For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure (MAOP) calculated under Sec. 192.620, a segment must meet the following additional design requirements. Records for alternative MAOP must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements: ------------------------------------------------------------------------
The pipeline segment must meet these
(a) General standards for the (1) The plate, skelp, or coil used
steel pipe. for the pipe must be micro-alloyed,
fine grain, fully killed,
continuously cast steel with
calcium treatment.
(2) The carbon equivalents of the
steel used for pipe must not exceed
0.25 percent by weight, as
calculated by the Ito-Bessyo
formula (Pcm formula) or 0.43
percent by weight, as calculated by
the International Institute of
Welding (IIW) formula.
(3) The ratio of the specified
outside diameter of the pipe to the
specified wall thickness must be
less than 100. The wall thickness
or other mitigative measures must
prevent denting and ovality
anomalies during construction,
strength testing and anticipated
operational stresses.
(4) The pipe must be manufactured
using API Spec 5L, product
specification level 2 (incorporated
by reference, see Sec. 192.7) for
maximum operating pressures and
minimum and maximum operating
temperatures and other requirements
(1) The toughness properties for
pipe must address the potential for
initiation, propagation and arrest
of fractures in accordance with:
(i) API Spec 5L (incorporated by
reference, see Sec. 192.7); or
(ii) American Society of Mechanical
Engineers (ASME) B31.8
(incorporated by reference, see
Sec. 192.7); and
(iii) Any correction factors needed
to address pipe grades, pressures,
temperatures, or gas compositions
not expressly addressed in API Spec
5L , product specification level 2
or ASME B31.8 (incorporated by
reference, see Sec. 192.7).
(2) Fracture control must:
(i) Ensure resistance to fracture
initiation while addressing the
full range of operating
temperatures, pressures, gas
compositions, pipe grade and
operating stress levels, including
maximum pressures and minimum
temperatures for shut-in
conditions, that the pipeline is
expected to experience. If these
parameters change during operation
of the pipeline such that they are
outside the bounds of what was
considered in the design
evaluation, the evaluation must be
reviewed and updated to assure
continued resistance to fracture
initiation over the operating life
of the pipeline;
(ii) Address adjustments to
toughness of pipe for each grade
used and the decompression behavior
of the gas at operating parameters;
(iii) Ensure at least 99 percent
probability of fracture arrest
within eight pipe lengths with a
probability of not less than 90
percent within five pipe lengths;
and
(iv) Include fracture toughness
testing that is equivalent to that
described in supplementary
requirements SR5A, SR5B, and SR6 of
API Specification 5L (incorporated
by reference, see Sec. 192.7) and
ensures ductile fracture and arrest
with the following exceptions:
(A) The results of the Charpy impact
test prescribed in SR5A must
indicate at least 80 percent
minimum shear area for any single
test on each heat of steel; and
(B) The results of the drop weight
test prescribed in SR6 must
indicate 80 percent average shear
area with a minimum single test
result of 60 percent shear area for
any steel test samples. The test
results must ensure a ductile
fracture and arrest.
(3) If it is not physically possible
to achieve the pipeline toughness
properties of paragraphs (b)(1) and
(2) of this section, additional
design features, such as mechanical
or composite crack arrestors and/or
heavier walled pipe of proper
design and spacing, must be used to
ensure fracture arrest as described
in paragraph (b)(2)(iii) of this
(1) There must be an internal
quality management program at all
mills involved in producing steel,
plate, coil, skelp, and/or rolling
pipe to be operated at alternative
MAOP. These programs must be
structured to eliminate or detect
defects and inclusions affecting
pipe quality.
(2) A mill inspection program or
internal quality management program
must include (i) and either (ii) or
(iii):
(i) An ultrasonic test of the ends
and at least 35 percent of the
surface of the plate/coil or pipe
to identify imperfections that
impair serviceability such as
laminations, cracks, and
inclusions. At least 95 percent of
the lengths of pipe manufactured
must be tested. For all pipelines
designed after December 22, 2008,
the test must be done in accordance
with ASTM A578/A578M Level B, or
API Spec 5L Paragraph 7.8.10
(incorporated by reference, see
Sec. 192.7) or equivalent method,
and either
(ii) A macro etch test or other
equivalent method to identify
inclusions that may form centerline
segregation during the continuous
casting process. Use of sulfur
prints is not an equivalent method.
The test must be carried out on the
first or second slab of each
sequence graded with an acceptance
criteria of one or two on the
Mannesmann scale or equivalent; or
(iii) A quality assurance monitoring
program implemented by the operator
that includes audits of: (a) all
steelmaking and casting facilities,
(b) quality control plans and
manufacturing procedure
specifications, (c) equipment
maintenance and records of
conformance, (d) applicable casting
superheat and speeds, and (e)
centerline segregation monitoring
records to ensure mitigation of
centerline segregation during the
(1) There must be a quality
assurance program for pipe seam
welds to assure tensile strength
provided in API Spec 5L
(incorporated by reference, see
Sec. 192.7) for appropriate
grades.
(2) There must be a hardness test,
using Vickers (Hv10) hardness test
method or equivalent test method,
to assure a maximum hardness of 280
Vickers of the following:
(i) A cross section of the weld seam
of one pipe from each heat plus one
pipe from each welding line per
day; and
(ii) For each sample cross section,
a minimum of 13 readings (three for
each heat affected zone, three in
the weld metal, and two in each
section of pipe base metal).
(3) All of the seams must be
ultrasonically tested after cold
expansion and mill hydrostatic
(1) All pipe to be used in a new
pipeline segment installed after
October 1, 2015, must be
hydrostatically tested at the mill
at a test pressure corresponding to
a hoop stress of 95 percent SMYS
for 10 seconds.
(2) Pipe in operation prior to
December 22, 2008, must have been
hydrostatically tested at the mill
at a test pressure corresponding to
a hoop stress of 90 percent SMYS
for 10 seconds.
(3) Pipe in operation on or after
December 22, 2008, but before
October 1, 2015, must have been
hydrostatically tested at the mill
at a test pressure corresponding to
a hoop stress of 95 percent SMYS
for 10 seconds. The test pressure
may include a combination of
internal test pressure and the
allowance for end loading stresses
imposed by the pipe mill
hydrostatic testing equipment as
allowed by ``ANSI/API Spec 5L''
(incorporated by reference, see
(1) The pipe must be protected
against external corrosion by a non-
shielding coating.
(2) Coating on pipe used for
trenchless installation must be non-
shielding and resist abrasions and
other damage possible during
installation.
(3) A quality assurance inspection
and testing program for the coating
must cover the surface quality of
the bare pipe, surface cleanliness
and chlorides, blast cleaning,
application temperature control,
adhesion, cathodic disbondment,
moisture permeation, bending,
coating thickness, holiday
(1) There must be certification
records of flanges, factory
induction bends and factory weld
ells. Certification must address
material properties such as
chemistry, minimum yield strength
and minimum wall thickness to meet
design conditions.
(2) If the carbon equivalents of
flanges, bends and ells are greater
than 0.42 percent by weight, the
qualified welding procedures must
include a pre-heat procedure.
(3) Valves, flanges and fittings
must be rated based upon the
required specification rating class
(1) A compressor station must be
designed to limit the temperature
of the nearest downstream segment
operating at alternative MAOP to a
maximum of 120 degrees Fahrenheit
(49 degrees Celsius) or the higher
temperature allowed in paragraph
(h)(2) of this section unless a
(2) of this section unless a
long-term coating integrity
monitoring program is implemented
in accordance with paragraph (h)(3)
of this section.
(2) If research, testing and field
monitoring tests demonstrate that
the coating type being used will
withstand a higher temperature in
long-term operations, the
compressor station may be designed
to limit downstream piping to that
higher temperature. Test results
and acceptance criteria addressing
coating adhesion, cathodic
disbondment, and coating condition
must be provided to each PHMSA
pipeline safety regional office
where the pipeline is in service at
least 60 days prior to operating
above 120 degrees Fahrenheit (49
degrees Celsius). 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.
(3) Pipeline segments operating at
alternative MAOP may operate at
temperatures above 120 degrees
Fahrenheit (49 degrees Celsius) if
the operator implements a long-term
coating integrity monitoring
program. The monitoring program
must include examinations using
direct current voltage gradient
(DCVG), alternating current voltage
gradient (ACVG), or an equivalent
method of monitoring coating
integrity. An operator must specify
the periodicity at which these
examinations occur and criteria for
repairing identified indications.
An operator must submit its long-
term coating integrity monitoring
program to each PHMSA pipeline
safety regional office in which the
pipeline is located for review
before the pipeline segments may be
operated at temperatures in excess
of 120 degrees Fahrenheit (49
degrees Celsius). 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.------------------------------------------------------------------------ [73 FR 62175, Oct. 17, 2008, as amended by Amdt. 192-111, 74 FR 62505, Nov. 30, 2009; Amdt. 192-119, 80 FR 180, Jan. 5, 2015; Amdt. 192-120, 80 FR 12777, Mar. 11, 2015]