# NORTHWEST PIPELINE LLC — Notice of Amendment

- **operation:** document
- **citation:** CPF 520071004M
- **title:** NORTHWEST PIPELINE LLC — Notice of Amendment
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2007-04-04
- **effective on:** Not available
- **summary:** CLOSED notice of amendment citing 192.905(a), 192.905(b), 192.905(c), 192.907(b), 192.909(b), 192.911(i), 192.911(k), 192.917(a), 192.917(b), 192.917(c), 192.917(e)(5), 192.921(a)(4), 192.921(f), 192.925(b)(1)(i), 192.925(b)(2), 192.925(b)(2)(i), 192.925(b)(3), 192.925(b)(3)(i), 192.933(a), 192.933(b), 192.933(c), 192.933(d)(1)(ii), 192.933(d)(3), 192.937(a), 192.945(a).
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Notice of Amendment involving NORTHWEST PIPELINE LLC. PHMSA's enforcement data identifies the cited regulations as 192.905(a),  192.905(b),  192.905(c),  192.907(b),  192.909(b),  192.911(i),  192.911(k),  192.917(a),  192.917(b),  192.917(c),  192.917(e)(5),  192.921(a)(4),  192.921(f),  192.925(b)(1)(i),  192.925(b)(2),  192.925(b)(2)(i),  192.925(b)(3),  192.925(b)(3)(i),  192.933(a),  192.933(b),  192.933(c),  192.933(d)(1)(ii),  192.933(d)(3),  192.937(a),  192.945(a). The case was opened on 2007-04-04 and is reported as closed as of 2008-04-14. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520071004M_notice letter_04042007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071004M/520071004M_notice%20letter_04042007.pdf

520071004m_notice letter_04042007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071004M/520071004m_notice%20letter_04042007_text.pdf

520071004M_Operator Response_08152007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520071004M/520071004M_Operator%20Response_08152007.pdf

520071004m_notice letter_04042007_text.pdf

U. S. Department
of Transportation
Pipeline and
Hazardous Materials Safety
Administration
12300 W Dakota Ave, Surete 110
Lakewood, CO 80228
NOTICE OF AMKNDMKNT
CERTIFIED MAIL - RETU1Vf RECEIPT RE UESTED
April 4, 2007
SENT TO COMPLIANCE REGISTRY
Hardcopy Electronically
4 of Copies&/ Date ~+~'p +Jyl
Mr. Randy Barnard
VP Operations and Gas Control
Williams Gas Pipeline
2800 Post Oak Blvd
P. O. Box 1396
Houston, TX 77056
CPF 5-2007-1004M
Dear Mr. Barnard:
On March 13-17 and March 27 — 30, 2006, a representative of the Pipeline and Hazardous
Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code,
inspected Williams Gas Pipeline's (WGP's) procedures for the Integrity Management
Program (IMP) in Salt Lake City, Utah.
On the basis of the inspection, PHMSA has identified the apparent inadequacies found within
WGP's plan or procedure and are described below. Probable non-violations resulting from
that same inspection were already sent to you in our letter, CPF No. 5-2007-1001, dated
January 29, 2007.
1. Identification of High Consequence Areas
)192. 911 What are the elements of an integrity management program'?
(a) An identification of all high consequence areas, in accordance with $192. 905.
(p) A process for identification and assessment of newly-identified high consequence
areas. (See $192. 905 and $192. 921. )
$192. 905 How does an operator identify a high consequence area?
(a) General. To determine which segments of an operator's transmission pipeline
system are covered by this subpart, an operator must identify the high consequence



areas. An operator must use method (1) or (2) from the definition in $192. 903 to
identify a high consequence area. An operator may apply one method to its entire
pipeline system, or an operator may apply one method to individual portions of the
pipeline system. An operator must describe in its integrity management program
which method it is applying to each portion of the operator's pipeline system. The
description must include the potential impact radius when utilized to establish a high
consequence area. (See appendix K. I. for guidance on identifying high consequence
areas. )
(b) Identified sites, An operator must identify an identified site, for purposes of this
subpart, from information the operator has obtained from routine operation and
maintenance activities and from public officials with safety or emergency response or
planning responsibilities who indicate to the operator that they know of locations that
meet the identified site criteria. These public officials could include officials on a
local emergency planning commission or relevant Native American tribal officials.
(c) Newly identified areas. When an operator has information that the area around a
pipeline segment not previously identified as a high consequence area could satisfy
any of the definitions in $192. 903, the operator must complete the evaluation using
method (1) or (2). If the segment is determined to meet the definition as a high
consequence area, it must be incorporated into the operator's baseline assessment
plan as a high consequence area within one year from the date the area is identified.
~ Item 1A: $192. 911(a) and $192. 905(a)
Williams Gas Pipeline's procedure 10. 09. 01. 10 and IMP Overview Chapter 4 define
Methods 1 and 2 consistent with rule requirements. However, these documents do not
provide detailed information on how these HCA identification methods are implemented.
The procedure needs amending to include Process steps, responsibilities, data inputs and
outputs, and documentation requirements.
~ Item 1B: $192. 911(a) and $192. 905(a)
Procedure 10. 09. 01. 10, Section 10. 1. 5 states that all WGP HCA locations shall be
permanently recorded and that the recorded information "may" include the method used to
identify HCA. The procedure needs amending to reflect the rule requirement this
information "must" be documented.
~ Item 1C: $192. 911(a) and $192. 905(a)
Procedure 10. 09. 01. 10, Section 10. 1. 6 is inadequate as it indicates system maps will be
maintained and updated with aerial photography for identifying HCAs without specifying
what frequency the aerial photography is to be updated.
~ Item 1D: $192. 911(a) and $192. 905(a)
Instructions provided to the field (e. g. , Appendix A of IMP Overview Chapter 4) do not
provide data accuracy instructions on how to measure and locate piping and adjacent
structure/identified site locations.



• Item 1E: §192.911(a) and §192.905(b)
WGP does not have a formalized procedure or process for how facility use data is collected
during routine operation and maintenance activities to document if sites meet the identified
site criteria.
• Item 1F: §192.911(a), §192.911(p) and §192.905(c)
WGP's integrity management program does not include documented processes for how
identified and integrated with the integrity management program. These documented
new information indicating a pipeline segment impacts a high consequence area is
processes do not include activity steps, responsibilities, data inputs and outputs, and
documentation requirements.
2. Baseline Assessment Plan
§192.911 What are the elements of an integrity management program?
(b) A baseline assessment plan meeting the requirements of §192.919 and §192.921.
§192.921(a)(4) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. An operator choosing this
option must notify the Office of Pipeline Safety (OPS) 180 days before conducting the
assessment, in accordance with $192.949. An operator must also notify a State or
local pipeline safety authority when either a covered segment is located in a State
where OPS has an interstate agent agreement, or an intrastate covered segment is
regulated by that State.
§192.921(f) Newly identified areas. When an operator identifies a new high
consequence area (see §192.905), an operator must complete the baseline assessment
of the line pipe in the newly identified high consequence area within ten (10) years
from the date the area is identified.
• Item 2A: §192.911(b) and §192.921(a) (4)
WGP's procedures for notifying OPS, State, or local pipeline safety authorities of the use
of "other technology" are not included in their integrity management plan documentation.
• Item 2B: §192.911(b) and §192.921(f)
For newly identified HAs or newly installed pipe that is covered by this subpart and
impacts an HCA, WGP does not have a procedural requirement to complete a baseline
assessment for the applicable segments) within ten (10) years from the date the area is
identified.
3. Identify Threats, Data Integration, and Risk Assessment
§192.911 What are the elements of an integrity management program?
- 3.



(c) An identification of threats to each covered pipeline segment, which must include
data integration and a risk assessment. An operator must use the threat
identification and risk assessment to prioritize covered segments for assessment
($192. 917) and to evaluate the merits of additional preventive and mitigative
measures ($192. 935) for each covered segment.
$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 ASMK/ANSI B31. 8S (ibr, see
$192. 7), section 2, which are as follows:
(1) Time dependent threats such as internal corrosion, external corrosion, and stress
corrosion cracking;
(2) Static or resident threats, such as fabrication or construction defects;
(3) Time independent threats such as third party damage and outside force damage;
and
(4) Human error.
(b) Data gathering and integration. To identify and evaluate the potential threats to a
covered pipeline segment, an operator must gather and integrate existing data and
information on the entire pipeline that coulld be relevant to the covered segment. In
performing this data gathering and integration, an operator must follow the
requirements in ASMK/ANSI B31. 8S, section 4. At a minimum, an operator must
gather and evaluate the set of data specified in Appendix A to ASMK/ANSI B31. 8S,
and consider both on the covered segment and similar non-covered segments, past
incident history, corrosion control records, continuing surveillance records,
patrolling records, maintenance history, internal inspection records and all other
conditions specific to each pipeline.
(c) Risk assessment. An operator must conduct a risk assessment that follows
ASME/ANSI B31. 8S, section 5, and considers the identified threats for each covered
segment. An operator must use the risk assessment to prioritize the covered segments
for the baseline and continual reassessments (@192. 919, 192. 921, 192. 937), and to
determine what additional preventive and mitigative measures are needed ($192. 935)
for the covered segment.
$192. 917(e)(5) Corrosion. If an operator identifies corrosion on a covered pipeline
segment that could adversely affect the integrity of the line (conditions specified in
$192. 933), the operator must evaluate and remediate, as necessary, all pipeline
segments (both covered and non- covered) with similar material coating and
environmental characteristics. An operator must establish a schedule for evaluating
and remediating, as necessary, the similar segments that is consistent with the
operator's established operating and maintenance procedures under part 192 for
testing and repair.
~ Item 3A: $192. 911(c) and $192. 917(a)
WGP threat identification process has not provided sufficient technical justification for the
elimination of the SCC threat.



~ Item 38: $192. 911(c) and $192. 917(a)
It is not apparent interactive threats have been considered in the WGP threat identification
process. SMEs have ability to recognize interactive threats and adjust risk based on their
knowledge of the threats, but WGP has not provided guidance in procedures for this
activity. The inspection team recognized that the Threat Identification Checklists have the
potential to provide for consideration of interacting threats.
~ Item 3C: $192. 911(c) and $192. 917(b)
Procedure 10. 25. 01, Section 4. 0 provides high level requirements for data collection and
integration. Integrity Sheet 1400. 13-101A shows data integration for an ECDA project.
However, procedioes are not in place to provide instructions on how data is to be included
on the Integrity Sheet. Documented procedures that include required activity steps,
responsibilities, data inputs and outputs, and documentation requirements have not been
established.
~ Item 3D: $192. 911(c) and $192. 917(b)
Processes have not been defined for the responsibilities for data collection or how the data
sets are assembled, how accuracy is verified, how the data is maintained, or defining the
sets of data that must be collected. WGP has the intent and is in the process of developing
a GIS that they will use to integrate data comprehensively by the end of 2006.
~ Item 3K: $192. 911(c) and $192. 917(b)
Data sources listed in ASME B31. 8S Table 2 are not specified as required data sets in the
WGP risk assessment process.
~ Item 3F: $192. 911(c) and $192. 917(b)
WGP procedures for data gathering and integration are inadequate as they do not include
processes for verifying data quality as required by ASME/ANSI B31. 8S Section 4.
Procedures do not require that conservative assumptions be applied if data is missing or
suspect. The procedures do not specify additional inspections or field data collection
efforts must be initiated for missing/suspect data.
~ Item 3C: $192. 911(c) and $192. 917(c)
Procedure 10. 25. 01, Section 9. 1. 1 specifies that risk assessment validation activities are to
be conducted each calendar year. The procedures are inadequate as a specific performance
date or link to an activity milestone is not defined in IMP procedures to trigger the activity.
Additionally, procedures have not been established describing how SMEs perform the
validation process to ensure risk results are logical and consistent with the operator's and
other industry experience.



~ Item 3H: $192. 911(c) and $192. 917(e)(5)
WGP's procedures do not describe the process by which all covered and non-covered
segments with similar environmental character istics and coating will be evaluated when
corrosion is discovered on a covered segment that can adversely affect the integrity of the
pipeline.
4. External Corrosion Indirect Assessment
$192. 911 What are the elements of an integrity management program?
(d) A direct assessment plan, if applicable, meeting the requirements of $192. 923, and
depending on the threat assessed, of g192. 925, 192. 927, or 192. 929.
$192. 925(b) General requirements. An operator that uses direct assessment to assess
the threat of external corrosion must follow the requirements in this section, in
ASME/ANSI B31. 8S (ibr, see $192. 7), section 6. 4, and in NACE RP 0502-2002 (ibr,
see $192. 7). An operator must develop and implement a direct assessment plan that
has procedures addressing preassessment, indirect examination, direct examination,
and post-assessment. If the ECDA detects pipeline coating damage, the operator
must also integrate the data from the ECDA with other information from the data
integration ($192. 917{b)) to evaluate the covered segment for the threat of third party
damage, and to address the threat as required by $192. 917(e)(1).
(1) Preassessment. In addition to the requirements in ASME/ANSI B31. 8S section 6. 4
and NACE RP 0502-2002, section 3, the plan's procedures for preassessment must
include-
(i) Provisions for applying more restrictive criteria when conducting ECDA for the
first time on a covered segment;
(2) Indirect examination. In addition to the requirements in ASME/ANSI B31. 8S
section 6. 4 and NACE RP 0502-2002, sectiion 4, the plan's procedures for indirect
examination of the ECDA regions must include-
(i) Provisions for applying more restrictive criteria when conducting ECDA for the
first time on a covered segment;
(ii) Criteria for identifying and documenting those indications that must be
considered for excavation and direct examination. Minimum identification criteria
include the known sensitivities of assessment tools, the procedures for using each tool,
and the approach to be used for decreasing the physical spacing of indirect
assessment tool readings when the presence of a defect is suspected;
{iii) Criteria for defining the urgency of excavation and direct examination of each
indication identified during the indirect examination. These criteria must specify
how an operator will define the urgency of excavating the indication as immediate,
scheduled or monitored; and
(iv) Criteria for scheduling excavation of indications for each urgency level.
(3) Direct examination. In addition to the requirements in ASME/ANSI B31. 8S
section 6. 4 and NACE RP 0502-2002, section 5, the plan's procedures for direct
examination of indications from the indirect examination must include-
(i) Provisions for applying more restrictive criteria when conducting ECDA for the
first time on a covered segment;



(ii) Criteria for deciding what action should be taken if either:
(A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of
(B) Root cause analysis reveals conditions for which ECDA is not suitable (Section
NACE RP0502-2002), or
5.6.2 of NACE RP0502-2002);
(iii) Criteria and notification procedures for any changes in the ECDA Plan,
reprioritize any of the provisions that are specified in section 5.9 of NACE RP0502-
• Item 4A: §192.911(d) and §192.925(b)(1)(i)
The ECDA procedure 20.19.01.02 does not include the 192.925 requirement initial ECDA
assessments include more restrictive criteria for the pre-assessment and that this be
documented.
• Item 4B: §192.911(d) and 192.925(b)(2)
There is no reference to industry standards for conducting and analyzing ECDA indirect
inspection results for each of the selected tools. The physical spacing of each tool is not
referenced in the ECDA procedure.
• Item 4C: §192.911(d) and 192.925(b)(2)
The NACE RP requires that conflicting results be documented and resolved. The ECDA
procedure does not address this issue nor was there any documentation that this was
considered or what actions are taken if this occurs.
• Item 4D: §192.911(d) and 192.925(b)(2)(i)
The ECDA procedure 20.19.01.02 does not include the 192.925 requirement that initial
ECDA assessments include more restrictive criteria for the indirect inspection and that this
be documented.
• Item 4E: §192.911(d) and §192.925(b)(3)
The ECDA procedure does not follow the NACE RP for all required excavations.
• Item 4F: §192.911(d) and §192.925(b)(3)
The ECDA procedure 20.19.01.02 section 6.1.2.3.1.1 requires that if significant external
corrosion is discovered it must be evaluated by a root cause analysis and consideration of
another method of assessment. There is no definition of the term "significant".
- 7.



~ Item 4G: $192. 911(d) and $192. 925(b)(3)
The %'GP ECDA procedure does not require an evaluation of the indirect inspection data
using the results of the remaIning strength calculations and root cause analysis as required
by NACE RP 0502-2002, section 5.
~ Item 4H: $192. 911(d) and $192. 925(b)(3)
The ECDA procedure does not address the need to use other assessment methods if defects
other than EC are discovered during an ECDA.
~ Item 4I: $192. 911(d) and $192. 925(b)(3)(i)
The ECDA procedure 20. 19. 01. 02 does not include the 192. 925 requirement that initial
ECDA assessments include more restrictive criteria for direct examinations and that this be
documented.
5. Remediation
$192. 911 What are the elements of an integrity management program?
(e) Provisions meeting the requirements of $192. 933 for remediating conditions found
during an integrity assessment.
$192. 933(a) General requirements. An operator must take prompt action to address
all anomalous conditions that the operator discovers through the integrity
assessment. In addressing all conditions, an operator must evaluate all anomalous
conditions and remediate those that could reduce a pipeline's integrity. An operator
must be able to demonstrate that the remediation of the condition will ensure that the
condition is unlikely to pose a threat to the integrity of the pipeline until the next
reassessment of the covered segment. If an operator is unable to respond within the
time limits for certain conditions specified in this section, the operator must
temporarily reduce the operating pressure of the pipeline or take other action that
ensures the safety of the covered segment. If pressure is reduced, an operator must
determine the temporary reduction in operating pressure using ASME/ANSI B31G
(ibr, see $192. 7) or AGA Pipeline Research Committee Project PR-3-805
("RSTRENG"; ibr, see $192. 7) or reduce the operating pressure to a level not
exceeding 80'/o of the level at the time the condition was discovered. (See appendix A
to this part 192 for information on availability of incorporation by reference
information). A reduction in operating pressure cannot exceed 365 days without an
operator providing a technical justification that the continued pressure restriction
will not jeopardize the integrity of the pipeline.
$192. 933(b) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about a condition to determine that the condition
presents a potential threat to the integrity of the pipeline. A condition that presents a
potential threat includes, but is not limited to, those conditions that require
remediation or monitoring listed under paragraphs (d)(1) through (d)(3) of this
section. An operator must promptly, but no later than 180 days after conducting an



integrity assessment, obtain sufficient information about a condition to make that
determination, unless the operator demonstrates that the 180-day period is
impracticable.
$192. 933(c) Schedule for evaluation and reniediation. An operator must complete
remediation of a condition according to a schedule that prioritizes the conditions for
evaluation and remediation. Unless a special requirement for remediating certain
conditions applies, as provided in paragraph (d) of this section, an operator must
follow the schedule in ASME/ANSI B31. 8S (ibr, see $192. 7), section 7, Figure 4. If an
operator cannot meet the schedule for any condition, the operator must justif'y the
reasons why it cannot meet the schedule and that the changed schedule will not
jeopardize public safety. An operator must notif'y OPS in accordance with $192. 949
if it cannot meet the schedule and cannot provide safety through a temporary
reduction in operating pressure or other action. An operator must also notify a State
or local pipeline safety authority when either a covered segment is located in a State
where OPS has an interstate agent agreement, or an intrastate covered segment is
regulated by that State.
$192. 933(d) Special requirements for scheduling remediation.
1. Immediate repair conditions. An operator's evaluation and remediation schedule
must follow ASME/ANSI B31. 8S, Section / in providing for immediate repair
conditions. To maintain safety, an operator must temporarily reduce operating
pressure in accordance with paragraph (a) of this section or shut down the pipeline
until the operator completes the repair of these conditions. An operator must treat
the following conditions as immediate repair conditions:
i. A calculation of the remaining strength of the pipe shows a predicted failure
pressure less than or equal to1. 1 times the maximum allowable operating pressure at
the location of the anomaly. Suitable remaining strength calculation methods
include, ASME/ANSI B31G (" Manual for Determining the Remaining Strength of
Corroded Pipelines" (1991); AGA Pipeline Research Committee Project PR-3-805
("A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe"
(December 1989)); or an alternative equivalent method of remaining strength
calculation. These documents are incorporated by reference and available at the
addresses listed in Appendix A to Part 192.
ii. A dent that has any indication of metal loss, cracking or a stress riser.
iii. An indication or anomaly that in the judgment of the person designated by the
operator to evaluate the assessment results requires immediate action. (1)(ii) A dent
that has any indication of metal loss, cracking or a stress riser.
3. Monitored conditions. An operator does not have to schedule the following
conditions for remediation, but must record and monitor the conditions during
subsequent risk assessments and integrity assessments for any change that may
require remediation:
i. A dent with a depth greater than 6% of the pipeline diameter (greater than 0. 50
inches in depth for a pipeline diameter less than NPS 12) located between the 4
o' clock position and the 8 o' clock position (bottom 1/3 of the pipe).
ii. A dent located between the 8 o' clock and 4 o' clock positions (upper 2/3 of the pipe)
with a depth greater than 6% of the pipeline diameter {greater than 0. 50 inches in



depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and engineering
analyses of the dent demonstrate critical strain levels are not exceeded.
iii. A dent with a depth greater than 2'/0 of the pipeline's diameter (D. 25D inches in
depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth
weld or a longitudinal seam weld, and engineering analyses of the dent and girth or
seam weld demonstrate critical strain levels are not exceeded. These analyses must
consider weld properties.
~ Item 5A: $192. 911(e) and $192. 933(a)
The ECDA procedure for determining remaining strength does not require that the
operating pressure be reduced to 80'/0 or less of the operating pressure if there is an
immediate repair per 192. 933.
~ Item 5B: $192. 911(e) and $192. 933(a)
Per Procedure 70. 17. 01. 07, Figure 7, a pressure reduction for an immediate repair
condition can be made using either a reduction to 80'/0 of operating pressure or based on
0. 9 x Pburst as calculated by RSTRENG. A pressure reduction must be taken based upon
Psafe as calculated by B31G or RSTRENG. WGP procedures do not reflect this
requirement.
~ Item 5C: $192. 911(e) and $192. 933(a)
WGP's repair procedure does not meet code requirements for using Type B sleeves for
repairs involving anomalies greater than 80'/0 wall loss.
~ Item 5D: $192. 911(e) and $192. 933(b)
Per Section 8. 1. 4 of Procedure 70. 17. 01. 07, "Pigging — Inline Inspection" a separate
discovery date is established for a geometry and MFL tool run when performed 120 days
or more apart; however, the analysis shall still be a joint analysis. This is inconsistent with
rule requirements. If any anomalies are discovered from the geometry tool assessment
results, a one year repair condition may not be addressed in accordance with IM rule repair
schedule requirements.
~ Item 5E: $192. 911(e) and $192. 933(c)
Per Section 8. 2. 3 of Procedure 70. 17. 01. 07, scheduled anomalies will be excavated within
365 days. Figure 4 of ASME B31. 8S provides a time frame for addressing scheduled
anomalies that have a Pf/MAOP ) 1. 1. In some cases the time frames are less than 365
days. WGP's procedures do not require examination or remediation in the appropriate
timeframe. Per Section 192. 933(c), "An operator must complete remediation of a
condition according to a schedule that prioritizes the conditions for evaluation and
remediation. " Section 8. 2. 3 of Procedure 70. 17. 01. 07 does not provide sufficient detail or
guidance for the development of a prioritized schedule.



• Item 5F: §192.911(e) and §192.933(c)
WGP's procedures do not meet the provisions of ASME B31.8S, Figure 4 for scheduling
anomalies for examination or remediation.
• Item 5G: §192.911(e) and §192.933(d)(1)(ii)
In Section 8.2.3 of Procedure 70.17.01.07, WGP states: "All dents with metal loss (where
the metal loss is believed to be corrosion) shall be considered a higher priority than other
scheduled anomalies and shall be excavated first." Per the IM rule 192.933(d)(ii): "A dent
that has an indication of metal loss, cracking, or a stress riser" is an immediate repair
condition.
• Item 5H: §192.911(e) and §192.933(d)(3)
Procedure 20.19.01.02 does not address "monitored" conditions as required by the Gas
IMP rule for external corrosion direct assessment.
• Item 5I: §192.911(e) and §192.933(d)(3)
WGP procedures allow a priority I coating indication to wait up to one year before
excavation which is inconsistent with PHMSA guidance. All required digs must be
completed within 6 months after the indirect inspection surveys.
6. Preventive and Mitigative Measures
§192.911 What are the elements of an integrity management program?
(h) Provisions meeting the requirements of §192.935 for adding preventive and
mitigative measures to protect the high consequence area.
§192.937(a) General requirements. An operator must take additional measures
mitigate the consequences of a pipeline failure in a high consequence area. An
beyond those already required by Part 192 to prevent a pipeline failure and to
operator must base the additional measures on the threats the operator has identified
to each pipeline segment. (See §192.917) An operator must conduct, in accordance
with one of the risk assessment approaches in ASME/ANSI B31.8S (ibr, see §192.7),
section 5, a risk analysis of its pipeline to identify additional measures to protect the
high consequence area and enhance public safety. Such additional measures include,
but are not limited to, installing Automatic Shut-off Valves or Remote Control
Valves, installing computerized monitoring and leak detection systems, replacing pipe
segments with pipe of heavier wall thickness, providing additional training to
personnel on response procedures, conducting drills with local emergency responders
and implementing additional inspection and maintenance programs.
• Item 6A: §192.911(h) and §192.937(a)
WGP's ECDA procedure does not require that mitigative actions be completed and
documented.
- 11 -



• Item 6B: §192.911(h) and §192.937(a)
Section 9.0 of procedure 10.25.01.02 describes the process for identifying additional
preventive and mitigative measures. The procedure does not delineate how risk analysis
will be used in the decision making process.
• Item 6C: §192.911(h) and §192.937(a)
Per section 9.0 of WGP procedure 10.25.01.02, decisions regarding preventive and
mitigative measures are made during the annual SME review of risk assessment results.
This procedure does not address the process of how the SMEs shall identify, evaluate, and
recommend additional preventive and mitigative measures. In addition, this procedure
does not delineate how the risk model will be used in the decision making process.
7. Performance Measures
§192.911 What are the elements of an integrity management program?
(i) A performance plan as outlined in ASME/ANSI B31.8S, Section 9 that includes
performance measures meeting the requirements of $192.945.
§192.945(a) General. An operator must include in its integrity management program
methods to measure, on a semi-annual basis, whether the program is effective in
assessing and evaluating the integrity of each covered pipeline segment and in
protecting the high consequence areas. These measures must include the four overall
performance measures specified in ASME/ANSI B31.8S (ibr, see §192.7), section 9.4,
and the specific measures for each identified threat specified in ASME/ANSI B31.8S,
electronic or other means, on a semi-annual frequency to OPS in accordance with
Appendix A. An operator must submit the four overall performance measures, by
$192.951. An operator must submit its first report on overall performance measures
by August 31, 2004. Thereafter, the performance measures must be complete
through June 30 and December 31 of each year and must be submitted within 2
months after those dates.
• Item 7A: §192.911(i) and §192.945(a)
The WGP procedure 10.24.01.02 does not provide sufficient detail for the responsibility of
who should collect information for submittal. [I.01.a]
8. Management of Change
§192.911 What are the elements of an integrity management program?
(k) A management of change process as outlined in ASME/ANSI B31.8S, section 11.
§192.909(b) Notification. An operator must notify OPS, in accordance with §192.949,
implementation or may significantly modify the program or schedule for carrying out
of any change to the program that may substantially affect the program's
the program elements. An operator must also notify a State or local pipeline safety
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authority when either a covered segment is located in a State where OPS has an
interstate agent agreement, or an intrastate covered segment is regulated by that
State. An operator must provide the notification within 30 days after adopting this
type of change into its program.
ASMK B31. 8S-2001, Section 11
(a) Formal management of change procedures shall be developed in order to identify
and consider the impact of changes to pipeline systems and their integrity. These
procedures should be flexible enough to accommodate both major and minor
changes, and must be understood by the personnel that use them. Management of
change shall address technical, physical, procedural and organizational changes to
the system whether permanent or temporary. The process should incorporate
planning for each of these situations and consider the unique circumstances of each.
A management of change process includes the following:
(1) Reason for change
(2) Authority for approving changes
(3) Analysis of implications
(4) Acquisition of required work permits
(5) Documentation
(6) Communication of change to affected parties
(7) Time limitations
(8) Qualification of staff
(b) The operator shall recognize that system changes can require changes in the
integrity management program and conversely, results from the program can cause
system changes. The following are examples that are gas pipeline specific but are by
no means all inclusive.
~ Item 8A: $192. 911(k) and ASME B31. 8S-2001, Section 11(a)
WGP has requirements for an annual review to keep the BAP up-to-date with respect to
newly arising information, applicable threats, and risks that may require changes to the
segment prioritization or assessment method. A specific performance date or link to an
activity milestone must be defined in IMP procedures for the performance of the annual
reviews.
~ item 88: $192. 911(k) and ASMK B31. 8S-2001, Section 11(a)
WGP IMP procedures do not address reasons for changes to the BAP, authority for
approving the change, analysis of implications of the change, or communication of the
change to affected parties.
~ item 8C: $192. 911(k) and ASMK B31. 8S-2001, Section 11(a)
WGP procedure 10. 25. 01, Section 9. 1. 1 requires an annual update of the risk assessment
but does not provide a process or define responsibilities for ensuring new information is
incorporated in a timely manner or to establish an interface with the management of



change process to ensure changes are appropriately reflected in risk analysis data.
Additionally a specific performance date or link to an activity milestone is not defined in
IMP procedures for the performance of the annual update.
~ Item SD: $192. 911{k) and ASMK B31. 8S-2001, Section 11(a)
Procedure 10. 29. 01. 02 addresses the MOC process; however, the process does not address
procedural and organizational changes.
~ Item SE: $192. 911(k) and ASME B31. 8S-2001, Section 11(a)
Not all of the requirements of ASME B31. 8S, Section 11 are addressed by WGP's
Management of Change procedures.
~ Item SFi $192. 911{k) and ASME B31. 8S-2001, Section 11(b)
Some important system changes were not reported to the IMP team that could have
affected pipeline integrity.
~ Item SG: $192. 911(k) and $192. 909(b)
WGP's Integrity Management Procedures do not require notification of OPS or the State or
local pipeline safety authorities of significant changes to the program, program
implementation, or schedules. Additionally, the definition of what constitutes a significant
change has not been identified in IMP procedures. It was noted that WGP did have a
change log that listed changes that have occurred and the log included limited examples of
what are considered to be significant changes.
9. Quality Assurance
$192. 911 What are the elements of an integrity management program?
(l) A quality assurance process as outlined in ASMK/ANSI B31. 8S, Section 12.
$192. 907(b) Implementation Standards. In carrying out this subpart, an operator
must follow the requirements of this subpart and of ASME/ANSI B31. 8S (ibr, see
$192. 7) and its appendices, where specified. An operator may follow an equivalent
standard or practice only when the operator demonstrates the alternative standard or
practice provides an equivalent level of safety to the public and property. In the
event of a conflict between this subpart and ASME/ANSI B31. 8S, the requirements in
this subpart control.
ASME B31. 8S-2001, Section 12. 2, Quality Management Control.
(b) Specifically, activities that should be included in the quality control program are
as follows:
(2) The responsibilities and authorities under this program shall be clearly and
formally defined.



(3) Results of the integrity management program and the quality control program
shall be reviewed at predetermined intervals, making recommendations for
improvement.
(4) The people involved in the integrity management program shaH be competent,
aware of the program and all of its activities and shall be properly trained to execute
the activities within the program. Documentation of such competence, awareness and
qualification, and the processes for their achievement, shall be part of the quality
control plan.
(7) Corrective actions to improve the integrity management program or quality plan
shall be documented and the effectiveness of their implementation monitored.
(c) When an operator chooses to use outside resources to conduct any process, for
example pigging, that affects the quality of the integrity management program, the
operator shall ensure control of such processes and document them within the quality
program.
$192. 915(a) Supervisory personnel. The integrity management program must
provide that each supervisor whose responsibilities relate to the integrity
management program possesses and maintains a thorough knowledge of the integrity
management program and of the elements for which the supervisor is responsible.
The program must provide that any person who qualifies as a supervisor for the
integrity management program has appropriate training or experience in the area for
which the person is responsible.
$192. 915(b) Persons who carry out assessments and evaluate assessment results. The
integrity management program must provide criteria for the qualification of any
person-
(1) Who conducts an integrity assessment allowed under this subpart; or
(2) Who reviews and analyzes the results from an integrity assessment and
evaluation; or
(3) Who makes decisions on actions to be taken based on these assessments.
~ Item 9A: $192. 911(l) and ASMK B31. 8S-2001, section 12. 2(b)(2)
Chapter 2 of the WGP Integrity Management Program Overview delineates
responsibilities; however, these responsibilities do not align with those delineated in
individual WGP O&M procedures applicable to the IM Program.
~ Item 9B: $192. 911(1) and ASMK B31. 8S-2001, section 12. 2(b)(3)
The WGP O&M manual has no procedures describing how internal Integrity Management
reviews are conducted or documented. Requirements for the conduct of annual reviews
should be tied to a specific calendar timeframe or event milestone.
~ Item 9C: $192. 911(l) and ASMK B31. 8S-2001, section 12. 2(b)(7)
WGP procedures do not document or track corrective actions identified by audits of the
Integrity Management Program.



~ Item 9D: $192. 911(l) and ASMK B31. 8S-2001, section 12. 2(c)
WGP needs to identify the minimum qualification requirements for vendor and WGP
personnel involved in the control of the outsourced resources affecting the quality of the
Integrity Management Program. In addition, to identifying the minimum qualification
requirements, WGP needs to ensure that personnel performing IM activities meet those
requirements.
~ Item 9E: $192. 911(1), ASMK B31. 8S-2001, section 12. 2{b){4) and $192. 915(a)
Chapter 14 of the Integrity Management Overview does not provide minimum
qualification requirement
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