several industry trade groups had
suggestions for changing the class
location regulations, and these
suggestions were developed further
through subsequent discussions at
advisory committee meetings and at
public workshops. The Interstate
Natural Gas Association of America
(INGAA) noted that IM should be
extended beyond HCAs with the caveat
that PHMSA should examine the effects
of such a change on other areas of the
pipeline safety regulations. Along with
this, it suggested that PHMSA revise
certain operations and maintenance
requirements that may no longer be
necessary given technological advances
and IM activities.
23 Federal
Register (78 FR 46560, August 1, 2013).
these questions, PHMSA received 30
comment letters, available at www.regulations.gov
at docket PHMSA–2013–0161.
24 Regarding
E:\FR\FM\31JYP1.SGM
31JYP1
36866
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
daltland on DSKBBV9HB2PROD with PROPOSALS
B. 2014 Pipeline Advisory Committee
Meeting, Class Location Workshop, and
Subsequent Comments
On February 25, 2014, PHMSA hosted
a joint meeting of the Gas and Liquid
Pipeline Advisory Committees.25 At that
meeting, PHMSA updated the
committees on its activities regarding
the Section 5 mandate of the 2011
Pipeline Safety Act, and committee
members and members of the public
provided their comments.
INGAA, reinforcing its comments on
the 2013 Notice of Inquiry, noted that
the original class location definitions in
ASME B31.8 were intended to provide
an increased margin of safety for
locations of higher population density
and stated that IM is a much better risk
management tool than class locations.
INGAA reiterated that it intends for its
members to perform elements of IM on
pipelines outside of HCAs.
On April 16, 2014, PHMSA sponsored
a Class Location Workshop to solicit
comments on whether applying the gas
pipeline IM program requirements
beyond HCAs would mitigate the need
for gas pipeline class location
requirements. Presentations were made
by representatives from PHMSA, the
National Energy Board of Canada (NEB),
National Association of Pipeline Safety
Representatives (NAPSR), pipeline
operators, industry groups, and public
interest groups.26
During the workshop, INGAA
representatives noted that the current
class location regulations require
changes that result in the replacement of
‘‘good pipe,’’ and the special permit
process for class location changes
should be embedded in part 192.
Representatives from the American Gas
Association (AGA) noted that applying
the current class location change
requirements can cost more than $1
million per change. AGA claimed the
special permit process for class location
changes is burdensome, the renewal
process is increasingly complex, and the
outcome is uncertain.27 Therefore, AGA
25 The Pipeline Advisory Committees are
statutorily mandated advisory committees that
advise PHMSA on proposed safety standards, risk
assessments, and safety policies for natural gas and
hazardous liquid pipelines (49 U.S.C. 60115). These
Committees were established under the Federal
Advisory Committee Act (Pub. L. 92–463, 5 U.S.C.
app. 1–16) and the Federal Pipeline Safety Statutes
(49 U.S.C. chap. 601–603). Each committee consists
of 15 members, with membership divided among
Federal and State agency representatives, the
regulated industry, and the public.
26 Meeting presentations are available online at:
https://primis.phmsa.dot.gov/meetings/
MtgHome.mtg?mtg=95.
27 PHMSA notes that the special permit process
is outlined in § 190.341 and is no different for the
class location regulations than for any other
pipeline safety regulation. Of the 18 special permits
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
suggested eliminating the special permit
process for class location changes and
incorporating specific requirements for
special permits into part 192 as part of
the base regulations. AGA
recommended two approach methods,
one based on IM and the other using the
current class location approach.
Public interest groups including
Accufacts and the Pipeline Safety Trust
(PST) pointed out how deeply the
concept of class locations is embedded
in part 192, while also noting that IM
requirements and class locations
overlap in densely populated areas to
provide a redundant, but necessary,
safety regime. The PST also suggested
that, in time, the older class location
method potentially could be replaced
with an IM method for regulation.
However, the PST noted that incidents
and data suggest there is room for
improvement in the IM regulations, as
data shows higher incident rates in
HCAs than in non-HCAs, and noted that
pipe installed after 2010 has a higher
incident rate than pipe installed a
decade earlier. Similarly, Accufacts
noted that the incident at San Bruno,
CA, exposed weaknesses in the
operator’s IM program and
demonstrated that the consequences
resulting from the incident spread far
beyond the potential radius in which
they were expected to occur.28
Therefore, Accufacts suggested that
shifting the class location approach to
solely an IM approach might decrease
the protection of public safety.
Following the Class Location
Workshop, INGAA submitted additional
comments to the docket stating that
advancements in IM technology and
processes have superseded the need for
mandatory pipe replacement following a
class location change. It noted that, in
the past, it was logical to replace a
pipeline when class locations changed
because of the widespread belief that
thicker pipe would take longer to
corrode and would withstand greater
external forces, such as damage from
excavators, before failure. However,
given current technology, improvements
in pipe quality, and ongoing regulatory
processes such as IM, operators can
mitigate most threats without the need
for pipe replacement. Therefore, INGAA
up for renewal from 2010–2017, 9 of them were for
class location changes. When reviewing the class
location change permits up for renewal, PHMSA
found no safety reason to extensively modify any
of the prior permits and made no major revisions
to any of the previously imposed safety conditions.
28 The potential impact radius for the ruptured
pipe segment involved in the San Bruno incident
was calculated at 414 feet. However, the NTSB, in
its accident report (NTSB/PAR–11/01), noted that
the subsequent fire damage extended to a radius of
about 600 feet from the blast center.
PO 00000
Frm 00075
Fmt 4702
Sfmt 4702
offered an approach to class locations
changes to not require pipe replacement
for existing pipelines if pipe segments
meet certain requirements that are in
line with current IM requirements.
Specifically, INGAA suggested that
pipelines meeting a ‘‘fitness for service’’
standard in 18 categories of
requirements could address potential
safety concerns and preclude the need
for pipe replacement.29 The 18
categories are very similar to the special
permit conditions that PHMSA uses for
a Class 1 to 3 location special permit as
noted in the 2004 Federal Register
notice.30
C. 2016 Class Location Report
The Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011
required that PHMSA evaluate whether
IM should be expanded beyond HCAs
and whether such expansion would
mitigate the need for class location
requirements. In its report titled
‘‘Evaluation of Expanding Pipeline
Integrity Management Beyond HighConsequence Areas and Whether Such
Expansion Would Mitigate the Need for
Gas Pipeline Class Location
Requirements,’’ 31 which was submitted
to Congress in April 2016 concurrently
with the publication of the NPRM titled
‘‘Safety of Gas Transmission and
Gathering Pipelines’’ (81 FR 20722),
PHMSA noted that the application of IM
program elements, such as assessment
and remediation timeframes, beyond
HCAs would not warrant the
elimination of class locations.
PHMSA notes that class locations
affect all gas pipelines and are integral
to determining MAOPs; design
pressures; pipe wall thickness; valve
spacing; HCAs, in certain cases; and
O&M inspection, surveillance, and
repair intervals. While IM measures are
a critical step towards pipeline safety
and are important to mitigate risk, the
assessment and remediation of defects
do not adequately compensate for these
other aspects of class locations. Thus, as
outlined in the report, PHMSA
determined the existing class location
29 Those 18 categories were as follows: Baseline
Engineering and Record Assessments—Girth Weld
Assessment, Casing Assessment, Pipe Seam
Assessment, Field Coating Assessment, Cathodic
Protection, Interference Currents Control, Close
Interval Survey, Stress Corrosion Cracking
Assessments, In-line Inspection Assessments, Metal
Loss Anomaly Management, Dent Anomaly
Management, Hard Spots Anomaly Management.
Ongoing Requirements—Integrity Management
Program, Root Cause Analysis for Failure or Leak,
Line Markers, Patrols, Damage Prevention Best
Practices, Recordkeeping & Documentation.
30 See also: https://primis.phmsa.dot.gov/classloc/
index.htm.
31 https://www.regulations.gov/
document?D=PHMSA-2011-0023-0153.
E:\FR\FM\31JYP1.SGM
31JYP1
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
daltland on DSKBBV9HB2PROD with PROPOSALS
requirements were appropriate for
maintaining pipeline safety and should
be retained. Therefore, any revisions to
the class location requirements would
have to be forward-looking (i.e.,
applying to pipelines constructed after a
certain effective date) and would have
to comport with the existing regulatory
regime to provide commensurate safety
if any changes are made to aspects of
pipeline safety related to design and
construction, which is where key safety
benefits of class locations are realized.32
As a part of the continuing discussion
on class location changes and
subsequent pipe replacement, PHMSA
summarized at the end of the Class
Location Report the concerns operators
expressed regarding the cost of
replacing pipe in locations that change
from a Class 1 to a Class 3 location or
a Class 2 to a Class 4 location. As
discussed throughout the document,
operators submitted that the safe
operation of pipelines constructed in
Class 1 locations that later change to
Class 3 locations can be achieved using
current IM practices.
However, over the past decade,
PHMSA observed problems with pipe
and fitting manufacturing quality,
including low-strength material; 33
construction practices; welding; field
coating practices; IM assessments and
reassessment practices; 34 35 and record
documentation practices.36 37 These
issues give PHMSA pause in
considering approaches allowing a twoclass bump (Class 1 to 3 or Class 2 to
4) without requiring pipe replacement,
especially for higher-pressure
transmission pipelines.
PHMSA stated in the conclusion of its
Class Location Report that it would
further evaluate the feasibility and the
appropriateness of alternatives to
32 In its comments following the public workshop
on Class Locations in 2014, INGAA noted that, after
further analysis, it appears that applying the
Potential Impact Radius (PIR) method to existing
pipelines may be unworkable.
33 PHMSA has documented pipe material lowstrength issues through an advisory bulletin and the
following website link: https://
primis.phmsa.dot.gov/lowstrength/index.htm.
34 IM and operational procedures and practices
were issues in the Pacific Gas & Electric (PG&E) San
Bruno, CA, rupture in September 2010 and the
Enbridge Marshall, MI, rupture in July 2010.
35 PHMSA issued Advisory Bulletins ADB–11–01
and ADB–2012–10 to operators regarding IM
meaningful metrics and assessments on January 10,
2011, and December 5, 2012, respectively, which
can be reviewed at: https://phmsa.dot.gov/pipeline/
regs/advisory-bulletin.
36 PHMSA issued Advisory Bulletin, ADB–12–06,
concerning documentation of MAOP on May 7,
2012, which can be reviewed at: https://
phmsa.dot.gov/pipeline/regs/advisory-bulletin.
37 Also note PHMSA’s Advisory Bulletin titled
‘‘Deactivation of Threats,’’ issued March 16, 2017
(82 FR 14106).
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
address issues pertaining to pipe
replacement requirements, continue to
reach out to and consider input from all
stakeholders, and consider future
rulemaking if a cost-effective and safetyfocused approach to adjusting specific
aspects of class location requirements
could be developed to address the
issues identified by industry. In doing
so, PHMSA would evaluate alternatives
in the context of other issues it is
addressing related to new construction
quality- and safety-management systems
and will also consider inspection
findings, IM assessment results, and
lessons learned from past incidents.
Therefore, PHMSA has initiated this
rulemaking to gain further information
on analyzing the current requirements
resulting in pipe replacement and
alternatives to that practice.
V. INGAA Submission on Regulatory
Reform—Proposal To Perform IM
Measures in Lieu of Pipe Replacement
When Class Locations Change
On July 24, 2017, INGAA submitted
comments to a DOT docket regarding
regulatory review actions (Docket No.
OST–2017–0057). In its submission,
INGAA estimated that gas transmission
pipeline operators incur annual costs of
$200–$300 million 38 nationwide
replacing pipe solely to satisfy the class
location change regulations and
requested PHMSA consider revising the
current class location change
regulations to include an alternative
beyond pressure reduction, pressure
testing, or pipe replacement.
INGAA’s proposed alternate approach
focuses on recurring IM assessments
that would leverage advanced
assessment technologies to determine
whether the pipe condition warrants
pipe replacement in areas where the
class location has changed. INGAA
states that such an approach would
further promote IM processes and
principles throughout the nation’s gas
transmission pipeline network, improve
economic efficiency by reducing
regulatory burden, and help fulfill the
purposes of Section 5 of the 2011
Pipeline Safety Act.
INGAA claims that the current
alternatives to pipe replacement
following a class location change do not
reflect the substantial developments in
IM processes, technologies, and
regulations over the past 15-plus years.
More specifically, in-line inspection
(ILI) technologies, such as high38 PHMSA requests further substantiation of this
estimate. In extrapolating the national data, PHMSA
estimates this number is the cost incurred for all
pipe replacement projects on transmission lines,
not just those projects triggered in response to class
location changes.
PO 00000
Frm 00076
Fmt 4702
Sfmt 4702
36867
resolution magnetic flux leakage tools,
can precisely assess the presence of
corrosion and other potential defects,
allowing an operator to establish
whether a pipeline segment requires
remediation or replacement.39
INGAA further notes that PHMSA’s
proposed rulemaking titled ‘‘Safety of
Gas Transmission and Gathering
Pipelines’’ aims to expand IM
assessments to newly defined
‘‘Moderate Consequence Areas’’
(proposed § 192.710), and such an
expansion provides a framework for
developing an alternative for managing
class location changes. INGAA suggests
that the costs saved from avoiding pipe
replacement using such an alternative
could mitigate, to some degree, part of
the costs of the proposed rulemaking.
Additionally, INGAA notes that the
proposed rulemaking contains several
new provisions that will require
operators to better manage the integrity
of their pipelines by implementing more
preventative and mitigative measures to
manage the threat of corrosion. INGAA
states that the inclusion of such
corrosion control measures as a part of
a program for managing the integrity of
pipeline segments, including ones that
have experienced class location
changes, would further justify the
development of an IM-focused
alternative to class location changes.
Based on those statements, INGAA
recommends PHMSA develop an
alternative approach to § 192.611 that
leverages the proposed § 192.710 for
areas outside of HCAs and the IM
requirements at § 192.921 to require
recurring IM assessments and
incorporation of those affected pipeline
segments into IM programs. Further,
INGAA suggests this approach require
operators to reconfirm pipeline MAOP
in a changed class location for any
pipeline segment without traceable,
verifiable, and complete records of a
hydrostatic pressure test supporting the
segment’s previous MAOP.
PHMSA acknowledges that the class
location change regulations predate the
development of modern pipeline
inspection technology such as ILI,
above-ground surveys, and modern
integrity management processes. In fact,
it wasn’t until the mid-1990s that
PHMSA, following models from other
industries such as nuclear power,
started to explore whether a risk-based
approach to regulation could improve
public and environmental safety.
PHMSA finalized the IM regulations for
gas transmission pipelines on December
39 PHMSA notes that ILI and in-the-ditch
evaluation technologies for crack identification are
under development and could further be improved.
E:\FR\FM\31JYP1.SGM
31JYP1
daltland on DSKBBV9HB2PROD with PROPOSALS
36868
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
15, 2003,40 in response to tragic
incidents on pipelines in Bellingham,
WA, in 1999 and near Carlsbad, NM, in
2000, which killed 3 people and 12
people, respectively. The IM regulations
designated HCAs where operators
would perform periodic assessments of
the condition of their pipelines and
make necessary repairs within specific
timeframes if discovered anomalies met
certain criteria. More specifically, the
IM regulations outline the risk-based
processes that pipeline operators must
use to identify, prioritize, assess,
evaluate, repair, and validate the
integrity of gas transmission pipelines.
For many years, the pipeline industry
used internal steel brush devices
(‘‘cleaning pigs’’) moved by product
flow to clean the inside of their
pipelines. This pigging concept was
later adapted through the application of
technology to measure and record
irregularities in the pipe and welds that
may represent corrosion, cracks,
deformations, and other defects. Now
operators use ILI technology (‘‘smart
pigging or ILI’’) as a backbone of the
modern IM program. ILI tools are
inserted into pipelines at locations, such
as near valves or compressor stations,
that have special configurations of pipes
and valves where the ILI tools can be
loaded into launchers, the launchers can
be closed and sealed, and the flow of the
product the pipeline is carrying can be
directed to launch the tool down the
pipeline. A similar setup is located
downstream where the tool is directed
out of the main line into a receiver so
that an operator can remove the tool and
retrieve the recorded data for analysis
and reporting. ILI tools come in several
different varieties that have distinct
advantages and disadvantages over
other methods of pipeline assessment.
For instance, while some ILI tools might
be able to reliably determine whether a
pipeline has internal corrosion, the
same tool might not be able to
determine whether the pipeline has any
crack indications. In selecting the tools
most suitable for inline inspections,
pipeline operators must know the type
of threats that are applicable to the
pipeline segment. Threats that ILI tools
can identify typically include existing
pipe wall thickness, pipe wall changes,
pipe wall loss, cracking, and dents.
At the time the class location
regulations were promulgated, it was
logical to replace a pipeline when
population growth resulted in a class
location change in order to restore the
safety margin appropriate for that
40 68 FR 69778; Pipeline Safety: Pipeline Integrity
Management in High Consequence Areas (Gas
Transmission Pipelines).
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
location because the industry did not
have the technology that is available
today to learn the in situ material
condition of the pipe. Further, since the
existing pipe would not achieve a
similar safety margin as replaced pipe,
operators would need to use applicable
inspection technology and pressure
testing to ensure pipe has the correct
wall thickness; strength; seam
condition; toughness; no detrimental
cracking or corrosion in the pipe body
or seam; and a pipe coating that has not
deteriorated or shields cathodic
protection currents to allow corrosion or
cracking issues such as girth weld
cracking, stress corrosion cracking, or
selective seam weld corrosion.
Currently, operators are not required
to inspect pipelines or otherwise
perform IM on those portions of
pipelines unless they are within high
consequence areas (HCAs) or the
operator otherwise voluntarily assesses
them and performs remediation
measures for threats to the pipeline. As
such, while prudent operators may
know the characteristics and conditions
of their pipelines outside of HCAs and
can be confident that they can manage
class location change expectations
through the performance of IM
measures, some operators may not.
PHMSA notes that while class
locations and HCAs both provide
additional protection to areas with high
population concentrations, they were
designed for different purposes. Unlike
class locations, which provide blanket
levels of safety throughout the nation’s
pipeline network at all locations by
driving MAOP and design, construction,
testing, and O&M requirements, the
purpose of the IM regulations is to
provide a structure for operators to
focus their resources on improving
pipeline integrity in the areas where a
failure would have the greatest impact
on public safety. Whereas over time the
safety margins that class locations
provide can be reduced due to corrosion
or other types of pipe degradation, IM
requirements provide a continuing
minimum safety margin for more
densely populated areas because
operators are required to inspect and
repair those applicable pipelines at a
minimum of every 7 years and more
frequently based upon risk assessments
of threats to the segment in the HCA.
PHMSA acknowledges that applying
modern IM assessments and processes
could potentially be a comparable
alternative to pipe change-outs. PHMSA
notes that if operators perform integrity
assessments on significant portions of
non-HCA pipe mileage, PHMSA could
further consider operators using such
assessments to determine whether pipe
PO 00000
Frm 00077
Fmt 4702
Sfmt 4702
in a changed class location is fit for
service rather than having to replace it.
PHMSA is concerned, however, that
some issues that result in pipeline
failures, including poor construction
practices 41 and operational
maintenance threats, are not always
being properly assessed and mitigated
by operators, whether due to lack of
technology or other causes. Further, as
the incident at San Bruno in 2010
showed, operators may not have
traceable, verifiable, and complete
records of pipe properties, such as pipe
material yield strength, pipe wall
thickness, pipe seam type, pipe and
seam toughness, and coating quality,
that are critical and necessary for IM
processes and pipeline safety in Class 3
and 4 locations and HCAs where there
are higher population densities. PHMSA
also points out that there might be
instances where a pipeline may be in
‘‘good condition’’ from a visual
standpoint, but it may not have the
initial pipe manufacturing, pipe
strength, construction quality, and O&M
history requirements that add the extra
level of safety required by the
regulations for the higher population
density area and the MAOP.42 Section
192.611 already allows a ‘‘one-class
location’’ bump for pipeline class
locations that are in satisfactory
physical condition and have the
required pressure test.
Because of these factors, PHMSA
seeks comment on the potential safety
consequences of altering the current
class location methodology and moving
to an IM-only method in certain areas.
41 PHMSA has met with operators constructing
new pipelines on several occasions to discuss
issues found during inspection. To reach out to all
members of the pipeline industry, PHMSA hosted
a public workshop in collaboration with our State
partners, the Federal Energy Regulatory
Commission (FERC) and Canada’s National Energy
Board (NEB) in April 2009. The objective of the
workshop was to inform the public, alert the
industry, review lessons learned from inspections,
and to improve new pipeline construction practices
prior to the 2009 construction season. This website
makes available information discussed at the
workshop and provides a forum in which to share
additional information about pipeline construction
concerns. This workshop focused on transmission
pipeline construction. https://primis.phmsa.dot.gov/
construction/index.htm.
42 Note that the potential impact radius (PIR) in
Integrity Management (IM) does not give any
criteria to establish the pipelines operating
pressure, anomaly repair criteria, safety surveys for
leaks, 3rd party encroachments, etc. When Class
locations change (from additional dwellings for
human occupancy) from one-level to a higher level
there are cut-off levels that may require a different
design factor, pressure test, or maintenance criteria.
For pipe to be replaced the class location change
would have to be from a Class 1 to 3 or Class 2 to
4, which is a large increase in dwellings along the
pipeline.
E:\FR\FM\31JYP1.SGM
31JYP1
daltland on DSKBBV9HB2PROD with PROPOSALS
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
VI. Questions for Consideration
PHMSA is requesting comments and
information that will be used to
determine if revisions should be made
to the Federal Pipeline Safety
Regulations regarding the current
requirements operators must meet when
class locations change. The list of
questions below is not exhaustive and
represents an effort to help in the
formulation of comments. Any
additional information that commenters
determine would be beneficial to this
discussion is also welcomed.
Q1—When the population increases
along a pipeline route that requires a
class location change as defined at
§ 192.5, should PHMSA allow pipe
integrity upgrades from Class 1 to Class
3 locations by methods other than pipe
replacement or special permits? 43 Why
or why not?
1a.—Should part 192 continue to
require pipe integrity upgrades when
class locations change from Class 1 to
Class 3 locations or Class 2 to 4
locations? Why or why not?
1b.—Should part 192 continue to
require pipe integrity upgrades from
Class 1 to Class 3 locations for the
‘‘cluster rule’’ (see § 192.5(c)) when 10
or fewer buildings intended for human
occupancy have been constructed along
the pipeline segment? Why or why not?
1c.—Should part 192 continue to
require pipe integrity upgrades for
grandfathered pipe (e.g., pipe segments
without a pressure test or with an
inadequate pressure test, operating
pressures above 72% SMYS, or
inadequate or missing material records;
see § 192.619(c))? Why or why not?
Q2—Should PHMSA give operators
the option of performing certain IM
measures in lieu of the existing
measures (pipe replacement, lower the
operating pressure, or pressure test at a
higher pressure; see § 192.611) when
class locations change from Class 1 to
Class 3 due to population growth within
the sliding mile? Why or why not?
2a.—If so, what, if any, additional
integrity management and maintenance
approaches or safety measures should
be applied to offset the impact on safety
these proposals might create?
Q3—Should PHMSA give operators
the option of performing certain IM
measures in lieu of the existing
measures (pipe replacement with a more
conservative design safety factor or a
combination of pressure test and lower
MAOP) when class locations change
due to additional structures being built
outside of clustered areas within the
43 Sections
involving class location requirements
include §§ 192.5, 192.609, 192.611, 192.619 and
192.620.
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
sliding mile, if operators are using the
cluster adjustment to class locations per
§ 192.5(c)(2)? Why or why not?
3a.—If so, what, if any, additional
integrity management and maintenance
approaches or safety measures should
be applied to offset the impact on safety
these proposals might create?
3b.—At what intervals and in what
timeframes should operators be required
to assess these pipelines and perform
remediation measures?
Q4—If PHMSA allows operators to
perform certain IM measures in lieu of
pipe replacement when class locations
change from Class 1 to Class 3, should
some sort of ‘‘fitness for service’’
standard determine which pipelines are
eligible? Why or why not?
4a.—If so, what factors should make
a pipeline eligible or ineligible?
(i) Should grandfathered pipe (lacking
records, including pressure test or
material records) or pipe operating
above 72% SMYS be eligible? Why or
why not?
(ii) Should pipe that has experienced
an in-service failure, was manufactured
with a material or seam welding process
during a time or by a manufacturer
where there are now known integrity
issues or has lower toughness in the
pipe and weld seam (Charpy impact
value) be eligible? Should pipe with a
failure or leak history be eligible? Why
or why not?
(iii) Should pipe that contains or is
susceptible to cracking, including in the
body, seam, or girth weld, or having
disbonded coating or CP shielding
coatings be eligible? Are there coating
types that should disqualify pipe?
Should some types of pipe, such as lapwelded, flash-welded, or low-frequency
electric resistance welded pipe be
ineligible? Should pipe where the seam
type is unknown be ineligible? Why or
why not?
(iv) Should pipe with significant
corrosion (wall loss) be eligible for
certain IM measures, or should it be
replaced? Why or why not?
(v) Should anomalies be repaired
similar to IM, allowed to grow to only
a 10-percent safety factor 44
(§ 192.933(d)) before remediation in
high population areas such as Class 2,
3 and 4 locations, or should they have
an increased safety factor for
remediation should these class location
factors be eliminated? Why or why not?
(vi) Should pipe that has been
damaged (dented) or has lost ground
cover due to 3rd party activity
44 Section 192.933 has anomaly repair
requirements based upon a predicted failure
pressure being less than or equal to 1.1 times the
MAOP.
PO 00000
Frm 00078
Fmt 4702
Sfmt 4702
36869
(excavation or other) be eligible? Why or
why not?
(vii) Should pipe lacking cathodic
protection due to disbonded coating be
eligible? Why or why not?
(viii) Should pipe with properties
such as low frequency electric
resistance weld (LF–ERW), lap welded,
or other seam types that have a history
of seam failure due to poor
manufacturing properties or seam types
that have a derating factor below 1.0 be
eligible? Why or why not?
4b.—Should PHMSA base any
proposed requirements off its criteria
used for considering class location
change waivers (69 FR 38948; June 29,
2004), including the age and
manufacturing and construction
processes of the pipe, and O&M history?
Why or why not?
4c.—In the 2004 Federal Register
notice (69 FR 38948), PHMSA outlines
certain requirements pipelines must
meet to be eligible for waiver
consideration, including no bare pipe or
pipe with wrinkle bends, records of a
hydrostatic test to at least 1.25 times
MAOP, records of ILI runs with no
significant anomalies that would
indicate systemic problems, and
agreement that up to 25 miles of pipe
both upstream and downstream of the
waiver location must be included in the
operator’s IM program and periodically
inspected using ILI technology. Further,
the criteria provides no waivers for
segments changing to Class 4 locations
or for pipe changing to a Class 3
location that is operating above 72%
SMYS. Should PHMSA require
operators and pipelines to meet the
threshold conditions outlined earlier in
this document (Section 3A; ‘‘Class
Location Change Special Permits—
Special Permit Conditions) or other
thresholds to be eligible for a waiver
when class locations change? Why or
why not?
Q5—As it is critical for operators to
have traceable, verifiable, and complete
(TVC) records to perform IM, should
operators be required to have TVC
records as a prerequisite for performing
IM measures on segments instead of
replacing pipe when class locations
change? Why or why not?
5a.—If so, what records should be
necessary and why? Should records
include pipe properties, including yield
strength, seam type, and wall thickness;
coating type; O&M history; leak and
failure history; pressure test records;
MAOP; class location; depth of cover;
and ability to be in-line inspected?
5b.—If operators do not have TVC
records for affected segments and TVC
records were a prerequisite for
performing IM measures on pipeline
E:\FR\FM\31JYP1.SGM
31JYP1
daltland on DSKBBV9HB2PROD with PROPOSALS
36870
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
segments in lieu of replacing pipe, how
should those records be obtained, and
when should the deadline for obtaining
those records be?
Q6—Should PHMSA incorporate its
special permit conditions regarding
class location changes into the
regulations, and would this
incorporation satisfy the need for
alternative approaches? Why or why
not? (Examples of typical PHMSA class
location special permit conditions can
be found at https://
primis.phmsa.dot.gov/classloc/
documents.htm.)
6a.—What, if any, special permit
conditions could be incorporated into
the regulations to provide regulatory
certainty and public safety in these high
population density areas (Class 2, 3, and
4)?
Q7—For all new and replaced
pipelines, to what extent are operators
consulting growth and development
plans to avoid potentially costly pipe
change-outs in the future?
Q8—What is the amount of pipeline
mileage per year being replaced due to
class location changes for pipelines: (1)
Greater than 24 inches in diameter, (2)
16–24 inches in diameter, and (3) less
than 16 inches in diameter?
8a.—Of this mileage, how much is
being replaced due to class locations
changing when additional structures for
human occupancy are built near
clustered areas, if operators are using
the cluster adjustment to class locations
per § 192.5(c)(2)?
8b.—At how many distinct locations
are pipe replacements occurring due to
class location changes and that involve
pipe with these diameters?
8c.—What is the average amount of
pipe (in miles) being replaced and cost
of replacement at the locations
described in question 8b. and for these
diameter ranges due to class location
changes?
Q9—Should any additional pipeline
safety equipment, preventative and
mitigative measures, or prescribed
standard pipeline predicted failure
pressures more conservative than in the
IM regulations be required if operators
do not replace pipe when class locations
change due to population growth and
perform IM measures instead? Why or
why not?
9a.—Should operators be required to
install rupture-mitigation valves or
equivalent technology? Why or why
not?
9b.—Should operators be required to
install SCADA systems for impacted
pipeline segments? Why or why not?
Q10—Should there be any maximum
diameter, pressure, or potential impact
radius (PIR) limits that should disallow
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
operators from using IM principles in
lieu of the existing requirements when
class locations change? For instance,
PHMSA has seen construction projects
where operators are putting in 42-inchdiameter pipe designed to operate at up
to 3,000 psig. The PIR for that pipeline
would be over 1,587 feet, which would
mean the total blast diameter would be
more than 3,174 feet.
VII. Regulatory Notices
A. Executive Order 12866, Executive
Order 13563, Executive Order 13771,
and DOT Regulatory Policies and
Procedures
Executive Orders 12866 and 13563
require agencies to regulate in the ‘‘most
cost-effective manner,’’ to make a
‘‘reasoned determination that the
benefits of the intended regulation
justify its costs,’’ and to develop
regulations that ‘‘impose the least
burden on society.’’ Executive Order
13771 (‘‘Reducing Regulation and
Controlling Regulatory Costs’’), issued
January 30, 2017, provides that ‘‘it is
essential to manage the costs associated
with the governmental imposition of
private expenditures required to comply
with Federal regulations.’’ One way to
manage the costs of rulemakings is to
propose new regulations that are
deregulatory in nature, i.e. regulations
that reduce the cost of regulatory
compliance. PHMSA seeks information
on whether this rulemaking could result
in a deregulatory action under E.O.
13771, meaning that a potential final
rule could have ‘‘total costs less than
zero.’’ 45 We therefore request
comments, including specific data if
possible, concerning the costs and
benefits of revising the pipeline safety
regulations to accommodate any of the
changes suggested in the advance
notice.
B. Executive Order 13132: Federalism
Executive Order 13132 requires
agencies to assure meaningful and
timely input by State and local officials
in the development of regulatory
policies that may have a substantial,
direct effect on the States, on the
relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government. PHMSA is
inviting comments on the effect a
possible rulemaking adopting any of the
amendments discussed in this
document may have on the relationship
45 See OMB Memorandum M–17–21, ‘‘Guidance
Implementing Executive Order 13771, Titled
‘Reducing Regulation and Controlling Regulatory
Costs,’ ’’ (April 5, 2017).
PO 00000
Frm 00079
Fmt 4702
Sfmt 4702
between national government and the
States.
C. Regulatory Flexibility Act
Under the Regulatory Flexibility Act
of 1980 (5 U.S.C. 601 et seq.), PHMSA
must consider whether a proposed rule
would have a significant impact on a
substantial number of small entities.
‘‘Small entities’’ include small
businesses, not-for-profit organizations
that are independently owned and
operated and are not dominant in their
fields, and governmental jurisdictions
with populations under 50,000. If your
business or organization is a small
entity and if adoption of any of the
amendments discussed in this ANPRM
could have a significant economic
impact on your operations, please
submit a comment to explain how and
to what extent your business or
organization could be affected and
whether there are alternative
approaches to the regulations the agency
should consider that would minimize
any significant negative impact on small
business while still meeting the
agency’s statutory objectives.
D. National Environmental Policy Act
The National Environmental Policy
Act of 1969 requires Federal agencies to
consider the consequences of Federal
actions and that they prepare a detailed
statement analyzing them if the action
significantly affects the quality of the
human environment. Interested parties
are invited to address the potential
environmental impacts of this ANPRM,
including comments about compliance
measures that would provide greater
benefit to the human environment or
any alternative actions the agency could
take that would provide beneficial
impacts.
E. Executive Order 13175: Consultation
and Coordination with Indian Tribal
Governments
Executive Order 13175 requires
agencies to assure meaningful and
timely input from Indian Tribal
Government representatives in the
development of rules that ‘‘significantly
or uniquely affect’’ Indian communities
and that impose ‘‘substantial and direct
compliance costs’’ on such
communities. We invite Indian Tribal
governments to provide comments on
any aspect of this ANPRM that may
affect Indian communities.
F. Paperwork Reduction Act
Under 5 CFR part 1320, PHMSA
analyzes any paperwork burdens if any
information collection will be required
by a rulemaking. We invite comment on
the need for any collection of
E:\FR\FM\31JYP1.SGM
31JYP1
Federal Register / Vol. 83, No. 147 / Tuesday, July 31, 2018 / Proposed Rules
information and paperwork burdens
related to this ANPRM.
G. Privacy Act Statement
daltland on DSKBBV9HB2PROD with PROPOSALS
Anyone can search the electronic
form of comments received in response
to any of our dockets by the name of the
VerDate Sep<11>2014
16:40 Jul 30, 2018
Jkt 244001
individual submitting the comment (or
signing the comment, if submitted on
behalf of an association, business, labor
union, etc.). DOT’s complete Privacy
Act Statement was published in the
Federal Register on April 11, 2000 (65
FR 19477).
PO 00000
Frm 00080
Fmt 4702
Sfmt 9990
36871
Issued in Washington, DC, on July 25,
2018, under authority delegated in 49 CFR
1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2018–16376 Filed 7–30–18; 8:45 am]
BILLING CODE 4910–60–P
E:\FR\FM\31JYP1.SGM
31JYP1
]]>Agencies
[Federal Register Volume 83, Number 147 (Tuesday, July 31, 2018)]
[Proposed Rules]
[Pages 36861-36871]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-16376]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
49 CFR Part 192
[Docket ID: PHMSA-2017-0151]
RIN 2137-AF29
Pipeline Safety: Class Location Change Requirements
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.
ACTION: Advance notice of proposed rulemaking (ANPRM).
-----------------------------------------------------------------------
SUMMARY: PHMSA is seeking public comment on its existing class location
requirements for natural gas transmission pipelines as they pertain to
actions operators are required to take following class location changes
due to population growth near the pipeline. Operators have suggested
that performing integrity management measures on pipelines where class
locations have changed due to population increases would be an equally
safe but less costly alternative to the current requirements of either
reducing pressure, pressure testing, or replacing pipe. This request
for public comment continues a line of discussion from a Notice of
Inquiry published in 2013 and a report to Congress in 2016 regarding
whether expanding integrity management requirements would mitigate the
need for class location requirements.
DATES: Persons interested in submitting written comments on this ANPRM
must do so by October 1, 2018.
ADDRESSES: You may submit comments identified by the Docket: PHMSA-
2017-0151 by any of the following methods:
E-Gov website: https://www.regulations.gov. This site allows the
public to enter comments on any Federal Register notice issued by any
agency. Follow the online instructions for submitting comments.
Fax: 1-202-493-2251.
Mail: Hand Delivery: U.S. DOT Docket Management System, West
Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE,
Washington, DC 20590-0001 between 9:00 a.m. and 5:00 p.m., Monday
through Friday, except Federal holidays.
Instructions: Identify the Docket ID at the beginning of your
comments. If you submit your comments by mail, submit two copies. If
you wish to receive confirmation that PHMSA has received your comments,
include a self-addressed stamped postcard. Internet users may submit
comments at https://www.regulations.gov/.
Note: Comments are posted without changes or edits to https://www.regulations.gov, including any personal information provided. There
is a privacy statement published on https://www.regulations.gov.
FOR FURTHER INFORMATION CONTACT:
Technical questions: Steve Nanney, Project Manager, by telephone at
713-272-2855 or by email at [email protected].
General information: Robert Jagger, Technical Writer, by telephone
at 202-366-4361 or by email at [email protected].
SUPPLEMENTARY INFORMATION:
Outline of This Document
I. Class Location History and Purpose
A. Class Location Determinations
B. Class Location--``Cluster Rule'' Adjustments
II. Changes in Class Location Due to Population Growth
III. Class Location Change Special Permits
A. Special Permit Conditions
IV. Pipeline Safety, Regulatory Certainty, and Job Creation Act of
2011--Section 5
A. 2013 Notice of Inquiry: Class Location Requirements
B. 2014 Pipeline Advisory Committee Meeting, Class Location
Workshop, and Subsequent Comments
C. 2016 Class Location Report
V. INGAA Submission on Regulatory Reform--Proposal To Perform IM
Measures In-Lieu of Pipe Replacement When Class Locations Change
VI. Questions for Consideration
VII. Regulatory Notices
Background
I. Class Location History and Purpose
The class location concept pre-dates Federal regulation of gas
transmission pipelines \1\ and was an early method of differentiating
areas and risks along natural gas pipelines based on the potential
consequences of a hypothetical pipeline failure. Class location
designations were previously included in the American Standards
Association B31.8-1968 version of the ``Gas Transmission and
Distribution Pipeline Systems'' standard, which eventually became the
American Society of Mechanical Engineers (ASME) International Standard,
ASME B31.8 ``Gas Transmission and Distribution Pipeline Systems.'' The
class location definitions incorporated into title 49, Code of Federal
Regulations (CFR) Sec. 192.5 were initially derived from the
designations in this standard and were first codified on April 19,
1970.\2\ These definitions were like the original ASME B31.8
definitions for Class 1 through 3 locations but added an additional
Class 4 definition and, with some modifications, still apply today.
---------------------------------------------------------------------------
\1\ The Department of Transportation first proposed class
location regulations on March 24, 1970 (35 FR 5012). The proposal
was part of a series of NPRMs published in response to the Natural
Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). The NPRMs were
directed at developing a comprehensive system of Federal safety
standards for gas pipeline facilities and for the transportation of
gas through such pipelines. The class location rulemaking was
finalized on August 19, 1970, as part of a consolidated rulemaking
establishing the first minimum Federal safety standards for the
transportation of natural gas by pipelines (35 FR 13248).
\2\ 35 FR 13248.
---------------------------------------------------------------------------
Gas transmission pipelines are divided into classes from 1 (rural
areas) to 4 (densely populated, high-rise areas) that are based on the
number of buildings or dwellings for human occupancy in the area. This
concept is to provide safety to people from the effects of a high-
pressure natural gas pipeline leak or rupture that could explode or
catch on fire. PHMSA uses class locations in 49 CFR part 192 to
implement a graded approach in many areas that provides more
conservative safety margins and more stringent safety standards
commensurate with the potential consequences based on population
density near the pipeline. When crafting the natural gas
[[Page 36862]]
regulations, DOT's Office of Pipeline Safety (OPS) determined that
these more stringent standards were necessary because a greater number
of people in proximity to the pipeline substantially increases the
probabilities of personal injury and property damage in the event of an
accident. At the same time, the external stresses, the potential for
damage from third-parties, and other factors that contribute to
accidents increase along with the population; consequently, additional
protective measures are often needed in areas with greater
concentrations of population.
The most basic and earliest use of the class location concept
focused on the design (safety) margin for the pipeline. As pipelines
are designed based, in part, on the population along their pipeline
route and therefore the class location of the area, it is important to
decrease pipe stresses in areas where there is the potential for higher
consequences or where higher pipe stresses could affect the safe
operation of a pipeline in larger-populated areas. Pipeline design
factors are derating factors that ensure pipelines are operated below
100 percent of the maximum pipe yield strength. From an engineering
standpoint, they were developed based on risk to the public \3\ and for
piping that may face additional operational stresses.\4\ Pipeline
design factors vary, ranging from 0.72 in a Class 1 location to 0.40 in
a Class 4 location. They are used in the pipeline design formula (Sec.
192.105) to determine the design pressure for steel pipe, and are
generally reflected in the maximum allowable operating pressure (MAOP)
based upon a percentage of the specified minimum yield strength (SMYS)
at which the pipeline can be operated.5 6 Design factors are
used along with pipe characteristics in engineering calculations
(Barlow's Formula) to calculate the design pressure and MAOP of a steel
pipeline. More specifically, the formula at Sec. 192.105 is P = (2St/
D) x F x E x T, where P is the design pressure, S is the pipe's yield
strength, t is the wall thickness of the pipe, D is the diameter of the
pipe, F is the design factor per the class location, E is the
longitudinal joint factor,\7\ and T is the temperature derating
factor.\8\ The formula in Sec. 192.105 can be used to calculate the
MAOP of a 1000 psig pipeline with the same operating parameters
(diameter, wall thickness, yield strength, seam type, and temperature)
but in different class locations (and therefore different design
factors), and the MAOP of that pipeline in the different class
locations would be as follows:
---------------------------------------------------------------------------
\3\ For instance, the number of human dwellings near the
pipeline or the type of dwelling (hospital, school, playground,
nursing care facility, etc.).
\4\ This can include piping at compressor stations, metering
stations, fabrications, and road or railroad crossings.
\5\ Design factors for steel pipe are listed in Sec. 192.111.
Class 1 locations have a 0.72 design factor, Class 2 locations have
a 0.60 factor, Class 3 locations have a 0.50 factor, and Class 4
locations have a 0.40 design factor.
\6\ SMYS is an indication of the minimum stress a pipe may
experience that will cause plastic, or permanent, deformation of the
steel pipe.
\7\ The seam type of a pipeline, per this formula, has a
limiting effect on the MAOP of the pipeline. While it is typically
``1.00'' and does not affect the calculation, certain types of
furnace butt-welded pipe or pipe not manufactured to certain
industry standards will have factors of 0.60 or 0.80, which will
necessitate a reduction in design pressure.
\8\ The temperature derating factor ranges from 1.000 to 0.867
depending on the operating temperature of the pipeline. Pipelines
designed to operate at 250 degrees Fahrenheit and lower have a
factor of 1.000, which does not affect the design pressure
calculation. Pipelines designed to operate at higher temperatures,
including up to 450 degrees Fahrenheit, will have derating factors
that will lower the design pressure of the pipeline.
No class location--design factor = 1.0 (none); MAOP = 1000
psig
Class 1--design factor = 0.72; MAOP = 720 psig
Class 2--design factor = 0.60; MAOP = 600 psig
Class 3--design factor = 0.50; MAOP = 500 psig
Class 4--design factor = 0.40; MAOP = 400 psig
As therefore evidenced, pipelines at higher class locations will
have lower operating pressures and maximum allowable operating
pressures due to more stringent design factors to protect people near
the pipeline.
As natural gas pipeline standards and regulations evolved, the
class location concept was incorporated into many other regulatory
requirements, including test pressures, mainline block valve spacing,
pipeline design and construction, and operations and maintenance (O&M)
requirements, to provide additional safety to populated areas. In
total, class location concepts affect 12 of 16 subparts of part 192 and
a total of 28 individual sections.\9\
---------------------------------------------------------------------------
\9\ Sec. Sec. 192.5, 192.8, 192.9, 192.65, 192.105, 192.111,
192.123, 192.150, 192.175, 192.179, 192.243, 192.327, 192.485,
192.503, 192.505, 192.609, 192.611, 192.613, 192.619, 192.620,
192.625, 192.705, 192.706, 192.707, 192.713, 192.903, 192.933, and
192.935.
---------------------------------------------------------------------------
A. Class Location Determinations
Pipeline class locations for onshore gas pipelines are determined
as specified in Sec. 192.5(a) by using a ``sliding mile.'' The
``sliding mile'' is a unit that is 1 mile in length, extends 220 yards
on either side of the centerline of a pipeline, and moves along the
pipeline. The number of buildings \10\ within this sliding mile at any
point during the mile's movement determines the class location for the
entire mile of pipeline contained within the sliding mile. Class
locations are not determined at any given point of a pipeline by
counting the number of dwellings in static mile-long pipeline segments
stacked end-to-end.
---------------------------------------------------------------------------
\10\ Per the regulations, a ``building'' is a structure intended
for human occupancy, whether it is used as a residence, for
business, or for another purpose. For the purposes of this
rulemaking, a ``building'' may be interchangeably referred to as a
``home,'' a ``house,'' or a ``dwelling.''
---------------------------------------------------------------------------
When higher dwelling concentrations are encountered during the
continuous sliding of this mile-long unit, the class location of the
pipeline rises commensurately. As it pertains to structure counts, a
Class 1 location is a class location unit along a continuous mile
containing 10 or fewer buildings intended for human occupancy, a Class
2 location is a class location unit along a continuous mile containing
11 to 45 buildings intended for human occupancy, and a Class 3 location
is a class location unit along a continuous mile containing 46 or more
buildings intended for human occupancy.\11\ Class 4 locations exist
where buildings with four or more stories above ground are prevalent.
Whenever there is a change in class location that will cause an
apparent overlapping of class locations, the higher-numbered class
location applies.
---------------------------------------------------------------------------
\11\ Under Sec. 192.5, Class 1 locations also include offshore
areas, and Class 3 locations contain areas where the pipeline lies
within 100 yards of a building or a small, well-defined outside area
(including playgrounds, recreation areas, and outdoor theaters) that
is occupied by 20 or more persons at least 5 days a week for 10
weeks in any 12-month period. The days and weeks need not be
consecutive.
---------------------------------------------------------------------------
B. Class Location--``Cluster Rule'' Adjustments
After proposing the initial natural gas safety regulations in 1970,
OPS received several comments stating that the proposed class location
definitions could create 2-mile stretches of higher class locations for
the sole protection of small clusters of buildings at crossroads or
road crossings. Because part 192 regulations become more stringent as
class locations increase from Class 1 to 4 locations, pipelines in
higher class location areas such as these can result in increased
expenditures to the pipeline operator in areas where there is no
population. When finalizing the class location definitions as a part of
establishing part 192 on August 19, 1970 (35 FR 13248), OPS added a new
paragraph to allow operators to adjust the boundaries of Class 2, 3,
and 4
[[Page 36863]]
locations. Under this provision, operators can choose to end Class 4
location boundaries 220 yards from the furthest edges of a group of 4-
story buildings, and operators can choose to end Class 2 and 3
boundaries up to 220 yards upstream and downstream from the furthest
edges of a group or ``cluster'' of buildings.\12\ ``Clustering,''
therefore, is a means of reducing the length of a Class 2, 3, or 4
location in a sliding mile unit that requires a Class 2, 3, or 4
location; in other words, it allows operators to cluster or reduce the
amount of pipe that is subject to the requirements of a higher class
location.\13\
---------------------------------------------------------------------------
\12\ See Sec. 192.5(c)(1) & (2).
\13\ For example, if all buildings for human occupancy in a
sliding mile containing enough buildings to require a Class 3
location were clustered in the middle of that sliding mile, the
Class 3 area would end 220 yards from the nearest building (on
either side of the cluster through which the pipeline passes) rather
than at the end of the 1-mile class location unit that would
otherwise be the basis for classification. Thus, if the cluster were
200 yards in length, the total length of the Class 3 area would be
640 yards (220 + 200 + 220).
---------------------------------------------------------------------------
It is important to note that while clustering allows for the
adjustment of the length of class locations in certain areas, it does
not change the length of class location units themselves nor the method
by which class location units are determined. Further, clustering does
not exclude ``buildings for human occupancy'' in a class location unit/
sliding mile, so all buildings within a specified class location unit
must be protected by the maximum class location level that was
determined for the entire class location unit. This concept becomes
especially important when other buildings for human occupancy are built
within a class location unit/sliding mile where a cluster exists and an
operator has adjusted the class location length to exclude certain
lengths of pipe outside of the cluster area.
For instance, assume there is a class location unit/sliding mile
containing 47 homes close to one another. The class location unit would
be a Class 3 location per the definition provided at Sec. 192.5(b). An
operator can consider these homes a ``cluster'' and appropriately apply
the adjustment at Sec. 192.5(c) so that the boundaries of the Class 3
location are 220 yards upstream and downstream from the furthest edges
of the clustered homes (buildings for human occupancy). Therefore,
while the entirety of the pipeline is in a Class 3 class location unit,
the only pipe subject to Class 3 requirements is the length of the
cluster plus 220 yards on both sides of the cluster. The remaining pipe
in the class location unit/sliding mile, the pipe that is outside of
this clustered area, could therefore be operated at Class 1
requirements rather than at the otherwise-required Class 3
requirements.
However, what would happen if new buildings were built within that
sliding mile but away from that single cluster? If, per the example
above, there is a cluster of 47 homes at one end of a class location
unit/sliding mile, and 3 homes are built at the other end of the class
location unit, the operator must count and treat those 3 homes as a
second cluster, with the length of the cluster plus 220 yards on both
sides of the cluster subject to Class 3 requirements. The pipeline
between these two clusters would still be in a Class 3 location per its
class location unit, as there would be 50 homes within the sliding
mile, but the pipeline between the clusters could be operated under
Class 1 location requirements. If the 220-yard extensions of any two or
more clusters intercept or overlap, the separate clusters must be
considered a single cluster for purposes of applying the adjustment.
An operator must use the clustering method consistently to ensure
that all buildings for human occupancy within a class location unit are
covered by the appropriately determined class location requirements.
Any new buildings for human occupancy built in a class location unit
where clustering has been used must also be clustered, whether they
form a new, independent cluster or are added to the existing cluster.
Note that even a single house could form the basis of a second cluster
under this requirement, as all buildings within a specified class
location unit must be protected by the maximum class location level
that was determined for the entire class location unit.
PHMSA's interpretation to Air Products and Chemicals, Inc., issued
on March 11, 2015,\14\ explains and diagrams this concept further.
---------------------------------------------------------------------------
\14\ PHMSA Interpretation #PI-14-0017, available at https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/legacy/interpretations/Interpretation%20Files/Pipeline/2015/Air_Products_PI_14_0017_10_01_2014_Part_192.5.pdf.
---------------------------------------------------------------------------
II. Changes in Class Location Due to Population Growth
Class locations can change as the population living or working near
a pipeline grows and, as outlined earlier, are specifically determined
based on the density of dwellings within the 440-yard-wide (quarter-
mile-wide) sliding mile down the pipeline centerline. Class locations
are used to determine a pipeline's design factor, which is a component
of the design formula equation at Sec. 192.105 and ultimately factors
into the pressure at which the pipeline is operated. As population
around a pipeline increases and the pipeline's class location
increases, the numeric value of the design factor decreases, which
translates, via the formula at Sec. 192.105, into a lower MAOP for the
pipeline. To illustrate this, a Class 4 location containing a
prevalence of 4-or-more-story buildings has a safety factor of 0.4,
whereas a Class 2 location containing 11 to 45 dwellings has a safety
factor of 0.6. If a Class 2 location is very quickly developed to a
point where there is a prevalence of 4-or-more story buildings, the
corresponding difference in safety factor when the class location
changes, from a 0.6 to a 0.4, equates to a 33% reduction in MAOP per
the design formula equation.
A change in class location requires operators to confirm safety
factors and to recalculate the MAOP of a pipeline. If the MAOP per the
newly determined class location is not commensurate with the present
class location, current regulations require that pipeline operators (1)
reduce the pipe's MAOP to reduce stress levels in the pipe; (2) replace
the existing pipe with pipe that has thicker walls or higher yield
strength to yield a lower operating stress at the same MAOP; or (3)
pressure test at a higher test pressure if the pipeline segment has not
previously been tested at the higher pressure and for a minimum of 8
hours.\15\ Depending on the pipeline's test pressure and whether it
meets the requirements in Sec. Sec. 192.609 and 192.611 (``Change in
class location: Required study,'' and ``Change in class location:
Confirmation or revision of maximum allowable operating pressure,''
respectively), an operator can base the pipeline's MAOP on a certain
safety factor times the test pressure for the new class location as
long as the corresponding hoop stress of the pipeline does not exceed
certain percentages of the specified minimum yield strength (SMYS) of
the pipe.\16\
[[Page 36864]]
This is often referred to as a ``one-class bump,'' as an operator can
use this method when class locations change from a Class 1 to 2, a
Class 2 to a 3, or a Class 3 to a 4.
---------------------------------------------------------------------------
\15\ See Sec. 192.611 as appropriate to one-class changes
(e.g., Class 1 to 2 or Class 2 to 3 or Class 3 to 4). As an example,
for a Class 1 to Class 2 location change, the pipeline segment would
require a pressure test to 1.25 times the MAOP for 8 hours.
Following a successful pressure test, the pipeline segment would not
need to be replaced with new pipe, but the existing design factor of
0.72 for a Class 1 location would be acceptable for a Class 2
location.
\16\ See Sec. 192.611. Specifically, if the applicable segment
has been hydrostatically tested for a period of longer than 8 hours,
the MAOP is 0.8 times the test pressure in Class 2 locations, 0.667
times the test pressure in Class 3 locations, or 0.555 times the
test pressure in Class 4 locations. The corresponding hoop stress
may not exceed 72% of SMYS of the pipe in Class 2 locations, 60% of
SMYS in Class 3 locations, or 50% of SMYS in Class 4 locations.
---------------------------------------------------------------------------
The Sec. Sec. 192.5 and 192.611 requirements to change-out pipe,
re-pressure test, or de-rate pipe to a lower MAOP when population
growth occurs and requires a class location change are the most
significant reasons that operators request that class locations be
revised or eliminated. Throughout the process of considering class
location changes,\17\ comments PHMSA received from the trade
associations state that reducing a pipeline's operating pressure below
that at which the pipeline historically operated may unacceptably
restrict deliveries to natural gas customers. These same commenters
suggest that pressure testing pipelines may be practicable in select
cases, but the test pressure required for higher class locations may
exceed what a pipeline is designed to accommodate. Operators also
contend that they should not have to change out pipe when a class
location change occurs if the operator can prove that the pipe segment
is fit for service through integrity assessments.\18\
---------------------------------------------------------------------------
\17\ See Section IV of this document. In the context of this
rulemaking, PHMSA has been considering issues related to class
location requirements since publishing an ANPRM on the gas
transmission regulations in 2011. Following that, PHMSA published a
notice of inquiry soliciting comments on expanding gas IM program
requirements and mitigating class location requirements (78 FR
46560; August 1, 2013) and held a public meeting on the notice of
inquiry topics on April 16, 2014 (both actions under Docket Number
PHMSA-2013-0161). PHMSA also received comments on the issues
discussed in this rulemaking in the docket titled ``Transportation
Infrastructure: Notice of Review of Policy, Guidance, and
Regulations Affecting Transportation Infrastructure Projects'' which
was noticed in the Federal Register on June 8, 2017 (82 FR 26734;
Docket Number OST-2017-0057).
\18\ Operators did not outline the type of integrity assessments
that would be appropriate from their perspective nor the factors
that should be considered to determine whether a pipeline segment is
fit for service (such as pipe, pipe seam, or coating conditions; O&M
history; material properties; pipe depth of cover; non-destructive
testing of girth welds; type pipe coatings used and if they shield
cathodic protection; seam type; failure or leak history; and
pressure testing or acceptance criteria and any re-evaluation
intervals).
---------------------------------------------------------------------------
III. Class Location Change Special Permits
As population growth occurs around pipelines that were formerly in
rural areas, some operators have applied for special permits to prevent
the need for pipe replacement or pressure reduction when the class
location changes. A special permit is an order issued under Sec.
190.341 that waives or modifies compliance with regulatory requirements
if the pipeline operator requesting it demonstrates a need and PHMSA
determines that granting the special permit would be consistent with
pipeline safety. PHMSA performs extensive technical analysis on special
permit applications and typically grants special permits on the
condition that operators will perform alternative measures to provide
an equal or greater level of public safety. PHMSA publishes a notice
and request for comment in the Federal Register for each special permit
application received and tracks issued, denied, and expired special
permits on its website.
Since 2004, PHMSA has approved over 15 class location special
permits based on operators adopting additional conditions, including
certain operating safety criteria and periodic integrity
evaluations.19 20 Generally, the additional conditions PHMSA
requires are designed to identify and mitigate integrity issues that
could threaten the pipeline segment and cause failure, especially given
the fact that the majority of class location special permits it
receives and reviews are for older pipelines that may have
manufacturing, construction, or ongoing maintenance issues, such as
seam or pipe body cracking, poor external coating, insufficient soil
cover, lack of material records, dents, or repairs not made to class
location design safety factors.
---------------------------------------------------------------------------
\19\ Special permit conditions are implemented to mitigate the
causes of gas transmission incidents and are based on the type of
threats pertinent to the pipeline. The conditions are generally more
heavily weighted on identifying: Material, coating and cathodic
protection issues, pipe wall loss, pipe and weld cracking, depth of
pipe cover, third party damage prevention, marking of the pipeline
and pipeline right-of-way patrols, pressure tests and documentation,
data integration of integrity issues, and reassessment intervals.
\20\ Examples of PHMSA's class location special permit
conditions can be found at: https://primis.phmsa.dot.gov/classloc/docs/SpecialPermit_ExampleClassLocSP_Conditions_090112_draft1.pdf,
and more information about PHMSA's special permit process for class
location changes can be found at: https://primis.phmsa.dot.gov/classloc/documents.htm
---------------------------------------------------------------------------
Typically, PHMSA requires operators to incorporate the affected
segments into the company's O&M procedures and integrity management
plan, perform additional assessments for threats to the pipeline
segments identified during an operator's risk assessment, perform
additional cathodic protection \21\ and corrosion control measures, and
repair any discovered anomalies to a specified schedule. Therefore, the
additional monitoring and maintenance requirements PHMSA prescribes
through this process help to ensure the integrity of the pipe and
protection of the population living near the pipeline segment at a
comparable margin of safety and environmental protection throughout the
life of the pipe compared to the regulations as written. The class
location change special permits that PHMSA has granted have allowed
operators to continue operating the pipeline segments identified under
the special permits at the current MAOP based on the previous class
locations. PHMSA notes that it developed its class location special
permit process by adapting Integrity Management (IM) concepts and
published the typical considerations for class location change special
permit requests in the Federal Register in 2004.\22\ Based on its
experiences when renewing some of the earliest class location change
special permits, PHMSA has extended the expiration date of its class
location change special permits from 5 years to 10 years. This
extension should provide additional regulatory certainty to operators
that apply for these permits. Further, throughout the renewal process
of existing special permits, PHMSA has not significantly changed the
original conditions imposed on individual operators. While PHMSA can
make modifications to its special permit conditions when it is in the
interest of safety and the public to do so, PHMSA has determined that
the present special permit conditions and process are consistent with
public safety.
---------------------------------------------------------------------------
\21\ Cathodic protection is a technique used to control the
corrosion of a metal surface by making it the cathode of an
electrochemical cell. This can be achieved with a special coating on
the external surface of the pipeline along with an electrical system
and anodes buried in the ground or with a ``sacrificial'' or
galvanic metal acting as an anode. In these systems, the anode will
corrode before the protected metal will.
\22\ Federal Register (69 FR 38948, June 29, 2004). Additional
guidance is provided online at: https://primis.phmsa.dot.gov/classloc/index.htm. Public notices were published in Federal
Register: 69 FR 22115 and 69 FR 38948, dated April 23, 2004 and June
29, 2004: Docket No. RSPA-2004-17401--Pipeline Safety: Development
of Class Location Change Waiver (Special Permit).
---------------------------------------------------------------------------
A. Special Permit Conditions
In the special permit conditions and criteria PHMSA published in
the Federal Register on June 29, 2004, PHMSA outlines several
``threshold conditions'' pipelines must meet to be considered for a
special permit when class locations change. For instance, PHMSA does
not consider any pipeline segments for a special permit where the class
location those segments are in changes to a Class 4 location.
Typically, PHMSA receives special permit requests
[[Page 36865]]
for pipeline segments where the class location is changing from Class 1
to Class 3. PHMSA also does not consider for class location change
special permits any segments that have bare pipe or wrinkle bends.
Other manufacturing- and construction-related items PHMSA considers
include whether the applicable segments have certain seam types that
may be more prone to defects and failures, whether the pipe has certain
coating types that provide an adequate level of cathodic protection,
and the design strength of the pipe.
There are also operation and maintenance factors that PHMSA
considers when evaluating pipeline segments for class location change
special permit feasibility. For example, PHMSA doesn't consider for a
Class 1 to Class 3 location change special permit any pipe segments
that operate above 72 percent SMYS. Operators also need to produce a
hydrostatic test record showing the segment was tested to 1.25 times
the MAOP. Also, operators are required to have pipe material records to
document the pipelines diameter, wall thickness, strength, seam type
and coating type. For operators who do not have these records, PHMSA
requires they make these records per the special permit conditions.
PHMSA often requires operators to operate each applicable segment at or
below its existing MAOP as well.
As part of the special permit conditions, operators are required by
PHMSA to incorporate the applicable pipeline segments into their IM
program and inspect them on a regular basis according to the operator's
procedures. As an extension of this requirement, operators must perform
in-line inspections on the applicable segments, and the segments must
not have any significant anomalies that would indicate any systemic
problems. Additionally, PHMSA's published special permit criteria
defines a ``waiver inspection area,'' also known as a ``special permit
inspection area,'' as up to 25 miles of pipe on either side of the
applicable segment. Operators must incorporate these areas into their
IM programs as well and inspect and repair them per the operator's IM
program procedures. Some of the factors PHMSA uses when deciding the
length of special permit inspection areas are based on factors
including what class location the surrounding pipe is in and whether
class location ``clustering'' has been used. For both the special
permit segments and the special permit inspection areas, PHMSA also
typically requires operators to perform assessments and surveys to
identify pipe that may be susceptible to certain issues, especially
seam or cracking issues in the pipe seam or pipe body, based on the
coating type, vintage, or manufacturing of the pipe. Pipelines in the
special permit segments or in the special permit inspection areas that
have had a leak or failure history are also taken into consideration
when PHMSA develops an individual special permit's conditions so as to
prevent similar issues in the future. Further, PHMSA looks at the
enforcement history of an operator applying for a special permit as a
benchmark for how the operator has followed the Federal Pipeline Safety
Regulations when developing the conditions following a special permit
request.
In class location change special permit requests, PHMSA also
ensures that integrity threats to pipelines in special permit segments
and special permit inspection areas are addressed in operator
operations and management plans, including a systematic, ongoing
program to review and remediate pipeline safety concerns. Some of the
typical integrity and safety threats PHMSA would expect operators to
address include pipe coating quality, cathodic protection
effectiveness, stress corrosion and seam cracking, and any long-term
pipeline system flow reversals. To this end, PHMSA often requires
coating condition surveys, the remediation of coating, and cathodic
protection systems for pipelines where the operator has requested a
class location change special permit. Any data gathered on the special
permit area and special permit inspection area would have to be
incorporated into the operator's greater IM program.
PHMSA incorporates these conditions into class location change
special permit requests to ensure that operators meet or exceed the
threshold requirements with equivalent safety to the provisions in the
Federal Pipeline Safety Regulations that are being waived and ensure
that granting the special permit will not be inconsistent with safety.
IV. Pipeline Safety, Regulatory Certainty, and Job Creation Act of
2011--Section 5
On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and
Job Creation Act of 2011 (Pub. L. 112-90) was enacted. Among the many
provisions of the Act, Section 5 required PHMSA to evaluate whether IM
system requirements, or elements thereof, should be expanded beyond
high-consequence areas (HCA) and, with respect to gas transmission
pipeline facilities, whether applying IM program requirements, or
elements thereof, to additional areas would mitigate the need for class
location requirements. PHMSA was required to report the findings of
this evaluation to Congress and was authorized to issue regulations
pursuant to the findings of the report following a prescribed review
period.
A. 2013 Notice of Inquiry: Class Location Requirements
In August 2013, through a Notice of Inquiry, PHMSA solicited
comments on whether expanding IM requirements would mitigate the need
for class locations in line with the Section 5 mandate of the 2011
Pipeline Safety Act.\23\ Several topics were discussed, including
whether class locations should be eliminated and a single design factor
used, whether design factors should be increased for higher class
locations, and whether pipelines without complete material records
should be allowed to use a single design factor if class locations were
to be eliminated.\24\
---------------------------------------------------------------------------
\23\ Federal Register (78 FR 46560, August 1, 2013).
\24\ Regarding these questions, PHMSA received 30 comment
letters, available at www.regulations.gov at docket PHMSA-2013-0161.
---------------------------------------------------------------------------
There was broad consensus among PHMSA's stakeholders that
eliminating class locations entirely would not lead to improvement to
pipeline safety. Further, commenters noted that establishing a single
design factor in lieu of class location designations might be too
complicated to implement. Many commenters noted that any changes in
class location requirements would impact not only the classifications
of many pipelines but would also possibly create several unintended
consequences within part 192, as the class location requirements are
referenced or built upon throughout the natural gas regulations.
Several industry trade groups had suggestions for changing the
class location regulations, and these suggestions were developed
further through subsequent discussions at advisory committee meetings
and at public workshops. The Interstate Natural Gas Association of
America (INGAA) noted that IM should be extended beyond HCAs with the
caveat that PHMSA should examine the effects of such a change on other
areas of the pipeline safety regulations. Along with this, it suggested
that PHMSA revise certain operations and maintenance requirements that
may no longer be necessary given technological advances and IM
activities.
[[Page 36866]]
B. 2014 Pipeline Advisory Committee Meeting, Class Location Workshop,
and Subsequent Comments
On February 25, 2014, PHMSA hosted a joint meeting of the Gas and
Liquid Pipeline Advisory Committees.\25\ At that meeting, PHMSA updated
the committees on its activities regarding the Section 5 mandate of the
2011 Pipeline Safety Act, and committee members and members of the
public provided their comments.
---------------------------------------------------------------------------
\25\ The Pipeline Advisory Committees are statutorily mandated
advisory committees that advise PHMSA on proposed safety standards,
risk assessments, and safety policies for natural gas and hazardous
liquid pipelines (49 U.S.C. 60115). These Committees were
established under the Federal Advisory Committee Act (Pub. L. 92-
463, 5 U.S.C. app. 1-16) and the Federal Pipeline Safety Statutes
(49 U.S.C. chap. 601-603). Each committee consists of 15 members,
with membership divided among Federal and State agency
representatives, the regulated industry, and the public.
---------------------------------------------------------------------------
INGAA, reinforcing its comments on the 2013 Notice of Inquiry,
noted that the original class location definitions in ASME B31.8 were
intended to provide an increased margin of safety for locations of
higher population density and stated that IM is a much better risk
management tool than class locations. INGAA reiterated that it intends
for its members to perform elements of IM on pipelines outside of HCAs.
On April 16, 2014, PHMSA sponsored a Class Location Workshop to
solicit comments on whether applying the gas pipeline IM program
requirements beyond HCAs would mitigate the need for gas pipeline class
location requirements. Presentations were made by representatives from
PHMSA, the National Energy Board of Canada (NEB), National Association
of Pipeline Safety Representatives (NAPSR), pipeline operators,
industry groups, and public interest groups.\26\
---------------------------------------------------------------------------
\26\ Meeting presentations are available online at: https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=95.
---------------------------------------------------------------------------
During the workshop, INGAA representatives noted that the current
class location regulations require changes that result in the
replacement of ``good pipe,'' and the special permit process for class
location changes should be embedded in part 192. Representatives from
the American Gas Association (AGA) noted that applying the current
class location change requirements can cost more than $1 million per
change. AGA claimed the special permit process for class location
changes is burdensome, the renewal process is increasingly complex, and
the outcome is uncertain.\27\ Therefore, AGA suggested eliminating the
special permit process for class location changes and incorporating
specific requirements for special permits into part 192 as part of the
base regulations. AGA recommended two approach methods, one based on IM
and the other using the current class location approach.
---------------------------------------------------------------------------
\27\ PHMSA notes that the special permit process is outlined in
Sec. 190.341 and is no different for the class location regulations
than for any other pipeline safety regulation. Of the 18 special
permits up for renewal from 2010-2017, 9 of them were for class
location changes. When reviewing the class location change permits
up for renewal, PHMSA found no safety reason to extensively modify
any of the prior permits and made no major revisions to any of the
previously imposed safety conditions.
---------------------------------------------------------------------------
Public interest groups including Accufacts and the Pipeline Safety
Trust (PST) pointed out how deeply the concept of class locations is
embedded in part 192, while also noting that IM requirements and class
locations overlap in densely populated areas to provide a redundant,
but necessary, safety regime. The PST also suggested that, in time, the
older class location method potentially could be replaced with an IM
method for regulation. However, the PST noted that incidents and data
suggest there is room for improvement in the IM regulations, as data
shows higher incident rates in HCAs than in non-HCAs, and noted that
pipe installed after 2010 has a higher incident rate than pipe
installed a decade earlier. Similarly, Accufacts noted that the
incident at San Bruno, CA, exposed weaknesses in the operator's IM
program and demonstrated that the consequences resulting from the
incident spread far beyond the potential radius in which they were
expected to occur.\28\ Therefore, Accufacts suggested that shifting the
class location approach to solely an IM approach might decrease the
protection of public safety.
---------------------------------------------------------------------------
\28\ The potential impact radius for the ruptured pipe segment
involved in the San Bruno incident was calculated at 414 feet.
However, the NTSB, in its accident report (NTSB/PAR-11/01), noted
that the subsequent fire damage extended to a radius of about 600
feet from the blast center.
---------------------------------------------------------------------------
Following the Class Location Workshop, INGAA submitted additional
comments to the docket stating that advancements in IM technology and
processes have superseded the need for mandatory pipe replacement
following a class location change. It noted that, in the past, it was
logical to replace a pipeline when class locations changed because of
the widespread belief that thicker pipe would take longer to corrode
and would withstand greater external forces, such as damage from
excavators, before failure. However, given current technology,
improvements in pipe quality, and ongoing regulatory processes such as
IM, operators can mitigate most threats without the need for pipe
replacement. Therefore, INGAA offered an approach to class locations
changes to not require pipe replacement for existing pipelines if pipe
segments meet certain requirements that are in line with current IM
requirements. Specifically, INGAA suggested that pipelines meeting a
``fitness for service'' standard in 18 categories of requirements could
address potential safety concerns and preclude the need for pipe
replacement.\29\ The 18 categories are very similar to the special
permit conditions that PHMSA uses for a Class 1 to 3 location special
permit as noted in the 2004 Federal Register notice.\30\
---------------------------------------------------------------------------
\29\ Those 18 categories were as follows: Baseline Engineering
and Record Assessments--Girth Weld Assessment, Casing Assessment,
Pipe Seam Assessment, Field Coating Assessment, Cathodic Protection,
Interference Currents Control, Close Interval Survey, Stress
Corrosion Cracking Assessments, In-line Inspection Assessments,
Metal Loss Anomaly Management, Dent Anomaly Management, Hard Spots
Anomaly Management. Ongoing Requirements--Integrity Management
Program, Root Cause Analysis for Failure or Leak, Line Markers,
Patrols, Damage Prevention Best Practices, Recordkeeping &
Documentation.
\30\ See also: https://primis.phmsa.dot.gov/classloc/index.htm.
---------------------------------------------------------------------------
C. 2016 Class Location Report
The Pipeline Safety, Regulatory Certainty, and Job Creation Act of
2011 required that PHMSA evaluate whether IM should be expanded beyond
HCAs and whether such expansion would mitigate the need for class
location requirements. In its report titled ``Evaluation of Expanding
Pipeline Integrity Management Beyond High-Consequence Areas and Whether
Such Expansion Would Mitigate the Need for Gas Pipeline Class Location
Requirements,'' \31\ which was submitted to Congress in April 2016
concurrently with the publication of the NPRM titled ``Safety of Gas
Transmission and Gathering Pipelines'' (81 FR 20722), PHMSA noted that
the application of IM program elements, such as assessment and
remediation timeframes, beyond HCAs would not warrant the elimination
of class locations.
---------------------------------------------------------------------------
\31\ https://www.regulations.gov/document?D=PHMSA-2011-0023-0153.
---------------------------------------------------------------------------
PHMSA notes that class locations affect all gas pipelines and are
integral to determining MAOPs; design pressures; pipe wall thickness;
valve spacing; HCAs, in certain cases; and O&M inspection,
surveillance, and repair intervals. While IM measures are a critical
step towards pipeline safety and are important to mitigate risk, the
assessment and remediation of defects do not adequately compensate for
these other aspects of class locations. Thus, as outlined in the
report, PHMSA determined the existing class location
[[Page 36867]]
requirements were appropriate for maintaining pipeline safety and
should be retained. Therefore, any revisions to the class location
requirements would have to be forward-looking (i.e., applying to
pipelines constructed after a certain effective date) and would have to
comport with the existing regulatory regime to provide commensurate
safety if any changes are made to aspects of pipeline safety related to
design and construction, which is where key safety benefits of class
locations are realized.\32\
---------------------------------------------------------------------------
\32\ In its comments following the public workshop on Class
Locations in 2014, INGAA noted that, after further analysis, it
appears that applying the Potential Impact Radius (PIR) method to
existing pipelines may be unworkable.
---------------------------------------------------------------------------
As a part of the continuing discussion on class location changes
and subsequent pipe replacement, PHMSA summarized at the end of the
Class Location Report the concerns operators expressed regarding the
cost of replacing pipe in locations that change from a Class 1 to a
Class 3 location or a Class 2 to a Class 4 location. As discussed
throughout the document, operators submitted that the safe operation of
pipelines constructed in Class 1 locations that later change to Class 3
locations can be achieved using current IM practices.
However, over the past decade, PHMSA observed problems with pipe
and fitting manufacturing quality, including low-strength material;
\33\ construction practices; welding; field coating practices; IM
assessments and reassessment practices; 34 35 and record
documentation practices.36 37 These issues give PHMSA pause
in considering approaches allowing a two-class bump (Class 1 to 3 or
Class 2 to 4) without requiring pipe replacement, especially for
higher-pressure transmission pipelines.
---------------------------------------------------------------------------
\33\ PHMSA has documented pipe material low-strength issues
through an advisory bulletin and the following website link: https://primis.phmsa.dot.gov/lowstrength/index.htm.
\34\ IM and operational procedures and practices were issues in
the Pacific Gas & Electric (PG&E) San Bruno, CA, rupture in
September 2010 and the Enbridge Marshall, MI, rupture in July 2010.
\35\ PHMSA issued Advisory Bulletins ADB-11-01 and ADB-2012-10
to operators regarding IM meaningful metrics and assessments on
January 10, 2011, and December 5, 2012, respectively, which can be
reviewed at: https://phmsa.dot.gov/pipeline/regs/advisory-bulletin.
\36\ PHMSA issued Advisory Bulletin, ADB-12-06, concerning
documentation of MAOP on May 7, 2012, which can be reviewed at:
https://phmsa.dot.gov/pipeline/regs/advisory-bulletin.
\37\ Also note PHMSA's Advisory Bulletin titled ``Deactivation
of Threats,'' issued March 16, 2017 (82 FR 14106).
---------------------------------------------------------------------------
PHMSA stated in the conclusion of its Class Location Report that it
would further evaluate the feasibility and the appropriateness of
alternatives to address issues pertaining to pipe replacement
requirements, continue to reach out to and consider input from all
stakeholders, and consider future rulemaking if a cost-effective and
safety-focused approach to adjusting specific aspects of class location
requirements could be developed to address the issues identified by
industry. In doing so, PHMSA would evaluate alternatives in the context
of other issues it is addressing related to new construction quality-
and safety-management systems and will also consider inspection
findings, IM assessment results, and lessons learned from past
incidents. Therefore, PHMSA has initiated this rulemaking to gain
further information on analyzing the current requirements resulting in
pipe replacement and alternatives to that practice.
V. INGAA Submission on Regulatory Reform--Proposal To Perform IM
Measures in Lieu of Pipe Replacement When Class Locations Change
On July 24, 2017, INGAA submitted comments to a DOT docket
regarding regulatory review actions (Docket No. OST-2017-0057). In its
submission, INGAA estimated that gas transmission pipeline operators
incur annual costs of $200-$300 million \38\ nationwide replacing pipe
solely to satisfy the class location change regulations and requested
PHMSA consider revising the current class location change regulations
to include an alternative beyond pressure reduction, pressure testing,
or pipe replacement.
---------------------------------------------------------------------------
\38\ PHMSA requests further substantiation of this estimate. In
extrapolating the national data, PHMSA estimates this number is the
cost incurred for all pipe replacement projects on transmission
lines, not just those projects triggered in response to class
location changes.
---------------------------------------------------------------------------
INGAA's proposed alternate approach focuses on recurring IM
assessments that would leverage advanced assessment technologies to
determine whether the pipe condition warrants pipe replacement in areas
where the class location has changed. INGAA states that such an
approach would further promote IM processes and principles throughout
the nation's gas transmission pipeline network, improve economic
efficiency by reducing regulatory burden, and help fulfill the purposes
of Section 5 of the 2011 Pipeline Safety Act.
INGAA claims that the current alternatives to pipe replacement
following a class location change do not reflect the substantial
developments in IM processes, technologies, and regulations over the
past 15-plus years. More specifically, in-line inspection (ILI)
technologies, such as high-resolution magnetic flux leakage tools, can
precisely assess the presence of corrosion and other potential defects,
allowing an operator to establish whether a pipeline segment requires
remediation or replacement.\39\
---------------------------------------------------------------------------
\39\ PHMSA notes that ILI and in-the-ditch evaluation
technologies for crack identification are under development and
could further be improved.
---------------------------------------------------------------------------
INGAA further notes that PHMSA's proposed rulemaking titled
``Safety of Gas Transmission and Gathering Pipelines'' aims to expand
IM assessments to newly defined ``Moderate Consequence Areas''
(proposed Sec. 192.710), and such an expansion provides a framework
for developing an alternative for managing class location changes.
INGAA suggests that the costs saved from avoiding pipe replacement
using such an alternative could mitigate, to some degree, part of the
costs of the proposed rulemaking. Additionally, INGAA notes that the
proposed rulemaking contains several new provisions that will require
operators to better manage the integrity of their pipelines by
implementing more preventative and mitigative measures to manage the
threat of corrosion. INGAA states that the inclusion of such corrosion
control measures as a part of a program for managing the integrity of
pipeline segments, including ones that have experienced class location
changes, would further justify the development of an IM-focused
alternative to class location changes.
Based on those statements, INGAA recommends PHMSA develop an
alternative approach to Sec. 192.611 that leverages the proposed Sec.
192.710 for areas outside of HCAs and the IM requirements at Sec.
192.921 to require recurring IM assessments and incorporation of those
affected pipeline segments into IM programs. Further, INGAA suggests
this approach require operators to reconfirm pipeline MAOP in a changed
class location for any pipeline segment without traceable, verifiable,
and complete records of a hydrostatic pressure test supporting the
segment's previous MAOP.
PHMSA acknowledges that the class location change regulations
predate the development of modern pipeline inspection technology such
as ILI, above-ground surveys, and modern integrity management
processes. In fact, it wasn't until the mid-1990s that PHMSA, following
models from other industries such as nuclear power, started to explore
whether a risk-based approach to regulation could improve public and
environmental safety. PHMSA finalized the IM regulations for gas
transmission pipelines on December
[[Page 36868]]
15, 2003,\40\ in response to tragic incidents on pipelines in
Bellingham, WA, in 1999 and near Carlsbad, NM, in 2000, which killed 3
people and 12 people, respectively. The IM regulations designated HCAs
where operators would perform periodic assessments of the condition of
their pipelines and make necessary repairs within specific timeframes
if discovered anomalies met certain criteria. More specifically, the IM
regulations outline the risk-based processes that pipeline operators
must use to identify, prioritize, assess, evaluate, repair, and
validate the integrity of gas transmission pipelines.
---------------------------------------------------------------------------
\40\ 68 FR 69778; Pipeline Safety: Pipeline Integrity Management
in High Consequence Areas (Gas Transmission Pipelines).
---------------------------------------------------------------------------
For many years, the pipeline industry used internal steel brush
devices (``cleaning pigs'') moved by product flow to clean the inside
of their pipelines. This pigging concept was later adapted through the
application of technology to measure and record irregularities in the
pipe and welds that may represent corrosion, cracks, deformations, and
other defects. Now operators use ILI technology (``smart pigging or
ILI'') as a backbone of the modern IM program. ILI tools are inserted
into pipelines at locations, such as near valves or compressor
stations, that have special configurations of pipes and valves where
the ILI tools can be loaded into launchers, the launchers can be closed
and sealed, and the flow of the product the pipeline is carrying can be
directed to launch the tool down the pipeline. A similar setup is
located downstream where the tool is directed out of the main line into
a receiver so that an operator can remove the tool and retrieve the
recorded data for analysis and reporting. ILI tools come in several
different varieties that have distinct advantages and disadvantages
over other methods of pipeline assessment. For instance, while some ILI
tools might be able to reliably determine whether a pipeline has
internal corrosion, the same tool might not be able to determine
whether the pipeline has any crack indications. In selecting the tools
most suitable for inline inspections, pipeline operators must know the
type of threats that are applicable to the pipeline segment. Threats
that ILI tools can identify typically include existing pipe wall
thickness, pipe wall changes, pipe wall loss, cracking, and dents.
At the time the class location regulations were promulgated, it was
logical to replace a pipeline when population growth resulted in a
class location change in order to restore the safety margin appropriate
for that location because the industry did not have the technology that
is available today to learn the in situ material condition of the pipe.
Further, since the existing pipe would not achieve a similar safety
margin as replaced pipe, operators would need to use applicable
inspection technology and pressure testing to ensure pipe has the
correct wall thickness; strength; seam condition; toughness; no
detrimental cracking or corrosion in the pipe body or seam; and a pipe
coating that has not deteriorated or shields cathodic protection
currents to allow corrosion or cracking issues such as girth weld
cracking, stress corrosion cracking, or selective seam weld corrosion.
Currently, operators are not required to inspect pipelines or
otherwise perform IM on those portions of pipelines unless they are
within high consequence areas (HCAs) or the operator otherwise
voluntarily assesses them and performs remediation measures for threats
to the pipeline. As such, while prudent operators may know the
characteristics and conditions of their pipelines outside of HCAs and
can be confident that they can manage class location change
expectations through the performance of IM measures, some operators may
not.
PHMSA notes that while class locations and HCAs both provide
additional protection to areas with high population concentrations,
they were designed for different purposes. Unlike class locations,
which provide blanket levels of safety throughout the nation's pipeline
network at all locations by driving MAOP and design, construction,
testing, and O&M requirements, the purpose of the IM regulations is to
provide a structure for operators to focus their resources on improving
pipeline integrity in the areas where a failure would have the greatest
impact on public safety. Whereas over time the safety margins that
class locations provide can be reduced due to corrosion or other types
of pipe degradation, IM requirements provide a continuing minimum
safety margin for more densely populated areas because operators are
required to inspect and repair those applicable pipelines at a minimum
of every 7 years and more frequently based upon risk assessments of
threats to the segment in the HCA.
PHMSA acknowledges that applying modern IM assessments and
processes could potentially be a comparable alternative to pipe change-
outs. PHMSA notes that if operators perform integrity assessments on
significant portions of non-HCA pipe mileage, PHMSA could further
consider operators using such assessments to determine whether pipe in
a changed class location is fit for service rather than having to
replace it.
PHMSA is concerned, however, that some issues that result in
pipeline failures, including poor construction practices \41\ and
operational maintenance threats, are not always being properly assessed
and mitigated by operators, whether due to lack of technology or other
causes. Further, as the incident at San Bruno in 2010 showed, operators
may not have traceable, verifiable, and complete records of pipe
properties, such as pipe material yield strength, pipe wall thickness,
pipe seam type, pipe and seam toughness, and coating quality, that are
critical and necessary for IM processes and pipeline safety in Class 3
and 4 locations and HCAs where there are higher population densities.
PHMSA also points out that there might be instances where a pipeline
may be in ``good condition'' from a visual standpoint, but it may not
have the initial pipe manufacturing, pipe strength, construction
quality, and O&M history requirements that add the extra level of
safety required by the regulations for the higher population density
area and the MAOP.\42\ Section 192.611 already allows a ``one-class
location'' bump for pipeline class locations that are in satisfactory
physical condition and have the required pressure test.
---------------------------------------------------------------------------
\41\ PHMSA has met with operators constructing new pipelines on
several occasions to discuss issues found during inspection. To
reach out to all members of the pipeline industry, PHMSA hosted a
public workshop in collaboration with our State partners, the
Federal Energy Regulatory Commission (FERC) and Canada's National
Energy Board (NEB) in April 2009. The objective of the workshop was
to inform the public, alert the industry, review lessons learned
from inspections, and to improve new pipeline construction practices
prior to the 2009 construction season. This website makes available
information discussed at the workshop and provides a forum in which
to share additional information about pipeline construction
concerns. This workshop focused on transmission pipeline
construction. https://primis.phmsa.dot.gov/construction/index.htm.
\42\ Note that the potential impact radius (PIR) in Integrity
Management (IM) does not give any criteria to establish the
pipelines operating pressure, anomaly repair criteria, safety
surveys for leaks, 3rd party encroachments, etc. When Class
locations change (from additional dwellings for human occupancy)
from one-level to a higher level there are cut-off levels that may
require a different design factor, pressure test, or maintenance
criteria. For pipe to be replaced the class location change would
have to be from a Class 1 to 3 or Class 2 to 4, which is a large
increase in dwellings along the pipeline.
---------------------------------------------------------------------------
Because of these factors, PHMSA seeks comment on the potential
safety consequences of altering the current class location methodology
and moving to an IM-only method in certain areas.
[[Page 36869]]
VI. Questions for Consideration
PHMSA is requesting comments and information that will be used to
determine if revisions should be made to the Federal Pipeline Safety
Regulations regarding the current requirements operators must meet when
class locations change. The list of questions below is not exhaustive
and represents an effort to help in the formulation of comments. Any
additional information that commenters determine would be beneficial to
this discussion is also welcomed.
Q1--When the population increases along a pipeline route that
requires a class location change as defined at Sec. 192.5, should
PHMSA allow pipe integrity upgrades from Class 1 to Class 3 locations
by methods other than pipe replacement or special permits? \43\ Why or
why not?
---------------------------------------------------------------------------
\43\ Sections involving class location requirements include
Sec. Sec. 192.5, 192.609, 192.611, 192.619 and 192.620.
---------------------------------------------------------------------------
1a.--Should part 192 continue to require pipe integrity upgrades
when class locations change from Class 1 to Class 3 locations or Class
2 to 4 locations? Why or why not?
1b.--Should part 192 continue to require pipe integrity upgrades
from Class 1 to Class 3 locations for the ``cluster rule'' (see Sec.
192.5(c)) when 10 or fewer buildings intended for human occupancy have
been constructed along the pipeline segment? Why or why not?
1c.--Should part 192 continue to require pipe integrity upgrades
for grandfathered pipe (e.g., pipe segments without a pressure test or
with an inadequate pressure test, operating pressures above 72% SMYS,
or inadequate or missing material records; see Sec. 192.619(c))? Why
or why not?
Q2--Should PHMSA give operators the option of performing certain IM
measures in lieu of the existing measures (pipe replacement, lower the
operating pressure, or pressure test at a higher pressure; see Sec.
192.611) when class locations change from Class 1 to Class 3 due to
population growth within the sliding mile? Why or why not?
2a.--If so, what, if any, additional integrity management and
maintenance approaches or safety measures should be applied to offset
the impact on safety these proposals might create?
Q3--Should PHMSA give operators the option of performing certain IM
measures in lieu of the existing measures (pipe replacement with a more
conservative design safety factor or a combination of pressure test and
lower MAOP) when class locations change due to additional structures
being built outside of clustered areas within the sliding mile, if
operators are using the cluster adjustment to class locations per Sec.
192.5(c)(2)? Why or why not?
3a.--If so, what, if any, additional integrity management and
maintenance approaches or safety measures should be applied to offset
the impact on safety these proposals might create?
3b.--At what intervals and in what timeframes should operators be
required to assess these pipelines and perform remediation measures?
Q4--If PHMSA allows operators to perform certain IM measures in
lieu of pipe replacement when class locations change from Class 1 to
Class 3, should some sort of ``fitness for service'' standard determine
which pipelines are eligible? Why or why not?
4a.--If so, what factors should make a pipeline eligible or
ineligible?
(i) Should grandfathered pipe (lacking records, including pressure
test or material records) or pipe operating above 72% SMYS be eligible?
Why or why not?
(ii) Should pipe that has experienced an in-service failure, was
manufactured with a material or seam welding process during a time or
by a manufacturer where there are now known integrity issues or has
lower toughness in the pipe and weld seam (Charpy impact value) be
eligible? Should pipe with a failure or leak history be eligible? Why
or why not?
(iii) Should pipe that contains or is susceptible to cracking,
including in the body, seam, or girth weld, or having disbonded coating
or CP shielding coatings be eligible? Are there coating types that
should disqualify pipe? Should some types of pipe, such as lap-welded,
flash-welded, or low-frequency electric resistance welded pipe be
ineligible? Should pipe where the seam type is unknown be ineligible?
Why or why not?
(iv) Should pipe with significant corrosion (wall loss) be eligible
for certain IM measures, or should it be replaced? Why or why not?
(v) Should anomalies be repaired similar to IM, allowed to grow to
only a 10-percent safety factor \44\ (Sec. 192.933(d)) before
remediation in high population areas such as Class 2, 3 and 4
locations, or should they have an increased safety factor for
remediation should these class location factors be eliminated? Why or
why not?
---------------------------------------------------------------------------
\44\ Section 192.933 has anomaly repair requirements based upon
a predicted failure pressure being less than or equal to 1.1 times
the MAOP.
---------------------------------------------------------------------------
(vi) Should pipe that has been damaged (dented) or has lost ground
cover due to 3rd party activity (excavation or other) be eligible? Why
or why not?
(vii) Should pipe lacking cathodic protection due to disbonded
coating be eligible? Why or why not?
(viii) Should pipe with properties such as low frequency electric
resistance weld (LF-ERW), lap welded, or other seam types that have a
history of seam failure due to poor manufacturing properties or seam
types that have a derating factor below 1.0 be eligible? Why or why
not?
4b.--Should PHMSA base any proposed requirements off its criteria
used for considering class location change waivers (69 FR 38948; June
29, 2004), including the age and manufacturing and construction
processes of the pipe, and O&M history? Why or why not?
4c.--In the 2004 Federal Register notice (69 FR 38948), PHMSA
outlines certain requirements pipelines must meet to be eligible for
waiver consideration, including no bare pipe or pipe with wrinkle
bends, records of a hydrostatic test to at least 1.25 times MAOP,
records of ILI runs with no significant anomalies that would indicate
systemic problems, and agreement that up to 25 miles of pipe both
upstream and downstream of the waiver location must be included in the
operator's IM program and periodically inspected using ILI technology.
Further, the criteria provides no waivers for segments changing to
Class 4 locations or for pipe changing to a Class 3 location that is
operating above 72% SMYS. Should PHMSA require operators and pipelines
to meet the threshold conditions outlined earlier in this document
(Section 3A; ``Class Location Change Special Permits--Special Permit
Conditions) or other thresholds to be eligible for a waiver when class
locations change? Why or why not?
Q5--As it is critical for operators to have traceable, verifiable,
and complete (TVC) records to perform IM, should operators be required
to have TVC records as a prerequisite for performing IM measures on
segments instead of replacing pipe when class locations change? Why or
why not?
5a.--If so, what records should be necessary and why? Should
records include pipe properties, including yield strength, seam type,
and wall thickness; coating type; O&M history; leak and failure
history; pressure test records; MAOP; class location; depth of cover;
and ability to be in-line inspected?
5b.--If operators do not have TVC records for affected segments and
TVC records were a prerequisite for performing IM measures on pipeline
[[Page 36870]]
segments in lieu of replacing pipe, how should those records be
obtained, and when should the deadline for obtaining those records be?
Q6--Should PHMSA incorporate its special permit conditions
regarding class location changes into the regulations, and would this
incorporation satisfy the need for alternative approaches? Why or why
not? (Examples of typical PHMSA class location special permit
conditions can be found at https://primis.phmsa.dot.gov/classloc/documents.htm.)
6a.--What, if any, special permit conditions could be incorporated
into the regulations to provide regulatory certainty and public safety
in these high population density areas (Class 2, 3, and 4)?
Q7--For all new and replaced pipelines, to what extent are
operators consulting growth and development plans to avoid potentially
costly pipe change-outs in the future?
Q8--What is the amount of pipeline mileage per year being replaced
due to class location changes for pipelines: (1) Greater than 24 inches
in diameter, (2) 16-24 inches in diameter, and (3) less than 16 inches
in diameter?
8a.--Of this mileage, how much is being replaced due to class
locations changing when additional structures for human occupancy are
built near clustered areas, if operators are using the cluster
adjustment to class locations per Sec. 192.5(c)(2)?
8b.--At how many distinct locations are pipe replacements occurring
due to class location changes and that involve pipe with these
diameters?
8c.--What is the average amount of pipe (in miles) being replaced
and cost of replacement at the locations described in question 8b. and
for these diameter ranges due to class location changes?
Q9--Should any additional pipeline safety equipment, preventative
and mitigative measures, or prescribed standard pipeline predicted
failure pressures more conservative than in the IM regulations be
required if operators do not replace pipe when class locations change
due to population growth and perform IM measures instead? Why or why
not?
9a.--Should operators be required to install rupture-mitigation
valves or equivalent technology? Why or why not?
9b.--Should operators be required to install SCADA systems for
impacted pipeline segments? Why or why not?
Q10--Should there be any maximum diameter, pressure, or potential
impact radius (PIR) limits that should disallow operators from using IM
principles in lieu of the existing requirements when class locations
change? For instance, PHMSA has seen construction projects where
operators are putting in 42-inch-diameter pipe designed to operate at
up to 3,000 psig. The PIR for that pipeline would be over 1,587 feet,
which would mean the total blast diameter would be more than 3,174
feet.
VII. Regulatory Notices
A. Executive Order 12866, Executive Order 13563, Executive Order 13771,
and DOT Regulatory Policies and Procedures
Executive Orders 12866 and 13563 require agencies to regulate in
the ``most cost-effective manner,'' to make a ``reasoned determination
that the benefits of the intended regulation justify its costs,'' and
to develop regulations that ``impose the least burden on society.''
Executive Order 13771 (``Reducing Regulation and Controlling Regulatory
Costs''), issued January 30, 2017, provides that ``it is essential to
manage the costs associated with the governmental imposition of private
expenditures required to comply with Federal regulations.'' One way to
manage the costs of rulemakings is to propose new regulations that are
deregulatory in nature, i.e. regulations that reduce the cost of
regulatory compliance. PHMSA seeks information on whether this
rulemaking could result in a deregulatory action under E.O. 13771,
meaning that a potential final rule could have ``total costs less than
zero.'' \45\ We therefore request comments, including specific data if
possible, concerning the costs and benefits of revising the pipeline
safety regulations to accommodate any of the changes suggested in the
advance notice.
---------------------------------------------------------------------------
\45\ See OMB Memorandum M-17-21, ``Guidance Implementing
Executive Order 13771, Titled `Reducing Regulation and Controlling
Regulatory Costs,' '' (April 5, 2017).
---------------------------------------------------------------------------
B. Executive Order 13132: Federalism
Executive Order 13132 requires agencies to assure meaningful and
timely input by State and local officials in the development of
regulatory policies that may have a substantial, direct effect on the
States, on the relationship between the national government and the
States, or on the distribution of power and responsibilities among the
various levels of government. PHMSA is inviting comments on the effect
a possible rulemaking adopting any of the amendments discussed in this
document may have on the relationship between national government and
the States.
C. Regulatory Flexibility Act
Under the Regulatory Flexibility Act of 1980 (5 U.S.C. 601 et
seq.), PHMSA must consider whether a proposed rule would have a
significant impact on a substantial number of small entities. ``Small
entities'' include small businesses, not-for-profit organizations that
are independently owned and operated and are not dominant in their
fields, and governmental jurisdictions with populations under 50,000.
If your business or organization is a small entity and if adoption of
any of the amendments discussed in this ANPRM could have a significant
economic impact on your operations, please submit a comment to explain
how and to what extent your business or organization could be affected
and whether there are alternative approaches to the regulations the
agency should consider that would minimize any significant negative
impact on small business while still meeting the agency's statutory
objectives.
D. National Environmental Policy Act
The National Environmental Policy Act of 1969 requires Federal
agencies to consider the consequences of Federal actions and that they
prepare a detailed statement analyzing them if the action significantly
affects the quality of the human environment. Interested parties are
invited to address the potential environmental impacts of this ANPRM,
including comments about compliance measures that would provide greater
benefit to the human environment or any alternative actions the agency
could take that would provide beneficial impacts.
E. Executive Order 13175: Consultation and Coordination with Indian
Tribal Governments
Executive Order 13175 requires agencies to assure meaningful and
timely input from Indian Tribal Government representatives in the
development of rules that ``significantly or uniquely affect'' Indian
communities and that impose ``substantial and direct compliance costs''
on such communities. We invite Indian Tribal governments to provide
comments on any aspect of this ANPRM that may affect Indian
communities.
F. Paperwork Reduction Act
Under 5 CFR part 1320, PHMSA analyzes any paperwork burdens if any
information collection will be required by a rulemaking. We invite
comment on the need for any collection of
[[Page 36871]]
information and paperwork burdens related to this ANPRM.
G. Privacy Act Statement
Anyone can search the electronic form of comments received in
response to any of our dockets by the name of the individual submitting
the comment (or signing the comment, if submitted on behalf of an
association, business, labor union, etc.). DOT's complete Privacy Act
Statement was published in the Federal Register on April 11, 2000 (65
FR 19477).
Issued in Washington, DC, on July 25, 2018, under authority
delegated in 49 CFR 1.97.
Alan K. Mayberry,
Associate Administrator for Pipeline Safety.
[FR Doc. 2018-16376 Filed 7-30-18; 8:45 am]
BILLING CODE 4910-60-P
