**White Paper on**

**Management of Time Dependent**

**Threats**

**Prepared for the Joint Industry Project (JIP) Committee -**

**Alternate Design with Life Cycle Management**

**May 16, 2008**

Prepared by:

Corrosion and Environmental Cracking Team

**Joint Industry Project Committee**

**Alternate Design with Life Cycle Design Management**

**Steering Committee:**

Alliance Pipeline, Inc. Harold Kraft

Boardwalk Pipeline Partners Frank Maria

CenterPoint Energy Chris Bullock

El Paso Pipeline Group David Bowmaster

Panhandle Energy David Johnson

Spectra Energy Richard Kivela

TransCanada Joe Zhou

Williams Larry Borski

**Committee Support:**

Kiefner and Associates (KAI) Michael Rosenfeld

Process Performance Improvement

Consultants, LLC (P-PIC) John Zurcher

Mark Hereth

Keith Leewis

**Corrosion and Environmental Cracking Team:**

Alliance Arti Bhatia

Gulf South Henry Wang

CenterPoint Energy Micky Redding

El Paso Pipeline Group Drew Helve &

Michelle Anderson Rodriguez

Panhandle Energy Dave McQuilling

TransCanada Shahani Kariyawasam

Williams Ron Douglas

P-PIC Keith Leewis

**BACKGROUND**

The current prescriptive pipeline requirements can be enhanced through
the use of alternative engineering analytical methodologies which allow
substitutions backed by an improved understanding in design and
construction. Alternatively, they may be enhanced in operations and
maintenance through the use of additional rigor in limit states analysis
or additional knowledge of the pipeline operational performance and
associated limits. Uncertainties can be addressed by more frequent and
directed sampling, inspection or monitoring, knowledge of facility
reliability and/or the frequency of threatening situations.

Those who desire to follow the prescriptive rules have the current
pipeline safety regulations and ASME B31.8. Alternate Design with Life
Cycle Management offers alternative solutions because the operator has
improved knowledge of the pipeline's performance ranges and engineering
parameters and has adopted more restrictive methodologies.

Most segments of gas transmission lines constructed since the mid 1980's
should be piggable. However for some portions of these lines it is not
practical for in-line inspection (ILI). Shorter segments, such as
cross-overs between parallel lines, valve bypasses, meter facilities and
headers and other pipe associated with compressor stations need
alternatives to ILI. Such alternatives include the NACE Direct
Assessment methodologies or pressure testing to assess integrity of time
dependent threats. In addition there are many smaller diameter, lower
pressure and sometimes even lower mass flow lines that can not provide
adequate differential pressures to reliably drive a conventional ILI
tools within the necessary window of data acquisition velocities.

The use of only one of three integrity assessment methodologies is
required by the current prescriptive pipeline safety regulations:

1.  In-line inspection tools, for internal and external corrosion

2.  Pressure testing, for time dependent and time independent threats,

3.  Direct Assessment methodologies for time dependent threats, and

A fourth alternative allows for new threat assessment technologies,
through petition.

ILI is generally considered the most convenient integrity assessment
methodology. It is estimated that ILI will be used for more than 99% of
length of transmission lines that will be operating at increased design
pressures; however the remaining 1% must use one of the other three
alternative integrity assessments. Two other integrity assessment tools,
pressure testing (API 1110) and Direct Assessment (NACE RP0502 ECDA,
SP0206, DG-ICDA, & RP0204 SCCDA) have been shown to confirm the
integrity of the pipeline. The ability to consider alternative
technologies promotes innovation.

Pipelines constructed in recent years and designed to operate at higher
operating pressures (i.e. up to 80% of SMYS) are built to more stringent
requirements than those operating under the current pipeline safety
regulations. These pipelines are assessed with a very high pressure
test, with geometry ILI tools and with MFL ILI tools. In addition, other
inspections and surveys are performed to confirm the integrity of the
pipeline. These assessments confirm that the stable, time dependent and
time independent threats are appropriately managed.

Pipelines constructed in earlier decades should be eligible for uprating
to higher operating pressures provided they are shown to meet a
comprehensive methodology of engineering assessments that support safe
operations. Regulators have suggested that the use of prior ILI and
other inspections can provide geometry and wall thickness assessments to
verify the pipeline was constructed in a competent manner. However,
perceived deficiencies in materials or other requirements needed for
uprating still need to be addressed with practical alternatives. The
pipelines are already required to have operations and maintenance
procedures, and with the appropriate prevention and mitigation
activities, the pipeline can manage their day to day operations to
offset perceived deficiencies from recent specifications and standards
in the design and construction phases.

**EXTERNAL CORROSION CONTROL LIFE CYCLE MANAGEMENT**

The external corrosion control practices, when fully employed, provide
for several layers of protection to prevent corrosion of the pipeline.
These layers provide a life-cycle approach to the management of external
corrosion. The practices/layers are discussed in the following
paragraphs.

[Anti-Corrosion Coatings]{.underline}

FBE has proven to be good performer but alternatives need to be
acceptable 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 continues to stifle innovation.

Coating is applied at the mill or in the field in accordance with
application specifications and quality controls. The coating application
and condition is verified by continuity checks after the coating process
and again before lowering the line into the ditch and backfilling.

Most coatings, other than some waxes, have been demonstrated effective
to temperatures much higher than 120ºF (50ºC). A prior coating design
deficiency can be upgraded by alternative activities in either the
construction or operations sectors. It is impractical to excavate to
install monitors to determine the temperature profiles for some number
of miles down stream from each compressor station. The observation of
the coating conditions is unlikely to add significant information. The
operator should be able to use the manufacturer's materials knowledge
and performance testing of current and innovative anticorrosion
coatings. This engineering data will demonstrate there is sufficient
anticorrosion performance for the desired operating temperature.

[Cathodic Protection Test Stations]{.underline}

Cathodic protection test stations are installed during construction of a
pipeline. Test station spacing is currently set by experience at about
one mile intervals along the right of way. Life Cycle Design should
demonstrate that the spacing between successive test points is adequate
to confirm the CP and such guidance is found in NACE RPO169 and other
standards. The operators through PRCI R&D have access to CP system
design courses available from NACE that use software such as PRCI's
report PR101-9512 CP3D - Design of CP Systems for Buried Pipelines. This
engineering methodology determines the appropriate test point spacing
for the variety of different soils and terrain found in pipeline rights
of way.

[Geometry Tool Assessment]{.underline}

Many operators run a geometry tool after construction and before the
pipeline is placed in service. This tool will detect any deformation of
the pipe, including a plain dent or a sharp dent. Sharp dents are often
associated with coating damage. Evaluation of the anomaly based on
pre-determined criteria may find that there is in fact a defect in the
pipe. The anomalies are visually examined for pipe and/or coating
damage. Any defect of the pipe or damage to the coating is repaired.

[AC/DC Interference Survey]{.underline}

Operators have indicated that the threat of electrical interference and
the associated incidences of external corrosion damage are more
prevalent as utility corridors become increasingly congested.
Municipalities and States are increasingly forced to route other
services, such as high voltage AC and transportation, by road and rail
into the limited terrain.

An early aboveground baseline electrical survey to the NACE ECDA
standard can locate areas where neighboring utilities are causing
interference. These surveys are typically performed within six months of
placing the pipeline in service. Special attention is paid to foreign
crossing and AC/DC interference locations.

If deficiencies are found during the baseline survey, then the Operators
procedures will provide information on how they can be mitigated or
prevented to minimize the potential external corrosion.

[Coating Condition Survey]{.underline}

A few Operators conduct a coating survey after construction using DCVG,
ACVG or other appropriate survey techniques. This is typically conducted
in areas where the construction quality control process may not have
adequately addressed coating damage or in areas where rocks or other
ditch and backfill characteristics may have an impact on the coating
system.

This practice is not widespread and usually not necessary due to the
many other layers of protection provided in the corrosion control
process. The cathodic protection system is employed in order to provide
corrosion control for the pipeline in and only in the event that the
coating system is compromised. In addition, baseline and periodic MFL
inspection will find any areas of corrosion on the pipeline.

[Cathodic Protection (CP) Initiation]{.underline}

The anti-corrosion coatings provide primary corrosion protection system.
The CP system provides the secondary protection system. CP on long
systems requires an integrated approach and the early provision of
protection section by section comes with scheduling problems. Activation
of the CP system should be completed as soon as practical after the pipe
goes in the ground but never longer than one year. The baseline survey
using the test points can be conducted once the whole new system is
installed and becomes operational. Adequate voltage readings at each
test point confirm that the CP system is operating correctly.

Deficiencies in the initial test point voltage readings, if found, are
usually not caused by coating problems but are most likely installation
related. The Operator's procedures should be used to determine the root
cause of the deficiency, rather than requiring DCVG or other aboveground
coating inspections both upstream and downstream of the deficient test.

[]{.mark}

[Cathodic Protection Verification]{.underline}

Some operators conduct an above ground electrical inspection, such as a
Close Interval Survey (CIS) after the cathodic protection system has
been installed. This inspection has proven to be helpful in finding
deficiencies in cathodic protection. An early survey, typically within
one year of placing the cathodic protection system in service, is
usually appropriate to confirm the adequacy of the CP system.

Other operators rely on the annual test point readings to confirm
appropriate cathodic protection. The choice of which verification method
is used should be left to the operator. The operator knows better the
condition of the coating when installed, the backfill methods, the
terrain and other variables that may impact the levels of cathodic
protection. There has not been any research or studies to support one
method over the other for post construction and post CP installation
verification.

[Direct Assessment (DA)]{.underline}

To date, Operators have not employed the direct assessment methodologies
for newly or recently constructed pipelines to be operated at higher
pressures. DA would constitute a third integrity assessment and such an
effort is deemed unnecessary and redundant to all the other inspections
and surveys performed.

[Periodic Test Point Voltage Survey]{.underline}

Periodic cathodic protection surveys are performed at least annually at
each cathodic protection test point. This is done to confirm that the
coating and CP system together provide the necessary corrosion
prevention. Adequate CP also prevents the initiation of external
corrosion as well as SCC and external MIC.

The Operator's procedures provide for appropriate responses to
deficiencies found during these surveys. The Operator's procedures
provide for determining the cause of the inadequate voltage readings,
the timing for conducting remediation based on the cause, remediation of
the cause and confirmation that the situation has in fact been remedied.
CIS is sometimes conducted in the area or the location where
deficiencies exist, however this is only done if the situation warrants
such a survey.

[Periodic Integrity Assessments]{.underline}

Periodic assessment for the external corrosion threat should be
performed at intervals determined by corrosion growth rates. An initial
or baseline assessment with a MFL tool may have value. However, how soon
after construction the tool should be run is debatable. ASME B31 .8S
requires periodic integrity inspections for pipe. Pipe operating above
80% SMYS is required to be assessed each five years. A baseline MFL tool
run conducted three years after construction will likely provide no more
information than one conducted five years after construction.

The initial assessment, whether run at year five or sooner, confirms
that the coating and cathodic protection systems are performing as
necessary by finding that no corrosion has occurred. Any indication of
corrosion found during this initial assessment should be investigated,
the cause determined, and the pipeline, coating and cathodic protection
systems remediated in accordance with the Operator's procedures.
Corrosion found early in the life of a pipeline should be an indication
to the operator that the corrosion control system is not working as
designed and that it must be remediated.

[Periodic Close Interval Survey]{.underline}

Periodic CIS is typically not performed on operating pipeline systems.
There is not a documented rationale for performing the surveys when
cathodic protection levels are maintained to appropriate levels and/or
when the Operator employs an integrity management program that addresses
the external corrosion threat.

CIS is a tool used to find areas of low cathodic protection levels when
determining the cause of the low cathodic protection level. These
options are discussed in the Operator's procedures for remediation of
external corrosion control issues.

[Integration of Base Line Inspection Techniques for EC]{.underline}

Integration of the ILI geometry and baseline CIS survey may provide a
QA/QC check on construction processes and results. A later ILI
inspection for base line wall thickness confirmation may be integrated
with the baseline geometry and CIS surveys to complete the initial
threat assessment and establish the completed baseline threat
assessment.

Integration of the data is unnecessary when the Operator addresses each
corrosion control issue thoroughly. This includes determination of the
cause for corrosion, remediation of the cause for corrosion, and
confirmation that the remediation effort was effective.

[]{.mark}

**INTERNAL CORROSION CONTROL LIFE CYCLE MANAGEMENT**

[Gas Quality]{.underline}

Gas compositional limits should be set by the requirements in the
current contractual documents as mandated by FERC in the Operators
tariff. These reflect the differences in natural gas composition arising
from different source gas field location, gas treatments, and the
recognition of historical swings and associated penalties rather than
setting arbitrary regulatory limits. The pipeline systems experience gas
compositional fluctuations and upper and lower bound limits are placed
in the contractual language to cover the operating consequences of
planned and unplanned excursions. Excursions such as a liquid slug falls
outside the established limits and are handled as exceptions. Management
of these exceptions in the gas composition triggers an engineering
assessment that in turn sets the operational and mitigation responses to
maintain the safety of the system.

[Facilities Design to Address Internal Corrosion]{.underline}

The pipeline safety regulations were recently updated and now ask
operators to monitor the gas quality, especially condensed water, and
require new segments to be designed for the passage of ILI tools. The
upstream natural gas transmission lines which are closest to storage and
producing fields are most susceptible to internal corrosion. These
segments may use coupons, separators, and similar technologies to
monitor for water and minimize internal corrosion downstream. Gas
chromatographs may be used in some locations for periodic chemical
analysis but these tools require considerable maintenance and
specialized housing. Generally operators periodically grab small gas
volumes and these samples are sent to a laboratory for analysis.

The large diameter pipelines tend to minimize gas quality excursions by
blending in all local field variations while the methane is gathered at
shipping points and before being transported across country. Interstate
gas transmission pipelines remain essentially free of condensed water
and if piggable, the periodic passage of ILI tools is very effective
when monitoring internal corrosion. The addition of additional filter
separators or scrubbers may reduce particulate content and reduce
erosion and associated wear in compressor systems but these facilities
were never designed to eliminate water transport.

The requirement to sample pooled water, and use cleaning pigs and
inhibitors to prevent and monitor internal corrosion is not practicable
in lines which are essentially dry and of course not possible in lines
which are not piggable. The Operator of these transmission lines may
wish to use NACE DG-ICDA to determine if they are susceptible to
internal corrosion. A methodology such as NACE ICDA indicates locations
for potential corrosion and if confirmed, these places would also be
suitable for coupon placement or other monitoring techniques for
monitoring the internal corrosion threat.

A guideline "Internal Corrosion Control: Design and Construction of
Transmission Line" was prepared by the INGAA Pipeline Safety Committee
on October 29, 2007. This document provides a valuable guideline
managing internal corrosion and for complying with the pipeline safety
regulations. The guidelines include information such as:

-   Liquid removal features and designing to allow for the use of
    monitoring devices for internal corrosion are unnecessary if there
    are no locations at which liquid water can collect under design
    conditions.

-   If the configuration would allow liquid water to collect, then
    effective liquid removal features must be installed. Compliance with
    the regulations is achieved by adding liquid removal features and
    designing to allow for the use of monitoring devices is unnecessary
    provided a program for liquid removal is instituted.

-   If there is significant potential for internal corrosion, meaning
    liquid water is likely to collect and a liquid removal system is not
    provided or does not effectively remove liquid water, then devices
    for monitoring must be provided.

Water as condensed moisture must be present before internal corrosion
can initiate and/or grow. The absence of condensed water makes the
corrosion process go dormant, hence the general requirement to keep the
maximum water impurity below 7#/MMCF. Other gas impurities such as CO~2~
and H~2~S, which generally come with underground methane sources, remain
inert unless condensed water is present. The essential presence of
condensed water is recognized in the NACE standard RP0206 DG-ICDA.
Limiting the gas composition of CO2 to 3%, H20 to 7#/MMCF, H2S to
0.50/100 mmcf by the gas transmission pipelines is impractical. The
composition is a function of the source, dry LNG, wet and possibly sour
gas compositions from coal beds or gas wells vary within a field, and
from region to region. Removal of water and other gas impurities,
especially those that could accelerate corrosion in the presence of
condensed water, must be done upstream; gas transmission pipeline
operators are not equipped to upgrade the received gas quality.

Periodic review of the gas quality is appropriate in order to determine
if a gas quality excursion may have occurred and the Operator was not
aware, through normal operations and maintenance activities that such an
excursion has occurred. Normal operations and maintenance activities
include looking for liquids at locations designed to collect liquids,
inspections of the internal surfaces of the pipe when exposed, and
through alarm management of any automated monitoring devices. An annual
review of the internal corrosion control program is appropriate and
conducted by many operators.

These annual reviews are already required for HCA's in an Operators
integrity management program. It is also an appropriate period as
determined during the development of the applicable ASME and NACE
standards.

Internal corrosion requires condensed water to be present and for this
water to persist and enable internal corrosion. The absence of water and
records that validate that no water is or has been present should show
that the threat is not present and allow re-inspection intervals to be
replaced by monitoring frequency. Lines that have had upsets may
eliminate the internal corrosion threat through corrective design.

**CORROSION RATES AND REASSESSMENT INTERVAL**

[Determination of Corrosion Rates]{.underline}

It is important to note that the default corrosion rates and associated
inspection frequencies in the ASME and NACE standards are excessive and
should be replaced by actual measured values. This may not be possible
until two or more integrity assessments are completed.

Several methodologies to determine the local corrosion rate and a remote
electro-chemical technique are being developed through PRCI funding to
help operators. Operators generally determine the actual corrosion rate
from successive ILI inspections and examination of the pipe. The
corrosion rate is improved with the integration of other integrity
assessments and actual supporting observations such as corrosion
measurements obtained over time in similar locations. The uncertainty in
the corrosion rate is a function of the ILI technology with high
resolution tools generally reducing the width of their statistical
distributions. Currently the operator measures the wall loss and then
assumes the pipe has been corroding at a constant rate from an
initiation date many years after installation. For pipe that is known to
have good external corrosion protection, corrosion rates are much less
than 0.004"/yr (considered high around 0.007"/yr and extreme at
0.012"/yr as set out in B31.8S).

Operators agree that the re-inspection intervals provided in the ASME
B31.8S standard, which were based on default corrosion rates, are
appropriate. Others have suggested these may not be appropriate for
higher stress operations. A White Paper "Safety Factors for Assessing
Pipeline Anomalies" provided an analysis of the tables and figures in
this standard in light of this concern.

[Determination of Reassessment Intervals]{.underline}

The JIP Corrosion and Environmental Cracking Team maintain that the
default corrosion rates required by the current prescriptive regulations
are almost an order of magnitude greater than those normally found.
These prescriptive default corrosion rates are one (ASME B31.8S) or two
(NACE 0502) standard deviations greater than the mean value derived from
the PHMSA incident records. Then these rates are effectively doubled (by
dividing the resulting interval by two) as a second arbitrary safety
factor.

Both the pipeline safety regulations and the ASME B31.8S and the three
NACE Direct Assessment standards provide methodologies to calculate an
interval for the next integrity assessment. The methodology requires the
interval to be arbitrarily divided by a factor of two and further reduce
the uncertainty of the estimate. The use of an actual corrosion rate for
each location is expected to generate intervals that exceed the current
ASME B31.8S prescriptive reinspection intervals.

The length of the prescriptive reassessment intervals were discussed in
the White Paper "Safety Factors for Assessing Pipeline Anomalies".
Essentially, when the internal MAOP is equal to 80% SMYS then a pressure
test to SMYS is 1.25 times the MAOP. ASME B31.8S Figure 4 shows that the
interval for the Pf /MAOP ratio equal to 1.25 is 5 years.

The White Paper shows that the corrosion rate is proportional to wall
thickness and suggests a "rule of thumb" relationship. New pipelines are
expected to exceed 1,000 psig and use larger diameter pipes, both
require thicker pipe. At the same corrosion rate the prescriptive
reassessment interval would be expected to increase however, ASME B31.8S
restricts it to 5 years.