**COMMENTS OF THE**

**WILLIAMS GAS PIPELINE**

**NOTICE OF PROPOSED RULEMAKING**

Pipeline Safety: Standards for Increasing the

Maximum Allowable Operating Pressure

For Gas Transmission Pipelines

Docket ID PHMSA-2005-23447; Notice 2

Docket No. RIN 2137-AE25

Pursuant to the proposed rulemaking notice ("Proposed Rule") issued by
the U.S. Department of Transportation ("DOT") Pipeline and Hazardous
Materials Safety Administrations ("PHMSA") on March 12, 200, Federal
Register Vol. 73, No. 49, 13167, Williams Gas Pipeline ("WGP"), 2800
Post Oak Boulevard, Houston, Texas 77056 submits the following comments
on PHMSA's proposal to amend the pipeline safety regulations to
prescribe safety requirements for the operation of certain gas
transmission pipeline at pressure based on higher stress levels.

Industry has been working with PHMSA on these criteria for 3 years. In
addition, individual companies, through the special permit process have
been working with PHMSA to set reasonable requirements. Some of the
requirements set by PHMSA are not supported by any technical data or
information. WGP therefore will be providing comments on those items.

Also during the special permit process, companies are inclined to agree
with PHMSA requirements in order to get the permit as expeditiously as
possible; costs of delays are not tenable. Therefore, companies have
agreed to non-technically based requirements in order to get the permit.
These issues will be addressed by WGP in the response for individual
items.

**GENERAL COMMENTS**

[]{.mark}

Several operators have sought and/or been granted Special Permits to
operate at higher stress levels. WGP is concerned that these Special
Permits will be revoked and the requirements of the proposed rule
implemented. This may cause an undo hardship on the companies that have
invested significant resources to meet the requirements of the Special
Permits. All Special Permits should be grandfathered. A company should,
however be allowed to suspend operations under the Special Permit and
instead follow the proposed regulations.

Many of the proposed requirements seem to ignore the requirements and
criteria set forth in Subpart O and the referenced ASME B31.8S standard.
These proposed requirements do not have a technical basis and there need
is not explained where as the requirements in Subpart O and in ASME
B31.8S are based on science and technical research. Where the elements
of integrity management are required, it is recommended that reference
to Subpart O be made instead of stating new, unjustified and conflicting
requirements.

**comments on the preamble**

The preamble has a few errors that WGP wishes to point out so that the
final rule will be correct. In addition, comments on some questions
posed in the preamble are provided These changes and comments are as
follows:

B.1 The phrase "but not to exceed 80% of MSYS" at the end of paragraph
one is not correct. There is no upper limit to the pressure under which
a grandfathered pipeline can operate.

B.6 Paragraph one, the review of existing permits, may be an appropriate
action for PHMSA to take. PHMSA should not use this review to impose
additional requirements on those operators which Special Permits nor
revoke any Special Permits already granted.

B.6 Paragraph two, PHMSA should continue to expeditiously process any
Special Permits they receive regardless of the status of this proposed
rulemaking. The operators who have submitted the Special Permits may
need to increase pressure to meet customer demand before the rulemaking
is complete. Additionally, operators may need relief from both existing
regulations and the proposed regulations as drafted.

C.3 Paragraph two makes reference to "level 2 of API Specification 5L'.
The new edition of this specification will likely be published before
this rulemaking is complete. The reference, as stated will be outdated.
PHMSA should review the proposed new edition of this specification and
make appropriate references as part of the final rule.

C.3 Paragraph eight requires certification of serviceability for
fittings and other components. It is not known what this requirement
means. PHMSA should clarify this requirement; does PHMSA mean that mill
certificates are required for each component?

C.4 Paragraph four states that "industry practice has been to
non-destructively test only a sample of girth welds". WGP takes
exception to this statement. Although this represents the regulatory
requirement, industry practice, including WGP is to non-destructively
test nearly all girth welds.

C.4 Paragraph six states that "since the initial strength test is a
destructive test, it only detects flaws relatively close to failure
during operation. This could leave in place smaller flaws that could
grow more rapidly at higher stress levels. WGP takes exception to this
statement. The pressure test eliminates all flaws that may fail
significantly above operating pressure and to the level of the strength
test (1.25 times MAOP or greater). Any flaws left in place will not grow
more rapidly at higher stress levels and there is nothing that will
cause them to grow. PHSMA should review research on pressure testing to
more accurately state the how flaws are manifested and grow and how
pressure testing minimizes the material and construction threats.

C.7.7 Paragraph one implies that geometry tools are run for baseline
purposes and during periodic assessments. This is not a correct
statement based on the proposed regulations. Geometry tools are required
for the baseline assessment but not for periodic assessments. The
language in the proposed rule is correct.

C.7.8 Paragraph one states that "The higher stress levels of operation
can allow more rapid growth of materials". This statement is not
correct. The growth of anomalies is not depended on operating stress
level.

D.2 Paragraph 4 has a statement that is not correct. "In the case of new
pipelines, the ability to use an alternative MAOP will make it possible
to transport more product". This statement may be true for existing
pipelines but new pipelines are designed for the required capacity as
certificated regardless of operating stress level.

**cOMMENTS ON pROPOSED Changes to paragraph 192.7-- INCORPORATION BY
REFERENCE**

In general, WGP supports the use of consensus standards to provide the
technical foundation for any regulatory actions; particularly those
developed under the provisions established by the American National
Standards Institute (ANSI). Specifically, WGP supports the incorporation
of the standard, ASTM A 578/A579M-96 (re-approved 2001) "Standard
Specification for Straight-Beam Ultrasonic Examination of Plain and Clad
Steel Plates for Special Applications" for use in inspecting plate
manufactured for pipe orders to be used for operation using the
alternative design basis and life cycle management proposed by PHMSA.

**COMMENTS ON PROPOSED PARAGRAPH 192.112**

This new paragraph sets the eligibility requirements for a new or
existing pipeline to operate at the alternative maximum allowable MAOP.
WGP's comments to the new language are as follows:

[Paragraph (a) -- General Standards for Steel Pipe]{.underline}

PHMSA proposes the use of a ratio of the diameter over the nominal wall
thickness, referred to as D/t to address the threat of damage during
construction and atypical loads and mechanical damage during operation
of the pipeline. WGP believes that while consideration of the
relationship between wall thickness relative to pipe diameter is
important, there is no hard and fast threshold that applies under all
circumstances. D/t limitations are particularly inappropriate for higher
yield strength pipe. For pipe grades X-80 and above, the D/t ratios may
exceed 100 to 1. Ovality and denting issues can be managed for these
higher D/t pipelines, and for that matter any pipe under this regulation
through the construction practices proposed by PHMSA in 192.328(a)(1),
Quality Assurance (during construction), and by provisions in the
existing ASME code that relate to analyses of instantaneous and
sustained loads during operation (ASME B31.8, Paragraph 833.4).

With respect to carbon equivalents, the consensus standard API 5L
establishes specifications for maximum carbon equivalents using the
Ito-Bessyo formula (Pcm formula) for varying grades and wall thicknesses
of steel pipe. PHMSA has proposed limitations that differ from those in
API 5L, without technical justification. WGP supports use of the limits
as expressed in API 5L, absent any other information to justify
differing limits.

[Paragraph (b) -- Fracture Control]{.underline}

In general, WGP agrees with the approach proposed by PHMSA with respect
to fracture control. It is critical that an operator's plan considers
and addresses initiation, propagation and arrest under the range of
operating pressures and temperatures anticipated on the pipeline. In
addition, it is important that the fracture control plan addresses the
potential under-conservatism of conventional Charpy toughness equations
for higher strength steels (grades X70 and above) and enriched gases. A
White Paper "Fracture Control" has been developed by the Joint Industry
Project on Alternative Design Basis and Life Cycle Management, and it
supports WGP's comments.

WGP agrees that the basis for arrest proposed by PHMSA is appropriate
for new pipeline design. The basis selected by PHMSA in effect requires
that approximately 58 percent of the pipe be arrest pipe. This basis is
also appropriate for existing pipelines as well except under one design
scenario; that is a scenario under which a crack arrest design is used.
WGP proposes that PHMSA amend the regulatory language to allow an
operator to alternatively apply a crack arrest design based on an
engineering analysis including an analysis of consequence.

*WGP recommends that the language under 192.112(b)(3) be changed to read
"If it is not physically possible to achieve the pipeline toughness
properties of paragraphs' (b)(1) and (2) of this section, a crack arrest
design must be developed and implemented or mechanical crack arrestors
of proper design and spacing must be used to insure fracture arrest as
described in (b)(2)(iii) of this section".*

[Paragraph (c) -- Plate/Coil Quality Control]{.underline}

In general WGP believes that the consensus standard API 5L provides the
foundation for the materials specification and manufacturing of line
pipe. Operators (purchasers of pipe) build upon API 5L through use of
materials specification and manufacturing quality management programs.
The Joint Industry Project on Alternative Design Basis and Life Cycle
Management has developed a White Paper "Material Specification and
Manufacturing" that describes how line pipe metallurgical, chemical and
dimensional properties are managed by a materials and manufacturing
quality management program. Materials and manufacturing quality
management programs draw upon international consensus-based standards in
combination with mill and source-specific specifications, quality
control measures used by the pipe mill and quality assurance used by the
purchaser. The quality management program comprises four steps:

1.  Pipe manufacturing mill qualification

2.  Pipe standard, specifications and contracting agreements

3.  Pipe manufacturing procedure specification review and agreement

4.  Surveillance and auditing

The purchaser engages in a technical evaluation of the mill to ensure
that the mill is qualified to produce pipe to the purchaser's
specifications. The purchaser will establish a pipe specification
knowing the requirements of the project for which the pipe is being
procured. The mill and purchaser engage in the development and agreement
upon a manufacturing procedure specification (MPS) that establishes the
materials specification to standards and the purchaser's additional
requirements and manufacturing procedures and quality control/quality
assurance (QA/QC) practices. The mill knows best how to source the
steel, roll and weld pipe to meet the performance parameters required by
the purchaser. The MPS sets out the kinds of inspections and frequencies
and how exceptions are to be dealt with. The MPS is designed to locate
issues before they become problems and minimize exceptions.

Steel properties are specified by the operator in the pipe specification
and the mill selects the chemical formulations that are designed to
ensure the slab mill producer, skelp mill and the pipe mill achieve the
desired final properties in the finished pipes. Most alloying elements
must fall within compositional limits that are known to lead to the
appropriate mechanical properties. Solidification control during
continuous casting minimizes centerline segregation and lamination from
refractory and slag entrapment.

Centerline segregation and lamination in the pipe body or pipe ends if
it extends into the weld preparation generally reduces weld strength and
may promote girth weld cracking. In particular, carbon, oxygen, sulfur
and phosphorous in the carbon equivalents formulation are minimized
controlled to promote weldability, and the controlled rolling (and
accelerated cooling/strip coiling where applicable) using advanced
thermo-mechanical parameters, and micro-alloying elements are used to
assure the fine grain size and precipitation hardening effects which
compensates for the loss of strength, due to the reduced carbon.

It is important to recognize that API 5L provides performance-based
requirements to address the outcomes of centerline segregation, or
failure of the source material to meet the metallurgical and dimensional
properties of the operator's pipe specification and API 5L. The
operator, the pipe mill and source mill must balance the use of quality
control measures and the potential for out-of-spec pipe to be formed.
This is not best achieved by the imposition of a single simple
prescriptive approach unrelated to the negotiated MPS. Delays always
lead to increase cost, and these will occur by improperly imposing
production constraints.

Even considering the performance-based requirements set forth in API 5L,
WGP recommends that the purchaser require specific slab mill
inspections, such as macro-etch testing. Macro-etch testing is a
valuable quality control method to be applied by the mill. This approach
aligns with the approach proposed by PHMSA. While WGP agrees with PHMSA
in the value of the tests, the frequency and acceptance criteria are
best left to be agreed upon between the purchaser and the mill, based on
mill configuration, slab source materials among others.

*WGP recommends that the language under 192.112(c)(2)(i)) be changed to
read "A macro etch test or other equivalent method to identify
inclusions that may form centerline segregation during the continuous
casting process. The acceptance criteria must be agreed to between the
purchase and the mill".*

With respect to ultrasonic inspection of plate/coil or pipe, WGP agrees
that the pipe mill must include a comprehensive plate/coil and pipe mill
inspection program to check for surface defects and inclusions that can
be injurious to the integrity of the pipe. This program can be conducted
on plate or rolled pipe (body and all ends) ultrasonic testing (UT)
inspection program using as a basis, guidelines in ASTM A578 to check
for imperfections such as laminations. Alternatively, WGP believes that
the pipe mill may conduct full-body UT of the pipe. Full-body UT entails
the use of a single transducer oscillating back and forth across the
internal pipe surface. The basis of either approach is to assure that
the inspection finds defects that exceed a certain minimum size in the
body of the plate or pipe, and provides coverage for 100 percent of the
pipe ends back a specified length. The work group recommends that the
performance criteria set forth in ASTM 578 be used for plate inspection
and as a basis for establishing criteria for full-body UT.

[Paragraph (d) -- Seam Quality Control]{.underline}

As a starting point, WGP believes that API 5L provides the technical
foundation for managing seam quality control. The pipe weld seam must
meet the minimum requirements for tensile strength as specified in API
5L for the appropriate pipe grade properties. WGP is aware of the work
being undertaken by the Joint Industry Project on Alternative Design
Basis and Life Cycle Management. The JIP has developed a white paper on
Materials Specification and Manufacturing and it supports WGP's
comments.

WGP agrees with PHMSA that pipe weld seam hardness test using the
Vickers hardness testing of a cross-section from the weld seam confirms
adequate ductility across the plate, HAZ, and weld material volumes and
must be performed on one length of pipe from each heat. WGP does not
agree with the use of a threshold value of 280 Vickers Hardness (Hv 10).
While API 5L does provide such a threshold value for sour gas service,
it does not provide a single, fixed value for the gas service addressed
under 49 CFR 192; that is the transportation of non-corrosive gases. WGP
believes that the pipe mill and the purchaser should establish a
hardness maximum in the manufacturing procedure specification and
quality assurance plan.

API 5L requires that the pipe weld seam must be 100 percent UT or x-ray
inspected to ensure there are no defects or cracks. In addition, API 5L
requires that pipe ends be non-destructively inspected by either UT or
x-ray, to identify there are injurious laminations or inclusions
interacting the weld volume.

*WGP recommends that the language under 192.112(d)(2) be changed to read
"There must be a hardness test method used to ensure hardness levels
established between the purchaser and the mill of the following:..."*

[Paragraph (e) -- Mill Hydrostatic Test]{.underline}

WGP understands that the mill hydrostatic test is really a quality
control test conducted on each pipe manufactured in the mill. It is an
important quality control test but none-the-less it is a quality control
test. The ultimate test of the pipe's integrity is the eight-hour
pressure test, often referred to as the proof test, conducted on the
pipe as constructed in the field.

WGP is aware of the work being undertaken by the Joint Industry Project
on Alternative Design Basis and Life Cycle Management. The JIP has
developed a White Paper "Materials Specification and Manufacturing" and
it supports WGP's comments. The JIP work group examined hydrostatic
testing practices in modern mills around the world and found that most
operators specify a hydrostatic test of 95 percent of the specified
minimum yield strength (SMYS) for a duration of 15 seconds. API 5L in
the forty-third edition and for a number of years has specified a test
to 90 percent of SMYS for 10 seconds[^1]. The members of the JIP work
group discussed test pressure and duration and reached the following
conclusions. Testing to 95 percent of SMYS is appropriate as long as the
current provisions that allow for end-loading compensation as per
Appendix K are applicable. In addition, the work group considered the
additional 10 seconds proposed by PHMSA beyond the 10 seconds stipulated
in API 5L is are also prudent. The work group found that a duration in
excess of 10 seconds did not add value to the test. Consequently, the
work group recommends,

*WGP recommends that the language under 192.112(e)(1) be changed to
read* **"***A hydrostatic test of all pipe will be conducted in the pipe
mill at a pressure of at least 95% of SMYS, for a duration of 10 seconds
including the allowance for end loading"*

[Paragraph (f) - Coating]{.underline}

Fusion bonded epoxy coatings (FBE) have proven performance in pipeline
applications for over thirty years around the world. WGP believes that
it is important to allow for alternatives to ensure improved
technologies are not arbitrarily restricted. Three layer coatings
especially FBE-PE and other hybrids have provided good performance in
other parts of the world. Performance coatings that have been shown as
semi-conductive and/or do not crack would be preferred over this "one
size fits all" statement. Abrasion resistant coatings and other high
integrity specialty coatings need inclusion through performance language
such as non-disbonding, non-shielding, or non-cracking. Prescriptive
language remains inappropriate because it risks stifling innovation.
Regulations should allow the use of manufacturer's coating performances
on petition.

*WGP recommends that performance language be used to describe the
expected coating performance rather than specify only FBE coatings. This
language should be "the pipeline must be protected against external
corrosion by non-disbonding, non-shielding, non-cracking coating".*

WGP agrees with the quality assurance approach proposed by PHMSA at
192.112(f)(3).

[Paragraph (g) -- Fittings and Flanges.]{.underline}

WGP agrees with the provisions proposed by PHMSA. But to clarify, pipe
fittings, valves and flanges, associated with line pipe and main line
block valves, should be designed and purchased in accordance with
applicable reference standards or their equivalent, already incorporated
within 49 CFR 192. The referenced standards may be supplemented by the
operator's supplemental requirements to ensure the materials meet the
minimum engineering design specifications. In all cases, the valves and
flanges should be ANSI Class 600 for pressures up to and including 1,480
psig, and ANSI 900 for pressures up to 2,200 psig. Valves should be
manufactured in accordance with API 6D. High-test flanges should be
manufactured in accordance with MSS SP-44 and normal flanges in
accordance with ASME B16.5. Small pipe fittings should be manufactured
in accordance with ASME B16.9 and large fittings with MSS SP-7. All of
these materials should be pressure tested in accordance with the
applicable standards.

[Paragraph (h) -- Compressor Stations]{.underline}

PHMSA concerns with respect to compressor station discharge temperatures
relate to the long-term durability and integrity of plant and field
applied fusion bond epoxy (FBE) coating for operations greater than
120^o^F. The concern arises when considering operating scenarios for
uncontrolled compressor discharge temperatures projected to heat the
downstream pipe to a temperature that may reach 150^o^F.

All pipelines built under PHMSA regulations must have two corrosion
protection systems. The first line of defense against corrosion is the
coating system and the second line of defense is the applied cathodic
protection current. PHMSA in 49CFR192 requires a minimum test point (or
close interval survey) voltage to ensure the imposed current provides
sufficient protection in the event the coating has deteriorated.

The FBE concern arises out of historical experience in the pipeline
industry when some pipeline systems were operated at temperatures above
120^o^F, even as high as 160^o^F. In many cases these early coatings
were non conductive and prevented the cathodic current from completing
the circuit. The pipe was "shielded" and the applied potential could not
protect the surface. Corrosion is prevented by applying small voltage
potential. These earlier reports refer to tar and asphalt based coatings
that predominated prior to the use of FBE.

Early FBE coatings did not appear in the US until about the mid 1970's.
Over time there was evidence that some pre-FBE coatings had degraded and
eventually became blistered or disbonded from the pipe. FBE however,
remains conductive even when disbonded and raised proud of the pipe. FBE
coatings do not block the cathodic protection current, meaning that
disbondment of the coating does not interrupt the cathodic protection
system, and the imposed CP continues to protect the pipe from external
corrosion and SCC.

Never the less, there remain two major concerns:

1.  absent a coated surface, the underlying steel can be prone to
    external corrosion and

2.  stress corrosion cracking (SCC) can occur under disbonded and
    non-conductive coatings.

It is known that the pipe shielded by disbonded non-conductive coating
is susceptible to SCC and more so for any pipe that has experienced
temperature excursions in excess of 120ºF. The TCPL study (3), which had
experience temperature excursions to 150ºF (65ºC), concluded that the
disbondment of FBE coatings did not present an integrity threat to a
pipeline as long as cathodic protection was present on the line.

NACE RP0394-2002, Standard for Application, Performance, and Quality
Control of

Plant-Applied, Fusion-Bonded Epoxy External Pipe Coating, states in
section 6.1.5 that a minimum coating thickness of 12 mils is required to
meet the acceptance criteria for tests in the RP, including cathodic
disbondment, for temperatures up to 150^o^F. Pipeline operators
interpret this standardized practice to mean that FBE coatings, applied
with a thickness of at least 12 mils, are appropriate for operating
temperatures up to 150^o^F. Since the FBE has been used in pipeline
construction, the normal practice is to verify the thickness, and the
integrity of the pipeline coating using a high voltage Jeeping
inspection, as the line is lowered into the ditch. Holidays are
immediately repaired before backfilling the ditch.

The Joint Industry Project on Alternative Design Basis and Life Cycle
Management has developed a White Paper "A Review of the Performance of
Fusion-Bonded Epoxy Coatings on Pipelines at Operating Temperatures
Above 120º F" is a review that summarizes operating and performance case
histories, as well as laboratory and field-testing of the long-term
performance of FBE coatings. This paper documents that FBE coatings have
demonstrated good adhesion and little disbondment in both
laboratory-testing environments and after 30 years of operation at
temperatures greater than 120^o^F on systems in the United States,
Canada and the Middle East. In addition, FBE remains conductive even
when disbonded as a continuous barrier like film proud of the pipe.
However, FBE coatings do not block the cathodic protection current,
meaning that disbondment of the coating does not interrupt the cathodic
protection system, and the imposed CP current continues to protect the
pipe from external corrosion and SCC.

The work summarized in the JIP white paper shows that even the first
generation FBE coatings having seen as many as thirty years service have
performed well at temperatures above 120^o^F. Even so, blistering and
disbondment has been observed on in-service lines in operation above
120^o^F. Laboratory tests conducted on FBE coatings in simulated
environments at temperatures above 120^o^F do indicate a greater degree
of disbondment as the temperature is increased towards 200^o^ F however
any corrosion is minimized by the CP system.

FBE coating is known to be conductive, meaning that even when disbonded,
cathodic protection remains effective. In-service experience described
in this white paper confirms this behavior. FBE coatings do not shield
the cathodic protection currents.

It is not apparent that additional laboratory testing on FBE coating at
temperatures above 120^o^F will add any information not already known
based on the studies described in this white paper. An operator may
elect to conduct additional laboratory testing.

Recognizing that there is the potential for disbondment, an operator may
elect to conduct above ground surveys using close interval surveys to
confirm the effectiveness of the applied potential and use direct
current voltage gradient (DCVG) surveys periodically to locate holidays,
if any, in the FBE coating. The conductivity of FBE coatings ensures the
integrity of the second line of protection, the applied CP system, is
not compromised.

*WGP recommends that the language under 192.112(h)(2) be changed to read
"If research or testing shows that the coating will withstand ..."*

**COMMENTS ON PROPOSED PARAGRAPH 192.328**

[Paragraph (a) -- Quality Assurance]{.underline}

WGP agrees with these proposed requirements.

[Paragraph (b) -- Girth welds]{.underline}

Item (2) in this paragraph refers to pipelines that were constructed
prior to the effective date of this rule. This requirement is in the
wrong area of the regulations. Paragraph 328 is a construction
requirement and is not a retro-active requirement. Paragraph 620 is an
Operations requirement and applies retro-actively to all pipelines.

*WGP recommend removing item (b)(2) from paragraph 192.328 and putting
it in paragraph 192.620, under (c)(3) in a manner that is similar to the
requirement for pressure testing.*

[Paragraph (c) -- Depth of Cover]{.underline}

WGP agrees with these proposed requirements.

[Paragraph (d) -- Initial strength testing]{.underline}

In a paper by John Kiefner, "Role of Hydrostatic Testing in Pipeline
Integrity Assessment" the technical benefits for the test is stated as
follows:

> "The purpose of hydrostatic testing a pipeline is to either eliminate
> any defect that might threaten its ability to sustain its maximum
> operating pressure or to show that none exists. A key work here is
> pressure. Hydrostatic testing consists of raising the pressure level
> above the operating pressure to see whether or not any defects with
> failure pressures above the operating pressure exist. If defects fail
> and are eliminated or if no failure occurs because no such defect
> exists, a safe margin of pressure above the operating pressure is
> demonstrated."

This statement is the underlying philosophy for all pressure tests
including the post construction test addressed in this paragraph. In the
case of post construction tests, the defects that the operator is trying
to find or prove do not exist are material and construction defects.

This item deals specifically with "any failures indicative of fault in
material". Material is produced as specified in the pipeline safety
regulations and the additional requirements of proposed 192.112. Even
with the rigorous controls, there is a possibility that a piece of pipe
will have a material defect. This unacceptable pipe will be found during
the pressure test if the defect is large enough to grow to failure. If
it does not grow to failure, the safety margin is sustained.

Special permits granted to date have addressed pressure test failures by
requiring a root cause failure analysis. If a systemic issue was found
during the test, discussions had to be held with the regional offices.
The requirement stated in the special permits is:

> "Assessment of Test Failures: Any pipe failure occurring during the
> pre-in service hydrostatic test must undergo a root cause failure
> analysis to include a metallurgical examination of the failed pipe.
> The results of this examination must preclude a systemic pipeline
> material issue and the results must be reported to PHMSA headquarters
> and the appropriate PHMSA regional office."

The requirement as stated in the NPRM, by stating that "the segment must
not experience any failure indicative of fault in material" during the
hydrotest is excessive. A root cause analysis of any test failure
however is appropriate. If there is a systemic issue with the material
more needs to be done to understand and address the issue.

*WGP recommends that the language under 192.328(d) be changed to what
was used in the special permits, namely "Any pipe failure occurring
during the pre-in service hydrostatic test must undergo a root cause
failure analysis to include a metallurgical examination of the failed
pipe. The results of this examination must preclude a systemic pipeline
material issue and the results must be reported to PHMSA headquarters
and the appropriate PHMSA regional office."*

[Paragraph (e) -- Cathodic Protection]{.underline}

This paragraph is not necessary. Existing paragraph 192.455 requires
that cathodic protection must be installed and placed in operation
within one year after the completion of construction.

*WGP recommends removal of this paragraph. If necessary, a reference to
192.455 can be added in stead of restating the requirement.*

[Paragraph (f) -- Interference currents]{.underline}

WGP agrees with these proposed requirements.

**COMMENTS ON PROPOSED PARAGRAPH 192.620**

[Paragraph (a)]{.underline}

Stated requirements in the NPRM are more restrictive than current
regulations and granted special permits. This inconsistency must be
addressed in the NPRM.

The design factors set in the NPRM do not recognize that the class
location may change after the pipeline has been constructed. Special
provisions are provided in the existing regulations to allow for the
class location change without the need for pipe replacement. This
provision is contingent on a pressure test to the next class location
test factor.

Waivers have been granted to pipelines operating to 80% or more of SMYS
that were grandfathered and have subsequently experienced a class change
from Class 1 to Class 2. In order obtain this waiver, companies agreed
to in-line inspection of the pipeline and to employ additional
preventative and mitigative measures such as those that are mandated
within a company's Integrity Management Plan. Today, there are pipelines
that have been granted waivers to operate at 80% or more of SMYS in
Class 2 areas.

Waivers have been granted to pipelines operating at 60% or more of SMYS
in Class 3 locations where the pressure test was not to the level
required by the regulations (1.5 times MAOP). Waivers have been granted
to pipelines operating at 72% or more of SMYS of design pressure in
Class 3 locations, where neither the design nor the pressure test met
the requirements of the regulations. The companies in these cases also
agreed to in-line inspection of the pipeline and operations in
accordance with the companies Integrity Management Plan. The granting of
these waivers was part of the agreement reached between PHMSA and the
industry in 2002 as part of the promulgation of the integrity management
regulations in order to help justify the extreme cost of the
regulations. Many of these pipelines contain HCA's.

There are significant inconsistencies between current regulations,
current waivers granted to existing pipelines, and the proposed
regulations. While changes to existing regulations is not part of the
scope of the NPRM, there is no reason to confuse the issue again with
this rule, it should be made simpler and more in line with current
waivers.

The proposed regulations do not have a provision for compressor station,
meter station, road crossings or fabricated assemblies to operate at
higher pressures. As written, a compressor station in a Class 1 area can
be operated at 80% of SMYS.

*WGP recommends the following changes to proposed Paragraph 192.620(a):*

> *For the new pipelines that meet all of the special provisions in the
> NPRM, it is recommend that:*

-   *Class 1 pipelines be limited to operation at 80% of SMYS and
    pressure tested to 1.25 times MAOP*

-   *Class 2 pipelines be limited to operation at 67% of SMYS and
    pressure tested to 1.25 times MAOP*

-   *Class 3 pipelines be limited to operation at 56% of SMYS and
    pressure tested to 1.5 times MAOP*

-   *Station piping be limited to operation at 56% of SMYS and pressure
    tested to 1.5 times MAOP*

-   *Fabricated assemblies would be limited to operation at 67% of SMY
    and pressure tested to 1.25 times MAOP*

-   *Uncased road and railroad crossing be limited to 67 % of SMYS in
    Class 1 locations and to 56% of SMYS in Class 2 locations.*

> *For Class location changes, it is recommended that a new paragraph be
> added to 192.611 to provide the following:*

-   *Pipe that operates at 80% and in accordance with paragraph 192.620
    and changes from Class 1 to Class 2, can continue to operate up to
    80% SMYS*

-   *Pipe that operates at 80% and changes from Class 2 to Class 3 or
    from Class 1 to Class 3 would need to have the pressure lowered to
    67% of SMYS or be replaced with pipe designed at 67% SMYS or less*

-   *Pipe that operates at 67% and in accordance with paragraph 192.620
    and changes from Class 2 to Class 3 can continue to operate at 67%*

These class change provisions are necessary or operators will be asking
for special permits in the very near future as population encroachment
drives the class location to change from Class 1 to Class 2 or from
Class 2 to Class 3. These criteria also provides for consistency with
Special Permits previously granted and gives the operator flexibility in
design for all pipeline facilities

It is important to note that the regulations require operations and
maintenance activity frequency be based on the class location. The
higher the class location, the more frequent the inspection or other
activity is performed. These provisions address the slightly higher risk
due to consequence by reducing the likelihood of an event through more
frequent inspection.

A White Paper "Alternative Pipeline Design Pressures" has been developed
on this topic. It discusses the current regulations, the special permits
granted for performing Integrity Management in lieu of replacing pipe
and the proposed regulations.

[Paragraph (b)]{.underline}

Item (6)

The NPRM states that the segment must not experience any failures during
normal operations indicative of fault in material. This requirement is
excessive as the failure may be a single event. If there is a failure, a
root cause analysis should be conducted in order to ascertain that the
failure is not indicative of a systemic materials issue. If there is a
systemic issue with the material more needs to be done to understand and
address the issue.

*WGP recommends that the language under 192.620(b)(6) be changed to read
"Any pipe failure occurring during normal operations must undergo a root
cause failure analysis to include a metallurgical examination of the
failed pipe. The results of this examination must preclude a systemic
pipeline material issue and the results must be reported to PHMSA
headquarters and the appropriate PHMSA regional office."*

[Paragraph (c)]{.underline}

Item (3)

This item shows the criteria for pressure testing in Class 1 areas but
does not say anything about Class 2 or 3 areas. For pipelines that are
presently in operation and are being up-rated to the higher pressures,
the pressure test requirements should not be the same as required in
paragraph (a) of this section.

For existing pipelines, pressure test levels may not have been to the
levels stated in paragraph (a) of this section; however the tests may
have been very near those levels. Some relief from this requirement
should be allowed. In 192.328(b)(2) the requirement for weld NDE is
somewhat reduced recognizing that every weld may have not have
experienced NDE. This rationale should apply to pressure tests as well
in order to gain some relief from the pressure test requirements.

In a paper written for Alliance Pipeline, and contained in the docket
for their waiver or special permit for increasing operating pressure,
Kiefner and Associates concluded "there would be little additional
benefit gained in terms of demonstrating that the pipeline is fit for
the modest proposed increase in operating stress by repeating the
hydrostatic test to the incrementally higher level necessary to meet the
1.25 factor". The paper states the reason for these conclusions and
included that more than ¾ of all joints were tested to 95% of SMYS, more
than ½ of all joints were tested to 97% SMYS or greater and more than
1/3 of all the joints were tested to 99% of SMYS. In addition, the
conclusions were justified by pipe manufacturing controls, resistance to
mechanical damage, the decay of pressure with distance downstream of
compression, and the minimal difference in safety factor as compared to
current regulations.

*WGP recommends that Item 3 of Paragraph C be changed to the following:*

*(i) Perform a strength test as described in 192.505 to at least the
factor stated in (a) of this section times the maximum allowable
operating pressure: or*

*(ii) For a segment in existence prior to the effective date of this
regulations, and the pressure test levels do note meet the requirements
of 192.620(a)(ii) of this paragraph, certify, under paragraph (c)(1) of
this section, that a strength test was conducted and provide an
engineering critical analysis discussing the relationship of the
pressure test to actual operating pressure and the affects of remaining
defect size, pipe toughness, fracture control properties and fatigue on
the pipeline ".*

[Paragraph (d)]{.underline}

Item (1) -- Assessing threats:

The way in which item 1 is written implies that operation at the higher
stress levels increases the risk and that the procedures used will
mitigate the risk. The slight increase in risk however is already
mitigated through all of the additional design, materials, construction,
and operations requirements of these proposed regulations. It is unclear
what procedures are being talked about.

*WGP recommends that this item be clarified to state that the operator
must include in their design, construction, material, operations, and
maintenance procedures and specifications, provisions to mitigate risk
for operation at the higher design pressures.*

Item (2) -- Notifying the public:

This item appears to require a special notification to the public near
pipelines that will be operating at higher pressures. The justification
for this requirement has not been provided other than to state the
information is necessary to people potentially impacted by a failure.
Everyone along the pipeline could be affected by a failure. Notification
about pipelines is already required by 192.616 "Public awareness".

*WGP recommends item (d)(2) be revised to change the title of the
section to "Assessing potential impact area". In addition, delete item
(d)(2)(ii) in its entirety.*

Item (3) -- Responding to an emergency in an area defined as a high
consequence area:

This item states the requirements for timing of valve closure in an HCA.
WGP is not aware of any study or research that supports this
requirement. The requirement seems arbitrary and is contrary to research
and operational experience.

Especially onerous is the requirement for additional pressure monitoring
upstream and downstream of the valve. WGP is not aware of any benefit in
monitoring the pipeline pressure upstream and downstream of the valve.
Pressure monitoring requires additional equipment and the resultant
maintenance where the benefit is not known and has not been justified.
Given a rupture of the pipeline, the pressure will read zero after the
valves are closed upstream and downstream of the rupture site. Upstream
of the first closed valve the pressure will equalize to the upstream
compressor station discharge pressure. Downstream of the second closed
valve the pressure will equalize to the downstream compressor station
suction pressure. There is no need for pressure monitoring.

In addition, the requirement to be able to remotely open the valve is
contrary to many companies operations policies. Many operators believe
that if the situation is so serious that remote closure of the valve is
required, on-site personnel should make the determination that the area
is safe prior to re-pressurizing the segment and therefore do not allow
remote opening of the valve.

*WGP recommends that 192.620(d)(3)(iii) be changed to read "Remote valve
control must include the ability to close the valve and monitor the
position (open and close) of the valve".*

Item (4) - [Patrolling]{.underline}

The patrolling frequency proposed in the NPRM is excessive. WGP is not
aware of any technical justification for the proposed frequency however
it does recognize that it follows the frequency mandated for hazardous
liquid pipelines.

A review of the incident data for both gas and hazardous liquid
transmission lines does not show any benefit from the increased
patrolling frequency for hazardous liquid lines. In 2007 there were 466
hazardous liquid incidents reported for the approximately 160,000 miles
of pipeline. Of these there were 26 due to third party damage. For gas
pipelines there were 127 incident reports for the approximately 300,000
of pipeline. Of these 14 were due to third party damage. There were
approximately 3.7 times more incidents reported for hazardous liquid
pipelines for a population equal to 53% of the gas pipeline mileage.
Taking these factors into account, the number of incidents for pipelines
patrolled 26 times per year is the same as for those patrolled twice per
year (twice per year is an average required number of patrols based on
one per year for Class 1, two per year for Class 2 and four per year for
Class 3). This comparison is arrived by taking 26 third party incidents
for gas pipelines divided by (3.7 \* .53) which equals 13, the expected
number for gas incidents. This compares to the 14 actual incidents.

A report by CFER Technologies for PRCI shows that unless patrolling is
done at least daily, there is not much chance of prevention for outside
force damage. In addition, B31.8 only requires once per year in Class 1
and 2 even when Class 1 pipe can operate at 80%.

*WGP recommends changing the patrolling requirements to four times per
year Class 1, six times per year in Class 2 and twelve times per year in
Class 3*.

This increase in frequency is akin to the frequency for the next higher
class location as are other of the additional requirements in the NPRM.
For example, the requirement in the NPRM for NDE to 100% of all girth
welds in Class 1 areas operating at 80% of SMYS is the same as required
in Class 3 areas in the existing regulations.

[Depth of Cover]{.underline}

The language used in the NPRM for maintaining depth of cover is
confusing. The first sentence says to maintain depth of cover to the
requirements stated in 192.327 or 192.328. The second sentence says that
if observed conditions indicate the possible loss of cover, perform a
depth of cover survey and replace cover as necessary. The first sentence
statement requiring that cover be maintained is a requirement that can
not be obtained in any practical sense. The second sentence statement is
more in line with a performance requirement that can be obtained and is
event driven.

Based on studies of incidents where depth of cover was recorded, it was
found that there is no correlation between depth of cover and third
party damage. There are situations where the removal of cover may pose a
threat of damage to the pipeline due to third party activities such as
in agricultural situations. In these cases the restoration of cover may
be appropriate.

There may be situations where cover can not be permanently restored. In
these situations there may be more appropriate measures that can be
employed, such as the addition of a barrier or some other prevention or
mitigation measure.

For existing pipelines that were installed in accordance with 192.327,
the depth of cover requirements in a Class 1 area was 30 inches. Some
removal of cover may have occurred during the life of the pipeline do to
agriculture, normal soil erosion or other factors. This paragraph, as
written would require the operator to maintain cover to 30 inches for
existing pipelines which may result in significant environmental
disturbance to replace cover over long segments of pipeline.

*WGP recommends changing the language to eliminate the first sentence so
that it reads "If observed conditions indicate the possible loss of
cover in an area where damage to the pipeline may result due to the loss
of cover, replace the cover or provide appropriate prevention and
mitigation measures as necessary".*

[Damage Prevention]{.underline}

The requirement to review the damage prevention program in light of
consensus standards and practices and employ the appropriate practices
into the damage prevention program seems appropriate. The language in
this requirement may lead to many interpretations by the companies and
by inspection personnel due to its ambiguity. The requirement, as
stated, does not identify the standards or practices to be reviewed,
however it may be assumed that the CGA best practices are what are being
referred to in this requirement. An operator may chose to follow one
standard or practice; however inspection personnel may believe the
operator should follow another. Another issue during inspections may be
the determination of which items in a standard or practice should be
followed by the operator.

*WGP recommend changing the requirement so it reads "Review of CGA best
practices and incorporation of the applicable practices into the
operator's damage prevention program"*

[Right-of-Way Plan]{.underline}

The requirement to develop and implement a right-of-way plan is
duplicative of an operator's damage prevention program and other
requirements in the regulations. This additional program is not
necessary or justified. The intent as stated is to protect the segment
from damage due to excavation damage and this requirement is the same as
required in a operator's damage prevention programs as stated in
192.614. Paragraph (a) of this section states "... each operator of a
buried pipeline must carry out, in accordance with this section, a
written program to prevent damage to that pipeline from excavation
damage...".

The other conditions required by the proposed plan are already covered
in 192.613 "Continuing surveillance", 192.705 "Transmission Lines:
Patrolling", 192.706 "Transmission Lines: Leakage surveys". These items
are addressed in an operator's manual of operations and maintenance
procedures as required by 192.605 "Procedural manual for operations,
maintenance, and emergency response".

*WGP recommends removing 192.620(d)(4)(ii) and 192.620(d)(4)(vi) from
the proposed regulations.*

Item (5) -- Controlling internal corrosion:

This proposed regulation is somewhat duplicative yet in conflict with
the new regulation at 192.476 "Internal corrosion control: Design and
construction of transmission line". The new regulation provides specific
requirements for new pipelines for the control of internal corrosion.
The new regulation also has a provision for "change to existing
transmission line" which would apply to any pipeline that is presently
in operation and would be up-rated based on the NPRM. With conflicting
regulations, the operator may not be able to meet both requirements.

This proposed regulation also sets limits on gas quality. These limits
may be in conflict with gas quality requirements set by FERC in an
operator's tariff. In addition, there is no justification in the NPRM
for the limits set.

The proposed regulation requires the use of cleaning pigs and inhibitors
and sampling of accumulated liquids. This requirement is required
regardless of the gas quality, whether or not there is liquid water and
whether or not there are other prevention and mitigation options
available to the operator. The language used in 192.476 is better stated
and covers all the same issues without the need to mandate work that may
not be needed.

In response to the new regulations at 192.476, INGAA companies,
including WGP developed guidelines in order to assist pipeline operators
in determining the requirements of this regulation. These guidelines
"Internal Corrosion Control: Design and Construction of Transmission
Line" should be used in developing regulations for internal corrosion
control measures. In addition, a White Paper, "Management of Time
Dependent Threats" has been developed which discusses the concerns and
remediation of gas quality issues.

*WGP recommends revising 192.620(d(5) to read "develop and implement a
program to monitor gas quality to prevent internal corrosion and to
remediate any gas quality excursions where internal corrosion may
result"*

Item (6) -- Controlling interference that can impact external corrosion:

WGP agrees with the proposed requirements.

Item (7) -- Confirming external corrosion control through direct
assessment:

The requirements in the NPRM and existing regulations provide several
layers of protection for corrosion control. There are specific and
comprehensive requirements for coating application at both the mill and
in the field. There are coating continuity checks after the coating is
applied and again before the pipe is lowered into the ditch and
backfilled. Cathodic protection test stations are installed during
construction. A geometry tool is run after construction which checks for
pipe and ultimately coating damage that may have been caused during
construction. Interference surveys are conducted within 6 months of
placing the pipeline in operation. Cathodic protection is added within
one year of placing the pipeline in operation. A close interval survey
is conducted within six months of placing the cathodic protection in
service. An in-line inspection with an MFL tools is performed within
three years of placing the pipeline in service.

The proposed rule requires operators to "assess the integrity of the
coating and adequacy of the cathodic protection through an indirect
method such as close-interval survey, direct current voltage gradient or
alternating current voltage gradient". Close-interval surveys are used
to confirm the adequacy of cathodic protection. Voltage gradient surveys
are used to determine coating defects. Neither tool can meet both
requirements. This implies that two separate surveys are required.

This proposed requirement also states that remediation of the coating
must be performed based on NACE RP-0502 for any indication that is
severe or moderate. This requirement is in conflict with the NACE
standard which determines severe or moderate based on two or more above
ground methods, not one.

The proposed regulation therefore implies that Direct Assessment must be
conducted on the pipeline after construction and installation of the
cathodic protection systems. These requirements together are excessive
and not necessary. These requirements are in addition to a pressure test
and in-line inspection with an MFL tool. This means that the pipeline
must be assessed using all three tools identified in Subpart O of the
pipeline safety regulations.

The close interval survey may be appropriate in order to confirm that
the cathodic protection system is operating as designed. The coating
survey is not necessary; any coating anomaly is protected from corrosion
by the cathodic protection system. In addition the requirement to base
and respond to results based on the NACE ECDA standard is not necessary.

The requirement to perform the close interval survey within 6 months is
excessive and in many cases not possible. CIS is not performed in winter
months in cold climates and the time between completion of construction
in the fall and CIS in the summer will exceed six months.

A White Paper "Management of Time Dependent Threats" has been developed
and discusses the requirements and needs for corrosion control
activities.

*WGP recommends revising 192.620(d)(7)(i) to read " Within one year of
placing the cathodic protection of a new segment in operations or within
one year after recalculating the maximum allowable operating pressure of
an existing segment under this section, perform a close-interval survey
to determine the adequacy of the cathodic protection system"*

*WGP recommends revising 192.620(d)(7)(ii) to read "Remediate the
coating or insure cathodic protection levels are appropriate to mitigate
corrosion"*

This new requirement states that results of the above ground assessment
results must be integrated with the ILI results within 6 months for
performing the ILI. This timing is burdensome and not necessary. The
value of this data integration is not explained or justified.

*WGP recommend revising 192.620(d)(7)(iii) to read "Within one
year...".*

This new requirement states that test stations be installed at half-mile
intervals in HCA's and that at least one station is in each HCA (see
item B). In addition, this item does not seem to fit under the topic of
periodic assessments. This item may better fit under 192.328(e) as a
construction requirement. In addition location of a test station within
the HCA may not be practical. For example a pipeline that is physically
600 feet from a church and in a farm field, but the church makes it an
HCA; it is not practical to place the test station in the HCA which is
in the farm field. The need for the ½ mile spacing is not justified and
is contrary to consensus standards.

*WGP recommends that this item should be moved to 192.328(e) and that it
could be clearer if it states that "no location in an HCA can be further
than one mile from a cathodic protection test station".*

This new requirement states that there must be periodic close interval
surveys of the pipelines in HCA's and that they are performed in
association with subpart O. This statement is not clear. Subpart O
addresses integrity management and allows the use of one of three
assessment techniques. Item 10 of this paragraph requires periodic
in-line inspections at a frequency determined by the operator. This item
implies that CIS is required at different intervals that the ILI
interval. The need for close interval surveys is not justified or
explained in the NPRM.

*WGP recommends deletion of 192.620(d)(7)(iv) in its entirety once item
(d)(7)(iv)(B) is moved to paragraph 192.328(e).*

Item (8) -- Controlling external corrosion through cathodic protection:

This item states requirements for what is required if a test point
reading falls below criteria. Since the test stations are required in or
near HCA's and are rather closely spaced, and with specific requirements
on what do if the readings fall below criteria, the need for CIS is not
justified.

This proposed requirement states that remediation must be completed
within 6-months. This requirement is excessive and not justified. Based
on the seasons and associated land use issues as well as the time it
takes to obtain permits, a one-year timeframe is more appropriate.

*WGP recommends changing 192.620(d)(8)(i) to read "... within one
year...".*

This item requires a CIS after remediation for a CP issue. This
requirement is excessive and not justified. The reason for a failed
reading may not require CIS to confirm restoration of CP. Example
include loss of power, a cable cut, a short, etc. all of which can be
fixed and have no baring on the effectiveness of the CP on the segment.
The operator does need to confirm that the remedial action was
appropriate and effective, however CIS in not always necessary or may be
inappropriate.

*WGP recommends changing 192.620(d)(8)(ii) to read "After remedial
action to address the loss of CP, the operator must confirm that the
remedial action did restore the CP system to criteria as identified in
192 subpart I".*

Item (9) -- Conducting a baseline assessment of integrity:

This item requires the use of DA for segments that are not piggable.
These segments may be designed per 192.111 and therefore would not be
required to follow the requirements of 192.620. In addition, DA may not
be appropriate for periodic assessments at these locations. Previous
waivers have allowed operators to develop a corrosion control plan that
does not require DA but is entirely appropriate for the subject
segments.

Pressure testing is also an alternative to DA where ILI can not be
performed and should be considered as an option as well

*WGP recommends changing 192.620(d)(9)(iii) to read "...use either DA or
pressure testing to assess that segment or develop and implement a
corrosion control plan to address corrosion of the segment".*

Item 10 -- Conducting periodic assessments of integrity:

WGP agrees with the proposed requirements.

Item (11) -- Making repairs:

Item 11(i) requires the use of the most conservative calculation for
determing remaining strength. This statement seems to imply that more
than one calculation must be performed. Each calculation method results
in slightly different answers with none being more accurate than the
other. This requirement is excessive and has not been justified.

The idea of tool tolerance is addressed in the Protocols used by PHMSA
for expectations of an operator's integrity management program. If
Subpart O is referenced in lieu of this proposed requirement, there is
no need for this requirement.

Item 11(ii) in general, proposes that immediate repair conditions must
be replaced based on the criteria set forth. These proposed requirements
are extremely conservative and in many cases are not achievable. These
criteria are not consistent with Subpart O requirements and have not
been technically justified. These issues have been addressed in a White
Paper "Safety Factors for Assessing Pipeline Anomalies" (attached) which
states that the requirements outlined in ASME B31.8S and incorporated
into Subpart O of part 192 are appropriate for pipelines operating up to
80% of SMYS.

Item 11(ii)(A) sets dent criteria to that required for new pipelines
even if the pipeline is already in operation. For existing pipelines,
this is not a readily achievable requirement and is not technically
justified. The requirements under 192.933(d) are the appropriate
criteria to apply to existing pipelines

Item 11(iii) in general proposes that one year repair conditions must be
replaced based on the criteria set forth. These proposed requirements
are extremely conservative and in many cases are not achievable. These
criteria are not consistent with Subpart O requirements and have not
been technically justified. Again, these issues have been addressed in
the White Paper "Safety Factors for Assessing Pipeline Anomalies".

Early Special Permits required that any anomaly with a predicted failure
pressure to MAOP ratio of 1.1 or less was an immediate repair condition.
A one year condition was an anomaly with a predicted failure pressure to
MAOP ratio of 1.25 or less. Later Special Permits tightened these
already conservative requirements by adding wall loss factors so that an
immediate repair condition also included any wall loss of 60% or more
and a one year condition included any wall loss of 40% or more. These
additional factors are not technically justified and add much more
conservatism than is necessary.

Item 11(iv) is not clear. The terminology is not consistent with Subpart
O requirements in the regulations or ASME b31.8S. If an indication from
an ILI or DA assessment does not require an examination or evaluation,
it is not determined to be a defect. Based on the assessment
information, the indications not remediated are classified and used to
determine the next integrity assessment. This paragraph seems to repeat
the requirements of 10(i) of this paragraph yet they terminology or
intent seems to conflict. Paragraph 10(i) is the appropriate language to
use to require subsequent inspections and references Subpart O where the
requirements are more clearly stated.

WGP would prefer that paragraph 192.620(d)(11) as written be deleted in
its entirety and replacing it with the statement "examination,
evaluation and remediation of any indication or anomaly must be in
accordance with Subpart O of this part". However some recognition for
more conservative repair criteria may be justified for pipelines
operating at the higher pressure levels.

*WGP recommends modification of 192.620(d)11) to read as follows:*

*(i) Do the following when evaluating an anomaly:*

*(A) Use a method for determining remaining strength of a corroded
pipeline that is appropriate for the pipe being evaluated*

*(B) Take into account the tolerance of the tools used for the
assessment*

*(ii) Repair a defect immediately if any of the following apply:*

*(A) For new pipelines, a dent discovered during the baseline assessment
under (d)(9) of this section and the defect meets the criteria in
192.309(b). For existing pipelines, a dent discovered during the
baseline assessment under (d)(9) of this section and the defect meets
the criteria in 192.933(d).*

*(B) The defect meets the criteria for immediate repair condition in
192.933(d)(1)(iii)*

*(C) A corrosion defect with a predicted failure pressure to MAOP ratio
of 1.1 or less; or with pitting depths of 80% or more.*

*(iii) If paragraph (d)(ii) of this section does not require an
immediate repair, repair a defect within one year of any of the
following:*

*(A) The defect meets the criteria for a one-year condition in
192.933(d)(2)*

*(B) A corrosion defect with a predicted failure pressure to MAOP ratio
of 1.25 or less; or with pitting depths of 70% of more.*

The criteria as it relates to the predicted failure pressure to MAOP
ratio will address any issues of remaining strength of the pipeline. The
pit depth criteria will address any issue with the potential for a
corrosion leak. The 80% value for immediate repair conditions is
consistent with the various methodologies for determining remaining
strength of pipelines. Any corrosion with depths of 80% or more is
outside the parameters of the methodologies and provides
conservativeness. The 70% value for one-year repair conditions allows
for extreme pitting corrosion over the one year period without exceeding
the 80% methodology parameters.

Paragraph (e)

WGP agrees with the proposed requirements.

[^1]: Even the Forty-Fourth edition of API 5L, effective October 1, 2008
    retains the 90% SMYS for at least 10 seconds for large diameter
    pipe.