# ENABLE GAS TRANSMISSION, LLC — Notice of Amendment

- **operation:** document
- **citation:** CPF 420071005M
- **title:** ENABLE GAS TRANSMISSION, LLC — Notice of Amendment
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2007-03-29
- **effective on:** Not available
- **summary:** CLOSED notice of amendment citing 192.903(c), 192.905(a), 192.907(a), 192.911(k), 192.911(l), 192.917(b), 192.917(e)(3), 192.917(e)(5), 192.921(a)(1), 192.925(b)(2), 192.927(c), 192.929(b)(1), 192.933(a), 192.933(c), 192.935(a), 192.935(b)(2), 192.937(b), 192.947(d).
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Notice of Amendment involving ENABLE GAS TRANSMISSION, LLC. PHMSA's enforcement data identifies the cited regulations as 192.903(c),  192.905(a),  192.907(a),  192.911(k),  192.911(l),  192.917(b),  192.917(e)(3),  192.917(e)(5),  192.921(a)(1),  192.925(b)(2),  192.927(c),  192.929(b)(1),  192.933(a),  192.933(c),  192.935(a),  192.935(b)(2),  192.937(b),  192.947(d). The case was opened on 2007-03-29 and is reported as closed as of 2008-01-30. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420071005M_operator response to notice letter_06292007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071005M/420071005M_operator%20response%20to%20notice%20letter_06292007.pdf

420071005M_Operator Response_10052007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071005M/420071005M_Operator%20Response_10052007.pdf

CPF 4-2007-1005M CenterPoint Engergy - NOA.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420071005M/CPF%204-2007-1005M%20CenterPoint%20Engergy%20-%20NOA.pdf

CPF 4-2007-1005M CenterPoint Engergy - NOA.pdf

U.S. Department
of Transportation
Pipeline and
Hazardous Materials Safety
Adminlstration
8701 South Gessner, Suite 11 10
Houston. TX 77074
NOTICE OF AMENDMENT
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
March 29,2007
Walter Ferguson
Senior Vice President and COO, Pipeline Services
CenterPoint Energy Gas Transmission
525 Milam
Shreveport, LA 71101
CPF 4-2007-1 005M
Dear Mr. Ferguson:
On September 12 - 16 and November 14 - 18,2005, representatives of the Pipeline and
Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United
States Code inspected CenterPoint Energy Gas Transmission's (CE) procedures for Integrity
Management in Shreveport, Louisiana.
On the basis of the inspection, PHMSA has identified the apparent inadequacies found within
CE1s plans or procedures, as described below:
1. § 192.903 What definitions apply to this subpart?
The following definitions apply to this subpart:
High consequence area means an area established by one of the methods
described in paragraphs (1) or (2) as follows:
1. An area defined as-
i.
A Class 3 location under 5 192.5; or
..
11. A Class 4 location under § 192.5; or
iii. Any area in a Class 1 or Class 2 location where the potential impact
radius is greater than 660 feet (200 meters), and the area within a potential
impact circle contains 20 or more buildings intended for human
occupancy; or



iv. Any area in a Class 1 or Class 2 location where the potential impact
circle contains an identified site.
2. The area within a potential impact circle containing-
i. 20 or more buildings intended for human occupancy, unless the
exception in paragraph (4) applies; or
ii. An identified site.
5 192.905 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 (a) or (b) from the definition in
CFR: 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 E.I. for
guidance on identifying high consequence areas.)
CE must modify its procedures to describe how and when either of the two HCA
identification methods in document PS-03-01-200, section 2.6 will be utilized and where
the information will be maintained or stored.
5 192.903 (see above)
(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 5192.903, 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.
CE must modify its procedure so that it clearly describes the process for updating and
documenting the HCA analysis. It must include procedures which clearly define reviews
for charlges in pipeline systems which could impact HCA identification results, and it
must provide sufficient detail to ensure all new HCAs are identified through processes
CE describes as routine. Accordingly, CE procedure PS-03-01-105, "HCA-Class
Review" describes the process for updating the HCA analysis. However, it was noted
that the annual and ongoing updates to the HCA identification did not include a review of
appropriate informational sources for changes in buildirrg use that may impact identified
site determinations. Additionally, changes in pipeline systems must be reviewed for
potential impact to HCA identification results. These types of changes are not
adequately addressed in CE's procedures. Finally, CE's procedure is not sufficiently
detailed to provide the needed level of specificity to assure that all HCAs are routinely
found.



3. 3 192.907 What must an operator do to implement this subpart?
(a) General. No later than December 17,2004, an operator of a covered pipeline
segment must develop and follow a written integrity management program that
contains all the elements described in CFR: 192.91 1 and that addresses the risks
on each covered transmission pipeline segment. The initial integrity management
program must consist, at a minimum, of a framework that describes the process
for implementing each program element, how relevant decisions will be made and
by whom, a time line for completing the work to implement the program element,
and how information gained from experience will be continuously incorporated
into the program. The framework will evolve into a more detailed and
comprehensive program. An operator must make continual improvements to the
program.
A. B. With regard to the following CE Procedures, CE must modify its procedures
beyond a framework into more detailed and comprehensive programs which
describe the 'who,' 'what,' 'where,' 'how,' and 'when' of the procedures to ensure
that they are consistently implemanted. Currently the procedures do not
sufficiently detail the implementation of the processes to ensure that they are
consistently implemented. CE must modify the following procedures and ensure
that each provides the necessary specificity to ensure consistent application
across the CE pipeline systems.
PS-03-01-105 HCA-Class Review
PS-03-01-110 Gather, Review, and Integrate Data
PS-03-01-200 HCA Segment Identification
PS-03-01-216 Threat Identification and Risk Assessment
PS-03-01-258 Preventive and Mitigative Measures
PS-03-01-264 IMP Communications Plan
In order to assure that there are continual improvements made to the prograni,
CE must modify procedures to ensure that there is continual feedback from the
performance of ongoing direct assessments on future direct assessments.
Accordingly, CE must modify procedures PS-03-01-232, "External Corrosion
Direct Assessment," PS-03-01-230, "Direct Assessment Plan," and PS-03-01-
268, "IMP Quality Assurance." CE must modify these procedures to ensure that
the continual improvement process is implemented consistently. Accordingly,
these requirements are due to the fact that during the inspection there was no
documentation that feedback from direct assessments performed early in the
schedule was used for assessments performed later. CE procedures PS-03-01-
232, "External Corrosion Direct Assessment," PS-03-01-230, "Direct Assessment
Plan," and PS-03-01-268, "IMP Quality Assurance", Appendix A states that CE
will apply the lessons learned on one ECDA assessment to future assessments
via the continual improvement process and the in-process evaluation step.
NACE RP 0502 S6.5 and §192.925(3) (iii) require operators to continually
irr~prove and use feedback to improve ECDA assessments. On the lines that
have had ECDA assessments, there were no completed post assessments, no
documentation that the lessons learned on one or more the ECDA assessments
were factored into future assessments, and there were no notifications of
changes made in the ECDA process as the result of any lessons learned.



4. 5. 3 192.911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see
CFR: 192.907) and evolves into a more detailed and comprehensive integrity
management program, as information is gained and incorporated into the
program. An operator must make continual improvements to its program. The
initial program framework and subserjuent program must, at minimum, contain
the following elements. (When indicated, refer to ASMEIANSI 831.8s for more
detailed information on the listed element.)
(k) A management of change process as outlined in ASMEIANSI B31.8S, Section
11.
ASME /ANSI B31.8S, 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. Etc.
(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. Etc.
CE must modify its Management of Change procedure and process to ensure that
impacts of changes to organizations and changes to pipeline systems and their integrity
are considered before being implemented. Accordingly, CE addresses their
Management of Change (MOC) process in procedure PS-03-01-266. The "Purpose"
section of the document limits the MOC process to changes in the IMP Program.
Additionally, the MOC process does not snsure that integrity management chauges are
properly reflected in the pipeline system and that pipeline system changes are properly
reflected in the integrity management program. CE's procedure PS-03-01-266, "IMP
Management of Change," describes the types of changes covered by CE's company-
wide management of change process, including changes to a process, policy,
procedure, standard, handbook or manual. However, changes to organizations and
changes to pipeline systems and their integrity are not addressed in this process and CE
must modify these procedures to address these requirements. Further, while the CE
IMP management of change process discusses impacts from pipeline equipment
additions, deletions or modifications, changes to product being transported, and
owrating condition changes, the procedure does not adequately address how these
types of changes are monitored and evaluated for IMP impact. Thus CE must change
the procedure to address how these changes are monitored and evaluated for IMP
impact.
3 192.91 1 (see above)
(I) Quality assurance process as outlined in ASMEIANSI B31.8S, Section 12.
ASMEIANSI B31.8S, Section 12.2 Quality Management Control
(b) Specifically, activities that should be included in the quality control program
are as follows:



6. 7. (7) Corrective actions to improve the integrity management program or quality
plan shall be documented and the effectiveness of their implementation
monitored.
CE must modify its procedures to ensure it has an effective quality control program to
determine the criteria and methods needed to ensure that both the operation and control
of IM processes are effective and accurate through documentation, implementation, and
maintenance. Accordingly, CE's IM quality control procedure, PS-03-01-268, section 2.2
states that the operator has assessed and developed processes to determine the criteria
and methods needed to ensure that both the operation and control of IIV processes are
effective. However, the inspection team identified numerous processes where the lack
of established quality criteria contributed to poor process implementation, including: risk
analysis data collection and evaluation; direct assessment minimum data requirements;
preventive and mitigative decision-making; post assessment evaluations; documentation
of remediation efforts; and periodic evaluations.
§ 192.91 1 (1) (see above)
12.2 Quality Management Control
(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.
CE must modify its procedures to ensure a formal process exists which can be
implemented consistently for providing oversight of outside resources. Accordingly, CE
procedure PS-03-01-268, "IMP Quality Assurance" describes the quality assurance
activities related to the IM program. This process does not adequately address quality
requirements for providing oversight of outside resources, such as assessment,
excavation, and remediation of pipeline anomalies.
5 192.917 How does an operator identify potential threats to pipeline integrity and
use the threat identification in its integrity program?
(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 could be relevant to the covered
segment. In performing this data gathering and integration, an operator must
follow the requirements in ASMElANSl 631 .8S, section 4. At a minimum, an
operator must gather and evaluate the set of data specified in Appendix A to
ASMElANSl 631.8S, 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.
A. CE must modify its procedures to ensure that it provides technical justifications
for assumptions used in the risk assessment process. In addition, CE must
modify its procedures to ensure data integration is thorough, complete, and
consistent and it must develop evaluation procedures to ensure the consistent
application of data integration. This requirement is consistent with Section 4 of
ASNIEIANSI 831.85 4.4 "Data Collection, Review, and Analysis" states "A plan



B. for collecting, reviewing, and analyzing the data shall be created and in place
from the conception of the data collection effort. These processes are needed to
verify the quality and consistency of the data. Records shall be maintained
throughout the process that identify where, and how unsubstantiated data is used
in the risk assessment process so its potential impact on the variability and
accuracy of assessment results can be considered." Similarly, Section 2.4 of CE
procedure PS-03-01-216, states that "When data is missing or is questionable,
conservative assumptions shall be used when performing the risk assessment or
alternatively the pipe segment shall be prioritized to a higher level. For missing or
questionable data, default values shall be used. The default values shall be
documented and the reason for their selection shall also be documented. Efforts
shall be taken to replace missing or questionable data with reliable, accurate
data. These efforts may include additional field surveys or inspections to obtain
the data." At the time of this inspection, CE had pulled all of the data available
from segments in HCA areas. CE expected that they would complete their data
acquisition on the entire pipeline system in about one year. The risk model
fields reviewed by the inspection team (Line MRT ML2) contained numerous
examples where actual data was not entered. CE used a default value of 0.49
(from 0 to 1 .O) when data was missing (refer to PS-03-01-216 Appendix B,
section 6.0 and Table, "Risk Variables Used for Threat Calculations"). This
default value puts the risk factor in the middle of the possible risk range. No
technical justification was provided that supported the use of this value for all
instances when data was missing from the risk analysis.
CE must develop a process to incorporate new data into the risk analysis when
changes in data occur (e.g., assessment results such as identification of MIC).
The frequency should be sufficient to ensure that risks are appropriately
addressed for any applicable HCAs. In addition, the identification of missing risk
data in the risk analysis must be expedited and tracked in a more formal manner.
Accordirlgly, the inspection team reviewed data in the risk analysis data-base
(vertical slice review of line MRT ML2) and determined that data was missing or
unavailable. At the time of this inspection, CE had pulled all of the data available
from segments in HCA areas. CE expected that they would complete their data
acquisition on the entire pipeline system in about one year. In response to
inquires made by the inspection team regarding the tracking of missing data, CE
stated that they were not formally tracking missing data and could not provide a
status of what data was missing for which segments.
8. 3 192.917 (see above)
(e) Actions to address particular threats. If an operator identifies any of the
following threats, the operator must take the following actions to address the
threat.
(3) Manufacturing and construction defects. If an operator identifies the threat of
manufacturing and construction defects (including seam defects) in the covered
segment, an operator must analyze the covered segment to determine the risk of
failure from these defects. The analysis must consider the results of prior
assessments on the covered segmenk. An operator may consider manufacturing
and construction related defects to be stable defects if the operating pressure on
the covered segment has not increased over the maximum operating pressure



9. 10. experienced during the five years precedirlg identification of the high
consequence area. 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.
i. Operating pressure increases above the maximum operating
pressure experienced during the preceding five years;
ii. MAOP increases; or
iii. The stresses leading to cyclic fatigue increase.
CE must modify its procedures to assure that threats to specific pipeline segments from
manufacturing and construction defects are reviewed against any MAOP increases in
order to eliminate potential threats. Accordingly, neither section 2.3 nor section 2.5 in
CE's document no. PS-03-01-216, "Threat Identification and Risk Assessment"
addressed how the need for review against MAOP increases would be addressed. CE
was unable to produce documentation related to MAOP increases for the last five years.
CE's procedure PS-03-01-216, "Threat Identification and Risk Assessment" must
address how MAOP will be reviewed to eliminate the threats from manufacturing and
construction defects.
§ 192.917 (e) (see above)
(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.
CE must modify its procedure, PS-03-01-258, "Preventive and Mitigative Measures," to
include the necessary specificity to address the need to evaluate other covered and non-
covered segments when corrosion exists on a covered segment that could adversely
impact the integrity of the line. During the inspection, the Inspection Team reviewed CE's
preventive and mitigative flow chart which provides structure to this undocumented
process.
§ 192.921 How is the baseline assessment to be conducted?
(a) Assessment methods. An operator must assess the integrity of the line pipe in
each covered segment by applying one or more of the following methods
depending on the threats to which the covered segment is susceptible. An
operator must select the method or methods best suited to address the threats
identified to the covered segment.
(1) Internal inspection tool or tools capable of detecting corrosion, and any other
threats to which the covered segment is susceptible. An operator must follow
ASlVlElANSl B31.8S, Section 6.2 in selecting the appropriate internal inspection
tools for the covered segment.



11. CE must modify its procedures to differentiate between the various types of ILI tools.
Accordingly, CE's procedure only indicates to "Perform ILI." CE describes the various
assessment methods in PS-03-01-224, "Assessment Methods Selection Process" which
references CE's "BAP - Integrity Assessment Selection Guide." Neither the procedure
nor the Guide specifies the type of ILI tot11 to be used for the threats to be assessed.
ASME B31.8S, Section 6.2, "Pipeline In-Line Inspection," describes tool section for the
various potential threats. According to ASME B31.8S section 6.2, "In-line inspection (ILI)
is an integrity assessment method used to locate and preliminarily characterize
indications in a pipeline. The effectiveness of the ILI tool used depends on the
conditions of the specific pipeline section to be inspected and how well the tool matches
the requirements set by the inspection objectives." To assure that the assessment
method matches the requirements set by the inspection objectives, CE must specify the
appropriate ILI tools planned for its assessments.
5 192.925 What are the requirements for using External Corrosion Direct
Assessment (ECDA)?
(b) General requirements. An operator that uses direct assessment to assess the
threat of external corrosion must follow the requirements in this section, in
ASMElANSl B31.8S (ibr, see §192.7), section 6.4, and in NACE RP 0502-2002 (ibr,
see 9192.7). 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 ).
(2) Indirect Examination. In addition to the requirements in ASMElANSl B31.8S
section 6.4 and NACE RP 0502-2002, section 4, the plan's procedures for indirect
examination of the ECDA regions must include -
..
11. 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.
CE must modify procedures PS-03-01-232, "External Corrosion Direct Assessment," PS-
03-01 -230, "Direct Assessment Plan," and PS-03-01-268, "IMP Quality Assurance",
Appendix A to ensure that whenever the spacing of the indirect tool readings is changed,
that the reason for the change will be documented and technically justified. CE must
modify procedures PS-03-01-232, "External Corrosion Direct Assessment," and PS-03-
01-230, "Direct Assessment Plan," to ensure that CE uses the latest information to
prioritize the urgency of the excavations based on the severity of the indication.



Accordingly, for the ECDA assessments performed on lines ALE, BT-1 and A-206, there
was no documentation on the tool spacing changes for the indirect inspection tools.
$192.925 (b) (2) (ii) requires that operators specify and document when the tool spacing
is changed over areas that have indications. The reason for the change must be
specified. In addition, the table which was presented to the inspection team and was
said to be used on one or more of the ECDA assessments regarding prioritization needs
to be formally incorporated into one of CE's procedures concerniug ECDA.
9 192.927 What are the requirements for using Internal Corrosion Direct
Assessment (ICDA)?
(c) The ICDA plan. An operator must develop and follow an ICDA plan that
provides for preassessment, identification of ICDA regions and excavation
locations, detailed examination of pipe at excavation locations, and post-
assessment evaluation and monitoring.
(2) ICDA region identification. An operator's plan must identify where all ICDA
Regions are located in the transmission system, in which covered segments are
located. An ICDA Region extends from the location where liquid may first enter
the pipeline and encompasses the entire area along the pipeline where internal
corrosion may occur and where further evaluation is needed. An ICDA Region
may encompass one or more covered segments. In the identification process, an
operator must use the model in GRI 02-0057, "Internal Corrosion Direct
Assessment of Gas Transmission Pipelines - Methodology." An operator may use
another model if the operator demonstrates it is equivalent to the one shown in
GRI 02-0057. A model must consider changes in pipe diameter, locations where
gas enters a line (potential to introduce liquid) and locations down stream of gas
draw-offs (where gas velocity is reduced ) to define the critical pipe angle of
inclination above which water film cannot be transported by the gas.
CE must modify its procedures to properly identify the source of the flow model used in
the ICDA Plan. Accordingly, the inspection team noted that the model specified in CE
procedure PS-03-01-238, "Dry Gas - Internal Corrosion Direct Assessment" section 3.4,
was described as the GRI model but the model in the procedure is not the GRI model
but rather the IVACE model. There was no specific concern here because the NACE
model has been validated against the GRI model and allowed for use. However, CE
needs to properly describe the model as the NACE model and not one that is based on
the Foude Number as in the GRI report.
5 192.927 (c) (see above)
(4) Post-assessment evaluation and monitoring. An operator's plan must provide
for evaluating the effectiveness of the ICDA process and continued monitoring of
covered segments where internal corrosion has been identified. 'The evaluation
and monitoring process includes:
i. Evaluating the effectiveness of ICDA as an assessment method for
addressing internal corrosion and determining whether a covered segment
should be reassessed at more frequent intervals than those specified in
9192.939. An operator must carry out this evaluation within a year of
conducting an ICDA;



14. CE must modify its procedures to ensure that post assessments for completed lnternal
Corrosion (IC) direct assessments are complete and consistently applied. There is no
documentation that feedback from IC direct assessments performed early in the
schedule was used for assessments periormed later. Accordingly, CE procedures PS-
03-01-238, "Dry Gas - lnternal Corrosion Direct Assessment," PS-03-01-230, "Direct
Assessment Plan," and PS-03-01-268, "IMP Quality Assurance", Appendix A state that
CE will apply the lessons learned from each ICDA assessment to future assessments.
s192.927 requires operators to continually improve and use feedback to improve ICDA
assessments. For the lines where the ICDA was complete there was no documentation
that the lessons learned were factored into future assessments and there was no
notification of changes made in the ICDA process as the result of any lessons learned.
CE procedure PS-03-01-238, "Dry Gas - lnternal Corrosion Direct Assessment," s6.2.1.2
states that improvements from one ICDA will be incorporated into future ICDA
assessments.
§ 192.927 (c) (4) (see above)
ii. Continually monitoring each covered segment where internal
corrosion has been identified using techniques such as coupons, UT
sensors or electronic probes, periodically drawing off liquids at low points
and chemically analyzing the liquids for the presence of corrosion
products. An operator must base the frequency of the monitoring and
liquid analysis on results from all integrity assessments that have been
conducted in accordance with the requirements of this subpart, and risk
factors specific to the covered segment. If an operator finds any evidence
of corrosion products in the covered segment, the operator must take
prompt action in accordance with one of the two following required actions
and remediate the conditions the operator finds in accordance with
51 92.933.
(A) Conduct excavations of covered segments at locations
downstream from where the electrolyte might have entered the pipe;
or
(B) Assess the covered segment using another integrity assessment
method allowed by this subpart.
CE must modify its procedures to ensure that the ICDA process provides assurance that
the monitoring actions for future internal corrosion will be accomplished. Accordingly,
CE procedures PS-03-01-238, "Dry Gas - lnternal Corrosion Direct Assessment," s5.10
states that "once a dig site has been excavated and the Direct Examination activities
have been completed, corrosion monitoring devices such as a coupon, electronic probe,
ultrasonic sensor, or electrical resistance matrix may be installed. The Corrosion
Manager shall determine whether or not to install a corrosion monitoring device and the
appropriate location within the DG-ICDA Region." CE must modify its procedures to
ensure mechanisms exist to inform the Corrosion Manager or other relevant personnel
what has been discovered at direct examination sites and if there is a need for corrosion
monitorirrg on this pipeline. One instance was identified where this information was not
forwarded to the Corrosion Manager.



15. 5 192.929 What are the requirements for using Direct Assessment for Stress
Corrosion Cracking (SCCDA)?
(b) General Requirements. An operator using direct assessment as an integrity
assessment method to address stress corrosion cracking in a covered pipeline
segment must have a plan that provides, at minimum, for -
(1) Data gathering and integration. An operator's plan must provide for a
systematic process to collect and evaluate data for all covered segments to
identify whether the conditions for SCC are present and to prioritize the covered
segments for assessment. This process must include gathering and evaluating
data related to SCC at all sites an operator excavates during the conduct of its
pipeline operations where the criteria in ASMElANSl B31.8S, Appendix A3.3
indicate the potential for SCC. This data includes at minimum, the data specified
in ASMElANSl B31.8S, Appendix A3.
A. CE must modify its SCCDA and related procedures to ensure that the gathering,
evaluation, and quality control of data related to SCC is consistently applied and
documented at all sites it excavates during the conduct of its pipeline operations
(not just covered segments) where the criteria indicate the potential for SCC. CE
must provide a notification to OPS and modify procedures as necessary to
ensure the notification or any future modifications of its proposed near-neutral
SCC plan. Finally, CE must modify its procedures to ensure the performance of
a spike test, per ASME B31.8S, when it experiences an in-service leak or rupture
attributable to SCC. Accordingly, CE procedures PS-03-01-240, "Stress
Corrosion Cracking Direct Assessment," PS-03-01-230, "Direct Assessment
Plan," and PS-03-01-268, "IMP Quality Assurance", Appendix A describe how
SCCDA assessments are to be conducted, the data to be collected and what
documentation needs to be retained. None of those procedures mandate that CE
obtain data on non-covered pipelines that may be susceptible to SCC. Studies
have shown that the screening criteria for both near neutral and high pH SCC
only cover 213 to 314 of the segments susceptible to SCC. Thus, operators are
expected to be looking for SCC in all areas of their pipelines. §192.917(e) (5)
has look beyond previsions for operators who have a history of any corrosion.
These previsions require operators to look at both covered and non-covered
segments that have sustained corrosion damage that is similar in physical and
environmental characteristics.
B. CE must modify procedures to ensure the quality of pre-assessment data for all
completed SCC direct assessments and develop quality controls for use of data
in future pre-assessments. During the review of SCC DA pre-assessments, data
quality was determined to be poor or missing. Accordingly, section A3.3 of
B31.8S states, "Where the operator is missing data, conservative assumptions
shall be used when performing the risk analysis or alternatively the segment shall
be prioritized higher." CE procedures PS-03-0 1-240, "Stress Corrosion Cracking
Direct Assessment," PS-03-01-230, "Direct Assessment Plan," and PS-03-01-
268, "IMP Quality Assurance", Appendix A require that the data elements used
for SCCDA be gathered. Based on some of the data elements that were
inspected, CE did not review the data as required in their procedures. This poor
quality data could lead to the incorrect bell hole locations being excavated. An
ineffective SCCDA may be the result of the poor quality data.



16. C. D. CE must modify its procedures to ensure the notification of OPS andlor local
regulatory authorities 180 days before proposing to use "other technology."
Accordingly, CE has not yet used its near neutral pH SCCDA process nor has it
notified any regulatory authority. However, section A3.1 of ASME 631.8s states,
"Near-neutral type of SCC similarly would require an inspection and alternative
mitigation plan." CE procedures PS-03-01-240, "Stress Corrosion Cracking
Direct Assessment," and PS-03-01-230, "Direct Assessment Plan," require CE
notify OPS and/or local regulatory authorities if CE plans to use "Other
Technology" as defined in 5192.921 (a)(4) (and follow the notification procedure
in 5192.949). ASlWE 631.8s for SCCDA covers only high pH SCC and requires
operators to develop a plan for near neutral pH SCC, which CE has done by
following the procedure in NACE RP 0204 for near neutral SCC. This
recommended practice is not referenced in the rule and thus is considered an
"Other Technology."
CE must modify its procedures to ensure that a spike hydrostatic pressure test
consistent with ASME 631.8s is conducted after an in-service leak or rupture
occurs which is attributed to SCC. Accordingly, section A3.4 of ASME 631.8s
states, "If the pipeline experiences an in-service leak or rupture, which is
attributed to SCC, the particular segment shall be subjected to a hydrostatic test
(as described below) within 12 months." CE procedures PS-03-01-240, "Stress
Corrosion Cracking Direct Assessment," and PS-03-01-230, "Direct Assessment
Plan," state that CE can use a pressure test to check for SCC. There is no
procedure requirement to perforr.1 a spike test following an in-service leak or
rupture attributable to SCC. ASME B31.8S specifically mandates that operators
use a spike hydrostatic pressure test following an in-service leak or rupture
attributable to SCC.
§ 192.933 What actions must be taken to address integrity issues?
(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 ASMElANSl B31G or RSTRENG or reduce the operating
pressure to a level not exceeding 80% 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.
A. CE must modify its procedures to ensure that ILI information is communicated to
the relevant departments in a timely manner to ensure the proper application of
any and all necessary remedial actions. Accordingly, ILI assessments completed



B. by CE identified internal corrosion but this information was not forwarded to
corrosion group for consideration of additional remedial actions. CE should
formalize this action within the IM program. CE procedure PS-03-01-250,
"Pipeline Evaluation and Remediation" describes the process for addressing
anomalous conditions identified through integrity management assessments. CE
procedures PS-03-01-110, "Gather, Review, and Integrate Data," describes the
process for data integration. Neither procedure specifies requirements to forward
internal corrosion information identified during lLls to the corrosion group for
evaluation. During the review of an ILI assessment (e.g., AT-5), the inspection
team identified an instance where internal corrosion was identified and this
information was not forwarded to the corrosion group for evaluation. CE
provided documentation to the inspection team that they had forwarded internal
corrosion information from other :LI assessments to the internal corrosion group
although the process was not formalized.
CE must modify its procedures to ensure the proper communication and
documentation of the operating pressure at the time of discovery related to an
immediate repair anomaly so that the required pressure reduction can be
accurately determined and documented. Accordingly, records reviewed by the
inspection team did not provide proper communications associated with
operating pressure at the time of discovery. Section 2.5 of CE procedure PS-03-
01 -250, "Pipeline Evaluation and Remediation" speci.fies the requirements for
temporary pressure reduction when an "immediate" repair anomaly is identified.
However, this procedure does not require that the operator document the
operating pressure at the time of discovery of the anomaly. During review of
assessment results, the inspection team noted that the operator did not
document the operating pressure at the time of discovery of anomalies. This lack
of documentation made it difficult to confirm that the pressure reduction was
appropriate.
17. 9 192.933 (see above)
(c) Schedule for evaluation and remediation. An operator must complete
remediation
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