# PAIUTE PIPELINE CO — Notice of Amendment

- **operation:** document
- **citation:** CPF 520070019M
- **title:** PAIUTE PIPELINE CO — Notice of Amendment
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2007-07-30
- **effective on:** Not available
- **summary:** CLOSED notice of amendment citing 192.905(a), 192.905(b), 192.905(c), 192.909(a), 192.911(c), 192.911(d), 192.911(e), 192.911(j), 192.911(k), 192.911(l), 192.917(a), 192.919(c), 192.921(a)(4), 192.925(b), 192.925(b)(1), 192.925(b)(2), 192.925(b)(3), 192.925(b)(3)(i), 192.925(b)(3)(ii)(b), 192.925(b)(3)(iii), 192.925(b)(3)(iv), 192.927(c)(1), 192.947(d).
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**body:**

Notice of Amendment involving PAIUTE PIPELINE CO. PHMSA's enforcement data identifies the cited regulations as 192.905(a),  192.905(b),  192.905(c),  192.909(a),  192.911(c),  192.911(d),  192.911(e),  192.911(j),  192.911(k),  192.911(l),  192.917(a),  192.919(c),  192.921(a)(4),  192.925(b),  192.925(b)(1),  192.925(b)(2),  192.925(b)(3),  192.925(b)(3)(i),  192.925(b)(3)(ii)(b),  192.925(b)(3)(iii),  192.925(b)(3)(iv),  192.927(c)(1),  192.947(d). The case was opened on 2007-07-30 and is reported as closed as of 2009-02-03. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

520070019M_notice of amendment_07302007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520070019M/520070019M_notice%20of%20amendment_07302007.pdf

520070019m_notice of amendment_07302007_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520070019M/520070019m_notice%20of%20amendment_07302007_text.pdf

520070019M_operator response to notice_09112007.pdf: https://primis.phmsa.dot.gov/enforcement-documents/520070019M/520070019M_operator%20response%20to%20notice_09112007.pdf

520070019m_notice of amendment_07302007_text.pdf

o
U S. Department
of Transportation
Pipeline and
Hazardous Materials Safety
Administration
$ENT TO COMPLIANCE REGISTiPP
Hardcopy Electrontcal y
¹ of Copiesg /Date o'7
12300 W Dakota Ave, SuIte 110
Lakewood, CO 80228
NOTICE OF AMENDMENT
CERTIFIED MAIL - RETURN RECEIPT RE UESTED
July 30, 2007
Ms. Marti Marek
Director, Engineering Staff
Southwest Gas Corporation
5421 Spring Mountam Road
Las Vegas, NV 89150
CPF 5-2007-0019M
Dear Ms. Marek:
On August 14-17 and August 28-31, 2006, representatives of the Pipeline and Hazardous
Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 Umted States Code,
inspected Southwest Gas Corporation and Paiute Pipeline Company's (SWG/Paiute) integrity
management program in Las Vegas, Nevada. Both entities are covered under the one Integrity
Management Program identified as Transmission Integrity Management Program (TRIMP).
On the basis of the inspection, PHMSA has identified the apparent inadequacies found within the
TRIMP plans or procedures, as described below:
High Consequence Area (HCA) Identification
g 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.
(b)(1) Identi Jted 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.
(2) If a public official with safety or emergency response or planning
responsibilities informs an operator that it does not have the information to
identify an identified site, the operator must use one of the following sources, as
appropriate, to identify these sites. (i) Visible marking (e. g. ,
a sign); or (ii) The
site is licensed or registered by a Federal, State, or local government agency; or
(iii) The site is on a list (including a list on an internet web site) or map
maintained by or available from a Federal, State, or local government agency
and available to the general public.
(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 g 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.
g 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 g 192. 911 and that addresses the risks on
each covered transmission pipeline segment.
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework
(see g 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 subsequent program must, at minimum, contain
the following elements. (When indicated, refer to ASME/ANSI B31. 8S (ibr, see g
192. 7) for more detailed information on the listed element. )



(a) An identiTication of all high consequence areas, in accordance with g 192. 905.
g 192. 947 What records must an operator keep?
An operator must maintain, for the useful life of the pipeline, records that
demonstrate compliance with the requirements of this subpart. At minimum, an
operator must maintain the following records for review during an inspection.
(d) Documents to support any decision, analysis and process developed and used
to implement and evaluate each element of the baseline assessment plan and
integrity management program. Documents include those developed and used in
support of any identification, calculation, amendment, modification,
justification, deviation and determination made, and any action taken to
implement and evaluate any of the program elements.
~ Item 1A: g 192. 905(a), g 192. 903(2), (3), and (4), g 192. 907(a) and g 192. 911(a)
The SWGiPaiute TRIMP and hnked Operations Manual sections do not define all
required process steps for identifying High Consequence Areas (HCA) in sufficient detail
to support consistent implementation of the segment identification process. A
considerable number of the HCA identification process steps that were described verbally
are not documented m the current TRIMP and hnked sections of the Operations Manual.
For example: The hnk from the TRIMP Plan to the "Mam and Service Design" portion of
Operations Manual does not provide process details (field measurements, use of field
measurements, processing of data and use of maps, how often it is done, who has to do
it).
~ Item 1B: g 192. 905(b), g 192. 903(4), and g 192. 947(d)
Decisions on which structures were considered identified sites are not documented. Field
information on excluded structures is not recorded. Examples that were included in the
"Main and Service Design" procedure and trainmg on HCA identification provide
incomplete guidance on what should be considered identified sites (e. g. ,
"stadium" and
"lake" examples). Consistent criteria for inclusion of specific types of areas (e. g. ,
parking lots) are not documented.
~ Item 1C: g 192. 905(b) and g 192. 947(d)
There is no documented program requirement to contact pubhc officials to obtain
information on potential identified sites. There are insufficient details provided for
contacting pubhc officials, such as a description of the method for establishing identified
sites, to ensure that the process is repeatable and thorough.



~ Item 1D: g 192. 903(c)
The process for revising HCAs or identifying new HCAs is not defined in sufficient
detail nor represented by procedures that describe how information on changes is
obtained, how the information is communicated to personnel responsible for updating
HCAs, how the information is used to update HCAs, how often this information is, —
obtained and used, and who is responsible for obtaining it. Changes that are required to
be addressed, but are not currently addressed by the TRIMP and implementing
procedures include:
a. Changes in pipehne maximum allowable operating pressure (MAOP),
b. Pipeline modifications affecting piping diameter,
c. Changes in the commodity transported in the pipeline,
d. Identification of new construction m the vicinity of the pipehne that results in
additional buildings intended for human occupancy or additional identified sites,
e Change in the use of existing buildings (e. g. ,
home),
hotel or house converted to nursing
f. Installation of new pipeline,
g. Change in pipeline class location (e. g. ,
class 2 to 3) or class location boundary,
h. Pipeline reroutes
Corrections to erroneous pipeline center hne data.
As a specific example, there is no detailed process description or procedure that addresses
how field personnel obtain and communicate information on new development along the
pipeline that could lead to additional HCAs being defined.
2. Baseline Assessment Plan
g 192. 911 What are the elements of an integrity management program'?
An operator's initial integrity management program begins with a framework (see g
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 subsequent program must, at minimum, contain the following elements. (When
indicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed
information on the listed element. )
(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.
g 192. 919 What must be in the baseline assessment plan?



An operator must include each of the following elements in its written baseline
assessment plan:
(c) A schedule for completing the integrity assessment of all covered segments,
including risk factors considered in establishing the assessment schedule;
g 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 (See g 192. 917).
(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.
~ Item 2A: g 192. 921 (a)(4)
A notification to PHMSA has not been filed for the use of guided wave or Long Range
Ultra Sonic (LRUT) technology as an "other" technology for assessing the carrier pip8 m
casings. The basis for this failure to notify is that SWG/Paiute is using guided wave as a
complementary tool to Pipehne Current Mapping (PCM) for these situations. However,
PCM is not considered an effective tool to assess pipe within a casing. In fact, NACE RP
0502-2002, Table 2 indicates that additional considerations are needed for External
Corrosion Direct Assessment (ECDA) tool selection for all cased piping. Therefore, use
of guided wave is considered "new" technology and requires notification.
~ Item 2B: g 192. 919 (c)
The SWG/Paiute Basehne Assessment Plan (BAP) does not contain proposed assessment
completion dates. As such, it is not possible to verify that assessments are completed on
schedule and in accordance with the plan.
~ Item 2C: g 192. 911(k)
There are insufficient program procedures to describe the method by which the Operator
keeps the BAP up-to-date with any newly arising information. Procedures to describe the
process by which the Operator makes needed BAP in accordance with referenced
Standard ASME B31. 85-2001 do not include:



Reasons for changes to the BAP,
ii. Authority for approving changes,
ni. Analysis of imphcations,
iv. Communication of changes to affected parties.
Identify Threats, Data Integration, and Risk Assessment
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
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 subsequent program must, at minimum, contain the following elements.
(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 (g
192. 917) and to evaluate the merits of additional preventive and mitigative measures
(g 192. 935) for each covered segment.
g 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 (ibr, see g
192. 7), section 2, which are grouped under the following four categories: (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.
(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 (gg 192. 919, 192. 921,
192. 937), and to determine what additional preventive and mitigative measures are
needed (g 192. 935) for the covered segment.
~ Item 3A: g 192. 911(c) and g 192. 917(a)
The documented process for threat identification and evaluation does not specify timing
of steps and the relation of threat evaluation steps to the conduct of basehne assessments.



The timmg of steps m the current threat identification does not support the scheduling of
integrity assessments in the BAP, because the specific required assessment methods
would not be known until after completion of threat identification and evaluation
(performed at the time of the assessment). Depending on the threats found to apply to a
specific HCA, all of the following methods could be necessary: External Corrosion
Direct Assessment (ECDA), Internal Corrosion Direct Assessment (ICDA), Stress, —
Corrosion Cracking Direct Assessment (SCCDA), and hydro-testing for manufacturing or
construction defects or Low Frequency Electric Resistance Welded (LFERW) pipe.
~ Item 3B: g 192. 911(c) and g 192. 917(a)
The screening criteria used in the evaluation of Stress corrosion Cracking (SCC) do not
address near neutral SCC.
~ Item 3C: g 192. 911(c) and g 192. 917(a)
The method of evaluation for interactive threats is not documented. No evaluation was
performed or documented for those HCAs that had completed threat and basehne
assessments. In addition, there is no adjustment made for these threats in the risk
algorithm.
~ Item 3D: g 192. 911(c) and g 192. 917(c)
The risk assessment process is not sufficiently detailed to identify how the risk
assessment supports the objectives required by ASME B31. 8S.
Section 5. 3. For
,
example, the use of risk assessment to support preventive and mitigative measure
evaluations or determination of assessment intervals is not addressed.
~ Item 3E: g 192. 911(c) and g 192. 917(c)
The scoring in the population consequences index shows some logical inconsistencies. A
single identified site would be given a higher score than any number of residences within
the Potential Impact Radius (PIR) used to estabhsh the HCA. The use of a calculated
radius based on the equation in B31. 8S (CFER Circle equation) as a vanable is used
without consideration of the number of residences or identified sites that exist within the
circle.
~ Item 3F: g 192. 911(c) and g 192. 917(c)
The risk assessment model does not adequately reflect leak/incident data. The current
treatment is to associate the occurrence of a leak or incident with a specific pipeline
segment. The applicability of the leak or incident to other HCAs is not considered in the
current risk assessment process.



~ Item 3G: g 192. 911(c) and g 192. 917(c)
The basis for the risk model weights for threat categories is not documented. The weight
used for third party damage is considerably higher than the average for transmission
pipelines. Although it may be suitable for the distribution portions of the SWG/Paiute
system, whether the same weights should be apphed to Pasute or certain transmission
sections of the SWG/Paiute system (e. g. ,
Southwest Gas Transmiss&on Co. ) have not been
evaluated.
~ Item 3H: g 192. 911(c) and g 192. 917(c)
Neither the TRIMP Plan nor the TRIMP Procedure adequately defines steps for revisions
to the risk assessment if new information is obtained or conditions change on the pipehne
segments.
~ Item 3I: g 192. 911(c) and g 192. 917(c)
The method for validation of the risk assessment results by SMEs is not documented in
the TRIMP Plan or TRIMP Procedure.
Direct Assessment (DA) Plan
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
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 subsequent program must, at minimum, contain the following elements.
(d) A direct assessment plan, if applicable, meeting the requirements of g 192. 923,
and depending on the threat assessed, of g 192. 925, 192. 927, or 192. 929.
g 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
ASMEIANSI B31. 8S (ibr, see g 192. 7), section 6. 4, and in NACE RP 0502 — 2002 (ibr,
see g 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 (g 192. 917(b)) to evaluate the covered segment for the threat of third
party damage, and to address the threat as required by g 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.
(ii) The basis on which an operator selects at least two different, but complementary
indirect assessment tools to assess each ECDA Region. If an operator utilizes an
indirect inspection method that is not discussed in Appendix A of NACE RP0502—
2002, the operator must demonstrate the applicability, validation basis, equipment
used, application procedure, and utilization of data for the inspection method.
(2) Indirect Examination. In addition to the requirements in ASME/ANSI 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—
(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
NACE RP0502 — 2002), or



(B) Root cause analysis reveals conditions for which ECDA is not suitable (Section
5. 6. 2 of NACE RP0502 — 2002).
(iii) Criteria and notification procedures for any changes in the ECDA Plan,
including changes that affect the severity classification, the priority of direct
examination, and the time frame for direct examination of indications; and (iv)
Criteria that describe how and on what basis an operator will reclassify and
reprioritize any of the provisions that are specified in section 5. 9 of NACE RP0502—
2002.
(4) Post assessment and continuing evaluation. In addition to the requirements in
ASME/ANSI B31. 8S section 6. 4 and NACE RP 0502 — 2002, section 6, the plan's
procedures for post assessment of the effectiveness of the ECDA process must
include—
(i) Measures for evaluating the long-term effectiveness of ECDA in addressing
external corrosion in covered segments;
and
(ii) Criteria for evaluating whether conditions discovered by direct examination of
indications in each ECDA region indicate a need for reassessment of the covered
segment at an interval less than that specified in g 192. 939. (See Appendix D of
NACE RP0502 — 2002. )
~ Item 4A: g 192. 911(d) and g 192. 925(b)
The TRIMP Procedure, Part 2, does not provide adequate procedural requirements
sufficient to describe how the ECDA Plan is to be conducted in a repeatable consistent
manner. This lack of program detail is noted through several of the PHMSA protocols
for the Direct Assessment processes, including [D. Ol. a] [D. 02. a] [D. 02. b] [D. 02. d]
[D. 03. a] [D. 04. e] [D. 04. g].
~ Item 4B: g 192. 925(b)
For the INA Road line, the pipeline is compressed of 4", 6", 8" and 12" diameter pipe;
however the preassessment only discusses 4", 6" and 12". Three sections of 8" pipe were
not mentioned. The final report only discusses 6" and 12" without an explanation of why
all sizes were not addressed, or how SWG/Paiute determmed preassessment information
of the 4", 6" and 12" lines was adequate and why the information m the final report on
the 6" and 12" lines was sufficient.
~ Item 4C: g 192. 925(b) and $192. 947(d)
The ECDA process for the INA Road does not fully integrate all leak data. The ECDA
process considered a total of 35 leak mamtenance reports (LMRs) for that segment.
However, records provided mdicated that only 8 were reviewed and utihzed in pre-
- 10-



assessment to capture coating data. No explanation of how the data was analyzed or why
only 8 leak records were considered in the ECDA assessment.
~ Item 4D: g 192. 925(b)(1) and $192. 947(d)
The NACE requirements for selecting and documenting the basis for indirect assessment
tools are not described in SWG's TRIMP, Part 2, Table 9. The basis for deviation from
the NACE indirect tool selection matrix has not been documented.
~ Item 4K: g 192. 925(b)
The SWG/Paiute TRIMP does not provide sufficient details within its procedures for
ECDA Region definition based on indirect inspection tools selected, corrosion histories,
and new data and information received from field surveys and indirect tool readings.
~ Item 4F: Q 192. 925(b)(1), Q 192. 925(b)(3)(i) and Q 192. 925(c)(5)(ii)
The operator's Direct Assessment (DA) Plan does not provide criteria for performance of
ECDA activities m each of the program phases, i. e.
, pre-assessment, indirect
examination, and direct examination.
~ Item 4G: g 192. 925(b)(2)
TRIMP Procedure, Part 2 does not provide proper linkage to the abnormal operations
procedure for cathodic protection (CP). The operator stated that the ECDA process stops
when a low CP reading is identified until the CP can be brought within acceptance
criteria and the abnormal operations procedural requirements are performed. No
documentation of this approach exists within the TRIMP.
~ Item 4H: g 192. 947(d)
PHMSA inspection team review of the SWG/Paiute use of LRUT in the Paradise Pipehne
Flamingo Wash location, determined that the indication locations did not match when
performing LRUT from both directions. There was no documentation or process by
which this discrepancy was resolved.
~ Item 4I: g 192. 925(b)(3)
A review of the Paradise pipehne ECDA Records indicated that the appropriate number
of ECDA direct examinations was not performed. Only one "C-level" anomaly was
excavated in region 1, only one "C" and no "no-indication" locations were excavated in
Region 2. In region 1 in accordance with NACE (5. 10 and (6. 4 criteria, SWG/Paiute did
not excavate an additional "B" and in region 2 SWG/Paiute did not excavate an
additional "C" and a "no-indication" location.
-11-



~ Item 4J: g 192. 925(b)(3)(ii)(b)
SWG/Paiute does not have a documented root cause determination process that will
enable them to determine if ECDA is or is not well-suited for assessing pipeline integrity.
~ Item 4K: g 192. 925(b)
TRIMP Procedure, Part 2, Section 9. 18. 1 states that an evaluation to assess the indirect
inspection data and the results from the remaining strength evaluation and the root cause
analyses must be performed.
TRIMP Procedure, Part 2, Section 9. 18. 2 states that the purpose of the evaluation is to
critically assess the criteria used to categorize the need for repair, and to critically assess
the criteria used to classify the severity of individual indications.
These sections are simply a restatement of NACE RP0502, Section 5. 8 which requires
the operator to conduct an In-Process Evaluation. The TRIMP wording does not describe
how Paiute will actually carry out the evaluation, and Paiute was unable to provide
documentation to demonstrate they performed the evaluation.
~ Item 4L: g 192. 925(b)(3)(iv)
A review of the Victorville, California ECDA data revealed that the Baseline Assessment
Results report, the ECDA Severity Analysis Table produced by Mears (contractor), and
the "Direct Examinations Dig Locations Listing" contain the indirect examination
priorities for indications. These documents do not match in their priorities for the
indirect inspections. There is no documentation of the process to establish the final dig
list. It is also not clear how feedback is given to Mears to ensure that they make the
proper priority call on indirect examination indications in the future.
~ Item 4M: g 192. 925(b)(3)(iii), g 192. 909, and g 192. 911(k)
Regarding establishing and implementing criteria and internal notification procedures for
changes in the ECDA Plan (including those affecting severity classification, priority of
direct examination, and the time frame for direct examination of indications),
SWG/Paiute identified ECDA procedure (TRIMP Procedure, Part 2, Section 9. 23) which
addresses FEEDBACK AND CONTINUOUS IMPROVEMENT, as well as TRIMP Plan
Section 16. 5 which states "Company management and other appropriate personnel will
be involved in the TRIMP communication process and support the integrity management
program", and "Changes to the integrity management program shall be communicated as
necessary". This wording is too general to require effective internal communication of
changes in ECDA plan.
— 12-



~ Item 4N: g 192. 927(c)(1) and g 192. 927(c)(5)(i)
SWG/Paiute was unable to demonstrate a structured process for data gathering and
integration to support performance of the ICDA methodology. The SWG/Paiute ICDA
Plan repeats the requirements contained in the proposed NACE RP ICDA Methodology.
~ Item 40: g 192. 927(c)(5)(i).
The PHMSA inspection team reviewed the Paradise Pipehne assessment and determined
that critical angles were not identified although dig locations were identified and
excavated.
5. Remediation
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
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 subsequent program must, at minimum, contain the following elements.
(e) Provisions meeting the requirements of g 192. 933 for remediating conditions
found during an integrity assessment.
g 192. 933 What actions must be taken to address integrity issues?
(a) General requirements. . . 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. . .
. . . 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.
(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.
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(c) Schedule for evaluation and remediation. 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 justify the reasoits
why it cannot meet the schedule and that the changed schedule will not jeopardize
public safety.
(d) Special requirements for scheduling remediation. —
(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% of the pipeline's diameter (0. 250 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.
g 192. 947 What records must an operator keep?
An operator must maintain, for the useful life of the pipeline, records that
demonstrate compliance with the requirements of this subpart. At minimum, an
operator must maintain the following records for review during an inspection.
(f) Schedule required by g 192. 933 that prioritizes the conditions found during an
assessment for evaluation and remediation, including technical justifications for the
schedule
~ Item 5A: g 192. 911(e) and g 192. 933(b)
The SWG/Paiute TRIMP does not provide information on where the date when the
"Discovery of Condition" as defined in 192. 933(b) is to be documented.
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~ Item 5B: g 192. 911(e) and g 192. 933(d)(1)
The SWG/Paiute Remediation Design procedure does not contam provisions to require a
temporary pressure reduction or the pipehne to be shut down upon discovery of all
immediate repair conditions.
~ Item 5C: g 192. 911(e) and g 192. 933(d)(3)
The SWG/Paiute TRIMP does not contam program requirements for the recording and
monitoring of anomahes that are classified as "monitored conditions" during subsequent
risk or integrity assessments for any change in their status that would require remediation.
Item 5D: g 192. 911(e), g 192. 933(a), g 192. 933(c), and g 192. 947(f)
There are no program requirements that specify how and by whom technical justifications
for schedule change contingencies are to be developed and documented.
Recordkeeping
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
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 subsequent program must, at minimum, contain the following elements.
(j) Record keeping provisions meeting the requirements of g 192. 947.
g 192. 947 What records must an operator keep?
An operator must maintain, for the useful life of the pipeline, records that
demonstrate compliance with the requirements of this subpart. At minimum, an
operator must maintain the following records for review during an inspection.
(a) A written integrity management program in accordance with g 192. 907;
(b) Documents supporting the threat identification and risk assessment in
accordance with g 192. 917;
(c) A written baseline assessment plan in accordance with g 192. 919;
(d) Documents to support any decision, analysis and process developed and used to
implement and evaluate each element of the baseline assessment plan and integrity
management program. Documents include those developed and used in support of
any identification, calculation, amendment, modification, justification, deviation



and determination made, and any action taken to implement and evaluate any of the
program elements;
(e) Documents that demonstrate personnel have the required training, including a
description of the training program, in
accordance with g 192. 915;
(f) Schedule required by g 192. 933 that prioritizes the conditions found during an
assessment for evaluation and remediation, including technical justifications for the
schedule;
(g) Documents to carry out the requirements in gg 192. 923 through 192. 929 for a
direct assessment plan;
(h) Documents to carry out the requirements in g 192. 931 for confirmatory direct
assessment;
(i) Verification that an operator has provided any documentation or notification
required by this subpart to be provided to OPS, and when applicable, a State
authority with which OPS has an interstate agent agreement, and a State or local
pipeline safety authority that regulates a covered pipeline segment within that State.
~ Item 6A: g 192. 911(j) and g 192. 947
The SWG/Paiute TRIMP and implementing procedures do not have instructions on
developing records and archivmg them appropnately. As an example, there is no record
of decisions made for identified site surveys and the basis for inclusion or exclusion.
7. Management of Change
g 192. 909 How can an operator change its integrity management program?
(a) General. An operator must document any change to its program and the reasons
for the change before implementing the change.
(b) Notification. An operator must notify OPS, in accordance with $192. 949, of any
change to the program that may substantially affect the program's implementation
or may significantly modify the program or schedule for carrying out the program
elements. 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. An
operator must provide the notification within 30 days after adopting this type of
change into its program.
g 192. 911 What are the elements of an integrity management program?
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An operator's initial integrity management program begins with a framework (see g
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 subsequent program must, at minimum, contain the following elements. (When
indicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed
information on the listed element. )
(k) A management of change process as outlined in ASME/ANSI B31. 8S, section 11.
~ Item 7A: g 192. 909(a), g 192. 909(b) and g 192. 911(k)
The SAG/Paiute Management of Change (MOC) process is fragmented and does not
contain sufficient detail to ensure that changes are thoroughly evaluated, tracked and
reviewed and that all required aspects of the changes are documented. This issue
includes changes to the IMP, documents developed by the IMP, procedure changes, and
physical system changes, such as pipehne replacements, MOP revisions where uprating
to a value greater than 20% SMYS is bemg considered.
Quality Assurance
g 192. 911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see g
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 subsequent program must, at minimum, contain the following elements. (When
indicated, refer to ASME/ANSI B31. 8S (ibr, see g 192. 7) for more detailed
information on the listed element. )
(l) A quality assurance process as outline
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