Final Report

On

Improvements to the External Corrosion Direct Assessment (ECDA) Process

(WP # 360)

Cased Pipes
(Project #241)

for

Pipeline and Hazardous Materials

Safety Administration (PHMSA)

U.S. Department of Transportation

Contract No. DTPH56-08-T-000012

by

CORRPRO COMPANIES, INC.

7000 B Hollister
Houston, Texas 77040

June 2010
PHMSA Project 241 – ECDA of Cased Pipeline Segments

PHMSA Contract No. DTPH56-08-T-000012

Improvements to the External Corrosion Direct Assessment (ECDA) Process (WP #360)

Acknowledgements
This project was completed under contract to the Pipeline and Hazardous Materials Safety
Administration, U. S. Department of Transportation, under Contract No, DTPH56-08-T-
000012, with Mr. Bill Lowry serving as the contracting officers’ technical representative. In-
kind cost-sharing contributions came from ExxonMobil Pipeline Company, El Paso Pipeline
Group, and Panhandle Energy.

Neither Corrpro nor Government, nor ExxonMobil Pipeline Company, nor El Paso Pipeline
Group, nor Panhandle Energy through their in-kind cost-share involvement, nor any person
acting on their behalf:

• Makes any warranty or representation, expressed or implied, with

respect to the accuracy, completeness or usefulness of any
information contained in this report or that the use of any information,
apparatus, method, or process disclosed in this report may not
infringe privately owned rights.

• Assumes any liabilities with respect to the use of, or for damages
resulting from the use of any information, apparatus, method or
process disclosed in this report.
PHMSA Project 241 – ECDA of Cased Pipeline Segments

PHMSA Contract No. DTPH56-08-T-000012

Improvements to the External Corrosion Direct Assessment (ECDA) Process (WP #360)

Improvements to the External Corrosion Direct Assessment (ECDA) Process

Cased Pipes

TABLE OF CONTENTS

Executive Summary....................................................................................................................1

Introduction ..............................................................................................................................2

1.1 Project Objectives ............................................................................................................4

1.2 Cased Pipes and ECDA Methodology .............................................................................4

1.3 Existing Cased Pipes Assessment Technologies ............................................................5

1.4 Drivers for Cased Pipes ECDA Methodology...................................................................9

1.5 Indirect Inspection Tools ..................................................................................................9

1.6 Indirect Inspection Survey Data Sources .......................................................................10

1.7 Pre-Assessment.............................................................................................................10

1.8 Indirect Inspection..........................................................................................................10

1.9 Results for 30 Example Cased Pipe Indirect Inspections...............................................13

1.10 Possible Improvements to Technologies .......................................................................19

1.11 PHMSA Committees ......................................................................................................20

1.12 Enhanced ECDA Methodology for Cased Pipes ............................................................20

1.13 Prospective Future Research Project ............................................................................20

1.14 Conclusion .....................................................................................................................20

1.15 References ....................................................................................................................21

Appendix – Draft Recommended Guidelines for ECDA of Cased Pipeline Segments

Supplemental Information - Casing ECDA Survey Data: Volumes 1 through 3 (Because of

size, the 3 volumes are to be submitted through ground transporation)
PHMSA Project 241 – ECDA of Cased Pipeline Segments 1
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

Improvements to the External Corrosion Direct Assessment (ECDA) Process

Cased Pipes

Executive Summary
On June 28, 2007, PHMSA released a Broad Agency Announcement (BAA),
DTPH56-07-BAA-000002, seeking white papers on individual projects and
consolidated Research and Development (R&D) programs addressing topics
on pipeline safety program. Although, not specifically suggested by PHMSA,
three Direct Assessment projects were proposed by Corrpro based on in-
house gap-analysis of the External Corrosion Direct Assessment (ECDA)
process. A white paper was submitted for a consolidated Research and
Development (R&D) program entitled “Improvements to the External
Corrosion Direct Assessment (ECDA) Process”. It was eventually approved
for implementation by PHMSA with the following 3 projects:
• Cased pipes
• Severity ranking of ECDA indirect inspection indications
• Potential measurements on paved areas
The ultimate goal of each of the program was to present the results and
recommendations to the applicable Standards Development Organizations
(SDOs) to ensure the strengthening of industry consensus standards and the
timely implementation of research benefits for improved safety, environmental
protection, and operational reliability. It was also to expand DA applicability
and increase the knowledge of the DA methodology.
The accomplishments and conclusion of Cased Pipes are summarized as
follows:
• An effective ECDA methodology was developed as another
assessment option for cased pipes.
• The methodology makes use of ECDA Indirect Inspection surveys
being used on uncased, buried pipe as part of the process for
identifying and ranking Direct Examination priorities and selecting the
most effective assessment tools
• The completed methodology will include guidelines produced by the
CASQAT committee.
• The completed methodology will be provided to industry organizations
for development of consensus standards.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 2
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

Introduction
A Government and Industry Pipeline R&D Forum was held in New Orleans on
February 7 and 8, 2007, by the U.S. Department of Transportation (DOT),
Pipeline and Hazardous Materials Safety Administration (PHMSA). The 2-day
event included approximately 240 representatives from Federal, State and
international government agencies, public representatives, research funding
organizations, standards developing organizations, and pipeline operators
from the U.S., Canada and Europe. The R&D Forum led to a common
understanding of current research efforts, key challenges facing government
and industry, and potential research areas where exploration can help meet
these challenges, and should therefore be considered in developing new
research and development applications. On June 28, 2007, PHMSA released
a Broad Agency Announcement (BAA), DTPH56-07-BAA-000002, seeking
white papers on individual projects and consolidated Research and
Development (R&D) programs addressing topics on pipeline safety program
areas identified at the R&D Forum, namely:
1. Excavation Damage Prevention Technologies
2. Direct Assessment Methods for Transmission and or Distribution
Pipelines
3. Defect Detection/Characterization
4. Defect Remediation/Repair/Mitigation
5. New Fuels Transportation
Several specific R&D projects were suggested in the BAA. Although, not
specifically suggested by PHMSA, three Direct Assessment projects were
proposed by Corrpro based on in-house gap-analysis of the External
Corrosion Direct Assessment (ECDA) process. Over several years, ECDA
has been used to assess the condition of thousands of miles of natural gas
pipelines. Corrpro’s gap analysis identified three key areas of opportunity to
enhance application of the technology. A white paper was submitted for a
consolidated Research and Development (R&D) program entitled
“Improvements to the External Corrosion Direct Assessment (ECDA)
Process”. It was eventually approved for implementation by PHMSA. One of
the three components of the consolidated R&D program is as follows:
PHMSA Project 241 – ECDA of Cased Pipeline Segments 3
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

Cased pipes: Technologies that are currently used to assess cased pipes
include in-line inspection, guided wave ultrasonic, electromagnetic wave,
pulsed eddy current, conformable array, bore scope, pressure testing and
visual inspection. The three most promising in-line technologies presently in
use or being developed are: In-Line Inspection (ILI), Guided Wave Ultrasonic
Inspection (GWUT) and Electromagnetic Wave Inspection (EMW). Several
other technologies are under development, some of which have the potential
to be better for inspecting cased pipe than these three tools. While these
technologies are recognized as the best minimally invasive technology
presently available for identifying and quantifying corrosion and other metal-
loss defects, they can not easily or economically be used on many pipelines.
The ultimate goal of each of the projects is to present the results and
recommendations to the applicable Standards Development Organizations
(SDOs) to ensure the strengthening of industry consensus standards and the
timely implementation of research benefits for improved safety, environmental
protection, and operational reliability. It is also to expand DA applicability and
increase knowledge of DA methodology.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 4
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

1.1 Project Objectives

The goals of the Cased Pipes Project are:
• To obtain, evaluate and utilize the results of industry surveys related to cased
pipes
• To Identify, analyze and determine applicability of existing and emerging
technologies for assessing cased pipes for external corrosion damage
• To develop and verify a new assessment methodology (that makes use of
existing ECDA methodologies, existing and emerging technologies, and best
practices of pipeline operators) for assessing pipelines in casings under
electrically (metallically) shorted, electrolytically coupled and electrically
isolated conditions
• To convey new methodology and application guidelines to industry
organizations for development into consensus standards
• To produce project report, and conduct web-based workshop and public
presentations
The project is designed such that its results parallel PHMSA program elements,
namely: pipeline assessment, defect characterization, improved design of data
collection systems, human factors and safety.

1.2 Cased Pipes and ECDA Methodology

Although modern horizontal directional drilling construction techniques tend to
eliminate benefits of casings, the legacy reasoning for the use of cased crossing was
to provide the capability to remove or replace carrier pipeline without disturbing the
road or rail-crossing. Casings accommodate higher dead loads (overburden for
deep pipe), live loads (traffic) and prevent third-party damage to the pipeline. On the
other hand, greater strength and/or pipeline wall thickness, concrete coatings and
other methods could provide protection to the pipeline from mechanical damage and
external loads.
The downsides to the use of casings are numerous, namely: additional design and
construction costs, additional maintenance and monitoring of electrical isolation and
the problems associated with electrical shorts, including remediation, and increased
loads on the cathodic protection (CP) systems. If the annular space between the
pipe and casing becomes filled with an electrolyte, possible corrosion mechanisms
include electrical shielding, crevice corrosion associated with nonmetallic casing
spacers and pipe corrosion at coating flaws.
Although it is possible for CP current to get to the pipe through the casing containing
electrolyte, mud or debris deposits in contact with the pipe may interrupt a
continuous electrical path to the casing. If there is an electrical short between the
pipelines and casing, the casing may appear as a large coating flaw on the pipeline,
consume the available CP current and reduce CP effectiveness at other locations
along the pipeline.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 5
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

While uncased road and railroad crossings are becoming common with the use of
concrete-coated pipe for damage protection and/or modern horizontal directional
drilling construction techniques, aging cased pipelines still pose significant corrosion
problems. Several pipeline failures caused by external corrosion on cased pipe in
the past have injured members of the public, damaged property and/or the
environment. More failures are likely to occur in the future on account of aging
cased pipes. It is simply not practical to assess many cased pipes for external
corrosion damage using standard assessment methods for the following reasons:
• Service interruption required for pressure testing is unacceptable particularly
for natural gas pipelines,
• Pipeline excavation required for attachment of equipment used to propagate
an inspection signal along the pipeline in the casing is either not possible or
impractical,
• Introducing water into the pipeline for pressure testing is unacceptable,
particularly for natural gas pipelines,
• Pipeline configuration prevents the use of in-line inspection tools, and
• Pipeline operating conditions preclude the use of in-line inspection tools.
There is a real need for an economic, effective ECDA methodology that can be
employed at cased crossings where ILI, pressure testing, or excavating the pipeline
are either not possible or impractical. The technology needs to be minimally intrusive
to limit disruption of pipeline operations and road and railroad use. NACE SP0502
and SP0200 provide some guidelines and methods but there is no specific standard
that provides detailed procedures for assessing cased pipelines using ECDA.
Conventional aboveground indirect inspection tools used in ECDA are not effective
for cased pipes if there is no electrical path in the annulus between the casing and
the pipeline. Even when an electrolyte is introduced into the annulus, the casing
may still act as a shield such that the results from most indirect inspection tools
regarding the CP level or coating condition may not be particularly meaningful.
The primary goal of this project is to develop a new ECDA methodology that can be
used to assess cased pipes which can not be assessed by standard methods. This
new ECDA methodology will fill the assessment gap, enhance safety and protect the
environment.

1.3 Existing Cased Pipes Assessment Technologies

Although, the focus of the present work is to develop a Cased Pipes External
Corrosion Direct Assessment methodology, it is instructive to examine the major
methodologies that have been used so far for inspecting cased pipes. These existing
technologies and methodologies are well grounded and are well accepted by the
pipeline industry. Examples include:
PHMSA Project 241 – ECDA of Cased Pipeline Segments 6
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

Pressure testing: Pressure Testing (PT), illustrated in Figure 2-1, is an important

integrity verification method. When used for pipeline testing, hydrocarbons are
removed and the pipeline is completely filled with water. Hydrostatic pressure is
increased until the required pressure is achieved. The required pressure is held for
a period while the pipeline is visually inspected for leaks. Testing is mandated to be
performed at 125% of the maximum operating pressure (MOP) for at least 4
continuous hours and an additional 4 hours at a pressure at least 110% MOP if the
piping is not visible. The use of hydrotesting for integrity verification purposes is
based on the supposition that, after defects that fail above MOP are removed, the
line is safe to operate at MOP and below.
A special type of pressure test, a spike test, is used to detect stress corrosion
cracking. During a spike test, the pipeline is maintained at the elevated pressure for
a short period to induce stress corrosion cracking. If failure occurs, the pipeline is
replaced. If failure does not occur, the elevated pressure imparts surface
compressive stresses on the pipe, providing an important stress corrosion cracking
control mechanism.
When pressure testing is used as a verification method, the tests are conducted on a
repeated frequency for the lifetime of the pipeline, or until an alternative verification
method is selected. Water is preferred as the pressure medium to limit safety
hazards and environmental damage in the event of a leak or rupture while testing.
After hydrotesting, the pipeline is safely emptied in accordance with the prevailing
regulation. The pipeline is dried to ensure it is free of all moisture before it is placed
in service. Some companies run a slug of biocide between two sealing pigs for
laying a tenacious film on the inner circumferential surface of the pipe wall to reduce
the risk of microbiologically induced corrosion (MIC).
Pressure testing has a few significant disadvantages for pipeline operations.
First, it is a destructive test.
Secondly, it requires an interruption in service, which can be a problem when a
single pipeline is feeding a plant or an entire city.
It is a pass or fail test with integrity conclusions that are relevant only at the time of
the test. For example, the size of the anomalies that remain can be very large and
no information is provided regarding non-critical flaws that might soon become
critical cracks.
In the event of a failure, the cost of repairing a rupture due to a defect on the pipeline
can be substantially more than the cost of repairing a defect if it was discovered
through non-destructive verification method.
Dewatering, cleaning, and drying a pipeline after hydrostatic testing can be both time
consuming and costly.
In-line Inspection: In-Line Inspection (ILI) technology has existed for more than 40
years and is recognized as a mature technology for inspecting pipelines in a manner
that is minimally disruptive for pipeline operations when compared to pressure
testing and other highly disruptive technologies. ILI is capable of identifying and
PHMSA Project 241 – ECDA of Cased Pipeline Segments 7
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

quantifying many pipe defects such as external corrosion damage, internal corrosion
damage, dents, gouges and hard spots. Specialty ILI tools are capable of identifying
and quantifying cracking defects such as stress corrosion cracking, selective
longitudinal seam corrosion and circumferential weld defects. It is widely accepted
by the pipeline industry that ILI technology is capable of obtaining sufficient
information to allow full assessment of pipe condition for many pipe defects;
particularly for corrosion damage and other metal-loss defects.
Some limitations of ILI are as follows:
While ILI is recognized as the best minimally invasive technology presently available
for identifying and quantifying corrosion and other metal-loss defects, it can not
easily or economically be used on many pipelines. Pipelines where ILI can easily
and economically be used are those that are constructed in manners that allow
insertion and removal of the inspection tools (launchers and receivers), allow
passage of the inspection tools through the pipelines (full-opening valves, uniform
pipe diameter and long radius bends), and operating conditions that satisfactorily
propel the inspections tools through the pipelines (product flow rates within the
ranges required by the tools for both liquid and gas pipelines, and adequate
pressure to prevent surging for gas pipelines). Most liquid and many gas
transmission pipelines were either built or can be relatively easily and economically
modified to accommodate ILI tools. Unfortunately, not all liquid and a significant
portion of gas transmission pipelines were not constructed to allow ILI, and most gas
distribution systems were not constructed and do not have operating conditions (flow
rates and pressures) that allow ILI.
Guided Wave Ultrasonic Inspection: Guided Wave Ultrasonic inspection
technology (GWUT) has been used to inspect difficult-to-access pipeline segments
for approximately 10 years. Over the past 3 to 5 years GWUT has seen widespread
use for inspecting cased pipe segments. GWUT is minimally disruptive for pipeline
operations because, unlike ILI, it does not require pipe to be opened for
insertion/removal of inspection devices, does not require pipe modifications (such as
for valves that are not full opening, pipe of varying diameter, and short radius
bends), and is not appreciably affected by product flow or pressure. The GWUT
transmitter/receiver sensors are mounted on a collar that simply wraps around the
pipe being inspected.
Other than pressure testing, ILI and visual inspection, GWUT is the only other
inspection technique for inspecting cased pipe formally recognized by PHMSA at the
present time. This acceptance is conditional upon a set of 18-point GWUT
requirements/restrictions. While not yet considered a mature technology for
inspecting pipe, significant improvements to GWUT over the coming years are likely.
It is reasonable to assume that GWUT technology will develop into a mature
inspection technology much like ILI technology.
Even though GWUT is limited to short lengths of pipeline, it is capable of inspecting
a significant percentage of cased pipe segments. Casings that are too long to be
inspected from one setup location at one end of the casings often can be inspected
by setting up the GWUT equipment at both ends and inspecting into the casings.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 8
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

Some present limitations of GWUT are as follows:

To be acceptable to PHMSA for inspecting cased pipe, GWUT inspections must
follow a strict 18-point inspection protocol. Even if the protocol is followed and
GWUT inspection meets the restrictions, it is still considered to be a Go/No Go
inspection technique for pipe defects with additional assessment requirements in No
Go situations.
GWUT technology for pipe inspection is at this time in its infancy when compared to
ILI technology. It is not presently capable of identifying and quantifying pipe defects
to the same degree as ILI, and information obtained by GWUT is not sufficiently
detailed to allow full assessment of pipe defects.
For all practical purposes, GWUT is now only capable of detecting gross metal loss
defects and is not extremely reliable for discriminating between metal loss defects
and acceptable cased pipe discontinuities such as casing spacers.
The primary inconveniences with use of GWUT technology are that buried pipe
segments must be excavated to allow mounting of the sensor collar on the pipe and
most types of external coatings must be removed from the area of the pipe where
the sensor collar is mounted.
Additionally, the inspection range of GWUT equipment is limited by conditions that
cause rapid attenuation of ultrasonic sound such as external coatings, contact with
soil and water, pipeline appurtenances such as valves and flanges, and products in
liquid pipelines.
Lengths of pipeline that can be inspected by GWUT from one setup location vary
widely depending on conditions, but typically range from about 50 feet to 200 feet.
Electromagnetic Wave Inspection: Electromagnetic Wave inspection technology
(EMW) has much in common with GWUT inspection technology in the way that it
functions and in the way that it is used. While GWUT uses ultrasonic sound waves
to inspect pipe, EMW uses electromagnetic waves. EMW application to pipeline
inspection is much more recent than GWUT and it is significantly more in its infancy
than GWUT. Although it is not yet considered a mature technology for inspecting
pipe, significant improvements to EMW over the coming years are likely. As with
GWUT, it is reasonable to expect EMW technology to develop into a mature
inspection technology. EMW appears to be developing much in the same manner as
GWUT, but EMW is in its infancy when compared to GWUT. Its first PHMSA
acceptance may be as a technique to judge the quality of filling when filling casings
with wax
Some present limitations of EMW are as follows:
Testing thus far indicates that EMW is more likely to be a technique for evaluating
the environment in the casing annulus rather than for evaluating cased pipes.
EMW appears to be capable of determining if the casing annulus is filled with liquids
or solids (water, mud, casing filler, etc.), and the locations of liquids and solids when
only partially filled.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 9
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

1.4 Drivers for Cased Pipes ECDA Methodology

Although, the major methodologies that have been used so far for inspecting cased
pipes are well grounded and are well accepted by the pipeline industry, there are
significant drivers for Cased Pipes ECDA Methodology:
• Pipeline operators are faced with tremendous challenges when assessing
cased pipe that cannot reasonably be assessed using pressure testing or in-
line inspection
• The emerging cased pipe assessment technologies are promising, but will
likely take years to develop into acceptable assessment techniques
• The deadline for assessing all Gas Transmission pipe, including cased pipe,
is December 17, 2012 – 2-1/2 years from now
• ECDA methodology that is now accepted for uncased buried pipe can be
developed, improved and/or augmented to be an acceptable assessment
technique for cased pipe where pipe and casing conditions allow its use
It has long been the pipeline industry consensus that standard coating and cathodic
protection surveys can not be applied to cased pipes because casings and/or lack of
continuous electrolyte in casing annuli prevent electrical measurements. Both past
and current Corrpro research and testing have demonstrated that cathodic
protection can reach cased pipes even if the casing is electrically shorted to the pipe
(GRI-05/0020 and other research). If cathodic protection current can reach cased
pipes, standard coating and cathodic protection surveys can be applied to cased
pipes even though application may be limited if casing is electrically shorted to pipe,
if casing is coated or if no electrolyte is present in casing annulus.
Based on evaluations of information obtained from previous research, industry
surveys, operator data, operator procedures, best practices, laboratory and field
testing, appropriate assessment technologies and/or methodologies could be
identified for various cased pipe parameters/situations. Given that cathodic
protection current can reach cased pipe under certain conditions, standard coating
and cathodic protection survey techniques should also be at least partially effective
under these certain conditions. As a minimum, standard coating and cathodic
protection survey techniques do produce pertinent data on buried pipe outside of
casings that can be used to ascertain likely conditions related to coating condition
and external corrosion on cased pipe. The methodology would make use of ECDA
indirect inspection surveys being used on uncased, buried pipe as part of the
process for identifying and ranking direct examination priorities and selecting the
most effective assessment tools.

1.5 Indirect Inspection Tools

NACE SP0502 provides guidance for the selection and use of numerous Indirection
Inspection tools that are capable of detecting and evaluating external coating defects
and cathodic protection deficiencies on buried pipe in order to identify locations
where external corrosion has occurred or may be occurring on buried pipelines.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 10
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Improvements to the External Corrosion Direct Assessment (ECDA) Process

Most of the Indirect Inspection tools depend on pipe being buried or submerged in
an electrolyte that can be contacted with electrical survey devices to detect coating
defects and cathodic protection deficiencies. Some of the tools do not depend on
pipe being buried or submerged in an electrolyte. For this project, two tools were
used that depend on the presence of an electrolyte, the DC Voltage Gradient survey
and the Close Interval Potential survey, and one tool was used that does not depend
on the presence of an electrolyte, the AC Current Attenuation survey. These three
tools are the most common tools used by the pipeline industry for ECDA of buried
pipe.

1.6 Indirect Inspection Survey Data Sources

Indirect Inspection survey data were obtained from numerous routine Indirect
Inspection surveys performed during the past 5 to 6 years and from Indirect
Inspection surveys performed specifically for this PHMSA project where the
pipelines that were surveyed included cased pipe segments. Much of the survey
data for these cased pipe segments and adjacent buried pipe were available for
evaluation. More than 200 cased pipe segments have been identified for which
ECDA Indirect Inspection survey data were available.

1.7 Pre-Assessment
The Pre-Assessment step of the ECDA process involves the collection and
evaluation of information pertinent to external corrosion to determine if ECDA is
appropriate for a given segment of pipeline, to determine which Indirect Inspection
tools are to be used, and to determine how the results of Indirect Inspection will be
validated. NACE RP0502 recommends a rigorous Pre-Assessment for ECDA and
lists information that should be collected and evaluated to ascertain the applicability
of ECDA.
NACE RP0502 does not address Pre-Assessment of cased pipe, but much of the
information pertinent to ECDA of buried pipe is also pertinent to cased pipe. During
this PHMSA project, all available Pre-Assessment information was collected. This
information was not strictly used to determine the applicability of ECDA to cased
pipe because, for the most part, ECDA Indirect Inspection surveys had already been
performed on cased pipe and pipe adjacent to cased pipe. The applicability of Pre-
Assessment information for cased pipe was evaluated using the results of the
Indirect Inspection surveys and other inspections used to validate Indirect Inspection
survey data.

1.8 Indirect Inspection

Indirect Inspection was accomplished using AC Current Attenuation, DC Voltage
Gradient and Close Interval Potential surveys performed either as part of this project
or during routine ECDA performed on pipelines operated by three pipeline
companies participating in the project. These Indirect Inspection surveys were
performed in accordance with pipeline operator and standard survey procedures,
and following recommendations in NACE RP0502.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 11
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Improvements to the External Corrosion Direct Assessment (ECDA) Process

Indirect Inspection Data: Most of the Indirect Inspection survey data were collected
during surveys on long sections of buried pipelines that included segments of cased
pipe. For these surveys, those portions of the survey data for approximately 500
feet of buried pipe upstream and downstream of the cased pipe were evaluated. For
surveys being performed exclusively for this project, the minimum lengths of buried
pipe being surveyed upstream and downstream of the cased pipe was 300 feet.
Based on data evaluated, it appears that data collected within 300 feet of the ends of
cased pipe are sufficient to evaluate the validity of Indirect Inspection survey data for
cased pipe and to evaluate the impact the casing may have on the data for adjacent
buried pipe.
Other data collected routinely during ECDA Indirect Inspection surveys include
cathodic protection system operating data, interference bond data, foreign structure
pipe-to-soil potentials, casing-to-soil potentials, terrain and soils information, pipe
depth measurements, and weather conditions. These data were used when
pertinent to evaluations of coating condition and cathodic protection effectiveness.
Spatial alignment of data collected during the Indirect Inspection surveys was
accomplished in two manners; 1) correlation of data with survey flags placed at 100-
foot interval along the pipeline route, and 2) correlation of data with sub-meter GPS
positions taken at 100-foot survey flags and physical features along the pipeline
route. Examples of physical features include valves, pipeline markers, cathodic
protection test stations, foreign pipeline crossings, edges of roads, casing vent
pipes, fences and edges of bodies of water. Because the Indirect Inspection survey
data were typically collected within 500 feet of roads and casing vents, spatial
alignment of data were relatively simple and very accurate.
Indirect Inspection Data Evaluation: Indirect Inspection data for cased pipe and
adjacent buried pipe were evaluated in compliance with pipeline operator and
standard procedures, and following recommendations in NACE RP0502. Data were
evaluated to identify external coating damage and cathodic protection deficiencies.
Data collected during individual Indirect Inspection surveys were evaluated
independently of data collected during other Indirect Inspection surveys, and data
from all Indirect Inspection surveys were combined and evaluated in conjunction with
one another.
Severity Classifications for Indications: Severity classifications for individual
ECDA Indirect Inspection survey indications provide relative severity rankings for the
indications. Because Severity Classifications vary widely among the pipeline
operators, strict Severity Classifications have not been developed. General Severity
Classifications used for this project for the Indirect Inspection survey indications may
be found in Table 1.
 PHMSA Project 241 – ECDA of Cased Pipeline Segments 12
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Improvements to the External Corrosion Direct Assessment (ECDA) Process

Table 1: Example ECDA Severity Classifications for Indirect Inspection Indications on Cased Pipes

Severity Classifications
Survey
Tools
None Minor Moderate Severe

Uniform attenuation Small change in Moderate change in Large change in

AC
profile with no attenuation profile over attenuation profile over attenuation profile over
Current
significant change short length of pipe short length of pipe short length of pipe
Attenuation
inside or near casing inside or near casing inside or near casing inside or near casing

No indications on Few indications on Several indications on Numerous indications

DC or AC adjacent buried pipe adjacent buried pipe adjacent buried pipe on adjacent buried pipe
Voltage – and – – but – – but – – or –
Gradient No indications No indications No indications Any indications
on cased pipe on cased pipe on cased pipe on cased pipe

Uniform potential
Minor Moderate Large
profile with no
Close potential depression potential depression potential depression
significant depression
Interval – but – – but – – or –
– and –
Potential All potentials more All potentials more Any potentials less
All potentials more
negative than -850mV negative than -850mV negative than -850mV
negative than -850mV

Action Prioritizations for Indication: Action prioritizations for combined ECDA

Indirect Inspection survey indications provide relative remedial response rankings for
the combined indications. Because Action Prioritizations vary widely among the
pipeline operators, strict Action Prioritizations have not been developed. General
Action Prioritizations used for this project for the Indirect Inspection survey
indications may be found in Table 2.

Table 2: Example ECDA Prioritization Criteria for Direct Examination of Cased Pipe Segments

Cathodic Protection Severity Classifications

Prioritization Criteria for Cased Pipe Segments Based on Close Interval Potential Survey Results
Based on ECDA Survey Severity Classifications No Minor Moderate Severe
Indications Indications Indications Indications
Based on No Indications No Action Monitor Schedule Immediate
AC Current Minor Indications Monitor Monitor Schedule Immediate
Attenuation
Survey Moderate Indications Monitor Schedule Schedule Immediate
Coating
Results Severe Indications Schedule Schedule Immediate Immediate
Condition
Severity Based on No Indications No Action Monitor Schedule Immediate
Classifications DC or AC
Voltage Minor Indications Monitor Monitor Schedule Immediate
Gradient Moderate Indications Monitor Schedule Schedule Immediate
Survey
Results Severe Indications Schedule Schedule Immediate Immediate
PHMSA Project 241 – ECDA of Cased Pipeline Segments 13
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

1.9 Results for 30 Example Cased Pipe Indirect Inspections

As stated previously, ECDA Indirect Inspection survey data were obtained and
evaluated for more than 200 cased pipes. Because the volume of these data is
extremely large, these data are provided in supplementary volumes 1 through 3 that
accompany this report. Information is provided in this report for an example set of
30 of these cased pipes. The survey data were processed, integrated and plotted
for these 30 cased pipes. The data plots for 4 of these cased pipes may be found in
Figures 1 through 4. For all 4 of these cased pipes, the casings were electrically
isolated from the cased pipes, the casings were bare, the pipelines are near the Gulf
coast where the casing annuli are likely to contain some water and/or mud, and
Indirect inspection surveys were performed on the cased pipes except where the
cased pipes were directly under pavement. Summary results of evaluations of
Indirect Inspection survey data for these 4 cased pipes are as follows:
 PHMSA Project 241 – ECDA of Cased Pipeline Segments 14
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

• Figure 1 - The survey data for the cased pipe segment appear to be
consistent with survey data for adjacent buried pipe and there are no
significant indications or variations in the data that indicate coating anomalies
or cathodic protection deficiencies. While it has not been determined by other
means whether or not the survey data represent actual coating and cathodic
protection conditions for the cased pipe, it appears that this cased pipe is a
low priority for further integrity assessment.

Figure 1: ECDA Survey Data - Pipeline 11 - Casing 1

Pipe Potentials - On & Off Casing Potential - On Casing Potential - Off -850 mV Potential Criterion
ACCA 98 Hz dBmA ACCA 4 Hz dBmA DCVG Percent IR
-1500 150

-1400 Casing GWUT Pending 140

-1300 130

-1200 120

-1100 110
Pipe & Casing Potentials (DC mV)

ACCA dBmA and DCVG %IR

-1000 100

-900 90

-800 80

-700 70

-600 60

-500 50

-400 40

-300 30

-200 20

-100 10

0 0
138+00 139+00 140+00 141+00 142+00 143+00 144+00 145+00 146+00 147+00 148+00 149+00 150+00
Survey Station
 PHMSA Project 241 – ECDA of Cased Pipeline Segments 15
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

• Figure 2 - The survey data for the cased pipe segment appear to be
consistent with survey data for adjacent buried pipe. While the AC Current
Attenuation and DC Voltage Gradient survey data show slight, but no
significant indications or variations in the data that indicate coating anomalies
or cathodic protection deficiencies, the Close Interval Potential survey data
indicate a significant decrease in cathodic protection near the middle of the
casing. This cased pipe is a high priority for further integrity assessment.

Figure 2: ECDA Survey Data - Pipeline 11 - Casing 2

Pipe Potentials - On & Off Casing Potential - On Casing Potential - Off -850 mV Potential Criterion
ACCA 98 Hz dBmA ACCA 4 Hz dBmA DCVG Percent IR
-1500 150

-1400 Casing GWUT Pending 140

-1300 130

-1200 120

-1100 110
Pipe & Casing Potentials (DC mV)

ACCA dBmA and DCVG %IR

-1000 100

-900 90

-800 80

-700 70

-600 60

-500 50

-400 40

-300 30

-200 20

-100 10

0 0
146+00 147+00 148+00 149+00 150+00 151+00 152+00 153+00 154+00 155+00 156+00 157+00 158+00
Survey Station
 PHMSA Project 241 – ECDA of Cased Pipeline Segments 16
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

• Figure 3 - The survey data for the cased pipe segment appear to be
consistent with survey data for adjacent buried pipe. While the AC Current
Attenuation and DC Voltage Gradient survey data show no significant
indications or variations in the data that indicate coating anomalies or
cathodic protection deficiencies, the Close Interval Potential survey data
indicate a moderate decrease in cathodic protection near the middle of the
casing. This cased pipe is a moderate priority for further integrity
assessment.

Figure 3: ECDA Survey Data - Pipeline 15 - Casing 5

Pipe Potentials - On & Off Casing Potential - On Casing Potential - Off -850 mV Potential Criterion
ACCA 98 Hz dBmA ACCA 4 Hz dBmA DCVG Percent IR
-1500 150

-1400 GWUT Pending Casing 140

-1300 130

-1200 120

-1100 110
Pipe & Casing Potentials (DC mV)

ACCA dBmA and DCVG %IR

-1000 100

-900 90

-800 80

-700 70

-600 60

-500 50

-400 40

-300 30

-200 20

-100 10

0 0
425+00 426+00 427+00 428+00 429+00 430+00 431+00 432+00 433+00 434+00 435+00 436+00 437+00
Survey Station
 PHMSA Project 241 – ECDA of Cased Pipeline Segments 17
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

• Figure 4 - The survey data for the cased pipe segment appear to be
consistent with survey data for adjacent buried pipe. While the AC Current
Attenuation and DC Voltage Gradient survey data show no significant
indications or variations in the data that indicate coating anomalies or
cathodic protection deficiencies, the Close Interval Potential survey data
indicate a significant decrease in cathodic protection near the middle of the
casing. This cased pipe is a high priority for further integrity assessment.
(The Close Interval Potential and DC voltage Gradient survey data also
indicate coating anomalies and cathodic protection deficiencies on adjacent
buried pipe that warrant further investigation.)

Figure 4: ECDA Survey Data - Pipeline 18 - Casing 1

Pipe Potentials - On & Off Casing Potential - On Casing Potential - Off -850 mV Potential Criterion
ACCA 98 Hz dBmA ACCA 4 Hz dBmA DCVG Percent IR
-3400 340
Casing
-3200 Dent Found by 320
Inline Inspection
-3000 Inside Casing 300

-2800 280

-2600 260
Pipe & Casing Potentials (DC mV)

-2400 240

ACCA dBmA and DCVG %IR

-2200 220

-2000 200

-1800 180

-1600 160

-1400 140

-1200 120

-1000 100

-800 80

-600 60

-400 40

-200 20

0 0
3+00 4+00 5+00 6+00 7+00 8+00 9+00 10+00 11+00 12+00 13+00
Survey Station
 PHMSA Project 241 – ECDA of Cased Pipeline Segments 18
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

After processing, integrating and plotting the survey data for the 30 cased pipes,
the data were evaluated using the Severity Classification guidelines provided in
Table 1 and using the Action Prioritization guidelines provided in Table 2. A
listing of Severity Classifications and Action Prioritizations for the 30 cased pipes
may be found in Table 3.
Table 3: ECDA for 30 Cased Pipe Segments - Severity Classifications & Action Prioritizations Based on Results of Indirect Inspections
(Highlighted Data Corresponds to Indirect Inspection Survey Data Figures 1 through 4 in Body of Report)

Electrical AC Current Attenuation DC Voltage Gradient Close Interval Potential Other Integrity Assessments
Seq. Pipeline Casing Isolation Severity Severity Pipe Meets Severity Action Performed to Date
No. Number No. Status Data Results Classification Data Results Classification Data Results CP Criteria Classification Prioritization Method Results

Indications at
1 1 1 Shorted Moderate Change Moderate Severe Moderate Depression Yes Moderate Immediate GWUT No Indications
Both Casing Ends

Few Indications
2 2 1 Isolated Uniform Profile None Minor Uniform Profile Yes None Monitor GWUT No Indications
Near Casing

Indications at
3 3 1 Isolated Moderate Change Moderate Severe Uniform Profile Yes None Schedule GWUT No Indications
and Near Casing

Possibly Indications at
4 4 1 Moderate Change Moderate Severe Uniform Profile Yes None Immediate GWUT No Indications
Shorted and Near Casing

Few Indications
5 5 1 Isolated Moderate Change Moderate Minor Uniform Profile Yes None Monitor GWUT No Indications
Near Casing

Several Indications
6 6 1 Unknown Significant Change Severe Moderate Uniform Profile Yes None Immediate GWUT No Indications
Near Casing

Few Indications
7 7 1 Isolated Minor Change Minor Minor Uniform Profile Yes None Monitor GWUT No Indications
Near Casing

Possibly No Indications
8 7 2 Moderate Change Moderate None Uniform Profile Yes None Schedule GWUT No Indications
Shorted Near Casing

Few Indications
9 8 1 Isolated Minor Change Minor Minor Uniform Profile Yes None Monitor GWUT No Indications
Near Casing

Possibly Few Indications

10 8 2 Moderate Change Moderate Minor Uniform Profile Yes None Schedule GWUT No Indications
Shorted Near Casing

No Indications
11 9 1 Isolated Minor Change Minor None Uniform Profile Yes None Monitor GWUT No Indications
Near Casing

No Indications
12 9 2 Isolated Minor Change Minor None Uniform Profile Yes None Monitor GWUT No Indications
Near Casing

Many Indications
13 10 1 Isolated Uniform Profile None Severe Minor Depressions Yes Minor Schedule None GWUT Pending?
Near Casing

Few Indications
14 11 1 Isolated Moderate Change Moderate Minor Uniform Profile Yes None Schedule None GWUT Pending?
Near Casing

Indications at Significant Depression

15 11 2 Isolated Minor Change Minor Severe No Severe Immediate None GWUT Pending?
and Near Casing and Low Off Potentials

Indications at
16 12 1 Isolated Moderate Change Moderate Severe Significant Depression No Severe Immediate None GWUT Pending?
and Near Casing

No Indications
17 13 1 Isolated Minor Change Minor None Minor Depressions Yes Minor Monitor None GWUT Pending?
Near Casing

No Indications
18 13 2 Isolated Minor Change Minor None Uniform Profile Yes None Monitor None GWUT Pending?
Near Casing

No Indications
19 13 3 Isolated Uniform Profile None None Uniform Profile Yes None No Action None GWUT Pending?
Near Casing

Indications at
20 14 1 Isolated Moderate Change Moderate Severe Uniform Profile Yes None Schedule None GWUT Pending?
and Near Casing

Indications at
21 14 2 Isolated Minor Change Minor Severe Uniform Profile Yes None Schedule None GWUT Pending?
Both Casing Ends

No Indications Significant Depression

22 15 1 Isolated Uniform Profile None None No Severe Immediate None GWUT Pending?
Near Casing and Low Off Potentials

No Indications
23 15 2 Unknown Minor Change Minor None Uniform Profile Yes None Monitor None Excavation Pending?
Near Casing

No Indications
24 15 3 Isolated Uniform Profile None None Marginal Off Potentials No Moderate Schedule None GWUT Pending?
Near Casing

Indications at
25 15 4 Isolated Minor Change Minor Severe Marginal Off Potentials No Moderate Immediate None GWUT Pending?
and Near Casing

Indications at
26 15 5 Isolated Uniform Profile None Severe Minor Depressions No Minor Schedule None GWUT Pending?
and Near Casing

Possibly Indications at
27 16 1 Uniform Profile None Severe Minor Depressions Yes Minor Immediate None Other Pending?
Shorted and Near Casing

Few Indications
28 17 1 Unknown Uniform Profile None Minor Uniform Profile Yes None Schedule None Other Pending?
Near Casing

Several Indications
29 18 1 Unknown Uniform Profile None Moderate Significant Depressions Yes Severe Immediate ILI Dent Inside Casing
Near Casing

Indications at
30 19 1 Isolated Minor Change Minor Severe Minor Depressions Yes Minor Schedule None Other Pending?
and Near Casing
PHMSA Project 241 – ECDA of Cased Pipeline Segments 19
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

Tables 4 and 5 provide summaries of the numbers of Severity Classifications for the
ECDA Indirect Inspection indications and the numbers of Action Prioritizations for
the 30 cased pipes. It is given that these Severity Classifications and Action
Prioritizations can not be strictly applied to cased pipe as they would be for ECDA of
buried pipe, these Severity Classifications and Action Prioritizations are useful for
ranking or prioritizing cased pipes for further integrity assessment and/or remedial
action.

Table 4: Numbers of Indications by Severity Classification for 30 Cased Pipes

Severity AC Current DC Voltage Close Interval
Classification Attenuation Gradient Potential
Severe 1 12 4
Moderate 9 2 3
Minor 11 7 5
None 9 9 18
Totals 30 30 30

Table 5: Numbers of Action Prioritizations for 30 Cased Pipes

Immediate Schedule Monitor No Action Total
9 11 9 1 30

1.10 Possible Improvements to Technologies

Possible improvements to technologies that have been identified thus far for Cased
Pipe ECDA methodology over the technologies addressed by buried pipe ECDA
methodology are as follows:
• More specific data requirements, data integration and data evaluation to
improve identification of corrosion threats to cased pipe

• Modifications to existing Indirect Inspection survey techniques or

development of new Indirect Inspection survey techniques that address
requirements and peculiarities of cased pipe

• More specific definition of Severity Classification categories to improve

assignment of severity ratings to Indirect Inspection indications
PHMSA Project 241 – ECDA of Cased Pipeline Segments 20
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

• More specific definition of Action Prioritization categories to improve selection

of types and timing of remedial action responses required for cased pipe
corrosion threats

1.11 PHMSA Committees

In late 2008, PHMSA formed a joint PHMSA/Industry advisory committee with
Corrpro as a member. The committee is charged with developing guidelines
for pipeline operators and regulators on cased pipe assessments. The goals
are:
• to provide guidance that will be used during regulatory inspection
activities
• to address all present and developing cased pipes assessment
methods (including ECDA)
In January 2009, PHMSA formed a Casing Quality Action Committee
(CASQAT) committee to develop guidelines for use by regulatory auditors
and pipeline operators for cased pipe assessments. The CASQAT committee
work independently of the Joint PHMSA/Industry Advisory committee. It is
comprised of about 20 people - 9 from regulatory agencies, 5 from pipeline
operators, 4 from industry organizations and 2 from service companies.
Some of its members are also on the Joint PHMSA/Industry Advisory
committee.

1.12 Enhanced ECDA Methodology for Cased Pipes

The draft guidelines for the External Corrosion Direct Assessment (ECDA) of
Cased Pipeline Segment are provided in the appendix to this report.

1.13 Prospective Future Research Project

Our current activities so far have indicated the need for in-depth research
projects in the following specific areas related to cased pipes:
• Development of quantitative models for predicting the condition of
cased pipe in casings that are not filled,
• Condition assessment of cased pipe in wax-filled casings, and
• Filling pipeline casings with polymerized structural materials to improve
or ensure structural integrity of cased pipes.

1.14 Conclusion
Based on the results of evaluations of ECDA Indirect Inspection surveys performed
on cased pipe segments and adjacent buried pipe, the following conclusions have
been drawn.
• Standard Indirect Inspection surveys on cased pipe may produce definitive
data for evaluating the condition of the coating and the effectiveness of
PHMSA Project 241 – ECDA of Cased Pipeline Segments 21
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

cathodic protection, and for predicting the likelihood of corrosion, but only
under specific conditions. As a minimum, specific conditions include electrical
isolation of the pipe from the casing, a conductive electrolyte in the casing
annulus, and a bare casing.

• Standard Indirect Inspection surveys on cased pipe will not produce

definitive data for evaluating the condition of the coating and the effectiveness
of cathodic protection, or for predicting the likelihood of corrosion, where:

a. the pipe is electrically shorted to the casing,

b. there is not a conductive electrolyte in the casing annulus, or
c. where the casing is coated.

• The results of standard Indirect Inspection surveys on cased pipe are useful
for ranking and prioritizing cased pipes for further integrity assessment and/or
remedial action.

• Additional research and testing is required to develop methods for

ascertaining the validity of standard Indirect Inspection survey data collected
on cased pipe.

1.15 References
1. External Corrosion Direct Assessment, NACE SP0502-2008, NACE
International (Houston, Texas: NACE 2008)

2. Steel-Cased Pipeline Practices, NACE SP0200-2008, NACE International

(Houston, Texas: NACE 2008).

3. External Corrosion Probability Assessment for Carrier Pipes Inside Casings

(Casing Corrosion Direct Assessment--CCDA), GRI-05/0020, Gas
Technology Institute.

4. L. Rankin, J. Carroll, D. Kroon, D. Lindemuth, M. Miller, O. Olabisi, PHMSA-

Sponsored Research: Improvements to ECDA Process – Cased Pipes,
CORROSION/2010, San Antonio TX, NACE International, 2010

5. J. Carroll, D. Kroon, D. Lindemuth, M. Miller, O. Olabisi, L. Rankin, PHMSA-

Sponsored Research: Improvements to ECDA Process – Potential
Measurements in Paved Areas, CORROSION/2010, San Antonio TX,
NACE International, 2010

6. J. Carroll, D. Kroon, D. Lindemuth, M. Miller, O. Olabisi, L. Rankin, PHMSA-

Sponsored Research: Improvements to ECDA Process – Severity Ranking,
CORROSION/2010, San Antonio TX, NACE International 2010.
PHMSA Project 241 – ECDA of Cased Pipeline Segments 22
PHMSA Contract No. DTPH56-08-T-000012
Improvements to the External Corrosion Direct Assessment (ECDA) Process

7. PHMSA – Pipeline Corrosion Final Report – Michael Baker Jr., Inc. – July
2008

8. PHMSA - Applying External Corrosion Direct Assessment (ECDA)In

Difficult-to-Inspect Areas DTRS56-05-T-0003 - E. B. Clark, B. N. Leis, and
S. A. Flamberg – March 2007

9. PHMSA - Demonstration of ECDA Applicability and Reliability for

Demanding Situations DTPH56-06-T-000001 - Daniel Ersoy – August 2008

10. PHMSA - Improvement of External Corrosion Direct Assessment

Methodology by Incorporating Soils Data DTRS56-03-T-0003 - B. N. Leis,
E. B. Clark, M. Lamontagne, and J. A. Colwell - November 2005
 Appendix

Draft Recommended Guidelines for

External Corrosion Direct Assessment (ECDA)
Of Cased Pipeline Segments
 An Insituform® Company

Draft Recommended Guidelines

for

External Corrosion Direct Assessment (ECDA)

of Cased Pipeline Segments

to

Pipeline and Hazardous Materials

Safety Administration (PHMSA)

U.S. Department of Transportation

Contract No. DTPH56-08-T-000012

Improvements to the External Corrosion Direct Assessment (ECDA) Process

(WP # 360)
Cased Pipes
Project No. 241

by

CORRPRO COMPANIES, INC.

7000 B Hollister
Houston, Texas 77040

June 2010
__________________________________________________________________________

Foreword

These recommended guidelines closely follow the format used by NACE

International in its standard practice SP0502-2008, Pipeline External Corrosion
Direct Assessment Methodology. The guidelines are written in this manner
because NACE SP0502-2008 is widely recognized, accepted, and used by the
pipeline community for assessing external corrosion on buried ferrous pipelines.
Additionally, it is expected that PHMSA will provide these guidelines to NACE for
consideration and perhaps use during development of a standard practice. If this
happens, having these guidelines in a format that follows the NACE standard
practice should reduce the time and effort required to develop a standard
practice for cased pipes.

The guidelines provided in Appendices B, C and D of these recommended

guidelines are the work product of the PHMSA Casing Quality Action Team
(CASQAT) committee. This committee was comprised of PHMSA employees,
pipeline operator personnel and pipeline service company representatives.

__________________________________________________________________________
 Improvements to the External Corrosion Direct Assessment (ECDA) Process
Recommended Guidelines for Cased Pipes

Table of Contents
Page

1.0 General.................................................................................................................... 1
1.1 Introduction...................................................................................................... 1
1.2 The ECDA Process ......................................................................................... 2
1.3 Additional Considerations for the ECDA Process ............................................ 2

2.0 Pre-Assessment ...................................................................................................... 3

2.1 Introduction...................................................................................................... 3
2.2 Pre-Assessment Data...................................................................................... 4
2.3 Data Integration ............................................................................................... 5
2.4 Data Evaluation ............................................................................................... 5
2.5 ECDA Feasibility Determination ...................................................................... 5
2.6 ECDA Regions Identification ........................................................................... 6
2.7 Indirect Inspection Tools Selection .................................................................. 7

3.0 Indirect Inspection ................................................................................................... 8

3.1 Introduction...................................................................................................... 8
3.2 Indirect Inspections.......................................................................................... 9
3.3 Data Evaluation and Severity Classification .................................................. 10
3.4 Data Alignment and Comparison................................................................... 11

4.0 Direct Examination ................................................................................................ 13

4.1 Introduction.................................................................................................... 13
4.2 Prioritization of Indications............................................................................. 14
4.3 Direct Examination Methods.......................................................................... 16
4.4 Number of Direct Examinations ..................................................................... 17
4.5 Direct Examination Data................................................................................ 18
4.6 Other Data, Observations and Considerations .............................................. 19
4.7 Remaining Strength Evaluation at Corrosion Damage .................................. 20
4.8 Root Cause Analysis ..................................................................................... 20
4.9 External Corrosion Mitigation ........................................................................ 21
4.10 Reclassification and Reprioritization of Indications........................................ 21
4.11 In-Process Evaluation.................................................................................... 22

5.0 Post Assessment................................................................................................... 23

5.1 Introduction.................................................................................................... 23
5.2 Remaining Life Calculations .......................................................................... 24
5.3 Reassessment Interval Determination........................................................... 26
5.4 Assessment of ECDA Effectiveness.............................................................. 26
5.5 Feedback and Continuous Improvement....................................................... 27
6.0 Documentation ...................................................................................................... 28
6.1 Introduction.................................................................................................... 28
6.2 Pre-Assessment ............................................................................................ 28
6.3 Indirect Inspection ......................................................................................... 28
6.4 Direct Examination ........................................................................................ 29
6.5 Post Assessment........................................................................................... 29

References ...................................................................................................................... 30

Tables
Table 1 – Example ECDA Severity Classifications for Indirect Inspection Indications ..... 11
Table 2 – Example ECDA Prioritization Criteria for Direct Examination ........................... 14

Appendices

A List of Example Pre-Assessment Data

B Guidelines for Establishing ECDA Regions for Cased Pipe
C Guidelines for Selecting Indirect Inspection Tools for Cased Pipe
D Indirect Inspection Survey Techniques for Cased Pipe
__________________________________________________________________________

Section 1: General
1.1 Introduction

1.1.1 These guidelines address the External Corrosion Direct Assessment

(ECDA) process for onshore segments of buried, externally coated, ferrous
pipelines that pass through buried ferrous casings. These guidelines are
intended to provide guidance for applying the ECDA process on typical pipeline
systems, and in typical cased pipe situations. These guidelines assume that
external corrosion is a pipeline integrity threat that is to be evaluated. They are
not intended for use on pipelines that were not provided with an external
coating at the time of construction.

1.1.2 ECDA was developed as a process for improving pipeline safety by

providing a method for evaluating external corrosion activity on buried ferrous
pipelines that cannot realistically be evaluated by other means such as in-line
inspection and pressure testing.

1.1.3 Unlike many assessment methods that only identify where external
corrosion has already occurred, ECDA provides the benefit of identifying
locations where external corrosion may have already occurred, may be
occurring, and may occur in the future.

1.1.4 ECDA applications can include but are not limited to the following
situations or activities:

1.1.4.1 Cased pipes that cannot realistically be assessed by other

means.

1.1.4.2 For establishing priorities for assessments by other means.

1.1.4.3 Where the desire is to identify conditions conducive to future

external corrosion so that proactive measures can be taken to prevent
future external corrosion.

1.1.4.4 When there would be benefits from establishing baselines from

which future external corrosion assessments could be evaluated.

1.1.4.5 When there is the need to establish reassessment intervals

that cannot be established by other means.

1.1.5 ECDA may assist with the detection of other pipeline integrity threats
under specific conditions. Other threats may include mechanical damage,
stress corrosion cracking (SCC), microbiologically influenced corrosion (MIC),

-1-
 and electrical interference from outside sources. ECDA is not intended to
facilitate evaluation of threats other than external corrosion, so when conditions
indicative of other threats are detected, assessments and/or inspections
appropriate for the other threats are to be performed.

1.1.6 These guidelines were written to provide flexibility for tailoring the ECDA
process to specific pipeline and cased pipe situations.

1.2 The ECDA Process

1.2.1 ECDA is a four step process. The steps are as follows:

1.2.1.1 Pre-Assessment: During this step, pertinent information is

collected, integrated and evaluated, ECDA feasibility is determined,
ECDA regions are identified, and Indirect Inspection tools are selected.
Details of these activities can be found in Section 2 of these guidelines.

1.2.1.2 Indirect Inspection: During this step, the Indirect Inspection

tools are employed to detect external coating defects and cathodic
protection deficiencies, the coating defect and cathodic protection
deficiency indications are evaluated and classified with respect to
severity, and the classified indications are prioritized to determine the
need and establish the priority for evaluation or inspection. Details of
these activities can be found in Section 3 of these guidelines.

1.2.1.3 Direct Examination: During this step, the indications that were
identified as needing to be evaluated or inspected are evaluated or
inspected, repair and/or remedial measures are taken where required,
and the need to evaluate or inspect additional indications is determined.
Details of these activities can be found in Section 4 of these guidelines.

1.2.1.4 Post Assessment: During this step, information obtained

during the first three steps is evaluated to determine the effectiveness of
the ECDA process, to determine reassessment intervals, and to
generate information to be used for planning and performing remedial
activities. Details of these activities can be found in Section 5 of these
guidelines.

1.3 Additional Considerations for the ECDA Process

1.3.1 ECDA is a continuous improvement process. Through successive

applications, ECDA should identify locations where corrosion activity has
occurred, is occurring, or may occur. Comparing the results of successive
ECDA applications will facilitate the evaluation of ECDA effectiveness and
demonstrate that pipeline integrity is continuously improving.

-2-
 1.3.2 For correct application of these guidelines, the guidelines should be
considered in their entirety and applicable guidelines used where appropriate.
Using only part of the guidelines without considering the guidelines in their
entirety can lead to misinterpretation or misapplication of the guidelines.

1.3.3 Because of the variety and complexity of cased pipes, these guidelines
may not accommodate every situation or condition related to external corrosion
that could exist. ECDA has limitations and not all cased pipes can be
successfully assessed using ECDA. Just as with all other assessment
methods, precautions should be taken when applying these ECDA guidelines.

1.3.4 When ECDA is used for the first time on cased pipes, more stringent
application of the guidelines should be employed to ensure that ECDA is
appropriate for the situations or conditions. This is particularly true when
material, construction, environment, operation, maintenance and corrosion
control information required for effective application of ECDA may be lacking.
More stringent application may include but is not limited to additional data
collection, Indirect Inspection surveys, Direct Examination inspections, and Post
Assessment evaluation.

1.3.5 These guidelines should be applied under the direction of competent

persons who, by reason of knowledge of the physical sciences and the
principles of engineering and mathematics, acquired by education and related
practical experience, are qualified to engage in the practice of corrosion control
and risk assessment of buried ferrous piping systems. Such persons may be
registered professional engineers or persons recognized by appropriate
industry organizations as specialists, engineers or technicians with suitable
levels of education and experience.

__________________________________________________________________________

Section 2: Pre-Assessment
2.1 Introduction

2.1.1 The objectives of the Pre-Assessment step are to collect data pertinent
to the ECDA process, to determine if ECDA is feasible for the cased pipes that
are to be assessed, to identify ECDA regions, and to select Indirect Inspection
tools. The Pre-Assessment step must be comprehensive and thorough.

2.1.2 The Pre-Assessment step is to include the following activities:

2.1.2.1 Data collection;

2.1.2.2 Data integration;

-3-
 2.1.2.3 Data evaluation;

2.1.2.4 ECDA feasibility determination;

2.1.2.5 ECDA regions identification; and

2.1.2.6 Indirect Inspection tools selection.

2.2 Pre-Assessment Data

2.2.1 A sufficient amount of data needed to determine ECDA feasibility, to

identify ECDA regions, and to select Indirect Inspection tools is to be collected.
Collected data are to include historical and contemporary data for the cased
pipes and for adjacent buried pipe where pertinent. Categories of data to be
collected are as follows:

2.2.1.1 Line pipe, casing pipe and associated materials;

2.2.1.2 Construction;

2.2.1.3 Environment;

2.2.1.4 Operation;

2.2.1.5 Maintenance; and

2.2.1.6 Corrosion control.

2.2.2 A list of example Pre-Assessment data can be found in Appendix A. The

list provides guidance for data to be collected. Not all data may be required for
all cased pipes, and other data not on the list may be required for some cased
pipes. Minimum data requirements are to be established by evaluating
individual data to determine its relevance to the occurrence of external
corrosion. Those data that are essential to the success of the ECDA process
are to be identified and extra effort made to collect the data. As a minimum, the
following data are to be considered essential:

2.2.2.1 Construction information for cased pipe and casing;

2.2.2.2 Coating type and condition information for cased pipe and
adjacent buried pipe;

2.2.2.3 Data related to the historical status of electrical isolation

between the cased pipe and casing;

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 2.2.2.4 Historical pipeline operating temperatures, particularly if in
excess of 120º F;

2.2.2.5 Operating stress level, particularly if above 60% SMYS;

2.2.2.6 Data relevant to ECDA region identification;

2.2.2.7 Data relevant to Indirect Inspection tool selection; and

2.2.2.8 For cased pipes where the casing annulus has been filled with
high dielectric material, information for the type of fill material,
date of fill, and fill condition monitoring.

2.3 Data Integration

The collected data are to be integrated in a manner that facilitates accurate and
thorough evaluation. Data integration may be accomplished by any suitable
means appropriate for the specific data to be integrated, including but not
limited to lists, tables, spreadsheets and electronic data bases. The means
selected for integrating the data are to provide for easy recognition of data
types, a clear understanding of the data, and logical evaluation of the impact
the data has on the ECDA process.

2.4 Data Evaluation

The integrated data are to be evaluated to determine if sufficient data are

available to determine ECDA feasibility, identify ECDA regions and select
Indirect Inspection tools. In the event it is determined that sufficient data cannot
be collected for some cased pipes or ECDA regions, ECDA is not to be used for
those cased pipes or ECDA regions.

2.5 ECDA Feasibility Determination

2.5.1 The ECDA feasibility determination is to consider all conditions that may
prevent the effective application of ECDA on cased pipes. The following
conditions may prevent the effective application of ECDA on cased pipes:

2.5.1.1 Casings electrically shorted to the cased pipe by direct metallic

contacts;

2.5.1.2 Casings that cannot be contacted for electrical measurements;

2.5.1.3 Casings coated externally or internally with effective high

dielectric coatings;

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 2.5.1.4 Coatings on cased pipes or on buried pipe adjacent to cased
pipes that cause electrical shielding;

2.5.1.5 Backfill on casings or on buried pipe adjacent to casings with

rock content or rock ledges that would interfere with collection
of reliable Indirect Inspection data;

2.5.1.6 Certain ground surfaces or surface conditions that prevent

surface electrical measurements (such as pavement and
frozen ground) unless actions can be implemented to eliminate
or minimize the effects of these surface conditions (such as
drilling holes through pavement or waiting until the ground is
not frozen);

2.5.1.7 Situations that prevent the collection of above ground

measurements within a reasonable time frame;

2.5.1.8 Locations with adjacent buried metallic structures that prevent

the collection of valid above ground measurements;

2.5.1.9 Areas that are not accessible for performing above ground
measurements; and

2.5.1.10 Any other conditions on casings, cased pipes or adjacent

buried pipe that prevent the successful use of ECDA Indirect
Inspection tools.

2.5.2 If it is determined that ECDA is not feasible for an individual cased pipe
or for cased pipes in an ECDA region, other acceptable methods of assessing
integrity are to be used.

2.6 ECDA Regions Identification

2.6.1 An ECDA region for cased pipes is those cased pipes that have similar
material and construction characteristics, environmental conditions, operation
and maintenance histories, corrosion and corrosion control histories, expected
future corrosion conditions, and that can be assessed using the same Indirect
Inspection tools.

2.6.2 A single ECDA region can include numerous cased pipes, does not need
to be contiguous along a single pipeline or pipeline section, and can include
cased pipes on more than one pipeline providing that the region criteria are met
and that all of the cased pipes can be assessed using the same Indirect
Inspection tools.

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 2.6.3 All cased pipes are to be included in an ECDA region, even when
situations and conditions for one cased pipe require it to be in a region of its
own.

2.6.4 Criteria for region identification are to be identified and defined. Criteria
are to take into account all conditions that could significantly affect external
corrosion. Example Pre-Assessment data in the list in Appendix A may be used
as guidance for identifying the criteria. The data collected during Pre-
Assessment are to be analyzed to define the criteria.

2.6.5 The identification of ECDA regions may need to be modified during the
application of the ECDA process based on the results of Indirect Inspection and
Direct Examination.

2.6.6 Additional guidelines for establishing ECDA regions for cased pipes can
be found in Appendix B.

2.7 Indirect Inspection Tools Selection

2.7.1 A minimum of two Indirect Inspection tools are to be selected and used
for all cased pipes where ECDA is being applied. Consideration should be
given for using more than two tools for the first application of ECDA on cased
pipes, for cased pipes where Pre-Assessment data are limited, or for cased
pipe situations or conditions that are not typical.

2.7.2 The Indirect Inspection tools are to be selected based on their ability to
reliably detect external coating defects, cathodic protection deficiencies, and
other conditions indicative of external corrosion under the specific cased pipe
conditions to be encountered.

2.7.3 The Indirect Inspection tools that are selected should be complementary
such that strengths of one tool compensate for limitations of the other tools.

2.7.4 If more than one ECDA region is identified for cased pipes along a
pipeline segment, the same Indirect Inspection tools do not have to be used for
all cased pipes along the pipeline segment. Using different tools for some of
the cased pipes along a pipeline segment may provide the benefit of obtaining
other valuable information than can be applied to other cased pipes along the
pipeline segment. If other tools are used, the tools are to be selected based on
their ability to reliably detect external coating defects, cathodic protection
deficiencies, and other conditions indicative of external corrosion under the
specific cased pipe conditions to be encountered.

2.7.5 Guidelines for selecting Indirect Inspection tools can be found in

Appendix C. The guidelines indicate situations and conditions under which
individual tools are likely to be reliable and situations and conditions under

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 which individual tools are not likely to be reliable. Additional guidelines and
other information for Indirect Inspection tools can be found in Appendix D.

2.7.6 The Indirect Inspection tools discussed in the guidelines in Appendix C

are not the only tools available for Indirect Inspection. Other technologies
presently exist and new technologies are being developed that will detect
external corrosion and/or conditions relevant to the occurrence of external
corrosion. Use of these other technologies may be considered for situations
and conditions where the tools discussed in Appendix C are not appropriate or
where these other technologies can provide cased pipe condition information
that is superior to the information that can be obtained from using the tools in
the table.

2.7.7 In the event it is determined that none of the available Indirect Inspection
tools are capable of reliably detecting coating defects, cathodic protection
deficiencies or other conditions indicative of external corrosion, other means
may be employed to determine the condition of the cased pipe. Other means
include in-line inspection, pressure testing and other technologies that provide
an equivalent understanding of the condition of the cased pipe. These other
means do not necessarily have to be used on all casings in an ECDA region,
and can be used on a sampling of cased pipes. When only a sampling of cased
pipes are evaluated by other means, the number of cased pipes evaluated
must be adequate to ensure that the evaluations are representative of the
remaining cased pipes that are not evaluated. In this situation, actions in the
Pre-Assessment and Post Assessment steps are still required to effect a full
and acceptable application of the ECDA process.

__________________________________________________________________________

Section 3: Indirect Inspection

3.1 Introduction

3.1.1 The objectives of the Indirect Inspection step are to detect areas on
cased pipes where external corrosion may have occurred, may be occurring, or
may occur in the future, and to classify the detected areas with respect to
severity.

3.1.2 The Indirect Inspection tools selected in the Pre-Assessment step are to
be used to collect external corrosion related data on cased pipes. The Indirect
Inspections are to be performed in all ECDA regions identified in the Pre-
Assessment step.

3.1.3 A minimum of two Indirect Inspection tools are to be used during Indirect
Inspection. Use of more than two tools should be considered for the first
application of ECDA on cased pipes, and may be necessary for cased pipes

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 where Pre-Assessment data are limited, or for cased pipe situations or
conditions that are not typical.

3.2 Indirect Inspections

3.2.1 The Indirect Inspections are to be performed and analyzed in

accordance with generally accepted industry practices. Typical procedures for
some of the Indirect Inspection tools discussed in Appendix C of these
guidelines can be found in NACE SP0502-2008 in Appendix A.

3.2.2 Indirect Inspections are to be performed on all cased pipes in ECDA

regions where cased pipes are to be assessed by ECDA. For those cased
pipes where Indirect Inspections cannot be performed, other assessment
methods are to be used.

3.2.3 The cased pipe and adjacent buried pipe on which the Indirect
Inspections are to be performed are to be identified, located with pipe location
equipment, and clearly marked prior to performing the Indirect Inspections. The
boundaries of the cased pipe and adjacent buried pipe on which the Indirect
Inspections are to be performed are also to be identified and clearly marked.

3.2.4 Ideally, the Indirect Inspections should be performed on the full lengths
of the cased pipes and sufficient lengths of adjacent buried pipe as is required
to facilitate a thorough evaluation of coating defects, cathodic protection
deficiencies, and other conditions related to external corrosion on the cased
pipe. Realistically, this is not always possible because of conditions and
restrictions created by land surface use at the cased pipes. When conditions
and restrictions exist that prevent Indirect Inspection on the full lengths of the
cased pipes, every effort is to be made to perform Indirect Inspection on as
much of the cased pipes as is practicable and/or allowable.

3.2.5 All of the Indirect Inspections performed in an ECDA region are to be

performed in a reasonable period of time so that conditions that could affect the
results of the Indirect Inspections do not change significantly. Significant
changes of conditions can cause the data to be difficult to evaluate and, in
extreme situations, render the data invalid. Conditions that could affect the
results include changes in soil moisture content and temperature, changes in
operations of cathodic protections systems, changes in piping configuration,
and changes of the ground surface over and near the pipelines.

3.2.6 Distances or intervals between Indirect Inspection measurements are to

appropriate for the individual Indirect Inspection tools and sufficiently short to
facilitate a detailed assessment. The distances or intervals are to be such that
the Indirect Inspection tools can detect and locate coating defects, cathodic
protection deficiencies and other conditions indicative of external corrosion.

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 3.2.7 Indirect Inspection measurements are to be collected in a manner that
facilitates spatial reference to at-grade and above-grade features located along
the cased pipes and adjacent buried pipe. Distances or intervals between
these features are to be sufficiently short to allow accurate alignment of data
from the Indirect Inspections and to allow future identification of locations of
Indirect Inspection indications within distances that are satisfactory for Direct
Examination requirements. Where features are not sufficiently close, flags may
be placed or marks may be painted to establish sufficient spatial references.
Incorporating global positioning system (GPS) location measurements with the
individual Indirect Inspections has proven to be invaluable for establishing
locations of Indirect Inspection indications, for aligning data from several
Indirect Inspections, and for resolving spatial errors.

3.2.8 When ECDA is applied for the first time, actions are to be taken to verify
accuracy and consistency of the Indirect Inspection measurements. These
actions may include repeating portions of the measurements, spot checking
measurements with other instruments, and any other means that verifies
accuracy and consistency of the measurements.

3.3 Data Evaluation and Severity Classification

3.3.1 After completing the Indirect Inspections, the data from the individual
Indirect Inspections are to be evaluated to identify indications specific to the
individual Indirect Inspections. Criteria for identifying indications are to be
defined.

3.3.2 After identifying indications for the individual Indirect Inspections, the
indications are to be classified according to severity. Classifying indications
according to severity is the process of defining the likelihood of corrosion
activity at each indication under typical year-round conditions. The following
are examples of classifications typically used in ECDA:

3.3.2.1 Severe: Indications that are considered to have the highest

likelihood of corrosion activity.

3.3.2.2 Moderate: Indications that are considered to have a likelihood

of corrosion activity that falls between “severe” and “minor”.

3.3.2.3 Minor: Indications that are considered to have the lowest

likelihood of corrosion activity or to be corrosion that is not active.

3.3.3 Criteria for classifying indication severity are to be defined. Defining the
criteria is to take into account the capabilities of the individual Indirect
Inspection tools, the unique conditions within an ECDA region, and the
experience level of persons evaluating the Indirect Inspection data.

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 3.3.4 For initial ECDA applications, severity classification is to be made more
stringent. For example, when uncertainty exists about the specific classification
that should be applied, the next higher classification is to be applied.

3.3.5 Table 1 provides example severity classifications for several Indirect

Inspection tools. These example severity classifications are general in nature
and are not absolute criteria.

Table 1: Example ECDA Severity Classifications for Indirect Inspection Indications on Cased Pipes

Severity Classifications
Survey
Tools
None Minor Moderate Severe

Uniform attenuation Small change in Moderate change in Large change in

AC
profile with no attenuation profile over attenuation profile over attenuation profile over
Current
significant change short length of pipe short length of pipe short length of pipe
Attenuation
inside or near casing inside or near casing inside or near casing inside or near casing

No indications on Few indications on Several indications on Numerous indications

DC or AC adjacent buried pipe adjacent buried pipe adjacent buried pipe on adjacent buried pipe
Voltage – and – – but – – but – – or –
Gradient No indications No indications No indications Any indications
on cased pipe on cased pipe on cased pipe on cased pipe

Uniform potential
Minor Moderate Large
profile with no
Close potential depression potential depression potential depression
significant depression
Interval – but – – but – – or –
– and –
Potential All potentials more All potentials more Any potentials less
All potentials more
negative than -850mV negative than -850mV negative than -850mV
negative than -850mV

3.4 Data Alignment and Comparison

3.4.1 After completing evaluation of individual Indirect Inspection data and

classifying severity of individual Indirect Inspection indications, the data and
indications from each of the individual Indirect Inspections are to be aligned with
one another and compared.

3.4.2 Spatial alignment of Indirect Inspection data and indications is to be

accomplished using locations of at-grade and above-grade features identified
during the Indirect Inspections and/or flags that were placed or marks that were
painted during the Indirect Inspections. If GPS location measurements were
taken during the Indirect Inspections, this information can be used to
accomplish or improve spatial alignment of data and indications.

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3.4.3 Aligned Indirect Inspection data and indications are to be compared to
determine if indications from one Indirect Inspection align with indications from
other Indirect Inspections. Particular attention to possible spatial alignment
errors is to be given to indications from multiple Indirect Inspections that are
close to one another but that do not align to determine if these indications do in
fact exist at the same location.

3.4.4 Indications from multiple Indirect Inspections that align with one another
are indicative of external corrosion conditions that are likely to be more severe
than external corrosion conditions that are indicated by only one Indirect
Inspection tool. The probable increase in severity is defined and evaluated in
the Direct Examination step.

3.4.5 After the Indirect Inspection data and indications are aligned and
compared, the aligned data and indications are to be evaluated to determine if
the results from the individual Indirect Inspections are consistent with one
another.

3.4.6 If the results from the individual Indirect Inspections are not consistent
with one another or if two or more Indirect Inspections indicate significantly
different sets of locations for Indirect Inspection indications, and the differences
cannot be explained by the inherent capabilities of the Indirect Inspection tools
or by spatial alignment errors caused by specific localized pipeline features or
conditions, additional action is to be taken in an effort to correct the
inconsistency.

3.4.6.1 Additional action generally is to involve repeating one or more

of the Indirect Inspections or performing additional Indirect Inspections.
Data from these Indirect Inspections are to be evaluated, classified,
aligned and compared as described in this section.

3.4.6.2 If the results from these Indirect Inspections are also

inconsistent, or if these Indirect Inspections are not performed for any
reason, the validity of ECDA for the involved cased pipe is to be
reassessed. If it is determine that ECDA is not valid for an individual
cased pipe or for cased pipes in an ECDA region, another integrity
assessment method is to be used to assess the integrity of the individual
cased pipe or cased pipes in the ECDA region.

3.4.7 After evaluation, classification, alignment and comparison of Indirect

Inspection data and indications have been completed, and after any
inconsistencies have be resolved, the results of Indirect Inspection is to be
compared with the results of the Pre-Assessment and prior corrosion history for
each ECDA region to determine if all results are consistent. If all results are not
consistent, ECDA feasibility and/or ECDA region definitions are to be
reassessed.

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 3.4.7.1 If reassessment of ECDA feasibility indicates that ECDA is not
feasible, another integrity assessment method is to be used to assess
the integrity of the cased pipes in the ECDA region.

3.4.7.2 If the ECDA region cannot be redefined to produce consistent

results, another integrity assessment method is to be used to assess the
integrity of the cased pipes in the ECDA region.

__________________________________________________________________________

Section 4: Direct Examination

4.1 Introduction

4.1.1 The objectives of the Direct Examination step are to evaluate Indirect
Inspection indications to determine the severity of the indications with respect to
their need for inspection, and to perform inspections at appropriate locations to
collect data needed to assess coating damage, cathodic protection adequacy
and corrosion activity. Typically, Direct Examination requires that the pipe and
casing be excavated to facilitate inspection.

4.1.2 The Direct Examination step is to include the following activities:

4.1.2.1 Prioritization of all Indirect Inspection indications to establish

pipe inspection priorities;

4.1.2.2 Excavation and inspection of pipe and coating at an

appropriate number of locations where corrosion activity is most likely;

4.1.2.3 Measurements of environmental factors, cathodic protection,

and coating damage;

4.1.2.4 Measurements of corrosion damage and evaluations of

remaining pipe strength at areas of corrosion damage;

4.1.2.5 Root cause analyses for coating damage and corrosion

damage; and

4.1.2.6 Process evaluation.

4.1.3 During pipe inspection, conditions other than external corrosion may be
found. Other conditions may include but are not limited to mechanical damage,
stress corrosion cracking (SCC), microbiologically influenced corrosion (MIC),
and electrical interference from outside sources. When found, these conditions
are to be inspected and remediated in manners appropriate for the conditions.

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4.2 Prioritization of Indications

4.2.1 Prioritization is the process of determining the need for Direct

Examination of each of the indications detected during Indirect Inspection.
Prioritization is to be based on the likelihood of past, present and future
corrosion activity.

4.2.2 Definitive criteria for prioritization are to be established. When

establishing criteria, consideration is to be given for the history of prior
corrosion, year-round environmental and operating conditions, Indirect
Inspection tools used, and criteria used for identification and classification of
indications.

4.2.2.1 Different criteria may be required for different pipelines, ECDA

regions, operating conditions, maintenance practices, corrosion and
cathodic protection histories, and other differences.

4.2.2.2 For initial applications of ECDA, prioritization criteria is to be

made more stringent.

4.2.3 Table 2 provides example prioritization criteria for several Indirect

Inspection tools. These example prioritization criteria are general in nature and
are not absolute criteria.

Table 2: Example ECDA Prioritization Criteria for Direct Examination of Cased Pipe Segments

Cathodic Protection Severity Classifications

Based on Close Interval Potential Survey Results
Prioritization Criteria for Cased Pipe Segments
Based on ECDA Survey Severity Classifications
No Minor Moderate Severe
Indications Indications Indications Indications

No Indications No Action Monitor Schedule Immediate

Based on
AC Current Minor Indications Monitor Monitor Schedule Immediate
Attenuation
Survey Moderate Indications Monitor Schedule Schedule Immediate
Results
Coating
Severe Indications Schedule Schedule Immediate Immediate
Condition
Severity
Classifications No Indications No Action Monitor Schedule Immediate
Based on
DC or AC
Minor Indications Monitor Monitor Schedule Immediate
Voltage
Gradient
Survey Moderate Indications Monitor Schedule Schedule Immediate
Results
Severe Indications Schedule Schedule Immediate Immediate

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Note: The example prioritizations in Table 2 are for cased pipe segments that
do not have construction or operation characteristics that increase the likelihood
for external corrosion. If a cased pipe segment has construction or operation
characteristics that increase the likelihood for external corrosion, the
prioritization rating is to be increased to a higher rating appropriate for the
characteristic that causes the rating increase. Construction or operation
characteristics that may require a rating increase include, but are not limited to,
pipe electrically shorted to casing, pipe exposed to high temperature, pipe
known to have coating damage under similar conditions, pipe known to be
essentially bare, pipe at locations where the likelihood for atmospheric
corrosion is high, older pipe, and pipe for which construction or operation
characteristics are generally unknown.

4.2.4 Minimum prioritization categories are as follows:

4.2.4.1 Immediate Action Required: Indications that are considered as

being likely to have ongoing corrosion activity and that are considered to
pose an immediate threat to pipeline integrity under normal operating
conditions. Immediate Action Required indications include but are not
limited to the following examples:

4.2.4.1.1 Multiple severe indications from one or more Indirect

Inspection tools in close proximity to one another;

4.2.4.1.2 Individual severe indications from more than one

Indirect Inspection tool that are essentially at the
same location;

4.2.4.1.3 Other severe indications if significant prior corrosion

activity is likely at or near the indications;

4.2.4.1.4 Indications for which prior corrosion or the likelihood

of ongoing corrosion activity cannot be determined;
and

4.2.4.1.5 For initial ECDA applications, locations at which

inconsistencies between Indirect Inspection results
were identified and could not be resolved.

4.2.4.2 Scheduled Action Required: Indications that are considered

as possibly having ongoing corrosion activity but are not considered to
pose an immediate threat to pipeline integrity under normal operating
conditions. Scheduled Action Required indications include but are not
limited to the following examples:

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 4.2.4.2.1 Severe indications that were not placed in the
Immediate Action Required category;

4.2.4.2.2 Multiple moderate indications from one or more

Indirect Inspection tools in close proximity to one
another;

4.2.4.2.3 Individual moderate indications from more than one

Indirect Inspection tool that are essentially at the
same location; and

4.2.4.2.4 Other moderate indications if significant prior

corrosion activity is likely at or near the indications.

4.2.4.3 Suitable for Monitoring: Indications that are considered to be

inactive or to have the lowest likelihood for prior or ongoing corrosion
activity. Suitable for Monitoring indications include but are not limited to
the following examples:

4.2.4.3.1 Moderate indications that were not placed in a

higher priority category; and

4.2.4.3.2 Minor indications.

4.3 Direct Examination Methods

4.3.1 Methods that may be used to accomplish Direct Examination pipe and
coating inspections include but are not limited to the following:

4.3.1.1 Visual Pipe and Coating Inspection

4.3.1.2 Guided Wave Ultrasonic Inspection

4.3.1.3 In-line Inspection

4.3.1.4 Pressure Testing

4.3.1.5 Other Technology

4.3.2 It should be understood that not all of these inspection methods provide
definitive information, such as corrosion damage dimensions and coating
condition, that may be used later in the ECDA process to determine remaining
life and reassessment intervals. Additionally it should be understood that it may
not be practicable to perform pipe and coating inspections on the full lengths of
all segments of cased pipes. In such instances, it will be necessary to apply

- 16 -
 sound engineering analyses to make determinations or decisions regarding the
condition of cased pipe segments that have not be fully inspected.

4.4 Number of Direct Examinations

4.4.1 Direct examinations are to be made based on the prioritization

categories determined earlier in the Direct Examination step. A minimum of
one direct examination is required for each ECDA region regardless of the
results of the Pre-Assessment and Indirect Inspection steps.

4.4.2 When more than one direct examination is performed, the order in which
the direct examinations are performed is to take into account safety and related
issues.

4.4.3 The following are guidelines for determining the number of direct
examinations based on prioritization categories of Indirect Inspection
indications.

4.4.3.1 Immediate: All indications prioritized as Immediate require

direct examination. If an Immediate indication is reprioritized from
Immediate to a lower prioritization before direct examination is
performed, direct examination of the indication may follow the guidelines
for the lower prioritization. Reprioritization of indications is not to be
performed for initial application of ECDA.

4.4.3.2 Scheduled: If there are any indications prioritized as

Scheduled, some will require direct examination as follows:

4.4.3.2.1 At least one Scheduled indication in each ECDA

region requires direct examination. This Scheduled indication
is to be the one considered to be the most severe in the ECDA
region. For initial application of ECDA, an additional indication
requires direct examination. This indication is to be the next
most severe in the ECDA region.

4.4.3.2.2 If a direct examination at a Scheduled indication

reveals corrosion damage that is deeper than 20% of the
original pipe wall thickness or that is deeper or more severe
than at an Immediate indication, at least one more direct
examination is to be performed at the next most severe
indication in the ECDA region. For initial application of ECDA,
an additional indication requires direct examination. This
indication is to be the next most severe in the ECDA region.

4.4.3.3 Monitored: If there are any indications prioritized as

Monitored, some will require direct examination as follows:

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 4.4.3.3.1 If there are not any Immediate or Scheduled
indications in an ECDA region, at least one Monitored
indication in the ECDA region requires direct examination.
This Monitored indication is to be the one considered to be the
most severe in the ECDA region. For initial application of
ECDA, an additional indication requires direct examination.
This indication is to be the next most severe in the ECDA
region.

4.4.3.3.2 If there are not any Immediate or Scheduled

indications in multiple ECDA regions, at least one Monitored
indication in the ECDA region identified as the most likely for
external corrosion in the Pre-Assessment step requires direct
examination. This Monitored indication is to be the one
considered to be the most severe in the ECDA region. For
initial application of ECDA, an additional indication requires
direct examination. This indication is to be the next most
severe in the ECDA region.

4.4.3.4 No Indications: In the event that no Indirect Inspection

indications are identified in an ECDA region, a minimum of one direct
examination is required at the location identified as the most likely for
external corrosion in the Pre-Assessment step. For initial ECDA
applications, an additional location requires direct examination. This
additional location is to be the next most likely location for external
corrosion identified in the Pre-Assessment step.

4.5 Direct Examination Data

4.5.1 Data to be collected during Direct Examination inspection of pipe are to

be adequate to allow assessment of the condition of the cased pipe with
respect to coating condition, external corrosion damage, cathodic protection,
and environmental parameters that affect external corrosion. Additionally, data
are to be collected regarding the condition of the casing and casing
appurtenances (end seals, spacers, vent pipes, etc.).

4.5.1.1 Because Direct Examination methods for cased pipe may

include visual inspection, guided wave ultrasonic inspection, in-line tool
inspection, or inspections using other technologies, the types of data that
are to be collected may vary widely. The types of data collected are to
be appropriate for the specific type of Direct Examination method used
and in agreement with standard industry practices.

4.5.1.2 Minimum data requirements are to be established before

performing pipe and casing inspections. Minimum data requirements

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 should include the types and accuracies of data to be collected and take
into account the conditions expected to be encountered, the types of
corrosion activity expected, and the availability and quality of historical
data.

4.5.1.3 If the Direct Examination method requires the excavation of

the pipeline and casing, data collection will need to occur in three phases
as follows:

4.5.1.3.1 Data collected prior to any excavation work to

include but not be limited to pipe-to-soil potentials, casing-to-
soil potentials, casing isolation test data and surface soil
resistivities.

4.5.1.3.2 Data collected during or immediately after pipe and

casing excavation, but before any pipe coating or casing
appurtenance removal, to include but not be limited to sample
collections of soil, water, and corrosion and cathodic protection
products, coating type and thickness, assessment of coating
condition and adhesion, dimensions of coating defects, under-
film liquid pH, MIC samples, and photographic documentation.

4.5.1.3.3 Data collected after pipe coating and casing

appurtenance removal to include but not be limited to locations
and dimensions of corrosion damage, other parameters
required for remaining pipe strength calculations, and
photographic documentation. (Prior to measuring dimensions
of corrosion damage, all damaged and disbonded coating is to
be removed and the pipe surface cleaned to expose native
pipe steel.)

4.6 Other Data, Observations and Considerations

4.6.1 The lengths of excavations are to be increased if conditions are found

that indicate coating defects or corrosion damage are likely to extend beyond
the original limits of the excavation.

4.6.2 Consideration is to be given to performing other pipe integrity

assessments unrelated to external corrosion while the pipe and casing are
exposed. Other integrity assessments include but are not limited to stress
corrosion cracking, longitudinal seam defects, circumferential weld defects, and
internal corrosion damage.

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4.7 Remaining Strength Evaluation at Corrosion Damage

4.7.1 At locations where corrosion damage is found on cased pipe, the

remaining strength of the damaged pipe is to be evaluated using industry
standard methods such as ASME B31G, RSTRENG, and Det Norske Veritas
(DNV) Standard RP-F101.

4.7.2 If the remaining strength of the cased pipe at corrosion damage is less
than the established level for the pipeline, the damaged pipe is to be replaced
or repaired, or the operating pressure decreased to a level appropriate for the
severity of corrosion damage.

4.7.3 Unless corrosion damage can be shown to be isolated and unique in a

root cause analysis, alternative methods of assessing pipeline integrity are to
be considered for the entire ECDA region.

4.7.3.1 While the ECDA process facilitates finding representative

corrosion damage in an ECDA region, it may not find all corrosion
damage in the ECDA region.

4.7.3.2 It should be assumed that other corrosion damage may be

present elsewhere in the ECDA region that is similar to corrosion
damage that was found by the ECDA process.

4.8 Root Cause Analysis

4.8.1 The root cause of significant corrosion activity is to be identified. Root

causes of corrosion activity for cased pipe includes but is not limited to the
following:

4.8.1.1 Most corrosion activities that are typical for uncased pipe
buried in soil or submerged in water;

4.8.1.2 Cathodic protection shielding caused by an electrically shorted

casing;

4.8.1.3 Cathodic protection shielding caused by a coated casing;

4.8.1.4 Cathodic protection shielding caused by the cased pipe

coating being disbonded;

4.8.1.5 Cathodic protection shielding caused by casing centralizers,

end seals or other cased pipe construction materials or
devices; and

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 4.8.1.6 Atmospheric corrosion, particularly for pipelines operating at
elevated temperatures where humidity or soil moisture content
is high.

4.8.2 If a root cause is identified for which ECDA is not well suited, such as
cathodic protection shielding caused by an electrically shorted casing, an
alternative method of assessing the integrity of the pipeline segment is to be
considered.

4.9 External Corrosion Mitigation

4.9.1 Remedial actions are to be taken to mitigate corrosion that may result
from identified root causes. Remedial actions for cased pipe include, but are
not limited to, removing the casing, electrically isolating the casing from the
cased pipe, filling the casing annulus with a high dielectric material, repairing or
replacing the cased pipe, repairing the coating on the cased pipe, and providing
supplemental cathodic protection.

4.9.2 Consideration is to be given for repeating Indirect Inspections or using

other assessment means after remedial actions are taken to verify the
effectiveness of the remedial actions.

4.9.3 It may be acceptable to reclassify and/or reprioritize Indirect Inspection

indications as a result of remedial actions. If remedial actions result in the
elimination of corrosion activity or conditions that caused an Indirect Inspection
indication, the indication is no longer a threat to the cased pipe and no longer
needs to be considered for the current assessment. However, future
assessments are to include techniques that are capable of detecting a
recurrence of the corrosion activity or conditions that caused the Indirect
Inspection indication.

4.10 Reclassification and Reprioritization of Indications

4.10.1 Reclassification of an Indirect Inspection indication may be acceptable

and may be required depending on corrosion activity found during pipe
inspection.

4.10.1.1 Except for initial application of ECDA, if corrosion activity is

less severe than classified, the classification may be downgraded to be
more representative of actual corrosion activity. Classification is not to
be downgraded for initial applications of ECDA.

4.10.1.2 If corrosion activity is more severe than classified, the

classification is to be upgraded to be more representative of actual
corrosion activity. If repeated pipe inspections reveal corrosion activity

- 21 -
 that is more severe than initial classifications, ECDA feasibility is to be
reevaluated.

4.10.2 Reprioritization of an Indirect Inspection indication may be acceptable

and may be required depending on corrosion severity found during pipe
inspection.

4.10.2.1 Except for initial application of ECDA, if corrosion severity

is less severe than prioritized, the prioritization may be downgraded to
be more representative of actual corrosion severity. Prioritization is not
to be downgraded for initial applications of ECDA.

4.10.2.2 If corrosion severity is more severe than prioritized, the

prioritization is to be upgraded to be more representative of actual
corrosion severity. If repeated pipe inspections reveal corrosion
severity that is more severe than initial prioritizations, ECDA feasibility
is to be reevaluated.

4.10.3 When corrosion activity classifications and/or corrosion severity

prioritizations are upgraded as the result of pipe inspections that reveal more
severe corrosion activity and/or corrosion severity, the root causes of corrosion
activity are to be identified. After identifying these root causes, all other Indirect
Inspection indications in the cased pipe region where similar root-cause
conditions may exist are to be evaluated to determine if there is a need to
upgrade classifications and/or prioritizations for these indications.

4.11 In-Process Evaluation

4.11.1 An evaluation is to be performed to assess the criteria used to classify

and prioritize Indirect Inspection indications. This assessment is to include
results from the Indirect Inspection data, the remaining pipe strength
evaluations, and the root cause analyses.

4.11.2 Assessing and Modifying Classification Criteria

4.11.2.1 Corrosion activity at each pipe inspection is to be assessed

to determine if the classification criteria are accurately representing the
severity of corrosion damage.

4.11.2.2 Except for initial application of ECDA, if corrosion activity is

less severe than classified, the classification criteria may be
downgraded to be more representative of actual corrosion activity.
Classification criteria are not to be downgraded for initial applications of
ECDA.

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 4.11.2.3 If corrosion activity is more severe than classified, the
classification criteria are to be upgraded to be more representative of
actual corrosion activity. Additional Indirect Inspections may be
necessary to obtain information needed to make appropriate upgrades
to classification criteria. If repeated pipe inspections reveal corrosion
activity that is more severe than upgraded classification criteria, ECDA
feasibility is to be reevaluated.

4.11.2.4 If classification criteria are modified, all Indirect Inspection

indications that have not been evaluated are to be reclassified using
the modified classification criteria.

4.11.3 Assessing and Modifying Prioritization Criteria

4.11.3.1 Corrosion severity at each pipe inspection is to be

assessed to determine if the prioritization criteria are accurately
predicting the need and response time for pipe repair.

4.11.3.2 Except for initial application of ECDA, if corrosion severity

is less severe than prioritized, the prioritization criteria may be
downgraded to be more appropriate for actual corrosion severity.
Prioritization criteria are not to be downgraded for initial applications of
ECDA.

4.11.3.3 If corrosion severity is more severe than prioritized, the

prioritization criteria are to be upgraded to be more appropriate for
actual corrosion severity. If repeated pipe inspections reveal corrosion
severity that is more severe than upgraded classification criteria, ECDA
feasibility is to be reevaluated.

4.11.3.4 If prioritization criteria are modified, all Indirect Inspection

indications that have not been evaluated are to be reprioritized using
the modified prioritization criteria.

__________________________________________________________________________

Section 5: Post Assessment

5.1 Introduction

5.1.1 The objectives of the Post Assessment step are to define

reassessment intervals and assess the effectiveness of the ECDA process.

5.1.2 The Post Assessment step is to include the following activities:

5.1.2.1 Remaining life calculations;

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 5.1.2.2 Determination of reassessment intervals;

5.1.2.3 Assessment of ECDA effectiveness; and

5.1.2.4 Feedback.

5.2 Remaining Life Calculations

5.2.1 Remaining life calculations are calculations made to determine the

period of time required for continuing corrosion activity to result in a failure. The
calculations require identification or selection of the worst remaining corrosion
damage and the determination or selection of a corrosion growth rate. If no
corrosion defects are found, remaining life calculations are not required and the
remaining life can be considered the same as for a new pipeline.

5.2.1.1 Worst Remaining Corrosion Damage

5.2.1.1.1 At this point in the ECDA process, all Indirect

Inspection indications prioritized as Immediate will either
have been or will be addressed. Therefore, identification or
selection of worst remaining corrosion damage may be
based on the worst remaining Indirect Inspection indication.

5.2.1.1.2 The most severe corrosion damage found at the

most severe Indirect Inspection indication with a
prioritization less than Immediate is to be used as the
maximum remaining flaw size for remaining life
calculations. If root-cause analyses indicate that the most
severe Indirect Inspection indication is unique, the size of
the next most severe indication may be used for remaining
life calculations.

5.2.1.1.3 As an alternative to using the most severe

corrosion damage found, a value based on sound
engineering analysis may be used. This analysis may be
based on a statistical or a more sophisticated analysis of
corrosion damage found at pipe and casing inspection
sites.

5.2.1.2 Corrosion Growth Rate

5.2.1.2.1 Determinations or selections of corrosion growth

rates are to be based on sound engineering analyses.

- 24 -
 5.2.1.2.2 Corrosion growth rates measured using corrosion
rate measurement methods or equipment may be used if
these rates are applicable to the ECDA region being
evaluated.

5.2.1.2.3 Corrosion growth rates may be determined using

the methods and values provided in Appendix D of NACE
SP0502.

5.2.1.2.4 Corrosion growth rates may be determined using

evaluations and analyses of actual corrosion damage found
during pipe and casing inspections.

5.2.2 Remaining Life Calculation

5.2.2.1 Remaining life may be calculated using sound engineering

analysis of the worst remaining corrosion damage and conservative
corrosion growth rates. The analysis is to assume that corrosion
damage grows continuously and is to take into account typical sizes
and geometries of corrosion damage.

5.2.2.2 Remaining life may also be calculated using the equation

that follows. This equation is based on corrosion damage that grows
continuously and takes into account typical sizes and geometries of
corrosion damage.

RL = C x SM x t / GR = C x ( FPR – MR ) x t / GR

Where: RL = Remaining Life (years)

C = 0.85 (dimensionless calibration factor)
SM = Safety Margin = Failure Pressure Ratio – MAOP Ratio

Failure Pressure Ratio (FPR) = Calculated Failure Pressure

(dimensionless) Yield Pressure

MAOP Ratio (MR) = MAOP

(dimensionless) Yield Pressure

t = Nominal Pipe Wall Thickness (mm [in])

GR = Corrosion Growth Rate (mm/y [in/y])

- 25 -
5.3 Reassessment Interval Determination

5.3.1 The reassessment interval is to be determined using a sound

engineering analysis and conservative determinations or selections of
remaining corrosion damage sizes, corrosion growth rates, and corrosion
growth periods. To ensure that the reassessment interval is not unreasonably
long, a maximum reassessment interval that cannot be exceeded regardless of
the findings of the ECDA is to be established. Guidance for establishing the
maximum reassessment interval may be found in pipeline industry standards
such as ASME B31.4, ASME B31.8, and API 1160.

5.3.2 The reassessment interval is to be determined using the half-life

method commonly used in engineering practice. The half-life method involves
determining or estimating the true life and setting the reassessment interval to
be one-half of the true life. The remaining life determination made in section
5.2.2 is to be used as the true life for determining the reassessment interval.

5.3.3 Because ECDA regions may have different corrosion mechanisms,

severities of corrosion damage and corrosion growth rates, remaining life
determinations are to be made for each ECDA region.

5.4 Assessment of ECDA Effectiveness

5.4.1 ECDA is a continuous improvement process. Successive applications

of ECDA will enhance the ability to identify locations where corrosion activity
has occurred, is occurring, or may occur. Assessment of ECDA effectiveness
during each application of ECDA, and during mitigation activities between
ECDA applications, is crucial to improving the likelihood that ECDA will identify
locations of past, present and future corrosion activity.

5.4.2 Criteria are to be established for assessing the effectiveness of the

ECDA process. The criteria may be for the application of ECDA, for the results
of the ECDA process, or absolute criteria. These criteria include but are not
limited to the following:

5.4.2.1 Criteria that track the reliability or repeatability of the

application of ECDA - An example of this is tracking the number of
instances where Indirect Inspection indications needed to be
reclassified or reprioritized. If the number of reclassifications or
reprioritizations is significant, the original classification or prioritization
criteria probably need to be modified.

5.4.2.2 Criteria that track the application of the ECDA process – An

example of this is tracking the number of inspections made to
investigate suspected problems. Increases in the number of
inspections indicate more aggressive corrosion monitoring.

- 26 -
 5.4.2.3 Criteria that track the numbers of cased pipes that are
subjected to multiple applications of Indirect Inspections - Increases in
the number of cased pipes that are subjected to multiple applications of
Indirect Inspections indicate more aggressive corrosion monitoring.

5.4.2.4 Criteria that track results of the various Indirect Inspection

methodologies to identify the more effective methodologies – Making
more use of the more effective methodologies and less use of
methodologies with lesser effectiveness indicates a more focused
application of ECDA.

5.4.2.5 Criteria that track the frequency at which Immediate and

Scheduled indications arise – A reduction in this frequency indicates an
improved management of corrosion.

5.4.2.6 Criteria that track the extent and severity of corrosion

damage – A decrease in the extent and/or severity of corrosion
damage indicates an improved management of corrosion.

5.4.2.7 Criteria that establish absolute performance requirements –

An example is requiring that no corrosion leaks or ruptures occur
between subsequent applications of ECDA. Meeting such a
requirement demonstrates improved integrity with regard to corrosion.

5.4.3 In the event that evaluation does not show improvement between
ECDA applications, the ECDA process is to be reevaluated and modified as
found necessary, or alternative methods of assessment are to be considered.

5.5 Feedback and Continuous Improvement

5.5.1 Throughout the ECDA process, as well as during scheduled activities

and reassessments, ECDA applications are to be improved by incorporating
feedback at all appropriate opportunities.

5.5.2 Opportunities for which feedback is to be incorporated include but are

not limited to the following:

5.5.2.1 Identification and classification of Indirect Inspection

indications;

5.5.2.2 Data collection from Direct Examination pipe inspections;

5.5.2.3 Remaining pipe strength analyses;

5.5.2.4 Root-cause analyses;

- 27 -
 5.5.2.5 Remediation activities;

5.5.2.6 In-process evaluations;

5.5.2.7 Process validation pipe inspections;

5.5.2.8 Criteria for monitoring long-term ECDA effectiveness; and

5.5.2.9 Scheduled monitoring and period reassessments.

__________________________________________________________________________

Section 6: ECDA Documentation

6.1 Introduction

This section addresses information that documents in a clear, concise, and

organized manner the data and activities pertinent to the Pre-Assessment,
Indirect Inspection, Direct Examination and Post Assessment steps of the
cased pipe ECDA process.

6.2 Pre-Assessment

6.2.1 All Pre-Assessment actions and data are to be recorded, including but
not limited to:

6.2.1.1 Data elements collected for the cased pipes being assessed.

6.2.1.2 Methods and procedures used to integrate collected data to

determine when Indirect Inspection tools can and cannot be used.

6.2.1.3 Methods and procedures used to select the Indirect Inspection

tools.

6.2.1.4 Characteristics and boundaries of cased pipe regions and the

Indirect Inspection tools used in each region.

6.3 Indirect Inspection

6.3.1 All Indirect Inspection actions and data are to be recorded, including but
not limited to:

6.3.1.1 Geographically referenced locations of the beginning and

ending points of each cased pipe Indirect Inspection and fixed points
used for determining the locations of Indirect Inspection measurements.

- 28 -
 6.3.1.2 Dates and weather conditions during which the Indirect
Inspections were conducted.

6.3.1.3 Indirect Inspection results at sufficient resolution to identify the

location of each indication.

6.3.1.4 Procedures for aligning Indirect Inspection measurements and

expected errors for each Indirect Inspection tool.

6.3.1.5 Procedures for defining the criteria used in classifying and

prioritizing the severity of Indirect Inspection indications.

6.4 Direct Examination

6.4.1 All Direct Examination activities and other pertinent information are to be
documented. Documentation includes, but is not limited to, the following:

6.4.1.1 Procedures and criteria for classifying and prioritizing Indirect

Inspection indications.

6.4.1.2 Data collected during Direct Examination inspections.

6.4.1.3 Results of root-cause identifications and analyses.

6.4.1.4 Descriptions and explanations for reclassification and

reprioritization of Indirect Inspection indications.

6.4.1.5 Planned mitigation activities.

6.5 Post Assessment

6.5.1 All Post Assessment activities and other pertinent information are to be
documented. Documentation includes, but is not limited to, the following:

6.5.1.1 Remaining life calculations to include descriptions of methods

of estimating remaining life, remaining life calculation results, and
determinations of maximum remaining flaw sizes and corrosion growth
rates.

6.5.1.2 Reassessment interval determination and scheduled related

activities.

6.5.1.3 Criteria used to assess ECDA effectiveness and results from

assessment of ECDA effectiveness to include criteria and metrics, and
data from periodic assessments.

- 29 -
 6.5.1.4 Feedback related to assessment of criteria used in each ECDA
step and any modifications of these criteria.

__________________________________________________________________________

References

1. External Corrosion Direct Assessment, NACE SP0502-2008, NACE International

(Houston, Texas: NACE 2008)

2. Steel-Cased Pipeline Practices, NACE SP0200-2008, NACE International (Houston,

Texas: NACE 2008).

3. External Corrosion Probability Assessment for Carrier Pipes Inside Casings (Casing
Corrosion Direct Assessment--CCDA), GRI-05/0020, Gas Technology Institute.

4. PHMSA – Pipeline Corrosion Final Report – Michael Baker Jr., Inc. – July 2008

5. PHMSA - Applying External Corrosion Direct Assessment (ECDA)In Difficult-to-Inspect

Areas DTRS56-05-T-0003 - E. B. Clark, B. N. Leis, and S. A. Flamberg – March 2007

6. PHMSA - Demonstration of ECDA Applicability and Reliability for Demanding

Situations DTPH56-06-T-000001 - Daniel Ersoy – August 2008

7. PHMSA - Improvement of External Corrosion Direct Assessment Methodology by

Incorporating Soils Data DTRS56-03-T-0003 - B. N. Leis, E. B. Clark, M. Lamontagne,
and J. A. Colwell - November 2005

8. PHMSA Casing Quality Action Team (CASQAT) Committee – Guidelines for Integrity
Assessment of Cased Pipe for Gas Transmission Pipelines in HCAs – March 2010

- End of Body of Guidelines -

- 30 -
 Appendix A

List of Example Pre-Assessment Data

 Appendix A: Pre-Assessment Data for Cased Pipe ECDA
The following is a listing of data that may be needed for Pre-Assessment of cased segments
of pipelines. Not all data listed may be required for all cased pipes, and other data not listed
may be required for some cased pipes. Minimum data requirements are to be established by
evaluating individual data to determine its relevance to the occurrence of external corrosion.
Those data that are essential to the success of the ECDA process are to be identified and
extra effort made to collect the data.

Pipe Related Data

• Material (steel, cast iron, etc.)

• Diameter
• Wall thickness
• Year manufactured
• Seam type
• External coating type on pipe
• External coating type on joints

Casing Related Data

• Material (steel, cast iron, etc.)

• Diameter
• Length
• Year manufactured
• Locations
• Construction techniques and practices
• External and internal coatings
• Casing spacers
• Casing end seals
• Casing vent pipes

Construction Related Data

• Year installed
• Changes and modifications
• Alignment sheets, route maps and aerial photos
• Construction techniques and practices
• Locations of appurtenances (valves, taps, flanges, etc.)
• Depth of cover
• Proximity to other pipelines and utilities
Soils and Environment Data

• Soil characteristics
• Soil types
• Drainage
• Topography
• Land use
• Frozen ground

Corrosion Control Data

• CP system types
• CP test stations
• Stray electrical current sources and locations
• Electrical isolation devices (isolation flanges, etc.)
• CP evaluation criteria
• CP maintenance history
• Periods without CP
• External coating condition
• CP current demand
• CP survey data
• CP history
• Casing electrical isolation tests
• Casing filling records

Operational Data

• Pipeline operating temperature

• Operating stress levels and fluctuations
• Leak monitoring programs
• Pipe and casing inspection reports
• Leak and rupture history
• Repair history
• MIC corrosion tests
• Mechanical damage types and locations
• Previous CP surveys
• Pressure test information
• Other integrity related activities
 Appendix B

Guidelines for Establishing ECDA Regions for Cased Pipe

Appendix B: Guidelines for Establishing ECDA Regions for Cased Pipe
The following Table B.1, Guidelines for Establishing ECDA Regions for Cased Pipe, lists 17 attributes that must be analyzed and considered when establishing
regions for ECDA of cased pipe. Guidance is provided on how these attributes should be applied when establishing ECDA regions for cased pipe. “R” indicates
that this attribute alone requires a separate ECDA region. “C” indicates that this attribute must be considered when determining ECDA regions, but alone does not
always require a separate ECDA region, depending on case-specific circumstances.

Table B.1 Guidelines for Establishing ECDA Regions for Cased Pipe

Item Attribute R C Comments Additional Guidance Material

Carrier Pipe Coating R Cased pipe with coatings that tend to shield cathodic It is envisioned that there will be two main groups of
protection (CP) shall be placed in a separate region. carrier pipe coatings, shielding type coatings and non-
All other coatings that do not tend to shield CP may be shielding type. Operators can segregate coatings into
1 placed in the same cased region. Operators may use additional groups if they desire.
as many regions as there are types of coatings.
Carrier pipe that is bare must also be placed in a
separate region.
Casing Materials and Design R Cased pipe with problematic casing materials and There are several types of casing designs and materials
designs that are known to cause or promote external that behave differently from others. Among these are
corrosion require separate regions. These may split sleeve type, nested type, coated type and those
include such things as wooden spacers, metal that are only tack welded. Each requires a separate
band/runner type spacers, corrugated casings, and region. In addition, the centralizer design can be critical
casings with extremely oversized or undersized annuli. to the behavior of the casing. Certain types present
Coated casings require separate regions, since they more problems than others: wooden, all metal, metal
can significantly impact the resolution and banded, and directly attached can create shorted
2
interpretation of the indirect inspection data. conditions if the coating fails because of age or initial
Additionally, casings that are too long to be fully method of installation. Additional design issues are end
inspected by a guided wave inspection as part of seal design, space between the carrier pipe and the
ECDA step 3 (indirect assessment) shall be evaluated casing, the likelihood of stress on the carrier pipe at the
in the pre-assessment to determine if ECDA is entry point, etc.
feasible. All data gathered and analyzed as part of the
pre-assessment must be utilized in the decision
process.
Corrosion History on R Casings that are in a pipe segment with known Corrosion history on a pipe segment may be an
Adjacent Buried Pipe corrosion problems and are influenced by the same excellent indicator for corrosion in a casing if there is a
Segments CP system shall be placed in a separate cased region. short or an electrolytic coupling. Per NACE RP 0502,
Table 1, these need to be in separate regions from
3
areas that do not promote corrosion. Leak and rupture
history can be dependent on corrosion history, which
according to NACE RP 0502 need to be identical for
each ECDA region.
 Table B.1 Guidelines for Establishing ECDA Regions for Cased Pipe

Item Attribute R C Comments Additional Guidance Material

Each carrier pipe must have R Cased crossings that reside in areas that are found Cathodic protection maintenance histories are important
a similar cathodic protection during the Pre-Assessment to have had intermittent or to determine the susceptibility of the carrier pipe to
4 maintenance history inadequate cathodic protection must be considered for external corrosion and may provide additional
a specific cased region. information on the likelihood of past, present and future
corrosion.
Past knowledge of metallic R Casings that are found to have been metallically Cased crossings with metallic shorts or electrolytic
contacts or electrolytic shorted or electrolytically contacted in the past (even couplings may have undergone external corrosion in the
5 couplings seasonally) and have not passed a Subpart O integrity past and may be susceptible to external corrosion in the
assessment shall be placed in a separate cased present and future and thus must be in separate
region. regions.
Each carrier pipe must have R If the cased crossing is in an area of the operator’s MIC can cause the corrosion growth rate to be
similar exposure to system that is known to have a high rate of MIC accelerated and may require a higher level of CP.
6 microbiologically influenced related corrosion, then the casing must be placed in a Areas that are prone to MIC must be in a separate
corrosion (MIC) separate region. region.
Casing Construction C Different construction techniques that result from Some construction techniques and crews may produce
Techniques changes in construction crews/contractors and poor quality construction or specific construction
7 installation procedures may require separate cased deficiencies, e.g., pushing centralizers together,
regions. damaging the pipe coating, etc.
Each carrier pipe should C Different pipe vintages may require different regions. Time in service may be an indication of the extent of
have a similar time in service Operators should rely on their experience and follow atmospheric corrosion or corrosion from shorted
8 the protocols established in their ECDA procedures for conditions and electrolytic couplings. Date of
buried pipe. installation can also assist in determining construction
techniques used.
Casing and Carrier Pipe C Different environments surrounding the casing may The environment may play a large role if there are
Environment require designation as separate regions, which should electrolytic coupling issues and shorted conditions.
be consistent with the operator’s ECDA procedure for Some environments are more prone to causing shorts
9
buried pipe. A separate region is needed for each than others. Environment may play a significant role in
area with similar drainage characteristics and each corrosion growth rates.
area with similar soil corrosivity properties.
Carrier Pipe Stress Level C The operating stress levels (e.g., 20% as compared to The stress on a carrier pipe can determine the
72%) must be considered when establishing regions. consequence of a failure. Low stress carrier pipes will
10 tend to leak rather than rupture while the converse is
true for high stress pipes. Pipe stress levels must be
considered when determining casing regions.
Carrier Pipe Seam C Operators should follow their ECDA procedure for Selective seam corrosion can be a threat to some older
11 buried pipelines. pipelines with specific seam types, and thus should be
in a separate region.
 Table B.1 Guidelines for Establishing ECDA Regions for Cased Pipe

Item Attribute R C Comments Additional Guidance Material

Land Use C Areas where the land use may increase corrosion due Land use can impact the threat of external corrosion to
to the corrosiveness of the environment (such as the carrier pipe within the casing. For example, cased
processing plants) should be considered for a crossings near major highways that have snow and ice
12 separate region. could be subject to salt contamination, i.e., low
resistivity of the surrounding ground. There are other
areas which could subject the pipeline to large soil loads
from above, etc.
Protection System on Carrier C Operators should consider the type of CP system Galvanic and impressed current CP systems will behave
Pipe used on the cased pipe and follow their ECDA differently and cased crossings should have the same
13 procedure for buried pipelines. type of CP systems in the same region.

Stray Current and Induced C Operators should follow their ECDA procedure for Stray currents, either DC or AC, can accelerate
AC on Carrier Pipe buried pipelines regarding stray current and induced corrosion or cause corrosion, and thus cased crossings
14 AC history. with potential stray current issues should be in separate
regions.

Temperature on Carrier Pipe C Different operating temperatures may require separate High temperatures can accelerate atmospheric
regions, especially if high operating temperatures, corrosion by allowing additional moisture and humidity
coupled with moist environments, could cause to permeate the casing annular space. Additionally,
degraded coatings by creating a steaming effect or fluctuations in temperature can cause condensation
15 causing moisture to condense in the annulus. which could cause atmospheric corrosion to form on the
Additionally, high operating temperatures that can carrier pipe.
accelerate corrosion should be considered when
establishing cased regions.

Carrier Pipe Exposure to C If the casing resides in an area that the operator has See the above guidance material. Cased crossing in
Humid/Dry Air identified as an atmospheric corrosion monitoring dry air regions should be less prone to atmospheric
16 area, such as salt marine environments, the casing corrosion and thus be in a separate region.
should be placed in a separate region.

Carrier Pipe Design C Operators should follow their ECDA procedure for Dissimilar designs with regard to piping design, MAOP,
buried pipelines. Each carrier pipe should have a diameter and other issues can affect both the likelihood
17 similar type pipe design: maximum allowable and consequence of failure and thus should be in
operating pressure, diameter, class location, end separate regions.
loading stresses and other design factors
 Appendix C

Guidelines for Selecting Indirect Inspection Tools for Cased Pipe

Appendix C: Indirect Inspection Tools for Cased Pipe
The following table provides guidance on indirect inspection tool selection for conducting ECDA on cased pipe. Information in this table is not valid if the carrier pipe is
weight coated with concrete.

Legend: A-Acceptable: This method should yield reliable results to identify metallic short or electrolytic coupling.
U-Unacceptable: This method does not yield reliable results.
1- Contact to pipeline is required at the location of signal transmitter set-up but not in the vicinity of the casing.
2- Contact to pipeline is not necessary in the immediate vicinity of the casing.
3- Capability exists but protocols and procedures have not been validated.
4- Indeterminate. Data that is not available to establish effectiveness.

Table C.1 Guidelines for Selection of Indirect Inspection Tools for Cased Pipe
Electrical Applicability
Name Contact
Item Type Required Bare Casing Coated Casing Identifies Description Comments Limitations
Reference Electro- Electro-
Pipe Case Clear Short
lytic Clear Short lytic
Stray DC
currents must
Coating holiday
be
indications near
Holidays, which may be considered.
the end of the There is a
DCVG a metallic path, in the For bare
casing denote a gradient.
coating of the pipe at casings, a
possible metallic Possible to
Direct Current 1 the ends of the casing, survey must
1 No No A A A A 3 3 or electrolytic have holiday
Voltage Gradient at casing spacers with be done over
path between detected and
metallic components or the casing to
the casing and there is no
NACE RP 0502 at other locations along determine if it
the pipe. short.
the cased pipe segment has an
Metallic=Very
electrolytic
Large Indication
coupling or
metallic short.
Compares
AC Current current flow at HVAC power
Metallic or electrolytic Signal
Attenuation 1 each end of lines or
2 No No A A A 3 3 3 path between pipe & attenuates at
casing. changes in
casing a contact
NACE RP 0502 Measurement in alignment
mA or dBmA/ft
Coating
Measure dBµV
AC Voltage anomaly tool.
Metallic or electrolytic signal. Strength
Gradient 1 Reliable HVAC power
3 No No A A A A A A path between pipe & & direction at
detection of lines
casing each end of the
NACE RP 0502 electrolytic
Casing
coupling
 Table C.1 Guidelines for Selection of Indirect Inspection Tools for Cased Pipe
Electrical Applicability
Name Contact
Item Type Required Bare Casing Coated Casing Identifies Description Comments Limitations
Reference Electro- Electro-
Pipe Case Clear Short
lytic Clear Short lytic
On Survey.
Utilize a
criterion.
CIS Preliminary Telluric
(no interruption) check. With Currents, AC
Metallic or electrolytic
Comparison of coated and DC
2 path between pipe &
4 Electrical Yes Yes A A A 4 4 4 "on" P/S and casing, there Strays, HVAC
casing. A preliminary
Potential C/S readings can be a consideration.
screening tool
problem with Complement-
NACE RP 0200 electrolyte in ary tool
the casing or
near a
rectifier
Compare P/S
and C/S shift
magnitude.
Same direction
CIS (interrupted)
and similar
magnitudes Telluric
Electrical
Metallic or Electrolytic suggest metallic Currents, AC
Potential. 2
5 Yes Yes A A A 4 4 4 Path between the Pipe contact. Same and DC
Comparing P/S
and Casing direction but Strays, HVAC
and C/S shifts
reduced C/S consideration
shift suggest
NACE RP 0200
electrolytic path.
C/S shift small or
opposite
indicates clear.
 Table C.1 Guidelines for Selection of Indirect Inspection Tools for Cased Pipe
Electrical Applicability
Name Contact
Item Type Required Bare Casing Coated Casing Identifies Description Comments Limitations
Reference Electro- Electro-
Pipe Case Clear Short
lytic Clear Short lytic
Signal between
pipe and casing
is traced to point
of metallic
HVAC power
contact and
lines. Cannot
returns (no
determine if it
appreciable
is electrolytic
Pipe/Cable signal outside
Metallic or electrolytic coupling or
Locator casing) or signal
6 Yes Yes A A A 4 4 4 path between the pipe metallic short
reduction within
and casing for bare
NACE RP 0200 casing may
casings. Can
indicate
determine if it
electrolytic path.
is clear for
Clear casing
bare casings.
results in strong
endwise signal
outside casing
along pipe.
Reverse current
applied to casing
Stray DC
to produce
Currents &
anodic
Panhandle Telluric
polarization. 0.01 ohm
Eastern "B" Currents-
C/S & P/S shifts may need to
consideration.
from 3 levels to be adjusted
Reverse Current Only detects if
Confirmation of applied current for coated
Applied to metallic short.
7 Yes Yes U A U U 4 U suspected pipe-to- are used to casings
Casing for P/S & Cannot
casing metallic contact calculate where the
C/S Comparison determine the
approximate casing
difference
pipe-to-casing contains an
AGA Research between clear
resistance with electrolyte.
Project and
values < 0.01
electrolytic
ohms confirming
coupling.
a metallic
contact.
 Table C.1 Guidelines for Selection of Indirect Inspection Tools for Cased Pipe
Electrical Applicability
Name Contact
Item Type Required Bare Casing Coated Casing Identifies Description Comments Limitations
Reference Electro- Electro-
Pipe Case Clear Short
lytic Clear Short lytic
Measured Stray DC
Internal
resistance Currents -
Resistance Resistance of
equated to path consideration.
path external
Pipe-to-casing metallic down casing and Complement-
8 Electrical Yes Yes U A U U A U to casing
or electrolytic coupling back along pipe ary tool. Can
Resistance must be
to calculate determine
considered
distance to metallic
NACE RP 0200
contact shorts only.
Uses flange Electrolytic
isolation checker range not
to indicate clear established.
Casing-Pipe
Pipe-to-casing metallic or shorted Complement-
9 Capacitance Yes Yes U A U U A U
contact condition based ary tool. Can
on pipe-to- determine
Ref: N/A
casing metallic
capacitance shorts only
Four Wire Drop Using current
Test span testing to
indicate the
Access over
Current Flow Pipe-to-casing metallic presence and Not typically
10 Yes Yes U A U U U U top of casing
Direction & contact location of used
required
Magnitude contact of the
carrier pipe to
NACE RP 0200 the casing
Compare P/S &
C/S potential or
Temporary
shifts with
Intentional Short Long casing
temporary short
vents, if used,
between pipe Pipe and
Electrical Confirmation of may distort
and casing in casing test
11 Potential Yes Yes A A U A A U suspected metallic results. Can
place and wires offer
Comparing P/S contact only
removed. No best results.
and C/S shifts determine
change indicates
metallic short.
contact of similar
NACE RP 0200
resistance
already existed.
 Appendix D

Indirect Inspection Survey Techniques for Cased Pipe

Appendix D: Above-Ground Survey Techniques for Cased Carrier Pipe Using ECDA
Indirect Inspection Tools
D.1 Introduction
This section contains guidance on the differences between doing an ECDA assessment on regular line
pipe and a carrier pipe in a casing. This guidance addresses:
• The tools that are available,
• A brief description of how the tools work,
• Guidance surrounding the use of the tools (e.g., is access to the pipe required?),
• How actual indications are measured and directly examined,
• Limitations such as interferences, etc.,
• The different types of contacts, shorts and electrolytic couples that can be detected, and
• Proper interpretation of indirect inspection tool readings when used for cased pipe.

D.2 Definitions:
Electrolytic Couple – Ionic path between two metallic structures via an electrolyte
Metallic Short – Direct or metallic (electrical) path between two metallic structures

D.3 References:
NACE RP 0200-2000 – Steel Cased Pipeline Practices
NACE RP 0502-2002 – Pipeline External Corrosion Direct Assessment Methodology

D.4 Indirect Inspection – Casing to Pipe Tests

There are several types of tests that can be used to determine if a carrier pipe is likely to be in metallic
contact or electrolytic couple with a casing. Some of them use the same principles and equipment as the
ECDA indirect inspection tools, though specific techniques and interpretation may differ. They are as
follows:

a) Direct Current Voltage Gradient (DCVG)

b) AC Current Attenuation (ACCA)
c) Alternating Current Voltage Gradient (ACVG)
d) Potential Surveys
1. Potential Surveys (CIS, No Interruption)
2. Potential Surveys (CIS, Interrupted)
e) Pipe/Cable Locator
f) Panhandle Eastern Test
g) Internal Resistance Test
h) Casing/Pipe Capacitance
i) Current Span Test – Four Wire Drop Test
j) Temporary Intentional Short

Operators who use these types of tests must have a procedure for the test that is specific to applying the
tool to cased pipe. Operators must ensure that the personnel performing the test are properly trained and
qualified and that the results are properly interpreted and documented.

D.4.1 Direct Current Voltage Gradient - DCVG

DCVG surveys are used to evaluate the coating condition on buried pipelines. In a DCVG
survey, a DC signal is typically created by interrupting the pipeline’s cathodic protection current,
and the voltage gradient in the soil above the pipeline is measured. Voltage gradients are the
result of current pickup/discharge at holiday locations. Electrically shorted and electrolytically
coupled conditions can occur only when there is a holiday in the coating.

A typical DCVG system consists of a current interrupter, a voltmeter, connection cables and two
copper-copper sulfate electrodes. On sacrificial anode systems a temporary DC power supply
needs to be installed. Ideally, the interrupter is installed at a rectifier. The electrodes are held 3
to 6 feet apart either perpendicular to the pipe or, more commonly, over the pipe. The
magnitude of the shift between the “on” and “off” readings and the direction of the meter are
recorded. When a coating holiday is approached, a noticeable signal swing can be observed on
 the voltmeter at the same rate as the interrupter switching cycle. A metallically shorted bare
casing would behave as an extremely large holiday on the pipe from both ends of the casing.
The DCVG may also be able to detect electrolytic couples which may present themselves as a
smaller holiday. In either situation, DCVG can give a positive indication that a short or couple
exists, but will not be able to locate the short or couple in the casing.

Since the DCVG method measures the difference between two copper-copper sulfate reference
cells, each cell must make good contact with the ground and the surface must be conductive
(wet). Since the cells are wired to a volt meter, no connection to either the casing or carrier pipe
is needed. There are no trailing wires or other attachments, except for an interrupter at the
rectifier.

D.4.2 AC Current Attenuation - ACCA

This type of survey is often used for ECDA of uncased pipe because it is normally an
assessment of the condition of the pipeline coating. A signal (4Hz AC) is applied to the pipeline,
and coating damage is located and prioritized according to the magnitude and change of current
attenuation.

The test is set up by first connecting the signal generator to the pipe, typically through a test
lead. A cycled AC signal is produced and transmitted along the pipe. The transmitter is
energized and adjusted. Signals along the pipe are then measured with the detector/receiver
unit array, which is sensitive to the electromagnetic field radiating from the pipeline.

In this test, a short should cause a noticeable drop in the AC signal strength between the
readings just before the start of the casing and just after the end of the casing. If there is no
short, there should be no drop since the carrier pipe is isolated from both the casing and the
ground (essentially just being suspended in air). Both electrolytic couples and direct shorts
should be detected and the relative loss of signal strength may indicate which type of contact is
present.

If testing over the actual casing is permitted by available access, the signal may be shielded by
the casing itself but the drop in signal strength should be apparent once the end of the casing is
passed. There should be a pronounced loss in signal as compared to other areas where the
coating is in good condition.

The only connection to the pipe is the signal generator which should be at least several pipe
lengths away from the casing (care must be taken with the ground for the signal generator to
prevent it becoming a pathway for signals to couple with the pipe). The receiver does not have
to have contact with soil and since it uses the magnetic flux/field, it can read signals under
paved surfaces as long as there is not significant metal reinforcement. The unit must locate the
pipe so it is an excellent pipe locator and pipe depth measurement tool. The receiver must be
kept perpendicular to the pipe regardless of the terrain.

For example, the following plot was taken from data on a test casing. The casing is located
between the north end and south end and is 100 ft. in length. Testing was performed at 100 ft.
and 50 ft. before and after the casing. This facility includes the capability of simulating metallic
and electrolytic couples with a series of test wires and rheostats. The simulated direct short
shows 100% attenuation; the clear condition shows 1.5% attenuation, the simulated electrolytic
couple shows 61% attenuation, and the actual electrolytic couple (done by flooding the casing
and having holidays on the carrier pipe) shows 45% attenuation.
 PCM Milli Amps
PCM Results on Test Casing

1800
1600
1400
1200
Clear
1000 Sim Coupling
800 Sim Short
Actual Short
600
400
200
0
0 50 North South 250 300
End End
Distance

D.4.3 Alternating Current Voltage Gradient - ACVG

ACVG surveys are similar to DCVG surveys, except that an AC signal is applied to the pipe by a
signal generator.

The ACVG test is conducted using two metal pins fixed in a proprietary frame device, usually in
conjunction with an AC attenuation device, that measure the AC potential difference between
the two fixed metal pins in contact with the soil. In this survey, the device is moved above the
pipeline and when the arrow changes direction, the equipment operator knows the contact has
been passed. As in DCVG, if the device is moved to either end of the casing, it should point
into the cased crossing. Typically, a reading cannot be obtained over the casing and thus only
the readings at each end are important. One indirect inspection survey contractor uses a range
of 50 to 80 dBµV as an electrolytic couple and all readings over 80 dBµV as direct shorts (direct
shorts are typically 90+ dBµV with 99 dBµV not being uncommon). The ACVG device does not
need a rectifier but uses a signal generator connected to the pipe and to an independent
ground, which inputs a 4 HZ signal on the pipe. The signal is used as pure AC to be picked up
by the two probes and to have the relative difference between the probes show the direction to
the contact.

As with DCVG and AC Attenuation, the receiver does not have to be connected to the carrier
pipe. The only connection is the signal generator and that should be at least several pipe
lengths (or more) away from the casing. The two fixed metal pins need to make good contact
with the soil, so wetting down dry surfaces is necessary. With porous and poor quality paving,
good readings can be obtained provided sufficient moisture exists or is added.

D.4.4 Potential Surveys

Potential surveys of pipelines and casings are made to monitor cathodic protection potentials
(voltages in volts DC) and are the initial tests conducted to identify possibly shorted casings.
The possible presence of a short may also be evaluated by measuring/comparing the pipe-to-
electrolyte (P/S) and casing-to-electrolyte (C/S) potentials.
 D.4.4.1 CIS, No Interruption (P/S and C/S Potential Differences)

This test is typically a screening tool used as part of a periodic survey. The P/S
potential and the C/S potential are read with protective current applied using a voltmeter
and reference electrode. A potential difference of 100 mV or less between the two
readings is typically an indication of a metallic short or an electrolytic couple condition.
Further testing is needed to confirm the casing condition. Protected bare and coated
casings may not show the same type of changes.

D.4.4.2 CIS, Interrupted (Cycling the Rectifier)

While taking the P/S and the C/S readings, the rectifier is cycled on and off. If the shift
in the potentials of both the pipe and the casing is in the same direction and of similar
magnitude, a metallic short is possible. If the potential shifts are in the same direction,
but of different magnitudes, an electrolytic couple condition is possible. If the potential
shifts are very small or in opposite directions, the casing is probably clear and the casing
may be in the gradient of a nearby ground bed. Protected bare and coated casings may
not show the same type of changes when the rectifier is cycled.

A CIS can show if there is a possible short to a casing, provided the casing is bare and
is not protected separately. Typically, the CIS will dip at both ends of the casing and will
recover as one goes away from the casing. In some situations, the potential drop may
not be very large, especially if the pipe coating is good and an electrolytic couple with a
fairly high resistance exists. In these situations, other testing methods may be more
appropriate.

D.4.5 Pipe/Cable Locator

The presence and location of a pipe-to-casing metallic contact may be approximated by
following the signal from a pipe and cable locator with the signal applied between the pipe and
casing. If there was a metallic short between the pipe and the casing, the signal from the
locator would follow one structure to the point of contact and return. If a clear signal can be
picked up at the opposite end of the casing on the carrier pipe, without appreciable degradation,
the casing is not shorted. If there is a reduction in the signal strength without an apparent signal
return location, an electrolytic couple is expected. This is not a very precise test and should be
used for screening purposes only and may not show all electrolytic couples.

D.4.6 Panhandle Eastern ‘B’ Method

The Panhandle Eastern method involves determining whether the casing is isolated or not by
discharging DC current from the casing and comparing the electrically coupled response of the
pipe. If the two structures are not metallically connected, a significant potential difference
occurs between the casing and the carrier pipe. Because the casing is anodically polarized with
respect to an independent ground, the C/S potential shifts in a positive direction. If the pipe and
casing are metallically shorted, P/S potential also shifts in a positive direction, usually by about
the same magnitude as the casing. As additional current is applied to the system, the P/S
potentials largely track the positive shifting potentials of the casing.

If the casing potential shifts in a positive direction and the carrier pipe potential remains near
normal, electrical isolation is indicated. For electrolytic couples, no conclusion can be
determined in many situations, so this test is not recommended for determination of electrolytic
couple between a casing and carrier pipe. Additional testing must be performed to confirm if an
electrolytic couple exists or does not exist.

D.4.7 Internal Resistance Test

This technique indicates whether direct metal-to-metal contact exists between the carrier pipe
and the casing by measuring electrical resistance.

A battery is inserted in a circuit set between the pipe (cathode) and the casing (anode). With a
known constant current (I) applied briefly, the potential difference between the pipe and the
casing is measured and recorded (Eon). With the test current interrupted, the pipe-to-casing
potential (Eoff) is measured.
 The change in voltage between each is determined (Eon-Eoff) and then divided by the current (I)
so that the internal resistance is determined by Ohm’s law. If the internal resistance is less than
0.01 ohm, then the casing is considered metallically shorted. If the internal resistance is greater
than 0.08 ohm, then the casing is considered electrically isolated. If the internal resistance is
between these two values, then no conclusion can be drawn regarding electrical isolation and
additional testing is required. In many situations, no conclusions concerning electrolytic couples
can be made. Therefore, this test is not recommended for determining whether or not a casing
and carrier pipe is coupled electrolytically. Additional testing must be performed to confirm if an
electrolytic couple exists or does not exist.

D.4.8 Casing/Pipe Capacitance

The actual resistance between a potentially shorted casing and the carrier pipe depends on
many factors, such as the environment in which the pipe is located. Checking the electrical
isolation of a carrier pipe in a casing for current leakage can be a reliable test. The capacitance
test looks at the electrical characteristics of the possible short. The device used and principles
involved are the same as for evaluation of the effectiveness of an isolation flange. In general,
the following conditions exist when effective isolation is measured:

1. Substantially different ground voltage readings are evidenced on the pipe and the
casing.
2. The percentage of current leakage that the short will allow to flow through it is low,
25 percent or less.
3. The voltage drop across a pipe and casing that is not shorted is significant. The
voltage drop across a shorted condition would be negligible, in the range of 10
millivolts or less.

The Isolation Checker uses the above three criteria to determine, and display, whether the pipe
and the casing are shorted or clear. For electrolytic couples no conclusion can be determined
in many situations, so this test is not recommended to determine if a casing and carrier pipe are
coupled electrolytically. Additional testing must be performed to confirm whether or not an
electrolytic couple exists.

D.4.9 Current Span Test (Four Wire Drop Test)

This test is similar to the evaluation of current leakage through an isolation device. The test
consists of measuring a current span along the casing while test current is applied in each of
three circuit configurations:

1. Current is applied through an ammeter along the length of the casing from contacts
just outside the ends of the current span. If the casing is clear, then all of this test
current must pass through the span (in agreement with the polarity of the current
circuit), and the calculated resistance (using Ohm’s Law) may be employed to
confirm the resistance of the span. If there is a metallic short between the pipe and
casing, part of the test current will flow along the pipe, and the measured resistance
will be reduced accordingly.

2. Current is applied through an ammeter between a contact to the pipe (cathode) at

one end of the casing and to the casing (anode) at the opposite end. Again,
essentially no current will flow along the pipe unless there is a metallic short between
the pipe and casing, with the measured resistance reduced accordingly.

3. Current is applied between the pipe and casing at one end of the casing. If the pipe
and casing are clear at that end, then all of the test current will flow along the casing
span away from the location of the current circuit. If a short exists at the end where
the current is applied, there will be virtually no current flowing along the span. If a
short exists at the end of the casing opposite the current circuit, then current flows
away from the current source along the casing and back to the source along the pipe
inside the casing. If a short exists between the casing ends, then the apparent
current flow along the span varies accordingly.
 Often this test does not provide conclusive identification of electrolytic couples and is not
recommended for determining if a casing and carrier pipe are electrolytically coupled.
Additional testing must be performed to confirm whether or not an electrolytic couple exists.

D.4.10 Temporary Intentional Short

This test is done by comparing/recording the pipe-to-soil and casing-to-soil potentials with and
without an external shorting jumper connected between the pipe and the casing at one end.
The reference cell is located in the same location over the pipeline for both the pipe-to-soil and
casing-to-soil potential measurements. Typically, the reference cell is located at least 3 feet
from the casing vent over the carrier pipeline beyond the end of the casing.

The following measurements are recorded:

1. The initial pipe-to-soil and casing-to-soil potentials without the external shorting
jumper connected.
2. The potential difference between the casing and the carrier pipe.
3. The pipe-to-soil and casing-to-soil shorted potentials with a shorting jumper
connected between the pipeline and the casing.

Indication of a shorted condition is apparent if all potential measurements are nearly identical to
those taken before the shorting jumper was connected. If possible, repeat the test by shorting
the pipe to the opposite end of the casing.

Often this test does not provide conclusive identification of electrolytic couples and is not
recommended for determining if a casing and carrier pipe are electrolytically coupled.
Additional testing must be performed to confirm whether or not an electrolytic couple exists.

In general, the above tests are usually excellent tools for the detection of direct or metallic
shorts, but lack precision when used to identify electrolytic couples. In most cases, operators
should use more than one technique to validate that the casing is clear and free from all types
of electrical shorts. If an operator cannot positively exclude the existence of an electrolytic
couple, the operator should assume such a condition currently exists or has previously
occurred.