(a) How does an operator calculate the alternative maximum allowable operating pressure? An operator calculates the alternative maximum allowable operating pressure by using different factors in the same formulas used for calculating maximum allowable operating pressure under Sec. 192.619(a) as follows:
(1) In determining the alternative design pressure under Sec. 192.105, use a design factor determined in accordance with Sec. 192.111(b), (c), or (d) or, if none of these paragraphs apply, in accordance with the following table: ------------------------------------------------------------------------
Alternative
Class location design factor
(F)------------------------------------------------------------------------1....................................................... 0.802....................................................... 0.673....................................................... 0.56------------------------------------------------------------------------
(i) For facilities installed prior to December 22, 2008, for which Sec. 192.111(b), (c), or (d) applies, use the following design factors as alternatives for the factors specified in those paragraphs: Sec. 192.111(b)-0.67 or less; 192.111(c) and (d)-0.56 or less.
(ii) [Reserved]
(2) The alternative maximum allowable operating pressure is the lower of the following:
(i) The design pressure of the weakest element in the pipeline segment, determined under subparts C and D of this part.
(ii) The pressure obtained by dividing the pressure to which the pipeline segment was tested after construction by a factor determined in the following table: ------------------------------------------------------------------------
Alternative
Class location test factor------------------------------------------------------------------------1....................................................... 1.252....................................................... \1\ 1.503....................................................... 1.50------------------------------------------------------------------------\1\ For Class 2 alternative maximum allowable operating pressure
segments installed prior to December 22, 2008 the alternative test
factor is 1.25.
(b) When may an operator use the alternative maximum allowable operating pressure calculated under paragraph (a) of this section? An operator may use an alternative maximum allowable operating pressure calculated under paragraph (a) of this section if the following conditions are met:
(1) The pipeline segment is in a Class 1, 2, or 3 location;
(2) The pipeline segment is constructed of steel pipe meeting the additional design requirements in Sec. 192.112;
(3) A supervisory control and data acquisition system provides remote monitoring and control of the pipeline segment. The control provided must include monitoring of pressures and flows, monitoring compressor start-ups and shut-downs, and remote closure of valves per paragraph (d)(3) of this section;
(4) The pipeline segment meets the additional construction requirements described in Sec. 192.328;
(5) The pipeline segment does not contain any mechanical couplings used in place of girth welds;
(6) If a pipeline segment has been previously operated, the segment has not experienced any failure during normal operations indicative of a systemic fault in material as determined by a root cause analysis, including metallurgical examination of the failed pipe. The results of this root cause analysis must be reported to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operation at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and
(7) At least 95 percent of girth welds on a segment that was constructed prior to December 22, 2008, must have been non-destructively examined in accordance with Sec. 192.243(b) and (c).
(c) What is an operator electing to use the alternative maximum allowable operating pressure required to do? If an operator elects to use the alternative maximum allowable operating pressure calculated under paragraph (a) of this section for a pipeline segment, the operator must do each of the following:
(1) For pipelines already in service, notify the PHMSA pipeline safety regional office where the pipeline is in service of the intention to use the alternative pressure at least 180 days before operating at the alternative MAOP. For new pipelines, notify the PHMSA pipeline safety regional office of planned alternative MAOP design and operation at least 60 days prior to the earliest start date of either pipe manufacturing or construction activities. An operator must also notify the state pipeline safety authority when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state.
(2) Certify, by signature of a senior executive officer of the company, as follows:
(i) The pipeline segment meets the conditions described in paragraph (b) of this section; and
(ii) The operating and maintenance procedures include the additional operating and maintenance requirements of paragraph (d) of this section; and
(iii) The review and any needed program upgrade of the damage prevention program required by paragraph (d)(4)(v) of this section has been completed.
(3) Send a copy of the certification required by paragraph (c)(2) of this section to each PHMSA pipeline safety regional office where the pipeline is in service 30 days prior to operating at the alternative MAOP. An operator must also send a copy to a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.
(4) For each pipeline segment, do one of the following:
(i) Perform a strength test as described in Sec. 192.505 at a test pressure calculated under paragraph (a) of this section or
(ii) For a pipeline segment in existence prior to December 22, 2008, certify, under paragraph (c)(2) of this section, that the strength test performed under Sec. 192.505 was conducted at test pressure calculated under paragraph (a) of this section, or conduct a new strength test in accordance with paragraph (c)(4)(i) of this section.
(5) Comply with the additional operation and maintenance requirements described in paragraph (d) of this section.
(6) If the performance of a construction task associated with implementing alternative MAOP that occurs after December 22, 2008, can affect the integrity of the pipeline segment, treat that task as a ``covered task'', notwithstanding the definition in Sec. 192.801(b) and implement the requirements of subpart N as appropriate.
(7) Maintain, for the useful life of the pipeline, records demonstrating compliance with paragraphs (b), (c)(6), and (d) of this section.
(8) A Class 1 and Class 2 location can be upgraded one class due to class changes per Sec. 192.611(a). All class location changes from Class 1 to Class 2 and from Class 2 to Class 3 must have all anomalies evaluated and remediated per: The ``original pipeline class grade'' Sec. 192.620(d)(11) anomaly repair requirements; and all anomalies with a wall loss equal to or greater than 40 percent must be excavated and remediated. Pipelines in Class 4 may not operate at an alternative MAOP.
(d) What additional operation and maintenance requirements apply to operation at the alternative maximum allowable operating pressure? In addition to compliance with other applicable safety standards in this part, if an operator establishes a maximum allowable operating pressure for a pipeline segment under paragraph (a) of this section, an operator must comply with the additional operation and maintenance requirements as follows: ------------------------------------------------------------------------
To address increased risk of a
maximum allowable operating
pressure based on higher stress Take the following additional step:
(1) Identifying and evaluating Develop a threat matrix consistent
threats. with Sec. 192.917 to do the
following:
(i) Identify and compare the
increased risk of operating the
pipeline at the increased stress
level under this section with
conventional operation; and
(ii) Describe and implement
procedures used to mitigate the
(i) Recalculate the potential impact
circle as defined in Sec. 192.903
to reflect use of the alternative
maximum operating pressure
calculated under paragraph (a) of
this section and pipeline operating
conditions; and
(ii) In implementing the public
education program required under
Sec. 192.616, perform the
following:
(A) Include persons occupying
property within 220 yards of the
centerline and within the potential
impact circle within the targeted
audience; and
(B) Include information about the
integrity management activities
performed under this section within
the message provided to the
audience.(3) Responding to an emergency in (i) Ensure that the identification
an area defined as a high of high consequence areas reflects
consequence area in Sec. 192.903. the larger potential impact circle
recalculated under paragraph
(d)(2)(i) of this section.
(2)(i) of this section.
(i) of this section.
(ii) If personnel response time to
mainline valves on either side of
the high consequence area exceeds
one hour (under normal driving
conditions and speed limits) from
the time the event is identified in
the control room, provide remote
valve control through a supervisory
control and data acquisition
(SCADA) system, other leak
detection system, or an alternative
method of control.
(iii) Remote valve control must
include the ability to close and
monitor the valve position (open or
closed), and monitor pressure
upstream and downstream.
(iv) A line break valve control
system using differential pressure,
rate of pressure drop or other
widely-accepted method is an
acceptable alternative to remote
(i) Patrol the right-of-way at
intervals not exceeding 45 days,
but at least 12 times each calendar
year, to inspect for excavation
activities, ground movement, wash
outs, leakage, or other activities
or conditions affecting the safety
operation of the pipeline.
(ii) Develop and implement a plan to
monitor for and mitigate
occurrences of unstable soil and
ground movement.
(iii) If observed conditions
indicate the possible loss of
cover, perform a depth of cover
study and replace cover as
necessary to restore the depth of
cover or apply alternative means to
provide protection equivalent to
the originally-required depth of
cover.
(iv) Use line-of-sight line markers
satisfying the requirements of Sec.
192.707(d) except in agricultural
areas, large water crossings or
swamp, steep terrain, or where
prohibited by Federal Energy
Regulatory Commission orders,
permits, or local law.
(v) Review the damage prevention
program under Sec. 192.614(a) in
light of national consensus
practices, to ensure the program
provides adequate protection of the
right-of-way. Identify the
standards or practices considered
in the review, and meet or exceed
those standards or practices by
incorporating appropriate changes
into the program.
(vi) Develop and implement a right-
of-way management plan to protect
the pipeline segment from damage
due to excavation activities.(5) Controlling internal corrosion (i) Develop and implement a program
to monitor for and mitigate the
presence of, deleterious gas stream
constituents.
(ii) At points where gas with
potentially deleterious
contaminants enters the pipeline,
use filter separators or separators
and gas quality monitoring
equipment.
(iii) Use gas quality monitoring
equipment that includes a moisture
analyzer, chromatograph, and
periodic hydrogen sulfide sampling.
(iv) Use cleaning pigs and sample
accumulated liquids. Use inhibitors
when corrosive gas or liquids are
present.
(v) Address deleterious gas stream
constituents as follows:
(A) Limit carbon dioxide to 3
percent by volume;
(B) Allow no free water and
otherwise limit water to seven
pounds per million cubic feet of
gas; and
(C) Limit hydrogen sulfide to 1.0
grain per hundred cubic feet (16
ppm) of gas, where the hydrogen
sulfide is greater than 0.5 grain
per hundred cubic feet (8 ppm) of
gas, implement a pigging and
inhibitor injection program to
address deleterious gas stream
constituents, including follow-up
sampling and quality testing of
liquids at receipt points.
(vi) Review the program at least
quarterly based on the gas stream
experience and implement
adjustments to monitor for, and
mitigate the presence of,
deleterious gas stream
constituents.(6) Controlling interference that (i) Prior to operating an existing
can impact external corrosion. pipeline segment at an alternate
maximum allowable operating
pressure calculated under this
section, or within six months after
placing a new pipeline segment in
service at an alternate maximum
allowable operating pressure
calculated under this section,
address any interference currents
on the pipeline segment.
(ii) To address interference
currents, perform the following:
(A) Conduct an interference survey
to detect the presence and level of
any electrical current that could
impact external corrosion where
interference is suspected;
(B) Analyze the results of the
survey; and
(C) Take any remedial action needed
within 6 months after completing
the survey to protect the pipeline
segment from deleterious current.(7) Confirming external corrosion (i) Within six months after placing
control through indirect the cathodic protection of a new
assessment. pipeline segment in operation, or
within six months after certifying
a segment under Sec. 192.620(c)(1)
of an existing pipeline segment
under this section, assess the
adequacy of the cathodic protection
through an indirect method such as
close-interval survey, and the
integrity of the coating using
direct current voltage gradient
(DCVG) or alternating current
voltage gradient (ACVG).
(ii) Remediate any construction
damaged coating with a voltage drop
classified as moderate or severe
(IR drop greater than 35% for DCVG
or 50 dB[micro]v for ACVG) under
section 4 of NACE RP-0502-2002
(incorporated by reference, see
Sec. 192.7).
(iii) Within six months after
completing the baseline internal
inspection required under paragraph
(d)(9) of this section, integrate
(9) of this section, integrate
the results of the indirect
assessment required under paragraph
(d)(7)(i) of this section with the
(7)(i) of this section with the
(i) of this section with the
results of the baseline internal
inspection and take any needed
remedial actions.
(iv) For all pipeline segments in
high consequence areas, perform
periodic assessments as follows:
(A) Conduct periodic close interval
surveys with current interrupted to
confirm voltage drops in
association with periodic
assessments under subpart O of this
part.
(B) Locate pipe-to-soil test
stations at half-mile intervals
within each high consequence area
ensuring at least one station is
within each high consequence area,
if practicable.
(C) Integrate the results with those
of the baseline and periodic
assessments for integrity done
under paragraphs (d)(9) and (d)(10)
of this section.(8) Controlling external corrosion (i) If an annual test station
through cathodic protection. reading indicates cathodic
protection below the level of
protection required in subpart I of
this part, complete remedial action
within six months of the failed
reading or notify each PHMSA
pipeline safety regional office
where the pipeline is in service
demonstrating that the integrity of
the pipeline is not compromised if
the repair takes longer than 6
months. An operator must also
notify a State pipeline safety
authority when the pipeline is
located in a State where PHMSA has
an interstate agent agreement, or
an intrastate pipeline is regulated
by that State; and
(ii) After remedial action to
address a failed reading, confirm
restoration of adequate corrosion
control by a close interval survey
on either side of the affected test
station to the next test station
unless the reason for the failed
reading is determined to be a
rectifier connection or power input
problem that can be remediated and
otherwise verified.
(iii) If the pipeline segment has
been in operation, the cathodic
protection system on the pipeline
segment must have been operational
within 12 months of the completion
of construction.(9) Conducting a baseline (i) Except as provided in paragraph
assessment of integrity. (d)(9)(iii) of this section, for a
new pipeline segment operating at
the new alternative maximum
allowable operating pressure,
perform a baseline internal
inspection of the entire pipeline
segment as follows:
(A) Assess using a geometry tool
after the initial hydrostatic test
and backfill and within six months
after placing the new pipeline
segment in service; and
(B) Assess using a high resolution
magnetic flux tool within three
years after placing the new
pipeline segment in service at the
alternative maximum allowable
operating pressure.
(ii) Except as provided in paragraph
(d)(9)(iii) of this section, for an
(9)(iii) of this section, for an
(iii) of this section, for an
existing pipeline segment, perform
a baseline internal assessment
using a geometry tool and a high
resolution magnetic flux tool
before, but within two years prior
to, raising pressure to the
alternative maximum allowable
operating pressure as allowed under
this section.
(iii) If headers, mainline valve by-
passes, compressor station piping,
meter station piping, or other
short portion of a pipeline segment
operating at alternative maximum
allowable operating pressure cannot
accommodate a geometry tool and a
high resolution magnetic flux tool,
use direct assessment (per Sec.
192.925, Sec. 192.927 and/or Sec.
192.929) or pressure testing (per
subpart J of this part) to assess
that portion.(10) Conducting periodic (i) Determine a frequency for
assessments of integrity. subsequent periodic integrity
assessments as if all the
alternative maximum allowable
operating pressure pipeline
segments were covered by subpart O
of this part and
(ii) Conduct periodic internal
inspections using a high resolution
magnetic flux tool on the frequency
determined under paragraph
(d)(10)(i) of this section, or
(10)(i) of this section, or
(i) of this section, or
(iii) Use direct assessment (per
Sec. 192.925, Sec. 192.927 and/or
Sec. 192.929) or pressure testing
(per subpart J of this part) for
periodic assessment of a portion of
a segment to the extent permitted
for a baseline assessment under
paragraph (d)(9)(iii) of this
(i) Perform the following when
evaluating an anomaly:
(A) Use the most conservative
calculation for determining
remaining strength or an
alternative validated calculation
based on pipe diameter, wall
thickness, grade, operating
pressure, operating stress level,
and operating temperature: and
(B) Take into account the tolerances
of the tools used for the
inspection.
(ii) Repair a defect immediately if
any of the following apply:
(A) The defect is a dent discovered
during the baseline assessment for
integrity under paragraph (d)(9) of
this section and the defect meets
the criteria for immediate repair
in Sec. 192.309(b).
(B) The defect meets the criteria
for immediate repair in Sec.
192.933(d).
(C) The alternative maximum
allowable operating pressure was
based on a design factor of 0.67
under paragraph (a) of this section
and the failure pressure is less
than 1.25 times the alternative
maximum allowable operating
pressure.
(D) The alternative maximum
allowable operating pressure was
based on a design factor of 0.56
under paragraph (a) of this section
and the failure pressure is less
than or equal to 1.4 times the
alternative maximum allowable
operating pressure.
(iii) If paragraph (d)(11)(ii) of
this section does not require
immediate repair, repair a defect
within one year if any of the
following apply:
(A) The defect meets the criteria
for repair within one year in Sec.
192.933(d).
(B) The alternative maximum
allowable operating pressure was
based on a design factor of 0.80
under paragraph (a) of this section
and the failure pressure is less
than 1.25 times the alternative
maximum allowable operating
pressure.
(C) The alternative maximum
allowable operating pressure was
based on a design factor of 0.67
under paragraph (a) of this section
and the failure pressure is less
than 1.50 times the alternative
maximum allowable operating
pressure.
(D) The alternative maximum
allowable operating pressure was
based on a design factor of 0.56
under paragraph (a) of this section
and the failure pressure is less
than or equal to 1.80 times the
alternative maximum allowable
operating pressure.
(iv) Evaluate any defect not
required to be repaired under
paragraph (d)(11)(ii) or (iii) of
this section to determine its
growth rate, set the maximum
interval for repair or re-
inspection, and repair or re-
inspect within that interval.------------------------------------------------------------------------
(e) Is there any change in overpressure protection associated with operating at the alternative maximum allowable operating pressure? Notwithstanding the required capacity of pressure relieving and limiting stations otherwise required by Sec. 192.201, if an operator establishes a maximum allowable operating pressure for a pipeline segment in accordance with paragraph (a) of this section, an operator must:
(1) Provide overpressure protection that limits mainline pressure to a maximum of 104 percent of the maximum allowable operating pressure; and
(2) Develop and follow a procedure for establishing and maintaining accurate set points for the supervisory control and data acquisition system. [73 FR 62177, Oct. 17, 2008, as amended by Amdt. 192-111, 74 FR 62505, Nov. 30, 2009; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]