# GULF SOUTH PIPELINE COMPANY, LLC — Notice of Amendment

- **operation:** document
- **citation:** CPF 220101011M
- **title:** GULF SOUTH PIPELINE COMPANY, LLC — Notice of Amendment
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2010-11-23
- **effective on:** Not available
- **summary:** CLOSED notice of amendment citing 192.461(a)(1), 192.463(a), 192.465(c), 192.473(a), 192.475(b)(1), 192.605(b)(8), 192.605(c)(4), 192.709(c), 192.736(c), 192.739(a)(1), 192.739(a)(4), 192.805(i), 192.911(l), 192.917(a), 192.917(b), 192.919(b), 192.925(b), 192.925(b)(3), 192.925(b)(4), 192.927(c)(1)(ii), 192.929(b)(2), 192.935(a), 192.939(a)(3).
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**body:**

Notice of Amendment involving GULF SOUTH PIPELINE COMPANY, LLC. PHMSA's enforcement data identifies the cited regulations as 192.461(a)(1),  192.463(a),  192.465(c),  192.473(a),  192.475(b)(1),  192.605(b)(8),  192.605(c)(4),  192.709(c),  192.736(c),  192.739(a)(1),  192.739(a)(4),  192.805(i),  192.911(l),  192.917(a),  192.917(b),  192.919(b),  192.925(b),  192.925(b)(3),  192.925(b)(4),  192.927(c)(1)(ii),  192.929(b)(2),  192.935(a),  192.939(a)(3). The case was opened on 2010-11-23 and is reported as closed as of 2012-04-03. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

220101011M_Closure Letter_04032012.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Closure%20Letter_04032012.pdf

220101011M_Closure Letter_04032012_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Closure%20Letter_04032012_text.pdf

220101011M_Notice Letter_11232010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Notice%20Letter_11232010.pdf

220101011M_Notice Letter_11232010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Notice%20Letter_11232010_text.pdf

220101011M_Operator_Response_and_Request_Extension_12162010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/220101011M/220101011M_Operator_Response_and_Request_Extension_12162010.pdf

220101011M_Notice Letter_11232010_text.pdf

NOTICE OF AMENDMENT
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
November 23, 2010
Mr. David Goodwin
Vice President Compliance and Operations Services
Gulf South Pipeline Co., L.P.
9 Greenway Plaza, Suite 2800
Houston, TX 77046
CPF 2-2010-1011M
Dear Mr. Goodwin:
Between June 22, 2009, and October 9, 2009, representatives of the Pipeline and Hazardous
Materials Safety Administration (PHMSA) inspected Gulf South Pipeline Co., L.P. (Gulf
South) procedures for Operations and Maintenance, Operator Qualification, and Integrity
Management in Gulf South’s offices and field locations in Louisiana, Texas, and Mississippi
pursuant to Chapter 601 of 49 United States Code.
On the basis of the inspection, PHMSA has identified apparent inadequacies found within
Gulf South’s Operations and Maintenance (O&M) procedures as described in Items 1 - 11
below:
1. § 192.739 Pressure limiting and regulating stations: Inspection and testing.
(a) Each pressure limiting station, relief device (except rupture discs), and
pressure regulating station and its equipment must be subjected at intervals not
exceeding 15 months, but at least once each calendar year, to inspections and
tests to determine that it is -
(1) In good mechanical condition;
Gulf South's written O&M relief valve inspection and testing procedures were
inadequate because they did not provide enough detail to instruct personnel on how to
properly determine if pilot-operated relief valves were in good mechanical condition.
Relief valves on pipeline systems must be inspected each calendar year for, among
other things, good mechanical condition. Gulf South’s work instruction procedure WI-
00074, Regulation and Over-Pressure Protection (rev. 06/15/09) did not contain the
detail required to instruct personnel on how to properly determine if pilot-operated



relief valves were in good mechanical condition. Instead WI-00074 refers Gulf South's
technicians to the relief valve manufacturer's operating and maintenance manuals for
inspection and testing. This reference was insufficient to perform the required task.
PHMSA inspectors observed Gulf South's technicians performing a pilot-operated
relief valve test at the Amite Town Border Station. The technicians explained that the
referenced manufacturer's documentation did not provide inspection and testing
requirements, and therefore, they did not known how to determine if the relief valve
was in good mechanical condition. Also, information provided by Gulf South relating
to a different relief valve manufacturer for a relief valve located at the International
Paper Meter Station did not specifically require the valve to be tested and observed to
be in good mechanical condition; i.e. to test and observe for the valve plug to move off
of the seat when required.
2. §192.739 Pressure limiting and regulating stations: Inspection and testing.
(a) Each pressure limiting station, relief device (except rupture discs), and
pressure regulating station and its equipment must be subjected at intervals not
exceeding 15 months, but at least once each calendar year, to inspections and
tests to determine that it is -
…. (4) Properly installed and protected from dirt, liquids, or other conditions
that might prevent proper operation.
Gulf South's written O&M relief valve inspection and testing procedures were
inadequate because they did not require inspections and tests to determine if pilot
operated relief valves were properly installed and protected from dirt, liquids, or other
conditions that might prevent proper operation.
Relief valves on pipeline systems must be inspected each calendar year to determine if
the relief valves were properly installed and protected from dirt, liquids, or other
conditions that might prevent proper operation. While Gulf South’s work instruction
procedure WI-00074, Regulation and Over-Pressure Protection (rev. 06/15/09)
required relief valve vent flapper and weep hole inspections of some relief valves, it
did not require these inspections for pilot operated relief valves.
3. §192.461 External corrosion control: Protective coating.
(a) Each external protective coating, whether conductive or insulating,
applied for the purpose of external corrosion control must—
(1) Be applied on a properly prepared surface;
Gulf South's written O&M external corrosion control protective coating procedures
were inadequate because they were incorrect, unclear, and lacked specificity.
Gulf South's work instruction procedure WI-00089, Apply Approved Coatings to
Above- and Belowground Piping (07/13/09) was incorrect in that it stated that a
company approved coatings list was provided in the Company Coating Specification
while no such document was provided. In lieu of the approved coatings list, Gulf
South provided a June 10, 2004, email which included a list of approved underground
coatings, with an attached undated draft procedure for selecting and applying below
grade field coatings. The draft procedure was incorrect because the application of 3M
hot melt patch sticks on thermal welded test lead installations was included (epoxy and
2



non-epoxy coated pipe) but the vendor's literature specifically stated that patch stick
applications should be restricted exclusively to the repair of pinholes and abrasions on
epoxy coatings.
Also, while protective coating surface preparation standards and specifications were
listed in Gulf South's WI-00089, including preparations for hand and power brush, it
was not clear what specific levels of surface preparation were required when small
coating repairs were made with products such as Enviroline 124 or Ceilcote 252. That
is, Section 5.3 of the undated draft procedure, Clean Small Areas by hand or Power
Brush, was unclear in that it required surface preparation by hand or power brush for
small areas such as taps, test lead connections, UT test areas and longitudinal seam
repairs, etc. but it did not include specific levels of surface preparation.
The draft procedure also lacked specificity. For example, one of the approved products
was Tapecoat TC 7100 Wet Bond Gray Epoxy. Detailed application procedures for
this product were not defined or directly referenced in the draft procedure. Moreover,
the Tapecoat published product information provided by Gulf South contained very
little detail, and recommended that a technician see the “detailed Field Specification
for complete instructions” and further indicated that Tapecoat agents were
strategically located throughout the world to provide technical service.
4. §192.463 External corrosion control: Cathodic protection.
(a) Each cathodic protection system required by this subpart must provide a
level of cathodic protection that complies with one or more of the applicable
criteria contained in appendix D of this part. If none of these criteria is
applicable, the cathodic protection system must provide a level of cathodic
protection at least equal to that provided by compliance with one or more of
these criteria.
Gulf South’s cathodic protection procedures were inadequate because they did not
provide the detail necessary to determine how Gulf South considers voltage (IR) drop.
Gulf South's O&M Manual, Section 3.3 - Criteria for Cathodic Protection states the
following as it relates to the current-applied - 0.850v criterion, "Interpretation of
voltage measurement: Voltage (IR) drops other than those across the structure-
electrolyte boundary shall be considered for valid interpretation of the voltage
measurement in paragraphs." Yet, nothing in the procedure explains how Gulf South
actually considers the IR for valid interpretation of the voltage measurement.
The inadequacy of these procedures was further supported by evidence in Gulf
South’s cathodic protection survey records. For example, Gulf South performed
annual cathodic protection surveys in 2007, 2008, and 2009 in the Jackson, MS area.
A review of the annual survey cathodic protection records showed numerous readings
ranging from - 0.850v to - 0.900v. While these readings were deemed acceptable by
Gulf South using the designated criterion of - 0.850v, there was no documentation
explaining how Gulf South considered IR drop with regards to these readings.
5. §192.465 External corrosion control: Monitoring.
…. (c) Each reverse current switch, each diode, and each interference bond
whose failure would jeopardize structure protection must be electrically checked
3



for proper performance six times each calendar year, but with intervals not
exceeding 21/2months. Each other interference bond must be checked at least
once each calendar year, but with intervals not exceeding 15 months.
Gulf South’s external corrosion control monitoring procedures were inadequate
because they did not provide specific criteria on how to determine if an interference
bond was "critical" to the Gulf South pipeline system. As used here, the term
"critical" means a bond whose failure would jeopardize structure protection; i.e.
jeopardize cathodic protection of the Gulf South pipeline.
An operator must electrically check each critical bond six times a calendar year, while
non-critical bonds must be checked only once each calendar year. Therefore, an
operator must have procedures to differentiate critical bonds from non-critical bonds.
While Gulf South's procedures discussed critical bonds, the procedures did not
describe how Gulf South personnel were to differentiate critical from non-critical
interference bonds.
The inadequacy of these procedures was further supported by evidence in Gulf
South’s cathodic protection survey records. Gulf South’s interference bond records in
the Sterlington area indicated significant electrical current through the bonds and were
labeled as “FROM US.” Gulf South subsequently determined that the current flow
direction across these bonds in these records was incorrect and that the bonds were not
critical. Yet, Gulf South’s records did not indicate that these bonds had been
identified as needing to be investigated further to determine if they could have been
critical based on the initially recorded bond electrical current and current direction.
6. §192.473 External corrosion control: Interference currents.
(a) Each operator whose pipeline system is subjected to stray currents shall
have in effect a continuing program to minimize the detrimental effects of such
currents.
Gulf South’s external corrosion control interference current procedures were
inadequate because they did not provide the guidance and detail necessary to identify
areas of potential stray current so the detrimental effects of stray currents could be
minimized.
Gulf South had a detailed interference current procedure which it used to comply with
special permit interference survey and remediation requirements but these procedures
were not included or referenced in Gulf South's O&M manual or Work Instructions.
7. §192.475 Internal corrosion control: General.
…. (b) Whenever any pipe is removed from a pipeline for any reason, the internal
surface must be inspected for evidence of corrosion. If internal corrosion is found
-
(1) The adjacent pipe must be investigated to determine the extent of internal
corrosion;
(2) Replacement must be made to the extent required by the applicable
paragraphs of §§192.485, 192.487, or 192.489; and
(3) Steps must be taken to minimize the internal corrosion.
4



Gulf South’s internal corrosion control procedures were inadequate because they did
not require the examination of all removed pipe coupons for evidence of internal
corrosion when hot taps were made.
Gulf South's O&M manual Chapter 9 described hot tapping procedures, but did not
require the examination of removed pipe coupons for evidence of internal corrosion.
This deficiency was further evidenced in Work Order No. 23660726, dated 02/20/09
(Bistineau-Clarence area), which did not indicate that a removed coupon was
examined for the presence of internal corrosion.
8. §192.709 Transmission lines: Record keeping.
Each operator shall maintain the following records for transmission lines for the
periods specified:
…. (c) A record of each patrol, survey, inspection, and test required by subparts
L and M of this part must be retained for at least 5 years or until the next patrol,
survey, inspection, or test is completed, whichever is longer.
Gulf South’s record keeping procedures were inadequate because they did not require
the full documentation of performance tests conducted on gas detection and alarm
systems at compressor stations.
Gulf South’s work instruction procedure WI-00085 Test/Maintain Gas Detection &
Alarm Systems and the referenced Engine Protective Devices Test Report form (Form
#PS5576, rev. 06/10/09) did not require adequate documentation of performance test
results. Also, Form #PS5576 did not provide enough detail to show 1) that the gas
detection and alarm system alarmed at not more than 25% of the lower explosive limit
(LEL), and 2) that each of the audible and visual alarms performed (or did not
perform) as required during the test.
9. §192.736 Compressor stations: Gas detection.
.… (c) Each gas detection and alarm system required by this section must be
maintained to function properly. The maintenance must include performance
tests.
Gulf South’s compressor station gas detection and alarm system performance test
procedures were inadequate because they did not detail all the steps necessary for
conducting gas detection and alarm system performance tests when a compressor unit
was running.
Gulf South’s work instruction procedure WI-00085 Test/Maintain Gas Detection &
Alarm Systems did not list certain required steps necessary to conduct the referenced
performance tests when the compressor units were running. For example, WI-00085
did not require opening the fuel gas bypass valve between step 3 and step 4, or placing
the PLC into bypass mode between step 4 and step 5 when the compressor units were
running during a PHMSA-observed test at the Montpelier Compressor Station. A
PHMSA inspector witnessed the technician performing these required steps to prevent
the compressor units from shutting down during the test. However, the steps were not
listed in the work instruction.
5



10. §192.605 Procedural manual for operations, maintenance, and emergencies.
…. (b) Maintenance and normal operations. The manual required by paragraph
(a) of this section must include procedures for the following, if applicable, to
provide safety during maintenance and operations.
…. (8) Periodically reviewing the work done by operator personnel to determine
the effectiveness and adequacy of the procedures used in normal operation and
maintenance and modifying the procedure when deficiencies are found.
Gulf South’s O&M procedures were inadequate because they did not include the
periodic review of work done by Gulf South gas control personnel to determine the
effectiveness and adequacy of the procedures used in normal operation and
maintenance and to modify the procedures if deficiencies were found.
At the time of the inspection, Gulf South management personnel expressed that only a
verbal review of normal operation and maintenance procedures was conducted with
Gulf South gas controllers.
11. §192.605 Procedural manual for operations, maintenance, and emergencies.
…. (c) Abnormal operation. For transmission lines, the manual required by
paragraph (a) of this section must include procedures for the following to provide
safety when operating design limits have been exceeded:
…. (4) Periodically reviewing the response of operator personnel to determine the
effectiveness of the procedures controlling abnormal operation and taking
corrective action where deficiencies are found.
Gulf South’s O&M procedures were inadequate because they did not include the
periodic review of the response of Gulf South gas control personnel to abnormal
operations to determine the effectiveness of abnormal operation procedures and to
correct deficiencies if found.
At the time of the inspection, Gulf South management personnel expressed that only a
verbal review of the response to abnormal operations was conducted with gas
controllers. They also expressed that corrective actions were adopted when
deficiencies were found.
On the basis of the inspection, PHMSA has identified apparent inadequacies found within
Gulf South’s Operator Qualification (OQ) program as described in Item 12 below:
12. §192.805 Qualification program.
Each operator shall have and follow a written qualification program. The
program shall include provisions to:
…. (i) After December 16, 2004, notify the Administrator or a state agency
participating under 49 U.S.C. Chapter 601 if the operator significantly modifies
the program after the Administrator or state agency has verified that it complies
with this section.
Gulf South’s Operator Qualification (OQ) program was inadequate because it did not
require all the notifications an operator was required to make to PHMSA to comply
with the OQ regulations.
6



Gulf South’s OQ program was covered under the Boardwalk OQ Plan (Boardwalk is
the parent company of Gulf South). The OQ Plan, Section 3.6, Management of
Change, contained the subsection entitled “Communication of Significant
Modifications of Program to Office of Pipeline Safety or Applicable State Agency.”
The OQ Plan then defined "significant change" as being “a change that would weaken
the program.
” Therefore, the OQ Plan required a notification to be made to PHMSA
only when plan modifications were made "that would weaken the program.” This is
not consistent with the regulations, which require notification to PHMSA of any
significant modification, regardless of the outcome or results of the modification.
For example, Gulf South did not notify PHMSA of the March 3, 2008, merging of the
Texas Gas and Gulf South OQ plans into a common Boardwalk OQ plan.
On the basis of the inspection, PHMSA has identified apparent inadequacies found within
Gulf South’s Integrity Management Program (IMP) as described in Items 13-17 below:
13. §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.
§192.919 What must be in the baseline assessment plan?
An operator must include each of the following elements in its written baseline
assessment plan:
…. (b) The methods selected to assess the integrity of the line pipe, including an
explanation of why the assessment method was selected to address the identified
threats to each covered segment. The integrity assessment method an operator
uses must be based on the threats identified to the covered segment. ( See
§192.917.) More than one method may be required to address all the threats to
the covered pipeline segment;
• Item 13A: §192.919(b)
Gulf South’s IMP was inadequate because it did not include in the assessment portion
(Chapter 6) of its IMP the process it used to assess for hard spot/sleeve interactive
threats on applicable pipelines. Gulf South should have documented this process to
provide a basis for its past use and to facilitate any modifications of the process for
ongoing assessments.
• Item 13B: §192.919(b)
Gulf South’s IMP was inadequate because Gulf South’s process for assessing for
third-party damage (TPD) when hydrostatic pressure testing was used as the
assessment method was not adequately documented in its IMP.
Chapter 6, Table 3-1 in the Gulf South IMP indicated that hydrostatic pressure testing
was not applicable to assess the TPD threat, with footnote 10 stating, "Third-Party
Damage is identified by data integration and managed by Preventative and
Maintenance Measures." But, footnote 10 did not provide sufficient detail as to what
was required to assess the TPD threat. There was no mention of the required data sets
that should have been used (e.g., one-call tickets, foreign line crossings,
7



encroachments, survey results, etc.), or how Gulf South integrated the data. There was
also no mention of the methods Gulf South used to gather additional information for
the data integration (e.g., CIS, DCVG, etc.). It is important to note that TPD was the
dominant weighted threat of Gulf South’s IMP, with an assigned threat weighting
factor of 0.43.
14. §192.911 What are the elements of an integrity management program?
…. (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 ASME/ANSI B31.8S
(incorporated by reference, see §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.
(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 ASME/ANSI B31.8S, section 4. At a minimum,
an operator must gather and evaluate the set of data specified in Appendix A to
ASME/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.
§192.935 What additional preventive and mitigative measures must an operator
take?
(a) General requirements. An operator must take additional measures beyond
those already required by Part 192 to prevent a pipeline failure and to mitigate
the consequences of a pipeline failure in a high consequence area. An 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 (incorporated
by reference, see §192.7), section 5, a risk analysis of its pipeline to identify
additional measures to protect the high consequence area and enhance public
8



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 14A: §192.917(a)
Gulf South’s IMP was inadequate because Gulf South’s practice of identifying hard
spot related threats was not adequately documented in its IMP.
The Gulf South threat identification process indicated that hard spots did not meet the
threshold for being a threat of concern. However, given past instances of leaks at
Type A sleeve-repaired hard spot locations on the Gulf South pipeline system (e.g.,
Index 129) and the ongoing potential for additional leaks, it would appear that certain
repaired hard spots represent a type of time dependent threat that, in fact, rises to a
level of concern.
Gulf South appeared to recognize this and was utilizing magnetic flux leakage (MFL)
in-line inspection (ILI) assessments to provide indicators that corrosion and/or coating
deterioration had occurred near Type A sleeve repaired hard spots, which could then
potentially lead to hydrogen induced hard spot cracking. This practice, however, was
not adequately addressed in the IMP Chapter 4, Threat Identification, Data
Integration, and Risk Assessment.
• Item 14B: §192.917(a)
Gulf South’s IMP was inadequate because Gulf South’s process for evaluating the
threat of potential pipe seam defects on certain vintage pipe was not properly
documented in its IMP, which resulted in inconsistencies.
Gulf South’s IMP had two different algorithms that addressed potential seam defects
and the two algorithms conflicted with each other in certain scenarios. Gulf South's
primary risk algorithm used to address potential seam defects was contained in
Appendix 1, Section 2.5.2 of its IMP. This risk algorithm generated a Seam Defect
Score. The secondary threat assessment algorithm used to address potential seam
defects was a flow chart shown in Chapter 4 Figure 2-7of the IMP, i.e. Manufacturing
Threat Criteria.
The source of the inconsistencies related to pressure tests requirements. The Seam
Defect Score risk algorithm indicated that pressure test applicability was only a
function of maximum test pressure. It did not, however, consider if the pressure test
was equivalent to a Part 192, Subpart J test, which has many requirements in addition
to maximum test pressure. Conversely, the Manufacturing Threat Criteria in Figure
2-7 did indicate that a Subpart J pressure test was required to address potential seam
defects.
9



This process inconsistency was reflected in the Seam Defect Score for Index 129, a
1952 A.O. Smith flash welded pipeline located in HCA 809. Because this pipeline
was not subjected to a Subpart J test, the algorithm used for Manufacturing Threat
Criteria, i.e. Figure 2-7 indicated this pipe to be a threat. Yet, the Seam Defect Score
was zero, which effectively eliminated this pipe at the time as a candidate for
assessment.
In the absence of a Subpart J pressure test, the federal pipeline safety regulations and
incorporated references consider seam defects to be stable threats only when there has
been no MAOP increase, the 5-yr historical maximum operating has not been
exceeded, the pipeline was not subjected to cyclic fatigue or other interacting threats,
and there was no failure history of similar pipe. If a pipeline meets all these criteria,
integrity assessments capable of assessing seam integrity are not required. Instead the
pipe must be monitored for MAOP increases, pressure increases exceeding the 5-yr
historical conditions, cyclic fatigue, seam failures elsewhere in the system, and other
interacting threats.
• Item 14C: §192.917(b)
Gulf South’s IMP was inadequate because Gulf South’s procedures did not require the
integration of ILI tool tolerance in making decisions regarding remediation of
anomalies.
Gulf South's IMP addressed ILI tool tolerance in Appendix 4 Section 13 only in the
context of determining reassessment intervals, not with regards to making decisions
regarding remediation of anomalies. PHMSA inspectors discussed this with Gulf
South during the inspection and were told it was being evaluated by Gulf South.
• Item 14D: §192.935(a)
Gulf South’s IMP preventive and mitigative (P&M) measures processes were
inadequate because they did not address all the threats to pipeline integrity that Gulf
South has identified. Gulf South's processes only specifically evaluated Third-Party
Damage, Corrosion, and Outside Force threats for P&M measures, though Chapter 8,
Section 2, Table 2-1 of its IMP lists other threats for which candidate measures are
available.
15. § 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 §§192.925, 192.927, or
192.929.
§ 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
ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4, and in
NACE RP 0502–2002 (incorporated by reference, 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
10



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 pre-
assessment must include—
(i) Provisions for applying more restrictive criteria when conducting ECDA
for the first time on a covered segment; and
(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.
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(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 §192.939. (See
Appendix D of NACE RP0502–2002.)
§ 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.
(1) Preassessment. In the preassessment stage, an operator must gather and
integrate data and information needed to evaluate the feasibility of ICDA for the
covered segment, and to support use of a model to identify the locations along the
pipe segment where electrolyte may accumulate, to identify ICDA regions, and to
identify areas within the covered segment where liquids may potentially be
entrained. This data and information includes, but is not limited to—
(ii) Information needed to support use of a model that an operator must use to
identify areas along the pipeline where internal corrosion is most likely to occur.
(See paragraph (a) of this section.) This information, includes, but is not limited
to, location of all gas input and withdrawal points on the line; location of all low
points on covered segments such as sags, drips, inclines, valves, manifolds, dead-
legs, and traps; the elevation profile of the pipeline in sufficient detail that angles
of inclination can be calculated for all pipe segments; and the diameter of the
pipeline, and the range of expected gas velocities in the pipeline;
§ 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—
…. (2) Assessment method. The plan must provide that if conditions for SCC are
identified in a covered segment, an operator must assess the covered segment
using an integrity assessment method specified in ASME/ANSI B31.8S, appendix
A3, and remediate the threat in accordance with ASME/ANSI B31.8S, appendix
A3, section A3.4.
• Item 15A: §192.925(b)
Gulf South’s IMP was inadequate because the definition of the word "should" was not
consistent throughout its IMP.
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The definition of "should" in Gulf South External Corrosion Direct Assessment Plan
(ECDAP), Section 1.10, Definitions, was not consistent with the definition of "should"
used in Gulf South’s overall IMP. That is, Gulf South's ECDAP did not require
written technical justification for deviations from “should” statements or
recommendations in incorporated documents, including NACE Standard RP0502-
2002 “Pipeline External Corrosion Direct Assessment Methodology.”
• Item 15B: §192.925(b)(3)(i)
Gulf South’s IMP was inadequate because the manner in which Gulf South
implemented the §192.925 (b)(3)(i) requirement for "more restrictive criteria when
conducting ECDA for the first time on a covered segment" in the direct examination
phase of ECDA was not apparent to PHMSA inspectors who reviewed Figure 4-2,
Table 4-1, and the narrative found in ECDAP Sections 4.1 and 4.2.
• Item 15C: §192.925(b)(3)
Gulf South’s IMP was inadequate because the verbiage in ECDAP Sections 4.1 and
4.2 and associated Table 4-1 and Figure 4-2 was not consistent and did not clearly
define the intent of the number of required digs for each case.
For example, Table 4-1 heading "For Each ECDA Region" was not consistent with
Containing/Action verbiage for the "most likely corroded region" in the Monitored
Only and No Indication cases. Table 4-1 did not address the Figure 4-2 description of
"Were any of the above digs found more severe than IMMEDIATE and have >20%
wall loss?" In addition, the word "uprated" (i.e. "If Indications Are Uprated") in
Table 4-1 was not defined in the ECDAP.
• Item 15D: §192.925(b)(4)
Gulf South’s IMP was inadequate because its ECDAP did not properly include the
requirements of NACE RP 0502–2002, Section 6, as required by §192.925(b)(4). The
following statement, found in ECDAP Section 5.1 was incorrect: "Calculation: The
largest scheduled indications for ECDA Region after the reprioritization process shall
have their remaining life determined." NACE RP0502-2002 Section 6.2.2 actually
requires the largest non-unique corrosion defect found to be applied regardless of
whether or not it has been repaired.
• Item 15E: §192.927(c)(1)(ii)
Gulf South’s IMP was inadequate because the minimum requirements to provide
accurate line and feature location elevation information to support Internal Corrosion
Direct Assessment (ICDA) were not well defined in its Internal Corrosion Direct
Assessment Plan (ICDAP), as required by §192.927(c)(1)(ii).
Gulf South's ICDAP (effective 08/01/09) Section 3.6 states, "USGS maps represent a
minimum profile accuracy requirement." This general reference to USGS, however,
did not specify a minimum accuracy needed to adequately perform ICDA while the
ICDAP Section 3.6 specifically states, "Collecting accurate information regarding the
elevation and inclination of a pipeline is particularly important in DB-ICDA.
"
PHMSA has inspected ICDA plans using USGS maps for the calculation of
inclination angles and has found the method to be insufficient in some applications.
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• Item 15F: §192.929(b)(2)
Gulf South’s IMP was inadequate because its Stress Corrosion Cracking Direct
Assessment Plan (SCCDAP) was not in accordance with the threat remediation
requirements of §192.929(b)(2). The SCCDAP was not clear in Sections 4 and 5 that
all areas of detected SCC indications (including those not defined as "significant")
must be mitigated in accordance with §192.929(b)(2) and ASME B31.8S Section
A3.4.1.d.2.
Also, the SCCDAP did not clearly specify actions Gulf South should take based on
conditions it identified during the direct examination phase. SCCDAP Sections 4 and
5 were not consistent with descriptions of certain SCC severity categories and how
they relate separately to mitigation and assessment intervals. For example, Section 4.4
states, "A category 2 crack has a failure pressure that is greater than Boardwalk's
[Gulf South's] safety tolerance and
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