20180215INT to Staff Attach 22 Scope for ASV and RCV.pdf

Scope for of Automatic Shut-off Valves and Remote-Controlled Valves
The scope of the proposed regulations for the requirement of Automatic Shut-off Valves and Remote-
Controlled Valves is currently found in the Federal Register / Vol. 81, No. 68 / Friday, April 8, 2016 /
Proposed Rules on Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines (See attached
PHMSA-2011-0023-0118.pdf).
Section H, Valve Spacing and the Need for Remotely or Automatically Controlled Valves, gives a good
history and overview of the subject and includes comments.
The specific scope for the proposed rule can be found on page 20846 – 192.935. To determine the need
for valves, 192.935 states in part…”additional measures must be based on the risk analyses required by
192.917, and must include, but are not limited to: …installing automatic shut-off valves or remote control
valves;…”
192.917 – outlines the process for threat identification and risk analysis.
§ 192.917 How does an operator identify
potential threats to pipeline integrity
and
use the threat identification in its
integrity program? (a) Threat identification. An operator
must identify and evaluate all potential
threats to each covered pipeline
segment. Potential threats that an
operator must consider include, but are
not limited to, the threats listed in
ASME/ANSI B31.8S (incorporated by
reference, see § 192.7), section 2, which
are grouped under the following four
threats:
(1) Time dependent threats such as
internal corrosion, external corrosion,
and stress corrosion cracking;
(2) Stable threats, such as
manufacturing, welding/fabrication, or
equipment defects;
(3) Time independent threats such as
third party/mechanical damage,
incorrect operational procedure,
weather related and outside force,
including consideration of seismicity,
geology, and soil stability of the area;
and
(4) Human error such as operational
mishaps and design and construction
mistakes.
(b) Data gathering and integration. To
identify and evaluate the potential
threats to a covered pipeline segment,
an operator must gather, verify,
validate,
and integrate existing data and could
be relevant to the covered
segment. In performing data gathering
and integration, an operator must
follow
the requirements in ASME/ANSI
B31.8S, section 4. At a minimum, an
operator must gather and evaluate the
set of data specified in paragraph
(b)(1)
of this section and appendix A to
ASME/ANSI B31.8S. The evaluation
must analyze both the covered segment
and similar non-covered segments, and
must:
(1) Integrate information about
pipeline attributes and other relevant
information, including, but not limited
to:
(i) Pipe diameter, wall thickness,
grade, seam type and joint factor;
(ii) Manufacturer and manufacturing
date, including manufacturing data and
records;
(iii) Material properties including, but
not limited to, diameter, wall thickness,
grade, seam type, hardness, toughness,
hard spots, and chemical composition;
(iv) Equipment properties;
(v) Year of installation;
(vi) Bending method;
(vii) Joining method, including
process and inspection results;
(viii) Depth of cover surveys
including stream and river crossings,
navigable waterways, and beach
approaches;
(ix) Crossings, casings (including if
shorted), and locations of foreign line
crossings and nearby high voltage
power
lines;
(x) Hydrostatic or other pressure test
history, including test pressures and
test
leaks or failures, failure causes, and
repairs;
(xi) Pipe coating methods (both
manufactured and field applied)
including method or process used to
apply girth weld coating, inspection
reports, and coating repairs;
(xii) Soil, backfill;
(xiii) Construction inspection reports,
including but not limited to:
(A) Girth weld non-destructive
examinations;
(B) Post backfill coating surveys;
(C) Coating inspection (‘‘jeeping’’)
reports;
(xiv) Cathodic protection installed,
including but not limited to type and
location;
(xv) Coating type;
(xvi) Gas quality;
(xvii) Flow rate;
(xviii) Normal maximum and
minimum operating pressures,
including maximum allowable
operating pressure (MAOP);
(xix) Class location;
(xx) Leak and failure history
including any in-service ruptures or
leaks from incident reports, abnormal
operations, safety related conditions
(both reported and unreported) and
failure investigations required by
§ 192.617, and their identified causes
and consequences;
(xxi) Coating condition;
(xxii) CP system performance;
(xxiii) Pipe wall temperature;
(xxiv) Pipe operational and
maintenance inspection reports,
including but not limited to:
(A) Data gathered through integrity assessments required under this part,
including but not limited to in-line
inspections, pressure tests, direct
assessment, guided wave ultrasonic
testing, or other methods;
(B) Close interval survey (CIS) and
electrical survey results;
(C) Cathodic protection (CP) rectifier
readings;
(D) CP test point survey readings and
locations;
(E) AC/DC and foreign structure
interference surveys;
(F) Pipe coating surveys, including
surveys to detect coating damage,
disbonded coatings, or other conditions
that compromise the effectiveness of
corrosion protection, including but not
limited to direct current voltage
gradient
or alternating current voltage gradient
inspections;
(G) Results of examinations of
exposed portions of buried pipelines
(e.g., pipe and pipe coating condition,
see § 192.459), including the results of
any non-destructive examinations of
the
pipe, seam or girth weld, i.e. bell hole
inspections;
(H) Stress corrosion cracking (SCC)
excavations and findings;
(I) Selective seam weld corrosion
(SSWC) excavations and findings;
(J) Gas stream sampling and internal
corrosion monitoring results, including
cleaning pig sampling results;
(xxv) Outer Diameter/Inner Diameter
corrosion monitoring;
(xxvi) Operating pressure history and
pressure fluctuations, including
analysis
of effects of pressure cycling and
instances of exceeding MAOP by any
amount;
(xxvii) Performance of regulators,
relief valves, pressure control devices,
or any other device to control or limit
operating pressure to less than MAOP;
(xxviii) Encroachments and right-of
way activity, including but not limited
to, one-call data, pipe exposures
resulting from encroachments, and
excavation activities due to
development or planned development
along the pipeline;
(xxix) Repairs;
(xxx) Vandalism;
(xxxi) External forces;
(xxxii) Audits and reviews; (xxxiii) Industry experience for
incident, leak and failure history;
(xxxiv) Aerial photography;
(xxxv) Exposure to natural forces in
the area of the pipeline, including
seismicity, geology, and soil stability of
the area; and
(xxxvi) Other pertinent information
derived from operations and
maintenance activities and any
additional tests, inspections, surveys,
patrols, or monitoring required under
this part.
(2) Use objective, traceable, verified,
and validated information and data as
inputs, to the maximum extent
practicable. If input is obtained from
subject matter experts (SMEs), the
operator must employ measures to
adequately correct any bias in SME
input. Bias control measures may
include training of SMEs and use of
outside technical experts (independent
expert reviews) to assess quality of
processes and the judgment of SMEs.
Operator must document the names of
all SMEs and information submitted by
the SMEs for the life of the pipeline.
(3) Identify and analyze spatial
relationships among anomalous
information (e.g., corrosion coincident
with foreign line crossings; evidence of
pipeline damage where overhead
imaging shows evidence of
encroachment). Storing or recording
the
information in a common location,
including a geographic information
system (GIS), alone, is not sufficient;
and
(4) Analyze the data for
interrelationships among pipeline
integrity threats, including
combinations of applicable risk factors
that increase the likelihood of incidents
or increase the potential consequences
of incidents.
(c) Risk assessment. An operator must
conduct a risk assessment that analyzes
the identified threats and potential
consequences of an incident for each
covered segment. The risk assessment
must include evaluation of the effects of
interacting threats, including the
potential for interactions of threats and
anomalous conditions not previously
evaluated. An operator must ensure
validity of the methods used to conduct
the risk assessment in light of incident,
leak, and failure history and other
historical information. Validation must ensure the risk assessment methods
produce a risk characterization that is
consistent with the operator’s and
industry experience, including
evaluations of the cause of past
incidents, as determined by root cause
analysis or other equivalent means, and
include sensitivity analysis of the
factors
used to characterize both the
probability of loss of pipeline integrity
and consequences of the postulated
loss
of pipeline integrity. An operator must
use the risk assessment to determine
additional preventive and mitigative
measures needed (§ 192.935) for each
covered segment, and periodically
evaluate the integrity of each covered
pipeline segment (§ 192.937(b)). The
risk assessment must:
(1) Analyze how a potential failure
could affect high consequence areas,
including the consequences of the
entire
worst-case incident scenario from
initial
failure to incident termination;
(2) Analyze the likelihood of failure
due to each individual threat or risk
factor, and each unique combination of
threats or risk factors that interact or
simultaneously contribute to risk at a
common location;
(3) Lead to better understanding of the
nature of the threat, the failure
mechanisms, the effectiveness of
currently deployed risk mitigation
activities, and how to prevent, mitigate,
or reduce those risks;
(4) Account for, and compensate for,
uncertainties in the model and the data
used in the risk assessment; and
(5) Evaluate the potential risk
reduction associated with candidate
risk
reduction activities such as preventive
and mitigative measures and reduced
anomaly remediation and assessment
intervals.
(d) Plastic transmission pipeline. An
operator of a plastic transmission
pipeline must assess the threats to each
covered segment using the information
in sections 4 and 5 of ASME B31.8S,
and consider any threats unique to the
integrity of plastic pipe such as poor
joint fusion practices, pipe with poor
slow crack growth (SCG) resistance,
brittle pipe, circumferential cracking,
hydrocarbon softening of the pipe, internal and external loads,
longitudinal
or lateral loads, proximity to elevated
heat sources, and point loading.
(e) * * *
(2) Cyclic fatigue. An operator must
evaluate whether cyclic fatigue or other
loading conditions (including ground
movement, suspension bridge
condition) could lead to a failure of a
deformation, including a dent or gouge,
crack, or other defect in the covered
segment. The evaluation must assume
the presence of threats in the covered
segment that could be exacerbated by
cyclic fatigue. An operator must use the
results from the evaluation together
with the criteria used to evaluate the
significance of this threat to the
covered
segment to prioritize the integrity
baseline assessment or reassessment.
Fracture mechanics modeling for
failure
stress pressures and cyclic fatigue
crack
growth analysis must be conducted in
accordance with § 192.624(d) for
cracks.
Cyclic fatigue analysis must be
annually, not to exceed 15 months.
(3) Manufacturing and construction
defects. An operator must analyze the
covered segment to determine the risk
of
failure from manufacturing and
construction defects (including seam
defects) in the covered segment. The
analysis must consider the results of
prior assessments on the covered
segment. An operator may consider
manufacturing and construction
related
defects to be stable defects only if the
covered segment has been subjected to
hydrostatic pressure testing satisfying
the criteria of subpart J of this part of at
least 1.25 times MAOP, and the
segment
has not experienced an in-service
incident attributed to a manufacturing
or construction defect since the date of
the pressure test. If any of the following
changes occur in the covered segment,
an operator must prioritize the covered
segment as a high risk segment for the
baseline assessment or a subsequent
reassessment, and must reconfirm or
reestablish MAOP in accordance with
§ 192.624(c).
(i) The segment has experienced an in-service incident, as described in
§ 192.624(a)(1);
(ii) MAOP increases; or
(iii) The stresses leading to cyclic
fatigue increase.
(4) ERW pipe. If a covered pipeline
segment contains low frequency
electric
resistance welded pipe (ERW), lap
welded pipe, pipe with seam factor less
than 1.0 as defined in § 192.113, or
other pipe that satisfies the conditions
specified in ASME/ANSI B31.8S,
Appendices A4.3 and A4.4, and any
covered or non-covered segment in the
pipeline system with such pipe has
experienced seam failure (including,
but
not limited to pipe body cracking, seam
cracking and selective seam weld
corrosion), or operating pressure on
the
covered segment has increased over
the
maximum operating pressure
experienced during the preceding five
years (including abnormal operation as
defined in § 192.605(c)), or MAOP has
been increased, an operator must select
an assessment technology or
technologies with a proven application
capable of assessing seam integrity and
seam corrosion anomalies. The
operator
must prioritize the covered segment as
a high risk segment for the baseline
assessment or a subsequent
reassessment. Pipe with cracks must be
evaluated using fracture mechanics
modeling for failure stress pressures
and
cyclic fatigue crack growth analysis to
estimate the remaining life of the pipe
in accordance with § 192.624(c) and
(d).